Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

2016 ◽  
Vol 56 (1) ◽  
pp. 225 ◽  
Author(s):  
Kunakorn Pokalai ◽  
David Kulikowski ◽  
Raymond L. Johnson ◽  
Manouchehr Haghighi ◽  
Dennis Cooke
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
High Stress ◽  
Gas Production ◽  
Natural Fracture ◽  
Rock Properties ◽  
Fracture Plane ◽  
Natural Fractures ◽  
Geomechanical Model ◽  
Well Design

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

scholarly journals A numerical investigation on the performance of hydraulic fracturing in naturally fractured gas reservoirs based on stimulated rock volume

2020 ◽  
Vol 10 (8) ◽  
pp. 3333-3345
Author(s):  
Ali Al-Rubaie ◽  
Hisham Khaled Ben Mahmud
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Shear Stresses ◽  
Individual Element ◽  
Natural Fractures ◽  
Gas Reservoirs ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Naturally Fractured

Abstract All reservoirs are fractured to some degree. Depending on the density, dimension, orientation and the cementation of natural fractures and the location where the hydraulic fracturing is done, preexisting natural fractures can impact hydraulic fracture propagation and the associated flow capacity. Understanding the interactions between hydraulic fracture and natural fractures is crucial in estimating fracture complexity, stimulated reservoir volume, drained reservoir volume and completion efficiency. However, because of the presence of natural fractures with diffuse penetration and different orientations, the operation is complicated in naturally fractured gas reservoirs. For this purpose, two numerical methods are proposed for simulating the hydraulic fracture in a naturally fractured gas reservoir. However, what hydraulic fracture looks like in the subsurface, especially in unconventional reservoirs, remain elusive, and many times, field observations contradict our common beliefs. In this study, the hydraulic fracture model is considered in terms of the state of tensions, on the interaction between the hydraulic fracture and the natural fracture (45°), and the effect of length and height of hydraulic fracture developed and how to distribute induced stress around the well. In order to determine the direction in which the hydraulic fracture is formed strikethrough, the finite difference method and the individual element for numerical solution are used and simulated. The results indicate that the optimum hydraulic fracture time was when the hydraulic fracture is able to connect natural fractures with large streams and connected to the well, and there is a fundamental difference between the tensile and shear opening. The analysis indicates that the growing hydraulic fracture, the tensile and shear stresses applied to the natural fracture.

Improving the efficiency of hydraulic fracturing treatment in CBM reservoirs by stimulating the surrounding natural fracture system

2015 ◽  
Vol 55 (1) ◽  
pp. 351
Author(s):  
Alireza Keshavarz ◽  
Alexander Badalyan ◽  
Raymond Johnson ◽  
Pavel Bedrikovetski
Keyword(s):  
Hydraulic Fracturing ◽  
Mathematical Modelling ◽  
Gas Production ◽  
Natural Fracture ◽  
Productivity Index ◽  
Coal Bed ◽  
Natural Fractures ◽  
Core Flooding ◽  
Induced Fractures ◽  
Water Gas

A method is proposed for enhancing the conductivity of micro-fractures and cleats around the hydraulically induced fractures in coal bed methane reservoirs. In this technique, placing ultra-fine proppant particles in natural fractures and cleats around hydraulically induced fractures at leak-off conditions keeps the coal cleats open during water-gas production, and this consequently increases the efficiency of hydraulic fracturing treatment. Experimental and mathematical studies for the stimulation of a natural cleat system around the main hydraulic fracture are conducted. In the experimental part, core flooding tests are performed to inject a flow of suspended particles inside the natural fractures of a coal sample. By placing different particle sizes and evaluating the concentration of placed particles, an experimental coefficient is found for optimum proppant placement in which the maximum permeability is achieved after proppant placement. In the mathematical modelling study, a laboratory-based mathematical model for graded proppant placement in naturally fractured rocks around a hydraulically induced fracture is proposed. Derivations of the model include an exponential form of the pressure-permeability dependence and accounts for permeability variation in the non-stimulated zone. The explicit formulae are derived for the well productivity index by including the experimentally found coefficient. Particle placement tests resulted in an almost three-times increase in coal permeability. The laboratory-based mathematical modelling, as performed for the field conditions, shows that the proposed method yields around a six-times increase in the productivity index.

A Peridynamics Model for the Propagation of Hydraulic Fractures in Heterogeneous, Naturally Fractured Reservoirs

2015 ◽  
Author(s):  
Hisanao Ouchi ◽  
Amit Katiyar ◽  
John T. Foster ◽  
Mukul M. Sharma
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Two Dimensions ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Nonlocal Continuum Theory

Abstract A novel fully coupled hydraulic fracturing model based on a nonlocal continuum theory of peridynamics is presented and applied to the fracture propagation problem. It is shown that this modeling approach provides an alternative to finite element and finite volume methods for solving poroelastic and fracture propagation problems and offers some clear advantages. In this paper we specifically investigate the interaction between a hydraulic fracture and natural fractures. Current hydraulic fracturing models remain limited in their ability to simulate the formation of non-planar, complex fracture networks. The peridynamics model presented here overcomes most of the limitations of existing models and provides a novel approach to simulate and understand the interaction between hydraulic fractures and natural fractures. The model predictions in two-dimensions have been validated by reproducing published experimental results where the interaction between a hydraulic fracture and a natural fracture is controlled by the principal stress contrast and the approach angle. A detailed parametric study involving poroelasticity and mechanical properties of the rock is performed to understand why a hydraulic fracture gets arrested or crosses a natural fracture. This analysis reveals that the poroelasticity, resulting from high fracture fluid leak-off, has a dominant influence on the interaction between a hydraulic fracture and a natural fracture. In addition, the fracture toughness of the rock, the toughness of the natural fracture, and the shear strength of the natural fracture also affect the interaction between a hydraulic fracture and a natural fracture. Finally, we investigate the interaction of multiple completing fractures with natural fractures in two-dimensions and demonstrate the applicability of the approach to simulate complex fracture networks on a field scale.

scholarly journals Numerical Investigation of the Fracturing Effect Induced by Disturbing Stress of Hydrofracturing

2021 ◽  
Vol 9 ◽  
Author(s):  
Xinglong Zhao ◽  
Bingxiang Huang ◽  
Giovanni Grasselli
Keyword(s):  
Shear Stress ◽  
Fracture Surface ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Shear Failure ◽  
Fluid Pressure ◽  
Natural Fracture ◽  
Coal Bed ◽  
Natural Fractures ◽  
Fracture Failure

Fracturing induced by disturbing stress of hydraulic fracturing is the frontier common core scientific problem of reservoir stimulation of coal bed methane and shale gas. The finite-discrete element method, numerical calculation method, is used to analyze the basic law of shear failure and tension failure of natural fractures induced by the disturbing stress of the hydraulic fracture. The simulation results show that when natural fractures and other weak structures exist on the front or both sides of hydraulic fracture, the shear stress acting on the surface of natural fracture will increase until the natural fracture failure, which is caused by the disturbing stress of hydraulic fracturing. The seepage area on the front and both sides of the hydraulic fracture did not extend to the natural fracture while the natural fracture failure occurred. It indicates that the shear failure of natural fractures is induced by the disturbing stress of hydraulic fracturing. When the hydraulic fracture propagates to the natural fracture, the hydraulic tension fracture and disturbed shear fractures are connected and penetrated. As the fluid pressure within the natural fracture surface increases, the hydraulic fracture will continue to propagate through the natural fracture. Meanwhile, due to the action of fluid pressure, a tensile stress concentration will occur at the tip of the natural fracture, which will induce the airfoil tension failure of the natural fracture. With the increase of the principal stress difference, the range of the disturbing stress area and the peak value of the disturbing stress at the front of the hydraulic fracture tip increase, as well as the shear stress acting on the natural fracture surface. During the process of hydraulic fracture approaching natural fracture, the disturbing stress is easier to induce shear failure of natural fracture. With the increase of the cohesive force of natural fracture, the ability of natural fractures to resist shear failure increases. As the hydraulic fracture approaches natural fractures, the disturbing stress is more difficult to induce shear failure of natural fracture. This study will help to reveal the formation mechanism of the fracture network during hydraulic fracturing in the natural fractures developed reservoir.

A Case Study Using Integrated Multi Disciplinary Approach to Model Microseismic Events During Stimulation

2021 ◽  
Author(s):  
Ghazal Izadi ◽  
Colleen Barton ◽  
Pierre-Francois Roux ◽  
Tebis Llobet ◽  
Thiago Pessoa ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Natural Fracture ◽  
Fracture Model ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Unconventional Reservoir ◽  
Geological Conditions ◽  
Source Mechanisms

Abstract For tight reservoirs where hydraulic fracturing is required to enable sufficient fluid mobility for economic production, it is critical to understand the placement of induced fractures, their connectivity, extent, and interaction with natural fractures within the system. Hydraulic fracture initiation and propagation mechanisms are greatly influenced by the effect of the stress state, rock fabric and pre-existing features (e.g. natural fractures, faults, weak bedding/laminations). A pre-existing natural fracture system can dictate the mode, orientation and size of the hydraulic fracture network. A better understanding of the fracture growth phenomena will enhance productivity and also reduce the environmental footprint as less fractures can be created in a much more efficient way. Assessing the role of natural fractures and their interaction with hydraulic fractures in order to account for them in the hydraulic fracture model is achieved by leveraging microseismicity. In this study, we have used a combination of borehole and surface microseismic monitoring to get high vertical resolution locations and source mechanisms. 3D numerical modelling of hydraulic fracturing in complex geological conditions to predict fracture propagation is essential. 3D hydraulic fracturing simulation includes modelling capabilities of stimulation parameters, true 3D fracture propagation with near wellbore 3D complexity including a coupled DFN and the associated microseismic event generation capability. A 3D hydraulic fracture model was developed and validated by matching model predictions to microseismic observations. Microseismic source mechanisms are leveraged to determine the location and geometry of pre-existing features. In this study, we simulate a DFN based on the recorded seismicity of multi stage hydraulic fractures in a horizontal well. The advanced 3D hydraulic fracture modelling software can integrate effectively and efficiently data from a variety of multi-disciplinary sources and scales to create a subsurface characterization of the unconventional reservoir. By incorporating data from 3D seismic, LWD/wireline, core, completion/stimulation monitoring, and production, the software generates a holistic reservoir model embedded in a modular, multi-physics software platform of coupled numerical solvers that capture the fundamental physics of the processes being modelled. This study illustrates the importance of a powerful software tool that captures the necessary physics of stimulation to predict the effects of various completion designs and thereby ensure the most accurate representation of an unconventional reservoir response to a stimulation treatment.

Impact of Hydraulic Fracture Fairway Development in Multi-Stage Horizontal Laterals - A Production Flow Simulation Study

2021 ◽  
Author(s):  
Abdul Muqtadir Khan ◽  
Jon Olson
Keyword(s):  
Hydraulic Fracture ◽  
Large Scale ◽  
Gas Production ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Production Flow ◽  
Depth Of Penetration ◽  
Multi Stage ◽  
Relative Production

Abstract The vast shale gas and tight oil reservoirs cannot be economically developed without multi-stage hydraulic fracture treatments. Owing to the disparity in the density of natural fractures and the different in-situ stress conditions in these formations, micro-seismic fracture mapping has shown that hydraulic fracture treatments develop a range of large-scale fracture networks. The effect of these various fracture geometries on production is a subject matter in question. The fracture networks approximated with micro-seismic mapping are integrated with a commercial numerical production simulator that discretely models different network structures. Two fracture geometries have been broadly proposed, i.e., orthogonal and transverse. The orthogonal pattern represents a network with cross-cutting fractures orthogonal to each other, whereas transverse profile maps uninterrupted fractures achieving maximum depth of penetration into the reservoir. The response for a single stage is further investigated by comparing the propagation of each stage to be dendritic versus planar. A dendritic propagation is a bifurcation of the induced hydraulic fracture due to the intersection with the natural fracture (failure along the plane of weakness). For the same injected fracture treatment volume, the transverse network attains a higher penetration into the reservoir, achieves a higher stimulated reservoir volume (SRV), and produces around 40-65% more than the orthogonal network over a timespan of 10 years. The SRV will largely dictate the drainage area in a tight environment. The cumulative production rises until the pressure drawdown reaches the extent of the fracture fairway. For the orthogonal network, the unstimulated reservoir boundary is reached at a sooner time than the transverse network. It is found that by increasing the fracture spacing in both the networks from 100 ft to 150 ft, the relative production was enhanced in the orthogonal network by 41%, but when it was further increased to 200 ft- there was a minor drop (not increase) in the relative production (4.5%). For an infinite conductivity fracture, the width of the fracture has minimal effect on oil and gas production. For the dendritic pattern, the size of the SRV created due to the interaction between the induced and natural fractures largely depends on the length of natural fractures and the point of interaction (center, off-center, or extremity). Effect of length, distance of natural fracture from wellbore, and the point of interaction is evaluated. A novel approach for reservoir simulation is used, where porosity (instead of permeability) is used as a scaling parameter for the fracture width. The forward modeling effort, including the comparative fracture geometries setup, induced, and natural fracture interaction parametric study, is unique.

Challenges in modelling of hydraulic fracturing in low-permeability coal seams with complex cleat networks and stress regimes

2019 ◽  
Vol 59 (1) ◽  
pp. 166
Author(s):  
Mohammad Ali Aghighi ◽  
Raymond Johnson Jr. ◽  
Chris Leonardi
Keyword(s):  
Numerical Methods ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fractured Reservoirs ◽  
Computational Cost ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Low Permeability ◽  
Natural Fractures ◽  
Fracture Development

Improved hydraulic fracturing models can better inform operational decisions regarding production from low-permeability coals and ultimately convert currently classified contingent resources to reserves. Improving current modelling approaches requires identification and investigation of the challenges involved in modelling hydraulic fracture stimulation in complex eastern Australian cases where permeability systems and stress regimes can vary significantly. This study investigated differences among existing and emerging advanced hydraulic fracture models and codes including numerical methods used to model fluid and rock behaviours during treatments; the ability to contextualise structure, behaviour and interaction of natural fractures with the propagating hydraulic fracture (e.g. cleat or natural fracture fabric, discrete fracture networks and pressure-dependent leak-off); and their capabilities in handling simultaneously growing or complex fracture development. One finding is that the new generation of models or codes that fully or partially use particle-based numerical methods are more capable in handling complexities associated with hydraulic stimulation of naturally fractured reservoirs. However, the computational cost and time for these models may cause concerns, particularly when modelling large reservoirs and treatments. Based on these limitations, many of the advanced, industry preferred, commercial hydraulic fracture simulators still choose to incorporate limited complexities with regard to natural fractures or represent them mathematically or implicitly. This investigation also indicates that most emerging models provide better representation of natural fractures, visualisation and integration into workflows for completion or stimulation design.

scholarly journals Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3852 ◽  
Author(s):  
Kiran Nandlal ◽  
Ruud Weijermars
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fractured Reservoirs ◽  
Test Site ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Midland Basin ◽  
Drained Rock Volume ◽  
The Impact

Hydraulic fracturing for economic production from unconventional reservoirs is subject to many subsurface uncertainties. One such uncertainty is the impact of natural fractures in the vicinity of hydraulic fractures in the reservoir on flow and thus the actual drained rock volume (DRV). We delineate three fundamental processes by which natural fractures can impact flow. Two of these mechanisms are due to the possibility of natural fracture networks to possess (i) enhanced permeability and (ii) enhanced storativity. A systematic approach was used to model the effects of these two mechanisms on flow patterns and drained regions in the reservoir. A third mechanism by which natural fractures may impact reservoir flow is by the reactivation of natural fractures that become extensions of the hydraulic fracture network. The DRV for all three mechanisms can be modeled in flow simulations based on Complex Analysis Methods (CAM), which offer infinite resolution down to a micro-fracture scale, and is thus complementary to numerical simulation methods. In addition to synthetic models, reservoir and natural fracture data from the Hydraulic Fracturing Test Site (Wolfcamp Formation, Midland Basin) were used to determine the real-world impact of natural fractures on drainage patterns in the reservoir. The spatial location and variability in the DRV was more influenced by the natural fracture enhanced permeability than enhanced storativity (related to enhanced porosity). A Carman–Kozeny correlation was used to relate porosity and permeability in the natural fractures. Our study introduces a groundbreaking upscaling procedure for flows with a high number of natural fractures, by combining object-based and flow-based upscaling methods. A key insight is that channeling of flow through natural fractures left undrained areas in the matrix between the fractures. The flow models presented in this study can be implemented to make quick and informed decisions regarding where any undrained volume occurs, which can then be targeted for refracturing. With the method outlined in our study, one can determine the impact and influence of natural fracture sets on the actual drained volume and where the drainage is focused. The DRV analysis of naturally fractured reservoirs will help to better determine the optimum hydraulic fracture design and well spacing to achieve the most efficient recovery rates.

scholarly journals Geomechanical modelling and two-way coupling simulation for carbonate gas reservoir

2020 ◽  
Vol 10 (8) ◽  
pp. 3619-3648
Author(s):  
Barzan I. Ahmed ◽  
Mohammed S. Al-Jawad
Keyword(s):  
Fluid Flow ◽  
Slip Flow ◽  
Gas Production ◽  
Natural Fracture ◽  
Rock Properties ◽  
Earth Model ◽  
Geomechanical Model ◽  
Gas Reservoir ◽  
Permeability Model ◽  
3D Geomechanical Model

Abstract Geomechanical modelling and simulation are introduced to accurately determine the combined effects of hydrocarbon production and changes in rock properties due to geomechanical effects. The reservoir geomechanical model is concerned with stress-related issues and rock failure in compression, shear, and tension induced by reservoir pore pressure changes due to reservoir depletion. In this paper, a rock mechanical model is constructed in geomechanical mode, and reservoir geomechanics simulations are run for a carbonate gas reservoir. The study begins with assessment of the data, construction of 1D rock mechanical models along the well trajectory, the generation of a 3D mechanical earth model, and running a 4D geomechanical simulation using a two-way coupling simulation method, followed by results analysis. A dual porosity/permeability model is coupled with a 3D geomechanical model, and iterative two-way coupling simulation is performed to understand the changes in effective stress dynamics with the decrease in reservoir pressure due to production, and therefore to identify the changes in dual-continuum media conductivity to fluid flow and field ultimate recovery. The results of analysis show an observed effect on reservoir flow behaviour of a 4% decrease in gas ultimate recovery and considerable changes in matrix contribution and fracture properties, with the geomechanical effects on the matrix visibly decreasing the gas production potential, and the effect on the natural fracture contribution is limited on gas inflow. Generally, this could be due to slip flow of gas at the media walls of micro-extension fractures, and the flow contribution and fracture conductivity is quite sufficient for the volume that the matrixes feed the fractures. Also, the geomechanical simulation results show the stability of existing faults, emphasizing that the loading on the fault is too low to induce fault slip to create fracturing, and enhanced permeability provides efficient conduit for reservoir fluid flow in reservoirs characterized by natural fractures.

scholarly journals Numerical Modelling of Interaction between Hydraulic Fractures and Natural Fractures by Using the Extended Finite Element Method

2020 ◽  
Vol 2020 ◽  
pp. 1-9
Author(s):  
Peilun Li ◽  
Yan Dong ◽  
Sheng Wang ◽  
Peichao Li
Keyword(s):  
Finite Element Method ◽  
Finite Element ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Extended Finite Element Method ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Extended Finite Element ◽  
Element Method

Natural fractures usually develop in shale reservoirs. Thereby, in the process of hydraulic fracturing, it is inevitable that hydraulic fractures will intersect with natural fractures. In order to reveal the interaction mechanism between hydraulic-induced fractures and natural fractures, a two-dimensional fracture intersection model based on the extended finite element method (XFEM) is proposed, and the different types of intersecting criteria reported in the literature are compared. Then, the effects of natural fracture azimuth, fluid pressure in hydraulic fracture, and in situ principal stress difference on hydraulic fracturing are studied in detail. The results show that the fracture morphology is different under different criteria and working conditions. And the stress concentration phenomenon mainly concentrates on the tip in the obtuse angle side of natural fracture. Meanwhile, different fluid pressures in hydraulic fracture can also induce different intersection patterns. The obtained results in this work are of great benefit to understand the intersection mechanism between hydraulic fractures and natural fractures.

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