Journal articles on the topic 'Hydrocarbon accumulation'
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Cvetković, Marko, Josipa Kapuralić, Marija Pejić, Iva Kolenković Močilac, David Rukavina, Duje Smirčić, Ana Kamenski, Bojan Matoš, and Marko Špelić. "Soil Gas Measurements of Radon, CO2 and Hydrocarbon Concentrations as Indicators of Subsurface Hydrocarbon Accumulation and Hydrocarbon Seepage." Sustainability 13, no. 7 (March 31, 2021): 3840. http://dx.doi.org/10.3390/su13073840.
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Soil gas measurements of radon (222Rn), CO2, and hydrocarbon concentrations, as well as gamma-ray spectrometry, were conducted at two separate locations to estimate the measurement results for known locations of hydrocarbon accumulations in the subsurface and oil seepage on the surface. The aim of the study was to confirm the applicability of the method for identifying migration pathways (e.g., faults) and to detect possible seepages of hydrocarbons to the surface as well as to investigate possible health issue potential about the soil gas analysis results. Site A investigations were performed with a large number of sampling points to provide sufficient spatial coverage to capture the influence of subsurface lithologic variability as well as the influence of the migration pathway on the measured parameters. For the investigation of site B, sampling points were positioned to reflect the situation between the area above producing hydrocarbon fields and areas with no confirmed accumulation. The results presented show that it is possible to distinguish the near-surface lithology (gamma-ray spectrometry), characterize the migration pathway, and indicate the area of oil seepage at the surface. Areas above the known hydrocarbon accumulations generally have elevated radon concentrations and detectable heavier hydrocarbons with sporadic methane in soil gas, which contrasts with the lower radon levels and lack of detectable heavier hydrocarbons in soil gas in the area with no confirmed hydrocarbon accumulation in the subsurface.
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Machel, H. G., and E. A. Burton. "Chemical and microbial processes causing anomalous magnetization in environments affected by hydrocarbon seepage." GEOPHYSICS 56, no. 5 (May 1991): 598–605. http://dx.doi.org/10.1190/1.1443076.
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(Aero‐)magnetic anomalies have been reported from several commercial hydrocarbon accumulations. However, the processes responsible for such anomalies are relatively poorly understood. This paper conceptually discusses chemical and microbiological processes involved in generating anomalous magnetization related to hydrocarbon accumulations, including hydrocarbon seepage environments. Based on thermodynamic criteria and microbiologic activity, the formation and destruction of magnetic mineral assemblages can be predicted. Under the influence of hydrocarbons, magnetite and pyrrhotite are the most important magnetic minerals formed, and the most abundant magnetic mineral destroyed is hematite. Hence, the invasion of hydrocarbons may result in “positive,” “absent,” or “negative” magnetic contrasts relative to the total magnetization prior to hydrocarbon invasion, depending upon the amounts of authigenic magnetite and pyrrhotite formed relative to the amounts of hematite destroyed. Magnetism may be generated also by natural and anthropogenic processes that have no relationships to an underlying or adjacent hydrocarbon accumulation. Consequently, anomalous magnetization, even if associated with a hydrocarbon accumulation, may or may not be genetically related to it. Magnetic mineral assemblages and the resulting magnetic contrasts, such as those predicted in this paper, have been documented from some hydrocarbon seepage environments. Hence, anomalous magnetization can be used for hydrocarbon exploration in association with other surface exploration methods.
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Pang, Xiongqi, Ian Lerche, Haiyan Zhou, and Zhengxue Jiang. "Hydrocarbon Accumulation Control by Predominant Migration Pathways." Energy Exploration & Exploitation 21, no. 3 (June 2003): 167–86. http://dx.doi.org/10.1260/014459803769520034.
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Geological analysis and physical analogy experiments indicate that, under geological conditions, hydrocarbon tends to migrate along a path of least resistance and attempt to follow the largest buoyancy component. There are four generalized modes of possible transport. First, hydrocarbons tends to migrate along the pathways with high porosity and permeability, and with a large grade difference relative to surrounding rocks (grade difference predominance); second, hydrocarbons tends to migrate in the opposite direction in overlying formations to the nadir of the sedimentation centre (divided syncline predominance); third, hydrocarbons tends to migrate in the direction of lower fluid pressure (fluid pressure predominance); fourth, hydrocarbons tends to migrate in the direction vertical to buoyancy (flow direction predominance). This paper reports on field observations in the Daqing oilfield area of China and also on physical analog experiments used to illuminate the four basic modes of transport. Under geological conditions, the hydrocarbon migration pathways are controlled by these four basic modes, which can be used to predict the directions of hydrocarbons migration and select favourable exploration locations.
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Fang, Qifei, Qingzhou Yao, Yongqiang Qu, Youlu Jiang, Huizhen Li, Dongdong Dai, Shan Fan, et al. "Variability and Main Controlling Factors of Hydrocarbon Migration and Accumulation in the Lower Paleozoic Carbonate Rocks of the Tazhong Uplift, the Tarim Basin, Northwest China." Geofluids 2021 (August 24, 2021): 1–14. http://dx.doi.org/10.1155/2021/6693658.
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Hydrocarbon migration patterns and pathways were studied on the basis of three-dimensional seismic interpretation, drilling, geochemistry, production performance, and other data. Using these findings, the main factors controlling hydrocarbon migration and accumulation in the Lower Paleozoic carbonate rocks of the Tazhong Uplift were discussed. The spatiotemporal relationship between the hydrocarbon kitchens and pathway systems of the Tazhong Uplift and the spatial pattern of pathway systems were considered the main factors causing differences in hydrocarbon enrichment. Results also revealed that the Lower Paleozoic carbonates of the Tazhong Uplift have two hydrocarbon accumulation systems (inside and outside the source rocks). For the accumulation system within the source rocks, hydrocarbon migration and enrichment are vertically differentiated. Middle Cambrian gypsum salt rocks serve as the boundary, above which thrust and strike-slip faults mainly allow vertical transport of hydrocarbons. A multistage superposition pattern of strike-slip faults controls the differences in hydrocarbon enrichment on the periphery of the fault zone. Beneath the gypsum-salt rocks, hydrocarbon migration and enrichment is controlled by the topography of paleostructures and paleogeomorphology. For the hydrocarbon accumulation system outside the source rocks, hydrocarbon migration and enrichment are restricted by the layered pathway system, and the topography of the paleostructures and paleogeomorphology is the key factor controlling hydrocarbon enrichment. The Tazhong No. 1 Fault is the main vertical pathway system in the area underlain by no source rocks, and hydrocarbons are enriched at the periphery of the Middle-Lower Cambrian and No. 1 Fault Zone.
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Leonov, M. G., V. Yu Kerimov, R. N. Mustaev, and Vu Nam Hai. "ON THE NATURE AND MECHANISM OF FORMATION OF HYDROCARBON DEPOSITS ON THE SHELF OF VIETNAM." Tikhookeanskaya Geologiya 39, no. 5 (2020): 3–16. http://dx.doi.org/10.30911/0207-4028-2020-39-5-3-16.
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The paper presents the results of the study of main factors determining conditions of formation and distribution of oil and gas deposits within the Cenozoic sedimentary cover and Precenozoic granite basement of the Vietnam shelf. The structural and tectonic model of the Kyulong basin constructed by the authors allows to reveal the conditions of formation of regional and local structures in the sedimentary cover containing hydrocarbon deposits; mechanisms of hydrocarbon traps emergence and hollow space (collectors); genesis of hydrocarbons, including the hydrocarbons existed in the basement rocks; the possible mechanism of migration and accumulation of hydrocarbons in the basement rocks. The traps which are real or potential reservoirs of hydrocarbons in the body of a crystal socle are widely developed. The structural and tectonic processes in the basement itself resulted in the development of positive morfostructures (domes, protrusions) the cores of which are made of disintegrated (granulated) rocks of a crystalline cap. In order to reconstruct the chronothermobaric conditions of occurrence and evolution of hydrocarbon generation centers and to restore the conditions of formation and distribution patterns of oil and gas accumulations on the shelf of Vietnam, three-dimensional modeling of generation and accumulation hydrocarbon systems was performed using the basin modeling technology and PetroMod software (Schlumberger, Ltd, USA). Studies of hydrocarbon biomarkers of oil fields in the Kyulong basin, including those located in the crystalline basement have shown the similarity of biomarker parameters of oil and organic matter, which demonstrates the organic nature of the oil fields of the basement on the shelf of Vietnam
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Liu, Shugen, Chuan Qin, Lubomir Jansa, Wei Sun, Guozhi Wang, Guosheng Xu, Haifeng Yuan, et al. "Transformation of Oil Pools into Gas Pools as Results of Multiple Tectonic Events in Upper Sinian (Upper Neoproterozoic), Deep Part of Sichuan Basin, China." Energy Exploration & Exploitation 29, no. 6 (December 2011): 679–98. http://dx.doi.org/10.1260/0144-5987.29.6.679.
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A center in the present paper is referred to as an area or region which may include one or more hydrocarbon accumulations. A hydrocarbon generation center is referred to as an area containing high quality source rock which was subjected to thermal maturation. A gas generation center is an area in which an oil pool or accumulation was present, and oil was thermally cracked to generate gas. A gas accumulation center is referred to as an area in which natural gas generated from cracked oil accumulated. A gas preservation center is referred to as an area or region where the present natural gas pool/pools is/are located. As one of the oldest petroleum reservoir rocks in the world, the upper Sinian Dengying Formation (Upper Proterozoic) in the Sichuan basin was deeply buried, and its paleo-oil pools (gas generation centers) underwent complex transformation into paleo-gas pools (gas accumulation centers) and the present gas pools (gas preservation centers) as a result of multiphase tectonic activities. The paleo oil pools (gas generation centers) were the main hydrocarbon sources of the paleo gas pools (gas accumulation centers), which were in turn the main sources of hydrocarbons for today's (remaining) gas pools (gas preservation centers). The key factor in the oil accumulation was the presence of rich hydrocarbon source rocks (hydrocarbon generation centers) in the Early Cambrian strata and a good seal development. Being controlled by the early tectonics and sedimentary development of the basin, the hydrocarbon generation centers appeared to have been stationary in space, while in time the other three centers (gas generation centers, gas accumulation centers and gas preservation centers) migrated as result of tectonic events in the basin. Therefore, the time-spatial relationships between these “three centers” (gas generation centers, gas accumulation centers and gas preservation centers) decides the final distribution of natural gas in the Sichuan basin. Relationship between generation, accumulation and preservation of hydrocarbons in the marine carbonates buried deeper than 4500 m in the Sichuan basin, can be separated into: (1) an accumulation mode with the “three centers” being superimposed; (2) an accumulation mode with “the preservation center” disintegrated; (3) an accumulation mode with the “three centers” migrated for a short distance; (4) a destruction mode with the preservation center lost. The natural gas exploration of the upper Sinian carbonate rocks in the Sichuan basin can be most successful where the “three centers” overlap, such as at the front area of the Micang Mountains, which could be the most promising area for the future gas exploration.
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Kerimov, Vagif, Rustam Mustaev, Uliana Serikova, and Javidan Ismailov. "Geochemical conditions of hydrocarbon accumulation in low-permeability shale sequences." E3S Web of Conferences 98 (2019): 02005. http://dx.doi.org/10.1051/e3sconf/20199802005.
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The report is devoted to the study of conditions for the formation of organic porosity–void spaces of organic origin formed during transformation of the organic matter into hydrocarbons, and their role in the formation of hydrocarbon accumulation in low-permeability shale strata. The experience of studying and developing known shale formations of the world testifies to the fact that such strata are hybrid phenomena, that is, they are both oiland gas-bearing strata containing traditional and non-traditional accumulations of hydrocarbons. Based on the results of the programmed pyrolysis by the Rock-Eval-6 method, an estimate has been performed to quantify organic (kerogen) porosity. This estimate allows for determining the forecast retention volume of HCs generated during catagenesis.
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Lü, Xiuxiang, Weiwei Jiao, Xinyuan Zhou, Jianjiao Li, Hongfeng Yu, and Ning Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tazhong Uplift, Tarim Basin, Western China." Energy Exploration & Exploitation 27, no. 2 (April 2009): 69–90. http://dx.doi.org/10.1260/0144-5987.27.2.69.
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Diverse types of marine carbonate reservoirs have been discovered in the Tazhong Uplift, Tarim Basin, and late alteration of such reservoirs is obvious. The marine source rocks of the Cambrian-lower Ordovician and the middle-upper Ordovician provided abundant oil and gas for hydrocarbon accumulation. The hydrocarbons filled various reservoirs in multiple stages to form different types of reservoirs from late Caledonian to early Hercynian, from late Hercynian to early Indosininan and from late Yanshanian to Himalayan. All these events greatly complicated hydrocarbon accumulation. An analysis of the discovered carbonate reservoirs in the Tazhong Uplift indicated that the development of a reservoir was controlled by subaerial weathering and freshwater leaching, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoir beds, the hydrocarbon accumulation zones in the Tazhong area were identified as: karsted reservoirs, reef/bank reservoirs, dolomite interior reservoirs, and hydrothermal reservoirs. Such carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift, respectively. Because of differences in the mechanism of reservoir formation, the reservoir space, capability, type and distribution of reservoirs are often different in different carbonate hydrocarbon accumulation zones.
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Leonov, M. G. "Crystalline protrusions as the typical stryctural-tectonic model of intragranite hydrocarbon accumulation." Геотектоника, no. 3 (June 26, 2019): 24–41. http://dx.doi.org/10.31857/s0016-853x2019324-41.
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The paper deals with issues related to the study questions on magmatic tectonics and intragranitic hydrocarbon accumulating formation: (i) post-magmatic structure of granitic massifs containing hydrocarbons; (ii) mechanisms of structure-material processing, exhumation and forming porosity in granitic bodies on post-magmatic evolutional stage; (iii) availability and distribution of hydrocarbon deposits in granitic massifs located in different geodynamic settings and different regions; (iv) description of crystal piercing bodies – granite protrusions. The role of structural tectonic factor in intra-granitic hydrocarbon accumulating was estimated. An evolutionary structural-tectonic model of their formation within granitic massifs and, above all, granitic protrusions is proposed.
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Gahramanov, G., M. Babayev, S. Shpyrko, and Kh Mukhtarova. "SUBSIDENCE HISTORY AND HYDROCARBON MIGRATION MODELING IN SOUTH CASPIAN BASIN." Visnyk of Taras Shevchenko National University of Kyiv. Geology, no. 1 (88) (2020): 82–91. http://dx.doi.org/10.17721/1728-2713.88.12.
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We study the mechanisms of migration and spacial distribution of hydrocarbon deposits along a regional 1000 km long SW - NE seismic cross section of the South Caspian Basin. A retrospective 2D geological simulation of basin subsidence and sediment filling history is performed taking into account accompanying processes of thermal and catagenetic transformations of organic matter, and subsequent migration and accumulation of hydrocarbons. The start of the basin opening with accumulation of considerable sedimentary mass can be dated as middle Mesozoic (Triassic or Jurassic), and hydrocarbon prone horizons can now be located at depths of 12 km. The hydrocarbon saturation of the Pliocene Productive Series is of epigenetic (allochtonous) nature, which is also confirmed in literature by geochemical data from mud volcanoes and by other facts. Geochemical age, depth of provenance and reworking degree of hydrocarbons point at generation sources in Mesozoic (gas) and Paleogene-Miocene formations (oil) with only subordinate participation of the lower "Productive Series" Pliocene suites. The dominant migration pattern of fluids is interformational (interstratal) intermittent injective subvertical flow along disjunctive planes, zones of increased fracturing and loose rocks, diapir intrusion contacts, eruptives of mud volcanoes, lithofacial unconformities and other structures, breaking the rocks continuity. This implies the possibility of commercial-scale accumulations of hydrocarbons at ultra high depths, if trap structures of sufficiently large sizes are available, comparable with already discovered giant oil and gas fields (Shah-Deniz, Azeri-Chirag-Gyuneshli etc).
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Fu, Siyi, Zhiwei Liao, Anqing Chen, and Hongde Chen. "Reservoir characteristics and multi-stage hydrocarbon accumulation of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, NW China." Energy Exploration & Exploitation 38, no. 2 (August 19, 2019): 348–71. http://dx.doi.org/10.1177/0144598719870257.
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The Chang-8 and Chang-6 members of the Upper Triassic Yanchang Formation (lower part) are regarded as the main oil producing members of the Ordos Basin. Recently, new hydrocarbon discoveries have been made in the upper part of the Yanchang Formation (e.g., Chang-3) in the southwestern Ordos Basin, implying that this interval also has a good potential for hydrocarbon exploration. However, studies on the origin of the high-quality reservoir, hydrocarbon migration, and accumulation patterns remain insufficient. In this study, integrated petrological, mineralogical, and fluid inclusion tests are employed to evaluate reservoir characteristics, and reconstruct the history of hydrocarbon migration and accumulation during oil and gas reservoir formation. The results reveal that the Yanchang Formation is characterized by low porosity (8 − 14%), medium permeability (0.5 − 5 mD), and strong heterogeneity; the reservoir properties are controlled by secondary porosity. Two types of dissolution are recognized in the present study. Secondary pore formation in the lower part of the formation is related to organic acid activity, while dissolution in the upper part is mainly influenced by atmospheric fresh water associated with the unconformity surface. The Yanchang Formation underwent hydrocarbon charging in three phases: the early Early Cretaceous, late Early Cretaceous, and middle Late Cretaceous. A model for hydrocarbon migration and accumulation in the Yanchang reservoirs was established based on the basin evolution. We suggest that hydrocarbon accumulation occurred at the early stage, and that hydrocarbons migrated into the upper part of the Yanchang Formation by way of tectonic fractures and overpressure caused by continuous and episodic hydrocarbon expulsion during secondary migration, forming potential oil reservoirs during the later stage.
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Fan, Bojiang, Liang Shi, Yating Li, Tianjing Zhang, Lei Lv, and Tong Shikai. "Lithologic heterogeneity of lacustrine shale and its geological significance for shale hydrocarbon-a case study of Zhangjiatan Shale." Open Geosciences 11, no. 1 (March 26, 2019): 101–12. http://dx.doi.org/10.1515/geo-2019-0009.
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Abstract The Zhangjiatan shale of the Southeastern Ordos Basin, which deposits in deep lake facies, has strong lithologic heterogeneity; it represents as shale, sandy laminae shale and thin sandstone. Shale with mm- to cm-scale sandy laminae is defined as Sandy Laminae Shale (SLS). However, the relationship between lithologic heterogeneity and hydrocarbon accumulation has never been studied. This study shows that lithologic heterogeneity, especially the occurrence of SLS will influence the accumulation of hydrocarbons within the shale system. SLS commonly has a larger pore size, higher porosity and better connectivity than thick and homogeneous shale. SLS commonly contains fewer residual hydrocarbons than homogeneous thick shale, indicating comparative ease in hydrocarbon expulsion. SLS commonly generates more bedding fractures. More fractures can be incurred when fracture extending into SLS. The occurrence of SLS can provide more storage spaces for fluids and gases, including oil, water, adsorbed gas, dissolved gas and free gas. SLS has been the pilot exploration and development target for shale hydrocarbon in the southeastern Ordos Basin. Homogeneous and thick shales, which have a large content of residual hydrocarbons, would be the targets for future exploration.
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Aliyeva, S. A. "Geodynamic and geological factors in the formation of large hydrocarbon deposits in subsalt sediments of the North Caspian region." Proceedings of higher educational establishments. Geology and Exploration 63, no. 2 (November 5, 2020): 47–60. http://dx.doi.org/10.32454/0016-7762-2020-63-2-47-60.
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Background. The Astrakhan-Primorsk region of oil and gas deposits located in the North Caspian region is one of the world’s largest reserves of hydrocarbons. This region stretches from land in the northwestern part of the Caspian basin, through the northern waters of the Caspian, to the south-eastern land part of the region under consideration.Aim. To identify geodynamic and geological factors in the formation of large hydrocarbon deposits in subsalt sediments in the complex structure of the North Caspian region of the Caspian syneclise. Materials and methods. An analysis of data on the geodynamic and geological evolution of the North Caspian region of the Caspian syneclise revealed specific features of its geological structure and development.Results. The nature of the formation series, as well as the geodynamic and geological conditions (the presens of spreading and subduction zones that caused an intense heat flow, the presense of an isolated sedimentation basin with intensive accumulation of carbonates in the Upper Devonian-lower Permian, a powerful salt-bearing Kungurian cap) were favourable for the generation, migration and accumulation of hydrocarbons in large tectonic-sedimentary Upper Devonian–Lower Permian uplifts characteristic of the Astrakhan-Primorsk oil-and-gas bearing region of the North Caspian. These uplifts were formed by shelf bioherms, barrier reefs and large reeftogenic atolls and emerged through ancient troughs. The large hydrocarbon accumulations, such as Kashagan, Tengiz, Astrakhanskoye and Korolevskoye, with high specific hydrocarbon reserves (more than 100 thousand/km2) are associated with these troughs.Conclusion. During the Upper Paleozoic, the main paleodepressions of the isolated basin of the North Caspian underwent a steady and long-term subsidence process, favourable for the accumulation of a thick stratum of carbonate (mainly reef) formations. This period was also characterized by the geothermal and baric conditions necessary for the transformation and subsequent migration of hydrocarbons from oil- and gas-producing complexes to reservoirs, which were mainly presented by massive carbonate formations of reef genesis. The as-formed deposits were preserved by thick salt-bearing Kungurian sediments. Directions for prospecting and exploration works aimed at discovering new hydrocarbon deposits in the subsalt sediments of the region were outlined.
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Ismailov, D. D., S. G. Serov, R. N. Mustaev, and A. V. Petrov. "Conditions of oil and gas formation in the territory of the Eastern and Central Ciscaucasia." Proceedings of higher educational establishments. Geology and Exploration, no. 6 (March 19, 2020): 63–72. http://dx.doi.org/10.32454/0016-7762-2019-6-63-72.
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The results of studies of hydrocarbon systems of the Eastern and Central Ciscaucasia are shown. The research area covers part of the Scythian platform, namely, the northern side of the Terek-Caspian foredeep, the north-eastern part of the East Kuban depression, the Tersko-Kum depression and the Stavropol arch. Based on the results of the work and basin modelling of hydrocarbons generation, emigration and accumulation processes, the reconstruction of the history of oil and gas formation and oil and gas accumulation in the sedimentary cover of the region was completed. The basin modelling of hydrocarbon formation processes in Central and Eastern Ciscaucasia was carried out using the PetroMod (Schlumberger) program complex. The obtained results made it possible to determine the dynamics of organic substance transformation processes, evolution of oil and gas formation zones, time and expected paths of hydrocarbon migration and phase composition and degree of hydrocarbon saturation of the section. The model reliability was corrected by comparing the values of benchmarks (modern reservoir temperatures measured in wells, with their calculated values obtained as a result of modelling). The location of possible foci of hydrocarbon generation in the sedimentary cover, the migration paths, the phase composition of hydrocarbons, the intensity of hydrocarbon saturation within individual tectonic zones and structures were determined. It has been established that the main foci of hydrocarbon generation in the southern part of the studied region are located in the Chechen depression (Tersko-Caspian deep), on the platform part–in the zone of the Manych deep and Nogai stage.
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Yuan, Hong Qi, Ying Hua Yu, and Fang Liu. "Controlling Factors of Hydrocarbon Accumulation in Talaha-Changjiaweizi Area." Advanced Materials Research 734-737 (August 2013): 1175–78. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1175.
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Based on the analysis of the relationships between the conditions of structures, sedimentations, source rocks, cap rocks, faults, oil and gas migration passages and traps and hydrocarbon accumulation, the controlling factors of hydrocarbon accumulation and distribution was studied in Talaha-changjiaweizi area. It is held that the source rocks control the hydrocarbon vertical distribution, the drainage capabilities control the hydrocarbon plane distribution, fracture belts control the hydrocarbon accumulation of Talaha syncline, underwater distributary channel is a favorable accumulation environment and reservoir physical properties control the oil and water distributions. Therefore, it is concluded that source rocks, fracture belts, sedimentary microfacies and reservoir physical properties are the main controlling factors of hydrocarbon accumulation and distribution in Talaha-changjiaweizi area.
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Zhao, Wenzhi, Shuichang Zhang, Bin Zhang, Kun He, and Xiaomei Wang. "New Insight into the Kinetics of Deep Liquid Hydrocarbon Cracking and Its Significance." Geofluids 2017 (2017): 1–11. http://dx.doi.org/10.1155/2017/6340986.
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The deep marine natural gas accumulations in China are mainly derived from the cracking of liquid hydrocarbons with different occurrence states. Besides accumulated oil in reservoir, the dispersed liquid hydrocarbon in and outside source also is important source for cracking gas generation or relayed gas generation in deep formations. In this study, nonisothermal gold tube pyrolysis and numerical calculations as well as geochemical analysis were conducted to ascertain the expulsion efficiency of source rocks and the kinetics for oil cracking. By determination of light liquid hydrocarbons and numerical calculations, it is concluded that the residual bitumen or hydrocarbons within source rocks can occupy about 50 wt.% of total oil generated at oil generation peak. This implies that considerable amounts of natural gas can be derived from residual hydrocarbon cracking and contribute significantly to the accumulation of shale gas. Based on pyrolysis experiments and kinetic calculations, we established a model for the cracking of oil and its different components. In addition, a quantitative gas generation model was also established to address the contribution of the cracking of residual oil and expulsed oil for natural gas accumulations in deep formations. These models may provide us with guidance for gas resource evaluation and future gas exploration in deep formations.
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Li, Yajun, Shu Jiang, Zhenglong Jiang, Hao Liu, and Bingxi Li. "Reconstruction of the Cenozoic History of Hydrocarbon Fluids from Rifting Stage to Passive Continental Margin Stage in the Huizhou Sag, the Pearl River Mouth Basin." Geofluids 2017 (2017): 1–32. http://dx.doi.org/10.1155/2017/4358985.
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The Eocene lacustrine sediments are the primary source rocks in the Huizhou Sag of the Pear River Mouth Basin. This study employs basin modeling for four representative wells and two profiles in the Huizhou Sag to reconstruct the process of generation, expulsion, migration, and accumulation of hydrocarbon fluids. The Eocene source rocks started to generate hydrocarbon at 33.9 Ma and are currently in a mid-mature and postmature stage. Hydrocarbons are mainly expelled from the Eocene Wenchang Fm, and the contribution of the Eocene Enping formation is minor. Under the driving forces of buoyancy and excess pressure, major hydrocarbons sourced from the Eocene source rocks firstly migrated laterally to the adjacent Eocene reservoirs during the postrift stage, then vertically via faults to Oligo-Miocene carrier beds, and finally laterally to the structural highs over a long distance during the Pliocene-Quaternary Neotectonic stage, which is controlled by both structural morphology and heterogeneity of carrier beds. Fault is the most important conduit for hydrocarbon fluid migration during the Neotectonic stage. Reactivation of previous faults and new-formed faults caused by the Dongsha Movement (9.8–4.4 Ma) served as vertical migration pathways after 10.0 Ma, which significantly influenced the timing of hydrocarbon accumulation in the postrift traps.
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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.
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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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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.
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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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Ricci Lucchi, F. "Evaporite sedimentology. Importance in hydrocarbon accumulation." Marine Geology 103, no. 1-3 (January 1992): 529–30. http://dx.doi.org/10.1016/0025-3227(92)90038-j.
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Harwood, G. "Evaporite sedimentology. importance in hydrocarbon accumulation." Sedimentary Geology 78, no. 1-2 (June 1992): 151–52. http://dx.doi.org/10.1016/0037-0738(92)90121-7.
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Hu, Yang, Zhi Ping Wu, and Guang Zeng Wang. "Hydrocarbon Accumulation Dominant Factors and Modes of Minghuazhen Formation in Chengdao Area." Applied Mechanics and Materials 628 (September 2014): 372–75. http://dx.doi.org/10.4028/www.scientific.net/amm.628.372.
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Chengdao area is a multiple hydrocarbon accumulation belt with the typical tectonic background, and its main target stratum is Neogene. However, the exploration and recognition level of Minghuazhen Formation is still at the primary stage. Based on the comprehensive analysis of seismic, well-logging, logging and geochemical data, and combined with its structural characteristics, intensity of fault activity and reservoir-caprock assemblage, this paper systematically analyzed the dominant factors of hydrocarbon accumulation in Minghuazhen Formation, and clarified that the tectonic setting controlled where the hydrocarbon enriched, intensity of fault activity influenced how much of hydrocarbon enriched and the reservoir-seal assemblage dominated hydrocarbon accumulation strata. Then two types of hydrocarbon accumulation models, that is, main fault-sand body and main fault-secondary fault–sand body were established.
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Liu, Hui Qing, and Yu Yuan Zhong. "Application of Organic Inclusion in Hydrocarbon Exploration." Advanced Materials Research 424-425 (January 2012): 545–50. http://dx.doi.org/10.4028/www.scientific.net/amr.424-425.545.
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Inclusion as a research method was mainly applied in the study of mineral deposit geology in the beginning. In recent years, organic inclusion research has become one of the important means in hydrocarbon exploration. The study of the inclusion can determine the role of diagenesis and reservoir of time and temperature, infer hydrocarbon migration, tectonic movement and paleo-heat flow history, in order to better guide hydrocarbon exploration. This paper mainly discussed research method of hydrocarbon inclusions type and oil and gas inclusion, and summarizes the inclusion of the fracture structure used to study and hydrocarbon accumulation relations, determines the gas accumulation time, evaluate hydrocarbon, calculate fluid potential, predict oil and gas accumulation zones, and other aspects of the role. Inclusions found early, at first is mainly applied in the study of mineral deposit geology. Since Marray (1957) discovered larger hydrocarbon inclusions in quartz especially[1], in the 70 s, with the development of oil geochemical, the minerals fluid inclusions in the oil field geological research has been widely used. G. m. Gigashvili and v. p. Kalish in 1977 are the first to report the use of mineral inclusions as the hydrocarbons containing hydrocarbon migration of physical and chemical condition of fluid of the index. At the beginning of the 80's, the technology has already been foreign research institutions and oil company are widely used in reservoir the diagenesis of research and oil and gas exploration [2,3,4]. China has begun to set up in the 1960 s, the early main inclusions laboratory to research various metal hydrothermal ore deposits in the ore-forming temperature and the composition of the ore-forming fluid. ShiJiXi (1985,1987) will fluid inclusions method is used to study the carbonate formation of China and the thermal evolution degree, division of hydrocarbon generation evolutionary stages, according to package the body type, distribution, homogenization temperature, salinity, gas organic composition various inclusions observation and analysis data put forward the carbonate hydrocarbon source rocks and oil and gas reservoir has performance evaluation method and hydrocarbon index[2,5,6]. In petroleum exploration, through[[ First Author: Huiqing Liu (1980－), male, doctoral students, Major: mineralogy petrology mineralogy,E-mail:liu8935959@163.com]] the study of the sandstone reservoir formation of diagenetic minerals fluid inclusions, and combining with the chip observation to judge whether have oil and gas migration to reservoir, and oil and gas accumulation of time, ancient geothermal, formation water such as the salinity has a very important significance
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Kerimov, V. Yu, M. G. Leonov, A. V. Osipov, R. N. Mustaev, and Vu Nam Khai. "Hydrocarbons in the basement of the South China Sea (Vietnam) shelf and structural-tectonic model of their formation." Геотектоника, no. 1 (April 1, 2019): 44–61. http://dx.doi.org/10.31857/s0016-853x2019144-61.
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Research of genesis of hydrocarbon accumulations located within pre-Cenozoic basement of the South China Sea shelf (Vietnam) presented. Formation of hydrocarbon deposits is confined to the protrusive massifs of granites that have undergone structural and tectonic processing at the stage of prototectonics and postmagmatic tectonics. The totality of post-structure-forming processes led to a change in the viscosity properties of rocks, to their tectonic and material heterogeneity and stratification and, as a consequence, to vertical and lateral redistribution in space with the formation of granite protrusions. The mechanisms of formation of voids and oil and gas traps within the protrusions are considered. Based on the similarity of the geochemical characteristics and biomarker parameters of the oils and organic matter in the Oligocene-Miocene sediments and in the basement rocks, a conclusion has been made about the organic nature of the oils in the basement of the shelf of the South China Sea (Vietnam). Possible mechanisms of migration and accumulation of hydrocarbons in basement rocks are considered. It is confirmed that the formation of hydrocarbon deposits occurred due to lateral and downward migration of hydrocarbons through the contact area from the Oligocene-Miocene source rocks into crystalline massifs — into voids and increased fracture zone in the protrusions.
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Yan, Wei, Guangxue Zhang, Li Zhang, Bin Xia, Zhen Yang, Kunsheng Qiang, and Miaomiao Meng. "Focused fluid flow systems discovered from seismic data at the southern margin of the South China Sea." Interpretation 8, no. 3 (August 1, 2020): T555—T567. http://dx.doi.org/10.1190/int-2019-0046.1.
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This research focuses on the seismic characteristics of various fluid flow systems at the southern margin of the South China Sea. We have considered their associated seismic responses and hydrocarbon accumulations and determined the relationships between fluid flow and hydrocarbon migration. From amplitude anomalies and geometric morphology, we identify different focused fluid flow systems, such as mud diapirs/mud volcanoes, gas chimneys, pipes, and fault-related flow systems. We observe that gas-bearing fields associated with high-amplitude anomalous, low-amplitude chaotic, and “drop-down” reflection events serve as distinguishing features of focused fluid flow systems. These systems are affected by tectonic movements and sedimentation, and they are closely related to deep, high-temperature, and high-pressure plastic fluids. Furthermore, our investigations show that focused fluid flow systems, which preferentially develop in the weak parts of the strata, as well as associated faults and fractures, often act as conduits for hydrocarbon migration and accumulation. Therefore, these systems should be given the utmost attention during seismic exploration for hydrocarbons.
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Chen, Panpan, Cunlei Li, Jinliang Zhang, Shengrong Li, Guiyang Ma, and Yang Zhao. "Causes of Oil Accumulation of Isolated Bars in Lacustrine Delta." Energies 13, no. 6 (March 21, 2020): 1489. http://dx.doi.org/10.3390/en13061489.
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After over 20 years of development in Daqingzijiang Oilfield, isolated sand bodies under the delta front and pro-delta in the Qingshankou Formation(qn)have become important oil and gas reservoir bodies. However, the cause for large amounts of isolated bar sand bodies in the lake-basin delta sediment system has not been reported in China. This article, through core observation, reveals plenty of evidence that there storm waves once existed. Combined with paleogeography and hydrodynamic force analysis, it describes the transformation effect of waves on delta sand bodies and on the formation mechanism of bar sand bodies. Based on a study on paleogeomorphology and the statistics of sand body distribution, we consider ‘Storm waves conveying sand’ and ‘landform controlling sand’ as the cause and distribution model of the delta’s isolated bar sand body formation. We also think that the superposition of multiple bar sand bodies is the direct cause of the strong anisotropy in reservoirs and the complex relationship between oil and water in reservoirs. Most of these sand bodies have formed into lenticular lithologic hydrocarbon accumulations. On the basis of this integrated study on hydrocarbon accumulation, we set up an accumulation model of lenticular hydrocarbon accumulation involving the variables ‘Surrounded by source rocks to generate hydrocarbon’, ‘Driven by pressure difference’, ‘Migration through multi pathways’ and ‘Accumulation by filtering water’.
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Wang, Na, Shuang Fang Lu, and Dian Shi Xiao. "Hydrocarbon Origin and Accumulation Model of Putaohua Reservoir in Southern Daqing Placanticline Area." Advanced Materials Research 616-618 (December 2012): 64–68. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.64.
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There are great oil and gas exploration prospect in south of Daqing Placanticline, with unclear understanding of source rock and accumulation model, the progress of oil exploration is restricted. To definite the source of oil and gas, according to chromatography data and analysis data, combined with potential of hydrocarbon generation and expulsion, oil-gas migration pathway, the hydrocarbon migration and accumulation model is proposed. It can be concluded that the oil from Putaohua reservoir in the south of Daqing Placanticline area mainly come from K2qn1 source rock locally, while the hydrocarbon sources of K2qn1 in the east and west of the depression makes small contribution to the research area. Migrate in source area is the main hydrocarbon migration and accumulation mode. Re-define the oil source of Putaohua reservoir can help enhance the cognition of the hydrocarbon accumulation condition and accumulation model, in order to direct the research for the accumulation and distribution principle of oil and gas exploration and favorable area prediction in the future.
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Xu, J. G., and R. L. Johnson. "Nitrogen dynamics in soils with different hydrocarbon contents planted to barley and field pea." Canadian Journal of Soil Science 77, no. 3 (August 1, 1997): 453–58. http://dx.doi.org/10.4141/s96-046.
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Nitrogen dynamics and cycling are important in plant-soil ecosystems, and they may differ between hydrocarbon-contaminated and uncontaminated soils. The objective of this experiment was to study the effects of petroleum hydrocarbons and remediation methods on nitrogen dynamics and cycling in plant-soil ecosystems. The experiment involved two plant species (barley and field pea) grown in soils at four different hydrocarbon levels (0, 5, 25 and 55 g kg−1). Hydrocarbon contamination significantly reduced N uptake by plants, but increased N accumulation in soil microbial biomass. It widened the C:N ratio in soil and led to more available N being immobilized by soil microorganisms, which reduced available N for plantuptake. Urease activity increased with hydrocarbon content in soil due to the increase of microbial biomass and activity. Key words: Nitrogen dynamics, hydrocarbon contamination, microbial activity, remediation, Black Chernozem
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Feng, Yue Gang, and Ming Qi Zhang. "The Controlling Effect of Unconformity Structure on Hydrocarbon Accumulation." Applied Mechanics and Materials 256-259 (December 2012): 90–96. http://dx.doi.org/10.4028/www.scientific.net/amm.256-259.90.
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Based on lots of previous studies, the unconformity structure characteristics were studied and the controlling effect of unconformity structure on hydrocarbon reservoir, migration path and oil-gas reservoir type were analyzed. The result shows that the unconformity structure is composed of upper basal conglomerate layer, lower weathering clay layer and semi-weathering rock; the interlocking pores in basal conglomerate layer and pore-cave-fracture system in semi-weathering rock are the main storage space of hydrocarbon reservoir; And hydrocarbon migrates laterally through capillary “channeling effect” in interlocking pores, and the pore-cave-fracture system in semi-weathering rock is an important path for hydrocarbon migration laterally and vertically; stratigraphic overlap hydrocarbon reservoir and stratigraphic unconformity reservoir are the two type of reservoirs related to unconformity, and buried hill reservoir is an important type of the latter.
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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.
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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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Sun, Yu, Chen Chen, Shi Zhong Ma, and Bai Quan Yan. "Hydrocarbon Accumulation Characteristics and its Main Controlling Factors in Lithologic Reservoirs Area: Example of Fuyu Oil Layer in the Southern Fuxin Uplift of Songliao Basin." Advanced Materials Research 524-527 (May 2012): 134–39. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.134.
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Taking Fuyu oil layer in the southern Fuxin Uplift of Songliao Basin as an example, through study on types and distribution characteristics of found reservoirs, this article discusses hydrocarbon accumulation characteristics and its main controlling factors in lithologic reservoirs area. The results show that reservoirs types of Fuyu oil layer are mainly local structure-lithologic reservoirs in the southern Fuxin Uplift. Characteristics of hydrocarbon accumulation is tertiary structure controlling direction, single trap controlling hydrocarbon accumulation, local structure controlling boundary and monosandbody controlling layer. General direction of hydrocarbon migration is controlled by tertiary structure, and hydrocarbon accumulation is controlled single trap. Planar distribution boundary of hydrocarbon is controlled by boundary of local structure and monosandbody in single trap, and vertical distribution layer of oil/water is controlled by vertical development characteristics of monosandbody. Local structure, single distributary channel sandbody and their array mode is main controlling factors on complicated distribution of oil/water. It is supported an important realistic significance to complicated exploration and development of lithologic reservoirs.
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Jiao, Wei Wei, Jie Zhang, Li Jun Cheng, Dan Dan Liu, and Zhi Deng. "Research of the Relationship between Characteristics of Carbonate Fracture-Cave Unit and Fluids Producing Status - A Case Study in Well Block ZG7 in North Slope of Tazhong Uplift." Advanced Materials Research 524-527 (May 2012): 1537–42. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1537.
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Carbonate reservoir is one of the main controlling factors of hydrocarbon accumulation. But the exploration proved that high-quality reservoir and commercial hydrocarbon flow had no absolute corresponding relationship, high-quality reservoir just was the necessary condition of hydrocarbon accumulation. It was found that local construction highs had an important control function to hydrocarbon accumulation. So it has a realistic guiding significance to exploration that enhancing the detailed study on carbonate fracture-cave unit. This paper selected Well Block ZG7 with complex oil-water relationship as a case, and comparative analyzed the structural position, structural characteristics, reservoir characteristics and fluid producing status before and after acid fracturing. It indicated that structural position of fracture-cave unit had a crucial control function to the fluid property in it, whose high accumulated hydrocarbon and the low was water commonly. The structure of facture-cave unit had a close relationship with the fluid producing status, which differed from the variation of fracture-cave unit structure. Carbonate reservoir and local construction were the important controlling factors of hydrocarbon accumulation, under the background of high-quality reservoir, local structures and structural highs were the favorable accumulation areas.
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Collen, J. D. "Diagenetic Control of Porosity and Permeability in Pakawau and Kapuni Group Sandstones, Taranaki Basin, New Zealand." Energy Exploration & Exploitation 6, no. 3 (June 1988): 263–80. http://dx.doi.org/10.1177/014459878800600307.
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Porosity and permeability of Cretaceous to Oliogocene Pakawau and Kapuni Group sandstones in Taranaki Basin, New Zealand, have been extensively modified by burial diagenesis. Mechanical compaction and the precipitation of silica, carbonate and authigenic clays have caused marked deterioration of potential and actual reservoirs for hydrocarbons. Other authigenic minerals have had less effect. Secondary reservoir porosity and permeability have developed in significant volumes in sandstones at various places, at depths below about 2.5 km. They have formed by dissolution of detrital grains, authigenic cements and authigenic replacement minerals, and by fracturing of rock and grains. The most important process for commercial hydrocarbon accumulation in New Zealand is mesogenetic carbonate (particularly calcite) dissolution. As the most prospective source and reservoir rocks are low in the Cretaceous-Tertiary sequence, the depth of burial necessary for hydrocarbon generation means that most primary porosity has been lost and secondary porosity is essential for a commercial accumulation. Entrapment of hydrocarbons in reservoirs higher in the sequence probably also requires the development of secondary permeability to allow migration.
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Sun, Yu, Shi Zhong Ma, Bai Quan Yan, and Chen Chen. "Controlling Factors for Reservoirs Distribution of the Putaohua Oil Layer in the Saozhao Sag." Advanced Materials Research 616-618 (December 2012): 816–20. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.816.
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Types of found reservoirs and its distribution characteristics of Putaohua oil layer in the Sanzhao Sag were analyzed. The controlling factors of hydrocarbon distribution were investigated. Sanzhao Sag is Sag-wide oil-bearing, but its distribution of oil and water is extremely complicated. The reservoir types are mainly fault block reservoirs, low amplitude structure reservoirs, fault-lithologic reservoirs and lithologic reservoirs. The distribution of reservoirs is mainly controlled by three geological factors: first, long-term inherited nose-like structure is predominant direction of petroleum migration; it induced oil and gas migration at a critical period of hydrocarbon accumulation and formed oil-gas accumulation area. Second, fault across main-line of hydrocarbon migration and high angle skew plug off hydrocarbon, and its side adjacent to Sag is a large number of hydrocarbon accumulation areas. Third, multi-fault region can easily form a fault (-lithological) reservoir accumulation area in the slope of sag.
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Xiao, Dian Shi, Hong Li Chen, and Hai Feng Chen. "Controlling Factors of Hydrocarbon Accumulation and Optimization of Favorable Blocks for Both Flanks of Putaohua Reservoir in Southern Daqing Placanticline." Applied Mechanics and Materials 214 (November 2012): 23–26. http://dx.doi.org/10.4028/www.scientific.net/amm.214.23.
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Putaohua reservoir in south of Daqing Placanticline is rich in oil and gas resources. However, the distribution of oil and gas is so complex and the hydrocarbon accumulation process is still unclear by now. Due to low proven reserves, it is not effective to explore the reserves. By use of the logging interpretation and results of production test and together with analysis of the oil and gas distribution and hydrocarbon accumulation process of Putaohua reservoir in south of Daqing Placanticline, the controlling factors of hydrocarbon accumulation in aspects of oil and gas migration pathway, developmental characteristics of sand, local structure etc are discussed in order to optimize potential blocks. The hydrocarbon of Putaohua reservoir in both flanks in south of Daqing Placanticline is from the local K1qn1 source rock. Hydrocarbon migration mainly depends on vertical movement and is supported by short-distance lateral migration; hydrocarbon accumulation is mainly affected by restrictions of oil source fault and high fault block, so that most of hydrocarbon accumulate in the distributary channel and distal bar of reverse faulting footwall, horst, reverse fault and other high fault blocks where are closely adjacent to the oil source faults.
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Arian, Natt, Peter Tingate, Richard Hillis, and Geoff O'Brien. "Petroleum systems of the Bass Basin: a 3D modelling perspective." APPEA Journal 50, no. 1 (2010): 511. http://dx.doi.org/10.1071/aj09030.
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Petroleum generation, expulsion, migration and accumulation have been modelled in 3D at basin-scale for the Bass Basin, Tasmania. The petroleum systems model shows several source rocks of different ages have generated and expelled sufficient hydrocarbons to fill structures in the basin; however, the lithologies and fault properties in the model result in generally limited migration after hydrocarbon expulsion started. Impermeable faults, together with several fine-gained sealing facies in the Lower and Middle Eastern View Group (EVG) have resulted in minor vertical hydrocarbon migration in the lower parts of the EVG. An exception occurs in the northeastern part of the basin, where strike-slip movement of suitably oriented faults during Miocene reactivation resulted in breaches in deeper accumulations and migration to upper reservoir sands and, in several cases, leakage through the regional seal. The Middle Eastern View Group source rocks have produced most of the gas in the basin. Oil appears to be largely limited to the Yolla Trough, related to the relatively high thermal maturation of Narimba Sequence source rocks. In general, most of the hydrocarbon expelled from the Otway Megasequence occurred prior to the regional seal being deposited; however, modelling predicts it can contribute to the hydrocarbon inventory of the Cape Wickham Sub-basin. In particular, the modelling predicted an Otway sourced accumulation at the site of the recently drilled Rockhopper–1. In the Durroon Sub-basin in the Bark Trough, the Otway Megasequence is predicted to be the main source of accumulations. The modelling has provided detailed insights into migration in the existing plays and has allowed assessment of the reasons for previous exploration failures (e.g., a migration shadow at Toolka–1) and to suggest new locations with viable migration histories. Reservoir sands of the Upper EVG are only prospective in the Yolla and Cormorant troughs where charged by Early Eocene sources; however, Miocene reactivation is a major exploration risk in this area.
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Kuske, Tehani, Steven le Poidevin, and Dianne Edwards. "Browse Basin petroleum accumulations." APPEA Journal 55, no. 2 (2015): 463. http://dx.doi.org/10.1071/aj14098.
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The Browse Basin lies offshore from WA’s Kimberley region and hosts vast accumulations of natural gas, some are rich in condensate, making it Australia’s next major gas producing province on the North West Shelf. It is estimated that the Ichthys gas accumulation contains 12.8 trillion cubic feet (Tcf) of gas and 527 million BBL of condensate, and represents the largest hydrocarbon accumulation with recoverable liquids found in Australia since the discovery of the Gippsland Basin and Barrow Island oil fields in the 1960s. Similar amounts of gas, albeit drier (CGR 20–30 BBL/MMscf) are hosted within the Brecknock, Calliance and Torosa accumulations (cumulative of 15.9 Tcf gas and 436 million BBL condensate). For this reason, the Browse Basin continues to be a focus of exploration, in which both international companies and Australian explorers are capitalising on LNG opportunities. This extended abstract provides a summary of hydrocarbon accumulations encountered in the Browse Basin (up until late 2014). Accumulations discovered in the Browse Basin include: Abalone, Adele, Argus, Bassett, Torosa, Brecknock and Calliance, Ichthys, Concerto, Mimia, Burnside, Caspar, Caswell, Columba, Cornea, Focus, Sparkle, Crux (including Libra), Hippolyte, Echuca Shoals, Gwydion, Marabou, Poseidon (including Kronos, Boreas, Zephyros and Poseidon North), Crown (including Proteus and Pharos), Psepotus and Lasseter. The authors provide a summary of the regional geology, evolution and tectonic development of the basin, and discuss the hydrocarbon reserves and hydrocarbon potential of the basin. This provides a guide to assist potential future exploration programs in the Browse Basin.
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Wang, Ming Jian, and Xun Hua Zhang. "Hydrocarbon Accumulation Conditions and Reservoir Characteriscs of Shahejie Formation in Tangzhuang Area." Advanced Materials Research 734-737 (August 2013): 1391–94. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1391.
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Guided by the theory of petroleum system, we analyzed hydrocarbon accumulation elements and conditions of the Shahejie Formation in Tangzhuang area and concluded the hydrocarbon accumulation model based on the geological and geophysical data. Hydrocarbon comes from the source rock of Es3 in Linyi sub-sag located to the southeast of Tangzhuang area. Reservoir mainly is clastic, followed by carbonate. There are 4 source-reservoir-cap assemblages in the Shahejie Formation. The Es3 source rock of different tectonic units in Linnan sub-sag has experienced different hydrocarbon generation stages. The central region experienced two hydrocarbon generation stages while the edge only experienced one stage. The hydrocarbon generated by the source rock of Es3 in Linnan sub-sag mainly migrated to Tangzhuang area along fault and sand body. The structural trap is the dominant type followed by structure-lithologic trap and lithologic trap. Based on the analysis of hydrocarbon accumulation condition, we concluded the lower generating and upper reserving model of the study area. The findings will play an important role in guiding Tangzhuang oil and gas exploration.
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Lăzăroaie, Mihaela. "Investigation of saturated and aromatic hydrocarbon resistance mechanisms in Pseudomonas aeruginosa IBBML1." Open Life Sciences 4, no. 4 (December 1, 2009): 469–81. http://dx.doi.org/10.2478/s11535-009-0050-0.
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AbstractPseudomonas aeruginosa IBBML1, isolated from Poeni petroleum sludge, was able to tolerate and degrade both saturated (n-hexane, n-heptane, n-hexadecane, cyclohexane) and aromatic (benzene, ethylbenzene, propylbenzene, xylene isomers, styrene) hydrocarbons. Molecular studies have revealed that the high hydrocarbon resistance of Pseudomonas aeruginosa IBBML1 could be due to the action of members of the HAE1 (hydrophobe/amphiphile efflux 1) family of transporters. It is further possible that additional mechanisms may account for the tolerance of Pseudomonas aeruginosa IBBML1 to hydrocarbons, and a combination of short-term and long-term mechanisms may act together in the adaptation of Pseudomonas aeruginosa IBBML1 cells to saturated and aromatic hydrocarbons. β-galactosidase activity measurements revealed that there was significant induction of the lacZ gene in Pseudomonas aeruginosa IBBML1 cells grown in the presence of either 5% and 10% (v/v) saturated or aromatic hydrocarbons, compared with control (cells incubated without hydrocarbons). Rhodamine 6G accumulation in Pseudomonas aeruginosa IBBML1 cells grown in the presence of 5% and 10% (v/v) saturated hydrocarbons was higher than rhodamine 6G accumulation in cells grown in the presence of 5% and 10% (v/v) aromatic hydrocarbons. The study of cellular and molecular modifications to Pseudomonas aeruginosa IBBML1 induced by 5% and 10% (v/v) saturated and aromatic hydrocarbons revealed a complex response of bacterial cells to the presence of different hydrophobic substrates in the culture medium.
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Zhu, Ruijing, Rongxi Li, Xiaoli Wu, Xiaoli Qin, Bangsheng Zhao, Futian Liu, and Di Zhao. "The Accumulation Characteristics of the Paleozoic Reservoir in the Central-Southern Ordos Basin Recorded by Organic Inclusions." Geofluids 2021 (September 16, 2021): 1–17. http://dx.doi.org/10.1155/2021/9365364.
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The Permian tight clastic reservoir and Ordovician carbonate reservoir were developed in the central-southern Ordos Basin. This study investigated the fluid inclusion petrography, diagenetic fluid characteristics, formation process of natural gas reservoir, source rock characteristics, and reservoir accumulation characteristics of these Paleozoic strata by petrographic observations, scanning electron microscope imaging, fluid inclusion homogenization temperature, salinity, laser Raman spectrum, and gas chromatograph analyses. The results have suggested two phases of fluid inclusions in both the Permian sandstone and the Ordovician Majiagou Formation dolomite reservoirs, and the fluid inclusions recorded the history from the early thermal evolution of hydrocarbon generation to the formation, migration, and accumulation of natural gas. The early-phase inclusions show weak yellow fluorescence and recorded the early formation of liquid hydrocarbons, while the late-phase inclusions are nonfluorescent natural gas inclusions distributed in the late tectonic fractures and recorded the late accumulation of natural gas. The brine systems of the Permian and Ordovician fluid inclusions are, respectively, dominated by CaCl2-H2O and MgCl2-NaCl-H2O. The diagenetic fluids were in the ranges of medium-low temperature and moderate-low salinity. The natural gas hydrocarbon source rocks in the Ordos Basin include both the Permian coal-bearing rocks and the Ordovician carbonates. The process of the early-phase liquid hydrocarbon formation and migration into the reservoir corresponded to 220 Ma (Late Triassic). The late large-scale migration and accumulation of natural gas occurred at 100 Ma (early Late Cretaceous), which was close to the inclusion Rb/Sr isochron age of 89.18 Ma, indicating that the natural gas accumulation was related to the Yanshanian tectonic movement.
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Diyakonov, A. I., L. V. Parmuzina, S. V. Kochetov, and A. Yu Malikova. "SEPARATE QUANTITATIVE PREDICTION OF OIL AND GAS CONTENT PROSPECTS FOR DZHEBOL STAGE PALEOZOIC DEPOSITS OF TIMAN-PECHORA OIL AND GAS BASIN." Oil and Gas Studies, no. 1 (February 28, 2015): 9–15. http://dx.doi.org/10.31660/0445-0108-2015-1-9-15.
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It is shown that the evolutionary-catagenetic model for calculating the initial potential hydrocarbon resources can serve as a scientific basis for the separate quantitative prediction of areas of oil-and-gas content. In this case retrospectively evaluated are the scales of generation and accumulation of hydrocarbons in the source rocks during catagenetic evolution of sedimentary basin. The authors propose a method, the results of evaluation of generation and accumulation scales and initial potential oil and gas resources for major oil-and-gas bearing complexes of Dzhebol stage.
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Shi, Hui, and Hui Li. "Late Accumulation of Kunbei Area in Qaidam Basin." Advanced Materials Research 690-693 (May 2013): 3549–52. http://dx.doi.org/10.4028/www.scientific.net/amr.690-693.3549.
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This paper is aimed to find out the main reason of late accumulation of Kunbei area in Qaidam Basin using geochemistry and seismic data and to provide scientific evidence to the potential petroleum exploration in this area. Reservoirs in Kunbei fault terrace zone originate from petreoleum generated by source rocks of E32 in Zhahaquan depression after N23(about 5.2Ma), which means a charcteristic of hysteretic hydrocarbon generation. Brine inclusions shows two hydrocarbon charging periods.The first charging most likely happens at N1 and the second begins at N21,continuing to Q.Two deformaton stages exist in the study area due to the Tibet Plateau uplifting. The accumulations of first stage have been damaged after Middle N1. The reservoirs of Kunbei zone at present are almost orignated from E32 in depression. Above all,the primary cause of late accumulation is due to long-distance effects of the Tibet Plateau uplifting.
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Abukova, L. A., and Yu A. Volozh. "Fluid Geodynamics of Deeply Buried Zones of Oil and Gas Accumulation in Sedimentary Basins." Russian Geology and Geophysics 62, no. 08 (August 1, 2021): 878–86. http://dx.doi.org/10.2113/rgg20214348.
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Abstract —We substantiate certain ideas concerning the key role of fluid-geodynamic processes in the evolvement of hydrocarbon accumulations at great depths, in the Earth’s crust. The presented geodynamic model of oil and gas accumulation is based on updated ideas of the structure of the Earth’s tectosphere, which includes plate, preplate, and folded complexes, and the model makes clearer the spatial scale of the organic matter transformation into hydrocarbons of the oil series. In the bottom layers of the Earth’s crust, we predict the existence of a special stagnation type of water-drive systems with the following distinguishing features: (a) different scales of manifestation, from local to regional; (b) a limited nature of processes of water exchange with the external environment; (c) absence of persistent drainage horizons (beds and interbeds); (d) alignment of hydrodynamic potentials in terms of depths and laterals; and (e) increasing importance of lithohydrochemical and organic-chemistry factors in the development of the void space of the fluid host medium. In their inner space, systems with difficult water exchange can exercise control over the evolvement and preservation of autoclave hydrocarbon systems for a long time, the key feature of the autoclave systems being spatial coincidence (localization) of the processes of oil and gas generation and accumulation. We assume that, in the settings of all-round compression, hydrodynamic instability, and no drainage, occurrence of productive zones is controlled by foci of low pore (reservoir) pressures rather than by local hypsometric highs. We present results of prediction of the development of water-drive stagnation systems occurring in the subsalt deposits of the Caspian depression within the unpenetrated areas of the subsalt profile. For the sedimentary cover at large (and ultralarge) depths, a prediction of reservoir pressures was made, which can be regarded as a necessary component in any prediction of oil and gas potential, since it makes it possible to contour some new (previously unknown) industrially significant zones of hydrocarbon accumulation.
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Semyrka, Roman, Michał Maruta, and Andrzej Pasternacki. "PROGNOSTIC ACCUMULATION ZONES FOR OIL AND NATURAL GAS IN THE CRITERIA FOR THE DISTRIBUTION OF PETROPHYSICAL PARAMETERS IN THE MAIN DOLOMITE IN GORZOW-PNIEWY AREA / PROGNOSTYCZNE STREFY AKUMULACJI DLA ROPY NAFTOWEJ I GAZU ZIEMNEGO W KRYTERIACH ROZKŁADU PARAMETRÓW PETROFIZYCZNYCH DOLOMITU GŁÓWNEGO W OBSZARZE GORZÓW-PNIEWY." Archives of Mining Sciences 58, no. 4 (December 1, 2013): 1111–32. http://dx.doi.org/10.2478/amsc-2013-0076.
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Abstract The carbonate reservoirs are anisotropic environments in terms of both the quantitative and qualitative evaluations of pore space. The oil-and-gas-bearing Main Dolomite horizon shows diversified lithology, facial development and thickness resulting in complicated, fluid capacity-fluid filtration system. This system influences both the evaluation and exploration perspectives in the Zechstein Main Dolomite (Ca2) from the Gorzów-Pniewy area. In order to clarify this problem and to determine the hydrocarbon accumulation perspectives, analysis of petrophysical parameters based upon the porosimetric measurements was carried on for the Main Dolomite in the study area, where oil and gas accumulations were discovered. The results of porosimetric measurements clearly indicate the heterogeneity of petrophysical parameters of the Main Dolomite referred to lithologically diversified palaeogeographic zones distinguished in the study area. Such analysis, including the hydrocarbon storage capacity of the Main Dolomite, enabled us to evaluate the possible hydrocarbon accumulation related to generation potential of this horizon.
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Yu, Ying Hua, Hong Qi Yuan, Xiang Li Zhong, and Xue Qiu. "Hydrocarbon Accumulation Characteristics in Cretaceous System Hailaer Basin." Advanced Materials Research 652-654 (January 2013): 2496–500. http://dx.doi.org/10.4028/www.scientific.net/amr.652-654.2496.
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Based on the sequence stratigraphy principle, reservoir forming elements has been detailed analysis in Cretaceous system of Hailaer basin, by using core, logging and 3-D seismic data. The study shows that the thick mudstone layer in the transgressive systems tract of the super-sequence is good regional source rock .and regional caprock, meanwhile the sandbody developed in transgressive systems tract and highstand systems of the super-sequence become the regional reservoir of depression. The main hydrocarbon migration pathway is uncomformable surface, fault, frame-sandstone, or that the hydrocarbon born in source rock went into the sandstone of sublacustrine fan directly, and then, lithologic reservoirs was formed.
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Ramdhani, Egi, Ordas Dewanto, Karyanto Karyanto, and Nanang Yulianto. "PERHITUNGAN CADANGAN HIDROKARBON FORMASI TALANG AKAR MENGGUNAKAN ANALISIS PETROFISIKA DAN SEISMIK INVERSI AI DENGAN PENDEKATAN MAP ALGEBRA PADA LAPANGAN BISMA, CEKUNGAN SUMATERA SELATAN." Jurnal Geofisika Eksplorasi 4, no. 3 (January 17, 2020): 3–14. http://dx.doi.org/10.23960/jge.v4i3.37.
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As a potential field in hydrocarbon prospect, Bisma field, the part of south Sumatra basin, can be evaluated in order to mapping the hydrocarbon accumulation and total reserve calculation purpose. Petrophysical analysis is an analytic method to evaluate the formation which sensitive with vertical contrast. Main output of this analysis is the compilation of some property value that useful on reservoir quality justification. Seismic acoustic impedance inversion is a method that can be used to define the distribution of porous zone as a hydrocarbon reservoir. This inversion result is the distribution of prospect area map by using combination of interpretation in AI map, density map and P-wave map. Map algebra is a calculation method that used to map that has the same grid number. By using those three methods, the reserve of hydrocarbon accumulation on Bisma field can be calculated. Petrophysical analysis results the indication of hydrocarbon in target zone is oil on two main layer, S and W3. Meanwhile, seismic inversion interpreting the distribution of porous zone is between 7400 – 9315 m/s*gr/cc in AI value context. Then, the effective porosity, Sw value and isopach are spread laterally using picked horizon and seismic acoustic impedance result as a guide, also, calculating the reserve. Layer S accumulating 21.1 million barrel oil and W3 accumulating 50.2 million barrel oil. This value resulted by aplicating Original Oil in Place (OOIP) equation on property map with map algebra approachment.
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Hirose, Mana, Fukiko Mukaida, Sigeru Okada, and Tetsuko Noguchi. "Active Hydrocarbon Biosynthesis and Accumulation in a Green Alga, Botryococcus braunii (Race A)." Eukaryotic Cell 12, no. 8 (June 21, 2013): 1132–41. http://dx.doi.org/10.1128/ec.00088-13.
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ABSTRACT Among oleaginous microalgae, the colonial green alga Botryococcus braunii accumulates especially large quantities of hydrocarbons. This accumulation may be achieved more by storage of lipids in the extracellular space rather than in the cytoplasm, as is the case for all other examined oleaginous microalgae. The stage of hydrocarbon synthesis during the cell cycle was determined by autoradiography. The cell cycle of B. braunii race A was synchronized by aminouracil treatment, and cells were taken at various stages in the cell cycle and cultured in a medium containing [ 14 C]acetate. Incorporation of 14 C into hydrocarbons was detected. The highest labeling occurred just after septum formation, when it was about 2.6 times the rate during interphase. Fluorescent and electron microscopy revealed that new lipid accumulation on the cell surface occurred during at least two different growth stages and sites of cells. Lipid bodies in the cytoplasm were not prominent in interphase cells. These lipid bodies then increased in number, size, and inclusions, reaching maximum values just before the first lipid accumulation on the cell surface at the cell apex. Most of them disappeared from the cytoplasm concomitant with the second new accumulation at the basolateral region, where extracellular lipids continuously accumulated. The rough endoplasmic reticulum near the plasma membrane is prominent in B. braunii , and the endoplasmic reticulum was often in contact with both a chloroplast and lipid bodies in cells with increasing numbers of lipid bodies. We discuss the transport pathway of precursors of extracellular hydrocarbons in race A.
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Doluda, V., N. Lakina, and R. Brovko. "Diethyl Ether to Hydrocarbons Catalytic Transformation Over Iron Modified H-ZSM-5 Zeolite." Bulletin of Science and Practice 5, no. 12 (December 15, 2019): 12–19. http://dx.doi.org/10.33619/2414-2948/49/01.
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Decrease of traditional hydrocarbon feed stock stimulates a widespread interest in the development hydrocarbons synthesis from renewable or low-value sources. The catalytic transformation of methanol into hydrocarbons, along with the Fischer–Tropsch process, can be considered as a possible way to obtain synthetic hydrocarbons. At the same time, the activity and stability of the catalysts have a decisive influence on the efficiency of the whole process. Zeolites and zeotypes of various structures traditionally used as catalysts are characterized by low rates of hydrocarbon accumulation and a short period of functioning, which requires a change in their structural characteristics or the synthesis of new systems. The aim of this work is to obtain iron-modified H-ZSM-5 type zeolites in order to increase the rate of liquid hydrocarbons accumulation and increase the lifetime of the catalyst. To achieve this goal zeolite was modified with iron, the main physicochemical characteristics of the obtained catalysts were determined and the catalytic properties were screened. Modification of zeolites by iron was carried out by the ion exchange method, as a result samples with an iron content of 0.004 wt.% to 0.240 wt.% were synthesized. In this case the decrease in the micropores surface from 280 m2/g to 190 m2/g and decrease in the number of acid sites from 1.08 mmol/g to 0.72 mmol/g was noticed. Modification of zeolite with iron of concentration up to 0.008 wt. % contributed to an increase in transformation rate of dimethyl ether from 0.04 to 0.06 kg (DME)/(kg (Cat)h) and decreace to 0.03 kg (DME)/(kg (Cat) h) during further increasing of iron content, however process selectivity to liquid hydrocarbons increase from 30% to 54%. Modification of zeolite with iron contributes to a significant change in hydrocarbon composition. With an increase in the iron concentration from 0.004 wt.% to 0.017 wt.%, the increase in the concentration of propane, butane and aliphatic hydrocarbons with the number of carbon atoms of six or more was noticed along with a decrease in the concentration of aromatic compounds.
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Cai, Jin Hang. "The Accumulation Rules of Budate Burial Hill Hydrocarbon Reservoir of Suderte Oilfield in Hailar Basin." Applied Mechanics and Materials 733 (February 2015): 140–43. http://dx.doi.org/10.4028/www.scientific.net/amm.733.140.
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Metamorphic rock burial hill reservoir of Beier rift in Hailaer Basin, with large scale reservoir and high output has complex fault system. The fault through going direction roughly is NEE direction, and has wide fault section and lateral quickly changed fault displacement. Metamorphic rock reservoir can be divided into the vertical weathered fracture zone, crack and dissolved pores and caves development belt and tight zone. Accumulation is controlled by hydrocarbon ability of source rock, contacting relationship of source rock and reservoir, oil storage ability of reservoir, and vertical and lateral hydrocarbon migration ability of fault and unconformity surface. And formed top surface weathering crust accumulation pattern which the hydrocarbon migrated laterally along the unconformity surface, and interior reservoir pattern of crack broken zone accumulation which hydrocarbon migrated vertically along fault.
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Wang, Ming Jian, and Xun Hua Zhang. "Lower Paleozoic Hydrocarbon Accumulation Conditions of Middle Uplift in Southern Yellow Sea Basin." Advanced Materials Research 524-527 (May 2012): 1252–55. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1252.
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Guided by the theory of petroleum system, we analyzed the Lower Palaeozoic hydrocarbon accumulation elements and conditions of the Middle uplift of Southern Yellow Sea Basin and concluded the hydrocarbon accumulation pattern. The results showed that: the source rock of lower Palaeozoic in the Middle uplift of Southern Yellow Sea Basin consists of the dark mudstone and carbonate rock; carbonate rock is the main favorable reservoir followed by clastic rock; there are three source-reservoir-cap assemblages; the source rock of Lower Palaeozoic has experienced two hydrocarbon generation stages which are late Silurian and late Middle Triassic; hydrocarbon generated by Lower Palaeozoic source rock can only migrate to the traps near the center of hydrocarbon generation by sandbody and cracks in a short distance; lithologic trap and broad anticlinal trap are the main types in the study area. Through the above analysis, we conclude two accumulation patterns of Lower Palaeozoic in the Middle uplift of Southern Yellow Sea Basin.