Changes

===Stage 5. Reservoir zonation===

===Stage 5. Reservoir zonation===

In this stage, it is necessary for the geologist to subdivide each well (reservoir quality profile) into relatively homogeneous units or zones. Initially it is best to construct a relatively detailed zonation reflecting major variations in reservoir rock characteristics regardless of their vertical dimensions (Figure 4).

In this stage, it is necessary for the geologist to subdivide each well (reservoir quality profile) into relatively homogeneous units or zones. Initially it is best to construct a relatively detailed zonation reflecting major variations in reservoir rock characteristics regardless of their vertical dimensions ([[:file:evaluating-diagenetically-complex-reservoirs_fig4.png|Figure 4]]).

Zonation may be facilitated by establishing criteria by which major categories of reservoir rock types present can be distinguished. Semilog crossplots of porosity and permeability keyed to texture, matrix content, and diagenetic component content are very useful. Through examination of these plots, the geologist can quickly separate samples into natural groupings (Figure 3). Because permeability directly reflects fluid flow capacity, it is the major parameter used to designate reservoir rock categories. Because porosity is commonly a major control on permeability, it generally exhibits a positive correlation with that variable. Attempts to create hierarchies of permeability heterogeneity based strictly on depositional criteria<ref name=Lewis, 1978>63rd Annual SPE Technical Conference Proceedings, p.449-463, SPE #18153</ref>  should be avoided in reservoirs where diagenetic alterations are major controls on permeability heterogeneity. If natural groupings are not present, it may be necessary to set arbitrary group boundaries, such as porosity or permeability cutoffs.

Zonation may be facilitated by establishing criteria by which major categories of reservoir rock types present can be distinguished. Semilog crossplots of porosity and permeability keyed to texture, matrix content, and diagenetic component content are very useful. Through examination of these plots, the geologist can quickly separate samples into natural groupings ([[:file:evaluating-diagenetically-complex-reservoirs_fig3.png|Figure 3]]). Because permeability directly reflects fluid flow capacity, it is the major parameter used to designate reservoir rock categories. Because porosity is commonly a major control on permeability, it generally exhibits a positive correlation with that variable. Attempts to create hierarchies of permeability heterogeneity based strictly on depositional criteria<ref name=Lewis, 1978>63rd Annual SPE Technical Conference Proceedings, p.449-463, SPE #18153</ref>  should be avoided in reservoirs where diagenetic alterations are major controls on permeability heterogeneity. If natural groupings are not present, it may be necessary to set arbitrary group boundaries, such as porosity or permeability cutoffs.

Estimation of the lateral distribution of zones is then guided by relationships developed in the integrated geological model and documented in the form of maps and cross sections.

Estimation of the lateral distribution of zones is then guided by relationships developed in the integrated geological model and documented in the form of maps and cross sections.