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.

Abstract Kuwait has proven oil reserves and production from supergiant and giant fields that include the Greater Burgan (Burgan, Ahmadi, and Maqwa), Raudhatain, Sabriya, and Minagish fields. These fields are associated with very gentle oval anticlines interpreted as drape structures over deep-seated fault scarps or as growth structures related to halokinesis. These structures are generally very simple, consisting of a series of roughly parallel, anticlinal uplifts trending NNW-SSE, with a few having a more N-S to NNE-SSW trend. Reservoir rocks are found in the Jurassic Marrat, Sargelu, and Najmah Formations (carbonates), the Lower Cretaceous Ratawi and Minagish Formations (sandstones and carbonates), and the Middle Cretaceous Burgan and Wara Formations (sandstones), as well as the Mauddud and Mishrif Formations (carbonates). Depth of reservoirs range from 3680 m (12,073 ft) in the Middle Jurassic to 2000–3650 m (6561–11,975 ft) in the Lower Cretaceous and 1000–2570 m (3281–8432 ft) in the Middle Cretaceous. The most important reservoirs are the Lower and Middle Cretaceous sandstones, which are sealed by interbedded and overlying shales. Several Jurassic and Cretaceous limestone units form additional, but subordinate, reservoirs that are generally sealed by shales. Only the Upper Jurassic Gotnia salt and the overlaying Hith Anhydrite seem to act as a regional seal for Middle Jurassic limestone reservoirs. Proven and potential source rocks with high TOC values, characterized by a mixture of marine and terrestrial sapropelic organic matter, are present in the upper-Lower and Middle Jurassic and the Lower and Middle Cretaceous. Kerogens from these rocks fall between Type II and II–III. The maturity level and quality of the kerogen in the Makhul (Sulaiy) Formation suggests that they are the most likely source rocks for the Cretaceous reservoirs, and responsible for generating part of the oil which has accumulated in present structures. Source rock characteristics for the Jurassic succession vary and range from moderate to excellent TOC values in the Sargelu and Najmah Formations. Similarly, the Middle Jurassic succession potentially represents mature oil generation. Oil generation from Jurassic source rocks began in the Late Cretaceous at the time when structural traps had already started to form. The Makhul (Sulaiy) source rock entered the oil window during the Early Tertiary, whereas oil expulsion occurred throughout Tertiary time.