The flow of particulate suspensions and brines in porous media is encountered in a wide range of industrial situations such as oil production, soil erosion, and ground water pollution and in the operation of filter beds. Three major classes of such problems are addressed in this thesis, namely particle movement, scale formation and filtration. Particle movement and scale formation are known to be serious problems in oil reservoirs where incompatible brine is brought into contact with the formation. Dramatic reductions in permeability are observed in such cases due to the release of fine particles that subsequently plug flow channels downstream. This study deals with an experimental and theoretical study of formation damage resulting from particle movement and scale formation in porous media. An experimental investigation was undertaken to look into the possible causes of the injectivity loss in a typical Iranian oilfield. Sets of experimental investigations were undertaken with different objectives in mind. Glass and sand bead packs were used to test the experimental set up and to observe the general behavior of fine particle movement and scale formation in porous media. The experiments were conducted with injection rates from 25 cm3/min to 100 cm3/min. Particles of alumina oxide were suspended in the injected water to simulate fine particle migration in porous media. The particles were injected at concentrations ranging from 500 ppm to 2000 ppm. It was observed that the build-up of flow resistance was mostly due to frontal face plugging. Alumina particles were added to the glass beads to study the effect of particles initially present in the glass bead pack. A mathematical model is presented that simulates the porosity impairment by particle movement. This model, which is based on the mass balance of particles flowing through the porous media, at first, proposes an overall equation to determine the porosity and by a special mechanism it can predict the overall change in porosity. The equations are quite general and can be used to model the permeability reduction for any given pore or particle size distribution. Also this study aims to investigate the calcium sulphate and calcium carbonate scaling in a porous medium to discover its possible effect upon the permeability of the porous medium. The information on the effect of scale deposition is obtained experimentally by flooding porous medium with incompatible brines. The experimental data are used to develop and validate models for predicting the permeability decline caused by scale. The model is intended to provide a link between what is known or can be assumed about brines in an oil reservoir. A computer program was developed which can predict the scaling tendency of the sulphate minerals and calcium carbonate, in water disposal wells, water injection systems, surface equipments and facilities that commonly form scale. This program is based on the latest correlations of experimental data relating to North Sea and Iranian oilfields. It is used to determine the degree to which brine becomes supersaturated with a scale forming mineral under specified conditions. Processes capable of creating supersatuartion in oilfields are described and it is shown that the distribution of scale depends on the process involved.

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This study presents an investigation of the concept of harvesting geothermal energy that remains in heavy oil reservoirs after abandonment when steamflooding is no longer economics. Substantial heat that has accumulated within reservoir rock and its vicinity can be extracted by circulating water relatively colder than reservoir temperature. We use compositional reservoir simulation coupled with a semianalytical equation of the wellbore heat loss approximation to estimate surface heat recovery. Additionally, sensitivity analyses provide understanding of the effect of various parameters on heat recovery in the artificial geothermal resources. Using the current state-of-art technology, the cumulative electrical power generated from heat recovered is about 246 MWhr accounting for 90percent downtime. Characteristics of heat storage within the reservoir rock were identified. The factors with the largest impact on the energy recovery during the water injection phase are the duration of the steamflood (which dictates the amount of heat accumulated in the reservoir) and the original reservoir energy in place. Outlet reservoir-fluid temperatures are used to approximate heat loss along the wellbore and estimate surface fluid temperature using the semianalytical approaches. For the injection well with insulation, results indicate that differences in fluid temperature between surface and bottomhole are negligible. However, for the conventional production well, heat loss is estimated around 13 percent resulting in the average surface temperature of 72 degrees C. Producing heat can be used in two applications: direct uses and electricity generation. For the electricity generation application that is used in the economic consideration, the net electrical power generated by this arrival fluid temperature is approximately 3 kW per one producing pattern using Ener-G-Rotors.

An integrated stratigraphic analysis of a ~350 ft drill core from Upton County (Texas) has revealed pervasive variability of several key siliciclastic and carbonate lithofacies in vertical section, where organic-rich siliceous mudrock beds alternate with aluminum-rich mudrocks and calcareous gravity flow deposits. Sediment chemistry, especially major and trace elements derived from x-ray fluorescence, captures this variability with high sensitivity. The high frequency chemostratigraphic variability appears to be cyclic, and it is interpreted to represent the first example of deep-water Late Pennsylvanian cyclothems for the Midland Basin. Positive trace metal (Mo, Cr) correlations to total organic carbon and gamma ray response in siliceous mudrocks, in conjunction with abundant pyrite, indicate bottom-water anoxia and possibly euxinia within the basin. The influence of glacial ice-sheets on the water level of the global ocean, in concert with local oceanographic gradients, regional tectonics, and tropical paleoclimate, constitute the primary controls on lithofacies and chemostratigraphy. The results of this study have implications for understanding the depositional history of the Midland Basin, as well as for identifying horizontal drilling zones for resource development.

Reservoir management strategies traditionally attempt to combine and balance complex geophysical, petrophysical, thermodynamic and economic factors to determine an optimal method to recover hydrocarbons from a given reservoir. Reservoir simulators have traditionally been too large and run times too long to allow for rigorous solution in conjunction with an optimization algorithm. It has also proven very difficult to marry an optimizer with the large set of nonlinear partial differential equations required for accurate reservoir simulation. A simple capacitance-resistance model (CRM) that characterizes the connectivity between injection and production wells can determine an injection scheme maximizes the value of the reservoir asset. Model parameters are identified using linear and nonlinear regression. The model is then used together with a nonlinear optimization algorithm to compute a set of future injection rates which maximize discounted net profit. This research demonstrates that this simple dynamic model provides an excellent match to historic data. Based on three case studies examining actual reservoirs, the optimal injection schemes based on the capacitance-resistive model yield a predicted increase in hydrocarbon recovery of up to 60% over the extrapolated exponential historic decline. An advantage of using a simple model is its ability to describe large reservoirs in a straightforward way with computation times that are short to moderate. However, applying the CRM to large reservoirs with many wells presents several new challenges. Reservoirs with hundreds of wells have longer production histories – new wells are created, wells are shut in for varying periods of time and production wells are converted to injection wells. Additionally, ensuring that the production data to which the CRM is fit are free from contamination or corruption is important. Several modeling techniques and heuristics are presented that provide a simple, accurate reservoir model that can be used to optimize the value of the reservoir over future time periods. In addition to optimizing reservoir performance by allocating injection, this research presents a few methods that use the CRM to find optimal well locations for new injectors. These algorithms are still in their infancy and represent the best ideas for future research. / text

Naturally fractured reservoirs have attracted an increased interest of exploration and production geophysics in recent years. In many instances, natural fractures control the permeability of the reservoir, and hence the ability to find and characterize fractured areas of the reservoir represents a major challenge for seismic investigations. In fractured and porous reservoirs the fluid affects elastic anisotropy of the rock and also causes significant frequency dependent attenuation and dispersion. In this study we develop a mathematical model for seismic wave attenuation and dispersion in a porous medium in a porous medium with aligned fractured, caused by wave induced fluid flow between pores and fractures. In this work fractures in the porous rock are modelled as very thin and highly porous layers in a porous background. Dry highly porous materials have low elastic moduli; thus dry skeleton of our system contains thin and soft layers, and is described by linear slip theory. The fluid saturated rock with high-porasity layers is described by equations of poroelasticity with periodically varying coefficients. These equations are analyzed using propagator matrix approach commonly used to study effective properties of layered system. This yields a dispersion equation for a periodically layered saturated porous medium taking into account fluid communication between pore spaces of the layers. Taking in this dispersion equation a limit of small thickness for high-porosity layers gives the velocity and attenuation as a function of frequency and fracture parameters. The results of this analysis show that porous saturated rock with aligned fractures exhibits significant attenuation and velocity dispersion due to wave induced fluid flow between pores and fractures. / At low frequencies the material properties are equal to those obtained by anisotropic Gassmann theory applied to a porous material with linear-slip, interfaces. At high frequencies the results are equivalent to those for fractures with vanishingly small normal slip in a solid (non-porous) background. The characteristic frequency of the attenuation and dispersion depends on the background permeability, fluid viscosity, as well as fracture density and spacing. The wave induced fluid flow between pores and fractures considered in this work has exactly the same physical nature as so-called squirt flow, which is widely believed to by a major cause of seismic attenuation. Hence, the present model can be viewed as a new model of squirt-flow attenuation, consistent with Biot’s theory of poroelasticity. The theoretical results of this work are also limited by the assumption of periodic distribution of fractures. In reality fractures may be distributed in a random fashion. Sensitivity of our results to the violation of the periodicity assumption was examined numerically using reflectivity modelling for layered poroelastic media. Numerical experiments for a random distribution of fractures of the same thickness still show surprisingly good agreement with theoretical results obtained for periodic fractures. However this agreement may break down if fracture properties are allowed to vary from fracture to fracture. The results of this thesis show how to compute frequency dependences of attenuation and velocity caused by wave induced fluid flow between pores and fractures. These results can be used to obtain important parameters of fractured reservoirs, such as permeability and fracture weakness, from attenuation measurements. The major requirement for the success of such an approach is that measurements must be made in over a relatively broad frequency range.

Concerns about elevated atmospheric carbon dioxide (CO 2 ) and the effect on global climate have created proposals for the reduction of carbon emissions from large stationary sources, such as power plants. Carbon dioxide capture and sequestration (CCS) in deep geologic units is being considered by Florida electric-utilities. Carbon dioxide-enhanced oil recovery (CO 2 -EOR) is a form of CCS that could offset some of the costs associated with geologic sequestration. Two potential reservoirs for geologic sequestration were evaluated in south-central and southern Florida: the Paleocene Cedar Keys Formation/Upper Cretaceous Lawson Formation (CKLIZ) and the Lower Cretaceous Sunniland Formation along the Sunniland Trend (Trend). The Trend is a slightly arcuate band in southwest Florida that is about 233 kilometers long and 32 kilometers wide, and contains oil plays within the Sunniland Formation at depths starting around 3,414 meters below land surface, which are confined to mound-like structures made of coarse fossil fragments, mostly rudistids. The Trend commercial oil fields of the South Florida Basin have an average porosity of 16% within the oil-producing Sunniland Formation, and collectively have an estimated storage capacity of around 26 million tons of CO 2 . The Sunniland Formation throughout the entire Trend has an average porosity of 14% and an estimated storage capacity of about 1.2 billion tons of CO 2 (BtCO2 ). The CKLIZ has an average porosity of 23% and an estimated storage capacity of approximately 79 BtCO 2 . Porous intervals within the CKLIZ and Sunniland Formation are laterally homogeneous, and low-permeability layers throughout the units provide significant vertical heterogeneity. The CKLIZ and Sunniland Formation are considered potentially suitable for CCS operations because of their geographic locations, appropriate depths, high porosities, estimated storage capacities, and potentiallyeffective seals. The Trend oil fields are suitable for CO 2 -EOR in the Sunniland Formation due to appropriate injected-CO 2 density, uniform intergranular porosity, suitable API density of formation-oil, sufficient production zones, and adequate remaining oil-in-place following secondary recovery. In addition to these in-depth investigations of the CKLIZ and Sunniland Formation, a more-cursory assessment of deep geologic units throughout the state of Florida, which includes rocks of Paleocene and Upper Cretaceous age through to rocks of Ordovician age, shows additional units in Florida that may be suitable for CO 2 -EOR and CCS operations. Furthermore, this study shows that deep geologic units throughout Florida potentially have the capacity to sequester billions of tons of CO 2 for hundreds of fossil-fuel-fired power plants. Geologic sequestration has not yet been conducted in Florida, and its implementation could prove useful to Florida utility companies, as well as to other energy-utilities in the southeastern United States.

[pt] Uma das tarefas mais importantes da Engenharia de Reservatórios é definir a estratégia de produção. Isso significa estabelecer, dentre outras coisas, quantidade, características, localização, planejamento operacional e cronograma de abertura dos poços, a fim de maximizar a recuperação de óleo e o valor presente líquido (VPL) do projeto. Assim, a definição da melhor estratégia de produção representa um problema de otimização complexo, devido à quantidade de variáveis envolvidas. Geralmente, muitas dessas etapas são executadas manualmente, demandando assim muito tempo e esforço por parte do especialista. A disponibilidade de uma ferramenta computacional, que possa auxiliar o especialista em parte desse processo, pode ser de grande utilidade tanto para a obtenção de respostas mais rápidas, quanto para a tomada de decisões mais acertadas. Diante disso, este trabalho propõe um modelo computacional, baseado em Algoritmos Genéticos, para otimizar o cronograma de abertura de poços, considerando restrições técnicas e operacionais impostas pelo problema. O modelo proposto foi avaliado por meio do estudo de três casos. O primeiro consiste em um reservatório simples que foi utilizado, principalmente, para identificar a configuração mais adequada dos parâmetros evolutivos do algoritmo genético. O segundo, que consiste em um reservatório com características similares às de um reservatório real, foi submetido a uma análise econômica para avaliar o desempenho do modelo de solução diante de cenários econômicos: real, favorável e desfavorável. Em todos os testes realizados, o modelo de solução obteve resultados promissores, com VPL s superiores em até 18,8 porcento comparados ao VPL obtido com o cronograma proposto pelo especialista. / [en] One of the most important tasks of Reservoir Engineering is setting the production strategy. That means establishing, among other things, amount, character, location, operational planning and well opening scheduling in order to maximize oil recovery and net present value (NPV) of the project. Thus, the definition of the best strategy for production represents a complex optimization problem due to the many variables involved. Generally, many of these steps are performed manually, requiring so much time and effort on the part of the expert. The availability of a computational tool that can assist the expert part of this process, may be useful both to obtain faster responses, as for making better decisions. Thus, this work proposes a computational model based on genetic algorithms to optimize the schedule of digging wells, considering technical and operational constraints imposed by the problem. The proposed model was evaluated by the study of three cases. The first consists of a single reservoir that was used primarily to identify the most suitable configuration of parameters evolutionary genetic algorithm. The second, consisting of a reservoir with characteristics similar to those of a real reservoir, was subjected to an economic analysis to evaluate the performance of the model solution in the face of economic scenarios: real, favorable and unfavorable. And the third is in a real reservoir. In all tests, the model solution obtained promising results, with higher NPV s up 18.8 percent compared to the NPV obtained with the schedule proposed by the expert.