STUDY OF INJECTION PRESSURE DIFFERENCES DURING THE SPONTANEOUS PROPAGATION OF HYDRAULIC FRACTURES
M. R. Gubaidullin1, A. Ya. Davletbaev1,2, I. G. Kuzin1, V. A. Nitsenko1, V. P. Miroshnichenko3, G. A. Shchutskii3
1OOO RN-BashNIPIneft’, Ufa, Russia
2Ufa University of Science and Technology, Ufa, Russia
3OOO RN-Yuganskneftegaz, Nefteyugansk, Russia
Keywords: hydraulic fracturing, low-permeability reservoir, spontaneous fracture propagation, injection well, Perkins-Kern-Nordgren model
Abstract
This paper investigates a line-drive waterflood pattern with two injection wells, between which a hydraulic fracture spontaneously propagates. Using a simplified model implemented in the RN-KIM hydrodynamic simulator, we consider a scenario where propped fractures from the two injectors connect to form a single dominant spontaneous hydraulic fracture. We model the propagation of a spontaneous fracture between two wells with existing propped fractures and analyze how the difference in wellhead injection pressures affects the injection rate in each well. The results demonstrate that an injection pressure difference between adjacent wells can cause a severalfold decrease in the injection rate or even a complete well shut-in. This occurs when the well with the higher bottomhole pressure “dominates” the flow within the high-conductivity fracture. Furthermore, we analyze the impact of the operating conditions of adjacent injectors and the geomechanical properties of the reservoir on the injection rate.
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