Carbonate rocks contain most of the world&rsquo / s proven hydrocarbon reserves. It is essential to predict flow properties and understand flow mechanisms in carbonates for estimating hydrocarbon recovery accurately. Pore network modeling is an effective tool in determination of flow properties and investigation of flow mechanisms. Topologically equivalent pore network models yield accurate results for flow properties. Due to their simple pore structure, sandstones are generally considered in pore scale studies and studies involving carbonates are limited. In this study, in order to understand flow mechanisms and wettability effects in heterogeneous carbonate rocks, a novel pore network model was developed for simulating two-phase flow. The constructed model was composed of matrix, fissure and vug sub domains and the sequence of fluid displacements was simulated typical by primary drainage followed by water flooding. Main mechanisms of imbibition, snap-off, piston like advance and pore body filling, were also considered. All the physically possible fluid configurations in the pores, vugs and fissures for all wettability types were examined. For configurations with a fluid layer sandwiched between other phases, the range of capillary pressures for the existence of such a layer was also evaluated. Then, results of the proposed model were compared with data available in literature. Finally, effects of wettability and pore structure on flow properties were examined by assigning different wettability conditions and porosity features. It was concluded that the proposed pore network model successfully represented two phase flow in fissured and vuggy carbonate rocks.

In this study a hybrid Pore Network (PN) model that simulates two-phase (water-oil) drainage and imbibition mechanisms is developed. The developed model produces Nuclear Magnetic Resonance (NMR) T2 relaxation times using correlations available in the literature. The developed PN was calibrated using experimental relative permeability data obtained for Berea Sandstone, Kuzey Marmara Limestone, Yenik&ouml / y Dolostone and Dolomitic Limestone core plugs. Pore network body and throat parameters were obtained from serial computerized tomography scans and thin section images. It was observed that pore body and throat sizes were not statistically correlated. It was also observed that the developed PN model can be used to model different displacement mechanisms. By using the synthetic data obtained from PN model, an Artificial Neural Network (ANN) model was developed and tested. It has been observed that the developed ANN tool can be used to estimate oil &ndash / water relative permeability data very well (with less than 0.05 mean square error) given a T2 signal. It was finally concluded that the developed tools can be used to obtain multiphase flow functions directly from an NMR well log such as Combinable Magnetic Resonance (CMR).

Chemical treatments using solvents and surfactants can be used to increase the productivity of gas-condensate wells with condensate banks. CMG’s compositional simulator GEM was used to simulate such treatments to gain a better understanding of design questions such as how much treatment solution to inject and to predict the benefits of such treatments. GEM was used to simulate treatments in vertical wells with and without hydraulic fractures and also horizontal wells. However, like other commercial compositional simulators, the flash calculations used to predict the phase behavior is limited to two phases whereas a three-phase flash is needed to accurately model the complex phase behavior that occurs during and after the injection of treatment solutions. UTCOMP is a compositional simulator with three-phase flash routine and attempts were made to use it to simulate such well treatments. However, this is a very difficult problem to simulate and all previous attempts failed because of numerical problems caused by inconsistent phase labeling (so called phase flipping) and the discontinuities this causes in the relative permeability values. In this research, a new relative permeability model based on molar Gibbs free energy was developed, implemented in a compositional simulator and applied to several difficult three-phase flash problems. A new way of modeling the residual saturations was needed to ensure a continuous variation of the residual saturations from the three-phase region to the two-phase region or back and was included in the new model. The new relative permeability model was implemented in the compositional reservoir simulator UTCOMP. This new relative permeability model makes it is unnecessary to identify and track the phases. This method automatically avoids the previous phase flipping problems and thus is physically accurate as well as computationally faster due to the improved numerical performance. The new code was tested by running several difficult simulation problems including a CO2 flood with three-hydrocarbon phases and a water phase. A new framework for doing flash calculations was also developed and implemented in UTCOMP to account for the multiple roots of the cubic equation-of-state to ensure a global minimum in the Gibbs free energy by doing an exhaustive search for the minimum value for one, two and three phases. The purpose was to determine if the standard method using a Gibbs stability test followed by a flash calculation was in fact resulting in the true minimum in the Gibbs free energy. Test problems were run and the results of the standard algorithm and the exhaustive search algorithm compared. The updated UTCOMP simulator was used to understand the flow back of solvents injected in gas condensate wells as part of chemical treatments. The flow back of the solvents, a short-term process, affects how well the treatment works and has been an important design and performance question for years that could not be simulated correctly until now due to the limitations of both commercial simulators and UTCOMP. Different solvents and chase gases were simulated to gain insight into how to improve the design of the chemical treatments under different conditions. / text

Gas wells suffer a decrease in productivity because of the formation of a liquid hydrocarbon “condensate” in the near wellbore area. This "condensate" forms near producing wells when the flowing pressure is below the reservoir fluid's dew point. Several methods have been shown to temporarily alleviate this problem, but eventually the condensate bank reforms and the productivity again decreases. The use of surfactants to alter the near wellbore wettability to neutral wetting is a potential longer term solution to liquid blocking in these reservoirs. This alteration increases the gas and liquid relative permeabilities and thereby the productivity by reducing the residual liquid saturation. This enhancement allows the accumulated liquid to flow and is durable as long as the wettability alteration is persistent. This solution has been shown to be successful through core flood experiments and field trials in high permeability sandstones, but no improvements had been observed in low permeability cores. As the global demand for energy increases, the petroleum industry has begun to develop unconventional (low permeability) assets, new techniques are needed to maintain and improve their productivity. Liquid blocking in these wells can have a much larger impact on both the gas and condensate production in such low permeability formations. Applying this technique increases both gas and condensate mobility and should increase the economic producing life of these wells. Core flood experiments were conducted to investigate the ability of a chemical treatment to alter the wettability of low permeability sandstones. Previous experimentation did not find any improvement because the increased capillary forces prevented the treatment solution from being easily displaced. This concealed the benefit achieved when the wettability was altered. These experiments recorded smaller relative permeability increases compared to higher permeability core floods, so super critical carbon dioxide was tested as an alternative solvent. While the new treatment was more injectable, it was not as successful at altering wettability. Progress has been made on a solution to liquid blocking in low permeability sandstones, but additional research needs to be completed to further optimize this method. / text

Depressurization is thought to be a promising method for gas recovery from methane hydrate reservoirs, but considerable water production is expected when this method is applied to the hydrate reservoir of high initial water saturation. In this case, the prediction of water production is a critical problem. This study examined relative permeability curves during hydrate dissociation by comparing numerical simulations with laboratory experiments. Data of gas and water volumes produced during depressurization were taken from gas recovery experiments using sand-packed cores containing methane hydrates. In each experiment, hydrates were dissociated by depressurization at a constant pressure. The surrounding temperature was held constant during dissociation. The volumes of gas and water produced, the temperatures inside of the core, and the pressures at the both ends of the core were measured continuously. The experimental results were compared with numerical simulations by using the simulator MH21-HYDRES (MH21 Hydrate Reservoir Simulator). The experimental results showed that considerable volume of water was produced during hydrate dissociation, and the simulator could not reproduce the large water production when we used typical relative permeability curves such as the Corey model. To obtain good matching for the volumes of gas and water produced during hydrate dissociation, the shape of relative permeability curves was modified to express the rapid decrease in gas permeability with increasing water saturation. This result suggests that the connate water can be easily displaced by hydrate-dissociated gas and move forward in the hydrate reservoir of high initial water saturation.

In the history of a reservoir, after the period of primary production, about 30 to 40%, of the original oil in place may be produced using a secondary recovery mechanism. Polymer injection, which is classified as a tertiary method, can be applied to the remaining oil in place. In this thesis, oil/water relative permeabilities, effect of polymer injection on end point relative permeabilities and residual oil saturations in heterogeneous carbonate reservoirs were investigated. Numereous core flood experiments were conducted on different heteroegneous carbonate cores taken from Midyat Formation. Before starting the displacement experiments, porosity, permeability and capillary pressure experiments were performed. The heterogeneity of the cores are depicted from thin sections. Besides the main aim stated above, effect of flow rate and fracture presence on end point relative permeability and on residual oil saturation and were investigated. According to the results of the displacement tests, end point hexane relative permeability increased when polymer solution was used as the displacing phase.Besides, end point hexane relative permeability increased with polymer injection and fracture presence.

[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.

The primary objective of this research is to develop a mathematical framework that could be used to model or predict the rate of fluid absorption and release in fibrous sheets made up of solid or porous fibers. In the first step, a two-scale two-phase modeling methodology is developed for studying fluid release from saturated/unsaturated thin fibrous media made up of solid fibers when brought in contact with a moving solid surface. Our macroscale model is based on the Richards’ equation for two-phase fluid transport in porous media. The required constitutive relationships, capillary pressure and relative permeability as functions of the medium’s saturation, are obtained through microscale modeling. Here, a mass convection boundary condition is considered to model the fluid transport at the boundary in contact with the target surface. The mass convection coefficient plays a significant role in determining the release rate of fluid. Moreover the release rate depends on the properties of the fluid, fibrous sheet, the target surface as well as the speed of the relative motion, and remains to be determined experimentally. Obtaining functional relationships for relative permeability and capillary pressure is only possible through experimentation or expensive microscale simulations, and needs to be repeated for different media having different fiber diameters, thicknesses, or porosities. In this concern, we conducted series of 3-D microscale simulations in order to investigate the effect of the aforementioned parameters on the relative permeability and capillary pressure of fibrous porous sheets. The results of our parameter study are utilized to develop general expressions for kr(S) and Pc(S). Furthermore, these general expressions can be easily included in macroscale fluid transport equations to predict the rate of fluid release from partially saturated fibrous sheets in a time and cost-effective manner. Moreover, the ability of the model has been extended to simulate the radial spreading of liquids in thin fibrous sheets. By simulating different fibrous sheets with identical parameters but different in-plane fiber orientations has revealed that the rate of fluid spread increases with increasing the in-plane alignment of the fibers. Additionally, we have developed a semi-analytical modeling approach that can be used to predict the fluid absorption and release characteristics of multi-layered composite fabric made up of porous (swelling) and soild (non-swelling) fibrous sheets. The sheets capillary pressure and relative permeability are obtained via a combination of numerical simulations and experiment. In particular, the capillary pressure for swelling media is obtained via height rise experiments. The relative permeability expressions are obtained from the analytical expressions previously developed with the 3-D microscale simulations, which are also in agreement with experimental correlations from the literature. To extend the ability of the model, we have developed a diffusion-controlled boundary treatment to simulate fluid release from partially-saturated fabrics onto surfaces with different hydrophilicy. Using a custom made test rig, experimental data is obtained for the release of liquid from partially saturated PET and Rayon nonwoven sheets at different speeds, and on two different surfaces. It is demonstrated that the new semi-empirical model redeveloped in this work can predict the rate of fluid release from wet nonwoven sheets as a function of time.

Non-Aqueous Phase Liquids (NAPLs) include commonly occurring organic contaminants such as gasoline, diesel fuel and chlorinated solvents. When released to subsurface environments their spreading is a complex process of multi-component, multi-phase flow. This work has strived to develop new models and methods to describe the spreading of NAPLs in heterogeneous geological media. For two-phase systems, infiltration and immobilisation of NAPL in stochastically heterogeneous, water-saturated media were investigated. First, a methodology to continuously measure NAPL saturations in space and time in a two-dimensional experiment setup, using multiple-energy x-ray-attenuation techniques, was developed. Second, a set of experiments on NAPL infiltration in carefully designed structures of well-known stochastic heterogeneity were conducted. Three detailed data-sets were generated and the importance of heterogeneity for both flow and the immobilised NAPL architecture was demonstrated. Third, the laboratory experiments were modelled with a continuum- and Darcy’s-law-based multi-phase flow model. Different models for the capillary pressure (Pc) – fluid saturation (S) – relative permeability (kr) constitutive relations were compared and tested against experimental observations. A method to account for NAPL immobility in dead-end pore-spaces during drainage was introduced and the importance of accounting for hysteresis and NAPL entrapment in the constitutive relations was demonstrated. NAPL migration in three-phase, water-NAPL-air systems was also studied. Different constitutive relations used in modelling of three-phase flow were analysed and compared to existing laboratory data. To improve model performance, a new formulation for the saturation dependence of tortuosity was introduced and different scaling options for the Pc-S relations were investigated. Finally, a method to model the spreading of multi-constituent contaminants using a single-component multi-phase model was developed. With the method, the migration behaviour of individual constituents in a mixture, e.g. benzene in gasoline, could be studied, which was demonstrated in a modelling study of a gasoline spill in connection with a transport accident. / Flerfasföroreningar innefattar vanligt förekommande organiska vätskor som bensin, dieselolja och klorerade lösningsmedel. Spridningen av dessa föroreningar i mark är komplicerad och styrs av det samtidiga flödet av organisk vätska, vatten och markluft samt utbytet av komponenter (föroreningar) mellan de olika faserna. Detta arbete syftade till att utveckla nya metoder och modeller för att studera spridningen av flerfasföroreningar i mark: (i) En metodik utvecklades för att i laboratorium noggrant och kontinuerligt mäta hur en organisk vätska är rumsligt fördelad i en tvådimensionell experimentuppställning. Metoden baserades på röntgenutsläckning för olika energinivåer. (ii) Infiltration av organisk vätska i vattenmättade medier studerades för olika konfigurationer av geologisk heterogenitet. I experimentuppställningen packades olika sandmaterial noggrant för att konstruera en välkänd, stokastiskt heterogen struktur. Spridningsprocessen dokumenterades i tre detaljerade mätserier och heterogenitetens påverkan på flöde och kvarhållning av den organiska vätskan påvisades. (iii) Experimenten simulerades med en numerisk modell. Olika modeller prövades för att beskriva de grundläggande relationerna mellan kapillärtryck (Pc) vätskehalt (S) och relativ permeabilitet (kr) för detta tvåfassystem av vatten och organisk vätska. En relation infördes för att beskriva partiell orörlighet hos den organiska vätskan i porer vars halsar tillfälligt blockeras av vatten då mediet avvattnas. Vikten av att i de grundläggande relationerna ta hänsyn till hysteresis och kvarhållning av organisk fas visades. (iv) Olika Pc-S-kr relationer för trefassystem av vatten, organisk vätska och markluft testades mot befintliga experimentella data. En ny relation för hur slingrigheten (eng. tortuosity) beror av vätskehalten infördes i kr-S relationen och olika möjligheter för att skala Pc-S relationen analyserades. (v) En modelleringsmetodik utvecklades för att studera spridningen av flerkomponentsföroreningar. Med metoden kunde spridningsbeteendet hos enskilda, särskilt skadliga komponenter som t.ex. bensen särskiljas då ett bensinutsläpp i samband med en transportolycka simulerades.

Producing since 1995, Bozova Field is a mature oil field to be re-evaluated. When evaluating an oil field, the common approach followed in a reservoir simulation study is: Generating a geological model that is expected to represent the reservoir / building simulation models by using the most representative dynamic data / and doing sensitivity analysis around a best case in order to get a history-matched simulation model. Each step deals with a great variety of uncertainty and changing one parameter at a time does not comprise the entire uncertainty space. Not only knowing the impact of uncertainty related to each individual parameter but also their combined effects can help better understanding of the reservoir and better reservoir management. In this study, uncertainties associated only to fluid properties, rock physics functions and water oil contact (WOC) depth are examined thoroughly. Since sensitivity analysis around a best case will cover only a part of uncertainty, a full factorial experimental design technique is used. Without pursuing the goal of a history matched case, simulation runs are conducted for all possible combinations of: 19 sets of capillary pressure/relative permeability (Pc/krel) curves taken from special core analysis (SCAL) data / 2 sets of pressure, volume, temperature (PVT) analysis data / and 3 sets of WOC depths. As a result, historical production and pressure profiles from 114 (2 x 3 x 19) cases are presented for screening the impact of uncertainty related to aforementioned parameters in the history matching of Bozova field. The reservoir simulation models that give the best match with the history data are determined by the calculation of an objective function / and they are ranked according to their goodness of fit. It is found that the uncertainty of Pc/krel curves has the highest impact on the history match values / uncertainty of WOC depth comes next and the least effect arises from the uncertainty of PVT data. This study constitutes a solid basis for further studies which is to be done on the selection of the best matched models for history matching purposes.