Summary
The wettability of a crude oil/brine/rock system influences both the form of petrophysical parameters (e.g., Pc and krw/kro) and the structure and distribution of remaining oil after secondary recovery. This latter issue is of central importance for improved oil recovery since it represents the "target" oil for any IOR process. In the present study, we have developed a three-dimensional network model to derive capillary pressure curves from nonuniformly wetted (mixed and fractionally wet) systems. The model initially considers primary drainage and the aging process leading to wettability alterations. This is then followed by simulations of spontaneous water imbibition, forced water drive, spontaneous oil imbibition and forced oil drive—i.e., we consider a complete flooding sequence characteristic of wettability experiments. The model takes into account many pore level flow phenomena such as film flow along wetting phase clusters, trapping of wetting and nonwetting phases by snapoff and bypassing. We also consider realistic variations in advancing and receding contact angles. There is a discussion of the effects of additional parameters such as the fraction of oil-wet pores, mean coordination number and pore size distribution upon fractionally and mixed wet capillary pressure curves. Moreover, we calculate Amott oil and water indices using the simulated curves. Results indicate that oil recovery via water imbibition in weakly water-wet cores can often exceed that obtained from strongly water-wet samples. Such an effect has been observed experimentally in the past. The basic physics governing this enhancement in spontaneous water imbibition can be explained using the concept of a capillarity surface. Based on these theoretical calculations, we propose a general "regime based" theory of wettability classification and analysis. We classify a range of experimentally observed and apparently inconsistent waterflood recovery trends into various regimes, depending upon the structure of the underlying oil- and water-wet pore clusters and the distribution of contact angles. Using this approach, numerous published experimental Amott indices and waterflood data from a variety of core/crude oil/brine systems are analyzed.
Introduction
In crude oil/brine/rock (COBR) systems, pore level displacements of oil and brine and hence the corresponding petrophysical flow parameters (e.g., Pc and krw/kro) describing these displacements are governed by the pore geometry, topology and wettability of the system. A number of excellent review papers are available that describe experimental investigations of the effect of wettability on capillary pressure and oil-water relative permeability curves.1–5 In COBR systems, wettability alterations depend upon the mineralogical composition of the rock, pH and/or composition of the brine, crude oil composition, initial water saturation, reservoir temperature, etc.6–12 Therefore, in recent years, interest in restoring the wettability of reservoir core using crude oil and formation brine has greatly increased.3,4,13,14 In this approach, cleaned reservoir core is first saturated with brine and then oil flooded to initial water saturation using crude oil. The core containing crude oil and brine is then aged to alter its wettability state. Wettability measurements, such as Amott and USBM tests, and waterflood experiments are then typically conducted on the aged core. This entire process broadly mimics the actual flow sequences in the reservoir; consequently, the wettability alterations are more realistic than those achieved using chemical treatment methods. During the aging process, wettability may be altered to vastly different degrees depending upon many factors, including those mentioned above. In addition, aging time, thickness of existing water films and wetting film disjoining pressure isotherms also play important roles. Hence, the final wettability state of a re-conditioned core will generally be case specific.
Estimating reservoir permeability with borehole radar
