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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.

Core and log data from Lower Cretaceous limestones of the Upper Shu’aiba Member were used to characterize the distribution of lithofacies, clay and porosity within two low-angle clinoforms that form the reservoirs for an oilfield of northwestern Oman. Data from 15 vertical wells, including four with core, and four horizontal well cores were projected into a dip-oriented cross-section derived from a static reservoir model as a basis for visualizing the above variations. Each clinoform consists of a basal “argillaceous zone” and a thicker “reservoir zone” of clean limestone, together reflecting fourth-order cycles of progradation along the margin of the Bab intra-shelf basin. Lithofacies vary in a proximal direction from mudstone and wackestone (mid-ramp) to mud-dominated packstone (slope) to mud-rich floatstone, rudstone and boundstone (ramp crest) and are arranged in a pattern of decreasing water depth and increasing energy both upwards and landward within each clinoform. In contrast, the reservoir zone of a younger clinoform from a nearby oilfield consists of well-sorted grainstone and grain-dominated packstone, illustrating the wide range of depositional conditions that occurred in the ramp-crest facies belt of different units.Except within the proximal extent of the younger clinoform, where values are transitional toward reservoir zone values, the argillaceous zones have total porosity mostly < 10% and baseline-normalized gamma-ray (GR) activity > 23 API units, reflecting clay contents of around 10–18%. In contrast, most parts of the reservoir zones have GR of 15–23 API units and porosity of 10–35%. Higher clay content is suggested to be linked with lower porosity through facilitation of both mechanical and chemical compaction, the latter providing a local supply of calcite cement. XRD analyses show that the clays are kaolin, illite/smectite and illite, similar to the clays in the overlying Nahr Umr shale. Most former macropores have been filled by blocky calcite cement in the main oilfield studied, but all lithofacies have similar wide ranges of total porosity of 8% to > 30%.The cores were also studied for evidence of diagenesis related to the contact with the overlying Nahr Umr Formation, but profiles of stable-isotope ratios, bulk-rock strontium, petrography and porosity-permeability data show no trends indicative of upward-increasing meteoric diagenesis below this sequence boundary. Meteoric leaching could nevertheless be pervasive throughout the Upper Shu’aiba reservoirs, at least partially accounting for extensive aragonite dissolution and low Sr and δ18O values. Two of the cores show trends of upwards-increasing bulk-rock uranium, manganese and iron, possibly indicative of sea-floor authigenesis. In addition, saddle dolomite near the tops of these cores may reflect late influx of magnesium derived from clay in the Nahr Umr Formation.

Abstract Core samples from 10 wells in Lower Cretaceous limestones of the Upper Shu'aiba Formation were characterized by conventional core analyses, petrography, bulk chemical analyses, and mercury injection capillary pressure data to define reservoir rock types (RRT) for input to reservoir modeling. Initial grouping by lithofacies allows linkage of rock types to a 3D geological model, but results in RRT with high degrees of overlap in petrophysical properties. When diagenesis is included, however, in the form of porosity cut-offs added to the lithofacies criteria, RRT can be defined having both 3D geological significance and distinct ranges of pore-throat size distribution. The use of total porosity as a rock typing criterion is based on the interpretation that porosity is controlled on reservoir scale by depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms have low clay and thus highest porosity. Although most of the pore space is microporosity, higher total porosity corresponds with higher proportions of macropores and probably also with greater frequency of open fractures, resulting in better permeability. High-porosity samples also have several systematic positive differences in MICP characteristics from lower-porosity samples of the same lithofacies. Because both lithofacies and porosity are related to the sedimentological and stratigraphic organization of the Upper Shu'aiba clinoforms, the RRT defined by these criteria can potentially be implemented in a reservoir model for assigning particular ranges of petrophysical properties to distinct portions of each clinoform. By this procedure, seven RRT have been defined in the present selection of samples.

Core samples from 10 wells in Lower Cretaceous limestones of the Upper Shu'aiba Formation were characterized by conventional core analyses, petrography, bulk chemical analyses, and mercury injection capillary pressure data to define reservoir rock types (RRT) for input to reservoir modeling. Initial grouping by lithofacies allows linkage of rock types to a 3D geological model, but results in RRT with high degrees of overlap in petrophysical properties. When diagenesis is included, however, in the form of porosity cut-offs added to the lithofacies criteria, RRT can be defined having both 3D geological significance and distinct ranges of pore-throat size distribution. The use of total porosity as a rock typing criterion is based on the interpretation that porosity is controlled on reservoir scale by depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms have low clay and thus highest porosity. Although most of the pore space is microporosity, higher total porosity corresponds with higher proportions of macropores and probably also with greater frequency of open fractures, resulting in better permeability. High-porosity samples also have several systematic positive differences in MICP characteristics from lower-porosity samples of the same lithofacies. Because both lithofacies and porosity are related to the sedimentological and stratigraphic organization of the Upper Shu'aiba clinoforms, the RRT defined by these criteria can potentially be implemented in a reservoir model for assigning particular ranges of petrophysical properties to distinct portions of each clinoform. By this procedure, seven RRT have been defined in the present selection of samples.

Core and log data from Lower Cretaceous limestones of the Upper Shu'aiba (US) Member in northwestern Oman were examined for evidence of diagenesis related to the top surface where this reservoir is overlain by shale of the Nahr Umr Formation. Cores from six vertical wells in three oilfields were studied by profiles of conventional core analyses, petrographic observations, and bulk-rock geochemical analyses. Neither bulk-carbonate stable-isotope analyses nor bulk-rock strontium concentrations show trends indicative of upward-increasing meteoric diagenesis below the top-US surface. Porosity and permeability data also show neither increasing nor decreasing vertical trends suggestive of surface-related diagenesis. Meteoric leaching and cementation may nevertheless be pervasive throughout the US reservoirs, at least partially accounting for extensive aragonite dissolution and filling of the resulting macropores with coarse calcite cement. Three of the cores show trends of upwards-increasing bulk-rock iron, manganese, phosphorous, and uranium. These effects are attributed to sea-floor authigenesis driven by reducing conditions within the upper several meters of sediment following each cycle of US sedimentation. In addition, the top 7 m of limestone in one of the cores contains several percent late saddle dolomite, and minor saddle dolomite also occurs near the tops of several other cores. Mg for dolomitization can have been provided from diagenesis of clay in the Nahr Umr Formation. The results of this study thus indicate both early sea-floor mineralization and late dolomitization in some places below the top-US surface, but do not confirm locally more intense meteoric diagenesis underlying this surface.