Intrinsic anisotropy in fracture permeability

2015 ◽  
Vol 3 (3) ◽  
pp. ST43-ST53 ◽  
Author(s):  
Mehdi Mokhtari ◽  
Azra N. Tutuncu ◽  
Gregory N. Boitnott
Keyword(s):  
Fluid Dynamics ◽  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Numerical Data ◽  
Fracture Aperture ◽  
Fracture Permeability ◽  
Fracture Geometry ◽  
Mechanical Fracture ◽  
Proppant Transport ◽  
Intrinsic Anisotropy

Contrary to the assumption in cubic law, the surface of fractures has some degree of roughness, which impacts their fluid dynamics. Incorporating the effect of roughness can improve the simulation of fluid flow in fractures and faults, as well as proppant transport in hydraulic fracturing. To investigate the effect of roughness on the fluid flow, we created a fracture using the Brazilian test, and its roughness was measured using a laser profilometer. Experimental permeability measurements showed a reduction in permeability as the effective stress increased. However, the unmatching surfaces of the fracture prevented its complete mechanical closure. Numerical simulations of the fluid dynamics were conducted on the measured fracture geometry. We determined that the hydraulic fracture aperture is less than the mechanical fracture aperture and that there was anisotropy in the fracture permeability. The ratio of hydraulic fracture aperture to mechanical fracture aperture, as well as anisotropy in fracture permeability, increased when the fracture aperture decreased. The anisotropy in fracture permeability was 45% at the lowest simulated fracture aperture. Integrating the experimental and numerical data, we estimated the fracture porosity and fracture permeability.

Numerical Simulation of Proppant Transport in Hydraulically Fractured Reservoirs

2021 ◽  
Author(s):  
Seyhan Emre Gorucu ◽  
Vijay Shrivastava ◽  
Long X. Nghiem
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fractured Reservoirs ◽  
Injection Timing ◽  
Fracture Permeability ◽  
Step Size ◽  
Time Step ◽  
Time Step Size ◽  
Proppant Transport ◽  
Fracture Closure

Abstract An existing equation-of-state compositional simulator is extended to include proppant transport. The simulator determines the final location of the proppant after fracture closure, which allows the computation of the permeability along the hydraulic fracture. The simulation then continues until the end of the production. During hydraulic fracturing, proppant is injected in the reservoir along with water and additives like polymers. Hydraulic fracture gets created due to change in stress caused by the high injection pressure. Once the fracture opens, the bulk slurry moves along the hydraulic fracture. Proppant moves at a different speed than the bulk slurry and sinks down by gravity. While the proppant flows along the fracture, some of the slurry leaks off into the matrix. As the fracture closes after injection stops, the proppant becomes immobile. The immobilized proppant prevents the fracture from closing and thus keeps the permeability of the fracture high. All the above phenomena are modelled effectively in this new implementation. Coupled geomechanics simulation is used to model opening and closure of the fracture following geomechanics criteria. Proppant retardation, gravitational settling and fluid leak-off are modeled with the appropriate equations. The propped fracture permeability is a function of the concentration of immobilized proppant. The developed proppant simulation feature is computationally stable and efficient. The time step size during the settling adapts to the settling velocity of the proppants. It is found that the final location of the proppants is highly dependent on its volumetric concentration and slurry viscosity due to retardation and settling effects. As the location and the concentration of the proppants determine the final fracture permeability, the additional feature is expected to correctly identify the stimulated region. In this paper, the theory and the model formulation are presented along with a few key examples. The simulation can be used to design and optimize the amount of proppant and additives, injection timing, pressure, and well parameters required for successful hydraulic fracturing.

scholarly journals Evolution of Fracture Aperture in Quartz Sandstone under Hydrothermal Conditions: Mechanical and Chemical Effects

Minerals ◽  
2020 ◽  
Vol 10 (8) ◽  
pp. 657
Author(s):  
Chaojie Cheng ◽  
Harald Milsch
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Chemical Equilibrium ◽  
Pore Fluid ◽  
Pressure Solution ◽  
Fracture Aperture ◽  
Hydraulic Aperture ◽  
Mechanical Aperture ◽  
Stagnant Flow

Fractures efficiently affect fluid flow in geological formations, and thereby determine mass and energy transport in reservoirs, which are not least exploited for economic resources. In this context, their response to mechanical and thermal changes, as well as fluid–rock interactions, is of paramount importance. In this study, a two-stage flow-through experiment was conducted on a pure quartz sandstone core of low matrix permeability, containing one single macroscopic tensile fracture. In the first short-term stage, the effects of mechanical and hydraulic aperture on pressure and temperature cycles were investigated. The purpose of the subsequent intermittent-flow long-term (140 days) stage was to constrain the evolution of the geometrical and hydraulic fracture properties resulting from pressure solution. Deionized water was used as the pore fluid, and permeability, as well as the effluent Si concentrations, were systematically measured. Overall, hydraulic aperture was shown to be significantly less affected by pressure, temperature and time, in comparison to mechanical aperture. During the long-term part of the experiment at 140 °C, the effluent Si concentrations likely reached a chemical equilibrium state within less than 8 days of stagnant flow, and exceeded the corresponding hydrostatic quartz solubility at this temperature. This implies that the pressure solution was active at the contacting fracture asperities, both at 140 °C and after cooling to 33 °C. The higher temperature yielded a higher dissolution rate and, consequently, a faster attainment of chemical equilibrium within the contact fluid. X-ray µCT observations evidenced a noticeable increase in fracture contact area ratio, which, in combination with theoretical considerations, implies a significant decrease in mechanical aperture. In contrast, the sample permeability, and thus the hydraulic fracture aperture, virtually did not vary. In conclusion, pressure solution-induced fracture aperture changes are affected by the degree of time-dependent variations in pore fluid composition. In contrast to the present case of a quasi-closed system with mostly stagnant flow, in an open system with continuous once-through fluid flow, the activity of the pressure solution may be amplified due to the persistent fluid-chemical nonequilibrium state, thus possibly enhancing aperture and fracture permeability changes.

Investigation of Rupture and Slip Mechanisms of Hydraulic Fractures in Multiple-Layered Formations

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2292-2307 ◽  
Author(s):  
Jizhou Tang ◽  
Kan Wu ◽  
Lihua Zuo ◽  
Lizhi Xiao ◽  
Sijie Sun ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Propagation Model ◽  
Rock Deformation ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Width ◽  
Hydraulic Fracture Propagation ◽  
Fracture Height

Summary Weak bedding planes (BPs) that exist in many tight oil formations and shale–gas formations might strongly affect fracture–height growth during hydraulic–fracturing treatment. Few of the hydraulic–fracture–propagation models developed for unconventional reservoirs are capable of quantitatively estimating the fracture–height containment or predicting the fracture geometry under the influence of multiple BPs. In this paper, we introduce a coupled 3D hydraulic–fracture–propagation model considering the effects of BPs. In this model, a fully 3D displacement–discontinuity method (3D DDM) is used to model the rock deformation. The advantage of this approach is that it addresses both the mechanical interaction between hydraulic fractures and weak BPs in 3D space and the physical mechanism of slippage along weak BPs. Fluid flow governed by a finite–difference methodology considers the flow in both vertical fractures and opening BPs. An iterative algorithm is used to couple fluid flow and rock deformation. Comparison between the developed model and the Perkins–Kern–Nordgren (PKN) model showed good agreement. I–shaped fracture geometry and crossing–shaped fracture geometry were analyzed in this paper. From numerical investigations, we found that BPs cannot be opened if the difference between overburden stress and minimum horizontal stress is large and only shear displacements exist along the BPs, which damage the planes and thus greatly amplify their hydraulic conductivity. Moreover, sensitivity studies investigate the impact on fracture propagation of parameters such as pumping rate (PR), fluid viscosity, and Young's modulus (YM). We investigated the fracture width near the junction between a vertical fracture and the BPs, the latter including the tensile opening of BPs and shear–displacement discontinuities (SDDs) along them. SDDs along BPs increase at the beginning and then decrease at a distance from the junction. The width near the junctions, the opening of BPs, and SDDs along the planes are directly proportional to PR. Because viscosity increases, the width at a junction increases as do the SDDs. YM greatly influences the opening of BPs at a junction and the SDDs along the BPs. This model estimates the fracture–width distribution and the SDDs along the BPs near junctions between the fracture tip and BPs and enables the assessment of the PR required to ensure that the fracture width at junctions and along intersected BPs is sufficient for proppant transport.

Some Effects of Stress, Friction, and Fluid Flow on Hydraulic Fracturing

1982 ◽  
Vol 22 (03) ◽  
pp. 321-332 ◽  
Author(s):  
M.E. Hanson ◽  
G.D. Anderson ◽  
R.J. Shaffer ◽  
L.D. Thorson
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Research Program ◽  
In Situ Stress ◽  
Material Interfaces ◽  
Fracture Geometry ◽  
Funded Research ◽  
Fracturing Process

Abstract We are conducting a U.S. DOE-funded research program aimed at understanding the hydraulic fracturing process, especially those phenomena and parameters that strongly affect or control fracture geometry. Our theoretical and experimental studies consistently confirm the well-known fact that in-situ stress has a primary effect on fracture geometry, and that fractures propagate perpendicular to the least principal stress. In addition, we find that frictional interfaces in reservoirs can affect fracturing. We also have quantified some effects on fracture geometry caused by frictional slippage along interfaces. We found that variation of friction along an interface can result in abrupt steps in the fracture path. These effects have been seen in the mineback of emplaced fractures and are demonstrated both theoretically and in the laboratory. Further experiments and calculations indicate possible control of fracture height by vertical change in horizontal stresses. Preliminary results from an analysis of fluid flow in small apertures are discussed also. Introduction Hydraulic fracturing and massive hydraulic fracturing (MHF) are the primary candidates for stimulating production from tight gas reservoirs. MHF can provide large drainage surfaces to produce gas from the low- permeability formation if the fracture surfaces remain in the productive parts of the reservoir. To determine whether it is possibleto contain these fractures in the productive formations andto design the treatment to accomplish this requires a much broader knowledge of the hydraulic fracturing process. Identification of the parameters controlling fracture geometry and the application of this information in designing and performing the hydraulic stimulation treatment is a principal technical problem. Additionally, current measurement technology may not be adequate to provide the required data. and new techniques may have to be devised. Lawrence Livermore Natl. Laboratory has been conducting a DOE-funded research program whose ultimate goal is to develop models that predict created hydraulic fracture geometry within the reservoir. Our approach has been to analyze the phenomenology of the fracturing process to son out and identify those parameters influencing hydraulic fracture geometry. Subsequent model development will incorporate this information. Current theoretical and stimulation design models are based primarily on conservation of mass and provide little insight into the fracturing process. Fracture geometry is implied in the application of these models. Additionally, pressure and flow initiation in the fractures and their interjection with the fracturing process is not predicted adequately with these models. We have reported previously on some rock-mechanics aspects of the fracturing process. For example, we have studied, theoretically and experimentally, pressurized fracture propagation in the neighborhood of material interfaces. Results of interface studies showed that natural fractures in the interfacial region negate any barrier effect when the fracture is propagating from a lower modulus material toward a higher modulus material. On the other hand, some fracture containment could occur when the fracture is propagating from a higher modulus into a lower modulus material. Effect of moduli changes on the in-situ stress field have to be taken into consideration to evaluate fracture containment by material interfaces. Some preliminary analyses have been performed to evaluate how stress changes when material properties change, but we have not evaluated this problem fully. SPEJ P. 321^

Acoustic velocity and permeability of acidized and propped fractures in shale

Geophysics ◽  
2021 ◽  
pp. 1-55
Author(s):  
Jihui Ding ◽  
Anthony C. Clark ◽  
Tiziana Vanorio ◽  
Adam D. Jew ◽  
John R. Bargar
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracturing ◽  
Seismic Velocity ◽  
Rock Physics ◽  
Elastic Stiffness ◽  
Acoustic Velocity ◽  
S Wave ◽  
Fracture Permeability ◽  
Mechanical Fracture ◽  
Flow Pathways

From geochemical reactions to proppant emplacement, hydraulic fracturing induces various chemo-mechanical fracture alterations in shale reservoirs. Hydraulic fracturing through the injection of a vast amount and variety of fluids and proppants has substantial impacts on fluid flow and hydrocarbon production. There is a strong need to improve our understanding on how fracture alterations affect flow pathways within the stimulated rock volume and develop monitoring tools. We conducted time-lapse rock physics experiments on clay-rich (carbonate-poor) Marcellus shales to characterize the acoustic velocity and permeability responses to fracture acidizing and propping. Acoustic P- and S-wave velocities and fracture permeability were measured before and after laboratory-induced fracture alterations along with microstructural imaging through X-ray computed tomography and scanning electron microscopy. Our experiments show that S-wave velocity is an important geophysical observable, particularly the S-wave polarized perpendicular to fractures since it is sensitive to fracture stiffness. The acidizing and propping of a fracture both decrease its elastic stiffness. This effect is stronger for acidizing, and so it is possible that proppant monitoring will be masked by chemical alteration except when propping is highly efficient (i.e., most fractures are propped). However, fracture permeability is undermined by the softening of fracture surfaces due to acidizing, while greatly enhanced by propping. These contrasting effects on fluid flow in combination with similar seismic attributes indicate the importance of experiments to improve existing rock physics models, which must include changes to the rock frame. Such improvements are necessary for a correct interpretation of seismic velocity monitoring of flow pathways in stimulated shales.

A Study of Proppant Transport With Fluid Flow in a Hydraulic Fracture

2018 ◽  
Vol 33 (04) ◽  
pp. 307-323 ◽  
Author(s):  
Christopher A. J. Blyton ◽  
Deepen P. Gala ◽  
Mukul M. Sharma
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Proppant Transport

scholarly journals Lattice Numerical Simulations of Hydraulic Fracture Propagation and Their Geometry Evolution in Transversely Isotropic Formations

2021 ◽  
Vol 9 ◽  
Author(s):  
Dezhi Qiu ◽  
Jun Zhang ◽  
Yinhe Lin ◽  
Jinchuan Liu ◽  
Minou Rabiei ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Numerical Models ◽  
Fractured Reservoirs ◽  
Fracture Propagation ◽  
Propagation Mechanism ◽  
Fracture Aperture ◽  
Natural Interfaces ◽  
Fracture Geometry ◽  
Hf Propagation ◽  
The Impact

Accurate prediction of the fracture geometry before the operation of a hydraulic fracture (HF) job is important for the treatment design. Simplified planar fracture models, which may be applicable to predict the fracture geometry in homogeneous and continuous formations, fail in case of fractured reservoirs and laminated formations such as shales. To gain a better understanding of the fracture propagation mechanism in laminated formations and their vertical geometry to be specific, a series of numerical models were run using XSite, a lattice-based simulator. The results were studied to understand the impact of the mechanical properties of caprock and injection parameters on HF propagation. The tensile and shear stimulated areas were used to determine the ability of HF to propagate vertically and horizontally. The results indicated that larger caprock Young’s modulus increases the stimulated area (SA) in both vertical and horizontal directions, whereas it reduces the fracture aperture. Also, larger vertical stress anisotropy and tensile strength of caprock and natural interfaces inhibit the horizontal fracture propagation with an inconsiderable effect in vertical propagation, which collectively reduces the total SA. It was also observed that an increased fluid injection rate suppresses vertical fracture propagation with an insignificant effect on horizontal propagation. The dimensionless parameters defined in this study were used to characterize the transition of HF propagation behavior between horizontal and vertical HFs.

Hydraulic fracture diagnostics from Krauklis-wave resonance and tube-wave reflections

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. D171-D186 ◽  
Author(s):  
Chao Liang ◽  
Ossian O’Reilly ◽  
Eric M. Dunham ◽  
Dan Moos
Keyword(s):  
Hydraulic Fracture ◽  
Guided Waves ◽  
Navier Stokes ◽  
Fracture Aperture ◽  
Navier Stokes Equation ◽  
Fracture Geometry ◽  
Hydraulic Impedance ◽  
Resonance Frequencies ◽  
Tube Wave ◽  
Viscous Boundary

Fluid-filled fractures support guided waves known as Krauklis waves. The resonance of Krauklis waves within fractures occurs at specific frequencies; these frequencies, and the associated attenuation of the resonant modes, can be used to constrain the fracture geometry. We use numerical simulations of wave propagation along fluid-filled fractures to quantify fracture resonance. The simulations involve solution of an approximation to the compressible Navier-Stokes equation for the viscous fluid in the fracture coupled to the elastic-wave equation in the surrounding solid. Variable fracture aperture, narrow viscous boundary layers near the fracture walls, and additional attenuation from seismic radiation are accounted for in the simulations. We then determine how tube waves within a wellbore can be used to excite Krauklis waves within fractures that are hydraulically connected to the wellbore. The simulations provide the frequency-dependent hydraulic impedance of the fracture, which can then be used in a frequency-domain tube-wave code to model tube-wave reflection/transmission from fractures from a source in the wellbore or at the wellhead (e.g., water hammer from an abrupt shut-in). Tube waves at the resonance frequencies of the fracture can be selectively amplified by proper tuning of the length of a sealed section of the wellbore containing the fracture. The overall methodology presented here provides a framework for determining hydraulic fracture properties via interpretation of tube-wave data.

Numerical Study on Proppant Transport in Hydraulic Fractures Using a Pseudo-3D Model for Multilayered Reservoirs

SPE Journal ◽  
2021 ◽  
pp. 1-16
Author(s):  
Xi Zhang ◽  
Lifeng Yang ◽  
Dingwei Weng ◽  
Zhen Wang ◽  
Robert G. Jeffrey
Keyword(s):  
Hydraulic Fracture ◽  
Transport Model ◽  
Numerical Study ◽  
Soft Rock ◽  
Injection Pressure ◽  
Field Measurements ◽  
Fracture Plane ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Proppant Transport

Summary In this paper, we incorporated a kinematic proppant transport model for spherical suspensions in hydraulic fractures developed by Dontsov and Peirce (2014) in a pseudo-3D hydraulic-fracture simulator for multilayered rocks to capture a different proppant transport speed than fluid flow and abridged fracture channel by highly concentrated suspensions. For pressure-driven proppant transport, the bridges made of compact proppant particles can lead to both proppant distribution discontinuity and increased fracture aperture and height because of the higher pressure. The model is applied to growth of a fracture from a vertical well, which can contain thin-bedded intervals and more than one opened hydraulic-fracture interval, because the fracture plane extends in height through layers with contrasts in stress and material properties. Three numerical examples demonstrate that a loss of vertical connectivity can occur among multiple fracture sections, and proppant particles are transported along the more compliant layers. The proppant migration within a narrow fracture in a thin soft rock layer can result in bridging and formation of a proppant plug that strongly limits fluid speed. This generates an increase of injection pressure associated with fracture screenout, and these screenout events can emerge at different places along the fracture. Next, because of the lack of pretreatment geomechanical data, the values of layer stress and leakoff coefficient are adjusted for a field case so that the varying bottomhole pressure and fracture length are in line with the field measurements. This paper provides a useful illustration for hydraulic-fracturing treatments with proppant transport affected by and interacting with reservoir lithological complexities.

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