The statistical histograms of core porosities and permeabilities illustrate that the distribution of reservoir porosity for Chang 6 Formation is from 5.0% to 12.0%, the average value is 8.2%, reservoir permeabilities range from 0.71 to 3.98 mD, and the average permeability is 1.26mD, belongs to typical tight sandstone reservoirs. In this study, based on the core scale logging method, the relationship between core derived porosity and interval travel time (the only acquired conventional porosity logging series in Chang 6 Formation of north Ordos basin) is established to estimate tight sandstone reservoir porosity. The relationship between core porosity and permeability is not classical power or exponential function. The tendency between core porosity and permeability is disparate for rocks with 9% as the boundary. When porosities are higher than 9%, permeabilities increase much faster when rock porosity increase. To establish the unified permeability estimation model, the cubic function is applied after the data set of reservoir permeabilities are taken logarithmic. Several wells that processed with the established models illustrate that the estimated porosities and permeabilities are coincided with the core analyzed results very well. The absolute errors between the estimated porosity and core analyzed results are lower than 0.45%, and the relative errors between them are lower than 5%. This meets the regulation of petroleum reserves estimation, and can be used for evaluation of reserves directly.

You can access this article if you purchase or spend a download.