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Abstract We investigate the main pumping parameters that influence a fluid driven fracture in cohesive poroelastoplastic weak formation. These parameters include the fluid viscosity and the injection rate. The first parameter dominates in the mapping of the propagation regimes from toughness to viscosity while the second parameter controls the storage to leak-off dominated regime through diffusion. The fracture is driven in weak permeable formation by injecting an incompressible viscous fluid at the fracture inlet assuming plane strain conditions. Fluid flow in the fracture is modeled by lubrication theory. Irreversible rock deformation is modeled with the Mohr-Coulomb yield criterion assuming associative flow rule. Fracture propagation criterion is based on the cohesive zone approach. Leak-off is also considered. We perform numerical calculations with the finite element method to obtain the fracture opening, length and propagation pressure versus time. We demonstrate that pumping parameters influence the fracture geometry and fluid pressures in weak formations through the diffusion process that create back stresses and large plastic zones as the fracture propagates. We also show that the product of propagation velocity and fluid viscosity, (ยตv) that appears in the scaling controls the magnitude of the plastic zones and influences the net pressure and fracture geometry.
- Europe (0.68)
- North America > United States (0.46)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.90)
- Well Drilling > Pressure Management > Well control (0.72)
Abstract The mechanics of fluid-driven fracture propagation through fracture networks is of central interest in gas and oil extraction procedures. A number of computational strategies have now been developed to simulate these processes although specific understanding of the propagation mechanics in the vicinity of pre-existing discontinuities or faults is still limited. This paper investigates the problem of formulating appropriate fluid branching logic at multiple flow path junctions and the influence of sudden contractions or expansions in the flow path channel width at discontinuity intersections. A plane strain model is assumed. A question of additional interest is the possible existence of a "fluid lag" region between the flow front and the mobilized fracture front. The paper explores some examples of flow propagation and branching through simple joint networks.
Abstract We present a numerical model for the simultaneous initiation and subsequent propagation of multiple transverse hydraulic fractures from a horizontal wellbore. In particular, we investigate the efficiency and robustness of the multistage hydraulic fracturing technique. We restrict the created hydraulic fractures to remain radial and planar but fully account for the stress interaction between fractures, the fluid flow in the wellbore and across the different perforation clusters which are modeled via a classical relation between the friction pressure drop and the flow rate entering a given fracture. The initiation is modeled from a radial notch of given initial length using linear elastic fracture mechanics. The solver models the complete pressurization of the wellbore, the initiation of the different fractures and their propagation and interactions. The split of the fluid between the different clusters is part of the solution at each time-step. We present some validations and a case study investigating the effect of a number of heterogeneities (in-situ stress etc.) on the robustness of the limited entry technique.
Abstract Robust and reliable hydraulic fracturing models that appropriately account for random initiation of fractures, strongly nonlinear coupling among deformation, fracturing and fluid flow in fracture apertures and leakage into porous rock matrix, would be a key step toward developing a better understanding of physics associated with hydraulic fracturing process. In this paper, we present a physics-based hydraulic fracturing simulator based on coupling a quasi-static discrete element model (DEM) for deformation and fracturing with conjugate lattice network flow model for fluid flow in both fractures and porous matrix. The coupled DEM-network flow model reproduces a variety of realistic growth patterns of hydraulic fractures. The effects of in situ stress, fluid viscosity, heterogeneity of rock mechanical properties and injection rate on the fracture patterns will be presented and discussed. In particular, simulation results of multistage horizontal wellbore with multiple perforations clearly demonstrate that elastic interactions among multiple propagating fractures, strong coupling between fluid pressure fluctuations within fractures and fracturing, and lower length scale heterogeneities, collectively lead to complicating fracturing patterns.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.51)
Abstract Rocks with natural fractures, cracks, faults and vugs have complex multi-connected pathways for fluid flow. In these systems, fluid flow, especially to production wellbores, can change as reservoir conditions change as fluids are injected to the reservoir. In typical practice, the more detailed the characterization of the fracture network, the easier it is to optimize recovery process design and well placement to maximize the recovery factor of petroleum fluids. Furthermore, for tight rocks where hydraulic fracturing is required to enable sufficient fluid mobility for economic production, it is critical to understand the placement of the induced fractures, their connectivity, extent, and interaction with natural fractures within the system. Stress anisotropy and interactions between new fractures and natural fractures in the formation can dictate the mode, orientation and size of the hydraulic fracture network. In this study, normal deformation is coupled with fluid flow to evaluate the effect of the stress anisotropy on fracture network propagation in rock. The results demonstrate that stress anisotropy and existing natural fractures networks are playing critical roles in creating fracture-network complexity and connectivity. The model developed here assumes that the flow is single-phase and isothermal, matrix permeability is zero, and that deformation arises from small normal displacement in an infinite, homogeneous, linearly elastic medium. Specifically, the model couples fluid flow and stresses induced by fracture deformation in a plane. For this purpose, a system of equations governing fracture deformation and fluid flow through a complex fracture network is solved. The results illustrate the importance of rock properties, stress magnitude, and stress orientation on fracture complexity in unconventional naturally fractured reservoirs.
- Research Report > New Finding (0.54)
- Overview (0.46)