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Seawater is characterized as an enhanced oil recovery (EOR) fluid for hot, fractured chalk oil reservoirs because it is able to modify the wetting conditions and improve the displacement of oil. The chemical mechanism for the wettability alteration has been described previously, and it was verified that Ca 2+ , Mg 2+ , and SO 4 2-played an important role because of their reactivity toward the chalk surface. Chalk, which is purely biogenic CaCO 3 , consists of fragmentary parts of calcite skeletons produced by plankton algae known as coccolithophorids, and it is believed to have a more reactive surface than ordinary limestone. To validate seawater as an EOR fluid also for limestone and dolomite, the affinities of these ions toward the rock surfaces must be evaluated. The present paper describes some preliminary experimental studies of the affinity of SO 4 2-, Ca 2+ , and Mg 2+ toward the surface of reservoir limestone cores at temperatures ranging from room temperature to 130°C. The results confirmed that the ions interacted with the rock surface, and that the established chemical equilibrium was sensitive to the relative concentrations of the ions. It was also observed that the adsorption of Ca 2+ and Mg 2+ from a NaCl solution onto the limestone surface was quite similar at room temperature but that Mg 2+ adsorbed more strongly at higher temperatures. At high temperatures, T ) 130°C, Mg 2+ in seawater was able to substitute Ca 2+ on the surface but the reactivity was less than for chalk. These findings indicate that seawater will act as an EOR fluid in limestone as well but its potential is probably smaller than for chalk. This was also confirmed by spontaneous imbibition tests performed at 120°C.

The wetting nature of a carbonate reservoir determines the potential of improved oil recovery by water injection, especially if the formation is highly fractured, which often is the case for chalk formations. The initial wetting state is mostly governed by the properties of the crude oil, where the acid number, AN, appeared to be a crucial parameter. The reservoir temperature plays, however, a minor role as a wetting parameter. Improved oil recovery by water injection decreases as the water-wetness decreases due to decrease in spontaneous imbibition. The relative high specific surface area of chalk, about 2–3 m2/g, indicates that compositional properties of injected fluid could influence the wetting properties of the formation somewhat during the production phase. The exceptional good response of seawater injection into the Ekofisk formation is an indication of a special rockwater interaction, which improves the spontaneous displacement of oil. In the present paper, we will summarize the results from ongoing research to improve spontaneous imbibition of water into oil-containing chalk samples at various wetting states and temperatures. The chemical composition of the imbibing fluid is discussed in relation to the composition of initial brine and changes in the rock-fluid (water and oil) equilibrium conditions. Major observations are:The presence of sulfate in seawater improved spontaneous imbibition at all wetting conditions tested.Sulfate is a potential determinig ion towards chalk, which has impact on the wetting state in a positive way.The adsorption of sulfate onto chalk increases as the temperature increases, which implies that the efficiency of sulfate as an active wettability modifier is improved as the temperature increases.The relative increase in sulfate adsorption onto chalk increases at temperatures above 100°C.Injection of produced water with a high Ca2+/SO4 2- ratio is recommended to be used only as pressure support and not as an oil displacing fluid. Introduction Improved oil recovery by water flooding of fractured carbonate reservoirs is usually not successful. The reason is that 90% of the carbonate reservoirs are characterized as neutral to slightly oil-wet, which prevents spontaneous imbibition of water from the fractures into the oil-containing matrix blocks1. The consequence is an early break through of injected fluid, which follows the fracture network from injector to producer. We have recently shown, that certain surface active compounds of the cationic type, [R-N(CH3)3]+, are able to modify the wetting condition to a more water-wet state2. In laboratory experiments, the oil recovery by spontaneous imbibition using such surface active material was even higher than the recovery obtained from a strongly waterwet system3. It was, however, discovered that sulfate in the injected fluid had a strong catalytic effect on the wettability alteration process. Both the imbibition rate and ultimate oil recovery increased, especially at low temperatures4. The properties of the imbibition process was also scaled using a scaling law containing both capillary and gravity forces developed by Li and Horn5. All parameters scaled properly, even the core dimension, when using just the core height as the shape factor in the scaling group. This indicated that gravity forces played an important role in the oil displacing process6. Recently, Hadhrami and Blunt7 observed wettability alteration of carbonates by injecting hot water/steam (240°C). They explained the wetting alteration by desorption of asphaltenic materials from the carbonate surface without any experimental verifications. Nomally, desorption of large molecules containing carboxylic groups from calcite surfaces requires special solvents8. Tang and Kovscek9 have also observed increased spontaneous imbibition into diatomic material containing heavy crude oil by hot-water injection. It was concluded from experimental observations that diatomic fines were detached with increasing temperature, and the authors suggested that fresh water-wet pore surfaces were created.

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.

Carbonate reservoirs are usually strongly fractured, with very high permeability contrasts between matrix blocks and fractures. Normally, a simulation of fluid flow with a dual porosity model is used, which is based on a fluid-exchange term where the dimensionless time is a key factor. Besides traditional reservoir rock and fluid parameters, the scaled dimensionless time must include the influence of capillary and gravitational forces. A very recent publication [Li and Horne, SPE Paper No. 77544, 2002] examined an “analytical” model that involved all these effects. In the present paper, we have tested the model for spontaneous imbibition of aqueous surfactant solution into preferential oil-wet carbonate cores. A chemical reaction occurs between the surfactant and adsorbed polar organic components/carboxylates at the carbonate surface, ahead of the fluid displacement process, as has been discussed previously [Standnes and Austad, J. Pet. Sci. Eng., 28, 123, 2000]. It was of great interest to determine if this new analytical model could handle such a process. The ranges for the scaling parameters were as follows:  interfacial tension (IFT), 0.3−0.8 mN/m; permeability, 3−350 mD; initial water saturation (S wi), 0−0.5; core height, 5−30 cm (but with the same diameter); diameter, 2.5 and 3.5 cm (but with the same core height); temperature, 40−70 °C; and sulfate concentration, 0−1.7 g/L. Temperature change has a great influence on the imbibition rate, because of changes in IFT, critical micelle concentration, and fluid viscosity. Sulfate, being a potential-determining ion toward CaCO3 [according to Pierre et al., J. Dispersion Sci. Technol., 11, 611, 1990] was observed to have catalytic effects on the wettability alteration process in chalk at low temperature [according to Strand et al., Energy Fuels, 17, 1133, 2003]. When the characteristic length (L a) is used as the shape factor of the cores, all the parameters scaled very well, except for the height of the core and the diameter of the core at low IFT (low temperature). However, when just the height of the cores was used as the shape factor, all the parameters scaled quite well when the normalized oil recovery was plotted versus dimensionless time. The fit of the scaling, using the height of the core as the shape factor, suggested that gravitational forces were very active in the oil recovery mechanism.