RIASSUNTO
Abstract
The goal of this work is to change the wettability of a carbonate rock from mixed-wet towards water-wet at high temperature and high salinity. Three types of surfactants in dilute concentrations (<0.2 wt%) were used. Initial surfactant screening was done on the basis of aqueous stability at these harsh conditions. Contact angle experiments on aged calcite plates were done to narrow down the list of surfactants and spontaneous imbibition experiments were conducted on field cores for promising surfactants. Secondary waterflooding was conduceted in cores with and without the wettability altering surfactants. It was observed that barring a few surfactants, most were aqueous unstable by themselves at these harsh conditions. Dual surfactant systems, a mixture of a non-ionic and a cationic surfactant increased the aqueous stability. Some of the dual surfactant systems proved very good for wettability alteration and could recover 70-80% of OOIP during spontaneous imbibition.
Secondary waterflooding with the wettability altering surfactant increased the oil recovery over the waterflooding without the surfactants (from 29% to 40% OOIP).
Introduction
Approximately half of the world's discovered oil reserves are in carbonate reservoirs and many of these reservoirs are naturally fractured (Roehl and Choquette 1985). Carbonate reservoirs often have a high degree of heterogeneity and the pore structure is complex. The carbonate rocks are often mixed-wet to oil-wet because of the positive zeta potential of the rock surface, the hardness of the brine and the presence of apshaltenes and organic acids in the oil. Due to microscopic oil trapping and macroscopic bypassing, waterflooding in carbonate reservoirs is often poor (Manrique et. al. 2006). Improved oil recovery from oil-wet, low-permeability carbonate reservoirs is a great challenge.
Reservoir wettability plays an important role during waterflooding. In a water-wet reservoir, the water relative permeability is low and oil relative permeability is high. Most of the oil is produced before water breakthrough; there is very little oil production after water breakthrough. In an oil-wet (or mixed-wet) reservoir, the water relative permeability is high and oil relative permeability is low. Water breaks through early and oil is co-produced with water for many pore volume of water injected. The residual oil saturation depends on wettability with a minimum for a mixed-wettability lower than either strongly water-wet or oil-wet rock (Salathiel et al. 1973, Jadhunandan and Morrow 1995). Reservoir wettability also affects the bypassing of oil in lower permeability zones. In a water-wet medium, water can be imbibed into bypassed zones by capillary forces and reduce bypassing. In oil-wet media, bypassing is expected to be higher because capillary forces discourage water to invade these bypassed zones. The goal of this study is to identify a wettability altering agent that can be added to waterflood which would change wettability and improve oil recovery in a secondary waterflooding in a non-fractured carbonate rock.
There are two main approaches to wettability alteration in originally oil-wet carbonate rocks. The first approach is through a change in the brine ionic composition. Strand et al. (2006, 2008) have shown that addition of sulfate and other potential determining ions can change the wettability of originally oil-wet chalk cores at high temperatures (above 90 °C). Increase in water-wetness was demonstrated by imbibitions of these brines into originally oil-wet chalk cores. It is hypothesized that
sulfate ions replace the adsorbed negatively charged organic acid groups thus making the surface more water-wet. High temperature is important for fast enough kinetics for this ion exchange. Yousef et al. (2010) have shown that diluting the injection brine salinity for a high temperature and high salinity carbonate reservoir improves the wettability towards more water-wet and gives an additional oil recovery of almost 20% over injection of sea brine.