PETROLEUM GEOLOGY AND HYDROCARBON POTENTIAL OF THE GUBAN BASIN,NORTHERN SOMALILAND

The Guban Basin is a NW‐SE trending Mesozoic‐Tertiary rift basin located in northern Somaliland (NW Somalia) at the southern coast of the Gulf of Aden. Only seven exploration wells have been drilled in the basin, making it one of the least explored basins in the Horn of Africa – southern Arabia region. Most of these wells encountered source, reservoir and seal rocks. However, the wells were based on poorly understood subsurface geology and were located in complex structural areas. The Guban Basin is composed of a series of on‐ and offshore sub‐basins which cover areas of 100s to 1000s of sq. km and which contain more than 3000 m of sedimentary section. Seismic, gravity, well, outcrop and geochemical data are used in this study to investigate the petroleum systems in the basin. The basin contains mature source rocks with adequate levels of organic carbon together with a variety of reservoir rocks. The principal exploration play is the Mesozoic petroleum system with mature source rocks (Upper Jurassic Gahodleh and Daghani shales) and reservoirs of Upper Jurassic to Miocene age. Maturity data suggest that maximum maturity was achieved prior to Oligocene rift‐associated uplift and unroofing. Renewed charge may have commenced during post‐ Oligocene‐Miocene rifting as a result of the increased heat flows and the increased depth of burial of the Upper Jurassic source rocks in localised depocentres. The syn‐rift Oligocene‐Miocene acts as a secondary objective owing to its low maturity except possibly in localised offshore sub‐basins. Seals include various shale intervals some of which are also source rocks, and the Lower Eocene evaporites of the Taleh Anhydrite constitute an effective regional seal. Traps are provided by drag and rollover anticlines associated with tilted fault blocks. However, basaltic volcanism and trap breaching as a consequence of the Afar plume and Oligocene‐Miocene rifting of the Gulf of Aden cause considerable exploration risk in the Guban Basin.     

3D BASIN MODELLING IN THE CENTRAL PERSIAN GULF,OFFSHORE IRAN

In the Central Persian Gulf, super‐giant natural gas accumulations in Permo‐Triassic reservoirs are assumed to be derived from “hot shale” source rocks in the lower Llandoverian (base‐Silurian) Sarchahan Formation, whereas oil in Mesozoic reservoirs is derived from Mesozoic source rocks. A 3D basin model has been established for a study area located in the Iranian part of the Central Persian Gulf in order to help understand the petroleum systems there. Sensitivity analyses considered different heat flow scenarios, and differences in the timing of Cenozoic uplift and erosion. For the Palaeozoic petroleum system, different thicknesses and distributions of the Silurian source rocks were considered. From current temperature profiles measured in five wells, present‐day heat flow was found to be in the order of 65 mW/m², while palaeo heat flow was probably between 60 and 68 mW/m² during Cenozoic maximum burial. For Llandoverian source rocks, oil and gas generation commenced during Jurassic and Late Cretaceous time respectively, and gas generation continued until the Neogene. Sensitivity analyses show that different assumptions on the timing of Cenozoic erosion do not have significant effects on the calculated timing of hydrocarbon generation or on the volume of generated hydrocarbons. As expected however, different heat flow scenarios (e.g. time‐constant heat flow of 65 mW/m² in the entire study area) had a significant influence. With an assumed 50 m thick Sarchahan “hot shale” succession developed uniformly in the study area (8 % TOC; 470 mg HC / g TOC HI), the model calculated gas accumulations which are of the same order of magnitude as those which have been discovered in this region (e.g. South Pars, Golshan and Balal fields). By contrast, scenarios with thinner “hot shales” and models without the Sarchahan Formation along the Qatar‐South Fars Arch do not predict the known accumulations. These scenarios suggest that prolific Silurian source rocks must be present on both sides of the South Pars / North Dome field, or that lateral gas migration from the south may have supplied the Permo‐Triassic reservoirs. This study shows that the Jurassic (mainly Hanifa / Tuwaiq Mountain Formation) and Cretaceous (Shilaif Formation) source units are not sufficiently mature in the study area to have generated significant volumes of oil. This result supports previous suggestions which envisaged lateral migration from the south of the oil present in Mesozoic reservoirs in the study area.     

HYDROCARBON ACCUMULATION PROCESSES IN THE YANGTAKE FOLDBELT,KUQA FORELAND BASIN,NW CHINA: INSIGHTS FROM INTEGRATED BASIN MODELLING AND FLUID INCLUSION ANALYSES

Abundant gas and condensate resources are present in the Kuqa foreland basin in the northern Tarim Basin, NW China. Most of the hydrocarbons so far discovered are located in foldbelts in the north and centre of the foreland basin, and the Southern Slope region has therefore been less studied. This paper focusses on the Yangtake area in the west of the Southern Slope. Basin modelling was integrated with fluid inclusion analyses to investigate the oil and gas charge history of the area. ID modelling at two widely spaced wells (DB‐1 and YN‐2) assessed the burial, thermal and hydrocarbon generation histories of Jurassic source rocks in the foreland basin. Results show that the source rocks began to generate hydrocarbons (R_o >0.5%) during the Miocene. In both wells, the source rocks became mature to highly mature between 12 and 1.8 Ma, and most oil and gas was generated at 5.3–1.8 Ma with peak generation at about 3 Ma. Two types of petroleum fluid inclusions were observed in Cretaceous and lower Paleocene sandstone reservoir rocks at wells YTK‐5 and YTK‐1 in the Yangtake area. The inclusions in general occur along healed microfractures in quartz grains, and have either yellowish or blueish fluorescence colours. Aqueous inclusions coexisting with both types of oil inclusions in Cretaceous sandstones in well YTK‐5 had homogenization temperatures of 96–128 °C and 115–135 °C, respectively. The integrated results of this study suggest that oil generated by the Middle Jurassic Qiakemake Formation source rocks initially charged sandstone reservoirs in the Yangtake area at about 4 Ma, forming the yellowish‐fluorescing oil inclusions. Gas, which was mainly sourced from Lower Jurassic Yangxia and Middle Jurassic Kezilenuer coaly and mudstone source rocks, initially migrated into the same reservoirs in the Yangtake area at about 3.5 Ma and interacted with the early‐formed oils forming blueish‐fluorescing oil inclusions. The migration of gas also resulted in formation of the condensate accumulations which are present at the YTK‐1 and YTK‐2 fields in the Yangtake area.     

HYDROCARBON POTENTIAL OF MIDDLE JURASSIC COALY AND LACUSTRINE AND UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SOURCE ROCKS IN THE SØGNE BASIN,NORTH SEA

The Søgne Basin in the Danish‐Norwegian Central Graben is unique in the North Sea because it has been proven to contain commercial volumes of hydrocarbons derived only from Middle Jurassic coaly source rocks. Exploration here relies on the identification of good quality, mature Middle Jurassic coaly and lacustrine source rocks and Upper Jurassic – lowermost Cretaceous marine source rocks. The present study examines source rock data from almost 900 Middle Jurassic and Upper Jurassic – lowermost Cretaceous samples from 21 wells together with 286 vitrinite reflectance data from 14 wells. The kerogen composition and kinetics for bulk petroleum formation of three Middle Jurassic lacustrine samples were also determined. Differences in kerogen composition between the coaly and marine source rocks result in two principal oil windows: (i) the effective oil window for Middle Jurassic coaly strata, located at ～3800 m and spanning at least ～650 m; and (ii) the oil window for Upper Jurassic – lowermost Cretaceous marine mudstones, located at ～3250 m and spanning ～650 m. A possible third oil window may relate to Middle Jurassic lacustrine deposits. Middle Jurassic coaly strata are thermally mature in the southern part of the Søgne Basin and probably also in the north, whereas they are largely immature in the central part of the basin. HI_max values of the Middle Jurassic coals range from ～150–280 mg HC/g TOC indicating that they are gas‐prone to gas/oil‐prone. The overall source rock quality of the Middle Jurassic coaly rocks is fair to good, although a relatively large number of the samples are of poor source rock quality. At the present day, Middle Jurassic oil‐prone or gas/oil‐prone rocks occur in the southern part of the basin and possibly in a narrow zone in the northern part. In the remainder of the basin, these deposits are considered to be gas‐prone or are absent. Wells in the northernmost part of the Søgne Basin / southernmost Steinbit Terrace encountered Middle Jurassic organic–rich lacustrine mudstones with sapropelic kerogen, high HI values reaching 770 mg HC/g TOC and E_a‐distributions characterised by a single dominant E_a‐peak. The presence of lacustrine mudstones is also suggested by a limited number of samples with HI values above 300 mg HC/g TOC in the southern part of the basin; in addition, palynofacies demonstrate a progressive increase in the abundance and areal extent of lacustrine and brackish open water conditions during Callovian times. A regional presence of oil‐prone Middle Jurassic lacustrine source rocks in the Søgne Basin, however, remains speculative. Middle Jurassic kitchen areas may be present in an elongated palaeo‐depression in the northern part of the Søgne Basin and in restricted areas in the south. Upper Jurassic – lowermost Cretaceous mudstones are thermally mature in the central, western and northern parts of the basin; they are immature in the eastern part towards the Coffee Soil Fault, and overmature in the southernmost part. Only a minor proportion of the mudstones have HI values >300 mg HC/g TOC, and the present‐day source rock quality is for the best samples fair to good. In the south and probably also in most of the northern part of the Søgne Basin, the mudstones are most likely gas‐prone, whereas they may be gas/oil‐prone in the central part of the basin. A narrow elongated zone in the northern part of the basin may be oil‐prone. The marine mudstones are, however, volumetrically more significant than the Middle Jurassic strata. Possible Upper Jurassic – lowermost Cretaceous kitchen areas are today restricted to the central Søgne Basin and the elongated palaeo‐depression in the north.     

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.     

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.     

BURIAL AND MATURATION HISTORY OF THE HEGLIG FIELD AREA, MUGLAD BASIN, SUDAN

The NW‐SE trending Muglad Basin (SW Sudan) is one of a number of Mesozoic basins which together make up the Central African Rift System. Three phases of rifting occurred during the Cretaceous and Tertiary, resulting in the deposition of at least 13 km of sediments in this basin. Commercial hydrocarbons are sourced from the Barremian‐Neocomian Sharaf Formation and the Aptian‐Albian Abu Gabra Formation. The Heglig field is located on a NW‐SE oriented structural high in the SE of the Muglad Basin, and is the second‐largest commercial oil discovery in Sudan. The high is characterised by the presence of rotated fault blocks, and is surrounded by sub‐basinal structural lows. We modelled the geohistories of three wells on different fault blocks in the Heglig field (Heglig‐2, Barki‐1 and Kanga‐1) and one well in the Kaikang Trough (May25–1). The models were calibrated to measured porosity‐depth data, temperature and vitrinite reflectance measurements. Predicted present‐day heat flow over this part of the Muglad Basin is about 55 mW/m². However, a constant heat‐flow model with this value did not result in a good fit between calculated vitrinite Ro and measured Ro at the wells studied. Therefore a variable heat‐flow model was used; heat flow peaks of 75, 70 and 70 mW/m² were modelled, these maxima corresponding to the three synrift phases. This model resulted in a better fit between calculated and measured Ro. The source rock section in the Sharaf and Abu Gabra Formations was modelled for hydrocarbon generation in the four wells. Model results indicate that the present‐day oil generation window in the Hegligfield area lies at depths of between 2 and 4 km, and that oil and gas generation from the basal unit of the Abu Gabra Formation occurred between about 90 and 55 Ma and from the Sharaf Formation between 120 and 50 Ma. The results suggest that the oils discovered in the Heglig area have been generated from a deep, mature as‐yet unpenetrated source‐rock section, and/or from source rocks in nearby sub‐ basinal areas.     

四川盆地北部上三叠统须家河组煤系烃源岩生烃史

为准确认识四川盆地北部上三叠统须家河组天然气成藏过程,基于近年来煤系烃源岩生排烃特征研究的最新进展和盆地模拟技术,对该区煤系烃源岩埋藏热演化史、生烃史进行了系统研究。首先,分别建立了盆地的地质、热力学和生烃动力学模型,其次,选取古水深、沉积水界面温度、古热流值作为模拟参数,对该区17口钻井进行了模拟。结果表明：①须家河组烃源岩生气时段发生在快速沉降阶段,总体表现为快速生气的特点,元坝地区的生气时间略早于通南巴地区;②须家河组烃源岩在中侏罗世中期Ro达到0.6%,开始生气,中侏罗世晚期-晚侏罗世Ro达到0.7%,开始大量生气,晚侏罗世-早白垩世Ro达到1.0%,进入生气高峰期;③随着埋深进一步增大（在早白垩世末期达到最大埋深）,烃源岩进入高-过成熟阶段,至晚白垩世盆地整体大幅度抬升,地温降低,逐渐停止生烃。     

四川盆地侏罗系沙溪庙组天然气地球化学特征及地质意义

四川盆地侏罗系沙溪庙组天然气具有埋藏浅、成本低、周期短、见效快等优点，受到广泛的重视，是目前低油价下效益开发的重要现实领域之一。通过对侏罗系沙溪庙组天然气组分、天然气碳同位素等地球化学实验数据的分析，揭示了川西地区侏罗系沙溪庙组天然气来自于下伏的须家河组煤系烃源岩，川中北地区沙溪庙组天然气来自于下伏侏罗系湖相烃源岩，川东北地区侏罗系沙溪庙组天然气来自于下伏的须家河组煤系烃源岩和侏罗系湖相烃源岩。结合气源分析结果、构造背景和目前盆地致密气勘探开发程度，明确了侏罗系沙溪庙组浅层致密气向川西北、川中北和川东北地区进行"深化、甩开勘探开发部署"的总体方针，其中川西地区龙门山前缘北段的梓潼凹陷，川中北地区的金华、秋林、公山庙、营山地区以及川东北大巴山前缘的五宝场、渡口河地区具备良好的成藏条件，是下一步浅层致密气的重点勘探地区。     

柴达木盆地中、新生界含油气系统演化

柴达木盆地的中、新生界可划分出侏罗系、第三系和第四系三大含油气系统。其中侏罗系含油气系统的油气资源各占一半，第三系是以含油为主的含油气系统，第四系是以含气为主的含油气系统。并对这三大含油气系统的形成及演化进行了分析。根据烃源岩及其生成油气的分布，划分出各含油气系统的分布范围：侏罗系含油气系统分布在盆地北部，以北缘块断带为主的东西向展布的条带，向南可延至碱山、鸭湖、盐湖；第三系含油气系统以盆地西部——茫崖坳陷为主，向东可延至一里沟、红三旱四号、船形丘及黄石构造一带；而第四系含油气系统以盆地中-东部的三湖坳陷为主。     

PETROLEUM GEOLOGY AND HYDROCARBON POTENTIAL OF THE ADRIATIC BASIN,OFFSHORE CROATIA

Offshore Croatia is a relatively underexplored area with no oilfields currently on production. Exploration commenced in 1970 and several biogenic gas fields were subsequently discovered producing from shallow Plio‐Pleistocene reservoir rocks in the northern Adriatic area; however, exploration wells drilled for oil in Mesozoic carbonates have failed, although several wells encountered oil shows. Using data from the Croatian and Italian Adriatic, we provide in this paper some new insights into the Mesozoic palaeogeography and hydrocarbon plays of offshore Croatia. Offshore Croatia has been divided into three areas – north, central and south – with distinctive geological characteristics and hydrocarbon systems. The effects and importance of halokinesis in the eastern Adriatic is described and its influence on the petroleum systems is discussed. The evaluation of a modern, regional, high‐resolution dataset has enhanced our understanding of the Adriatic Basin and supports the presence of petroleum systems with potential mature source rocks in shales from the Triassic succession, supplying reservoir rocks in Jurassic and Cretaceous carbonate platform margins/slope talus plays, and Cenozoic siliciclastic plays.     

DISTRIBUTION OF SOURCE ROCKS AND MATURITY MODELLING IN THE NORTHERN CENOZOIC SONG HONG BASIN (GULF OF TONKIN), VIETNAM

The northern offshore part of the Cenozoic Song Hong Basin in the Gulf of Tonkin (East Vietnam Sea) is at an early stage of exploration with only a few wells drilled. Oil to source rock correlation indicates that coals are responsible for the sub‐commercial oil and gas accumulations in sandstones in two of the four wells which have been drilled on faulted anticlines and flower structures. The wells are located in a narrow, structurally inverted zone with a thick predominantly deltaic Miocene succession between the Song Chay and Vinh Ninh/Song Lo fault zones. These faults are splays belonging to the offshore extension of the Red River Fault Zone. Access to a database of 3,500 km of 2D seismic data has allowed a detailed and consistent break‐down of the geological record of the northern part of the basin into chronostratigraphic events which were used as inputs to model the hydrocarbon generation history. In addition, seismic facies mapping, using the internal reflection characteristics of selected seismic sequences, has been applied to predict the lateral distribution of source rock intervals. The results based on Yükler ID basin modelling are presented as profiles and maturity maps. The robustness of the results are analysed by testing different heat flow scenarios and by transfer of the model concept to IES Petromod software to obtain a more acceptable temperature history reconstruction using the Easy%R₀ algorithm. Miocene coals in the wells located in the inverted zone between the fault splays are present in separate intervals. Seismic facies analysis suggests that the upper interval is of limited areal extent. The lower interval, of more widespread occurrence, is presently in the oil and condensate generating zones in deep synclines between inversion ridges. The Yükler modelling indicates, however, that the coaly source rock interval entered the main window prior to formation of traps as a result of Late Miocene inversion. Lacustrine mudstones, similar to the highly oil‐prone Oligocene mudstones and coals which are exposed in the Dong Ho area at the northern margin of the Song Hong Basin and on Bach Long Vi Island in Gulf of Tonkin, are interpreted to be preserved in a system of undrilled NW–SE Paleogene half‐grabens NE of the Song Lo Fault Zone. This is based on the presence of intervals with distinct, continuous, high reflection seismic amplitudes. Considerable overlap exists between the shale‐prone seismic facies and the modelled extent of the present‐day oil and condensate generating zones, suggesting that active source kitchens also exist in this part of the basin. Recently reported oil in a well located onshore (BIO‐STB‐IX) at the margin of the basin, which is sourced mainly from “Dong Ho type” lacustrine mudstones supports the presence of an additional Paleogene sourced petroleum system.     

川东北地区热流史及成烃史研究

根据热流史及剥蚀量恢复结果对川东北地区二叠系及上三叠统两套主要烃源层的成烃史进行了研究。热流史恢复结果表明,在晚二叠世初期古热流值达到最高(可达62~70 mW/m²,井底热流),此后热流持续降低直到现今(平均约45 mW/m²,井底热流)。研究区中-新生界不整合面的剥蚀厚度最大,平均可达2 100 m. 二叠系烃源岩快速生烃时期是在早三叠世、晚三叠世及早-中侏罗世,而上三叠统烃源岩快速生烃时期是在中-晚侏罗世及晚白垩世。     

河控三角洲水下分流河道砂体储集层构型精细分析——以扶余油田探51区块为例

基于“模式拟合、动态验证”的研究思路,结合密井网区10口取心井、257口井测井资料及近10年的生产动态资料,对松辽盆地扶余油田探51区块泉四段扶余油层三角洲前缘水下分流河道储集层进行分析,探究水下分流河道储集层内部构型单元的空间展布特征及识别标志.结果表明:研究区目的层单河道砂体宽度为300~500 m,其识别标志分别为:河道间沉积、邻井砂体高程差异、河道砂体厚度差异、相邻砂体的“厚—薄—厚”组合;单河道砂体内部4级构型界面的倾角为0°~2°.明确了水下分流河道储集层中单河道砂体及单河道砂体内部增生体的测井响应特征及识别方法,建立了研究区目的层水下分流河道砂体的三维构型模型,为全区水下分流河道砂体解剖提供了定量、可靠的地质模式.图11表1参25     

PETROLEUM GEOLOGY OF THE NOGAL BASIN AND SURROUNDING AREA,NORTHERN SOMALIA: PART 1, STRATIGRAPHY AND TECTONIC EVOLUTION

In this study, 92 closely‐spaced reflection seismic profiles (～4000 line‐km) were tied to biostratigraphic and lithological data from six deep exploration wells in the poorly‐known Nogal rift basin, northern Somalia, and were integrated with outcrop and aeromagnetic data to investigate the basin stratigraphy and tectonic evolution. Aeromagnetic data show NW‐SE trending magnetic anomalies which are interpreted as plutonic bodies intruded during the Early Cretaceous, probably contemporaneously with a pre‐Cenomanian uplift phase. The aeromagnetic data also suggest a change of basement type from Inda Ad Series metasediments in the SE of the study area to igneous and high‐grade metamorphic basement in the NW. Biostratigraphic data and seismic reflection profiles define the Nogal Basin as a WNW–ESE striking half‐graben, approximately 250 km long and 40 km wide, which formed as a result of mainly Cenomanian–Maastrichtian and Oligocene–Miocene intracontinental rifting. The depocentre contains at least 7000 m of Mesozoic and Cenozoic sediments and is located in the centre of the basin (east of well Nogal‐1), to the south of the Shileh Madu Range. To the north, the basin is bounded by a major border fault along which significant variations in the thickness of sedimentary units are observed, suggesting that the fault controlled basin architecture and patterns of sedimentation. Oligocene–Miocene normal faults which resulted in north‐tilted fault blocks are widespread within the main basin; smaller‐scale sub‐basins oriented NW‐SE to WNW‐ESE are observed to the NW of the basin and probably developed contemporaneously. The Late Jurassic rift phase which has been documented elsewhere in northern Somalia is either missing in the Nogal Basin or is preserved only in localised grabens in the western and central parts of the basin. This is probably due to the pre‐Cenomanian uplift and erosion which removed almost the entire Jurassic and Lower Cretaceous successions over a wide area referred to as the Nogal‐Erigavo Arch. A more pronounced rifting episode followed this erosional event in the Cenomanian–Maastrichtian and resulted in the deposition of well‐sorted fluvio‐deltaic sandstones (Gumburo and Jesomma Formations), more than 2000 m thick. In wells in the Nogal Basin, these formations are between two and three times thicker than in wells drilled in footwall locations, and include excellent reservoir rocks sealed by transgressive mudstones and carbonates. A final rifting event in the Oligocene–Miocene was related to the opening of the Gulf of Aden. A rift sag phase which accommodated the Early Oligocene continental sediments of the Nogal Group initially developed at the centre of the basin. This was followed by a period of strong rotational faulting and tilting, which reactivated the Cenomanian–Maastrichtian structures.     

澳大利亚波拿巴盆地油气地质特征及勘探潜力

波拿巴盆地是澳大利亚重要的产油气盆地,也是世界上著名的富气盆地之一。盆地经历了古生代和中生代多期裂谷作用和新生代挤压作用,充填了15 km厚的显生宙沉积。垂向上,油气主要储集于侏罗系Montara组和Plover组;平面上,石油主要分布在武尔坎次盆和西北构造区,凝析油主要分布在萨胡尔台地和西北构造区,天然气主要分布在卡尔德尔地堑和萨胡尔台地。油气地质综合研究表明,该盆地仍具有较好的勘探前景,勘探程度中等的卡尔德尔地堑、莫利塔地堑和皮特尔次盆西北部勘探潜力较大。     

东海陆架和台西南盆地中生界及其油气勘探潜力

东海陆架和台西南盆地中生界业已成为油气勘探的新领域。构造、沉积、有机地化和储集层物性的研究表明 :该区在中生代为主动大陆边缘盆地 ;该区白垩纪岩浆活动比浙闽沿海地区弱且晚 ,对烃源岩的破坏相对较弱 ,有利于油气的生成和保存 ;该区持续的近岸和滨海环境、晚三叠世 (?)—中侏罗世温暖潮湿的古气候条件 ,有利于烃源岩的形成 ;台北坳陷南部的烃源层系为中下侏罗统 ,储集层系为白垩系 ,台西盆地和台西南盆地的侏罗系—白垩系具有类似的生储条件。台北坳陷南部、闽东坳陷北部和台西南盆地为中生界油气勘探的有利远景区     

GEOLOGY AND GEOCHEMISTRY OF SOURCE ROCKS IN THE QAIDAM BASIN, NW CHINA

In this paper, we discuss the organic geochemistry of source rocks in the Qaidam Basin, NW China, using data generated during a recent four-year study. This study addressed some basic problems concerning petroleum systems in the basin, problems which persist despite some five decades of exploration. We show that three separate source rocks are present and these are distinct in terms of both age and depositional facies and also geographical distribution.
The oldest source rocks are Lower Jurassic fresh-water lacustrine deposits which are generally confined to northern Qaidam. These are currently thermally mature or highly mature and have generated the oils, condensates and gases which have been discovered in Jurassic and Tertiary reservoirs in the North Qaidam area.
By contrast, Tertiary source rocks were deposited in saline lakes. Previous studies have shown that they are characterized by low TOC values (0.2–0.6%). However, we found Tertiary source rocks with TOC > 1.0%; these were deposited in hypersaline lakes around the Manya Depression in western Qaidam. These source rocks have probably generated the oils at fields recently discovered in the western part of the basin.
The youngest (gas-prone) source rocks in the basin are Quaternary. These were deposited in saline lakes in the east and central parts of the basin and are thermally immature. However they are thought to have generated the large volumes of biogenic gas which are present in Quaternary reservoirs.     

波斯湾盆地大气田的形成条件与分布规律

以波斯湾盆地已发现的54个大气田数据为基础,应用含油气系统的概念和分析方法,对大气田逐个进行解剖,探讨了波斯湾盆地大气田的形成条件与分布规律。研究表明,波斯湾盆地大气田的气源主要为志留系Gahkum组和Qusaiba热页岩段及白垩系的Kazhdumi组,主要储集于二叠系、侏罗系和白垩系中,受下三叠统Sudair组致密灰岩区域盖层、上侏罗统提塘阶Hith组硬石膏盖层和下—中新统下Fars组(Gachasaran组)蒸发岩系等封盖,在构造圈闭的环境下聚集成藏。区域上大气田主要分布于两个大区:前陆带和被动大陆边缘区,不同地区天然气富集的层系不同。天然气的分布主要受4个因素的控制,即烃源岩的有机质类型与热演化,储层有利的储集条件,优质的区域和直接盖层,以及侧向挤压、盐流动、基底断裂等构造因素。这些因素控制了天然气的分布区域和天然气聚集的层位。预测有利勘探区为:一是"老区"的构造型勘探目标;二是"老区"的非构造型勘探目标;三是"新区"的勘探目标。     

墨西哥湾盆地深水区油气分布特征及勘探潜力

通过分析墨西哥湾盆地油气资源勘探现状、油气地质特征,及与油气成藏密切相关的盐岩形成、演化和分布特征,进一步认识到墨西哥湾盆地上侏罗统牛津阶—第四系更新统发育了4套优质烃源岩和多套性能优越的储集层,封堵性能良好的局部和区域盖层遍布整个新生界层系,断层提供了运移通道,构造和地层圈闭发育,具有优越的生储盖等油气成藏条件。盆内中侏罗统发育一套广泛分布的厚层盐岩,很多大型油气藏均与该盐岩相关。盐上和盐下储层中均有可观的油气发现,随着油气勘探理论和技术的进步,盐下油气藏的潜力逐渐显现出来,勘探潜力很大。