Development and Verification of an Enhanced Equation of State in TOUGH2

A reservoir-geomechanics coupled simulation tool is required to interpret and predict stimulation and production performance in unconventional reservoirs in a physically rigorous manner. This work presents a simulation platform by integrating a multiphase fluid flow and heat transport code (TOUGH2) with a geomechanics code (FLAC3D) using an iteratively coupled method. In the communication between the two codes during coupled simulation, the fluid pressure, saturation, temperature and capillary pressure are transferred from the reservoir simulation code to the geomechanics code, which feedbacks updated variables, such as stresses, strains, porosity and permeability, to the reservoir simulation code in return. To optimize the communication process, a generic mesh generator was developed and added to the platform so that two identical computational meshes will be used in both reservoir and geomechanics models in a coupled simulation. The equation of state was significantly enhanced for modeling gas reservoir more appropriately. The development was verified and validated using four well-defined problems that are related to fluid diffusion, thermal conduction, thermal fluid conduction and convection, and fluid-geomechanics interaction, respectively. The first three problems were verified with analytical solutions and the fourth one was validated with laboratory measurements.

Effect of capillary pressure and geomechanics on multiphase fluid flow in rocks

<p>Understanding interactions between rock and fluids is important for many applications including CO<sub>2</sub> storage in the subsurface. Today significant effort is aimed at research on CO<sub>2</sub> flow through low-permeable shale formations. In some experiments, CO<sub>2</sub> is injected in a shale sample at a constant rate, and the upstream pressure exhibits rise until a certain moment followed by a decline, representing the so called breakthrough phenomenon. After the breakthrough, downstream flux significantly rises. This behavior was thought to be the result of fracture occurence or mechanical effects. <br><br>Here, we present a 3D numerical model of flow through experiments in shale. Our model accounts for poroelastic compaction/decompaction of shale, its time-dependent permeability, and two-phase flow, the fluid phases being CO<sub>2</sub> and air. The model also accounts for a capillary entry pressure threshold observed in experiments. The key feature of the model are saturation-based relative permeabilities which result in sharp overall permeability increases as the CO<sub>2</sub> moves through the shale sample. The model is implemented for 3D calculations with the finite volume method. Our results show that CO<sub>2</sub> breakthrough is a natural outcome of two-phase fluid flow dynamics and does not need a fracture to exhibit pressure behavior observed in experiments.</p>

Pressure Drop Determination for Multiphase Flow in a Vertical Well Tubing

Several studies have been carried out, by researchers to predict multiphase flow pressure drop in the oil and gas industry, but yet there seems to be one being generally acceptable for accurate prediction of pressure drop. This is as a result of some constraints in each of these models, which makes the pressure drop predicted by the model far from accurate when compared to measured data from the field. This study is aimed at developing a multiphase fluid flow model in a vertical tubing using the Duns and Ros flow model. Data from six wells were utilized in this study and results obtained from the Modified model compared with that of Duns and Ros model along other models. From the result, it was observed that the newly developed model (Modified Duns and Ros Model) gives more accurate result with a R-squared value of 0.9936 over the other models. The Modified model however, is limited by the choice of correlations used in the computation of fluid properties.

An extension of the multiple marker algorithm for study of phase separation problems at the mesoscale

Multiphase fluid flow is an active field of research in numerous branches of science and technology. An interesting subset of multiphase flow problems involves the dispersion of one phase into another in the form of many small bubbles or droplets, and their subsequent separation back into bulk phases after this has occurred. Phase dispersion may be a desirable effect, for example in the production of emulsions of otherwise immiscible liquids or to increase interfacial surface area for chemical reactions, or an undesirable one, for example in the intermixing of waste and product phases during processing or the generation of foams preventing gas-liquid decoupling. The present paper describes a computational fluid dynamics method based on the multiple marker front-capturing algorithm – itself an extension of the volume-of-fluids method for multiphase flow – which is capable of scaling to mesoscale systems involving thousands of droplets or bubbles. The method includes sub-grid models for solution of the Reynolds equation to account for thin film dynamics and rupture. The method is demonstrated with an implementation in the OpenFOAM® computational mechanics framework. Comparisons against empirical data are presented, together with a performance benchmarking study and example applications.