Abstract: Microporosity in carbonate reservoirs is generated by the complex interplay between depositional and diagenetic processes. This petrographical, SEM, fluid-inclusion and isotopic study of a Lower Cretaceous carbonate reservoir, Abu Dhabi, UAE, revealed that: (1) micritization of ooids and skeletal fragments, which resulted in spheroidal (rounded) micrite, accounts for most microporosity in peloidal packstones and grainstones; and (2) transformation of spheroidal micrite into subhedral/euhedral micrite and microspar, known as aggrading neomorphism, could happen via precipitation of syntaxial calcite overgrowths around micrite (micro-overgrowths) and not only, as suggested previously in the literature, by recrystallization involving the dissolution (of micrite) and reprecipitation (of microspar). Precipitation of calcite cement around micrite (i.e. destruction of microporosity) is more extensive in the water zone than in the oil zone, which is possibly contributing to the lower porosity and permeability of the carbonate reservoir in the water zone. Similarity in bulk oxygen isotopic values of micritized packstones and grainstones in the water and oil zones (average δ 18 O V-PDB = −7.2‰ and −7.8‰, respectively) is attributed to: (1) a small difference in temperatures between the crest (oil zone) and the flanks (water zone); and (2) calcite precipitation around micrite occurred prior and subsequent to oil emplacement. Bulk carbon and strontium isotopic compositions of micritized packstones and grainstones in the water and oil zones (average δ 13 C V-PDB = +3.7‰ and average 87 Sr/ 86 Sr ratios = 0.707469) indicate that calcite cement was derived from marine porewaters and/or dissolution of the host limestones. The minimum formation temperatures of bulk micrite/microspar, which are inferred based on paragenetic relationships, fluid-inclusion microthermometry and oxygen isotope data, are around 58–78°C.

Abstract Diagenetic changes such as cementation or dissolution have a strong control on carbonate pore structure, and often disconnect the original intergranular pore space. Spatial distribution of submicron porosity (microporosity) that develops in the process, as well as its influence on flow properties, is difficult to image and characterize. Yet, a petrophysically rigorous pore-scale model that accounts for submicron porosity interconnectivity would help in the understanding and development of carbonate reservoirs dominated by microporosity. We present algorithms to geometrically match pore–throat networks from two separate length scales that can be extracted directly from three-dimensional (3D) rock images, or be constructed to match the relevant measured properties. We evaluate the combined influence of cementation and dissolution using a Bentheimer Sandstone sample, as well as image-identified microporosity on flow transport properties in an Estaillades Limestone sample.

Abstract Oolitic grainstone reservoirs, such as the Jurassic Smackover (Guillotte et al, 1979), the Cretaceous Sligo (Mitchell-Tapping, 1981), and the Cretaceous Rodessa (Keith and Pittman, 1983) can be diagenetically altered so that the oolites are micritized and microporosity forms. Because of the very high capillary pressures associated with microporosity in the oolites, hydrocarbons cannot enter the very small pores which, then, contain only immoveable, bound water. The water saturated microporosity results in the grains, which are the micritized oolites, acting as conductors of electric current (Figure 10). When this occurs, the path of electric current is less tortuous since it is flowing through the micritized oolites rather then around them. This causes resistivity logs to read erroneously low resistivities when microporosity is present. When water saturation, based on resistivity measurements, is calculated in a hydrocarbon-bearing zone with microporosity, the values will be too high suggesting a reservoir which will produce water. The water saturation values are merely reflecting the lower resistivity due to the very high bound-water content, and are not giving correct information about the hydrocarbon content of a reservoir. Keith and Pittman (1983) developed a logging technique for differentiating bimodal (mega and microporosity) from unimodal (megaporosity) carbonates in the Cretaceous Rodessa Limestone. To do this, they plot true formation resistivity (R t ) versus the ratio of the flushed zone's resistivity to the resistivity of the mud filtrate (R xo /R mf ). They found that a plot of R t versus R xo /R mf differentiated facies with bimodal porosity from facies with unimodal porosity. Consistently, oolitic carbonates with mega and microporosity (bimodal) have a much lower ratio of R xo /R mf than do carbonates with only mega porosity (unimodal). The lower ratio of R xo /R mf in oolitic carbonates with bimodal porosity is the result of the high bound-water content in the microporosity (Figure 10) which can't be flushed during invasion. The presence of large amounts of bound formation water in the flushed zone lowers the resistivity of the shallow reading resistivity log (R xo ).