Numerical Modeling of Fracture Propagation During Temporary-Plugging Fracturing

Summary Temporary-plugging fracturing (TPF) is becoming a promising technique for maximizing the stimulated-reservoir volume in tight reservoirs by injecting diverting agents to plug the preferred perforations and/or hydraulic fractures (HFs). Previous work has developed diverting agents and evaluated their blocking efficiency. However, the mechanism and dominant influence factors of HF growth during TPF remain poorly understood to date, which restricts the application of this technique. To understand the problem and help improve the TPF design, this study simulated the HF-propagation process during TPF in a naturally fractured formation using a previously developed 3D discrete-element-method (DEM) -based complex fracture model. Plugged fracture elements with negligible permeability were incorporated into the model to characterize the blocking intervals of diverting agents within HFs. Parameters, including horizontal differential stress (Δσh), natural-fracture (NF) properties, the number of pluggings, plugging positions, and pumping rate, were investigated to determine their effects on the HF/NF-interaction behavior and the resulting HF geometry. The change in injection pressure before and after plugging under different conditions was also recorded in detail. Modeling results show that the HF/NF-interaction behavior might surprisingly change before and after plugging the preferred HF, ranging from HF crossing of NFs to HF opening of NFs. Notably, Δσh is still the most influential geological parameter that governs the HF-growth behavior during TPF. For a moderate Δσh (=8 MPa), the growth of a single planar HF before plugging can be changed easily into a complex HF network (HFN) through opening of NFs after plugging in the target stimulated region (TSR). In this case, the complexity and covering area of the resulting HFN is closely related to the NF density (positive correlation) and plugging positions. However, for a high Δσh (=12 MPa), opening (usually partially) the NFs after plugging is difficult even in formations with a high density of NFs. In such a case, a large volume of fluid, a high pumping rate, and several repeat pluggings during TPF are necessary. The results of this study help to understand the HF-growth mechanism during TPF and help to optimize the treatment design of TPF and to adjust it in a timely manner.

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

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-00980-8 ◽

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.

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Analytical and Machine-LearningAnalysis of Hydraulic Fracture-Induced Natural Fracture Slip

SPE Journal ◽

10.2118/205346-pa ◽

2021 ◽

pp. 1-17

Author(s):

Peidong Zhao ◽

K. E. Gray

Keyword(s):

Failure Modes ◽

Statistical Significance ◽

Frictional Coefficient ◽

Natural Fracture ◽

Hydraulic Fractures ◽

Well Performance ◽

Stimulated Reservoir Volume ◽

Relative Angle ◽

Statistical Measures ◽

Net Pressure

Summary Stimulated reservoir volume (SRV) is a prime factor controlling well performance in unconventional shale plays. In general, SRV describes the extent of connected conductive fracture networks within the formation. Being a pre-existing weak interface, natural fractures (NFs) are the preferred failure paths. Therefore, the interaction of hydraulic fractures (HFs) and NFs is fundamental to fracture growth in a formation. Field observations of induced fracture systems have suggested complex failure zones occurring in the vicinity of HFs, which makes characterizing the SRV a significant challenge. Thus, this work uses a broad range of subsurface conditions to investigate the near-tip processes and to rank their influences on HF-NF interaction. In this study, a 2D analytical workflow is presented that delineates the potential slip zone (PSZ) induced by a HF. The explicit description of failure modes in the near-tip region explains possible mechanisms of fracture complexity observed in the field. The parametric analysis shows varying influences of HF-NF relative angle, stress state, net pressure, frictional coefficient, and HF length to the NF slip. This work analytically proves that an NF at a 30 ± 5° relative angle to an HF has the highest potential to be reactivated, which dominantly depends on the frictional coefficient of the interface. The spatial extension of the PSZ normal to the HF converges as the fracture propagates away and exhibits asymmetry depending on the relative angle. Then a machine-learning (ML) model [random forest (RF) regression] is built to replicate the physics-based model and statistically investigate parametric influences on NF slips. The ML model finds statistical significance of the predicting features in the order of relative angle between HF and NF, fracture gradient, frictional coefficient of the NF, overpressure index, stress differential, formation depth, and net pressure. The ML result is compared with sensitivity analysis and provides a new perspective on HF-NF interaction using statistical measures. The importance of formation depth on HF-NF interaction is stressed in both the physics-based and data-driven models, thus providing insight for field development of stacked resource plays. The proposed concept of PSZ can be used to measure and compare the intensity of HF-NF interactions at various geological settings.

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Hydraulic Fractures Simulation and Stimulated Reservoir Volume Estimation for Shale Gas Fracturing

10.2118/195547-ms ◽

2019 ◽

Author(s):

Ran Lin ◽

Lan Ren ◽

Jinzhou Zhao ◽

Yongfu Tao ◽

Xiucheng Tan ◽

...

Keyword(s):

Shale Gas ◽

Volume Estimation ◽

Hydraulic Fractures ◽

Stimulated Reservoir Volume ◽

Reservoir Volume

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Numerical Investigation of Complex Hydraulic Fracture Development in Naturally Fractured Reservoirs

10.2118/spe-173326-ms ◽

2015 ◽

Author(s):

Wu Kan ◽

Jon E. Olson

Keyword(s):

Fracture Propagation ◽

Injection Pressure ◽

Natural Fracture ◽

Hydraulic Fractures ◽

Differential Stress ◽

Complex Fracture ◽

Fracture Patterns ◽

Fracture Development ◽

Fracture Complexity ◽

Shale Reservoirs

Abstract Complex fracture networks have become more evident in shale reservoirs due to the interaction between pre-existing natural and hydraulic fractures. Accurate characterization of fracture complexity plays an important role in optimizing fracturing design, especially for shale reservoirs with high-density natural fractures. In this study, we simulated simultaneous multiple fracture propagation within a single fracturing stage using a complex hydraulic fracture development model. The model was developed to simulate complex fracture propagation by coupling rock mechanics and fluid mechanics. A simplified three-dimensional displacement discontinuity method was implemented to more accurately calculate fracture displacements and fracture-induced dynamic stress changes than our previously developed pseudo-3d model. The effects of perforation cluster spacing, differential stress (SHmax - Shmin) and various geometry natural fracture patterns on injection pressure and fracture complexity were investigated. The single stage simulation results shown that (1) higher differential stress suppresses fracture length and increases injection pressure; (2) there is an optimal choice for the number of fractures per stage to maximize effective fracture surface area, beyond which increasing the number of fractures actually decreases effective fracture area; and (3) fracture complexity is a function of natural fracture patterns (various regular pattern geometries were investigated). Natural fractures with small relative angle to hydraulic fractures are more likely to control fracture propagation path. Also, natural fracture patterns with more long fractures tend to increase the likelihood to dominate the preferential fracture trend of fracture trajectory. Our numerical model can provide a physics-based complex fracture network that can be imported into reservoir simulation models for production analysis. The overall sensitivity results presented should serve as guidelines for fracture complexity analysis.

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Numerical Simulation Study on Seepage Theory of a Multi-Section Fractured Horizontal Well in Shale Gas Reservoirs Based on Multi-Scale Flow Mechanisms

Energies ◽

10.3390/en11092329 ◽

2018 ◽

Vol 11 (9) ◽

pp. 2329 ◽

Cited By ~ 6

Author(s):

Chao Tang ◽

Xiaofan Chen ◽

Zhimin Du ◽

Ping Yue ◽

Jiabao Wei

Keyword(s):

Shale Gas ◽

Large Scale ◽

Gas Diffusion ◽

Gas Production ◽

Hydraulic Fractures ◽

Klinkenberg Effect ◽

Stimulated Reservoir Volume ◽

Multi Scale ◽

Reservoir Volume ◽

Flow Mechanisms

Aimed at the multi-scale fractures for stimulated reservoir volume (SRV)-fractured horizontal wells in shale gas reservoirs, a mathematical model of unsteady seepage is established, which considers the characteristics of a dual media of matrix and natural fractures as well as flow in the large-scale hydraulic fractures, based on a discrete-fracture model. Multi-scale flow mechanisms, such as gas desorption, the Klinkenberg effect, and gas diffusion are taken into consideration. A three-dimensional numerical model based on the finite volume method is established, which includes the construction of spatial discretization, calculation of average pressure gradient, and variable at interface, etc. Some related processing techniques, such as boundedness processing upstream and downstream of grid flow, was used to limit non-physical oscillation at large-scale hydraulic fracture interfaces. The sequential solution is performed to solve the pressure equations of matrix, natural, and large-scale hydraulic fractures. The production dynamics and pressure distribution of a multi-section fractured horizontal well in a shale gas reservoir are calculated. Results indicate that, with the increase of the Langmuir volume, the average formation pressure decreases at a slow rate. Simultaneously, the initial gas production and the contribution ratio of the desorbed gas increase. With the decrease of the pore size of the matrix, gas diffusion and the Klinkenberg effect have a greater impact on shale gas production. By changing the fracture half-length and the number of fractured sections, we observe that the production process can not only pursue the long fractures or increase the number of fractured sections, but also should optimize the parameters such as the perforation position, cluster spacing, and fracturing sequence. The stimulated reservoir volume can effectively control the shale reservoir.

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Pressure Response of a Horizontal Well in Tight Oil Reservoirs with Stimulated Reservoir Volume

Lithosphere ◽

10.2113/2021/5383603 ◽

2021 ◽

Vol 2021 (Special 1) ◽

Author(s):

Peng Chen ◽

Changpeng Hu ◽

Pingguo Zou ◽

Lili Lin ◽

Song Lu ◽

...

Keyword(s):

Horizontal Well ◽

Fracture Network ◽

Stress Sensitivity ◽

Pressure Response ◽

Hydraulic Fractures ◽

Tight Oil ◽

Stimulated Reservoir Volume ◽

Pressure Behavior ◽

Reservoir Volume ◽

Interpretation Model

Abstract Stimulated reservoir volume is an effective stimulation measure and creates a complex fracture network, but the description and characterization of fracture network are very difficult. Well test analysis is a common method to describe the fracture network, and it is the key to build a proper interpretation model. However, most published works only consider the shape of the fractured area or the stress sensitivity effect, and few works take both factors into account. In this paper, based on reservoir properties and flow law after a stimulated reservoir volume, an interpretation model is established with an arbitrary shape of the fractured area and stress sensitivity effect of different flow areas. The model is solved to conduct the pressure response using Laplace transform, point source function, and boundary element theory. The influence of fractures’ parameters and stress sensitivity effect is analyzed on the pressure behavior. Results from this study show that the special flow regimes for a horizontal well with a stimulated reservoir volume are (1) bilinear flow dominated by hydraulic fractures, (2) linear flow dominated by formation around the hydraulic fractures, (3) crossflow from a matrix system to the fractured area, and (4) radial flow control by properties of the fractured area. Parameters of hydraulic fractures mainly affect the early stage of pressure behavior. On the contrary, the stress-sensitive effect mainly affects the middle and late stages; the stronger the stress sensitivity effect is, the more obvious the effect is. The findings of this study can help for better understanding of the fracture network in a tight oil reservoir with a stimulated reservoir volume.

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Experimental Studies on Shale Cracks and Permeability Evolution Based on Acoustic Emission Monitoring

Geofluids ◽

10.1155/2021/6620538 ◽

2021 ◽

Vol 2021 ◽

pp. 1-16

Author(s):

Hao Chen ◽

Hongkui Ge ◽

Xiaoqiong Wang ◽

Jianbo Wang ◽

Shan Wu

Keyword(s):

Acoustic Emission ◽

Percolation Threshold ◽

Microseismic Monitoring ◽

Permeability Evolution ◽

Stimulated Reservoir Volume ◽

Reservoir Volume ◽

Longmaxi Shale ◽

Before And After ◽

Shale Reservoirs ◽

The Relationship

The matrix permeability of shale reservoirs is extremely low. Therefore, massive volume fracturing is needed to form a complex crack network and get adequate sufficient capacity during the well completion. After fracturing, the effective stimulated reservoir volume (ESRV) is vital for developing shale reservoirs, mainly determined by stimulated reservoir volume (SRV) and the increase in permeability. Microseismic monitoring is widely used in the field to describe the crack shape and determine the SRV, to evaluate the stimulation effect. However, no studies have been conducted on the relationship between microseismic parameters and permeability. Thereby, we conducted uniaxial compression tests on Longmaxi shale samples and measured their changes in porosity and permeability before and after loading combining the microseismic monitoring under a laboratory scale (acoustic emission (AE)). Results show that porosity has little influence on the permeability before and after loading, while the propagation and connection of cracks are the most critical factors. As the loading stress increases, the crack volume and sample connectivity both grow. Besides, for the Longmaxi shale, when the stress is loaded to 30~50% of uniaxial compressive strength (UCS), the cracks start to propagate steadily (dilation), the permeability begins to increase rapidly, and percolation occurs, which indicates that the dilation point is closely related to the percolation threshold. The AE rate and accumulative ringing number both increase when it is larger than the percolation threshold value. The variation of AE characteristics can be used to identify the percolation threshold. Finally, the graphic model including AE parameters, crack, and permeability evolution is established based on the experimental results, which could help us understand the relationship between microseismic parameters and permeability and provide a methodological basis for the ESRV evaluation in the field.

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

Journal of Applied Mechanics ◽

10.1115/1.4040479 ◽

2018 ◽

Vol 85 (10) ◽

Cited By ~ 4

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.

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Experimental Study on Injection Pressure Response and Fracture Geometry during Temporary Plugging and Diverting Fracturing

SPE Journal ◽

10.2118/199893-pa ◽

2020 ◽

Vol 25 (02) ◽

pp. 573-586 ◽

Cited By ~ 2

Author(s):

Bo Wang ◽

Fujian Zhou ◽

Chen Yang ◽

Daobing Wang ◽

Kai Yang ◽

...

Keyword(s):

Injection Pressure ◽

Fracture Network ◽

Pressure Response ◽

Hydraulic Fractures ◽

Fracturing Fluid ◽

Breakdown Pressure ◽

Multiple Fractures ◽

Differential Stress ◽

Fracture Geometry ◽

Stimulated Reservoir Volume

Summary Temporary plugging and diverting fracturing (TPDF) has become one of the fastest-growing techniques to maximize the stimulated reservoir volume (SRV). During the field operation of TPDF, diverters are injected to redirect the hydraulic fractures into the under-stimulated region of the reservoir, and, thus, to obtain better coverage of the created fracture network. In this study, the commonly used true tri-axial hydraulic fracturing system is modified to investigate the influences of various factors on the injection pressure response and resultant fracture geometry during diversion treatments. The experimental results show the feasibility of creating multiple fractures through TPDF, and more importantly give the following findings: (1) a complex diverted fracture network tends to be created at a small differential stress (2.5 MPa in this case), while diverted fractures tend to grow parallel to the initial fractures at a high differential stress (7.5 MPa in this case); (2) with the same concentration in the fracturing fluid, 40-mesh powder-shaped diverters can plug the created fractures and increase the net pressure more rapidly than 6-mm fiber-shaped diverters; (3) an excess of diverters can lead to a strong injection pressure response, and, thus, enhance the difficulty of creating multiple fractures; (4) when diverters are injected with the fracturing fluid, no obvious breakdown pressure or propagation pressure is shown during the fracture propagation.

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Multiporosity and Multiscale Flow Characteristics of a Stimulated Reservoir Volume (SRV)-Fractured Horizontal Well in a Tight Oil Reservoir

Energies ◽

10.3390/en11102724 ◽

2018 ◽

Vol 11 (10) ◽

pp. 2724 ◽

Cited By ~ 3

Author(s):

Long Ren ◽

Wendong Wang ◽

Yuliang Su ◽

Mingqiang Chen ◽

Cheng Jing ◽

...

Keyword(s):

Horizontal Well ◽

Oil Reservoirs ◽

Natural Fracture ◽

Tight Oil ◽

Fracture System ◽

Stimulated Reservoir Volume ◽

Discrete Fracture Model ◽

Reservoir Volume ◽

Fractured Horizontal Well ◽

Tight Oil Reservoirs

There are multiporosity media in tight oil reservoirs after stimulated reservoir volume (SRV) fracturing. Moreover, multiscale flowing states exist throughout the development process. The fluid flowing characteristic is different from that of conventional reservoirs. In terms of those attributes of tight oil reservoirs, considering the flowing feature of the dual-porosity property and the fracture network system based on the discrete-fracture model (DFM), a mathematical flow model of an SRV-fractured horizontal well with multiporosity and multipermeability media was established. The numerical solution was solved by the finite element method and verified by a comparison with the analytical solution and field data. The differences of flow regimes between triple-porosity, dual-permeability (TPDP) and triple-porosity, triple-permeability (TPTP) models were identified. Moreover, the productivity contribution degree of multimedium was analyzed. The results showed that for the multiporosity flowing states, the well bottomhole pressure drop became slower, the linear flow no longer arose, and the pressure wave arrived quickly at the closed reservoir boundary. The contribution ratio of the matrix system, natural fracture system, and network fracture system during SRV-fractured horizontal well production were 7.85%, 43.67%, and 48.48%, respectively in the first year, 14.60%, 49.23%, and 36.17%, respectively in the fifth year, and 20.49%, 46.79%, and 32.72%, respectively in the 10th year. This study provides a theoretical contribution to a better understanding of multiscale flow mechanisms in unconventional reservoirs.

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