The injection or production of large volumes of fluid into or from a reservoir can result in significant changes to the effective in-situ stress distributions. Field evidence of this has been provided in the past by mapping refracturing treatments in tight gas sands and micro-seismic monitoring of injection wells in water-flooded reservoirs.

A poro-elastic model is presented to show how the extent of fracture reorientation can be estimated under different conditions of fluid injection and production. The extent of fracture reorientation is a function of the in-situ stresses, the mechanical properties of the rock and the pore pressure gradients. In reservoirs where the pore pressure gradients are complicated due to multiple injection and production wells, fracture reorientation is sensitive to the net pore-pressure gradients. Fractures tend to reorient themselves towards the injection wells and away from production wells, if the pressure gradients are comparable to the in-situ stress contrast.

While far-field principal stress orientations are impacted only by in-situ stresses and pore-pressure gradients, near-wellbore in-situ stress orientation is also impacted by the hoop stress and the wellbore pressure. These can have a significant effect on near-wellbore fracture reorientation. The results of our model are compared with field observations obtained from micro-seismic monitoring of water injection wells. The implications of the results to refracturing operations and candidate well selection are discussed.


The reduction of pore pressure in reservoirs results in changes in field stresses and in compaction and subsidence. This coupling between pore pressure and geo-mechanical stresses can have important consequences in orientation of hydraulically induced fractures in injection or production wells. In addition, the withdrawal of fluid and the resulting reduction in pore pressure can give rise to significant reductions in porosity and permeability associated with rock compaction. In some cases, this can result in subsidence being observed all the way to the surface.

A large body of literature exists that clearly demonstrates stress reorientation due to a reduction in the pore pressure resulting from fluid withdrawal in reservoirs. Warpinski and Branagan[1] proposed taking advantage of stress reorientation in the region of influence to create a favorable fracture orientation. The process is referred to as altered stress fracturing. Palmer[2] elaborated on the process of altered-stress fracturing with emphasis on the application to coalbed methane reservoirs. Elbel and Mack[3] suggested that changes in horizontal stress due to production can cause initiation of fractures during a re-fracturing treatment normal to that of the initial treatment. Hidayati et.al.[4] studied stress reorientation in a multiple-well reservoir and suggested that well interference is an important factor affecting stress reorientation. Regulating the production/injection rate and the placement of wells surrounding a point of interest allows some control of the stress orientation at that point.

Fracture reorientation was first postulated to occur in refracturing operations to explain unexpected and favorable production responses[5]. Experimental studies and field observations verified the existence of fracture reorientation [3, 5, 6].

Bruno and Nakagawa[7] did laboratory tests in 1991 and showed that fracture initiation and orientation are affected by pore pressure changes. They showed that the local pore pressure gradient near the fracture tip controls the fracture growth direction. A fracture turns towards a region of higher local pore pressure if in-situ stresses are not dominant. Elbel[3, 8, 9] presented a fracture reorientation theory in 1993 and applied the theory to tight gas wells in 1998 and 2000. They showed that the elliptical pore pressure distribution due to fracture growth reduces the maximum effective horizontal stress by a greater amount than the reduction in the minimum horizontal stress. If the difference in stress reduction is greater than the original horizontal stress contrast (maximum horizontal stress - minimum horizontal stress), then the principal stress directions will switch directions and subsequent fractures may propagate perpendicular to the original fracture treatment.

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