НЕФТИ И КОНДЕНСАТЫ ГЕОФИЗИЧЕСКОГО И СОЛЕТСКО-ХАНАВЕЙСКОГО МЕСТОРОЖДЕНИЙ (ЗАПАДНАЯ СИБИРЬ): ОСОБЕННОСТИ СОСТАВА И ГЕОХИМИЯ

Six analyzed oils, produced from Middle Jurassic to Upper Cretaceous strata in the Middle Ob region of the West Siberian basin, show biomarker and stable carbon isotope compositions indicating an origin from the Upper Jurassic Bazhenov Formation. The chemical compositions of these oils are representative of more than 85% of the reserves in West Siberia (Kontorovich et al., 1975). Bazhenov-sourced oil in Cenomanian strata in the Van-Egan field underwent biodegradation in the reservoir, resulting in a low API gravity, an altered homohopane distribution, and the appearance of 25-norhopanes without alteration of the steranes. High API gravity oil from the Salym field has surpassed the peak of the oil window, consistent with abnormally high temperatures and pressures in the Bazhenov source rock from which it is produced. The remaining oils are very similar, including samples from Valanginian and Bathonian-Callovian intervals in a sequence of stacked reservoirs in the Fedorov field. Bazhenov rock samples from the study area contain abundant oil-prone, marine organic matter preserved under anoxic conditions. Organic matter in a Bazhenov core from the Pokachev 58 well was compared with the oils because it is thermally mature and shows total organic carbon (TOC = 13.8 wt.%) and hydrogen index values (HI = 489 mg HC/g TOC) representative of the average for the formation (10.7 wt.% for 840 samples; 420 mg HC/g TOC for 75 samples). Other rocks in the Middle Ob region are far less likely to have generated these oils than the Bazhenov Formation. No prospective source rocks older than Middle Jurassic were available. Geochemical analyses indicate a lack of thermally mature Hauterivian or younger source rocks in the study area. Core samples from the Lower Cretaceous Frolov Formation either are thermally immature (Hauterivian) or show little oil-generative potential (Berriasian-Valanginian). The Upper Jurassic Vasyugan Formation shows lower oil-generative potential than the Bazhenov Formation. The average TOC for Vasyugan rocks is 3.20 wt.% (240 samples). Average atomic H/C ratios for Vasyugan and Bazhenov kerogens are 0.90 (10 samples) and 1.13 (25 samples), respectively. The Vasyugan Formation cannot be excluded as a source rock because insufficient sample was available for biomarker analysis. Core from the Lower to Middle Jurassic Tyumen Formation in the YemYegov 15 well was compared with the oils because it is thermally mature and shows TOC and HI values (2.78 wt.% and 137 mg HC/g TOC, respectively) indicating slightly more favorable oil-generative characteristics than the average for the formation (2.75 wt.% for 720 samples; 95 mg HC/g TOC for 25 samples). The core contains terrigenous, gas-prone organic matter that shows no relationship with the analyzed oils.

Approximately half of the hydrocarbons discovered in the North Atlantic petroleum provinces are found in sandstones of latest Triassic – Jurassic age with the Middle Jurassic Brent Group, and its correlatives, being the economically most important reservoir unit accounting for approximately 25% of the reserves. Hydrocarbons in these reservoirs are generated mainly from the Upper Jurassic Kimmeridge Clay and its correlatives with additional contributions from Middle Jurassic coal, Lower Jurassic marine shales and Devonian lacustrine shales. Equivalents to these deeply buried rocks crop out in the well-exposed sedimentary basins of East Greenland where more detailed studies are possible and these basins are frequently used for analogue studies (Fig. 1). Investigations in East Greenland have documented four major organic-rich shale units which are potential source rocks for hydrocarbons. They include marine shales of the Upper Permian Ravnefjeld Formation (Fig. 2), the Middle Jurassic Sortehat Formation and the Upper Jurassic Hareelv Formation (Fig. 4) and lacustrine shales of the uppermost Triassic – lowermost Jurassic Kap Stewart Group (Fig. 3; Surlyk et al. 1986b; Dam & Christiansen 1990; Christiansen et al. 1992, 1993; Dam et al. 1995; Krabbe 1996). Potential reservoir units include Upper Permian shallow marine platform and build-up carbonates of the Wegener Halvø Formation, lacustrine sandstones of the Rhaetian–Sinemurian Kap Stewart Group and marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group, the Upper Bajocian – Callovian Pelion Formation and Upper Oxfordian – Kimmeridgian Hareelv Formation (Figs 2–4; Christiansen et al. 1992). The Jurassic sandstones of Jameson Land are well known as excellent analogues for hydrocarbon reservoirs in the northern North Sea and offshore mid-Norway. The best documented examples are the turbidite sands of the Hareelv Formation as an analogue for the Magnus oil field and the many Paleogene oil and gas fields, the shallow marine Pelion Formation as an analogue for the Brent Group in the Viking Graben and correlative Garn Group of the Norwegian Shelf, the Neill Klinter Group as an analogue for the Tilje, Ror, Ile and Not Formations and the Kap Stewart Group for the Åre Formation (Surlyk 1987, 1991; Dam & Surlyk 1995; Dam et al. 1995; Surlyk & Noe-Nygaard 1995; Engkilde & Surlyk in press). The presence of pre-Late Jurassic source rocks in Jameson Land suggests the presence of correlative source rocks offshore mid-Norway where the Upper Jurassic source rocks are not sufficiently deeply buried to generate hydrocarbons. The Upper Permian Ravnefjeld Formation in particular provides a useful source rock analogue both there and in more distant areas such as the Barents Sea. The present paper is a summary of a research project supported by the Danish Ministry of Environment and Energy (Piasecki et al. 1994). The aim of the project is to improve our understanding of the distribution of source and reservoir rocks by the application of sequence stratigraphy to the basin analysis. We have focused on the Upper Permian and uppermost Triassic– Jurassic successions where the presence of source and reservoir rocks are well documented from previous studies. Field work during the summer of 1993 included biostratigraphic, sedimentological and sequence stratigraphic studies of selected time slices and was supplemented by drilling of 11 shallow cores (Piasecki et al. 1994). The results so far arising from this work are collected in Piasecki et al. (1997), and the present summary highlights the petroleum-related implications.

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. HImax 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 Ea‐distributions characterised by a single dominant Ea‐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.

Potential hydrocarbon source rocks of Lower and Middle Jurassic age have been reported from outcrop, shallow boreholes and exploration wells in Atlantic margin basins of the UK (Hebrides, West of Shetlands and flanking the NE Rockall Trough) and, recently, in the continuation of this trend offshore Ireland (Slyne, Erris and Porcupine basins). Previously these organic-rich mudrocks were considered to be of little economic importance, due largely to their perceived limited areal distribution and low maturity. However, recent geochemical studies of oils and shales from exploration drilling of these basins shows the Lower and Middle Jurassic to have considerable potential as effective hydrocarbon source rocks, supplanting the Late Jurassic-Early Cretaceous Kimmeridge Clay Formation equivalents as the only viable oil source rock in the region. Flanking the Atlantic margin in the Irish and UK sectors, rich oil source potential occurs in two transgressive mudrock cycles of Lower Jurassic age. These are the Sinemurian-Pliensbachian interval and the overlying Toarcian section, present in basins such as the Solan, Minch, Hebrides, Slyne, North Celtic Sea, St George’s Channel and Central English Channel. The Middle Jurassic source rocks have a more limited areal distribution and occur in the Faroe-Shetland, Solan, West Lewis, West Flannan, Hebrides, Slyne and North Porcupine basins with oil source potential in regressive marginal marine to lacustrine facies mudrocks. Geochemical studies were undertaken on mudrocks from the Lower and Middle Jurassic sections in Atlantic margin basins (outcrop, shallow borehole core and exploration well cores and cuttings samples) and on oils from drill stem test and shows (core and cuttings extracts). Detailed analyses using GC, GC-MS and carbon isotopes allowed both characterization of the source rocks and oil-to-source correlation. Biomarker and carbon isotope studies of oils from the Faroe-Shetland Basin (Foinaven and Schiehallion fields), the Porcupine Basin (Connemara accumulation), the Wessex Basin (Wytch Farm and Kimmeridge oil fields) and wells in the Slyne Basin show strong correlations to the various source rock developments in the Lower and Middle Jurassic. The mixed biodegraded Foinaven and Schiehallion oils have a major waxy component and correlate with lacustrine Middle Jurassic source rocks in the Solan and West Lewis/West Flannan basins. Middle Jurassic sourcing of the Connemara oils is also suggested, while oils in the Slyne Basin appear to have been largely sourced by the Lower Jurassic Pabba Shale Formation. Oils in the Wessex Basin (Wytch Farm and Kimmeridge) appear to have been sourced by Hettangian-Sinemurian mudrocks and those in the North Celtic Sea Basin by Toarcian source rocks. The results from this study, in combination with previously published data, show that rich, effective oil-prone source rocks occur in both the Lower and Middle Jurassic of the Atlantic margin basins offshore Ireland and the UK. These source rocks can be correlated with indigenous oils, indicating the existence of a previously under-evaluated petroleum system.

Transient fluid overpressure development appears to be a major control on the contrasting petroleum systems of Faroe–Shetland Basin (FSB) on the UK North East Atlantic margin and the northern North Sea North Viking Graben (NVG). Middle and Upper Jurassic shales are the main source rocks in both the NVG and the FSB, but the hydrocarbons within these basins differ significantly. Oil is predominant with only minor associated gas in the FSB while the NVG has a significantly higher proportion of dry gas. Both are rifted basins but the amount of rifting, heat flow and depth of burial were all considerably greater in the FSB, and consequently higher maturity hydrocarbons should be present in the FSB than in the NVG. The difference in hydrocarbon type between the basins arises from the different Cenozoic burial and, importantly, pressure histories in the two basins. Oil generation commenced during the early Cretaceous in both basins and some Mesozoic reservoirs may have been charged at this time. Rapid burial of thick argillaceous sediments in both basins from the late Cretaceous into the Tertiary led to overpressure development. The thermodynamic effect of this fluid overpressure in the source rocks was the retardation of hydrocarbon generation. In the NVG, regional uplift during the Tertiary resulted in transient overpressure reductions in the source rocks such that hydrocarbon generation, which had ceased prior to the uplift events, restarted due to the pressure reduction outstripping the effects of reduced temperatures. Although the source rocks were cooler than those in the FSB, the reduction in overpressure was sufficient to result in gas generation from both the Middle Jurassic and lower part of the Upper Jurassic source rocks. Conversely, although the FSB was also uplifted during short-lived Paleogene and Neogene events, the greater thickness of argillaceous late Cretaceous sediments reduced the transient overpressure loss in the source kitchens compared with the NVG. The maturity of the source rocks in the FSB was therefore held in the late oil window and, as a consequence, oil is the predominant hydrocarbon phase in this basin. The importance of overpressure development (or lack of it) and its subsequent release has major implications for petroleum prospectivity of basins. This is illustrated using the NE Kwanza Basin (Angola) and the Mississippi Fold Belt in the Gulf of Mexico (GoM). Whereas there are no commercial hydrocarbon discoveries in the deepwater Kwanza Basin due to lack of regional seal between the oil mature Pre-Salt source and the overlying migration conduit into the shelf, significant oil reserves occur in the deepwater GOM where the source rock depth (∼10 km) might be expected to preclude the presence of oil. The key to the release of oil from the source kitchens is the salt movement that occurs during the Neogene with the formation of salt canopies. As the salt moves vertically, it reduces the overpressure, thereby enabling oil generation to restart and migrate vertically along faults.

Depositional environment and petroleum source rock potential of Mesozoic lacustrine sedimentary rocks in central Mongolia

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.

Geochemical characteristics of coal-measure source rocks and coal-derived gas in Junggar Basin, NW China

This paper addresses potential application of data on stable carbon and oxygen isotope composition of carbonates for study of organic rich source rocks on the example of the Late Jurassic–Early Cretaceous Bazhenov Formation (West Siberian petroleum basin, Russia). Geochemical studies were conducted for sections located in central (most productive) and peripheral (northern and southern) regions of the Bazhenov Formation distribution area, containing deposits formed under different conditions. We identified key factors impacting stable isotope composition of carbonate minerals and established relation of their isotope composition to the formation conditions. Using a thermodynamic model of carbon and oxygen isotope exchange in the carbonate–water–carbon dioxide system, it is shown that variations in the isotope composition of secondary carbonates are affected by isotopic composition of primary carbonates in sediments and by the isotope exchange reactions with water and carbon dioxide, generated during the source rocks transformation. Our results demonstrate that stable isotope data for carbonates in the Bazhenov Formation together with standard geochemical methods can be efficiently applied to determine sedimentation conditions and secondary alteration processes of oil source rocks.

Hydrocarbon source for oil and gas indication associated with gas hydrate and its significance in the Qilian Mountain permafrost, Qinghai, Northwest China

Analyzing geochemical characteristics and hydrocarbon generation history of the Middle and Upper Jurassic source rocks in the North Yellow Sea Basin

The Qaidam basin is a nonmarine, petroliferous basin on the northeastern margin of the Tibet Plateau. Potential source rocks are reported from Tertiary saline lacustrine deposits and Jurassic freshwater lacustrine or terrestrial strata. The Jurassic source rock is similar, in terms of depositional system, lithology, age, and organic geochemistry, to nonmarine Jurassic rocks that are thought to be potentially significant hydrocarbon sources in many basins of central Asia, including the Tarim, Junggar, and other important petroleum-producing basins. These Jurassic source rocks were deposited in freshwater lacustrine systems in intracontinental foreland-style basins during the Early and Middle Jurassic. These lacustrine strata are associated with coals and coaly mudstones with possible secondary importance as hydrocarbon source rocks. Oils from the northern Qaidam basin can be divided into two groups based on molecular indicators of depositional environment and age-diagnostic biomarkers: those derived from this Jurassic freshwater lacustrine source rock and those derived from a Tertiary hypersaline lacustrine source rock. The correlation of some Qaidam oils to a Jurassic source establishes a petroleum system involving these nonmarine Jurassic source rocks. Oils of this petroleum system have been produced from Tertiary and Mesozoic reservoirs in anticlinal and thrust-related traps in northeastern Qaidam. Maturation modeling of the Jurassic source rock indicates that these oils were generated and expelled during the Miocene-Pliocene in much of northern Qaidam. The geological context of the basin suggests that drainage within the basin primarily was vertical, probably mainly along faults, until evaporite or overpressured shale seals were encountered in the overlying Cenozoic section. Documentation of this petroleum system suggests other exploration targets remain underevaluated in northern and southwestern Qaidam; furthermore, the northern Qaidam petroleum system is a useful analog to interpret the role of similar Jurassic source rocks in other, sparsely documented, basins of central Asia.

This assessment focuses on regional 3D basin modeling through integration of a stratigraphic framework, newly defined gross depositional environments (GDEs) and lithofacies maps of Triassic and Jurassic source rocks, reservoirs, and seals that were revealed by integrating seismic interpretations and geological and petrophysical mapping in northeastern Saudi Arabia. The Triassic Jilh and Minjur formations represent two separate third-order composite sequences, consisting of proven source rocks, reservoirs (e.g., Jilh Dolomite and Minjur Sandstone), and seals. The Lower Jurassic Marrat Formation and Middle Jurassic Dhruma Formation represent a third-order and a second-order composite sequence, respectively. Proven Dhruma source rocks (equivalent of Sargelu source rocks) and a variety of grainier carbonate reservoir rocks, spanning the Marrat, Faridah, Sharar, and Lower Fadhili reservoirs, were taken into account as inputs. Well-defined depth grids, derived from regional seismic and well-based mapping and integrated GDE/lithofacies maps of Triassic and Jurassic source rocks, reservoirs and seals, have been utilized for constraining this newly built 3D basin model. This integrated 3D basin modeling has resulted in significant insights for hydrocarbon migration and charge of the Triassic and Jurassic petroleum systems. The Triassic hydrocarbon accumulations are primarily self-sourcing from Jilh source rocks, with exceptions where hydrocarbons are charged from Paleozoic source rocks due to breaching at high-relief structures (e.g., Northeastern Arabian Offshore). The Dhruma source rocks (Sargelu equivalent) primarily charged a variety of Lower and Middle Jurassic reservoirs. Additionally, basin modeling results support insights on HC migration and charge for exploration concepts related to stratigraphic traps and new play fairways.

Relationship between petroleum generation, migration and sandstone diagenesis, Middle Jurassic, Gifhorn Trough, N Germany

SummaryThe Duva oil and gas field is located at ca. 5 km northeast of the Gjøa field in the Northern North Sea. The reservoir contains oil and gas in a turbiditic sandstone of the Early Cretaceous Agat formation. Highly waxy oils were collected, and its geochemical characteristics were investigated by GC and GC-MS analyses. We performed position-specific isotope analysis (PSIA) on a gas sample from the Duva field to identify the effective source rock of the gas. 2-dimensional basin modelling was conducted to understand the petroleum system including complex migration and accumulation processes of the Duva field. The abnormally waxy oil in the Duva field possibly formed by the large input of terrestrial organic matter into the Upper Jurassic marine source rocks and/or the evaporative migration fractionation based on the biomarkers and carbon isotopic compositions. Intramolecular carbon isotopic compositions of propane in the gas sample suggested that the gas in the Duva field was generated from coals in the Middle Jurassic or older. A late charge of the gas derived from the coaly source rock into an initial oil accumulation may have caused the evaporative fractionation resulting in the formation of the waxy oil in the Duva field.