Stephen N. Ehrenberg

Carbonate porosity creation by mesogenetic dissolution: Reality or illusion?

Many authors have proposed that significant volumes of porosity are created by deep-burial dissolution in carbonate reservoirs. We argue, however, that this model is unsupported by empirical data and violates important chemical constraints on mass transport. Because of the ubiquitous presence and rapid kinetics of dissolution of carbonate minerals, the mesogenetic pore waters in sedimentary basins can be expected to be always saturated and buffered by carbonates, providing little opportunity for the preservation of significantly undersaturated water chemistry during upward flow, even if the initial generation of such undersaturated pore water could occur. A review of the literature where this model has been advanced reveals a consistent lack of quantitative treatment. In consequence, the presumption of mesogenetic dissolution producing a net increase in secondary porosity should not be used in the prediction of carbonate reservoir quality.

Uranium depletion across the Permian–Triassic boundary in Middle East carbonates: Signature of oceanic anoxia

We present a geochemical profile through a 445-m (1459.9-ft) section of shallow-water carbonate platform strata in the upper part of the Khuff Formation. The Permian–Triassic boundary (PTB) is recognized in this section based on the immediately preceding negative shift in bulk-rock carbonate carbon isotope composition (equivalent to the end-Permian extinction horizon), combined with biostratigraphic control from nearby wells. These strata show an abrupt and long-lasting decrease in bulk-rock uranium (U) content coincident with the carbon isotope shift. Because of low siliciclastic content and the consequently low potassium and thorium of these carbonates, the decrease in U is clearly reflected in the total gamma-ray (GR) profile recorded by wire-line logging. Published log curves show similar distinctive GR profiles throughout a large area of the Middle East, indicating that U depletion across the PTB is a regional characteristic. This feature cannot be explained as diagenetic and is not related to the organic matter content of the host sediments, but it is suggested to reflect the global depletion of U in earliest Triassic seawater, caused by the abrupt onset of deep-ocean anoxia and the resulting increase in U precipitation in oxygen-poor sediments. This explanation carries the implication that similar U depletion should be characteristic of lowermost Triassic carbonates from shallow-water (oxygenated) settings worldwide. Analogous signatures of U depletion should also have developed in shallow-water carbonates deposited contemporaneously with episodes of deep-ocean anoxia during other periods of geological time. These predictions can be tested by high-accuracy U profiling of other well-characterized carbonate successions, potentially yielding a new approach for tracking the degree of oceanic circulation throughout Earths history.

An overview of reservoir quality in producing Cretaceous strata of the Middle East

ABSTRACT A compilation of average porosity and permeability data for Cretaceous petroleum reservoirs of the Middle East reveals important differences between the two main tectonic provinces. The Arabian Platform is characterized by inverse correlation of average porosity with burial depth in both carbonates and sandstones, whereas the Zagros Fold Belt (almost exclusively carbonates) has distinctly lower porosity and no depth correlation. These contrasts are suggested to reflect the fact that Arabian Platform strata are mostly near their maximum burial depth, whereas Zagros strata have experienced varying uplift and erosion following maximum burial in mid-Tertiary time. The carbonate reservoirs show no correlation between average porosity and average permeability, probably because of wide differences in the dominant pore types present, and permeabilities tend to be much higher for sandstones than for carbonates. Existence of the Arabian Platform porosity–depth correlation, despite an apparently wide diversity of depositional settings and early diagenetic porosity modifications among the individual reservoirs, illustrates and confirms some fundamental generalities about how burial diagenesis controls the overall porosity evolution of reservoir rock bodies. Although porosity commonly shows enormous small-scale heterogeneity in both carbonates and sandstones, the average pre-burial porosity of larger stratigraphic intervals tends to be very high. Burial diagenesis progressively destroys this porosity by chemical compaction and associated (stylolite-sourced) cementation. Thus, all portions of the affected rock body move toward the zero limit as depth increases, although the rates of porosity occlusion vary greatly, depending on rock fabric and early diagenesis. Average reservoir porosity therefore tends to correlate inversely with maximum burial depth, regardless of initial lithological heterogeneity.

Reservoir rock typing of Upper Shu’aiba limestones, northwestern Oman

Core samples from seven wells in Lower Cretaceous limestones of the Upper Shu’aiba Member were characterized by conventional core analyses, petrography, bulk chemistry and mercury-injection capillary pressure data to define reservoir rock types (RRT). In the main oilfield studied, lithofacies are arranged in three main belts corresponding to ramp crest, upper slope and lower slope, with bioclast content and size decreasing down depositional dip. Rock typing is based on the observation of distinct, but overlapping, porosity–permeability transforms for each lithofacies, although most samples plot in or below the class 3 field of Lucia, reflecting the presence of abundant lime-mud matrix. Because of the wide range of porosity in each of the main lithofacies, an arbitrary division at 20% porosity is used in combination with lithofacies to define RRT with both three-dimensional (3D) geological significance and distinct ranges of permeability and capillary pressure characteristics. The use of total porosity as a rock-typing criterion is based on the interpretation that porosity is controlled on the reservoir scale by the depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms a have low clay, and, thus, highest porosity. Because both lithofacies and porosity are linked to the sedimentological and stratigraphic organization of the Upper Shu’aiba clinoforms, the RRT can potentially be implemented in a reservoir model for assigning distinct ranges of petrophysical properties to the different architectural elements comprising each clinoform. Two additional grain-dominated RRT have also been defined in a single core that was available from a second oilfield.

Upper Shu'aiba Limestone Reservoirs of Northwest Oman - Geometry, Depositional Facies and Controls on Reservoir Quality

A comprehensive geological and petrophysical dataset from Upper Shu’aiba clinoform bodies in northwest Oman has been used for reservoir characterization, understanding the factors determining reservoir quality, and reservoir rock typing. Lithofacies are grouped into three main facies belts, showing increasing bioclast proportions and size both upwards within each clinoform and towards the basin margin. Most lithofacies are mud-rich, with even the coarsest floatstones and rudstones containing abundant mud matrix between rudist, sclerosponge, and coral clasts. Total porosity is strongly partitioned between the lower and upper hemicycles of each clinoform and also increases towards the basin margin. Wide porosity variations within each lithofacies reflect control of porosity loss by clay abundance, as reflected in overall inverse correlation between total porosity and bulk-rock alumina content. Reservoir rock types with meaningful differences in both porosity-permeability transforms and MICP parameters were defined by applying porosity cut-offs at an arbitrary value of 20% to the three main lithofacies. Because both lithofacies and porosity are predictably related to the sedimentological and stratigraphic organization within the clinoform bodies, the RRT thus defined can potentially be implemented for assigning specific ranges of petrophysical properties throughout a reservoir model.