One of the aims of a pre-drill pore pressure prediction is to create a mud weight and casing program to allow wells to be drilled safely and with as much forewarning of potentially overpressured zones as possible. Knowledge and understanding of overpressured zones can be derived from many sources such as formation pressure tests, daily drilling and End of Well Reports. In addition, a common practice is the interpretation of wireline data (sonic, density, resistivity) from offset wells and increasingly, seismic interval velocities, as a means of predicting pore pressure. One concern arises in that the workflows used to derive seismic velocities can differ depending on whether improving the image is the requirement, i.e. optimizing the stacking process, or whether velocities are to be used for pressure prediction. In addition, both well-based and seismic interval velocities (regardless of how they are processed) are affected by changes in rock properties related to increasing temperatures with increasing depth. These changes may result in additional overpressure, which is no longer related to effective stress and porosity. Such changes can also result in the precipitation of silica cement, which produces artificially fast shales, where velocity, porosity and, therefore, effective stress are no longer related in a predictable manner (Hoskin and O’Connor, 2016).

 

Carbonate reservoirs are the targets of many drilling programs. One of the challenges in developing these types of reservoir is to mitigate the risk caused by unexpected pore pressure; these pressures can vary dramatically from relatively benign to highly overpressured.  Problems arise, however, when existing pore pressure prediction techniques (that were developed for shales) are being applied to these targets with little consistency. There is a tendency in the industry to use seismic velocity data and porosity-based, shale-centric techniques to predict pore pressure directly in carbonates. This approach, at best, will only ever give a local, empirical fit. An approach looking at the basin history is advised, as the paleo-history of a carbonate will dictate its current pressure regime, coupled with sensible pressure modelling in any associated shales, and understanding of elastic (Poisson’s Ratio, Young’s Modulus, Vp, Vs and Rho) and mechanical (UCS, coefficient of friction) properties of the carbonates (Green et al, 2016). In this paper we present examples of how a coupled Geological Pressure Model may be used to estimate pore pressure in carbonate targets