Waterflooding of preferential oil-wet carbonates: Oil recovery related to reservoir temperature and brine composition

Abstract

Abstract Much effort has been focused on wettability modifying methods to improve the water-wetting nature of carbonates in order to enhance the oil recovery by spontaneous imbibition of water. The use of expensive surface active additives like cationic surfactants of the type R-N(CH[3])[3]+ have been suggested, as well as steam injection. In this study, we will discuss possible wetting modifications of carbonates in relation to potential determining ions present in the injected fluid. Artificial seawater is used as the base or reference imbibing fluid. Outcroup chalk cores of high porosity and low permeability and reservoir limestone cores were saturated with oils with high acid number at residual water saturation to render the cores preferential oil-wet. Spontaneous imbibition tests were performed at different temperatures ranging from 70–130 ºC using modified seawater with various concentrations of sulfate, which is regarded as a potential determining ion towards carbonates. Major observations were:Spontaneous imbibition of seawater took place only at elevated temperatures,For the chalk samples, the oil recovery increased beyond the recovery at completely water-wet conditions when the concentration of sulfate was increased 3 times relative to seawater at 130 ºC,Reservoir limestone cores also responded with increased oil recovery at 120 ºC as the sulfate concentration increased,at lower temperatures, increased spontaneous imbibition was obtained when adding cationic surfactant to the imbibing fluid,The activity of sulfate as a potential determining ion, and thus a wettability modifier, appeared to increase as the temperature is increased. The results show that sulfate is a very efficient wettability modifying agent towards carbonates at elevated temperatures. Key words: Carbonate, wettability, imbibition, sulfate, surfactant. Introduction In contrast to sandstone reservoirs, literature data indicate that about 80–90% of the worlds carbonate reservoirs show a negative capillary pressure, i. e., they are preferentially oil-wet. It is documented that close to 50% of the world proven petroleum reserves are located in carbonates, which usually show a rather low oil recovery factor (less than 30%) mainly due to the fractured nature of these reservoirs. Furthermore, the permeability of the matrix blocks is often in the range of 1–10 mD. Thus, the IOR potential from this type of reservoirs is very high. In a water-wet to mixed-wet formation, injected water may imbibe the matrix blocks spontaneously[1]. However in an oil-wet rock, spontaneous imbibition may not be possible due to small or negative capillary pressure. In fractured oil wet reservoirs the injected water will advance in the high permeable fractures resulting in early water breakthrough and low oil recovery[2]. Clean chalk is naturally water-wet, but crude oil may rupture the water film, and the surface active components of the crude oil can adsorb onto the rock surface rendering it oil-wet, as discussed in several papers[3–7]. The wettability depends both on the nature of the solid and the fluid properties, both oil and initial formation brine[8]. Several studies have shown that carbonate rocks become more water wet as the reservoir temperature increases[9–10]. Recent laboratory experiments by Zhang and Austad[11] have, however, documented that aging temperature played a minor role regarding wetting properties of chalk. The most important factor was the acid content in the crude oil determined by the acid number, AN. At pH conditions close to neutral or slightly basic, the carboxylic material in the crude oil acts as surface active material, making the oil-water interface negatively charged due to dissociation of the acid. The water solid interface is normally positively charged due to a large concentration of the potential determining ion Ca[2+] present in the initial brine[12]. The water film then becomes unstable, and the carbonate rock will chang wetting conditions depending on the amount of carboxylic groups present in the crude oil[11,13]. It is also known from the literature that carboxylic acid undergoes decarboxylation as the temperature increases, and the decarboxylation process is catalysed by CaCO[3](s)[14]. Thus, carbonate reservoirs at high temperature usually contain crude oils with a lower AN, and may therefore act somewhat more water-wet.