The solid skeleton of the mudcake consists of fine-grain particles; therefore, a mudcake plug is expected to have a very low permeability and a very good ability to isolate the fracture from wellbore pressure. This requires a relatively permeable formation for two reasons: Mudcake buildup requires fluid loss into the formation, and fracture pressure needs to dissipate after being isolated from the wellbore (Kumar et al. 2010).
The hydraulic fracture containment and the impact of layering on pumping energy are critical factors in a successful stimulation treatment. Height confinement is needed to ensure effective stimulation of target zones and to maintain the fractures in the target zones. Also, the existence of beds with different ductility can impact the net pressure and pumping requirements. Layered rock properties, in-situ stress, and formations interfaces influence the lateral and height growth of hydraulic fractures. Conventionally, it is considered that the in-situ stress is the dominant factor controlling the fracture height. The influence of mechanical properties on fracture height growth is often ignored or is limited to consideration of different Young's modulus. Also, it is commonly assumed that the interfaces between different layers are perfectly bounded without slippage, and interface permeability is not considered. In-situ experiments have demonstrated that variation of modulus and in-situ stress alone cannot explain the containment of hydraulic fractures observed in field (SPE39950). Enhanced toughness, in-situ stress, interface slip and energy dissipation in the layered rocks should be combined to contribute to the fracture containment. In this study, we consider these factors in a fully coupled 3D hydraulic fracture simulator developed based on finite element method. We use laboratory and numerical simulations to investigate the above factors and how they impact hydraulic fracture propagation, height growth, and injection pressure.
In this work a 3D fully coupled hydro-mechanical model is developed and utilized. The model uses a special zero-thickness interface element and the cohesive zone model (CZM) to model fracture propagation, interface slippage, and fluid flow in fractures. The nonlinear mechanical behavior of frictional sliding along interface surfaces is considered. The hydro-mechanical model has been successfully verified through benchmarked analytical solutions. The influence of layered Young's modulus on fracture height growth in layered formations is analyzed. The formation interfaces between different layers are explicitly simulated through the usage of the hydro-mechanical interface element. The impacts of mechanical and hydraulic properties of the formation interfaces on preventing hydraulic fracture growth are studied.
Hydraulic fractures tend to propagate in the layer with lower Young's modulus so that soft layers could potentially act as barriers to limit the height growth of hydraulic fractures. Depending on the mechanical properties and the conductivity of the interfaces, the shear-slippage and/or opening along the formation interfaces could result in flow along the interface surfaces and terminate the fracture growth. The frictional slippage along the interfaces could be an effective mechanism that contributes to the containment of hydraulic fractures in layered formations. It is suggested that whether a hydraulic fracture would cross a discontinuity depends not only on the mechanical properties but also on the hydraulic properties of the discontinuity; both the frictional slippage and fluid pressure along horizontal formation interfaces contribute to the reinitiation of a hydraulic fracture from a pre-existing flaw along the interfaces, producing an offset from the interception point to the reinitiation point.
Processing acoustic data downhole as well as at the surface is necessary to transform the raw acoustic signals recorded by modern logging instruments into data suitable for interpretation and analysis. The goal of acoustic-data processing is to minimize the data noise while maximizing the petrophysical information. Data preprocessing reduces the influences of these sources, thus allowing extraction of the true formation signal. Following the rapid theoretical advances in acoustic-wave propagation made during the 1980s and 1990s, significant advances in data processing provided improved quality in slowness measurements and enabled a number of new applications using Stoneley and dipole-shear wave in open and cased holes. The combined interpretation of Stoneley and dipole-shear acoustic measurements with NMR and borehole imaging enhances formation evaluation.
Objectives and Scope: Natural fractures were observed in core and image logs from the Hydraulic Fracture Test Site (HFTS) in Reagan Co., Texas. This paper provides an analysis of these fractures, including their orientation, size, spatial distribution, and openness.
Methods: We measured kinematic aperture sizes of two sets of sealed, opening-mode natural fractures in a slant core taken through a stimulated volume, and we analyzed the population distribution using cumulative frequency plots. For the spatial organization study, in addition to fractures identified in the slant core, we used data from image logs from three nearby horizontal producing wells. The spatial organization of fractures was investigated using our statistical method, Normalized Correlation Count (NCC), and by calculating the Coefficient of Variation, Cv, which is a measure of clustering.
Results: In the slant core 197 Set 1 (NE-SW) fractures are present (154 kinematic apertures measured), and there are 112 Set 2 (WNW-ESE) fractures (62 measured). The aperture-size distribution for Set 1 fractures follows a negative-exponential function, whereas Set 2 fractures follow a weak power-law. Only two fractures, both in Set 1 and ~ 1 mm wide, were open in the subsurface, although many more are now parted, mostly in Set 2. Linear intensity, P10, for measured fractures ≥1 mm wide is 0.01 frac/ft (Set 1) and 0.006 frac/ft (Set 2). Both natural fracture sets in an FMI image log from a nearby well have spatial arrangement patterns of regularly-spaced fractal clusters and Cv greater than 3 (3.22 to 4.05). Fracture cluster widths are 100–200 m, and cluster spacings range from 350–600 m. Fractures in COI image logs in two other wells have lower Cv (1.59 to 2.32). Both sets in the 6U well and Set 1 in the 6M well show elevated intensity along the middle section of the well and NCC indicates broad, but weak non-fractal clustering, likely related to lithological control of fracture growth. In the slant core Upper Wolfcamp Set 1 fractures are indistinguishable from random; Set 2 show a log-periodic clustering but with Cv less than 2.
Significance: Incorporation of Discrete Fracture Networks (DFN's) into hydraulic fracture modeling and reservoir simulation requires high-quality natural fracture data from image logs and core. This paper provides such data and provides information on natural-hydraulic fracture interaction at the HFTS site.
Pre-existing fractures in the subsurface can serve as preferential fluid flow pathways, and have the potential to be shear activated during hydraulic stimulation operations. This shearing could significantly increase natural fracture permeability, improve access to additional reservoir volume for production, and contribute to induced seismicity if not adequately managed. We perform triaxial direct shear experiments to evaluate the permeability of freshly created fractures as a function of stress (e.g. depth) using specimens of carbonate-rich Marcellus Shale. The strength required to form and reactivate fractures was measured over a range of effective confining stresses from 2 to 30 MPa. Initially intact, specimens of 25 mm diameter and 25 mm length were stressed to reservoir conditions, fractured by direct-shear, and then subjected to shearing displacements of up to 3 mm. Continuous permeability measurements were acquired through the course of experiments. Simultaneous X-ray video and computed tomography were used to directly measure fracture displacement and apertures at stressed conditions. The creation of fractures at higher effective stresses resulted in an overall lower permeability compared to the compression of fractures created at lower effective pressures. Results include the analysis of transient fracture permeability following renewed shear displacement and direct evidence of hydroshearing from fracture reactivation caused by increases in fracture pore pressure.
Fracture initialization and subsequent behavior remains a critical uncertainty in the development of better hydraulic fracturing practices. Key parameters governing the stress required to initiate a fracture through rock include the effective stress of a system (Anderson, 2017; Einstein and Dershowitz, 1990; Hoek, 2000; Hoek and Martin, 2014; Scholz, 1998; Wyllie and Mah, 2005), and the amount of shear stress a preexisting fracture can support before displacing (Ruina, 1983). These measurements are important in both the potential exploitation of existing natural fractures within a formation to increase the stimulated rock volume of hydraulic stimulation operations (Warpinski and Teufel, 2007), and in managing risk of induced seismicity events (Davies et al., 2013).
Hu, Lianbo (The University of Oklahoma) | Hemami, Behzad (The University of Oklahoma) | Ghassemi, Ahmad (The University of Oklahoma) | Riley, Spencer (Devon Energy) | Kahn, Dan (Devon Energy) | Langton, David (Devon Energy)
Moment Tensor Inversion (MTI) of microseismic data recorded during hydraulic fracturing shows that a large number of events have been found to have moment tensors consistent with either vertical or bedding plane slip. We are endeavoring to verify the occurrence of bedding plane slip events via analog experiments and numerical modeling. Though extensive experimental and numerical studies have been carried out to obtain a better understanding of the potential for crossing and arrest of a hydraulic fracture (HF) intersecting a natural fracture (NF), the actual mechanical interaction between a hydraulic fracture near a natural fracture or a bedding plane discontinuity has not been studied, particularly under triaxial stress and hydraulic fracturing conditions. In this paper we present the results of lab-scale experimental work with shales and numerical modeling to demonstrate HF/NF interaction with emphasis on slippage of a discontinuity surface. The tested samples have a near critical stressed incline natural fracture before fracturing. Hydraulic fracture is induced by injecting oil into a horizontal well with a vertical notch. Injection pressure, stresses, and acoustic emission (AE) are monitored during the test. In addition, strain gauges are used to measure the slippage on the natural fracture. Furthermore, a coupled distinct numerical model is built to simulate the analog tests. The fluid flow in the hydraulic fracture, fluid leak-off (for rock sample), induced deformation in the matrix and displacement in fracture are considered in this coupled model. At the breakdown point during hydraulic fracturing, a strain jump is recorded, which is accompanied by increased AE activity. Analysis of the data clearly shows the occurrence of slippage on the joint in response to an approaching hydraulic fracture. Expectedly, the degree of shear slip varies with natural fracture dip, and friction angle. The numerical results help reveal the complex stress and pore pressure distributions in the test assembly and show shear displacement on the natural fracture after pressurization of hydraulic fracture. The value of the maximum induced shear displacement on the natural fracture increased by orders of magnitude as the hydraulic fracture propagated in the sample.
Recent studies of core extracted adjacent to fractured wells show evidence of multi-stranded fractures as opposed to the conventional expectation of a single fracture per cluster. The cores show that fractures propagate as tightly spaced network of parallel strands and their number exceeded the number of perorations/clusters by a large amount. Previously (Sesetty and Ghassemi, 2019), we examined the conditions for the formation of multiple fractures from a perforation by focusing on the near wellbore region. In this work, we study hydraulic fracture segmentation and its impact on the net pressure. Furthermore, an advanced, rigorous P3D model is used to simulate multi-cluster multi-stage field scale planar hydraulic fracture propagation. In our modeling, we use the displacement discontinuity method (DD) to incorporate stress shadow between the parallel fracture strands. Depending on the regime of fracture propagation viscous/leak-off/toughness tip solutions are employed. A number of numerical simulations are considered for each stimulation concept, under varying field conditions with emphasis on the resultant treatment pressures and fracture conductivities. Results indicate that traditional modelling approach even when accounting for natural fractures cannot explain very high ISIP's (>1000 psi) that are often observed in field. On the other hand, simulations of multi-stranded hydraulic fractures considered under different geometric configurations can explain tight fracture spacing and high ISIP's. Also, formation of multi-clusters or stranded fractures adversely impact fracture apertures (especially the inner fractures) due to high stress shadow effect between the fractures, which poses a challenge to effective proppant placement. The fracture segment or strand height is the controlling parameter that dictates the minimum spacing allowed between the parallel strands for them to propagate simultaneously to very large distances from wellbore. Results show that accounting for the effects of multi-stranded fractures in numerical models can capture the field observed phenomena of high net pressures, multiple hydraulic fractures, and less than optimum proppant placement without resorting to ad hoc variation of natural fracture and rock properties. The novel numerical models used in this study have a computation time comparable to the conventional single fracture models, while handling a large number of interacting fractures.
Crandall, Dustin (National Energy Technology Laboratory) | Gill, Magdalena (National Energy Technology Laboratory, LRST) | Moore, Johnathan (National Energy Technology Laboratory, LRST) | Brown, Sarah (West Virginia Geological and Economic Survey) | Mackey, Paige (National Energy Technology Laboratory, ORISE)
The behavior of fractured low-permeability rock in many subsurface formations is critical for unconventional resource extraction. Understanding how flow through individual fractures changes during shearing, and what influence heterogeneity of the rock has on shearing behavior, was the focus of our laboratory study. Computed tomography (CT) scanning of fractured rocks undergoing shear was coupled with numerical simulations of fluid flow through these fractures. We sheared multiple cores from the Marcellus and Eau Claire shales in a closed system with confining pressures of greater than 1000 psi. Samples were manually sheared in a step wise fashion. After each shearing event we assessed the bulk hydrodynamic response by measuring permeability through the core and performed a high-resolution CT scan to understand how the principal and secondary fractures were changing in the core volume. The mineralogy of each sample was examined via x-ray fluorescence.
A range of interdependent characteristics influence fracture network evolution and sample cohesion: mineralogy, lithological heterogeneity, principal fracture morphology, fracture asperities, and shearing direction in relation to bedding. We found that samples sheared parallel to bedding were less likely to develop extensive networks of secondary fractures, with secondary fracture growth contingent on the presence of large asperities. Fracture permeability tended to increase with continued shear and secondary fracture development, but a high variance existed between samples. In some instances, permeabilities decreased in response to shear-initiated aperture reduction due to fracture mating. Gouge formation is another factor contributing to the transmissivity decreases, particularly in shale-dominated fracture regions. The ability to study this complex behavior in a controlled fashion using CT scanning enables a view into processes that impact production in many unconventional formations. Findings show that small scale features and details can play a significant role in fracture behavior and should be accounted for.
Shale properties vary significantly and understanding how fractures evolve due to geomechanical stressing can improve our understanding of how to effectively stimulate a variety of formations.While hydraulic fracturing is a large-scale activity, the microfabric and heterogeneity of shale can control fracture evolution and flow properties. Upscaling the impact of microfabric and heterogeneity is poorly captured in most modeling and planning efforts; this disconnect between small scale features and large-scale operations is understandable. It is difficult to measure changes in fractures directly, difficult to implement upscaled equations of value, and difficult to know if studied laboratory/outcrop samples are representative of activities in the subsurface. This study describes the observed behavior of two distinctly different shales under controlled geomechanical stressing to examine what impact small features have on fracture evolution. By examining two shales with distinctly different structure and composition our goal is to understand when inclusions of micro-features in upscaling is critical to understanding system dynamics.
In recent years much research effort has focused on hydraulic fracture height growth because height containment is needed to ensure effective stimulation of target zones. In many cases, fracture height growth determines the success or failure of a hydraulic stimulation. For layered rock systems, material properties, interface’s mechanical characteristics and its permeability, as well as the in-situ stresses influence both the lateral and height growth of hydraulic fractures. It is generally believed that stress contrast is a dominant factor that directly controls the fracture height. The influence of Young’s modulus contrast on height growth is usually ignored. Simplified “average methods” are often proposed and utilized to homogenize layered modulus. Also, it is commonly assumed that the layer interfaces are perfectly bonded without slippage even when high stress contrast exits. Use of theses simplifying assumptions in modeling analysis are partially due to the difficulty in handling all the factors involved. In this study, a fully coupled 3D hydraulic fracture simulator based on finite element method is used to investigate the above factors and study how they impact hydraulic fracture propagation and height growth. The influence of modulus contrast, interface conditions, and in-situ stress on hydraulic fracturing and especially on fracture height growth is analyzed.
The numerical approach is a 3D finite element model with a special zero-thickness interface element based on the cohesive zone model (CZM) to simulate the fracture propagation and fluid flow in fractures. A local traction-separation law with strain-softening is used to capture tensile cracking. The nonlinear mechanical behavior of frictional sliding along interface surfaces is also considered. Since discontinuities are explicitly simulated through the use of the interface element, details of the deformation processes are captured and revealed. For example, information related to aperture opening/sliding and stress distribution along the discontinuities is obtained in the simulations. After model verification and validation, it is used to simulate height growth in layered rock of practical interest. The numerical model is evaluated through a commonly used crossing/arrest criterion. Laboratory experiments on fracture-discontinuity interaction under triaxial-stress conditions are also studied. Numerical results match well with predictions of theoretical formulations and laboratory observations. Typical processes associated with fracture-discontinuity interaction are reveled. The recorded injection pressure increases when the hydraulic fracture reaches a bedding interface (or other discontinuities). Continuously opening and/or sliding along the interface requires higher injection pressure. With the existence of a horizontal interface, the influence of modulus contrast and stress contrast on hydraulic fracture height growth is analyzed. The combined effects of rock properties, mechanical properties of the interfaces, and in-situ stress distribution can effectively inhibit the height growth of hydraulic fractures.