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1.
扬子地块东南古生代上升流沉积相及其与烃源岩的关系 总被引：34，自引：0，他引：34
长江中下游苏、皖、赣、鄂一带属古生代扬子地块被动大陆边缘的东南缘,通过该区64条古生界剖面的实测、分析和对比,得出该区古生界寒武、奥陶、志留、石炭和二叠系等地层中的黑色碳质页岩、硅质页岩、硅质条带和结核以及磷矿层和磷结核等沉积是古特提斯海中上升流作用形成的。上升流水体中富营养盐和SiO2,在古生代低纬度的扬子地块东南缘生物大量繁殖,引发缺氧事件,形成上述硅质和磷质沉积以及有机质丰富的烃源岩、石煤和磷矿层等,由于上升流水体富营养盐和SiO2,生物化石属种丰富,个体大,多营底栖或固着浅海底生活,硅质生物放射虫等丰富。区内烃源岩有机质与上升流的强度呈正相关关系,可见它们之间存在着成因联系。上古生界油气发现于苏北及南黄海,因而,这一区域是与上升流沉积有关的、最有利的油气勘探目标区。 相似文献
2.
The middle Permian Lucaogou Formation in the Jimusaer Sag of the southeastern Junggar Basin, NW China, was the site of a recent discovery of a giant tight oil reservoir. This reservoir is unusual as it is hosted by lacustrine mixed dolomitic-clastic rocks, significantly differing from other tight reservoirs that are generally hosted by marine/lacustrine siliciclastic–calcitic sequences. Here, we improve our understanding of this relatively new type of tight oil reservoir by presenting the results of a preliminarily investigation into the basic characteristics and origin of this reservoir using field, petrological, geophysical (including seismic and logging), and geochemical data. Field and well core observations indicate that the Lucaogou Formation is a sequence of mixed carbonate (mainly dolomites) and terrigenous clastic (mainly feldspars) sediments that were deposited in a highly saline environment. The formation is divided into upper and lower cycles based on lithological variations between coarse- and fine-grained rocks; in particular, dolomites and siltstones are interbedded with organic-rich mudstones in the lower part of each cycle, whereas the upper part of each cycle contains few dolomites and siltstones. Tight oil accumulations are generally present in the lower part of each cycle, and dolomites and dolomite-bearing rocks are the main reservoir rocks in these cycles, including sandy dolomite, dolarenite, dolomicrite, and a few dolomitic siltstones. Optical microscope, back scattered electron, and scanning electron microscope imaging indicate that the main oil reservoir spaces are secondary pores that were generated by the dissolution of clastics and dolomite by highly acidic and corrosive hydrocarbon-related fluids. 相似文献
3.
Sedimentary heterogeneities are ubiquitous in nature and occur over a range of scales from core, reservoir to basin scales. They may thus exert significant influences on hydrocarbon generation, migration and accumulation. The sedimentary heterogeneities of the Permian Shanxi Formation in the Ordos Basin, China were modelled using Sedsim, a stratigraphic forward modelling program. The simulation results were then used to construct a 3D petroleum system model using PetroMod. The effects of sedimentary heterogeneities on hydrocarbon accumulations were evaluated by comparing the integrated Sedsim-PetroMod model with the classic 3D basin model. The Sedsim simulation shows that considerable sedimentary heterogeneities are present within the Shanxi Formation, as a result of the interplay of the initial topography, tectonic subsidence, base level change and sediment inputs. A variety of lithologies were developed both laterally and vertically within the Shanxi Formation at kilometre and metre scales, respectively, with mudstones mainly developed in the depositional centre, while sandstones developed in the southern and northern margin areas. A typical source-ward retrogradation is well developed within the Lower Shanxi Formation.A base-case classic 3D basin model was constructed to quantify the Permian petroleum system in the Ordos Basin. The geological and thermal models were calibrated using Vr and borehole temperature data. The source rocks of the Upper Paleozoic became mature (Ro > 0.5%) and high mature (Ro > 1.2%) in the late Triassic and late Jurassic, respectively, in the central and southern areas. During the Early Cretaceous, a tectonically induced geothermal event occurred in the southern Ordos Basin. This caused the source rocks to reach over maturity (Ro > 2.0%) quite rapidly in the early Late Cretaceous in the central and southern areas. All the source rock transformation ratios (TR) at present are greater than 70% in the P1 coal and P1 mudstone layers with TR values approaching 100% in the central and southern areas. The transformation ratios of the P1 limestone are close to 100% over the entire interval.In the base-case model, a large amount of hydrocarbons appear to have been expelled and migrated into the Shanxi Formation, but only a minor amount was accumulated to form reservoirs. In the model, the Shanxi Formation sandstone layer was set to be homogeneous vertically and there was no regional seal rocks present at the top of the Shanxi Formation. Therefore hydrocarbons could not be trapped effectively with only minor accumulations in some local structural highs where hydrocarbons are trapped both at the top and in the up-dip direction by the adjacent mudstone facies. In contrast, the integrated Sedsim-PetroMod model takes into account of the internal lithological and sedimentary facies heterogeneities within the Shanxi Formation, forming complex contiguous sandstone-mudstone stacking patterns. Hydrocarbons were found to have accumulated in multiple intervals of lithological traps within the Shanxi Formation. The results indicate that lithological distinctions, controlled by sedimentary heterogeneities in three dimensions can provide effective sealing in both the top and up-dip directions for hydrocarbon accumulations, with gas being mainly accumulated near the depocentre where lithological traps usually formed due to frequent oscillations of the lake level. 相似文献
4.
Evolution of the western Barents Sea 总被引：2，自引：0，他引：2
Jan Inge Faleide Steinar T. Gudlaugsson Gerard Jacquart 《Marine and Petroleum Geology》1984,1(2):123-150
Information from multichannel seismic reflection data complemented by seismic refraction, gravity and magnetics forms the basis for a regional structural and evolutionary model of the western Barents Sea during post-Caledonian times. The western Barents Sea contains a thick succession, locally > 10 km, of Upper Paleozoic to Cenozoic sedimentary rocks covering a basement of probably Caledonian origin. The area is divided into three regional geological provinces: (1) an east-west trending basinal province between 74°N and the coast of Norway; (2) an elevated platform area to the north towards Svalbard; and (3) the western continental margin. Several structural elements of different origin and age have been mapped within each of these provinces. The main stratigraphic sequence boundaries have been tentatively dated from available well information, correlation with the geology of adjacent areas, and correlation with the interregional unconformities caused by relative changes of sea level. The main structural elements were developed during three major post-Caledonian tectonic phases: the Svalbardian phase in Late Devonian to Early Carboniferous times, the Mid and Late Kimmerian phase in Mid Jurassic to Early Cretaceous times and Cenozoic tectonism related to the progressive northward opening of the Norwegian-Greenland Sea. The sediments are predicted to be of mainly clastic origin except for a thick sequence of Middle Carboniferous — Lower Permian carbonates and evaporites. Salt diapirs have developed in several sub-basins, especially in the Nordkapp Basin where they form continuous salt walls that have pierced through > 7 km of sediments. 相似文献
5.
科尔占地区位于滨里海盆地阿斯特拉罕-阿克纠宾斯克隆起带东南部的比伊克扎尔次级隆起上,该地区广泛发育下二叠统孔谷组盐岩,以盐岩沉积为界,它将整个剖面划分为盐上层系（以碎屑岩为主的含油气层系）和盐下层系（以碳酸盐岩为主的含油气层系）两个大的含油气层系,石炭系为盐下层系中主要的含油气层系之一。通过对研究区唯一的盐下井K井岩屑及其薄片的详细观察,并结合该井测井资料,分析了石炭系的沉积特征,并对其沉积相进行了划分与描述。K井石炭系主要发育3种类型沉积相,分别为深水浊积扇相、斜坡相和台地相,其中深水浊积扇相可进一步划分为内扇、中扇和外扇3个亚相,台地相划分为滩间洼地和台内滩2个亚相。利用K井钻探结果,结合区域资料,初步预测出科尔占地区早石炭世和中石炭世末期沉积相带的平面分布特征。 相似文献
6.
Three bitumen fractions were obtained and systematically analysed for the terpane and sterane composition from 30 Paleozoic source rocks and 64 bitumen-containing reservoir rocks within the Upper Sinian, Lower Cambrian, Lower Silurian, Middle Carboniferous, Upper Permian and Lower Triassic strata in the Sichuan Basin and neighbouring areas, China. These bitumen fractions include extractable oils (bitumen I), oil-bearing fluid inclusions and/or closely associated components with the kerogen or pyrobitumen/mineral matrix, released during kerogen or pyrobitumen isolation and demineralization (bitumen II), and bound compounds within the kerogen or pyrobitumen released by confined pyrolysis (bitumen III). In addition, atomic H/C and O/C ratios and carbon isotopic compositions of kerogen and pyrobitumen from some of the samples were measured. Geochemical results and geological information suggest that: (1) in the Central Sichuan Basin, hydrocarbon gases in reservoirs within the fourth section of the Upper Sinian Dengying Formation were derived from both the Lower Cambrian and Upper Sinian source rocks; and (2) in the Eastern Sichuan Basin, hydrocarbon gases in Middle Carboniferous Huanglong Formation reservoirs were mainly derived from Lower Silurian source rocks, while those in Upper Permian and Lower Triassic reservoirs were mainly derived from both Upper Permian and Lower Silurian marine source rocks. For both the source and reservoir rocks, bitumen III fractions generally show relatively lower maturity near the peak oil generation stage, while the other two bitumen fractions show very high maturities based on terpane and sterane distributions. Tricyclic terpanes evolved from the distribution pattern C20 < C21 < C23, through C20 < C21 > C23, finally to C20 > C21 > C23 during severe thermal stress. The concentration of C30 diahopane in bitumen III (the bound components released from confined pyrolysis) is substantially lower than in the other two bitumen fractions for four terrigenous Upper Permian source rocks, demonstrating that this compound originated from free hopanoid precursors, rather than hopanoids bound to the kerogen. 相似文献
7.
A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis, GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window. 相似文献
8.
The Sørkapp Basin (NW Barents Shelf) contains a comprehensive sedimentary succession that provides insight into regional tectonics and depositional development of the shelf from the Devonian to the Cretaceous. With its location east of the mid-Atlantic spreading ridge and south of Svalbard, the Basin serves as an important link between the offshore and onshore realms.This study subdivides this sparsely studied basin into six main seismic units (three Paleozoic and three Mesozoic). A metamorphic basement together with assumed Devonian sedimentary deposits form the foundation for a chiefly Carboniferous basin. The Basin forms a syncline with infill showing limited fault-influence. Overlying the early infill are Late Carboniferous deposits which show less lateral variation in thickness but also active growth on the few faults showing significant displacement. The overlying platform deposits of the latest Carboniferous and Permian show a change in depositional geometry, with onlapping deposits towards the east probably resulting from uplift of the Stappen High and regional flooding. Subsequent, particularly Late, Triassic sedimentation shows a more distinctly progradational pattern with a dominantly southeastern source for sediments. During this shallow shelf-filling stage, the Sørkapp Basin is sheltered by the Gardarbanken High, blocking the Early Triassic clinoform development. The High was transgressed in the Middle Triassic and the platform-edge progressively approached the present Svalbard coastline.The youngest Mesozoic unit forms a separate saucer-shaped depocenter west of the Sørkapp Basin, where deposits are truncated by the seafloor in a mid-basin position and across the Gardarbanken High. The depositional pattern for this succession correlates with the outcrop pattern of the Adventdalen Group implying a post Middle Jurassic to Cretaceous age. The Sørkapp Basin has been referred to as a Cretaceous feature based in this depocenter. However, the foundations are much older and the Cretaceous depression is located west of the deeper basin. Accordingly, we propose the informal term Sørkapp Depression for the Cretaceous basin. 相似文献
9.
The Ukrainian Dniepr-Donets Basin (DDB) is a Late Palaeozoic intracratonic rift basin, with sedimentary thicknesses up to 19 km, displaying the effects of salt tectonics during its entire history of formation, from Late Devonian rifting to the Tertiary. Hundreds of concordant and discordant salt structures formed during this time. It is demonstrated in this paper that the variety of styles of salt structure formation in the DDB provide important constraints on understanding the triggering and driving mechanisms of salt kinematics in sedimentary basins in general. Salt movement in the DDB began during the Devonian syn-rift phase of basin development and exerted controls on the later distribution of salt structures though the geometry of basement faults is not directly responsible for the regular spacing of salt structures. Post-rift salt movements in the DDB occurred episodically. Episodes of salt movement were triggered by tectonic events, specifically two extensional events during the Carboniferous, an extensional reactivation at the end of Carboniferous–earliest Permian, and a compressional event at the end of the Cretaceous. Extensional events that induced salt movement were ‘thick-skinned’ (i.e. basement involved in deformation) rather than ‘thin-skinned’. Most overburden deformation related to salt movements is ductile regardless of sedimentary bulk lithology and degree of diagenesis, while the deformation of sedimentary cover in areas where salt is absent is mainly brittle. This implies that the presence of salt changes the predominant mode of deformation of overlying sedimentary rocks. Episodes of salt movement lasted longer than the periods of active tectonics that initiated them. Buoyancy, erosion, and differential loading all played a role in driving halokinesis once tectonic forces had pushed the salt-overburden system into disequilibrium; among these factors, erosion of overburden above growing salt structures acted as a key self-renewing force for development of salt diapirs. Very high sedimentation rates (related to high post-rift tectonic subsidence rates), particularly during the Carboniferous, were able to bury diapirs and to load salt bodies such that buoyancy, erosion, and differential loading forces eventually became insufficient to continue driving diapirism—until the system was perturbed by an ensuing tectonic event. In contrast, some salt anticlines and diapirs developed continuously during the entire Mesozoic because of much-reduced tectonic subsidence rates (and sedimentation supply) during this time. However, a Lower Permian salt series and overhangs of buried diapirs played an important role in preventing overburden piercing (and fracturing) during the Mesozoic and, specifically, during the Late Cretaceous salt diapirism phase. 相似文献
10.
下扬子区面积177020km^2,包括江苏、浙江、安徽、江西和上海绝大部分地区,这一区域的构造属性为被动大陆边缘,通过对该区古生界中二叠统的几十条剖面的实测、分析和对比,得出该区古生界中二叠统地层中的黑色碳质页岩、硅质页岩、硅质岩、硅质条带和结核以及磷矿层和磷结核等沉积是古特提斯海中上升流作用形成的。上升流水体中富营养盐和SiO2在古生代低纬度的下扬子地块生物大量繁殖,引发缺氧事件,形成上述硅质和磷质沉积以及有机质丰富的烃源岩、石煤和磷矿层等,由于上升流水体富营养盐和SiO2,生物化石属种丰富,个体大,多营底栖或固着浅海底生活,硅质生物放射虫等丰富。区内烃源岩有机质与上升流的强度呈正相关关系,可见它们之间存在着成因联系。 相似文献
11.
Source rock studies are one of the key issues of petroleum exploration activities. In the supercontinent of Gondwana, ice ages related to the Upper Ordovician (Hirnantian) and rising sea levels caused by glacial melting at the end of the Ordovician and Early Silurian (Llandoverian) created excellent source rocks along the margin of Gondwana. Investigations conducted in the Arabian Peninsula have been indicated indicating that the lower Qalibah Formation (the so-called Qusaiba Member or Hot Shale) is a good source rock for the Paleozoic petroleum system in this area. Likewise, the Sarchahan Formation was recently introduced as a source rock in the Zagros Basin of Iran, which is probably equivalent to the Qalibah Formation in the Arabian Peninsula. In this study, samples were prepared from surface and subsurface Paleozoic rock units in Iran's Zagros Basin. The emphasis of the paper was on the Sarchahan Formation in Kuh-e Faraghan, ranging in age from the Late Ordovician (Hirnantian) to Lower Silurian (Llandoverian) to determine whether the high richness of organic matter in the Sarchahan Formation is related to the Late Ordovician or Lower Silurian. The basal part of the Sarchahan Formation belongs to the Late Ordovician (Hirnantian) because of the presence of the persculptus graptolite biozone, while the remainder belongs to the Lower Silurian. The Ordovician and early Llandoverian parts of the Sarchahan Formation contain type II and III kerogen with TOC ranging from 2.94 to 7.19, but the rest of the Sarchahan Formation (late Llandoverian) has TOC ranging from 0.1 to 0.58. Therefore, the Hot Shale in Iran falls within the Hirnantian and early Llandoverian (Rhuddanian), and not the latest Llandoverian (Aeronian and Telychian). Utilizing organic petrography, kerogen type was found II/III. The carbon stable isotope studies revealed that the source rock of hydrocarbons in Dalan and Kangan reservoirs has been the Sarchahan Formation. Based on analytical data, the kerogenous shales in the lower part of the Sarchahan Formation are at end of gas window, and the gamma ray amount is approximately 180 API. This research indicates the differences between the source rocks in the southern and northern Persian Gulf and suggesting, the Hot Shale should be considered in different views and used in modeling studies of sedimentary basins for future exploration targets. 相似文献
12.
南华北盆地石炭-二叠系沉积环境与聚煤规律研究 总被引：1，自引：0，他引：1
Four major sedimentary systems of the Carboniferous and Permian in the Southern North China (SNC) Basin were identified in sedimentological and depositional features,such as trace fossil,silt body shape,vertical sequence and logging curve. In addition,the sedimentary facied and typical sequences of sedimentary systems were analyzed in principles of sedimentology and coalfield geology,Furthermore,geological patterns of the coal accumulation,paleogeography and tectonic setting in each geological stage were reconstructed. Corresponding to sedimentary system and facies,there was no coal accumulation in the late carboniferous,while Shihezi Formation of the Middle Permian is the best coal accumulation period. And the delta front and sea-water swamp (the gulf) facies were the best environment for coal accumulation,which are meaningful for coalfield prediction and exploration in the Southern North China (SNC) Basin. 相似文献
13.
黄海海域地质构造特征及其油气资源潜力 总被引：4，自引：0，他引：4
姚伯初 《海洋地质与第四纪地质》2006,26(2):85-93
综合前人的研究成果,利用2000年以来在黄海采集的综合地球物理资料,结合我国及邻国在该海域的钻井成果,分析和讨论了黄海地区从古生代至新生代的构造演化历史;对南、北黄海沉积盆地形成的构造背景和盆地的构造类型进行了研究,认为在古生代它们是台地相沉积,中生代和新生代是张裂盆地;通过对我们采集的地震剖面之分析和研究,认为盆地中的中生界和古近系发育了良好的烃源岩,新近系发育了良好的区域盖层,储层在盆地中普遍发育。因此,在南、北黄海沉积盆地中可以找到中、小型油气田。另外,对盆地中的古生界应加强研究,在保存较好并且中新生代沉积较薄的地方做探查工作,应该有一定的油气前景。 相似文献
14.
Fluid inclusion gases in minerals from shale hosted fracture-fill mineralization have been analyzed for stable carbon isotopic ratios of CH4 using a crushing device interfaced to an isotope ratio mass spectrometer (IRMS). The samples of Paleozoic strata under study originate from outcrops and wells in the Rhenish Massif and Campine Basin, Harz Mountains, and the upper slope of the Southern Permian Basin. Fracture-fill mineralization hosted by Mesozoic strata was sampled from drill cores in the Lower Saxony Basin. Some studied sites are candidates for shale gas exploration in Germany. Samples of Mesozoic strata are characterized by abundant calcite-filled horizontal fractures which preferentially occur in TOC-rich sections of the drilled sediments. Only rarely are vertical fractures filled with carbonates and/or quartz in drill cores from Mesozoic strata but in Paleozoic shale they occur frequently. The δ13C(CH4) values of fluid inclusions in calcite from horizontal fractures hosted by Mesozoic strata suggest that gaseous hydrocarbons were generated during the oil/early gas window and that the formation of horizontal fractures seems to be related to hydraulic expulsion fracturing. The calculated maturity of the source rocks at the time of gas generation lies below the maturity derived from measured vitrinite reflectance. Thus, the formation of horizontal fractures and trapping of gas that was generated in the oil and/or early gas window obviously occurred prior to maximal burial. Rapidly increasing vitrinite reflectance data seen locally can be explained by hydrothermal alteration, as indicated by increasing δ13C (CH4–CO2) values in fluid inclusions. The formation of vertical fractures in studied Mesozoic sediments is related to stages of post-burial inversion; gas-rich inclusions in fracture filling minerals recorded the migration of gas that had probably been generated instantaneously, rather than cumulatively, from high to overmature source rocks. Since no evidence is given for the presence of early generated gas in studied Paleozoic shale, it appears likely that major gas loss from shales occurred due to deformation and uplift of these sediments in response to the Variscan Orogeny. 相似文献
15.
The Dniepr-Donets Basin (DDB) hosts a multi-source petroleum system with more than 200 oil and gas fields, mainly in Carboniferous clastic rocks. Main aim of the present study was to correlate accumulated hydrocarbons with the most important source rocks and to verify their potential to generate oil and gas. Therefore, molecular and isotopic composition as well as biomarker data obtained from 12 oil and condensate samples and 48 source rock extracts was used together with USGS data for a geological interpretation of hydrocarbon charging history.Within the central DDB, results point to a significant contribution from (Upper) Visean black shales, highly oil-prone as well as mixed oil- and gas-prone Serpukhovian rocks and minor contribution from an additional Tournaisian source. Devonian rocks, an important hydrocarbon source within the Pripyat Trough, have not been identified as a major source within the central DDB. Additional input from Bashkirian to Moscovian (?) (Shebelinka Field) as well as Tournaisian to Lower Visean rocks (e.g. Dovgal Field) with higher contents of terrestrial organic matter is indicated in the SE and NW part, respectively.Whereas oil–source correlation contradicts major hydrocarbon migration in many cases for Tournaisian to Middle Carboniferous reservoir horizons, accumulations within Upper Carboniferous to Permian reservoirs require vertical migration up to 4000 m along faults related to Devonian salt domes.1-D thermal models indicate hydrocarbon generation during Permo-Carboniferous time. However, generation in coal-bearing Middle Carboniferous horizons in the SE part of the basin may have occurred during the Mesozoic. 相似文献
16.
The petrographic and micropaleontological studies of the rocks in the sedimentary cover of the Primorye continental slope in the area of Vladimir Bay in the Sea of Japan made it possible to establish that the sedimentary cover is represented in this area by two different facial complexes of Late Miocene rocks. The first facial complex consists of terrigenous rocks (siltstones, sandstones, and conglomerates) that were accumulated under relatively shallow-water conditions of the shelf and the uppermost part of the continental slope. The second one is formed by diatomaceous-clayey rocks under more deep-water conditions, mainly in the upper part of the continental slope. The carbonate nodules that are widely distributed among the deposits of the first complex but are also recorded in the second one were formed as a result of diagenetic processes in the terrigenous or silicious-terrigenous sediments that had been formed. With respect to their age, the Late Miocene deposits are characterized by a full succession of diatomaceous zones over 10.0–5.5 mln yr. The sediments of the first facial complex accumulated during the first third of the Late Miocene (10.0–8.5 mln yr), while those of the second began to accumulate somewhat later, but their accumulation continued until the late Miocene (9.2–5.5 mln yr). 相似文献
17.
18.
Riphean basins of the central and western Siberian Platform 总被引：1，自引：0，他引：1
Sergey V. FrolovGrigorii G. Akhmanov Elena V. KozlovaOleg V. Krylov Ksenia A. SitarYuriy I. Galushkin 《Marine and Petroleum Geology》2011,28(4):906-920
The Siberian Platform is unique by its volume of Meso-Neoproterozoic sedimentary deposits. For about one billion years (∼1650-650 Ma) several sedimentary basins were developed here, resulting in the formation of several kilometers thickness of sedimentary cover. The Riphean (Mesoproterozoic-Lower Neoproterozoic) rocks are exposed mainly along platform peripheries. The most complete sections are represented by several megacycles. Each megacycle contains terrigenous series at the base and carbonate formations in the upper part. Several isolated and anisochronous basins were created during the Riphean on the territory of East Siberia. Some of them were intracratonic, others were developed on passive margins. Neoproterozoic orogeny along the platform boundaries resulted in re-organization of the Siberian basins, with extensive faulting, uplifting and erosion of the territories.In eastern Siberia, Riphean series contain large hydrocarbon accumulations. The reservoirs were formed mainly due to fracturing and leaching of carbonate strata (e.g. vugular carbonates of the pre-Vendian weathering crust). The Upper Proterozoic deposits are overlain by thick clayey-carbonate and saliferous-carbonate series of the Upper Vendian and Cambrian, isolating them from the upper sedimentary cover. The Riphean basins contained thick, organic rich, clayey and clayey carbonate. In some of them a hydrocarbon generation maximum took place at the end of the Riphean. The pre-Vendian erosion has removed a significant volume of Riphean sediments. During this time a majority of already formed hydrocarbon accumulations have been lost or degraded. Remaining Riphean series have generated hydrocarbons during the Paleozoic.Despite its complex history, the Riphean is still considered highly prospective, with source rocks developing at multiple levels and reservoirs occurring in both carbonate and clastic rocks. Discoveries of new oil-and-gas fields in East Siberia are likely, but will depend on integration of detailed seismic data and a large volume of core data for the correct prognosis of Riphean reservoir distribution. 相似文献
19.
《Marine and Petroleum Geology》2012,37(1):13-34
Structured organic matters of the Palynomorphs of mainly dinoflagellate cysts are used in this study for dating the limestone, black shale, and marl of the Middle Jurassic (Bajocian–Bathonian) Sargelu Formation, Upper Jurassic (Upper Callovian – Lower Oxfordian) Naokelekan Formation, Upper Jurassic (Kimeridgian and Oxfordian) Gotnia and Barsarine Formations, and Upper Jurassic – Lower Cretaceous (Tithonian-Beriassian) Chia Gara source rock Formations while spore species of Cyathidites australis and Glechenidites senonicus are used for maturation assessments of this succession. Materials' used for this palynological study are 320 core and cutting samples of twelve oil wells and three outcrops in North Iraq.Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils potential source rock extracts of Jurassic-Lower Cretaceous strata to determine valid oil-to-source rock correlations in North Iraq. Two subfamily carbonate oil types-one of Middle Jurassic age (Sargelu) carbonate rock and the other of mixed Upper Jurassic/Cretaceous age (Chia Gara) with Sargelu sources as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA & PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well Mk-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of C28/C29 steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field.Palynofacies assessments are performed for this studied succession by ternary kerogen plots of the phytoclast, amorphous organic matters, and palynomorphs. From the diagram of these plots and maturation analysis, it could be assessed that the formations of Chia Gara and Sargelu are both deposited in distal suboxic to anoxic basin and can be correlated with kerogens classified microscopically as Type A and Type B and chemically as Type II. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminifera test linings, and phytoclasts in all these formations and hence affected with upwelling current. These deposit contain up to 18 wt% total organic matters that are capable to generate hydrocarbons within mature stage of thermal alteration index (TAI) range in Stalplin's scale (Staplin, 1969) of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation. Case study examples of these oil prone strata are; one 7-m (23-ft) thick section of the Sargelu Formation averages 44.2 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt% TOC especially in well Mk-2 whereas, one 8-m (26-ft) thick section of the Chia Gara and 1-m (3-ft) section of Naokelekan Formations average 44.5 mg HC/g S2 and 440 °C Tmax and 14 wt% TOC especially in well Aj-8. One-dimension, petroleum system models of key wells using IES PetroMod Software can confirm their oil generation capability.These hydrocarbon type accumulation sites are illustrated in structural cross sections and maps in North Iraq. 相似文献
20.
Hydrocarbon compositions of bitumens from mineralized Devonian lavas and Carboniferous sedimentary rocks, central Scotland 总被引：1，自引：0，他引：1
Solid bitumens occur in mineralized veins in the Lower Devonian Ochil Volcanic Formation in the Midland Valley of Scotland. Bitumens are also widespread in the Carboniferous of the Midland Valley. Gas chromatography (g.c.) - mass spectrometry (m.s.) studies undertaken on bitumens from the Devonian rocks and on Devonian and Carboniferous mudrocks show that the bitumens contain biomarkers and that Carboniferous rocks are the more likely source for the bitumens. Hydrocarbons may have migrated into the Devonian rocks along the Ochil Fault zone from a downthrown Carboniferous basin to the south of the fault. The organic geochemistry of bitumen samples from the Carboniferous rocks reflects varying degrees of biodegradation, and heating by igneous intrusions. 相似文献