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Overpressure is widely developed in deep petroliferous strata in the hinterland of the Junggar Basin. However, a comprehensive understanding of its origin and effect on hydrocarbon distribution and enrichment remains lacking. In this study, we employ five empirical methods and comprehensive geological analysis to identify the origin of overpressure, and uncover the effect of overpressure on hydrocarbon enrichment. The results indicate that disequilibrium compaction is not a significant factor in overpressure generation. Instead, hydrocarbon generation, pressure transfer and diagenesis are the primary causes. The empirical methods support this conclusion. There is a positive correlation between overpressure intensity and source rock thickness and maturity. Notably, widespread cross‐formational migration of hydrocarbon bearing fluid occurred, with sandstone overpressure exceeding that of adjacent shale in non‐source strata. Furthermore, there is a distinct transformation from smectite to illite near the top of overpressure. Hydrocarbon generation pressurization and pressure transfer significantly effect hydrocarbon enrichment. The overpressure caused by hydrocarbon generation drives hydrocarbon migration and accumulation, establishing an optimal energy configuration between reservoir and cap rock. Faults play a crucial role in hydrocarbon vertical migration and pressure relief. The overpressure in reservoirs can reduce the porosity and permeability thresholds and enhance the charging capacity of oil and gas. [ABSTRACT FROM AUTHOR]

How gabbro affects the generation and expulsion of hydrocarbons in muddy surrounding rocks is clarified by analyzing thin section, major and trace elements, total organic carbon (TOC), pyrolysis, extracts and vitrinite reflectance data from source rocks in the Chunxi area the Dongying Sag, Bohai Bay Basin, eastern China. The results show that a magma intrusion brings copious heat to the source rocks, which promotes abnormal maturation of organic matter (OM) and rapid hydrocarbon generation. The CH4 and H2 produced by gabbro alteration play a role in hydrocarbon generation of source rocks. The hydrothermal process during magma intrusion provides many different minerals to the source rock, resulting in carbonate‐rich surrounding mudstone. The carbonate and clay minerals produced by volcanic mineral alteration jointly catalyze the hydrocarbon generation of the source rock. The high‐temperature baking of the intrusion results in hydrothermal pressurization and hydrocarbon generation pressurization, causing many fractures in the surrounding rock. The generated oil and gas are discharged through the fractures under diffusion and pressure. Mantle‐derived CO2 is also conducive to the expulsion of hydrocarbons because of its strong enrichment capacity for hydrocarbons. [ABSTRACT FROM AUTHOR]

The Yingen–Ejina Basin (YEB) located in the western part of the North China Plate is a significant area for petroleum exploration. During the Early Cretaceous, the YEB witnessed the extensive development of source rocks. However, the subsequent tectonic evolution and multi‐stage thermal history of these source rocks have posed challenges to oil and gas exploration in the basin. This study focuses on the Mesozoic and Cenozoic tectonic evolution of the YEB, utilizing Apatite fission track (AFT) and vitrinite reflectance (Ro) data of samples from Well BC‐1 in the Suhongtu Depression, northern YEB. The central ages of six AFT samples ranged from 28 ± 2 to 49 ± 3 Ma with corresponding track lengths between 10.8 ± 1.9 and 12.3 ± 1.5 μm. Combining with the study of Ro and thermal history simulation, the thermal history of the YEB is summarized as follows: In the late Early Cretaceous, the study area experienced tectonic elevation, as evidenced by the discontinuous change in Ro values along the vertical column. Towards the end of the Late Cretaceous, there was a subsidence in the study area. The Ro data indicate that the Early Cretaceous source rocks, although experiencing several tectonic uplifts, had remained within the hydrocarbon generation temperature range, and reached the maximum thermal uplifts before the end of the Late Cretaceous. Therefore, hydrocarbon generation from early Cretaceous source rocks is an important exploration target in the study area and will be the focus of oil and gas exploration in the future. [ABSTRACT FROM AUTHOR]

Because of the influence of hydrocarbons, especially adsorbed hydrocarbons, on the detection of cracked hydrocarbon (S2) and total organic carbon (TOC), the hydrogen index (HI)‐based hydrocarbon generation model deviates from actual practice. In this study, the shale in the first member of the Qingshankou Formation in the central depression of the Songliao Basin, where in northeastern China, was taken as the research object and a correction method for S2 and TOC was established. By correcting the experimental results of different maturity samples, the actual hydrocarbon generation model has been revealed, the differences before and after correction compared, and the evolutionary characteristics of the adsorbed hydrocarbon content were clarified. The results show that the organic matter enters the hydrocarbon generation threshold at Ro–0.5% and reaches the hydrocarbon generation peak at Ro–1.0% and that the hydrocarbon generation process ends at Ro–1.3%. The hydrocarbon generation model established based on the measured values has a 'lag effect' compared to actual values, and this extends the hydrocarbon generation window of organic matter and delays the hydrocarbon generation peak. With the increase of maturity, adsorbed hydrocarbon content shows the characteristics of 'first increasing, then stabilizing, and then decreasing', and reaches the most abundant stage at Ro of 0.9%–1.3%. [ABSTRACT FROM AUTHOR]

Unraveling the complex relationship between orogenesis and hydrocarbon formation and accumulation is challenging and is often hampered by physical and chemical overprints of younger events. The Permian reservoir in the Longmen Shan orogen, South China, is such an example, and its evolution has been hotly debated. In this study, we use a new combination of paleomagnetic dating analysis and Re–Os isotope dating to try to resolve this. Paleomagnetic dating of the hydrocarbon‐host carbonate indicates two remagnetization events during: (a) the Late Triassic, and (b) the Middle Jurassic–Cretaceous. These two remagnetization events are shown to represent two distinct stages of hydrocarbon accumulation. The paleomagnetic estimates are supported by Re–Os dating of bitumen (∼264 Ma) and oil (∼94 Ma). The two different Re–Os ages are associated with two periods of oil generation. We interpret these data in terms of known geological processes: (a) the ∼260 Ma Dongwu large igneous province caused oil generation, and the Indosinian tectonic event caused the migration and accumulation; and (b) the Late Cretaceous Yanshan orogenic events promoted another generation and entrapment of oil in the same reservoir. This combined approach reliably tracks the sequence of oil generation and accumulation, even when the source rock is uncertain, and multi‐phase accumulation and complex tectonism has occurred. Given that paleomagnetic and Re–Os dating are independent methods which can constrain multiple geological processes, when used together they have the potential to be universally applied. Plain Language Summary: Key to understanding complex geological processes is the dates and sequence of each event. The timing of hydrocarbon formation and accumulation is one such complex geological process that can be difficult to unravel, but critical to evaluate the complex orogenesis and hydrocarbon explorations. In this paper, we combine for the first time two independent dating methods to study hydrocarbon reservoirs of Longmen Shan orogen: (a) paleomagnetic and (b) rhenium‐osmium isotope dating. The two methods identified two periods of hydrocarbon formation, followed by two extended periods of hydrocarbon migration. This combined method is particularly powerful as it is independent of the hydrocarbon source rock and complex geological settings. Moreover, the two methods can provide additional tests for each dating technique. The new combined methods can, therefore, be applied in complex hydrocarbon‐bearing regions worldwide. Key Points: Paleomagnetic and Re–Os isotope data were collected for a hydrocarbon carbonate reservoir to determine the hydrocarbon evolution processesOil accumulations are found to have remagnetized the reservoir carbonates during the Late Triassic and CretaceousTiming of oil generation is constrained by Re‐Os dates of bitumen and oil hosted in carbonates at ∼264 and ∼94 Ma, respectively [ABSTRACT FROM AUTHOR]

Heat carried by deep fluid might greatly affect hydrocarbon generation and pore space in shale. Dyke intrusion carrying high levels of heat may be a means by which to explore the influence of deep fluid on shale reservoirs. This study evaluates hydrocarbon generation and analyzed the evolution of shale storage space in the third member of the Xiamaling Formation in the Zhaojiashan section, Hebei Province, based on experimental data such as TOC, SEM, VRo, low‐temperature N2 adsorption and high‐pressure mercury injection. The results show that the dyke intrusion reduced the shale TOC content drastically—by up to 77%—and also induced instantaneous hydrocarbon generation over a range about 1.4 times the thickness of the intrusion. Furthermore, the dyke intrusion might transform organic pores in surrounding shales into inorganic pores. There were two shale porosity peaks: one appeared when VRo = 2.0%, caused by the increase of organic pores as thermal maturity increased, the other occurred when the VRo value was between 3% and 4%, caused by the increase of inorganic mineral pores. It can be concluded that dyke intrusion can be an effective tool with which to study how deep fluid affects instantaneous hydrocarbon generation and pore space in shale. [ABSTRACT FROM AUTHOR]

The Vaca Muerta Formation (Tithonian–early Valanginian) is the main source rock in the Neuquén Basin and the most important unconventional shale resource in South America. In the present study, organic geochemistry, electron microscopy and basin and petroleum system modelling (BPSM) were combined to evaluate source rock properties and related processes along a transect from the early oil (east) to the dry gas (west) window. The unit is characterized by high present‐day (1%–8% average) and original (2%–16% average) total organic carbon contents, which increase towards the base of the unit and basinal (west) settings. Scanning electron microscopy shows that organic pores derived from the transformation of type II kerogen. Isolated bubble pores are typical of the oil window, whereas bubble and densely distributed spongy pores occur in the gas stage, indicating that the maturity gradient exerts strong control on organic porosity. Organic geochemistry, pressure and porosity data were incorporated into a 2D basin petroleum system model that includes the sequential restoration of tectonic events and calculation of compaction trends, kerogen transformation, hydrocarbon generation and estimation of pore pressure through geologic time. The W–E regional model extends from the Agrio Fold and Thrust Belts to the basin border and allows us to evaluate the relationship between thermal maturity and timing of hydrocarbon generation from highly deformed (west) to undeformed (east) regions. Modelling results show a clear decrease in maturity and organic matter (OM) transformation towards the eastern basin margin. Maximum hydrocarbon generation occurred in the inner sectors of the belt, at ca. 120 Ma; long before the first Andean compression phase, which started during the Late Cretaceous (ca. 70 Ma). Miocene compression (15–7 Ma) promoted tectonic uplift of the inner and outer sectors of the belt associated with a reduction in thermal stress and kerogen cracking, as well as massive loss of retained fluids and a decrease in pore pressure. The OM transformation impacted (a) the magnitude of effective porosity associated with organic porosity development, and (b) the magnitude and distribution of pore pressure within the unit controlled by hydrocarbon generation and compaction disequilibrium. BPSM shows a progressive increase in effective porosity from the top to the base and towards the west region related to the original organic carbon content and maturity increasing along the same trend. Overpressure intervals with high organic carbon contents are the most prone to develop organic pores. The latter represent favourable sites for the storage of hydrocarbons in the Vaca Muerta Formation. [ABSTRACT FROM AUTHOR]

A 3D numerical modelling workflow was applied to the Barremian—Aptian source rock interval in a shelfal to lower slope area of the northern Orange Basin, offshore western South Africa. The main objective was to investigate the timing of hydrocarbon generation and migration. Hydrocarbon migration has previously been investigated in the south of the basin by relating gas escape features with structural elements as seen on seismic sections, but migration pathways are still poorly understood. The modelling study was based on data from three exploration wells (AO‐1, AE‐1 and AF‐1) together with 42 2D seismic sections totalling 3537 km in length, and a 3D seismic cube covering an area of 750 sq. km. Modelled formation temperatures increase from north to south in the study area and were consistent with downhole temperatures at well locations. However, there is variation between measured and modelled values of vitrinite reflectance (VR), especially in the Turonian and Cenomanian intervals. The measured VR is lower than the modelled VR within the Turonian section in the north of the study area, suggesting that erosion has affected the thermal maturity of the sediments. However, in the Cenomanian interval, the measured VR is higher than the modelled VR. Uplift, increased erosion in the hinterland and sediment transport to the coastal areas resulted in Cenomanian progradation of the Orange Basin fill. This together with a heat flow pulse resulted in increased thermal maturities in the study area. Modelling results show that hydrocarbon generation began in the central part of the study area by 116 Ma and reached a peak in the Late Cretaceous (65 Ma). Hydrocarbon migration began at about 110 Ma with an expulsion efficiency of 0.77. At the present day, ∼100% transformation of reactive kerogen into hydrocarbons has taken place in the central part of the study area, with random gas migration within Cenomanian and Albian reservoirs. Modelled oil migration likely influenced by hydrodynamic factors is down‐dip (westwards), towards deeper‐water, more distal parts of the basin. Gas saturation on a reactivated listric fault, which was ∼100% saturated at 93 Ma, declined to ∼15% by 65 Ma. This decrease in gas saturation is linked to uplift of the African margin in the Late Cretaceous which resulted in fault reactivation and re‐migration of gas. Despite the uncertainties which are associated with petroleum systems modelling, the study provides an insight into hydrocarbon migration in the northern part of the Orange Basin and contributes to the de‐risking of future oil and gas exploration in this area. [ABSTRACT FROM AUTHOR]

Organic‐rich shales, deposited in marine‐continental transitional environments, are widely distributed in southern China. The pore evolution of the Late Permian Longtan Formation shale (Guizhou Province) during its diagenesis and organic matter (OM) evolution was quantitatively and qualitatively investigated through thermal simulation, mercury intrusion capillary pressure, gas adsorption, fractal dimension, and field emission‐scanning electron microscopy observation. Diagenesis and OM evolution stage were subdivided on the basis of X‐ray diffraction, rock pyrolysis, and vitrinite reflectance test; moreover, the main controlling factors of pore structure during evolution were also discussed. Shales were heated to different temperatures with their vitrinite reflectance ranged between 1.23% and 3.12%, indicating that organic matter had evolved from a low‐ to a post‐mature stage. According to the changes in clay mineral composition, hydrocarbon generation, and Tmax, we subdivided diagenesis into four parts, each of which has a good correspondence with OM evolution. Pore volume (PV) varied between 0.012162 and 0.033482 cm3/g, while the specific surface area (SSA) varied between 13.3693 and 23.0094 m2/g. Mesopores were the main contributors to the total pore volume, while mesopores and micropores were the main contributors to the total specific surface area. In this study, the evolution of pore structure was not monotonous, but intermittent: The PV and SSA of shale samples first decreased and then increased. Maturity was the most important factor affecting the evolution of pore structure. The abundance of pores in OM, associated with hydrocarbon generation, resulted in large micro‐PV and micro‐SSA; moreover, the composition of clay minerals also influenced the pore structure evolution. The transformation of kaolinite into illite increased the content of illite and illite/smectite mixed layer, hence affecting the overall meso‐PV and meso‐SSA. [ABSTRACT FROM AUTHOR]

An analysis of variations in the tectonic subsidence of the Bremer sub‐basin (offshore SW Australia) since 160 Ma using the GALO numerical basin modelling programme has made it possible both to refine previous models and to estimate the intensity of stretching and thermal activation of the lithosphere. The new model explains the rapid subsidence of the sub‐basin and the deposition of the synrift Bremer 1 unit during the initial rift phase in the Late Jurassic (160 to 130 Ma). This phase of extension was accompanied by high heat flows, typical of the axial zones of continental rifts, and lithospheric stretching with a β‐factor of about 1.4. Between 130 and 43 Ma, the abnormally low depositional rate and the shallow water depths suggest moderate thermal activation of the mantle and the absence of extension‐driven subsidence. However during the Eocene (43 to 37 Ma), the modelling suggests that another phase of intense stretching of the sub‐basin lithosphere took place with β = 1.7, explaining both the subsidence and an abrupt increase in water depth from about 50–200 m to nearer 2000 m. The high heat flows during the initial stage of rifting and thermal activation during Cenozoic extension contributed to the early generation of hydrocarbons by source rocks in the Bremer 1 unit at the base of sedimentary cover. At the present day, these source rocks are overmature. At the same time, the modelling suggests that generation of light and heavy oil in the overlying Bremer 2 and 3 units has occurred. Source rock intervals in the upper half of the Bremer 3 unit and in the overlying successions are early mature or immature and may have generated minor volumes of hydrocarbons. [ABSTRACT FROM AUTHOR]

The coexistence of hydrogen‐containing materials and radioactive substances in source rocks is universal. Few documents have researched whether the latter can radiate the former to generate hydrogen gas (H2) as well as the factors controlling this process. This work conducted a series of radiation experiments to address this issue. Samples were placed in sealed Pyrex glass containers and subject to cobalt (60Co) γ irradiation and components and contents of resultant gases were analyzed using gas‐chromatography. The results show that all the samples released variable amounts of H2 after irradiation and that the yield (H2) of decane is lower than that of 3‐tetradecylthiophene but higher than that of distilled water, which implies that a weaker H‐X bond energy (X indicates O, C or other element) in homogeneous materials corresponds with increased yield (H2). The yields (H2) of samples decreased with the decreasing solutions concentrations in sequence from mixed salts solution, KCl solution, Yellow Sea water, oil field water, gypsum solution to distilled water. The experimental results also show that the yield (H2) of distilled water with montmorillonite is higher than that of distilled water with kaolinite, because due to the larger specific surface area, ion exchange capacity and more effective energy transfer effect of montmorillonite. Meanwhile, the irradiation of oxygen‐ and carbon‐containing materials also releases O2 and CH4. The production of H2 via the irradiation of hydrogen‐containing materials makes the involvement of exogenous H2 into hydrocarbon generation possible, which can enhance the hydrocarbon volume and optimize crude oil. [ABSTRACT FROM AUTHOR]

The Dongpu Depression, containing huge amounts of hydrocarbons, is a typical petroliferous province in the Bohai Bay Basin, east China. As one set of the main source rocks, the first member of Shahejie Formation (E2s1) shows huge exploration potential with approximately 0.83 × 108 t resources remaining to be discovered. However, the geochemical characteristics and thermal evolution history of E2s1 source rocks have still not been determined. In this study, the sedimentary features were firstly analysed based on the geological data. Then the organic matter abundance, kerogen type, and thermal maturity of E2s1 source rocks in the present day were evaluated according to the Rock‐Eval pyrolysis, micro‐components of kerogen, total organic carbon (TOC), and vitrinite reflectance analysis. Furthermore, the evolution of thermal history and hydrocarbon generation was determined using the PetroMod procedure. The results show that dark mudstones and salt rocks were well developed in E2s1, which are propitious for organic matter to grow and preserve. E2s1 source rocks contain abundant organic matter and moderate to good generative source rock potential. E2s1 source rocks mainly consist of Type II kerogen and have entered early to maturation stage for hydrocarbon generation. Due to the limited buried depth, E2s1 source rocks only attained lower thermal maturity and generated finite hydrocarbons. The initial rapid subsidence and the second rift after uplift erosion resulted in the higher geo‐temperature at the end of E3d and the present day. Corresponding to the geo‐temperature evolution, there are two stages of hydrocarbon generation for E2s1 source rocks: The first stage was in the late E3d period, and the late stage was from the late Neogene to the present day. Moreover, the hydrocarbon generation rate and quantity of the late stage are much higher than the first stage, indicating the major hydrocarbon generation stage. Due to the limited hydrocarbon generation capacity, oils generated from E2s1 source rocks are low maturity; thus, it cannot migrate for a long distance and only accumulated around the sag belts. [ABSTRACT FROM AUTHOR]

The Mesoproterozoic Jixian System is widely distributed at the south‐western margin of the Ordos Basin. It is mainly dominated by siliceous laminated algal micritic dolomite that is a set of potential carbonate source rocks. The magmatic activities at the south‐western margin of the Ordos Basin were frequent and intensive, and the Tongcheng intrusion exposed in this area has an intrusive contact relationship with the Jixian System. This paper uses geochemical methods to study the influence of magmatism to lithology, physical properties, hydrocarbon generating property, and geochemistry of the Jixian System. Analysis data reveal that, with the increasing distance to the intrusion, the porosity, permeability, and content of dolomite, trace elements, and rare earth elements in surrounding rock decrease while the density and silica content increase gradually. In addition, the parameters have a weakening trend about adsorbed hydrocarbon (S1), pyrolysis hydrocarbon (S2), hydrocarbon generating potential (S1 + S2), and pyrolysis peak temperature (Tmax). The results suggest that the magmatic hydrothermalism and the thermal effect of magmatic intrusion changed the physical and geochemical characteristics of the surrounding rock and promoted the hydrocarbon generation of organic matter. However, these characteristics reflect that the magmatic activities only have a relatively small effect on the laminated algal micritic dolomite in Jixian System without a destructive effect at the south‐western margin of the Ordos Basin. The petroleum potential of the Jixian System is worthy to be further explored. [ABSTRACT FROM AUTHOR]

This paper presents a numerical petroleum systems model for the Jurassic-Tertiary Austral (Magallanes) Basin, southern Argentina, incorporating the western part of the nearby Malvinas Basin. The modelling is based on a recently published seismo-stratigraphic interpretation and resulting depth and thickness maps. Measured vitrinite reflectance data from 25 wells in the Austral and Malvinas Basins were used for thermal model calibration; eight calibration data sets are presented for the Austral Basin and four for the Malvinas Basin. Burial history reconstruction allowed eroded thicknesses to be estimated and palaeo heat-flow values to be determined. Six modelled burial, temperature and maturation histories are shown for well locations in the onshore Austral Basin and the western Malvinas Basin. These modelled histories, combined with kinetic data measured for a sample from the Lower Cretaceous Springhill Formation, were used to model hydrocarbon generation in the study area. Maps of thermal maturity and transformation ratio for the three main source rocks (the Springhill, Inoceramus and Lower Margas Verdes Formations) were compiled. The modelling results suggest that deepest burial occurred during the Miocene followed by a phase of uplift and erosion. However, an Eocene phase of deep burial leading to maximum temperatures cannot be excluded based on vitrinite reflectance and numerical modelling results. Relatively little post-Miocene uplift and erosion (approx. 50-100 m) occurred in the Malvinas Basin. Based on the burial- and thermal histories, initial hydrocarbon generation is interpreted to have taken place in the Early Cretaceous in the Austral Basin and to have continued until the Miocene. A similar pattern is predicted for the western Malvinas Basin, with an early phase of hydrocarbon generation during the Late Cretaceous and a later phase during the Miocene. However, source rock maturity (as well as the transformation ratio) remained low in the Malvinas Basin, only just reaching the oil window. Higher maturities are modelled for the deeper parts of the Austral Basin, where greater subsidence and deeper burial occurred. [ABSTRACT FROM AUTHOR]

The Lower Palaeozoic succession in SE Poland and West Ukraine has source rock potential, particularly the Ordovician and Silurian which contain oil-prone Type II kerogen. The thermal maturity of these units ranges from early to late-phase oil window (locally up to gas window). Within the Mesozoic succession, source rock potential is highest in the Middle Jurassic which has TOC of up to 26 wt% and a genetic potential of up to 39 mg/g of rock, with organic matter dominated by gas-prone Type III kerogen. In SE Poland, the organic matter in this unit is generally immature, whereas maturities in West Ukraine are sufficient for hydrocarbon generation to occur. Modelling of hydrocarbon generation suggested that petroleum in Lower Palaeozoic source rocks began to be generated in the Early Carboniferous. Peak generation took place from the late Visean to the early Namurian, and terminated either as a result of source rock depletion or Variscian inversion. Expelled hydrocarbons migrated during post-Carboniferous and Mesozoic uplift. Middle Jurassic source rocks in SE Poland have only reached the early oil window. Higher thermal maturities in the Ukraine resulted in hydrocarbon generation and expulsion. This took place after Miocene burial and maturation. A number of small hydrocarbon accumulations occur in Mesozoic reservoirs in SE Poland / West Ukraine, and hydrocarbons have migrated from Cambrian and Ordovician source rocks. However, the prospectivity of the study area is reduced as a result of phases of uplift and intense erosion which allowed hydrocarbons to escape from structural traps. [ABSTRACT FROM AUTHOR]

The Anticosti Basin is a large Paleozoic basin in eastern Canada where potential source and reservoir rocks have been identified but no economic hydrocarbon reservoirs have been found. Potential source rocks of the Upper Ordovician Macasty Formation overlie carbonates of the Middle Ordovician Mingan Formation, which are underlain by dolostones of the Lower Ordovician Romaine Formation. These carbonates have been subjected to dissolution and dolomitization and are potential hydrocarbon reservoirs. Numerical simulations of fluid-overpressure development related to sediment compaction and hydrocarbon generation were carried out to investigate whether hydrocarbons generated in the Macasty Formation could migrate downward into the underlying Mingan and Romaine formations. The modeling results indicate that, in the central part of the basin, maximum fluid overpressures developed above the Macasty Formation due to rapid sedimentation. This overpressured core dissipated gradually with time, but the overpressure pattern (i.e. maximum overpressure above source rock) was maintained during the generation of oil and gas. The downward impelling force associated with fluid-overpressure gradients in the central part of the basin was stronger than the buoyancy force for oil, whereas the buoyancy force for gas and for oil generated in the later stage of the basin is stronger than the overpressure-related force. Based on these results, it is proposed that oil generated from the Macasty Formation in the central part of the basin first moved downward into the Mingan and Romaine formations, and then migrated laterally up-dip toward the basin margin, whereas gas throughout the basin and oil generated in the northern part of the basin generally moved upward. Consequently, gas reservoirs are predicted to occur in the upper part of the basin, whereas oil reservoirs are more likely to be found in the strata below the source rocks. Geofluids (2010) 10, 334–350 [ABSTRACT FROM AUTHOR]

The thermal history of the sedimentary successions at the Soroosh-17, Soroosh-02 and Nowrooz-16 wells in the northern Persian Gulf have been studied using apatite fission track analysis and vitrinite reflectance data. These data were used to identify and quantify episodes of heating and cooling which have affected the sections penetrated by these wells. This information was synthesised to provide a thermal history framework for the wells, within which the history of hydrocarbon generation, as well as regional structural development, can be understood. Preliminary hydrocarbon generation histories are presented for the Soroosh and Nowrooz oilfields and nearby areas. Modelling of hydrocarbon generation histories based on the AFTA- and VR-derived thermal histories, assuming a dominant Type III kerogen for possible Albian Kazhdumi Formation source rocks and a dominant Type II kerogen for possible Neocomian Fahliyan (Lower Ratawi) Formation source rock, suggest that local sourcing of oil from the Kazhdumi Formation is unlikely. The most likely source rock for oil in the Burgan Formation reservoir at Soroosh-17 and Nowrooz-16 is interpreted to be the Fahliyan Formation based on the available data. On the other hand, speculative modelling of the Hendijan-I well down-dip from the Nowrooz field does allow some oil to be generated from the Kazhdumi sequence at that location, and this might be available for migration to the Nowrooz field. [ABSTRACT FROM AUTHOR]

Numerical modelling is used to investigate for the first time the interactions between a petroleum system and sill intrusion in the NE Sverdrup Basin, Canadian Arctic Archipelago. Although hydrocarbonexploration has been successful in the western Sverdrup Basin, the results in the NE part of thebasin have been disappointing, despite the presence of suitable Mesozoic source rocks, migrationpaths and structural/stratigraphic traps, many involving evaporites. This was explained by (i) theformation of structural traps during basin inversion in the Eocene, after the main phase ofhydrocarbon generation, and/or (ii) the presence of evaporite diapirs locally modifying the geothermalgradient, leading to thermal overmaturity of hydrocarbons. This study is the first attempt at modellingthe intrusion of Cretaceous sills in the east-central Sverdrup Basin, and to investigate how theymay have affected the petroleum system. A one-dimensional numerical model, constructed using PetroMod9.0®, investigates the effectsof rifting and magmatic events on the thermal history and on petroleum generation at the DepotPoint L-24 well, eastern Axel Heiberg Island (79°23′40″N, 85°44′22″W). The thermal history isconstrained by vitrinite reflectance and fission-track data, and by the tectonic history. The simulationidentifies the time intervals during which hydrocarbons were generated, and illustrates the interplaybetween hydrocarbon production and igneous activity at the time of sill intrusion during the EarlyCretaceous. The comparison of the petroleum and magmatic systems in the context of previouslyproposed models of basin evolution and renewed tectonism was an essential step in the interpretationof the results from the Depot Point L-24 well. The model results show that an episode of minor renewed rifting and widespread sill intrusionin the Early Cretaceous occurred after hydrocarbon generation ceased at about 220 Ma in theHare Fiord and Van Hauen Formations. We conclude that the generation potential of these deeperformations in the eastern Sverdrup Basin was not likely to have been affected by the intrusion ofmafic sills during the Early Cretaceous. However, the model suggests that in shallower sourcerocks such as the Blaa Mountain Formation, rapid generation of natural gas occurred at 125 Ma, contemporaneous with tectonic rejuvenation and sill intrusion in the east-central Sverdrup Basin.A sensitivity study shows that the emplacement of sills increased the hydrocarbon generation ratesin the Blaa Mountain Formation, and facilitated the production of gas rather than oil. [ABSTRACT FROM AUTHOR]

An abstract of the article "Saline Lacustrine Source Rocks and their Generated Gas Composition," by Liu Chenglin and colleagues is presented.