The Use of High Pressure MICP Data In Reservoir Characterization, Developing A New Model For Libyan Reservoirs

Abstract

Abstract Mercury injection capillary pressure data have been widely used to characterize reservoir rocks, evaluating sealing capacity for traps and to explain the locations of hydrocarbon accumulations and transition zones. This method can determine a broader pore size distribution more quickly and accurately than other methods. It can be used to characterize pores ranging from 0.003 pm to 360 µm using a single theoretical model. The data produced (mercury intrusion volume at various pressures) can be used to calculate numerous sample characteristics such as pore size distributions, total pore volume, total pore surface area, median pore diameter, and sample densities (bulk and skeletal). In this study the application of the high pressure mercury porosimetry technique in determination of different reservoir parameters have been investigated and a comparison between clastic and non clastic reservoirs was made. This was done by using data obtained from forty core samples from sandstone and carbonate reservoirs in North Africa. The results of different measurements and techniques were processed and interpreted. Theses included calculating the capillary pressure curves for the two rock types, converting the air/mercury curves to subsurface conditions and making sensitivity analysis for different parameters such as interfacial tension and contact angle. The distribution of pore-throat sizes and thus understanding the structures of pore systems in the reservoir has also been investigated. Another petrophysical reservoir property which was examined by this method was the existence of different types of porosity, (micro, meso and macro), which can be derived from the pore size distributions and compared between the two rock types, and therefore an attempt was made to classify the different rock types present in the studied samples. A set of Empirical relationships which relate absolute permeability to the pore throat size distribution, pore throats at different mercury saturations, were derived for each rock type, and then these relationships were more investigated by introducing the effect of porosity. Finally, an estimation of the pore size from routine core data was made and compared with the measured data. These empirical relationships were also compared with other available relatioships obtained by other authors such as Pittman and Winland. Introduction Capillary pressure is a critical parameter in reservoir characterization because it is a petrophysical property that controls the flow of different fluids in the reservoir and the amount of hydrocarbon that can be produced. Usually capillary pressure curves are obtained by using different laboratory techniques including centrifuge, porous plate and mercury injection. In this study the high pressure mercury injection technique was used to study the different parameters which can be obtained from capillary pressure curve and compare these parameters for different reservoir rock types. In general, reservoir rock types can be classified to clastic and non-clastic (sandstone and carbonate) reservoirs, these rock types can have different effects on the capillary pressure curve and hence on the interpretation of the reservoir potential. Sandstone rocks usually consist of particles ranging in size from 0.0625 to 2 mm and the dominated mineral in most sands is quarts (SiO2). They tend to be fine to coarse grained and usually poorly sorted with a clay matrix. They become more poorly sorted when they are finer; however, the coarser sands have very little in terms of matrix and are thus very porous. Carbonate rocks are usually formed in special environments and they are biochemical in origin, the distinctive and unique properties of carbonate rocks are their predominantly intrabasinal origin, their primary dependence on organic activities for their constituent and their susceptibility to modification by post-depositional mechanisms. Mercury injection as a laboratory method for determining the capillary pressure curve and pore throat size distribution in porous rocks was suggested at the first by Washburn (1921). Afterwards, Purcell (1949) was instrumental in developing mercury injection techniques and the following equation (1) was the basis of further work by many authors: