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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]

Highlights • The Grosmont Formation hosts heavy to severely biodegraded bitumen. • Degradation-resistant biomarkers are remarkably consistent laterally and vertically. • Degradable biomarker distributions are highly variable and profiles offset by shales. • Compartmentalization impacts degradation systematics in hopanes and 25-norhopanes. • C 31 –C 33 22R hopanes degrade prior to C 31 –C 33 22S hopanes. Abstract The hydrocarbon composition of the Grosmont Formation bitumen was investigated in 51 core samples by gas chromatography–mass spectrometry (GC–MS). The bitumen composition is highly variable and is heavily to severely biodegraded. Molecular ratios based on biodegradation-resistant compounds are highly uniform laterally and vertically, even across shale barriers indicating the bitumens are genetically related. Biodegradation-resistant biomarker maturity parameters suggests the bitumen was likely sourced during the early oil window stage of petroleum generation. Biomarkers responding to biodegradation display strong lateral and vertical variations in composition with geochemical profiles based on concentration data, displaying dramatic offsets when shales are present indicating the reservoir units are compartmentalised. Considering the relationship between 25-norhopanes and hopanes, the hydrocarbon composition data indicate progressive hopane degradation, both with concomitant formation of 25-norhopanes and hopane degradation without the formation of 25-norhopanes. In wells 07-08-085-18W4 and 10-12-093-24W4, the degradation of hopanes occurs in Upper Grosmont unit 3 (UG3) without the formation of 25-norhopanes (unless 25-norhopanes have been synchronously consumed), whereas in unit UG2, hopane degradation occurs with the concomitant formation of the 25-norhopanes. Therefore, the shale compartmentalizes the reservoir creating two isolated environments whereby the biogeochemical setting contributing to 25-norhopane formation is found in the UG2 unit, whereas it is absent or inactive in unit UG3. The degradation of the 22R epimer prior to the 22S epimer in the C 31 –C 33 17α-hopanes was recognized in well 16-05-088-19W4, which indicates that the consortia of microbes more readily biodegraded the epimer having the biological conformation. [ABSTRACT FROM AUTHOR]

Bitumen, the heavy residue of crude oil, can display a rich microscale morphology, including so-called Bee structures. The use of Atomic Force Microscopy (AFM) measurements in literature strongly indicates that the appearance of Bee structures is related to the presence of paraffin wax crystals. Most studies have investigated standard bitumen surfaces when cooling bitumen in an air atmosphere. Only a few investigations have analysed surfaces formed in other media or have analysed fractured surfaces which relate to the bulk morphology. Although considerable research has focussed on identifying Bee structures, less attention has been paid to the Bee structure morphology of different bitumen types and the relations to other binder parameters. The comparison between the micro morphology of the air-oil interface compared to the bulk phase volume has been studied even less. In this experimental study, five bitumen samples were selected based on differences in their natural wax content. Both the air-cooled surface interface and fractured surfaces were characterised using AFM in tapping mode. All the air-cooled surfaces revealed Bee structures, except the wax-free bitumen, which did not display the presence of any Bee structure. None of the fracture surfaces revealed Bee structures. Reheating a fractured surface of a wax-containing bitumen transformed the morphology into Bee structures. The experiments demonstrate that Bee structures are present in different binders but display very different shapes and sizes. However: image analysis indicates that the unit cell inside these structures is rather constant and independent of the binder type. This work confirms a relationship between natural wax and Bee structures and it also shows that Bee structures, as such, are a surface phenomenon which is not present in the bulk phase volume of samples. [ABSTRACT FROM AUTHOR]

Graptolite reflectance was thought to be one of the most useful thermal maturity indicators for graptolite-bearing sediments, however, the relationship between graptolite reflectance and vitrinite reflectance is not well-established. Graptolites, especially in the Wufeng–Longmaxi Formations from the Ordovician to Silurian of South China, have been mistaken for vitrinite-like particles or solid bitumen, which results in inconsistent data on the thermal maturity. In this paper, we have employed optical microscope techniques to describe the detailed optical characteristics of graptolites and solid bitumen in the Wufeng–Longmaxi Formations. Laboratory simulation of maturation was used to determine the relationship between graptolite reflectance and vitrinite reflectance. The organic constituents in the Wufeng–Longmaxi Formations are mainly composed of graptolites and solid bitumen. Granular and non-granular graptolites were observed in the Wufeng–Longmaxi Formations, with non-granular as the most common texture. Solid bitumen can be distinguished from non-granular graptolites by its coarse surface, weaker anisotropy, and lower random reflectance. The combination of non-polarized and polarized light is very helpful to distinguish solid bitumen from graptolite. For comparison, organic material from the early Ordovician Alum Shale Formation of Sweden and Estonia was also studied. The macerals of the Alum shales are mainly composed of lamalginites, mineral-bituminous groundmasses, graptolites, and solid bitumen. The major textures of the graptolites in the Sweden and Estonia sediments are non-granular and granular, respectively. Both non-granular graptolite and vitrinite reflectances display a systematic increase with the increase of heating temperature and time. The granular graptolites in the Estonian sample were gradually changed to non-granular graptolites following laboratory simulated maturation, indicating that granular graptolites can transform into non-granular graptolites with maturation. Solid bitumen in the Wufeng–Longmaxi Formations was derived from the solid residue of kerogen and/or post-oil bitumen. The graptolite random reflectance is a better thermal maturity indicator than graptolite maximum reflectance and is more precise due to the smaller standard deviation. Several equations are proposed to determine the thermal maturity of the graptolite-bearing sediments based on graptolite random reflectance, graptolite maximum reflectance and solid bitumen random reflectance. [ABSTRACT FROM AUTHOR]

This paper reviews the significance of solid bitumen with emphasis on source-rock reservoirs. We discuss difficulties and discrepancies with terminology, especially those terms related to the origin of solid bitumen and its physical and chemical properties. Various definitions of solid bitumen have their own justifications and can be used provided there is clarity about which defining criteria are being considered. Difficulties in conforming to chemical-, solubility-, or origin-related definitions lead us to suggest adapting the reflectance of solid hydrocarbon as a practical choice for placing the boundary between solid bitumen and pyrobitumen, and 1.50% is proposed as the boundary value. It has to be noted that this boundary may be shifted down to 1.3% for sulfur-rich kerogen. Recently, much progress has been made by combining imaging and physical adsorption techniques in porosity studies, and so the porosity of solid bitumen is given special emphasis. Comparing pore characteristics obtained from SEM versus those generated by gas adsorption, mercury intrusion, or neutron scattering techniques indicates that the SEM pore inventory fails to account for the smallest pores (<5 nm in size) present in organic matter. Therefore, low-pressure CO 2 adsorption is still the most effective technique to assess microporosity (pores <2 nm in diameter) in shales. We conclude that combining observational in situ techniques with techniques based on physical principles is necessary to make progress toward a better understanding of porosity systems in organic matter, including solid bitumen. We review the implications of the abundance of solid bitumen on reservoir quality, porosity, permeability, and producibility, based on examples of selected sequences. One of the difficulties in predicting the influence of solid-bitumen-bearing horizons on reservoir quality arises from the problems with detecting organic phases using various logging techniques. The use of specialized techniques such as NMR logging that allows two-dimensional T 1 and T 2 measurements should be expanded, and other potential techniques need to be further researched and tested. Certain aspects of the properties of solid bitumen that are not as well understood, such as its hydrocarbon generation potential or its role in hydrocarbon migration are also discussed with the aim of identifying further research that could lead to a better understanding of the role that solid bitumen plays in unconventional reservoirs. [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]

Solid bitumen is a common organic component of thermally mature shales and typically is identified by embayment against euhedral mineral terminations and by groundmass textures. However, because these textures are not always present, solid bitumen can be easily misidentified as vitrinite. Hydrous-pyrolysis experiments (72 hr, 300°C-360°C) on shale and coal samples show that solid-bitumen reflectance (BR0) in shales is less responsive to thermal stress than vitrinite reflectance (R0) in coal. This effect is most pronounced at lower experimental temperatures (300°C-320°C), whereas reflectance changes are more similar at higher temperatures [340°C-360°C]. Neither a "vitrinitelike" maceral nor "suppressed vitrinite" was identified or measured in our sample set; instead, the experiments show that solid bitumen matures slower than vitrinite. The data may explain some reports of "R0 suppression," particularly at lower thermal maturity (R0 < 1.0%}, as a simple case of solid bitumen being mistaken for vitrinite. Further, the experimental results confirm previous empirical observations that Ra and BR0 are more similar at higher maturities (R0 > 1.0%]. It is suggested that R0 suppression, commonly reported from upper Paleozoic marine shales of early to midoil window maturity, is a misnomer. This observation has important implications to petroleum exploration models and resource assessment, because it may change interpretations for the timing and spatial locations of kerogen maturation and petroleum generation. [ABSTRACT FROM AUTHOR]

Subsurface natural fractures in shales are vital for fluid transport pre- and post-hydraulic fracturing in naturally fractured reservoirs such as the Woodford Shale. However, the dominant fracture sets that control the fluid flow in the subsurface are mostly unseen, and their intensity variation is unknown due to non-availability of image logs in most wells. In this paper, we have assessed the possibility of the existence of subsurface natural fractures in the Woodford Shale by understanding their generation history from outcrop and thin section studies. Additionally, we have addressed their relative abundance based on the bed thickness and composition. Out of the several fracture sets identified in the Woodford Shale, two joint sets (E-W and NE-SW) were interpreted as the oldest sets based on crosscutting and fill. These sets date back to before the Mid-Virgilian Arbuckle Orogeny and likely have different generation timings. The relatively silica- and carbonate-rich beds primarily contain the E-W fractures and the highly clay- and organic-rich beds mainly contain the NE-SW fractures. The E-W and NE-SW sets origins (both not related to local structural bending) are likely more numerous in the flat subsurface compared to fractures sets whose origins are related to structural bending. These two fracture sets probably also control the fluid flow in the subsurface. Younger fracture sets show more influence of local folding and are overrepresented in the outcrops with tilted beds. Therefore, they do not likely control relatively flat subsurface fluid flow. Although some fractures (fold or non-fold related) only have one type of cement or bitumen fill, others have two types of fills, i.e., bitumen along with another cement, or two types of cement (non-bitumen) indicating that these fractures underwent more than one stage of opening. Also, a negative correlation between fracture intensity and bed thickness, and a positive relationship between fracture intensity and quartz/carbonate content exist in the studied location. [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]

Polymer modified bitumen (PMB) pavement have gained significant importance in the twentieth century and they now play a very crucial role in the field of road construction in every part of world. However, due to well-known difficulties related to the poor solubility of polymers, high temperature stability, sever manufacturing condition and high polymer cost restricts the use of polymer for bitumen modification. To overcome all these difficulties the present study has attempted to demonstrate a new approach where in situ polymerization of monomers bis(2-hydroxyethyl) terephthalamide (BHETA) (which is synthesized from aminolysis reaction of waste Poly Ethylene Terephthalate (PET)) with diphenylmethane-diisocyanate (MDI) in the body of bitumen for the development of polyurethane based Polymer modified bitumen (BHETA-PU). The resulting BHETA-PU product is comparable performance under laboratory condition with conventional styrene butadiene styrene (SBS) based PMB. To investigate the modified bitumen properties and mixture properties, conventional binder tests (Penetration, Softening Point, Marshall Stability, Hot water Stripping & short-term aging test) and Superpave binder tests (Rotational Viscosity, Dynamic Shear Rheometer (DSR), Bending Beam Rheometer (BBR) were carried out. The result reveals that BHETA-PU show significant improvement of antistripping as well as other physico-chemical properties and Marshall Stabilities. This research studies, therefore, suggests not only a new method for making PMB based on PET but also opens a new chapter for the recycling of waste PET in bitumen concrete roads which may help in easy disposal of waste PET polymer. [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]

In this research calcium-alginate capsules containing vegetable oil that can release their content due to a mechanical trigger have been made and mixed in asphalt mixture to improve its natural self-healing properties. The physical, mechanical and self-healing properties of asphalt mixture containing these capsules have been evaluated for the first time. Three different capsule contents were used, with oil-to-bitumen ratio 1.1, 2.8 and 5.5, respectively. Capsules were strongly bonded to the asphalt mixture and results showed similar mechanical performance to that of asphalt with and without capsules in the water sensitivity, particle loss and permanent deformation tests. This shows that capsules for asphalt self-healing can be safely used in the road, without affecting its quality. Asphalt containing capsules had slightly lower stiffness, which can be easily solved by reducing the size of the capsules in the future. Furthermore, a new method for testing asphalt containing capsules was designed and tested. It was found that cracked asphalt mixture with capsules recovered 52.9% of initial strength at 20 °C versus 14.0% of asphalt mixture without capsules. [ABSTRACT FROM AUTHOR]

High-pressure methane sorption isotherms were measured on seven representative samples of Silurian shales from the Barrandian Basin, Czech Republic. Excess sorption measurements were performed at a temperature of 45 °C and at pressures up to 15 MPa on dry samples, using a manometric method. Experimental methane high-pressure isotherms were fitted to a modified Langmuir equation. The maximum measured excess sorption parameter ( n max ) and the Langmuir sorption capacity parameter ( n L ) were used to study the effect of TOC content, organic maturity, inorganic components and pore size distribution on the methane sorption capacity. The values of n max ranged from 0.050 to 0.088 mmol.g −1 , and the values of n L ranged from 0.068 to 0.133 mmol.g −1 . The studied shale samples with random reflectance R r of graptolite 0.56–1.76% had a very low TOC content from 0.34 to 2.37 wt% and dominant mineral fractions. Illite was the prevailing clay mineral (0–51%). Organic matter of the Silurian black shales was consisted of residues of graptolites, chitinozoans, two types of bitumen including dispersed and massive bitumens, recycled organic matter, and organic detritus. In the shales, the occurrence of fractures parallel with the original sedimentary bending was highly significant. A greater proportion of fragments of carbonaceous particles of graptolites and bitumens in the Barrandian shales had a smooth surface without pores. The sample porosity Por calc ranged from 4.6 to 18.8%. In most samples, the micropore volumes were markedly lower than the meso- and macropore volumes. No relation has been proven between TOC-normalized excess sorption capacities or the TOC-normalized Langmuir sorption capacities and thermal maturation of the shales. The methane sorption capacities of shale samples show a positive correlation with TOC and a positive correlation with the clay content. The assumption that the sorption capacity is a function mainly of the microporous system of shales was not confirmed. The highest sorption capacity was observed in shale samples with the lowest volume of micropores and the highest TOC content, indicating that the organic matter content and the microporosity of clay minerals are the principal factors affecting the sorption capacity of shale samples. [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]

The unique Moxi–Gaoshiti Bulge of Sichuan Basin in southwestern China provides insights into the biomarker signatures of bitumens and their geological significance for paleo-oil reservoirs in Precambrian strata. Solid bitumens with various shapes occur widely in the voids, solution pores, cracks, stylolites, and veins of reservoir rocks. Biomarker analysis was conducted on bitumens and the associated source rocks by quantitative detection with gas chromatography–mass spectrometry (GC–MS) to constrain thermal maturity, sedimentary environments, bitumen/paleo-oil sources, and the possible paleo-oil filling directions, which are dominant geological factors that control paleo-oil accumulations. Quantitative analysis of biomarkers showed that the bitumens in the Sinian dolomite of the Moxi–Gaoshiti Bulge belong to the same group. The bitumens are highly matured, and their reflectance values (%R b ) are greater than 1.5 with an average of 2.96. These bitumens originated from thermal cracking of oil (pyrobitmen) via a high-temperature process. The biomarker characteristics revealed that the bitumens and related paleo-oil reservoirs originated from a highly reduced but moderately saline marine shale environment. The marine shales of the Sinian Dengying and lower Cambrian Qiongzhusi formations are their major source rocks. The directions of the primary oil-filling pathways in the Gaoshiti and Moxi sub-bulges are from west to east and from northwest to southeast, respectively. These directions indicate that the Deyang–Anyue sag west of the Moxi–Gaoshiti Bulge is the major hydrocarbon source kitchen. [ABSTRACT FROM AUTHOR]

The thiourea adduct (TUA) and thiourea non-adduct (TUNA) saturated hydrocarbons from the Cold Lake oil-sand bitumen have been analyzed by GLC-electron impact mass spectrometer (EIMS)-computer and GLC-field ionization mass spectrometer (FIMS)-computer systems. FIMS gives information on the molecular weights of individual components within the complex mixture, and augments the fragmentation picture obtained by EIMS. These two methods complement each other and in combination provide a powerful analytical tool for the study of complex mixtures of saturated hydrocarbons. The Cold Lake bitumen is a moderately biodegraded oil, and it is shown that the predominant series of compounds present in the TUA and TUNA fractions are the various homologues of decalin. [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]

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]

This article explores the political controversy surrounding the proposed Northern Gateway bitumen pipeline by analyzing the modalities through which elite rationalities structure public news discourse. First, through a news analysis, the authors identify the most common pro-approval actors cited speaking in favour of the project. Next, they identify the most prominent pro-approval civil society sources and ascertain their level of embeddedness in conservative discourse coalitions. Finally, the authors identify the dominant framing techniques that disproportionately structure the public discourse around the Gateway project. The article ultimately argues that over-reliance on "official sources," the prominence of industry-backed civil society organizations, and the influence of hegemonic discourses on journalistic practice all conspire to structure the public discourse on Northern Gateway in favour of elite preferences and rationalities. [ABSTRACT FROM AUTHOR]

Particle-size distribution (PSD) is a list of values that defines the relative amount of particles present according to the size in a sample. The PSD of the McMurray Formation sediments characterizes rock granulometry and is a fundamental indicator of the nature of the sediment. The size distribution of the component solid particles in the McMurray Formation sediments relates to their porosity; volume of water and bitumen contained within the pore space; and the depositional environment, including lithological association, stratigraphy, areal distribution, and associated physical processes. PSD is known to be a significant factor for evaluating bitumen recovery from an oil-sand mine. This is because presence of fines (evaluated by PSD analysis) affects the hot-water-separation process and processing-plant recovery prediction and provides grade control. Presence of more fines translates into lower recovery from commercial oil-sand processing. In this study, we investigate whether the PSD should be also considered a critical parameter for evaluation and estimation of permeability of an oil-sand reservoir. We show, by use of the data from Cenovus Energy's Telephone Lake lease, that there is a strong relationship between permeability and PSD data. We also show that the information provided by the PSDs for permeability prediction is more significant than that inferred from a simple porosity/permeability relationship. Subsequently, we comment on permeability modeling by use of PSD data and list the techniques available for cleaning and modeling of multivariate PSDs. We document a methodology for modeling of PSDs and provide a work flow for incorporating these data in improved understanding and modeling of permeability and its distribution. [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]

Organic-rich deposits of Qalikuh locality, Zagros Basin, Southwest of Iran are unconventional hydrocarbon resources considered as an oil shale, which is hosted within a carbonate succession with the age range of Middle Jurassic to Lower Cretaceous. Leco carbon, Rock–Eval VI and modified Fischer Assay analysis were performed on some outcrop samples of these resources to investigate the occurrence of oil shale. In the studied samples, mean total organic carbon (TOC) is 17.3 wt.% and the average of petroleum genetic potential (S 1 + S 2 ) is 98 kg HC/t rock. Furthermore, TOC has direct relationship with petroleum genetic potential. Hydrogen index (HI)–T max diagram indicates that the organic matter corresponds to Type II kerogen of probable marine origin with high quality of oil generation. According to Rock–Eval data, and bitumen reflectance (BR r ), the samples are thermally early mature. Based on the studied samples, oil yield of the Qalikuh oil shales ranges from 6.1 to 7.9 wt.%. Mean oil–gas ratio is 2.7 and mean oil yield is 56.7 l/t rock. According to the observations, the production value of Qalikuh oil shale is more or less similar in the entire studied regions. Whereas the total production is below the expected values, the produced oil is considerably lighter (higher API) than that of most other known oil shales. [ABSTRACT FROM AUTHOR]

Bitumen extraction from oil sands ores after surface mining produces different tailings waste streams: ‘froth treatment tailings’ are enriched in pyrite relative to other streams. Tailings treatment can include addition of organic polymers to produce thickened tailings (TT). TT may be further de-watered by deposition into geotechnical cells for evaporative drying to increase shear strength prior to reclamation. To examine the acid rock drainage (ARD) potential of TT, we performed predictive analyses and laboratory experiments on material from field trials of two types of thickened froth treatment tailings (TT1 and TT2). Acid–base accounting (ABA) of initial samples showed that both TT1 and TT2 initially had net acid-producing potential, with ABA values of − 141 and − 230 t CaCO 3 equiv. 1000 t − 1 of TT, respectively. In long-term kinetic experiments, duplicate ~ 2-kg samples of TT were incubated in shallow trays and intermittently irrigated under air flow for 459 days to simulate evaporative field drying. Leachates collected from both TT samples initially had pH ~ 6.8 that began decreasing after ~ 50 days (TT2) or ~ 250 days (TT1), stabilizing at pH ~ 2. Correspondingly, the redox potential of leachates increased from 100–200 mV to 500–580 mV and electrical conductivity increased from 2–5 dS m − 1 to 26 dS m − 1 , indicating dissolution of minerals during ARD. The rapid onset and prolonged ARD observed with TT2 is attributed to its greater pyrite (13.4%) and lower carbonate (1.4%) contents versus the slower onset of ARD in TT1 (initially 6.0% pyrite and 2.5% carbonates). 16S rRNA gene pyrosequencing analysis revealed rapid shift in microbial community when conditions became strongly acidic (pH ~ 2) favoring the enrichment of Acidithiobacillus and Sulfobacillus bacteria in TT. This is the first report showing ARD potential of TT and the results have significant implications for effective management of pyrite-enriched oil sands tailings streams/deposits. [ABSTRACT FROM AUTHOR]

Bitumen reflectance (BRo) is an alternative maturity indicator to vitrinite reflectance (VRo) in Lower Paleozoic and marine rocks where few higher plant macerals can be found. In unconventional petroleum rocks, locally exuded and/or migrated oil are retained in the tight rocks and thermally and diagenetically consolidated into solid bitumen and pyrobitumen. Finding suitable bitumen macerals for BRo measurements pose a challenge in indicating the proper thermal maturity. This study reports the effects of surface imperfections caused by nanoporosity, surface granularities, and impurities on measuring BRo in core samples from the Jurassic Nordegg Shale (shale oil) and the Triassic Montney siltstone (tight gas) in the Western Canada Sedimentary Basin. The degree that bitumen's surface imperfections influence any given reflectance measurement was controlled by changing the probe size area. The larger the measuring probe, the higher the degree of surface imperfections is included in BRo readings. The effect is quantified in this paper, showing up to 27% diminishment of mean BRo values when the probe size increased from 0.31 to 5.85 μm 2 . The mode in which bitumen accumulates within the rock has a strong influence on the degree of surface imperfections. Bitumen which is disseminated within clay matrix introduces a high degree of nanoporosity and mineral interference and hence will result in lowest BRo. In contrast, inclusions of high reflecting micrinite or diagenetic minerals such as pyrite result in higher BRo. These effects can vary at the microscopic scale leading to multiple populations of reflectance readings and difficult interpretations of thermal maturity. [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]

The uptick in hydrocarbon production from shale in the United States has generated interest in metrics of unconventional reservoir quality, like permeability. We use conventional gas sorption to characterize shale microstructure, which provides insight on the features that govern mass transport. The gas sorption data are analyzed to determine the surface area, AS (m²/g), and pore volume, VP (cm³/g) of 30 samples from basins across North America. With this information, we quantify the effect of composition and thermal maturity on shale microstructure. In particular, we find that the specific surface area of the organic component evolves from ~50 m²/g total organic carbon (TOC) in immature shale to ~500 m²/g TOC for regions that produce dry gas. The increase in AS is accompanied by an increase in VP and concomitant decline in average pore size (e.g., rH = 4VP/AS). We contend that the latter is due to the development of nanometer-sized pores in kerogen as it is converted to mobile hydrocarbon which is ultimately expelled. This hypothesis is supported by similar measurements on companion samples after bitumen extraction or combustion, which underscore the intimate spatial association of petroleum and kerogen. Coupled with information on accessibility to the porosity garnered by varying the particle size, these results establish a clear link between organic matter, thermal maturity, and reservoir quality in unconventional shale systems. [ABSTRACT FROM AUTHOR]

Abstract: Facies models are used to better capture heterogeneity in mineral deposits and petroleum reservoirs. Facies are often considered as mutually exclusive and exhaustive at the scale of the geological model. These two assumptions are needed for sequential indicator simulation and most other facies modeling techniques; however, the assumption that an entire grid block consists of one facies type becomes unreasonable as the scale increases. Most geological models are built at a scale that is larger than the scale of variation of facies. Mixing of multiple facies types within a grid cell is common, especially in zones of transition between different facies. This paper develops a new technique to address the issue of non-exclusivity of facies within grid cells. The approach quantifies the uncertainty resulting from majority-vote upscaling of facies from core or well log scale to the grid cell scale and utilizes this uncertainty to build better models of continuous reservoir properties such as bitumen grade. Uncertainty is quantified using a measure of entropy that is capable of handling situations where there may be similarity between different facies types. A methodology to implement entropy in geo-modeling is introduced and demonstrated with several small examples. An example involving real data from the McMurray formation of Total''s Joslyn lease is used to demonstrate the improvement in accuracy compared with traditional modeling workflows. [Copyright &y& Elsevier]

The microstructure of oil sand samples extracted at a depth of 75 m from the estuarine Middle McMurray Formation (Alberta, Canada) has been investigated using high resolution three-dimensional (3D) X-ray microtomography (µCT) and cryo scanning electron microscopy (CryoSEM). µCT images evidenced some dense areas composed of highly angular grains surrounded by fluids, which are separated by larger pores full of gas. In dense areas, 3D image analysis provided porosity values comparable with in situ log data and macroscopic laboratory determinations, showing that they are representative of intact states. µCT hence provided some information on the morphology of the cracks and disturbance created by gas expansion. The CryoSEM technique, in which the sample is freeze fractured within the SEM chamber prior to observation, provided pictures in which the (frozen) bitumen clearly appears between the sand grains. No evidence of the existence of a thin connate water layer between grains and the bitumen, frequently mentioned in the literature, has been obtained. Bitumen appears to strongly adhere to the grains, with some grains being completely coated. The curved shape of some bitumen menisci suggests a bitumen wet behaviour. [ABSTRACT FROM AUTHOR]

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]

Abstract: Jordan has huge reserves of energy sources such as oil sand, oil shale, and olive cake. This work presents a part of an ongoing project to develop an appropriate low cost beneficiation technology for Jordanian oil sand. This study presents the utilization of a modified fluidized froth flotation process for beneficiation and bitumen recovery from Jordanian oil sand. This modification includes fluidization technology to replace the agitation process found in a typical flotation technology. Results of this research show that the recovery of bitumen from Jordanian oil sand reaches its maximum of 86% during the addition of 0.35wt% of a special cut of light cycle oil as a collector. The results show that the amount of hydrocarbon content (H.C) in oil sand has a minimal impact on floatability of oil sand. In addition, the results show that increasing the temperature enhances the bitumen recovery from Jordanian oil sand. The addition of NaOH is found to have a similar effect of increasing bitumen recovery. The results show that a special cut of cycle oil increases the bitumen recovery more than the normal cut of cycle oil. [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]

Viscosity is directly related to the mobility and quality of hydrocarbons in reservoirs, and its distribution is commonly heterogeneous. Therefore, viscosity has a great impact on the exploitation of heavy oil and bitumen reservoirs. Previous studies showed that viscosity measurements are problematic and are often inconsistent mainly because of the challenges of sample preparation and lack of a standard procedure for measuring viscosity in the oil and gas industry. This study aims to improve the characterization of reservoir viscosity by understanding the rheological properties of bitumen using bitumen samples from the Upper Devonian Grosmont reservoir, Alberta, Canada. This study shows that Grosmont bitumen is essentially a non-Newtonian fluid, exhibiting a distinctive shear-thinning behavior at low temperatures of less than 40°C. With increasing temperature, however, the bitumen changes from a non-Newtonian fluid to a Newtonian fluid. At low temperatures, the viscosity variations can be divided into four stages. A standard viscosity called "zero-shear viscosity" is obtained from the viscosity variations and can be used throughout the reservoir as characteristic viscosity for Grosmont bitumen. The viscosity distribution in the Grosmont reservoir is complex and appears to be stratigraphically related. Bitumen samples from formation boundaries tend to have higher viscosities, suggesting more severe biodegradation at these locations. Possible causes for the observed patterns in the Grosmont include (1) oil-water contacts migrating up and down over time; (2) oil migration and/or biodegradation controlled by aquitards that divide the reservoir into hydrostratigraphically separated units; and (3) differences in microbial activity, that is, aerobic versus anaerobic, possibly controlled by the level of oxygenation over time. [ABSTRACT FROM AUTHOR]

Abstract: Samples from two argillaceous formations (Opalinus Clay and Posidonia Shale) of near-identical maturity from northern Switzerland were subjected to a geochemical characterisation of organic matter and to confined-system pyrolysis experiments. Throughout the study area, the characteristics of organic matter are similar, indicating a spatially homogeneous sedimentary facies. Posidonia Shale contains marine organic matter deposited in a reducing environment, while a predominantly terrigenous source and a more oxidising environment of deposition was identified for Opalinus Clay. In the western and central parts of the study area, organic maturity is close to the onset of oil generation. In the easternmost part, a higher maturity has been reached due to a deeper burial below thick Tertiary Molasse deposits. Isothermal pyrolysis experiments were conducted at temperatures between 250 and 390°C over 24h. Bitumen yields increase along similar pathways for both Opalinus Clay and Posidonia Shale, but the maximum values are displaced by 10–20°C. Data pertaining to maturity were determined from GC–MS analyses of saturated hydrocarbons, and specific attention was given to C29-sterane and C32-hopane isomerisation ratios. The evolution of these parameters with rising temperature is slightly different in the two formations, which is attributed to the contrasting organic facies. The pyrolysis data, together with literature data from natural basins, were used to calculate kinetic parameters for C29-sterane and C32-hopane, assuming a single-step isomerisation scheme according to the Arrhenius law. The resulting values based on pyrolysis data alone are very similar to those based on the combination of pyrolysis and natural data. Activation energies are similar in both formations, while the frequency factors are up to one order of magnitude higher for Posidonia Shale when compared to Opalinus Clay. For the Benken site, maximum temperature during Cretaceous burial was calculated on the basis of the kinetic data, using the TTI approach. The resulting temperatures of 75–80°C are 5–10°C below those derived in the literature from apatite fission-track analysis, vitrinite reflectance and basin modelling. [Copyright &y& Elsevier]

Abstract: The formation and evolution of Silurian sandstone reservoirs, which are characterized by the coexistence of reservoir bitumen with different types of commercial oil pools in a very extensive area around the slope and uplift areas of the Manjiaer Depression in the Tarim Basin, NW China, are still in question. In this paper we report our investigations on the geological and geochemical characteristics of this reservoir. The results show there are four types of oil shows in the reservoir: severely biodegraded solid bitumen, biodegraded heavy oil, normal oils and light oils with slight biodegradation. Three suites of petroleum inclusions were identified in the reservoir which were formed during the early Devonian, Triassic to Cretaceous and late Tertiary, respectively. Petroleum in the Silurian sandstone reservoirs mainly originated from the mid-lower Cambrian source rock and mid-upper Ordovician source rock. The thermal maturity evolution of the source rocks in slope areas has shown that there were three main stages of oil generation that controlled the formation of the above three stages of petroleum inclusions. This evidence indicates that the Silurian reservoir has experienced three petroleum charge events during its geological history. The first charge event occurred during the early Devonian and it resulted in giant paleo-pools, which gradually evolved into the presently widespread bitumen due to the combination of biodegradation and thermal alteration. The second charge covered a long period from Triassic to Cretaceous and probably was related to both the mid-lower Cambrian source rock and the mid-upper Ordovician source rock. The petroleum generated during this stage mixed and interacted with the low matured residual bitumen and eventually formed the present soft bitumen and some residual heavy oils in the reservoirs. The third charge event, mainly associated with the mid-upper Ordovician source rocks, occurred mainly during late Tertiary and accounted for most of the present commercial petroleum pools (mainly normal and light oils). [Copyright &y& Elsevier]

Abstract: Biodegraded bitumens associated with quartz and calcite veins in the Cambrian Fish River Subgroup sediments of the Nama Group of southern Namibia have a geochemical signature diagnostic for organic matter that was deposited in a saline lacustrine palaeoenvironment. In particular, they contain abundant gammacerane, β-carotane and 3β-methylhopanes while 24-isopropyl cholestanes and dinosteroids are not detectable. Sealed tube hydrous pyrolysis of asphaltene and polar fractions yielded saturated hydrocarbons amenable to C isotopic analysis, and these analyses show unusually low δ 13C values. These combined characteristics are also present in immature bitumens from the Permian Irati Formation of Brazil and a saline lacustrine facies of the Whitehill Formation in the Karoo Basin, South Africa. We conclude that the bitumens originated from Whitehill equivalent strata of the Kalahari Basin deposited in what was an extensive saline lacustrine basin in southwestern Gondwana during the Early Permian. In southern Africa, source rocks of the Whitehill Formation are generally immature for petroleum generation and it is therefore likely that the Nama bitumens were expelled by contact metamorphism during emplacement of Karoo dolerite sills and dykes in the Jurassic. [Copyright &y& Elsevier]

Abstract: The province of Alberta is endowed with the second largest oil reserves in the world behind Saudi Arabia in the form of bitumen in oil sands, with established bitumen reserves of 27.0 109 m3 extracted from initial bitumen in place of 286.6 109 m3. This huge resource base presents enormous challenges to produce and upgrade bitumen in an environmentally responsible manner, related to potential greenhouse gas emissions. Extracting this bitumen from oil sands and thereafter upgrading it to synthetic crude oil requires extensive processing using either carbon rejection (coking) or hydrogen addition (hydrocracking). The production of hydrogen for hydrocracking necessitates emissions of CO2 into the atmosphere which contributes in a significant manner to Alberta’s greenhouse gas emissions. Enhance Energy Inc. and NorthWest Upgrading Inc., two privately funded Alberta based companies, are proposing a solution by constructing CO2 capture and a backbone CO2 gathering and distribution system from Alberta’s industrial heartland area, which is the site of current and proposed bitumen upgraders, to enhanced oil recovery fields in central and southern Alberta for ultimate sequestration of such CO2. This paper presents an overview of the project which is scheduled for operation in late 2013. [Copyright &y& Elsevier]

Solid bitumen was identified within the Mississippian Chester sandstone reservoir in the Hitch field, southwest Kansas. The adjacent Etzold field has similar reservoir properties but lacks solid bitumen, although the Hitch and Etzold fields were thought to be in pressure communication and have common source rocks. Hitch and Etzold crude oils and core extracts were characterized geochemically to gain a better understanding of the reservoir-filling history and geological and geochemical controls on solid bitumen formation in the Hitch reservoir. Based on a variety of geochemical characteristics, we propose that the Hitch and Etzold oils are mixtures derived from Ordovician and Late Devonian--early Mississippian (Woodford Shale) source rocks. The solid bitumen in the Hitch reservoir probably results from mixing of oils having different geochemical compositions, which filled the reservoir over an extended period. No evidence of severe biodegradation or thermal alteration is observed. A reservoir-filling scenario is proposed in an effort to explain why the Hitch oils are geochemically more heterogeneous than Etzold oils. Furthermore, gas de-asphalting and regional pressure drops as a result of post-Laramide orogeny may have contributed to a phase change in the reservoir fluid and deposition of solid materials by disturbance of thermodynamic equilibrium. The major significance of this study is related to improving our knowledge on the occurrence of the presence of solid bitumen in reservoirs that can introduce barriers into the reservoir, complicating waterflood operations and leading to erroneous oil-in-place calculations and subsequently lower than expected oil recovery. [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]

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]

Abstract: Silurian sandstone reservoirs in the Tazhong Uplift in the Tarim Basin, northwestern China are rich in bitumen and movable oil. Analysis of the biological markers indicates that the bitumen and movable oil came from two source rocks in the Cambrian and Middle/Upper Ordovician system, both of which are belong to marine facies. The Silurian system experienced three stages of oil filling, namely Late Caledonian period (400Ma), Late Hercynian period (240Ma) and Yanshan-Himalayan (40Ma) period. Most of the oil emplaced in the Late Caledonian was subsequently oxidized to bitumen. The movable oil found at the present time was mainly generated from the Middle/Upper Ordovician source rocks, with only a minor contribution from the Cambrian source rocks generating in the two later periods. Bitumen and heavy crude were largely trapped below a red mudstone unit while movable oil was concentrated below an underlying gray mudstone unit (the middle sub-section of bitumen sandstone section). Lateral migration into the Silurian reservoirs took place from northwest to southeast in each stage and was controlled by an inherited palaeohigh. While individual relatively limited in extent, the tidal-flat sandstones of the main reservoir have stacking patterns that generate extensive sand sheets. Faulting can both enhance connectivity and create traps. [Copyright &y& Elsevier]

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 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]

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]

Horizontal bitumen-filled microcracks are common within clay laminae of the finely laminated organic carbon-rich shale in the lower half of the heavily jointed Upper Devonian Dunkirk Shale, western New York state. Such cracks are not found higher in the Dunkirk Shale, where moderate bioturbation resulted in a relatively porous and permeable microfabric. Horizontal microcracks in a hydrocarbon source rock that carries regional vertical joints indicating a horizontal least principal stress owe their presence to material properties of the fractured shale and the magnitude and orientation of the crack-driving stress during kerogen maturation. Three material properties favored the horizontal initiation of microcracks in the Dunkirk Shale: (1) the abundance of flat kerogen grains oriented parallel to layering; (2) a marked strength anisotropy in large part caused by the laminated nature of the rock; and (3) the tight, strongly oriented planar clay-grain fabric produced by gravitational compaction of flocculated clay at shallow-burial depth. The latter was especially important to sustaining elevated pore pressure, the crack-driving stress, which was generated by the conversion of kerogen to bitumen. Poroelastic deformation of the low-permeability laminated shale pressurized by catagenesis, perhaps enhanced by compaction disequilibrium prior to kerogen conversion, elevated the in-situ horizontal stress in excess of the vertical stress, which remained constant during pore-pressure buildup, thereby favoring the propagation of microcracks in the horizontal plane. [ABSTRACT FROM AUTHOR]