Abstract
3D imaging and pore network modeling is a potential breakthrough reservoir engineering tool that allows the prediction of petrophysical properties of a reservoir from small sample sizes not suited for laboratory testing (e.g, drill cuttings, sidewall core or damaged core). If a reasonable sample size (5mm-1cm) can be obtained, micro-CT scanning can be undertaken at resolutions of 2-4 microns. Using advanced image analysis techniques the pore structure and an equivalent pore network model of the rock can be extracted. This model retains key properties of the pore space of the rock sample in 3D. We then conduct flow simulations to predict key petrophysical properties such as porosity, permeability, formation factor, capillary pressure and resistivity.
In this work, a number of Saudi Aramco core plugs were chosen. A series of experimental measurements were also undertaken on the plugs. Smaller pieces of rocks (8mm diameter) were cut from the plugs and CT scanned at 4 microns resolution. Corresponding topologically equivalent networks were then constructed. Petrophysical properties were analyzed directly on the images and the pore network models.
The numerical results are compared with experimental counterparts. While porosity and resistivity data is in agreement, the predictions of capillary pressure and permeability can be significantly different. Reasons for the differences are explored. A key observation is that the modeling and experimental data may not match when comparing measurements at varying length scales — core scale heterogeneity should be accounted for. The need for incorporation of spatial information at varying length scales is discussed. An example of data integration on multiple scales is given. Necessary improvements to pore scale modeling techniques are discussed to address improved reliability in carbonate samples.
