Sandstone vs. carbonate petroleum reservoirs: A global perspective on porosity-depth and porosity-permeability relationships

Abstract

Plots are presented comparing average porosity vs. depth for 30,122 siliciclastic petroleum reservoirs and 10,481 carbonate petroleum reservoirs covering all petroleum-producing countries except Canada. However, separate plots cover 5534 siliciclastic and 2830 carbonate reservoirs of the Alberta basin in Canada. Average permeability vs. average porosity is shown for the non-Canadian reservoirs. Key similarities and differences between sandstones and carbonates are noted, and implications are discussed regarding the dominant factors controlling reservoir quality in each lithology. Trends of steadily decreasing median and maximum porosity with increasing depth reflect burial diagenetic porosity loss in response to increasing thermal exposure with depth. These trends seem inconsistent with the suggestions that both sandstones and carbonates commonly increase in porosity by dissolution during deeper burial. Carbonate reservoirs have lower values of median and maximum porosity for a given burial depth, probably because of greater chemical reactivity of carbonate minerals relative to quartz and the resulting lower resistance to chemical compaction and associated cementation. Relative paucity of low-porosity (0–8%) siliciclastic reservoirs at all depths compared with carbonates may reflect the more common occurrence of fractures in carbonates and the effectiveness of these fractures for facilitating economic flow rates in low-porosity rock. Overall, carbonate reservoirs do not have lower permeability for a given porosity compared with sandstones but do have strikingly lower proportions of both high-porosity and high-permeability values. The data presented can serve as a general guide for the distribution of reservoir quality that can reasonably be expected in exploration wells drilled to any given depth in the absence of detailed geologic information, such as burial and thermal history.