A REVIEW OF THE COALY SOURCE ROCKS AND GENERATED PETROLEUMS IN THE DANISH NORTH SEA: AN UNDEREXPLORED MIDDLE JURASSIC PETROLEUM SYSTEM?

This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (>150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up to the present day. High Middle Jurassic reservoir temperatures prevent biodegradation.     

THE PALEOCENE SANDY SIRI FAIRWAY: AN EFFICIENT “PIPELINE” DRAINING THE PROLIFIC CENTRAL GRABEN?

A new petroleum charge model is presented for the sand‐dominated Paleocene channel system known as the Siri Fairway in the Central Graben of the North Sea. The Siri Fairway is located in the platform area along the Danish ‐ Norwegian border and extends from the Norwegian palaeo shelf into the Tail‐End Graben and Søgne Basin. The nearest known expelling source rocks are located in the Central Graben. The discovery of the Siri oilfield and later the Cecilie and the Nini fields proves that petroleum has migrated through these Paleocene sandstones for up to 70 km, which is a considerable distance in the North Sea. If the Siri Fairway has acted as a “pipeline” for petroleum migrating from the Graben to the platform area, the chemical composition of the hydrocarbons discovered in the Graben and within the Fairway itself should be similar in terms of maturity and organic facies signature. This study shows this not to be the case. The Graben oils have a mature signature, whereas the oils from the Siri field have an early mature signature and are mixed with biogenic gas generated in situ. The biogenic gas “signature”, which was inherited from gas which accumulated in the trap before the arrival of the oil charge, should have disappeared if petroleum had continuously been introduced to the Fairway. It therefore appears that hydrocarbon charging to the Fairway ceased for some reason before the source rocks in the Graben entered the main oil window; the Siri Fairway therefore represents an aborted migration route, and limited charging of the Paleocene sandstone deposits in the platform has occurred. The chemical composition of the oils from the Siri field indicates that the Fairway was charged from two different basins with different subsidence histories. The Siri‐2 trap is thus interpreted to have been filled with the same oil as that found in Siri‐1 and Siri‐3, but this oil was later partly displaced by oil generated in a shallower sub‐basin. The sandstones in the Siri Fairway were deposited as turbidites and/or gravity slides in the Late Paleocene, and consist of stacked interfingering sandstone lobes which are encased to varying degrees in fine‐grained sediments. Although long distance migration through the sandstones has been proved to occur, connectivity between individual sandlobes may be problematic. The number of dry wells drilled in the Fairway and the early‐mature character of the analysed oils, together with the general absence of more mature later petroleum, indicate that migration routes in this region are limited and difficult to predict.     

SOURCE ROCK QUALITY VARIATIONS OF UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES AND THEIR RELATIONSHIP TO OILS IN THE VALDEMAR FIELD,DANISH NORTH SEA

The main source rocks for the hydrocarbons at the Valdemar field (Danish North Sea) are the Upper Jurassic – lowermost Cretaceous organic-rich marine shales of the Farsund Formation. However, geochemical analyses of retained petroleum in reservoir cores show variations in oil type and maturity which indicate a complex charging history. This paper reviews the organofacies and source rock quality variations in 55 samples of the Farsund Formation from the North Jens-1 well (Valdemar field) within a sequence stratigraphic framework in order to discuss the source of the hydrocarbons. Petrographic and geochemical data, including biomarker analyses, were integrated in order to characterize the kerogen composition, original source rock potential and depositional environment of the Farsund Formation. The thermal maturity, source rock quality and kerogen quality all vary at the sequence level, and in general change upwards from early mature, primarily gas-prone Type II kerogen in the Kimmeridgian Kimm-2 and Kimm-3 sequences to immature, highly oil-prone sapropelic Type II kerogen in the Volg-4 and Ryaz-1 sequences (Volgian, Ryazanian). The kerogen has a maceral composition dominated by fluorescing amorphous organic matter (AOM) and liptodetrinite, with variable but generally minor amounts of terrigenous organic matter. The stratigraphic distribution of organic matter is similar to that in regional observations from the Danish Central Graben but minor differences occur, especially in the amount of fluorescing AOM in the Kimmeridgian sequences. The decrease in terrigenous input (vitrinite) upwards through the marine shale succession likely reflects a marine transgression of the Danish Central Graben area during Late Jurassic time. The source potential of the Upper Jurassic – lowermost Cretaceous shales in the North Jens-1 well is generally lower than that observed regionally, including an absence of relatively organic-rich, oil-prone intervals in the older part of the succession which have been demonstrated to occur elsewhere in the Danish Central Graben. However, in agreement with the regional trend, back-calculated source rock data and calculated Ultimate Expulsion Potentials show that the uppermost Volgian (Volg-4) and Ryazanian (Ryaz-1) sequences are the most oil-prone intervals. The Ryaz-1 sequence represents a condensed section formed during a period characterised by low sedimentation rates and high preservation of algal organic matter. Biomarker compositions from source rock extracts from the North Jens-1 well cannot be directly correlated to Valdemar reservoir oils, suggesting that the mature organofacies which charged the oils are not represented in the samples from North Jens-1.     

TEMPORAL AND SPATIAL DISTRIBUTION OF ORIGINAL SOURCE ROCK POTENTIAL IN UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES,DANISH CENTRAL GRABEN,NORTH SEA

The Danish Central Graben, North Sea, is a mature oil‐ and gas‐producing basin in which the principal source rocks are the Upper Jurassic – lowermost Cretaceous marine shales of the Farsund Formation (Kimmeridge Clay Formation equivalent), with possible additional potential in the directly underlying Lola Formation. This study investigates the initial source rock potential of the basin by evaluating the original (back‐calculated) source rock properties (TOCo, S2o, HIo) of the shales in the Farsund and Lola Formations within a temporal and spatial framework. About 4800 samples from 81 wells regionally distributed in the Danish Central Graben were included in the study. Samples for source rock analysis were in general collected with varying sampling density from the entire shale section. The shale section has been divided into seven units (referred to as pre‐FSU1 to FSU6; FSU: Farsund Seismic Unit) which are delineated by mappable, regional‐scale seismic markers. For the pre‐FSU1 and FSU2–FSU6 units, the number of available samples ranged from 608 to 1145, while 433 samples were available for FSU1. Good source rock quality varies through space and time and reflects both the structural development of the basin and the effects of the Late Jurassic transgression, with primary kitchen areas developing in the Tail End Graben, Feda Graben, Gertrud Graben and the Rosa Basin. The source rock quality of the shales increases gradually through time and reaches a maximum in FSU6 which includes the “hot shales” of the Bo Member. The maximum source rock quality appears to correspond to an original Hydrogen Index (HIo) of approximately 675 mg HC/g TOC. The proportion of oil‐prone samples per unit (with HIo >350 mg HC/g TOC) ranges from 7 to 11% in the pre‐FSU1 to FSU2 units (Lower Kimmeridgian – Lower Volgian), increasing to 18 – 22% in FSU3 and FSU4/FSU5 (Lower Volgian – Middle Volgian), and reaching a maximum of 53% in FSU6 (Upper Volgian – Ryazanian). FSU6 is the most prolific oil‐prone source rock interval, but the presence of oil‐prone intervals in older and deeper parts of the shale succession is important for assessing the generation potential of the Upper Jurassic petroleum system. The breakdown of the Upper Jurassic – lowermost Cretaceous shale section into mappable seismic units with assigned original source rock properties will contribute to a considerably improved understanding of the temporal and spatial distributions of source rock quality in the Danish Central Graben.     

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.     

PREDICTING THE TIMING AND CHARACTERISTICS OF PETROLEUM FORMATION USING TAR MATS AND PETROLEUM ASPHALTENES: A CASE STUDY FROM THE NORTHERN NORTH SEA

The Northern Viking Graben area in the Norwegian North Sea was studied in order to investigate the petroleum formation characteristics of the Upper Jurassic Draupne Formation. In this area, the organofacies of the Draupne Formation, and consequently its petroleum generation characteristics, show significant variations. These variations represent a major risk, particularly in the context of basin modelling studies. Therefore, tar‐mat asphaltenes, oil asphaltenes and source‐rock samples from this area were studied in order to evaluate the use of migrated asphaltenes from petroleum reservoirs and tar mats in basin modelling. The samples were studied using bulk kinetic analysis, open‐system pyrolysis‐gas chromatography and elemental analyses, and the results were integrated into a basin modelling study. The results from these different sample materials were compared both to each other and to natural petroleum, in order to assess their significance for future petroleum exploration activities. We show that in cumulative petroleum systems, the transformation characteristics of the asphaltenes incorporate those of the individual source rock intervals which have contributed to the relevant reservoir system. Thus, the petroleum formation window predicted by the use of asphaltene kinetics is broad, and covers the majority of the formation windows predicted from the individual source rock samples. In addition, the molecular characteristics of asphaltene‐derived hydrocarbons show that compositional characteristics, such as aromaticity, correspond more closely to natural oils than to the respective source‐rock products. Our results confirm that the heterogeneous nature of the Draupne Formation results in a significantly broader petroleum formation window than is conventionally assumed. We propose that oil and tar‐mat asphaltenes from related reservoirs represent macromolecules which account for this heterogeneity in the source rock, since they represent mixtures of charges from the different organofacies. One conclusion is that the use of oil and tar‐mat asphaltenes in kinetic studies and compositional predictions may significantly improve definitions of petroleum formation characteristics in basin modelling.     

OIL CHARGE HISTORY OF BITUMENS OF DIFFERING MATURITIES IN EXHUMED PALAEOZOIC RESERVOIR ROCKS AT TIANJINGSHAN,NW SICHUAN BASIN,SOUTHERN CHINA

Low‐maturity soft bitumen (or biodegraded heavy oil) and higher maturity solid bitumen are present in Palaeozoic siliciclastics at Tianjingshan in the NW Sichuan Basin, southern China. The origin of these bitumens of variable maturities was investigated. Samples of low‐maturity bitumen from Lower Devonian sandstones and high‐ and low‐maturity bitumen from Upper Cambrian siltstones were analysed to investigate their organic geochemistry and stable isotope compositions. Lower Cambrian and Upper Permian black shales were also investigated to assess their source rock potential, and the burial and maturation history of potential source rocks was modelled using PetroMod. Liquid and gaseous hydrocarbon fluid inclusions in the Devonian sandstones were analysed. Results suggest that both the soft and solid bitumens are derived from crude oil generated by Lower Cambrian organic‐rich black shales. Reservoir rocks at Tianjingshan have experienced two separate oil charge events – in the early‐middle Triassic and early‐middle Jurassic, respectively. The first oil charge was generated by Lower Cambrian black shales in a kitchen area located in the hanging wall of the Tianjingshan fault. The later oil charge was also derived from Lower Cambrian black shales, but the kitchen area was located in the footwall of the fault. Movement on the Tianjingshan fault resulted in progressive burial of the Lower Devonian sandstone reservoir rocks until the end of the middle Triassic, and the “early” charged oil was thermally degraded into high‐maturity solid bitumen. The later‐charged oil was altered into soft bitumen of lower maturiy by biodegradation during uplift of the reservoir after the Jurassic.     

渤海湾盆地冀中坳陷霸县凹陷深层沙四段源岩有机相评价及意义

渤海湾盆地冀中坳陷霸县凹陷沙四段烃源岩为凹陷深层油气的主要来源,对沙四段不同有机相源岩进行定量描述有助于理解深层油气成藏过程.沙四段源岩有机相包括C、D/E和F相,其中C相源岩厚度较薄,总体上小于40 m,沙四段主要以D/E相和F相源岩为主,D/E相源岩厚度介于50～250 m之间.凹陷中钻揭的沙四段源岩镜质体反射率最...     

GEOCHEMICAL CHARACTERIZATION OF LOWER TOARCIAN SOURCE ROCKS FROM NW GERMANY: INTERPRETATION OF AROMATIC AND SATURATED HYDROCARBONS IN RELATION TO DEPOSITIONAL ENVIRONMENT AND MATURATION EFFECTS

The characterization of crude oils in terms of source rock facies and depositional environment, as well as their maturity and alteration stage, is a crucial element in exploration studies. The present contribution has implications for oil‐oil and oil‐source rock correlations. In the past, numerous parameters have been used for this purpose most of which are based on the analysis of saturated and aromatic hydrocarbons (including sulphur aromatics) and also on stable isotope signatures and elemental compositions. Recently, molecular indicators based on dibenzothiophene (DBT), phenanthrene (PHE) and their methyl derivatives methyldibenzothiophene (MDBT) and methylphenanthrene, as well as pristane (PRI) and phytane (PHY), have also been proposed (Hughes et al., 1995). These studies have attempted to infer a crude oil's source rock facies and lithology, and to classify the source rock's depositional environment. In the present study, the above compounds have been quantified by solvent extraction, liquid chromatography and capillary gas chromatography in 98 core samples of the Lower Toarcian Posidonia Shale Formation, a source rock in NW Germany. Most samples, cored between depths of 7m and 70 m, came from the Hils Half‐Graben in the Lower Saxony Basin. With a few exceptions from one borehole, the samples were unweathered marls or calcareous shales. The rocks contained mainly marine organic matter (Type II kerogen), the thermal maturity of which ranged from early mature to postmature (corresponding to 0.48‐1.44% mean vitrinite reflectance), therefore encompassing the range over which effective petroleum generation had occurred. We found that the influences of organic matter type and maturity on the molecular distributions of the above compounds were not obvious when interpreted in terms of a DBT/PHE vs PRI/PHY diagram. However, Principal Component Analysis (PCA) of our data‐set showed that alkylphenanthrene concentrations are strongly controlled by maturity, while the concentrations of PRI, PHY, and 1‐MDBT display a distinct source effect.     

GEOCHEMICAL CORRELATION OF OILS AND SOURCE ROCKS FROM CENTRAL AND NE SYRIA

Eighteen crude oils and seven source rock samples from the Mesopotamian foredeep, NE Syria, and from the NE Palmyrides in the centre of the country have been characterized by geochemical techniques. The presence of two oil families ("A" and "B") generated by different source rock types of different ages has been established on the basis of biomarker and carbon isotopic analyses. The data indicates that Groups A and B oils were generated by marine clastic and marine carbonate-evaporitic source rocks, respectively. Group A oils, occurring in Middle Triassic, Middle Jurassic and Upper Cretaceous reservoir rocks in the NE Palmyride area, are geochemically similar to extracts from the Lower Triassic Amanus Shale Formation. Group B oils, which are present in Middle Triassic, Middle Jurassic and Upper Cretaceous reservoirs in the Mesopotamian foredeep, are geochemically similar to extracts of the Middle Triassic Kurra Chine Dolomite and Upper Cretaceous Shiranish Formations.     

中国海、陆相页岩层系岩相组合多样性与非常规油气勘探意义

富有机质细粒沉积岩相组合和有机相之间存在着很强的相关性,富碳酸盐细粒沉积岩相组合以Ⅰ-S或Ⅱ-S型有机相为主,长英质页岩相组合多数为Ⅱ型有机相,而富粘土质页岩相组合的有机相多为Ⅲ/Ⅳ型有机质。因此,全岩矿物X衍射分析既可用于研究细粒沉积岩相与沉积环境,也可提供有机质类型、烃类产物特征、岩石力学性质和可压性等重要参考信息。在北美和四川盆地海相页岩对比分析的基础上,以中国主要陆相页岩层系为研究对象,利用全岩矿物X衍射分析,结合岩心观察、薄片鉴定、总有机碳含量（TOC）分析等多种手段,开展岩相和有机相类型识别及岩相组合特征和不同页岩层系差异性分析,并探讨它们对非常规页岩油气勘探的指导意义。研究结果表明,中国陆相湖盆沉积类型多样,陆相盆地拗陷期淡水-微咸水湖泊页岩层系以贫碳酸盐矿物的粘土质-长英质页岩相组合为主;而陆相盆地裂陷期咸化、碱化湖泊沉积以碳酸盐质页岩相组合和含碳酸盐的粘土质-长英质页岩相组合为主,各种陆相细粒沉积体系均以相带变化快、岩性-岩相复杂、储-盖组合样式多变为特征。中国陆相细粒沉积岩相的非均质性和岩相组合的多样性,带来了陆相页岩油气“甜点”类型的多样性;不同岩相组合对应的有机相存在显著差异,有机质的差异演化又带来了不同岩相中烃类赋存状态的差异性。这些分析结果证实,每套陆相页岩都具有各自的地质特点。细粒沉积岩相和有机相组合的多样性和差异性,揭示了陆相页岩油气“甜点”和资源分类评价的必要性。     

SOURCE-ROCK GEOCHEMISTRY AND HYDROCARBON GENERATION IN THE JEANNE D'ARC BASIN, GRAND BANKS, OFFSHORE EASTERN CANADA

A thick calcareous shale of Early/Middle Kimmeridgaiann age is the principal source rock for the oils discovered in the Jeanne d'Arc Basin of the Grand Bankks. This Upper Jurassic source rock forms a geological marker throughout the basin, but is not a stratigraphic marker. Its regional distribution is controlled by the tectonic and sedimentary history and the depositional enviornment. Rift tectonics in the Grand Banks during Oxfordian/Kimmeridgian times formed a series of silled, anoxic basins, which received low input of terrigenoous material from the adjacent continent. This favoured the accumulation of a thick sequence of calcareous shales rich in oil-prone, amorphous organic matter. The principal source-rock unit is generally 200-300m (656–984 ft) thick in the southern and western part of the basin and thickens in the NE to more than 700m (2,296ft). Anoxic conditions were maintained in the NE area throughout the Late Kimmeridgian. While the SW area underwent uplift and was flooded by terrigenous clastics. Detailed geochemical analysis of oils and condensates discovered in many wells allows distinction of two principal oil families of different origins: one of Jurassic source, and the other of a probable Teritary origin. Most oils found in the basin belong to the Jurassic oil family. Distinct regional variations in the maturity and composition of the Jurasssic oil family are evident. These can be explained by the regional maturity pattern of the principal source rock, and by the co-contribution of a secondary, slightly younger source-rock interval, which contains a predominantly terrestrial type of organic matter. This secondary source input is recognized in areas where the younger source rock reaches fully-mature conditions. Condensates in the centre of the basin are derived from the deeply-buried source beds at present in late- to overmature conditions. The Adolphus oil in the centre of the basin represents the second oil family, and is probably derived from a Teritary source rock. No oil-source correlation could be established due to lack of data and proper cutting samples. However, geological and heat-flow considerations suggest a Teritary source. Heat-flow values are high in the Adolphus structure as a result of salt diapirsm and the base of the Tertiary shale section is currently fully mature.     

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     

羌塘盆地三叠系、侏罗系石油地质特征和含油远景评价

羌塘盆地是发育在前泥盆结晶基底和上古生界浅变质褶皱基底之上以中生界海相沉积为主体的复合型残留盆地。它由北羌塘坳陷带、中央隆起带和南羌塘坳陷带3个二级构造单元组成,主要发育三叠系和侏罗系两套生储盖组合。北羌塘坳陷带内,三叠系及侏罗系组合发育良好;中央隆起带内基本没有侏罗系组合,三叠系组合也仅分布于倾伏部位;南羌塘坳陷带内,三叠系组合发育良好,局部范围内也有较好的侏罗系组合。青藏高原的油气勘探实践表明,该区含油远景取决于构造运动的强弱及保存条件的好坏。结合生储盖组合情况,羌塘盆地可分为3类含油气远景区:北羌塘坳陷带有利区、南羌塘坳陷带有利区和中央隆起带次有利区。      

柴达木盆地北缘东段大煤沟组一段优质烃源岩

柴达木盆地北缘地区的中 下侏罗统是主要的油气源岩,而其中的大煤沟组七段是优质油气源岩。为了进一步评价柴达木盆地北缘东段侏罗系生烃能力,系统采集了大煤沟剖面中 下侏罗统大煤沟组的泥岩、油页岩、碳质泥岩、煤岩等样品,并进行了系统的常规的有机地球化学分析（有机碳,S₁+S₂,I _H,沥青A,总烃,H/C与O/C值,干酪根,碳同位素组成δ¹³C,生物标志化合物规则甾烷的组成等）。结果表明,大煤沟组一段与七段一样,是优质油气源岩,这是柴达木盆地北缘地区的新发现。大煤沟组孢粉的显微沉积有机质组成及有机质类型的研究也证实了上述结论。在对盆地中-下侏罗统进行油气资源评价及勘探部署时,对大煤沟组一段的优质油气源岩应给予足够的重视。     

ORGANIC GEOCHEMISTRY OF CRUDE OILS AND UPPER CRETACEOUS SOURCE ROCKS FROM CONCESSION 11, WEST SIRTE BASIN,LIBYA

This paper reports the results of Rock‐Eval pyrolysis and total organic carbon analysis of 46 core and cuttings samples from Upper Cretaceous potential source rocks from wells in the West Sirte Basin (Libya), together with stable carbon isotope (δ¹³C) and biomarker analyses of eight oil samples from the Paleocene – Eocene Farrud/Facha Members and of 14 source rock extracts. Oil samples were analysed for bulk (°API gravity and δ¹³C) properties and elemental (sulphur, nickel and vanadium) contents. Molecular compositions were analysed using liquid and gas chromatography, and quantitative biological marker investigations using gas chromatography – mass spectrometry for saturated hydrocarbon fractions, in order to classify the samples and to establish oil‐source correlations. Core and cuttings samples from the Upper Cretaceous Etel, Rachmat, Sirte and Kalash Formations have variable organic content and hydrocarbon generation potential. Based on organofacies variations, samples from the Sirte and Kalash Formations have the potential to generate oil and gas from Type II/III kerogen, whereas samples from the Etel and Rachmat Formations, and some of the Sirte Formation samples, have the potential to generate gas from the abundant Type III kerogen. Carbon isotope compositions for these samples suggest mixed marine and terrigenous organic matter in varying proportions. Consistent with this, the distribution of n‐alkanes, terpanes and steranes indicates source rock organofacies variations from Type II/III to III kerogen. The petroleum generation potential of these source rocks was controlled by variations in redox conditions during deposition together with variations in terrigenous organic matter input. Geochemical analyses suggest that all of the oil samples are of the same genetic type and originated from the same or similar source rock(s). Based on their bulk geochemical characteristics and biomarker compositions, the oil samples are interpreted to be derived from mixed aquatic algal/microbial and terrigenous organic matter. Weak salinity stratification and suboxic bottom‐water conditions which favoured the preservation of organic matter in the sediments are indicated by low sulphur contents and by low V/Ni and Pr/Ph ratios. The characteristics of the oils, including low Pr/Ph ratio, CPI ～l, similar ratios of C₂₇:C₂₈:C₂₉ ααα‐steranes, medium to high proportions of rearranged steranes, C₂₉ <C₃₀‐hopane, low Ts/Tm hopanes, low sulphur content and low V/Ni ratio, suggest a reducing depositional environment for the source rock, which was likely a marine shale. All of the oil samples show thermal maturity in the early phase of oil generation. Based on hierarchical cluster analysis of 16 source‐related biomarker and isotope ratios, four genetic groups of extracts and oils were defined. The relative concentrations of marine algal/microbial input and reducing conditions decrease in the order Group 4 > Group 3 > Group 2 > Group1. Oil – source rock correlation studies show that some of the Sirte and Kalash Formations extracts correlate with oils based on specific parameters such as DBT/P versus Pr/Ph, δ¹³C_saturates versus δ¹³C_aromatics, and gammacerane/hopane versus sterane/hopane.     

Oil Families and Their Potential Sources in the Southern Gulf of Suez, Egypt

Four oil families are identified in the southern Gulf of Suez, through high-resolution geochemical studies including gas chromatography, gas chromatography-mass spectrometry, and carbon isotope analyses. Biological features characterize oils in family 1a, suggesting tertiary carbonate source rocks for these oils, rich in type II organic matter and deposited under anoxic depositional environment. Family 1b oil shows minor variations in the source of organic matter and the depositional environment, as it was derived from carbonate source rock with more algal and bacterial contribution and minor input of terrestrial organic sources, deposited under less saline condition compared to family 1a oil. Family 2 oil, although genetically related to family 1a oil, has some distinctive features, such as diasterane to sterane and pristane to phytane ratios, which suggest clay-rich source rocks and a more oxic depositional environment. Also, the lack of oleanane indicates pre-tertiary source rocks for this oil. In contrast, family 3 oil is of mixed sources (marine and non-marine), generated from low sulfur and clay-rich source rock of tertiary and/or younger age. Family 4 oil seems to be mixed from family 1b and family 3 oils, sourced mainly from carbonate source rocks rich in clay minerals with algal and bacterial contributions. Family 4 oil is highly mature, family 1b oil lies within equilibrium values (peak oil generation stage), while the other families are more or less near equilibrium.     

THE GEOLOGY AND HYDROCARBON HABITAT OF THE SARIR SANDSTONE, SE SIRT BASIN, LIBYA

The Jurassic — Lower Cretaceous Sarir Sandstone Cformerly known as the Nubian Sandstone) in the SE Sirt Basin is composed of four members which can be correlated regionally using a lithostratigraphic framework. These synrift sandstones unconformably overlie a little known pre‐rift succession, and are in turn unconformably overlain by post‐rift marine shales of Late Cretaceous age. Within the Sarir Sandstone are two sandstone‐dominated members, each reflecting a rapid drop in base level, which are important oil reservoirs in the study area. Between these sandstones are thick shales of continental origin which define the architecture of the reservoir units. This four‐fold lithostratigraphic subdivision of the Sarir Sandstone contrasts with previous schemes which generally only recognised three members. The sandstones below the top‐Sarir unconformity host in excess of 20 billion barrels of oil in‐place. The dominant traps are structural (e.g. Sarir C field), stratigraphic (e.g. Messla field), hanging‐wall fault plays (e.g. UU1–65 field) and horst‐block plays (e.g. Calanscio field). Three Sarir petroleum systems are recognised in the SE Sirt Basin. The most significant relies on post‐rift (Upper Cretaceous) shales, which act as both source and seal. The Variegated Shale Member of the Sarir Sandstone may also provide source and seal; while a third, conceptual petroleum system requires generation of non‐marine oils from pre‐rift (?Triassic) source rocks in the axis of the Sarir Trough. The intrabasinal Messla High forms a relatively rigid block at the intersection of two rift trends, around which stress vectors were deflected during deposition of the syn‐rift Sarir Sandstone. Adjacent troughs accommodated thick, post‐rift shale successions which comprise excellent source rocks. Palaeogene subsidence facilitated oil generation, and the Messla High was a focus for oil migration. Wrenching on master faults with associated shale smear has facilitated fault seal and the retention of hydrocarbons. In the Calanscio area, transpressional faulting has resulted in structural inversion with oil entrapment in “pop‐up” horst blocks. Elsewhere, transtensional faulting has resulted in numerous fault‐dependent traps which, in combination with stratigraphic and truncation plays, will provide the focus for future exploration.     

OIL-PRONE LOWER CARBONIFEROUS COALS IN THE NORWEGIAN BARENTS SEA: IMPLICATIONS FOR A PALAEOZOIC PETROLEUM SYSTEM

In this study, we assess the oil generation potential of Lower Carboniferous, liptinite-rich coals in the Tettegras Formation on the Finnmark Platform, southern Norwegian Barents Sea. Oil from these coals has been expelled into intercalated sandstones. The coals may have contributed to petroleum recorded in well 7128/4–1 on the Finnmark Platform and may constitute a new Palaeozoic source rock in the Barents Sea. The Tettegras Formation coals contain up to 80 vol.% liptinite (mineral matter free base) and have low oxygen indices. Hydrogen indices up to 367 mg HC/g TOC indicate liquid hydrocarbon potential. In wells 7128/4–1 and 7128/6–1, the coals have vitrinite reflectance R_o= 0.75–0.85 %. Compared to shale and carbonate source rocks, expulsion from coal in general begins at higher maturities (R_o= 0.8–0.9% and T_max= 444–453°C). Thus, the coals in the wells are mostly immature with regard to oil expulsion. The oil in well 7128/4–1 most likely originates from a more mature part of the Tettegras Formation in the deeper northern part of the Finnmark Platform. Wide variations in biomarker facies parameters and δ¹³C isotope values indicate a heterogeneous paralic depositional setting. The preferential retention by coal strata of naphthenes (e.g. terpanes and steranes) and aromatic compounds, compared to n-alkanes and acyclic isoprenoids, results in a terrigenous and waxy oil. This oil however contains marine biomarkers derived from the intercalated shales and siltstones. It is therefore important to consider the entire coal-bearing sequence, including the intercalated shales, in terms of source rock potential. Coals of similar age occur on Svalbard and Bjørnøya. The results of this study therefore suggest that a Lower Carboniferous coaly source rock may extend over large areas of the Norwegian Barents Sea. This source rock is mature in areas where the otherwise prolific Upper Jurassic marine shales are either immature or missing and may constitute a new Palaeozoic coal-sourced petroleum system in the Barents Sea.