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Hydrocarbon Migration (hydrocarbon + migration)
Selected AbstractsSyntectonic infiltration by meteoric waters along the Sevier thrust front, southwest MontanaGEOFLUIDS (ELECTRONIC), Issue 4 2006A. C. RYGEL Abstract Structural, petrographic, and isotopic data for calcite veins and carbonate host-rocks from the Sevier thrust front of SW Montana record syntectonic infiltration by H2O-rich fluids with meteoric oxygen isotope compositions. Multiple generations of calcite veins record protracted fluid flow associated with regional Cretaceous contraction and subsequent Eocene extension. Vein mineralization occurred during single and multiple mineralization events, at times under elevated fluid pressures. Low salinity (Tm = ,0.6°C to +3.6°C, as NaCl equivalent salinities) and low temperature (estimated 50,80°C for Cretaceous veins, 60,80°C for Eocene veins) fluids interacted with wall-rock carbonates at shallow depths (3,4 km in the Cretaceous, 2,3 km in the Eocene) during deformation. Shear and extensional veins of all ages show significant intra- and inter-vein variation in ,18O and ,13C. Carbonate host-rocks have a mean ,18OV-SMOW value of +22.2 ± 3, (1,), and both the Cretaceous veins and Eocene veins have ,18O ranging from values similar to those of the host-rocks to as low as +5 to +6,. The variation in vein ,13CV-PDB of ,1 to approximately +6, is attributed to original stratigraphic variation and C isotope exchange with hydrocarbons. Using the estimated temperature ranges for vein formation, fluid (as H2O) ,18O calculated from Cretaceous vein compositions for the Tendoy and Four Eyes Canyon thrust sheets are ,18.5 to ,12.5,. For the Eocene veins within the Four Eyes Canyon thrust sheet, calculated H2O ,18O values are ,16.3 to ,13.5,. Fluid,rock exchange was localized along fractures and was likely coincident with hydrocarbon migration. Paleotemperature determinations and stable isotope data for veins are consistent with the infiltration of the foreland thrust sheets by meteoric waters, throughout both Sevier orogenesis and subsequent orogenic collapse. The cessation of the Sevier orogeny was coincident with an evolving paleogeographic landscape associated with the retreat of the Western Interior Seaway and the emergence of the thrust front and foreland basin. Meteoric waters penetrated the foreland carbonate thrust sheets of the Sevier orogeny utilizing an evolving mesoscopic fracture network, which was kinematically related to regional thrust structures. The uncertainty in the temperature estimates for the Cretaceous and Eocene vein formation prevents a more detailed assessment of the temporal evolution in meteoric water ,18O related to changing paleogeography. Meteoric water-influenced ,18O values calculated here for Cretaceous to Eocene vein-forming fluids are similar to those previously proposed for surface waters in the Eocene, and those observed for modern-day precipitation, in this part of the Idaho-Montana thrust belt. [source] Influence of fault map resolution on pore pressure distribution and secondary hydrocarbon migration; Tune area, North SeaGEOFLUIDS (ELECTRONIC), Issue 2 2006A. E. LOTHE Abstract Pressure and hydrocarbon migration modelling was carried out in the Tune Field area, Viking Graben, offshore Norway. The pressures are considered to be controlled by compartments bounded by mapped faults. Two different interpreted fault maps at the top reservoir level (Brent Group) are used as input to the modelling. First, a low-resolution fault map is used, with only the large faults interpreted, and next, both large and small faults are included. The simulations show high overpressures generated in the western area, in the deeper part of the Viking Graben, and hydrostatic in the eastern areas. A sharp transition zone results from using the low-resolution fault map in the simulations. Small N,S striking faults situated in between the wells have to have higher sealing capacity than expected from juxtaposition analysis alone, to be able to match the overpressures measured in well 30/5-2 and 30/8-1S in the Tune Field, and well 30/8-3 east of Tune. The intermediate pressure in the western part is probably related to flow in the deeper parts of the sedimentary column in the compartment, where well 30/8-3 is situated. The secondary oil migration models show that overpressures have major effects on the migration pathways of hydrocarbons. The level of detail in the fault interpretation is important for simulation results, both for pressure distribution and for hydrocarbon migration. [source] Equations of state for basin geofluids: algorithm review and intercomparison for brinesGEOFLUIDS (ELECTRONIC), Issue 4 2002J. J. Adams ABSTRACT Physical properties of formation waters in sedimentary basins can vary by more than 25% for density and by one order of magnitude for viscosity. Density differences may enhance or retard flow driven by other mechanisms and can initiate buoyancy-driven flow. For a given driving force, the flow rate and injectivity depend on viscosity and permeability. Thus, variations in the density and viscosity of formation waters may have or had a significant effect on the flow pattern in a sedimentary basin, with consequences for various basin processes. Therefore, it is critical to correctly estimate water properties at formation conditions for proper representation and interpretation of present flow systems, and for numerical simulations of basin evolution, hydrocarbon migration, ore genesis, and fate of injected fluids in sedimentary basins. Algorithms published over the years to calculate water density and viscosity as a function of temperature, pressure and salinity are based on empirical fitting of laboratory-measured properties of predominantly NaCl solutions, but also field brines. A review and comparison of various algorithms are presented here, both in terms of applicability range and estimates of density and viscosity. The paucity of measured formation-water properties at in situ conditions hinders a definitive conclusion regarding the validity of any of these algorithms. However, the comparison indicates the versatility of the various algorithms in various ranges of conditions found in sedimentary basins. The applicability of these algorithms to the density of formation waters in the Alberta Basin is also examined using a high-quality database of 4854 water analyses. Consideration is also given to the percentage of cations that are heavier than Na in the waters. [source] Ancient hydrocarbon seeps from the Mesozoic convergent margin of California: carbonate geochemistry, fluids and palaeoenvironmentsGEOFLUIDS (ELECTRONIC), Issue 2 2002K. A. Campbell Abstract More than a dozen hydrocarbon seep-carbonate occurrences in late Jurassic to late Cretaceous forearc and accretionary prism strata, western California, accumulated in turbidite/fault-hosted or serpentine diapir-related settings. Three sites, Paskenta, Cold Fork of Cottonwood Creek and Wilbur Springs, were analyzed for their petrographic, geochemical and palaeoecological attributes, and each showed a three-stage development that recorded the evolution of fluids through reducing,oxidizing,reducing conditions. The first stage constituted diffusive, reduced fluid seepage (CH4, H2S) through seafloor sediments, as indicated by Fe-rich detrital micrite, corroded surfaces encrusted with framboidal pyrite, anhedral yellow calcite and negative cement stable isotopic signatures (,13C as low as ,35.5, PDB; ,18O as low as ,10.8, PDB). Mega-invertebrates, adapted to reduced conditions and/or bacterial chemosymbiosis, colonized the sites during this earliest period of fluid seepage. A second, early stage of centralized venting at the seafloor followed, which was coincident with hydrocarbon migration, as evidenced by nonluminescent fibrous cements with ,13C values as low as ,43.7, PDB, elevated ,18O (up to +2.3, PDB), petroleum inclusions, marine borings and lack of pyrite. Throughout these early phases of hydrocarbon seepage, microbial sediments were preserved as layered and clotted, nondetrital micrites. A final late-stage of development marked a return to reducing conditions during burial diagenesis, as implied by pore-associated Mn-rich cement phases with bright cathodoluminescent patterns, and negative ,18O signatures (as low as ,14, PDB). These recurring patterns among sites highlight similarities in the hydrogeological evolution of the Mesozoic convergent margin of California, which influenced local geochemical conditions and organism responses. A comparison of stable carbon and oxygen isotopic data for 33 globally distributed seep-carbonates, ranging in age from Devonian to Recent, delineated three groupings that reflect variable fluid input, different tectono-sedimentary regimes and time,temperature-dependent burial diagenesis. [source] An exhumed palaeo-hydrocarbon migration fairway in a faulted carrier system, Entrada Sandstone of SE Utah, USAGEOFLUIDS (ELECTRONIC), Issue 3 2001I. R. Garden Abstract The Moab Anticline, east-central Utah, is an exhumed hydrocarbon palaeo-reservoir which was supplied by hydrocarbons that migrated from the Moab Fault up-dip towards the crest of the structure beneath the regional seal of the Tidwell mudstone. Iron oxide reduction in porous, high permeability aeolian sandstones records the secondary migration of hydrocarbons, filling of traps against small sealing faults and spill pathways through the Middle Jurassic Entrada Sandstone. Hydrocarbons entered the Entrada Sandstone carrier system from bends and other leak points on the Moab Fault producing discrete zones of reduction that extend for up to 400 m from these leak points. They then migrated in focused stringers, 2,5 m in height, to produce accumulations on the crest of the anticline. Normal faults on the anticline were transient permeability barriers to hydrocarbon migration producing a series of small compartmentalized accumulations. Exsolution of CO2 as local fault seals were breached resulted in calcite cementation on the up-dip side of faults. Field observations on the distribution of iron oxide reduction and calcite cements within the anticline indicate that the advancing reduction fronts were affected neither by individual slip bands in damage zones around faults nor by small faults with sand: sand juxtapositions. Faults with larger throws produced either sand: mudstone juxtapositions or sand: sand contacts and fault zones with shale smears. Shale-smeared fault zones provided seals to the reducing fluid which filled the structural traps to spill points. [source] PETROLEUM MIGRATION, FAULTS AND OVERPRESSURE, PART I: CALIBRATING BASIN MODELLING USING PETROLEUM IN TRAPS , A REVIEWJOURNAL OF PETROLEUM GEOLOGY, Issue 3 2006D.A. Karlsen This paper considers the principles of deciphering basin-scale hydrocarbon migration patterns using the geochemical information which is present in trapped petroleum. Petroleum accumulations in subsiding basins can be thought of as "data archives" within which stored information can help us to understand aspects of hydrocarbon formation and migration. This information can impart a time-resolved picture of hydrocarbon migration in a basin in response to processes associated with progressive burial, particularly in the context of the occurrence and periodic activity of faults. This review, which includes a series of tentative models of migration-related processes in the extensional Halten Terrace area, offshore mid-Norway, illustrates how we can use information from the migrating mobile hydrocarbon phase to improve our knowledge of the static geological system. Of particular importance is the role of sub-seismic heterogeneities and faults in controlling migration processes. We focus on how the secondary migration process can be enhanced in a multi-source rock basin such as the Halten Terrace, thereby increasing prospectivity. [source] HYDROCARBON SEEPAGE AND CARBONATE MOUND FORMATION: A BASIN MODELLING STUDY FROM THE PORCUPINE BASIN (OFFSHORE IRELAND)JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2005J. Naeth This study assesses whether the growth of deep water carbonate mounds on the continental slope of the north Atlantic may be associated with active hydrocarbon leakage. The carbonate mounds studied occur in two distinct areas of the Porcupine Basin, 200 km offshore Ireland, known as the Hovland-Magellan and the Belgica areas. To evaluate the possible link between hydrocarbon leakage and mound growth, we used two dimensional cross-section and map-based basin modelling. Geological information was derived from interpretation of five seismic lines across the province as well as the Connemara oilfield. Calibration data was available from the northern part of the study area and included vitrinite reflectance, temperature and apatite fission track data. Modelling results indicate that the main Jurassic source rocks are mature to overmature for hydrocarbon generation throughout the basin. Hydrocarbon generation and migration started in the Late Cretaceous. Based on our stratigraphic and lithologic model definitions, hydrocarbon migration is modelled to be mainly vertical, with only Aptian and Tertiary deltaic strata directing hydrocarbon flow laterally out of the basin. Gas chimneys observed in the Connemara field were reproduced using flow modelling and are related to leakage at the apices of rotated Jurassic fault blocks. The model predicts significant focussing of gas migration towards the Belgica mounds, where Cretaceous and Tertiary carrier layers pinch out. In the Hovland-Magellan area, no obvious focus of hydrocarbon flow was modelled from the 2D section, but drainage area analysis of Tertiary maps indicates a link between mound position and shallow Tertiary closures which may focus hydrocarbon flow towards the mounds. [source] THE HYDROCARBON POTENTIAL OF LEBANON: NEW INSIGHTS FROM REGIONAL CORRELATIONS AND STUDIES OF JURASSIC DOLOMITIZATIONJOURNAL OF PETROLEUM GEOLOGY, Issue 3 2004F. H. Nader This paper presents an updated review of the petroleum prospects of Lebanon. We briefly describe the known hydrocarbon shows in Lebanon and compare them with adjacent countries, leading to the construction of a model for hydrocarbon migration which takes into account regional facies and reservoir correlations. The oldest exposed rocks in Lebanon are the Jurassic carbonates of the Kesrouane Formation (over 1,000m thick). This formation can be divided into a basal unit dominated by seepage-reflux stratabound dolostones (the Chouane Member,) and an overlying limestone-prone unit (the Nahr Ibrahim Member). A two-stage dolomitisation model for the Jurassic carbonates in Lebanon has recently been proposed by the authors. According to this model, second-stage Late Jurassic hydrothermal dolomitisation is believed to have occurred as a result of the circulation of mixed dolomitising fluids along faults. Hence, the resulting dolostones are fault-controlled and strata-discordant, and may occur at any level within the Kesrouane Formation, locally redolomitising the Chouane Member dolostones and replacing the Nahr Ibrahim Member limestones. In this paper, we discuss the implications of diagenesis (especially dolomitisation) on the petroleum prospects of the Kesrouane Formation in Lebanon. The hydrothermal fault-related dolostones possess porosities of up to 20%, which result from intercrystalline and mouldic porosity enhancement. Porosities in the stratabound reflux dolostones (Early Jurassic) and limestones are much lower. The fact that most of the Jurassic system in onshore Lebanon was affected by meteoric diagenesis during the Late Jurassic - Early Cretaceous and the Cenozoic may downgrade hydrocarbon prospectivity. However, offshore areas far from the meteoric realm may have been less (or not at all) affected by meteoric invasion. If effective seals are present there, these areas may host promising Jurassic reservoir units. We also review the prospectivity of unexposed Triassic potential reservoir units in onshore Lebanon (e. g. the "Qartaba" structure). By analogy with the Syrian portion of the Palmyride Basin, Triassic strata here may include both reservoir units and evaporite seals. [source] Origin of the Silurian Crude Oils and Reservoir Formation Characteristics in the Tazhong UpliftACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010YANG Haijun Abstract: The Silurian stratum in the Tazhong uplift is an important horizon for exploration because it preserves some features of the hydrocarbons produced from multi-stage tectonic evolution. For this reason, the study of the origin of the Silurian oils and their formation characteristics constitutes a major part in revealing the mechanisms for the composite hydrocarbon accumulation zone in the Tazhong area. Geochemical investigations indicate that the physical properties of the Silurian oils in Tazhong vary with belts and blocks, i.e., heavy oils are distributed in the TZ47,15 well-block in the North Slope while normal and light oils in the No. I fault belt and the TZ16 well-block, which means that the oil properties are controlled by structural patterns. Most biomarkers in the Silurian oils are similar to that of the Mid-Upper Ordovician source rocks, suggesting a good genetic relationship. However, the compound specific isotope of n -alkanes in the oils and the chemical components of the hydrocarbons in fluid inclusions indicate that these oils are mixed oils derived from both the Mid-Upper Ordovician and the Cambrian,Lower Ordovician source rocks. Most Silurian oils have a record of secondary alterations like earlier biodegradation, including the occurrence of "UCM" humps in the total ion current (TIC) chromatogram of saturated and aromatic hydrocarbons and 25-norhopane in saturated hydrocarbons of the crude oils, and regular changes in the abundances of light and heavy components from the structural low to the structural high. The fact that the Silurian oils are enriched in chain alkanes, e.g., n -alkanes and 25-norhopane, suggests that they were mixed oils of the earlier degraded oils with the later normal oils. It is suggested that the Silurian oils experienced at least three episodes of petroleum charging according to the composition and distribution as well as the maturity of reservoir crude oils and the oils in fluid inclusions. The migration and accumulation models of these oils in the TZ47,15 well-blocks, the No. I fault belt and the TZ16 well-block are different from but related to each other. The investigation of the origin of the mixed oils and the hydrocarbon migration and accumulation mechanisms in different charging periods is of great significance to petroleum exploration in this area. [source] Different Hydrocarbon Accumulation Histories in the Kelasu-Yiqikelike Structural Belt of the Kuqa Foreland BasinACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010WANG Zhaoming Abstract: The Kuqa foreland basin is an important petroliferous basin where gas predominates. The Kela-2 large natural gas reservoir and the Yinan-2, Dabei-1, Tuzi and Dina-11 gas reservoirs have been discovered in the basin up to the present. Natural gases in the Kelasu district and the Yinan district are generated from different source rocks indicated by methane and ethane carbon isotopes. The former is derived from both Jurassic and Triassic source rocks, while the latter is mainly from the Jurassic. Based on its multistage evolution and superposition and the intense tectonic transformation in the basin, the hydrocarbon charging history can be divided into the early and middle Himalayan hydrocarbon accumulation and the late Himalayan redistribution and re-enrichment. The heavier carbon isotope composition and the high natural gas ratio of C1/C1,4 indicate that the accumulated natural gas in the early Himalayan stage is destroyed and the present trapped natural gas was charged mainly in the middle and late Himalayan stages. Comparison and contrast of the oils produced in the Kelasu and Yinan regions indicate the hydrocarbon charging histories in the above two regions are complex and should be characterized by multistage hydrocarbon migration and accumulation. [source] Characteristics of Oil Sources from the Chepaizi Swell, Junggar Basin, ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010LIU Luofu Abstract: So far there has been no common opinion on oil source of the Chepaizi swell in the Junggar Basin. Therefore, it is difficult to determine the pathway system and trend of hydrocarbon migration, and this resulted in difficulties in study of oil-gas accumulation patterns. In this paper, study of nitrogen compounds distribution in oils from Chepaizi was carried out in order to classify source rocks of oils stored in different reservoirs in the study area. Then, migration characteristics of oils from the same source were investigated by using nitrogen compounds parameters. The results of nitrogen compounds in a group of oil/oil sand samples from the same source indicate that the oils trapped in the Chepaizi swell experienced an obvious vertical migration. With increasing migration distance, amounts and indices of carbazoles have a regular changing pattern (in a fine linear relationship). By using nitrogen compounds techniques, the analyzed oil/oil sand samples of Chepaizi can be classified into two groups. One is the samples stored in reservoir beds of the Cretaceous and Tertiary, and these oils came from mainly Jurassic source rock with a small amount of Cretaceous rock; the other is those stored in the Jurassic, Permian and Carboniferous beds, and they originated from the Permian source. In addition, a sample of oil from an upper Jurassic reservoir (Well Ka 6), which was generated from Jurassic coal source rock, has a totally different nitrogen compound distribution from those of the above-mentioned two groups of samples, which were generated from mudstone sources. Because of influence from fractionation of oil migration, amounts and ratios of nitrogen compounds with different structures and polarities change regularly with increasing migrating distance, and as a result the samples with the same source follow a good linear relationship in content and ratio, while the oil samples of different sources have obviously different nitrogen compound distribution owing to different organic matter types of their source rocks. These conclusions of oil source study are identical with those obtained by other geochemical bio-markers. Therefore, nitrogen compounds are of great significance in oil type classification and oil/source correlation. [source] Oil and Gas Accumulation in the Foreland Basins, Central and Western ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 2 2010Yan SONG Abstract: Foreland basin represents one of the most important hydrocarbon habitats in central and western China. To distinguish these foreland basins regionally, and according to the need of petroleum exploration and favorable exploration areas, the foreland basins in central and western China can be divided into three structural types: superimposed, retrogressive and reformative foreland basin (or thrust belt), each with distinctive petroleum system characteristics in their petroleum system components (such as the source rock, reservoir rock, caprock, time of oil and gas accumulation, the remolding of oil/gas reservoir after accumulation, and the favorable exploration area, etc.). The superimposed type foreland basins, as exemplified by the Kuqa Depression of the Tarim Basin, characterized by two stages of early and late foreland basin development, typically contain at least two hydrocarbon source beds, one deposited in the early foreland development and another in the later fault-trough lake stage. Hydrocarbon accumulations in this type of foreland basin often occur in multiple stages of the basin development, though most of the highly productive pools were formed during the late stage of hydrocarbon migration and entrapment (Himalayan period). This is in sharp contrast to the retrogressive foreland basins (only developing foreland basin during the Permian to Triassic) such as the western Sichuan Basin, where prolific hydrocarbon source rocks are associated with sediments deposited during the early stages of the foreland basin development. As a result, hydrocarbon accumulations in retrogressive foreland basins occur mainly in the early stage of basin evolution. The reformative foreland basins (only developing foreland basin during the Himalayan period) such as the northern Qaidam Basin, in contrast, contain organic-rich, lacustrine source rocks deposited only in fault-trough lake basins occurring prior to the reformative foreland development during the late Cenozoic, with hydrocarbon accumulations taking place relatively late (Himalayan period). Therefore, the ultimate hydrocarbon potentials in the three types of foreland basins are largely determined by the extent of spatial and temporal matching among the thrust belts, hydrocarbon source kitchens, and regional and local caprocks. [source] Tectonic,Hydrocarbon Accumulation of Laoyemiao Region in the Nanpu Sag, Bohai Bay BasinACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2009Cuimei ZHANG Abstract: This paper aims to gain insight into Laoyemiao (LYM) tectonic features and utilizes the tectonic,hydrocarbon accumulation model by integrated analysis tectonic controls on suitable reservoirs, trap styles, and hydrocarbon migration. On the basis of 3-D seismic data interpretation and the Xi'nanzhuang (XNZ) Fault geometry analysis, it has been assessed that the LYM tectonics is essentially a transverse anticline produced by flexure of the XNZ Fault surface and superimposed by Neocene north-east-trending strike-slip faults. Transverse anticline is found to exert controls both on major sediment transportation pathways and sedimentary facies distribution. Fan-delta plains that accumulated on the anticline crest near the XNZ Fault scrap and fan-delta front on the anticline front and the upper part of both limbs slumps on synclines and the Linque subsag. In combination with the reservoir properties, suitable reservoirs are predicted in the subfacies of subaqueous distributary channel and mouth bar deposited on the anticline crest. The LYM-faulted anticline accounts for the following trap groups: faulted-block and anticline-dominated trap, fault-dominated traps, and combined and stratigraphic traps. Evidence from biomarkers of crude oil and hydrocarbon-filling period simultaneous, or a little later to the strike-slip fault activity, reveal that the strike-slip faults penetrating into the deep source rock, by connecting with shallow reservoirs, provide the major hydrocarbon migration pathways. [source] Origin and Accumulation of Natural Gases in the Upper Paleozoic Strata of the Ordos Basin in Central ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 1 2009Yangming ZHU Abstract: The natural gases in the Upper Paleozoic strata of the Ordos basin are characterized by relatively heavy C isotope of gaseous alkanes with ,13C1 and ,13C2 values ranging mainly from ,35, to ,30, and ,27, to ,22,, respectively, high ,13C excursions (round 10) between ethane and methane and predominant methane in hydrocarbon gases with most C1/(C1 -C5) ratios in excess of 0.95, suggesting an origin of coal-derived gas. The gases exhibit different carbon isotopic profiles for C1 -C4 alkanes with those of the natural gases found in the Lower Paleozoic of this basin, and believed to be originated from Carboniferous-Permian coal measures. The occurrence of regionally pervasive gas accumulation is distinct in the gently southward-dipping Shanbei slope of the central basin. It is noted that molecular and isotopic composition changes of the gases in various gas reservoirs are associated with the thermal maturities of gas source rocks. The abundances and ,13C values of methane generally decline northwards and from the basin center to its margins, and the effects of hydrocarbon migration on compositional modification seem insignificant. However, C isotopes of autogenetic calcites in the vertical and lateral section of reservoirs show a regular variation, and are as a whole depleted upwards and towards basin margins. Combination with gas maturity gradient, the analysis could be considered to be a useful tool for gas migration. [source] Characteristics of Overpressure Systems and Their Significance in Hydrocarbon Accumulation in the Yinggehai and Qiongdongnan Basins, ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 2 2003XIE Xinong Abstract Overpressure systems are widely developed in the central depression and palco-uplift in the Yinggehai and Qiongdongnan basins. They can be divided into three types according to the origin of abnormally high formation pressure in the reservoirs, i.e. the autochthonous, vertically-transmitted and laterally-transmitted types. The autochthonous overpressure system results from rapid disequilibrium sediment loading and compaction. In the allochthonous overpressure system, the increase of fluid pressure in sandstone originates from the invasion of overpressured fluid flowing vertically or laterally through the conduit units. The autochthonous overpressure system occurs in the deep-lying strata of Neogene age in the central depression of the Yinggehai and Qiongdongnan basins. The vertically transmitted overpressure system is developed in the shallow strata of Late Miocene and Pliocene ages in the diapiric zone of the central Yinggehai basin, and the laterally transmitted overpressure system occurs in the Oligocene strata of paleo-uplifts, such as the structure of Ya-211 in the Qiongdongnan basin. The results indicate that the autochthonous overpressure system is generally a closed one, which is unfavorable for the migration and accumulation of hydrocarbons. In the allochthonous overpressure system, hydrocarbon accumulation depends on the relationship between the formation of overpressure systems and the spatial location and duration of hydrocarbon migration. The interval overlying the overpressure system is usually a favorable hydrocarbon accumulation zone if the duration of fluid expulsion coincides with that of hydrocarbon accumulation. [source] | ||||||||||