Propagation, proppant transport and the evolution of transport properties of hydraulic fractures

2018 ◽  
Vol 855 ◽  
pp. 503-534 ◽  
Author(s):  
Jiehao Wang ◽  
Derek Elsworth ◽  
Martin K. Denison
Keyword(s):  
Preferential Flow ◽  
Fluid Pressure ◽  
Fracture Propagation ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Fluid Viscosity ◽  
Fracture Conductivity ◽  
Proppant Transport ◽  
Fracture Closure ◽  
Proppant Embedment

Hydraulic fracturing is a widely used method for well stimulation to enhance hydrocarbon recovery. Permeability, or fluid conductivity, of the hydraulic fracture is a key parameter to determine the fluid production rate, and is principally conditioned by fracture geometry and the distribution of the encased proppant. A numerical model is developed to describe proppant transport within a propagating blade-shaped fracture towards defining the fracture conductivity and reservoir production after fracture closure. Fracture propagation is formulated based on the PKN-formalism coupled with advective transport of an equivalent slurry representing a proppant-laden fluid. Empirical constitutive relations are incorporated to define rheology of the slurry, proppant transport with bulk slurry flow, proppant gravitational settling, and finally the transition from Poiseuille (fracture) flow to Darcy (proppant pack) flow. At the maximum extent of the fluid-driven fracture, as driving pressure is released, a fracture closure model is employed to follow the evolution of fracture conductivity with the decreasing fluid pressure. This model is capable of accommodating the mechanical response of the proppant pack, fracture closure of potentially contacting rough surfaces, proppant embedment into fracture walls, and most importantly flexural displacement of the unsupported spans of the fracture. Results show that reduced fluid viscosity increases the length of the resulting fracture, while rapid leak-off decreases it, with both characteristics minimizing fracture width over converse conditions. Proppant density and size do not significantly influence fracture propagation. Proppant settling ensues throughout fracture advance, and is accelerated by a lower viscosity fluid or greater proppant density or size, resulting in accumulation of a proppant bed at the fracture base. ‘Screen-out’ of proppant at the fracture tip can occur where the fracture aperture is only several times the diameter of the individual proppant particles. After fracture closure, proppant packs comprising larger particles exhibit higher conductivity. More importantly, high-conductivity flow channels are necessarily formed around proppant banks due to the flexural displacement of the fracture walls, which offer preferential flow pathways and significantly influence the distribution of fluid transport. Higher compacting stresses are observed around the edge of proppant banks, resulting in greater depths of proppant embedment into the fracture walls and/or an increased potential for proppant crushing.

High-Resolution and Multimaterial Fracture Productivity Calculator for the Successful Design of Channel Fracturing Jobs

2021 ◽  
Author(s):  
Dimitry Chuprakov ◽  
Ludmila Belyakova ◽  
Ivan Glaznev ◽  
Aleksandra Peshcherenko
Keyword(s):  
High Resolution ◽  
Effective Conductivity ◽  
Productivity Index ◽  
Hydraulic Fractures ◽  
Total Production ◽  
Fracture Conductivity ◽  
Hindered Settling ◽  
Accurate Evaluation ◽  
Skin Factor ◽  
Fracture Closure

Abstract We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy. We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life. We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.

Laboratory Experiments in Fracture Propagation

1984 ◽  
Vol 24 (03) ◽  
pp. 256-268 ◽  
Author(s):  
W.L. Medlin ◽  
L. Masse
Keyword(s):  
Hydraulic Fracturing ◽  
Fracture Propagation ◽  
Fluid Viscosity ◽  
Confining Stress ◽  
Fracture Width ◽  
Metal Plates ◽  
Fracture Closure ◽  
Crack Volume ◽  
Aluminum Plates ◽  
Fracturing Experiments

Abstract This paper describes fracturing experiments in dry blocks of various rock materials. The results have application to evaluation of hydraulic fracturing theories. The block dimensions were 3 in.×4 in.×12 in. [7.6 cm×10.2 cm×30.5 cm] with metal plates epoxied to the 3-in.×12-in. [7.6-cm×30.5-cm] faces. Remaining faces were coated with soft epoxy to provide an impermeable jacket. The blocks were loaded in a pressure cell with an upper movable piston bearing on the 3-in.×4-in. [7.6-cm×10.2-cm] faces. A servo-controlled press applied constant stress to these faces higher than a lateral confining stress applied by oil pressure. Fractures were initiated by injection of various fluids into a small notch located on a center plane parallel to the 4-in.×12-in. [10.2-cm×30.5-cm] faces. Fracture growth along the same plane was assured by the stress conditions. Use of these experiments to test theories of fracture propagation required measurement of three variables, fracture width bi, and propagation pressure pi at the notch entrance, and fracture length, L. bi was determined by a capacitance method, and pi was measured directly by a pressure transducer. L was measured by two methods - either ultrasonic signals or pressure pulses generated in miniature cavities. The ultrasonic method confirmed the existence of a Barenblatt liquid-free crack ahead of the liquid front whose relative length decreased with confining stress. The metal plates bonded to the 3-in.×4-in. [7.6-cm×10.2-cm] faces prevented slip at the top and bottom of the fracture, giving a three-dimensional (3D) crack of constant height. However, the bi, pi, and L data followed trends predicted by two-dimensional (2D) (plane strain) elastic theory reasonably well. Fracture closure measurements after shut-in showed an initial period of leakoff-controlled closure and a final period of creep-controlled closure. A pi slope change at the transition is identified with the instantaneous shut-in pressure (ISIP) in field records and is higher than the true confining stress. Introduction Methods of predicting crack dimensions during fracturing operations are essential to proper design of field treatments. Many fracture-propagation theories have been advanced. Contributions have been made by Barenblatt,1 Khristianovitch and Zheltov,4,5 Howard and Fast,6 Perkins and Kern,7 LeTirant and Dupuy,8 Nordgren,9 Geertsma and de Klerk,10 Daneshy,11 and Cleary12,13 among others. However, practical methods of evaluating the theoretical work have been few. Mostly they have been. limited to indirect and generally inconclusive field evaluations. The Sandia mineback experiments14–16 have provided more direct evaluations. However, even here important fracturing parameters are uncontrolled or unknown. This paper describes laboratory-scale hydraulic fracturing experiments that provide critical data for evaluating crack propagation theories. In these experiments we measured the fundamental variables of crack growth under controlled conditions with known fracturing parameters. Experimental Methods All fracturing experiments were carried out in dry blocks 3 in.×4 in.×12 in. [7.6 cm×10.2 cm×30.5 cm] in size. Mesa Verde sandstone and Carthage and Lueders limestone were used as sample materials. Scaling considerations were important. It was necessary to scale down injection rate and leakoff to be consistent with fracture dimensions. The scaling factor of importance was taken to be fluid efficiency, the ratio of crack volume to injected volume. This factor was controlled through appropriate combinations of sample permeability and fracturing fluid viscosity. As fracturing fluids we used thick grease, hydraulic oils of various viscosities, and gelled kerosene (Dowell's YFGO™). Fluid efficiencies ranged from 3 to 70%. Most experiments were conducted at efficiencies between 30 and 50 %, a range typical of most field treatments. Fig. 1 shows the experimental arrangement. Shaped aluminum plates were bonded with Hysol clear epoxy to the 3-in.×12-in. [7.6-cm×30.5-cm] faces of the sample block as shown. The remaining faces were coated with a thin layer of the same epoxy to provide an impermeable jacket for confining pressure. One of the aluminum plates contained an injection port communicating with a 1.4-in. [0.64-cm] borehole as illustrated. A pair of brass plates with faces 0.2 in.×0.5 in. [0.5 cm×1.3 cm] was epoxied into the borehole at its center. These plates, separated by a gap of 0.01 in. [0.025 cm] served as a parallel plate capacitor. They were connected to a capacitance bridge that detected changes in gap width through changes in capacitance. This provided a direct, continuous measurement of fracture width at the borehole.

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 History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

Energies ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1634 ◽  
Author(s):  
Juhyun Kim ◽  
Youngjin Seo ◽  
Jihoon Wang ◽  
Youngsoo Lee
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Gas Flow ◽  
Fluid Pressure ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Fracture Closure

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs.

Hydraulic Fracture Propagation in Layered Formations

1978 ◽  
Vol 18 (01) ◽  
pp. 33-41 ◽  
Author(s):  
A.A. Daneshy
Keyword(s):  
Mechanical Properties ◽  
Material Properties ◽  
General Trend ◽  
Elliptic Integral ◽  
Fluid Pressure ◽  
Fracture Propagation ◽  
Physical And Mechanical Properties ◽  
Hydraulic Fractures ◽  
Complete Elliptic Integral ◽  
Propagation Result

Abstract This paper reports theoretical and experimental developments involving propagation of hydraulic fractures in layered formations. Unobstructed fractures are shown experimentally to propagate with a decreasing fracturing fluid pressure. This general trend is in agreement with pressure. This general trend is in agreement with theoretical predictions. Restrictions in fracture propagation result in an increase in fluid pressure. propagation result in an increase in fluid pressure. The relative fracturability of rocks can be determined by a direct experiment, the results of which are clear, easy to interpret, and include all pertinent parameters, such as physical and pertinent parameters, such as physical and mechanical properties of rocks, as well as the reactions between formation and fracturing fluid (for example, leak-off). Fracturing experiments with layered samples show that with strong bonding between rocks it is difficult to contain a fracture in a formation totally. The strength of the interface between adjacent formations is shown theoretically to be an important factor in fracture containment. With a weak bonding, fracture containment is possible and is associated with slippage at the interface. The pattern of propagation then will depend on the relative propagation then will depend on the relative mechanical properties of fractured formations. Introduction Most industrial hydraulic fractures are created in layered formations. During propagation, these fractures encounter various formations with different physical and mechanical properties. This paper physical and mechanical properties. This paper discusses the effect of those properties on propagation of the fracture. propagation of the fracture.Most of the theoretical studies on fracture propagation have been extensions of Griffith's propagation have been extensions of Griffith's work. Based on an energy criterion, Griffith developed a relationship among fracture shape, material properties, and the external force needed for fracture propagation. The energy source in hydraulic fracturing is the fluid pressure inside the fracture. The relationship between this pressure and material properties is (1) (2) in which L = fracture extent (length of a two-dimensionalfracture or radius of a penny-shapedfracture) E = Young's modulus of material mu = Poisson's ratio of material gamma = effective fracture surface energy of material sigma = least in-situ principal stress A similar equation for a three-dimensional fracture is derived in Appendix A in the form of (3) in which hf = fracture height E(k) = complete elliptic integral of the secondkind K(k) = complete elliptic integral of the first kind k = parameter of the elliptic integrals Eqs. 1 through 3 show p to decrease with increasing L (Fig. 1) As the fracture becomes larger, it needs less pressure for propagation. In deriving these equations, no allowance has been made for fluid leak-off into the formation. SPEJ P. 33

scholarly journals Influence of proppant physical properties on sand accumulation in hydraulic fractures

2021 ◽  
Author(s):  
Jiangtao Li ◽  
Jianguang Wei ◽  
Xiaofeng Zhou ◽  
Ao Zhang ◽  
Ying Yang ◽  
...  
Keyword(s):  
Physical Properties ◽  
Fluid Model ◽  
Experimental Simulation ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Equal Proportion ◽  
Particle Sedimentation ◽  
Fracture Closure ◽  
Sand Accumulation ◽  
Two Fluid Model

AbstractThe proppant accumulation form in fractures is related to the formation conductivity after fracture closure, also closely related to the production rate of oil/gas wells. In order to investigate the influence of proppant physical properties on sand accumulation in fractures, a particle–fluid coupling flow model is established based on the Euler two-fluid model. Geometric parameters of a fracture in tight oil wells are approximately scaled in equal proportion as the physical model, which is solved by the finite volume method. And the model accuracy is verified by comparing with the physical experimental simulation in the literature. Results show that the higher proppant concentration corresponds to the faster particle sedimentation rate, and the greater sand embankment accumulation as well. However, the fluid viscosity will increase, inhibiting proppant migration to the deep part of the fracture. Reducing proppant density and particle size will enhance the fluidization ability of particles, which is conducive to the migration to the deep fracture at the initial stage of pumping. But, it is not beneficial to have a desirable accumulation state in the middle and later pumping stage, so it is difficult to obtain a higher comprehensive equilibrium height.

scholarly journals Assessing the effect of proppant compressibility on the conductivity of heterogeneously propped hydraulic fracture

2021 ◽  
Vol 2057 (1) ◽  
pp. 012078
Author(s):  
A M Skopintsev
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Production Performance ◽  
Fracture Aperture ◽  
Strong Impact ◽  
Gas Reservoirs ◽  
Fracture Conductivity ◽  
Fracture Closure ◽  
Oil And Gas Reservoirs ◽  
Treatment Design

Abstract Hydraulic fracturing is a technology that is widely used in the development of oil and gas formations. Given that the fracture closure has a strong impact on production, quantifying the resulting fracture conductivity is critical for optimizing treatment design. The goal of this paper is to better understand the influence of the closing stress on the fracture conductivity when the proppant distribution is heterogeneous. In addition to the spatial proppant distribution, the conductivity of the propped fracture is affected by proppant deformation and embedment. Numerical results indicate that compressibility of proppant can significantly change the residual fracture aperture and, consequently, production performance in oil and gas reservoirs

Proppant Transport? Viscosity Is Not All It's Cracked Up To Be

2015 ◽  
Author(s):  
A.M.. M. Gomaa ◽  
D.V.S.. V.S. Gupta ◽  
P.. Carman
Keyword(s):  
Shear Stress ◽  
Hydraulic Fracturing ◽  
Main Tool ◽  
Solid Material ◽  
Viscosity Reduction ◽  
Fluid Viscosity ◽  
Fracture Conductivity ◽  
Proppant Transport ◽  
Two Fluids ◽  
Fluid Elasticity

Abstract Post-treatment production analyses for hydraulic fracturing treatments with conventional crosslinked gel often indicate that the treatments do not achieve the designed stimulation effectiveness, which could be attributed to non-optimal proppant placement and/or significantly damaged fracture conductivity. Although conventional crosslinked fluids are observed to provide good proppant suspension in laboratory environments, they might not provide the desired proppant transport under downhole conditions. Crosslinked fluids are known to be difficult to clean up, and thus are notorious for imparting gel damage to proppant pack and formation. Surfactant gels have been developed to mitigate some of the issues. Viscosity measurements are used as the main tool to judge and optimize the performance of both polymer and surfactant based fracture fluids, especially their ability to transport proppant. While efficient proppant transport is essential for successful hydraulic fracturing, recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. The objective of the paper is to investigate and determine the minimum rheological properties required for efficient proppant transport. Thus, combinations of rotational and oscillatory measurements were conducted to better predict the proppant transport characteristics. Also, proppant settling tests were conducted at static and dynamic conditions. A strong correlation was established between fluid's elasticity and its ability to suspend the proppant with a required minimum elastic modulus (G') value to be greater than viscous modulus (G”). Experimental results show that for two fluids that both have a close viscosity value (similar power law parameters); one fluid with G'>G” while the other one G'< G”, the fluid that has G'>G” behaves as semi-solid material where it deforms instead of flowing when shear stress is applied, while the fluid that has G”>G', flows when shear stress is applied and time to flow depends on viscosity. A proppant particle in a fluid undergoes shear stress due to its density. Therefore, for the fluid G”>G', proppant settles as the fluid moves around it and the speed of settling depends on fluid viscosity, whereas for the elastic fluid (G'>G”), fluid elasticity does not allow the proppant to settle. This observation was confirmed for both polymer and surfactant based fracturing fluids. Additives can be divided into categories that may enhance or reduce fluid elasticity based on their effect on the internal structure of the fluids. For example, breakers tend to significantly reduce the fluid elasticity, even when viscosity reduction is minimized. Data obtained from this study can be used as a guideline to optimize and select the fluid that has ability to carry proppant for field treatment design.

On the Application of the Channel-Fracturing Technique to Soft Rock Formations

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 395-412 ◽  
Author(s):  
Aditya Khanna ◽  
Andrei Kotousov ◽  
Hao Thanh Luong
Keyword(s):  
Parametric Study ◽  
Analytical Approach ◽  
Volume Fraction ◽  
Effective Conductivity ◽  
Soft Rock ◽  
Open Channels ◽  
Hydraulic Fractures ◽  
Fracture Conductivity ◽  
Rock Formations ◽  
Fracture Closure

Summary The application of the channel-fracturing technique can result in a significant increase in the conductivity of hydraulic fractures and reduced proppant usage. In soft rock formations, the conductivity of the partially propped fractures would depend not only on the volume fraction of the open channels, but also on the elastic deformation of open channels and fracture closure resulting from proppant consolidation and embedment. In this study, an analytical approach is developed for identifying the optimal proppant column spacing that maximizes the effective conductivity. The latter parameter can guide the design of the proppant-injection schedule and well-perforation scheme. To demonstrate the approach, we conduct a parametric study under realistic field conditions and identify the folds of increase in fracture conductivity and reduction in proppant use resulting from the optimized application of the channel-fracturing technique. The outcomes of the parametric study could be particularly useful in the application of the developed approach to soft rock formations.

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