Integrated characterization of hydraulic fracture treatments in the Barnett Shale: The Stocker geophysical experiment

2014 ◽  
Vol 2 (2) ◽  
pp. T111-T127 ◽  
Author(s):  
Baishali Roy ◽  
Bruce Hart ◽  
Anastasia Mironova ◽  
Changxi Zhou ◽  
Ulrich Zimmer
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Wells ◽  
Time Lapse ◽  
Seismic Facies ◽  
Barnett Shale ◽  
Hydraulic Fractures ◽  
Fracture Networks ◽  
Data Set ◽  
Stochastic Inversion ◽  
Wireline Logs

We integrated several independent geophysical and geologic methods to examine the effects of stratigraphic and structural heterogeneities on the growth of hydraulic fracture networks from two horizontal wells in the Barnett Shale, Fort Worth Basin, Texas. Our data set included time-lapse 3D seismic surveys, microseismic data, wireline logs, and distributed temperature sensing (DTS) data. We first created a local stratigraphic framework using wireline logs. In our area, the lower Barnett Shale consists of siliceous mudstones (the primary reservoir) intercalated with carbonate submarine fan deposits. The latter are low porosity (i.e., nonreservoir) and, if thick enough are potential baffles to the growth of hydraulic fractures. We used stochastic inversion to define the 3D distribution of fan lobes with much better resolution than could be obtained using deterministic inversion and obtained a geologically reasonable lithology prediction. The lowest of the fan lobes partially overlies the two horizontal wells, and its limits could be defined using wireline logs, the stochastic inversion, and seismic attributes (e.g., coherence, seismic facies classification). As suggested by the distribution of microseismic events, the extent of this lobe (locally up to 80 ft/24-m-thick) had a significant impact on the growth of the hydraulic fracture networks. The DTS data showed that high production correlates to dense microseismic activity in this area. Our time-lapse seismic analyses suggested that velocity changes induced by the hydraulic injections are detectable, although (largely because of logistical problems) the data were inadequately sampled to quantitatively define these changes. Alone, none of the analyses described herein provided an adequate understanding of the subsurface. However, once integrated, our multidisciplinary work provided a coherent, if still largely qualitative, understanding of the relationships between the geology and the growth of hydraulic fracture networks and some of the geophysical and engineering methods that can be used to define those links.

Monitoring the width of hydraulic fractures with acoustic waves

Geophysics ◽  
1998 ◽  
Vol 63 (1) ◽  
pp. 139-148 ◽  
Author(s):  
Jeroen Groenenboom ◽  
Jacob T. Fokkema
Keyword(s):  
Hydraulic Fracture ◽  
Acoustic Waves ◽  
Direct Determination ◽  
Time Lapse ◽  
Ultrasonic Waves ◽  
Hydraulic Fractures ◽  
Slip Model ◽  
Layer Model ◽  
Incident Wavelength ◽  
Linear Slip Model

During scaled hydraulic fracturing experiments in our laboratory, the fracture growth process is monitored in a time‐lapse experiment with ultrasonic waves. We observe dispersion of compressional waves that have propagated across the hydraulic fracture. This dispersion appears to be related to the width of the hydraulic fracture. This means that we can apply the dispersion measurements to monitor the width of the hydraulic fracture in an indirect manner. For a direct determination of the width, the resolution of the signal is required to distinguish the reflections that are related with two distinct fluid/solid interfaces delimiting the hydraulic fracture from its solid embedding. To make this distinction, the solid/fluid interfaces must be separated at least one eighth of a wavelength and represent sufficient impedance contrast. The applicability of the indirect dispersion measurement method however, extends to a fracture width that is in the order of 1% of the incident wavelength. The time‐lapse ultrasonic measurements allow us to relate the small difference in arrival time and amplitude between two measurements solely to the small changes in the width of the fracture. Additional experimental data show that shear waves are completely shadowed by hydraulic fractures, indicating that there is no acoustic contact mechanism at the fracture interface. Therefore we think it is appropriate to use a thin fluid‐filled layer model for these hydraulic fractures instead of the standard empirically oriented linear slip model. Nevertheless, the thin layer model is consistent with the linear‐slip model, if interpreted correctly. A comparison of width measurements inside the wellbore and width estimates by means of dispersion measurements close to the wellbore shows that the method can be successfully applied, at least under laboratory conditions, and that small changes in the width of the fracture are directly expressed in the dispersion of the transmitted signal. This opens the way for the important new application of width monitoring of hydraulic fractures.

Grid-Sensitivity Analysis and Comparison Between Unstructured Perpendicular Bisector and Structured Tartan/Local-Grid-Refinement Grids for Hydraulically Fractured Horizontal Wells in Eagle Ford Formation With Complicated Natural Fractures

SPE Journal ◽  
2016 ◽  
Vol 21 (06) ◽  
pp. 2260-2275 ◽  
Author(s):  
Jianlei Sun ◽  
David Schechter ◽  
Chung-Kan Huang
Keyword(s):  
Horizontal Wells ◽  
Work Flow ◽  
Hydraulic Fractures ◽  
Grid Refinement ◽  
Fracture Networks ◽  
Structured Grids ◽  
Local Grid Refinement ◽  
Production Behavior ◽  
Local Grid ◽  
Fractured Horizontal Wells

Summary In the context of modeling fractured horizontal wells, unstructured grids have been applied to generate simulation meshes for complex fracture networks. It is necessary to investigate how to choose an unstructured mesh to accurately simulate production performance. In this paper, a new unstructured gridding and discretization work flow is proposed to handle nonorthogonal and low-angle intersections of extensively clustered fractures with nonuniform apertures. The work flow is then validated with two models in terms of production behavior and central-processing-unit (CPU) performance: a synthetic model with one horizontal well and orthogonal intersected hydraulic fractures built by tartan grid, and a field-scale local-grid-refinement (LGR) model with three horizontal wells and irregular hydraulic fractures in a slightly dipping reservoir created by a commercial software plug-in. Good-quality matches are obtained between unstructured and structured grids in both pressure and production behavior. Sensitivity analysis of the meshing parameters suggests that refinement in the vicinity of fractures has improved both early and late production of a well, whereas background density has a dominant effect on the late production. Background-grid type and orientation have less influence as long as they have the same grid density. Fewer cells can be achieved by increasing reservoir-background size and size-progression ratio, replacing unstructured-background grids with structured grids, and reducing the complexity of the fracture networks without loss of the accuracy, resulting in improved CPU performance. This study applies unstructured grids to simulate multiple horizontal wells with complicated fracture networks, and provides detailed comparisons between unstructured and structured grids. Most importantly, it resolves the question regarding how to choose an appropriate mesh to yield both accurate results and high-quality CPU performance.

Fully Coupled Hydromechanical Simulation of Hydraulic Fracturing in Three-Dimensional Discrete Fracture Networks

2015 ◽  
Author(s):  
Mark W. McClure ◽  
Mohsen Babazadeh ◽  
Sogo Shiozawa ◽  
Jian Huang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Three Dimensional ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Field Scale ◽  
Discrete Fracture Networks ◽  
Discrete Fracture

Abstract We developed a hydraulic fracturing simulator that implicitly couples fluid flow with the stresses induced by fracture deformation in large, complex, three-dimensional discrete fracture networks. The simulator can describe propagation of hydraulic fractures and opening and shear stimulation of natural fractures. Fracture elements can open or slide, depending on their stress state, fluid pressure, and mechanical properties. Fracture sliding occurs in the direction of maximum resolved shear stress. Nonlinear empirical relations are used to relate normal stress, fracture opening, and fracture sliding to fracture aperture and transmissivity. Fluid leakoff is treated with a semianalytical one-dimensional leakoff model that accounts for changing pressure in the fracture over time. Fracture propagation is treated with linear elastic fracture mechanics. Non-Darcy pressure drop in the fractures due to high flow rate is simulated using Forchheimer's equation. A crossing criterion is implemented that predicts whether propagating hydraulic fractures will cross natural fractures or terminate against them, depending on orientation and stress anisotropy. Height containment of propagating hydraulic fractures between bedding layers can be modeled with a vertically heterogeneous stress field or by explicitly imposing hydraulic fracture height containment as a model assumption. The code is efficient enough to perform field-scale simulations of hydraulic fracturing with a discrete fracture network containing thousands of fractures, using only a single compute node. Limitations of the model are that all fractures must be vertical, the mechanical calculations assume a linearly elastic and homogeneous medium, proppant transport is not included, and the locations of potentially forming hydraulic fractures must be specified in advance. Simulations were performed of a single propagating hydraulic fracture with and without leakoff to validate the code against classical analytical solutions. Field-scale simulations were performed of hydraulic fracturing in a densely naturally fractured formation. The simulations demonstrate how interaction with natural fractures in the formation can help explain the high net pressures, relatively short fracture lengths, and broad regions of microseismicity that are often observed in the field during stimulation in low permeability formations, and which are not predicted by classical hydraulic fracturing models. Depending on input parameters, our simulations predicted a variety of stimulation behaviors, from long hydraulic fractures with minimal leakoff into surrounding fractures to broad regions of dense fracturing with a branching network of many natural and newly formed fractures.

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.

Novel Completion Designs in Horizontal Well with Transverse Hydraulic Fractures for Enhanced Recovery in Unconventional or Tight Reservoirs

2021 ◽  
Author(s):  
Shubham Mishra ◽  
Christopher Fredd ◽  
Dean Wilberg ◽  
Umur Yanbollu
Keyword(s):  
Oil Recovery ◽  
Hydraulic Fracture ◽  
Enhanced Recovery ◽  
Horizontal Wells ◽  
Face Alignment ◽  
Hydraulic Fractures ◽  
Fracture Face ◽  
Face To Face ◽  
Tight Reservoirs ◽  
Transverse Fractures

Abstract Low recovery, 2 to 15%, in unconventional plays (including tight reservoirs and source rocks) has long been recognized as a business deterrent. The industry applies enhanced oil recovery (EOR) techniques, along with hydraulic fractures in tight/unconventional plays, to improve the recovery. To maximize matrix sweep, the fractures are aligned in a face-to-face assembly. Such an arrangement can be achieved using vertical or longitudinal hydraulic fracture on horizontal wells, but these, generally, do not provide as effective reservoir contact (hydraulic fracture surface area) as horizontal wells with multistage transverse hydraulic fractures. The multistage transverse hydraulic fracture, however, comes at the costs of conformance issues with early water breakthrough from short-circuiting and inability to achieve fracture face-to-fracture face alignment of the injection and production fractures. The vast majority of wells drilled in unconventional plays are in the transverse configuration; hence, there is a need for an optimal solution for transverse fractures combined with improved oil recovery (IOR)/EOR approaches. In this work, we introduce the multistage enhanced recovery (MS-ER) techniques that enable face-to-face alignment for optimal enhanced hydrocarbon recovery/IOR/EOR in horizontal wells with multistage transverse fractures, thereby enabling optimal recovery and mitigating the key risk of fracture short-circuiting.

Fully Coupled Hydromechanical Simulation of Hydraulic Fracturing in 3D Discrete-Fracture Networks

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1302-1320 ◽  
Author(s):  
Mark W. McClure ◽  
Mohsen Babazadeh ◽  
Sogo Shiozawa ◽  
Jian Huang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Field Scale ◽  
Discrete Fracture Networks ◽  
Discrete Fracture

Summary We developed a hydraulic-fracturing simulator that implicitly couples fluid flow with the stresses induced by fracture deformation in large, complex, 3D discrete-fracture networks (DFNs). The code is efficient enough to perform field-scale simulations of hydraulic fracturing in DFNs containing thousands of fractures, without relying on distributed-memory parallelization. The simulator can describe propagation of hydraulic fractures and opening and shear stimulation of natural fractures. Fracture elements can open or slide, depending on their stress state, fluid pressure, and mechanical properties. Fracture sliding occurs in the direction of maximum resolved shear stress. Nonlinear empirical equations are used to relate normal stress, fracture opening, and fracture sliding to fracture aperture and transmissivity. Fluid leakoff is treated with a semianalytical 1D leakoff model that accounts for changing pressure in the fracture over time. Fracture propagation is modeled with linear-elastic fracture mechanics. The Forchheimer equation (Forchheimer 1901) is used to simulate non-Darcy pressure drop in the fractures because of high flow rate. A crossing criterion is implemented that predicts whether propagating hydraulic fractures will cross natural fractures or terminate against them, depending on orientation and stress anisotropy. Height containment of propagating hydraulic fractures between bedding layers can be modeled with a vertically heterogeneous stress field or by explicitly imposing hydraulic-fracture-height containment as a model assumption. Limitations of the model are that all fractures must be vertical; the mechanical calculations assume a linearly elastic and homogeneous medium; proppant transport is not included; and the locations of potentially forming hydraulic fractures must be specified in advance. Simulations were performed of a single propagating hydraulic fracture with and without leakoff to validate the code against classical analytical solutions. Field-scale simulations were performed of hydraulic fracturing in a densely naturally fractured formation. The simulations demonstrate how interaction with natural fractures in the formation can help explain the high net pressures, relatively short fracture lengths, and broad regions of microseismicity that are often observed in the field during stimulation in low-permeability formations, and that are not predicted by classical hydraulic-fracturing models. Depending on input parameters, our simulations predicted a variety of stimulation behaviors, from long hydraulic fractures with minimal leakoff into surrounding fractures to broad regions of dense fracturing with a branching network of many natural and newly formed fractures.

scholarly journals Optimization of Multiple Hydraulically Fractured Horizontal Wells in Unconventional Gas Reservoirs

2013 ◽  
Vol 2013 ◽  
pp. 1-16 ◽  
Author(s):  
Wei Yu ◽  
Kamy Sepehrnoori
Keyword(s):  
Horizontal Wells ◽  
Barnett Shale ◽  
Hydraulic Fractures ◽  
Uncertain Parameters ◽  
Gas Reservoirs ◽  
Well Placement ◽  
Unconventional Gas ◽  
Fracture Conductivity ◽  
Gas Desorption ◽  
Unconventional Gas Reservoirs

Accurate placement of multiple horizontal wells drilled from the same well pad plays a critical role in the successful economical production from unconventional gas reservoirs. However, there are high cost and uncertainty due to many inestimable and uncertain parameters such as reservoir permeability, porosity, fracture spacing, fracture half-length, fracture conductivity, gas desorption, and well spacing. In this paper, we employ response surface methodology to optimize multiple horizontal well placement to maximize Net Present Value (NPV) with numerically modeling multistage hydraulic fractures in combination with economic analysis. This paper demonstrates the accuracy of numerical modeling of multistage hydraulic fractures for actual Barnett Shale production data by considering the gas desorption effect. Six uncertain parameters, such as permeability, porosity, fracture spacing, fracture half-length, fracture conductivity, and distance between two neighboring wells with a reasonable range based on Barnett Shale information, are used to fit a response surface of NPV as the objective function and to finally identify the optimum design under conditions of different gas prices based on NPV maximization. This integrated approach can contribute to obtaining the optimal drainage area around the wells by optimizing well placement and hydraulic fracturing treatment design and provide insight into hydraulic fracture interference between single well and neighboring wells.

Predicting Well Performance in Naturally Fractured Reservoir

2013 ◽  
Author(s):  
Yunsuk Hwang ◽  
Jiajing Lin ◽  
David Schechter ◽  
Ding Zhu
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Network ◽  
Darcy Flow ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Performance ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Complex Fracture Network

Multiple hydraulic fracture treatments in reservoirs with natural fractures create complex fracture networks. Predicting well performance in such a complex fracture network system is an extreme challenge. The statistical nature of natural fracture networks changes the flow characteristics from that of a single linear fracture. Simply using single linear fracture models for individual fractures, and then summing the flow from each fracture as the total flow rate for the network could introduce significant error. In this paper we present a semi-analytical model by a source method to estimate well performance in a complex fracture network system. The method simulates complex fracture systems in a more reasonable approach. The natural fracture system we used is fractal discrete fracture network model. We then added multiple dominating hydraulic fractures to the natural fracture system. Each of the hydraulic fractures is connected to the horizontal wellbore, and some of the natural fractures are connected to the hydraulic fractures through the network description. Each fracture, natural or hydraulically induced, is treated as a series of slab sources. The analytical solution of superposed slab sources provides the base of the approach, and the overall flow from each fracture and the effect between the fractures are modeled by applying the superposition principle to all of the fractures. The fluid inside the natural fractures flows into the hydraulic fractures, and the fluid of the hydraulic fracture from both the reservoir and the natural fractures flows to the wellbore. This paper also shows that non-Darcy flow effects have an impact on the performance of fractured horizontal wells. In hydraulic fracture calculation, non-Darcy flow can be treated as the reduction of permeability in the fracture to a considerably smaller effective permeability. The reduction is about 2% to 20%, due to non-Darcy flow that can result in a low rate. The semi-analytical solution presented can be used to efficiently calculate the flow rate of multistage-fractured wells. Examples are used to illustrate the application of the model to evaluate well performance in reservoirs that contain complex fracture networks.

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