Numerical Simulation Study of Proppant Transport in Cross Fractures

2022 ◽  
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Jianchun Guo
Keyword(s):  
Hydraulic Fracturing ◽  
Transport Model ◽  
Injection Rate ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Natural Fractures ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Approach Angle

Abstract Hydraulic fracturing technology is an important means to stimulate unconventional reservoirs, and the placement morphology of proppant in cross fractures is a key factor affecting the effect of hydraulic fracturing. It is very important to study the proppant transport law in cross fractures. In order to study the proppant transportation law in cross fractures, based on the CFD-DEM method, a proppant transport model in cross fractures was established. From the two aspects of the flow field in the fractures and the morphology of the proppant dune, the influence of the natural fracture approach angle, the fracturing fluid viscosity and injection rate on the proppant transport is studied. Based on the principle of hydropower similarity, the conductivity of proppant dune under different conditions is quantitatively studied. The results show that the natural fracture approach angle affects the distribution of proppant and fracturing fluid in natural fractures, and further affects the proppant placement morphology in hydraulic fractures and natural fractures. When the fracturing fluid viscosity is low and the displacement is small, the proppant forms a "high and narrow" dune at the entrance of the fracture. With the increase of the fracturing fluid viscosity and injection rate, the proppant settles to form a "short and wide" placement morphology. Compared with the natural fracture approach angle, the fracturing fluid viscosity and injection rate have a more significant impact on the conductivity of proppant dune. This paper investigated the proppant transportation in cross fractures, and quantitatively analyzes the conductivity of proppant dunes with different placement morphology. The results of this study can provide theoretical guidance for the design of hydraulic fracturing.

scholarly journals A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study

2020 ◽  
Vol 10 (9) ◽  
pp. 3027
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Zhili Li ◽  
Fenglan Huang ◽  
Chuhao Huang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Variable Viscosity ◽  
Oil Reservoirs ◽  
Fluid Viscosity ◽  
Low Density ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Fracturing Fluids ◽  
Transport Experiment

For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil 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.

scholarly journals Numerical Simulation of the Influence of Natural Fractures on Hydraulic Fracture Propagation

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-12 ◽  
Author(s):  
Song Yaobin ◽  
Lu Weiyong ◽  
He Changchun ◽  
Bai Erhu
Keyword(s):  
Tensile Strength ◽  
Principal Stress ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Stress Difference ◽  
Natural Fractures ◽  
Approach Angle ◽  
Hydraulic Fracture Propagation

According to the theory of plane mechanics involving the interaction of hydraulic and natural fractures, the law of hydraulic fracture propagation under the influence of natural fractures is verified using theoretical analysis and RFPA2D-Flow numerical simulation approaches. The shear and tensile failure mechanisms of rock are simultaneously considered. Furthermore, the effects of the approach angle, principal stress difference, tensile strength and length of the natural fracture, and elastic modulus and Poisson’s ratio of the reservoir on the propagation law of a hydraulic fracture are investigated. The following results are obtained: (1) The numerical results agree with the experimental data, indicating that the RFPA2D-Flow software can be used to examine the hydraulic fracture propagation process under the action of natural fractures. (2) In the case of a low principal stress difference and low approach angle, the hydraulic fracture likely causes shear failure along the tip of the natural fracture. However, under a high stress difference and high approach angle, the hydraulic fracture spreads directly through the natural fracture along the original direction. (3) When natural fractures with a low tensile strength encounter hydraulic fractures, the hydraulic fractures likely deviate and expand along the natural fractures. However, in the case of natural fractures with a high tensile strength, the natural fracture surface is closed, and the hydraulic fracture directly passes through the natural fracture, propagating along the direction of the maximum principal stress. (4) Under the same principal stress difference, a longer natural fracture corresponds to the easier initiation and expansion of a hydraulic fracture from the tip of the natural fracture. However, when the size of the natural fracture is small, the hydraulic fracture tends to propagate directly through the natural fracture. (5) A smaller elastic modulus and larger Poisson’s ratio of the reservoir result in a larger fracture initiation pressure. The presented findings can provide theoretical guidance regarding the hydraulic fracturing of reservoirs with natural fractures.

Finite-Element Simulation of a Hydraulic Fracture Interacting With a Natural Fracture

SPE Journal ◽  
2016 ◽  
Vol 22 (01) ◽  
pp. 219-234 ◽  
Author(s):  
Zuorong Chen ◽  
Robert G. Jeffrey ◽  
Xi Zhang ◽  
James Kear
Keyword(s):  
Finite Element ◽  
Hydraulic Fracture ◽  
Injection Pressure ◽  
Quantitative Information ◽  
Injection Rate ◽  
Interfacial Stress ◽  
Natural Fracture ◽  
Fluid Viscosity ◽  
Fracturing Fluid ◽  
Bedding Planes

Summary In this paper, the problem of a hydraulic fracture (HF) interacting with a pre-existing natural fracture (NF) has been investigated with a cohesive zone finite-element model. The model fully couples fluid flow, fracture propagation, and elastic deformation, taking into account the friction between the contacting fracture surfaces and the interaction between the HF and the NF. The effect of the field conditions—such as in-situ stresses, rock and fracture mechanical and geometrical (initial conductivity of the NF) properties, intersection angle, and the treatment parameters (fracturing fluid viscosity and injection rate)—on the HF propagation behavior has been analyzed. The finite-element-modeling results provide detailed quantitative information on the development of various types of HF/NF interaction, interfacial stress distribution, fracture-geometry evolution, and injection-pressure history, and allow us to gain an in-depth understanding of the relative roles of various parameters. The value of a parameter calculated as the product of fracturing-fluid viscosity and injection rate can be used as an indicator to gauge if crossing or diverting behavior is more likely. In addition, using a finite-element approach allows the analysis to be extended to include the effects of fluid leakoff and poroelastic effect, and allows the study of HF height growth through a system of nonhomogeneous layers and their bedding planes.

Hydraulic Fracturing at Clair: Unlocking the Potential of Europe's Largest Reservoir

2022 ◽  
Author(s):  
Alistair Malcolm Roy ◽  
Graeme Henry Allan ◽  
Corrado Giuliani ◽  
Shakeel Ahmad ◽  
Charlotte Giraud ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Phase 1 ◽  
Poor Quality ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Production Test ◽  
Natural Fractures ◽  
The South ◽  
Initial Development ◽  
Matrix Quality

Abstract The Greater Clair area, Europe's largest oilfield, has two existing platforms, Clair Phase 1 and Clair Ridge, on production with future potential for a third platform targeting undeveloped Lower Clair Group to the South of Ph1. Clair Phase 1 was the initial development of Clair, targeting Lower Clair Group (LCG) reservoir consisting of a complex Devonian sandstone in six units. Most Phase 1 wells penetrated relatively good quality reservoir enhanced by natural fractures, while more recently Clair Ridge wells took a similar approach targeting natural fractures, however that strategy is continually being evaluated. In some areas however low matrix quality and lack of natural fractures were the dominant characteristics resulting in lower production rates. A brief comparison of the range of production outcomes will be presented, including potential downsides of reliance on natural fractures. Given the large oil volumes in areas of known poorer rock quality, alongside variable production results, a hydraulic fracturing trial was initiated in 2017. Well 206/08-A23 (A23) targeted previously under-developed, poor-quality Unit VI within the Phase 1 Graben area where natural fractures are absent. A pre-frac production test established baseline production of 900BOPD in December 2018. The A23 objectives included subsequent hydraulically fracturing the well to test this techniques ability to unlock production from tight, matrix dominated formation. Detailed analysis of core, log and limited vertical well fracturing data (from initial fracturing trials of 1980's vintage), yielded robust designs. Key challenges included overcoming very low KV/KH ratios with fracture heights exceeding 300ft. The resulting detailed designs provided consistent and predictable hydraulic fracturing execution in A23 in 2019, including placement of four planned 500klbs treatments combined with coil clean-outs after each stage to unload solids and fluids from the well. Initial fracture designs were conservative in terms of pad and proppant scheduling which, alongside learnings around operational logistics offshore West of Shetlands and completion design, offer significant optimisations for future hydraulic fractures. Post frac A23 became the highest non-natural fractured producer across Clair. Initially a six-fold production increase was observed with monitoring of transient production ongoing. Tracer analysis confirmed production contribution from all zones. Proving fracturing technology brings opportunities to unlock poorer Phase 1 and Ridge reservoir areas. Additionally, significant portions of the undeveloped Lower Clair Group to the South of Ph1 comprises lower permeability reservoir with higher viscosity oil and reduced natural fracture presence. Hydraulic fracturing is therefore a crucial completion technique for developing this lower quality reservoir and brings significant value enhancement to the project. Efficient delivery of numerous large fractures in a harsh offshore environment West of Shetlands presents significant challenges. The influence of how the A23 fracturing results and learnings are guiding future hydraulic fracturing concept are detailed, including optimising platform engineering design to facilitate efficient fracturing operations while maintaining the required productivity in this challenging scenario.

Mechanics of Hydraulic-Fracture Growth from a Wellbore Intersecting Natural Fractures

SPE Journal ◽  
2019 ◽  
Vol 25 (02) ◽  
pp. 646-661 ◽  
Author(s):  
Yang Liu ◽  
Ping Chen ◽  
Bisheng Wu ◽  
Tianshou Ma ◽  
Bailin Wu ◽  
...  
Keyword(s):  
Fractured Rock ◽  
Maximum Principal Stress ◽  
Injection Rate ◽  
Reservoir Rock ◽  
Fluid Loss ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Natural Fractures ◽  
Principal Stress Direction ◽  
Fully Coupled

Summary The creation and propagation of hydraulic fractures (HFs) emanating from a well in a naturally fractured rock is important not only to the success of fracturing treatments, but also for interpretation of the data from diagnostic fracture injection tests (DFITs). In this paper, we consider the reservoir rock to consist of an impermeable rock matrix and a system of discrete natural fractures (NFs) that are permeable. The well is assumed to intersect two sets of NFs at their midpoints, and injection into the wellbore might open the NFs and/or create new fractures that extend along the maximum-principal-stress direction. Both new fractures and pre-existing NFs can act as either a main HF or a fluid-loss path. In this near-well transient-fracture analysis, the NFs are short segments characterized by size, orientation, and aperture. A fully coupled HF model is used to investigate the interaction between the fractures to determine how the fluid injected is distributed to the fractures for a range of stress, fluid-injection-rate, and NF-geometry conditions. We find that a more-isotropic stress condition and a lower value of the fluid-viscosity/injection-rate product favor propagation of NFs. These conditions cause the NFs to accept more fluid, and, as a result, the growth of new fractures is suppressed. The post-shut-in pressure responses for the cases with propagating new fractures and nonpropagating NFs are studied.

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.

scholarly journals A parametric study of hydraulic fracturing interference between fracture clusters and stages based on numerical modeling

2020 ◽  
pp. 014459872095325
Author(s):  
Ang Chen ◽  
Xuyang Guo ◽  
Huiyong Yu ◽  
Lei Huang ◽  
Shanzhi Shi ◽  
...  
Keyword(s):  
Numerical Modeling ◽  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Shale Oil ◽  
Fracturing Fluid ◽  
Multi Stage ◽  
Study Results ◽  
Stress Contrast

Shale oil reservoirs are usually developed by horizontal wells completed with multi-stage hydraulic fractures. The fracture interference between clusters in a single stage and between consecutive stages has an impact on the stimulation quality in terms of fracture geometries and fracture widths. This study introduces a non-planar hydraulic fracture model based on the extended finite element method and its use in quantifying the effects of relevant parameters on multi-stage fracture quality in a realistic shale oil scenario. The numerical model is validated with field diagnostics based on vertical seismic profiling. Relevant parameters including stress contrast, fracturing fluid viscosity, cluster density, and fracturing in consecutive stages are quantitatively analyzed in the numerical study. Results show that effects of stress contrast on fracture quality are greater than those of fracturing fluid viscosity, while the effects are more significant in outer fractures instead of the inner fracture. Denser cluster design leads to greater inhibition for the growth of inner fractures which eventually divert them transversely. In fracturing for consecutive stages, the opening of fractures in the subsequent stages is inhibited and the fracture geometries are also altered by the inter-stage interference caused by the previous stage. Based on field data and numerical modeling, this study identifies key parameters and quantifies their effects on inter-fracture and inter-stage interference in multi-stage hydraulic fracturing in horizontal wells.

scholarly journals Slurry flow, gravitational settling and a proppant transport model for hydraulic fractures

2014 ◽  
Vol 760 ◽  
pp. 567-590 ◽  
Author(s):  
E. V. Dontsov ◽  
A. P. Peirce
Keyword(s):  
Boundary Layer ◽  
Approximate Solution ◽  
Hydraulic Fracturing ◽  
Transport Model ◽  
Fluid Velocity ◽  
Spherical Particles ◽  
Hydraulic Fractures ◽  
Gravitational Settling ◽  
Proppant Transport ◽  
Two Dimensional Flow

AbstractThe goal of this study is to analyse the steady flow of a Newtonian fluid mixed with spherical particles in a channel for the purpose of modelling proppant transport with gravitational settling in hydraulic fractures. The developments are based on a continuum constitutive model for a slurry, which is approximated by an empirical formula. It is shown that the problem under consideration features a two-dimensional flow and a boundary layer, which effectively introduces slip at the boundary and allows us to describe a transition from Poiseuille flow to Darcy’s law for high proppant concentrations. The expressions for both the outer (i.e. outside the boundary layer) and inner (i.e. within the boundary layer) solutions are obtained in terms of the particle concentration, particle velocity and fluid velocity. Unfortunately, these solutions require the numerical solution of an integral equation, and, as a result, the development of a proppant transport model for hydraulic fracturing based on these results is not practicable. To reduce the complexity of the problem, an approximate solution is introduced. To validate the use of this approximation, the error is estimated for different regimes of flow. The approximate solution is then used to calculate the expressions for the slurry flux and the proppant flux, which are the basis for a model that can be used to account for proppant transport with gravitational settling in a fully coupled hydraulic fracturing simulator.

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.

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