With 20 years of exploration and development history, X field is at high water-cut, and the distribution of remaining oil is difficult to predict. This paper describes a method of pre-stack elastic inversion using the Poisson’s’ ratio attribute, that is sensitive to reservoir fluid, to model the distribution of remaining oil are in good agreement with the present oil production, providing confidence that the predicted distribution of un-swept oil is accurate.
X field is located in a normal fault belt, and has structure related to folding above a fault-bend. The reservoir is mainly Paleocene carbonate, primarily calcarenite. The porosity is up to 27%. The reservoir is covered by a 30ft layer of marl that provides an effective seal. The original hydrocarbon is mainly concentrated in the anticline related to a major fault. Although the reservoir is a good producer, previous studies relied on a reservoir model developed from 2D seismic data and somewhat limited geological and reservoir engineering data. Because of long term production, the oil leg is thin, and production is decreasing as SW increases rapidly. To maximize production, a 3D seismic data set has been collected to better define the remaining distribution of oil. Beginning with pre-stack gathers, extracting the different lithology and fluid information from both near and far offset data, Poisson’s ratio attributes are used to determine the distribution of remaining oil in the reservoir of hydrocarbon reservoir distribution.
Seismic waves propagating into subsurface strata are elastic waves, influenced by rock elastic properties. However, rock elastic properties are affected by the fluid features within rocks. Therefore, using rock elastic parameters to detect fluid is more reliable and accurate than seismic wave velocity. Only VP (P wave velocity) can be determined from poststack seismic data, while both VP wave and VS (shear wave velocity) can be determined from pre-stack seismic data, using the information available from incidence angle (offset) data (formula ? , ? , ? ). Additional elastic parameters such as Lame’s constant, the shear modulus, Poisson’s ratio and density, etc. can be calculated.
Logging information Figure 2 shows the porosity logs and fluids from well tests for the three wells used in this study. The average porosity of oil leg is almost 27%, while the average porosity of transition zone is lower. Differences in the thickness of the oil leg suggest that the reservoir is inhomogeneous. The thickness of oil layer in well TD1, TD2 and TD3 are 32ft, 38ft and 12ft, respectively. Although the reservoir is thick in total, most of them are filled with water, and the oil layer at the top is relatively thin and the mixing zone is not considered productive. Using the original logging data, this paper calculates rock elastic parameters such as the P-velocity (VP), shear velocity (VS), Poisson’s ratio (?), the Lame constant and the shear modulus. Experience in this field has indicated that Poisson’s’ ratio is the most sensitive property for characterizing variations in the reservoir fluid.