Characteristics and origin of carbon isotopes of n-alkanes in crude oils from the western Pearl River Mouth Basin,South China sea

The quantitative characterization of carbon isotopes of n-alkanes is commonly carried out in organic geochemical studies. Possible controls on carbon isotopes include source organic matter, maturity, fractionation during oil expulsion and migration, and the mixing of different oils. In this study of the origin of crude oils in the western Pearl River Mouth Basin, the influences of all of these factors have been considered in reaching a conclusion. Carbon isotopes of n-alkanes in the crude oils, and the extracts of the two effective source rocks (the Wenchang and Enping formations) in the basin, exhibit clear differences. The Wenchang source rocks have heavy δ¹³C values that remain almost constant or become slightly heavier with increasing carbon number. The Enping source rocks have light δ¹³C values that become lighter with increasing carbon number. Two groups of oils in this area were identified based on the carbon isotopes of the n-alkanes; groupIoils are similar to extracts of the Wenchang source rocks. However, the groupIIoils are different from both the Wenchang and Enping source rocks and the carbon isotopic profiles of their n-alkanes exhibit a “V” feature with increasing carbon number. The results of artificial thermal maturation experiments indicate that, from the early stage to the peak stage of oil generation (with EasyRo between 0.64% and 1.02%), the δ¹³C values of n-alkanes in the pyrolysis oils become heavier by about 3‰ with increasing thermal maturity, but the shape of the carbon isotopic profiles are not significantly changed. Calculated δ¹³C values of n-alkanes in “mixed” artificial pyrolysis oils indicate that the mixture of oils generated from the same source rocks with different maturities could not change the carbon isotopic profile of the n-alkanes, however, a mixing of the Wenchang and Enping oils could give the “V” feature in the profiles, similar to the groupIIoils in this area. The groupIIoils appear to be mixed Wenchang and Enping oils, the latter being the dominant component in the mixture. We conclude that the source organic matter and the degree of mixing are the main factors controlling the carbon isotopic characteristics of n-alkanes in crude oils in the western Pearl River Mouth Basin.     

Inorganic geochemical evaluation of hydrocarbon source rock potential of Neoproterozoic strata in the Amadeus Basin,Australia

The Neoproterozoic sedimentary succession of the Amadeus Basin, Central Australia, includes potential hydrocarbon source and reservoir rocks with maturity indicators in the oil to dry-gas window. However, petroleum well distribution across the basin is sparse and a general lack of organic geochemical data encourages the use of whole-rock inorganic geochemistry and mineralogy as proxy for the evaluation of the hydrocarbon-generating potential. The present study provides a detailed investigation of the geochemistry and mineralogy of the majority of Neoproterozoic strata across the Amadeus Basin and suggests that the Pertatataka and Aralka formations are the most favourable potential source rocks. A decreasing K/Rb ratio in these units is interpreted as higher degree of illitisation and therefore increased maturity. Sulphide versus sulphate abundance show that the Pertatataka and Aralka formations are the only units of significant stratigraphic thickness deposited under dominantly anoxic conditions. However, low concentrations of the redox-sensitive trace elements Mo, U and V, and low organic matter abundance suggest that these units were deposited under anoxic-ferruginous, not anoxic-sulphidic (euxinic) conditions. We interpret this to reflect an overall low hydrocarbon-generating potential. The present study highlights the benefit of using a multi-proxy approach for large-scale evaluation of the hydrocarbon potential in sedimentary successions, especially when organic geochemical data are sparse.     

Enrichment and distribution of shale oil in the Cretaceous Qingshankou Formation,Songliao Basin,Northeast China

The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K₂qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K₂qn¹), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (T_max) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K₂qn¹ shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K₂qn¹ shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin.     

Comparative petroleum systems analysis of the interior basins of Turkey: Implications for petroleum potential

The interior basins of Turkey remain effectively unexplored and their petroleum systems are poorly understood. This paper presents a comparative summary of the geological evolution, petroleum potential and prospectivity of the Central (Tuz Gölü, Sivas and Çankırı) and East Anatolian (Muş-Hınıs, Pasinler-Horasan and Tercan-Aşkale) basins using geological, seismic, geochemical and petrophysical data, and a series of quantitative basin models. The studied basins are ranked on the basis of source effectiveness, reservoir quality, seal efficiency, and the timing of hydrocarbon expulsion and migration relative to trap formation. A qualitative risk assessment, based on the elements of the petroleum system, is used to evaluate the likelihood of hydrocarbon discovery in each of the basins. This study shows that the chance of hydrocarbon discovery in the East Anatolian basins is unlikely-very unlikely and Tuz Gölü, Sivas and Çankırı basins are equally likely/unlikely-unlikely, likely and unlikely, respectively. Heavy oil and minor gas associated with two mature petroleum systems were discovered in the Tuz Gölü basin. Various trap forming mechanisms such as salt tectonics and Middle Eocene compression, accompanied by the effective sealing capacity of the Eocene evaporites favor the hydrocarbon exploration potential of the Tuz Gölü basin. The highest exploration risk in the Tuz Gölü basin arises from the poor quality sandstone reservoirs. The biggest risk factor in the Eastern Anatolian basins is insufficient thermal maturity, despite the presence of good quality source rocks. The Sivas basin is one of the most promising interior basins of Turkey due to the presence of multiple mature petroleum systems and high quality reservoirs. There is a high chance of accumulation of multi-phase hydrocarbons in the Eocene and Miocene traps. The major problem in the Sivas basin is the lack of an efficient seal rock. The Çankırı basin contains all of the necessary elements of an ideal petroleum system except the presence of an organic-rich source rock. Thus, the chance of hydrocarbon discovery in the Çankırı basin is low.     

Organic geochemistry of the Silurian Tanezzuft Formation and crude oils,NC115 Concession,Murzuq Basin,southwest Libya

Thirty-six Silurian core and cuttings samples and 10 crude oil samples from Ordovician reservoirs in the NC115 Concession, Murzuq Basin, southwest Libya were studied by organic geochemical methods to determine source rock organic facies, conditions of deposition, thermal maturity and genetic relationships. The Lower Silurian Hot Shale at the base of the Tanezzuft Formation is a high-quality oil/gas-prone source rock that is currently within the early oil maturity window. The overall average TOC content of the Hot Shale is 7.2 wt% with a maximum recorded value of 20.9 wt%. By contrast, the overlying deposits of the Tanezzuft Formation have an average TOC of 0.6 wt% and a maximum value of 1.1 wt%. The organic matter in the Hot Shale consists predominantly of mixed algal and terrigenous Type-II/III kerogen, whereas the rest of the formation is dominated by terrigenous Type-III organic matter with some Type II/III kerogen. Oils from the A-, B- and H-oil fields in the NC115 Concession were almost certainly derived from marine shale source rocks that contained mixed algal and terrigenous organic input reflecting deposition under suboxic to anoxic conditions. The oils are light and sweet, and despite being similar, were almost certainly derived from different facies and maturation levels within mature source rocks. The B-oils were generated from slightly less mature source rocks than the others. Based on hierarchical cluster analysis (HCA), principal component analysis (PCA), selected source-related biomarkers and stable carbon isotope ratios, the NC115 oils can be divided into two genetic families: Family-I oils from Ordovician Mamuniyat reservoirs were probably derived from older Palaeozoic source rocks, whereas Family-II oils from Ordovician Mamuniyat–Hawaz reservoirs were probably charged from a younger Palaeozoic source of relatively high maturity. A third family appears to be a mixture of the two, but is most similar to Family-II oils. These oil families were derived from one proven mature source rock, the Early Silurian, Rhuddanian Hot Shale. There is a good correlation between the Family-II and -III oils and the Hot Shale based on carbon isotope compositions. Saturated and aromatic maturity parameters indicate that these oils were generated from a source rock of considerably higher maturity than the examined rock samples. The results imply that the oils originated from more mature source rocks outside the NC115 Concession and migrated to their current positions after generation.     

Mantle plumes and the metamorphism of the lower crust and their influence on basin evolution

Since the stretching model appears to be not applicable to the subsidence of accretionary crust, basins located on this crust type may have an alternative origin. Examples of such basins are the West Siberia Basin and the North German Basin. Both basins showed intensive volcanism and magmatism during the initial phase of their development. Remarkably, the West Siberia Basin is closely located to the (hotspot related) Siberian flood basalts with a similar Permo-Triassic age, and the location of the North German Basin in Permian times is identical with the present day position of the Tibesti hotspot in Northern Africa. These two basins may have specific relations to hotspot heat sources of the Earth's underlying mantle. Due to these heat sources, thermal metamorphism within the lower layers of the (accretionary) crust may occur, resulting in rock density increase and subsequent shrinkage of the affected rock volumes. These shrinkage processes will lead to the development of topographic lows, their filling with sediments, and the subsequent start of an exponentially declining isostatic/metamorphic basin subsidence. In addition to the analyses of metamorphic processes, potential field anomalies, temperature fields, and histories of subsidence have been integrated into one single model that can explain the development of the North German Basin. Similarly, the East African Rift and Eifel Hotspots affected parts of the overriding continental plates. The East African Rift Hotspot can be traced back to the Afar flood basalts and the Dniepr–Donets Basin, whereas the Eifel Hotspot can be linked to the North Sea Basin. Continental drift templates, present day hotspot locations, flood basalt areas, metamorphic facies as function of temperature, and crust categories are taken as published in recent literature.     

The basins of Sundaland (SE Asia): Evolution and boundary conditions

Most of the basins developed in the continental core of SE Asia (Sundaland) evolved since the Late Cretaceous in a manner that may be correlated to the conditions of the subduction in the Sunda Trench. By the end of Mesozoic times Sundaland was an elevated area composed of granite and metamorphic basement on the rims; which suffered collapse and incipient extension, whereas the central part was stable. This promontory was surrounded by a large subduction zone, except in the north and was a free boundary in the Early Cenozoic. Starting from the Palaeogene and following fractures initiated during the India Eurasia collision, rifting began along large faults (mostly N–S and NNW–SSE strike-slip), which crosscut the whole region. The basins remained in a continental fluvio-lacustrine or shallow marine environment for a long time and some are marked by extremely stretched crust (Phu Khanh, Natuna, N. Makassar) or even reached the ocean floor spreading stage (Celebes, Flores). Western Sundaland was a combination of basin opening and strike-slip transpressional deformation. The configuration suggests a free boundary particularly to the east (trench pull associated with the Proto-South China Sea subduction; Java–Sulawesi trench subduction rollback). In the Early Miocene, Australian blocks reached the Sunda subduction zone and imposed local shortening in the south and southeast, whereas the western part was free from compression after the Indian continent had moved away to the north. This suggests an important coupling of the Sunda Plate with the Indo-Australian Plate both to SE and NW, possibly further west rollback had ceased in the Java–Sumatra subduction zone, and compressional stress was being transferred northwards across the plate boundary. The internal compression is expressed to the south by shortening which is transmitted as far as the Malay basin. In the Late Miocene, most of the Sunda Plate was under compression, except the tectonically isolated Andaman Sea and the Damar basins. In the Pliocene, collision north of Australia propagated toward the north and west causing subduction reversal and compression in the short-lived Damar Basin. Docking of the Philippine Plate confined the eastern side of Sundaland and created local compression and uplift such as in NW Borneo, Palawan and Taiwan. Transpressional deformation created extensive folding, strike-slip faulting and uplift of the Central Basin and Arakan Yoma in Myanmar. Minor inversion affected many Thailand rift basins. All the other basins record subsidence. The uplift is responsible for gravity tectonics where thick sediments were accumulated (Sarawak, NE Luconia, Bangladesh wedge).     

Evolution of the western Barents Sea

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.     

Hydrocarbon potential of the Zechstein Main Dolomite in the western part of the Wielkopolska platform,SW Poland: New sedimentological and geochemical data

The results of identification of facies and microfacies of highstand systems tract (HST) deposits in the Zechstein Main Dolomite (Ca2) are presented followed by a critical analysis of the existing views on the paleogeography and facies architecture of the Wielkopolska Platform (eastern part of the Fore-Sudetic Monocline, SW Poland). The authors discuss and question, the existence in zones that have been treated as basinal flat in the analysed area, and an extensive platform margin ooidal barrier. In general, the facies architecture of the study area resembles the block built of the Paleozoic basement.On this background analytical geochemical results are presented and their source nature characterized in the context of a new revised model of the Ca2 basin paleogeography. A new facies classification of carbonates, which has not been applied for the Polish part of the Ca2 basin yet, was presented. The geochemical characteristic of Ca2 rocks indicates that good oil-prone source rocks are present only locally and are connected with calcisiltites and dolomudstones of facies II and dolobindstones of facies IV. These facies are mainly present in the slope and toe-of-slope zones. The microbial-algal facies, abundant in the carbonate platform, have a weaker residual potential. However, the thermal maturity stays within the entire range of the “oil window”, the rocks should be re-labeled as good source rocks. The presence of oil-prone kerogen Type II, and locally even Type I, makes the Ca2 beds in this part of the Wielkopolska Platform a very efficient source rock, the character of which is confirmed by numerous hydrocarbon accumulations, related to the course of tectonic zones and morphology of the basement. The proposed characteristic of source rocks in the new paleogeographic-facies system, enables their better petroleum evaluation and shall enable future prospecting of the perspective zones.     

Macro- and megafauna communities in three deep basins of the South-East Atlantic

During ‘Meteor’ expedition ‘DIVA 2’ in 2005 the abyssal macro- and megafauna communities were studied in the northern Cape Basin, in the northern Angola Basin and in the eastern and western Guinea Basin. Water depths varied between 5040 and 5670 m.Surface deposit feeding or predatory ophiuroids dominated the megafaunal community in the northern Cape Basin, sponges, sipunculids and fish in the northern Angola Basin, and asteroids, crustaceans and fish in the eastern Guinea Basin, while in the western Guinea Basin sipunculids dominated.In the northern Cape Basin, peracarid crustaceans were the dominant macrofaunal group, followed by polychaetes and bivalves. In the Guinea Basin, polychaetes, peracarid crustaceans and bivalves dominated, although omnivorous or predatory free-living nematodes of macrofaunal size (>0.5 mm) made up 40–60% of the total abundance, with maxima in the western basin.The chlorophyll a content of sediments was lower in the northern Cape and Angola Basins than in the Guinea Basin, which was consistent with the differences in water masses, primary production and flux rate of organic matter in the three basins of the South-East Atlantic. The differences in structure and function of the macro- and megafauna communities in the three basins correlated with the differences in the amount of food reaching the seafloor in tropical and subtropical settings.     

南海西部深水区崖城组煤系烃源岩的识别方法

琼东南盆地古近系崖城组海陆过渡相煤系烃源岩已被证实是该盆地的主要气源岩,但由于崖城组煤层具有层数多、单层薄、横向变化快的特点,而难以被识别和预测,尤其是勘探程度较低的深水区.本文利用综合种地质与地球物理法对煤系烃源岩进行更加准确的预测.首先,煤层可通过“三高,三低,一扩”的测井响应特征识别,而炭质泥岩可通过“四高,一低”的特征识别.基于该测井逻辑判断,煤系地层可通过测井曲线的聚类分析进行垂向的自动识别.在井震标的的约束下,煤层组可通过地震数据的“负相位,高吸收因子,低波阻抗和低频”等综合特征进行横向识别.然而,地球物理方法识别的煤系烃源岩分布范围不一定符合成煤的地质规律,因此本文从构造、层序和沉积的角度研究了煤系发育的主控因素约束其分布范围:①古地形及构造沉降控制了海陆过渡相煤系烃源岩在凹陷中的平面发育部位;②相对海平面变化通过控制可容空间变化以及海岸线迁移,从而控制烃源岩的发育规模以及垂向分布——具体的说,可容纳空间的增长速率和泥炭堆积速率的关系是控制煤层形成的最根本因素,在其平衡位置,煤层发育最厚、延伸最大;③原地碎屑的供应和沉积场所与古物源的距离,是制约高丰度烃源岩发育的关键因素,即距离古隆起海岸较近的沉积环境中陆源有机质较为丰富,便可形成高丰度煤系烃源岩.通过上述地质与地球物理联合识别方法,提高了煤系烃源岩发育的预测精度和可信度,为南海西部深水区的早期勘探提供了重要的参考依据.     

莫桑比克盆地构造演化与沉积充填特征

在阅读相关文献资料的基础上,分析了莫桑比克盆地的区域性幕式构造演化,并进一步总结归纳了其沉积充填特征。研究显示该盆地为东非边缘陆内裂谷盆地,以晚侏罗世破裂不整合面为界划分为断陷期及坳陷期,断陷期为陆相湖盆沉积充填,进入坳陷期后逐渐从海陆过渡相向浅海相和深水相演变。晚白垩世末和渐新世末两次构造抬升,使得盆地沉积环境及物源供应发生明显改变,也逐渐从深水相向滨浅海相或三角洲相演变。     

Marine hydrocarbon source rocks of the Upper Permian Longtan Formation and their contribution to gas accumulation in the northeastern Sichuan Basin,southwest China

Identification of the main hydrocarbon source rocks of the large Puguang gas field (northeastern Sichuan Basin, southwest China) has been the subject of much discussion in recent years. A key aspect has been the lack of a comprehensive understanding of the development of hydrocarbon source rocks of the Upper Permian Longtan Formation, which had been thought to contain mainly coal seams and thick carbonate layers. In this paper, based on geological data from more than ten wells and outcrops and their related mineralogy and geochemistry, we investigated the depositional environment and main factors controlling organic matter enrichment in the Longtan Formation. We propose a model which combines information on the geological environment and biological changes over time. In the model, organic matter from prolific phytoplankton blooms was deposited in quiescent platform interior sags with rising sea-levels. During the Longtan period, the area from Bazhong to Dazhou was a platform interior sag with relatively deep water and a closed environment, which was controlled by multiple factors including syngenetic fault settling, isolation of submarine uplifts and rising sea-levels leading to water column stratification. Although the bottom water was anoxic, the phytoplankton were able to bloom in the well-lit upper euphotic zone thus giving rise to a set of sapropelic black shales and marlstones containing mostly algal organic matter with minor terrestrial contributions. As a consequence, these rocks have a high hydrocarbon generation potentials and can be classified as high-quality source rocks. The area from Bazhong to Dazhou is a center of hydrocarbon generation, being the main source of reservoired paleo-oils and presently discovered as pyrobitumen in the Puguang gas field. The identification of these source rocks is very important to guide future petroleum exploration in the northeastern Sichuan Basin.     

东海陆架盆地南部构造演化及对油气的控制作用

通过对东海陆架盆地形成的动力学机制研究,分析了动力学机制控制下的盆地南部构造演化特征,提出构造演化对油气成藏的四个控制作用：（1）构造运动控制了盆地演化阶段与凹陷结构;（2）构造运动控制了盆地沉降中心迁移与地层分布;（3）构造运动决定了油气成藏关键时期和油气分带的差异性;（4）构造运动控制了油气聚集与分布。构造运动是盆地演化及油气成藏的主导因素,盆地构造演化结合油气地质综合研究是东海陆架盆地南部油气勘探工作的重点。     

3.7 Ma以来西菲律宾海XT-4孔沉积物元素特征及其古环境指示意义

对西菲律宾海盆南部XT-4孔柱状沉积物进行了元素地球化学分析,利用常量元素上地壳标准化图解和R型因子分析方法进行了物源探究,利用因子分析得出的陆源因子得分变化探讨了物源区的古环境演化。结果表明:XT-4常微量元素垂向上变化主要受控于亚洲内陆的风尘物质和周边火山物质的输入,海洋自生物质也有一定的贡献。以TiO₂和K₂O等元素为代表的陆源因子得分自3.7 Ma BP以来表现出阶段性上升的变化趋势,与中国黄土和北太平洋ODP885/886站沉积物记录的东亚冬季风演化记录有着良好的对比性,同时与青藏高原主要的阶段性隆升时间相对应,响应了晚新生代以来青藏高原隆升对东亚冬季风加强的作用。本研究丰富了西菲律宾海盆的风尘沉积研究,为后续研究提供一定的认识基础。     

马努斯海盆东部裂谷岩浆演化过程——火山岩中斜长石斑晶的启示

岩浆岩中斜长石矿物的结构、成分特征记录了岩浆演化过程的重要信息。本文对马努斯海盆东部裂谷(East Rift, ER)火山岩中的斜长石斑晶进行了详细的矿物学研究,结果表明:在玄武质安山岩中,斜长石斑晶具正环带结构,核-幔部属高An值(斜长石中钙长石分子百分数)斜长石(An值大于80,最大为87),而边缘的An值骤降(最小为63);而在英安岩中,大多数斜长石斑晶的成分从核部到边部变化较小, An值逐渐缓慢降低,呈现正环带结构,少量为韵律环带。结合火山岩斑晶矿物形成的温压条件计算结果,ER地区岩浆演化过程为:地幔源区发生部分熔融产生玄武质岩浆(温度～1300℃);在岩浆活动早期,由于岩浆供应充足,岩浆上升过程中速度较快,仅发生很小程度的分离结晶,形成少量斑晶矿物,并以较高的速度、温度(～1 100℃)直接喷出海底后形成玄武岩-玄武质安山岩;至岩浆活动晚期,岩浆供应量减少,岩浆在岩浆房(3～10km)停留较长时间,岩浆温度已经明显下降(960～1 020℃),发生强烈的分离结晶作用,岩浆喷出海底形成酸性火山岩;而在整个岩浆演化过程中,未有明显的岩浆混合作用发生。     

东马努斯弧后盆地中酸性火山岩岩浆演化中的锂同位素特征

通过分析东马努斯海盆中酸性火山岩的全岩主量、微量元素以及锂同位素组成,并结合前人数据,讨论盆地岩浆体系的演化过程.分析数据显示,东马努斯海盆主、微量元素与SiO2含量之间呈线性变化关系,表明岩浆结晶分异过程控制东马努斯海盆岩浆演化过程.东马努斯弧后盆地火山岩富集流体相关元素,指示东马努斯弧后盆地岩浆源区可能经历了俯冲流...     

东海陆架盆地丽水凹陷热演化模拟及现今地温场特征

东海陆架盆地丽水凹陷烃源岩埋深大、钻井少、油气发现少,至今对其生油气能力具有较大的争议。为明确烃源岩热演化史,从少量具备实测地层温度和镜质体反射率（Ro）资料的钻井出发,利用正演模拟方法,通过地温与地层深度相关性分析,将钻井地温研究结果外推到无井区。在恢复丽水凹陷探井岩石圈结构及其演化史的基础上,首次系统建立了丽水凹陷的区域地温场并分析其对烃源岩演化的作用。研究表明,古新统下段月桂峰组底界（T100）烃源岩大部分都已成熟,次洼中心局部过成熟;月桂峰组顶界（T90）烃源岩大部分处于低熟—成熟阶段,次洼中心局部高—过成熟;灵峰组顶界（T85）烃源岩处于未熟—低熟状态,西次洼中心有成熟烃源岩。烃源岩特征及演化分析表明,古新统下段月桂峰组烃源岩是丽水凹陷的主力生油气烃源岩。     

西太平洋弧后盆地的热液系统及其岩浆环境研究

研究海底热液系统及其岩浆环境,可为了解西太平洋流固界面跨圈层物质与热交换过程,揭示板块俯冲过程的岩浆活动和资源环境效应提供研究支撑。为此,研究了冲绳海槽热液活动的岩浆环境、马努斯海盆的热液柱以及弧后盆地和洋中脊背景下的硫化物与玄武岩的同位素组成,对冲绳海槽热液区附近玄武岩、安山岩、粗安岩、英安岩、流纹岩及其基性岩浆包体进行了岩相学、矿物学以及主量元素、微量元素和同位素组成分析,对马努斯海盆PACMANUS和Desmos热液区的热液柱及海水进行了测量,在海底热液区岩浆混合过程及时间尺度、透视冲绳海槽深部岩浆房及岩浆演化过程和岩浆对热液系统物质贡献研究方面获新进展,揭示了俯冲蛇纹岩对琉球构造带南部岩浆活动的影响,论证了熔体包裹体对弧后盆地岩浆演化的指示,获得了冲绳海槽玄武质岩浆来源新证据,揭示了弧后盆地与洋中脊硫化物和玄武岩中铁、铜、锌的来源及其同位素在硫化物形成和岩浆活动过程中的分馏情况,明确了热液柱的物理、化学空间结构与物质组成特征,以及热液柱的扩散受深度和底流流速的影响,且热液柱扩散过程中溶解铁浓度异常比溶解锰的维持时间更长。未来,发展非传统稳定同位素和挥发份测试技术,进一步了解西太平洋板块俯冲环境下热液活动与岩浆作用的关系,将有助于海底热液系统及其成矿过程研究获得新进展。     

Quantitative modelling of hydrocarbon expulsion and quality grading of tight oil lacustrine source rocks: Case study of Qingshankou 1 member,central depression,Southern Songliao Basin,China

The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (R_o) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, R_o >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at R_o >1%. Source rocks with TOC and R_o <0.8%, type-II₂ & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable.