Source Rock Sequence Research Articles

Deciphering the laminated botryococcus-dominated shales in saline lacustrine basin, Western Qaidam Basin, NW China: Implications for shale oil potential

Given the high lipid content and potentially huge biomass, the explosive occurrence Botryococcus is regarded as a significant marker of high-quality oil source rocks in petroliferous basins. However, they are rarely discovered in saline lacustrine source rocks, and the formation mechanism of these alga-rich shales remains uncertain. In this study, abundant Botryococcus fossils were firstly found, accounting for an average of 43.5% of the total organic debris from the upper Xiaganchaigou Formation in the Yingxiongling and Zhahaquan hydrocarbon-rich sags of the western Qaidam Basin. The Botryococcus-dominated palynofacies assemblages were usually interpreted as derived from a distal oxic shelf environment. These Botryococcus-dominated sediments were characterized by a perfect laminated texture and composed of detrital, carbonate, and clay laminae. The Botryococcus fossils exclusively occur in the detrital laminae with large-grained quartz and feldspar and low carbonate content, possibly reflecting increased river input under relatively heavy precipitation. The cyclothymic deposition between these Botryococcus-rich detrital laminae and other laminae probably indicates that sufficient terrestrial nutrient inputs and lake salinity decreases driven by periodic heavy precipitation result in Botryococcus bloom under fresh or brackish water environments. These Botryococcus-dominated shales in the western Qaidam Basin usually have a high oil-prone hydrocarbon generation potential, as evidenced by their organic geochemistry parameters. These sediments have biomarker features extremely similar to crude oil with a high relative abundance of C20–C24 tricyclic terpanes, phytane, C27ααR sterane, and a unimodal distribution of n-alkanes with the maximum at n-C18. Therefore, these Botryococcus-dominated shales are possibly important oil sources of these prolific oil sags. Additionally, these high-quality source rock sequences can reach a few tens of meters in thickness and evidently have significance for future shale oil resources.

Organic-rich source rock/H2/brine interactions: Implications for underground hydrogen storage and methane production

There is increasing global interest in the attainment of a carbon dioxide-free global economy by replacement of carbon-based fossil fuels with clean hydrogen. But huge volume of hydrogen needs to be stored to address the imbalance between energy demand and supply due to low volumetric energy content of H2. Underground Hydrogen Storage (UHS) is an integral part of the hydrogen economy value chain and an appealing technology for the attainment of global decarbonization. The Jordan oil shale (Upper Cretaceous, organic-rich source rock sequence) has been proposed as a promising geological storage medium for hydrogen due to its exceptionally high organic content because methane can be produced from the reaction of trapped hydrogen with the kerogen. However, the extraction of methane from kerogen during hydrogen storage in organic-rich shale has not yet been reported. In this study, pressurized hydrogen was injected into high TOC shale samples for 80 days at 1500 psi and 75 °C to assess the extent of hydrogen-rock reaction and possible methane production. We also measured H2/brine and CH4/brine interfacial tensions (IFT), as well as the contact angles of H2/brine/shale and CH4/brine/shale systems at 75 °C and varying pressure (500–1500 psi) to understand the shale-fluid interaction at subsurface conditions. Results indicate some reaction of H2 with the shale after 80 days. No hydrogen sulfide was detected from gas chromatography analysis at the end of the experiment, but traces of methane (0.018 %) were detected. The reaction between hydrogen and organic matter of the shale yielded only a little methane under the conditions investigated in this research, possibly because the experimental temperature and reaction time was insufficient for copious methane generation. Furthermore, contact angle values of CH4/brine were found to be higher than of H2/brine. This means that under geo-storage conditions, the surface becomes fully CH4-wet condition (131o-149o) but remains only intermediate-wet in the presence of the H2/brine system (94o -106o) with increasing pressure, confirming that the interaction of methane with the shale surface is higher than hydrogen-shale surface interaction at similar conditions. The opposite trend was observed for IFT values. The hydrogen/brine IFT was 69.4 mN/m at 500 psi but decreased to 67.9 mN/m at 1500 psi. Likewise, the methane/brine IFT decreased from 69.7 mN/m to 58.3 mN/m with increasing pressure from 500 to 1500 psi. The findings of this study contribute to a better understanding of the adsorption trapping potential of organic-rich source rocks.

On the determination of oil charge history and the practical application of molecular maturity markers

Determining the thermal maturity and the charge history of crude oil to any reservoir, has key implications for understanding petroleum generation, accumulation history and hence identification of exploration potential. In this paper we combine studies of several source rock sequences and associated crude oils using quantitative component concentration data in addition to traditional molecular marker ratio parameter approaches. The case history studies include examination of organic-rich sapropelic marine source rocks from the Second White Speckled Shale Formation (2 WS Fm.), in the Western Canada Sedimentary Basin and the upper Jurassic Draupne Fm. in the North Sea and their related oils. Each molecular component in the petroleum has a unique concentration evolution curve during source rock maturation, in which n-alkanes, light aromatic hydrocarbons and diamondoid hydrocarbons increase in concentration with increasing maturity, while biomarkers decrease in concentration with maturity. This maturity dependent concentration variation plus the ubiquitous mixing of multiple oils in the reservoir is a key process that complicates the direct application of qualitative molecular marker ratio approaches to analysis of petroleum systems. We suggest an alternative maturity assessment approach using maturation calibrated curves of absolute concentrations of biomarkers and other alkanes in petroleum, coupled with selected aromatic hydrocarbon ratios to track the maturity/petroleum mass fraction relationships for a reservoired oil mixture in a more complex but realistic manner. Isoprenoid alkanes show less variation in concentration with maturity than other components and may be used as an internal reference point for mass fraction maturity and charge history assessment. Using component concentration data normalized to the concentration of the isoprenoid alkanes and calibrated using source rock analyses at different maturity levels from a single petroleum system (2WS), a simple mass balance model was constructed that allowed aggregate concentration data to be calculated for any mixture of oils produced in a prescribed oil charge history. In principle any charge history can be simulated using this approach and comparing the modelled and actual quantitative compositional profiles of crude oils allows differentiation of the more plausible and implausible oil charge histories for that particular reservoir. Clearly considerable refinement of this approach is needed but it appears that such a procedure has the potential, if developed further, to be a useful addition to the arsenal of petroleum geochemists and basin modelers. Knowing what a typical complete charge mass fraction maturity profile would look like for a given source rock type, enables the estimation of missing charge in the basin, allows the detection of complex multi-history charge scenarios, and provides a much more robust and complete data set for calibration of basin model charge history assessments. It also, with further development may be integrated into stochastic basin modelling approaches to study petroleum systems.

Study of mechanism for petroleum generation, migration and accumulation, block 04-3, Nam Con Son basin

Exploration drilling and production results in block 04-3 confirmed oil and gas potential on the Thien Ung-Mang Cau prospect. The remaining potential prospects that are not drilled should continue to be studied and evaluated for petroleum potential. The purpose of this paper is to integrate and digitize the data from results of facies and environment studies, petrographic characteristics, and geochemical data to simulate the petroleum system model to determine the processes of generation, migration, the mechanism for hydrocarbon trap charging, and distribution of petroleum accumulations. Based on the reality of successful oil and gas discovery and exploration in block 04-3, the process of building a 3D petroleum system model is settled and consists of four main steps: input data combined with boundary conditions, running simulations, assess model results and adjusting data. Utilizing studying the role and contribution of hydrocarbon composition in the source rock, the migration direction, the paper clarifying the generation process, the trend of distribution, and the assessment of the hydrocarbon migration and charging mechanism in block 04-3 area. The results of digitalization of data on the geochemical analysis of effective source rock, building facies modeling and the sedimentary environment, boundary conditions models, and 1D models, the 3D petroleum system model has successfully simulated. The results allow to draw following findings: there are two formations of source rock Oligocene (H-150) and lower Miocene (H-80), in which the source rock belongs to the Oligocene sediment section at 16.5 Ma in the oil generation phase and 10.5 Ma - 5 Ma mostly in the late oil to wet gas and condensate production phases, this source rock plays a crucial role in hydrocarbon generation; hydrocarbon accumulations formed in the suitable trap mechanisms within Oligocene and Miocene periods in the with channel deposits, deltaic (fluvio-deltaic) environments, preserved in stable conditions until hydrocarbon accumulation established in which contribution mainly from Oligocene-aged claystone source rocks; Two potential accumulation groups existence in block 04-3 also revealed: the Hai Au structure and the Hoang Hac structure with the Oligocene, lower Miocene, and middle Miocene reservoirs. The results of the model will be used to propose the allocation of exploration wells for evaluating the remaining oil and gas potential accumulations in block 04-3. Furthermore, the study not only focuses on evaluating the effective source rocks, determination of the main hydrocarbon charging area, the migration process and mechanism for the petroleum-filled trap but also clarify the role of effective source rock sequences for providing hydrocarbon of potential petroleum accumulation in the study area.

Basin modelling and bulk kinetics of heterogeneous organic-rich Nyalau Formation sediments of the Sarawak Basin, Malaysia

The investigation of the Nyalau Formation and its offshore equivalents (Cycles I and I) using 1D-basin modeling was carried to evaluate the timing and maturity aspects of their petroleum system. The Nyalau Formation and its offshore equivalents show a very remarkable source rock sequence for oil and gas in the Sarawak Basin. About twenty typical samples of the Nyalau Formation, with its maturity range beginning at immature to early-mature were evaluated, adopting bulk and quantitative pyrolysis procedures to reveal the kerogen characteristics and define the inherent optical properties of the organic matter and the effect it has on petroleum generation. Pyrolysis data identified two organic facies that indicate petroleum generation tendencies; Kerogen Type II/III having fairly high values of hydrogen index (HI) above 200 mg HC/g TOC whilst the kerogen Type III is comparatively with low HI values below 200 mg HC/g TOC. The aforementioned is reinforced with respect to distribution appertaining to energy activation a derivative of the bulk kinetic analysis. This study in a wide distribution of energy activation of kcal/mole to 69 kcal/mol which is unswervingly correlated heterogeneously to the organic matter. Also, the bulk kinetic analysis shows substantial variation in petroleum formation tract with regards to onset as well as the Nyalau's source rocks samples peak generation temperatures.At the temperatures between 121 and 131 °C petroleum generation for kerogen Type II/III commenced while at the temperatures of 134–145 °C for kerogen Type III. There is a variation of the peak generation temperatures (geological temperature maximum) in the range of 135–142 °C for Type II/III kerogens, whilst 153–167 °C for kerogen Type III. A notable transformation ratio of about 33% is reached as a result of these peak generation temperatures. The results were then integrated into the basin modelling, thereby predicting the timing, generation, and expulsion of hydrocarbons from the Nyalau equivalent source rocks in the offshore basin. This models suggests the onset of petroleum generation from Nyalau source rocks began in the Early Miocene (23-16 Ma), and the generation peaked at the Middle Miocene (18-12 Ma). The evolution and the expulsion of hydrocarbon as modeled indicate the timing of the expelled petroleum commenced in Pliocene and continued to present-day (5–0.0Ma). One dimensional basin models and bulk kinetics provide a quantitative way of predicting the timing, generation, and expulsion of hydrocarbon from Nyalau Formation within the Sarawak Basin.

DIAMONDOIDS AND BASIN MODELLING REVEAL ONE OF THE WORLD'S DEEPEST PETROLEUM SYSTEMS, SOUTH CASPIAN BASIN, AZERBAIJAN

The South Caspian Basin has been one of the world's most prolific petroleum provinces since the 19th Century. However, despite the large number of discovered petroleum accumulations, the source rock sequence has not been penetrated by the drill in the offshore basin and is therefore poorly defined. In this paper, geochemistry together with broad estimates of in‐place volumes of petroleum fluids, onshore outcrop data and basin modelling have been used to place constraints on the source rock description.Diamondoids, the most thermally stable group of hydrocarbons, have been measured in a suite of liquid petroleum samples from Pliocene fluvio‐deltaic sandstone reservoirs at the Shah Deniz gas‐condensate field and the Azeri‐Chirag‐Gunashli oil field, offshore Azerbaijan. Samples from both fields exhibit elevated concentrations of diamondoids and C29 steranes, indicating a mixture of thermally cracked and non‐cracked petroleum. We use diamondoid concentrations to estimate that 4.8 B brl of oil may have been cracked to 12 Tcf of gas below the Shah Deniz reservoirs. Source rock properties from the outcropping Oligocene – Miocene Maikop and Diatom Formations have been used to model source rock maturation. The results indicate that pre‐cracking volumes of petroleum could be explained reasonably by the presence of source rock intervals in the offshore that are of similar richness but increased thickness compared to measured onshore outcrops.Relatively high diamondoid concentrations in Shah Deniz condensate (up to 160 ppm 3‐ + 4‐methyldiamantanes) are in agreement with gas isotope compositions (δ13C1 – δ13C3) with respect to thermal maturity. Both parameters indicate the presence of source rock that is at a high level of thermal maturity at a vitrinite reflectance equivalent (VRE) of ca. 1.5–2.0% Ro. Given the low geothermal gradients in the South Caspian Basin (16 – 17°C/km at Shah Deniz) and the relatively high temperatures required for maturation due to rapid, relatively recent burial and heating, the source rock must be buried to depths in excess of 13 km in the Shah Deniz drainage area. In the absence of any evidence of a working Mesozoic petroleum system in the South Caspian Basin, this depth of burial highlights the significant thickness of Paleogene sediments in the offshore basin. Of prolific petroleum‐producing basins, only in the deep‐water Gulf of Mexico are actively‐generating source rocks buried to similar depths.

Reconstruction of hydrocarbon generation and accumulation on the Gydan Peninsula and adjacent offshore areas using basin modeling approach

Based on structural and lithological grid models, a three-dimensional numerical dynamic model of the Mesozoic-Cenozoic sedimentary cover of the Gydan source kitchen and adjacent territories was built. The thermal history of sediments was reconstructed. A map of effective deep heat flow was compiled. A good agreement was found between the measured and calculated degrees of catagenetic transformation for Upper Jurassic rocks. The possible types of kerogens from the main Jurassic and Cretaceous source rock sequences were justified. The study also provides assessments of the volumes of hydrocarbon generation from the main source rock sequences, timing of formation of regional seals and possible extent of hydrocarbon accumulation in structural traps.

Hydrocarbon potential of the Lower Cretaceous mudstones in coastal southeastern China

The Cretaceous hosts the highest hydrocarbon potential among all geological stratigraphic sequences worldwide, and the Lower Cretaceous in coastal southeastern China, with the development of black mudstones and shales, has potential for hydrocarbon generation. This potential, therefore, is of significance to regional hydrocarbon exploration both onshore and offshore; however, it has not been investigated in detail. Here, we address this issue based on the results of integrated organic geochemistry and petrology of four representative outcrop sections in the region. Results show that there are two possible source rock sequences in the Lower Cretaceous of coastal southeastern China, that is, a lower sequence represented by the Bantou Formation black mudstones in the Fujian Province and an upper interval represented by the Guantou Formation black mudstones or calcareous mudstones in the Zhejiang Province. The organic matter abundance of these two formations reaches levels of poor to good source rocks. The kerogen is dominated by type III, whereas type II can also be found locally in the northwestern Fujian Province. Most samples are highly mature to overmature, except for the samples with less influence of volcanism in the northern Guangdong Province. Comparatively, the organic matter abundance of the early-stage source rocks is higher than for the late-stage rocks, and the kerogen type is less favorable; however, the maturity shows little correlation with age and is largely related to volcanism. Therefore, the Lower Cretaceous in coastal southeastern China seems to have hydrocarbon potential (gas in particular) in local areas, including the northern Guangdong Province and its analog in offshore basins for the early stage and the northwestern Fujian Province and its analog in offshore basins for the late stage. These results and understanding provide insights for expanding new hydrocarbon exploration targets in southeastern China both onshore and offshore and may also have implications for understanding the regional Cretaceous geology.

Modeling of the Thermal Evolution of the Sedimentary Cover and the Maturity of Organic Matter in the Source-Rock Sequences of Sedimentary Basins of the East Siberian Sea

In this paper 2D and 3D modeling of thermal evolution of sedimentary cover and OM evolution of the source-rock sequences (SRSs) of the East Siberian Sea were conducted. The distribution of the temperature and reflection of vitrinite in sedimentary cover is presented along the composite seismic profile of the section. Maps of the distribution of the temperature of sedimentary sequences, reflection of vitrinite of the SRSs for various temporal boundaries, and the degree of OM transformation of the SRSs for the presentday stage of evolution were plotted. The evolution of OM maturity and possible processes of hydrocarbon generation of the SRSs were analyzed on the basis of modeling results.

Control of facies, maturation and primary migration on biomarkers in the Barnett Shale sequence in the Marathon 1 Mesquite well, Texas

A great deal is known about the genetic relationships between biomarkers and their biogenic precursors in organic rich rocks. The same is true of the way in which biomarker compound ratios change during maturation. On the other hand, very little is known about whether a crude oil can fully retain its inherent compositional ancestry during expulsion from a source rock. Thanks to shales being characterized in great detail for their unconventional resource potential, new information is gradually coming to light. Here we report on observations in biomarker geochemistry of a thermally mature core of the Barnett Shale, in which organofacies and maturity are essentially the same, but where intraformational sources and reservoirs have already been reported.Our results indicate that most biomarkers are not fractionated as the primary migration of petroleum within source rocks takes place. The 20S/(20S + 20R) ratio of C27 steranes is uniform in the whole source-rock sequence, while the 20S/(20S + 20R) ratio of C29 steranes shows indistinctly high values in the reservoir unit. The 20S/(20S + 20R) ratio of diasteranes and the 22S/(22S + 22R) ratio of C31 17α-hopanes do not appear to have been fractionated, which may be a result of the thermal isomerization reactions predominating over and masking out the possible fractionation effects. Diasteranes/steranes ratios do not exhibit features that suggest an association with fractionation, but rather are broadly correlated with lithology. However, compared to the diasteranes/steranes ratios, the Ts/(Ts + Tm) ratio is much more sensitive to changes in mineral compositions. Variations in the Ts/(Ts + Tm) ratio show a positive correlation (R2 = 0.73) with mixed-layer illite-smectite content. Fractionation in the Ts/(Ts + Tm) ratio, if it has so occurred, may be subsequently overprinted by in-situ clay-catalyzed reactions.

The petroleum prospectivity of the Oobagooma Sub-basin and adjacent Leveque Platform, North West Shelf, Australia

The Oobagooma Sub-basin of the Roebuck Basin includes the offshore extension of the onshore Fitzroy Trough of the Canning Basin. Together with the Leveque Platform, it covers an area of approximately 50,000 km2, yet only 14 exploration wells have been drilled in the area to date, five of which were drilled in the past 30 years. The sub-basin contains sediments ranging in age from Ordovician to Recent. This study examines the petroleum prospectivity of a region that is one of the least explored on Australia’s North West Shelf. Recent exploration drilling has revived interest in the area, with the 2014 Phoenix South–1 oil discovery in the offshore Bedout Sub-basin and the 2015 Ungani Far West–1 oil discovery in the onshore Fitzroy Trough. The two most significant source rock sequences relevant to the Oobagooma Sub-basin are the Carboniferous Laurel Formation and the Jurassic section. The former interval is part of a proven petroleum system onshore and is the source of the gas discovered at Yulleroo and oil at Ungani and Ungani Far West. A thick Jurassic trough to the north of the Oobagooma Sub-basin is believed to be the source of the oil and gas in Arquebus–1A and gas in Psepotus–1. Hydrocarbon charge modelling indicates significant expulsion occurred during both the Cretaceous and Tertiary from both source intervals. Trap timing is generally favourable given that inversion structures formed in several episodes during the Late Jurassic to Late Tertiary. The Early Triassic, now proven to be oil prone in the Phoenix South area (Molyneux et al, 2015), provides an additional (albeit less likely) source for the Oobagooma Sub-basin. These rocks are thin to absent within the Oobagooma Sub-basin, so long-distance migration would be required from deep troughs to the west.

Geochemistry, origin and accumulation of continental condensate in the ultra-deep-buried Cretaceous sandstone reservoir, Kuqa Depression, Tarim Basin, China

A continental condensate field, with the deepest burial depth (7084 m) so far in China, was recently discovered from the Cretaceous sandstone reservoir in the Bozi area of the Kuqa Depression, Tarim Basin. In this paper, we report general features of this field, including geochemistry of the condensates, their origin, and migration and accumulation. General geochemistry of the condensate reflects that it is an over pressured condensate reservoir. Analytical results by newly-developed high-resolution GC × GC–TOFMS method indicate that the condensate is rich in n-alkanes from nC3 to nC34 and in diamondoid hydrocarbons with a high content of adamantanes. The condensate has a high abundance of aromatic hydrocarbons. The gas δ13C2 values in these are −23.3‰, which is characteristic of coal-derived gases. Compared with the contents of conventional condensate oils, the BZ1 well has a high content of aromatic hydrocarbons, suggesting that the condensate is in a stage of highly mature cracking. Analyses of oil biomarkers, carbon isotopes, gas compositions, etc., revealed that the condensate is dominantly sourced from the highly mature coals of the Jurassic Qiakemake Formation in the western Kuqa Depression. This set of coal source sequences has generated large quantities of condensate since 3 Ma, when the study area was subjected to a rapid subsidence with sediments over 2000 m and consequently attained at the condensate-generating stage. Such condensates then migrated vertically into the Cretaceous traps along faults. Therefore, the Bozi condensate field is a typical case of large-scale oil/gas field characterized by late-stage accumulation. Multiple elements favor the formation of this large-scale condensate field. The timing of trap formation accords with that of the condensate generation (since 3 Ma). The traps and source rocks are stacked vertically. Faults connect the source rock sequences and the reservoirs. The hydrocarbon charge is strong and efficient. Thick Paleogene gypsum beds act as an excellent cap rock, favoring the accumulation and preservation of the condensate.

Petroleum source rocks of the Arctic region

Criteria for defining petroleum source rocks (PSR) in the Arctic region are analyzed. Lithological composition of rocks, quantitative parameters of organic matter in them, biomarker composition of hydrocarbons, and carbon isotope compositions of bitumens and oils are given. Based on the synthesis of these materials, the formation conditions of organic matter, its nature, hydrocarbon-generating potential, and contribution of different sources to oil accumulations are interpreted. The PSR distribution in sedimentary basins of three best studied sectors with the high petroleum resource potential (Norwegian, West Russian, and North American) is considered. These regions are characterized by regionally discontinuous patterns of source rock distribution. The high-quality source rock sequence of Upper Devonian-Lower Carboniferous domanikites exhibits wide distribution, while Upper Triassic, Lower Jurassic, and Neocomian PSRs of North Alaska and Upper Jurassic bazhenovites of the West Russian Arctic sector are less developed. Inconsistency between the positions of PSRs in the stratigraphic section is determined by local, frequently asynchronous tectonic phases. Regularities revealed in the PSR distribution within the sedimentary cover of the Arctic region are used for their prediction through the East Russian sector.

Source rocks in sedimentary basins of continental margins in the early paleozoic

During the Paleozoic, epochs with the relatively cold climate alternated with epochs marked by significant warming. Moreover, cooling epochs were characterized by the substantial sea level fall, while warming was accompanied by its rapid rise. In many basins located at margins of Laurentia, Baltica, and the North China continental block, such an alternation is reflected in the structure of sedimentary sequences and the lateral/vertical distribution of reservoirs, confining beds, and source rocks. Despite the fact that sediments with high concentrations of sapropelic OM accumulated in different periods, their distribution areas on continents and their margins became highly reduced during cold epochs, when these sediments filled mostly rift troughs and foreland basins. After the colonization of land by higher plant communities in the Carboniferous and Permian sediments deposited during cold epochs, the humic material became an important constituent of OM in the source rock sequences.

Marine influence helps preserve the oil potential of coaly source rocks: Eocene Mangahewa Formation, Taranaki Basin, New Zealand

Many Cretaceous–Cenozoic coaly source rocks in Australasian and southeast Asian basins were deposited in coastal plain environments, yet the effect of early diagenetic marine influence on their oil potential is not well understood. An integrated organic geochemical and petrographic study of humic coals from the Eocene Mangahewa Formation (Taranaki Basin, New Zealand) was undertaken with coals predominantly from raised mire petrofacies, with subordinate proportions from planar mires. The total S content of 0.63–4.4% (dry, ash-free) indicated very slight to strong degrees of marine influence. Other than minor addition of inferred mangrove derived suberinite and associated liptodetrinite, the degree of marine influence had no obvious effect on maceral or plant tissue abundance. However, hydrogen index (HI) values were up to ca. 150% (109mgHC/gTOC) higher, and total (C6+) oil potential up to ca. 140% (43mg/gTOC) higher among the more strongly marine influenced coals. Correlation of organic S with solvent extract parameters pristane/phytane, C27–C29 diasteranes/steranes, C29 steranes/hopanes, C35/(C35+C34) homohopanes and oleanane index suggested that inundation of brackish water into the early diagenetic peat forming environment enhanced the bio-resistance of higher plant and other lipids through sulfurization, thereby helping to preserve more of the inherent H content and total oil potential of the original peat biomass. Conversely, marine influence had only a minor effect on the capacity of Mangahewa coals to generate paraffinic oil. Total (n-C6+) and non-volatile (n-C15+) paraffinic oil potentials were instead controlled primarily by the abundance of leaf derived cutinite and associated liptodetrinite. This, in turn, was dependent on the type of peat mire facies, with planar mire facies having better potential for preservation of leaf litter than raised mire facies because of their generally higher groundwater level. Marine influence is nonetheless beneficial for paraffinic oil charge from coaly source rock sequences in that the associated higher HIs enhance the efficiency and quantum of paraffinic oil expulsion through increased saturation of the coal pore system.

Oil source rocks at mesozoic and cenozoic continental margins: Communication 2. Oil source rocks at continental margins in the second half of the cretaceous and in the Cenozoic

Oil source rocks represent sequences with the Corg content ranging from 3–5 to 15–20%. Sedimentary sections of large petroliferous basins usually include one or two such sequences, which generated liquid and gaseous hydrocarbons (HCs) during their long-term subsidence to the elevated temperature zone. The middle episode of the Late Cretaceous was marked by the accumulation of sediments with a high Corg content in different areas of the World Ocean. However, truly unique settings favorable for accumulation of the sapropelic organic matter (OM) appeared at continental margins that primarily faced the Tethys Ocean. The La Luna Formation is one of the best known source rock sequences responsible for the generation of liquid HCs in basins of the Caribbean region. In the Persian Gulf, the Kazhdumi Formation composed of marls and clayey limestones is considered the main oil-generating sequence. In the Paleogene after closure of the Tethys, the Pacific continental margins became the main domains that accumulated source rocks. The maximal deposition of sapropelic OM in this region corresponded to the early-middle Eocene. In the Neogene, the accumulation of source sediments was associated with deltas and submarine fans of large rivers and with upwelling zones. In basins of the Californian borderland, the main oil-generating sequences are represented by siliceous rocks of the Monterey Formation. They were deposited in a regional upwelling zone related to the cold California Current.

Bulk kinetic parameters and structural moieties of asphaltenes and kerogens from a sulphur-rich source rock sequence and related petroleums

Non-isothermal open system pyrolysis-gas chromatography and bulk petroleum generation experiments were performed on type II-S petroleum asphaltenes, source rock asphaltenes and related kerogens to evaluate petroleum composition and generation timing. The results show that, contrary to convention, there are significant differences in the reactivity between petroleum asphaltenes and their related kerogens in the studied type II-S petroleum system and these samples yield kinetic models that predict onset, peak, and completion of petroleum generation under different temperatures. Petroleum asphaltenes and source rock asphaltenes are less stable and show tighter petroleum formation windows than kerogens when extrapolated to geological heating rates. Source rock asphaltene, related kerogen, and oil asphaltene pyrolysates possess structural differences as revealed in the aromaticity and organic sulphur content. Aromaticity was highest in pyrolysates of source rock asphaltenes, intermediate in kerogen pyrolysates, and lowest in pyrolysates from petroleum asphaltenes. In addition, the highest organic sulphur content was identified in kerogen pyrolysates, whereas pyrolysates of both source rock and petroleum asphaltenes are similar in organic sulphur content. Thus, the amount of organic sulphur is not proportional to the reactivity of petroleum generation from asphaltenes at lower thermal stress. It is more likely that kerogens and asphaltenes possess different configurations and types of sulphur bonds resulting in cracking of covalent bonds at different levels of thermal stress.

Stratigraphy, structure and petroleum potential of the Lady Franklin and Maniitsoq Basins, offshore southern West Greenland

The Lady Franklin Basin, which contains a thick succession of Cretaceous and Cenozoic sediments, constitutes the western part of the southern West Greenland offshore area. In the Davis Strait and Labrador Sea region rifting was initiated in the earliest Cretaceous and a number of basins formed. In time these basins deepened, although subsidence was interrupted by two main phases of uplift and erosion that took place in middle and late Cretaceous time, resulting in two hiatuses in the succession. Sediments with source or reservoir potential were deposited in the basins. Source rocks are known to occur in the marine Cretaceous successions of onshore northern Canada and central West Greenland and also offshore eastern Canada, and can therefore be expected to occur in the Lady Franklin and Maniitsoq basins. In the Lady Franklin area Paleocene volcanism associated with further tectonism caused the eruption of flood basalts and hyaloclastites on top of the Cretaceous mudstone and sandstone succession. A Lower Palaeogene sediment succession, which may contain both source and reservoir rocks, was then deposited on top of the basalts, as seen in the nearby Canadian Hekja O-71 well. Around the Ypresian to Lutetian transition a regression took place. The regression gave rise to an unconformity and a hiatus spanning a few million years throughout the entire West Greenland shelf. New deposition followed and, after a long period, major compression set in and a regression occurred across the whole shelf in Late Oligocene time. Erosion set in and was deep on the southern shelf, resulting in a hiatus spanning about 39 Ma. To the north the hiatus is only about 19 Ma. In early Middle Miocene time the tectonic regime in the Davis Strait area changed. Subsidence and deposition resumed offshore West Greenland. These events may have created conditions for generation of hydrocarbons in the potential source-rock sequences in the Cretaceous succession. Therefore, although hydrocarbon exploration has been limited in this region and had little success, it is thought that conditions are favourable for the discovery of significant oil and gas accumulations.

The Permian hybrid petroleum system in the northwest margin of the Junggar Basin, northwest China

In this paper, we define the concept of a hybrid petroleum system for the Permian petroleum system in the northwest margin of the Junggar Basin, by documenting the complexity in its formation and evolution. It is termed hybrid because there are three source rock sequences, seven reservoir-caprock combinations, and three petroleum events, and multiple source rocks source the same reservoir and the same source rocks also feed multiple reservoirs. The Mahu sag centre is the petroleum source area with three sets of source rocks: dark shale of the Lower Permian Jiamuhe Formation, black shale of the Lower Permian Fengcheng Formation, and black shale of the Middle Permian Lower Wuerhe Formation. The reservoir rocks include volcanic and clastic rocks of Upper Carboniferous to Lower Cretaceous age, mainly characterized by alluvial conglomerate and sandstone. There are three sets of ultimate caprocks, among which the mudstone of the Upper Triassic Baijiantan Formation is the most important due to its wide distribution throughout almost the whole northwest margin and greatest thickness (up to 300 m), whereas the Lower Jurassic and Lower Cretaceous mudstone acts as an effective seal. Oil and gas were generated mainly during the Middle-Late Permian, Late Triassic, and Middle Jurassic-Early Cretaceous. The reconstruction of the oil-filling history shows that the three source rocks charged reservoirs mainly in three geologic intervals, with common mixing of oils from different sources and/or with different maturities. These three hydrocarbon charges coincide with the three main stages of petroleum generation, related to the Hercynian, Indosinian, and Yanshannian orogenies. During these three petroleum events, oil and gas migrated along the migration framework controlled by faults, unconformities, and good permeability reservoir rocks; the faults are mainly well-developed and episodically active thrust faults and secondary faults. As a result, the Permian petroleum system in the northwest margin of the Junggar Basin is hybrid.

Thermal maturity and suppressed vitrinite reflectance for Neogene petroleum source rocks of Japan

The northern part of Honshu Island contains the major petroleum resources of Japan. The source rocks mainly comprise a sequence of Miocene marine mudstones that are overlain in places by thick Pliocene and Pleistocene sediments. In the past, mainly vitrinite reflectance analyses have been used to evaluate thermal maturities of these rocks. However, vitrinite reflectance suppression caused by compositional variation of vitrinite is common in marine-deposited rocks, and therefore, modeled estimations of the extent of petroleum generation from the Japanese sequences could be in error. Fluorescence alteration of multiple macerals (FAMM) analysis is a method that aids in solving the problem of vitrinite reflectance suppression and gives improved evaluations of thermal maturity. Combined vitrinite reflectance and FAMM analyses of potential source rock sequences intersected by the Ministry of International Trade and Industry (MITI) Shin-Takenomachi and MITI Nishi-Kubiki wells of the Niigata Basin and the MITI Honjo-Oki and MITI Yuri-Oki-Chubu wells of the Akita Basin show that vitrinite reflectance suppression is common in the Neogene source rocks. This leads to major differences between the depth profiles for vitrinite reflectance and for FAMM-derived, equivalent vitrinite reflectance. On the basis of vitrinite reflectance, the thermal maturity and hence, the petroleum source rock potential is underestimated for the Miocene Noudani Formation of the Niigata Basin and the Pliocene Funakawa and Miocene Onnakawa and Nishikurosawa formations of the Akita Basin. The new thermal maturity data indicate that these formations would have generated more oil than previously thought, such that petroleum prospectivity for areas including these sequences should be reassessed.