Coupling geomechanical reservoir models with fluid flow models improves accuracy when simulating phenomena relevant to production forecast, drilling and well integrity, and environmental impact (e.g. fault reactivation). A geomechanical model provides to a hydrodynamical model updated values of pore volume and permeability, and a hydrodynamical model in turn provides to a geomechanical model updates to the pore pressure, which then alters effective stress. The main challenge in coupling is the exchange of data. This work presents three different pore pressure projection schemes used for data exchange, that are based on weighted averages (inverse distance, volume, and by inverse of the volume). To validate the three methods, the pressure projected was compared with a hydrostatic pressure distribution while accounting for changes in the size of the surrounding cells of the hydrodynamical model. The weighting by the inverse of the volume shows the better agreement with hydrostatic pore pressure distribution of the three techniques presented. As a further demonstration, the three methods were compared within a small reservoir model with varying cell sizes, and the inverse volume method performs favorably. Finally an extension to the inverse volume method was developed, in which permeability is included in the weighting factors. Its effect is demonstrated in a benchmark system including both a reservoir and a nonpay region.