Most available data from shale production zones tends to point towards the presence of complex hydraulic fracture networks, especially in the Barnett and Marcellus formations. Representing these complex hydraulic fracture networks in reservoir simulators while incorporating the geo-mechanical parameters and fracture apertures is a challenge. In our work we developed a fracture to production simulation workflow using complex hydraulic fracture propagation model and a commercial reservoir simulator. The workflow was applied and validated using geological, stimulation and production data from the Marcellus shale. For validation, we used published data from a 5200 ft. long horizontal well drilled in the lower Marcellus. There were 14 fracturing stages with micro-seismic data and an available production history of 9 months. Complex hydraulic fractures simulations provided the fracture network geometry and aperture distributions as the output, which were up-scaled to grid block porosity and permeability values and imported into a reservoir model for production simulation and history match. The approach of using large grid blocks with conductivity adjustment to represent hydraulic fractures in a reservoir simulator which has been employed in this workflow was validated by comparing with published numerical and analytical solutions. Our results for history match were found to be in reasonable agreement with published results. The incorporation of apertures, complexity and geo-mechanics into reservoir models through this workflow reduces uncertainty in reservoir simulation of shale plays and leads to more realistic production forecasting. The workflow was utilized to study the effect of fracture conductivity damage on production. Homogenous and heterogeneous damage cases were considered. Capillary pressures, determined using empirical relationships and experimental data, were studied using the fracture to production workflow. Assuming homogenous instead of heterogeneous permeability damage in reservoir simulations was shown to have a significant impact on production forecasting, overestimating production by 70% or more over the course of two years. Capillary pressure however was less significant and ignoring capillary pressure in damaged hydraulic fractures led to only 3% difference in production in even the most damaged cases. / text

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Orientador: Denis José Schiozer / Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências / Made available in DSpace on 2018-08-16T03:09:54Z (GMT). No. of bitstreams: 1 Bento_DeboraFerreira_M.pdf: 5080634 bytes, checksum: fb4f6d1d73f4079215e05919e962ccb6 (MD5) Previous issue date: 2010 / Resumo: O sucesso de um projeto de desenvolvimento de um campo de petróleo depende de uma estratégia de produção adequada. A seleção da estratégia através de um processo de otimização busca menores investimentos e custos operacionais e maiores produções de óleo e gás, melhorando o lucro medido através do valor presente líquido do projeto (VPL). Existem inúmeras metodologias para otimização da estratégia de produção que, em geral, são trabalhosas e demandam grande esforço computacional. Como o tempo é uma variável impactante no retorno econômico de projetos, a indústria tende a simplificar as simulações numéricas, principalmente separando as modelagens dos reservatórios e dos sistemas operacionais. Este trabalho tem como objetivo verificar se estas simplificações influenciam no resultado final do processo de seleção de estratégias de produção. Complementando trabalhos anteriores, foram selecionadas e estudadas duas restrições operacionais: perda de carga nas linhas de produção e o limite de escoamento do gás. Foi proposta ainda uma metodologia de otimização de estratégia de produção e de análise da influência da restrição operacional, com foco nos casos estudados. Os resultados mostram a influência das restrições no processo, possibilitando ainda identificar as características dos reservatórios, fluídos e cenário econômico onde essa influência é mais significativa / Abstract: The success of a development project of a petroleum field depends on adequate production strategy. The selection of the strategy through an optimization process searches for minors investments and operational costs and greater oil and gas productions, improving the profit measured through the liquid present value of the project (LPV). There are innumerable methodologies for production strategy optimization and, in general, they are laborious and demand a great computational effort. Considering that time is an important variable in the project economic return, the industry tends to simplify the numerical simulations, mainly separating the reservoir and operational systems. The objective of this work is to verify if these simplifications have significant influence on the final result of the production strategy selection process. Complementing previous works, two operational constraints were selected and studied: pressure drop in the production lines and the gas flow limit. Two methodologies were proposed, with focus in the studied cases: a production strategy optimization process and an operational constraints influence analysis. The results demonstrate the influence of the operational constraints restrictions in the process, making it possible to identify the characteristics of the reservoirs, fluids and economic scenario where this influence is more significant / Mestrado / Reservatórios e Gestão / Mestre em Ciências e Engenharia de Petróleo

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A variety of oil recovery improvement techniques has been developed and applied to the productive life of an oil reservoir. Reservoir simulators have a definitely established role in helping to identify the opportunity and select the most suitable techniques to optimum improvement in reservoir productivity. This is significantly important for those reservoirs whose operating and development costs are relatively expensive, because numerical modeling helps simulate the increased oil productivity process and evaluates the performance without undertaking trials in field. Moreover, rapid development in modeling provides engineers diverse choices. Hence the need for complete and comprehensive case studies is increasing. This study will show the different characteristics of in-house (UTCOMP and GPAS) and commercial simulators and also can validate implementation and development of models in the future. The purpose of this thesis is to present a series of case studies with analytical solutions, in addition to a series of more complicated field cases studies with no exact solution, to verify and test the functionality and efficiency of various simulators. These case studies are performed with three reservoir simulators, including UTCOMP, GPAS, and CMG. UTCOMP and GPAS were both developed at the Center for Petroleum and Geosystem Engineering at The University of Texas at Austin and CMG is a commercial reservoir simulator developed by Computer Modelling Group Ltd. These simulators are first applied to twenty case studies with exact solutions. The simulation results are compared with exact solutions to examine the mathematical formulations and ensure the correctness of program coding. Then, ten more complicated field-scale case studies are performed. These case studies vary in difficulty and complexity, often featuring heterogeneity, larger number of components and wells, and very fine gridblocks. / text

Orientadores: Denis José Schiozer, Gabriel Alves da Costa Lima / Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências / Made available in DSpace on 2018-08-19T18:25:23Z (GMT). No. of bitstreams: 1 Carvalho_MarcosHenriquede_M.pdf: 3436602 bytes, checksum: 6fc653eb73d82869d8e3b2d81634b94d (MD5) Previous issue date: 2011 / Resumo: A simulação de reservatório é a base para as previsões de produção, dimensionamento de equipamentos de superfície e planejamento de atividades de produção. É uma ferramenta para elaborar a estratégia de produção que gera curvas de previsão de produção de petróleo. No entanto, mesmo sem considerar incertezas geológicas e econômicas, na prática, tal curva de produção pode apresentar baixa probabilidade de ser verificada, uma vez que a disponibilidade operacional dos sistemas físicos é uma variável incerta com valor abaixo de 100%. Então, o resultado final depende de: estratégia de produção, das incertezas presentes no modelo e da confiabilidade dos sistemas (equipamentos); este último item é o foco deste trabalho. O objetivo principal deste trabalho é verificar a importância e a influência de um estudo da análise da confiabilidade dos sistemas de produção integrada com a simulação do reservatório, a fim de verificar o impacto sobre a produção de petróleo e sobre o valor presente líquido. Sendo assim, além da opção no simulador disponível para incluir, de forma simplificada, as informações de confiabilidade dos sistemas, por meio de um índice de disponibilidade média constante, foi desenvolvido um algoritmo que trata o fechamento e restabelecimento dos sistemas de forma probabilística, a fim de a operação ser tratada em um cenário mais realista. A metodologia proposta é aplicada a um campo de petróleo com óleo leve e a um campo de petróleo com óleo pesado. Com os resultados, conclui-se que, quando as informações de confiabilidade são inseridas no simulador de forma dinâmica, a produção acumulada de óleo leve não apresenta uma diferença significativa quando comparada com o caso em que as informações de confiabilidade dos sistemas não são consideradas. Por outro lado, para o campo de óleo pesado, apesar de a média também não ter apresentado diferença significativa, observa-se uma alta variação na produção de óleo. Em ambos os campos ocorre um atraso na produção, afetando o fluxo de caixa, resultando em diferenças significativas no VPL / Abstract: The reservoir simulation is the basis for the forecasts of production, dimensioning of surface equipments and the planning of activities related to production. Therefore, a production strategy which generates oil and gas production curves over the operational lifetime. However, even without considering geological and economic uncertainties, in practice, this curve presents low probability of being verified, since the operational availability of the production systems is an uncertain variable with value below 100%. Then, the final result depends on: production strategy, uncertainties present in the model and the reliability of the systems (equipments), which is the focus of this paper. The main objective of this work is to verify the importance and influence of a study of the analysis of the reliability of the production systems integrated to the reservoir simulation, in order to verify the impact on the oil production and on the net present value. Thus, besides de option in the simulator available for including, in a simplified way, the information of reliability of the systems, through an index of availability constant, it was developed an algorithm that treats the shutting and restore of the systems in a probabilistic way, in order to them be treated in a more realistic operation scenario. The proposed methodology is applied to a light oil field and a heavy oil field. With the results, it is concluded that, when the reliability information are inserted in the simulator in a dynamic way, the cumulative production of light oil does not present a significant difference when compared to the case where the reliability information of the systems are not considered. On the other hand, the heavy oil Field, despite the mean also does not present a significant difference, it is noted a high variation in the production figures. However, for both fields occurs a delay in production, affecting the cash flow resulting in significant differences in NPV / Mestrado / Reservatórios e Gestão / Mestre em Ciências e Engenharia de Petróleo

Significant quantities of hydrocarbon are bypassed during conventional waterfloods. This is the direct result of fluid channeling through high permeability zones within the reservoir. Conformance control offers a mean of increasing vertical and areal sweep efficiency, thus decreasing the amount of hydrocarbon bypassed. This, in turn, results in increased hydrocarbon production, decreased water cut, and field life extension. This thesis focuses on the use of polymer microgels as a relatively novel conformance control agent. Polymer-microgel-enhanced waterflooding tackles fluid channeling by “plugging” high permeability channels, or thief zones, and diverting trailing flooding fluid to adjacent poorly swept areas of the reservoir. The first major objective of this thesis was to provide an extensive literature survey on polymer microgel technology, which can serve as the go-to reference on this topic. Colloidal Dispersion Gels (CDGs), Preformed Particle Gels (PPGs), temperature-sensitive polymer microgels (Bright Water), and pH-sensitive polymer microgels are all discussed in detail, and an attempt is made to highlight the potential mechanisms by which they plug thief zones and improve oil recovery. This thesis then outlines the results of simulating numerous polymer microgel floods, ranging from experimental cases to field cases. Specifically, Colloidal Dispersion Gels (CDGs) were chosen for the simulations undergone. All simulations were run using UTGEL, a newly developed in-house simulator designed exclusively for the simulation of polymer, gel, and microgel floods. The simulations performed provide insight on the polymer microgel flooding process, and also served as a means of validating UTGEL’s polymer microgel (CDG) models. The development of the UTGEL simulator was important as it enables the optimization of polymer microgel floods for maximized hydrocarbon recovery efficiency. The results of a simulation study, using a synthetic field case, are also outlined. This sensitivity study provides additional insight on optimal operational conditions for polymer microgel technology. More specifically, this study aimed to investigate the effectiveness of microgel flooding treatments in layered reservoirs of varying permeability contrasts, vertical-to-horizontal permeability ratios, and under a variety of different injection concentrations. / text

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Recently, there has been considerable interest in the study of coupled fluid flow – geomechanics simulation, integrated into reservoir engineering. One of the most challenging problems in the petroleum industry is the understanding and predicting of subsidence at the surface due to formation compaction at depth, the result of withdrawal of fluid from a reservoir. In some oil fields, the compacting reservoir can support oil and gas production. However, the effects of compaction and subsidence may be linked to expenditures of millions of dollars in remedial work. The phenomena can also cause excessive stress at the well casing and within the completion zone where collapse of structural integrity could lead to loss of production. In addition, surface subsidence can result in problems at the wellhead or with pipeline systems and platform foundations. Recorded practice reveals that although these problems can be observed and measured, the technical methods to do this involve time, expense, with consideration uncertainty in expected compaction and are often not carried out. Alternatively, prediction of compaction and subsidence can be done using numerical reservoir simulation to estimate the extent of damage and assess measurement procedures. With regard to reservoir simulation approaches, most of the previous research and investigations are based on deterministic coupled theory applied to continuum porous media. In this work, uncertainty of parameters in reservoir is also considered. This thesis firstly investigates and reviews fully coupled fluid flow – geomechanics modeling theory as applied to reservoir engineering and geomechanics research. A finite element method is applied for solving the governing fully coupled equations. Also simplified analytical solutions that present more efficient methods for estimating compaction and subsidence are reviewed. These equations are used in uncertainty and stochastic simulations. Secondly, porosity and permeability variations can occur as a result of compaction. The research will explore changes of porosity and permeability in stress sensitive reservoirs. Thirdly, the content of this thesis incorporates the effects of large structures on stress variability and the impact of large structural features on compaction. Finally, this thesis deals with affect of pore collapse on multiphase fluid and rock properties. A test case from Venezuelan field is considered in detail; investigating reservoir performance and resultant compaction and subsidence. The research concludes that the application of coupled fluid flow – geomechanics modeling is paramount in estimating compaction and subsidence in oil fields. The governing equations that represent behaviour of fluid flow and deformation of the rock have been taken into account as well as the link between increasing effective stress and permeability/porosity. From both theory and experiment, this thesis shows that the influence of effective stress on the change in permeability is larger than the effect of reduction in porosity. In addition, the stochastic approach used has the advantage of covering the impact of uncertainty when predicting subsidence and compaction. This thesis also demonstrates the influence of a large structure (i.e. a fault) on stress regimes. Mathematical models are derived for each fault model to estimate the perturbed stress. All models are based on Mohr–Coulomb’s failure criteria in a faulted area. The analysis of different stress regimes due to nearby faults shows that effective stress regimes vary significantly compared to a conventional model. Subsequently, the selection of fault models, fault friction, internal friction angle and Poisson’s ratio are most important to assess the influence of the discontinuity on the reservoir compaction and subsidence because it can cause a significant change in stress regimes. To deal with multiphase flow in compacting reservoirs, this thesis presents a new method to generate the relative permeability curves in a compacting reservoir. The principle for calculating the new values of irreducible water saturation (Swir) due to compaction is demonstrated in this research. Using coupled reservoir simulators, fluid production due to compaction is simulated more comprehensively. In the case example presented, water production is reduced by approximately 70% compared to conventional modeling which does not consider changes in relative permeability. This project can be extended by applying the theory and practical methodologies developed to other case studies, where compaction and stress sensitivity dominate the drive mechanism. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1374653 / Thesis (Ph.D.) - University of Adelaide, Australian School of Petroleum, 2007

In this work, two topics of reservoir simulations are discussed. The first topic is the two-phase compositional flow simulation in hydrocarbon reservoir. The major obstacle that impedes the applicability of the simulation code is the long run time of the simulation procedure, and thus speeding up the simulation code is necessary. Two means are demonstrated to address the problem: parallelism in physical space and the application of sparse grids in parameter space. The parallel code can gain satisfactory scalability, and the sparse grids can remove the bottleneck of flash calculations. Instead of carrying out the flash calculation in each time step of the simulation, a sparse grid approximation of all possible results of the flash calculation is generated before the simulation. Then the constructed surrogate model is evaluated to approximate the flash calculation results during the simulation. The second topic is the wormhole propagation simulation in carbonate reservoir. In this work, different from the traditional simulation technique relying on the Darcy framework, we propose a new framework called Darcy-Brinkman-Forchheimer framework to simulate wormhole propagation. Furthermore, to process the large quantity of cells in the simulation grid and shorten the long simulation time of the traditional serial code, standard domain-based parallelism is employed, using the Hypre multigrid library. In addition to that, a new technique called “experimenting field approach” to set coefficients in the model equations is introduced. In the 2D dissolution experiments, different configurations of wormholes and a series of properties simulated by both frameworks are compared. We conclude that the numerical results of the DBF framework are more like wormholes and more stable than the Darcy framework, which is a demonstration of the advantages of the DBF framework. The scalability of the parallel code is also evaluated, and good scalability can be achieved. Finally, a mixed finite element scheme is proposed for the wormhole simulation.