Modeling of Facies and Net-to-Gross Ratio Conditioned by Seismic Attribute Maps

Abstract

Abstract The facies and net-to-gross ratio (NTG) modeling methodology presented in this paper has been successfully applied on geological characterization of a giant field at Campos Basin, offshore Brazil. Such methodology aimed to preserve the seismic attribute original trend for NTG property in the facies model. In this way, more reliable horizontal parameters could be determined. These are usually hard to obtain, due to the scarceness and huge spacing between wells in an oilfield at its initial development stages. The technique may be described as follows: Choice of a seismic attribute that shows good correlation with average NTG at wells using programme Log Property Mapping (SIS-Schlumberger Information Solutions). After that one must elaborate a non-reservoir average distribution map (NR=1-NTG map).Generation of reservoir facies proportion maps (three altogether) obtained by facies proportion interpolation at the wells (collocated co-Kriging) using the NTG distribution map as a secondary variable.Determination of horizontal variogram parameters. These are used in the non-reservoir facies simulation (from NTG distribution map) and correlated with vertical variogram range, obtained from well data.Determination of horizontal variogram parameters for each of the three reservoir facies using ratios between horizontal variograms range (two directions) and the vertical ones.Determination of NTG, naming 1 for reservoir facies and 0 for non-reservoir facies. In the modeling phase, mainly in the upscaling step, a particular interval named inter-stratified has been given special treatment. It shows a NTG value around 50% (against a 85% value for the field as a whole) and has been defined in order to preserve the critical reservoir heterogeneities. Once treated in a different way during the upscaling step, its characteristics can be preserved during the scale transfer, and consequently improving history match.