The role of hydraulic fracture geometry and conductivity profile, unpropped zone conductivity and fracturing fluid flowback on production performance of shale oil wells

Horizontal drilling and multi-stage hydraulic fracturing have made the commercial development of nano-darcy shale resources a success. Low recovery factors in shale reservoirs highlight the importance of accurate modeling of fluid flow and well performance for wells draining such resources. Currently reported simulation studies assume a constant conductivity for the hydraulic fractures. However, in reality fracture conductivity varies greatly depending on the local proppant placement and concentration. An effective simulation model should also consider the presence of fracturing fluid in hydraulic fractures and matrix prior to production.

This paper presents a workflow for proper modeling of flow simulation in shale oil wells by incorporating results from the hydraulic fracturing simulator into the reservoir simulator. This approach honors the actual proppant distribution, lateral and vertical variability of the fracture conductivity, and the presence of fracturing fluid in the fractures and surrounding matrix prior to production commencement. It also gives an estimate of the recovered fracturing fluid.

It was found that ignoring the presence of fracturing fluid in the simulation model overestimated oil recovery by about 18%. Assuming elliptical and rectangular shape hydraulic fractures with constant conductivity overestimated the oil recovery factor by 27% and 35%, respectively. The conductivity of the unpropped zone affected the predicted recovery factor by as much as 50%. For the case investigated, most of fracturing fluid recovery occurred during the first year and particularly the first 2 months of production.