Factor Affecting Mercury Capillary Pressure Behavior of Saudi Arabian Carbonate Reservoir Rocks

Abstract

SPE Members Abstract Capillary pressure can be viewed as the pressure required to drive a fluid through a pore throat, with greater pressure being required as the pore throat becomes smaller. The size and distribution of pore throats within a host rock control its capillary pressure characteristics, which in turn control fluid behavior in the pore system. The pore geometry of carbonate rocks has as great influence on the ability of the rock to contain and produce oil and gas as do porosity and permeability. This has been demonstrated by examining a large number of samples from a Saudi Arabian carbonate reservoir. By studying the lithology and genesis of the rocks, and comparing families of capillary pressure curves, it was possible to establish very clear mutual relationships. The mercury injection technique followed by ejection and reinjection was used to determine capillary pressure behavior for each sample. Experiments were also performed to test the plug size and surface effects on capillary pressure plug size and surface effects on capillary pressure characteristics. A detailed interpretation of the data was carried out in order to extract various correlation parameters. These data were combined with basic rock properties and incorporated in generating families of capillary pressure curves for several carbonate rock types, and in the computation of pore throat size distributions. pore throat size distributions. Experimental data are presented using J-Functions for the correlation of capillary pressure and saturation relations for all samples. It is shown that the correlation improves significantly when the samples are grouped together based on the rock lithology. Introduction The distribution of immiscible fluids within the pores of a porous media depends on the capillary pressure which is a porous media depends on the capillary pressure which is a function of interfacial tension, pore size, wetting conditions and the manner in which the saturations of the fluids are attained. The two processes in which the fluid saturations are changing are the drainage process (non-wetting phase displacing wetting phase) and the imbibition process (wetting phase displacing the non-wetting phase). phase displacing the non-wetting phase). Mercury injection method is one of the methods used to obtain the capillary pressure curve. This method has the advantage of being a simple and fast test. In this method, the mercury is injected into an evacuated small core sample. The capillary pressure data obtained by this method can be transformed to reflect the fluid distribution in strong water-wet water-oil systems. For mercury injection method, the drainage process is referred to as the injection process while the imbibition process is referred to as the withdrawal process. For a given pair of immiscible fluids in a particular reservoir rock for any process, the capillary pressure is a unique function of the fluid saturation. Wardlaw et al. studied the various factors that influence the mercury injection and withdrawal curves. The factors include the sample size, coating effect and rates of injection and withdrawal using Indiana limestone. The results showed that:the sample size has not significantly affected the capillary pressure curves for Indiana limestone,the coated sample pressure curves for Indiana limestone,the coated sample requires a higher pressure for the mercury to enter the pores than that for uncoated sample, andthe rapid injection increased the apparent displacement pressure. P. 815