A basin modeling and organic geochemistry study in the Vallecitos syncline,San Joaquin Basin,California

The Vallecitos syncline is a westerly structural extension of the San Joaquin Basin. The Vallecitos oil field, comprised of eight separate areas that produce from Cretaceous and Paleogene reservoirs, accounted for 5.4 MMB of oil and 5.6 BCF associated of gas through 2010. However, exploration for oil and gas in the Vallecitos area is challenging due to structural complexity and limited data. The purpose of this study is to evaluate whether source rocks are actively generating petroleum in the Vallecitos syncline and to improve our understanding of burial history and timing of hydrocarbon generation. We conducted biomarker analysis on twenty-two oil samples from the Vallecitos syncline. Source-related biomarkers show two genetic groups of oil, which originated from two different source rocks. These results differ from earlier published interpretations in which the Kreyenhagen Formation is the only source rock in the Vallecitos syncline, and suggest that the Cretaceous Moreno Formation in the syncline also is an active source rock.Stratigraphic evidence and modeling suggest that late Cenozoic episodes of erosion due to folding and uplift removed significant overburden on the flanks of the syncline. To better understand the petroleum systems and clarify the total active source rocks in the area, 2D burial histories were generated through the Vallecitos syncline. A published cross-section through the deepest part of the syncline was selected to conduct thermal history, basin evolution, and migration analyses. The 2D model results indicate that the lower Kreyenhagen Formation has various maturities within the formation at different locations in the present-day syncline. The basal part of the Kreyenhagen Formation is in the dry gas window and maturity decreases away from the central part to the flanks. It remains immature along shallow portions of the present-day flanks. In contrast, the basal part of the Moreno Formation achieved extremely high maturity (past the gas generation zone) but is in the oil generation zone on the flanks of the syncline at shallow depth. All of our geochemical and 2D model results suggest that there are two active source rocks in the Vallecitos syncline. Accordingly, we propose that there are two active petroleum systems in the Vallecitos syncline.     

Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt

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 T_max 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).     

Beef veins and thrust detachments in Early Cretaceous source rocks,foothills of Magallanes-Austral Basin,southern Chile and Argentina: Structural evidence for fluid overpressure during hydrocarbon maturation

We describe (1) bedding-parallel veins of fibrous calcite (beef) and (2) thrust detachments, which we believe provide good evidence for fluid overpressure in source rocks for petroleum. Our examples are from the surface or subsurface of the Magallanes-Austral Basin, which lies at the southern tip of South America. There, the best source rocks for petroleum are of Early Cretaceous age. In the central parts of the basin these source rocks have become overmature, but at the eastern edge, onshore and offshore, they are today either immature or in the oil window.In Tierra del Fuego, the foothills of the Andes consist mainly of sedimentary rocks, which have undergone thin-skinned thrusting. In the Vicuña area (Chile), Early Cretaceous source rocks have reached the surface above thrust detachments, which are visible on seismic data and well data. At the surface, we have found calcite beef, containing hydrocarbons (solid and/or fluid), in the Rio Jackson and Vicuña formations, which have reached the wet gas window. In the Rio Gallegos area (Argentina), the source rocks have not reached the surface, but seismic and well data provide good evidence for thin-skinned thrusting above flat-lying detachments in Early Cretaceous source rock, where it is in the early oil window. In contrast, there is little or no deformation where the source rock is still immature. Thus the deformation front coincides with the maturity front. Next to the central parts of the basin, where the source rocks have reached the surface within the Andes proper, they have undergone low-grade metamorphism. Within these source rocks, we have found beef veins, but of quartz, not calcite. To the east, within the foreland basin, seismic and well data provide evidence for a few compressional structures, including thin-skinned detachments in the deeply buried source rock. Finally, in the northern part of the basin (Santa Cruz province, Argentina), where it is shallower, the source rocks have reached the surface in the foothills, above a series of back-thrusts. At Lago San Martín, the source rocks have reached the oil window and they again contain calcite beef.In conclusion, where we have examined Early Cretaceous source rocks at the surface, they contain either calcite beef (if they have reached the late oil window or wet gas window) or quartz beef (if they are overmature). Independent evidence for overpressure, in the form of source-rock detachments, comes from subsurface data, especially at the southern end of the basin, where the source rocks are not overmature and deformation is relatively intense. Thus we argue that hydrocarbon generation has led to overpressure, as a result of chemical compaction and load transfer, or volume changes, or both.     

Source rocks and related petroleum systems of the Chelif Basin, (western Tellian domain,north Algeria)

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.     

鄂尔多斯盆地塔巴庙地区上古生界源岩热演化特征

鄂尔多斯盆地北部主力气源岩太原组、山西组煤系地层热成熟史的研究对本区天然气充注过程和有利目标区预测具有重要的参考价值。在对研究区烃源岩评价和一维、二维地质建模研究的基础上。利用BasinMod盆地模拟软件对单井以及研究区内二维剖面、平面进行了煤系烃源岩热演化史模拟研究。研究结果表明：（1）该区在中三叠世进入生烃门限,中侏罗世以后,烃源岩持续埋深,早白垩世末期至最大埋深（4000m左右）,绝大多数的天然气都在这一阶段生成,早白垩世末构造抬升以后只有少量天然气生成;（2）研究区上古生界太原组和山西组煤系源岩最大累积生烃强度可达到2200×10^8m^3／km^2,对现今天然气的分布具有较强的控制作用。     

Petroleum generation and charge history of the northern Dongying Depression,Bohai Bay Basin,China: Insight from integrated fluid inclusion analysis and basin modelling

The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% R_o at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% R_o at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation.Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation.     

Petroleum geochemistry of the Kimmeridge Clay of onshore Southern and Eastern England

The Kimmeridge Clay is considered a major oil source rock for the North Sea hydrocarbon province. The formation is also developed onshore in an organic-rich mudstone facies. This paper examines the possibility of onshore oil generation from the Kimmeridge Clay. Geochemically, onshore basin margin sediments contain rich, potential source horizons with mainly Type l/Type ll oil-prone kerogen, but are immature. Some deeper Cleveland Basin sediments have reached marginal maturity. Burial history reconstruction suggests significant formation palaeoburial depths in central areas of the Cleveland and Wessex Basins. Computed vitrinite isoreflectance contours show the Wealden and Isle of Wight Kimmeridge Clay to be thermally mature. Basin modelling suggests an early Palaeogene onset of oil generation in parts of the Cleveland Basin, while maximum oil generation could have been reached by the formation base in the Isle of Wight area during the late Cretaceous. Although basin subsidence ceased in the Neogene, in the Weald and Isle of Wight, where the formation is still deeply buried, oil generation probably continued for some time during uplift. Thus significant quantities of oil could have been generated. Whether or not this oil is present today however, would depend on the correct timing of suitable migration and trap structures.     

Thermal maturity history and petroleum generation modelling for the Lower Cretaceous Abu Gabra Formation in the Fula Sub-basin,Muglad Basin,Sudan

Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation.     

Petroleum source rock characterisation and hydrocarbon generation modeling of the Cretaceous sediments in the Jiza sub-basin,eastern Yemen

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.     

马来盆地前I群油气成藏条件及富集规律

马来盆地前I群(即J、K、L、M群,渐新统—下中新统)具有良好的油气成藏条件:①发育多期有利于成藏的构造运动:前中新世伸展断裂阶段,湖相烃源岩大量发育;早、中中新世构造沉降阶段,并伴随盆地反转,形成前I群油气系统的储盖系统;②烃源岩优越:烃源岩为湖相富含藻类的页岩,成熟度较高,有机质含量较高;③储集层丰富:K群储集层为辫状河砂岩,J群储集层为河口湾河道砂岩和潮间砂岩;④盖层良好:主要盖层为盆地海侵期沉积的前J群三角洲—浅海相泥岩,次要盖层为K、L和M群内的湖泊相泥岩;⑤油气运移通道畅通:上倾侧向运移为主;⑥有利的生储盖组合:自生自储和下生上储的组合方式有利于油气藏的形成。前I群油气系统位于马来盆地的东南部,以生油为主。分析认为盆地的油气分布主要受烃源岩的分布、质量和成熟度以及构造圈闭形成的相对时间和油气运移方式的控制。     

Hydrocarbon systems of Northeastern Venezuela: plate through molecular scale-analysis of the genesis and evolution of the Eastern Venezuela Basin

The prolific, oil-bearing basins of eastern Venezuela developed through an unusual confluence of Atlantic, Caribbean and Pacific plate tectonic events. Mesozoic rifting and passive margin development created ideal conditions for the deposition of world-class hydrocarbon source rocks. In the Cenozoic, transpressive, west-to-east movement of the Caribbean plate along the northern margin of Venezuela led to the maturation of those source rocks in several extended pulses, directly attributable to regional tectonic events. The combination of these elements with well-developed structural and stratigraphic fairways resulted in remarkably efficient migration of large volumes of oil and gas, which accumulated along the flanks of thick sedimentary depocenters.At least four proven and potential hydrocarbon source rocks contribute to oil and gas accumulations. Cretaceous oil-prone, marine source rocks, and Miocene oil- and gas-prone, paralic source rocks are well documented. We used reservoired oils, seeps, organic-rich rocks, and fluid inclusions to identify probable Jurassic hypersaline-lacustrine, and Albian carbonate source rocks. Hydrocarbon maturation began during the Early Miocene in the present-day Serrania del Interior, as the Caribbean plate moved eastward relative to South America. Large volumes of hydrocarbons expelled during this period were lost due to lack of effective traps and seals. By the Middle Miocene, however, when source rocks from the more recent foredeeps began to mature, reservoir, migration pathways, and topseal were in place. Rapid, tectonically driven burial created the opportunity for unusually efficient migration and trapping of these later-expelled hydrocarbons. The generally eastward migration of broad depocenters across Venezuela was supplemented by local, tectonically induced subsidence. These subsidence patterns and later migration resulted in the mixing of hydrocarbons from different source rocks, and in a complex map pattern of variable oil quality that was further modified by biodegradation, late gas migration, water washing, and subsequent burial.The integration of plate tectonic reconstructions with the history of source rock deposition and maturation provides significant insights into the genesis, evolution, alteration, and demise of Eastern Venezuela hydrocarbon systems. We used this analysis to identify additional play potential associated with probable Jurassic and Albian hydrocarbon source rocks, often overlooked in discussions of Venezuela. The results suggest that oils associated with likely Jurassic source rocks originated in restricted, rift-controlled depressions lying at high angles to the eventual margins of the South Atlantic, and that Albian oils are likely related to carbonate deposition along these margins, post-continental break up. In terms of tectonic history, the inferred Mesozoic rift system is the eastern continuation of the Espino Graben, whose remnant structures underlie both the Serrania del Interior and the Gulf of Paria, where thick evaporite sections have been penetrated. The pattern of basin structure and associated Mesozoic deposition as depicted in the model has important implications for the Mesozoic paleogeography of northern South America and Africa, Cuba and the Yucatan and associated new play potential.     

构造生烃

生烃是岩石中所含的有机质产生流体有机化合物的化学反应。岩石有机质化学反应存在两种系统：封闭系统和开放系统,随着埋深加大,烃源岩越来越致密,岩石的化学反应逐渐由开放系统转变为封闭系统。目前的生烃理论仅仅是开放系统下烃源岩成熟与生烃理论,烃源岩成熟与生烃是不匹配的。封闭系统下烃源岩成熟与生烃是不匹配的,烃源岩成熟但不生烃,而是形成另外一种成熟的固体有机质。大多数情况是烃源岩为半封闭系统,烃源岩处于欠生烃状态。构造运动形成的断层和裂隙将烃源岩与疏导层沟通,烃源岩迅速由封闭、半封闭系统转变为开放系统。这种生烃系统的转变形成短时间内过量生烃,笔者将这种生烃作用命名为构造生烃,意味着构造运动期即为主生烃期,伴随着多次构造运动可以形成多个幕式生烃高峰。构造生烃理论开拓两个极其重要的勘探领域：第一,新构造勘探。以往认为已经过了生、排烃期的构造得以解放,如渤海湾郯庐断裂带第四纪圈闭不是过了主生烃期,而是正处于构造生烃的过生烃高峰期。以PL19-3为代表的油气运聚强度只有构造生烃能够解释;第二,超深勘探,特别是天然气勘探。深层勘探的下限将大大延伸,生烃门限,特别是生气门限将大大加深,仅生烃而言万米都不是天然气勘探的极限。     

A new Carboniferous coal/shale driven gas play in the Western Black Sea Region (Turkey)

The sedimentary sequence in the Western Black Sea region of Turkey both onshore and offshore offers many possibilities for different hydrocarbon plays. This study presents a new play, which considers Carboniferous coals and shales as source beds, Cretaceous sandstones as reservoirs and Cretaceous shales and marls as seal rocks. The evaluation of this play is performed using the petroleum system approach. Results suggest that the coals and shales have a good to very good source rock potential for gas, that the Cretaceous synrift sandstones are good reservoirs. On the other hand, the sealing efficiency of respective Cretaceous units is assumed to be sufficient based on their lithological (shales and carbonaceous marls) characteristics. Stratigraphic traps, which formed by transgression and by onlap on paleohighs, were sealed and potentially available at 97 million years (ma) before present. Structural traps related to Early Cretaceous extension were also sealed around 97 ma. On the contrary, traps formed by folding and thrusting during the Alpine orogeny only formed during the last 50 ma. The timing of gas generation and migration was determined by one and two-dimensional basin modeling in one well and along a cross-section. The modeling results indicated that during the period between 90 and 42 ma, large volumes of gas were generated from the Carboniferous source rocks. Comparison with the age of stratigraphic and structural traps showed that stratigraphic and normal fault traps were potentially available for the entire volume of generated gas and that the other structural traps associated with Alpine orogeny were available only for gas generated and/or re-migrated during the last 50 ma. The evaluation of this new play results in the conclusion, that the Western Black Sea region is worthy of further exploration for conventional accumulations of thermogenic gas.     

Source rock characteristics and hydrocarbon generation modelling of Upper Cretaceous Mukalla Formation in the Jiza-Qamar Basin,Eastern Yemen

The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis T_max in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S₂) pyrograms with n-alkane/alkene doublets extending beyond nC₃₀. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m² to 70.0 mW/m² and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m² at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day.     

二次生烃机理在中下扬子高演化烃源岩评价中的应用

在野外地质观察、油气地球化学和样品分析的基础上,通过总结二次生烃特征和生烃机理,将其应用到中下扬子区海相高演化烃源岩生烃潜力的评价。模拟实验结果表明,二次生烃具有明显的迟缓现象,也仍具有相对的生烃高峰,二次生烃量与一次生烃量的总和小于连续热演化的生烃量,这些特征都与一次生烃的演化程度密切相关,初始演化程度成为评价高演化烃源岩二次生烃潜力的关键因素。中下扬子区中—古生界发育的6套烃源岩中,下二叠统、下志留统和下寒武统烃源岩具有较强的生烃能力,是主要的烃源层。下古生界烃源岩进入生烃时间较早,在强烈的构造运动背景下,生成的油气难以保存;上古生界烃源岩热演化程度相对较低,燕山—喜山期的再次沉降地区成为二次生烃的供源区。因此,下古生界台地相区和上古生界烃源岩具有一定的二次生烃潜力。     

松辽盆地登娄库—永安地区油气成藏模式研究

在已了解的松辽盆地登娄库—永安地区构造和沉积演化特点的基础上,利用现有钻井的岩心资料、测井资料和地震资料,对该地区的成藏模式特征从运移方式和生储盖空间组合两个方面上进行了研究和分类,分析了各自形成的主控因素.研究表明,该区域地层具有断坳双层结构,按油气运移类型划分,在断陷期主要发育两种油气成藏模式,分别为原生油气成藏模式和次生油气成藏模式;在坳陷期主要发育次生油气成藏模式和混生油气藏.从储层与烃源岩的空间组合上来看,区域内主要发育有上生下储、下生上储和自生自储这三种油气成藏模式.形成这些不同成藏模式的主要因素是该区深至基底的大型断裂构造和继承性断裂、反转构造以及固有沉积环境等.     

Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands,Arctic Russia

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.     

民和盆地侏罗系生烃潜力与油气勘探方向

从有机碳含量、可溶有机质含量及其转化率、热解参数、饱和烃的生物表示化合物特征、有机岩石学特征几个方面分析了民和盆地侏罗系烃源岩的有机质丰度、类型和成熟度,并进行了地球化学特征分析和生烃潜力评价。分析认为盆地发育湖相泥岩和煤系两大类烃源岩,有机质以较富含低等水生生物原始母质的腐泥腐殖型为主,主要分布于中侏罗统。通过对盆地石油地质条件的评价,结合各区带落实认识程度和资料品质条件认为：武家鼻隆构造带是最有利的勘探区带,万泉堡鼻状构造带具有良好勘探潜力,大庄构造带是寻找浅层次生油气藏的有利区带。永登凹陷面积大,资源丰富,勘探认识程度低,具有良好勘探前景。     

Black shales in Ukraine – A review

As a result of a long-lasting and complex geological history, organic-matter-rich fine-grained rocks (black shales) with widely varying ages can be found on Ukrainian territory. Several of them are proven hydrocarbon source rocks and may hold a significant shale gas potential.Thick Silurian black shales accumulated along the western margin of the East European Craton in a foreland-type basin. By analogy with coeval organic-matter-rich rocks in Poland, high TOC contents and gas window maturity can be expected. However, to date information on organic richness is largely missing and maturity patterns remain to be refined.Visean black shales with TOC contents as high as 8% and a Type III-II kerogen accumulated along the axis of the Dniepr-Donets rift basin (DDB). They are the likely source for conventional oil and gas. Oil-prone Serpukhovian black shales accumulated in the shallow northwestern part of the DDB. Similar black shales probably may be present in the Lviv-Volyn Basin (western Ukraine).Middle Jurassic black shales up to 500 m thick occur beneath the Carpathian Foredeep. They are the likely source for some heavy oil deposits. TOC contents up to 12% (Type II) have been recorded, but additional investigations are needed to study the vertical and lateral variability of organic matter richness and maturity.Lower Cretaceous black shales with a Type III(-II) kerogen (TOC > 2%) are widespread at the base of the Carpathian flysch nappes, but Oligocene black shales (Menilite Fm.) rich in organic matter (4–8% TOC) and containing a Type II kerogen are the main source rock for oil in the Carpathians. Their thermal maturity increases from the external to the internal nappes.Oligocene black shales are also present in Crimea (Maykop Fm.). These rocks typically contain high TOC contents, but data from Ukraine are missing.     

Oil-oil and oil-source rock correlations in the Alpine Foreland Basin of Austria: Insights from biomarker and stable carbon isotope studies

The Alpine Foreland Basin is a minor oil and moderate gas province in central Europe. In the Austrian part of the Alpine Foreland Basin, oil and minor thermal gas are thought to be predominantly sourced from Lower Oligocene horizons (Schöneck and Eggerding formations). The source rocks are immature where the oil fields are located and enter the oil window at ca. 4 km depth beneath the Alpine nappes indicating long-distance lateral migration. Most important reservoirs are Upper Cretaceous and Eocene basal sandstones.Stable carbon isotope and biomarker ratios of oils from different reservoirs indicate compositional trends in W-E direction which reflect differences in source, depositional environment (facies), and maturity of potential source rocks. Thermal maturity parameters from oils of different fields are only in the western part consistent with northward displacement of immature oils by subsequently generated oils. In the eastern part of the basin different migration pathways must be assumed. The trend in S/(S + R) isomerisation of ααα-C₂₉ steranes versus the αββ (20R)/ααα (20R) C₂₉ steranes ratio from oil samples can be explained by differences in thermal maturation without involving long-distance migration. The results argue for hydrocarbon migration through highly permeable carrier beds or open faults rather than relatively short migration distances from the source. The lateral distance of oil fields to the position of mature source rocks beneath the Alpine nappes in the south suggests minimum migration distances between less than 20 km and more than 50 km.Biomarker compositions of the oils suggest Oligocene shaly to marly successions (i.e. Schoeneck, Dynow, and Eggerding formations) as potential source rocks, taking into account their immature character. Best matches are obtained between the oils and units a/b (marly shale) and c (black shale) of the “normal” Schöneck Formation, as well as with the so-called “Oberhofen Facies”. Results from open system pyrolysis-gas chromatography of potential source rocks indicate slightly higher sulphur content of the resulting pyrolysate from unit b. The enhanced dibenzothiophene/phenanthrene ratios of oils from the western part of the basin would be consistent with a higher contribution of unit b to hydrocarbon expulsion in this area. Differences in the relative contribution of sedimentary units to oil generation are inherited from thickness variations of respective units in the overthrusted sediments. The observed trend towards lighter δ¹³C values of hydrocarbon fractions from oil fields in a W-E direction are consistent with lower δ¹³C values of organic matter in unit c.