Thesis (Ph.D.)--University of Tulsa, 1989.

Thesis (Ph.D.)--University of Tulsa, 1988. / Bibliography: leaves 250-253.

Thesis (Ph.D.)--University of Tulsa, 1993. / Bibliography: leaves 179-186.

Thesis (Ph.D.)--University of Tulsa, 1987. / Bibliography: leaves 204-211.

Thesis (Ph.D.)--University of Adelaide, Australian School of Petroleum (ASP), 2004. / "February 2003" PhD (by publication). Includes bibliographical references.

Thesis (Ph.D.)--University of Tulsa, 1981. / Bibliography: leaves 176-179.

Thesis (doctoral)--Université de Rennes, 2003. / Includes bibliographical references (p. 244-258) . Also available on the World Wide Web.

Thesis (Ph. D.)--University of Texas at Austin, 2004. / Supervisor: A. Daniel Hill. Vita. Includes bibliographical references.

This work addresses the poroelastic effect on the processes involved in hydraulic fracturing and post-fracture production using a finite element based fully coupled poroelastic model which includes a triple system of wellbore-fracture-reservoir. A novel numerical procedure for modeling hydraulic fracture propagation in a poroelastic medium is introduced. The model directly takes into account the interaction of wellbore, hydraulic fracture and reservoir in a fully coupled manner. This allows realistic simulation of near fracture phenomena such as back stress and leak-off. In addition, fluid leak-off is numerically modeled based on the concept of fluid flow in porous media using a new technique for evaluating local pressure gradient. Besides, the model is capable of accommodating the zone of reduced pressure (including intermediate and fluid lag zones) at the fracture front so as to capture the behavior of fracture tip region more realistically. A fully coupled poroelastic model for gas reservoirs has been also developed using an innovative numerical technique. From the results of this study it has been found that fracture propagation pressure is higher in poroelastic media compared to that of elastic media. Also high formation permeability (in the direction normal to the hydraulic fracture) and large difference between minimum horizontal stress (in case of it being the smallest principal stress) and reservoir pressure reduce the rate of fracture growth. Besides, high pumping rate is more beneficial in elongating a hydraulic fracture whereas high viscous fracturing fluid is advantageous in widening a hydraulic fracture. It has been also shown that rock deformation, permeability anisotropy and modulus of elasticity can have a significant effect on fluid flow in a hydraulically fractured reservoir. Furthermore, it has been shown that long stress reversal time window and large size of stress reversal region can be caused by high initial pressure differential (i.e. the difference between flowing bottomhole pressure and reservoir pressure), low initial differential stress (i.e. the difference between maximum and minimum horizontal stresses) and low formation permeability in tight gas reservoirs. By taking advantage of production induced change in stress state of a reservoir, this study has also shown that a refracture treatment, if carried out in an optimal time window, can lead to higher economic gain. Besides, analysis of stress reversal region has depicted that a small region with high stress concentration in the vicinity of the wellbore could impede refracture from initiating at the desired place. Moreover, re-pressurization of the wellbore can result in further propagation of the initial fracture before initiation or during propagation of the secondary fracture.

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