Search

Hydraulic fracturing, a production enhancement technique, is widely used in the development of unconventional oil and gas reservoirs. The formation of a complex network of hydraulic fractures that connect with natural fractures is crucial for hydraulic fracturing in unconventional reservoirs. However, the current understanding of vertical fracture propagation behavior under the influence of variations in the mechanical properties of interbedded rock is insufficient to meet the requirements for simulations of unconventional reservoirs under complex geological conditions. In this study, a three-dimensional discrete grid method was employed to establish a model of three-dimensional fracture propagation. Numerical simulations were conducted to investigate the vertical growth of fractures while considering the influence of bedding planes. The effects of formation factors (stress, Young's modulus) and bedding planes (cohesion, density) on the height growth of hydraulic fractures were explored. The results indicated that the interbedded stress contrast, Young's modulus contrast, and bedding planes collectively controlled the height growth of hydraulic fractures. The height of hydraulic fractures decreased with increasing minimum horizontal principal stress of adjacent layers. When the minimum horizontal principal stress of adjacent layers exceeded the vertical stress, hydraulic fractures gradually deflected into the horizontal plane. Adjacent layers with large values of Young's modulus promoted the height growth of hydraulic fractures, while adjacent layers with small values of Young's modulus inhibited the height growth of hydraulic fractures. The presence of bedding planes further suppressed height growth, and the degree of suppression was related to the cohesion and density of the bedding planes. Weaker cohesion and higher density resulted in greater suppression. The results of this study provide a reference for the design and optimization of hydraulic fracturing treatments in unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

The clear mechanism of hydraulic fracture propagation in glutenite reservoirs with high heterogeneity is still not obtained, thus it is difficult to carry out the design of fracturing plan effectively. Based on the characteristics of the glutenite reservoirs, a coupled flow-stress-damage (FSD) model of hydraulic fracture propagation with gravels is established. This model is experimentally verified and the research on the influence of rock physical parameters and gravel property on the hydraulic fracture propagation is conducted. It is shown that as the gravel tensile strength increases, the hydraulic fracture is prone to propagate around the gravel, where the fracture deflection always occurs; as the gravel Young's modulus increases, there is high probability that hydraulic fracture propagates around the gravel, with more obvious fracture deflection; the matrix permeability influences fracture propagating morphology when encountering gravel and total fracture length; the horizontal geostress difference seriously impacts the fracture deflection; as the fracturing fluids injection displacement increases, the fracture is prone to deflect when encountering gravel; the low viscosity fracturing fluids result in the shorter fracture; the larger gravel increases the possibility of fracture deflection; in case of smaller gravel sizes, the increasing gravel content has a big influence on fracture deflection, and the increasing content of large gravel complicates the fracture morphology, resulting in the fine branched fractures; for the well rounded gravel, the fracture propagation around the gravel is prone to occur, and the fracture is not prone to deflect. Compared with the conventional sandstone reservoir, the glutenite reservoirs have higher breakdown and extension pressures, which fluctuate due to the gravel; the larger gravel size results in higher extension pressure. In this paper, a simulation method of hydraulic fracture propagation in the glutenite reservoirs is introduced, and the result provides the theoretical support for prediction of fracture propagation morphology and plan design of hydraulic fracturing in the glutenite reservoirs. [ABSTRACT FROM AUTHOR]

The conventional hydraulic fracturing is not effective in the target oil development zone (remaining oil or gas, trap reservoir, etc.) with available wellbores located in the azimuth of non-maximum horizontal in-situ stress. The technology of directional propagation of hydraulic fracture guided by vertical multi-radial boreholes was innovatively developed. In order to verify the technology, a 3D extended finite element numerical model of hydraulic fracturing promoted by vertical multi-radial boreholes was established using Abaqus Software, and the influence of horizontal in-situ stress differences, azimuth, diameters, spacing, and lengths of radial boreholes, rates and viscosities of fracturing fluids, Young modulus and Poisson's ratio of rock, and reservoir permeability on propagation of hydraulic fracture guided by radial borehole row were comprehensively analyzed. Moreover, the term ‘Guidance factor (G)’ was introduced for the first time to effectively quantify guidance of radial borehole row. Finally, the guidance of the above ten factors is comprehensively evaluated through gray correlation analysis. The results showed that the directional propagation of hydraulic fracture is realized through scientifically arranged vertical radial borehole row, and ‘G’ reflects the real guidance strength of radial borehole row to hydraulic fracture. The azimuth of radial borehole row increases by 75°, G increases by 18 times. Horizontal in-situ stress difference increases by 9 MPa, G increases by 95%. The borehole diameter increases by 4 cm, G decreases by 54%. The borehole spacing increases by 0.5 m, G increases by 18%. The borehole length increases by 10 m, G decreases by 40%. Young's modulus of reservoir rock increases by 20 GPa, G decreases by 23%. Poisson's ratio increases by 0.1, G increases by 57%. Permeability of reservoir increases by 100 times, G increases by 3.3 times. Injection rate increases by 9 m 3 /min, G decreases by 63%. Both excessively high and low viscosities are adverse to guidance of radial borehole to hydraulic fracture, and 50 mPa s fracturing fluid creates best guidance to propagation of hydraulic fracture. The gray correlation analysis showed that the influences (from strong to weak) of the above factors on guidance of radial borehole were listed as follows: azimuth of radial borehole > injection rate of fracturing fluid > horizontal in-situ stress differences > Young's modulus of rock > viscosity of fracturing fluid > borehole diameter of radial borehole > radial borehole spacing > reservoir permeability > length of radial borehole > Poisson's ratio. This study provided theoretical evidence for directional propagation of hydraulic fracture promoted by radial borehole, and it predicted the guidance of radial borehole to hydraulic fracture in a certain extent, which is helpful for planning well-completion and fracturing operation in technology of hydraulic fracturing promoted by radial borehole. [ABSTRACT FROM AUTHOR]

On the basis of damage mechanics, a 2D fracture propagation model for seepage-stress-damage coupling in multi-fracture shales was established. Numerical simulations of hydraulic fracture propagation in the presence of natural fractures were carried out, with the use of mechanical parameters of shale reservoirs. The results showed that when hydraulic fractures encountered natural fractures in a shale reservoir, the morphology of fracture propagation was jointly affected by the properties of natural fractures (permeability and mechanical properties of rocks), approaching angle, horizontal stress difference, and flow rate of fracturing fluids. At a small horizontal stress difference, or low approaching angle, or small friction coefficient, natural fractures had increased potential to be damaged due to shear and tension. In such cases, the hydraulic fractures tended to propagate along the natural fractures. As the flow rate of fracturing fluid increased and the width of hydraulic fractures expanded, branch fractures formed easily when the net pressure exceeded the sum of horizontal stress difference and tensile strength of the rocks in which natural fractures with approaching angle smaller than 60° existed. It is seen, a high flow rate will increase the complexity of fracture network. However, when a large number of natural fractures with approaching angles greater than 60° existed, a large flow rate generally led to propagation of hydraulic fractures beyond natural fractures, which was not favored. Hence, an appropriate flow rate should be selected based on the orientations of natural fractures and hydraulic fractures. At the early stage of hydraulic fracturing, a low flow rate was favorable for the initiation of natural fractures and the growth of complexity of regional fractures near the well. Later, a higher flow rate facilitated a further propagation of hydraulic fractures into the depth of reservoir, thus forming a network of fractures. The underlying control mechanism of flow rate and net pressure on the formation of fracture network still requires clarification. The bending degree of the fracture propagation path depended on the ratio of net pressure to stress difference at a distant point as well as on the spacing between fractures. When the horizontal stress difference (<9 MPa) or coefficient of horizontal stress difference (<0.25) was low, the ratio of net pressure to stress difference was high. In this case, the fracture-induced stress obtained an enhanced significance, while the interactions of hydraulic fractures intensified, leading to a non-planar propagation of fractures. In addition, a smaller spacing between fractures caused intensified interactions of hydraulic fractures, so the propagation path altered more easily. This work contributes to the prediction of morphology of fracture propagation in unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

Compared with conventional hydrofracturing fluid, SC-CO 2 has the merits of no water sensitivity and effective carbon dioxide storage. At present, the research on the fracture initiation mechanism of SC-CO 2 fracturing is still at the exploring phase. This paper conducts a detailed study on the fracture initiation mechanism of SC-CO 2 fracturing, and establishes a fracture initiation and propagation model of flow-stress-damage coupling according to damage mechanics. A series of numerical simulation studies have been carried out on the rock physical parameters, fracturing construction parameters, natural fracture distribution and other factors that affect the fracture propagation of the reservoir to provide a reference for the SC-CO 2 fracturing construction design. The findings suggest: the lower formation permeability, the less SC-CO 2 filtration loss, and the larger total fracture length and width; SC-CO 2 is easier to improve the reservoir continuity and result in a complex fracture network; The lower the viscosity of SC-CO 2 , the larger total length of fractures, and the more complex the fracture network; As the delivery of pump increases, the width of fracture continues to increase, and the total fracture length decreases; SC-CO 2 has a better effect on communicating natural fractures and porous media, and the fracture network is more complex. • Fracture propagation model with flow-stress-damage (FSD) coupling is developed. • A simulation method of hydraulic fracture propagation in the glutenite reservoirs is introduced. • The model accuracy is validated through comparison between results of physical experiment and numerical simulation. • The effects of multiple factors on fracture propagating in the glutenite reservoirs are analyzed. [ABSTRACT FROM AUTHOR]