ABSTRACT The Cenomanian–Turonian Eagle Ford of South Texas is largely composed of two interbedded rock types: marls and limestones. The marls consist mainly of coccoliths with sand- and silt-size grains predominantly comprised of planktonic foraminifera with lesser amounts of inoceramid fragments and other carbonate grains. The limestones are recrystallized, and they contain calcified radiolarians and calcispheres, with almost all pore spaces having been filled with calcite cement. Most of the hydrocarbons in the Eagle Ford, regardless of thermal maturity, reside in the pore network of the marls. Economic production of hydrocarbons stored in these marls, which have nanodarcy permeabilities, can only be obtained by inducing and maintaining fractures with hydraulic stimulation. The interbedding of the marls with limestones form centimeter-scale brittle–ductile (or stiff-compliant) couplets that influence hydraulic fracturing over a range of scales, and at the smallest scale it may increase production by hosting complex near-wellbore fracture systems. Natural fractures that were already present may be open or cemented and reactivated during hydraulic stimulation and contribute to production. This can generate a hybrid fracture system with a larger drainage area and fracture surface area to allow for crossflow from the matrix to fractures. The Eagle Ford is a dual-porosity system, with the hydrocarbon stored in the marls feeds a network of progressively larger natural and induced fractures that carry those hydrocarbons to the wellbore. In most cases, the Eagle Ford will be most productive when the “right” mixture of marl and limestone are present. Too much limestone lowers the storage capacity of the system, and too much marl reduces the complexity of the fracture system. The distribution of the limestones is important: Even if the percentage of limestone in two sections is equal, hydraulic stimulation will produce a more complex fracture network when the limestone is present as a series of thin interbeds rather than as a single thick limestone. The interbedding of limestone and marl can be measured using limestone frequency—the number of limestone beds per unit thickness. Variation in production is observed in wells on the same pad completed with the same treatment but landed in zones of differing limestone frequency, with production in these wells increasing with limestone frequency. Also, in a multivariate analysis involving numerous engineering and geologic variables and over 1000 wells, all measures of interbedding reduced to a single factor, which we call limestone frequency, which positively correlated with production.

ABSTRACT The Lower Cretaceous (Barremian) Zubair Formation in North Kuwait represents a major clastic pulse above the Ratawi Formation. Depositional environments and the sequence stratigraphic framework play a key part in the reservoir development and production strategy with distinct depositional barriers giving rise to multiple fluid contacts. Reservoir structure and fault pattern control fluid redistribution. The Zubair Formation was deposited within a (weakly) tidally influenced deltaic system with episodes of marine influence. The sedimentary sequence consists of highly mature clastic deposits with variable and heterogeneously distributed argillaceous matter, containing negligible amounts of expandable clay minerals. The dominant sandstones range from very fine to medium-grained and are weakly to moderately overprinted by authigenic mineral precipitates. Reservoir quality is mainly controlled by the primary depositional detrital clay content, with additional control by grain size and minor quartz cementation within the cleanest deposits. A sequence stratigraphic framework adopting field-wide correlatable surfaces forms the basis for the division of the Zubair layers. Lower Zubair deposition (Z10 gross reservoir unit) occurred within a tidally influenced deltaic system locally with a stronger marine influence and diminished clastic influx at the very base. Above a widespread mud-prone marine barrier, the heterogeneous middle Zubair interval (Z20–30) comprises a mixture of sand and mud-prone delta-top-or-front deposits and tidally influenced channel-fills. The main reservoir unit of the upper Zubair (Z40) comprises at least four episodes of incision and fills by sand-prone, tidally influenced channel deposits. The overlying upper Zubair (Z50–60) is largely mud-prone with only minor channel development, including channel-fill sandbodies incised into more marine-influenced deposits in the uppermost part of the Zubair. Reservoir development to a large extent depends on genetic aspects of the Zubair reservoirs. The tidally influenced upper Zubair channel-fills represent the best reservoir facies in the Raudhatain field and have been the main targets of initial development. The amalgamation of individual channels forms a number of complex, heterogeneous, and variably interconnected reservoirs. There is good aquifer support for the upper Zubair sand in such a depositional setting. The middle Zubair channel sandbodies show lesser support from the aquifer and represent a second priority for development. Shoreface and mouthbar sandstones potentially form more aerially extensive intervals of poorer quality reservoir that are locally interconnected with the channels. Such thin but laterally extensive sands are the target of current and future development of the reservoir with maximum reservoir contact wells. Complex structural aspects, filling, and up-structure oil migration have resulted in a leaking trap in the Zubair reservoir in the Sabiriyah field. Only stratigraphic traps and extensive sealing by deltaic and marine mudrocks have trapped oil in the Lower Zubair sand (Z10). Other prolific oil reservoirs in the Raudhatain field are water wet with residual oil saturation in the Sabiriyah field. The mechanism for the formation of tar plugs in the Raudhatain field has illustrated the importance of leaking faults. The Raudhatain field has been produced for the last six decades. The initial phase of depletion continued until 2000. Subsequently, peripheral water injection began into different zones of the reservoir. The injection plan is based on the reservoir geometry and sandbody continuity, pressure depletion, and the production plan. Well design and type have evolved over time with higher well diameters drilled after effective control of the lost circulation zone in the overlying Shuaiba limestones. The current development plan includes drilling horizontal wells for effective depletion of the reservoir. Production in the Sabiriyah field started in 2008, mainly from thin shoreface, mouthbar, and channel sandbodies at the Zubair base in the southern part of the field.

Many important geotechnical issues (e.g., groundwater supply and contamination, subsurface waste disposal, hydrocarbon exploration and production) require a detailed understanding of porosity and permeability in subsurface clastic formations (= reservoir quality). Reservoir quality depends on the size, shape, and packing of sand grains as they are originally deposited, as well as diagenetic changes during burial. Obtaining enough samples to fully characterize the target formation is prohibitively expensive or physically impossible. Therefore, reservoir quality estimates must be extrapolated from analogues (± sparse samples) or derived from models. Forward-modeling approaches to predicting diagenetic effects on reservoir quality are well established, but they require information about the character of deposited sand, including mean grain size, sorting, matrix content, and composition of diagenetically relevant particles (i.e., all rock fragments, not just lithic fragments). In cases where deposited sand characteristics are not known, they must be estimated. To this end, we advocate an integrated genetic analysis, which simultaneously predicts multiple sand characteristics as a function of many environmental controls, including tectonic setting, provenance lithotype abundance, climate, regional topographic gradient, hinterland transport distance, basin transport distance, basin subsidence rate, and depositional environment. We have implemented this analytic procedure as a Bayesian belief network–based forward model that successfully predicts sand composition and texture in diverse settings, including provenance areas dominated by either volcanic, high-grade metamorphic, or sedimentary lithologic assemblages; climates ranging from tropical to desert; and a range of alluvial/fluvial drainage types represented by small steep drainages as well as continental-scale big rivers.