Geomechanics of Fluid Injection in Geological Reservoirs
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Numerous petroleum engineering, mining, and enhanced geothermal energy operations involve cyclic injection of fluids into geological formations. Geomechanics of injection operations in weakly consolidated or unconsolidated reservoirs is complex, and means for analyzing the involved physical processes are limited. The key feature that must be considered is parting of the formation during injection, which occurs at near zero effective stresses when strength and stiffness of the medium become effectively zero. Even if peculiarities of the granular media behavior at near zero effective stresses are disregarded and a highly idealized Mohr-Coulomb behavior coupled with constant permeability Darcy flow is assumed, the injection problem is still highly challenging. This type of poroplastic formulation remains analytically intractable even for simplest geometries. Numerical computations are highly challenging as well, due to high fluid-solid matrix stiffness contrast. Much effort has been devoted thus far to understand soil-fluid interactions in geological reservoirs triggered by borehole excavation and production operations. With regards to injection operations however, practically no comprehensive study has been performed to access the fundamental geomechanical processes involved. Previous attempts to evaluate injection operations mainly concentrate on describing fracture growth in hard brittle formations. In principle, the geomechanical processes prior to fracture initiation are particularly complicated in weakly consolidated strata. This dissertation presents analytical solutions and numerical models to examine geomechanics of high pressure fluid injection in conditions when flow rates are high enough to induce plasticity yet not parting of the formation. The study considers injection through a fully-penetrating vertical wellbore into an isotropic, homogeneous unconsolidated geological layer confined between impermeable seal rock layers. Axisymmetric conditions are assumed. The main objective is to evaluate the time dependent geomechanical response of the unconsolidated reservoir in such conditions focusing on failure mechanisms and permanent changes in stress conditions around the injection area. Results of this research makes it possible to address the issue of integrity of confining strata, facilitate assessments of potential leakage areas, and offer aid for optimization of injection operations as well as in formulating monitoring strategies. First, rock-fluid interactions are evaluated prior to the state where limiting shear resistance is reached during injection. Unlike previous studies, impacts of vertical confinement governed by the stiffness of the overburden layer are incorporated. The Winkler spring model approximation is implemented to describe the response of the confining strata in the plane perpendicular to the reservoir. New poroelastic analytical solutions are derived to describe evolution of stress and strain components in time as a function of induced pore pressures. Solutions are verified against fully-coupled numerical models designed in this study. Next, novel insights into the geomechanics of parting in various stress regimes is offered via a comprehensive assessment of stress perturbations surrounding vertical injection wellbores. A thorough sensitivity analysis is conducted to examine the effect of vertical confinement and rock-fluid characteristic parameters on the reservoir response in the wellbore vicinity. Results demonstrate a notable impact of seal rock stiffness on the near wellbore rock behavior in formations with high intrinsic permeability (typically exceeding 0.05 Darcy). The study shows that the key parameter controlling the injection process in the poroelastic regime is the ratio of the overburden Winkler stiffness to the reservoir’s bulk modulus, with the Winkler parameter reflecting the seal rock stiffness. When this ratio approaches unity, practically no shear stress is induced in the reservoir while for ratios exceeding unity, deviatoric stresses gradually increase. In situations when the stiffness ratio is below unity, the porous formations can behave in a rather complicated manner depending on the initial stress regime where redirection of the minimal principal stress occurs from a horizontal to a vertical plane. Sensitivity analyses reveal that at the same injection rate rock failure occur more rapidly in conditions of higher stress anisotropy, higher elastic moduli, lower permeability, higher degree of rock-fluid coupling, and a higher vertical confinement. Next, rock-fluid interactions are evaluated in an unconsolidated reservoir formation confined between two stiff seal rock layers subjected to injection pressures high enough to induce plasticity yet not parting of the formation. The injection process is first examined numerically by constructing a fluid-coupled poro-elasto-plastic model in which propagation of the significant influence zone surrounding the injection borehole is quantified by the extent of the plastic domain. A comprehensive assessment of stresses, pore pressures, as well as failure planes is carried out throughout an entire transient state of an injection cycle, at steady state, and also during the shut-in period. The numerical solution describes five distinct zones evolving with time around the injection well and corresponding to different stress states: liquefaction at the wellbore followed by three inner plastic domains where directions of major principal stress changes from vertical to radial and failure planes change accordingly. The plastic domains are followed by a region where stress states remain in the elastic range. Failure mechanisms at the wellbore is found to be in shear initially, followed by development of a state of zero effective stress, i.e. liquefaction. Next, a novel methodology is proposed based on which new weakly-coupled poro-elasto-plastic analytical solutions are derived for the stress/strain components during injection. Unlike previous studies, extension of the plastic zone is obtained as a function of injection pressure, incorporating the plasticity effects around the injection well. The derived loosely-coupled solutions are proven to be good approximations of fully-coupled numerical models. These solutions offer a significant advantage over numerical computations as the run time of a fully-coupled numerical model is exceedingly long (requiring about six months for 661 million time computational steps using FLAC3D 3.0 code on Intel® i7 3.33 GHz CPU). The final part of this dissertation includes a brief chapter on the post-injection behavior of unconsolidated reservoir formations confined with stiff seal rock layers. Pore pressure dissipation, stress variations, and the transition behavior of the plastic domain surrounding the injection wellbore to an elastic state are numerically evaluated. Results offer an original insight into the permanent geomechanical effects of injection operations in such formations.
Cite this version of the work
Kamelia Atefi Monfared (2015). Geomechanics of Fluid Injection in Geological Reservoirs. UWSpace. http://hdl.handle.net/10012/9608