This paper highlights an unconventional approach of using DPDP (Dual Porosity Dual permeability) simulation technique for modelling hydraulic fractures in a full field simulation model during the forecast analysis performed on a tight carbonate reservoir in Kuwait. This was a part of integrated study in which ‘multi-stage hydraulic fracturing’ was recommended as the most optimum stimulation technique in order to enhance the productivity of all the proposed horizontal producers. Importance of DPDP model increases multi-fold when contrast between fracture and matrix permeability is in the order of 10 times or more. In the studied case, as average matrix permeability of the reservoir is in the range of 2-3 mD, this contrast is magnified to the order of 1000-10000 times (considering fracture permeability is in Darcies) which further complements the use of DPDP model.
Three different approaches were tried to model the impact of multi-stage hydraulic fracturing in the full field simulation model; 1) ‘Enhance Well PI’ for all the stimulated wells, 2) ‘Enhance Matrix Permeability’ in the vicinity of all the stimulated wells, hereby referred as SPSP (Single Porosity Single Permeability) approach, and 3) build ‘DPDP Model’ by using upscaled fracture porosity and fracture permeability without changing the matrix properties. First two approaches are very common in the industry but most of the times are not able to capture the real impact of hydraulic fracturing on flow behaviour (bi-linear flow), whereas DPDP model is designed to capture the flow through dual medium. In both SPSP and DPDP approaches permeability anisotropy (increased permeability in the direction perpendicular to horizontal section of the well) in the fractured zone was very well captured and was needed to honour the hydraulic fractures direction. Fracture permeability was calculated using the Poiseuille's law; few sensitivity cases were run to address the associated uncertainty.
Field cumulative oil production and recovery factor were analysed for ‘Enhanced Well PI’ case, SPSP cases and DPDP cases. Field oil cumulative production in DPDP cases is 6% more than SPSP cases and around 10% more than ‘Enhanced Well PI’ case. The hypothesis for the higher recovery in DPDP case with respect to other two cases is that bi-linear flow (fractures are getting filled with the matrix fluid and then feeding to well) is better represented in the DPDP model. Impact in this case is more significant due to the big contrast between matrix and fracture permeability.
Low capacity with high conductivity signature of hydraulic fracture is difficult to model in the SPSP or just by enhancing the well PI. Study clearly demonstrated the benefits of DPDP model for modelling hydraulic fractures over the conventional methods.