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Abstract

The water flooding in the carbonate fracture reservoir is low efficiency because of higher permeability in fractures than in matrix, and water will not imbibe spontaneously into the matrix due to a negative capillary pressure.  Spontaneous imbibition of water into carbonate fracture reservoir is a very important issue in secondary oil recovery method.  However, almost more than 80% of the entire known carbonate reservoir can be categorized as oil wet. It is therefore important to find methods to alter the wettability from oil-wet to water-wet conditions that are effective in order to improve the recovery from carbonate fracture reservoir. So far, two methods have been developed wettability alterations: 1) addition of certain chemical surface active agent to the injection water, and 2) thermally wettability alteration by steam injection.

In this study, an oil sample with 20 API was used to investigate the effect of the understudied surfactants on wettability alteration in the oil-water-limestone system.

Understudied surfactants were SDBS (sodium dodecylbenzene sulfonate), C₁₂TAB (dodecyl trimethyl ammonium bromide), C₁₆TAB (hexadecyl trimethyl ammonium bromide) and Triton X-100 that were utilized at 0.5, 1.5 and 2.5 wt% concentrations. The experiments were performed several times (0, 1, 6, 12, 24, 48, 72, 96 h) after injection of oil drop under limestone rock sample at reservoir temperature of 80^oC.

The obtained results showed that the increasing each of the surfactant could cause wettability alteration of the rock from oil-wet towards water-wet situation by passing of time. This alteration was very sharp at the beginning, but it was increases slightly at the time. It was observed that Triton X-100 was more efficient than C₁₆TAB, C₁₂TAB and SDBS to alter the wettability of the rock.

1. Introduction

About half the world’s discovered oil reserves are in carbonate reservoir forms and many of them are naturally fractured (Roehl and Choquette, 1985). The Total oil recovery does not exceed generally 30%. Such reservoirs are often characterized by high-permeability fractures and a low permeability matrix medium. Most of the injected water will pass through the fracture network and displaces only the oil residing in the fracture (Cuiec, 1984; Treiber et al., 1972). Spontaneous imbibition of water from the fractures into the matrix takes place if the reservoir is water-wet. However, up to 65% of carbonate rocks are oil-wet and 12% are intermediate-wet (Chillingar and Yen, 1983). Most of the oil reservoirs are found in carbonate rocks, many of which contain fractures with high hydraulic conductivity surrounding low-permeability matrix blocks that are mixed-wet to oil-wet (Allan and Sun, 2003; Roehl and Choquette, 1965; Salehi, et al., 2008).