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.

scholarly journals Study of Cyclic Fracturing in Vertical CBM Wells

2017 ◽  
Vol 10 (1) ◽  
pp. 108-117 ◽  
Author(s):  
Ting Li ◽  
Ji-fang Wan
Keyword(s):  
Hydraulic Fracturing ◽  
Economic Benefits ◽  
Natural Fracture ◽  
Coal Bed ◽  
Coal Bed Methane ◽  
Plastic Behavior ◽  
Natural Fractures ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Coal Rock

Background:Coal-bed methane productivity of single well is very low, and has been the bottleneck of the coal-bed methane industry in China.Objective:Although hydraulic fracturing is the only stimulation measure to develop CBM, it cannot increase production effectively, conventional fracturing method to create opening fractures should be improved. How to make good use of natural fractures, which are plentiful in CBM reservoirs, is also an important subject for hydraulic fracturing.Method:In this paper, the plastic deformation of coal rock is analyzed by harnessing a pseudo-Maxwell creep phenomenon, which is normally present in rock. The Kelvin-Voigt model is utilized to describe pseudo-plastic behavior of coal rock to determine pressurization and decay cyclic time for cyclic fracturing design. The mechanical requirement for shearing natural fractures is also analyzed, and shearing distance between the faces of natural fracture can be calculated by Westergaard stress function. Ultimately, the cyclic fracturing method is proposed according to theories about stress alteration and shearing of natural fractures. This method includes such periods as fracturing, pumping shut-down and so on.Conclusion:A complex fracture system can be created, which consists of opened and sheared fractures, then, large SRV(stimulated reservoir volume)and flowing drainage area can be acquired. In comparison with conventional fracturing method, this new way can make full use of the characteristics of CBM reservoirs and is more suitable to CBM. This method will lead to a significant increase of CBM production, and will achieve huge economic benefits.

Some challenges in hydraulic fracturing of tight gas reservoirs: an experimental study

2011 ◽  
Vol 51 (1) ◽  
pp. 499 ◽  
Author(s):  
Vamegh Rasouli ◽  
Mohammad Sarmadivaleh ◽  
Amin Nabipour
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Interaction Mechanism ◽  
Natural Fracture ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
True Triaxial ◽  
Rock Types ◽  
Interface Parameters

Hydraulic fracturing is a technique used to enhance production from low quality oil and gas reservoirs. This approach is the key technique specifically in developing unconventional reservoirs, such as tight formations and shale gas. During its propagation, the hydraulic fracture may arrive at different interfaces. The mechanical properties and bounding quality of the interface as well as insitu stresses are among the most significant parameters that determine the interaction mechanism, i.e. whether the hydraulic fracture stops, crosses or experiences an offset upon its arrival at the interface. The interface could be a natural fracture, an interbed, layering or any other weakness feature. In addition to the interface parameters, the rock types of the two sides of the interface may affect the interaction mechanism. To study the interaction mechanism, hydraulic fracturing experiments were conducted using a true triaxial stress cell on two cube samples of 15 cm. Sample I had a sandstone block in the middle surrounded by mortar, whereas in sample II the location of mortar and tight sandstone blocks were changed. The results indicated that besides the effect of the far field stress magnitudes, the heterogeneity of the formation texture and interface properties can have a dominant effect in propagation characteristics of an induced fracture.

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 APPLICATION OF FRACTAL GEOMETRY IN EVALUATION OF EFFECTIVE STIMULATED RESERVOIR VOLUME IN SHALE GAS RESERVOIRS

Fractals ◽  
2017 ◽  
Vol 25 (04) ◽  
pp. 1740007 ◽  
Author(s):  
GUANGLONG SHENG ◽  
YULIANG SU ◽  
WENDONG WANG ◽  
FARZAM JAVADPOUR ◽  
MEIRONG TANG
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Fractal Geometry ◽  
Fracture Network ◽  
Gas Reservoirs ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Adsorbed Gas ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs

According to hydraulic-fracturing practices conducted in shale reservoirs, effective stimulated reservoir volume (ESRV) significantly affects the production of hydraulic fractured well. Therefore, estimating ESRV is an important prerequisite for confirming the success of hydraulic fracturing and predicting the production of hydraulic fracturing wells in shale reservoirs. However, ESRV calculation remains a longstanding challenge in hydraulic-fracturing operation. In considering fractal characteristics of the fracture network in stimulated reservoir volume (SRV), this paper introduces a fractal random-fracture-network algorithm for converting the microseismic data into fractal geometry. Five key parameters, including bifurcation direction, generating length ([Formula: see text]), deviation angle ([Formula: see text]), iteration times ([Formula: see text]) and generating rules, are proposed to quantitatively characterize fracture geometry. Furthermore, we introduce an orthogonal-fractures coupled dual-porosity-media representation elementary volume (REV) flow model to predict the volumetric flux of gas in shale reservoirs. On the basis of the migration of adsorbed gas in porous kerogen of REV with different fracture spaces, an ESRV criterion for shale reservoirs with SRV is proposed. Eventually, combining the ESRV criterion and fractal characteristic of a fracture network, we propose a new approach for evaluating ESRV in shale reservoirs. The approach has been used in the Eagle Ford shale gas reservoir, and results show that the fracture space has a measurable influence on migration of adsorbed gas. The fracture network can contribute to enhancement of the absorbed gas recovery ratio when the fracture space is less than 0.2 m. ESRV is evaluated in this paper, and results indicate that the ESRV accounts for 27.87% of the total SRV in shale gas reservoirs. This work is important and timely for evaluating fracturing effect and predicting production of hydraulic fracturing wells in shale reservoirs.

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.

Numerical Modeling of Multistranded-Hydraulic-Fracture Propagation: Accounting for the Interaction Between Induced and Natural Fractures

SPE Journal ◽  
2011 ◽  
Vol 16 (03) ◽  
pp. 575-581 ◽  
Author(s):  
Arash Dahi-Taleghani ◽  
Jon E. Olson
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Fracture Pattern ◽  
Design Tool ◽  
Propagation Model ◽  
Natural Fracture ◽  
Shear Stresses ◽  
Natural Fractures ◽  
Complex Fracture ◽  
Standard Design

Summary Recent examples of hydraulic-fracture diagnostic data suggest that complex, multistranded hydraulic-fracture geometry is a common occurrence. This reality is in stark contrast to the industry-standard design models based on the assumption of symmetric, planar, biwing geometry. The interaction between pre-existing natural fractures and the advancing hydraulic fracture is a key condition leading to complex fracture patterns. Performing hydraulic-fracture-design calculations under these less-than-ideal conditions requires modeling fracture intersections and tracking fluid fronts in the network of reactivated fissures. Whether a hydraulic fracture crosses or is arrested by a pre-existing natural fracture is controlled by shear strength and potential slippage at the fracture intersections, as well as potential debonding of sealed cracks in the near-tip region of a propagating hydraulic fracture. We present a complex hydraulic-fracture pattern propagation model based on the extended finite-element method (XFEM) as a design tool that can be used to optimize treatment parameters under complex propagation conditions. Results demonstrate that fracture-pattern complexity is strongly controlled by the magnitude of anisotropy of in-situ stresses, rock toughness, and natural-fracture cement strength, as well as the orientation of the natural fractures relative to the hydraulic fracture. Analysis shows that the growing hydraulic fracture may exert enough tensile and shear stresses on cemented natural fractures that the latter may be debonded, opened, and/or sheared in advance of hydraulic-fracture-tip arrival, while under other conditions, natural fractures will be unaffected by the hydraulic fracture. Detailed aperture distributions at the intersection between fracture segments show the potential for difficulty in proppant transport under complex fracture-propagation conditions.

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.

Case Study: 4D Coupled Reservoir/Geomechanics Simulation of a High-Pressure/High-Temperature Naturally Fractured Reservoir

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1518-1538 ◽  
Author(s):  
Xiangtong Yang ◽  
Yuanwei Pan ◽  
Wentong Fan ◽  
Yongjie Huang ◽  
Yang Zhang ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Fracture System ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Well Integrity ◽  
3D Geomechanical Model ◽  
Naturally Fractured ◽  
Reservoir Geomechanics

Summary The Keshen Reservoir is a naturally fractured, deep, tight sandstone gas reservoir under high tectonic stress. Because the reservoir matrix is very tight, the natural-fracture system is the main pathway for gas production. Meanwhile, stimulation is still required for most production wells to provide production rates that sufficiently compensate for the high cost of drilling and completing wells to access this deep reservoir. Large depletion (and related stress change) was expected during the course of the production of the field. The dynamic response of the reservoir and related risks, such as reduction of fracture conductivity, fault reactivation, and casing failure, would compromise the long-term productivity of the reservoir. To quantify the dynamic response of the reservoir and related risks, a 4D reservoir/geomechanics simulation was conducted for Keshen Reservoir by following an integrated work flow. The work started from systematic laboratory fracture-conductivity tests performed with fractured cores to measure conductivity vs. confining stress for both natural fractures and hydraulic fractures (with proppant placed in the fractures of the core samples). Natural-fracture modeling was conducted to generate a discrete-fracture network (DFN) to delineate spatial distribution of the natural-fracture system. In addition, hydraulic-fracture modeling was conducted to delineate the geometry of the hydraulic-fracture system for the stimulated wells. Then, a 3D geomechanical model was constructed by integrating geological, petrophysical, and geomechanical data, and both the DFN and hydraulic-fracture system were incorporated into the 3D geomechanical model. A 4D reservoir/geomechanics simulation was conducted through coupling with a reservoir simulator to predict variations of stress and strain of rock matrix as well as natural fractures and hydraulic fractures during field production. At each study-well location, a near-wellbore model was extracted from the full-field model, and casing and cement were installed to evaluate well integrity during production. The 4D reservoir/geomechanics simulation revealed that there would be a large reduction of conductivity for both natural fractures and hydraulic fractures, and some fractures with certain dip/dip azimuth will be reactivated during the course of field production. The induced-stress change will also compromise well integrity for those poorly cemented wellbores. The field-development plan must consider all these risks to ensure sustainable long-term production. The paper presents a 4D coupled geomechanics/reservoir-simulation study applied to a high-pressure/high-temperature (HP/HT) naturally fractured reservoir, which has rarely been published previously. The study adapted several new techniques to quantify the mechanical response of both natural fractures and hydraulic fractures, such as using laboratory tests to measure stress sensitivity of natural fractures, integrating DFN and hydraulic-fracture systems into 4D geomechanics simulation, and evaluating well integrity on both the reservoir scale and the near-wellbore scale.

Characterizing the Stimulated Reservoir Volume During Hydraulic Fracturing-Connecting the Pressure Fall-Off Phase to the Geomechanics of Fracturing

2018 ◽  
Vol 85 (10) ◽  
Author(s):  
Erfan Sarvaramini ◽  
Maurice B. Dusseault ◽  
Robert Gracie
Keyword(s):  
Hydraulic Fracturing ◽  
Fracture Network ◽  
Natural Fracture ◽  
Breakdown Pressure ◽  
Pressure Derivative ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Flow Capacity ◽  
Pressure Fall

Microseismic imaging of the hydraulic fracturing operation in the naturally fractured rocks confirms the existence of a stimulated volume (SV) of enhanced permeability. The simulation and characterization of the SV evolution is uniquely challenging given the uncertainty in the nature of the rock mass fabrics as well as the complex fracturing behavior of shear and tensile nature, irreversible plastic deformation and damage. In this paper, the simulation of the SV evolution is achieved using a nonlocal poromechanical plasticity model. Effects of the natural fracture network are incorporated via a nonlocal plasticity characteristic length, ℓ. A nonlocal Drucker–Prager failure model is implemented in the framework of Biot's theory using a new implicit C0 finite element method. First, the behavior of the SV for a two-dimensional (2D) geomechanical injection problem is simulated and the resulting SV is assessed. It is shown that breakdown pressure and stable fracturing pressure are the natural outcomes of the model and both depend upon ℓ. Next, the post-shut-in behavior of the SV is analyzed using the pressure and pressure derivative plots. A bilinear flow regime is observed and it is used to estimate the flow capacity of the SV. The results show that the flow capacity of the SV increases as ℓ decreases (i.e., as the SV behaves more like a single hydraulic fracture); however, for 0.1m≤ℓ≤1m, the calculated flow capacity indicates that the conductivity of the SV is finite. Finally, it is observed that as ℓ tends to zero, the flow capacity of the SV tends to infinity and the SV behaves like a single infinitely conducting fracture.

scholarly journals Numerical Simulation of Artificial Fracture Propagation in Shale Gas Reservoirs Based on FPS-Cohesive Finite Element Method

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-16 ◽  
Author(s):  
Xiaoqiang Liu ◽  
Zhanqing Qu ◽  
Tiankui Guo ◽  
Ying Sun ◽  
Zhifeng Shi ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Finite Element ◽  
Hydraulic Fracturing ◽  
In Situ Stress ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Rock Matrix ◽  
Gas Reservoirs ◽  
Artificial Fracture

The simulation of hydraulic fracturing by the conventional ABAQUS cohesive finite element method requires a preset fracture propagation path, which restricts its application to the hydraulic fracturing simulation of a naturally fractured reservoir under full coupling. Based on the further development of a cohesive finite element, a new dual-attribute element of pore fluid/stress element and cohesive element (PFS-Cohesive) method for a rock matrix is put forward to realize the simulation of an artificial fracture propagating along the arbitrary path. The effect of a single spontaneous fracture, two intersected natural fractures, and multiple intersected spontaneous fractures on the expansion of an artificial fracture is analyzed by this method. Numerical simulation results show that the in situ stress, approaching angle between the artificial fracture and natural fracture, and natural fracture cementation strength have a significant influence on the propagation morphology of the fracture. When two intersected natural fractures exist, the second one will inhibit the propagation of artificial fractures along the small angle of the first natural fractures. Under different in situ stress differences, the length as well as aperture of the hydraulic fracture in a rock matrix increases with the development of cementation superiority of natural fractures. And with the increasing of in situ horizontal stress differences, the length of the artificial fracture in a rock matrix decreases, while the aperture increases. The numerical simulation result of the influence of a single natural fracture on the propagation of an artificial fracture is in agreement with that of the experiment, which proves the accuracy of the PFS-Cohesive FEM for simulating hydraulic fracturing in shale gas reservoirs.

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