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1
Meng, Qingqiang, Jiajun Jing, Jingzhou Li, Dongya Zhu, Ande Zou, Lunju Zheng, and Zhijun Jin. "New exploration strategy in igneous petroliferous basins – Enlightenment from simulation experiments." Energy Exploration & Exploitation 36, no. 4 (March 11, 2018): 971–85. http://dx.doi.org/10.1177/0144598718758338.
Повний текст джерелаАнотація:
There are two kinds of relationships between magmatism and the generation of hydrocarbons from source rocks in petroliferous basins, namely: (1) simultaneous magmatism and hydrocarbon generation, and (2) magmatism that occurs after hydrocarbon generation. Although the influence of magmatism on hydrocarbon source rocks has been extensively studied, there has not been a systematic comparison between these two relationships and their influences on hydrocarbon generation. Here, we present an overview of the influence of magmatism on hydrocarbon generation based on the results of simulation experiments. These experiments indicate that the two relationships outlined above have different influences on the generation of hydrocarbons. Magmatism that occurred after hydrocarbon generation contributed deeply sourced hydrogen gas that improved liquid hydrocarbon productivity between the mature and overmature stages of maturation, increasing liquid hydrocarbon productivity to as much as 451.59% in the case of simulation temperatures of up to 450°C during modelling where no hydrogen gas was added. This relationship also increased the gaseous hydrocarbon generation ratio at temperatures up to 450°C, owing to the cracking of initially generated liquid hydrocarbons and the cracking of kerogen. Our simulation experiments suggest that gaseous hydrocarbons dominate total hydrocarbon generation ratios for overmature source rocks, resulting in a change in petroleum accumulation processes. This in turn suggests that different exploration strategies are warranted for the different relationships outlined above. For example, simultaneous magmatism and hydrocarbon generation in an area means that exploration should focus on targets likely to host large oilfields, whereas in areas with magmatism that post-dates hydrocarbon generation the exploration should focus on both oil and gas fields. In addition, exploration strategies in igneous petroliferous basins should focus on identifying high-quality reservoirs as well as determining the relationship between magmatism and initial hydrocarbon generation.
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Kerimov, V. Yu, E. A. Lavrenova, R. N. Mustaev, and Yu V. Shcherbina. "Hydrocarbon potential and prospects for exploration of Eastern Arctic oil and gas deposits." SOCAR Proceedings, SI2 (December 30, 2021): 85–92. http://dx.doi.org/10.5510/ogp2021si200556.
Повний текст джерелаАнотація:
Conditions for the formation of hydrocarbon systems and prospects for searching for accumulations of oil and gas in the waters of the Eastern Arctic are considered. Significant hydrocarbon potential is predicted in the sedimentary basins of this region. All known manifestations of oil hydrocarbons are installed on land adjacent to the south, as well as on the east of the shelf. The East Arctic waters are included in a single model in order to perform an adequate comparative analysis of the evolution of hydrocarbon systems. The purpose of the research was to build space-time digital models of sedimentary basins and hydrocarbon systems, and to quantify the volume of generation, migration, and accumulation of hydrocarbons for the main horizons of source rocks. To achieve this goal, a spatiotemporal numerical basin simulation was carried out, based on which the distribution of probable hydrocarbon systems was determined and further analyzed. Following to the data obtained the most probable HC accumulation zones and types of fluids contained in potential traps were predicted. Keywords: numerical space-time basin modeling; modeling of hydrocarbon systems; evidence of oil and gas presence; Eastern Arctic; elements of hydrocarbon systems; oil and gas reservoirs; migration; accumulation; perspective objects
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Senin, B. V., V. Yu Kerimov, E. A. Lavrenova, and R. N. Mustaev. "GEODYNAMIC ANALYSIS AND REGIONAL-SCALE PROGNOSTICATION OF THE HYDROCARBON EXPLORATION POTENTIAL FOR THE TATAR STRAIT OF THE SEA OF JAPAN BASED ON THE APPLICATION OF NUMERICAL MODELING TECHNOLOGIES." Tikhookeanskaya Geologiya 41, no. 4 (2022): 41–59. http://dx.doi.org/10.30911/0207-4028-2022-41-4-41-59.
Повний текст джерелаАнотація:
The article presents the results of analysis and numerical modeling of sedimentary basins of the Tatar Strait riftogenic trough of the Sea of Japan, which made it possible to create its structural 3D model and determine the conditions for the formation of its generation-accumulation hydrocarbon systems. To study the geodynamic evolution of the sedimentary basins of the Tatar Strait, a digital reconstruction of the history of subsidence and sedimentation was carried out using numerical basin modeling technologies. The chronothermobaric conditions for the occurrence and evolution of sources of hydrocarbon generation and the formation of oil and gas accumulations in sedimentary basins of the riftogenic trough were reconstructed by three-dimensional modeling of generation-accumulation hydrocarbon systems using the PetroMod software (Schlumberger, Ltd, USA). Modeling of the hydrocarbon systems made it possible to identify the fundamental features of their structure in the water area of the Tatar Strait at the present stage of their development, which in general terms are as follows: the sources of hydrocarbon (HC) generation are located in depressions of the sedimentary basin; the maturity of rocks decreases from south to north with depth; and hydrocarbons accumulate along the flanks of the basins.
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Lavrenova, E. A., S. A. Guryanov, and V. Yu Kerimov. "Assessment of the hydrocarbon potential of the Bering Sea." Proceedings of higher educational establishments. Geology and Exploration 63, no. 5 (August 30, 2021): 42–56. http://dx.doi.org/10.32454/0016-7762-2020-63-5-42-56.
Повний текст джерелаАнотація:
Background. The issues of hydrocarbon (HC) forecasting and prospecting on sea shelves remain relevant. In this paper, an experience of assessing the hydrocarbon potential of the Bering Sea using the method of basin modelling is demonstrated.Aim. To assess the hydrocarbon potential of the Bering Sea and to identify prospective areas on the basis of a comprehensive analysis of factual data and the results of modelling sedimentary basins and hydrocarbon systems.Materials and methods. A large volume of geological and geophysical materials and the results of geochemical studies were analysed. Modelling was carried out based on factual data, which made it possible to design space-time digital models of sedimentary basins and hydrocarbon (HC) systems for the main horizons of oil and gas source rocks. Geochemical and lithological studies, as well as modelling, were performed using the Schlumberger PetroMod and QGIS software. A smallscale modelling of sedimentary basins and hydrocarbon systems of the region under study was conducted. In the process of preparing the input data for modelling, a number of necessary structural constructions, lithological-paleogeographic and paleodynamic reconstructions and other special studies were performed, which made it possible to determine the modelling boundary conditions.Results. The studied hydrocarbon systems of the Bering Sea differ in the area and size of the generation source, and consequently, in the volumes of generated hydrocarbons. The maximum specific (per unit area of the generation-accumulation hydrocarbon system (GAHS)) volumes of generated hydrocarbons are predicted in the Mainitsko-Sobolkovskaya GAHS of the East Anadyr depression, the Nikolaevskaya Mainitsko-Sobolkovskaya and Mainitsko-Sobolkovskaya of the Lagoon trough. However, even the most promising areas are attributed to the V category due to the low quality of kerogen and a low accumulation coefficient.Conclusion. In the water area of the Anadyr trough, prospective areas were identified. Two promising levels of oil and gas potential were determined. A quantitative assessment of the hydrocarbon potential of the GAHS was carried out.
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Shaw, R. D., and G. H. Packham. "THE TECTONIC SETTING OF SEDIMENTARY BASINS OF EASTERN INDONESIA: IMPLICATIONS FOR HYDROCARBON PROSPECTIVITY." APPEA Journal 32, no. 1 (1992): 195. http://dx.doi.org/10.1071/aj91016.
Повний текст джерелаАнотація:
The region east of the Sunda Craton, in Indonesia, formed during the past 50 million years as a consequence of interaction between the Southeast Asia, India–Australia and Philippine plates. These interactions were initially dominated by oceanic plate convergence but since the Miocene the overall northward movement of the India–Australia Plate, and with it the Australian continent, has led increasingly to convergence between oceanic and continental plates. The result has been the creation of a wide range of tectonic regimes and the development of twenty-three major sedimentary basins.Many of these basins exhibit indications of hydrocarbons, but most are frontier basins; several have not yet been drilled and only three have commercial production of oil. Gas production may be feasible soon in one other basin.The preferential occurrence of hydrocarbons in Southeast Asian basins of certain tectonic settings provides a basis for ranking the Eastern Indonesian basins. Seven distinct tectonic settings are represented. The foreland/rifted basins underlain by crust of continental affinity are considered to have the greatest hydrocarbon prospectivity whereas the fore-arc basins bordering the Celebes Basin and Molucca Plate are considered to have the least prospectivity.
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Pedersen, K. S., and P. L. Christensen. "Fluids in Hydrocarbon Basins." Reviews in Mineralogy and Geochemistry 65, no. 1 (July 1, 2007): 241–58. http://dx.doi.org/10.2138/rmg.2007.65.8.
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Korsch, J., C. J. Boreham, J. M. Totterdell, R. D. Shaw, and M. G. Nicoll. "DEVELOPMENT AND PETROLEUM RESOURCE EVALUATION OF THE BOWEN, GUNNEDAH AND SURAT BASINS, EASTERN AUSTRALIA." APPEA Journal 38, no. 1 (1998): 199. http://dx.doi.org/10.1071/aj97011.
Повний текст джерелаАнотація:
The Early Permian to Middle Triassic Bowen and Gunnedah basins and the Early Jurassic to Early Cretaceous Surat Basin in eastern Australia developed in response to a series of interplate and intraplate tectonic events located to the east of the basin system. The initial event was extensional and stretched the continental crust to form a significant Early Permian East Australian Rift System. The most important of the rift-related features are a series of half graben that form the Denison Trough, now the site of several commercial gas fields. Several contractional events from the mid-Permian to the Middle Triassic are associated with the development of a foreland fold and thrust belt in the New England Orogen. This caused a foreland loading phase of subsidence in the Bowen and Gunnedah basins. Thick coal measures deposited towards the end of the Permian are the most important hydrocarbon source rocks in these basins. The development of the Surat Basin marked a major change in the subsidence and sedimentation patterns. It was only towards the end of this subsidence that sufficient burial was achieved to put the source rocks over much of the basin into the oil window. Based on an evaluation of the undiscovered hydrocarbon resources for the Bowen and Surat basins in southern Queensland, our estimates of the yields of hydrocarbons suggest that significant volumes of hydrocarbons have been produced in the basins. The bulk of the hydrocarbons were generated after 140 Ma and most of the generation occurred in the late Early Cretaceous. Because the estimated volume of the hydrocarbons generated far exceeds the volume of discovered hydrocarbons, preservation of accumulations may be the main risk factor. The yield analysis, by demonstrating the potentially large quantities of hydrocarbons available, should act as a stimulus to exploration initiatives, particularly in the search for stratigraphic traps.
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Liu, Xiaoping, Zhijun Jin, Guoping Bai, Jie Liu, Ming Guan, Qinghua Pan, and Ting Li. "A comparative study of salient petroleum features of the Proterozoic–Lower Paleozoic succession in major petroliferous basins in the world." Energy Exploration & Exploitation 35, no. 1 (December 11, 2016): 54–74. http://dx.doi.org/10.1177/0144598716680308.
Повний текст джерелаАнотація:
The Proterozoic–Lower Paleozoic marine facies successions are developed in more than 20 basins with low exploration degree in the world. Some large-scale carbonate oil and gas fields have been found in the oldest succession in the Tarim Basin, Ordos Basin, Sichuan Basin, Permian Basin, Williston Basin, Michigan Basin, East Siberia Basin, and the Oman Basin. In order to reveal the hydrocarbon enrichment roles in the oldest succession, basin formation and evolution, hydrocarbon accumulation elements, and processes in the eight major basins are studied comparatively. The Williston Basin and Michigan Basin remained as stable cratonic basins after formation in the early Paleozoic, while the others developed into superimposed basins undergone multistage tectonic movements. The eight basins were mainly carbonate deposits in the Proterozoic–early Paleozoic having different sizes, frequent uplift, and subsidence leading to several regional unconformities. The main source rock is shale with total organic carbon content of generally greater than 1% and type I/II organic matters. Various types of reservoirs, such as karst reservoir, dolomite reservoir, reef-beach body reservoirs are developed. The reservoir spaces are mainly intergranular pore, intercrystalline pore, dissolved pore, and fracture. The reservoirs are highly heterogeneous with physical property changing greatly and consist mainly of gypsum-salt and shale cap rocks. The trap types can be divided into structural, stratigraphic, lithological, and complex types. The oil and gas reservoir types are classified according to trap types where the structural reservoirs are mostly developed. Many sets of source rocks are developed in these basins and experienced multistage hydrocarbon generation and expulsion processes. In different basins, the hydrocarbon accumulation processes are different and can be classified into two types, one is the process through multistage hydrocarbon accumulation with multistage adjustment and the other is the process through early hydrocarbon accumulation and late preservation.
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Roberts, David G. "Hydrocarbon habitat in rift basins." Marine and Petroleum Geology 14, no. 1 (February 1997): 88–89. http://dx.doi.org/10.1016/s0264-8172(97)88317-1.
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Bosworth, William, and Gábor Tari. "Hydrocarbon accumulation in basins with multiple phases of extension and inversion: examples from the Western Desert (Egypt) and the western Black Sea." Solid Earth 12, no. 1 (January 14, 2021): 59–77. http://dx.doi.org/10.5194/se-12-59-2021.
Повний текст джерелаАнотація:
Abstract. Folds associated with inverted extensional faults are important exploration targets in many basins across our planet. A common cause for failure to trap hydrocarbons in inversion structures is crestal breaching or erosion of top seal. The likelihood of failure increases as the intensity of inversion grows. Inversion also decreases the amount of overburden, which can adversely affect maturation of source rocks within the underlying syn-extensional stratigraphic section. However, many rift basins are multi-phase in origin, and in some cases the various syn-rift and post-rift events are separated by multiple phases of shortening. When an inversion event is followed by a later phase of extension and subsidence, new top seals can be deposited and hydrocarbon maturation enhanced or reinitiated. These more complex rift histories can result in intra-basinal folds that have higher chances of success than single-phase inversion-related targets. In other basins, repeated inversion events can occur without significant intervening extension. This can also produce more complicated hydrocarbon maturation histories and trap geometries. Multiple phases of rifting and inversion affected numerous basins in North Africa and the Black Sea region and produced some structures that are now prolific hydrocarbon producing fields and others that failed. Understanding a basin's sequence of extensional and contractional events and the resulting complex interactions is essential to formulating successful exploration strategies in these settings.
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Parinos, C., A. Gogou, I. Bouloubassi, R. Pedrosa-Pàmies, I. Hatzianestis, A. Sànchez-Vidal, G. Rousakis, D. Velaoras, G. Krokos, and V. Lykousis. "Occurrence, sources and transport pathways of natural and anthropogenic hydrocarbons in deep-sea sediments of the Eastern Mediterranean Sea." Biogeosciences Discussions 9, no. 12 (December 13, 2012): 17999–8038. http://dx.doi.org/10.5194/bgd-9-17999-2012.
Повний текст джерелаАнотація:
Abstract. Surface sediments collected from deep basins (22 stations, 1018–4087 m depth) of the Eastern Mediterranean Sea (EMS) were analyzed for aliphatic, triterpenoid and polycyclic aromatic hydrocarbons (PAHs) as tracers of natural and anthropogenic inputs. Concentrations of total aliphatic hydrocarbons (TAHC), n-alkanes (NA) and the Unresolved Complex Mixture (UCM) of aliphatic hydrocarbons ranged from 1.34 to 49.2 µg g−1, 145 to 4810 ng g−1 and 0.73 to 36.7 µg g−1, respectively, while total PAHs (TPAH25) concentrations ranged from 11.6 to 223 ng g−1. Molecular profiles of aliphatic hydrocarbons and PAHs reflect the contribution of both natural (epicuticular plant waxes) and anthropogenic (degraded petroleum products, unburned fossil fuels and combustion of petroleum, grass, wood and coal) compounds in deep EMS sediments, with hydrocarbon mixtures displaying significant regional variability. Hydrocarbon concentrations correlated significantly with the Total Organic Carbon (TOC) content of sediments, indicating that organic carbon exerts an important control on their transport and fate in the study area, while strong sub-basin and mesoscale variability of water masses also impact their regional characteristics. Major findings of this study support that deep basins/canyons of the EMS could act as traps of both natural and anthropogenic hydrocarbons.
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Hart, Bruce. "Stratigraphy and hydrocarbon resources of the San Juan Basin: Lessons for other basins, lessons from other basins." Mountain Geologist 58, no. 2 (April 1, 2021): 43–103. http://dx.doi.org/10.31582/rmag.mg.58.2.43.
Повний текст джерелаАнотація:
This paper examines the relationships between stratigraphy and hydrocarbon production from the San Juan Basin of New Mexico and Colorado. Abundant data and the long production history allow lessons to be learned, both from an exploration and development perspective, that can be applied in other basins. Conversely, as new play types and technologies are defined and developed elsewhere, the applicability of those tools in the San Juan Basin needs to be understood for well-informed exploration and development activities to continue. The San Juan Basin is a Latest Cretaceous – Tertiary (Paleogene) structure that contains rocks deposited from the Lower Paleozoic to the Tertiary, but only the Upper Cretaceous section has significant hydrocarbon, mostly gas, production. Herein I make the case for studying depositional systems, and the controls thereon (e.g., basin development, eustasy, sediment supply), because they are the first-order controls on whether a sedimentary basin can become a hydrocarbon province, or super basin as the San Juan Basin has recently been defined. Only in the Upper Cretaceous did a suitable combination of forcing mechanisms combine to form source and reservoir rocks, and repeated transgressive-regressive cycles of the Upper Cretaceous stacked multiple successions of source and reservoir rocks in a way that leads to stacked pay potential. Because of the types of depositional systems that could develop, the source rocks were primarily gas prone, like those of other Rocky Mountain basins. Oil-prone source rocks are present but primarily restricted to episodes of peak transgression. A lack of suitable trapping mechanisms helps to explain the relative dearth of conventional oil pools. Although gas production has dropped precipitously in the past decade, driven primarily by overabundance of gas supply associated with the shale-gas boom, the combination of horizontal drilling and multi-stage hydraulic fracturing is being applied to revive oil production from some unconventional stratigraphic targets with success.
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Wan, Yang, Yun Feng Zhang, and Jing Yao Zhang. "Hydrocarbon Migration Mechanisms of Hailar - Tamsag Basin." Applied Mechanics and Materials 490-491 (January 2014): 1415–18. http://dx.doi.org/10.4028/www.scientific.net/amm.490-491.1415.
Повний текст джерелаАнотація:
Based on the discourse of Hailar - Tamsag Basin description of hydrocarbon accumulation period and the distribution of hydrocarbon accumulation controlling factors, the paper pointed out Hailar - Tamsag basin specific landforms, which has significance to the study of ocean basins hydrocarbon migration mechanisms.
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Barbosa, Gustavo Santana, Rui Pena dos Reis, Antônio Jorge Vasconcellos Garcia, Gabriel de Alemar Barberes, and Gustavo Gonçalves Garcia. "Petroleum Systems Analysis of Turbidite Reservoirs in Rift and Passive Margin Atlantic Basins (Brazil and Portugal)." Energies 15, no. 21 (November 3, 2022): 8224. http://dx.doi.org/10.3390/en15218224.
Повний текст джерелаАнотація:
Due to the success of oil and gas production, turbidites have become exploratory targets over the past 40 years in the rift and passive margin basins in the North and South Atlantic. The turbiditic reservoirs in rift and passive margin settings of Atlantic sedimentary basins located in Brazil (Campos Basin) and Portugal (Lusitanian Basin) represent potential economic units for the hydrocarbon exploration. However, despite being considered analogous reservoirs, these units present distinct potentials for the accumulation of hydrocarbons. In this context, the work presented discusses the results obtained from the analysis of static (source rock, reservoir rock, seal and trap) and dynamic elements (migration, tectonic, diagenetic and thermal processes) of both studied petroleum systems, using geological, seismic, well, geochemical and petrographic data. The developed methodology of multiscalar characterization of the two petroleum systems was successful, leading to a specific classification of the efficiency of the static and dynamic elements. These served as the basis for a petroleum systems analysis of the potential of turbiditic reservoirs in both analyzed basins. In the Campos Basin, the salt diapirs and the associated faults provided the origin of excellent migration routes for the hydrocarbons generated in lower intervals, allowing them to reach Cretaceous turbidite reservoirs. At Lusitanian Basin, the diagenetic processes reduced significantly the porosities of the potential turbiditic reservoirs, besides the intense influence of the salt tectonics that may have been responsible for the migration of hydrocarbons along faults or by their walls, towards upper formations and to the surface.
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O'Brien, G. W., and D. T. Heggie. "HYDROCARBON GASES IN SEAFLOOR SEDIMENTS, OTWAY AND GIPPSLAND BASINS: IMPLICATIONS FOR PETROLEUM EXPLORATION." APPEA Journal 29, no. 1 (1989): 96. http://dx.doi.org/10.1071/aj88014.
Повний текст джерелаАнотація:
During April- May 1988, the BMR research vessel Rig Seismic carried out a 21- day geochemical and sedimento- logical research program in the Otway (17 days) and Gippsland (4 days) Basins. The concentrations and molecular compositions of light hydrocarbon gases (C1- C4) were measured in sediments at 203 locations on the continental shelf and upper continental slope: the presence of thermogenic hydrocarbons was inferred from the molecular compositions of the gas mixtures. Thermogenic hydrocarbons were identified in near- surface sediments at 32 locations in the Otway Basin; 6 of these locations were on the Crayfish Platform, 7 were on the Mussel Platform and 17 were in the Voluta Trough. Thermogenic hydrocarbons were identified at 10 locations in the Gippsland Basin. Data from the Otway Basin indicated that total C1- C4 gas concentrations were higher in the Voluta Trough than on the basin margins, probably because intense faulting in the trough facilitates gas migration from deeply buried source rocks and/or reservoirs to the seafloor. However, anomalies were detected where the Tertiary sequence was thick and relatively unfaulted. The wet gas contents of the anomalies were highest on the basin margins, lower in the Voluta Trough and co- varied with the depth of burial of the basal Early Cretaceous sedimentary sequence. These data, when integrated with geohistory, thermal maturation modelling and well data, suggest that the areas with the best potential for liquid hydrocarbon entrapment and preservation are the Crayfish Platform and the inshore part of the Mussel Platform. In contrast, the Late Cretaceous Sherbrook Group and much of the Voluta Trough appear to be gas prone.Thermogenic anomalies in the Gippsland Basin were concentrated within and along the margins of the Central Deep where mature Latrobe Group source rocks are present. The wet gas content of these anomalies was variable, which is consistent with the spatial heterogeneity of hydrocarbon accumulations in the Gippsland Basin.
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Cao, Song, and Ian Lerche. "Geo History, Thermal History and Hydrocarbon Generation History of the Northern North Sea Basin." Energy Exploration & Exploitation 5, no. 4 (August 1987): 315–55. http://dx.doi.org/10.1177/014459878700500404.
Повний текст джерелаАнотація:
A one-dimensional, fluid flow/compaction model has been developed for petroleum explorationists to make quantitative studies of sedimentary basins. The following results can be obtained from the model: (1) basement subsidence (sediment load and tectonic effect); (2) structural evolution; (3) determination of erosion thickness of an unconformity; (4) changes of porosity, permeability, fluid flow rate and pore pressure with time and depth; (5) heat flow history; (6) temperature change with time and depth; (7) the value of thermal maturity indicators which change with time and depth; (8) hydrocarbon generation history including time and depth of peak hydrocarbon generation; and (9) prediction of possible directions of hydrocarbon migration and accumulation with time. The model is applicable to both frontier basins where only a few wells have been drilled and also to well-developed basins. The input data for the model are based mainly on commonly used geological and geochemical data from one well in a frontier basin or on similar data from many wells in a well-developed basin. Fifty-eight wells in the northern North Sea Basin have been used to reconstruct the geohistory, thermal history and hydrocarbon generation and migration history of the northern North Sea. The results accurately conformed to the well data, allowing determination of hydrocarbon generation amounts, migration times and accumulation sites, which are helpful for further hydrocarbon exploration in the northern North Sea Basin.
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Parinos, C., A. Gogou, I. Bouloubassi, R. Pedrosa-Pàmies, I. Hatzianestis, A. Sanchez-Vidal, G. Rousakis, D. Velaoras, G. Krokos, and V. Lykousis. "Occurrence, sources and transport pathways of natural and anthropogenic hydrocarbons in deep-sea sediments of the eastern Mediterranean Sea." Biogeosciences 10, no. 9 (September 24, 2013): 6069–89. http://dx.doi.org/10.5194/bg-10-6069-2013.
Повний текст джерелаАнотація:
Abstract. Surface sediments collected from deep basins (1018–4087 m depth) of the eastern Mediterranean Sea (Ionian Sea, southern Aegean Sea and northwestern Levantine Sea) were analyzed for aliphatic and polycyclic aromatic hydrocarbons as tracers of natural and anthropogenic inputs. Concentrations of total aliphatic hydrocarbons, n-alkanes and the unresolved complex mixture (UCM) of aliphatic hydrocarbons varied significantly, ranging from 1.34 to 49.2 μg g−1, 145 to 4810 ng g−1 and 0.73 to 36.7 μg g−1, respectively, while concentrations of total polycyclic aromatic hydrocarbons (PAHs) ranged between 11.6 and 223 ng g−1. Molecular profiles of determined hydrocarbons reflect a mixed contribution from both natural and anthropogenic sources in deep-sea sediments of the eastern Mediterranean Sea, i.e., terrestrial plant waxes, degraded petroleum products, unburned fossil fuels and combustion of grass, wood and coal. Hydrocarbon mixtures display significant variability amongst sub-regions, reflecting differences in the relative importance of inputs from various sources and phase associations/transport pathways of individual hydrocarbons that impact on their overall distribution and fate. Hydrocarbon concentrations correlated significantly with the organic carbon content of sediments, indicating that the latter exerts an important control on their transport and ultimate accumulation in deep basins. Additionally, water masses' circulation characteristics also seem to influence the regional features and distribution patterns of hydrocarbons. Our findings highlight the role of deep basins/canyons as repositories of both natural and anthropogenic chemical species.
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Lowrie, A., M. G. MacKenzie, E. Guderion, and F. E. Talbert. "Sedimentary Shattering as Hydrocarbon Migration Avenues in Salt-floored Basins: A New Migration Paradigm." Energy Exploration & Exploitation 15, no. 4-5 (September 1997): 387–95. http://dx.doi.org/10.1177/0144598797015004-505.
Повний текст джерелаАнотація:
The salt-floored basin concept as applied to the Louisiana offshore, with its total dependence on laterally migrating salt, provides a dynamic view of geologic evolution. Salt domes, ridges, and massifs move basinward at rates of one to ten cm/yr, causing extensive fracturing, thermal anomalies, and under- and over-pressured horizons. The ever-enlarging sedimentary wedge contains its own tectonics; principally basin-spanning shelf-edge growth faults that sole out in shale layers. Advancing salt tongues can create counter-regional and local growth faults that terminate in the semi-plastic salt. Additional stresses, some by basement faulting, are also active within the salt-floored passive margin. A geologically reasonable conclusion, derived from the abundance of tectonics, is that the sediments may be thought of as shattered. Porous flowage would be reminiscent of that through a colander, not a sieve. Given the possibility of such massive shattering, it is obligatory to prepare a different paradigm relative to hydrocarbon migration. The now decades old notion that most, if not all, hydrocarbons migrate along regional faults must be modified. The shattered sedimentary wedge becomes a conduit for hydrocarbon migration with some concentration of hydrocarbon flow along regional faults, however intermittent that may be. The sedimentary shattering may be so extensive that a new paradigm need be applied to hydrocarbon migration.
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Passmore, V. L., P. E. Williamson, T. U. Mating, and A. R. G. Gray. "THE GULF OF CARPENTARIA—A NEW BASIN AND NEW EXPLORATION TARGETS." APPEA Journal 33, no. 1 (1993): 297. http://dx.doi.org/10.1071/aj92021.
Повний текст джерелаАнотація:
The sparsely explored Gulf of Carpentaria is a shallow water frontier area of stacked basins. The petroleum potential was not tested by the one offshore well drilled in the Gulf in 1984.Recent re-interpretation of offshore seismic in Queensland waters delineated the Bamaga Basin, a new infrabasin below the Carpentaria Basin. This new basin is a northerly trending asymmetrical sag basin that continues north of the international boundary. The Bamaga Basin, containing up to 1.8 seconds of gently folded and faulted sediments, is untested and offers a new exploration objective. Apparent high velocities make the age of the basin uncertain, but Paleozoic reservoir and source rocks, similar to sedimentary rocks in nearby basins, are inferred, although analogue basins are not readily identifiable.Bamaga Basin source rock burial is sufficient to generate hydrocarbons and could source reservoirs in the Bamaga and Carpentaria Basins via migration along faults. Possible direct hydrocarbon indicators increase support for the presence of hydrocarbons in the Gulf.Structural and stratigraphic plays in the Carpentaria Basin that provide new exploration targets include: basal sandstones onlapping areas of higher relief or filling basin floor depressions, sandstone layers within the Wallumbilla Formation draping highs and possible carbonate zones appearing as high amplitude chaotic reflectors. Within the Bamaga Basin, horst, fault structures and anticlinal features are potential structural plays, and termination of units against the main unconformity are possible stratigraphic play targets.
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Li, Sitian, and Shu Sun. "Basin geodynamic analysis and hydrocarbon resources prediction in East China basins." Journal of the Sedimentological Society of Japan 58, no. 58 (2004): 85–89. http://dx.doi.org/10.4096/jssj1995.58.85.
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Stewart, S. A. "Negatively buoyant CO2 solution sequestration in synformal traps." Petroleum Geoscience 28, no. 1 (November 22, 2021): petgeo2021–074. http://dx.doi.org/10.1144/petgeo2021-074.
Повний текст джерелаАнотація:
Dissolving CO2 into water or brine produces a denser fluid than the CO2-free equivalent at all salinity, temperature and pressure conditions relevant to sedimentary basins. Negative buoyancy of CO2 solutions opens the possibility of utilizing negative-relief trapping configurations for CO2 sequestration, as opposed to structural highs conventionally sought for positively buoyant fluids, such as hydrocarbons or pure CO2. Exploring sedimentary basins for negative buoyancy traps can readily utilize hydrocarbon exploration datasets and techniques. Some major systemic differences when exploring for negative as opposed to positive buoyancy traps are examined here. Trap spatial scale is a consideration due to the inherent long-wavelength synformal geometry of basins. Antiforms are areally restricted relative to synforms, which may be embedded within larger-scale synformal closure at length scales right up to that of the basin itself. Multiscale synformal structures vary with basin type and may not be fully identified due to truncation effects arising from data-coverage limitations. Similar to hydrocarbon exploration, CO2 trap exploration must consider potential sequestration volumes in an uncertainty and risk framework. Charge risk is unnecessary in sequestration projects; however, the multiscale nature of synformal traps should be considered when estimating the range of storage volumes.Thematic collection: This article is part of the Geoscience for CO2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage
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Warris, B. J. "THE HYDROCARBON POTENTIAL OF THE PALAEOZOIC BASINS OF WESTERN AUSTRALIA." APPEA Journal 33, no. 1 (1993): 123. http://dx.doi.org/10.1071/aj92010.
Повний текст джерелаАнотація:
There are four main Palaeozoic Basins in Western Australia; the Perth Basin (Permian only), the Carnarvon Basin (Ordovician-Permian), the Canning Basin (Ordovician-Permian) and the Bonaparte Basin (Cambrian-Permian).The Perth Basin is a proven petroleum province with commercially producing gas reserves from Permian strata in the Dongara, Woodada and Beharra Springs gas fields.The Palaeozoic of the Carnarvon Basin occurs in three main sub-basins, the Ashburton, Merlinleigh and Gascoyne Sub-basins. No commercial petroleum discoveries ahve been made in these basins.The Canning Basin can be divided into the southern Ordovician-Devonian province of the Willara and Kidson sub-basins and Wallal Embayment and Anketell Shelf, and the northern Devonian-Permian province of the Fitzroy and Gregory sub-basins. Commercial production from the Permo-Carboniferous Sundown, Lloyd, West Terrace, Boundary oilfields and from the Devonian Blina oilfield is present only in the Fitzroy sub-basins.The Bonaparte Basin contains Palaeozoic strata of Cambrian-Permian age but only the Devonian-Permian is considered prospective. Significant but currently non-producing gas discoveries have been made in the Permian of the Petrel and Tern offshore gas fields.Based on the current limited well control, the Palaeozoic basins of Western Australia contain excellent marine and non marine clastic reservoirs together with potential Upper Devonian and Lower Carboniferous reefs. The dominantly marine nature of the Palaeozoic provides thick marine shale seals for these reservoirs. Source rock data is very sparse but indicates excellent gas prone source rocks in the Early Permian and excellent—good oil prone source rocks in the Early Ordovician, Late Devonian, Early Carboniferous and Late Permian.Many large structures are present in these Palaeozoic basins. However, most of the existing wells were drilled either off structure due to insufficient and poor quality seismic or on structures formed during the Mesozoic which postdated primary hydrocarbon migration from the Palaeozoic source rocks.With modern seismic acquisition and processing techniques together with a better understanding of the stratigraphy, structural development and hydrocarbon migration, the Palaeozoic basins of Western Australia provide the explorer with a variety of high risk, high potential plays without the intense bidding competition currently present along the North West Shelf of Australia.
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Nguimbous-Kouoh, Jean Jacques, Jacques Tchutchoua, Simon Ngos III, Theophile Ndougsa Mbarga, and Eliezer Manguelle-Dicoum. "Hydrocarbon Potential of Two Coastal Basins (Cameroon)." International Journal of Geosciences 09, no. 02 (2018): 131–47. http://dx.doi.org/10.4236/ijg.2018.92009.
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Haszeldine, R. S., C. I. Macaulay, A. Marchand, M. Wilkinson, C. M. Graham, A. Cavanagh, A. E. Fallick, and G. D. Couples. "Sandstone cementation and fluids in hydrocarbon basins." Journal of Geochemical Exploration 69-70 (June 2000): 195–200. http://dx.doi.org/10.1016/s0375-6742(00)00126-6.
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Li, Diquan, and Qiaoxun Zhang. "Application of the Wide Field Electromagnetic Method for Oil and Gas Exploration in a Red-bed Basin of South China." Journal of Environmental and Engineering Geophysics 26, no. 1 (March 2021): 25–34. http://dx.doi.org/10.32389/jeeg20-041.
Повний текст джерелаАнотація:
Red-bed basins with rich hydrocarbon source rocks are widely distributed in south China, such as Banshi Basin in southern Jiangxi, which may have very good prospects for oil and gas exploration. However, due to poor ground conditions, and complex geological structures, seismic exploration and conventional electromagnetic methods cannot provide useful information for hydrocarbon evaluation. This study uses the wide field electromagnetic (WFEM) method to investigate the distribution and geoelectric characteristics of the target stratum of a red-bed basin in Jiangxi province, China. The inversion results demonstrate that the WFEM method could quickly delineate the favorable area and determine the location of the parametric well, confirming that the WFEM method is an effective geophysical exploration method for evaluating hydrocarbon resources in red-bed basins.
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Silva-Gonzalez, Patricio, and Jarrad Grahame. "High-quality data from the Eendracht MC3D seismic survey gives insight about the hydrocarbon potential of the Carnarvon Basin." APPEA Journal 53, no. 2 (2013): 486. http://dx.doi.org/10.1071/aj12097.
Повний текст джерелаАнотація:
The Eendracht 3D multi-client seismic survey covers an area of about 8,000 km2. It is located in the Carnarvon Basin, one of Australia’s most hydrocarbons-prolific basins. The basin is filled with thick Paleozoic, Mesozoic, and Cenozoic sedimentary successions, deposited during multiple phases of extension and following the breakup of Gondwana. The most prominent structural trend is northeast—southwest with basins and sub-basins aligned as a consequence of the rifting event, which occurred during Jurassic to Early Cretaceous. Recent discoveries like Ragnar–1 and Tallaganda–1 show a working petroleum system and the high prospectivity of the Carnarvon Basin. The Eendracht survey covers a relatively less-explored but prolific area of the basin and provides a large volume of high-quality 3D seismic data. New technologies for acquisition and processing such as Fresnel Zone Bining, Interactive Azimuthal Anisotropy Analysis, and Diffracted Noise/Multiple Attenuation have been used. The hydrocarbon generation, migration, and entrapment in the Carnarvon Basin is controlled by Jurassic to Early Cretaceous syn- and post-rift structures, deposition, and Neogene reactivation. The most dominant successions in the Basin are Triassic to Lower Cretaceous sedimentary units. The Triassic Mungaroo Formation is the main reservoir found in the area covered by the Eendracht survey. Northeast–southwest-oriented extensional structures create potential traps for hydrocarbons and structures like horsts, tilted fault blocks, drapes, and fault-over anticlines can now be better visualised and analysed due to the 3D character of the Eendracht survey.
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Sarkowi, Muh, Rahmat Catur Wibowo, Suhayat Minardi, and Indra Arifianto. "Identification of Hydrocarbons Sub-Basin Based on Gravity Data Analysis in Lampung Area." Jurnal Penelitian Fisika dan Aplikasinya (JPFA) 11, no. 2 (December 30, 2021): 106–13. http://dx.doi.org/10.26740/jpfa.v11n2.p106-113.
Повний текст джерелаАнотація:
Gravity Data analyses in Lampung area are carried out to identify potential hydrocarbon sub-basins. The hydrocarbon potential in the Lampung sub-basin is indicated by the presence of hydrocarbon seepage found in Wai Imus, Wai Tahmi, and from oil shown in Ratu-1 and Tujo-1 exploration wells. Spectrum analysis, filtering, gradient, and gravity anomaly modeling determine the presence of potential hydrocarbon sub-basins in the Lampung sub-basin. Our results show that the Bouguer anomaly in the Lampung sub-basin ranges from 0 mGal to 90 mGal. A high anomaly appears in the southern part associated with basement high and a low anomaly in the center area of the western region related to the existence of the large Sumatra fault zone. The Bouguer Anomaly spectrum analysis result shows that basement depth in the Lampung sub-basin is 2400 m to 4400 meters deep. Data analysis of residual Bouguer anomaly, SVD residual Bouguer anomaly, and fault structure identified 18 sub- hydrocarbon potential basins scattered in Way Kanan, Tulang Bawang Barat, Menggala, Mesuji, Terbanggi Besar - Seputih Surabaya (Central Lampung), Sukadana and Labuhan Maringgai (East Lampung) areas. Some volcanic paths were also identified from Ratu-1 well, and Tujo-1 well in the Lampung WKP block. 2.5D modeling results of residual Bouguer anomaly show Kasai, Muara Enim, and Air Benakat, respectively, overburdened rock formations deposited from the top, followed by the Gumai Formation, which acts as a seal formation, while the hydrocarbon reservoirs are from the Baturaja and Talang Akar Formation. Our subsurface depth model has been verified by Ratu-1 and Tujo-1 exploration well.
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Holford, Simon, Nick Schofield, Justin MacDonald, Ian Duddy, and Paul Green. "Seismic analysis of igneous systems in sedimentary basins and their impacts on hydrocarbon prospectivity: examples from the southern Australian margin." APPEA Journal 52, no. 1 (2012): 229. http://dx.doi.org/10.1071/aj11017.
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The increasing availability of 3D seismic data from sedimentary basins at volcanic and non-volcanic continental margins has provided fundamental new insights into both the storage and transport of magma in the continental crust. As global hydrocarbon exploration increasingly focuses on passive margin basins with evidence for past intrusive and extrusive igneous activity, constraining the distribution, timing and pathways of magmatism in these basins is essential to reduce exploration risk. Producing and prospective Australian passive margin basins where igneous systems have been identified include the Bight, Otway, Bass, Gippsland and Sorell basins of the southern margin. This paper reviews both the impacts of volcanic activity on sedimentary basin hydrocarbon prospectivity (e.g. advective heating, reservoir compartmentalisation and diagenesis), and the styles, distribution and timing of late Cretaceous–Recent extrusive and intrusive igneous activity along basins of the southern Australian margin, providing illustrative examples based on 2D and 3D seismic reflection data.
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Cook, R. A., E. M. Crouch, J. I. Raine, C. P. Strong, C. I. Uruski, and G. J. Wilson. "INITIAL REVIEW OF THE BIOSTRATIGRAPHY AND PETROLEUM SYSTEMS AROUND THE TASMAN SEA HYDROCARBON-PRODUCING BASINS." APPEA Journal 46, no. 1 (2006): 201. http://dx.doi.org/10.1071/aj05012.
Повний текст джерелаАнотація:
Understanding the genesis and habitat of hydrocarbons in a sedimentary basin takes knowledge of that basin at many levels, from basic infill geology to petroleum systems, plays, prospects and detailed sequence stratigraphy. While geophysics can define the basins and their internal structures, biostratigraphy and paleogeography provide greater understanding of basin geology. Micropaleontology and palynology are the chief tools that we need to define both the environment and dimension of time.As an example, the reconstruction of the Tasman Sea region to the mid-Cretaceous (ca 120 Ma) shows that the hydrocarbon-producing Gippsland and Taranaki petroleum basins developed at similar latitudes and in similar geological contexts. Other basins within the region have been lightly explored and need evaluation as to the value of further exploration.As paleontology has developed separately in Australia and New Zealand, comparison of biostratigraphic zones and their chronostratigraphy is critical to understand the similarity or otherwise of the sedimentary record of the two regions. Recent refinement of the NZ timescale and comparative studies on Gippsland Basin wells by NZ paleontologists have provided some key insights that enable us to compare the geological history of both regions more closely, and to recognise similarities in petroleum systems that may enhance petroleum prospects on both sides of the Tasman Sea.
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Wang, Ziyi, Zhiqian Gao, Tailiang Fan, Hehang Zhang, Lixin Qi, and Lu Yun. "Hydrocarbon-bearing characteristics of the SB1 strike-slip fault zone in the north of the Shuntuo Low Uplift, Tarim Basin." Petroleum Geoscience 27, no. 1 (July 1, 2020): petgeo2019–144. http://dx.doi.org/10.1144/petgeo2019-144.
Повний текст джерелаАнотація:
The SB1 strike-slip fault zone, which developed in the north of the Shuntuo Low Uplift of the Tarim Basin, plays an essential role in reservoir formation and hydrocarbon accumulation in deep Ordovician carbonate rocks. In this research, through the analysis of high-quality 3D seismic volumes, outcrop, drilling and production data, the hydrocarbon-bearing characteristics of the SB1 fault are systematically studied. The SB1 fault developed sequentially in the Paleozoic and formed as a result of a three-fold evolution: Middle Caledonian (phase III), Late Caledonian–Early Hercynian and Middle–Late Hercynian. Multiple fault activities are beneficial to reservoir development and hydrocarbon filling. In the Middle–Lower Ordovician carbonate strata, linear shear structures without deformation segments, pull-apart structure segments and push-up structure segments alternately developed along the SB1 fault. Pull-apart structure segments are the most favourable areas for oil and gas accumulation. The tight fault core in the centre of the strike-slip fault zone is typically a low-permeability barrier, whilst the damage zones on both sides of the fault core are migration pathways and accumulation traps for hydrocarbons, leading to heterogeneity in the reservoirs controlled by the SB1 fault. This study provides a reference for hydrocarbon exploration and development of similar deep-marine carbonate reservoirs controlled by strike-slip faults in the Tarim Basin and similar ancient hydrocarbon-rich basins.
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Boreham, C. J., J. M. Hope, and B. Hartung-Kagi. "UNDERSTANDING SOURCE, DISTRIBUTION AND PRESERVATION OF AUSTRALIAN NATURAL GAS: A GEOCHEMICAL PERSPECTIVE." APPEA Journal 41, no. 1 (2001): 523. http://dx.doi.org/10.1071/aj00026.
Повний текст джерелаАнотація:
Natural gases from all of Australia’s major gas provinces in the Adavale, Amadeus, Bass, Bonaparte, Bowen/ Surat, Browse, Canning, Carnarvon, Cooper/Eromanga, Duntroon, Gippsland, Otway and Perth basins have been examined using molecular and carbon isotopic compositions in order to define their source, maturity and secondary alteration processes.The molecular compositions of the gaseous hydrocarbons range from highly wet to extremely dry. On average, reservoired gases predominantly derived from land plants are slightly wetter than those derived from marine sources. The non-hydrocarbon gases CO2 and N2 were sourced from both inorganic and organic materials. A mantle and/or igneous origin is likely in the majority of gases with CO2 contents >5%. For gases with lower CO2 contents, an additional organic input, associated with hydrocarbon generation, is recognised where δ13C CO2 is A strong inter-dependency between source and maturity has been recognised from the carbon isotopic composition of individual gaseous hydrocarbons. This relationship has highlighted some shortcomings of common graphical tools for interpretation of carbon isotopic data. The combination of the carbon isotopic composition of gaseous hydrocarbons and the low molecular weight nalkanes in the accompanying oil allows our knowledge of oil-source correlations and oil families to be used to correlate gases with their sources. This approach has identified source rocks for gas ranging in age from the Ordovician in the Amadeus Basin to Late Cretaceous- Early Tertiary sources in the Bass and Gippsland basins. The carbon isotopic composition of organic matter, approximated using the δ13C of iso-butane, shows a progressive enrichment in 13C with decreasing source age, together with marine source rocks for gas being isotopically lighter than those from land plant sources. The Permian was a time when organic matter was enriched in 13C and isotopically uniform on a regional scale.Secondary, in-reservoir alteration has played a major role in the modification of Australian gas accumulations. Thus, biodegradation, prominent in the Bowen/Surat, Browse, Carnarvon and Gippsland basins, is found in both hydrocarbon and non-hydrocarbon gases. This is recognised by an increase in gas dryness, elevated isoalkane to n-alkane ratio, differential increase in δ13C of the individual wet gas components, a decrease in δ13C of methane and a reduction in CO2 content concomitant with enrichment in 13C. Evidence of water-washing has been identified in accumulations in the Bonaparte and Cooper/Eromanga basins, resulting in an increase in the wet gas content. Seal integrity is also a major risk for the preservation of natural gas accumulations, although its effect on gas composition is only evident in extreme cases, such as the Amadeus Basin, where preferential leakage of methane in the Palm Valley field has resulted in the residual methane becoming enriched in 13C.The greater mobility of gas within subsurface rocks can have a detrimental effect on oil composition whereby gas-stripping of light hydrocarbons is common amongst Australian oil accumulations. Alternatively, the availability of gas, derived from a source rock common to or different from oil, was likely to have been a prime factor controlling the regional distribution of oil, whereby mixing of both results in increased oil mobility and can lead to a greater access to the number and types of traps in the subsurface.
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Powell, T. G. "AUSTRALIA’S HYDROCARBON PROVINCES—WHERE WILL FUTURE PRODUCTION COME FROM?" APPEA Journal 44, no. 1 (2004): 729. http://dx.doi.org/10.1071/aj03037.
Повний текст джерелаАнотація:
The cumulative graph of reserves added to a basin through time is a measure of that basins’ exploration maturity. Additions of reserves through new field discovery are limited in the Bowen-Surat, Gippsland, Cooper-Eromanga and Bonaparte Basins whilst significant discoveries continue to be made in the Carnarvon Basin. The recent discoveries in the Perth Basin represent a significant new phase in the addition to reserves for this basin. Reserves growth in existing fields represents a very significant source of new crude oil reserves. All gas bearing basins including those in eastern Australia show potential for additional gas discoveries. Coal Bed Methane also represents a significant gas resource into the future.Australia’s production of crude oil has averaged 11% of the remaining reserves over the last decade. In the late 90s, the rate of production has exceeded the rate of addition to reserves and production must decline in the medium term. Medium- to long-term forecasts of future crude oil production are uncertain because of the difficulty in predicting the rate of crude oil discovery, particularly since many of the established plays in established crude oil basins appear to have little remaining potential and success rates and potential for new plays in established and frontier areas of exploration is unknown.Rates of gas production are not related to existing reserves, but rather to the dynamics of the commercial market which is strongly influenced by regional infrastructure.
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Okoro, E. M., K. M. Onuoha, C. G. Okeugo, and C. I. P. Dim. "Structural interpretation of High-resolution aeromagnetic data over the Dahomey basin, Nigeria: implications for hydrocarbon prospectivity." Journal of Petroleum Exploration and Production Technology 11, no. 4 (March 22, 2021): 1545–58. http://dx.doi.org/10.1007/s13202-021-01138-w.
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AbstractThe renewed quest to boost Nigeria’s dwindling reserves through aggressive search for oil and gas deposits in Cretaceous sedimentary basins has re-ignited the need to re-evaluate the hydrocarbon potentials of the Dahomey Basin. Aeromagnetic data are a low-cost geophysical tool deployed in mapping regional basement structures and determination of basement depths and sedimentary thickness in frontier basin exploration. In this study, high-resolution aeromagnetic (HRAM) data covering the Dahomey Basin Nigeria have been interpreted to map the basement structural configuration and to identify mini-basins favorable for hydrocarbon prospectivity. The total magnetic intensity grid was reduced to the equator (RTE) and edge detection filters including first vertical derivative (FVD), total horizontal derivative (THDR), tilt derivative (TDR) and total horizontal derivative of upward continuation (THDR_UC)) were applied to the RTE grid to locate the edges and contacts of geological structures in the basin. Depth to magnetic sources were estimated using the source parameter imaging (SPI) method. Data interpretation results revealed shallow and deep-seated linear features trending in the NNE-SSW, NE-SW, NW-SE and WNW-ESE directions. The SPI map showed a rugged basement topography which depicted a horst-graben architecture on 2D forward models along some selected profiles. Two mini-basins ranging in basement depths between 4.5 – 6.3km were mapped offshore of the study area. It appears the offshore Dahomey Basin holds greater promises for hydrocarbon occurrence due to the presence of thicker succession of sedimentary deposits in the identified mini-basins.
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Bradshaw, Marita, Dianne Edwards, Chris Boreham, Emmanuelle Grosjean, Jennifer Totterdell, Thomas Bernecker, and Andrew Heap. "Geochemical underpinnings of Australia's offshore hydrocarbon prospectivity." APPEA Journal 54, no. 1 (2014): 415. http://dx.doi.org/10.1071/aj13041.
Повний текст джерелаАнотація:
Molecular and isotopic analyses of oils and gases can provide information on the depositional environment, maturation and age of their source rocks, and the post expulsion history of the hydrocarbons generated. Source rock analyses can determine their potential to generate hydrocarbons of varying type over specific thermal ranges, as well as demonstrating the strength of oil- or gas-to-source correlations. Together, this geochemical interpretation can provide insights about the extent of petroleum systems and can help delineate the relationships between hydrocarbon occurrences in a basin and across the continent. Oils that do not fit the well-established framework of oil families and Australian petroleum systems point to new source rock fairways. Examples include vagrant oils with lacustrine affinities found at various locations on the western Australian margin. Other examples are oil occurrences in the Gippsland Basin whose geochemical signatures contrast with the dominant non-marine oils, supporting the existence of a viable marine source rock facies. In under-explored and frontier basins, geochemical analyses of potential source rocks can provide key evidence to underpin new exploration efforts. For example, the recent acreage uptake in the Bight Basin was supported by Geoscience Australia’s recovery and analysis of oil-prone marine source rocks, and in the northern Perth Basin by new geochemical analysis extending the distribution of Lower Triassic Hovea marine source rocks offshore. Geoscience Australia has now embarked on a regional petroleum geological program that includes a national source rock study aimed at identifying and characterising Australia’s hydrocarbon sources, families and systems.
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Macgregor, Duncan S. "Hydrocarbon habitat and classification of inverted rift basins." Geological Society, London, Special Publications 88, no. 1 (1995): 83–93. http://dx.doi.org/10.1144/gsl.sp.1995.088.01.06.
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Belonin, Michael D., George V. Chilingar, and Yuri N. Grigorenko. "Hydrocarbon distribution in sedimentary basins of Northeastern Asia." Journal of Petroleum Science and Engineering 15, no. 2-4 (August 1996): 261–69. http://dx.doi.org/10.1016/0920-4105(95)00070-4.
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Radkovets, Nataliya, Kostyantyn Hrygorchuk, Yuriy Koltun, Volodymyr Hnidets, Ihor Popp, Marta Moroz, Yuliya Hayevska, et al. "Dynamics of lithogenesis of Phanerozoic sedimentary sequence of the Carpathian-Black Sea region in the aspect of their oil- and gas-bearing potential." Geology and Geochemistry of Combustible Minerals 1-2, no. 183-184 (2021): 60–75. http://dx.doi.org/10.15407/ggcm2021.01-02.060.
Повний текст джерелаАнотація:
The objective of this work was to study the environments and processes of ancient sedimentation in the epi- and mesopelagic basins of the Carpathian-Black Sea region and to clarify the conditions of oil and gas basins formation within the study region as well as the main aspects of hydrocarbon generation. The burial history of the basins, some aspects of their fluid regime, issues of lithogenetic record, features of transformation of sedimentary basins into the rock-formation basins and the development of the latter during the Phanerozoic are considered. The spatial and temporal peculiarities of the evolution of epi-mesopelogic systems and their influence on the formation of oil- and gas-bearing strata within the Carpathian-Black Sea region have been studied. It has been established that in the sedimentary basins of the Carpathian-Black Sea continental margin of the Tethys Ocean during the long geological history the different intensity structural and morphological changes took place: changes of the subsidence rate of the basin bottom, inversion uplifts, sedimentation pauses, deformation of the sedimentary fill. This was reflected both in the peculiarities of the development of sedimentary environments and in the processes of substance differentiation with the formation of certain post-sedimentary mineral-structural parageneses. It was proved that discrete processes of differentiated compaction and defluidization of sediments cause a number of deformation phenomena, which can be reflected in the features of the morphology of the sedimentary basin bottom, influencing the nature of sediment transportation and accumulation. On the basis of the conducted investigations a number of practical results were obtained which will allow forming new approaches to criteria of hydrocarbons prospecting, in particular the lithophysical aspect which is concentrated on the reservoir properties of rocks; sedimentary reconstructions and the diversity of cyclicity of the studied sediments as a factor of the establishment of prospective areas, reconstruction of the burial history, which provides an information on the state of transformation of organic matter and hydrocarbons, and therefore the range of prospective depths for oil and gas occurrence.
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Løtveit, Ingrid F., Willy Fjeldskaar, and Magnhild Sydnes. "Tilting and Flexural Stresses in Basins Due to Glaciations—An Example from the Barents Sea." Geosciences 9, no. 11 (November 11, 2019): 474. http://dx.doi.org/10.3390/geosciences9110474.
Повний текст джерелаАнотація:
Many of the Earth’s sedimentary basins are affected by glaciations. Repeated glaciations over millions of years may have had a significant effect on the physical conditions in sedimentary basins and on basin structuring. This paper presents some of the major effects that ice sheets might have on sedimentary basins, and includes examples of quantifications of their significance. Among the most important effects are movements of the solid Earth caused by glacial loading and unloading, and the related flexural stresses. The driving factor of these movements is isostasy. Most of the production licenses on the Norwegian Continental Shelf are located inside the margin of the former Last Glacial Maximum (LGM) ice sheet. Isostatic modeling shows that sedimentary basins near the former ice margin can be tilted as much as 3 m/km which might significantly alter pathways of hydrocarbon migration. In an example from the SW Barents Sea we show that flexural stresses related to the isostatic uplift after LGM deglaciation can produce stress changes large enough to result in increased fracture-related permeability in the sedimentary basin, and lead to potential spillage of hydrocarbons out of potential reservoirs. The results demonstrate that future basin modeling should consider including the loading effect of glaciations when dealing with petroleum potential in former glaciated areas.
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Setiadi, I., Marjiyono, and T. B. Nainggolan. "Gravity Data Analysis Based on Optimum Upward Continuation Filter and 3D Inverse Modelling (Case Study at Sedimentary Basin in Volcanic Region Malang and Its Surrounding Area, East Java)." IOP Conference Series: Earth and Environmental Science 873, no. 1 (October 1, 2021): 012008. http://dx.doi.org/10.1088/1755-1315/873/1/012008.
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Abstract The study on the fore-arc sedimentary basin for hydrocarbon exploration is rare because of the more complicated geological structures, and conventional seismic methods cannot optimally penetrate the rock layers as there are many volcanic and limestone rocks. One of the natural resources potential in the Southern part of the East Java region, especially in Malang and its surrounding areas is the possibility of hydrocarbons in the fore-arc basin, so research is needed to know the existence of these sedimentary basins. The gravity method is one of the geophysical methods used to assess sedimentary basins based on physical parameters of mass density. The aims of this research are to delineate the sedimentary sub-basin, to find out its structure pattern, interpret subsurface geological and basement configuration. The data analysis approach used in this study involves spectral analysis, upward continuation filter, and 3D inverse modeling. The maximum height for the optimum upward continuation filter is 3000 m, which results in regional and residual anomalies. There were five sedimentary sub-basins identified based on residual gravity anomaly, and the gravity anomalies can also detect structure patterns such as basement high, lineament, and fault pattern. The bedrock is supposed as an intermediate igneous rock with a mass density of around 2.7 gr/cc according to the results of 3D inverse modeling. Deposition from bottom to upward is Mandalika, Nampol, and Wonosari Formations and completed by the uppermost are quaternary volcanic rocks. The inversion modeling results show that the Malang and surrounding areas have thick sedimentary rocks covered by volcanic deposits, which is impressive for further investigation to explore the possibility of the hydrocarbon existence in these areas.
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Kiomourtzi, P., N. Pasadakis, and A. Zelilidis. "GEOCHEMICAL CHARACTERIZATION OF SATELLITE HYDROCARBON FORMATIONS IN PRINOS-KAVALA BASIN (NORTH GREECE)." Bulletin of the Geological Society of Greece 40, no. 2 (January 1, 2007): 839. http://dx.doi.org/10.12681/bgsg.16728.
Повний текст джерелаАнотація:
Conditions favoring generation, migration and trapping of hydrocarbons generated economically significant reservoirs in Prinos-Kavala Basin. Prinos oil field and South Kavala gas field are characteristic examples. The submarine fan packed the basin during Upper Miocene. The hydrocarbons were accumulated in turbidites, deposited in a strongly reducing environment, with high sulfur concentration. Evaporates are also deposited before and after the turbidite system. In this study, which is part of a doctorate thesis, extracts retrieved from cored samples of two satellite formations in Prinos-Kavala Basin, Epsilon and Kalirahi, selected at the "Prinos equivalent" formations, have been analyzed, using geochemical methods, and found to exhibit common compositional characteristics. The analysis of biomarkers indicates that the bitumens are immature and non-biodegraded, while their origin is considered mainly algal, with minor terrestrial contribution. Variations on characteristic geochemical ratios between formations, such as Pr/Ph, Ts/Tm, oleanane/hopane and steranes index, are attributed to differences on the type of organic mater input, or the depositional setting of sediments. The identification of the organic matter type, the hydrocarbons generation, migration paths and traps of each structure within the basin is vital for the evaluation of a reliable model of the basin and further hydrocarbon exploration in North Aegean basins
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DeVito, Steve, and Hannah Kearns. "Overview of the exploration potential of offshore Argentina – insight from new seismic interpretations." Petroleum Geoscience 28, no. 2 (January 19, 2022): petgeo2020–132. http://dx.doi.org/10.1144/petgeo2020-132.
Повний текст джерелаАнотація:
Argentina's offshore sedimentary basins cover a vast area on one of the widest continental margins on the planet, yet they remain underexplored today. Previous exploration drilling has failed to encounter commercial volumes of hydrocarbons, in part due to the poor seismic imaging of legacy 1960s–1990s 2D seismic data, and to the majority of wells being drilled on structural highs outside of the source rock kitchens. In this study, we reviewed 52 000 km of recently acquired (2017–2018) regional 2D long-offset seismic data with broadband pre-stack time (PSTM) and depth migration (PSDM) processing. We identified five major structural domains with hydrocarbon prospectivity on the Northern Margin of Argentina and four on the Southern Margin, and the presence of previously unseen structural and stratigraphic traps involving sequences assigned to proven regional source rocks and reservoirs in Permian, Jurassic and Cretaceous rocks. The source and reservoir rocks, petroleum systems, and play types present in the deepwater of the undrilled Argentina Basin represent a true frontier for hydrocarbon exploration. Pseudo relief attribute seismic displays and amplitude v. angle (AVA) analysis are demonstrated to be valuable tools in predicting the stratigraphy of the basins. A new framework for understanding the oil and gas prospectivity of the study area is presented.
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Hall, Lisa, Tehani Palu, Chris Boreham, Dianne Edwards, Tony Hill, Alison Troup, and Paul Henson. "Cooper Basin source rock atlas." APPEA Journal 56, no. 2 (2016): 594. http://dx.doi.org/10.1071/aj15100.
Повний текст джерелаАнотація:
The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.
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Muslimov, Renat Kh. "An in-depth study of the crystalline basement of sedimentary basins is a dictate of the time." Georesursy 21, no. 4 (October 30, 2019): 55–62. http://dx.doi.org/10.18599/grs.2019.4.55-62.
Повний текст джерелаАнотація:
The history of studying the crystalline basement in the Republic of Tatarstan, the state of implementation of the super-deep drilling program is given. The scientific substantiation of the replenishment of exploited oil and oil-gas fields is provided by feeding them with deep hydrocarbons through oil supply channels connecting the deep source of hydrocarbons with sedimentary cover deposits. The crystalline basement is of interest for the search for hydrocarbon deposits, but its role as a transit for replenishing deposits of hydrocarbon sedimentary cover in the process of constant degassing of the Earth is more attractive and justified. To use these processes, a fundamentally new approach to the construction of geological and hydrodynamic models of oil fields is proposed, taking into account the fundamental principles of geological science on the formation and reformation of oil deposits and the deep processes of Earth degassing. Prospects are substantiated for the development of “old” fields that are in long-term development, for the calculation of oil recovery factor taking into account oil entering the reservoir from the depths of the Earth, the need for adjusting methods for calculating and accounting reserves, changing levels of material balance, and scientific and practical suggestions for accounting when calculating reserves and designing the development of fundamental principles of field geology. Further prospects for the introduction of hydrodynamic development methods and their significant expansion due to the opening of the processes of replenishment of sedimentary basin deposits with deep hydrocarbons and the reformation of deposits at a late stage of development are shown.
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Pang, Xiongqi, Ian Lerche, Chen Fajin, and Chen Zhangming. "Hydrocarbon Expulsion Threshold: Significance and Applications to Oil and Gas Exploration." Energy Exploration & Exploitation 16, no. 6 (December 1998): 539–55. http://dx.doi.org/10.1177/014459879801600603.
Повний текст джерелаАнотація:
Hydrocarbon explusion threshold (HET) is the critical condition for hydrocarbon expulsion in separate phase from a source rock when the generated hydrocarbon amount has satisfied all needs for absorption by minerals, solution in water, and blocking of capillary pressure. Research results show that the HET varies mainly with three geological parameters: total organic carbon content (C%), kerogen type index (KTI) and thermal maturation degree (R0). Source rocks with low C% and KTI cross the HET at a high level of maturation degree (larger R0); source rocks with lower R0 and C% can also cross the HET if the kerogen has a larger KTI. Under general geological conditions, a source rock first crosses the methane expulsion threshold (HETgl), then the heavy hydrocarbon gas threshold (HETgn), and finally the liquid hydrocarbon expulsion threshold (HET0). In this paper the concept of HET, and its critical conditions, are applied to establish the scientific validity of the concept and grade the source rocks, to study the phases of hydrocarbons in migration and the mechanisms of hydrocarbon accumulation, and to divide the hydrocarbon expulsion into stages. Applications to different basins in China show that HET provides an accurate and efficient method to guide oil and gas prospecting.
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Mai, P. S. Moore D. K. Hobday H., and Z. C. Sun. "COMPARISON OF SELECTED NON-MARINE PETROLEUM-BEARING BASINS IN AUSTRALIA AND CHINA." APPEA Journal 26, no. 1 (1986): 285. http://dx.doi.org/10.1071/aj85026.
Повний текст джерелаАнотація:
This paper summarises the geology and hydrocarbon potential of two Chinese and two Australian basins (Ordos, Northern Jiangsu, Eromanga, and Surat basins) in order to compare factors affecting the generation, migration, and entrapment of hydrocarbons. In all four basins, hydrocarbons are generated from nonmarine source rocks of lacustrine and fluvial-overbank origin. While the Chinese and Australian basins contain a similar range of sedimentary facies, from alluvial fan to lacustrine, the arrangement and relative thicknesses of these facies vary considerably as a result of different tectonic and palaeoclimatic settings.During the Triassic, the Ordos Basin was dominated by retroarc foredeep subsidence and the development of deep, fresh-water lakes with anoxic bottom waters. This non-bioturbated substrate, with Type I and II kerogen precursors, provided an excellent oil source for adjacent fan-delta, deltaic, and fluvial reservoirs, and for the unconformably overlying Jurassic fluvial valley-fill sandstone reservoirs.The Northern Jiangsu Basin was initiated by back-arc extension and underwent very rapid half-graben subsidence in the Eocene. Alluvial fan, shoreline, and fluvial facies aggraded in a relatively narrow zone along the active, faulted margin, and merged laterally into organic-rich shales which provided a local source for oil.By comparison, the Eromanga/Surat basins developed in response to gentle downwarp and reactivation of older structural trends. Reservoirs are largely restricted to craton-derived quartzose facies such as in the Hutton, Precipice, and Namur sandstones. There is probably a dual source for oil, from the underlying Permian (which may be the dominant source in the Surat Basin), and from shales deposited in shallow, partly oxygenated lakes and overbank facies of Jurassic age (important in the Eromanga, and possibly subordinate in the Surat Basin). Deep lacustrine facies, typical of the Chinese basins, did not develop. The greater abundance of oil in the Chinese nonmarine basins is explained in terms of tectonic and palaeoclimatic factors which yielded thicker and better quality source rocks, more rapid maturation, and a better juxtaposition of source rocks and good-quality reservoirs, thus providing short, highly efficient migration routes.
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Stemmerik, L., T. C. R. Pulvertaft, and H. C. Larsen. "Current activities in the field of hydrocarbon geology." Rapport Grønlands Geologiske Undersøgelse 148 (January 1, 1990): 21–24. http://dx.doi.org/10.34194/rapggu.v148.8111.
Повний текст джерелаАнотація:
GGU has two principal functions in the field of hydrocarbon geology: (1) to identify and investigate sedimentary basins with hydrocarbon potential, in order to obtain information that can attract and guide industry in its choice of target areas for exploration, and (2) on the basis of the insight gained from (1), to advise the Mineral Resources Administration for Greenland in technical matters concerning the administration of licences and concessions.
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Ramseyer, Karl, Joachim E. Amthor, Christoph Spötl, Jos M. J. Terken, Albert Matter, Marietta Vroon-ten Hove, and Jean R. F. Borgomano. "Impact of basin evolution, depositional environment, pore water evolution and diagenesis on reservoir-quality of Lower Paleozoic Haima Supergroup sandstones, Sultanate of Oman." GeoArabia 9, no. 4 (October 1, 2004): 107–38. http://dx.doi.org/10.2113/geoarabia0904107.
Повний текст джерелаАнотація:
ABSTRACT Sandstones of the Early Paleozoic Miqrat Formation and Barik Sandstone Member (Haima Supergroup) are the most prolific gas/condensate containing units in the northern part of the Interior Oman Sedimentary Basin (IOSB). The reservoir-quality of these sandstones, buried to depths exceeding 5 km, is critically related to the depositional environment, burial-related diagenetic reactions, the timing of liquid hydrocarbon charge and the replacement of liquid hydrocarbon by gas/condensate. The depositional environment of the sandstones controls the net-sand distribution which results in poorer reservoir properties northwards parallel to the axis of the Ghaba Salt Basin. The sandy delta deposits of the Barik Sandstone Member have a complex diagenetic history, with early dolomite cementation, followed by compaction, chlorite formation, hydrocarbon charge, quartz and anhydrite precipitation and the formation of pore-filling and pore-lining bitumen. In the Miqrat Formation sandstone, which is comprised of inland sabkha deposits, similar authigenic minerals occur, but with higher abundances of dolomite and anhydrite, and less quartz cement. The deduced pore water evolution from deposition to recent, in both the Miqrat Formation and the Barik Sandstone Member, reflects an early addition of saline continental waters and hydrocarbon-burial related mineral reactions with the likely influx of lower-saline waters during the obduction of the Oman Mountains. Four structural provinces are recognized in the IOSB based on regional differences in the subsidence/uplift history: the Eastern Flank, the Ghaba and Fahud Salt Basins and the Mabrouk-Makarem High. In the Fahud Salt Basin, biodegradation of an early oil charge during Late Paleozoic uplift resulted in reservoir-quality degradation by bitumen clogging of the pore space. On the Eastern Flank and the Mabrouk-Makarem High, however, the early oil bypassed the area. In contrast, post-Carboniferous liquid hydrocarbons were trapped in the Mabrouk-Makarem High, whereas on the Eastern Flank surface water infiltration and loss of hydrocarbons or biodegradation to pore occluding bitumen occurred. In the Ghaba Salt Basin, post-Carboniferous hydrocarbon charge induced a redox reaction to form porosity/permeability preserving chlorite in the reservoirs. The liquid hydrocarbons were replaced since the obduction of the Oman Mountains by gas/condensate which prevented the deep parts (>5,000 m) of the Ghaba Salt Basin from pore occluding pyrobitumen and thus deterioration of the reservoir quality.
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Pang, Bo, Junqing Chen, Xiongqi Pang, Tuo Liu, Haijun Yang, Hui Li, Yingxun Wang, and Tao Hu. "Possible new method to discriminate effective source rocks in petroliferous basins: A case study in the Tazhong area, Tarim Basin." Energy Exploration & Exploitation 38, no. 2 (September 11, 2019): 417–33. http://dx.doi.org/10.1177/0144598719871414.
Повний текст джерелаАнотація:
Sediments with organic matter content (total organic carbon) TOC ≤ 0.5% which can act as effective source rocks are critical and challenging in the field of petroleum geology. A new method is proposed through a case study to identify and evaluate the effective source rocks, which is applied to study the changing characteristic of hydrocarbon-generation potential index with depth. The burial depth corresponding to the beginning of hydrocarbon-generation potential index reduction represents the hydrocarbon expulsion threshold in source rocks. Then, new identification standards are established for discrimination of effective source rocks of Middle–Upper Ordovician in Tarim Basin. The critical value of TOC for effective source rocks change with their burial depth: the TOC > 0.5% with source rock depth > 4000 m, TOC > 0.4% with depth >4500 m, TOC > 0.3% with depth > 5000 m, TOC > 0.2% with depth >5500 m. Based on the new criteria, effective source rocks in the Middle–Upper Ordovician are identified and their total potential hydrocarbon resources is evaluated, reaches 0.68 × 109 t in the Tazhong area, which is 65.4% higher than that of previous studies and consistent with the exploration result. Thus, this new method is of significance to resource evaluation and can be applied in the carbonate source rocks and mudstone source rocks with high degree of exploration.
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Bernecker, Thomas, Aaron Heugh, Karen Higgins, and Ryan Owens. "The hydrocarbon potential of the 2016 proposed Offshore Acreage Release Areas for petroleum exploration." APPEA Journal 56, no. 1 (2016): 451. http://dx.doi.org/10.1071/aj15033.
Повний текст джерелаАнотація:
The Australian Government usually releases new offshore exploration acreage once a year. The proposed 2016 Release Areas are located across various offshore hydrocarbon provinces and include mature basins with ongoing oil and gas production as well as exploration frontiers. In support of the annual acreage release, Geoscience Australia provides a variety of geological information with an emphasis on basin evolution, stratigraphic frameworks, and overviews of hydrocarbon prospectivity. Geoscience Australia’s petroleum geological studies are aimed at the evolution of hydrocarbon-bearing basins at a regional scale, and include a review of source rock occurrences, their distribution and geochemical characters. Following the recent oil discovery in the Roebuck Basin, a strong focus of Geoscience Australia’s work is being placed on the Triassic period, and any new findings will directly underpin the release of new exploration acreage. Recent updates to stratigraphic frameworks and new results from geochemical studies are regularly published, and are used by Geoscience Australia for prospectivity assessments. Furthermore, the Australian Government continues to assist offshore exploration activities by providing ready access to a wealth of geological and geophysical data.
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Bujok, Petr, Martin Klempa, Petr Skupien, Dalibor Matýsek, and Michal Porzer. "Potential Unconventional Gas Plays in the Mature Basin of the Czech Republic." GeoScience Engineering 62, no. 4 (December 1, 2016): 19–26. http://dx.doi.org/10.1515/gse-2016-0026.
Повний текст джерелаАнотація:
Abstract The presence of unconventional resources has been proven in deeper parts of mature oil and gas provinces and coal basins of the world. In this context, it is worth to focus also on the prospects of unconventional gas production from within hydrocarbon provinces of the Moravian part of the Vienna basin. The estimation of hydrocarbon generation potential of Jurasic marls from the Mikulov Formation of the Czech part of the Vienna Basin was performed based on the Rock Eval pyrolysis.