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Hydrocarbon Generation (hydrocarbon + generation)

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Earth and Environmental Science	100%

Terms modified by Hydrocarbon Generation

hydrocarbon generation history

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HYDROCARBON SEEPAGE AND CARBONATE MOUND FORMATION: A BASIN MODELLING STUDY FROM THE PORCUPINE BASIN (OFFSHORE IRELAND)

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2005
J. 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]

Overpressure and petroleum generation and accumulation in the Dongying Depression of the Bohaiwan Basin, China

GEOFLUIDS (ELECTRONIC), Issue 4 2001
X. Xie
Abstract The occurrence of abnormally high formation pressures in the Dongying Depression of the Bohaiwan Basin, a prolific oil-producing province in China, is controlled by rapid sedimentation and the distribution of centres of active petroleum generation. Abnormally high pressures, demonstrated by drill stem test (DST) and well log data, occur in the third and fourth members (Es3 and Es4) of the Eocene Shahejie Formation. Pressure gradients in these members commonly fall in the range 0.012,0.016 MPa m,1, although gradients as high as 0.018 MPa m,1 have been encountered. The zone of strongest overpressuring coincides with the areas in the central basin where the principal lacustrine source rocks, which comprise types I and II kerogen and have a high organic carbon content (>2%, ranging to 7.3%), are actively generating petroleum at the present day. The magnitude of overpressuring is related not only to the burial depth of the source rocks, but to the types of kerogen they contain. In the central basin, the pressure gradient within submember Es32, which contains predominantly type II kerogen, falls in the range 0.013,0.014 MPa m,1. Larger gradients of 0.014,0.016 MPa m,1 occur in submember Es33 and member Es4, which contain mixed type I and II kerogen. Numerical modelling indicates that, although overpressures are influenced by hydrocarbon generation, the primary control on overpressure in the basin comes from the effects of sediment compaction disequilibrium. A large number of oil pools have been discovered in the domes and faulted anticlines of the normally pressured strata overlying the overpressured sediments; the results of this study suggest that isolated sandstone reservoirs within the overpressured zone itself offer significant hydrocarbon potential. [source]

PETROLEUM PROSPECTIVITY OF CRETACEOUS FORMATIONS IN THE GONGOLA BASIN, UPPER BENUE TROUGH, NIGERIA: AN ORGANIC GEOCHEMICAL PERSPECTIVE ON A MIGRATED OIL CONTROVERSY

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2008
M. B. Abubakar
Organic geochemical studies of Cretaceous formations in the Gongola Basin, northern Nigeria, show TOC values that are generally higher than the minimum (0.5 wt %) required for hydrocarbon generation. Data from Rock-Eval pyrolysis and biomarker studies indicate the presence of both terrestrial and marine derived Types II and III organic matter, which is immature in the Gombe Formation and of marginal maturity in the Yolde Formation. Immature Type III to IV OM is present in the Pindiga Formation; and Type III OM, with a maturity that corresponds to the conventional onset (or perhaps peak) of oil generation occurs in the Bima Formation. However, Bima Formation samples from the 4710 , 4770 ft (1435.6 , 1453.9 m) depth interval within well Nasara-1 indicate Type I OM of perhaps lacustrine origin (H31R/H30 ratio generally ,0.25). Although the Nasara-1 well was reported to be dry, geochemical parameters (high TOCs, S1, S2 and Hls, low Tmax compared to adjacent samples, a bimodal S2 peak on the Rock-Eval pyrogram, a dominance of fluorinite macerals), together with generally low H3IR/H30 biomarker ratios within the 4710,4770 ft (1435.6,1453.9 m) interval, suggest the presence of migrated oil, perhaps sourced by lacustrine shales in the Albian Bima Formation located at as-yet unpenetrated depths. The presence of the migrated oil in the Bima Formation and its possible lacustrine origin suggest that the petroleum system in the Gongola Basin is similar to that of the Termit, Doba and Doseo Basins of the Chad Republic, where economic oil reserves have been encountered. [source]

THERMAL HISTORY RECONSTRUCTION IN THE SOROOSH AND NOWROOZ FIELDS, PERSIAN GULF, BASED ON APATITE FISSION TRACK ANALYSIS AND VITRINITE REFLECTANCE DATA

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2008
A. Bashari
The thermal history of the sedimentary successions at the Soroosh-17, Soroosh-02 and Nowrooz-16 wells in the northern Persian Gulf have been studied using apatite fission track analysis and vitrinite reflectance data. These data were used to identify and quantify episodes of heating and cooling which have affected the sections penetrated by these wells. This information was synthesised to provide a thermal history framework for the wells, within which the history of hydrocarbon generation, as well as regional structural development, can be understood. Preliminary hydrocarbon generation histories are presented for the Soroosh and Nowrooz oilfields and nearby areas. Modelling of hydrocarbon generation histories based on the AFTA- and VR-derived thermal histories, assuming a dominant Type III kerogen for possible Albian Kazhdumi Formation source rocks and a dominant Type II kerogen for possible Neocomian Fahliyan (Lower Ratawi) Formation source rock, suggest that local sourcing of oil from the Kazhdumi Formation is unlikely. The most likely source rock for oil in the Burgan Formation reservoir at Soroosh-17 and Nowrooz-16 is interpreted to be the Fahliyan Formation based on the available data. On the other hand, speculative modelling of the Hendijan-I well down-dip from the Nowrooz field does allow some oil to be generated from the Kazhdumi sequence at that location, and this might be available for migration to the Nowrooz field. [source]

IMPACT OF MAGMATISM ON PETROLEUM SYSTEMS IN THE SVERDRUP BASIN, CANADIAN ARCTIC ISLANDS, NUNAVUT: A NUMERICAL MODELLING STUDY

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2007
S.F. Jones
Numerical modelling is used to investigate for the first time the interactions between a petroleum system and sill intrusion in the NE Sverdrup Basin, Canadian Arctic Archipelago. Although hydrocarbonexploration has been successful in the western Sverdrup Basin, the results in the NE part of thebasin have been disappointing, despite the presence of suitable Mesozoic source rocks, migrationpaths and structural/stratigraphic traps, many involving evaporites. This was explained by (i) theformation of structural traps during basin inversion in the Eocene, after the main phase ofhydrocarbon generation, and/or (ii) the presence of evaporite diapirs locally modifying the geothermalgradient, leading to thermal overmaturity of hydrocarbons. This study is the first attempt at modellingthe intrusion of Cretaceous sills in the east-central Sverdrup Basin, and to investigate how theymay have affected the petroleum system. A one-dimensional numerical model, constructed using PetroMod9.0®, investigates the effectsof rifting and magmatic events on the thermal history and on petroleum generation at the DepotPoint L-24 well, eastern Axel Heiberg Island (79°23,40,N, 85°44,22,W). The thermal history isconstrained by vitrinite reflectance and fission-track data, and by the tectonic history. The simulationidentifies the time intervals during which hydrocarbons were generated, and illustrates the interplaybetween hydrocarbon production and igneous activity at the time of sill intrusion during the EarlyCretaceous. The comparison of the petroleum and magmatic systems in the context of previouslyproposed models of basin evolution and renewed tectonism was an essential step in the interpretationof the results from the Depot Point L-24 well. The model results show that an episode of minor renewed rifting and widespread sill intrusionin the Early Cretaceous occurred after hydrocarbon generation ceased at about 220 Ma in theHare Fiord and Van Hauen Formations. We conclude that the generation potential of these deeperformations in the eastern Sverdrup Basin was not likely to have been affected by the intrusion ofmafic sills during the Early Cretaceous. However, the model suggests that in shallower sourcerocks such as the Blaa Mountain Formation, rapid generation of natural gas occurred at 125 Ma, contemporaneous with tectonic rejuvenation and sill intrusion in the east-central Sverdrup Basin. A sensitivity study shows that the emplacement of sills increased the hydrocarbon generation ratesin the Blaa Mountain Formation, and facilitated the production of gas rather than oil. [source]

A REVIEW OF GEOLOGICAL DATA THAT CONFLICT WITH THE PARADIGM OF CATAGENIC GENERATION AND MIGRATION OF OIL

JOURNAL OF PETROLEUM GEOLOGY, Issue 3 2005
H. Hugh Wilson
The majority of petroleum geologists today agree that the complex problems that surround the origin, generation, migration and accumulation of hydrocarbons can be resolved by accepting the geochemical conclusion that the process originates by catagenic generation in deeply-buried organically-rich source rocks. These limited source rock intervals are believed to expel hydrocarbons when they reach organic maturity in oil kitchens. The expelled oil and gas then follow migration pathways to traps at shallower levels. However, there are major geological obstacles that cast doubt upon this interpretation. The restriction of the source rock to a few organically rich levels in a basin forces the conclusion that the basin plumbing system is leaky and allows secondary horizontal and vertical migration through great thicknesses of consolidated sedimentary rocks in which there are numerous permeability barriers that are known to effectively prevent hydrocarbon escape from traps. The sourcing of lenticular traps points to the enclosing impermeable envelope as the logical origin of the trapped hydrocarbons. The lynch-pin of the catagenic theory of hydrocarbon origin is the expulsion mechanism from deeply-buried consolidated source rock under high confining pressures. This mechanism is not understood and is termed an "enigma". Assuming that expulsion does occur, the pathways taken by the hydrocarbons to waiting traps can be ascertained by computer modelling of the basin. However, subsurface and field geological support for purported migration pathways has yet to be provided. Many oilfield studies have shown that oil and gas are preferentially trapped in synchronous highs that were formed during, or very shortly after, the deposition of the charged reservoir. An unresolved problem is how catagenically generated hydrocarbons, expelled during a long-drawn-out maturation period, can have filled synchronous highs but have avoided later traps along the assumed migration pathways. From many oilfield studies, it has also been shown that the presence of hydrocarbons inhibits diagenesis and compaction of the reservoir rock. This "Füchtbauer effect" points to not only the early charging of clastic and carbonate reservoirs, but also to the development of permeability barriers below the early-formed accumulations. These barriers would prevent later hydrocarbon additions during the supposed extended period of expulsion from an oil kitchen. Early-formed traps that have been sealed diagenetically will retain their charge even if the trap is opened by later structural tilting. Diagenetic traps have been discovered in clastic and carbonate provinces but their recognition as viable exploration targets is discouraged by present-day assumptions of late hydrocarbon generation and a leaky basin plumbing system. Because there are so many geological realities that cast doubt upon the assumptions that devolve from the paradigm of catagenic generation, the alternative concept of early biogenic generation and accumulation of immature oil, with in-reservoir cracking during burial, is again worthy of serious consideration. This concept envisages hydrocarbon generation by bacterial activity in many anoxic environments and the charging of synchronous highs from adjacent sources. The resolution of the fundamental problem of hydrocarbon generation and accumulation, which is critical to exploration strategies, should be sought in the light of a thorough knowledge of the geologic factors involved, rather than by computer modelling which may be guided by questionable geochemical assumptions. [source]

HYDROCARBON SEEPAGE AND CARBONATE MOUND FORMATION: A BASIN MODELLING STUDY FROM THE PORCUPINE BASIN (OFFSHORE IRELAND)

BURIAL HISTORY RECONSTRUCTION AND THERMAL MODELLING AT KUH-E MOND, SW IRAN

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2003
M. R. Kamali
At the Kuh-e Mond anticline (Fars Province, SW Iran) and in nearby offshore structures, large volumes of natural gas are reservoired in the Permian , Early Triassic Dehram Group while heavy oil has been discovered in the Cretaceous Sarvak and Eocene Jahrum Formations. In this paper, we use data from six exploration wells and from nearby surface exposures to reconstruct the burial history at Kuh-e Mond. Regional observations show that the thick sedimentary fill in this part of the Zagros Basin was subjected to intense tectonism during the Zagros Orogeny, with a paroxysmal phase during the late Miocene and Pliocene. Thermal modelling and geochemical data from Kuh-e Mond and adjacent fields allows possible hydrocarbon generation and migration mechanisms to be identified. Maturities predicted using Lopatin's TTI model are in accordance with maturities obtained from vitrinite reflectance measurements. We show that formations which have source potential in the nearby Dezful Embayment (including the Pabdeh, Gurpi, Gadvan and Kazhdumi Formations) have not reached the oil window in the Mond wells. Moreover, their organic carbon content is very low as they were deposited in oxic, shallow-water settings. Underlying units (including the Ordovician and Cambrian) could have reached the gas window but contain little organic matter. Silurian shales (Sarchahan Formation), which generate gas at Kuh-e Gahkum and Kuh-e Faraghan (north of Bandar Abbas) and in Saudi Arabia and elsewhere in the Middle East, are absent from the Mond structure. The absence of source rocks suggests that the gas and heavy oil accumulations at Kuh-e Mond and at nearby fields have most probably undergone long-distance lateral migration from distant source kitchens. [source]

DEPOSITIONAL ENVIRONMENT AND DIAGENESIS OF THE EOCENE JDEIR FORMATION, GABES-TRIPOLI BASIN, WESTERN OFFSHORE, LIBYA

JOURNAL OF PETROLEUM GEOLOGY, Issue 4 2000
J. M. Anketell
The late Ypresian (early Eocene) Jdeir Formation was deposited in the Mesozoic-Cenozoic Gabes-Tripoli Basin, offshore Libya. The basin developed on the northern passive margin of the African Plate and was relatively unstable being affected by syn-sedimentary tectonic movements. Deposition was coeval with a relative rise of sea-level and the subsequent highstand. A lower, thinly-developed nummulitic bank facies with restricted distribution records the transgressive event and is succeeded by more micritic sediments that record the time of maximum flooding. The succeeding sea-level highstand is represented by a thick, and widely developed, progradational-aggradational nummulitic sequence that displays lateral changes across WE-ESE trending facies belts. Three major lithofacies are recognized in the Jdeir Formation: Nummulites packstone-grainstone, Alveolina-Orbitoliteswackestone-packtone, andFragmental-Discocyclina-Assilina wackestone-packstone, depositedin bank, back-bank, and fore-bank environments, respectively. The formation passes to the NNE into the pelagic lithofacies of the Hallab Formation; landward, to the south, it passes into shoreline evaporitic facies of the Taljah Formation. The lithofacies were structurally controlled by contemporaneous and/or syndepositional tectonic movements, with nummulitic facies tending to develop on uplifted areas. Petrographic and petrophysical studies indicate that porosity in the Jdeir Formation is controlled by depositional environment, tectonic setting and diagenesis. The combined effects of salt tectonics, a major unconformity at the top of the formation and meteoric diagenesis have produced excellent-quality reservoir facies at the Bouri oilfield and in other areas. Porosity is highest in the nummulitic bank facies and lowest in the Alveolina-Orbitolites micrite facies. Good to excellent reservoir quality occurs in the upper part of the nummulitic packstone-grainstone facies, especially where these sediments overlie structurally high areas. High rates of dissolution found at the crests of domes and anticlines suggest that early diagenetic processes and features are, in part, structurally controlled. Future exploration success will depend on investigation of similar structures within the Gabes-Tripoli Basin. Both porosity initiation and preservation are related to early depositional and diagenetic processes. The wide time-gap between hydrocarbon generation and reservoir formation points to the role of the seal in porosity preservation and rules out the assumption that early emplacement of oil had preserved the porosity. [source]

THE NATURE AND ORIGIN OF PETROLEUM IN THE CHAIWOPU SUB-BASIN (JUNGGAR BASIN), NW CHINA

JOURNAL OF PETROLEUM GEOLOGY, Issue 2 2000
H. P. Huang
The Chaiwopu Sub-basin is a minor extension of the Junggar Basin, hW China, and covers an area of about 2,500 sq. km. It is bounded to the east and north by the Bogda Shan and to the south by the Tian Shan ("Shan" meaning "mountains" in Chinese). Four wells have been drilled in the sub-basin; condensate and gas have been produced in noncommercial quantities at one of the wells (Well C), but the other three wells were dry. In this paper, I investigate the nature and origin of the petroleum at Well C. Three of the four wells in the Chaiwopu Sub-basin penetrated the Upper Permian Lucaogou Formation. Previous studies in the Junggar Basin have established that laminated lacustrine mudstones assigned to this formation comprise a very thick high quality source rock. However, the analysis of cores from wells in the sub-basin shows that the Lucaogou Formation is composed here of shallow lacustrine, fluvial and alluvial deposits which have very low petroleum generation potential. Overlying sediments (Upper Permian, Triassic and younger strata) likewise have little source potential. Around 1,000 m of Upper Permian laminated oil shales crop out at Dalongkou and Tianchi on the northern side of the Bogda Shan. On the southern side of the Bogda Shan, however, only 30 m of Upper Permian oil shales occur at Guodikong. Shales and oil seeps from these locations were analysed using standard organic-geochemical techniques. The physical properties of the petroleum present at Well C, and its carbon isotope and biomarker characteristics, suggest that it has migrated over long distances from its source rock, although an alternative explanation for its origin is not precluded. Burial history modelling indicates that hydrocarbon generation and migration may have occurred before the uplift of the Bogda Shan in the Late Jurassic,Early Cretaceous, the orogenic episode which resulted in the diflerentiation of the Chaiwopu Sub-basinfrom the Junggar Basin. [source]

BURIAL AND MATURATION HISTORY OF THE HEGLIG FIELD AREA, MUGLAD BASIN, SUDAN

JOURNAL OF PETROLEUM GEOLOGY, Issue 1 2000
A. Y. Mohamed
The NW-SE trending Muglad Basin (SW Sudan) is one of a number of Mesozoic basins which together make up the Central African Rift System. Three phases of rifting occurred during the Cretaceous and Tertiary, resulting in the deposition of at least 13 km of sediments in this basin. Commercial hydrocarbons are sourced from the Barremian-Neocomian Sharaf Formation and the Aptian-Albian Abu Gabra Formation. The Heglig field is located on a NW-SE oriented structural high in the SE of the Muglad Basin, and is the second-largest commercial oil discovery in Sudan. The high is characterised by the presence of rotated fault blocks, and is surrounded by sub-basinal structural lows. We modelled the geohistories of three wells on different fault blocks in the Heglig field (Heglig-2, Barki-1 and Kanga-1) and one well in the Kaikang Trough (May25,1). The models were calibrated to measured porosity-depth data, temperature and vitrinite reflectance measurements. Predicted present-day heat flow over this part of the Muglad Basin is about 55 mW/m2. However, a constant heat-flow model with this value did not result in a good fit between calculated vitrinite Ro and measured Ro at the wells studied. Therefore a variable heat-flow model was used; heat flow peaks of 75, 70 and 70 mW/m2 were modelled, these maxima corresponding to the three synrift phases. This model resulted in a better fit between calculated and measured Ro. The source rock section in the Sharaf and Abu Gabra Formations was modelled for hydrocarbon generation in the four wells. Model results indicate that the present-day oil generation window in the Hegligfield area lies at depths of between 2 and 4 km, and that oil and gas generation from the basal unit of the Abu Gabra Formation occurred between about 90 and 55 Ma and from the Sharaf Formation between 120 and 50 Ma. The results suggest that the oils discovered in the Heglig area have been generated from a deep, mature as-yet unpenetrated source-rock section, and/or from source rocks in nearby sub- basinal areas. [source]

Fluid dynamics and subsurface sediment mobilization processes: an overview from Southeast Caribbean

BASIN RESEARCH, Issue 4 2010
Éric Deville
ABSTRACT This paper discusses the origin and the dynamics of subsurface sediment mobilization processes in tectonically mobile regions and shale-rich environment. This is illustrated by the example of Trinidad and the south of the Barbados prism. In this area of the southeast Caribbean, geophysical acquisitions have spectacularly shown the widespread development of sediment mobilization features in the interference area between the southern part of the Barbados prism and the active turbidite system of the Orinoco. Numerous mud volcanoes are especially developed along ramp anticline crests through hydraulic fracture systems. The area also exhibits trends of structures that correspond to massive uplifts of well-preserved turbidite and hemipelagic sediments that cut up the surrounding sediments. Some of these structures are complicated by the development of collapse structures, calderas and superimposed mud volcanoes. The mobilized sediments expelled by the mud volcanoes are not only liquefied argillaceous but also fine sandy material from deep horizons, and various shallower formations pierced by the mud conduits. Both in the Barbados prism and in Trinidad, the expelled mud is rich in thin, angular and mechanically damaged quartz grains, which are probably cataclastic flows issued from sheared and collapsed deep sandy reservoirs. The exotic clasts and breccias result mostly from hydraulic fracturing. In Trinidad, the gas phase is mainly deep thermogenic methane associated with hydrocarbon generation at depth. Subsurface sediment mobilization notably differs from salt mobilization by the role taken by the fluid dynamics that control overpressured shale mobilization and induce sediment liquefaction. A reaction chain of several deformation processes develops around the conduits. Massive sedimentary uplift corresponds to large movements of stratified solid levels, possibly due to the tectonic inversion of pre-existing mud volcano systems. All these phenomena are controlled by the development of overpressure at depth. No evidence for piercing shale diapirs has been observed in the area studied. [source]

Classification of Complex Reservoirs in Superimposed Basins of Western China

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010
PANG Xiongqi
Abstract: Many of the sedimentary basins in western China were formed through the superposition and compounding of at least two previously developed sedimentary basins and in general they can be termed as complex superimposed basins. The distinct differences between these basins and monotype basins are their discontinuous stratigraphic sedimentation, stratigraphic structure and stratigraphic stress-strain action over geological history. Based on the correlation of chronological age on structural sections, superimposed basins can be divided into five types in this study: (1) continuous sedimentation type superimposed basins, (2) middle and late stratigraphic superimposed basins, (3) early and late stratigraphic superimposed basins, (4) early and middle stratigraphic superimposed basins, and (5) long-term exposed superimposed basins. Multiple source-reservoir-caprock assemblages have developed in such basins. In addition, multi-stage hydrocarbon generation and expulsion, multiple sources, polycyclic hydrocarbon accumulation and multiple-type hydrocarbon reservoirs adjustment, reformation and destruction have occurred in these basins. The complex reservoirs that have been discovered widely in the superimposed basins to date have remarkably different geologic features from primary reservoirs, and the root causes of this are folding, denudation and the fracture effect caused by multiphase tectonic events in the superimposed basins as well as associated seepage, diffusion, spilling, oxidation, degradation and cracking. Based on their genesis characteristics, complex reservoirs are divided into five categories: (1) primary reservoirs, (2) trap adjustment type reservoirs, (3) component variant reservoirs, (4) phase conversion type reservoirs and (5) scale-reformed reservoirs. [source]

Hydrocarbon Generation Evolution of Permo-Carboniferous Rocks of the Bohai Bay Basin in China

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 2 2010
Yanming ZHU
Abstract: The Bohai Bay Basin is a Mesozoic subsidence and Cenozoic rift basin in the North China Craton. Since the deposition of the Permo-Carboniferous hydrocarbon source rock, the basin has undergone many tectonic events. The source rocks have undergone non-uniform uplift, twisting, deep burying, and magmatism and that led to an interrupted or stepwise during the evolution of hydrocarbon source rocks. We have investigated the Permo-Carboniferous hydrocarbon source rocks history of burying, heating, and hydrocarbon generation, not only on the basis of tectonic disturbance and deeply buried but also with new studies on apatite fission track analysis, fluid inclusion measurements, and the application of the numerical simulation of EASY %Ro. The heating temperature of the source rocks continued to rise from the Indosinian to Himalayan stage and reached a maximum at the Late Himalayan. This led to the stepwise increases during organic maturation and multiple stages of hydrocarbon generation. The study delineated the tectonic stages, the intensity of hydrocarbon generation and spatial and temporal distribution of hydrocarbon generations. The hydrocarbon generation occurred during the Indosinian, Yanshanian, and particularly Late Himalayan. The hydrocarbon generation during the late Himalayan stage is the most important one for the Permo-Carboniferous source rocks of the Bohai Bay Basin in China. [source]

Petroleum System of the Sufyan Depression at the Eastern Margin of a Huge Strike-slip Fault Zone in Central Africa

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 6 2009
ZHANG Yamin
Abstract: The present paper mainly studies the petroleum system of the Sufyan Depression in the Muglad Basin of central Africa and analyzes its control of hydrocarbon accumulation. On the basis of comprehensive analysis of effective source rock, reservoir bed types and source,reservoir,seal assemblages, petroleum system theory has been used to classify the petroleum system of the Sufyan Depression. Vertically, the Sufyan Depression consists of two subsystems. One is an Abu Gabra subsystem as a self generating, accumulating and sealing assemblage. The other subsystem is composed of an Abu Gabra source rock, Bentiu channel sandstone reservoir and Darfur group shale seal, which is a prolific assemblage in this area. Laterally, the Sufyan Depression is divided into eastern and western parts with separate hydrocarbon generation centers more than 10 000 m deep. The potential of the petroleum system is tremendous. Recently, there has been a great breakthrough in exploration. The Sufyan C-1 well drilled in the central structural belt obtained high-yielding oil flow exceeding 100 tons per day and controlled geologic reserves of tens of millions of tons. The total resource potential of the Sufyan Depression is considerable. The central structural belt is most favorable as an exploration and development prospect. [source]

Effects of Overpressured Fluid Flow on Petroleum Accumulation in the Yinggehai Basin

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 4 2004
HAO Fang
Abstract, The Yinggehai Basin is a strongly overpressured Cenozoic basin developed in the northern continental shelf of the South China Sea. The flow of overpressured fluids in this basin has given rise to strong effects on petroleum accumulation. (1) The overpressured fluid flow has enhanced the maturation of shallow-buried source rocks, which has caused the source rocks that would have remained immature under the conduction background to be mature for hydrocarbon generation. As a result, the overpressured fluid flow has increased the volume and interval of mature source rocks. (2) The overpressured fluid flow has strong extraction effects on the immature or low-mature source rocks in the shallow parts. This has increased, to some extent, the expulsion efficiency of the source rocks. More importantly, the extraction effects have strongly limited the effectiveness of biomarker parameters from oil and condensate in reflecting the source and maturity of the oil and gas. (3) The flow has caused the sandstones in the shallow parts to get into the late diagenesis stage, and significantly reduced the porosity and permeability of the sandstones. This study confirms that even in sedimentary basins in which no topography-driven groundwater flow systems have ever developed, the cross-formation migration of overpressured fluids and the resultant energy conduction and material exchange can significantly affect the thermal regime, source rock maturation and sandstone diagenesis. As a result, the effects of overpressured fluid flow must be taken into account in analyzing the mechanism of petroleum accumulation. [source]

Late-stage Hydrocarbon Accumulation in the Bozhong Depression of the Bohai Bay Basin as Controlled by Neotectonism

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 3 2004
GONG Zaisheng
Abstract, Neotectonism occurred intensively in the Bozhong depression in the Bohai Bay Basin, which was reflected vertically by dramatic subsidence and a number of uplifts and laterally by notable fault movements. This particularity has resulted in the special petroleum geological conditions of the Bozhong depression which are different from those of adjacent lands. For example, the source rocks of the Shahejie Formation were overpressured and hydrocarbon generation occurred in the late stage; the Dongying Formation was deeply buried below the hydrocarbon-generating threshold, therefore there were sufficient oil sources. The rapid subsidence led to starved sedimentation of the Guantao Formation fine sandstone and the regional Minghuazhen Formation lacustrine shale, which formed the Neogene regional reservoir-caprock association. The active faults formed in the neotectonism became passages for oil to migrate from the Paleogene to Neogene. The traps formed by late fault activity and accompanied anticlines provided spaces for the formation of reservoirs. All the above factors match well with one another in the Bozhong depression, providing favorable conditions for the formation of a series of large oilfields in the region [source]

Maturity Control on the Patterns of Hydrocarbon Regeneration from Coal

ACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 2 2000
ZOU Yanrong
Abstract Rock-Eval pyrolysis and Py-GC experiments on naturally and artificially matured coal samples were carried out. The results suggest that both depolymerization and defuctionalization exist during the maturation and evolution of coal. The patterns of hydrocarbon regeneration are diverse at different stages of the maturation and evolution. When the vitrinite reflectance (R0) is 0.7%-0.9%, bitumen is the richest in coal while activation energy is the minimum, and the temperature of peak yield is lower than that of primary hydrocarbon generation. However, if reflectance is greater than 0.9%, defunctionalization predominates and the temperature of peak regeneration is shown in lagging compared with the primary hydrocarbon generation. When reflectance is out of the "oil window", the peak temperature of hydrocarbon regeneration and that of the primary hydrocarbon generation seems to be continuous. [source]