scholarly journals Experimental and Numerical Investigation on Basic Law of Dense Linear Multihole Directional Hydraulic Fracturing

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Xin Zhang ◽  
Yuqi Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Large Scale ◽  
Pore Water Pressure ◽  
Water Pressure ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Directional Hydraulic Fracturing ◽  
Basic Law

Using the dense linear multihole to control the directional hydraulic fracturing is a significant technical method to realize roof control in mining engineering. By combining the large-scale true triaxial directional hydraulic fracturing experiment with the discrete element numerical simulation experiment, the basic law of dense linear holes controlling directional hydraulic fracturing was studied. The results show the following: (1) Using the dense linear holes to control directional hydraulic fracturing can effectively form directional hydraulic fractures extending along the borehole line. (2) The hydraulic fracturing simulation program is very suitable for studying the basic law of directional hydraulic fracturing. (3) The reason why the hydraulic fracture can be controlled and oriented is that firstly, due to the mutual compression between the dense holes, the maximum effective tangential tensile stress appears on the connecting line of the drilling hole, where the hydraulic fracture is easy to be initiated. Secondly, due to the effect of pore water pressure, the disturbed stress zone appears at the tip of the hydraulic fracture, and the stress concentration zone overlaps with each other to form the stress guiding strip, which controls the propagation and formation of directional hydraulic fractures. (4) The angle between the drilling line and the direction of the maximum principal stress, the in situ stress, and the hole spacing has significant effects on the directional hydraulic fracturing effect. The smaller the angle, the difference of the in situ stress, and the hole spacing, the better the directional hydraulic fracturing effect. (5) The directional effect of synchronous hydraulic fracturing is better than that of sequential hydraulic fracturing. (6) According to the multihole linear codirectional hydraulic fracturing experiments, five typical directional hydraulic fracture propagation modes are summarized.

scholarly journals Mechanical Mechanism of Hydraulic Fracturing Effect Caused by Water Inrush in Tunnel Excavation by Blasting

2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Quan Zhang ◽  
Jiong Wang ◽  
Longfei Feng
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Water Pressure ◽  
Water Pressure ◽  
Water Inrush ◽  
In Situ Stress ◽  
Confined Water ◽  
Shear Damage ◽  
Splitting Factor ◽  
Blasting Excavation

When the deep tunnel is excavated, the pressure of the confined water is relatively high, causing the water inrush to have a hydraulic fracturing effect. The method of theoretical analysis was adopted to study this effect. A mechanical model for fracturing water inrush under blasting excavation conditions was established. The water inrush under this condition is the result of the combined action of static load (water pressure and in situ stress) and dynamic load (explosive stress wave). According to whether the normal stress on the hydraulic crack surface was tensile stress or compressive stress, two types of water inrush were proposed: water inrush caused by tensile-shear damage and water inrush caused by compression-shear damage. These two types of critical water pressures were calculated separately. The relationship between critical water pressure, in situ stress, and blasting disturbance load was given, and a pore water pressure splitting factor was introduced in the calculation process. The theoretically obtained critical water pressure had been verified in the case of water inrush in a deep-buried tunnel. The established theory can guide field practice well.

scholarly journals Numerical simulation of the laws of fracture propagation of multi-hole linear co-directional hydraulic fracturing

2021 ◽  
pp. 014459872198899
Author(s):  
Weiyong Lu ◽  
Changchun He
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Minimum Principle ◽  
Fracture Propagation ◽  
Axial Direction ◽  
Rock Breaking ◽  
Hydraulic Fractures ◽  
Directional Hydraulic Fracturing ◽  
Fracture Intersection ◽  
Expansion Stage

Directional rupture is one of the most important and most common problems related to rock breaking. The goal of directional rock breaking can be effectively achieved via multi-hole linear co-directional hydraulic fracturing. In this paper, the XSite software was utilized to verify the experimental results of multi-hole linear co-directional hydraulic fracturing., and its basic law is studied. The results indicate that the process of multi-hole linear co-directional hydraulic fracturing can be divided into four stages: water injection boost, hydraulic fracture initiation, and the unstable and stable propagation of hydraulic fracture. The stable expansion stage lasts longer and produces more microcracks than the unstable expansion stage. Due to the existence of the borehole-sealing device, the three-dimensional hydraulic fracture first initiates and expands along the axial direction in the bare borehole section, then extends along the axial direction in the non-bare hole section and finally expands along the axial direction in the rock mass without the borehole. The network formed by hydraulic fracture in rock is not a pure plane, but rather a curved spatial surface. The curved spatial surface passes through both the centre of the borehole and the axial direction relative to the borehole. Due to the boundary effect, the curved spatial surface goes toward the plane in which the maximum principal stress occurs. The local ground stress field is changed due to the initiation and propagation of hydraulic fractures. The propagation direction of the fractures between the fracturing boreholes will be deflected. A fracture propagation pressure that is greater than the minimum principle stress and a tension field that is induced in the leading edge of the fracture end, will aid to fracture intersection; as a result, the possibility of connecting the boreholes will increase.

Predicting Hydraulic Fracturing in a Carbonate Gas Reservoir in Abu Dhabi Using 1D Mechanical Earth Model: Uncertainty and Constraints

2015 ◽  
Author(s):  
Manhal Sirat ◽  
Mujahed Ahmed ◽  
Xing Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Abu Dhabi ◽  
Hydraulic Fractures ◽  
Gas Reservoir ◽  
In Situ Stresses ◽  
Tight Carbonate ◽  
Different Depths

Abstract In-situ stress state plays an important role in controlling fracture growth and containment in hydraulic fracturing managements. It is evident that the mechanical properties, existing stress regime and the natural fracture network of its reservoir rocks and the surrounding formations mainly control the geometry, size and containments of produced hydraulic fractures. Furthermore, the three principal in situ stresses' axes swap directions and magnitudes at different depths giving rise to identifying different mechanical bedrocks with corresponding stress regimes at different depths. Hence predicting the hydro-fractures can be theoretically achieved once all the above data are available. This is particularly difficult in unconventional and tight carbonate reservoirs, where heterogeneity and highly stress variation, in terms of magnitude and orientation, are expected. To optimize the field development plan (FDP) of a tight carbonate gas reservoir in Abu Dhabi, 1D Mechanical Earth Models (MEMs), involving generating the three principal in-situ stresses' profiles and mechanical property characterization with depth, have been constructed for four vertical wells. The results reveal the swap of stress magnitudes at different mechanical layers, which controls the dimension and orientation of the produced hydro-fractures. Predicted containment of the Hydro-fractures within the specific zones is likely with inevitable high uncertainty when the stress contrast between Sv, SHmax with Shmin respectively as well as Young's modulus and Poisson's Ratio variations cannot be estimated accurately. The uncertainty associated with this analysis is mainly related to the lacking of the calibration of the stress profiles of the 1D MEMs with minifrac and/or XLOT data, and both mechanical and elastic properties with rock mechanic testing results. This study investigates the uncertainty in predicting hydraulic fracture containment due to lacking such calibration, which highlights that a complete suite of data, including calibration of 1D MEMs, is crucial in hydraulic fracture treatment.

scholarly journals Apparent Toughness Anisotropy Induced by “Roughness” of In-Situ Stress: A Mechanism That Hinders Vertical Growth of Hydraulic Fractures and Its Simplified Modeling

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2148-2162 ◽  
Author(s):  
Pengcheng Fu ◽  
Jixiang Huang ◽  
Randolph R. Settgast ◽  
Joseph P. Morris ◽  
Frederick J. Ryerson
Keyword(s):  
Hydraulic Fracture ◽  
High Stress ◽  
In Situ Stress ◽  
Height Growth ◽  
Hydraulic Fractures ◽  
Simple Relationship ◽  
Vertical Growth ◽  
Stress Profiles ◽  
Fracture Height

Summary The height growth of a hydraulic fracture is known to be affected by many factors that are related to the layered structure of sedimentary rocks. Although these factors are often used to qualitatively explain why hydraulic fractures usually have well–bounded height growth, most of them cannot be directly and quantitatively characterized for a given reservoir to enable a priori prediction of fracture–height growth. In this work, we study the role of the “roughness” of in–situ–stress profiles, in particular alternating low and high stress among rock layers, in determining the tendency of a hydraulic fracture to propagate horizontally vs. vertically. We found that a hydraulic fracture propagates horizontally in low–stress layers ahead of neighboring high–stress layers. Under such a configuration, a fracture–mechanics principle dictates that the net pressure required for horizontal growth of high–stress layers within the current fracture height is significantly lower than that required for additional vertical growth across rock layers. Without explicit consideration of the stress–roughness profile, the system behaves as if the rock is tougher against vertical propagation than it is against horizontal fracture propagation. We developed a simple relationship between the apparent differential rock toughness and characteristics of the stress roughness that induce equivalent overall fracture shapes. This relationship enables existing hydraulic–fracture models to represent the effects of rough in–situ stress on fracture growth without directly representing the fine–resolution rough–stress profiles.

Some Effects of Stress, Friction, and Fluid Flow on Hydraulic Fracturing

1982 ◽  
Vol 22 (03) ◽  
pp. 321-332 ◽  
Author(s):  
M.E. Hanson ◽  
G.D. Anderson ◽  
R.J. Shaffer ◽  
L.D. Thorson
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Research Program ◽  
In Situ Stress ◽  
Material Interfaces ◽  
Fracture Geometry ◽  
Funded Research ◽  
Fracturing Process

Abstract We are conducting a U.S. DOE-funded research program aimed at understanding the hydraulic fracturing process, especially those phenomena and parameters that strongly affect or control fracture geometry. Our theoretical and experimental studies consistently confirm the well-known fact that in-situ stress has a primary effect on fracture geometry, and that fractures propagate perpendicular to the least principal stress. In addition, we find that frictional interfaces in reservoirs can affect fracturing. We also have quantified some effects on fracture geometry caused by frictional slippage along interfaces. We found that variation of friction along an interface can result in abrupt steps in the fracture path. These effects have been seen in the mineback of emplaced fractures and are demonstrated both theoretically and in the laboratory. Further experiments and calculations indicate possible control of fracture height by vertical change in horizontal stresses. Preliminary results from an analysis of fluid flow in small apertures are discussed also. Introduction Hydraulic fracturing and massive hydraulic fracturing (MHF) are the primary candidates for stimulating production from tight gas reservoirs. MHF can provide large drainage surfaces to produce gas from the low- permeability formation if the fracture surfaces remain in the productive parts of the reservoir. To determine whether it is possibleto contain these fractures in the productive formations andto design the treatment to accomplish this requires a much broader knowledge of the hydraulic fracturing process. Identification of the parameters controlling fracture geometry and the application of this information in designing and performing the hydraulic stimulation treatment is a principal technical problem. Additionally, current measurement technology may not be adequate to provide the required data. and new techniques may have to be devised. Lawrence Livermore Natl. Laboratory has been conducting a DOE-funded research program whose ultimate goal is to develop models that predict created hydraulic fracture geometry within the reservoir. Our approach has been to analyze the phenomenology of the fracturing process to son out and identify those parameters influencing hydraulic fracture geometry. Subsequent model development will incorporate this information. Current theoretical and stimulation design models are based primarily on conservation of mass and provide little insight into the fracturing process. Fracture geometry is implied in the application of these models. Additionally, pressure and flow initiation in the fractures and their interjection with the fracturing process is not predicted adequately with these models. We have reported previously on some rock-mechanics aspects of the fracturing process. For example, we have studied, theoretically and experimentally, pressurized fracture propagation in the neighborhood of material interfaces. Results of interface studies showed that natural fractures in the interfacial region negate any barrier effect when the fracture is propagating from a lower modulus material toward a higher modulus material. On the other hand, some fracture containment could occur when the fracture is propagating from a higher modulus into a lower modulus material. Effect of moduli changes on the in-situ stress field have to be taken into consideration to evaluate fracture containment by material interfaces. Some preliminary analyses have been performed to evaluate how stress changes when material properties change, but we have not evaluated this problem fully. SPEJ P. 321^

scholarly journals Numerical Investigation on the Mechanism of Rock Directional Fracturing Method Controlled by Hydraulic Fracturing in Dense Linear Multiholes

2020 ◽  
Vol 2020 ◽  
pp. 1-10
Author(s):  
Qingying Cheng ◽  
Bingxiang Huang ◽  
Xinglong Zhao
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Water Pressure ◽  
Ground Control ◽  
Hydraulic Fractures ◽  
Seepage Water ◽  
Concentration Zone ◽  
Propagation Process ◽  
Directional Hydraulic Fracturing ◽  
Initiation And Propagation

Rock directional fracturing is one of the difficult problems in deep mines. Directional fracturing controlled by hydraulic fracturing in dense linear multiboreholes is a novel directional fracturing technology of rock mass, which has been applied to the ground control in mines. In this paper, a physical model experiment was performed to study the fracture propagation process between multiboreholes. The results show that the intersecting of fractures between boreholes caused the sharp fluctuation of injecting water pressure. A directional fracturing plane was formed along with the direction of boreholes layout, and the surface of the fracturing plane is relatively flat. The dynamic initiation and propagation process of cracks between boreholes during directional hydraulic fracturing were simulated. The evolution of poroelastic stress and pore pressure between multiboreholes was analyzed. The numerical results indicated that a poroelastic stress concentration zone and pore pressure increase zone appeared between boreholes in the direction of boreholes layout. The pore pressure distribution is generally an elliptical seepage water pressure zone with the long axis along the direction of the boreholes layout. After the hydraulic fractures are initiated along the direction of the boreholes layout, the poroelastic stress on both sides of fractures decreases.

Finite Element Model Simulations Associated With Hydraulic Fracturing

1982 ◽  
Vol 22 (02) ◽  
pp. 209-218 ◽  
Author(s):  
Sunder H. Advani ◽  
J.K. Lee
Keyword(s):  
Finite Element ◽  
Hydraulic Fracturing ◽  
Finite Element Model ◽  
Hydraulic Fracture ◽  
Element Model ◽  
In Situ Stress ◽  
Fracture System ◽  
Model Simulations ◽  
Fracture Fluid

Abstract Recently emphasis has been placed on the development and testing of innovative well stimulation techniques for the recovery of unconventional gas resources. The design of optimal hydraulic fracturing treatments for specified reservoir conditions requires sophisticated models for predicting the induced fracture geometry and interpreting governing mechanisms. This paper presents methodology and results pertinent to hydraulic fracture modeling for the U.S. DOE's Eastern Gas Shales Program (EGSP). The presented finite-element model simulations extend available modeling efforts and provide a unified framework for evaluation of fracture dimensions and associated responses. Examples illustrating the role of multilayering, in-situ stress, joint interaction, and branched cracks are given. Selected comparisons and applications also are discussed. Introduction Selection and design of stimulation treatments for Devonian shale wells has received considerable attention in recent years1-3. The production of natural gas from such tight eastern petroliferous basins is dependent on the vertical thickness of the organically rich shale matrix, its inherent fracture system density, anisotropy, and extent, and the communication-link characteristics of the induced fracture system(s). The investigation of stimulation techniques based on resource characterization, reservoir property evaluation, theoretical and laboratory model simulations, and field testing is a logical step toward the development of commercial technology for optimizing gas production and related costs. This paper reports formulations, methodology, and results associated with analytical simulations of hydraulic fracturing for EGSP. The presented model extends work reported by Perkins and Kern,4 Nordgren,5 Geertsma and DeKlerk,6 and Geertsma and Haafkens.7 The simulations provide a finite-element model framework for studying vertically induced fracture responses with the effects of multilayering and in-situ stress considered. In this context, Brechtel et al.,8 Daneshy,9 Cleary,10 and Anderson et al.11 have done recent studies addressing specific aspects of this problem. The use of finite-element model techniques for studying mixed-mode fracture problems encountered in dendritic fracturing and vertical fracture/joint interaction also is illustrated along with application of suitable failure criteria. Vertical Hydraulic Fracture Model Formulations Coupled structural fracture mechanics and fracture fluid response models for predicting hydraulically induced fracture responses have been reported previously.12,13 These simulations incorporate specified reservoir properties, in-situ stress conditions, and stimulation treatment parameters. One shortcoming of this modeling effort is that finite-element techniques are used for the structural and stress intensity simulations, while a finite-difference approach is used to evaluate the leakoff and fracture-fluid response in the vertical crack. A consistent framework for conducting all simulations using finite-element modeling is formulated here.

scholarly journals Study on Propagation Behaviors of Hydraulic Fracture Network in Tight Sandstone Formation with Closed Cemented Natural Fractures

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-22
Author(s):  
Jun Zhang ◽  
Yu-Wei Li ◽  
Wei Li ◽  
Zi-Jie Chen ◽  
Yuan Zhao ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
In Situ Stress ◽  
Injection Rate ◽  
Fluid Viscosity ◽  
Tight Sandstone ◽  
Propagation Behavior ◽  
Sandstone Formation

Natural fractures in tight sandstone formation play a significant role in fracture network generation during hydraulic fracturing. This work presents an experimental model of tight sandstone with closed cemented preexisting fractures. The influence of closed cemented fractures’ (CCF) directions on the propagation behavior of hydraulic fracture (HF) is studied based on the hydraulic fracturing experiment. A field-scaled numerical model used to simulate the propagation of HF is established based on the flow-stress-damage (FSD) coupled method. This model contains the discrete fracture network (DFN) generated by the Monte-Carlo method and is used to investigate the effects of CCFs’ distribution, CCFs’ strength, and in-situ stress anisotropy, injection rate, and fluid viscosity on the propagation behavior of fracture network. The results show that the distribution direction of CCFs is critical for the formation of complex HFs. When the angle between the horizontal maximum principal stress direction and the CCFs is in the range of 30° to 60°, the HF network is the most complex. There are many kinds of compound fracture propagation patterns, such as crossing, branching, and deflection. The increase of CCFs’ strength is not conducive to the generation of branched and deflected fractures. When the in-situ stress difference ranges from 3 MPa to 6 MPa, the HF network’s complexity and propagation range can be guaranteed simultaneously. The increase in the injection rate will promote the formation of the complex HF network. The proper increase of fracturing fluid viscosity can promote HF’s propagation. However, when the viscosity is too high, the complex HFs only appear around the wellbore. The research results can provide new insights for the hydraulic fracturing optimization design of naturally fractured tight sandstone formation.

scholarly journals An Analytical Framework for Stress Shadow Analysis During Hydraulic Fracturing – Applied to the Bakken Formation, Saskatchewan, Canada

2021 ◽  
Author(s):  
Mostafa Gorjian ◽  
Sepidehalsadat Hendi ◽  
Christopher D. Hawkes
Keyword(s):  
Hydraulic Fracturing ◽  
Large Scale ◽  
Shear Failure ◽  
Microseismic Monitoring ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Bakken Formation ◽  
Stress Shadow

Abstract. This paper presents selected results of a broader research project pertaining to the hydraulic fracturing of oil reservoirs hosted in the siltstones and fine grained sandstones of the Bakken Formation in southeast Saskatchewan, Canada. The Bakken Formation contains significant volumes of hydrocarbon, but large-scale hydraulic fracturing is required to achieve economic production rates. The performance of hydraulic fractures is strongly dependent on fracture attributes such as length and width, which in turn are dependent on in-situ stresses. This paper reviews methods for estimating changes to the in-situ stress field (stress shadow) resulting from mechanical effects (fracture opening), poro-elastic effects, and thermo-elastic effects associated with fluid injection for hydraulic fracturing. The application of this method is illustrated for a multi-stage hydraulic fracturing operation, to predict principal horizontal stress magnitudes and orientations at each stage. A methodology is also presented for using stress shadow models to assess the potential for inducing shear failure on natural fractures. The results obtained in this work suggest that thermo and poro-elastic stresses are negligible for hydraulic fracturing in the Bakken Formation of southeast Saskatchewan, hence a mechanical stress shadow formulation is used for analyzing multistage hydraulic fracture treatments. This formulation (and a simplified version of the formulation) predicts an increase in instantaneous shut-in pressure (ISIP) that is consistent with field observations (i.e., ISIP increasing from roughly 21.6 MPa to values slightly greater than 26 MPa) for a 30-stage fracture treatment. The size of predicted zones of shear failure on natural fractures are comparable with the event clouds observed in microseismic monitoring when assumed values of 115°/65° are used for natural fracture strike/dip; however, more data on natural fracture attributes and more microseismic monitoring data for the area are required before rigorous assessment of the model is possible.

Containment of Massive Hydraulic Fractures

1978 ◽  
Vol 18 (01) ◽  
pp. 27-32 ◽  
Author(s):  
E.R. Simonson ◽  
A.S. Abou-Sayed ◽  
R.J. Clifton
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Propagation ◽  
Rocky Mountain ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Pressure Gradients ◽  
In Situ Stresses ◽  
Gas Bearing

Abstract Hydraulic fracture containment is discussed in relationship to linear elastic fracture mechanics. Three cases are analyzed,the effect of different material properties for the pay zone and the barrier formation,the characteristics of fracture propagation into regions of varying in-situ stress, propagation into regions of varying in-situ stress, andthe effect of hydrostatic pressure gradients on fracture propagation into overlying or underlying barrier formations. Analysis shows the importance of the elastic properties, the in-situ stresses, and the pressure gradients on fracture containment. Introduction Application of massive hydraulic fracture (MHF) techniques to the Rocky Mountain gas fields has been uneven, with some successes and some failures. The primary thrust of rock mechanics research in this area is to understand those factors that contribute to the success of MHF techniques and those conditions that lead to failures. There are many possible reasons why MHF techniques fail, including migration of the fracture into overlying or underlying barrier formations, degradation of permeability caused by application of hydraulic permeability caused by application of hydraulic fracturing fluid, loss of fracturing fluid into preexisting cracks or fissures, or extreme errors in preexisting cracks or fissures, or extreme errors in estimating the quantity of in-place gas. Also, a poor estimate of the in-situ permeability can result in failures that may "appear" to be caused by the hydraulic fracture process. Previous research showed that in-situ permeabilities can be one order of magnitude or more lower than permeabilities measured at near atmospheric conditions. Moreover, studies have investigated the degradation in both fracture permeability and formation permeability caused by the application of hydraulic fracture fluids. Further discussion of this subject is beyond the scope of this paper. This study will deal mainly with the containment of hydraulic fractures to the pay zone. In general, the lithology of the Rocky Mountain region is composed of oil- and gas-bearing sandstone layers interspaced with shales (Fig. 1). However, some sandstone layers may be water aquifers and penetration of the hydraulic fracture into these penetration of the hydraulic fracture into these aquifer layers is undesirable. Also, the shale layers can separate producible oil- and gas-bearing zones from nonproducible ones. Shale layers between the pay zone and other zones can be vital in increasing successful stimulation. If the shale layers act as barrier layers, the hydraulic fracture can be contained within the pay zone. The in-situ stresses and the stiffness, as characterized by the shear modulus of the zones, play significant roles in the containment of a play significant roles in the containment of a hydraulic fracture. The in-situ stresses result from forces in the earth's crust and constitute the compressive far-field stresses that act to close the hydraulic fracture. Fig. 2 shows a schematic representation of in-situ stresses acting on a vertical hydraulic fracture. Horizontal components of in-situ stresses may vary from layer to layer (Fig. 2). For example, direct measurements of in-situ stresses in shales has shown the minimum horizontal principal stress is nearly equal to the overburden principal stress is nearly equal to the overburden stress. SPEJ P. 27

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