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Abstract

Examination of porosity data from Holocene and Pleistocene carbonate strata indicates that there generally is little or no porosity loss in the zone of near-surface water circulation [that is, in the vadose, meteoric-phreatic, or mixing zone(s)]. Thus, the transition from very porous carbonate sediments to well-cemented, low-porosity carbonate rocks is a dominantly subsurface process. Indeed, both shallow-and deep-marine carbonate strata show a continuous loss of porosity with depth, indicating that porosity-reducing processes act continuously from the surface to depths in excess of 4 km.

Experimental, observational, and geochemical data show that porosity loss through burial diagenesis results from both physical and chemical compaction and from cementation. In near-surface sections, dewatering, grain reorientation, grain breakage, and other mechanical processes lead to sediment/rock porosities as low as 30 percent. Continued porosity loss requires mechanical compaction, chemical dissolution at grain contacts and along solution seams or stylolites, and/or re-precipitation of dissolved calcite as intergranular cement. Calcareous shales or marl seams (donor beds) can act as significant sources of dissolved carbonate which is precipitated as cement in adjacent limestones (recipient beds). Quantitantive studies of stylolites and solution seams commonly underestimate the total magnitude of pressure solution because they ignore contributions from associated thick calcareous shale sections and from thinner, regularly and irregularly distributed marl interbeds. Through these mechanisms, carbonate rock porosity may be reduced to values near zero in “semi-closed” systems without significant introduction of allochthonous cementing material.

In many young, subsiding basins, patterns of porosity loss with depth are crudely predictable. These patterns provide standards against which individual case studies of diagenesis may be compared and provide predictive tools for estimating porosity prior to drilling. In other areas, the standards allow identification of anomalously high porosity and focus attention on specific mechanisms which would act to preserve primary (or early diagenetic) porosity or to create secondary porosity at depth. Comparisons of oil field porosities with standard curves will allow further refinement of our understanding of diagenetic processes.

Predictive models are still in their infancy, however. There is a critical need to independently assess how rates of porosity loss with depth are affected by time, temperature, depositional setting, early diagenetic history, maturation history of organic matter, and other factors. In addition, overpressuring, early oil migration, dolomitization, and hydrothermal alteration are known to affect porosity-depth relationships. Refining our understanding of these factors may help geologists trse their general knowledge of basin history to make valid predictions of carbonate reservoir quality in frontier areas.

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