Since the plus fraction of reservoir fluids has some uncertainty in its molecular weight and critical properties, equation-of-state, EOS, are generally not predictive without tuning its parameters to match experimental data. Tuning of the EOS is found to be the best method for improving the predictions of compositional reservoir simulators. The proposed strategy for tuning EOS consists of seven steps: (1) split the laboratory plus fraction to single carbon number groups, SCN, usually up to SCN 44; the last component will be C45+, (2) use set of correlations to calculate the critical properties and acentric factor for each SCN group, (3) match the saturation pressure at reservoir temperature by altering the measured value of the molecular weight of the plus fraction using the extended composition, (4) group SCN groups to multiple carbon number groups, MCN, (5) assign critical properties and acentric factor for each MCN group, (6) rematch the saturation pressure at reservoir temperature using the grouped composition, and (7) match the volumetric data by regressing on volume shift parameters of all components in grouped composition. This research shows an accurate method to split the plus fraction to SCN groups. The most accurate set of correlations to calculate the critical properties and acentric factor for each SCN group that will result in a small adjustment for the molecular weight of the plus fraction when saturation pressure is matched using the extended composition. The proposed strategy groups the extended composition to eight pseudocomponents. The binary interaction coefficients between hydrocarbons and between hydrocarbons and non-hydrocarbons are set to zero which dramatically reduces the simulation time. The strategy proposed in this research for tuning EOS to match experimental data has been tested for a wide range of C7+ mole% (4 – 25) which covers gas condensate and volatile oil samples. Also, using this strategy to tune EOS at reservoir temperature will accurately predict the fluid properties at separator conditions and saturation pressures at different temperatures. The scope of this research is to come up with an accurate and systematic technique for tuning an EOS for use in compositional simulation.

CoordenaÃÃo de AperfeÃoamento de Pessoal de NÃvel Superior / In reservoir simulation, the compositional model is one of the most used models for enhanced oil recovery. However, the physical model involves a large number of equations with a very complex interplay between equations. The model is basically composed of balance equations and equilibrium constraints. The way these equations are solved, the degree of implicitness, the selection of the primary equations, primary and secondary variables have a great impact on the computation time. In order to verify these effects, this work proposes the implementation and comparison of some implicit and semi-implicit methods. The following formulations are tested: an IMPEC (implicit pressure, explicit composition), an IMPSAT (implicit pressure and saturations), and two fully implicit formulations, in which one these formulations is being proposed in this work. However, the literature reports some intrinsic inconsistencies of the IMPSAT formulation mentioned. In order to verify it, an iterative IMPSAT is implemented to check the quality of the IMPSAT method previously mentioned. The finite volume method is used to discretize the formulations using Cartesian grids and unstructured grids in conjunction with the EbFVM (Element based finite volume method) for 2D and 3D reservoirs. The implementations have been performed in the UTCOMP simulator from the University of Texas at Austin. The results of several case studies are compared in terms of volumetric oil and gas rates and the total CPU time. It was verified that the FI approaches increase their performance, when compared to the other approaches, as the grid is refined. A good performance was observed for the IMPSAT approach when compared to the IMPEC formulation. However, as more complex stencils are used, the IMPSAT performance reduces. / Em simulaÃÃo de reservatÃrios, o modelo composicional à um dos mais usados para a recuperaÃÃo avanÃada de petrÃleo. Entretanto, o modelo fÃsico envolve um grande nÃmero de equaÃÃes com uma complexa interelaÃÃo entre elas. O modelo à basicamente composto por equaÃÃes de balanÃo e restriÃÃes de equilÃbrio. A forma como essas equaÃÃes sÃo resolvidas como, o grau de implicitude, a seleÃÃo das equaÃÃes primÃrias, variÃveis primÃrias e secundÃrias tem um grande impacto no tempo de computaÃÃo. Com o intuito de verificar esse efeito, esse trabalho propÃe a implementaÃÃo e comparaÃÃo de alguns mÃtodos implÃcitos e semi-implÃcitos. As seguintes formulaÃÃes sÃo testadas: uma IMPEC (implicit pressure, explicit composition), uma IMPSAT (implicit pressure and saturations), e duas formulaÃÃes totalmente implicitas, das quais uma destas està sendo proposta neste trabalho. Entretanto, a literatura relata algumas inconsistÃncias intrÃnsecas da formulaÃÃo IMPSAT mencionada. Para verificar isso, um IMPSAT iterativo foi implementado para verificar a qualidade nos resultados do mÃtodo IMPSAT prÃviamente mencionado. O mÃtodo de volumes finitos à usado para discretizar as formulaÃÃes usando malhas Cartesianas e nÃo-estruturadas em conjunto com o EbFVM (Element based finite volume method) para reservatÃrios 2D e 3D. A implementaÃÃo foi realizada no simulador UTCOMP da Univeristy of Texas at Austin. Os resultados de diversos casos de estudo sÃo comparados em termos das vazÃes volumÃtricas de Ãleo e gÃs e do tempo total de CPU. Verificou-se que as abordagens totalmente implÃcitas melhoram sua performance, quando comparado com os demais mÃtodos, a medidaque a malha à refinada. Um bom desempenho foi observado para as formulaÃÃes IMPSAT quando comparadas com a formulaÃÃo IMPEC. Entretando, com o uso de conexÃes mais complexas entre os blocos da malha, o desempho da formulaÃÃo IMPSAT reduziu.

Multiple hydrocarbon phases are observed during miscible gas floods. The possible phases that result from a gas flood include a vapor phase, an oleic phase, a solvent-rich phase, a solid phase, and an aqueous phase. The solid phase primarily consists of aggregated asphaltene particles. Asphaltenes can block pore throats or change the formation wettability, and thereby reduce the hydrocarbon mobility. The dissolution of injected gas into the aqueous phase can also affect the gas flooding recovery because it reduces the amount of gas available to contact oil. This is more important in CO₂ flooding as the solubility of CO₂ in brine is much higher than hydrocarbons. In this research, we developed efficient and fast multi-phase equilibrium calculation algorithms to model phase behavior of asphaltenes and the aqueous phase in the compositional simulation of gas floods. The PC-SAFT equation of state is implemented in the UTCOMP simulator to model asphaltene precipitation. The additional computational time of PC-SAFT is substantially decreased by improving the root finding algorithm and calculating the derivatives analytically. A deposition and wettability alteration model is then integrated with the thermodynamic model to simulate dynamics of precipitated asphaltenes. Asphaltene deposition is shown to occur with pressure depletion around the production well and/or with gas injection in the reservoir domain that is swept by injected gas. It is observed that the profile of the damaged area by asphaltene deposition depends on the reservoir fluid. A general strategy is proposed to model the phase behavior of CO₂/hydrocarbon/water systems where four equilibrium phases exist. The developed four-phase reduced flash algorithm is used to investigate the effect of introducing water on the phase behavior of CO₂/hydrocarbon mixtures. The results show changes in the phase splits and saturation pressures by adding water to these CO₂/hydrocarbon systems. We used a reduced flash approach to reduce the additional computational time of the four-phase flash calculations,. The results show a significant speed-up in flash calculations using the reduced method. The computational advantage of the reduced method increases rapidly with the number of phases and components. We also decreased the computational time of the equilibrium calculations in UTCOMP by changing the sequential steps in the flash calculation where it checks the previous time-step results as the initial guess for the current time-step. The improved algorithm can skip a large number of flash calculation and stability analyses without loss of accuracy. / text

Accurate phase behavior modeling of hydrocarbon and aqueous mixtures plays a critical role in simulation of compositional flow in subsurface reservoirs, such as miscible gas flooding and CO2 sequestration. As Michelsen proposed his groundbreaking works in stability test and phase split calculation, PT flash calculation has been well developed in the past four decades and become the most popular flash technique. However, as research interests move to more complicated reservoir fluids, some inherent drawbacks of PT flash formulations show up and recent researches focus on a promising alternative called VT flash calculation. In this thesis, VT flash calculation is used in place of PT flash to model phase behaviors of hydrocarbon and aqueous mixtures. A dynamical model, together with a thermodynamically stable numerical algorithm, is developed to calculate equilibrium phase amounts and compositions with/without capillary effect to simulate phase behaviors of unconventional/conventional hydrocarbon mixtures. In order to model water-containing mixtures, the cubic equation of state is replaced by the Cubic-PlusAssociation equation of state, and a salt-based Cubic-Plus-Association model is developed to calculate phase behaviors of CO2-brine systems. The combination of VT flash calculation and the salt-based Cubic-Plus-Association model accurately estimate CO2 solubility in both single- and mixed-salt solutions, and it exhibits close prediction accuracy with a more sophisticated electrolyte Cubic-Plus-Association model. At the end, the ultimate goal is to develop an efficient two-phase VT-flash compositional flow algorithm. The multilayer nonlinear elimination method is used to remove locally high nonlinearities based on the feedback of intermediate Newton solutions. To further improve the computational efficiency, a modified shadow region method is used to bypass unnecessary stability tests. Although nonlinear elimination fails to fully resolve the convergence issue, which roots in the nondifferentiable equilibrium pressure at the points of phase boundary, the number of time refinements is significantly reduced and the improved VT-flash compositional flow algorithm with multilayer nonlinear elimination method successfully simulates a number of numerical examples with and without gravity.

This Ph.D. research project targets Cooper Basin oil reservoirs of very low permeability (approximately 1mD) where injectivities required for water flooding are not achievable. However, the use of injection gases such as CO₂ would not have injectivity problems. CO₂ is abundant in the region and available for EOR use. CO₂ was compared to other CO₂-rich injection gases with a hydrocarbon content including pentane plus components. While the effect of hydrocarbon components up to butane have been investigated in the past, the effect of n-pentane has on impure CO₂ gas streams has not. One particular field of the Cooper Basin was investigated in detail (Field A). However, since similar reservoir and fluid characteristics of Field A are common to the region it is expected that the data measured and developed has applications to many other oil reservoirs of the region and similar reservoirs elsewhere. The aim of this Ph.D. project is to determine the applicability of CO₂ as an injection gas for Enhanced Oil Recovery (EOR) in the Cooper Basin oil reservoirs and to compare CO₂ with other possible CO₂-rich injection gases. The summarised goals of this research are to: • Determine the compatibility of Field A reservoir fluid with CO₂ as an injection gas. • Compare CO₂ to other injection gas options for Field A. • Development of a correlation to predict the effect of nC₅ on MMP for a CO₂- rich injection gas stream. These goals were achieved through the following work: • Extensive experimental studies of the reservoir properties and the effects of interaction between CO₂-rich injection gas streams and Field A reservoir fluid measuring properties related to: • Miscibility of the injection gas with Field A reservoir fluid • Solubility and swelling properties of the injection gas with Field A reservoir fluid • Change in viscosity-pressure relationship of Field A reservoir fluid due to addition of injection gas • A reservoir condition core flood experiment • Compositional simulation of the reservoir condition core flood to compare expected recoveries from different injection gases • Development of a set of Minimum Miscibility Pressure (MMP) measurements targeted at correlating the effect of nC₅ on CO₂ MMP. The key findings of this research are as follows: • Miscibility is achievable at practical pressures for Field A and similar reservoir fluids with pure CO₂ or CO₂-rich injection gases. • For Field A reservoir fluid, viscosity of the remaining flashed liquid will increase at pressures below ~2500psi due to mixing the reservoir fluid with a CO₂-rich injection gas stream. • Comparison of injection gases showed that methane rich gases are miscible with Field A so long as a significant quantity of C₃+ components is also present in the gas stream. • There is a defined trend for effect of nC₅ on MMP of impure CO₂. This trend was correlated with an error of less than 4%. • Even though oil composition is taken into account with the base gas MMP, it still affects the trend for effect of nC₅ on MMP of a CO₂-rich gas stream. • An oil characterisation factor was developed to account for this effect, significantly improving the results, reducing the error of the correlation to only 1.6%. The significance of these findings is as follows: • An injection pressure above ~3000psi should be targeted. At these pressures miscibility is achieved and the viscosity of the reservoir fluid injection gas mix is reduced. • CO₂ should be compared to gases such as Tim Gas should after considering the cost of compression, pipeline costs and distance from source to destination will need to be considered. • The addition of nC₅ will reduce the MMP and increase the recovery factor, however the cost of the nC₅ used would be more than the value of increased oil recovered. • The developed correlation for the effect of nC₅ on impure CO₂ MMP can be used broadly within the limits of the correlation. • Further research using more oils is necessary to validate the developed oil characterisation factor and if successful, using the same or similar method used to improve other correlations. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1369016 / Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum, 2009.

[pt] Campos de petróleo com gás não associado do tipo gás condensado possuem destaque pelo maior valor econômico agregado associado a seu recurso energético: a expressiva quantidade de condensado produzida, além do próprio gás. Porém, tais reservatórios possuem um comportamento termodinâmico particular, induzindo mudanças de composição e, consequentemente, fase ao longo do processo de produção por depleção. Nas condições de reservatório, por exemplo, pode ocorrer o fenômeno chamado de condensate blockage, em que bancos de condensado se formam, geralmente em regiões próximas aos poços, dificultando assim o escoamento e afetando a produção de gás. A fim de definirmos a melhor estratégia de gerenciamento de um projeto a ser implementado ao longo da explotação desse tipo de reservatório, uma ferramenta importante utilizada pelos engenheiros é a simulação numérica. Especialmente relacionadas à representação do fenômeno físico-químico citado, nas simulações se utilizam as curvas de permeabilidade relativa. Na realidade, porém, existe uma certa limitação de representatividade do fenômeno nos ensaios laboratoriais praticados pela indústria e os melhores insumos poderiam ser fornecidos por simulações em rede de poros, com modelos que representem a sua alteração com função das mudanças na tensão interfacial e na velocidade de escoamento ao longo do reservatório. A reprodução de uma simulação de escoamento em rede de poros para a escala mais próxima possível em uma simulação de simulador comercial de diferenças finitas é validada. Da simulação em rede de poros até a escala de campo praticada nas simulações de reservatórios, uma metodologia de scale-up é proposta, utilizando um processo de otimização, procurando ser fiel à curva de permeabilidade relativa original, em escala de microporo, obtida simulando fenomenologicamente o processo de condensação no reservatório, através de um modelo que reproduza sua dependência com a velocidade desenvolvida pelas fases em meio poroso. A comparação de produtividades na escala de campo e na evolução da saturação de condensado em regiões próximas aos poços foi apresentada para as três curvas de permeabilidade relativa utilizadas. Os resultados mostram que a metodologia proposta consegue ser mais fiel à influência da condensação no reservatório sobre a produtividade dos poços quando comparada ao insumo de curva de permeabilidade relativa de ensaio laboratorial que apresenta o condensado mais móvel. / [en] Oil fields with non-associated gas like gas condensate type stand out due to the higher added economic value associated with their energy resource: the significant amount of condensate produced, in addition to the gas itself. However, such reservoirs have a particular thermodynamic behavior, inducing changes in composition and, consequently, phase throughout the depletion production process. Under reservoir conditions, for example, the phenomenon called condensate blockage may occur, in which bridges of condensate are formed, usually in regions close to the wells, thus hindering flow and affecting gas production. In order to define the best management strategy for a project to be implemented throughout the exploitation of this type of reservoir, an important tool used by engineers is numerical simulation. The relative permeability curves are used in the simulations, especially related to the representation of the mentioned physical phenomenon. In reality, however, there is a specific limitation of representativeness of the phenomenon in the laboratory tests carried out by the industry, and the best inputs could be provided by simulations in a pore network, with models that represent its alteration as a function of changes in interfacial tension and flow velocity along the reservoir. The reproduction of a pore network flow simulation to the closest possible scale in a commercial finite difference simulation is validated. From the pore network simulation to the field scale practiced in reservoir simulations, a scale-up methodology is proposed, using an optimization process, seeking to be faithful to the original relative permeability curve, on a microporous scale, obtained by simulating phenomenologically the condensation process in the reservoir, using a model that reproduces its dependence on the velocity flow developed by the phases in a porous medium. The three relative permeability curves used were presented by comparing productivities at the field scale and the evolution of condensate saturation in regions close to the wells. The results show that the proposed methodology proves to be more faithful to the influence of condensation in the reservoir on the productivity of the wells when compared to the relative permeability curve input from the laboratory test, which presents the condensate with more mobility.