[pt] Reservatórios carbonáticos respondem por mais de 50 por cento da produção mundial de hidrocarbonetos. No Brasil, ganharam mais importância com o descobrimento do Pré-Sal, em 2006. A principal ferramenta de previsão e gerenciamento de reservatórios é a simulação numérica que, tradicionalmente, tem na compressibilidade do poro o único parâmetro geomecânico. Normalmente é adotado apenas um valor, mantido constante, deste parâmetro para todo o reservatório. Porém, a rocha-reservatório sofre deformações durante a explotação do campo, as quais induzem redução da porosidade e permeabilidade. Enquanto o primeiro efeito não é bem representado pela compressibilidade, o segundo não sofre qualquer alteração. Além disso, cada fácies tem um comportamento tensão versus deformação diferente. Por isso a importância de se fazer modelagens acopladas de fluxo e geomecânica em que cada tipo de rocha é representado individualmente. Visando essas análises integradas, mas sem aumento do custo computacional, utiliza-se o pseudoacoplamento, o que permite que esses modelos sejam usados de forma rotineira pelos engenheiros de reservatórios. Esse tipo de acoplamento atualiza a porosidade e a permeabilidade com base em tabelas que relacionam poropressão com multiplicadores de porosidade e permeabilidade. Visando uma boa representação do comportamento da rocha-reservatório, as tabelas de pseudoacoplamento são elaboradas com base em ensaios mecânicos laboratoriais realizados com amostras do próprio campo, representativas de cada fácies. São realizadas análises comparativas utilizando modelos homogêneos e heterogêneos, variando o tipo de representação da geomecânica, que pode ser através da compressibilidade ou do pseudoacoplamento. Conhecidos os efeitos geomecânicos da compactação, a etapa final desta metodologia consiste no estudo de um modelo que visa atenuá-los. / [en] Carbonate reservoirs are responsible for over 50 per cent of world hydrocarbon production. In Brazil, they started to gain more importance after the Pre-Salt discovery, in 2006. The main method to predict and manage reservoirs is numerical simulation in which, traditionally, the only geomechanical parameter is the rock compressibility. Usually it is adopted one single value for the whole model, which is kept constant. During exploitation, though, the reservoir-rock deforms, causing porosity and permeability reduction. While the first effect is not well predicted by rock compressibility, the second is simply kept constant. Besides that, each facies has its own stress-strain behavior. That is why it is so important to model the reservoir flow coupled to geomechanics representing each rock type in a single layer. With the aim of obtaining these integrated analyses, but without additional computational cost, the pseudo-coupling is used, which lets such models to be ran on day-by-day basis by reservoir engineers. This kind of coupling updates both porosity and permeability based on tables that correlate porepressure and porosity and permeability multipliers. In order to have the mechanical behavior of the reservoir-rock well represented, the pseudo-coupling tables are elaborated based on laboratory mechanical tests with samples from the same field to be modeled. In this way, each facies represented on the model has its own table that takes to reservoir simulation the geomechanical effects through porosity and permeability variation. Comparative analyses are done using homogeneous and heterogeneous models, varying the type of geomechanical representation, through rock compressibility or pseudo-coupling. Once known the compaction geomechanical effects, it is simulated a model that tries to attenuate them.

The injection of carbon dioxide (CO2) into saline formations for the purpose of limiting greenhouse gas emissions has been proposed as an alternative to the atmospheric venting of carbon dioxide. In the evaluation process for selecting a potential target saline formation for the disposal of carbon dioxide, flow characterisation of the disposed plume should be undertaken by reservoir simulation of the target formation. The movement of injected carbon dioxide in the saline formation is influenced by many factors including the physics of carbon dioxide at deep formation depths and pressure, physical interactions with formation rock and pore water and variations in the rock flow pathways through changes in formation heterogeneity. This thesis investigates the roles of physical interactions on the disposal of carbon dioxide and the ability to contain the injected gas through evaluation of trapping mechanisms such as dissolution of CO2 in formation water and residual gas trapping through the process of gas-water relative permeability hysteresis. Variable formation heterogeneity is evaluated for its impact on the migration of injected CO2 plume movement and the role of formation heterogeneity in impeding or accelerating the immobilisation of injected carbon dioxide. Multiple reservoir simulation studies were conducted to evaluate, initially, the role of different trapping mechanisms in immobilising the movement of injected carbon dioxide and subsequently, the role of variations in formation rock in the migration and trapping of and injected plume of carbon dioxide. The major simulation study shows that the selection process for identifying appropriate saline formations should not only consider their size and permeability but should also consider their degree of heterogeneity endemic to the formation. / A set of reservoir performance metrics were developed for the CO2 disposal projects. The metrics were applied to compare plume migration of injected CO2 (both vertically and laterally) and containment (through dissolution and residual phase trapping) in these studies. The findings demonstrate how formation heterogeneity has a significant impact on the subsurface behaviour of the carbon dioxide. Formation dip influences the rate of migration, with low formation dipping reservoirs having slower rates of vertical migration. Increasing the tortuousity of the migration flow path by either increasing the shale (non-reservoir) content or lengthening the shale baffles in the formation (corresponding to a gradual decrease in reservoir quality), can progressively inhibit the vertical flow of the plume whilst promoting its lateral flow. The increase in the tortuosity of the CO2 migration pathway delays the migration of CO2 and increases the residence time for the CO2 in the formation. Thus, formation heterogeneity impedes the onset of residual gas trapping through hysteresis effects. Ultimately less carbon dioxide is likely to collect under the seal in heterogeneous formations due to increased reservoir contact and long residence times, thereby reducing the risk of seepage to overlying formations. / Given sufficient permeability for economic injection of CO2, then low to mid net-to-gross heterogeneous saline formations with low formation dip and lengthy intra-bedded shales are desirable for selection for the geological disposal of CO2. Detailed reservoir characterisation of any potential geological disposal saline formations is required in order to accurately predict the range of outcomes in the long term flow characterisation of injected CO2 into those formations.

Uncertainty quantification involves sampling the reservoir parameters correctly from a posterior probability function that is conditioned to both static and dynamic data. Rigorous sampling methods like Markov Chain Monte Carlo (MCMC) are known to sample from the distribution but can be computationally prohibitive for high resolution reservoir models. Approximate sampling methods are more efficient but less rigorous for nonlinear inverse problems. There is a need for an efficient and rigorous approach to uncertainty quantification for the nonlinear inverse problems. First, we propose a two-stage MCMC approach using sensitivities for quantifying uncertainty in history matching geological models. In the first stage, we compute the acceptance probability for a proposed change in reservoir parameters based on a linearized approximation to flow simulation in a small neighborhood of the previously computed dynamic data. In the second stage, those proposals that passed a selected criterion of the first stage are assessed by running full flow simulations to assure the rigorousness. Second, we propose a two-stage MCMC approach using response surface models for quantifying uncertainty. The formulation allows us to history match three-phase flow simultaneously. The built response exists independently of expensive flow simulation, and provides efficient samples for the reservoir simulation and MCMC in the second stage. Third, we propose a two-stage MCMC approach using upscaling and non-parametric regressions for quantifying uncertainty. A coarse grid model acts as a surrogate for the fine grid model by flow-based upscaling. The response correction of the coarse-scale model is performed by error modeling via the non-parametric regression to approximate the response of the computationally expensive fine-scale model. Our proposed two-stage sampling approaches are computationally efficient and rigorous with a significantly higher acceptance rate compared to traditional MCMC algorithms. Finally, we developed a coarsening algorithm to determine an optimal reservoir simulation grid by grouping fine scale layers in such a way that the heterogeneity measure of a defined static property is minimized within the layers. The optimal number of layers is then selected based on a statistical analysis. The power and utility of our approaches have been demonstrated using both synthetic and field examples.

This work presents a new approach that combines the comprehensive capabilities of the ensemble Kalman filter (EnKF) and the flow path information from streamlines to eliminate and/or reduce some of the problems and limitations of the use of the EnKF for history matching reservoir models. The recent use of the EnKF for data assimilation and assessment of uncertainties in future forecasts in reservoir engineering seems to be promising. EnKF provides ways of incorporating any type of production data or time lapse seismic information in an efficient way. However, the use of the EnKF in history matching comes with its shares of challenges and concerns. The overshooting of parameters leading to loss of geologic realism, possible increase in the material balance errors of the updated phase(s), and limitations associated with non-Gaussian permeability distribution are some of the most critical problems of the EnKF. The use of larger ensemble size may mitigate some of these problems but are prohibitively expensive in practice. We present a streamline-based conditioning technique that can be implemented with the EnKF to eliminate or reduce the magnitude of these problems, allowing for the use of a reduced ensemble size, thereby leading to significant savings in time during field scale implementation. Our approach involves no extra computational cost and is easy to implement. Additionally, the final history matched model tends to preserve most of the geological features of the initial geologic model. A quick look at the procedure is provided that enables the implementation of this approach into the current EnKF implementations. Our procedure uses the streamline path information to condition the covariance matrix in the Kalman Update. We demonstrate the power and utility of our approach with synthetic examples and a field case. Our result shows that using the conditioned technique presented in this thesis, the overshooting/undershooting problems disappears and the limitation to work with non- Gaussian distribution is reduced. Finally, an analysis of the scalability in a parallel implementation of our computer code is given.

Thermal properties of pure methane hydrate, under conditions similar to naturally occurring hydrate-bearing sediments being considered for potential production, have been determined both by a new experimental technique and by advanced molecular dynamics simulation (MDS). A novel single-sided, Transient Plane Source (TPS) technique has been developed and used to measure thermal conductivity and thermal diffusivity values of low-porosity methane hydrate formed in the laboratory. The experimental thermal conductivity data are closely matched by results from an equilibrium MDS method using in-plane polarization of the water molecules. MDS was also performed using a non-equilibrium model with a fully polarizable force field for water. The calculated thermal conductivity values from this latter approach were similar to the experimental data. The impact of thermal conductivity on gas production from a hydrate-bearing reservoir was also evaluated using the Tough+/Hydrate reservoir simulator (Revised version of ICGH paper 5646).

The Unconventional Resource Plays consisting of the lowest tier of resources (large volumes and most difficult to develop) have been the main focus of US domestic activity during recent times. Horizontal well drilling and hydraulic fracturing completion technology have been primarily responsible for this paradigm shift. The concept of drainage volume is being examined using pressure diffusion along streamlines. We use diffusive time of flight to optimize the number of hydraulic fracture stages in horizontal well application for Tight Gas reservoirs. Numerous field case histories are available in literature for optimizing number of hydraulic fracture stages, although the conclusions are case specific. In contrast, a general method is being presented that can be used to augment field experiments necessary to optimize the number of hydraulic fracture stages. The optimization results for the tight gas example are in line with the results from economic analysis. The fluid flow simulation for Naturally Fractured Reservoirs (NFR) is performed by Dual-Permeability or Dual-Porosity formulations. Microseismic data from Barnett Shale well is used to characterize the hydraulic fracture geometry. Sensitivity analysis, uncertainty assessment, manual & computer assisted history matching are integrated to develop a comprehensive workflow for building reliable reservoir simulation models. We demonstrate that incorporating proper physics of flow is the first step in building reliable reservoir simulation models. Lack of proper physics often leads to unreasonable reservoir parameter estimates. The workflow demonstrates reduced non-uniqueness for the inverse history matching problem. The behavior of near-critical fluids in Liquid Rich Shale plays defies the production behavior observed in conventional reservoir systems. In conventional reservoirs an increased gas-oil ratio is observed as flowing bottom-hole pressure is less than the saturation pressure. The production behavior is examined by building a compositional simulation model on an Eagle Ford well. Extremely high pressure drop along the multiple transverse hydraulic fractures and high critical gas saturation are responsible for this production behavior. Integrating pore-scale flow modeling (such as Lattice Boltzmann) to the field-scale reservoir simulation may enable quantifying the effects of high capillary pressure and phase behavior alteration due to confinement in the nano-pore system.

[pt] O conhecimento do que acontece no reservatório em produção a partir de variações temporais dos atributos sísmicos devido aos processos dinâmicos vem atingindo um valor crescente na indústria do petróleo, especialmente em arenitos. Este processo possui vários desafios, focados em grande parte a desvendar a superposição dos diferentes efeitos provocados pelas mudanças do reservatório nos dados sísmicos. As propriedades sísmicas são afetadas de maneira complexa por vários fatores, sendo a saturação um dos mais importantes, principalmente em rochas porosas como o arenito. Esta propriedade influencia no módulo elástico da rocha e sua resposta sísmica e, ao mesmo tempo, introduz dispersão da velocidade (variação da velocidade com a freqüência). A transição de fluido efetivo (distribuição homogênea e menores velocidades) para fluido com distribuição heterogênea (e maiores velocidades) estabelece um mecanismo de dispersão presente para freqüências sísmicas in situ, especialmente no arenito. O método mais utilizado para aplicar a técnica de substituição de fluidos se baseia na teoria de Gassmann (1951), que considera o meio poroso estático (estado de isostress), onde o fluido não é afetado pela perturbação da onda. No entanto, pesquisas mostram que as velocidades acústicas em rochas saturadas de fluido dependem da freqüência, do tipo de fluido e sua distribuição no meio poroso, viscosidade e outras propriedades que tornam as ondas dispersivas. Neste trabalho são realizadas simulações de fluxo de reservatórios, transformações de física de rochas, upscaling e modelagem sísmica em cenários de injeção de gás com o objetivo de esclarecer a importância de levar em conta a dispersão da velocidade na análise time-lapse. Para isso, são analisados para cada modelo mapas de saturação, velocidade, impedância e sismogramas sintéticos (seções de contraste) calculados com as teorias de substituição Gassmann (1951) e Mavko E Jizba (1991). Os resultados mostram que a resposta sísmica pode ter um incremento de até 15 por cento quando a dispersão devida ao fluxo local é considerada. Porosidade e tortuosidade são parâmetros essenciais que influenciam de maneira diferente na resposta sísmica. / [en] The evaluation of reservoir dynamics during production through time-lapse interpretation has reached a substantial importance in the petroleum industry, mainly in sandstones. This evaluation presents many challenges, mainly concerned to unmask the overlapping of different effects in seismic data due to reservoir changes. Several factors affect seismic properties and saturation is one of the most important. This property influences the rock bulk modulus and seismic response and also causes a velocity dependence on the frequency. This phenomenon is known as velocity dispersion. Furthermore, the transition from effective homogeneous fluid to heterogeneous saturation represents a dispersion mechanism that appears for seismic frequencies in situ in sandstones. The most commonly method used to perform the fluid substitution technique is based in Gassmann theory (1951). This approach considers a static porous media (isostress condition), where fluid is not affected by wave propagation. However, it is well known that acoustic velocities in fluid saturated rocks depends on frequency, according to fluid type and distribution on porous media, viscosity, and others properties that become waves dispersive. In this work reservoir flow-simulation, rock physics transformations, upscaling and seismic modeling were performed in gas injection scenarios. Synthetic seismograms and some contrast sections were generated using Gassmann (1951) and Mavko & Jizba (1991) substitution theories. The goal is to clarify the relevance of considering velocity dispersion on time-lapse seismic analyzing possible differences in the seismic parameters. Results show that seismic response could increase in 15% when squirt flow dispersion is considered. Porosity and tortuosity are essential parameters to analyze seismic response.

Made available in DSpace on 2014-12-17T14:08:49Z (GMT). No. of bitstreams: 1 CindyPAR_DISSERT.pdf: 3888295 bytes, checksum: 74ba5d896661a5a41c98018b93246cd9 (MD5) Previous issue date: 2012-02-17 / Conselho Nacional de Desenvolvimento Cient?fico e Tecnol?gico / Oil recovery using waterflooding has been until now the worldwide most applied method, specially for light oil recovery, its success is mainly because of the low costs involved and the facilities of the injection process. The Toe- To-Heel Waterflooding TTHWTM method uses a well pattern of vertical injector wells completed at the bottom of the reservoir and horizontal producer wells completed at the top of it. The main producing mechanism is gravitational segregation in short distance. This method has been studied since the early 90?s and it had been applied in Canada with positive results for light heavy oils, nevertheless it hasn?t been used in Brazil yet. In order to verify the applicability of the process in Brazil, a simulation study for light oil was performed using Brazilian northwest reservoirs characteristics. The simulations were fulfilled using the STARS module of the Computer Modelling Group Software, used to perform improved oil recovery studies. The results obtained in this research showed that the TTHWTM well pattern presented a light improvement in terms of recovery factor when compared to the conventional 5- Spot pattern, however, it showed lower results in the economic evaluation / A recupera??o de ?leo com inje??o de ?gua tem sido at? agora o m?todo mais aplicado no mundo inteiro, principalmente para a recupera??o de ?leos leves; o sucesso deve-se aos baixos custos envolvidos e a facilidade de inje??o. O m?todo Toe-to-Heel Waterflooding TTHWTM utiliza uma configura??o de po?os injetores verticais completados no fundo do reservat?rio e po?os produtores horizontais completados no topo. O mecanismo de produ??o principal ? a segrega??o gravitacional em dist?ncias curtas. Este m?todo tem sido estudado desde o in?cio dos anos 90 e tem sido aplicado no Canad? com resultados positivos para ?leos levemente pesados, no entanto o m?todo ainda n?o tem sido utilizado no Brasil. Para verificar a aplicabilidade do processo no Brasil foi realizado um estudo de simula??o em reservat?rios de ?leo leve com caracter?sticas do Nordeste Brasileiro. O objetivo da pesquisa foi analisar quais os fatores operacionais que podem influenciar no processo. As simula??es foram realizadas utilizando o m?dulo STARS da Computer Modelling Group , com o objetivo de realizar estudos de m?todos de recupera??o avan?ada de ?leo. Os resultados obtidos neste trabalho mostraram que a configura??o de po?os aplicada para este caso apresentou uma leve melhora em rela??o ? configura??o convencional de 5 pontos (5-Spot) em termos de fator de recupera??o, no entanto, apresentou menores resultados na avalia??o econ?mica

Made available in DSpace on 2014-12-17T14:09:16Z (GMT). No. of bitstreams: 1 JoseCSJ_TESE_PARCIAL.pdf: 3198681 bytes, checksum: 3124bf4fcf475e3c972bb5266fef2405 (MD5) Previous issue date: 2013-02-20 / Steam injection is a method usually applied to very viscous oils and consists of injecting heat to reduce the viscosity and, therefore, increase the oil mobility, improving the oil production. For designing a steam injection project it is necessary to have a reservoir simulation in order to define the various parameters necessary for an efficient heat reservoir management, and with this, improve the recovery factor of the reservoir. The purpose of this work is to show the influence of the coupled wellbore/reservoir on the thermal simulation of reservoirs under cyclic steam stimulation. In this study, the methodology used in the solution of the problem involved the development of a wellbore model for the integration of steam flow model in injection wellbores, VapMec, and a blackoil reservoir model for the injection of cyclic steam in oil reservoirs. Thus, case studies were developed for shallow and deep reservoirs, whereas the usual configurations of injector well existing in the oil industry, i.e., conventional tubing without packer, conventional tubing with packer and insulated tubing with packer. A comparative study of the injection and production parameters was performed, always considering the same operational conditions, for the two simulation models, non-coupled and a coupled model. It was observed that the results are very similar for the specified well injection rate, whereas significant differences for the specified well pressure. Finally, on the basis of computational experiments, it was concluded that the influence of the coupled wellbore/reservoir in thermal simulations using cyclic steam injection as an enhanced oil recovery method is greater for the specified well pressure, while for the specified well injection rate, the steam flow model for the injector well and the reservoir may be simulated in a non- coupled way / A inje??o de vapor ? um m?todo aplicado geralmente em ?leos muito viscosos e consiste em injetar calor para reduzir a viscosidade e, portanto, aumentar a mobilidade do ?leo, resultando em incremento na produ??o dos po?os. Para o planejamento de um projeto de inje??o de vapor ? necess?rio efetuar um estudo de reservat?rio com o objetivo de se definir os v?rios par?metros necess?rios para um eficiente gerenciamento de calor no meio poroso e, com isto, melhorar o fator de recupera??o do reservat?rio. Neste estudo, para o sistema de inje??o, representado pelo po?o injetor, ? normalmente adotado um modelo padr?o em todos os casos estudados, sendo desta forma, a integra??o entre o po?o injetor e o reservat?rio, realizada de forma bastante simplificada. Este trabalho tem como objetivo mostrar a influ?ncia do acoplamento do po?o injetor nas simula??es t?rmicas de reservat?rios submetidos ? inje??o c?clica de vapor. Neste estudo, a metodologia utilizada na solu??o do problema envolveu o desenvolvimento de um modelo de po?o para a integra??o do modelo de escoamento de vapor em po?os de petr?leo, VapMec, e o modelo de reservat?rio tipo beta para a inje??o c?clica de vapor em reservat?rios de petr?leo. Assim, desenvolveram-se estudos de caso para reservat?rios rasos e profundos, considerando as principais configura??es de po?o injetor existentes na ind?stria de petr?leo, ou seja, coluna convencional sem packer, coluna convencional com packer e coluna isolada com packer. Foi realizado um estudo comparativo dos par?metros de inje??o e produ??o obtidos na simula??o, considerando sempre as mesmas condi??es de opera??o, para os dois modelos de simula??o, sendo um modelo n?o acoplado e o outro modelo acoplado. Observou-se que os resultados entre os modelos s?o bastante similares para a situa??o de vaz?o de inje??o igual ? vaz?o especificada, tendo sido encontrado diferen?as significativas na situa??o em que a press?o de inje??o ? igual ? press?o especificada. Finalmente, com base nos experimentos computacionais, foi poss?vel concluir que a influ?ncia do acoplamento do po?o injetor nos estudos de reservat?rios que utilizam a inje??o c?clica de vapor como m?todo especial de recupera??o ? maior para a condi??o de press?o especificada, sendo que para a condi??o de vaz?o especificada, o modelo de escoamento no po?o injetor e o modelo do reservat?rio podem ser simulados de forma n?o integrada

Made available in DSpace on 2015-03-13T17:08:22Z (GMT). No. of bitstreams: 1 Flavio_LS.pdf: 1955029 bytes, checksum: 8e0fa408c324ef805ccd084d89be3a06 (MD5) Previous issue date: 2005-07-15 / Conselho Nacional de Desenvolvimento Cient?fico e Tecnol?gico / The history match procedure in an oil reservoir is of paramount importance in order to obtain a characterization of the reservoir parameters (statics and dynamics) that implicates in a predict production more perfected. Throughout this process one can find reservoir model parameters which are able to reproduce the behaviour of a real reservoir.Thus, this reservoir model may be used to predict production and can aid the oil file management. During the history match procedure the reservoir model parameters are modified and for every new set of reservoir model parameters found, a fluid flow simulation is performed so that it is possible to evaluate weather or not this new set of parameters reproduces the observations in the actual reservoir. The reservoir is said to be matched when the discrepancies between the model predictions and the observations of the real reservoir are below a certain tolerance. The determination of the model parameters via history matching requires the minimisation of an objective function (difference between the observed and simulated productions according to a chosen norm) in a parameter space populated by many local minima. In other words, more than one set of reservoir model parameters fits the observation. With respect to the non-uniqueness of the solution, the inverse problem associated to history match is ill-posed. In order to reduce this ambiguity, it is necessary to incorporate a priori information and constraints in the model reservoir parameters to be determined. In this dissertation, the regularization of the inverse problem associated to the history match was performed via the introduction of a smoothness constraint in the following parameter: permeability and porosity. This constraint has geological bias of asserting that these two properties smoothly vary in space. In this sense, it is necessary to find the right relative weight of this constrain in the objective function that stabilizes the inversion and yet, introduces minimum bias. A sequential search method called COMPLEX was used to find the reservoir model parameters that best reproduce the observations of a semi-synthetic model. This method does not require the usage of derivatives when searching for the minimum of the objective function. Here, it is shown that the judicious introduction of the smoothness constraint in the objective function formulation reduces the associated ambiguity and introduces minimum bias in the estimates of permeability and porosity of the semi-synthetic reservoir model / O processo de ajuste de hist?rico de produ??o em um reservat?rio de petr?leo ? de fundamental import?ncia para que se possa obter uma caracteriza??o dos par?metros do reservat?rio (est?ticos e din?micos) que implique em uma previs?o de produ??o mais acurada. Atrav?s deste processo pode-se encontrar par?metros para um modelo de reservat?rio que sejam capazes de reproduzir o comportamento do reservat?rio real. Assim, esse modelo de reservat?rio pode ser utilizado em previs?es de produ??o e no aux?lio ao gerenciamento do campo de ?leo/g?s. No processo de ajuste de hist?rico, os par?metros do modelo do reservat?rio s?o modificados e para cada modelo com o novo conjunto de par?metros, uma simula??o de fluxo ? realizada para que se possa avaliar se este conjunto reproduz ou n?o as curvas de produ??o de um reservat?rio real. O reservat?rio ? ajustado quando as discrep?ncias entre as previs?es do modelo de reservat?rio e a do reservat?rio real s?o abaixo de certa toler?ncia. Determinar um modelo de reservat?rio por meio do processo de ajuste de hist?rico requer a minimiza??o de uma fun??o objetivo (diferen?a entre a produ??o observada e simulada) em um espa?o de par?metros que em geral possui muitos m?nimos, ou seja, mais de um modelo de reservat?rio ajusta as observa??es. No sentido da n?o-unicidade da solu??o, o problema inverso associado ao processo de ajuste de hist?rico ? mal-posto. A fim de reduzir esta ambig?idade e regularizar o problema, ? necess?ria a incorpora??o de informa??es a priori e de v?nculos nos par?metros do reservat?rio a serem determinados. Neste trabalho, a regulariza??o do problema inverso associado ao ajuste de hist?rico foi realizada por meio da introdu??o de um v?nculo de suavidade nos par?metros: porosidade e permeabilidade, de um reservat?rio. Esse v?nculo possui o vi?s geol?gico de que os valores de porosidade e permeabilidade variam suavemente ao longo do reservat?rio. Nesse sentido, ? necess?rio encontrar um valor do peso deste v?nculo, na fun??o objetivo, que estabilize o problema e ainda introduza nos par?metros do modelo de reservat?rio o menor vi?s geol?gico poss?vel