South Oman Salt Basin Research Articles

Integration of seismic modeling and interpretation of real seismic data for the detection and characterization of carbonate stringers: example from Oman

Carbonate stringers are well known geological targets in Oman due to their high estimated prospective resources and production rate, especially in the South Oman Salt Basin (SOSB). A carbonate stringer is defined as a slab of rock completely encased inside the salt body. In this study, we integrate seismic attribute analysis, structural interpretation, seismic modeling, inversion and analog fields to understand and delineate carbonate stringers from South Oman Salt Basin. We use a newly processed seismic data acquired over the area on which we carry out a thorough seismic attribute analysis to help us build a seismic model for the salt structures of the area. A major challenge we faced in the study is the lack of well data. We thus generate pseudo wells at some selected areas based on results from our attribute analysis, structural interpretation, and initial inversion results. The pseudo wells helped improve the seismic inversion and produce more accurate impedance models. The results from seismic inversion and from seismic attribute analysis inferred that some stringers that were difficult to see in seismic data are visible in impedance and some attributes. The conducted study not only increased the confidence related to identifying and characterizing carbonate stringers in the area, but also allowed us to propose some potential stringers for future drilling programs.

Late Neoproterozoic alkaline intrusives in Huqf sediments; a new reservoir target in southern Oman

Abstract Recent drilling in Block 56 on the southern Oman coast NE of Salalah has revealed the presence of intrusive rocks in Huqf sediments. The igneous bodies are found as both discrete and composite, decametre scale sills separated by screens of Huqf host rock. Compositionally they form a cogenetic suite of monzonites and syenites that can be related by fractional crystallization to a gabbro–diorite parental magma. Enrichment in alkalis and other large ion lithophile elements points to either an enriched mantle source or magma-crust interaction on ascent. Geochemical profiles match closely those of the latest Neoproterozoic alkaline eruptives now found as exotic volcanic blocks entrained in the salt diapirs of the Ghaba Salt Basin. Limited geochronological data indicate that the Block 56 intrusives are contemporaneous and derived from the same magma source. Porosities in excess of 10% have been recorded in the intrusives; it is a dissolution porosity created by volume loss during the conversion of primary ferromagnesian minerals to biotite and ferroan dolomite. Porosity creation took place during a short lived, fault-controlled Cretaceous hydrothermal event contemporaneous with uplift and alkaline volcanic activity in the Masirah Ophiolite. The intrusives contain a Huqf-sourced oil with light to medium viscosity appearance. Charging is believed to be coming from the cooler and shallower parts of the South Oman Salt Basin to the north and from beneath thick Cenozoic cover in the basin to the south.

Study Details Strategy of Bottom-Up Water injection in a Heavy Oil Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203783, “Challenges, Opportunities, and Threats of Deep Bottom-Up Water Injection in a Heavy Oil Reservoir: Lessons Learned From the G Field, South Oman,” by Chaitanya Behera, SPE, Sandip Mahajan, and Carlos Annia, Petroleum Development Oman, et al. The paper has not been peer reviewed. _ The complete paper presents the results of a comprehensive study aimed at improving the understanding of deep bottom-up water injection, which enabled optimizing recovery in a heavy oil field in south Oman. The work concludes that the well-reservoir-management (WRM) strategy for a heavy oil field is not the same as one for a classic light oil waterflood. Nevertheless, the reservoir heterogeneity, oil-column thickness, and saturation history also are important factors for variable water-injection response in a heavy oil field. Field Background The G field is on the eastern flank of the South Oman Salt Basin 700 km south of Muscat. The main producing reservoir, the Mahwis sand of the Haima group, culminates in two accumulations (G Main and G East). The Mahwis formation is composed of clastic sediments interlayered with several cemented zones, which often act as baffles in some areas (Fig. 1). However, all stratigraphic units are hydrodynamically connected. No major pressure shift along repeat-formation-tester (RFT) pressure profiles was observed, except at few locations across a major baffle in an oil leg in the crestal area. The reservoir quality is good, with porosity averaging 28% and permeability in the range of 200–2000 md. The maximum oil column thickness is approximately 70 m. Oil viscosity ranges from 250 to 1500 cp across the field both laterally and vertically. The viscosity in the northeast crestal area is relatively low compared with the thee southeastern part of the field. The compositional grading, multiple charging, and biodegradation of oil close to the oil/water contact (OWC) contribute to such a widespread variance in oil viscosity across the G field. The field, initially delineated by five vertical wells in 1990–91, was developed in multiple phases by horizontal producers placed at the top of the reservoir. The field produced under primary depletion until deep bottom-up water injection began in 2015. Water-Injection Development A secondary recovery scheme with infill wells and bottom-up water injection was proposed in 2009 as reservoir pressure dropped by 40%. The water-injection development consisted of injecting untreated produced water at a depth of 100 m below the original OWC under fracture conditions through 35 vertical water injectors. One hundred and thirty-three infill horizontal producers (86 single laterals and 47 dual laterals) were proposed to drill at a denser spacing. The infill campaign began in 2010, while water injection was initiated in December of 2014. The plan was to ramp up the water-injection rate to 70 000 m3/d in 3 years and double the field liquid production. After 3 years of water injection, however, only 33% of the predicted incremental rate was achieved. Approximately 40% of the incremental reserves of the redevelopment scheme was estimated to be at risk.

Numerical modeling on deformation of viscous stringers in deforming salt bodies under a compressive environment—a case study from the South Oman Salt Basin

Salt deposits are extremely potent seals for hydrocarbon reservoirs present in the sedimentary basins worldwide. Large rock inclusions (stringers) encased within various salt bodies may adopt diverse modes of deformation and displacement. Analyzing the movement and segmentation of these elastic and viscous stringers provides a comprehensive understanding of the intricate internal deformation mechanisms in the associated salt diapirs. The difference in viscosity between the stringers and the surrounding salt deposit yields a massive impact on the internal complexity of the salt structures. An analytical finite element model was built in combination with an adaptive remeshing process in this study, to achieve a suitable downbuilding simulation. The standard model setup is regulated with observations from South Oman Salt Basin. In this paper, the evaluation of parameter sensitivity concerning the dynamics of viscous stringers in salt diapirs was carried out, especially the sensitivity study pertaining to varied salt and stringer viscosities, which contribute to the distinct pattern of the internal structure in salt diapirs. The results of the study establish that viscous stringers exhibit characteristic extension and folding. When the viscosity contrast between the salt and the stringer is 1000:1, strong folding of stringers dominates the internal structure of the salt diapirs, and when the viscosity contrast between the two is 10:1, only small-scale minor folding of the stringers takes place. This variation in the viscosity contrast causes disparate internal stress distribution of the stringers. In addition, the location of the stringers and the thickness of salt deposit between the stringers as well as between the stringers and the base also govern the deformation pattern of the internal structure of the salt domes.

Biomarker stratigraphy in the Athel Trough of the South Oman Salt Basin at the Ediacaran-Cambrian Boundary.

The South Oman Salt Basin (SOSB) has been studied extensively for knowledge concerning the habitat of the enigmatic Ediacaran-Cambrian oils that are produced from that region. Geological, geochemical, geophysical, and geochronological investigations have all contributed to improved understanding of the range of late Neoproterozoic depositional environments recorded there. Of particular interest has been the deep Athel depocenter within the SOSB that features a silica-rich interval known as the Al Shomou Member or Athel Silicilyte and the co-eval A4 carbonate-evaporite sequence that straddles the Ediacaran-Cambrian boundary. The deep basin has been suggested to be anoxic and euxinic based on studies of sulfur isotopes, trace metal distributions and other proxies. Organic geochemistry has provided some clues concerning aspects of the depositional environments and microbial communities prevailing during this interval. However, ambiguities remain including a paucity of convincing molecular evidence for euxinia in the photic zone of the basin. Here, we present a comprehensive study of biomarker hydrocarbons, including steroids, triterpenoids, and carotenoids. Among the compounds detected is a distinctive array of aromatic carotenoids. Relatively low abundances of monoaromatic carotenoids, such as chlorobactane, okenane, and β-isorenieratane, suggest the possibility of transient photic zone euxinia with a shallow chemocline or, perhaps, exogenous inputs from microbial mats. However, it is the dominance of renieratane and renierapurpurane over isorenieratane in diaromatic carotenoids and their association with abundant C38 and C39 carotenoids that identifies cyanobacteria as major contributors to the inventory of carotenoids. Our results, based on multiple lines of molecular evidence and statistical analysis, also suggest that the Athel Silicilyte was biogeochemically distinct from the other units of the Ara Group. Overall, our study has important implications for understanding other late Neoproterozoic depositional environments.

Constraints on Meso- to Neoproterozoic seawater from ancient evaporite deposits

Marine sulfate (SO42−) is intimately connected to the global carbon and oxygen cycles through its important role as an electron acceptor for the microbial respiration of organic carbon. The biogeochemical feedbacks within the sulfur, carbon, and oxygen cycles may have changed through time, reflecting changes in the concentration of sulfate in the oceans. Unfortunately, there is much uncertainty about the size of the marine sulfate reservoir throughout Earth history. In particular, conflicting estimates for marine sulfate exist during the latest Neoproterozoic, an interval of time associated with striking changes in Earth system evolution and oxidation: published interpretations of fluid inclusion chemistry place sulfate greater than 16 mmol/kg, whereas other interpretations of carbonate-associated sulfate data suggest concentrations less than 2 mmol/kg. Calcium isotope ratios in evaporite successions provide an independent method for deriving semi-quantitative constraints on sulfate concentrations, as well as other properties of seawater chemistry. Here, the calcium isotope behavior of bedded sulfate evaporites from ∼1050 Ma (Baffin and Bylot Islands, Nunavut, Canada), ∼830 Ma (Officer Basin, Western Australia), and ∼545 Ma (South Oman Salt Basin, Sultanate of Oman) are examined. In combination with other geological observations, the results suggest relatively low, millimolal-level sulfate in the latest Mesoproterozoic and a more specific range of 6–10 mmol/kg sulfate during the latest Neoproterozoic. These new constraints suggest that previous interpretations of sulfate concentrations and seawater chemistry need to be revised, opening up new possible solution spaces for the major ion composition of seawater.

New Technology Reduces High Water Production in Heavy-Oil Field in Oman

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193658, “Tackling High Water Production in Oman South Fields With New Technology,” by Ayca Sivrikoz, Maria Jimenez Chavez, and Salim Buwaiqi, Petroleum Development Oman, prepared for the 2018 SPE International Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 10–12 December. The paper has not been peer reviewed. The subject field is one of the largest mature oil accumulations in the South Oman Salt Basin. Production and integrity issues have been challenging in recent years, manifesting in abnormal water cut with time. A multidisciplinary study concluded that this water-cut behavior was the result of naturally occurring fractures that are limited in length and not vertically extensive.• The proposed solutions included detecting fractures early using borehole imaging techniques and using elastomeric zonal isolation packers (EZIPs) in sealing as many fractures as possible. This completion method resulted in delayed water production and increased net present value by $2 to $3 million per•well. Introduction Field N is a complex heavy-oil field in the north of the Sultanate of Oman. It produces heavy oil from more than 1,000 wells, 80% of which are horizontal; all wells penetrate sandstone reservoirs. Production from these reservoirs started from vertical wells in 1985, but the field-development plan recommended a strategy of horizontal wells targeting the topmost part of the sand reservoirs to avoid the predicted oil/water contact to deter possible early water breakthrough. The dynamic behavior of Field N is characterized by strong aquifer and is dominated by bottomwater drive. The study focused on the westernmost accumulation of Field N, called Field NG. From the time Field NG first came on production in 1984 until 2004, the water cut of the field gradually increased to 30% with an average of 20% initial water cut in this 20-year period. However, after 2004, the average initial basic sediment and water (BSW), or water cut, of new wells in the field jumped to 85%, and even wells that started with initially low BSW soon developed a very high water cut in 2–3 months. Through numerical simulation models calibrated with production history from Field N, it was observed that, if matrix conditions are assumed, water is unable to break through immediately at the start of production. Instead, for matrix reservoirs, 1–2 years are required before the water cut can reach 80%. High initial water cuts could only be explained by conductive features such as high-permeability streaks, fractures, and faults. The simulation models investigating the effect of fracture orientation on water development indicated that vertically nonextensive fractures had no influence on water production early on, thus demonstrating matrix-like behavior in the beginning. However, as cones developed and the water table rose with time, water was able to reach these short fractures, and therefore very high initial BSW was observed in new wells. To prove this concept, an extensive literature search—many authors have studied fractures as a possible cause of early water breakthrough—and data-mining study was conducted, which suggested the presence of fractures in the field.

Diagenetic Processes and Reservoir Heterogeneity in Salt-Encased Microbial Carbonate Reservoirs (Late Neoproterozoic, Oman)

A common problem in dolomite reservoirs is the heterogeneous distribution of porosity-reducing diagenetic phases. The intrasalt carbonates of the Ediacaran-Early Cambrian Ara Group in the South Oman Salt Basin represent a self-sourcing petroleum system. Depositional facies and carbonate/evaporite platform architecture are well understood, but original reservoir properties have been modified by diagenesis. Some of the carbonate reservoirs failed to produce hydrocarbons at acceptable rates, which triggered this study. The extent of primary porosity reduction by diagenetic phases was quantified using point counting. To visualize the distribution of diagenetic phases on a field scale, we constructed 2D interpolation diagenesis maps to identify patterns in cementation. The relative timing of diagenetic events was constrained based on thin-section observations and stable isotope analyses. Near-surface diagenesis is dominated by reflux-related processes, leading to porosity inversion in initial highly porous facies and a patchy distribution of early cements. This strong diagenetic overprint of primary and early diagenetic porosity by reflux-related cements leads to a reduction of stratigraphic and facies control on porosity. Calcite was identified as a burial-related cement phase that leads to an almost complete loss of intercrystalline porosity and permeability. Bitumen is an important pore-occluding phase and time marker of the deep-burial realm. The stratigraphic position of the dolomite reservoirs embedded at the base of a salt diapir had a strong impact on its diagenetic development. The salt isolated the dolomites from external fluids, leading to a closed system diagenesis and the buildup of near lithostatic fluid pressures. In combination, these processes decreased the impact of further burial diagenetic processes. The study highlights that cement distribution in salt-encased carbonate reservoirs is mainly related to early diagenetic processes but can be very heterogeneous on a field scale. Further work is needed to implement these heterogeneities in an integrated numerical reservoir model.

Micro- and nano-pores in intrasalt, microbialite-dominated carbonate reservoirs, Ara Group, South-Oman salt basin

Abstract Dolomitic microbialites form important exploration targets for the oil and gas industry in many parts of the world. It is known that a significant portion of their total porosity and potential storage capacity is formed by micropores. Despite their economic importance few studies attempted to characterize the micro-to nanoporosity in dolomitic microbialites. Recent advances in the field of microscopy now allow to image and analyze their pore systems on a hitherto unprecedented scale. This study evaluates pore systems in Neoproterozoic Ara-Group carbonates forming part of the deeply buried intra-salt A2C hydrocarbon play of the South-Oman Salt-Basin (SOSB). Micro- and nanoporosity there is hosted by aphanocrystalline and, to a minor extent, microcrystalline dolomite. Image analysis derived from broad-ion-beam milling and scanning-electron microscopy (BIB-SEM) of representative samples display a contribution between ∼50 and 100% from micro- and nanopores to total porosities which are up to ∼17%. The main diagenetic controls on microporosity in the A2C are the formation and preservation of primary or early diagenetic (aphanocrystalline) dolomite and the presence of evaporites, calcite and solid bitumen. Petrographic and petrophysical observations show good preservation of the original textural and geochemical attributes in most dolomite samples, even after burial to 5 km depth for the past 500 million years. This suggests a structurally and hydrodynamically isolated, rockbuffered system with a limited extent of cementation. Confocal laser-scanning microscopy (CLSM) reveals significant amounts of hydrocarbons which manifest as degenerated organic material in the carbonates. They originated from precursor bacterial organic matter in microbial laminite, thrombolite and peloidal source-rocks and might have prevented extensive recrystallization of the aphanocrystalline dolomite matrix and further cementation of the porespace. Primary dolomite might still be preserved in the A2C microbialites as petrographic observations reveal similarities in crystal sizes and the texture of euhedral aphanocrystalline dolomite as observed in comparable sedimentary systems.

Demosponge steroid biomarker 26-methylstigmastane provides evidence for Neoproterozoic animals.

Sterane biomarkers preserved in ancient sedimentary rocks hold promise for tracking the diversification and ecological expansion of eukaryotes. The earliest proposed animal biomarkers from demosponges (Demospongiae) are recorded in a sequence around 100 Myr long of Neoproterozoic-Cambrian marine sedimentary strata from the Huqf Supergroup, South Oman Salt Basin. This C30 sterane biomarker, informally known as 24-isopropylcholestane (24-ipc), possesses the same carbon skeleton as sterols found in some modern-day demosponges. However, this evidence is controversial because 24-ipc is not exclusive to demosponges since 24-ipc sterols are found in trace amounts in some pelagophyte algae. Here, we report a new fossil sterane biomarker that co-occurs with 24-ipc in a suite of late Neoproterozoic-Cambrian sedimentary rocks and oils, which possesses a rare hydrocarbon skeleton that is uniquely found within extant demosponge taxa. This sterane is informally designated as 26-methylstigmastane (26-mes), reflecting the very unusual methylation at the terminus of the steroid side chain. It is the first animal-specific sterane marker detected in the geological record that can be unambiguously linked to precursor sterols only reported from extant demosponges. These new findings strongly suggest that demosponges, and hence multicellular animals, were prominent in some late Neoproterozoic marine environments at least extending back to the Cryogenian period.

REGIONAL 3D MODELLING OF THE PERMO‐CARBONIFEROUS AL KHLATA FORMATION IN THE RIMA AREA, EASTERN FLANK OF THE SOUTH OMAN SALT BASIN

The glaciogenic Al Khlata Formation (Late Carboniferous – Early Permian) contains important reservoir and seal intervals in oil fields in southern Oman. Here we describe a 3D regional geological model of the Al Khlata Formation and the underlying Misfar Group in a 1750 km2 area in the Eastern Flank of the South Oman Salt Basin. The Misfar Group (Devonian‐Carboniferous?) was included in the model because it also contains glaciogenic facies in the study area. The 3D model is based on wireline logs from 42 wells, palynological zonation in 31 wells, cores from three wells, and a 2011 3D seismic dataset from which three horizons (top‐Huqf, top‐Rahab Shale and top‐Gharif) were interpreted throughout the study area.The combined Al Khlata and Misfar interval varies in thickness in the area from 20 to 730 m over relatively short distances. These large variations in thickness were due to the creation of accommodation in mini‐basins resulting from the removal of underlying Infracambrian salt at the basin margin. In places, some of the available accommodation was occupied by Cambrian sandstones of the Nimr Group and Haima Supergroup, influencing the location and thickness of the Al Khlata mini‐basins. These local depocentres vary in scale, shape and orientation relative to the present‐day salt edge: some are ovoid in plan‐view, others more linear and parallel to the salt edge, and one takes the form of a narrow graben almost perpendicular to the salt edge. By the Early Permian, towards the end of Al Khlata time, deposits become more blanket‐like and uniform, indicating an external or more regional control on base level.Four key lithofacies have been distinguished from wireline logs and were populated zone‐by‐zone through the geological model: sandstone (reservoir), shale (seal), and sandy and silty diamictite. Sandstones are most common towards the base of the Misfar – Al Khlata interval and shales towards the top. The Rahab Shale (Early Permian) at the top of the Al Khlata Formation forms an important seal for oil fields in South Oman, often in combination with seals in overlying intervals. The Rahab Shale was the first widespread seal to be deposited which may have trapped oil migrating from the South Oman Salt Basin during the Palaeozoic.The most common lithofacies in the Misfar – Al Khlata interval in the modelled area is diamictite (60%), which is normally considered to be a waste‐rock lithology. However thick silty diamictites of sufficient extent can seal hydrocarbon accumulations, and some sandy diamictites have the potential to be unconventional reservoir rocks.Even after 50 years of exploration and production of oil from the Al Khlata Formation, there remains potential for further discoveries and overlooked pay zones due to its heterogeneous character and the occurrence of intra‐formational seals.

Paleoecology and paleoceanography of the Athel silicilyte, Ediacaran-Cambrian boundary, Sultanate of Oman.

The Athel silicilyte is an enigmatic, hundreds of meters thick, finely laminated quartz deposit, in which silica precipitated in deep water (>~100-200m) at the Ediacaran-Cambrian boundary in the South Oman Salt Basin. In contrast, Meso-Neoproterozoic sinks for marine silica were dominantly restricted to peritidal settings. The silicilyte is known to contain sterane biomarkers for demosponges, which today are benthic, obligately aerobic organisms. However, the basin has previously been described as permanently sulfidic and time-equivalent shallow-water carbonate platform and evaporitic facies lack silica. The Athel silicilyte thus represents a unique and poorly understood depositional system with implications for late Ediacaran marine chemistry and paleoecology. To address these issues, we made petrographic observations, analyzed biomarkers in the solvent-extractable bitumen, and measured whole-rock iron speciation and oxygen and silicon isotopes. These data indicate that the silicilyte is a distinct rock type both in its sedimentology and geochemistry and in the original biology present as compared to other facies from the same time period in Oman. The depositional environment of the silicilyte, as compared to the bounding shales, appears to have been more reducing at depth in sediments and possibly bottom waters with a significantly different biological community contributing to the preserved biomarkers. We propose a conceptual model for this system in which deeper, nutrient-rich waters mixed with surface seawater via episodic mixing, which stimulated primary production. The silica nucleated on this organic matter and then sank to the seafloor, forming the silicilyte in a sediment-starved system. We propose that the silicilyte may represent a type of environment that existed elsewhere during the Neoproterozoic. These environments may have represented an important locus for silica removal from the oceans.

Numerical modeling of the deformation of embedded brittle rock bodies in compressive environment during salt tectonics – A case study from SOSB

Large rock inclusions (called stringers) such as carbonate or anhydrite blocks are embedded in many salt bodies. The observation from seismic data shows different ways of movement and deformation of the inclusions, including displacement, folding and fracturing. There remains much unknown about the deformation process of embedded inclusions in a compressive environment during salt tectonics. In this research, we investigate how the differential displacement of the top salt surfaced caused by downbuilding process leads to the deformation of brittle stringers located in-between two sediment pods in a compressive environment by an interative procedure with adaptive remeshing technique to detect and simulate fracture, overtrusting, folding deformation in a finite element model which is established as the generic model from the observations from South Oman Salt Basin (SOSB). The model shows that the compressive environment induces different deformation ways such as shear failure, folding and thrusting of stringers and the stringers can break soon after the onset of salt tectonics. The orientation of the possible shear failure plane (first break) determines the final complex deformation pattern. The initial depth and position of stringer (parallel or horizontal location) strongly influences the time and frequency of breaks.

A sensitivity study on the numerical model of displacement and deformation of embedded brittle rock bodies in extension environment during salt tectonics

Many salt bodies contain large rock inclusions (called stringers) such as carbonate or anhydrite bodies. Mostly, large rock inclusions embedded in salt bodies have different ways of movement and deformation, including displacement, folding and fracturing. A finite element model with adaptive remeshing has been built for downbuilding simulation. The standard model set-up is constrained by observations from the South Oman Salt Basin. Based on the generic model in the previous research which shows the fracture, overtrusting or folding deformation during downbuilding process, a sensitivity study has been conducted on the numerical model of the deformation and displacement of brittle rock bodies, including the parameters such as the initial depth and the distance between them. The results of simulation are analyzed based on the data from SOSB and Zechstein salt basin. The study shows that the frequency of the break and the size of stringer fragments are strongly affected by the initial depth and thickness of stringers and the basement configuration.

Steranes in neoproterozoic oils from the Nepa-Botuoba anteclise in the Siberian platform and the South Oman salt basin in the Arabian platform

A number of rare sterane hydrocarbons untypical of younger Phanerozoic petroleum systems have been found by gas chromatography-mass spectrometry in crude oils from the Nepa-Botuoba anteclise of the Siberian platform and the South Oman salt basin of the Arabian platform (Huqf family oils). Among regular steranes, a continuous series of C21 to C30 hydrocarbons including the previously unknown C23-C25 isomers have been identified. It has been noted that short-chain C21 and C22 steranes are represented by the most thermally stable pregnane species diginane and methyldiginane. Another series of steroids is represented by A-norsteranes, the structures demethylated at C10 (main fragment ion in the mass spectrum at m/z 203). Tricyclic hydrocarbons C26-C29 identified by m/z 219 have been attributed to the homologous series of 8,14-secosteranes. These chemofossils have a wide stratigraphic range of occurrence and, like modern minor secosterynes, can be associated with lipid membranes of sponge and their bacterial synbiotics.

Diagenesis of a light, tight-oil chert reservoir at the Ediacaran/Cambrian boundary, Sultanate of Oman

ABSTRACT The Al Shomou Silicilyte Member (Athel Formation) in the South Oman Salt Basin shares many of the characteristics of a light, tight-oil (LTO) reservoir: it is a prolific source rock mature for light oil, it produces light oil from a very tight matrix and reservoir, and hydraulic fracking technology is required to produce the oil. What is intriguing about the Al Shomou Silicilyte, and different from other LTO reservoirs, is its position related to the Precambrian/Cambrian Boundary (PCB) and the fact that it is a ‘laminated chert’ rather than a shale. In an integrated diagenetic study we applied microstructural analyses (SEM, BSE) combined with state-of-the-art stable isotope and trace element analysis of the silicilyte matrix and fractures. Fluid inclusion microthermometry was applied to record the salinity and minimum trapping temperatures. The microstructural investigations reveal a fine lamination of the silicilyte matrix with a mean lamina thickness of ca. 20 μm consisting of predominantly organic matter-rich and finely crystalline quartz-rich layers, respectively. Authigenic, micron-sized idiomorphic quartz crystals are the main matrix components of the silicilyte. Other diagenetic phases are pyrite, apatite, dolomite, magnesite and barite cements. Porosity values based on neutron density logs and core plug data indicate porosity in the silicilyte ranges from less than 2% to almost to 40%. The majority of the pore space in the silicilyte is related to (primary) inter-crystalline pores, with locally important oversized secondary pores. Pore casts of the silica matrix show that pores are extremely irregular in three dimensions, and are generally interconnected by a complex web or meshwork of fine elongate pore throats. Mercury injection capillary data are in line with the microstructural observations suggesting two populations of pore throats, with an effective average modal diameter of 0.4 μm. The acquired geochemical data support the interpretation that the primary source of the silica is the ambient seawater rather than hydrothermal or biogenic. A maximum temperature of ca. 45°C for the formation of microcrystalline quartz in the silicilyte is good evidence that the lithification and crystallization of quartz occurred in the first 5 Ma after deposition. Several phases of brittle fracturing and mineralization occurred in response to salt tectonics during burial. The sequences of fracture-filling mineral phases (dolomite - layered chalcedony – quartz – apatite - magnesite I+II - barite – halite) indicates a complex fluid evolution after silicilyte lithification. Primary, all-liquid fluid inclusions in the fracture-filling quartz are good evidence of growth beginning at low temperatures, i.e. ≤ 50ºC. Continuous precipitation during increasing temperature and burial is documented by primary two-phase fluid inclusions in quartz cements that show brines at 50°C and first hydrocarbons at ca. 70°C. The absolute timing of each mineral phase can be constrained based on U-Pb geochronometry, and basin modelling. Secondary fluid inclusions in quartz, magnesite and barite indicate reactivation of the fracture system after peak burial temperature during the major cooling event, i.e. uplift, between 450 and 310 Ma. A number of first-order trends in porosity and reservoir-quality distribution are observed which are strongly related to the diagenetic and fluid history of the reservoir: the early in-situ generation of hydrocarbons and overpressure development arrests diagenesis and preserves matrix porosity. Chemical compaction by pressure dissolution in the flank areas could be a valid hypothesis to explain the porosity variations in the silicilitye slabs resulting in lower porosity and poorer connectivity on the flanks of the reservoir. Most of the hydrocarbon storage and production comes from intervals characterized by preserved micropores, not hydrocarbon storage in a fracture system. The absence of oil expulsion results in present-day high oil saturations. The main diagenetic modifications of the silicilyte occurred and were completed relatively early in its history, i.e. before 300 Ma. An instrumental factor for preserving matrix porosity is the difficulty for a given slab to evacuate all the fluids (water and hydrocarbons), or in other words, the very good sealing capacity of the salt embedding the slab.

Origin and variability of a terminal Proterozoic primary silica precipitate, Athel Silicilyte, South Oman Salt Basin, Sultanate of Oman

AbstractThe Precambrian–Cambrian Athel Silicilyte is a 400 m thick, salt‐encased siliceous succession in the South Oman Salt Basin. It is a self‐sourcing hydrocarbon reservoir and comprises up to 95% microcrystalline quartz and exhibits wavy discontinuous lamination, comprising thin, alternating organic‐rich and silica‐rich layers. Textures and geochemical fingerprinting indicate that it is a primary precipitate formed by microbially mediated precipitation of silica from sea water, within the water column at the sulphidic/oxic interface. The unique occurrence of the Athel Silicilyte in the terminal Proterozoic implies that optimal conditions for this style of silica precipitation occurred only briefly. Basin anoxia, coupled with the growth of microbial mats, low pH and high silica pore water saturations, created optimal chemical conditions for silica precipitation. Volumes of microcrystalline quartz are highest within the transgressive and early highstand systems tract and towards the centre of the Athel Basin. At the basin margins, and within the late highstand systems tract, volumes of microcrystalline quartz decreased as the volume of detrital sediment increased. Mass‐balance calculations indicate that silica‐enriched sea water would have been supplied to the basin by infrequent marine incursions that replenished ambient sea water in the upper part of the water column. In conclusion, precipitation of the Athel Silicilyte was driven by the coincidence of basin restriction, limited clastic input, availability of organic matter and water column anoxia. The observation that there are few documented examples of chert deposits younger than ca 700 Ma, prior to the Cambrian explosion, suggests that although silica budgets within marine basins probably remained high prior to the evolution of silica‐secreting organisms, direct precipitation from sea water was restricted. This is tentatively related to the gradual increase in alkalinity of sea water through the Palaeo‐Proterozoic and Meso‐Proterozoic, such that silica precipitation could only occur through the coincidence of basin anoxia and low siliciclastic input.

The main structural styles of the hydrocarbon reservoirs in Oman

Abstract The subsurface structural styles vary across Oman. Understanding this diversity has a strong impact on optimizing hydrocarbon exploration and production. This work is an attempt to summarize the main structural features that characterize the reservoir types in different tectonic domains in Oman in order to provide structural constraints on the interpretation of subsurface data, particularly in areas of poor data coverage or quality. In the South Oman Salt Basin, salt halokinesis dominated the deformation style and the orientation of local stresses. This has resulted in a tortuous framework of faults and folds. During the Palaeozoic, simultaneous differential loading of overlying sediments and salt dissolution were the main deformation mechanisms. The regional stresses are more defined in north Oman. Two structural orientations are observed within the Fahud and Ghaba Salt Basins: NW–SE and NE–SW. The first was formed during Late Cretaceous time, whereas the second developed during the Late Cenozoic. Pre-existing faults were reactivated in both tectonic episodes. The deformation within the north Oman salt basins is localized above pre-existing faults. Outside the salt basins, in the Lekhwair and Makarem highs, the faults mainly trend NW–SE. These tend to be uniformly distributed throughout the basins and have uniform orientation, throw and vertical continuity.

Carbon isotopes and lipid biomarkers from organic‐rich facies of the Shuram Formation, Sultanate of Oman

The largest recorded carbon isotopic excursion in Earth history is observed globally in carbonate rocks of middle Ediacaran age. Known from the Sultanate of Oman as the 'Shuram excursion', this event records a dramatic, systematic shift in δ(13) Ccarbonate values to ca. -12‰. Attempts to explain the nature, magnitude and origin of this excursion include (i) a primary signal resulting from the protracted oxidation of a large dissolved organic carbon reservoir in seawater, release of methane from sediment-hosted clathrates, or water column stratification; and (ii) a secondary signal from diagenetic processes. The compositions and isotope ratios of organic carbon phases during the excursion are critical to evaluating these ideas; however, previous work has focused on localities that are low in organic carbon, hindering straightforward interpretation of the observed time-series trends. We report carbon isotope data from bulk organic carbon, extracted bitumen and kerogen, in addition to lipid biomarker data, from a subsurface well drilled on the eastern flank of the South Oman Salt Basin, Sultanate of Oman. This section captures Nafun Group strata through the Ediacaran-Cambrian boundary in the Ara Group and includes an organic-rich, deeper-water facies of the Shuram Formation. Despite the high organic matter contents, the carbon isotopic compositions of carbonates - which record a negative δ(13) C isotope excursion similar in shape and magnitude to sections elsewhere in Oman - do not covary with those of organic phases (bulk TOC, bitumen and kerogen). Paired inorganic and organic δ(13) C data only display coupled behaviour during the latter part of the excursion's recovery. Furthermore, lipid biomarker data reveal that organic matter composition and source inputs varied stratigraphically, reflecting biological community shifts in non-migrated, syngenetic organic matter deposited during this interval.

From global geology to hydrocarbon exploration: Ediacaran-Early Cambrian petroleum plays of India, Pakistan and Oman

Abstract The vast amount of new lithostratigraphic, chemostratigraphic and geochronologic data from the Huqf Supergroup (Sultanate of Oman) has established it as the Cryogenian (850–635 Ma) and Ediacaran (635–542 Ma) reference section for the Neoproterozoic of the Middle East Region. A direct litho- and chemostratigraphic comparison of the Huqf Supergroup of Oman with the supposed time-equivalent succession of the Marwar Supergroup in western Rajasthan (India) reveals remarkable affinities in facies evolution and chemostratigraphic signature through time. Ara Group equivalent strata are also found in the Salt Range Formation of Pakistan, which shows an almost identical repetition of evaporites and carbonates with six to seven basin refreshening–desiccation cycles, comparing well with the A0–A6 Ara Group stratigraphy of the South Oman Salt Basin. These similarities bring out a consistent picture of a cratonic setting for the Marwar Supergroup of West Rajasthan, changing into a more open marine setting towards Pakistan until Oman, suggesting an assembly of Oman–Pakistan and India ‘terrains’ prior to being accreted to the Arabian shield sometime after 650 Ma. From a petroleum exploration perspective, key success factors when pursuing the Late Neoproterozoic plays in the Salt Basins of India, Pakistan and Oman are source rock maturity, charge preservation and seal integrity.