Modelling of hydraulic fracturing and fluid flow change in saturated porous domains

Abstract Hydraulic fracturing or fracking is a procedure used extensively by oil and gas companies to extract natural gas or petroleum from unconventional sources. During this process, a pressurized liquid is injected into wellbores to generate fractures in rock formations to create more permeable pathways in low permeability rocks that hold the oil. To keep the rock fractures open after removing the high pressure, proppant, which typically are sands with different shapes and sizes, are injected simultaneously with the fracking fluid to spread them throughout rock fractures. The extraction productivity from shale reservoirs is significantly affected by the performance and quality of the proppant injection process. Since these processes occur under the ground and in the rock fractures, using experimental investigations to examine the process is challenging, if not impossible. Therefore, employing numerical tools for analyzing the process could provide significant insights leading to the fracking process improvement. Accordingly, in this investigation, a 4-way coupled Computational Fluid Dynamic and Discrete Element Method (CFD-DEM) code was used to simulate proppant transport into a numerically generated realistic rock fracture geometry. The simulations were carried out for a sufficiently long period to reach the fractures’ steady coverage by proppant. The proppant fracture coverage is a distinguishing factor that can be used to assess the proppant injection process quality. A series of simulations with different proppant sizes as well as various fracking fluid flow rates, were performed. The corresponding estimated fracture coverages for different cases were compared. The importance of proppant size as well as the fluid flow rate on the efficiency of the proppant injection process, were evaluated and discussed.

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Nonlinear Autoregressive Neural Networks to Predict Hydraulic Fracturing Fluid Leakage into Shallow Groundwater

Water ◽

10.3390/w12030841 ◽

2020 ◽

Vol 12 (3) ◽

pp. 841 ◽

Cited By ~ 2

Author(s):

Reza Taherdangkoo ◽

Alexandru Tatomir ◽

Mohammad Taherdangkoo ◽

Pengxiang Qiu ◽

Martin Sauter

Keyword(s):

Neural Networks ◽

Fluid Flow ◽

Hydraulic Fracturing ◽

Flow Rate ◽

Shallow Groundwater ◽

Fluid Flow Rate ◽

Shallow Aquifers ◽

Fracturing Fluid ◽

Upward Migration ◽

Nonlinear Autoregressive

Hydraulic fracturing of horizontal wells is an essential technology for the exploitation of unconventional resources, but led to environmental concerns. Fracturing fluid upward migration from deep gas reservoirs along abandoned wells may pose contamination threats to shallow groundwater. This study describes the novel application of a nonlinear autoregressive (NAR) neural network to estimate fracturing fluid flow rate to shallow aquifers in the presence of an abandoned well. The NAR network is trained using the Levenberg–Marquardt (LM) and Bayesian Regularization (BR) algorithms and the results were compared to identify the optimal network architecture. For NAR-LM model, the coefficient of determination (R2) between measured and predicted values is 0.923 and the mean squared error (MSE) is 4.2 × 10−4, and the values of R2 = 0.944 and MSE = 2.4 × 10−4 were obtained for the NAR-BR model. The results indicate the robustness and compatibility of NAR-LM and NAR-BR models in predicting fracturing fluid flow rate to shallow aquifers. This study shows that NAR neural networks can be useful and hold considerable potential for assessing the groundwater impacts of unconventional gas development.

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Initiation and Extension of Hydraulic Fractures in Rocks

Society of Petroleum Engineers Journal ◽

10.2118/1710-pa ◽

1967 ◽

Vol 7 (03) ◽

pp. 310-318 ◽

Cited By ~ 271

Author(s):

Bezalel Haimson ◽

Charles Fairhurst

Keyword(s):

Fluid Flow ◽

Hydraulic Fracturing ◽

Cross Section ◽

Elastic Constants ◽

Fluid Pressure ◽

Principal Stresses ◽

Regional Stress ◽

Flow Through ◽

Elastic Rock ◽

Regional Stresses

Abstract A criterion is proposed for the initiation of vertical hydraulic fracturing taking into consideration the three stress fields around the wellbore. These fields arise fromnonhydrostatic regional stresses in earththe difference between the fluid pressure in the wellbore and the formation fluid pressure andthe radial fluid flow through porous rock from the wellbore into the formation due to this pressure difference. The wellbore fluid pressure required to initiate a fracture (assuming elastic rock and a smooth wellbore wall) is a function o/ the porous elastic constants of the rock, the two unequal horizontal principal regional caresses, the tensile strength of the rock and the formation fluid pressure. A constant injection rate will extend the fracture to a point where equilibrium is reached and then, to keep the fracture open, the pressure required is a function of the porous elastic constants of the rock, the component of the regional stress normal to the plane of the fracture, the formation fluid pressure and the dimensions of the crack. The same expression may also be used to estimate the vertical fracture width, provided all other variables are known. The derived equations for the initiation and extension pressures in vertical fracturing may be employed to solve for the two horizontal, regional, principal stresses in the rock. Introduction Well stimulation by hydraulic fracturing is a common practice today in the petroleum industry. However, this stimulation process is not a guaranteed success; hence, the deep interest shown by the petroleum companies in better 'understanding the mechanism that brings about rock fracturing, fracture extension and productivity increase. Geologists and mining people became interested in hydraulic fracturing from a different point of view: the method may possibly be employed to determine the magnitude and direction of the principal stresses of great depth. Numerous articles in past years have dealt with the theory of hydraulic fracturing, but they all seem to underestimate the effect of stresses around the wellbore due to penetration of some of the injected fluid into the porous formation. Excellent papers on stresses in porous materials due to fluid flow have been published but no real attempt has been made to show the effect of these stresses in the form of a more complete criterion for vertical hydraulic fracturing initiation and extension. This paper is such an attempt. ASSUMPTIONS It is assumed that rock in the oil-bearing formation is elastic, porous, isotropic and homogeneous. The formation is under a nonhydrostatic state of regional stress with one of the principal regional stresses acting parallel to the vertical axis of the wellbore. This assumption is justified in areas where rock formations do not dip at steep angles and where the surface of the earth is relatively flat. This vertical principal regional stress equals the pressure of the overlying rock, i.e. S33= -pD where S33 is the total vertical principal stress (positive for tension), p is average density of the overlying material and D is the depth of the point where S 33 is calculated. The wellbore wall in the formation is considered to be smooth and circular in cross-section. The fluid flow through the porous elastic rock obeys Darcy's law. The whole medium is looked upon as an infinitely long cylinder with its axis along the axis of the wellbore. The radius of the cylinder is also very large. Over the range of depth at which the oil-bearing formation occurs, it will be assumed that any horizontal cross-section of the cylinder is subjected to the same stress distribution, and likewise that it will deform in the same manner. SPEJ P. 310ˆ

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Modeling hydraulic fracturing and induced seismicity in unconventional reservoirs using multiphase fluid-flow simulations

10.1190/segam2015-5838538.1 ◽

2015 ◽

Author(s):

Juan E. Santos* ◽

Lucas A. Macias ◽

Gabriela B. Savioli ◽

José M. Carcione

Keyword(s):

Fluid Flow ◽

Hydraulic Fracturing ◽

Induced Seismicity ◽

Unconventional Reservoirs ◽

Flow Simulations ◽

Multiphase Fluid Flow ◽

Multiphase Fluid

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Simulation of Hydraulic Fracturing Processes

Society of Petroleum Engineers Journal ◽

10.2118/7693-pa ◽

1980 ◽

Vol 20 (06) ◽

pp. 487-500 ◽

Cited By ~ 18

Author(s):

A. Settari

Keyword(s):

Heat Transfer ◽

Fluid Flow ◽

Hydraulic Fracturing ◽

Fracture Propagation ◽

Thermal Recovery ◽

Reservoir Rock ◽

Flow And Heat Transfer ◽

Fracture Closure ◽

Fracturing Process

Abstract A mathematical model of the fracturing process, coupling the fracture mechanics and fracture propagation with reservoir flow and heat transfer, has been formulated. The model is applicable to fracturing treatments as well as to high leakoff applications such as fractured waterfloods and thermal fractures. The numerical technique developed is capable of simulating fracture extension for reasonably coarse grids, with truncation error being minimized for high leakoff applications when the grid next to the fracture is approximately square. With the aid of the model, a generalization of Carter's propagation formula has been developed that is also valid for high fluid-loss conditions. The capabilities of the model are illustrated by examples of heat transfer and massive-hydraulic-fracturing (MHF) treatment calculation. Introduction Induced fracturing of reservoir rock occurs under many different circumstances. Controlled hydraulic fracturing is an established method for increasing productivity of wells in low-permeability reservoirs. The technology of fracturing and the earlier design methods are reviewed by Howard and Fast.1 In waterflooding, injection pressures also often exceed fracturing pressures. This may result from poor operational practices, but it also could be intended to increase injectivity.2 In heavy oils, such as Alberta oil sands, most in-situ thermal recovery techniques rely on creating injectivity by fracturing the formation with steam.3 Fracturing also is being used as a method for deterining in-situ stresses4 and for establishing communication between wells for extraction of geothermal energy.5,6 Finally, fractures may be produced by explosive treatment or induced thermal stresses (such as in radioactive waste disposal). To date, most of the research has been directed toward the understanding and design of fracture stimulation treatments, with emphasis on predicting fracture geometry.7–11 The influence of fluid flow and heat transfer in the reservoir has been neglected or accounted for by various approximations in these methods. On the other hand, the need for reservoir engineering analysis of fractured wells led to the development of analytical techniques and numerical models for predicting postfracture performance.1 A common feature of all these methods is that they treat only stationary fractures, which therefore must be computed using some of the methods of the first category mentioned earlier. With the high costs associated with MHF,17–19 and with increasing complexity of the treatments, it is becoming important to be able to understand the interaction of the physical mechanisms involved and to improve the designs. This paper presents a numerical model of the fracturing process that simultaneously accounts for the rock mechanics, two-phase fluid flow, and heat transfer, both in the fracture and in the reservoir. The model is capable of predicting fracture propagation, fluid leakoff and heat transfer, fracture closure, cleanup, and postfracture performance. Although the detailed calculations of geometry, proppant transport, etc., have not been included, they can be integrated in a natural way within the present model. Because vertical fractures are prevalent except for very shallow depths, the discussion is limited to vertical fracturing. The paper focuses attention on the formulation of the basic model and the numerical techniques in general. Applications to fracturing treatments and the specific enhancements of the model are described in a more recent paper.20

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

Society of Petroleum Engineers Journal ◽

10.2118/9831-pa ◽

1982 ◽

Vol 22 (03) ◽

pp. 321-332 ◽

Cited By ~ 15

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^

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