Determining Petrophysical Parameters of Rock during Phase Displacement with CT Technique

Abstract

Abstract This paper states that Computerized Tomagraphy (CT) is used to determine the porosity of unconsolidated rock (loose and unshaped), porosity distribution and saturations of solid rocks during oil/water or water/oil, air/water or water/air displacement. The results show that (1) the mean porosities and saturations of artificial or natural samples measured with CT technique are within experimental error of conventional results. (2) Oil/water or air/water non-uniform distributions and fingering phenomenon are interpreted during the displacement process. (3) Air/water distributions of 27 cm artificial samples during the displacement are non-uniform at the end of water/air displacement compared with the oil/water, water/oil or air/water samples. (4) Fractures between two spliced artificial samples with identical porosity and permeability leads to the fact that the saturation change in the region between fractures and inlet is greater than that between the fractures and outlet. Introduction Since 1972, the CT technique created by Housfield in England has been used successfully in exploration and development ofoilfields throughout the world. It can describe rock petrophysics and hydrocarbon reservior, and be used to study the interaction between oil and the driving fluid, oil saturation variations with production time, mud erosion. Combined with nuclear magnetic resonance (NMR), it can provide images of rock petrophysics and parameters of oil-bearing formation such as porosity, porosity distribution and distribution of the fluid in pore volume. Both porosity and saturation are important petrophysical parameters characterizing the formation, and are indispensable in formation evaluation and field development. In the past, measured values in the laboratory have been measured using the mean values of samples. The measurement error produced by this conventional test technology is too great for unconsolidated samples. Sometimes, it is very difficult to determine porosities of the unconsolidated samples with conventional methods, but easy to do with CT technique. It can be shown from porosity measurements of artificial or natural samples that results with CT are within experimental error of conventional testing. CT scanning can be used to determine pore distributions of rocks, and is especially useful for finding porosity in unconsolidated samples because of the reduction in measurement errors compared with conventional test technology. According to actual reservoir development, natural samples and 27cm long artificial samples are adopted to study saturation distribution during oil/water or water/oil, air/water or water/air displacement. The results show that CT scanning can directly display variations of fluid saturations in two-phase flow displacement, and determine distributions of saturations quantitatively. Experimental Principle In an actual formation, rock is composed of rock matrix and a pore system filled with gas or liquid. Fig. 1 shows this volumetric model expressed with the attenuation coefficients of the CT. Equation (1) where CTm is the attenuation coefficient of rock in HU unit (CT number); F is porosity of measured rock; CTR is the attenuation coefficient of rock's matrix; Sf, CTf is saturation and attenuation coefficient of liquid in pore system, respectively; Sg, CTg is saturation and attenuation coefficient of gas in pore system, respectively.