Contributions of non-tectonic micro-fractures to hydraulic fracturing—A numerical investigation based on FSD model

Shale gas has been discovered in the Upper Triassic Yanchang Formation, Ordos Basin, China. Due to the weak tectonic activities in which the shale plays, core observations indicate abundant random non-tectonic micro- fractures in the producing shales. The non-tectonic micro-fractures are different from tectonic fractures and are characterized by being irregular, curved, discontinuous, and randomly distributed. The role of micro-fractures in hydraulic fracturing for shale gas development is currently poorly understood yet potentially critical. Two-dimensional computational modeling studies have been used in an initial attempt toward understanding how naturally random fractured reservoirs respond during hydraulic fracturing. The aim of the paper is to investigate the effect of random non-tectonic fractures on hydraulic fracturing. The numerical models with random non-tectonic micro-fractures are built by extracting the fractures of rock blocks after repeated heating and cooling, using a digital image process. Simulations were conducted as a function of: (1) the in-situ stress ratio; (2) internal friction angle of random fractures; (3) cohesion of random fractures; (4) operational variables such as injection rate; and (5) variable injection rate technology. A sensitivity study reveals a number of interesting observations resulting from these parameters on the shear stimulation in a natural fracture system. Three types of fracturing networks were observed from the studied simulations, and the results also show that variable injection rate technology is most promising for producing complex fracturing networks. This work strongly links the production technology and geomechanical evaluation. It can aid in the understanding and optimization of hydraulic fracturing simulations in naturally random fractured reservoirs.     

Numerical evaluation of the effect of fracture network connectivity in naturally fractured shale based on FSD model

In this paper, the effect of pre-existing discrete fracture network (DFN) connectivity on hydraulic fracturing is numerically investigated in a rock mass subjected to in-situ stress. The simulation results show that DFN connectivity has a significant influence on the hydraulic fracture (HF) & DFN interaction and hydraulic fracturing effectiveness, which can be characterized by the total interaction area, stimulated DFN length, stimulated HF length, leak-off ratio, and stimulated total length. In addition, even at the same fluid injection rate, simulation models exhibit different responses that are strongly affected by the DFN connectivity. At a low injection rate, total interaction area decreases with increasing DFN connectivity; at a high injection rate, total interaction area increases with the increase of DFN connectivity. However, for any injection rate, the stimulated DFN length increases and stimulated HF length decreases with the increase of connectivity. Generally, this work shows that the DFN connectivity plays a crucial role in the interaction between hydraulic fractures, the pre-existing natural fractures and hydraulic fracturing effectiveness; in return, these three factors affect treating pressure, created microseismicity and corresponding stimulated volume. This work strongly relates to the production technology and the evaluation of hydraulic fracturing effectiveness. It is helpful for the optimization of hydraulic fracturing simulations in naturally fractured formations.     

基于方位地震数据的地应力反演方法

在页岩油气藏的开发和勘探阶段,需要对储层进行水力压裂改造,形成有利于油气聚集和运移的裂缝.地应力是进行水力压裂改造的重要参数,能够决定裂缝的大小、方向以及分布形态,影响着压裂的增产效果,且最大和最小水平应力差异比（ODHSR,Orthorhombic Differential Horizontal Stress Ratio）是评价储层是否可压裂成网的重要因子.本文探讨了基于地震数据估算地应力的方法,以指导页岩气的水力压裂开发.首先,利用叠前方位地震数据反演得到地层的弹性参数和各向异性参数;其次,基于正交各向异性水平应力差异比近似公式,利用反演得到的弹性参数和各向异性参数估算地层的ODHSR;最后,选取某工区的裂缝型页岩储层的叠前方位地震数据对该方法进行实际应用.实际工区地震数据应用表明,基于叠前方位地震数据反演得到的ODHSR能够有效的识别储层中易于压裂成网的区域.     

Matrix–fracture transfer shape factor for modeling flow of a compressible fluid in dual-porosity media

The matrix–fracture transfer shape factor is one of the important parameters in the modeling of fluid flow in fractured porous media using a dual-porosity concept. Warren and Root [36] introduced the dual-porosity concept and suggested a relation for the shape factor. There is no general relationship for determining the shape factor for a single-phase flow of slightly compressible fluids. Therefore, different studies reported different values for this parameter, as an input into the flow models. Several investigations have been reported on the shape factor for slightly compressible fluids. However, the case of compressible fluids has not been investigated in the past. The focus of this study is, therefore, to find the shape factor for the single-phase flow of compressible fluids (gases) in fractured porous media. In this study, a model for the determination of the shape factor for compressible fluids is presented; and, the solution of nonlinear gas diffusivity equation is used to derive the shape factor. The integral method and the method of moments are used to solve the nonlinear governing equation by considering the pressure dependency of the viscosity and isothermal compressibility of the fluid. The approximate semi-analytical model for the shape factor presented in this study is verified using single-porosity, fine-grid, numerical simulations. The dependency of the shape factor on the gas specific gravity, pressure and temperature are also investigated. The theoretical analysis presented improves our understanding of fluid flow in fractured porous media. In addition, the developed matrix–fracture transfer shape factor can be used as an input for modeling flow of compressible fluids in dual-porosity systems, such as naturally fractured gas reservoirs, coalbed methane reservoirs and fractured tight gas reservoirs.     

沁水盆地南部煤层气储层压裂过程数值模拟研究

储层改造是煤层气井提高产能的重要措施,水力压裂是煤层气储层改造的重要方法.为研究煤层气储层压裂过程及其天然裂缝对煤储层压裂时破裂压力的影响,本文以山西沁水盆地南部高煤级煤矿区为研究区,运用有限元数值模拟方法,计算不同地应力条件下、裂缝处于不同位置时煤储层的破裂压力.结果表明:(1)不同类型地应力场对破裂压力的影响不同.对于均匀应力场,破裂压力随着围压的增大而增大,其增幅约为围压的两倍;对于非均匀应力场,当一个水平主应力不变时,破裂压力会随着水平主应力差的增加而减少;(2)如果地应力条件不变,煤储层破裂压力随着天然裂缝与最大水平主应力方向夹角的增加而增加,水平主应力差越大煤储层破裂压力增幅也越大;(3)在有天然裂隙的地层中进行压裂,当天然裂缝的方位不同时压裂裂缝既可能是沿着天然裂缝扩展的裂缝,也可能是压裂过程中产生的新裂缝,因此天然裂缝的方位对破裂压力具有一定的影响.     

Characterizing production‐induced anisotropy of fractured reservoirs having multiple fracture sets

Since natural fractures in petroleum reservoirs play an important role in determining fluid flow during production, knowledge of the orientation and density of fractures is required to optimize production. This paper outlines the underlying theory and implementation of a fast and efficient algorithm for upscaling a Discrete Fracture Network (DFN) to predict the fluid flow, elastic and seismic properties of fractured rocks. Potential applications for this approach are numerous and include the prediction of fluid flow, elastic and seismic properties for fractured reservoirs, model‐based inversion of seismic Amplitude Versus Offset and Azimuth (AVOA) data and the optimal placement and orientation of infill wells to maximize production. Given that a single fracture network may comprise hundreds of thousands of individual fractures, the sheer size of typical DFNs has tended to limit their practical applications. This paper demonstrates that with efficient algorithms, the utility of Discrete Fracture Networks can be extended far beyond mere visualization.     

Integrated application of 3D seismic and microseismic data in the development of tight gas reservoirs

The development of unconventional resources, such as shale gas and tight sand gas, requires the integration of multi-disciplinary knowledge to resolve many engineering problems in order to achieve economic production levels. The reservoir heterogeneity revealed by different data sets, such as 3D seismic and microseismic data, can more fully reflect the reservoir properties and is helpful to optimize the drilling and completion programs. First, we predict the local stress direction and open or close status of the natural fractures in tight sand reservoirs based on seismic curvature, an attribute that reveals reservoir heterogeneity and geomechanical properties. Meanwhile, the reservoir fracture network is predicted using an ant-tracking cube and the potential fracture barriers which can affect hydraulic fracture propagation are predicted by integrating the seismic curvature attribute and ant-tracking cube. Second, we use this information, derived from 3D seismic data, to assist in designing the fracture program and adjusting stimulation parameters. Finally, we interpret the reason why sand plugs will occur during the stimulation process by the integration of 3D seismic interpretation and microseismic imaging results, which further explain the hydraulic fracture propagation controlling factors and open or closed state of natural fractures in tight sand reservoirs.     

Influence of Bedding and Mineral Composition on Mechanical Properties and Its Implication for Hydraulic Fracturing of Shale Oil Reservoirs

The premise of hydraulic fracturing is to have an accurate and detailed understanding of the rock mechanical properties and fracture propagation law of shale reservoirs. In this paper, a comprehensive evaluation of the mechanical properties of the shale oil reservoir in the south of Songliao Basin is carried out. Based on the experiments and the in-situ stress analysis, the fracture propagation law of three types of shale reservoirs is obtained, and the suggestions for fracturing are put forward. The results have shown that the fracture propagation of pure shale and low mature reservoir is easy to open along the bedding plane under compression loading, which is greatly influenced by the bedding. Sand-bearing shale is slightly better, the fractures of which are not easy to open along the bedding plane. The mechanical experimental results show that all the samples have the characteristics of low compressive strength, low Young''s modulus and strong anisotropy, indicating that the shale oil reservoir is certain plastic, which is related to its high clay mineral content and controlled by the bedding development. Compared with pure shale and low mature shale, the sand-bearing shale has less clay content and less developed bedding, which maybe the main reason for its slightly better brittleness. Overall, the expansion of hydraulic fracture is controlled by in-situ stress and bedding. Because of the development of bedding, it is easy to form horizontal fractures. Thus it is not suitable for horizontal well fracturing. Because of the high content of clay minerals, the applicability of conventional slick hydraulic fracturing fluid is poor. It is suggested to use vertical well or directional well to carry out volume fracturing. In this way, the effect of bedding can be effectively used to open and connect the bedding and form a larger fracture network.     

Characterization of fractured reservoirs using a consistent stiffness‐permeability model: focus on the effects of fracture aperture

In this paper we propose a method for the characterization of naturally fractured reservoirs by quantitative integration of seismic and production data. The method is based on a consistent theoretical frame work to model both effective hydraulic and elastic properties of fractured porous media and a (non‐linear) Bayesian method of inversion that provides information about uncertainties as well as mean (or maximum likelihood) values. We model a fractured reservoir as a porous medium containing a single set of vertical fractures characterized by an unknown fracture density, azimuthal orientation and aperture. We then look at the problem of fracture parameter estimation as a non‐linear inverse problem and try to estimate the unknown fracture parameters by joint inversion of seismic amplitude versus angle and azimuth data and dynamic production data. Once the fracture parameters have been estimated the corresponding effective stiffness and permeability tensors can be estimated using consistent models. A synthetic example is provided to clearly explain and test the workflow. It shows that seismic and production data complement each other, in the sense that the seismic data resolve a non‐uniqueness in the fracture orientation and the production data help to recover the true fracture aperture and permeability, because production data are more sensitive to the fracture aperture than the seismic data.     

Numerical Modeling of Methane Leakage from a Faulty Natural Gas Well into Fractured Tight Formations

Horizontal drilling and hydraulic fracturing have enabled hydrocarbon recovery from unconventional reservoirs, but led to natural gas contamination of shallow groundwaters. We describe and apply numerical models of gas‐phase migration associated with leaking natural gas wells. Three leakage scenarios are simulated: (1) high‐pressure natural gas pulse released into a fractured aquifer; (2) continuous slow leakage into a tilted fractured formation; and (3) continuous slow leakage into an unfractured aquifer with fluvial channels, to facilitate a generalized evaluation of natural gas transport from faulty natural gas wells. High‐pressure pulses of gas leakage into sparsely fractured media are needed to produce the extensive and rapid lateral spreading of free gas previously observed in field studies. Transport in fractures explains how methane can travel vastly different distances and directions laterally away from a leaking well, which leads to variable levels of methane contamination in nearby groundwater wells. Lower rates of methane leakage (≤1 Mcf/day) produce shorter length scales of gas transport than determined by the high‐pressure scenario or field studies, unless aquifers have low vertical permeabilities (≤1 millidarcy) and fractures and bedding planes have sufficient tilt (～10°) to allow a lateral buoyancy component. Similarly, in fractured rock aquifers or where permeability is controlled by channelized fluvial deposits, lateral flow is not sufficiently developed to explain fast‐developing gas contamination (0‐3 months) or large length scales (～1 km) documented in field studies. Thus, current efforts to evaluate the frequency, mechanism, and impacts of natural gas leakage from faulty natural gas wells likely underestimate contributions from small‐volume, low‐pressure leakage events.     

Microearthquake analysis for hydraulic frac－turing proces

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Influence of Hydraulic Fracturing on Overlying Aquifers in the Presence of Leaky Abandoned Wells

The association between hydrocarbon‐rich reservoirs and organic‐rich source rocks means unconventional oil and gas plays usually occur in mature sedimentary basins—where large‐scale conventional development has already taken place. Abandoned wells in proximity to hydraulic fracturing could be affected by increased fluid pressures and corresponding newly generated fractures that directly connect (frac hit) to an abandoned well or to existing fractures intersecting an abandoned well. If contaminants migrate to a pathway hydraulically connected to an abandoned well, upward leakage may occur. Potential effects of hydraulic fracturing on upward flow through a particular type of leaky abandoned well—abandoned oil and gas wells converted into water wells were investigated using numerical modeling. Several factors that affect flow to leaky wells were considered including proximity of a leaky well to hydraulic fracturing, flowback, production, and leaky well abandonment methods. The numerical model used historical records and available industry data for the Eagle Ford Shale play in south Texas. Numerical simulations indicate that upward contaminant migration could occur through leaky converted wells if certain spatial and hydraulic conditions exist. Upward flow through leaky converted wells increased with proximity to hydraulic fracturing, but decreased when flowback and production occurred. Volumetric flow rates ranged between 0 and 0.086 m³/d for hydraulic‐fracturing scenarios. Potential groundwater impacts should be paired with plausible transport mechanisms, and upward flow through leaky abandoned wells could be unrelated to hydraulic fracturing. The results also underscore the need to evaluate historical activities.     

Fault detection based on microseismic events

In unconventional reservoirs, small faults allow the flow of oil and gas as well as act as obstacles to exploration; for, (1) fracturing facilitates fluid migration, (2) reservoir flooding, and (3) triggering of small earthquakes. These small faults are not generally detected because of the low seismic resolution. However, such small faults are very active and release sufficient energy to initiate a large number of microseismic events (MEs) during hydraulic fracturing. In this study, we identified microfractures (MF) from hydraulic fracturing and natural small faults based on microseismicity characteristics, such as the time–space distribution, source mechanism, magnitude, amplitude, and frequency. First, I identified the mechanism of small faults and MF by reservoir stress analysis and calibrated the ME based on the microseismic magnitude. The dynamic characteristics (frequency and amplitude) of MEs triggered by natural faults and MF were analyzed; moreover, the geometry and activity types of natural fault and MF were grouped according to the source mechanism. Finally, the differences among time–space distribution, magnitude, source mechanism, amplitude, and frequency were used to differentiate natural faults and manmade fractures.     

Effect of seismic waves on the hydro-mechanical properties of fractured rock masses

The transmission of seismic waves in a particular region may influence the hydraulic properties of a rock mass, including permeability, which is one of the most important. To determine the effect of a seismic wave on the hydraulic behavior of a fractured rock mass, systematic numerical modeling was conducted. A number of discrete fracture network(DFN) models with a size of 20 m × 20 m were used as geometrical bases, and a discrete element method(DEM) was employed as a numerical simulation tool. Three different boundary conditions without(Type Ⅰ) and with static(Type Ⅱ) and dynamic(Type Ⅲ) loading were performed on the models, and then their permeability was calculated. The results showed that permeability in Type Ⅲ models was respectively 62.7% and 44.2% higher than in Type I and Type Ⅱ models. This study indicates that seismic waves can affect deep earth, and, according to the results, seismic waves increase the permeability and change the flow rate patterns in a fractured rock mass.     

Study on anisotropy of Longmaxi shale using hydraulic fracturing experiment

Hydraulic fracturing reservoir reconstruction technology is crucial in the development of shale gas exploitation techniques.Large quantities of high-pressure fluids injected into shale reservoirs significantly alter compressional(P)and shear(S)wave velocities,rock mechanical parameters,and anisotropic characteristics.In this study,differentiated hydraulic fracturing petrophysical experiments were carried out on Longmaxi Formation shale under pseudo-triaxial stress loading conditions.The effects of stress loading methods,and water-rock physical and chemical reactions on P-and S-wave velocities and rock mechanical parameters were compared.The experimental results showed that isotropic stress loading may increase the P-and Swave velocities and Young’s modulus of dry shale kldnsample.Furthermore,it may lead to a weakening of the corresponding anisotropy.In contrast,differential stress loading was able to improve the anisotropy of Young’s modulus and accelerate the decrease in the compressive strength of shale in the vertical bedding direction.The water-rock physical and chemical reactions prompted by hydraulic fracturing was found to"soften"shale samples and reduce Young’s modulus.The influence of this"soften"effect on the compressional and shear wave velocities of shale was negligible,whilst there was a significant decrease in the anisotropy characteristics of Thomsen parameters,Young’s modulus,and Poisson’s ratio.The negative linear relationship between the Poisson’s ratios of the shale samples was also observed to lose sensitivity to stress loading,as a result of the"soften"effect of fracturing fluid on shale.The results of this study provide a reliable reference point and data support for future research on the mechanical properties of Longmaxi shale rocks.     

FracKfinder: A MATLAB Toolbox for Computing Three-Dimensional Hydraulic Conductivity Tensors for Fractured Porous Media

Fractures in porous media have been documented extensively. However, they are often omitted from groundwater flow and mass transport models due to a lack of data on fracture hydraulic properties and the computational burden of simulating fractures explicitly in large model domains. We present a MATLAB toolbox, FracKfinder, that automates HydroGeoSphere (HGS), a variably saturated, control volume finite-element model, to simulate an ensemble of discrete fracture network (DFN) flow experiments on a single cubic model mesh containing a stochastically generated fracture network. Because DFN simulations in HGS can simulate flow in both a porous media and a fracture domain, this toolbox computes tensors for both the matrix and fractures of a porous medium. Each model in the ensemble represents a different orientation of the hydraulic gradient, thus minimizing the likelihood that a single hydraulic gradient orientation will dominate the tensor computation. Linear regression on matrices containing the computed three-dimensional hydraulic conductivity (K) values from each rotation of the hydraulic gradient is used to compute the K tensors. This approach shows that the hydraulic behavior of fracture networks can be simulated where fracture hydraulic data are limited. Simulation of a bromide tracer experiment using K tensors computed with FracKfinder in HGS demonstrates good agreement with a previous large-column, laboratory study. The toolbox provides a potential pathway to upscale groundwater flow and mass transport processes in fractured media to larger scales.     

Natural hydraulic cracking: numerical model and sensitivity study

Natural hydrofracturing caused by overpressure plays an important role in geopressure evolution and hydrocarbon migration in petroliferous basins. Its mechanism is quite well understood in the case of artificial hydraulic fracturing triggered by high-pressure fluid injection in a well. This is not so for natural hydraulic fracturing which is assumed to initiate as micro-cracks with large influence on the permeability of the medium. The mechanism of natural hydraulic cracking, triggered by increasing pore pressure during geological periods, is studied using a fracturing model coupled to the physical processes occurring during basin evolution. In this model, the hydraulic cracking threshold is assumed to lie between the classical failure limit and the beginning of dilatancy. Fluid pressure evolution is calculated iteratively in order to allow dynamic adjustment of permeability so that the fracturing limit is always preserved. The increase of permeability is interpreted on the basis of equivalent fractures. It is found that fracturing is very efficient to keep a stress level at the rock’s hydraulic cracking limit: a fracture permeability one order of magnitude larger than the intrinsic permeability of the rock would be enough. Observations reported from actual basins and model results strongly suggest that natural hydraulic cracking occurs continuously to keep the pressure at the fracturing limit under relaxed stress conditions.     

Role of Stress-controlled Flow Pathways in HDR Geothermal Reservoirs

— We addressed effects of in situ stress on the formation of flow pathways in fractured rocks in geothermal reservoirs, especially for HDR projects. Here we focused on fractures which are critically-stressed, causing shear slip in a current stress field. The sliding is likely to break sealing in the fractures and, as a result, to increase their permeability. Such a mechanism is possibly significant under high-temperature conditions at geothermal fields because of temperature enhancement on chemical reactions for the sealing. We present a procedure to estimate the orientation of the critically-stressed fractures relative to axes of in situ principal stress with the aid of the Mohr diagram. The procedure allows us to evaluate intuitively how the orientation changes with factors such as magnitude of in situ principal stresses and pore pressure. We applied the procedure to estimate possible orientations of the critically-stressed fractures in major HDR test sites. Results show that overall alignments of microseismicity during hydraulic stimulation are within predicted ranges for possible orientations of the critically-stressed fractures. Furthermore, it was found that if the state of in situ stress is not favorable to cause sliding of natural fractures, it tends to lead a high wellhead pressure at hydraulic stimulation and a high recovery rate at circulation. On the other hand, if the state of in situ stress is favorable for sliding, it tends vice versa to lead a low wellhead pressure at hydraulic stimulation and a low recovery rate at circulation.     

全球油气开采诱发地震的研究现状与对策

人工诱发地震现象已经有很久的历史.水库蓄水、采矿、地热开发、从地下提取液体或气体,或将液体注入地球内部都可能诱发地震.大量地震监测数据与科学分析结果显示:美国俄克拉何马州的地震剧增主要与页岩油气开采的废水回注量相关;加拿大阿尔伯塔省的地震剧增主要与页岩油气开采水力压裂的工作量相关;而荷兰罗宁根天然气田的传统天然气开采也同样诱发了较强的地震活动.在中国四川盆地的页岩油气开发区域,地震活动近几年也大幅度增强,但目前监测与科研工作较少,对某些地震成因尚有争议.目前研究诱发地震问题已成为学术界与工业界的一门专业学科.推断诱发地震,除了分析时空分布与工业活动的相关性之外,本文综述了该领域基于地震学、地质动力学、构造地质学的多种分析方法.如何在油气开采过程中减少诱发地震的灾害影响成为当前相关各界极为关注的科研问题,本文介绍了多个国家或地区建立的控制诱发地震的管理系统、基于地震大数据的诱发地震概率预测方法,以及基于地球物理与地质信息的综合诱发地震风险评估方法,并对我国控制诱发地震问题提出建设性意见.     

Determining the microseismic event source parameters from the surface seismic array data with strong correlated noise and complex focal mechanisms of the source

The world experience shows that hydraulic fracturing (fracking) is an efficient tool for increasing oil and gas production of low-permeable reservoirs in hydrocarbon fields. The fracking-induced fractures in the rock, which are hydrodynamically connected with the wells, significantly enhance the volumes of extracted hydrocarbons. Controlling the processes of fracture formation and propagation is a vital question in the oil and gas reservoir management. A key means to implement this control is provided by microseismic monitoring of fracking, which makes it possible to promptly reconstruct the geometry of the fractures from the data on seismic waves from the microearthquakes induced by the formation and propagation of fractures.