Yafes Abacioglu

The rate of pressure dissipation from abnormally pressured compartments

An improved analytic solution is presented that describes the dissipation of abnormal pressures via Darcy flow out of a compartment formed of high-permeability rock capped top and bottom by lower permeability rock. The solution tends to the solutions presented by previous workers in the limit of (1) a thick compartment and thin barrier and (2) a thick barrier and a thin compartment. The importance of including fluid compressibility when analyzing hydrocarbon reservoirs is demonstrated. Previous workers in this field have only included the effect of bulk rock compressibility and have neglected fluid compressibility.The solution is applied to pressure compartments on the scale of a typical hydrocarbon reservoir and overpressured regions on the basin scale. It is shown that the pressure gradient in a typical hydrocarbon reservoir compartment will return to the hydrostatic gradient over timescales of the order of hours or days, but that abnormal pressures are likely to dissipate over periods of tens of thousands to hundreds of thousands of years. Thus, any reservoir compartment with a different pressure from its neighbors at discovery can be considered as an independent unit during production. However, abnormal pressures on the basin scale may take tens or hundreds of millions of years to dissipate. There is thus no need to invoke zero-permeability seals or capillary-pressure seals in order to explain the existence of abnormal pressures over geological time.

Rates of reservoir fluid mixing: implications for interpretation of fluid data

Abstract This paper highlights the benefits of using knowledge of the rates of fluid mixing in the interpretation of reservoir fluid data. Comparison of the time it would take for a fluid difference to mix with the actual time available for mixing to occur allows two significant advances over a purely statistical analysis of reservoir fluid data: (1) differentiation of a step in fluid properties, indicative of a barrier to fluid communication, from a gradient indicative of incomplete mixing; and (2) quantitative estimation of the degree of compartmentalization that can readily be adapted into models for prediction of reservoir production performance. We review the existing equations that estimate the mixing times for three main types of variation in fluid properties (fluid contacts, fluid density and fluid chemistry). In addition, a new relationship for fluid pressure mixing is presented. In each case the relationships were validated by comparison with numerical simulation. The different fluid mixing processes were compared by applying the equations to a range of simple fluid scenarios in one simple reservoir description. This shows that mixing times for fluid mixing processes are diffusion > fluid density > fluid contacts > fluid pressure. For each scenario, the processes were analysed in terms of the volume of fluid that must move in order to bring the system to equilibrium and the drive for fluid mixing (pressure difference × permeability/viscosity). Perhaps surprisingly, there is an excellent linear relation between fluid mixing times (a) calculated from the mixing equations and (b) estimated from volume/drive. This indicates that fluid volumes and mixing drive are the main controls on fluid mixing times. This can be used to derive simple interpretation guidelines to estimate mixing rates even in the absence of quantitative modelling. A simple field case study demonstrates how this understanding of fluid mixing times can add value to the interpretation of reservoir fluid data.