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 As the operator of several exploratory blocks in ultradeep waters, Petrobras was responsible for many presalt oil discoveries in Santos Basin such as Tupi, Carioca, Guará, and Iara. In partnership with the National Petroleum, Natural Gas and Biofuels Agency (ANP), Petrobras drilled well 2-ANP-2A, which resulted in the Libra discovery. In 2013, Libra was offered in the first bidding round executed by the Brazilian government under the new Production Sharing Contract for presalt areas. The winning consortium is comprised of Petrobras (operator), Shell, Total, CNOOC (China National Offshore Oil Corporation), CNPC (China National Petroleum Corporation), and PPSA (Pré-Sal Petróleo S.A.). The Libra discovery is sitting over a structural trap of about 550 km 2 (212 mi 2 ) closure at the Aptian top reservoirs level presenting a maximum oil column that can reach up to 900 m (2953 ft). The main reservoirs are lacustrine carbonates, deposited from the Neobarremian until the Aptian. Preliminary estimates indicate a volume of oil in place between 8 and 12 billion BOE. The development proposed for Libra started with Phase 0, in 2014, and is focused on information gathering, including appraisal wells, extended well tests (EWT), early production systems (EPS), and a pilot project. Phase 1 encompasses the definitive production systems and is expected to start in 2022 and finish in 2030.

Abstract The well-exposed Djebel Bou Dahar (DBD) carbonate platform (Lower Jurassic, High Atlas, Morocco) demonstrates the role played by different carbonate factories on the growth and architectural evolution of a high-relief, flat-topped carbonate depositional system. It also shows, in contrast with the generally accepted idea that lithiotid bivalve accumulations dominated Lower Jurassic platform margins, that microbial carbonates substantially contributed to the carbonate factory, as in Upper Jurassic reefs. The DBD carbonate depositional system accumulated on the footwall high of an active marine rift. Its depositional architecture evolved from a low- relief ramp profile (Hettangian p.p.-Sinemurian) to a high-relief platform with slopes up to 32° and 600 m in relief (uppermost Sinemurian- Pliensbachian) as a function of changes in accommodation and carbonate factory. The Sinemurian low-relief system consisted of siliceous sponge microbial mounds associated with coated grain skeletal packstone and grainstone in middle and outer ramp facies belts. This deep-water carbonate factory did not build into wave-agitated shallow settings and lacked the capability of constructing high-relief platform margins. From the latest Sinemurian, the platform built significant relief and the slope steepened (20-32°). This switch in platform architecture coincided with the accumulation of a highly productive, coral calcareous sponge microbial boundstone at the platform margin and on the slope (from 10 to 60 m in depth). This was adjacent to deeper water siliceous sponge microbial boundstone (from 60 to 140 m below the platform break). During the late Pliensbachian increased accommodation and retrogradation, coral calcareous sponge microbial boundstone extended from the upper slope onto the outermost platform, 350 to 400 m inward of the platform break, associated with microbial microencruster boundstone and lithiotid bivalve biostromes. During this aggradational- retrogradational phase, microbialites were able to expand on the outer platform top because low-energy substrates were made available on the platform top by increased accommodation. Outer platform strata consisted of coral calcareous sponge microbial boundstone and coated grain skeletal grainstone, dipping 5° basinward, as observed in other Mesozoic and Paleozoic microbial boundstone-dominated platform margins. The platform interior was dominated by subtidal peloidal skeletal packstone with Cayeuxia-calcified cyanobacteria and intertidal fenestral packstone with laminated microbial boundstone, which contributed to the sediment budget maintaining a flat-topped platform interior geometry. The DBD shares similarities for facies and depositional geometry with Upper Jurassic Southern Tethyan and North Atlantic carbonate systems, implying that the main components of Upper Jurassic reefs were already present in the Early Jurassic rift basin of Morocco.