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Microporosity is very common in limestone reservoirs globally and is especially significant in many large Mesozoic reservoirs in the Middle East. Despite its common occurrence there is:Wide variation in its definition,Uncertainty around characterization, genetic controls, and distributionA rudimentary understanding of its influence on reservoir performance and hydrocarbon recovery. The results of this study, based on a global survey of microporosity and specific Middle Eastern case studies, provide clarity on each of these topics. One volumetrically significant type of microporosity occurs between micron size subhedral crystals of low magnesium calcite in matrix and within grains. This micro-pore system is very homogenous in terms of pore size distribution with 90% of pores between 1 and 3 microns in diameter. Pore throat radii range between 0.1 and 1.5 microns. Porosity, permeability, and capillarity relationships reflect this homogeneity for rocks dominated by microporosity. Rocks with less than approximately 80% microporosity exhibit a marked increase in pore system heterogeneity. A pore geometry characterization approach incorporating digital image analyses of petrographic thin-sections was developed and provides a very effective means of rapidly characterizing and quantifying the total pore system, including microporosity. The lateral and stratigraphic distribution of microporosity is systematically related to the distribution of depositional facies and the regional extent of burial diagenetic processes. Factors that inhibit burial diagenesis, such as hydrocarbon charge, also have a strong influence on the nature and distribution of microporosity. Remaining oil saturation in microporous limestone, as measured from centrifuge capillary pressure and steady state (SS) core flood experiments, is negatively correlated with the percent fraction of microporosity. Due to the homogenous nature of the micro-pore system, rocks dominated by microporosity have more favorable oil recovery than rocks with mixed pore systems. In the specific cases studied here, water provides more favorable recovery than gas. These results have implications for resource assessment, field development planning and optimization of ultimate recovery in limestone reservoirs with significant microporosity.

Flank margin caves are extreme endmembers of vuggy porosity that form as diagenesis drives the progressive coalescence of smaller solutional pore spaces.Due to their morphological isolation during formation, the prevailing hypothesis has been that fluid flow in and out of flank margin caves occurs via the matrix permeability and that adjacent chambers only become hydraulically connected through nonmatrix porosity during burial, collapse, and fracturing. To our knowledge, however, no studies have evaluated how flank margin caves are connected to regional flow systems in modern carbonate platforms. In this study, we evaluate the connectivity of wells, boreholes, blue holes, and flank margin caves in increasingly older bedrock on San Salvador Island, Bahamas, using tidal attenuation analysis. Phreatic karst features are not reported in Holocene bedrock, and permeability magnitudes from wells suggest Holocene deposits connect to the ocean along matrix-dominated flow paths. Permeability magnitudes in bedrock surrounding wells, boreholes, and karst features deposited during Marine Isotope Substage (MIS) 5e suggest connection to the ocean through matrix and touching vug porosity. Boreholes, blue holes, and flank margin caves in pre-MIS5 bedrock connect to the ocean via touching vugs. We suggest that increasing bedrock permeability, cave number, and cave size observed within progressively older bedrock on San Salvador is a function of the cumulative number of freshwater lenses emplaced over successive sea-level stillstands. We suggest that the morphologies of the two largest caves are consistent with dissolution in multiple lenses occupying lower elevations, collapse resulting in breakout domes, and overprinting of collapse chambers during subsequent highstands. As a result, some caves may not reflect connectivity of the bedrock surrounding the main chambers but may reflect connectivity of more diagenetically mature bedrock at lower elevations where their antecedent chambers formed.

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Microporosity is very common in limestone reservoirs globally and is especially significant in many large Mesozoic reservoirs in the Middle East. Despite its common occurrence there is: Wide variation in its definition, Uncertainty around characterization, genetic controls, and distribution A rudimentary understanding of its influence on reservoir performance and hydrocarbon recovery. The results of this study, based on a global survey of microporosity and specific Middle Eastern case studies, provide clarity on each of these topics. One volumetrically significant type of microporosity occurs between micron size subhedral crystals of low magnesium calcite in matrix and within grains. This micro-pore system is very homogenous in terms of pore size distribution with 90% of pores between 1 and 3 microns in diameter. Pore throat radii range between 0.1 and 1.5 microns. Porosity, permeability, and capillarity relationships reflect this homogeneity for rocks dominated by microporosity. Rocks with less than approximately 80% microporosity exhibit a marked increase in pore system heterogeneity. A pore geometry characterization approach incorporating digital image analyses of petrographic thin-sections was developed and provides a very effective means of rapidly characterizing and quantifying the total pore system, including microporosity. The lateral and stratigraphic distribution of microporosity is systematically related to the distribution of depositional facies and the regional extent of burial diagenetic processes. Factors that inhibit burial diagenesis, such as hydrocarbon charge, also have a strong influence on the nature and distribution of microporosity. Remaining oil saturation in microporous limestone, as measured from centrifuge capillary pressure and steady state (SS) core flood experiments, is negatively correlated with the percent fraction of microporosity. Due to the homogenous nature of the micro-pore system, rocks dominated by microporosity have more favorable oil recovery than rocks with mixed pore systems. In the specific cases studied here, water provides more favorable recovery than gas. These results have implications for resource assessment, field development planning and optimization of ultimate recovery in limestone reservoirs with significant microporosity.