Capillary-Pressure Characteristics and Pore-System Evolution of Mesozoic and Tertiary Carbonates from the Exmouth Plateau and Argo and Gascoyne Abyssal Plains

Abstract

The capillary-pressure characteristi cs of 22 samples of lithified post-Paleozoic Indian-Ocean carbonates were compared to published data from older carbonate rocks (lower Paleozoic Hunton Group of Texas and Oklahoma). The Indian-Ocean samples are considerably more porous than are the Paleozoic samples, yet all of the Indian-Ocean samples fit readily into a descriptive petrofacies scheme previously established for the Hunton Group. The Indian-Ocean samples may be assigned to four petrophysical facies (petrofacies) based on the shapes of their capillary-pressure curves, their pore-throat-size distributions, their estimated recovery efficiency values (for nonwetting fluids), and the visual characteristics of their pore systems, as observed with a scanning-electron microscope. Petrofacies assignments for the Indian-Ocean samples are as follows. Petrofacies I includes six samples collected from the coarse basal portions of event deposits (primarily turbidites). These samples have large throats, leptokurtic throat-size distributions, low- to moderate recovery efficiency values, concave cumulative-intrusion capillary-pressure curves, and high porosity values. Petrofacies II includes two sedimentologically dissimilar samples that have medium-size throats, platykurtic throat-size distributions, moderate- to-high recovery efficiency values, gently sloping cumulative-intrusion capillary-pressure curves, and high porosity values. Petrofacies III includes two polymictic sandstones and a skeletal packstone that have small throats, polymodal throat-size distributions, moderate recovery efficiency values, gently sloping cumulative-intrusion capillary-pressure curves, and high porosity values. Petrofacies IV includes 11 samples, mostly recrystallized neritic carbonates, that have small throats, leptokurtic throat-size distributions, high recovery efficiency values, convex cumulative-intrusion capillary-pressure curves, and low porosity values. Comparison of petrofacies assignment to core-, thin-section-, and smear-slide data, and to inferred depositional setting, suggests that pore systems in most samples from Holes 765C and 766A result from primary depositional features, whereas pore systems in samples from Hole 761C and one sample from Hole 765C have been strongly influenced by diagenetic processes. For Hole 761C, prediction of petrophysical parameters should be most successful if based on diagenetic facies patterns. By contrast, the distribution of favorable reservoir facies and of permeability barriers in less highly altered rocks collected from Holes 765C and 766A is related to depositional patterns. Recovery efficiency is inversely related to both porosity and median throat size for the present data set. This relationship is similar to that observed for carbonates of the lower Paleozoic Hunton Group and the Ordovician Ellenburger dolomite, but opposite of that observed for some other ancient carbonates. The coarse deposits of the massive basal units of turbidites are petrophysically distinct and form a coherent petrophysical group (Petrofacies I) with substantial reservoir potential. Two samples assigned to Petrofacies I have extremely large throats (median throat size at least 4 µm, and at least six times that of any other sample) and therefore high permeability values. These two samples come from thin, coarse turbidites that lack or have poorly developed fine divisions and are interpreted to have been deposited on channeled suprafan lobes in a proximal mid-fan setting. The restriction of extremely high permeability values to a single depositional facies suggests that careful facies mapping of deep-sea fans in a deliberate search for such coarse turbidites could dramatically enhance the success of exploration for aquifers or hydrocarbon reservoirs. Such reservoirs should have substantial vertical heterogeneity. They should have high lateral permeability values but low vertical permeability values, and reservoir sections should include numerous thin units having widely differing petrophysical characteristics.