Seismic velocities were measured in the laboratory vs pressure, temperature, and saturation on over 80 cores from various carbonate reservoirs in Alberta, using an ultrasonic pulse transmission method. Porosity, permeability, electrical properties, and capillary pressure were also measured in order to characterize the pore systems. All the measured data and other information are compiled into a database. The results show that both permeabilities and seismic velocities are related to the porosities of the cores, although the data are scattered. Liquid saturation (e.g. oil and water) increases the compressional velocity but has only nominal effect on the shear velocity. The magnitude of the increase in compressional velocities with liquid saturation is dependent upon the pore geometry of the rocks, reservoir pressure, as well as the distribution and properties of the saturating fluids. The velocity data are also fit to the time-average equation and the Gassmann equation. The results are usually unsatisfactory, which mean that the time-average equation used in sonic log interpretation is inadequate. For log interpretation, it might be desirable to establish a porosity-velocity relationship specific to carbonate reservoirs, instead of using the time-average equation. Furthermore, the Gassmann equation does not adequately explain the laboratory results. In most of the cores measured, the compressional velocities increase by more than 5% with oil saturation, with a subsequent decrease by over 5% when flooded with a hydrocarbon solvent. This suggests that seismic monitoring of injected gases and hydrocarbon solvent in carbonate reservoirs should be possible. Introduction Seismic properties or rocks are very important to petroleum exploration and production. In seismic exploration, velocity and density contrast between two rock layers causes reflection of seismic waves at the interface. The reflected seismic waves bring out information on the structure of the earth's crust, so that the seismic interpreter can look for potential hydrocarbon traps from the seismic profile. In the process of seismic exploration, a thorough understanding of seismic velocities in rocks plays a vital role in the success of seismic methods. In recent years, seismic methods have found other applications with success in petroleum production assessment, reservoir characterization, and enhanced oil recovery (EOR) and production monitoring. In seismic monitoring applications, the velocity contrast caused by various EOR and production processes is the physical basis of the method. Laboratory results have shown that large velocity decreases are found in heavy oil sands as temperature increases(1–5), in oil-saturated rocks when flooded with carbon dioxide (CO2(6,7) and in oil-saturated rocks when flooded with gas and hydrocarbon solvent(8,9). Furthermore, laboratory result also show large differences between the compressional velocities in gas and liquid (e.g. water or oil) saturated rocks(10). These results open the door for using seismic methods to monitor EOR and production processes. In the literature, most of the seismic velocity data were measured in sandstones and sand. Little has been published on seismic properties of carbonate rocks. Rafavich er al.(11) measured 93 Mission Canyon formation carbonate cores from four wells in the Williston basin field, North Dakota, which appears to be the only systematic study of seismic velocities in carbonates.

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Electrical and other petrophysical properties were measured in the laboratory versus pressure in 54 carbonate core samples from 11 oil-producing reservoirs. The measured electrical and petrophysical properties include formation factor F, cementation exponent m, and saturation exponent n, porosity φ, permeability K, grain density ps, capillary pressure Pc, residual (irreducible) water saturation Swr, and sonic velocities. In the measured cores, systematic relationships exist between formation factor and porosity, permeability and porosity, permeability and residual water saturation, saturation exponent and residual water saturation, and formation factor and sonic velocities, although the data are significantly scattered. The formation factors were best-fit to Archie’s equation so that the coefficient a and cementation exponent m were obtained. The empirical equations allow for calculation of porosity from formation factor, permeability from porosity and residual water saturation, and saturation exponent from residual water saturation, or vise versa.