Accurate modeling of vertical and horizontal permeability is difficult due to the lack of representative permeability data. A two step hierarchical process is presented where core photographs are used to assess small scale permeability followed by upscaling to a representative geomodeling cell size. Reservoir performance in general and SAGD performance specifically is largely governed by permeability. Traditionally, core plug and log data are used to model reservoir permeability through the inference of a porosity-permeability bivariate relationship; drawbacks include (1) variability and uncertainty in the porosity-permeability scatter plot as a result of sparse sampling and (2) biased core plug data taken preferentially from core located in sandy or homogeneous intervals. This paper expands on a methodology that utilizes core photographs to infer porosity-permeability relationships. The authors experience has been that this methodology is more robust because (1) there is abundant core photograph data available compared to core plug permeability and (2) bias can be avoided and/or corrected.
The proposed methodology entails building micro-scale models with 1-5mm cells conditional to ~5cm x 5cm samples from the core photographs. The micro-models are composed of a sand/shale indicator and realistic permeability values (ksand≈7000mD, kshale≈0.5mD). The spatial structure of the micro-model controls the resulting bivariate porosity-permeability relationships that are obtained from upscaling. Previously, these models were generated with sequential indicator simulation (SIS). However, SIS may not capture the spatial structure of the complex facies architecture observed in core photographs. Models based on multiple point statistics and object based techniques are proposed to enhance realism. Micro-models are upscaled with a steady-state flow simulation to determine a 5cm scale porosity-permeability relationship. The required geomodeling scale porosity-permeability relationships are determined with mini-modeling and further upscaling. This porosity-permeability relationship can be used to populate reservoir models with permeability and enhance traditional core data. A sample well from the Alberta Athabasca oil sands region is used to demonstrate the methodology.