Abstract Understanding and predicting architecture and facies distribution of syn-rift carbonates is challenging owing to complex control by climatic, tectonic, biological and sedimentological factors. CarboCAT is a three-dimensional stratigraphic forward model of carbonate and mixed carbonate–siliciclastic systems that has recently been developed to include processes controlling carbonate platform development in extensional settings. CarboCAT has been used here to perform numerical experiment investigations of the various processes and factors hypothesized to control syn-rift carbonates sedimentation. Models representing three tectonic scenarios have been calculated and investigated, to characterize facies distribution and architecture of carbonate platforms developed on half-grabens, horsts and transfer zones. For each forward stratigraphic model, forward seismic models have also been calculated, so that modelled stratal geometries presented as synthetic seismic images can be directly compared with seismic images of subsurface carbonate strata. The CarboCAT models and synthetic seismic images corroborate many elements of the existing syn-rift and early-post-rift conceptual model, but also expand these models by describing how platform architecture and spatial facies distributions vary along-strike between hanging-wall, footwall and transfer zone settings. Synthetic seismic images show how platform margins may appear in seismic data, showing significant differences in overall seismic character between prograding and backstepping stacking patterns.

Oil and gas reside in reservoirs within peritidal and shallow subtidal lagoonal carbonate sediments across the globe. This is a zone of facies heterogeneity, controlled by changes in depositional energy, water depth, clastic influx, and evapotranspiration. Close proximity to evaporitic brine pools means that it is also an environment with the potential for dolomitization during shallow burial. As a result, the original pore system of carbonate sediment can become drastically altered prior to burial, such that reservoir properties may not be predictable from facies models alone. The Miocene Santanyí Limestone Formation, Mallorca, Spain, is well exposed and has undergone minimal burial and therefore presents an excellent opportunity to integrate sedimentology, facies architecture, and diagenesis to determine how porosity evolves within individual facies in the shallow subsurface. From here, the impact on pore type, pore volume, pore connectivity, and petrophysical anisotropy can be assessed. The Santanyí Limestone consists of pale mudstones and wackestones, rooted wacke-packstones, stratiform laminites, and skeletal and oolitic, cross-bedded grainstone. Thin-section analysis reveals a paragenetic pathway of grain micritization, followed by dissolution of aragonite, possibly by meteoric fluids associated with karstification. Subsequently, the unit underwent fracturing, compaction, recrystallization, cementation, dolomitization, and matrix dissolution to form vugs. Petrophysical analyses of 2.54-cm-diameter plugs indicate that these complex diagenetic pathways created petrophysical anisotropy [mean horizontal permeability (Kh)/vertical permeability (Kv) of whole formation = 3.4] and that measured parameters cannot be related directly to either geological facies or pore type. Instead, petrophysical data can be grouped according to the diagenetic pathways that were followed after deposition. The best reservoir quality (i.e., typical porosity 15 to >40% and permeability >100 mD) is associated with pale mudstones, stratiform laminites, and skeletal and oolitic grainstone that have undergone pervasive recrystallization or dolomitization. These rocks have the some of the lowest formation resistivity factor (FRF) values (<200) and thus the simplest pore system. The poorest reservoir properties ( k <10 mD) occur in mudstones and wackestones that have not been recrystallized and, hence, are dominated by a simple network of micropores (FRF <101). Skeletal and oolitic grainstones and rooted and brecciated wacke-packstones that have undergone some cementation and partial recrystallization have moderate reservoir properties and a high FRF (>>1000), reflecting a complex pore system of biomolds, vugs, and microporosity. Consequently, reservoir properties can be predicted based on their primary rock properties and the diagenetic pathway that they followed after deposition.

Although carbonate reservoirs often have high total pore volumes, permeability often does not show a strong correlation to total porosity. Carbonate pore networks are also widely recognized as being highly heterogeneous, with marked variability in pore size (from submicron to millimeter scale and above) within an individual core plug. It is perhaps for this reason that there has been relatively little quantification of carbonate pore size and shape, despite significant advances in our ability to image naturally porous media using electron microscopy and advanced X-ray imaging. This study focuses on four samples of limestone from the uppermost Shuaiba Formation in northern Oman. These samples were selected for X-ray computerized tomography (CT) and environmental scanning electron microscope (ESEM) imaging and quantitative analysis following a detailed reservoir quality evaluation of the study interval across seven fields. This interval has been well studied sedimentologically, but the processes and timing of diagenetic modification, and the nature of the resultant pore network are less well understood. The samples represent a range of lithofacies associations that occur immediately beneath the Shuaiba–Nahr Umr unconformity, within an interval that is recognized for possessing higher permeability than the underlying reservoir. The samples were imaged at multiple scales, and their pore network was analyzed. Within the sample set, over 70% of the total pore volume was <1 μm in diameter. The three-dimensional (3D) equivalent pore radii within individual samples ranged from <0.1 μm to >100 μm, with the size of the X-ray imaged samples being limited to 1 mm 3 . The average aspect ratios of all pores was <2, and it was highest in micropores (<1 μm pore radii). Mean coordination number was <3 in all samples, and it was highest within micropores. Since most pore throat radii are <1 μm, this most likely reflects the higher resolution needed to image micropores. Multivariant analysis shows that permeability prediction is improved when pore topological parameters are known. The highest measured permeability within the data set occurred in the sample with the highest volume of resolved porosity, highest aspect ratio, and highest coordination number. However, average permeability overall was highest in those facies associations with abundant macropores, where the representative elemental volume is greater than the sample size required for X-ray CT analysis and even routine core analysis. In these samples, high permeability is facilitated by the connectivity of a low volume of large (>>30 μm) pores embedded within a network of micropores. In these samples, sweep efficiency during hydrocarbon production is likely to be poor. The results of this study provide one of the first detailed data sets of 3D pore shape and size within this volumetrically important reservoir and insight into pore connectivity within microporous reservoirs on the Arabian Plate. The results provide good evidence that the >1 μm fraction of these rocks contributes to single-phase flow, but they demonstrate the complexity of pore shape even at the micron scale.

Abstract The purpose of this chapter is to provide a workflow for modeling uncertainty. It focuses upon a mature (brown) field redevelopment in a giant fractured carbonate field in Oman. We used experimental design to constrain the range and impact of individual parameters on production forecasts using historical field performance data. The approach allowed for an assessment of the interaction and impact of the uncertainty for a large number of subsurface parameters with a manageable number of model runs. A priori assumptions of the uncertainty range of each parameter were first modeled and then challenged during initial screening runs. Subsequently, historical data were used to constrain the uncertainty range of those parameters that were sensitive to past production performance. The uncertainty range of all other parameters was carried forward into the production forecast, and their impact on various development options was tested. The results of this work were input into a data gathering and pilot production plan to further delimit uncertainty ranges and to help select and optimize development options. The predictive capacity of a reservoir model is strongly influenced by the uncertainty range associated with the individual subsurface parameters that are captured in it. A large uncertainty range results in a low predictive power, but if uncertainty ranges are too narrow, then realistic forecasts of future production may not be achieved. Integrated subsurface teams are routinely tasked with identifying and quantifying uncertainty and capturing the probabilistic ranges in production forecasts. Of the many methods of handling this challenge, experimental design provides a robust mechanism for assessing the impact of a combined range of subsurface parameters on future production. This chapter outlines a case study of how experimental design can be used to handle such uncertainty in production forecasts.

Abstract The Minagish Oolite occurs in the Middle Minagish Member of the Minagish Formation (Berriasian-Valanginian) in Kuwait. Ten distinct lithofacies are recognized, which suggest sedimentation on a homoclinal carbonate ramp. A relatively small proportion of the Minagish Oolite (< 15%) consists of oolitic grainstone (Lithofacies 2), and this is confined to the lower part of the oil column. The dominant lithofacies comprises peloidal packstones to grainstones (Lithofacies 3). Sedimentation was highly storm-influenced, with significant reworking of shallow-water, inner-ramp skeletal allochems into the midrramp. The high level of reworking is believed to account for the relatively high proportion of grainstone and poorly washed packstones in the inner mid-ramp setting. The reservoir is interpreted as the product of sedimentation within late highstand, lowstand, and trasgressive systems tracts, which together represent a low- (third?) order relative sea-level change. Within each systems tract, laterally correlatable flooding surfaces at the tops of parasequences are directly overlain by thin units of bioturbated wackestones to packstones (Lithofacies 7). These wackestones to packstones are interpreted as deeper-water, outer-ramp environments, and indicative of higher-frequency, fourth- or fifth-order, cyclicity. There is strong evidence of a southwestward lateral facies change into more argillaceous limestones (“marls”) in the upper part of the Minagish Oolite. The geometry of the transition suggests that it marks the extreme fringe of a shallow-water clastic system. It represents the earliest evidence of delta progradation in the early Cretaceous of the Kuwait area. Evidence of associated shallowing is absent, and it seems that tectonic uplift in the hinterland was more influential than relative sea-level change. Intense micritization has generated high proportions of microporosity, and it is the distribution of these micropores which mostly influences permeability. The best reservoir facies are grainstones of Lithofacies 2 and 3, where the pore network is macropore-dominated and microporosity is concentrated within micritized allochems. More heterogeneous packstones of Lithofacies 3 and 5 have mixed pore systems, whilst wackestones and packstones of Lithofacies 7 and 8 have micropore-dominated pore networks. In these samples, the pore network is dominated by interparticle micropores, and macroporosi try is rare and isolated. These microporous facies typically form laterally correlatable beds above flooding surfaces and are capable of forming baffles and barriers to vertical transmissibility. Overall, the proportion of facies exhibiting mixed and microporous pore systems increases upwards through the reservoir, and hence there is a corresponding decrease in reservoir quality. During the later stages of production, as the oil-water contact rises, increasingly detailed understanding of the reservoir architecture wil be required to maintain production levels. The lateral facies change at the top of the reservoir allied to increased compartmentalization indicates that a more comprehensive secondary recovery scheme will be required in this part of the reservoir.