Orientador: Denis Jose Schiozer / Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica e Instituto de Geociencias / Made available in DSpace on 2018-08-04T17:38:31Z (GMT). No. of bitstreams: 1 Magalhaes_TassoCordeiroBenevidesde_M.pdf: 3378169 bytes, checksum: 1fce57c554e09b19fe2b8796625d7f8b (MD5) Previous issue date: 2005 / Resumo: Estratégias de produção para campos petrolíferos são escolhidas com o objetivo de obter o melhor desempenho possível dos reservatórios, considerando restrições físicas, operacionais e econômicas. Em vários trabalhos publicados sobre otimização das estratégias de produção considera-se apenas o reservatório, simplificando o processo de definição por não considerar as restrições operacionais das facilidades de produção. Entretanto, as restrições da unidade de processamento e dos equipamentos necessários para o escoamento do petróleo, não só influenciam a produtividade do reservatório e o retorno financeiro do empreendimento, como também podem causar impacto significativo na definição da estratégia de drenagem, influenciando a quantidade e localização de poços produtores e injetores e no gerenciamento das condições de operação. No presente trabalho, duas restrições operacionais são analisadas: a limitação da capacidade de tratamento de líquidos da unidade de produção e a quantidade gás no sistema de elevação, gas-lift. Foram otimizadas estratégias de produção com e sem tais restrições para alguns casos e várias diferenças puderam ser observadas nos valores de indicadores técnicos e financeiros, como valor presente líquido, produção e injeção de fluidos e a quantidade e posicionamento de poços produtores e injetores. Foi possível demonstrar a influência das restrições operacionais e que se as mesmas não forem incluídas no processo de otimização antes da definição da quantidade e posição dos poços, o desempenho do campo pode ser prejudicado / Abstract: Production strategies for petroleum fields are chosen with the objective of achieving the best possible performance of the reservoir, considering physical, operational and economical constraints. In many published papers regarding production strategy optimization, only the reservoir is considered, simplifying the analysis process by not considering the operational constraints of production facilities. However, the restrictions of a production unit and the necessary equipments to guarantee the flow of petroleum not only have influence on the reservoir production and on the enterprise profits, but can also cause significant impact on the definition of the drainage strategy, influencing the number and location of producer and injector wells and the operational conditions management. In this work, two operational constraints are analyzed: the limitation of the capacity for liquid treatment and the amount of available gas for gas-lift operation. Production strategies were optimized with and without these restrictions for some case-studies and many differences were noted in the value of technical and financial indicators, such as the net present value, the production and injection of fluids and the number and location of producer and injector wells. It was possible to demonstrate the influence of operational constraints and how their exclusion from the optimization process, before definition of the number and location of wells, can lead to a wrong assessment of the field performance / Mestrado / Reservatórios e Gestão / Mestre em Ciências e Engenharia de Petróleo

This study analyses the impact of oil-related developments on output, incomes and employment in Shetland. An Input-Output approach is adopted based on a Shetland transactions table constructed by the author. Using this, the pre-oil Shetland economy is analysed as base for assessing oil impact. Three major oil activities are identified and their local effects estimated: Supply Bases, the Sullom Voe Tanker Terminal, and Oil-related Construction. Estimates of the impact of these on local activity are given in aggregate and on an individual industry basis. Appropriate oil sector 'multipliers' are derived. Attempts are made to modify the basic estimates by allowing for 'negative multiplier' effects, induced investment and other elements of impact excluded in the basic model. Finally, the possibility of oil-induced changes in local technology is considered and its implications for the preceding impact estimates discussed. In the conclusions the results of the previous analysis are drawn together and some policy implications suggested by them are considered briefly.

[pt] Em diversas etapas da cadeia de trabalho da Indústria de Óleo e Gás a atividade de Engenharia de Petróleo demanda processos que envolvem otimização. Mais especificamente, no gerenciamento de reservatórios, as metodologias para a tomada de decisão pelo uso de poços inteligentes envolvem processos de otimização. Nestes processos, normalmente, visa-se maximizar o VPL (Valor Presente Líquido), que é calculado através das curvas de produção de óleo, gás e água fornecidas por um simulador de reservatório. Estas simulações demandam alto custo computacional, muitas vezes inviabilizando processos de otimização. Neste trabalho, empregam-se técnicas de inteligência computacional - modelos de redes neurais artificiais e neuro-fuzzy - para a construção de aproximadores de função para simulador de reservatórios com o objetivo de diminuir o custo computacional de um sistema de apoio à decisão para utilização ou não de poços inteligentes em reservatórios petrolíferos. Para reduzir o número de amostras necessárias para a construção dos modelos, utiliza-se também Projeto de Experimentos Fatoriais Fracionado. Os aproximadores de função foram testados em dois reservatórios petrolíferos: um reservatório sintético, muito sensível às mudanças no controle de poços inteligentes e outro com características reais. Os resultados encontrados indicam que estes aproximadores de reservatório conseguem bom desempenho na substituição do simulador no processo de otimização - devido aos baixos erros encontrados e à substancial diminuição do custo computacional. Além disto, os testes demonstraram que a substituição total do simulador pelo aproximador se revelou uma interessante estratégia para utilização do sistema de otimização, fornecendo ao especialista uma rápida ferramenta de apoio à decisão. / [en] In many stages of the work chain of Oil & Gas Industry, activities of petroleum engineering demand processes that involve optimization. More specifically, in the reservoirs management, the methodologies for decision making by using intelligent wells involve optimization processes. In those processes, usually, the goal is to maximize the NVP (Net Present Value), which is calculated through the curves of oil, gas and water production, supplied by a reservoir simulator. Such simulations require high computational costs, therefore in many cases the optimization processes become unfeasible. Techniques of computational intelligence are applied in this study - artificial neural networks and neuro-fuzzy models - for building proxies for reservoirs simulators aiming at to reduce the computational cost in a decision support system for using, or not, intelligent wells within oil reservoirs. In order to reduce the number of samples needed for build the models, it was used the Fractional Factorial Design of Experiments. The proxies have been tested in two oil reservoirs: a synthetic one, very sensitive to changes in the control of intelligent wells and another one with real characteristics. The replacement of the simulator by the reservoir proxy, in an optimization process, indicates a good result in terms of performance - low errors and significantly reduced computational costs. Moreover, tests demonstrate that the total replacement of the simulator by the proxy, turned out to be an interesting strategy for using the optimization system, which provides to the users a very fast tool for decision support.

Thesis (M.C.P.)--Massachusetts Institute of Technology, Dept. of Urban Studies and Planning, 1982. / MICROFICHE COPY AVAILABLE IN ARCHIVES AND ROTCH / Bibliography: leaves 75-76. / by Oscar Salazar Rodriguez. / M.C.P.

No description available.

This work addresses the poroelastic effect on the processes involved in hydraulic fracturing and post-fracture production using a finite element based fully coupled poroelastic model which includes a triple system of wellbore-fracture-reservoir. A novel numerical procedure for modeling hydraulic fracture propagation in a poroelastic medium is introduced. The model directly takes into account the interaction of wellbore, hydraulic fracture and reservoir in a fully coupled manner. This allows realistic simulation of near fracture phenomena such as back stress and leak-off. In addition, fluid leak-off is numerically modeled based on the concept of fluid flow in porous media using a new technique for evaluating local pressure gradient. Besides, the model is capable of accommodating the zone of reduced pressure (including intermediate and fluid lag zones) at the fracture front so as to capture the behavior of fracture tip region more realistically. A fully coupled poroelastic model for gas reservoirs has been also developed using an innovative numerical technique. From the results of this study it has been found that fracture propagation pressure is higher in poroelastic media compared to that of elastic media. Also high formation permeability (in the direction normal to the hydraulic fracture) and large difference between minimum horizontal stress (in case of it being the smallest principal stress) and reservoir pressure reduce the rate of fracture growth. Besides, high pumping rate is more beneficial in elongating a hydraulic fracture whereas high viscous fracturing fluid is advantageous in widening a hydraulic fracture. It has been also shown that rock deformation, permeability anisotropy and modulus of elasticity can have a significant effect on fluid flow in a hydraulically fractured reservoir. Furthermore, it has been shown that long stress reversal time window and large size of stress reversal region can be caused by high initial pressure differential (i.e. the difference between flowing bottomhole pressure and reservoir pressure), low initial differential stress (i.e. the difference between maximum and minimum horizontal stresses) and low formation permeability in tight gas reservoirs. By taking advantage of production induced change in stress state of a reservoir, this study has also shown that a refracture treatment, if carried out in an optimal time window, can lead to higher economic gain. Besides, analysis of stress reversal region has depicted that a small region with high stress concentration in the vicinity of the wellbore could impede refracture from initiating at the desired place. Moreover, re-pressurization of the wellbore can result in further propagation of the initial fracture before initiation or during propagation of the secondary fracture.

"September 2002" / Includes bibliographical references (leaves 200-209) / xi, 209, [51] leaves : ill. (chiefly col.), maps, plates (chiefly col.) ; 30 cm. / Title page, contents and abstract only. The complete thesis in print form is available from the University Library. / Outlines an evaluation procedure for stratigraphic trap exploration by employing sequence stratigraphy, 3D seismic data visualisation and quantitative risk analysis with case studies in an actual exploration basin. / Thesis (Ph.D.)--University of Adelaide, National Centre for Petroleum Geology and Geophysics, 2002

<p>Since the 1950s, oil has been the dominant source of energy in the world. The cheap supply of oil has been the engine for economic growth in the western world. Since future oil demand is expected to increase, the question to what extent future production will be available is important. </p><p>The belief in a soon peak production of oil is fueled by increasing oil prices. However, the reliability of the oil price as a single parameter can be questioned, as earlier times of high prices have occurred without having anything to do with a lack of oil. Instead, giant oil fields, the largest oil fields in the world, can be used as a parameter.</p><p>A giant oil field contains at least 500 million barrels of recoverable oil. Only 507, or 1 % of the total number of fields, are giants. Their contribution is striking: over 60 % of the 2005 production and about 65 % of the global ultimate recoverable reserve (URR). </p><p>However, giant fields are something of the past since a majority of the largest giant fields are over 50 years old and the discovery trend of less giant fields with smaller volumes is clear. A large number of the largest giant fields are found in the countries surrounding the Persian Gulf. </p><p>The domination of giant fields in global oil production confirms a concept where they govern future production. A model, based on past annual production and URR, has been developed to forecast future production from giant fields. The results, in combination with forecasts on new field developments, heavy oil and oil sand, are used to predict future oil production.</p><p>In all scenarios, peak oil occurs at about the same time as the giant fields peak. The worst-case scenario sees a peak in 2008 and the best-case scenario, following a 1.4 % demand growth, peaks in 2018.</p>

Thesis (M.A.)--University of Montana, 2006. / Mode of access: Internet. Title from title screen. Description based on contents viewed Feb. 8, 2007. Includes bibliographical references (p. 50-52).

Since the 1950s, oil has been the dominant source of energy in the world. The cheap supply of oil has been the engine for economic growth in the western world. Since future oil demand is expected to increase, the question to what extent future production will be available is important. The belief in a soon peak production of oil is fueled by increasing oil prices. However, the reliability of the oil price as a single parameter can be questioned, as earlier times of high prices have occurred without having anything to do with a lack of oil. Instead, giant oil fields, the largest oil fields in the world, can be used as a parameter. A giant oil field contains at least 500 million barrels of recoverable oil. Only 507, or 1 % of the total number of fields, are giants. Their contribution is striking: over 60 % of the 2005 production and about 65 % of the global ultimate recoverable reserve (URR). However, giant fields are something of the past since a majority of the largest giant fields are over 50 years old and the discovery trend of less giant fields with smaller volumes is clear. A large number of the largest giant fields are found in the countries surrounding the Persian Gulf. The domination of giant fields in global oil production confirms a concept where they govern future production. A model, based on past annual production and URR, has been developed to forecast future production from giant fields. The results, in combination with forecasts on new field developments, heavy oil and oil sand, are used to predict future oil production. In all scenarios, peak oil occurs at about the same time as the giant fields peak. The worst-case scenario sees a peak in 2008 and the best-case scenario, following a 1.4 % demand growth, peaks in 2018.