OIL FAMILY TYPING,BIODEGRADATION AND SOURCE ROCK AFFINITY OF LIQUID PETROLEUM IN THE DANISH NORTH SEA

Variations in liquid petroleum compositions in the Danish Central Graben and Siri Fairway, North Sea, demonstrate the presence of several active source rock facies. To address this issue in detail, a total of 213 samples of liquid petroleum from the Danish Central Graben and the Siri Fairway were typed to eight main oil families and three sub‐families based on characteristic geochemical properties and principal component analysis (PCA). Comparison with source rock extract data made it possible to suggest correlative source rocks for each oil family together with the source rock depositional environments. The main oil families are: 1(B), 2(B), 3a(B), 3b(B), 4(B‐D/E), 5(D/E‐B), 6(D/E‐F) and 7(A), where the capital letters in brackets refer to the organofacies types of Pepper and Corvi (1995), thus directly linking the oil family type to the source rock facies. Oil families 1(B), 2(B), 3a(B) and 3b(B) were charged from marine shales (principally the Upper Jurassic Farsund Formation); oil families 4(B‐D/E) and 5(D/E‐B) are mixed petroleums with both terrigenous and marine components; oil family 6(D/E‐F) was charged from Middle Jurassic coaly units; whereas oil family 7(A) was charged from a carbonate source (Zechstein dolomites). Family 7(A) has only been documented in the form of oil stains. The most widespread oil family is 3a(B), sourced from Upper Jurassic marine shales. Charging from different organofacies is indicated by oil family 3b(B), which was derived from parts of the same shale succession which were more terrigenous‐influenced and possibly slightly more oxic; and families 2(B) and 1(B), which were sourced from more organic‐rich, anoxic parts of the shales. Mildly biodegraded oils (Level 1 to 2) appear mainly to occur in the central to southern parts of the Danish Central Graben.     

MATURITY AND PETROLEUM SYSTEMS MODELLING IN THE OFFSHORE ZAMBEZI DELTA DEPRESSION AND ANGOCHE BASIN,NORTHERN MOZAMBIQUE

Petroleum systems analysis and maturity modelling is used to predict the timing and locations of hydrocarbon generation in the underexplored offshore Zambezi Delta depression and Angoche basin, northern Mozambique. Model inputs include available geological, geochemical and geophysical data. Based on recent plate‐tectonic reconstructions and regional correlations, the presence of Valanginian and Middle and/or Late Jurassic marine source rock is proposed in the study area. The stratigraphy of the Mozambique margin was interpreted along reflection seismic lines and tied to four wells in the Zambezi Delta depression. Thermal maturity was calibrated against measured vitrinite reflectance values from these four wells. Four 1‐D models with calibration data were constructed, together with another five without calibration data at pseudo‐well locations, and indicate the maturity of possible source rocks in the Zambezi Delta depressions and Angoche basin. Two 2‐D petroleum systems models, constrained by seismic reflection data, depict the burial history and maturity evolution of the Zambezi Delta basin. With the exception of the deeply‐buried centre of the Zambezi Delta depression where potential Jurassic and Lower Cretaceous source rocks were found to be overmature for both oil and gas, modelling showed that potential source rocks in the remaining parts of the study area are mature for hydrocarbon generation. In both the Zambezi Delta depression and Angoche basin, indications for natural gas may be explained by early maturation of oil‐prone source rocks and secondary oil cracking, which likely began in the Early Cretaceous. In distal parts of the Angoche basin, however, the proposed source rocks remain in the oil window.     

沥青质中官能团结构和氢键的红外光谱表征

利用傅里叶红外光谱表征渣油沥青质和煤焦油沥青质分子的官能团结构,并通过软件Origin 2018对沥青质红外光谱的氢键区、脂肪族碳氢伸缩振动区和C—O区的吸收峰进行分峰拟合。结果表明：两种沥青质均主要以碳、氢元素为主,二者杂原子的含量存在明显差异,但杂原子官能团的类型基本相同;渣油沥青质中的氢键主要是由苯环O—H与芳香醚键中的O原子、O—H自缔合形成的氢键,而煤焦油沥青质中的氢键主要是苯环O―H与芳香醚键中的O原子形成的氢键;与渣油沥青质相比,煤焦油沥青质的烷基侧链更短。     

COAL-GENERATED OIL: SOURCE ROCK EVALUATION AND PETROLEUM GEOCHEMISTRY OF THE LULITA OILFIELD, DANISH NORTH SEA

Controversy still exists as to whether coals can source commercial accumulations of oil. The Harald and Lulita fields, Danish North Sea, are excellent examples of coal‐sourced petroleum accumulations, the coals being assigned to the Middle Jurassic Bryne Formation. Although the same source rock is present at both fields, Lulita primarily contains waxy crude oil in contrast to Harald which contains large quantities of gas together with secondary oil/condensate. A compositional study of the coal seams at well Lulita‐IXc (Lulita field) was therefore undertaken in order to investigate the generation there of liquid petroleum. Lulita‐IXc encountered six coal seams (0.15–0.25 m thick) which are associated with reservoir sandstones. The coals have a complex petrography dominated by vitrinite, with prominent proportions of inertinite and only small amounts of liptinite. Peat formation occurred in coastal‐plain mires; the coal seams at Lulita‐IXc represent the waterlogged, oxygen‐deficient and occasionally marine‐influenced coastal reaches of these mires. Vitrinite reflectance values (mostly 0.82–0.84%Ro) indicate that the coals are thermally mature. Most of the coal samples have Rock‐Eval Hydrogen Index values above 220 mg HC/g TOC, although the HI values may be increased due to the presence of extractable organic matter. Oil‐source rock correlations indicate that there are similarities between crude oil samples (and an oil‐stained sandstone extract) from the Lulita field, and extracts from the Bryne Formation coals immediately associated with the reservoir sandstones; from this, we infer that the coals have generated the crude oil at Lulita. The presence in the coals of oil‐droplets, exsudatinite and micrinite is further evidence that they have generated liquid petroleum. The generation of aliphatic‐rich crude oil by the coals in the Lulita field area, and the coals' high expulsion efficiency, may have been facilitated by a combination of the coals'favourable petrographic composition and their capability to generate long‐chain n‐alkanes (C₂₂₊). Moreover_; all the Lulita coal seams are relatively thin and this may have facilitated oil saturation to the expulsion threshold. We suggest that during further maturation of the coals, 19–22% of the organic carbon will potentially participate in petroleum‐generation, of which about 42–53% will be in the gas‐range and 47–58% in the oil‐range.     

THE PETROLEUM SYSTEM IN THE SANDINO FOREARC BASIN, OFFSHORE WESTERN NICARAGUA

The underexplored Sandino Basin (Nicaragua Basin/Trough) is located within the forearc area of western Nicaragua and NW Costa Rica. Exploration activity since 2004 has focussed on the onshore sector of the basin, and has included the first drilling campaign for over 30 years. Recent 2D basin modelling of the offshore sector together with organic geochemical studies has attempted to reassess the basin's petroleum potential. Geochemical data from the deepest offshore well indicate that Middle Eocene to Lower Oligocene sediments of the Brito Formation, as well as Upper Oligocene to Lower Miocene sediments of the Masachapa Formation, may have source rock potential. A third and perhaps more significant potential source rock interval is associated with the Lower Cretaceous black shales of the Loma Chumico Formation, which has been studied in the adjacent forearc area in NW Costa Rica (Tempisque Basin) and is inferred to be present in the Sandino Basin.
The thermal history of the forearc basin is controlled by the low basal heat flow (39 mW/m²). 2D modelling has shown that the Sandino Basin is thermally mature, resulting in the potential for hydrocarbon generation in organic-rich intervals in the Brito and Masachapa Formations. A petroleum-generating "kitchen" has tentatively been identified on a NE-SW seismic section which crosses the basin. Modelling suggests that this kitchen has been active from the Late Eocene until the present day, and that the main phases of petroleum generation in general coincide with phases of maximum subsidence in the Late Eocene, Late Oligocene and Plio-Pleistocene. Hydrocarbon migration most probably occurred from the deep basin towards the flanks. Significant volumes of petroleum may have been lost prior to the Late Miocene before the formation of a coastal flexure which can be recognised in the NE of the seismic profile.     

PETROLEUM GEOLOGY OF THE NOGAL BASIN AND SURROUNDING AREA,NORTHERN SOMALIA,PART 2: HYDROCARBON POTENTIAL

Seismic reflection profiles and well data show that the Nogal Basin, northern Somalia, has a structure and stratigraphy suitable for the generation and trapping of hydrocarbons. However, the data suggest that the Upper Jurassic Bihendula Group, which is the main source rock elsewhere in northern Somalia, is largely absent from the basin or is present only in the western part. The high geothermal gradient (～35–49 °C/km) and rapid increase of vitrinite reflectance with depth in the Upper Cretaceous succession indicate that the Gumburo Formation shales may locally have reached oil window maturity close to plutonic bodies. The Gumburo and Jesomma Formations include high quality reservoir sandstones and are sealed by transgressive mudstones and carbonates. ID petroleum systems modelling was performed at wells Nogal‐1 and Kalis‐1, with 2D modelling along seismic lines CS‐155 and CS‐229 which pass through the wells. Two source rock models (Bihendula and lower Gumburo) were considered at the Nogal‐1 well because the well did not penetrate the sequences below the Gumburo Formation. The two models generated significant hydrocarbon accumulations in tilted fault blocks within the Adigrat and Gumburo Formations. However, the model along the Kalis‐1 well generated only negligible volumes of hydrocarbons, implying that the hydrocarbon potential is higher in the western part of the Nogal Basin than in the east. Potential traps in the basin are rotated fault blocks and roll‐over anticlines which were mainly developed during Oligocene–Miocene rifting. The main exploration risks in the basin are the lack of the Upper Jurassic source and reservoirs rocks, and the uncertain maturity of the Upper Cretaceous Gumburo and Jesomma shales. In addition, Oligocene‐Miocene rift‐related deformation has resulted in trap breaching and the reactivation of Late Cretaceous faults.     

ORGANIC FACIES, DEPOSITIONAL ENVIRONMENT AND PETROLEUM GENERATING CHARACTERISTICS OF THE LACUSTRINE SHAHEJIE FORMATION, ES4 MEMBER, WESTERN DEPRESSION, LIAOHE BASIN (NE CHINA)

Organic petrological and organic geochemical investigations have been carried out on Eocene lacustrine deposits from the Western Depression of the Liaohe Basin (NE China). The purpose was to conduct a systematic organofacies classification of these rocks, to determine their source rock potential and hydrocarbon characteristics, and to study depositional processes within this palaeo‐lake setting. Rock‐Eval data and molecular biomarkers indicate that samples analysed were immature in terms of thermal maturation. Three distinct organofacies have been identified within the ES₄ member of the Shahejie Formation. The depositional model envisages the formation of good to excellent oil‐prone source rocks in a shallow saline‐alkaline lake with a stratified water column; of source rocks with moderate source potential in a deep and freshwater lake; and of poor quality source rocks towards the lake margins. The shallow lake organofacies is characterised by high total organic carbon contents (up to 17.6%) and high Hydrogen Index values (up to 908 mg HC/g TOC). The laminated sediments contain elevated amounts of fluorescing amorphous organic matter (OM) and lamalginite. High primary production dominated by cyanobacteria together with anoxic bottom waters and a paucity of terrestrial vegetation in an arid climate resulted in the deposition of Type I OM. The presence of monoaromatic carotenoids, typically derived from photosynthetic purple and green sulphur bacteria Chromatiaceae and Chlorobiaceae, suggests a water body in which an anoxic photic zone occurred at least periodically. The source rocks deposited in this type of lake have the potential to generate high‐wax paraffinic petroleum at high subsurface temperatures (up to 159°C at a heating rate of 5.3° C/million years). The quality and quantity of the OM within the freshwater organofacies (Shale I, Shale II) were determined to be lower. Petrologic observations point to the absence of laminations and the presence of Botryococcus braunil telalginite. The abundance of lycopane and its aromatised abundance of lycopane and its aromatised diagenetic analogues confirmed the presence of this algal species. Generally low concentrations of gammacerane and high pristane/phytane ratios indicate a low salinity, hydrologically open environment in which oxic conditions generally prevailed, resulting in relatively poor preservation of OM. Sediments of poor source rock quality deposited in the marginal fan‐delta setting (the Shu‐Du area) can be distinguished visually by the presence of terrigenous particles (vitrinite, inertinite and terrigenous liptinites), and geochemically by the presence of phenols in the pyrolysates.     

LATE TO MIDDLE JURASSIC SOURCE FACIES AND QUALITY VARIATIONS, SOUTH VIKING GRABEN, NORTH SEA

Source facies and quality of the Late to Middle Jurassic source rock system in the South Viking Graben between 58°N and 60°15'N are highly variable both regionally and stratigraphically. In order to assess the degree of variability and to create a model of source rock quality and potential, isochore maps of the syn‐ and post‐rift sections of the Upper Jurassic Draupne Formation and underlying Heather Formation were generated from seismic and well data, and maturity‐corrected Rock‐Eval data were used to generate quantitative maps of oil and gas potential. The thin post‐rift section at the top of the Draupne Formation is a rich oil‐prone source, while the up to 1,600 m thick syn‐rift section contains a mixture of Type III and Type II material with substantial amounts of gas‐prone and inert organic matter. The Heather Formation, which reaches modelled thicknesses of up to 930 m, is a lean source and is generally gas‐prone. Detailed analyses and interpretations of biomarker and isotopic characteristics support this upward increase in oil‐prone Type II material. The analytical parameters include increasing relative amounts of C₂₇ regular steranes; decreasing ratios of C₃₀ moretane relative to C₃₀ hopane; and an increasing predominance of short chain n‐alkanes and progressively lighter isotopic values for saturate and aromatic fractions of source rock extracts. In addition, increasing amounts of 17α(H),21β(H)‐28,30‐bisnorhopane and decreasing amounts of C₃₄ homohopanes relative to C³⁵ homohopanes, as well as decreasing Pr/Ph ratios, suggest a general decrease in oxygenation upwards. Maps of average Pr/Ph ratios for the syn‐ and post‐rift Draupne Formation and for the Heather Formation are consistent with permanent water column stratification and gradual ascent of the O₂:H₂S interface from the Callovian to the Ryazanian. Interpretation of oil and gas potential maps, molecular parameters and estimates of sediment accumulation rates in combination suggest that the source facies of the upper, post‐rift Draupne Formation is controlled by widespread anoxia, reduced siliciclastic dilution and reduced input of gas‐prone organic and inert material; by contrast, the potential of the lower, syn‐rift Draupne Formation is strongly controlled by dilution by gas‐prone and inert organic matter resulting from mass flows and also by varying degrees of oxygenation. The oil and gas potential of the Heather Formation is mainly controlled by the degree of oxygenation and siliciclastic dilution.     

PETROLEUM SYSTEMS MODELLING IN A FOLD‐AND‐THRUST BELT SETTING: THE INVERTED CAMEROS BASIN,NORTH‐CENTRAL SPAIN

The Mesozoic Cameros Basin, northern Spain, was inverted during the Cenozoic Alpine orogeny when the Tithonian – Upper Cretaceous sedimentary fill was uplifted and partially eroded. Tar sandstones outcropping in the southern part of the basin and pyrobitumen particles trapped in potential source rocks suggest that hydrocarbons have been generated in the basin and subsequently migrated. However, no economic accumulations of oil or gas have yet been found. This study reconstructs the evolution of possible petroleum systems in the basin from initial extension through to the inversion phase, and is based on structural, stratigraphic and sedimentological data integrated with petrographic and geochemical observations. Petroleum systems modelling was used to investigate the timing of source rock maturation and hydrocarbon generation, and to reconstruct possible hydrocarbon migration pathways and accumulations. In the northern part of the basin, modelling results indicate that the generation of hydrocarbons began in the Early Berriasian and reached a peak in the Late Barremian – Early Albian. The absence of traps during peak generation prevented the formation of significant hydrocarbon accumulations. Some accumulations formed after the deposition of post‐extensional units (Late Cretaceous in age) which acted as seals. However, during subsequent inversion, these reservoir units were uplifted and eroded. In the southern sector of the basin, hydrocarbon generation did not begin until the Late Cretaceous due to the lower rates of subsidence and burial, and migration and accumulation may have taken place until the initial phases of inversion. Sandstones impregnated with bitumen (tar sandstones) observed at the present day in the crests of surface anticlines in the south of the basin are interpreted to represent the relics of these palaeo‐accumulations. Despite a number of uncertainties which are inherent to modelling the petroleum systems evolution of an inverted and overmature basin, this study demonstrates the importance of integrating multidisciplinary and multi‐scale data to the resource assessment of a complex fold‐and‐thrust belt.     

对叠合型盆地油气系统研究方法和分类问题的思考

在前人研究的基础上,探讨叠合型盆地油气系统分析的思路、流程和研究内容,强调在进行油气系统划分前,要对盆地的构造格架、沉降充填史、热过程以及盆地的构造单元、烃源岩发育的层段和范围、生储盖组合的基本特征,做系统的分析和评估,再在油气源对比的基础上对油气系统进行划分。鉴于叠合盆地存在多套烃源岩、多个生烃单元,断裂和不整合发育,认为叠合型油气系统的划分应以烃源岩+构造单元(生烃凹陷或洼陷及油气可能的运聚区域)为最主要依据,以烃源岩+构造单元+可靠程度来进行命名比较合适,也较为实用。叠合型油气系统分析要从静态地质要素分析和动态地质过程分析2个方面进行,静态地质要素包括有效的烃源岩、储集层、盖层、输导层和圈闭,动态地质要素包括油气生成过程、储层演化过程、油气运移过程、圈闭形成过程、油气成藏过程等。各要素组合关系分析、油气系统保存作用分析、各油气系统叠合关系分析、勘探有利靶区及目标分析等都是叠合型盆地油气系统研究内容的组成部分。      

HYDROCARBON HABITAT OF THE SEDANO TROUGH,BASQUE‐CANTABRIAN BASIN,SPAIN

This paper analyzes the hydrocarbon habitat and potential of the Sedano trough in the SW sector of the Basque‐Cantabrian Basin (northern Spain). The study is based on regional geological data, geochemical analyses, basin modelling simulations and play analysis techniques, and attempts to quantify by volumetric resource appraisal the volume of hydrocarbons generated, expelled and migrated from the main Sedano trough depocentre. A Lower Jurassic shale source rock has been identified and is responsible for the oil at Ayoluengo field, for the oil shows at the Polientes and Tozo wells, and for the Zamanzas and Basconcillos de Tozo tar sands which outcrop at the NE and SW margins of the Sedano trough respectively. Thermal history modelling indicates that petroleum generation and expulsion from the Lower Jurassic source rock started in the Sedano trough in the Early Cretaceous, with the main oil generation phase occurring in latest Cretaceous to Paleogene times. GC, GC‐MS and isotopic analyses of oils, tar sands and source rock extracts from the Sedano trough indicate good correlations between the Lower Jurassic source rock and the Ayoluengo oil, and tar sands from the basin margins. Petroleum plays and traps are abundant and are a result of a complex polyphase geological history. They can be grouped into:(i) early salt‐induced structural plays; (ii) later structural plays associated with a mid‐Tertiary compressional phase; and (iii) stratigraphic plays within the Upper Jurassic – Lower Cretaceous siliciclastic succession. A volumetric resource appraisal of the Lower Jurassic source rock indicates that a total of 11 billion bbl of oil could have been generated and expelled in the Sedano trough, and around 880 million bbl of oil have migrated into potential traps in 15 identified drainage areas. This results in a generation‐accumulation efficiency of 7%. Undiscovered resources have been estimated at 154 million bbl of oil, indicating that there is still moderate undiscovered hydrocarbon potential in the area.     

THE NATURE AND ORIGIN OF PETROLEUM IN THE CHAIWOPU SUB-BASIN (JUNGGAR BASIN), NW CHINA

The Chaiwopu Sub-basin is a minor extension of the Junggar Basin, hW China, and covers an area of about 2,500 sq. km. It is bounded to the east and north by the Bogda Shan and to the south by the Tian Shan ("Shan" meaning "mountains" in Chinese). Four wells have been drilled in the sub-basin; condensate and gas have been produced in noncommercial quantities at one of the wells (Well C), but the other three wells were dry. In this paper, I investigate the nature and origin of the petroleum at Well C.
Three of the four wells in the Chaiwopu Sub-basin penetrated the Upper Permian Lucaogou Formation. Previous studies in the Junggar Basin have established that laminated lacustrine mudstones assigned to this formation comprise a very thick high quality source rock. However, the analysis of cores from wells in the sub-basin shows that the Lucaogou Formation is composed here of shallow lacustrine, fluvial and alluvial deposits which have very low petroleum generation potential. Overlying sediments (Upper Permian, Triassic and younger strata) likewise have little source potential.
Around 1,000 m of Upper Permian laminated oil shales crop out at Dalongkou and Tianchi on the northern side of the Bogda Shan. On the southern side of the Bogda Shan, however, only 30 m of Upper Permian oil shales occur at Guodikong. Shales and oil seeps from these locations were analysed using standard organic-geochemical techniques.
The physical properties of the petroleum present at Well C, and its carbon isotope and biomarker characteristics, suggest that it has migrated over long distances from its source rock, although an alternative explanation for its origin is not precluded. Burial history modelling indicates that hydrocarbon generation and migration may have occurred before the uplift of the Bogda Shan in the Late Jurassic—Early Cretaceous, the orogenic episode which resulted in the diflerentiation of the Chaiwopu Sub-basinfrom the Junggar Basin.     

微量元素在煤成烃研究中的应用

通过对吐哈盆地不同类型烃源岩有机质及原油中微量元素的研究，并在与世界及我国其它地区原油对比的基础上，探讨了煤成烃中和微量元素的分布规律，运用微量元素进行了油源对比的尝试。     

酒东盆地营尔凹陷油气生成和运移聚集

酒东盆地营尔凹陷存在下白垩统和中、下侏罗统２套生油层。其中，下白垩统中沟组下段有机质丰度类型最好，但尚处于低熟阶段；成熟的、中、下株罗统是极重要的生油层。营尔凹陷内，２套生油层生物标志物分布截然不同；下白垩统和中、下侏罗统的原油是２类自生自储原油；３个异常高压流体带严格控制油气的纵向运移聚集。     

准噶尔盆地二叠系含油气系统类型及展布

准噶尔盆地二叠系由海陆过渡相、泻湖相和河流相沉积组成,烃源岩发育,具有生、储、盖、圈、保的良好配置条件。中、晚石炭世和二叠纪,准噶尔古陆块受西伯利亚板块、哈萨克斯坦板块、塔里木板块的碰撞,形成了西缘、南缘、东北缘三大前陆盆地系统。由于三个不同地区前陆盆地系统的发育,构成了以二叠系风城组、下乌尔禾组为主要烃源岩的三大盆地级含油气系统。根据对形成盆地内含油气系统的充要条件──静态要素和动态要素的分析,确定出了以三个盆地级含油气系统为单元的七个盆地内含油气系统。各含油气系统都有着各自的形成和分布规律。按其空间展布,又可划为同期并列式、同期交叉式、异期叠合式、异期重合式四种形式。这些形式的有效组合,构成了准噶尔盆地内有利的油气聚集带。     

凝析油充注对油藏沥青质分子结构的影响

用原油沥青质的地球化学研究结果分析油气藏形成条件，前提是油藏沥青质分子结构不因后期天然气或凝析油的再次充注而变化。在塔里木盆地轮南1井产出原油中加入不同体积的石油醚，模拟后期凝析油充注早期油藏的过程，测定不同沉淀条件下原油的沥青质沉淀量变化，并用瞬间热解-色谱-质谱的方法研究沥青质的分子结构。实验结果，原油沥青质随低分子烃类注入量的变化发生沉淀和再溶解，但沉淀出的沥青质分子结构相同。据此认为，低分子烃类加入原油体系不会改变沥青质的分子结构特征，沥青质热解产物能够反映原油的母质结构特征，可以根据该特征进行油／源、油／油对比或探讨混源油的母源类型。图5参19     

SOURCE ROCK POTENTIAL OF THE BLUE NILE (ABAY) BASIN, ETHIOPIA

The Blue Nile Basin, a Late Palaeozoic ‐ Mesozoic NW‐SE trending rift basin in central Ethiopia, is filled by up to 3000 m of marine deposits (carbonates, evaporites, black shales and mudstones) and continental siliciclastics. Within this fill, perhaps the most significant source rock potential is associated with the Oxfordian‐Kimmeridgian Upper Hamanlei (Antalo) Limestone Formation which has a TOC of up to 7%. Pyrolysis data indicate that black shales and mudstones in this formation have HI and S₂ values up to 613 mgHC/gCorg and 37.4 gHC/kg, respectively. In the Dejen‐Gohatsion area in the centre of the basin, these black shales and mudstones are immature for the generation of oil due to insufficient burial. However, in the Were Ilu area in the NE of the basin, the formation is locally buried to depths of more than 1,500 m beneath Cretaceous sedimentary rocks and Tertiary volcanics. Production index, T_max, hydrogen index and vitrinite reflectance measurements for shale and mudstone samples from this areas indicate that they are mature for oil generation. Burial history reconstruction and Lopatin modelling indicate that hydrocarbons have been generated in this area from 10Ma to the present day. The presence of an oil seepage at Were Ilu points to the presence of an active petroleum system. Seepage oil samples were analysed using gas chromatography and results indicate that source rock OM was dominated by marine material with some land‐derived organic matter. The Pr/Ph ratio of the seepage oil is less than 1, suggesting a marine depositional environment. n‐alkanes are absent but steranes and triterpanes are present; pentacyclic triterpanes are more abundant than steranes. The black shales and mudstones of the Upper Hamanlei Limestone Formation are inferred to be the source of the seepage oil. Of other formations whose source rock potential was investigated, a sample of the Permian Karroo Group shale was found to be overmature for oil generation; whereas algal‐laminated gypsum samples from the Middle Hamanlei Limestone Formation were organic lean and had little source potential     

酒西盆地含油气系统与油气勘探方向

本文解剖了酒西盆地烃源岩发育的地质背景及主要烃源岩的性质、分布规律,分析了油气生成期与圈闭发育期的配置关系、油气运移方向与通道、储集岩特征及分布、区域盖层分布与成藏规律,总结了该盆地油气生、储、盖、运、圈、保的基本规律。在此基础上,研究了制约酒西盆地的主要油气成藏条件,并指出了有利的勘探领域及目标。      

酒东,酒西盆地的异同与油气勘探

酒东盆地和酒西盆地都是祁连褶皱系为山前盆地，在同一区域构造应力场控制下发育，有很多相似性。酒西盆地自３０年代以来发现了一批浅层油气藏，酒东盆地多年勘探却无重大突破。分析二者的异同，认为：（１）盆地边界条件不同，导致局部应力作用方式有别，酒西盆地逆冲－褶皱变形强列，酒东盆 构造变形微弱，中浅、浅层断裂少；（２）主要是油源层都是深部下白垩统赤金堡组的成熟－－高成熟烃源岩；（３）酒西盆地的深部油气以断裂     

准噶尔盆地含油气系统的形成与演化

将准噶尔盆地划分为石炭系、二叠系、侏罗系和第三系四套含油气系统,其中石炭系和侏罗系是以含气为主的含(油)气系统,二叠系和第三系是以含油为主的含油(气)系统。根据烃源岩及其生成油气的分布,划出了含油气系统的分布范围:石炭系含(油)气系统分布范围为盆地中部的中拐—石西——五彩湾东西展布的条带并向东南延伸至三台凸起;二叠系含油(气)系统的分布范围包括西北缘、陆南凸起及其以南地区;侏罗系含(油)气系统分布于中央隆起带及其以南地区;第三系含油(气)系统分布仅限于南缘四棵树凹陷附近。并对四套含油气系统的形成与演化进行了深入分析,强调“关键时刻”在含油气系统形成中的重要作用。