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HYDROCARBON POTENTIAL (hydrocarbon + potential)
Selected AbstractsHYDROCARBON POTENTIAL OF THE LATE CRETACEOUS GONGILA AND FIKA FORMATIONS, BORNU (CHAD) BASIN, NE NIGERIAJOURNAL OF PETROLEUM GEOLOGY, Issue 4 2010B. Alalade The hydrocarbon potential of possible shale source rocks from the Late Cretaceous Gongila and Fika Formations of the Chad Basin of NE Nigeria is evaluated using an integration of organic geochemistry and palynofacies observations. Total organic carbon (TOC) values for about 170 cutting samples range between 0.5% and 1.5% and Rock-Eval hydrogen indices (HI) are below 100 mgHC/gTOC, suggesting that the shales are organically lean and contain Type III/IV kerogen. Amorphous organic matter (AOM) dominates the kerogen assemblage (typically >80%) although its fluorescence does not show a significant correlation with measured HI. Atomic H/C ratios of a subset of the samples indicate higher quality oil- to gas-prone organic matter (Type II-III kerogens) and exhibit a significant correlation with the fluorescence of AOM (r2= 0.86). Rock-Eval Tmax calibrated against AOM fluorescence, biomarker and aromatic hydrocarbon maturity data suggests a transition from immature (<435°C) to mature (>435°C) in the Fika Formation and mature to post-mature (>470°C) in the Gongila Formation. The low TOC values in most of the shales samples limit their overall source rock potential. The immature to early mature upper part of the Fika Formation, in which about 10% of the samples have TOC values greater than 2.0%, has the best oil generating potential. Oil would have been generated if such intervals had become thermally mature. On the basis of the samples studied here, the basin has potential for mostly gaseous rather than liquid hydrocarbons. [source] NEOGENE TECTONIC HISTORY OF THE SUB-BIBANIC AND M'SILA BASINS, NORTHERN ALGERIA: IMPLICATIONS FOR HYDROCARBON POTENTIALJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2007H. L. Kheidri The southern Bibans region in northern Algeria is located in the external zone of the Tell fold-and-thrust belt. Field observations in this area together with seismic data integrated with previous studies provide evidence for a number of Tertiary deformation phases. Late Eocene Atlassic deformation was followed by Oligocene (?)-Aquitanian-Burdigalian compression, which was associated with the development of a foreland basin in front of a southerly-propagating thrust system. Gravity-driven emplacement of the Tellian nappes over the basin margin probably occurred during the Langhian-Serravallian-Tortonian. The Hodna Mountains structural culmination developed during the Miocene-Pliocene. Analysis of brittle structures points to continued north-south shortening during the Neogene, consistent with convergence between the African and Eurasian Plates. The unconformably underlying Mesozoic-Cenozoic autochthonous sequence in this area contains two potential source rock intervals: Cenomanian-Turonian and Eocene. Reservoir rocks include Lower Cretaceous siliciclastics and Upper Cretaceous to Palaeogene carbonates. Structural style has controlled trap types. Thus traps in the Tell fold-and-thrust belt are associated with folds, whereas structural traps in the Hodna area are associated with reactivated normal faults. In the latter area, there is also some evidence for base-Miocene stratigraphic traps. [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] HYDROCARBON POTENTIAL OF JURASSIC SOURCE ROCKS IN THE JUNGGAR BASIN, NW CHINAJOURNAL OF PETROLEUM GEOLOGY, Issue 3 2003A. N. Ding Jurassic source rocks in the Junggar Basin (NW China) include coal swamp and freshwater lacustrine deposits. Hydrocarbon-generating macerals in the coal swamp deposits are dominated by desmocollinite and exinite of higher-plant origin. In lacustrine facies, macerals consists of bacterially-altered amorphinite, algal- amorphinite, alginite, exinite and vitrinite. Coals and coaly mudstones in the Lower Jurassic Badaowan Formation generate oil at the Qigu oilfield on the southern margin of the basin. Lacustrine source rocks generate oil at the Cainan oilfield in the centre of the basin. The vitrinite reflectance (Ro) of coal swamp deposits ranges from 0.5% to 0.9%, and that of lacustrine source rocks from 0.4% to 1.2%. Biomarker compositions likewise indicate that thermal maturities are variable. These variations cause those with lighter compositions to have matured earlier. Our data indicate that oil and gas generation has occurred at different stages of source-rock maturation, an "early" stage and a "mature" stage. Ro values are 0.4%,0.7% in the former and 0.8%,1.2% in the latter. [source] Overpressure and petroleum generation and accumulation in the Dongying Depression of the Bohaiwan Basin, ChinaGEOFLUIDS (ELECTRONIC), Issue 4 2001X. 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] OIL-PRONE LOWER CARBONIFEROUS COALS IN THE NORWEGIAN BARENTS SEA: IMPLICATIONS FOR A PALAEOZOIC PETROLEUM SYSTEMJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2010J.H. Van Koeverden In this study, we assess the oil generation potential of Lower Carboniferous, liptinite-rich coals in the Tettegras Formation on the Finnmark Platform, southern Norwegian Barents Sea. Oil from these coals has been expelled into intercalated sandstones. The coals may have contributed to petroleum recorded in well 7128/4,1 on the Finnmark Platform and may constitute a new Palaeozoic source rock in the Barents Sea. The Tettegras Formation coals contain up to 80 vol.% liptinite (mineral matter free base) and have low oxygen indices. Hydrogen indices up to 367 mg HC/g TOC indicate liquid hydrocarbon potential. In wells 7128/4,1 and 7128/6,1, the coals have vitrinite reflectance Ro= 0.75,0.85 %. Compared to shale and carbonate source rocks, expulsion from coal in general begins at higher maturities (Ro= 0.8,0.9% and Tmax= 444,453°C). Thus, the coals in the wells are mostly immature with regard to oil expulsion. The oil in well 7128/4,1 most likely originates from a more mature part of the Tettegras Formation in the deeper northern part of the Finnmark Platform. Wide variations in biomarker facies parameters and ,13C isotope values indicate a heterogeneous paralic depositional setting. The preferential retention by coal strata of naphthenes (e.g. terpanes and steranes) and aromatic compounds, compared to n-alkanes and acyclic isoprenoids, results in a terrigenous and waxy oil. This oil however contains marine biomarkers derived from the intercalated shales and siltstones. It is therefore important to consider the entire coal-bearing sequence, including the intercalated shales, in terms of source rock potential. Coals of similar age occur on Svalbard and Bjørnøya. The results of this study therefore suggest that a Lower Carboniferous coaly source rock may extend over large areas of the Norwegian Barents Sea. This source rock is mature in areas where the otherwise prolific Upper Jurassic marine shales are either immature or missing and may constitute a new Palaeozoic coal-sourced petroleum system in the Barents Sea. [source] ORDOVICIAN,PERMIAN PALAEOGEOGRAPHY OF CENTRAL EURASIA: DEVELOPMENT OF PALAEOZOIC PETROLEUM-BEARING BASINSJOURNAL OF PETROLEUM GEOLOGY, Issue 3 2003V. A. Bykadorov In this paper, we discuss three petroleum-bearing basins of Palaeozoic age in Central Eurasia,the Precaspian, Tarim and Chu-Sarysu Basins. We make use of recently-published palaeogeographic maps of the Central Eurasian region, six of which are presented here (Late Ordovician, Early-Middle Devonian, Late Devonian, Early Carboniferous, Early Permian and Late Permian). The maps illustrate the development through the Palaeozoic of the Palaeoasian and Palaeotethys Oceans; of the East European, Siberian and Tarim cratons; and of the Kazakhstan and other microcontinental blocks. The Kazakhstan block formed during the Late Ordovician and is a collage of Precambrian and Early Palaeozoic microcontinents and island arcs. It is surrounded by collisional foldbelts (Ob-Zaisan, Ural-Tianshan and Junggar-Balkhash) which formed in the Late Carboniferous , Permian. We believe that the formation of a stable Kazakhstan block is not consistent with the existence of the previously-identified "Kipchak arc" within the Palaeoasian ocean, or (as has previously been proposed) with activity on this arc up to the end of the Palaeozoic. The oil and gas potential of the Precaspian, Tarim and Chu-Sarysu Basins depends to a large extent on their tectonic stability during the Palaeozoic and subsequent time. The Precaspian Basin has been stable since the Cadomian orogeny (Early Cambrian) and is known to have major hydrocarbon potential. The Tarim Basin (NW China) has somewhat lower potential because the margins of the Tarim continental block have been affected by a series of collisional events; that margin with the Palaeotethys Ocean, for example, was active during the Late Palaeozoic. The Chu-Sarysu Basin on the Kazakhstan block is the least stable of the three and contains only minor gas accumulations. [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] | ||||||||||