Compacted shales cause problems because they tend to degrade with time due to weathering. Degradation results in the shale deteriorating from a hard rock-like material to a soft fine-grained soil mass with lower shear strength and high deformability. Consequently, common problems that occur in embankments constructed with compacted shales include settlement and instabilities. Therefore, accelerating weathering prior to compaction by wetting and breaking down the shales before placement can reduce the deterioration during the service life of the construction. Extensive laboratory testing was performed in order to characterize the mechanical behavior of compacted shales. Critical State theory is a clever framework that describes the mechanical behavior of soils with a simple system of equations that explains all the aspects of compression and shear of soils. NorSand is a model constructed in the framework of the Critical State theory that decouples the yield loci from the normally consolidated line. This characteristic made this model suitable for compacted shales. Also, empirical evidence showed that the plastic behavior of compacted shales is controlled by a Nova type flow rule that is a function of the mineralogical characteristics of the shales. This finding has implications in the shape of the yield loci and the hardening rule.

Thesis (M.S.)--West Virginia University, 2004. / Title from document title page. Document formatted into pages; contains viii, 105 p. : ill. (some col.), map. Includes abstract. Includes bibliographical references (p. 96-97).

Thesis (M.Sc.)--Memorial University of Newfoundland, 1995. / Typescript. Bibliography: leaves 75-86. Also available online.

The Piceance Creek Basin in northwestern Colorado contains extensive oil shale deposits that produce natural gas and which could potentially yield ~1.5 trillion barrels of shale oil. However, much of the oil shale lies at depths too great for traditional mining practices and various innovative approaches for in situ conversion of kerogen to oil have been proposed. A firm understanding of the existing hydrogeochemistry is needed as resulting mineralogical changes or rock-fluid reactions may affect rock porosity and permeability. Using an existing database complied by the USGS, the water chemistry of 267 surface and groundwater samples in the Piceance Creek primary drainage basin have been evaluated by mapping major ion concentrations and mineral saturation indicies with respect to hydrostratigraphic units and geologic structures. Controlling processes have been further assessed using statistical correlation and factor analysis. Results indicate that shallow waters in recharge zones are dominated by mixed cations (Na, Ca, Mg) and bicarbonate anions but with increased depth, groundwater transition to nearly 100% sodium bicarbonate type water. The chemistry of lower aquifer waters are principally controlled by nahcolite dissolution, but evidence of sulfate reduction and cation exchange aid in maintaining a sodium-bicarbonate water type. Ion evolution in surface and upper aquifer waters are influenced by an increase in sulfate concentration which is necessary to evolve water to an intermediate stage with sulfate-dominant anions. The source of sulfate is speculative, but likely due in part to the oxidation of sulfide-enriched groundwater and possible dissolution of sulfate-bearing carbonates. Surface and upper aquifer water chemistry in the northern portion of the basin is the result of discharge of deeper groundwater which is controlled to some degree by preferential pathways created by faults. Lower aquifer water migrates upward and mixes with the less-concentrated near-surface water, resulting in sodium bicarbonate type water in all hydrologic units.

Thesis: M.S., Massachusetts Institute of Technology, Department of Mechanical Engineering, 1979 / Bibliography: leaves 204-212. / by Peter Michael Switchenko. / M.S. / M.S. Massachusetts Institute of Technology, Department of Mechanical Engineering

Considerable work has been done on the economic production of shale oil from oil shale. Of the possible materials which could replace crude petroleum as used today, oil shale possesses the greatest possibilities since, when retorted, it produces a shale oil very similar to crude petroleum, and on refining the products produced are similar. Of the fuel resources available in the United States, 98.8 percent is attributed to coal, 0.8 percent to oil shale, 0.2 percent to crude petroleum, and 0.2 percent to natural gas. The purpose of this investigation was to study the effect of oil shale particle size on the shale oil obtained from oil shale retorted in a fluidized bed. Oil shale of minus 16 plus 28, minus 28 plus 70, minus 70 plus 100, and minus 100 plus 200 mesh (Tyler screen scale) was retorted at 715°F in a 4-inch diameter retort 36 inches long using carbon dioxide as the fluidizing medium. A retorting unit consisting of a fluidizing retort, fluidizing gas-heating section, disengaging section, cyclone separator, condensers, a surge tank, gas circulation system, and temperature measurement and control equipment was designed and constructed. The fluidizing gas-heating section was constructed from a flanged 5-foot section of 8-inch diameter black iron pipe with eight 1250-watt heaters placed in the heating section at 6-inch intervals along the vertical axis. Additional heaters were provided on the gas transfer line to reduce the heating time. The condensers were simple tube-in-shell heat exchangers constructed from 1-1/2-inch and 3/4-inch deoxidized copper pipe with headers for the oil receivers. The condensers were designed and constructed to operate counter-currently using return gas from the brine cooled condenser as the cooling medium in the first two condensers, water in the third condenser, and brine in the fourth condenser. A gas circulation section consisting of a gas pump and appropriate valves was constructed to circulate the gas through the system. Temperature control and measuring equipment were provided for control of the gas temperature to the retort, and for measuring the temperature of the entering and exit material in each section. On retorting 16-1/4 pounds of oil shale for one hour at a gas pressure of 10 pounds per square inch gage, yields of 50.5, 47.3, 40.9, and 39.4 percent of the available shale oil were obtained from oil shale of minus 16 plus 28, minus 28 plus 70, minus 70 plus 100, and minus 100 plus 200 mesh (Tyler screen scale), respectively. The A.P.I. gravity was found to increase from 15.2, 17.9, 18.6, and 22.4 degrees, and the kinematic viscosity decrease from 12.18, 4.64, 2.94, and 1.66 centipoises for a decrease in particle size from minus 16 plus 28, minus 28 plus 70, minus 70 plus 100, and minus 100 plus 200 mesh (Tyler screen scale), respectively. The mid-boiling point of the shale oil decreased 510, 500, 482, and 380°F for the above particle sizes as did the average boiling point which decreased from 824, 724, 690, and 590 for oil shale of the same particle size. The yield of non-condensable gases increased 0.67, 0.72, 1.01, and 1.2 cubic feet for oil shale of minus 16 plus 28, minus 28 plus 70, minus 70 plus 100, and minus 100 plus 200 mesh (Tyler screen scale). A decrease in particle size of oil shale retorted at 715°F in a 4-inch fluidized retort using carbon dioxide as the fluidizing medium, was found to definitely reduce the mid-boiling point, average boiling point, and the kinematic viscosity of the shale oil, and to increase the A.P.I. gravity of the shale oil obtained as well as the volume of retort gas. / Master of Science

La production d'hydrocarbures de schistes (shales) connait un regain d'intérêt à la fois scientifique et industriel depuis une quinzaine d’années. Cela représente de par le monde d’énormes ressources et risque de modifier durablement le marché énergétique, comme c'est le cas actuellement aux États Unis. Cependant, la récupération des hydrocarbures reste un enjeu majeur impactant au premier ordre la rentabilité de ces ressources. La majorité des hydrocarbures de shales est contenue dans des nodules micrométriques de matière organique : le kérogène, qui est à la fois la roche mère et le réservoir des fluides pétroliers. L’objectif de cette thèse est d’étudier le comportement du kérogène et de ses hydrocarbures grâce à la simulation moléculaire. Pour cela, nous avons effectué des simulations de Dynamique Moléculaire et de Monte Carlo à l’aide de logiciels existants et de développements internes. La première partie de ce travail a consisté à construire des modèles moléculaires visant à reproduire la matière organique contenue dans les shales (le kérogène et ses fluides). À partir de ces modèles, des structures 3D ont été générées en conditions de réservoirs. La représentativité de ces structures a été validée par des mesures expérimentales sur les propriétés volumiques, mécaniques, de stockage et de transport. Puis, nous avons mené une étude approfondie sur l’adsorption et la diffusion d’hydrocarbures dans la matrice kérogène. Les simulations moléculaires ont été effectuées en vue de fournir des données pseudo-expérimentales ainsi que des données de références pour la modélisation. Concernant les propriétés de stockage, un modèle théorique pour l’adsorption de mélanges de fluides sous-critiques (type gaz à condensats ou huiles légères) et super-critique (type gaz sec) a été proposé et validé sur les données de simulation moléculaires. Concernant les propriétés de transport, les mécanismes régissant les transferts de masses ont été identifiés et un modèle a été proposé pour prédire l’évolution des coefficients de diffusion des hydrocarbures avec la température, la pression et la composition des hydrocarbures. / Hydrocarbons production from shales has been of growing industrial and scientific interest for the last fifteen years. The different kinds of shale resources represent huge quantities around the world and may durably change the energy market, as for example in the US. However, the recovery process remains critical and may drastically impact the profitability of these resources. In shales, the majority of the fluids are contained in micrometered nodules of organic matter : the kerogen, which acts as source rock and as reservoir for the oil and gas. The aim of the PhD thesis is to study the kerogen and the petroleum fluids contained in shales, by molecular simulations. For this purpose, Monte Carlo and Molecular Dynamics simulations with existing molecular simulation softwares and in-house codes have been used. The first part of the work has been dedicated to the construction of molecular models mimicking shales organic matter (kerogen and embedded fluids), based on analytical data. From these models, 3D structures have been generated under typical reservoir conditions. Agreements with available experimental results have been found on volumetric, storage, transport and mechanical properties. Then, we have focused our efforts on the adsorption and diffusion of hydrocarbon mixtures in such materials. Molecular simulations have been performed to provide both pseudo-experimental and reference data. On storage properties, a theoretical model which accounts for multicomponent adsorption of super-critical (dry gas) and sub-critical (condensate gas, light oil) mixtures has been developed and validated. On transport properties, the mechanisms governing hydrocarbon mass transfer have been identified and a model has been proposed which describes the dependence of mixture diffusion coefficients with thermodynamic conditions (composition, pressure and temperature).

Σκοπός της εργασίας είναι η μελέτη της ωριμότητας της οργανικής ύλης ορισμένων σχηματισμών της Ιόνιας Ζώνης, όπως οι αργιλικοί σχίστες του ανώτερου και κατώτερου Ιουρασικού, ο Ανώτερος Πυριτικός Ορίζοντας της Βίγλας του Κρητιδικού και οι βιτουμενιούχοι Ψαμμίτες του Τριτογενούς, χρησιμοποιώντας τεχνικές Οργανικής Πετρολογίας. Τα δείγματα συλλέχθηκαν από επιφανειακές εμφανίσεις στην Ήπειρο. Αρχικά χρησιμοποιήθηκαν οξέα (HCl-HF) για να απομακρυνθεί το μεγαλύτερο μέρος των ανθρακικών και πυριτικών ορυκτών. Το συμπύκνωμα που προέκυψε, αναμίχθηκε με ZnCl2 συγκεκριμένης πυκνότητας, ώστε να επέλθει βαρυτικός διαχωρισμός του πετρώματος σε ελαφρύ και βαρύ κλάσμα. Το οργανικό μέρος οξειδώθηκε χημικά για να υπολογιστεί η περιεκτικότητα σε Ολικό Οργανικό Άνθρακα. Στιλπνές τομές παρασκευάστηκαν με ανάμιξη του οργανικού υλικού με διάλυμα εποξικής ρητίνης και μελετήθηκαν στο ανθρακοπετρογραφικό μικροσκόπιο. Έμφαση δόθηκε στην ανακλαστικότητα βιτρινίτη και τον προσδιορισμό των maceral. Εφαρμόστηκε επίσης περιθλασιμετρία ακτίνων Χ για να προσδιοριστεί η ορυκτολογική σύσταση των πετρωμάτων. Διαπιστώθηκε ότι οι αργιλικοί σχίστες του κατώτερου Ιουρασικού περιέχουν οργανική ύλη (TOC: 4,74%), ο βαθμός ωριμότητας (Rr 0,68%) της οποίας βρίσκεται εντός του παραθύρου πετρελαίου. Ωστόσο περαιτέρω έρευνα εστιασμένη στους Κατω-Ιουρασικούς αργιλικούς σχίστες με Posidonia, με τη βοήθεια της Οργανικής Πετρολογίας και της πυρόλυσης Rock-Eval είναι αναγκαία, προκειμένου να διαπιστωθεί η ποιότητά τους ως μητρικά πετρώματα υδρογονανθράκων. / The main objective of this paper is to study by means of Organic Petrology techniques, the maturity of the dispersed organic matter from certain sedimentary formations of the Ionian Zone, such as the Bituminous Shale, the Upper Siliceous Vigla Formation and the Bituminous Sandstone. The samples were collected from outcropping sites located in the region of Epirus. Initially they were treated with acids (HCl-HF) to remove most of the carbonate and silicate minerals. Then a ZnCl2 solution was used to concentrate the organic-rich fraction. Total Organic Carbon (TOC) content was determined applying dichromate oxidation. Polished blocks were prepared from the concentrated organic matter mounted in epoxy resin and examined under the coal-petrography microscope. Emphasis was given to maceral identification and vitrinite reflectance (Rr) measurements, which provide information regarding the quality and the maturity of the organic matter respectively, with implications for the petroleum generation potential regardless the level of alteration. The TOC and Rr values (4.74% and 0.68%, respectively) confirm to the oil potential of the Lower Jurassic Posidonia Shale. Nevertheless, it is suggested that detailed and higher resolution sampling focusing on the Lower Posidonia Shale, as well as organic petrography analyses coupled with Rock-Eval pyrolysis should be carried out in order to accurately determine its quality as petroleum source rocks.

The Jurassic (Toarcian) Posidonienschiefer of southern Germany is famous for its well preserved vertebrate fossils and its high organic content. The majority of the Posidonienschiefer (10 meters thick in the study area) consists of the Bituminous Shale, a fossiliferous laminated illite claystone. Two thin (30-40 mm) clayey pyritic biomicrosparites, the Upper and Lower Schlacken, interrupt the Bituminous Shale. Geologists who have studied the Posidonienschiefer disagree about the exact nature of its depositional environment. The argument centers on the interpretation of an impoverished benthic fauna and whether or not the water column directly above the sediment-water interface was anoxic or normally oxygenated. Kauffman (1981) proposed that an algal/fungal mat located at or near the sediment/water interface marked the boundary between aerobic and anaerobic conditions during deposition. The purpose of my research was to investigate the geologic conditions during deposition and early diagenesis of the Bituminous Shale and the Schlacken and to search for evidence of microbial activity. A detailed petrologic investigation of these two lithologies found no evidence of an algal/fungal mat, but did reveal the important contribution of microbial activity in the formation of pyrite and calcite cement. The Bituminous Shale was deposited in a low-energy tropical seaway. The upper water-column supported a diverse marine fauna. The aerobic/anaerobic boundary in the water column may have been located several millimeters above the sediment/water interface. Pore waters of the ocean-floor mud were dysaerobic to anaerobic. Occasional oxygenation events allowed opportunistic benthic organisms to colonize the sea-floor. Compaction of the Bituminous Shale occured prior to cementation of original porosity. Framboidal pyrite was formed during sulfidic diagenesis under anaerobic, but open, sediment/pore water conditions. Euhedral pyrite formed later as communication between pores became restricted during sediment compaction. The skeletal grains of the Schlacken formed as a winnowed lag deposit of Bituminous Shale sediment. During the early stages of sulfidic diagenesis the winnowed beds were rapidly cemented in a concretion-like sheet. Early cementation preserved delicate algal spores and clay fabric. Fossil bacteria were discovered in the calcite cement of the Schlacken by modified petrographic techniques, and confirmed with the scanning electron microscope. Experiments in which live bacteria were gradually entrapped in halite produced a crystal fabric identical to that of the fossiliferous calcite cement of the Schlacken. The microbial production of bicarbonate and ammonia during sulfidic diagenesis played a significant role in altering local geochemical conditions in the Schlacken sediment and initiated the precipitation of calcite cements. Fossil bacteria in the cements of the Schlacken are direct evidence of the presence and entrapment of bacteria during cementation, but do not conclusively prove their active role in the formation of calcite. / text

Characterizing natural and man-made fracture networks is fundamental to predicting the storage capacity and pathways for flow of both carbonate and shale reservoirs. The goal of this study is to determine the seismic response specifically to networks of fractures clustered closely together through the analysis of seismic wavefield scatter, directional phase velocities, and amplitude attenuation. To achieve this goal, finite element modeling techniques are implemented to allow for the meshing of discontinuous fracture interfaces and, therefore, provide the most accurate calculation of seismic events from these irregular surfaces. The work presented here focuses on the center layer of an isotropic model that is populated with two main phases of fracture network alteration: a single large-scale cluster and multiple smaller-scale clusters. Phase 1 first confirms that the seismic response of a single idealized vertically fractured cluster is distinct crosscutting energy within a seismogram. Further investigation shows that, as fracture spacing within the cluster decreases, the depth at which crosscutting energy appears exponentially increases, placing it well below the true location of the cluster. This relationship holds until 28% of the fractures are moved from their uniformly spaced locations to random locations within the cluster. The vertical thickness of the cluster has little effect on the location or strength or the crosscutting signature. Phase 2 shows that, although clusters of more randomly spaced fractures mask crosscutting energy, a marked decrease in amplitude coinciding with a bend in the wavefront produces a heterogeneous anisotropic seismic response. This amplitude decay and heterogeneous anisotropy is visible until cluster spacing drops below one half of the wavelength or the ratio of fractured material to matrix material within a cluster drops below 37%. Therefore, the location of an individual fracture cluster can be determined from the location of amplitude decay, heterogeneous anisotropy, and crosscutting energy. Furthermore, the density of the cluster can be determined from the degree of amplitude decay, the angle of heterogeneous anisotropy, and the depth of cross-cutting energy. These relationships, constrained by limits on their detectability, can aid fracture network interpretation of real seismic data. / text