首页 | 本学科首页   官方微博 | 高级检索  
相似文献
 共查询到20条相似文献，搜索用时 656 毫秒
1.
通过对研究区中生代地层典型剖面或代表性剖面系统考察和综合研究,对上侏罗统及其上覆、下伏岩石地层进行进一步系统清理和修订：（1）将济阳坳陷原上侏罗统蒙阴组划归下白垩统,与之相对应的是鲁西南地区为杨家庄组;将山东地区中—上侏罗统三台组界定为中侏罗统;（2）将皖北地区合肥盆地圆筒山组划入中—上侏罗统;原上侏罗统周公山组认为是跨时代地层单元（J3K1）。（3）大别山北麓北淮阳六安、金寨地区的凤凰台组、三尖铺组定为晚侏罗世早期。在此基础上建立了中国东部地区准确可行的地层对比关系,提出了与国际接轨的地层划分与对比表。对比结果表明中国东部晚侏罗世除了在南北缘存在沉积外,整个地区缺失上侏罗统。该现象表明中国东部在晚侏罗世仍为挤压应力环境甚至比早中侏罗世更为强烈,甚至一直维持到早白垩世初。  相似文献   

2.
In this study we provide evidence for methane hydrates in the Taranaki Basin, occurring a considerable distance from New Zealand's convergent margins, where they are well documented. We describe and reconstruct a unique example of gas migration and leakage at the edge of the continental shelf, linking shallow gas hydrate occurrence to a deeper petroleum system. The Taranaki Basin is a well investigated petroleum province with numerous fields producing oil and gas. Industry standard seismic reflection data show amplitude anomalies that are here interpreted as discontinuous BSRs, locally mimicking the channelized sea-floor and pinching out up-slope. Strong reverse polarity anomalies indicate the presence of gas pockets and gas-charged sediments. PetroMod™ petroleum systems modelling predicts that the gas is sourced from elevated microbial gas generation in the thick slope sediment succession with additional migration of thermogenic gas from buried Cretaceous petroleum source rocks. Cretaceous–Paleogene extensional faults underneath the present-day slope are interpreted to provide pathways for focussed gas migration and leakage, which may explain two dry petroleum wells drilled at the Taranaki shelf margin. PetroMod™ modelling predicts concentrated gas hydrate formation on the Taranaki continental slope consistent with the anomalies observed in the seismic data. We propose that a semi-continuous hydrate layer is present in the down-dip wall of incised canyons. Canyon incision is interpreted to cause the base of gas hydrate stability to bulge downward and thereby trap gas migrating up-slope in permeable beds due to the permeability decrease caused by hydrate formation in the pore space. Elsewhere, hydrate occurrence is likely patchy and may be controlled by focussed leakage of thermogenic gas. The proposed presence of hydrates in slope sediments in Taranaki Basin likely affects the stability of the Taranaki shelf margin. While hydrate presence can be a drilling hazard for oil and gas exploration, the proposed presence of gas hydrates opens up a new frontier for exploration of hydrates as an energy source.  相似文献   

3.
The Unst Basin is situated in the northern North Sea between the East Shetland Basin and the Shetland Isles. The basin is essentially a three-armed, Permo-Triassic fault-controlled basin containing up to 3600 m of red-beds. This is overlain by a westerly thickening Jurassic and early Cretaceous sequence, the stratigraphy of which is very similar to that of the East Shetland Basin. In particular, the Brent Group (140 m), Humber Group (685 m) and Cromer Knoll Group (300 m) are well represented.As a result of Laramide uplift of the area, the thick Upper Cretaceous and Palaeocene strata of the East Shetland Basin are absent from the Unst Basin. This uplift resulted in substantial erosion within the Unst Basin providing the major source for Palaeocene sands in the Viking Graben and the Faeroes Basin. Late Palaeocene and younger Tertiary strata transgress westwards across this erosion surface.Petroleum exploration within the basin culminated in the drilling of two exploration wells. These wells encountered potential reservoir and source rocks in the Jurassic section. However, geochemical analyses indicate these source rocks are immature for hydrocarbon generation within the Unst Basin. It is concluded that the Unst Basin has a low petroleum potential.  相似文献   

4.
Gravity-flow sediments from the South Virgin Islands Trough Escarpment (west of the island of St. Croix) contain Late Cretaceous through Late Miocene nannofossils that are well mixed even within individual samples. These sediments, reworked and redeposited in latest Miocene or Early Pliocene, apparently occur within a sequence of Late Miocene-to-recent fan deposits. Marine source beds representing all pre-Pliocene epochs of the Cenozoic and latest Cretaceous must have been exposed along the NW-facing West St. Croix Escarpment. Southward tilting of the St. Croix Ridge has subsequently altered the depositional pattern.  相似文献   

5.
东海陆架盆地是位于中国东部华南大陆边缘的一个中、新生代叠合盆地,具有较大油气潜力。目前东海陆架盆地油气的发现均来自于新生界,对中生代残留地层的各方面特征认识不足:在空间上通常集中于特定构造单元,且基本位于盆地西部;在时间上主要涉及白垩纪和侏罗纪,且多是定性或半定量的研究。本文在前人研究的基础上,收集、整理了研究区目前最新、最全的反射地震资料和钻井数据,从钻遇中生界井的标定出发,以地震资料的层序划分和解释为基础,进行残留地层的研究,空间上统一盆地东、西两大坳陷带,时间上统揽白垩纪、侏罗纪以及前侏罗纪三个时期。结果表明,东海陆架盆地中生代残留地层遭受了后期严重的剥蚀改造,总体呈现东厚西薄、南厚北薄的特征,残留地层范围随时间不断东扩。对比各时期残留地层平面展布特征,揭示了东海陆架盆地的演变过程:三叠纪时期盆地原型为被动大陆边缘坳陷型盆地,早、中侏罗世时期为活动大陆边缘弧前盆地,晚侏罗世—晚白垩世时期为大陆边缘弧后伸展盆地;与此相对应,古太平洋板块俯冲肇始于晚三叠世—早、中侏罗世时期,板块后撤始于晚侏罗世。东海陆架盆地在中生代的东侧边界位于钓鱼岛隆褶带的东侧。  相似文献   

6.
Dredged samples have been studied to establish the stratigraphy as well as the probable paleogeographic evolution of the sedimentary cover of Galicia Bank, and Vigo and Porto Seamounts. The sedimentation appears to have been neritic up to the Late Jurassic. These structural features evolved separately from the Iberic continental margin in Late Jurassic to Early Cretaceous times. Part of the sediments is made of calpionellid limestones, which is indicative of open marine conditions in this area of the Atlantic at that time. This also suggests the establishment of marine connections between this area and the “Mésogée”. These open marine conditions would have persisted since the Early Cretaceous.  相似文献   

7.
Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S1 + S2) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin.  相似文献   

8.
Using a 2D seismic dataset that covers part of the southern Orange Basin offshore South Africa, we reconstructed the geological evolution of the basin. This evolutionary model was then used to investigate the occurrence of natural gas within the sedimentary column and the distribution of gas leakage features in relation to the observed sedimentary and tectonic structures developed in the post-rift succession since the Early Cretaceous. The Cretaceous succession has been subdivided into five seismic units. The highest sedimentation rates occur within the Barremian/Aptian (unit C1) and the Turonian/Coniacian (unit C3). Two Cenozoic units (T1 and T2) have been distinguished. These show a sudden decrease in sedimentation rate for the whole of the Cenozoic. Three phases of gravitational tectonics, with two Late Cretaceous phases of mass movement in the northern study area and Cenozoic slumping in the southern study area, have been related to sedimentation rates, sea-level changes, paleoenvironmental evolution and regional tectonics. The occurrence of natural gas leakage follows a coast-parallel distribution within the study area. In the near shore part at water depths shallower than 400 m, massive gas chimneys penetrate through the sediment layers and reach the (near-) surface. Within an intermediate narrow band, between 300 and <500 m water depth, the gas migrates more diffusely through sub-vertical faulted Cretaceous sediments, while in the outer part of the basin, through the Cretaceous and Cenozoic gravitational wedges, only very few signs of gas accumulation and migration can be seen along the faults. A conceptual model has been established with the Aptian source rock generating gas in the outer part of the basin. This source rock underlies the Cenozoic wedge in the south and the thick Cretaceous wedge in the north and is a postulated source for the natural gas within the sedimentary column. This thermogenically generated gas does not migrate directly through the gravitational faults and the above lying sediments, but moves buoyancy driven up-dip along stratigraphic layers, to escape through the sediments to the sea-floor in the inner shelf area.  相似文献   

9.
Exposed Late Cretaceous (Albian-Maastrichtian) marine rocks of the Ariyalur area in the Cauvery Basin have been extensively studied based on biostratigraphy and paleobathymetry with paleobathymetric interpretation carried out using vertical and lateral relationships of rock facies, macro- and microfossil assemblages, textural characteristics and diagenetic changes of the lithologic units. The integration of these data reveals four Transgressive-Regressive (T-R) cycles, viz. Dalmiapuram, Garudamangalam, Sillakkudi and Kallankurichchi (in stratigraphic order). These T-R cycles have been compared with global published relative sea level curves of the study area. The major sea level changes during the Late Turonian and Late Maastrichtian in the study area correlate well with global sea level changes of [Vail et?al., 1977] and [Haq et?al., 1987] and Miller et al. (2005). Based on biostratigraphy, stratal patterns and their relationship, the Late Cretaceous succession of the Ariyalur area is thus subdivided into four 2nd/3rd order sequences.  相似文献   

10.
The petroleum system of the Kunsan Basin in the Northern South Yellow Sea Basin is not well known, compared to other continental rift basins in the Yellow Sea, despite its substantial hydrocarbon potential. Restoration of two depth-converted seismic profiles across the Central Subbasin in the southern Kunsan Basin shows that extension was interrupted by inversions in the Late Oligocene-Middle Miocene that created anticlinal structures. One-dimensional basin modeling of the IIH-1Xa well suggests that hydrocarbon expulsion in the northeastern margin of the depocenter of the Central Subbasin peaked in the Early Oligocene, predating the inversions. Hydrocarbon generation at the dummy well location in the depocenter of the subbasin began in the Late Paleocene. Most source rocks in the depocenter passed the main expulsion phase except for the shallowest source rocks. Hydrocarbons generated from the depocenter are likely to have migrated southward toward the anticlinal structure and faults away from the traps along the northern and northeastern margins of the depocenter because the basin-fill strata are dipping north. Faulting that continued during the rift phase (∼ Middle Miocene) of the subbasin probably acted as conduits for the escape of hydrocarbons. Thus, the anticlinal structure and associated faults to the south of the dummy well may trap hydrocarbons that have been charged from the shallow source rocks in the depocenter since the Middle Miocene.  相似文献   

11.
The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1-47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval Tmax values in the range 438-458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene).  相似文献   

12.
Seismic reflection data indicate the Moroccan salt basin extends to the Cap Boujdour area in the Aaiun Basin. Two salt diapir structures have been identified and several areas of collapsed strata indicate probable salt removal at the shelf edge. The presence of salt in this area correlates to the conjugate southern George's Bank Basin and the Baltimore Canyon area, and it is suggested that the salt extends southward from the known salt diapir province in the George's Bank Basin southward to the Great Stone Dome. The paucity of salt diapirs is attributed to the thick carbonate and anhydrite sequence, which was deposited soon after salt deposition that inhibited halokinesis. The presence of salt along this large segment of the Atlantic margin should increase its hydrocarbon potential with traps created around salt diapirs and provision of migration pathways from deep potential source rocks in the early Cretaceous and Jurassic strata to shallower levels.  相似文献   

13.
Fault seal due to juxtaposition or the generation of low-permeability fault rock has the potential to change through time with displacement accumulation. Temporal variations in cross-fault flow of hydrocarbons have been assessed for the Cape Egmont Fault (CEF), Taranaki Basin New Zealand, using displacement backstripping, juxtaposition and Shale Gouge Ratio (SGR) analysis. The timing of hydrocarbon migration and charge of the giant Maui Gas-condensate Field across the CEF have been assessed using seismic reflection lines (2D & 3D), coherency cubes, VShale curves from the Maui-2 well and PetroMod modelling. Displacement–backstripping analysis suggests that between the Late Miocene and early Pleistocene (5.5 and 2.1 Ma) sandstone reservoir units of the Maui Field (Mangahewa, Kaimiro and Farewell Formations) and underlying source rocks (Rakopi Formation) were partly juxtaposed across the CEF with low SGRs (< 0.2) present in the fault zone. Following 2.1 Ma SGRs increased to 0.2–0.55 adjacent to the Eocene–Palaeocene reservoir succession which was not in juxtaposed contact with source rocks. PetroMod modelling using these SGR values and juxtaposition relationships supports cross-fault flow prior to 2.1 Ma with later charge across the fault being less likely. Gas chimneys and the gas–water contact in the Eocene reservoir proximal to the fault suggest that despite limited cross-fault flow, upward leakage of hydrocarbons from the reservoir occurred after 2.1 Ma, possibly associated with active fault movement or fracturing related to faulting, and may account for the loss of an early oil phase.  相似文献   

14.
The northern Mascarene Basin, lying between Madagascar and the Seychelles Plateau in the north-west Indian Ocean, is marked at its north-western end by the Amirante Arc, an enigmatic ridge-trench complex superficially resembling an island arc. Structural trends in the area have been mapped using GLORIA sidescan sonar data, seismic reflection profiles and bathymetric maps. It is concluded that the north-west Mascarene Basin was created during the Late Cretaceous by sea-floor spreading about a north-west trending spreading axis cut by northeast trending transform faults. A major transform fault between the northern tip of Madagascar and the western margin of the Seychelles Plateau is proposed as a boundary between the Late Cretaceous Mascarene basin and the older Somali Basin to the north-west. The northern segment of the Amirante Ridge may mark part of the transform. The southern segment of the Ridge and its associated trench are, however, wholly contained within the Late Cretaceous ocean floor of the Mascarene Basin, and are best explained as compressional features related to a change in sea-floor spreading geometry in the Late Cretaceous or earliest Tertiary. Two models for the evolution of the Mascarene Basin are proposed, the major differences between them being the amount of subduction at the southern Amirante Arc and the timing of the initial separation between India and the Seychelles.  相似文献   

15.
The Orange Basin records the development of the Late Jurassic to present day volcanic-rifted passive margin of Namibia. Regional extension is recorded by a Late Jurassic to Lower Cretaceous Syn-rift Megasequence, which is separated from a Cretaceous to present day post-rift Megasequence by the Late Hauterivian (ca. 130 Ma) break-up unconformity. The Late Cretaceous Post-rift evolution of the basin is characterized by episodic gravitational collapse of the margin. Gravitational collapse is recorded as a series of shale-detached gravity slide systems, consisting of an up-dip extensional domain that is linked to a down-dip zone of contraction domain along a thin basal detachment of Turonian age. The extensional domain is characterized by basinward-dipping listric faults that sole into the basal detachment. The contractional domain consists of landward-dipping listric faults and strongly asymmetric basinward-verging thrust-related folds. Growth stratal patterns suggest that the gravitational collapse of the margin was short-lived, spanning from the Coniacian (ca. 90 Ma) to the Santonian (ca. 83 Ma). Structural restorations of the main gravity-driven system show a lack of balance between up-dip extension (24 km) and down-dip shortening (16 km). Gravity sliding in the Namibian margin is interpreted to have occurred as a series of episodic short-lived gravity sliding between the Cenomanian (ca. 100 Ma) and the Campanian (ca. 80 Ma). Gravity sliding and spreading are interpreted to be the result of episodic cratonic uplift combined with differential thermal subsidence. Sliding may have also been favoured by the presence of an efficient detachment layer in Turonian source rocks.  相似文献   

16.
Extensive, large-scale pervasive cementation in the form of cement bodies within fluvial strata has rarely been documented although fluvial strata commonly act as important hydrocarbon reservoirs, as well as groundwater aquifers. Here, we present outcrop, petrographic and geochemical data for pervasive ferroan dolomite cement bodies up to 250 m in size from Upper Cretaceous Desert Member and Castlegate Sandstone fluvial strata exposed in the Book Cliffs in Utah. These cement bodies are present with coastal plain fluvial strata within both the Desert and Castlegate lowstand sandstones and are most abundant in the thin, distal fluvial strata. Cement bodies are almost entirely absent in updip, thicker, fluvial strata. Petrographic observations suggest a predominantly early diagenetic timing to the mildly ferroan dolomite, with a component of later burial origin. δ13C values for the cement (+4.8 to −5.7‰ V-PDB) suggest a marine-derived source for the earliest phase with a burial organic matter source for later cement. δ18O data (−6.3 to −11.8‰ V-PDB) suggest precipitation from freshwater dominated fluids. It is proposed here that dolomite was derived from leaching of detrital dolomite under lowstand coals and cementation took place in coastal aquifers experiencing mixed meteoric-marine fluids as a result of base-level fluctuations. This data presented here shows that large cement bodies can be an important component within fluvial sandstones with a potentially significant impact upon both reservoir quality and fluid flow within reservoirs, especially at the marine-non-marine interface.  相似文献   

17.
Organic geochemical and palynofacies studies of 172 ditch cuttings samples of possible source rock shales from the Late Cretaceous Gongila and Fika formations in the Chad Basin of NE Nigeria were carried out to determine their paleoenvironments of deposition. Although dominated by amorphous organic matter, C/S ratios and molecular parameters suggest the mostly organic lean shales (TOC contents typically below 1.5%) were deposited in a normal marine environment. Levels of oxygenation influenced by water depth in the depositional environment appear to control organic richness and quality of the dark grey shales.The organic rich (TOC > 2.0%) upper part of the Fika Formation was deposited under anoxic conditions during the Late Cretaceous and could represent an Oceanic Anoxic Event. Mature intervals where such conditions prevailed would have generated liquid hydrocarbon, although none were sampled here.A trend of increasing organic richness towards the central part of the larger Chad Basin observed in this and other studies supports the development of organic rich marine shales (average TOC contents of 2–3%) of equivalent age in the Termit Basin where water depth would have been deeper and oxygen conditions at levels that permitted preservation of marine organic matter.  相似文献   

18.
The Lower Cretaceous Knurr Sandstone deposited along the southern slope of Loppa High and overlain by the Kolje and Kolmule seals forms an attractive play in the Hammerfest Basin of the Barents Sea. Late Jurassic organic-rich Hekkingen shale directly underlies the Knurr Sandstone and acts as a source to provide effective charge. Three wells, 7120/2-2, 7122/2-1 and 7120/1-2, have proven the Knurr-Kolje play in structural traps, with an oil discovery in 7120/1-2. Prospectivity related to stratigraphic traps is, however, highly under-explored.In order to document and map the reservoir distribution and stratigraphic-trap fairway, the Lower Cretaceous sedimentary package containing the Knurr Sandstone is divided into a number of depositional sequences and systems tracts using key regional seismic profiles calibrated with logs. Mapping of the key surfaces bounding the Knurr sandstone has been carried out using all the seismic vintages available from Norwegian Petroleum Directorate (NPD).The thick massive nature of the sandstone (123 m in well 7122/2-1), sedimentary features characteristic of gravity flow deposits, high-resolution internal seismic reflections and stratal geometries (truncations and lapout patterns), and sequence stratigraphic position of the Knurr Sandstone on seismic profiles confirm that the lobes identified on the seismic section are gravity driven base of the slope lobes. These Knurr lobes and slope aprons were formed as a result of uplift of the Loppa paleo-high in the Late Jurassic to Early Cretaceous times which caused subaerial exposure and incision. The characteristic mounded, lobate geometry evident on the seismic can be mapped along the toe-of-slope and records multiple stacked lobes fed by multiple feeder canyons. Lateral partitioning and separation of the lobes along the toe-of-slope could potentially create stratigraphic traps. The existing 2D seismic coverage is, however, not sufficient to capture lateral stratigraphic heterogeneity to identify stratigraphic traps. 3D seismic coverage with optimum acquisition parameters (high spatial and vertical resolution, appropriate seismic frequency and fold, long offsets and original amplitudes preserved) can allow for the reconstruction of 3D geomorphologic elements to de-risk potential stratigraphic traps prior to exploratory drilling.  相似文献   

19.
The Manihiki Plateau is an elevated oceanic volcanic plateau that was formed mostly in Early Cretaceous time by hotspot activity. We analyze new seismic reflection data acquired on cruise KIWI 12 over the High Plateau region in the southeast of the plateau, to look for direct evidence of the location of the heat source and the timing of uplift, subsidence and faulting. These data are correlated with previous seismic reflection lines from cruise CATO 3, and with the results at DSDP Site 317 at the northern edge of the High Plateau. Seven key reflectors are identified from the seismic reflection profiles and the resulting isopach maps show local variations in thickness in the southeastern part of the High Plateau, suggesting a subsidence (cooling) event in this region during Late Cretaceous and up to Early Eocene time. We model this as a hotspot, active and centered on the High Plateau area during Early Cretaceous time in a near-ridge environment. The basement and Early Cretaceous volcaniclastic layers were formed by subaerial and shallow-water eruption due to the volcanic activity. After that, the plateau experienced erosion. The cessation of hotspot activity and subsequent heat loss by Late Cretaceous time caused the plateau to subside rapidly. The eastern and southern portions of the High Plateau were rifted away following the cessation of hot spot activity. As the southeastern portion of the High Plateau was originally higher and above the calcium carbonate compensation depth, it accumulated more sediments than the surrounding plateau regions. Apparently coeval with the rapid subsidence of the plateau are normal faults found at the SE edge of the plateau. Since Early Eocene time, the plateau subsided to its present depth without significant deformation.  相似文献   

20.
In the Chelif basin, the geochemical characterization reveals that the Upper Cretaceous and Messinian shales have a high generation potential. The former exhibits fair to good TOC values ranging from 0.5 to 1.2% with a max. of 7%. The Messinian series show TOC values comprised between 0.5 and 2.3% and a high hydrogen index (HI) with values up to 566 mg HC/g TOC. Based on petroleum geochemistry (CPLC and CPGC) technics, the oil-to source correlation shows that the oil of the Tliouanet field display the same signature as extracts from the Upper Cretaceous source rocks (Cenomanian to Campanian). In contrast, oil from the Ain Zeft field contains oleanane, and could thus have been sourced by the Messinian black shale or older Cenozoic series. Two petroleum systems are distinguished: Cretaceous (source rock) – middle to upper Miocene (reservoirs) and Messinian (source rock)/Messinian (reservoirs). Overall, the distribution of Cretaceous-sourced oil in the south, directly connected with the surface trace of the main border fault of the Neogene pull-apart basin, rather suggests a dismigration from deeper reservoirs located in the parautochthonous subthrust units or in the underthrust foreland, rather than from the Tellian allochthon itself (the latter being mainly made up of tectonic mélange at the base, reworking blocks and slivers of Upper Cretaceous black shale and Lower Miocene clastics). Conversely, the occurrence of Cenozoic-sourced oils in the north suggests that the Neogene depocenters of the Chelif thrust-top pull-apart basin reached locally the oil window, and therefore account for a local oil kitchen zone. In spite of their limited extension, allochthonous Upper cretaceous Tellian formations still conceal potential source rock layers, particularly around the Dahra Mountains and the Tliouanet field. Additionally they are also recognized by the W11 well in the western part of the basin (Tahamda). The results of the thermal modelling of the same well shows that there is generation and migration of oil from this source rock level even at recent times (since 8 Ma), coevally with the Plio-Quaternary traps formation. Therefore, there is a possibility of an in-situ oil migration and accumulation, even from Tellian Cretaceous units, to the recent structures, like in the Sedra structure. However, the oil remigration from deep early accumulations into the Miocene reservoirs is the most favourable case in terms of hydrocarbon potential of the Chelif basin.  相似文献   

设为首页 | 免责声明 | 关于勤云 | 加入收藏

Copyright©北京勤云科技发展有限公司  京ICP备09084417号