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Current methods of production forecasting such as decline curve analysis (DCA) or numerical simulation require years of historical production data, and their accuracy is limited by the choice of model parameters. Unconventional resources have proven challenging to apply traditional methods of production forecasting because they lack long production histories and have extremely variable model parameters. This research proposes a data-driven alternative to reservoir simulation and production forecasting techniques. We create a proxy-well model for predicting cumulative oil production by selecting statistically significant well completion parameters and reservoir information as independent predictor variables in regression-based models. Then, principal component analysis (PCA) is applied to extract key features of a well’s time-rate production profile and is used to estimate cumulative oil production. The efficacy of models is examined on field data of over 400 wells in the Eagle Ford Shale in South Texas, supplied from an industry database. The results of this study can be used to help oil and gas companies determine the estimated ultimate recovery (EUR) of a well and in turn inform financial and operational decisions based on available production and well completion data.

<p>Cutting greenhouse gas emissions to as close to zero as possible, or ”net-zero”, may be the biggest sustainability goal to be achieved in the next 30 years. While chemical engineering evolved against the backdrop of an abundant supply of fossil resources for chemical production and energy, renewable energy resources such as solar and wind will find more usage in the future. This thesis work develops new concepts, methods and algorithms to identify and synthesize process schemes to address multiple aspects towards sustainable chemical and energy systems. Shale gas can serve as both energy resource and chemical feedstock for the transition period towards a sustainable economy, and has the potential to be a carbon source for the long term. The past two decades have seen increasing natural gas flaring and venting due to the lack of transforming or transportation infrastructure in emerging shale gas producing regions. To reduce carbon emission and wastage of shale resources, an innovative process hierarchy is identified for the valorization of natural gas liquids from shale gas at medium to small scale near the wellhead. This paradigm shift fundamentally changes the sequencing of various separation and reaction steps and results in dramatically simplified and intensified process flowsheets. The resulting processes could achieve over 20% lower capital with a higher recovery of products. Historically, heat energy is supplied to chemical plants by burning fossil resources. However, in future, with the emphasis on greenhouse gas reduction, renewable energy resources will find more usage. Renewable electricity from photovoltaic and wind has now become competitive with the electricity from fossil resources. Therefore, a major challenge for chemical engineering processes is how to use renewable electricity efficiently within a chemical plant and eliminate any carbon dioxide release from chemical plants. We introduce several decarbonization flowsheets for the process to first convert natural gas liquids (NGLs) to  mainly ethylene in an energy intensive dehydrogenation reactor and subsequent conversion of ethylene into value-added and easy-to-transport liquid fuels. </p> <p><br></p> <p>Molecular separations are needed across many types of industries, including oil and gas, food, pharmaceutical, and chemical industries. In a chemical plant, 40%–60% of energy and capital cost is tied to separation processes. For widespread use of membrane-based processes for high recovery and purity products from gaseous and liquid mixtures on an industrial scale, availability of models that allow the use of membrane cascades at their optimal operating modes is desirable towards sustainable separation systems. This will also enable proper comparison of membrane performance vis-a-vis other competing separation technologies. However, such a model for multicomponent fluid separation has been missing from the literature. We have developed an MINLP global optimization algorithm that guarantees the identification of minimum power consumption of multicomponent membrane cascades. The proposed optimization algorithm is implemented in GAMS and is demonstrated to have the capability to solve up to 4-component and 5-stage membrane cascades via BARON solver, which is significantly more advantageous than the state-of-the-art processes. The model is currently being further developed to include optimization of total cost including capital. Such a model holds the promise to be useful for the development in implementation of energy-efficient separation plants with least carbon footprint. This thesis work also addresses important topics in separation including dividing wall columns and water desalination. </p>

The Thesis aims to analyze the possible shale gas development in the EU in context with raising problem of energy security. Based on the experience of shale revolution in the USA and econometric modelling using the method of Ordinary Least Squares with Fixed Effects to test the dependence of price on shale gas production, the transfer of US model to the EU is discussed. The results show that shale production affects the price negatively and that US model is successful due to multiple reasons, primarily presence of experienced companies, geological structure and strong regulation rules. The Thesis shows the unsuitability of the US model for the EU market. After the first enthusiasm for shale plays research in late 2000s the multiple barriers for drilling have risen up; the most significant are the environmental worries; both on governmental and public levels. US companies have lost interest in the EU and moved to other parts of the world. The shale gas development is not able to affect the energy security of the EU on European, international level.

não-convencionais de metano biogênico em folhelhos podem representar importante recurso energético e contribuir significativamente para emissões de gases do efeito estufa. Com o intuito de avançar na compreensão dos controles na geração de metano (CH4) e dióxido de carbono (CO2) em folhelhos ricos em matéria orgânica, o presente estudo avaliou o potencial de geração e a estrutura de poros de folhelhos das bacias sedimentares do Paraná e Taubaté, localizadas na região sudeste do Brasil. As formações Ponta Grossa (Devoniano, Bacia do Paraná), Irati (Permiano, Bacia do Paraná) e Tremembé (Paleógeno, Bacia de Taubaté) foram analisadas de modo a obter-se taxas de produção biogênica de CH4 e CO2 sob diferentes condições. Para tanto, foram efetuadas incubações de 24 amostras de folhelho em laboratório, sob meios seco, aquoso e com adição de ácido ácetico, durante períodos de até 1 ano. Também foram realizadas análises para a determinação do teor de carbono orgânico e testes de adsorção para caracterização de poros e superfície específica das amostras de folhelho com o intuito de compreender o papel destas variantes na geração de gases biogênicos. As taxas de produção de gás biogênico em amostras incubadas a seco atingiram valores de até 3,17 ml/t.d (CH4) e 2,45x10³ ml/t.d (CO2) durante os primeiros 30 dias. Amostras incubadas com adição de água demonstraram aumento de 54% na produção de CH4 e 151% na produção de CO2. A adição de ácido acético no sistema foi responsável pelo reínicio ou aumento da produção de CH4 e CO2 na maioria dos casos avaliados. A Formação Irati apresentou o maior potencial para produção de metano biogênico entre as unidades estratigráficas estudadas, fator que pode estar ligado à biodegradação de petróleo pesado presente nos poros. O volume total de poros e a superfície específica de amostras aparenta não afetar a produção biogênica. Entretanto, a umidade e disponibilidade de substrato exercem controle predominante no potencial de geração de CH4 e CO2 biogênicos em folhelhos ricos em matéria orgânica. / Unconventional biogenic shale gas systems may represent an important energy resource and significantly contribute to geological greenhouse gases emissions. In order to better understand the controls on biogenic methane (CH4) and carbon dioxide (CO2) generation in organic-rich shales, the present study evaluated the generation potential and the pore structure of shales from Taubaté and Paraná basins, located in southeastern Brazil. The Ponta Grossa (Devonian, Paraná basin), Irati (Permian, Paraná basin) and Tremembé Formations were analyzed in order to quantify production rates of biogenic CH4 and CO2 under distinct experimental conditions. Twenty four shale samples were used for batch incubations under dry, wet and acetic acid solution conditions during time periods reaching up to 1 year. The organic carbon content and nitrogen adsorption analysis for determining specific surface area and porosity were also performed to evaluate their role on biogenic gas generation.The biogenic gas production rates in samples under dry conditions reached up to 3.17 ml/t.d (CH4) and 2.45x10³ ml/t.d (CO2) during the first 30 days of incubation. Samples under wet conditions demonstrated production rates 54% higher for CH4 and 151% higher for CO2 in comparison with dry tests. Acetic acid addition restarted or increased CH4 and CO2 production in most cases. The Irati Formation showed the highest potential for biogenic methane production, which could be linked to the biodegradation of heavy liquid hydrocarbons occurring in this unit. Total pore volume and specific surface does not appear to significantly affect the biogenic production of CH4 and CO2. However, water content and substrate availability would exert predominant control over the biogenic gas generation within organic rich shales.

Dans de nombreuses régions du monde, d’immenses réserves gazéifères dites non conventionnelles sont piégées dans des roches faiblement perméables qui ne peuvent pas être exploitées par des méthodes de forage classiques. Bien que très controversée, la seule méthode d’exploitation de ces gisements repose actuellement sur la technique de fracturation hydraulique. Pour ces raisons, une collaboration de recherche a débuté en 2007 entre la société TOTAL et le Laboratoire de Génie Electrique de l’université de Pau (récemment devenu le laboratoire SIAME), visant à étudier l’opportunité d’utiliser la fracturation électrique comme solution alternative à la fracturation hydraulique. Cette méthode repose sur un procédé dynamique de fracturation de la roche par application d’une onde de pression créée suite à l’initiation d’un arc électrique dans un liquide. Ce travail, financé par TOTAL dans le cadre d’une bourse CIFRE, s’inscrit dans la continuité de travaux déjà engagés sur cette thématique et vise particulièrement à approfondir les connaissances concernant le cœur du procédé de fracturation : la décharge électrique dans l’eau et la caractérisation de l’onde de pression résultante. Dans cette optique, l’importance du circuit et des paramètres électriques de l’arc a été démontrée en termes d’injection de courant et de transfert de puissance. Une formule empirique permettant de prévoir la valeur de la pression dynamique a, par conséquent, été établie. Afin d’optimiser le rendement électro-acoustique, une étude spécifique a été menée sur l’effet du mode de rupture diélectrique du fluide. Ces travaux ont également permis de proposer des solutions concernant le contrôle de la dynamique de l’onde de pression. Enfin, les effets des propriétés thermodynamiques du fluide sur sa rigidité diélectrique, sur la consommation d’énergie, ainsi que sur la propagation de l’onde de pression ont été analysés afin d’établir une série de conclusions permettant d’optimiser le procédé. / Numerous parts of the world contain huge unconventional gas reserves which are located in low permeability rocks, and consequently, cannot be produced by classical drilling techniques. Besides its numerous detractors, the only currently available method to exploit these reservoirs relies on hydraulic fracturing. For these reasons, a research collaboration was started in 2007 between the Total Company and the Electrical Engineering Laboratory of Pau university (recently renamed SIAME Laboratory). The main goal was to study the potential concerning the use of the electrical fracturing technique as an alternative to hydraulic fracturing. This method is based on a dynamic rock fracturing process through the applying of a pressure wave enhanced by the generation of an electrical arc into a liquid. This work, which is financed by TOTAL through a CIFRE funding, follows the track initiated on this topic and mainly intends to improve the knowledge concerning the critical part of the fracturing process: the electrical discharge in water and the resulting pressure wave characterization. In this purpose, the importance of the circuit and of the arc electrical parameters was demonstrated in terms of current injection and power transfer. An empirical formula used to predict the dynamic pressure value has consequently been established. In order to optimize the electro acoustic efficiency, a specific study was performed on the liquid dielectric breakdown modus. This work allowed us to suggest new solutions concerning the dynamic pressure wave control. Finally, the fluid thermodynamic properties effects on its dielectric strength, on the energy consumption, and on the pressure wave propagation were analyzed in order to draw conclusions for the process optimization.

Multistage hydraulic fracturing of horizontal wells continues to be a major technological tool in the oil and gas industry. Creation of multiple transverse fractures in shale gas has enabled production from very low permeability. The strategy entails the development of a Stimulated Reservoir Volume (SRV), defined as the volume of reservoir, which is effectively stimulated to increase the well performance. An ideal model for a shale gas SRV is a rectangle of length equal to horizontal well length and width equal to twice the half length of the created hydraulic fractures. This project focused on using the Multistage Transverse Fractured Horizontal Wells (MTFHW) for two novel applications. The first application considers using the SRV of a shale gas well, after the gas production rate drops below the economic limit, for low grade geothermal heat extraction. Cold water is pumped into the fracture network through one horizontal well drilled at the fracture tips. Heat is transferred to the water through the fracture surface. The hot water is then recovered through a second horizontal well drilled at the other end of the fracture network. The basis of this concept is to use the already created stimulated reservoir volume for heat transfer purposes. This technique was applied to the SRV of Haynesville Shale and the results were discussed in light of the economics of the project. For the second application, we considered the use of a similarly created SRV for producing hydrocarbon products from oil shale. Thermal decomposition of kerogen to oil and gas requires heating the oil shale to 700 degrees F. High quality saturated steam generated using a small scale nuclear plant was used for heating the formation to the necessary temperature. Analytical and numerical models are developed for modeling heat transfer in a single fracture unit of MTFHW. These models suggest that successful reuse of Haynesville Shale gas production wells for low grade geothermal heat extraction and the project appears feasible both technically and economically. The economics of the project is greatly aided by eliminating well drilling and completion costs. The models also demonstrate the success of using MTFHW array for heating oil shale using SMR technology.

Modern reservoir management typically involves simulations of geological models to predict future recovery estimates, providing the economic assessment of different field development strategies. Integrating reservoir data is a vital step in developing reliable reservoir performance models. Currently, most effective strategies for traditional manual history matching commonly follow a structured approach with a sequence of adjustments from global to regional parameters, followed by local changes in model properties. In contrast, many of the recent automatic history matching methods utilize parameter sensitivities or gradients to directly update the fine-scale reservoir properties, often ignoring geological inconsistency. Therefore, there is need for combining elements of all of these scales in a seamless manner. We present a hierarchical streamline-assisted history matching, with a framework of global-local updates. A probabilistic approach, consisting of design of experiments, response surface methodology and the genetic algorithm, is used to understand the uncertainty in the large-scale static and dynamic parameters. This global update step is followed by a streamline-based model calibration for high resolution reservoir heterogeneity. This local update step assimilates dynamic production data. We apply the genetic global calibration to unconventional shale gas reservoir specifically we include stimulated reservoir volume as a constraint term in the data integration to improve history matching and reduce prediction uncertainty. We introduce a novel approach for efficiently computing well drainage volumes for shale gas wells with multistage fractures and fracture clusters, and we will filter stochastic shale gas reservoir models by comparing the computed drainage volume with the measured SRV within specified confidence limits. Finally, we demonstrate the value of integrating downhole temperature measurements as coarse-scale constraint during streamline-based history matching of dynamic production data. We first derive coarse-scale permeability trends in the reservoir from temperature data. The coarse information are then downscaled into fine scale permeability by sequential Gaussian simulation with block kriging, and updated by local-scale streamline-based history matching. he power and utility of our approaches have been demonstrated using both synthetic and field examples.

Various models featuring horizontal wells with multiple induced fractures have been proposed to characterize flow behavior over time in tight gas and shale gas systems. Currently, there is little consensus regarding the effects of non-ideal fracture geometries and coupled primary-secondary fracture interactions on reservoir performance in these unconventional gas reservoirs. This thesis provides a grid construction tool to generate high-resolution unstructured meshes using Voronoi grids, which provides the flexibility required to accurately represent complex geologic domains and fractures in three dimensions. Using these Voronoi grids, the interaction between propped hydraulic fractures and secondary "stress-release" fractures were evaluated. Additionally, various primary fracture configurations were examined, where the fractures may be non-planar or non-orthogonal. For this study, a numerical model was developed to assess the potential performance of tight gas and shale gas reservoirs. These simulations utilized up to a half-million grid-blocks and consider a period of up to 3,000 years in some cases. The aim is to provide very high-definition reference numerical solutions that will exhibit virtually all flow regimes we can expect in these unconventional gas reservoirs. The simulation results are analyzed to identify production signatures and flow regimes using diagnostic plots, and these interpretations are confirmed using pressure maps where useful. The coupled primary-secondary fracture systems with the largest fracture surface areas are shown to give the highest production in the traditional "linear flow" regime (which occurs for very high conductivity vertical fracture cases). The non-ideal hydraulic fracture geometries are shown to yield progressively lower production as the angularity of these fractures increases. Hence, to design optimum fracture completions, we should endeavor to keep the fractures as orthogonal to the horizontal well as possible. This work expands the current understanding of flow behavior in fractured tight-gas and shale-gas systems and may be used to optimize fracture and completion design, to validate analytical models and to facilitate more accurate reserves estimation.

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