Search

The unpredicted discovery of downdip oil in Permian–Carboniferous Unayzah sandstone reservoirs along the southern flank of the predominantly gas condensate Ghazal field in Saudi Arabia highlighted the need for a thorough assessment of controls on hydrocarbon properties, with the aim to improve prediction and reduce uncertainty. Primary controls on hydrocarbon property variations (condensate-to-gas ratio) here appear to be compartmentalization, multiple charging, presumably from a Lower Silurian Qusaiba kitchen to the south and east within the late-oil to wet-gas generation window, and dysmigration to the north and west. Gas on production represents mostly unmixed thermogenic accumulations of variable maturities, with no sign of biodegradation or thermal cracking. Light oil (1.06–1.21% calculated vitrinite reflectance [Rc]) in the southern part of the field represent late-mature accumulations that apparently escaped flushing by subsequent gas condensate charges generated near the wet-gas generation window (1.41–1.55% Rc) and currently occupying the field to the north. Constant maturity variations for both gasoline range and heavier components in each sample testify to a lack of mixing between the hydrocarbon phases. Petroleum inclusions similarly comprise either light oil or gas condensate that coexist with significantly overlapping homogenization temperatures, suggesting considerable overlap in their trapping history (135–35 Ma). Less mature petroleum has not been identified in the field, possibly because of a lack of trap closure or migration focus prior to the inferred Late Jurassic filling or because of displacement to updip structures, thereby high grading the probability of undiscovered oil west and northwest of Ghazal. If thermal generation instead of retrograde condensation or phase separation controls this petroleum system, then the potential for deeper oil accumulations is limited.

Summary The Marjan complex is a large offshore oil field located in the Arabian Gulf and composed of four fields: Marjan 1, Marjan 2, Marjan 3, and Marjan 4. Currently, production in the complex is limited to the Khafji reservoir. For several years, it was known that the H2S concentration in the Khafji reservoir varied across the complex. A comprehensive study was initiated to map the concentration profile of H2S across the complex and to address the migration of H2S within it. This study included area-wide wellstream H2S measurement and geochemical fingerprinting of Marjan oil and gas. For the first time, the concentrations of H2S were mapped across the complex. The southern and southwestern wells show relatively high concentrations of H2S, and the northern wells show no (or negligible) amounts of H2S (less than 10 ppm). The migration of H2S into the northern part of the field has serious implications because the crude-handling facilities, or the gas/oil separation plant (GOSP), were designed for sweet crude processing. If migration is proven, the facilities in the northern part of the field must be upgraded to handle sour crude. The results of this study indicate that there is a hot spot of high H2S located in the southwestern part of the complex. There is a significant H2S gradient across the Marjan complex, with H2S decreasing from the southwest to the northeast. H2S concentration profiles also indicate that there is an increase in H2S concentration with time in the hot spot. The data negate the possibility of H2S generation in the Khafji reservoir from either sulfate-reducing bacteria (SRB) or thermochemical sulfate reduction (TSR). Therefore, it is suggested that the H2S is migrating into the Khafji reservoir from somewhere else, probably from the Ratawi or other, deeper reservoirs. The geochemical analyses show that the hydrocarbon composition is uniform across the complex, and there is no evidence for barriers to fluid flow within the Khafji reservoir. It is proposed that the lateral migration of H2S within the reservoir is arrested because of the presence of H2S-scavenging iron minerals. Two hypotheses are proposed for the migration of H2S into the Khafji reservoir from the Ratawi reservoir: (a) through interreservoir faults, or (b) through channeling leaks behind well casings. These two hypotheses are discussed in the paper.

Safaniya Member of the mid-Cretaceous Wasia Formation was deposited as fluvio-marine deltaic sediments in northeastern Saudi Arabia and the northwestern Arabian Gulf. After its deposition and initial burial, the mid-Cretaceous sequence was uplifted during Late Cretaceous structural movements. Structural traps in the region also started forming at this time, but structural growth continued during the Eocene, and new structures developed during the Plio-Pleistocene. The diagenetic mineral assemblage in the Safaniya sandstones includes kaolinite, illite, glauconite, pyrite, quartz and carbonate cements. Kaolinite and illite occur both as authigenic and detrital minerals. Authigenic kaolinite exists as skeletal and euhedral plates forming vermicules and aggregates of booklets infilling the pore spaces. Authigenic illite occurs as overgrowths of projecting laths. Quartz cement is present as syntaxial overgrowths and as microcrystalline quartz. Carbonates occur as patches and show replacement textures. Early diagenetic events include the formation of calcite, siderite, glauconite and pyrite, at or close to the sediment/water interface. Vermicular kaolinite and microcrystalline quartz probably formed by meteoric-water diagenesis during the Late Cretaceous uplift. Quartz overgrowths and the bulk of the euhedral kaolinite may have formed during the Late Cretaceous-Early Tertiary burial. Illite and ankerite were precipitated during deep burial, probably from fluids expelled from the basinal Kazhdumi shales to the east and northeast. The precipitation of authigenic minerals in the clean quartz sandstones has reduced the primary interparticle porosity by an average of about 9% of the rocks. Because the clays occur mainly as pore filling cements, their precipitation has caused only a small reduction in the permeability of these rocks.

During the 1960s, petroleum exploration activities in the offshore Red Sea areas of Saudi Arabia tested gas and condensate reservoired in the Miocene sands immediately below the Mansiyah evaporites in the offshore Midyan basin. Recent onshore exploration activity in the Red Sea has resulted in the discovery of accumulations of oil, gas and condensate in the Lower Miocene Maqna Group in the Midyan and Jaizan basins. As a result of this exploration success, an effort to understand the origin of these hydrocarbons was initiated. The two basins were assessed geochemically by addressing: (1) the potential source rocks; (2) the extent of the hydrocarbon kitchens; and (3) characterization of the hydrocarbons. The potential source rocks for the reservoired hydrocarbons are: (1) the organic-rich, oil-prone shales of the predominantly evaporitic Mansiyah Formation; (2) the variable quality shales and carbonates of the Magna Group; and (3) the moderately organic-rich shales of the Burqan and Tayran Groups. The reservoired hydrocarbons were characterized by carbon isotopes, gas chromatography-mass spectrometry and gas chromatography and compared with the potential source rocks. The results showed an acceptable match to the Maqna and Burqan organic-rich units. Detailed burial history/thermal modelling projects were undertaken to assess the hydrocarbon kitchens of both basins. Results for the Midyan basin indicated that over large areas Tayran and Burqan sediments are oil to gas mature and may be sources for the gas and/or condensate accumulations, whereas the limited area of mature Maqna sediments may be responsible for sourcing the black oil accumulations. In the Jaizan basin, the Maqna and Burqan sediments range from high oil maturity to thermally spent due to high geothermal conditions and excessive burial. The burial of the source rocks increases fairly rapidly from east to west in the Jaizan basin.

The Paleozoic petroleum system of the Central and Northern Provinces of Saudi Arabia contains one of the most prolific oil-prone source rocks of Silurian age worldwide, the Qusaiba shale of the Qalibah Formation. This source rock is responsible for charging the large, gentle structures of the Central Province with billions of barrels of light, sweet, crude oil. Organic geochemical methods such as biomarkers, organic petrography, and characterization of the source rock facies have been used to determine the most likely candidate source rock for the Paleozoic oils of Saudi Arabia. By using detailed extract and oil characterizations, the basal «hot» shales of the Qusaiba Member of the Silurian Qalibah Formation have been correlated to the oils reservoired in the Permian sands of the Central Province of Saudi Arabia.

The ∼ 1.9 Ga Gunflint Formation, in the Thunder Bay district of Ontario, principally comprises iron-formation, overlain by an iron-poor limestone/dolostone member (the Upper Limestone Member). Rocks are virtually unmetamorphosed, retaining primary textures, except locally around diabase sills. The Gunflint presents an opportunity to study both unmetamorphosed and metamorphosed iron-formation and to study the changes from iron-rich to iron-poor sedimentation. Of the carbonate minerals in iron-rich units, siderite formed at or near the sediment/water interface, with ankerite and calcite forming later during diagenesis and during metamorphism around sills. Heaviest δ13C values of siderite, and of dolomite in the Upper Limestone Member, are consistently near 0ℵ throughout the stratigraphic section, indicating that marine bicarbonate was the source of carbon. A spread of values between 0 and −7ℵ for unmetamorphosed rocks is the result of the incorporation of oxidized organic matter during diagenesis, whereas δ13C values more negative than −7ℵ are the result of metamorphism. The heaviest δ18O values from unmetamorphosed rocks, −5.3ℵ (PDB) for siderite, −6.1ℵ for ankerite, and −6.7ℵ for calcite, are considered to represent the original marine composition. Lighter values (to −17ℵ) represent isotopic exchange reactions with pore fluids at higher temperatures and/or isotopic exchange with 18O-depleted meteoric water. Low S/C ratios and a relatively narrow range of positive δ34S values in pyrite throughout most of the formation are consistent with bacterial sulphate reduction of seawater containing sulphate at a significantly lower concentration than the modern ocean. Locally, higher sulfide contents and a wider range of δ34S values were the product of the introduction of sulfur after deposition. It is proposed that the Gunflint Formation was deposited in a stratified water column with anoxic bottom water. The depositional basin had restricted communication with the open ocean and was affected by distal volcanism. Hydrothermal activity associated with the volcanism provided a large source of dissolved iron, and possibly silica, which helped buffer O2 and sulphate in water to low levels. Low concentrations of sulphate limited the generation of H2S that would otherwise have restricted the solubility of iron. During periods of increased hydrothermal activity, the anoxic/oxic water boundary moved upwards, permitting transport of iron to the shallow shelf, where it was precipitated as siderite, iron hydroxides, iron-silicates, or pyrite depending on physico-chemical conditions. The transition to the overlying limestone marks a decrease in hydrothermal activity with a contraction of the redox boundary.

Marjan complex is a large offshore oil field located in the Arabian Gulf and is composed of four fields: Marjan 1, Marjan 2, Marjan 3 and Marjan 4. Currently production in the complex is limited to the Khafji reservoir. For several years, it was known that the H2S concentration in the Khafji reservoir varied across the complex. A comprehensive study was initiated to map the concentration profile of H2S across the complex and to address the migration of H2S within it. This included area-wide well-stream H2S measurement and geochemical fingerprinting of Marjan oils. For the first time, the concentrations of H2S were mapped across the complex. The southern and southwestern wells show relatively high concentrations of H2S, and the northern wells show no, or negligible amounts of H2S (less than 10 ppm). The migration of H2S into the northern part of the field has serious implications because the crude handling facilities, or the gas-oil separation plant (GOSP), were designed for sweet crude processing. If migration is proven, the facilities in the northern part of the field need to be upgraded to handle sour crude. The results of this study indicate that there is a ‘hot’ spot of high H2S located in the southwestern part of the complex. There is a significant H2S gradient across the Marjan complex with H2S decreasing from the southwest to the northeast. H2S concentration profiles with time also indicate that there is an increase in H2S concentration with time in the hot spot. The data negate the possibility of H2S generation in the Khafji reservoir from either sulfate reducing bacteria (SRB) or thermochemical sulfate reduction (TSR). Therefore, it is suggested that the H2S is migrating into the Khafji reservoir from somewhere else, probably from the Ratawi or other, deeper reservoirs. The geochemical analyses show that the hydrocarbon composition is very uniform across the complex, and there is no evidence for barriers to fluid flow within the Khafji reservoir. It is proposed that the lateral migration of H2S within the reservoir is arrested due to the presence of H2S-scavenging iron minerals. Two hypotheses are proposed for the migration of H2S into the Khafji reservoir from the Ratawi reservoir: (a) through inter-reservoir faults, or (b) through channeling leaks behind well casings. These two hypotheses are discussed in the paper.