Geological Understanding is the Key to Predicting Pore Pressure
Authors: S. Idris Ismatul Hani , Wijnands Frank 
Published: March 2015

With an increasing number of wells drilled deeper and into more severely overpressured formations, we realize that traditional pore pressure prediction concepts cannot always provide the required prediction accuracy. This paper presents a compilation of pore pressure prediction case studies from various areas operated by PETRONAS and is intended to share and discuss lessons learnt from case studies. Comparisons of pressure predictions with real-time or post-drill formation pressure demonstrate which methods and input data resulted in accurate pressure predictions and where and why other predictions fell short.

Conventional pressure predictions are often based on velocities derived from seismic data. Post-drill, these velocities may turn out to be far from accurate but even high quality velocity profiles do not necessarily result in accurate pressure predictions. It is necessary to have a thorough understanding of the various pore pressure generating mechanisms that are active in an area of interest. In many basins, the formations that generate high overpressures have never been drilled but pressure is transmitted upwards or laterally to formations penetrated by wells. Basin modelling plays a role in such cases and it becomes important to assess the quality of regional seals, which can trap high overpressure in some structures but may not in others. It is also important to have an accurate geological prediction of formations to be penetrated by a planned well, as regional seals can sometimes be correlated over larger areas.

Often, there is insufficient offset well data, or a well may drill formations not previously penetrated, resulting in significant uncertainty in even the best possible pressure prediction. Pore pressure monitoring while drilling can significantly reduce the uncertainty and updating geological correlations and facies interpretations while drilling can be just as important.

Introduction

East Malaysian basins are considered mature in terms of hydrocarbon exploration. Many fields were discovered in the 1980s and 90s and are still producing today. All producing reservoirs are of tertiary age and reservoir sands are often of deltaic origin. As an example, a conceptual regional cross section for the SW Sabah continental margin is presented in figure 1. Tertiary deltaic sequences are found in a variety of tectonic settings, which can be compressional in Lower to Mid Miocene deposits. Sometimes, this is associated with tectonic uplift, especially in near-coastal ranges. Late Miocene to Pliocene deposits are more likely to be found in extensional tectonic settings, dominated by sometimes very large normal faults. Lower Micoene or older sediments are rarely drilled but are thought to consist predominantly of shale-prone deep-water sediments and are assumed to be the source rocks for the shallower reservoirs. These shales are considered to be relatively poor source rocks but make up for a lack of quality with very large thicknesses. Much of the lower Miocene is presently within the gas generation window.

Apart from clastics, carbonate deposits are also important for the Malaysian oil and gas industry, but since carbonate pressure issues are of a very different nature and in the interest of brevity, we only discuss clastics pore pressures in this paper.