A Bacia do Araripe, conforme Brito Neves et al. (2000), está inserida na unidade geotectônica da Província Borborema, abrangendo os estados do Ceará, Pernambuco e Piauí. Este trabalho buscou identificar possíveis intervalos potencialmente geradores da Formação Santana (Aptiano-Albiano) na Bacia do Araripe, a partir de técnicas de geoquímica e petrografia orgânica para caracterizar dez amostras de campo, referentes a folhelhos orgânicos provenientes deste intervalo estratigráfico. Os valores de COT indicam que todas as amostras possuem mais que o mínimo de carbono orgânico necessário para geração de hidrocarbonetos, a partir de 1 % em massa. Foram encontrados valores no pico S2 que variam de 7,44 a 13,56 mg HC/g de rocha para os Membros Crato e Romualdo (base e topo da Formação estudada), conferindo-lhes um potencial petrolífero bom e muito bom, respectivamente. No Membro intermediário, Ipubi, há um acréscimo na produção de hidrocarbonetos rumo ao seu topo estratigráfico, mas ocorre também a amostra com mais pobre potencial petrolífero, a amostra 9, com valor de S2 de 0,05 mg HC/g de rocha. O tipo de querogênio é classificado como tipo II para os Membros Crato e Romualdo, e tipos I, II e III para o Membro Ipubi. Os valores de ICE variam entre 3.0 a 4.0 (Robertson Research Limited), e de Tmax (361 a 433 ºC), permitindo classificar as amostras como imaturas a marginalmente maturas, conforme classificação de Peters & Cassa (1994) Foram encontradas vitrinitas apenas no Membro Ipubi, indicando material imaturo com 0,29 – 0,48% Rrandom, e baixo grau de maturação 0,60% Rrandom na amostra 2. A petrografia sob luz refletida mostra que as amostras 2, 3 e 9 estão contaminadas por betumen, interferindo nos valores de índice de produção, além de reflectância da vitrinita para a amostra 9. Análises de DRX mostram que o quartzo é o mineral mais abundante nas amostras, seguido pela esmectita e calcita, por vezes gipso, pirita e ilita e raramente caolinita. A petrografia sob luz transmitida, indica a matéria orgânica amorfa, como sendo o principal componente do querogênio estudado, seguido por fitoclastos e palinomorfos. A Análise elementar das razões atômicas de N, C, H e S, apontam os maiores valores nas amostras 5 a 8 (Membro Ipubi), podendo relacioná-las também aos maiores valores de COT e pertencentes a querogênio do tipo I, o menor valor dos parâmetros supracitados ocorre na amostra 9, a única que possui querogênio do tipo III. Os valores intermediários encontrados nas amostras 1 a 4 e 10, coincidem com amostras referentes a querogênio do tipo II. O intervalo em que se observa maior predominância destas condições está localizado no topo do Membro Ipubi, englobando as amostras 5 a 8. Foi determinado, a partir das análises realizadas, que este grande intervalo é caracterizado como o maior potencial gerador de petróleo identificado neste trabalho, apesar das amostras analisadas estarem imaturas. / The Araripe Basin, according to Brito Neves et al. (2000), is inserted in the geotectonic unit of the Borborema Province, covering the states of Ceará, Pernambuco and Piauí. This study aimed to identify possible potentially generating intervals of the Santana Formation (Aptian-Albian) in the Araripe Basin, from geochemical techniques and organic petrography to characterize ten samples field, referring to organic shales from this stratigraphic interval. The COT values indicate that all samples have more than the minimum of organic carbon required for generation of hydrocarbons, from 1% by mass. The S2 values ranging from 7.44 to 13.56 mg HC / g of rock for the Crato and Romualdo Members (base and top of the study Formation), giving them a good petroleum potential and very good, respectively. In the intermediate member, Ipubi, there is an increase in production of hydrocarbons toward its top stratigraphic, but also occurs the sample with poorer oil potential, the sample 9, with a value of S2 0.05 mg HC / g rock. The type of kerogen is classified as type II for Members Crato and Romualdo, and types I, II and III to the Member Ipubi. SCI values range from 3.0 to 4.0 (Robertson Research Limited), and Tmax (361-433 °C), allowing classifying the samples as immature to marginally mature, as Peters & Cassa classification (1994). Vitrinitas were found only in the Member Ipubi indicating immature material with from 0.29 to 0.48% Rrandom and low degree maturity 0.60% Rrandom the sample 2 The petrographic under reflected light shows that samples 2, 3 and 9 are contaminated with bitumen, interfering with the production index values, and the vitrinite reflectance for sample 9. XRD analysis shows that quartz is the most abundant mineral in the samples, followed by the smectite and calcite sometimes gypsum, pyrite and illite and kaolinite rarely.The petrographic under transmitted light, indicates the amorphous organic material as the main component of kerogen studied, followed by phytoclasts and palinomorphs. The Analysis of the atomic ratios of N, C, H and S, indicate the highest values in samples 5-8 (Member Ipubi), associated also to higher TOC values and belonging to Type I kerogen, the lowest value the above parameters occurs in the sample 9, the one that has the type III kerogen. Intermediate values found in samples 1 to 4 and 10 matching samples related to type II kerogen. The interval in which there is a predominance of these conditions is located at the top of the Member Ipubi, encompassing the samples 5 to 8. It was determined from the analyzes carried out, this long interval is characterized as the greatest potential for generating oil identified in this work although of the samples are immature.

Organic shales have become one of the greatest sources of hydrocarbon thanks to novel production techniques such as hydraulic fracturing. A successful hydraulic fracturing job, however, is dependent on several rock properties such as mineralogy and elasticity. A reliable estimation of such properties is therefore necessary to determine ideal rocks for horizontal well placement. In this study, rock types within the Eagle Ford shale that would be suitable for hydraulic fracturing are identified through interpretations of available well logs and core data. A comparative study of petrophysical properties such as mineral content, kerogen type and maturity, porosity, and saturation in six wells is performed to characterize the Eagle Ford shale. Two of the wells studied are within the wet gas window of the shale while the remaining four are in the oil window. Based on the calculated petrophysical properties, rock typing was performed using k-means clustering. Two rock types (RT1 and RT2) were identified and their compositions compared in each well. Elastic properties for the various rock types identified were then estimated using the differential effective medium (DEM) theory and were validated through simulation of slowness logs. The final rock type assessment was then performed to identify ideal rocks for hydrofracturing. Results indicate that the Eagle Ford mineralogy varies greatly with depth and with geographic location relative to the San Marcos Arch, a geological arching prominence across the shale. Northeast of the arch, the Eagle Ford shale is clay-rich. Preferred rocks for hydrocarbon production, RT1, are characterized by volumetric concentrations of ~0.44 carbonate, ~0.09 kerogen, ~0.07 porosity, and ~0.42 clay; RT1 also exhibits high sonic velocities (> 3400 m/s and > 1500 m/s compressional and shear, respectively) and high apparent electrical resistivity (> 2 ohm-m). In the Southwest region, on the other hand, the Eagle Ford shale is mostly calcareous. Ideal rocks in the region, RT1, are rich in kerogen (~0.1) with carbonate content of ~0.56, ~0.1 porosity, ~0.19 clay content, and resistivity > 20 ohm-m. In both regions, porosity and pore aspect ratio displayed substantial effects on elastic properties. For example, over 80% decrease in Young’s modulus was quantified when pore aspect ratio approached zero; high pore aspect ratio is preferred for stiff rocks. Poisson’s ratio estimates were not always reliable therefore fracturability was assessed based on Young’s modulus estimates. The study shows that depth intervals exhibiting Young’s moduli above 18GPa and 21GPa in the Northeast and Southwest region, respectively, are suitable for hydrofracturing. / text

The Marcellus Shale is an important resource play prevalent in several states in the eastern United States. The productive zone of the Marcellus Shale has variations in rock properties such as clay content, kerogen content and pore aspect ratio, and these variations may strongly effect elastic anisotropy. The objective of this study is to characterize surface seismic sensitivity for variations in anisotropic parameters relating to kerogen content and aspect ratio of kerogen saturated pores. The recognized sensitivity may aid to characterize these reservoir from surface seismic observations for exploration and production of hydrocarbon. In this study, I performed VTI anisotropic modeling based on geophysical wireline log data from Harrison County, WV. The wireline log data includes spectral gamma, density, resistivity, neutron porosity, monopole and dipole sonic logs. Borehole log data were analyzed to characterize the Marcellus Shale interval, and quantify petrophysical properties such as clay content, kerogen content and porosity. A rock physics model was employed to build link between petrophysical properties and elastic constants. The rock physics model utilized differential effective medium (DEM) theory, bounds and mixing laws and fluid substitution equations in a model scheme to compute elastic constants for known variations in matrix composition, kerogen content and pore shape distribution. The seismic simulations were conducted applying a vertical impulse source and three component receivers. The anisotropic effect to angular amplitude variations for PP, PS and SS reflections were found to be dominantly controlled by the Thomsen Ɛ parameter, characterizing seismic velocity variations with propagation direction. These anisotropic effect to PP data can be seen at large offset (>15o incidence angle). The most sensitive portion of PS reflections was observed at mid offset (15o-30o). I also analyzed seismic sensitivity for variations in kerogen content and aspect ratio of structural kerogen. Elastic constants were computed for 5%, 10%, 20% and 30% kerogen content from rock physics model and provided to the seismic model. For both kerogen content and aspect ratio model, PP amplitudes varies significantly at zero to near offset while PS amplitude varied at mid offsets (12 to 30 degree angle of incidences). / text

A Bacia do Araripe, conforme Brito Neves et al. (2000), está inserida na unidade geotectônica da Província Borborema, abrangendo os estados do Ceará, Pernambuco e Piauí. Este trabalho buscou identificar possíveis intervalos potencialmente geradores da Formação Santana (Aptiano-Albiano) na Bacia do Araripe, a partir de técnicas de geoquímica e petrografia orgânica para caracterizar dez amostras de campo, referentes a folhelhos orgânicos provenientes deste intervalo estratigráfico. Os valores de COT indicam que todas as amostras possuem mais que o mínimo de carbono orgânico necessário para geração de hidrocarbonetos, a partir de 1 % em massa. Foram encontrados valores no pico S2 que variam de 7,44 a 13,56 mg HC/g de rocha para os Membros Crato e Romualdo (base e topo da Formação estudada), conferindo-lhes um potencial petrolífero bom e muito bom, respectivamente. No Membro intermediário, Ipubi, há um acréscimo na produção de hidrocarbonetos rumo ao seu topo estratigráfico, mas ocorre também a amostra com mais pobre potencial petrolífero, a amostra 9, com valor de S2 de 0,05 mg HC/g de rocha. O tipo de querogênio é classificado como tipo II para os Membros Crato e Romualdo, e tipos I, II e III para o Membro Ipubi. Os valores de ICE variam entre 3.0 a 4.0 (Robertson Research Limited), e de Tmax (361 a 433 ºC), permitindo classificar as amostras como imaturas a marginalmente maturas, conforme classificação de Peters & Cassa (1994) Foram encontradas vitrinitas apenas no Membro Ipubi, indicando material imaturo com 0,29 – 0,48% Rrandom, e baixo grau de maturação 0,60% Rrandom na amostra 2. A petrografia sob luz refletida mostra que as amostras 2, 3 e 9 estão contaminadas por betumen, interferindo nos valores de índice de produção, além de reflectância da vitrinita para a amostra 9. Análises de DRX mostram que o quartzo é o mineral mais abundante nas amostras, seguido pela esmectita e calcita, por vezes gipso, pirita e ilita e raramente caolinita. A petrografia sob luz transmitida, indica a matéria orgânica amorfa, como sendo o principal componente do querogênio estudado, seguido por fitoclastos e palinomorfos. A Análise elementar das razões atômicas de N, C, H e S, apontam os maiores valores nas amostras 5 a 8 (Membro Ipubi), podendo relacioná-las também aos maiores valores de COT e pertencentes a querogênio do tipo I, o menor valor dos parâmetros supracitados ocorre na amostra 9, a única que possui querogênio do tipo III. Os valores intermediários encontrados nas amostras 1 a 4 e 10, coincidem com amostras referentes a querogênio do tipo II. O intervalo em que se observa maior predominância destas condições está localizado no topo do Membro Ipubi, englobando as amostras 5 a 8. Foi determinado, a partir das análises realizadas, que este grande intervalo é caracterizado como o maior potencial gerador de petróleo identificado neste trabalho, apesar das amostras analisadas estarem imaturas. / The Araripe Basin, according to Brito Neves et al. (2000), is inserted in the geotectonic unit of the Borborema Province, covering the states of Ceará, Pernambuco and Piauí. This study aimed to identify possible potentially generating intervals of the Santana Formation (Aptian-Albian) in the Araripe Basin, from geochemical techniques and organic petrography to characterize ten samples field, referring to organic shales from this stratigraphic interval. The COT values indicate that all samples have more than the minimum of organic carbon required for generation of hydrocarbons, from 1% by mass. The S2 values ranging from 7.44 to 13.56 mg HC / g of rock for the Crato and Romualdo Members (base and top of the study Formation), giving them a good petroleum potential and very good, respectively. In the intermediate member, Ipubi, there is an increase in production of hydrocarbons toward its top stratigraphic, but also occurs the sample with poorer oil potential, the sample 9, with a value of S2 0.05 mg HC / g rock. The type of kerogen is classified as type II for Members Crato and Romualdo, and types I, II and III to the Member Ipubi. SCI values range from 3.0 to 4.0 (Robertson Research Limited), and Tmax (361-433 °C), allowing classifying the samples as immature to marginally mature, as Peters & Cassa classification (1994). Vitrinitas were found only in the Member Ipubi indicating immature material with from 0.29 to 0.48% Rrandom and low degree maturity 0.60% Rrandom the sample 2 The petrographic under reflected light shows that samples 2, 3 and 9 are contaminated with bitumen, interfering with the production index values, and the vitrinite reflectance for sample 9. XRD analysis shows that quartz is the most abundant mineral in the samples, followed by the smectite and calcite sometimes gypsum, pyrite and illite and kaolinite rarely.The petrographic under transmitted light, indicates the amorphous organic material as the main component of kerogen studied, followed by phytoclasts and palinomorphs. The Analysis of the atomic ratios of N, C, H and S, indicate the highest values in samples 5-8 (Member Ipubi), associated also to higher TOC values and belonging to Type I kerogen, the lowest value the above parameters occurs in the sample 9, the one that has the type III kerogen. Intermediate values found in samples 1 to 4 and 10 matching samples related to type II kerogen. The interval in which there is a predominance of these conditions is located at the top of the Member Ipubi, encompassing the samples 5 to 8. It was determined from the analyzes carried out, this long interval is characterized as the greatest potential for generating oil identified in this work although of the samples are immature.

A Bacia do Araripe, conforme Brito Neves et al. (2000), está inserida na unidade geotectônica da Província Borborema, abrangendo os estados do Ceará, Pernambuco e Piauí. Este trabalho buscou identificar possíveis intervalos potencialmente geradores da Formação Santana (Aptiano-Albiano) na Bacia do Araripe, a partir de técnicas de geoquímica e petrografia orgânica para caracterizar dez amostras de campo, referentes a folhelhos orgânicos provenientes deste intervalo estratigráfico. Os valores de COT indicam que todas as amostras possuem mais que o mínimo de carbono orgânico necessário para geração de hidrocarbonetos, a partir de 1 % em massa. Foram encontrados valores no pico S2 que variam de 7,44 a 13,56 mg HC/g de rocha para os Membros Crato e Romualdo (base e topo da Formação estudada), conferindo-lhes um potencial petrolífero bom e muito bom, respectivamente. No Membro intermediário, Ipubi, há um acréscimo na produção de hidrocarbonetos rumo ao seu topo estratigráfico, mas ocorre também a amostra com mais pobre potencial petrolífero, a amostra 9, com valor de S2 de 0,05 mg HC/g de rocha. O tipo de querogênio é classificado como tipo II para os Membros Crato e Romualdo, e tipos I, II e III para o Membro Ipubi. Os valores de ICE variam entre 3.0 a 4.0 (Robertson Research Limited), e de Tmax (361 a 433 ºC), permitindo classificar as amostras como imaturas a marginalmente maturas, conforme classificação de Peters & Cassa (1994) Foram encontradas vitrinitas apenas no Membro Ipubi, indicando material imaturo com 0,29 – 0,48% Rrandom, e baixo grau de maturação 0,60% Rrandom na amostra 2. A petrografia sob luz refletida mostra que as amostras 2, 3 e 9 estão contaminadas por betumen, interferindo nos valores de índice de produção, além de reflectância da vitrinita para a amostra 9. Análises de DRX mostram que o quartzo é o mineral mais abundante nas amostras, seguido pela esmectita e calcita, por vezes gipso, pirita e ilita e raramente caolinita. A petrografia sob luz transmitida, indica a matéria orgânica amorfa, como sendo o principal componente do querogênio estudado, seguido por fitoclastos e palinomorfos. A Análise elementar das razões atômicas de N, C, H e S, apontam os maiores valores nas amostras 5 a 8 (Membro Ipubi), podendo relacioná-las também aos maiores valores de COT e pertencentes a querogênio do tipo I, o menor valor dos parâmetros supracitados ocorre na amostra 9, a única que possui querogênio do tipo III. Os valores intermediários encontrados nas amostras 1 a 4 e 10, coincidem com amostras referentes a querogênio do tipo II. O intervalo em que se observa maior predominância destas condições está localizado no topo do Membro Ipubi, englobando as amostras 5 a 8. Foi determinado, a partir das análises realizadas, que este grande intervalo é caracterizado como o maior potencial gerador de petróleo identificado neste trabalho, apesar das amostras analisadas estarem imaturas. / The Araripe Basin, according to Brito Neves et al. (2000), is inserted in the geotectonic unit of the Borborema Province, covering the states of Ceará, Pernambuco and Piauí. This study aimed to identify possible potentially generating intervals of the Santana Formation (Aptian-Albian) in the Araripe Basin, from geochemical techniques and organic petrography to characterize ten samples field, referring to organic shales from this stratigraphic interval. The COT values indicate that all samples have more than the minimum of organic carbon required for generation of hydrocarbons, from 1% by mass. The S2 values ranging from 7.44 to 13.56 mg HC / g of rock for the Crato and Romualdo Members (base and top of the study Formation), giving them a good petroleum potential and very good, respectively. In the intermediate member, Ipubi, there is an increase in production of hydrocarbons toward its top stratigraphic, but also occurs the sample with poorer oil potential, the sample 9, with a value of S2 0.05 mg HC / g rock. The type of kerogen is classified as type II for Members Crato and Romualdo, and types I, II and III to the Member Ipubi. SCI values range from 3.0 to 4.0 (Robertson Research Limited), and Tmax (361-433 °C), allowing classifying the samples as immature to marginally mature, as Peters & Cassa classification (1994). Vitrinitas were found only in the Member Ipubi indicating immature material with from 0.29 to 0.48% Rrandom and low degree maturity 0.60% Rrandom the sample 2 The petrographic under reflected light shows that samples 2, 3 and 9 are contaminated with bitumen, interfering with the production index values, and the vitrinite reflectance for sample 9. XRD analysis shows that quartz is the most abundant mineral in the samples, followed by the smectite and calcite sometimes gypsum, pyrite and illite and kaolinite rarely.The petrographic under transmitted light, indicates the amorphous organic material as the main component of kerogen studied, followed by phytoclasts and palinomorphs. The Analysis of the atomic ratios of N, C, H and S, indicate the highest values in samples 5-8 (Member Ipubi), associated also to higher TOC values and belonging to Type I kerogen, the lowest value the above parameters occurs in the sample 9, the one that has the type III kerogen. Intermediate values found in samples 1 to 4 and 10 matching samples related to type II kerogen. The interval in which there is a predominance of these conditions is located at the top of the Member Ipubi, encompassing the samples 5 to 8. It was determined from the analyzes carried out, this long interval is characterized as the greatest potential for generating oil identified in this work although of the samples are immature.

L’exploitation des ressources naturelles non conventionnelles en substitution du pétrole est un des défis du 21e siècle. La transformation microbiologique in situ de ces ressources en méthane est une des voies les plus prometteuses développées aujourd’hui mais son application reste à démontrer. Mes objectifs ont été de démontrer l'existence d'une conversion microbiologique en méthane de la matière organique (MO) de schistes immatures et de la quantifier pour extrapoler la production potentielle de méthane à l’échelle d’un bassin sédimentaire. Une méthode de détection et de suivi des consortia méthanogènes des schistes cartons en microcosmes, par une combinaison de PCR quantitative, GC-FID et pyrolyse Rock-Eval, a été mise au point et validée. Elle a été appliquée à l’étude de la distribution spatiale des méthanogènes dans les schistes cartons du bassin de Paris et à la démonstration de la méthanisation de la MO de ces roches. Les résultats montrent comme attendu la conversion des fractions solubles de la MO (bitume) par un consortium méthanogène isolé des schistes, mais également la transformation d’une fraction plus complexe (kérogène). L’absence de corrélation stricte entre la lithologie et la présence de méthanogènes actifs rend l’extrapolation au niveau du bassin plus difficile, mais la localisation des méthanogènes à la fois dans et hors les zones riches en MO constitue un avantage certain dans l'optique d'une exploitation économique de ces ressources. Ces travaux démontrent un potentiel élevé de production microbiologique de méthane dans le bassin de Paris et ouvrent la voie vers des études de faisabilité et rentabilité économique à l’échelle d’un site de production. / The exploitation of natural unconventional resources in substitution for petroleum is one of the challenges of the 21st century. In situ microbial transformation of these resources in methane is one of the most promising pathway currently developed, although its application needs to be demonstrated. My objectives were to demonstrate the existence of a microbial conversion into methane of the organic matter (OM) of immature shales, and to quantify it in order to extrapolate the potential for methane production of the rocks at the sedimentary basin scale. A method of detection and monitoring of methanogenic consortia from paper shales in microcosms, combining quantitative PCR, GC-FID and Rock-Eval pyrolysis, was developed and validated. It was used to study the spatial distribution of methanogens in paper shales of the Paris Basin and to demonstrate the methanization of the OM of these rocks. The results show the conversion of the soluble fractions of the OM (bitumen) by methanogenic consortia isolated from shales, but also the transformation of a more complex fraction (kerogen). No strict correlation was established between lithology and presence of active methanogens, which makes the extrapolation of methane production to the basin scale more difficult. However, the localization of methanogens in both OM-rich and OM-poor zones constitute an advantage in the perspective of an economic exploitation of these resources. This work demonstrates a great potential for microbial methane production in the Paris Basin and paves the way to studies of economic feasibility and profitability on the scale of a production site.

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).

The Cretaceous Mowry Shale is an organic-rich, siliceous marine shale, and as such is a known source rock in the Western United States. Studies have documented that total organic carbon (TOC) in the Wind River Basin, Wyoming increases to the southeast. These studies cover large areas with limited sample sets. In this study, over 250 samples were collected near Lander, Wyoming to address spatial heterogeneity of TOC within the Mowry Shale at a much finer scale than previously examined. Samples were collected along five vertical sections at three localities, and following correlation of the vertical sections, which was strongly aided by the presence of regional bentonite horizons, samples were collected laterally from the same unit at regular 25-foot intervals. These samples were analyzed using pyrolysis and x-ray diffraction techniques. Average TOC values are fairly consistent within the study area (1.65%, with a range of 2.10% to 1.15%). Average Tmax values for vertical and lateral samples is 433 °C with a standard deviation of 7.25 °C suggesting immature to very early oil window thermal maturity. Kerogen types are determined to be dominantly type III, suggesting a dominance of terrestrial input, becoming slightly more mixed type II/III to the southeast. Redox-sensitive trace metals such as uranium, thorium, vanadium, chromium, cobalt, and molybdenum values all suggest a slightly oxygenated sediment water interface during time of deposition. These pyrolysis and trace metal data suggest that the study area was in a prograding proximal marine/prodeltaic depositional environment during Upper Mowry time with influences from higher energy bottom flows. Lateral homogeneity of strata and the low variability in geochemical character across the study area suggest that the local basin in the study area was not segmented by structural or oceanographic conditions. While efforts were made to collect unaltered outcrop samples (digging back into what appeared to be unfractured, unaltered rock), alteration or weathering of organic material is a concern for source rock evaluation of near-surface outcrops. In order to address this concern, a 5-foot-deep trench was dug back into the outcrop at the target horizon in one locality. Samples were taken at regular three-inch intervals from this trench as it was excavated to determine the effect of weathering on TOC in the study area. Based on pyrolysis results, TOC was affected by weathering only along fracture sets (several samples intersected fractures in the shallow subsurface) and did not appreciably increase from the surface to a depth of five feet. Due to the impermeable nature of shale rock, decreases of TOC due to weathering appear to be limited to the immediate surface of samples and along fracture sets.

The Northern Carnarvon Basin is the richest petroleum province in Australia. About 50 gas/condensate and oil fields, associated mainly with Jurassic source rocks, have been discovered in the sub-basins and on the Rankin Platform since 1964. The basin is located at the southern end of the North West Shelf of Australia. It can be mainly subdivided into the Exmouth, Barrow, Dampier and Beagle Sub-basins, the Rankin Platform and Exmouth Plateau. The sub-basins are rift-related grabens and half-grabens developed during the Jurassic to the earliest Cretaceous and contain over 10 kilometres of Mesozoic and Cainozoic sedimentary rocks, among which are several thousand meters of Jurassic rocks. The formations of the Jurassic and the lower part of the Barrow Group of Early Cretaceous age in the sub-basins of the Northern Carnarvon Basin were found to be overpressured with excess pressures of 5-29 MPa at depths of 2900-3600 m indicated by repeat formation tests (RFTs) and drill stem tests (DSTs). The characteristics of organic matter, thermal history and thermal maturity, pressure seal and overpressure evolution in the sub-basins are crucial to a proper understanding of the nature and dynamic processes of hydrocarbon generation and migration in the basin. Based on organic geochemical data, the important source rocks in the basin are Jurassic organic-rich fine-grained rocks including the Murat Siltstone, the rift-related Athol Formation and Dingo Claystone. The Mungaroo Formation of the Middle-Upper Triassic contains gas-generating source rocks. These formations recognised to be organic rich based on 1256 values of the total organic carbon content (TOC, %) from 17 wells. Average TOC values (calculated from samples with TOC < 15 %) are about 2.19 % in the Mungaroo Formation, about 2.09 % in the Murat Siltstone and about 1.74 % in the Athol Formation and Dingo Claystone. / Data from kerogen element analysis, Rock-Eval pyrolysis, visual kerogen composition and some biomarkers have been used to evaluate the kerogen type in the basin. It appears that type III kerogen is the dominant organic-matter type in the Triassic and Jurassic source rocks, while the Dingo Claystone may contain some oil-prone organic matter. The vitrinite reflectance (Ro) data in some wells of the Northern Carnarvon Basin are anomalously low. As a major thermal maturity indicator, the anomalously low Ro data seriously hinder the assessment of thermal maturity in the basin. This study differs from other studies in that it has paid more attention to Rock-Eval Tmax data. Therefore, problems affecting Tmax data in evaluating thermal maturity were investigated. A case study of contaminated Rock-Eval data in Bambra-2 and thermal modelling using Tmax data in 16 wells from different tectonic subdivisions were carried out. The major problems for using Tmax data were found to be contamination by drilling-mud additives, natural bitumen and suppression due to hydrogen index (HI) > 150 in some wells. Although the data reveal uncertainties and there is about ±3-10 % error for thermal modelling by using the proposed relationship of Ro and Tmax, the "reliable" Tmax data are found to be important, and useful to assess thermal maturity and reduce the influence of unexpectedly low Ro data. / This study analyzed the characteristics of deep overpressured zones and top pressure seals, in detail, in 7 wells based on the observed fluid pressure data and petrophysical data. The deep overpressured system (depth greater than 2650-3000 m) in the Jurassic formations and the lower part of the Barrow Group is shown by the measured fluid pressure data including RFTs, DSTs and mud weights. The highly overpressured Jurassic fine-grained rocks also exhibit well-log responses of high sonic transit times and low formation resistivities. The deep overpressured zone, however, may not necessarily be caused by anomalously high porosities due to undercompaction. The porosities in the deep overpressured Jurassic rocks may be significantly less than the well-log derived porosities, which may indicate that the sonic-log and resistivity-log also directly respond to the overpressuring in the deep overpressured fine-grained rocks of the sub-basins. Based on the profiles of fluid pressure and well-log data in 5 wells of the Barrow Sub-basin, a top pressure seal was interpreted to be consistent with the transitional pressure zone in the Barrow Sub-basin. This top pressure seal was observed to consist of a rock layer of 60-80 % claystone and siltstone. The depths of the rock layer range from 2650 m to 3300 m with thicknesses of 300-500 m and temperatures of 110-135 °C. Based on the well-log data, measured porosity and sandstone diagenesis, the rock layer seems to be well compacted and cemented with a porosity range of about 2-5 % and calculated permeabilities of about 10-19 to 10-22 M2. / This study performed thermal history and maturity modelling in 14 wells using the BasinMod 1D software. It was found that the thermal maturity data in 4 wells are consistent with the maturity curves predicted by the rifting heat flow history associated with the tectonic regime of this basin. The maximum heat flows during the rift event of the Jurassic and earliest Cretaceous possibly ranged from 60-70 mW/m2 along the sub-basins and 70-80 mW/m2 on the southern and central Exmouth Plateau. This study also carried out two case studies of thermal maturity and thermal modelling within the deep overpressured system in the Barrow and Bambra wells of the Barrow Sub-basin. These case studies were aimed at understanding whether overpressure has a determinable influence on thermal maturation in this region. It was found that there is no evidence for overpressure-related retardation of thermal maturity in the deep overpressured system, based on the measured maturity, biomarker maturity parameters and 1D thermal modelling. Therefore, based on the data analysed, overpressure is an insignificant factor in thermal maturity and h hydrocarbon generation in this basin. / Three seismic lines in the Exmouth, Barrow and Dampier Sub-basins were selected and converted to depth cross-sections, and then 2D geological models were created for overpressure evolution modelling. A major object of these 2D geological models was to define the critical faults. A top pressure seal was also detected based on the 2D model of the Barrow Sub-basin. Two-dimensional overpressure modelling was performed using the BasinMod 2D software. The mathematical 2D model takes into consideration compaction, fluid thermal expansion, pressure produced by hydrocarbon generation and quartz cementation. The sealed overpressured conditions can be modelled with fault sealing, bottom pressure seal (permeabilities of 10-23 to 10-25 M2 ) and top pressure seal (permeabilities of 10-19 to 10-22 m2). The modelling supports the development of a top pressure seal with quartz cementation. The 2D modelling suggests the rapid sedimentation rates can cause compaction disequilibrium in the fine-grained rocks, which may be a mechanism for overpressure generation during the Jurassic to the Early Cretaceous. The data suggest that the present-day deep overpressure is not associated with the porosity anomaly due to compaction disequilibrium and that compaction may be much less important than recurrent pressure charges because most of the porosity in the Jurassic source rocks has been lost through compaction and deposition rates have been very slow since the beginning of the Cainozoic. / Three simple 1D models were developed and applied to estimate how rapidly the overpressure dissipates. The results suggest that the present day overpressure would be almost dissipated after 2 million years with a pressure seal with an average permeability of 10-22 M2 (10-7 md). On the basis of numerous accumulations of oil and gas to be expelled from the overpressured Jurassic source rocks in the basin and the pressure seal modelling, it seems that the top pressure seal with permeabilities of 10-19 to 10-22 M2 (10-4 to 10-7 md) is not enough to retain the deep overpressure for tens of millions of years without pressure recharging. Only if the permeabilities were 10-23 m2 (10-8 md) or less, would a long-lived overpressured system be preserved. This study suggests that hydrocarbon generation, especially gas generation and thermal expansion, within sealed conditions of low-permeability is a likely major cause for maintaining the deep overpressure over the past tens of millions of years. Keywords: Thermal history; Deep overpressure; Type III kerogen; Rock-Eval Tmax; Thermal maturity; Palaeoheatflow modelling; Pressure seal; 2D deep overpressure modelling; Pressure behaviour modelling; Overpressure generation; Northern Carnarvon Basin.

The main objective of this dissertation is to quantify petrophysical properties of conventional and unconventional reservoirs using a mechanistic approach. Unconventional transport mechanisms are described from the pore to the reservoir scale to examine their effects on macroscopic petrophysical properties in hydrocarbon-bearing organic shale. Petrophysical properties at the pore level are quantified with a new finite-difference method. A geometrical approximation is invoked to describe the interstitial space of grid-based images of porous media. Subsequently, a generalized Laplace equation is derived and solved numerically to calculate fluid pressure and velocity distributions in the interstitial space. The resulting macroscopic permeability values are within 6% of results obtained with the Lattice-Boltzmann method after performing grid refinements. The finite-difference method is on average six times faster than the Lattice-Boltzmann method. In the next step, slip flow and Knudsen diffusion are added to the pore-scale method to take into account unconventional flow mechanisms in hydrocarbon-bearing shale. The effect of these mechanisms is appraised with a pore-scale image of Eagle Ford shale as well as with several grain packs. It is shown that neglecting slip flow in samples with pore-throat sizes in the nanometer range could result in errors as high as 2000% when estimating permeability in unconventional reservoirs. A new fluid percolation model is proposed for hydrocarbon-bearing shale. Electrical conductivity is quantified in the presence of kerogen, clay, hydrocarbon, water, and the Stern-diffuse layer in grain packs as well as in the Eagle Ford shale pore-scale image. The pore-scale model enables a critical study of the [delta]LogR evaluation method commonly used with gas-bearing shale to assess kerogen concentration. A parallel conductor model is introduced based on Archie's equation for water conductivity in pores and a parallel conductive path for the Stern-diffuse layer. Additionally, a non-destructive core analysis method is proposed for estimating input parameters of the parallel conductor model in shale formations. A modified reservoir model of single-phase, compressible fluid is also developed to take into account the following unconventional transport mechanisms: (a) slip flow and Knudsen diffusion enhancement in apparent permeability, (b) Langmuir desorption as a source of gas generation at kerogen surfaces, and (c) the diffusion mechanism in kerogen as a gas supply to adsorbed layers. The model includes an iterative verification method of surface mass balance to ensure real-time desorption-adsorption equilibrium with gas production. Gas desorption from kerogen surfaces and gas diffusion in kerogen are the main mechanisms responsible for higher-than-expected production velocities commonly observed in shale-gas reservoirs. Slip flow and Knudsen diffusion marginally enhance production rates by increasing permeability during production. / text