Research paperStatistical modeling of biogenically enhanced permeability in tight reservoir rock

- Hydrofacies (HF) are defined on the basis of sedimentary and ichnologic features.
- Markov chain analysis is used to assess the effect of grain size vs. HF on kmax.
- The volumetric proportions of kmax show a 15% correlation with grain size.
- The volumetric proportions of kmax show a 97% correlation with HF.

Bioturbation is generally perceived to be detrimental to bulk permeability by reducing primary grain sorting, homogenizing sediment, and introducing mud as burrow linings and feces. Recent studies show, however, that some ichnogenera and biogenic fabrics serves to increase porosity and permeability. In tight hydrocarbon reservoirs, subtle changes in sand and silt distributions, such as may be generated by bioturbation, can greatly affect the resulting porosity and permeability distribution. Despite this, permeability across unfractured sedimentary reservoirs is commonly assessed solely on the basis of average grain size. This study of the Lower Cretaceous Viking Fm integrates sedimentary and ichnologic features to define recurring “hydrofacies” that possess distinct permeability grades. Grain size, lithology, bioturbation index, and trace fossil suites were described from a cored section of well 14-30-22-16W4. The kmax values from small plugs and full-diameter core samples were used to represent each hydrofacies. Hydrofacies were qualitatively defined at the bed/bedset scale, based on sedimentary, ichnological and permeability attributes, all of which affect flow pathways in heterolithic facies. The Markov chain method was employed to compare the vertical transitions of permeability (kmax) within a borehole against grain size and hydrofacies at the bed to bedset scale. This provided an intuitive framework for interpreting facies relationships such as coarsening-upwards successions. The results show that in the studied core, grain size only correlates to permeability in homogeneous rock units. The transiograms show that the volumetric proportions of different kmax classes show a 15% correlation with grain size, compared to a 97% correlation with the hydrofacies, indicating that variations in permeability down the well are strongly related to variations in the hydrofacies. The hydrofacies approach potentially can be used as a conceptual framework for the spatial modeling of permeability in tight hydrocarbon reservoirs, where grain size may not be the primary factor on permeability distributions.