South Oman Research Articles

Exploration history of the Ara intrasalt carbonate stringers in the South Oman Salt Basin

ABSTRACT The Ara intrasalt carbonate ‘stringer’ play is one of oldest petroleum occurrences known in the world (terminal Neoproterozoic to Early Cambrian age), and it constitutes one of the most complex and unconventional deep oil and gas plays in Oman. The reservoirs are commonly over-pressured, and consist of porous dolomitic carbonates that are encased in salt at depths of 3–5 km. The mostly shallow-water carbonates pose a challenge; both in terms of understanding the origin and spatial distribution of the various lithofacies, and in building predictive reservoir models. In addition, early phases of salt movement influenced carbonate sedimentation and dolomitization, the sedimentation of reservoir and source-rock facies and the structural development that later governed oil migration. While the thick halite sequences provide the seal for the intra-formational trapping of hydrocarbons, the geometry of these thick salt pillows (combined with deep, present-day burial of these reservoirs) affects seismic resolution. The intrasalt stringers were previously regarded as a self-charging hydrocarbon system, containing carbonate source rocks in close proximity or even within the dolomite reservoirs. More recent documentation of a presalt charge, in some of these stringers, adds a new level of complexity to this petroleum system. Carbonate intrasalt stringer exploration in the South Oman Salt Basin (SOSB) started with the unexpected discovery of moveable oil in Nasir-1 in 1976. This launched the first phase of stringer exploration that focused on the Birba and Dhahaban areas. Despite the addition of significant reserves during this campaign, the stringer play proved to be complex. Limited knowledge of the depositional systems and diagenetic history of the stringers made the predicton of reservoir quality difficult and the understanding of production behaviors next to impossible. Difficulty in delivering expected reserves forced the play to become dormant in 1986. The second phase of stringer exploration started in 1988 after a review of deep exploration opportunities that highlighted the play potential outside the proven Birba and Dhahaban areas. All wells drilled during this phase failed to discover commercial hydrocarbon accumulations, thus forcing the play to become dormant for a second time. This short-lived campaign, however, led to the Al Noor Athel discovery, a silicious tight reservoir also encased in the Ara salt. This discovery launched an Athel exploration campaign that lasted until 1997. The Athel campaign did not result in any further commercial discoveries either, however it revived the interest in the Ara stringers with the discovery of oil in Harweel Deep-1 in 1997. Continued success in the Harweel area has maintained interest in stringer exploration to this day and has led to the fast-track development of some Harweel stringer discoveries, which are now contributing significantly to PDO’s oil production. Since 2001, the play has been tested outside the Harweel fairway with limited success. A substantial part of the prospect portfolio remains untested mostly residing outside the Harweel area. Increasing the chance of exploration success will require significant improvements in seismic imaging, better prediction of reservoir occurrence, improved produceability from discovered reservoirs, and a better understanding of hydrocarbon charge history.

Carbonate deposition and hydrocarbon reservoir development at the Precambrian–Cambrian boundary: The Ara Group in South Oman

The Ediacaran–Early Cambrian Ara Group in the South Oman Salt Basin consists of six evaporite–carbonate cycles (A0/A1 to A6) that record tectono-eustatic sea-level changes. The A4 cycle developed at the Precambrian–Cambrian boundary (∼ 542 Ma). It forms a single depositional sequence with evaporites deposited in a lowstand systems tract (LST). Overlying carbonates represent an open-marine shallowing-upward ramp succession that developed in transgressive (TST) and highstand systems tracts (HST). The low-energy carbonate ramp occupied a relatively protected site between a large shelf and an exposed paleogeographical high. The TST facies include sulfates, evaporite–carbonate laminites, and organic-rich carbonate laminites that record initial flooding, deepening of the basin, and establishment of an outer ramp depositional environment. Carbonate sediment flux was low and the environment was partly subject to cyclically elevated salinity. Subsequent HST facies comprise mostly fine-grained clastic carbonates and stromatolites that formed in middle and inner ramp settings. These facies show evidence of shoaling and establishment of a carbonate factory that probably operated over most of the middle and inner ramp. Sediment was redistributed in suspension, by muddy turbidity currents, muddy debris flows, storm and shallow-water currents. During the late HST, carbonate facies were affected by elevated salinity and recorded the gradual transition to the overlying LST evaporite unit. A combination of strong tectonic subsidence and transient flooding caused significant shallow-water evaporite deposition to occur not only down dip, but also on top of the former carbonate platform, where several hundreds of meters of evaporites accumulated. The transgressive carbonate laminites are the main reservoir facies and thus represent a relatively unusual reservoir unit. The presence of organic material and the relative scarcity of carbonate mud influenced diagenesis and reservoir properties. Distribution of organic material and carbonate mud can be linked to specific environmental conditions (low physical and biogenic disturbance of sediment and stratified water mass) and the sequence stratigraphic position (low flux of fine-grained carbonate during TST). In contrast, diagenetic evaporite formation has largely degraded reservoir quality in porous shallow-water facies near the top of the A4C.

Chloroplast DNA variation in the shrub Justicia areysiana (Acanthaceae) endemic to the monsoon affected coastal mountains of the southern Arabian Peninsula

The monsoon affected mountains of the southern Arabian Peninsula harbour in climatically favoured refugia vegetation elements of palaeo-African origin. To understand better the temporal and spatial differentiation of these refugia, chloroplast variation in Justicia areysiana Deflers (Acanthaceae), a shrub species endemic to the Yemeni and Omani mountains close to the Arabian Sea, was studied using PCR-RFLP and chloroplast microsatellite diversity. Eleven haplotypes were characterized and show a distinct geographical distribution pattern with a deep split between populations from south Yemeni fog oases and those from Hawf Mountains/Dhofar region in east Yemen and south Oman. Very limited haplotype diversity within populations (hS = 0.15) and a high level of population differentiation (GST = 0.81) demonstrate the strong genetic isolation of populations from each other. Past oscillations between humid and arid periods connected with glacial and interglacial episodes in the Pleistocene and Holocene are considered responsible for the observed patterns of genetic variation. © 2005 The Linnean Society of London, Botanical Journal of the Linnean Society, 2005, 148, 437–444.

Investigating the record of Permian climate change from argillaceous sedimentary rocks, Oman

A standard method for the analysis of carbon isotope composition of bulk organic matter (δ 13 C bulk ) in palaeoenvironmental and stratigraphic studies of sedimentary basins associated with hydrocarbons is suggested. This method includes the removal of interstitial hydrocarbon within the sediments, which is shown to have a negative effect on δ 13 C. Using the method, a δ 13 C bulk trend ( c . −21 to −24‰) was found within the Lower Permian Al Khlata and lower Gharif formations of Thuleilat-16 and -42 well sections, south Oman. Palaeontological and sedimentological evidence indicates considerable palaeoenvironmental change, from a cold climate lowland fern flora and upland primitive conifer flora low in the sequence, to a lowland cycad-like and upland glossopterid or other gymnospermous flora higher in the sequence. The lithologies range from glacial diamictite at the base to calcrete horizons and redbeds at the top. It is therefore likely that the δ 13 C bulk trend is related to palaeoenvironmental change.

Coral reef guide: Red Sea to Gulf of Aden, South Oman

Coral reef guide: Red Sea to Gulf of Aden, South Oman

Subsurface Uncertainty Management and Development Optimization in the Harweel Cluster, South Oman

Summary In the past 5 years, there has been a string of exploration successes in discovering some 350 million m3 (2 billion bbl) of oil in the Harweel Cluster in south Oman. This oil is deep, under high pressure, and comes with a high gas/oil ratio (GOR), and the fluids contain 15% CO2 and 5% H2S. Of the nine Precambrian carbonate reservoirs, six are lithostatically pressured, and three are hydrostatic. The Harweel Cluster is more than 70 km from existing infrastructure. If gas can be reinjected, miscible displacement is expected in many of the reservoirs. The Harweel Cluster is one of Oman's major opportunities for "green field" oil development. There is a large degree of subsurface uncertainty in gross rock volume and oil/water contact (OWC), reservoir architecture, faults and fractures and reservoir compartmentalization, degree of dolomitization, permeability level and heterogeneity, fluid properties, and so on. However, little is known about the scale and relative importance of each of these uncertainties. Some uncertainties, such as compositional grading, might turn out to be more important than anticipated when evaluating development options because of non-linearities and dependencies. Analyzing the effects of all uncertainty combinations in all reservoirs is not a realistic option. Therefore, a structured scenario-based approach has been developed to analyze and assess all potential factors influencing recovery schemes, reserves, and productivity. After evaluating the range of possible values and calculating the impact of each uncertainty, realizations were created to represent the range of possible values in each new reservoir. Field-scale equation-of-state models were used to simulate both primary depletion and gas reinjection. Development scenarios were optimized for each discrete realization. The resulting reservoir models serve as a basis for the development-concept selection and the subsequent field-development plans.

Stratigraphy and sedimentology of a chert reservoir at the Precambrian-Cambrian Boundary: the Al Shomou Silicilyte, South Oman Salt Basin

ABSTRACT The Al Shomou Silicilyte is a unique source and reservoir rock found in the South Oman Salt Basin, where up to 400 m thick and several kilometers wide slabs of silicilyte are entrapped in salt domes at depths of 4 to 5 km. Discovered in the early 1990s, the play is characterized by light and sour oil, high overpressures (19.8 kPa/m), and a high-porosity, low-permeability microcrystalline silica matrix rich in organic matter, deposited around the Precambrian-Cambrian boundary. The palaeogeographic setting during the Al Shomou Silicilyte deposition was a restricted, marine intra-cratonic basin, surrounded by carbonate platforms. The basin was most likely segmented into structural highs and lows, with potential relief of more than 200 m. The deposits of the Al Shomou Silicilyte are stratigraphically ‘sandwiched’ by two regionally extensive shale units, the underlying ‘U’-Shale Formation and the overlying Thuleilat Shale Member. The basinal Al Shomou Silicilyte and the time-equivalent platform carbonates were deposited during a TST to HST in sea-level characterised by reduced siliciclastic input. Silicilyte formation was replaced by the regionally extensive lower Thuleilat Shale and Thamoud Carbonate. The Al Shomou Silicilyte is typically organic-rich, finely laminated and consists of 80–90% microcrystalline quartz with a crystal-size of 2–3 microns. Commonly, the silica crystals form sheet-like aggregates with high intercrystalline microporosity (up to 30%). Other authigenic phases in the silicilyte are pyrite, apatite, magnesite and illite/smectite clay minerals. Minor silt- and sand-sized detrital components are mica/illite flakes, K-feldspar, quartz and sedimentary rock fragments. The organic material averages 7% of the bulk rock volume and is finely disseminated and/or concentrated in laminae. No identifiable macro- or microfossils have been found to-date in the silicilyte. The textural and chemical characteristics suggest formation in a reducing, probably anoxic environment below wave base. The 300–400 m thickness and uniform character of the silicilyte indicate relatively stable conditions during deposition. The lack of recognizable biogenic components and only traces of detrital particles, suggest that the silicilyte is mostly composed of chemically formed silica. The microcrystalline silica could well be the result of a rapid inorganic nucleation of silica gel. The large volumes of silica necessary for silicilyte formation require a silica reservoir of reasonable magnitude, i.e. sea water. A model with a stratified water column is proposed, in which the oxic surface waters probably represented the site of organic productivity and carbonate deposition, and the deeper water at the thermocline/chemocline, the site of silica formation and bacterial mat growth. Silica gel formation may well have been linked to the biological cycle, i.e. mediated by sulfate-reducing bacteria (chemoautotrophs). Comparison with other siliceous deposits indicates that there are no known analogues. Models proposed for banded iron formations are probably the closest approximation to the type of processes involved in the formation of the silicilyte. Given its apparent chronostratigraphic position at the Precambrian-Cambrian boundary, it may well represent a global deepwater facies related to key events which are suggestive of extinction and faunal turnover at the Precambrian-Cambrian boundary.

Petrology and geochronology of a Neoproterozoic dyke swarm from Marbat, South Oman

A suite of NW–SE trending tholeiitic dykes in the Marbat area of south Oman was emplaced into calc-alkaline gneisses and intrusives during the Neoproterozoic. A three point Sm/Nd isochron from the most primitive sample and an Rb/Sr whole rock isochron together with geological evidence, suggest an intrusion age of about 700 Ma. The dykes form a co-genetic suite ranging in composition from basalt to rhyolite. The most primitive rock has an Mg # of 67.48, a Ni content of 268 ppm and Cr of 571 ppm. All rocks in the suite are quartz normative. Initial 143Nd/ 144Nd and 87Sr/ 86Sr isotope ratios suggest some interaction between the magmas and the continental crust during ascent. Magmatic evolution was controlled by AFC processes involving fractionation of hornblende, clinopyroxene, plagioclase and magnetite. Trace element variation diagrams show negative spikes for Rb, Ta, Nb, Sr and Ti. Nb depletion results in high Th/Nb (0.9) and La/Nb ratios (3.8). Comparison of the Marbat dykes with Neoproterozoic dykes from SW Egypt, Sinai, volcanic rocks from the Andean active continental margin and the Basin and Range Province, a low-Nb dykes suite from New South Wales, Australia and a suite from the Congo shows considerable compositional overlap. These comparisons suggests that the dykes were formed by melting of subduction modified lithospheric mantle and mobilised by crustal extension. The ubiquity of dykes in the ANS showing similar signatures suggests that such modified mantle is regionally developed and results from enrichment is a supra-subduction setting during the Neoproterozoic accretionary phase of the ANS. The mantle shows compositional similarities to lithospheric mantle underlying the western USA. The calc-alkaline geochemistry of the basement gneisses and intrusive suite into which the Marbat were intruded suggest analogy with the Al-Bayda island arc terrane in Yemen. Fracture pattern analysis from Marbat suggests that intrusion of the major swarm may be related to sinistral strike-slip faulting caused by regional east–west compression. A similar stress regime can also explain the orientation of the Mukeras dyke swarms of the Al-Bayda terrane. Additional geochronological data from Marbat and the Hallaniyat Islands imply the existence of a second phase of dyke intrusion at ∼600 Ma which is again similar to the situation prevailing in the Al-Bayda terrane.

The Sahmah Formation of Oman: exploration implications for the Rub’ Al-Khali Basin

ABSTRACT The Sahmah Formation (Safiq Group, Haima Supergroup) of Oman is divided into a lower ‘Shale Member’ (or ‘Sahmah Shale’), and an upper ‘Sandy Member’. The Shale Member was deposited in a deep-marine environment, and the Sandy Member in a marginal marine setting. The formation is greater than 500 meters thick in the Burkanah-1 exploration well, located in south Oman along the eastern edge of the Rub’ Al-Khali Basin. In many areas in Oman, the formation is absent due to erosion by the ‘Hercynian’ unconformity. The age of the Sahmah is generally interpreted as Early Silurian Llandovery; however, recent biostratigraphic studies suggest that it may range in age from latest Ordovician Ashgill to Llandovery. The basal Sahmah Shale (3–10 meters thick) is an excellent source rock, as confirmed by its correlation to the ‘B’ oil in the overlying Permian Gharif Formation in the Sahmah field in central Interior Oman. This study combined new and previously acquired geological data from 16 wells in Oman, and includes source rock analytical data. A basin model was used to assess the maturation history of the Sahmah Shale, and the hydrocarbon potential of two associated petroleum systems. The first system occurs along the ‘Hercynian’ erosional edge of the Sahmah source rock. The migration pathway involves vertical charging of the overlying Upper Carboniferous-Lower Permian Al Khlata Formation or/and the Permian Gharif Formation. This area constitutes the Sahmah Shale:Gharif Formation(!) Petroleum System. The second Petroleum System, the Sahmah Shale:Hasirah Formation(?), applies to regions where the Sahmah is thick, and intra-Sahmah shales act as a seal. In these regions, if the shale is mature and the pre-Sahmah section is porous, then down charging provides the migration pathway to the trap.

Stable isotopic study of late Neoproterozoic-early Cambrian (?) sediments from Nagaur-Ganganagar basin, western India: Possible signatures of global and regional C-isotopic events

Carbonate rocks of late Neoproterozoic-early Cambrian (?) age occur in two extremities of the Nagaur-Ganganagar basin in western India: in east as part of Bilara hills (type locality) and in west as part of Baghewala oil field. These rocks have close stratigraphic correlation with the Ara Formation (Huqf Group, south Oman salt basin) which transgresses the late Neoproterozoic-early Cambrian boundary. Sedimentological and stable isotopic studies of these rocks show prevalence of arid and evaporitic conditions during their depostion. Close resemblance of C-isotopic profiles of Hanseran evaporites and Bilara carbonates allows intra-basinal correlation and suggests that they are coeval facies variants. There are several characteristic carbon isotopic excursions one of which can be tentatively correlated with the globally recorded excursion close to the late Neoproterozoic-early Cambrian boundary. In contrast other peaks are possibly of regional significance and can be attributed to fluctuations in bioproductivity, correlatable with variation in nutrient supply on a basinal scale. Highly depleted carbon isotopic composition of the organic matter in subsurface organic-rich carbonates (Upper carbonate Formation, Baghewala-II core) has been ascribed to incorporation of biomass synthesized by chemoautotrophic bacteria under anoxic or eutrophic basinal condition caused by salinity stratification.

A depositional model for the terminal Neoproterozoic–Early Cambrian Ara Group evaporites in south Oman

Abstract Six evaporite–carbonate sequences are recognized in the terminal Neoproterozoic–Early Cambrian Ara Group in the subsurface of Oman. Individual sequences consist of a lower, evaporitic part that formed mainly during a lowstand systems tract. Overlying platform carbonates contain minor amounts of evaporites and represent transgressive and highstand systems tracts. Detailed sedimentological and geochemical investigation of the evaporites allowed reconstruction of the depositional environment, source of brines and basin evolution. At the beginning of the evaporative phase (prograding succession), a shallow‐water carbonate ramp gradually evolved into a series of shallow sulphate and halite salinas. Minor amounts of highly soluble salts locally record the last stage of basin desiccation. This gradual increase in salinity contrasts sharply with the ensuing retrograding succession in which two corrosion surfaces separate shallow‐water halite from shallow‐water sulphate, and shallow‐water sulphate from relatively deeper water carbonate respectively. These surfaces record repeated flooding of the basin, dissolution of evaporites and stepwise reduction in salinity. Final flooding led to submergence of the basin and the establishment of an open‐water carbonate ramp. Marine fossils in carbonates and bromine geochemistry of halite indicate a dominantly marine origin for the brines. The Ara Group sequences represent a time of relatively stable arid climate in a tectonically active basin. Strong subsidence allowed accommodation of evaporites with a cumulative thickness of several kilometres, while tectonic barriers simultaneously provided the required restricted conditions. Subsidence allowed evaporites to blanket basinal and platform areas. The study suggests a deep‐basin/shallow‐water model for the evaporites.

Lateral clay injection into normal faults

ABSTRACT The clay content of fault gouge is one of the main factors controlling transport and mechanical properties of a fault zone. This paper addresses the process of lateral clay injection into normal faults, which is one of the many processes contributing to the development of clay smear, and can lead to local enrichment of clay in a fault gouge. We combined field observations with geomechanical models to quantify the parameters leading to lateral clay injection into fault zones. Detailed field study shows that a releasing fault bend in a clay layer is required for clay injection to occur. The clay injection process is often associated with the formation of a branch in the fault and the development of a “squeezing block” which injects the clay into the fault zone. A simple analytical model predicts the onset of clay injection when C = σ'v (1 - sin ϕ) / (2 cos ϕ), where C is cohesion (MPa), σ'v is vertical stress (MPa) and ϕ (°) is friction angle. More detailed analysis using 2-D geomechanical finite element models is in good agreement with the analytical models and allows study of the system at higher fault throw. Results of sandbox models containing layers of an elastoplastic clay analogue also compare well with field observations and numerical models, and show the initiation of the releasing step and the evolution of the clay injection process with increasing fault throw. Using our results it is possible to predict the likelihood of lateral clay injection in the subsurface, in settings like the Gharif formation of the Haushi group of Central and South Oman or the Natih formation of North Oman. This requires an estimation of the mechanical properties of the clays at the time of faulting; data which can be obtained from wireline logs and cuttings. This approach to fault seal analysis emphasizes the mechanical aspects of the clay smear process, in addition to the kinematics which were considered in previous analyses. Its application should lead to improved prediction of fault seal processes in the subsurface.

Hydrocyclone Field Tests for Removal of Sand From Production Wells in South Oman

Abstract Petroleum Development Oman is developing a major oil field, Haima West, to increase production levels using a new production technology not previously applied in Oman. The wells will co-produce large quantities of sand to improve productivity. The sand needs to be separated from the well fluids at the surface to protect the integrity of the production facility. No sand separation technology has been tested elsewhere in operating conditions comparable to Haima West. This paper describes the results of field tests performed on a hydrocyclone, processing the high viscosity multiphase fluid. The objectives of the tests were to evaluate the sand separation performance and determine the capacity for the Haima West conditions. In total, 100 tests were conducted and the main findings were:At very low GLR (< 5 Std.m3/m3) the differential pressure should be at least 200 kPa to obtain recoveries of over 80% at a feed particle size of 200 micron (d80 = 200 micron).The recovery was improved in a step change when free water, in excess of 20% of the crude flow, was added.Gas reduces the gross handling capacity for a given pressure differential over the hydrocyclone.Gas, particularly at low differential pressures (< 200 kPa), has a beneficial effect on the separation performance. To the authors' knowledge, this is the first time that such complex tests have been undertaken in the field. The impact of gas and free water on the separation performance have not previously been observed and documented. Introduction Petroleum Development Oman has recently started the redevelopment of a major oil producing reservoir, "Haima West," in South Oman(1). This development utilizes horizontal wells, with artificial lift, in which co-production of sand is a key element. The chosen well completion, without application of downhole sand control, is new in Oman but Canada's heavy oil industry(2) has benefited from co-production of sand. Initial production rates (per unit well length) for Haima West wells without sand control were demonstrated to be three times more, compared to wells with sand control(1). The economics of this development are extremely attractive. Production of large quantities of sand has a definite impact on the integrity of the sub surface and surface facilities. Loss of integrity can manifest itself as a safety or environmental risk as well as causing production deferments. The effects of sand production on a facility's integrity as well as the application of surface sand removal equipment are relatively new areas in the oil and gas industry. This article reviews the application of hydrocyclones for sand removal in Haima West. In particular, it reports the results of field tests to determine the relationships of the separation efficiency and hydrocyclone capacity to various operating parameters. Review of Previous Work Hydrocyclones have been operated in the field for many years; References (3) to (6) provide a comprehensive and qualitative overview of the application of this technology. In the following, a synopsis of this previous work is discussed in relation to the Haima West conditions.

Surface-piercing salt domes of interior North Oman, and their significance for the Ara carbonate ‘stringer’ hydrocarbon play

ABSTRACT The six surface-piercing salt domes of interior North Oman form prominent topographic and geological features in an otherwise flat, rocky desert environment. These domes in the central part of the Ghaba Salt Basin have been known since the 1950s but very little data has been published on them. Our geological survey in 2001 provided significant new lithological, stratigraphic, and sedimentological information on the rocks exposed in the domes. This paper provides a comprehensive overview of the morphology, geometry, structural geology and geological evolution of the salt domes. Furthermore, it incorporates relevant information from unpublished subsurface studies to place the new geological field data in the context of ongoing exploration for deep hydrocarbon plays in Oman. A wide variety of rocks is exposed in the salt domes: carbonates, clastics (conglomerates, sandstones, siltstones and clays), volcanics, evaporites and ‘caprocks’. Constituent rocks and structural style vary considerably from one dome to another, but at the surface the main lithological elements of the diapirs are carbonates and evaporites of the ‘Infracambrian’ (Late Precambrian to Early Cambrian) Ara Group, the uppermost unit of the Huqf Supergroup. Very large exotic blocks of bedded Ara carbonates––commonly hundreds of meters long––are well-exposed and form distinctive hills and ridges, thus allowing detailed field observations on intra-salt carbonate ‘stringers’ that have been carried up by rising diapiric salt. A close correlation exists between the facies of the carbonate exotics in the salt domes and Ara ‘stringer’ carbonates penetrated and extensively cored in recent deep exploration wells in the South Oman Salt Basin. This demonstrates the regional significance of the salt domes for the intra-salt ‘stringer’ hydrocarbon play in Oman. Our work has implications for the prospectivity of other ‘Infracambrian’ evaporite basins in Oman, and possibly also for time-equivalent (‘Hormuz’) salt basins elsewhere in the Middle East.

A 780‐year annually resolved record of Indian Ocean monsoon precipitation from a speleothem from south Oman

Meteorological records of monsoon rainfall in the Indian Ocean are generally less than 100 years long. The relative brevity of these records makes it difficult to investigate monsoon variation on decadal and centennial timescales, to determine what factors influence the intensity of rainfall on these timescales, or to place possible changes in the twentieth century into a broader historical context. Development of a geologic proxy for rainfall that records annual variation in the monsoon over much longer time periods than are covered by instrumental records would be a significant step forward. We have developed an annually resolved record of monsoon rainfall variation for the past 780 years based on annual layer thickness and stable isotope analyses of a laminated stalagmite from southern Arabia. Our results show that monsoon variation over the past century is not outside of the range of the past 800 years. Decreasing monsoon rainfall over the past century is related to increasing sea surface temperature in the Indian Ocean. Spectral analyses of the record are dominated by cycles that are similar to those observed in records of solar activity on centurial timescales. Decadal to interannual cycles in the record appear to originate in the tropical Pacific Ocean.

ABSTRACT: Facies and Reservoir Architecture of Isolated Microbial Carbonate Platforms, Terminal Proterozoic-Early Cambrian Ara Group, South Oman Salt Basin

ABSTRACT: Facies and Reservoir Architecture of Isolated Microbial Carbonate Platforms, Terminal Proterozoic-Early Cambrian Ara Group, South Oman Salt Basin

ABSTRACT: Digital Mapping of Neoproterozoic Thrombolite-Grainstone Facies Architecture in Namibia: Analog for Intrasalt Reservoirs in South Oman Salt Basin

ABSTRACT: Digital Mapping of Neoproterozoic Thrombolite-Grainstone Facies Architecture in Namibia: Analog for Intrasalt Reservoirs in South Oman Salt Basin

Petroleum systems of Oman: Charge timing and risks

After 35 years of exploration, creaming of the conventional plays in Oman is nearly complete, and consequently, the search has commenced for new, less obvious plays. Many of the new opportunities occur beyond the known hydrocarbon provinces and are considered to have significant charge risks. To define these risks, extensive basin modeling studies have been conducted in recent years. Modeling and empirical data show that Mesozoic and Cenozoic kitchen areas are restricted to western north Oman, the only areas currently buried at their maximum temperature. Large parts of north and central Oman depend on lateral migration from these kitchens for their charge. Progressive uplift of the east flank and basin inversion since the middle Paleozoic provides favorable conditions for long-distance migration in the post-Carboniferous interval. In central Oman, geochemical tracer molecules (benzocarbazoles) suggest that a north-south-trending, reactivated basement grain has funneled charge up to 300 km southeastward. Charge risks increase in the deeper sequence, in which eastward migrating hydrocarbons have to traverse the Ghaba salt basin, a pronounced syncline at depths greater than 3 km. The south Oman salt basin is currently cool because of shallow depths and hydrodynamic fluid-flow activity. The shallow post-Cambrian reservoirs rely on storage of early (Cambrian-Ordovician) charge by the Ara salt (Cambrian) sequence, followed by release of hydrocarbons as the salt edge retreats through time. Basin modeling has outlined the extent of the different petroleum systems and provided us with risk maps to guide our next exploration phase. It has revitalized some of the mature plays, for instance the Gharif Formation, where oil exploration is now focused along Late Cretaceous and Tertiary migration paths. Deeper sections are envisaged to have significant scope for gas.

Harmonic analysis of global irradiation

Harmonic models were computed using mean monthly average daily values of global irradiation for seven stations in Oman. Pertinent amplitudes and phase angles have been obtained for each station. The results show the dominance of the first two harmonics in the southern stations, Salalah and Marmul and the dominance of only the first harmonic in the north, Buraimi and Seeb. There is near perfect fit of the data by only one or two harmonics for almost all the stations. Typical equations are suggested for the north and south of Oman.

PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS

Sedimentary successions belonging to three petroleum su persy stems can be recognised in and below the Late Carboniferous to Late Triassic onshore Tasmania Basin. These are the Centralian, Larapintine and Gondwanan. The oldest (Centralian) is poorly known and contains possible mature source rocks in Upper Proterozoic dolomites. The Larapintine 2 system is represented by rocks of the Devonian fold and thrust belt beneath the Tasmania Basin. Potential source rocks are micrites and shales within the 1.8 km-thick tropical Ordovician Gordon Group carbonates. Conodont CAI plots show that the Gordon Group lies in the oil and gas windows over most of central Tasmania and probably under much of the Tasmania Basin. Potential reservoirs are the upper reefal parts of the Gordon Group, paleokarsted surfaces within the Gordon Group and the overlying sandstones of the Siluro-Devonian Tiger Range and Eldon Groups. Seal rocks include shales within the Siluro-Devonian and Upper Carboniferous-Permian tillites and shales.The Gondwanan supersystem is the most promising supersystem for petroleum exploration within the onshore Tasmania Basin. It is divided into two petroleum systems— the Early Permian Gondwanan 1 system, and the Late Permian to Triassic Gondwanan 2 system. Excellent source rocks occur in the marine Tasmanite Oil Shale and other sections within the Lower Permian Woody Island and Quamby Formations of the Gondwanan 1 system and within coals and freshwater oil shales of the Gondwanan 2 system. These sources are within the oil and gas windows across most of the basin and probably reached peak oil generation at about 100 Ma. An oil seep, sourced from a Tasmanites-rich, anoxic shale, is found within Jurassic dolerite 40 km WSW of Hobart. Potential Gondwanan 1 reservoirs are the glaciofluvial Faulkner Group sandstones and sandstones and limestones within the overlying parts of the glaciomarine Permian sequence. The Upper Permian Ferntree Mudstone Formation provides an effective regional seal. Potential Gondwanan 2 reservoirs are the sandstones of the Upper Permian to Norian Upper Parmeener Supergroup. Traps consisting of domes, anticlines and faults were formed probably during the Early Cretaceous. Preliminary interpretation of a short AGSO seismic profile in the Tasmania Basin shows that, contrary to earlier belief, structures can be mapped beneath extensive and thick (300 m) sills of Jurassic dolerite. In addition, the total section of Gondwana to Upper Proterozoic to Triassic sediments appears to be in excess of 8,500 m. These recent studies, analysis of the oil seep and drilling results show that the Tasmanian source rocks have generated both oil and gas. The Tasmania Basin is considered prospective for both petroleum and helium and is comparable in size and stratigraphy to other glaciomarine-terrestrial Gondwanan basins such as the South Oman and Cooper Basins.