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In various countries such as Belgium and Germany, deep clay formations are investigated as potential host rock to dispose of radioactive waste. Intermediate-level long-lived bituminised waste, produced from spent fuel reprocessing, is currently foreseen to be disposed of in such a deep repository. This type of waste typically contains large amounts of salts embedded in an organic matrix, of which NaNO 3 is the most prevalent. NaNO 3 , along with radionuclides immobilised in the bitumen matrix, will slowly dissolve and leach out into the surrounding host rock. The transport and reactivity of nitrate in a deep clay formation, in the presence and absence of electron donors coming from bituminised waste (i.e. acetate, H 2), has been studied extensively inside anoxic and water-saturated chambers in the clay in the Bitumen–Nitrate–Clay interaction (BN) experiment. This in situ experiment in Opalinus clay is located in the Mont Terri rock laboratory (Switzerland). The effect of a nitrate plume on redox-sensitive radionuclides is also studied with stable selenium in selenate form as a proxy for 79 Se, an important fission product for the long-term dose to humans. The BN experiment consists of a vertical borehole containing three packed-off intervals, in contact with the surrounding clay through cylindrical sintered stainless steel filter screens. The intervals are saturated with artificial Opalinus clay pore water at a pH between 7.5 and 8, containing all major ions at concentrations specific to the location of the BN experiment but without natural organic matter. Each interval is connected to a water circulation system with a gear pump, a flow meter and water sampling containers. This ensures a chemically well-mixed solution, constant water flow and easy sampling of the interval solutions under anoxic conditions. Water samples are regularly taken to assess the chemical composition and the microbial population in the intervals. An online UV spectrophotometer and pH and redox electrodes are installed in the water circuit of the intervals, to continuously monitor the nitrate and nitrite concentrations, pH and Eh. A given solution can be injected into the intervals to follow up redox reactions affecting nitrate and selenate in situ, in the presence or absence of additional electron donors. From 2011 to 2019, several injections with nitrate were performed in the intervals to investigate the biogeochemical reactivity of nitrate in the borehole and clay. These tests showed microbial reduction of nitrate, using electron donors from Opalinus clay (e.g. dissolved organic matter or pyrite). Nitrite and nitrogenous gases were formed. Pulses of electron donors (acetate or H 2) boosted the microbial activity and nitrate reduction rate. From 2019 until now, injection tests with selenate, with and without nitrate, have been performed. These tests showed clearly that the presence of nitrate, a stronger oxidiser, inhibited the microbial reduction of selenate. In the absence of nitrate, the microbial population was able to reduce selenate to selenite and more reduced Se species. The results obtained in this in situ experiment will be summarised in this work, addressing questions concerning the effect of biogeochemical perturbations of the clay on the migration of redox-sensitive radionuclides. [ABSTRACT FROM AUTHOR]

Previous studies divided the Sinian-Cambrian gas accumulation processes into three stages, including (1) paleo-oil accumulation; (2) paleo-oil cracking; and (3) gas reservoir adjustment and finalization. The author thinks that they ignored a key process, during which the natural gas invades and changes the paleo-oil reservoirs into paleo-gas reservoirs. According to the micro-observation of bitumen in reservoirs, there were great differences between the asphaltene formed by gas invasion and the pyrobitumen formed by paleo-oil cracking. When the gas invasion happened in paleo-reservoirs, asphaltene was separated out and the liquid hydrocarbon was partially changed into solid bitumen which lead to the increase of gas storage for oil-cracking gas and source rocks pyrolysis gas. [ABSTRACT FROM AUTHOR]

The water-rock interaction is discussed in this study for some Central Apennine aquifers and their relative springs, where the geological and hydrogeological setting is potentially responsible for hydrocarbon contamination. The contamination is related to the presence of limestone formations with high organic content that are connected to the genesis of hydrocarbons in the Central-Southern Apennines. Thanks to a multidisciplinary approach based on a seasonal monitoring of hydrogeological, hydrogeochemical, organic chemical, and isotopic variables, and to a detailed geological analysis, it was possible to demonstrate that the bituminous schists within the bituminous dolomite formation (a Triassic Formation presents in the Gran Sasso acquifer), the bituminous intercalations within the Bolognano Formation (an Olocenic calcareous Formation in the Majella acquifer), and the petroleum-saturated rocks of the Bolognano Formation (in the Morrone acquifer) are all able to leach hydrocarbons into groundwater. The results suggest that more detailed studies are required for areas where lithologies with fossil organic components are present. Insights should further investigate the interaction between groundwater and rocks in terms of organic compounds as well as inorganic compounds. In particular, the study also suggests that the supplementary quantification of hydrocarbon compounds in bituminous rock and the leaching tests are analyses that provide reliable results. From the normative point of view, the results of the study can be useful when dealing with hydrocarbon contamination resulting from anthropogenic activities within catchments where formations with high concentration of organic matter are present. In these cases, it will possible to assess the natural background concentrations and review the threshold values upwards. [ABSTRACT FROM AUTHOR]

ABSTRACT: The oil shale exploration program in Jordan is undertaking great activity in the domain of applied geophysical methods to evaluate bitumen‐bearing rock. In the study area, the bituminous marl or oil shale exhibits a rock type dominated by lithofacies layers composed of chalky limestone, marls, clayey marls, and phosphatic marls. The study aims to present enhancements for oil shale seam detection using progressive interpretation from a one‐dimensional inversion to a three‐dimensional modelling and inversion of ground‐based transient electromagnetic data at an area of stressed geological layers. The geophysical survey combined 58 transient electromagnetic sites to produce geoelectrical structures at different depth slices, and cross sections were used to characterise the horizon of the most likely sites for mining oil shale. The results show valuable information on the thickness of the oil shale seam at 3.7 Ωm, which is correlated to the geoelectrical layer between 2‐ and 4 ms transient time delays, and at depths ranging between 85 and 105 m. The 300 m penetrated depth of the transient electromagnetic soundings allows the resolution of the main geological units at narrow resistivity contrast and the distinction of the main geological structures that constrain the detection of the oil shale seam. This geoelectrical layer at different depth slices illustrates a localised oil shale setting and can be spatially correlated with an area bounded by fold and fault systems. Also, three‐dimensional modelling and inversion for synthetic and experimental data are introduced at the faulted area. The results show the limitations of oil shale imaging at a depth exceeding 130 m, which depends on the near‐surface resistivity layer, the low resistivity contrast of the main lithological units, and the degree of geological detail achieved at a suitable model's misfit value. [ABSTRACT FROM AUTHOR]

Norwegian oils are generally considered sourced primarily from the Kimmeridge Clay equivalent shales such as the Draupne, Mandal, Spekk and Hekkingen formations, with secondary contributions from the mid-lower Jurassic, and also from the Triassic in the Barents Sea (Botneheia Formation). Still, as most of our age inferences concerning source-oil correlation are based on facies-specific biomarkers, a number of proposed correlations have been questioned. Thus, source to oil correlations were frequently made on the basis of facies parameters, and rightfully so, but facies-specific signatures in oils will transgress age - and, in principle, not correlate with the phylogenetic evolution. This means that one could, in principle assign an oil to 'the wrong' age - when one is, in fact, linking it to a known source rock signature. A series of 40 oil samples and core extracts, which cover a wide range both stratigraphically and geographically, have been analysed. In this paper, we present for the first time a Norwegian oil-age map based on age-specific biomarkers among the nordiacholestanes and triaromatic steroids parameters, and delineate also wherewe find Cretaceous- and Palaeozoic-derived oils. The reasons for this distribution pattern, compared to that of Mesozoic oils on the Norwegian Continental Shelf (NCS), are discussed. [ABSTRACT FROM AUTHOR]

Abundant organic inclusions are present in the Qinglong antimony deposit. However, the source rocks of these organic matters have not been reliably identified. Recently, a paleo-oil reservoir was found in the Qinglong antimony deposit. In view of similar components of gaseous hydrocarbon, we propose that the organic matters observed in inclusions in Qinglong antimony deposit would come from this paleo-oil reservoir. We used the Re-Os dating method to determine the age of the bitumen from this paleo-oil reservoir, and obtained an isochron age of 254.3±2.8 Ma. The age indicates that the oil-generation from source rock occurred in the early Late Permian, earlier than the Sb mineralization age (∼148±8.5 Ma) in the Qinglong antimony deposit area. After oil generation from Devonian source rock, first and secondary migration, the crude oil have probably entered into the fractures and pores of volcanic rocks and limestone and formed a paleo-oil reservoir in the western wing of Dachang anticline. As burial process deepened, the crude oil has turned into natural gas, migrates into the core of Dachang anticline and formed a paleo-gas reservoir. The hydrocarbons (including CH4) in the reservoirs can serve as reducing agent to provide the sulfur required for Sb mineralization through thermal chemical reduction of sulfates. Therefore, the formation of oil-gas in the area is a prerequisite for the Sb mineralization in the Qinglong antimony deposit. [ABSTRACT FROM AUTHOR]

Petroleum asphaltenes consist of complex hydrocarbon molecules that pose a marked difficulty in the production of crude oils. They tend to flocculate and precipitate during oils refinery and this stimulates considerable interest in the elucidation of their molecular structure for improved processing. In this investigation, five bitumen samples obtained from oil sand outcrops at five localities in Nigeria were used. These were treated with n-pentane that necessitates the precipitation of asphaltene. The different asphaltene samples were analyzed by the x-ray diffraction technique to obtain their various structural parameters. The parameters were determined from the peaks of the gamma (γ) band, graphene (c=c) or (002) band and the (10) or (11) band in the diffraction spectra of the respective samples. Slight variations in the distance between the aliphatic chains and the distance between the aromatic sheets were observed for three of the samples, while the remaining two presented significant variations in the structural parameters. Variations in the average number of carbon atoms per aromatic units correspond to the variation in the size and number of aromatic units and aliphatic chains. The variations consequently determined the level of processing necessary to improve the heavy oil (bitumen). [ABSTRACT FROM AUTHOR]

Approximately 60 per cent of Alberta's oil sands production is non-upgraded bitumen which, after being mixed with a diluting agent (diluent) to allow transport, is exported. A popular view within Alberta -- and particularly among Albertan politicians -- is that a much larger share of oil sands bitumen should be upgraded in the province. However, without public subsidies or government underwriting, it is uneconomic to build and operate new facilities in Alberta to fully upgrade the bitumen into synthetic crude oil. But there are new partial upgrading technologies being developed that, subject to successful testing at a larger (commercial) pilot scale, can prove to be not only economic in Alberta, but also generate large social and economic benefits for the province. The advantages include a much smaller capital investment, a significant increase in the value of the product and market for the product and, even more importantly, a dramatic reduction in the need for large amounts of expensive diluent to transport the product to market. Indeed, the only diluent required will be that to move the bitumen from the production site to the partial upgrader and this can be continually recycled. The market for the synthetic crude oil produced by full upgrading is only getting tougher. Any Alberta bitumen fully upgraded here would compete closely with the rapidly expanding supply of light U.S. unconventional oil. Partial upgrading does not upgrade bitumen to a light crude, but to something resembling more of a medium or heavy crude, and at a lower cost per barrel than full upgrading. Unlike in the increasingly crowded light-crude market, the Alberta Royalty Review Advisory Panel recognized that currently there are gaps in several North American refineries that could be filled by this partially upgraded Alberta oil. A partial upgrader serving that less-competitive market not only appears to hold the potential for investors to make attractive returns in the long term, it would also provide important benefits to Alberta from a social perspective. Since partially upgraded crude can be shipped via pipeline without diluent (as bitumen requires), producing it in Alberta would free up pipeline capacity otherwise tied up by current volumes of diluted bitumen or dilbit (diluent typically represents about one-third of each barrel of dilbit). It also reduces the cost to shippers of paying tolls for diluent exported in the dilbit and recovering diluent at the U.S. pipeline terminal, where it is less valuable than if it were recovered in Alberta at the partial upgrader. The value of each barrel produced would also be higher, benefitting oil sands producers. Partial upgrading also seems to promise a lower emissions-intensity profile compared to other bitumen-processing technologies. Based on the model of a single 100,000-barrel-a-day partial upgrader, the value uplift could be $10 to $15 per bitumen barrel. Meanwhile, there could be an average annual increase to Alberta's GDP of $505 million, and as many as 179,000 person-years of employment created (assuming a 40.5-year operating period). The increase in taxable earnings would increase provincial revenues by an average of $60 million a year, not including additional federal tax revenues. If successful, there would be many such partial upgraders with corresponding multiplication of these benefits. But there remains the critical task of proving partial upgrading technology at a higher scale than current testing. This might also depend on the province helping sustain investors through the "death-valley" between successful research and initial testing and demonstration of full commercial viability. The province has stepped into help technologies cross that "death valley" before. The promise of partial upgrading may well justify, as manager and steward of Alberta's resources, helping bridge that valley again. [ABSTRACT FROM AUTHOR]

This study employs the response surface method in conjunction with a user-defined design to model the solubility of carbon dioxide in different bitumen cuts. Two different sets of data for carbon dioxide solubility in Cold Lake bitumen were considered. Temperature, pressure, and the bitumen cuts' molecular mass were selected as the explanatory variables. Scatter plots were used to determine the appropriate transformations for the explanatory variables. An ANOVA test was considered in a step-wise manner to select the significant parameters. A second-order dependency on temperature and a first-order dependency on the pressure and molecular mass were observed. In addition, a binary interaction between the molecular mass and pressure was observed. The developed correlation modelled carbon dioxide solubility in bitumen cuts with an AARD of 5 % for all the experimental data. The perturbation curve emphasized the strong dependency of solubility on temperature and pressure. [ABSTRACT FROM AUTHOR]

The Ufimian tectonic concentric structure (UTC) is a regional structure with concentric and zonal structure of the internal gravity field. In the Neoproterozoic this structure was at higher hypsometric level relative to the Bashkir Meganticlinorium. The most significant uplift of this tectonic concentric structure happened at the beginning of the Karatau time (~825 Ma) and was accompanied by the formation of a ring fractured zone, favorable for hydrocarbon migration from the Lower Riphean black shales. Due to this, bitumens with higher Mo content in the Neoproterozoic and Paleozoic deposits are confined spatially to this zone. The bitumenosity of the Neoproterozoic deposits on the southern slope of the Ufimian tectonic concentric structure could have contributed to the formation of complex Cu-Ag-Mo-Re ores (copper sands) at the upper boundary of terrigenous red deposits of the Zilmerdak Formation. Positive structures identified in the Neoproterozoic deposits near the margin of the Ufimian tectonic concentric structure are considered to be promising for searching for hydrocarbon fields. [ABSTRACT FROM AUTHOR]

Within BlackGold Lease located in northern Alberta, the Lower Cretaceous McMurray Formation contains the most prolific bitumen reservoirs deposited in fluvial to tidally-influenced estuarine environments. Based on core descriptions and wire-line log evaluation, this study reveals six lithofacies: cross-stratified sandstone and mudstone-clast breccia (Lf1), sandstone-dominated IHS (Lf2), mudstone-dominated IHS (Lf3), thinly interbedded sandstone and mudstone (Lf4), laminated mudstone (Lf5), and clean sandstone with interbedded mudstone (Lf6). To understand the evolution of depositional environments vertical and lateral associations of lithofacies are examined using well cross-sections and lithofacies slice maps. During overall rise in relative sea level, the McMurray Formation evolved through three stages of deposition: early stage represents fluvial channels with minor tidal influence, middle stage represents tidally-influenced estuary with well-developed meandering channels, and late stage represents a drowning of tidally-influenced estuary. The potential bitumen reservoirs are fluvial channel sandstones in the early stage and lower point-bar deposits in the middle stage. The fluvial channel sandstones are well stacked and correlatable between wells, forming sheet-like sandstone bodies that align in a SW-NE direction parallel to the inferred orientation of major channel systems. The lower point-bar deposits consist mainly of base-of-channel and sandstone-dominated IHS deposits. The direction of point-bar migration, which is crucial in horizontal well design for bitumen production, is inferred from lithofacies slice maps. The lateral changes in lithofacies from base-of-channel to abandoned channel-fills through IHS deposits, shown in lithofacies slice maps, probably indicate that the point bar once migrated toward abandoned channel-fills. Based on this lateral lithofacies trend, the dip direction of some point-bar deposits are approximately estimated to be southwestward or northwestward, which is oblique or perpendicular to the major channel orientation. [ABSTRACT FROM AUTHOR]

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The regularities of reaction of the viscous bitumen (maltha) structure when affected by modulated and impulse electromagnetic and acoustic fields via recording of infrared emission spectra are studied. It has been found that characteristic reactions of viscous oil clusters and links between them are located in the THz range for electromagnetic waves and in the MHz range for acoustic actions, which are revealed in absorption and emission spectra. The reaction of the rest (non-THz) part of the infrared spectrum is described on the basis of the physical-mathematical model of the process of a photon-phonon soliton, which causes decrease of emission IR spectrum intensity after microwave action due to fixation of the electromagnetic field by a soliton. The obtained results, which establish selectability of the maltha specimen reaction on spectral composition of the affected radiation, are important for increasing the efficiency of ultrasonic and electromagnetic microwave actions on the productive stratum during application of secondary methods for oil deposit exploration. [ABSTRACT FROM AUTHOR]

A worldwide dataset of organic material from 553 samples belonging to coal and carbonaceous materials was used to analyze the evolution of hydrogen index (HI) and bitumen index (BI) with increasing thermal maturity. Basic statistical analyses were applied to detect the boundary lines of HImax and BImax in delineating the upper and lower limits of the HI and BI bands for the majority of samples. In addition, cross-plots of HI or BI versus maturity (Ro% and Tmax) also provide criteria for defining the HImax and BImax boundary lines. The constructed HI and BI bands are broad at low maturities and become narrower with increasing thermal maturities. The petroleum generation potential is completely exhausted at the vitrinite reflectance of 2.0–2.2% or Tmax of 510–520°C. An increase in HI implies extra petroleum generation which was related to changes in structure of organic materials. A declining BI means that the oil expulsion window starts to occur at the vitrinite reflectance range of 0.75–1.05%. The petroleum potential can be divided into four different areas based on the cross-plot of HI versus Ro%. The highest petroleum potential area is located in section II with Ro = 0.6–1.0% and HI > 100. The oil generation potential is rapidly exhausted at section III with Ro > 1.0%. This result is also in accordance with the result of curve regression of HI versus Ro% based on 80 samples with Ro = 1.02–3.43% ( R2 = 0.72). Overall, the total oil window can be extended up to Ro = ~1.25–1.95%. Finally, in the cross-plots of S1 versus S2, shale or C-shale exhibits a higher and slowly decreased slope, compared with a lower and then sharply increased slope of coal samples, which is attributable to their compositional difference in organic material. [ABSTRACT FROM AUTHOR]

Late Neoproterozoic to Early Cambrian carbonates of the Ara Group form important intra-salt ‘stringer’ reservoirs in the South Oman Salt Basin. Differential loading of thick continental clastics above the six carbonate to evaporite cycles of the Ara Group led to the formation of salt diapirs, encasing a predominantly self-charging hydrocarbon system within partly highly overpressured carbonate bodies (‘stringers’). These carbonates underwent a complex diagenetic evolution, with one stage of halite cementation in a shallow (early) and another in a deep (late) burial environment. Early and late halite cements are defined by their microstructural relationship with solid bitumen. The early phase of halite cementation is post-dated by solid reservoir bitumen. This phase is most pervasive towards the top of carbonate stringers, where it plugs nearly all available porosity in facies with initially favourable poroperm characteristics. Bromine geochemistry revealed significantly higher bromine contents (up to 280 p.p.m.) in the early halite compared with the late halite (173 p.p.m.). The distribution patterns and the (high) bromine contents of early halite are consistent with precipitation caused by seepage reflux of highly saturated brines during deposition of the overlying rock salt interval. Later in burial history, relatively small quantities of early halite were dissolved locally and re-precipitated as indicated by inclusions of streaky solid bitumen within the late halite cements. Late halite cement also seals fractures which show evidence for repeated reopening. Initially, these fractures formed during a period of hydrothermal activity and were later reopened by a crack-seal mechanism caused by high fluid overpressures. Porosity plugging by early halite cements affects the poroperm characteristics of the Ara carbonates much more than the volumetrically less important late halite cement. The formation mechanisms and distribution patterns of halite cementation processes in the South Oman Salt Basin can be generalized to other petroliferous evaporite basins. [ABSTRACT FROM AUTHOR]

The Ordovician buried hill reservoir in the western Lunnan area, a type of dissolved fracture and cavernous reservoir, is mainly composed of heavy oil. The oil is the mixture sourcing from the Middle-Lower Cambrian and Middle-Lower Ordovician, with three stages of pool forming process: (1) the destruction and parallel migration/accumulation during the late Caledonian to early Hercynian; (2) the oil and gas accumulation during the late Hercynian characterized by adjustment upward along faults and parallel migration/accumulation; (3) the formation of heavy oil during the latest Hercynian. The Ordovician buried hill reservoir is affected by the diffusion of light oil and gas but had no hydrocarbon charging during the late Yanshan period to Himalayan period, but in this period, formed the association of heavy oil and dissolved gas cracked from crude oil with dry coefficient of 0.91-0.96. The study on accumulation process of the Ordovician buried hill reservoir has important implications for the exploration potential of early oil and gas accumulation in the cratonic area of the Tarim Basin. [ABSTRACT FROM AUTHOR]

The platform carbonates of the Upper Devonian Grosmont Formation hold an estimated 50 billion m3 of bitumen in place and therefore host a significant amount (one-sixth) of the total bitumen resources in northern Alberta. However, unlike the overlying Athabasca oil sands, the bitumen resource has not been tapped as yet. The present study is an overview and integration of recent subsurface studies, largely focused along the eastern subsurface erosional edge of the Winterburn Group in northern Alberta. The basis of the regional geologic framework includes a detailed study of 42 cores with an emphasis on facies description of both reservoir and nonreservoir facies, and the summary of a diagenetic sequence model to demonstrate the major influences on bitumen accumulation. The Grosmont Formation carbonates have been subject to various stages of diagenesis, including dolomitization and karstification with a profound effect on the distribution of porosity and permeability, which resulted in highly heterogeneous reservoirs. In addition, low effective permeabilities because of high bitumen saturation, the high viscosity of the heavily biodegraded bitumen, and the continuity and integrity of shales capping bitumen-bearing reservoir facies are further factors that must be considered in applying future in-situ recovery schemes to the Grosmont carbonate bitumen deposit. [ABSTRACT FROM AUTHOR]

At the Muskeg River Mine, bitumen is hosted in the clastic sediments of the lower Cretaceous McMurray Formation. Within the mine area, the McMurray Formation is divided informally into mappable units representing fluvial, continental floodplain, open estuarine, estuarine channel complex (ECC), and marine environments. Fluvial, open estuarine, and ECCdeposits host more than 90% of the mineable bitumen reserves. Bitumen grade is more consistent within the fluvial and open estuarine units (12-15 mass%), whereas ECC sediments are characterized by significant lateral and vertical grade variability (0-15 mass%). In the ECC deposits, bitumen grade is controlled by significant reservoir heterogeneity. Facies assemblages including point-bar deposits (PB), abandoned channel-fills (AC), and tidal flat deposits (TF), create complex internal geometries, architectures and associated reservoir properties. Traditional facies mapping and correlation has proven to be difficult even in closely spaced wells for the ECC deposits of the McMurray Formation; thus, an alternative technique using concepts of Stratigraphic Dip Analysis (SDA) was developed to assess bitumen grade for the deposits at the Muskeg River Mine. This approach involves three main steps: (l) juxtaposing azimuth maps (rose diagrams) over horizon slice facies maps for selected stratigraphic intervals to identify major channel trends (paleo-current directions); (2) comparison of dips, with corresponding sedimentary structures allows for a better prediction and geometries of point bars and abandoned channel-fills; and (3) comparison of dip trends with dominant lithology of facies assemblages and available bitumen grades provides a base for accurate delineation of architectural elements. A detailed case study is presented and shows that this approach provides a base for accurate delineation of architectural elements and confirms that bitumen grade decreases laterally with inferred maturity of point bar successions. [ABSTRACT FROM AUTHOR]

The Albian to Santonian Colorado Group in the heavy oil area of Cold Lake, east-central Alberta represents a relatively condensed section of shale-dominated sedimentation within the Western Interior Sea. These shales form the cap rock to the underlying Clearwater and Grand Rapids formations that are exploited for bitumen extraction. Two cores covering the entire Colorado Group provide a unique opportunity for establishment of a stratigraphic reference in an area that has received attention only for its heavy oil-bearing Mannville Group. Based on sedimentology, geochemistry, micropaleontology, nannofossils, and wireline log data, the Colorado Group was subdivided into the Joli Fou, Viking, Westgate, Fish Scales, Belle Fourche, Second White Specks, and Niobrara formations. The Niobrara Formation was subdivided further into the Verger Member, informal Cold Lake member, and First White Specks Member. Because of this regions small accommodation space and distance to sources of coarse clastic sediment, disconformities are indicated lithologically by bioclastic layers and missing biozones. Foraminiferal subzones revealed two erosional boundaries associated with the Viking Formation. Faunal and floral evidence coupled with wireline log correlations suggest that the Middle to Upper Turonian Carlile Formation, as described from southeastern Alberta, is missing. That extends the Middle Turonian to Coniacian unconformity, as recognized in central Saskatchewan, westwards into Alberta. [ABSTRACT FROM AUTHOR]

Most of the bitumen in the Athabasca deposit is hosted within fluvial, estuarine, and marginal marine deposits of the Lower Cretaceous Wabiskaw-McMurray succession. The present study is an integration of recent outcrop and subsurface studies, mainly focused in the Fort McMurray area of northeastern Alberta. The basis of the regional geologic framework includes outcrop sections (78), detailed core descriptions (165), and a net of subsurface wire-line log sections (14), all framed within modern concepts of regional correlation and sequence-stratigraphy. The paleogeographic evolution of the Athabasca Wabiskaw-McMurray succession includes five main phases: (1) Lower McMurray fluvial as lowstand deposits; (2) the lower part of the Upper McMurray fluvio-estuarine channel complexes which formed during early transgressive conditions; (3) the upper part of the Upper McMurray A sequences as relict bay-fill and marginal marine deposits formed during early and middle transgressive phases; (4) Wabiskaw D valley-fill developed during a relative sea-level drop at the end of Mc-Murray time (valley-incision phase), which was backfilled during the ensuing transgression; (5) Wabiskaw D regional marine shale, deposited during widespread flooding of the main McMurray-Wabiskaw transgression; and (6) Wabiskaw C deposits formed during continued transgression or early regressive pulses. The regional geological framework has both economic and academic significance, providing better documentation and understanding of the compartmentalization of the oil sands mainly the result of the inherent geological heterogeneity of the Wabiskaw-McMurray succession. Such regional correlation and framework will aid in predicting subsurface and surface reservoir quality and in increased understanding of marginal marine and non-marine sequence stratigraphy. [ABSTRACT FROM AUTHOR]

The very particular material of 500 artefacts from the excavations of Suse, kept in the Musée du Louvre, has been carefully examined with the help of the Elf Company. Analysis brought to the conclusion that it was an artificial mixture even when the artefacts bore the stamp of a sculpture work. Some months after the publication of the final study, geological samples gathered in the Susian area showed an identical structure to those of the archaeological samples. Thus, the hypothesis of an artificial material had to be revised. The difficulty to identify the exact nature of this material, even by scientists, explains the variety of the names given by excavators to the artefacts when they discovered them: bitumen, black limestone, bituminous limestone, bituminous paste, brown or black substance, black asphalt, etc... Some of these terms brought back stone and sculpture marks. It has led into a regrettable confusion between artificial mixture and natural rock. Thus, an unsharp terminology has been carried by excavators because of the unusual aspect of this material. [ABSTRACT FROM AUTHOR]

The article focuses on oil and gas explorations in the lower Cretaceous period in Songlibao Peripheral Basin, China. It includes information on a geological survey related to the study of hydrocarbon geological conditions of the Hongmiaozi Basin. It also includes information on organic carbon, rock pyrolysis, and chloroform bitumen.