Formation evaluation in overpressured reservoirs is very challenging due to abnormally high pressures, relatively high reservoir temperatures, uncertainty in the determination of reservoir rock properties and in fluid types and contacts. Accurate determination of these parameters is a key in obtaining a reliable hydrocarbon volume assessment which would otherwise lead to an uncertainty of hydrocarbon accumulation in these reservoirs and subsequently impose a risk in developing such reservoirs.

In this paper, we present an integrated approach for improved formation evaluation in overpressured reservoir rocks. The data used in this paper comes from two gas fields in Eastern Baram delta provincewhich is a sandstone reservoir separated by a fault. The approach makes use of various types of data including petrophysical, geological, reservoir, extracted core samples, downhole logs, in-situ fluid sampling, spill points, and saturation height data which provide key pieces of information in the evaluation of these reservoirs.

One of the key conclusions is that the porosity and permeability of cores in overpressure reservoirs have better quality preservation compared to normal/under pressure reservoir intervals. Also a unique trend of QV vs porosity was seen for overpressure and normal/under pressure reservoir rocks. There is an uncertainty in fluid contacts determination in the studied fields. The formation pressure andlog data have been utilized to identify fluid contacts in a few reservoirs. However there are still some contacts which can not be identified where no water zones have been penetrated. In such reservoirs, free water levels are determined using gas/oil down to (G/ODT) and spill point data.

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