Browsing by Subject "Capillary pressure"
Now showing 1 - 4 of 4
Results Per Page
Sort Options
Item Compositional three-phase relative permeability and capillary pressure models using Gibbs free energy(2016-08) Sadeghi Neshat, Sajjad; Pope, G. A.; Ezekoye, Ofodike E.; Lake, LarryBoth relative permeability and capillary pressure depend on composition as well as saturation, but classical models neglect this dependence. The objective of this research was to develop coupled three-phase relative permeability and capillary pressure models for implementation in a four-phase flow compositional equation-of-state simulator. The models applied to several complex but practical reservoir simulation problems. Models independent of phase label have many advantages in terms of both numerical stability and physical consistency. Identification of hydrocarbon and aqueous phases based on their molar Gibbs Free Energy (GFE) is a key feature of the new model. Instead of using labels (gas/oil/2nd liquid/aqueous) to define permeability parameters such as end points, residual saturation and exponents, the parameters are continuously interpolated between reference values using the Gibbs free energy of each phase at each time step. Consequently, the formulation used to implement other relevant physical parameters must be consistent with the new approach. A comprehensive but simple vii algorithm was developed for this purpose. The algorithm allows for very general threephase hysteresis in both relative permeability and capillary pressure. An important part of this thesis is analyzing the results of a recent series of experiments on the effect composition on relative permeability. These new data were used to calibrate the new GFE relative permeability model and apply it in a compositional reservoir simulator. The robustness of the new GFE model was shown through complex simulations such as solvent flooding, miscible/immiscible WAG processes, well stimulation processes using solvents to remove condensate and/or water blocks in both conventional and unconventional formations and other challenging applications involving both mass transfer between phases and phase changes. The interpolation of relative permeability parameters based on GFE instead of phase labels completely solves the discontinuity problem caused by phase flipping or misidentification. Therefore, simulations run significantly faster and are physically correct. The novelty of this research is in integrating and unifying relevant physical parameters including trapping number, hysteresis and capillary pressure into one rigorous algorithm with compositional consistency and in the development and application of a practical procedure for numerical compositional reservoir simulations.Item Local capillary trapping in geological carbon storage(2012-08) Saadatpoor, Ehsan, 1982-; Bryant, Steven L.; Sepehrnoori, Kamy, 1951-After the injection of CO₂ into a subsurface formation, various storage mechanisms help immobilize the CO₂. Injection strategies that promote the buoyant movement of CO₂ during the post-injection period can increase immobilization by the mechanisms of dissolution and residual phase trapping. In this work, we argue that the heterogeneity intrinsic to sedimentary rocks gives rise to another category of trapping, which we call local capillary trapping. In a heterogeneous storage formation where capillary entry pressure of the rock is correlated with other petrophysical properties, numerous local capillary barriers exist and can trap rising CO₂ below them. The size of barriers depends on the correlation length, i.e., the characteristic size of regions having similar values of capillary entry pressure. This dissertation evaluates the dynamics of the local capillary trapping and its effectiveness to add an element of increased capacity and containment security in carbon storage in heterogeneous permeable media. The overall objective is to obtain the rigorous assessment of the amount and extent of local capillary trapping expected to occur in typical storage formations. A series of detailed numerical simulations are used to quantify the amount of local capillary trapping and to study the effect of local capillary barriers on CO₂ leakage from the storage formation. Also, a research code is developed for finding clusters of local capillary trapping from capillary entry pressure field based on the assumption that in post-injection period the viscous forces are negligible and the process is governed solely by capillary forces. The code is used to make a quantitative assessment of an upper bound for local capillary trapping capacity in heterogeneous domains using the geologic data, which is especially useful for field projects since it is very fast compared to flow simulation. The results show that capillary heterogeneity decreases the threshold capacity for non-leakable storage of CO₂. However, in cases where the injected volume is more than threshold capacity, capillary heterogeneity adds an element of security to the structural seal, regardless of how CO₂ is accumulated under the seal, either by injection or by buoyancy. In other words, ignoring heterogeneity gives the worst-case estimate of the risk. Nevertheless, during a potential leakage through failed seals, a range of CO₂ leakage amounts may occur depending on heterogeneity and the location of the leak. In geologic CO₂ storage in typical saline aquifers, the local capillary trapping can result in large volumes that are sufficiently trapped and immobilized. In fact, this behavior has significant implications for estimates of permanence of storage, for assessments of leakage rates, and for predicting ultimate consequences of leakage.Item Scale effects on the latent heat of phase change & the effect of dynamic contact angles on dynamic capillary pressure(2014-12) Shin, Jeong-Heon; Deinert, Mark; Shi, Li; DiCarlo, David; Halil Berberoglu; Bogard, David G.Surface tension is an important material property that affects the behavior of micro/nano size thermal-fluid systems. In this dissertation, I investigate how surface tension affects the latent heat of a phase change in nanoscale systems as well as on the movement of water in microstructures. Classical thermodynamic models were developed to describe how the latent heat of melting in nano-pores depends on scale and were extended to the melting of metallic nano-particles. The results from these models were verified by comparison with experimental data from the open literature for hydrocarbons and water in nano-size pores, as well as for free standing metallic nano particles. A classical thermodynamic model was also developed to describe how the latent heat of vaporization depends on scale. This was verified experimentally using a Thermogravimetric Analysis/Differential Scanning Calorimeter available in the core facilities of the Texas Materials Institute. This verified that the latent heat of vaporization for water confined nano-pores decreases with pore size. A model for dynamic capillary pressure in porous media was analyzed using experimentally derived data for the velocity dependent contact angle of water on SiO₂ glass. The data were derived from images of microfluidic flows in capillary tubes, obtained using high speed digital microscopy.Item Semi-analytical estimates of permeability obtained from capillary pressure(Texas A&M University, 2006-04-12) Huet, Caroline CecileThe objective of this research is to develop and test a new concept for predicting permeability from routine rock properties. First, we develop a model predicting permeability as a function of capillary pressure. Our model, which is based on the work by Purcell, Burdine and Wyllie and Gardner models, is given by: (Equation 1 - See PDF) Combining the previous equation and the Brooks and Corey model for capillary pressure, we obtain: (Equation 2 - See PDF) The correlation given by this equation could yield permeability from capillary pressure (and vice-versa). This model also has potential extensions to relative permeability (i.e., the Brooks and Corey relative permeability functions) - which should make correlations based on porosity, permeability, and irreducible saturation general tools for reservoir engineering problems where relative permeability data are not available. Our study is validated with a large range/variety of core samples in order to provide a representative data sample over several orders of magnitude in permeability. Rock permeabilities in our data set range from 0.04 to 8700 md, while porosities range from 0.3 to 34 percent. Our correlation appears to be valid for both sandstone and carbonate lithologies.