Fluid Pressure Gradients in Tight Formations

Abstract

Low-permeable reservoirs have long been recognized as a challenge for economical production. Characterization of complex carbonate reservoirs exhibits some special challenges. Pay zones may be poorly defined due to marginal reservoir properties, i.e., uncertainties regarding the distribution of oil on the pore scale and the ability of oil to flow at high initial water saturation. Hence, the oil water contact may not be a precise level in the reservoir and the vertical span of the oil-water transition zone may be greater than 100 meters in such reservoirs. The traditional reservoir engineering approach defines free water level and hence the water- and oil-zones from the oil- and water pressure gradients. Pressure gradients are, however, difficult to obtain in low-permeable media and it has been reported that supercharging effects may be the result of mobile oil and water at the same place in the reservoir. A case study is made for an offshore exploration well in a complex and heterogeneous carbonate oil reservoir. The well is not production tested and gives a clear water gradient. However, there is indication of relatively high oil saturation with possible live oil properties. This is not typical for a reservoir that has been completely water washed during historical time. Different initial fluid distributions are studied in simulation of filtrate invasion in order to explain the observations in the exploration well. The results are of general interest, with application to many low-permeable reservoirs. This work gives new insight into the important interplay between type of drilling mud, reservoir wettability and interpretation of fluid gradients. The novel implication of the results is that a water-gradient is measured in the transition zone if an oil-wet reservoir is drilled with water-based mud. A water gradient can therefore exist even though the oil saturation is high. The shift between the water gradient and oil gradient occurs when mobile oil is present in water-wet pores giving a positive oil-water capillary pressure. Introduction The fluid distribution in oil reservoirs reflects the accumulation history and hence chemical, biological and geological processes during millions of years. The complexity of such processes seems to be significantly and the outcome difficult to predict. However, by experience it is known that some simple physical laws may adequately explain today's water and oil saturation without detailed knowledge of the accumulation history during millions of years. The main assumptions made for practical engineering purpose are i) the equilibrium between gravity and capillarity; and ii) the oil has originally migrated into a water-wet environment. The initial conditions in a homogenous reservoir with high permeability can therefore most often be described easily from the primary drainage process and the reservoir divides into clearly defined oil and water zones. Hence, water is the only mobile phase in the water zone and oil is the only mobile phase in the oil zone. The initial fluid mobilities are thus a matter of single phase flow with possible modifications for the connate water saturation or the residual oil saturation (if paleo oil is present). Fluid gradients will reflect the mobile phase and capillary pressure effects on the gradient can be neglected. The most common reservoir engineering interpretation of fluid gradients is accordingly that an oil gradient implies producible oil and a water gradient implies either 100% water saturation or in some special cases water and residual oil saturation (paleo zone). This is most often supported by the petrophysical evaluation with a rapid change in resistivity at the oil-water contact (OWC). The free water level (FWL) is per definition the position where the oil-water capillary pressure is zero and is estimated to be where the extrapolated oil and water gradients do cross.