Competition Between Transverse And Axial Hydraulic Fractures In Horizontal Wells (original) (raw)
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Initiation and growth of a hydraulic fracture from a circular wellbore
International Journal of Rock Mechanics and Mining Sciences, 2011
A two-dimensional (2D) model is presented for initiation and growth of one or more hydraulic fractures from a well that is aligned with either the maximum or intermediate principal in-situ stress. The coupling of fluid flow and rock deformation plays a key role in reorientation and pattern evolution of the fractures formed. After fracture initiation, the fracture can reorient as it extends from the wellbore until it becomes aligned with the preferred direction for fracture growth relative to the far-field stresses. Initiation and growth of multiple fractures are considered to study their interaction and competition with each other. In such cases, some fractures are unable to extend at all or they arrest after some limited growth, but others can grow in length relative to earlier developed fractures. For fractures that are driven by a uniformly distributed internal pressure, which implies injection of an inviscid fluid, fracture closure may occur at the portion of the fracture path adjacent to the wellbore. This local fracture closure does not typically occur when fluid viscous dissipation is introduced, but the local width is greatly reduced and a fluid lag zone develops. The reduced fracture width results in fluid viscous friction and an associated pressure drop near the wellbore, which makes fracture stimulation more expensive and less successful and may reduce well productivity. Initiation of a fracture using a viscous fluid and a higher injection rate causes the fracture to curve more gradually as it seeks to align with the maximum principal stress direction, a result from our model that is consistent with widely used tortuosity remedy methods. A dimensionless parameter is developed that is shown to characterise near wellbore reorientation and curving of hydraulic fractures driven by viscous
The Geomechanical Interaction of Multiple Hydraulic Fractures in Horizontal Wells
The technology of multiple hydraulic fracture stimulation in horizontal wells has transformed the business of oil and gas exploitation from extremely tight, unconventional hydrocarbon bearing rock formations. The fracture stimulation process typically involves placing multiple fractures stage-by-stage along the horizontal well using diverse well completion technologies. The effective design of such massive fracture stimulation requires an understanding of how multiple hydraulic fractures would grow and interact with each other in heterogeneous formations. This is especially challenging as the interaction of these fractures are subject to the dynamic process of subsurface geomechanical stress changes induced by the fracture treatment itself. This paper consists of two parts. Firstly, an idealised analytical model is used to highlight some key features of multiple hydraulic fractures interaction, and to provide a quantification of 'stress shadow'. Secondly, a new non-planar three dimensional (3D) hydraulic fracturing numerical model is used to provide an insight into the growth of multiple fractures under the influence of subsurface geomechanical stress shadows. Attention is given to studying the height growth of multiple fractures.
Interaction of Multiple Hydraulic Fractures in Horizontal Wells
All Days, 2013
The use of multi-fracced horizontal well technology in unconventional gas and liquid rich reservoirs is one of the key reasons for the recent success in the exploitation of Unconventional Resources. These multiple fractures are placed in many stages along the horizontal well using diverse completion technologies. Yet, the understanding of fracture growth mechanics and the optimum fracture placement design methodology are still preliminary. Recent advances in computational mechanics and the development of appropriate stimulation modeling technology will further nurture innovation and press forward much needed optimization of the Completion and Stimulation technology in multi-fracced horizontal wells. This paper contains two key components. Firstly, an analytical model is used to highlight some of the salient features of multiple hydraulic fractures interaction. The advantage of an analytical model is that it provides immediate insights into the controlling parameters and steer furthe...
Journal of Petroleum Science and Engineering, 2000
Considering the influence of casing, analytical solutions for stress distribution around a cased wellbore are derived, based on which a prediction model for hydraulic fracture initiation with the oriented perforation technique (OPT) is established. Taking well J2 of Z5 oilfield for an example, the predicted initiation pressure with the OPT of our model is about 4.2 MPa higher than the existing model, which neglects the influence of casing. In comparison with the results of laboratory fracturing experiments with OPT on a 400 9 400 9 400 mm 3 rock sample for a cased well with the deviation of 45°, the fracture initiation pressure of our model has an error of 3.2 %, while the error of the existing model is 6.6 %; when the well azimuth angle is 0°a nd the perforation angle is 45°, the prediction error of the fracture initiation pressure of the existing model and our model are 3.4 and 7.7 %, respectively. The study verifies that our model is more applicable for hydraulic fracturing prediction of wells with OPT completion; while the existing model is more suitable for hydraulic fracturing with conventional perforation completion.
MODELING INITIATION OF HYDRAULIC FRACTURES FROM A WELLBORE
ISRM International Symposium 2008, 5th Asian Rock Mechanics Symposium (ARMS5), 24-26 November 2008 Tehran, Iran , 2008
This paper is concerned with the initiation of plane strain hydraulic fractures (HF) from a wellbore in an impermeable homogeneous elastic rock. The fractures are driven by Newtonian fluids injected into the wellbore. The solid deformation is modeled according to linear elasticity, and the viscous fluid flow within the fracture is modeled using lubrication theory. Compressibility effects are introduced though the addition of a fluid pressure-dependent wellbore storage term in the condition on the fluid flow at the fracture inlet. A solution is obtained in terms of fluid net pressure, fracture length, and opening. The problem depends on a dimensionless viscosity and two additional dimensionless parameters, one that is related to the compressibility and the other that is related to the deviatoric in-situ stress. We compute the solution for initiation and the early stages of propagation of a HF using an implicit finite difference scheme with a fixed spatial grid coupled with the displacement discontinuity method. An instability is identified in the problem after breakdown for an inviscid fluid, and results of the numerical simulation indicate that viscosity effects mitigate the initial instability. We also show that the difference between the breakdown (peak) pressure and the fracture initiation pressure increases with the viscosity of the fracturing fluid.
SPE Annual Technical Conference and Exhibition, 2015
Multi-stage hydraulic fracturing together with horizontal drilling plays an important role in the economic development of unconventional reservoirs. However, according to field analysis of stimulation effectiveness, only a small percentage of perforation clusters contribute to most of the well production. One reason for this low effectiveness is that multiple fractures do not take the same amount of fluid and proppant due to fracture interaction (i.e., stress shadow effects). Unfortunately, how best to minimize the negative effects of stress shadowing is still poorly understood in the petroleum industry. In this paper, we analyzed this problem in order to promote more uniform fracture growth using our complex hydraulic fracture development model. We employed our fracture propagation model that couples rock deformation and fluid flow in the fracture and horizontal wellbore. Partitioning of flow rate between multiple fractures was calculated by analogizing to the electric circuit netw...
Hydraulic-Fracture Propagation in a Naturally Fractured Reservoir
SPE Production & Operations, 2011
We present the results of numerical modeling that quantify the physical mechanisms of mechanical activation of a natural fault because of contact with a pressurized hydraulic fracture (HF). We focus on three stages of interactions: HF approaching, contact, and subsequent infiltration of the fault. Fracture interaction at the contact is shown to depend on four dimensionless parameters: net pressure in the HF, in-situ differential stress, relative angle between the natural fault and the HF, and friction angle of the natural fault. A numerical model based on the displacement discontinuity method (DDM) allowing for fracture closure and Mohr-Coulomb friction was used to calculate the displacements and stresses along the natural fracture as a result of the interaction with the pressurized HF. The analysis of the total stress state along the fault during the HF coalescence stage makes it possible to define a criterion for reinitiation of a secondary tensile crack from the natural fault. We show that the most probable location for tensile-crack initiation is the end of the open zone of the fault where the highest tension peak is generated by the HF contact. In our numerical analysis, we study the magnitude of maximum tensile stress and its position along the fault for a wide range of key dimensionless parameters. Given real reservoir properties, these measurements can be used to detect the possible fracturing scenarios in naturally fractured reservoirs. Using simplified uncoupled modeling of fluid penetration into the fault after the contact with the HF, we demonstrate that either an increase or a decrease of the tensile stress at the opposite side of the fault can be realized depending on the ratio of increments of net pressure and the fluid front as it penetrates the natural fault.
Transport in Porous Media, 2015
In this study, we present a mesh-free semi-analytical technique for modeling pressure transient behavior of continuously and discretely hydraulically and naturally fractured reservoirs for a single-phase fluid. In our model, we consider a 3D reservoir, where each fracture is explicitly modeled without any upscaling or homogenization as required for dualporosity media. Fractures can have finite or infinite conductivities, and the formation (matrix) is assumed to have a finite permeability. Our approach is based on the boundary element method. The method has advantages such as the absence of grids and reduced dimensionality. It provides continuous rather than discrete solutions. The uniform-pressure boundary condition over the wellbore is used in our mathematical model. This is the true physical boundary condition for any type of well, whether fractured or not, provided that the friction pressure drop in the wellbore is small and the fluid is Newtonian. The method is sufficiently general to be applied to many different well geometries and reservoir geological settings, where the spatial domain may include arbitrary fracture and/or fault distribution, a number of horizontal wells with and without hydraulic fractures, and different types of outer boundaries. The model also applies to multistage hydraulically fractured horizontal wells in homogenous reservoirs. More specifically, it is applied to investigate the pressure transient behavior of horizontal wells in continuously and discretely naturally fractured reservoirs, including multistage hydraulically fractured horizontal wells. A number of solutions have been published in the literature for horizontal wells in naturally fractured reservoirs using the conventional dual-porosity models that are not applicable to many of these reservoirs that contain horizontal wells with multiple fractures. Most published solutions for fractured horizontal wells in homogenous and naturally fractured reservoirs ignore the presence of the wellbore and the contribution to flow from the formation directly into the unfractured horizontal sections of the wellbore. Therefore, some of the flow regimes from these solutions are incorrect or do not exist, such as fracture-radial flow regime. In our solutions, all or some of multistage hydraulic fractures may intersect the natural fractures, which is very important for shale gas and oil reservoir production. The number and type of fractures (hydraulic or
Journal of Petroleum Science and Engineering, 2020
For maximum productivity enhancement when targeting low permeability formations, horizontal wells must be made to induce multiple transverse fractures. An orientation criterion for fracture initiation is developed using analytically-derived approximations for the longitudinal and transverse fracturing stresses for perforated wellbores from the literature. The validity of the criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; pertaining to low breakdown pressure and low formation tensile strength. A three-dimensional numerical model shows that contrary to existing approximations, the transverse fracturing stress from perforated horizontal wells becomes more compressive as wellbore pressure increases. This shrinks the "breakdown pressure window," which is the range of wellbore pressures over which transverse fracture initiation takes place. This creates a second constraint for transverse fracture initiation, which is the "critical tensile strength" value. This determines the maximum formation tensile strength at which transverse fracture initiation is possible for a given in-situ stress state and perforation direction. Sensitivity analyses are performed based on data from seven unconventional shale reservoirs (Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus and Vaca Muerta) for horizontal wells drilled parallel to S hmin. The frequent longitudinal fracture initiation occurrence indicated suggests fracture reorientation in the near-wellbore region to be a common event, through which the propagating fractures become aligned with the preferred fracture plane (perpendicular to the least compressive principal stress). This induces near-wellbore fluid tortuosity, which in turn can lead to completions and production-related problems, such as early screenouts and poststimulation well underperformance.
Fracture propagation stimulated by hydraulic injection under stress field
Recent Advances in Exploration Geophysics, 2015
Hydraulic fracturing is a major scheme for improving the production of unconventional oil and gas as well as in horizontal wells. Created fractures increase the permeability of reservoir formations, which are usually tight and of low permeability, through a network of fractures in the reservoir. Laboratory experiments indicate that hydraulic fractures would propagate in the direction of the maximum principal stress around the fracture tip. This indicates that in-situ stress could play an important role in the behavior of hydraulic fracture propagation in the field scale. It is, however, difficult to observe the fracture propagation directly due to the depth of the reservoir layer (>2km generally). There are two types of rock failure that are suggested to take place at the hydraulic fracturing, (i) tensile and (ii) shear fractures. In earthquake seismology, we know the latter is dominant in the generation of natural earthquakes. However, the ratio of tensile to shear fracture events induced by the fluid injection has not been well investigated yet due to the small magnitudes of failures. To tackle this problem, we adopted the extended finite element method (X-FEM) and added a new degree of freedom for the effects of the fluid inside fractures. It would bring an idea on how fracture propagates in a stable stress field no matter how the magnitude of each event becomes small. We developed a hydraulic fracturing simulation tool to explore the mechanism of fracture propagation triggered by the fluid injection. For the evaluation of the fracture propagation, we assumed a numerical simulation model in real scale and put external forces as an in-situ stress. We conducted two types of simulations, one homogeneous and the other inhomogeneous in the rock strength distribution. The homogeneous model showed that fractures propagate with both tensile and shear failures even if the injected fluid acts homogeneously outward at the fluid-solid interface. The inhomogeneous model showed that fractures no longer propagate simply in the direction to the maximum principal stress field. Our results indicate that both tensile and shear failures take place even in the homogeneous model probably due to the influence of stress field, and that the propagation of small fractures takes place randomly in the inhomogeneous model due to localized small-scale inhomogeneous stress field acting at the tip of fractures.