Calibration of the Water Flowback in Unconventional Reservoirs with Complex Fractures using Embedded Discrete Fracture Model EDFM

Abstract

Abstract Modelling fracture systems where fracture mechanics and fluid flow are consistent, constitutes an essential part for predicting the performance of shale oil and gas operations. One of the challenges in these complex systems is the reconciliation of volumes of injected water during fracturing, hydraulic fracture volume and the water flowback after the well is open to production. Achieving consistency becomes even more challenging given the interdependence of multiple sources of uncertainty. We propose a workflow that uses multiple sources of observed operational data, such as volume of water injected and produced, static pressure, soaking time and saturation logs, to calibrate a static model representing the fracture volume and rates of water imbibed into the matrix. The soaking period is modeled using Embedded Discrete Fracture Model (EDFM) that honors the fracture geometry generated by a commercial software based on unconventional fracture model (UFM). The allocation of water imbibed into the matrix during the soaking period uses imbibition capillary pressure from 3D numerical models. After applying the proposed methodology to calibrate stimulated shale oil reservoir in a multi well pad, we can assess the relative impact of fracture complexity compared to capillary dominated flow. Additionally, we can perform sensitivities on impact of the water retained in the fracture volume and matrix, respectively. Finally, the methodology showed that we can use the imbibition capillarity to explain and reconcile water losses during the soaking period. This information is of key importance while deciding the value of the flowback rates as input during calibration of hydraulic fracture area and quality of the stimulation procedure. Extended applications of this workflow include performance assessment of gas entrapment and evaluation of EOR operations in unconventional systems. We propose a methodology based on the hypothesis of capillary imbibition mechanism to explain and capture the volume of injected water that does not return during hydrocarbon production. This workflow, well suited for realistic complex Hydraulic Fracture Networks (HFNs) consisting of millions of fractures planes, enables calibration of fracturing fluids and water flowback while assessing the effect of the spontaneous imbibition.