Browsing by Subject "Capillary"
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Item Analytical and experimental investigation of capillary forces induced by nanopillars for thermal management applications(2010-05) Zhang, Conan; Hidrovo, Carlos H.This thesis presents an analytical and experimental investigation into the capillary wicking limitation of an array of pillars. Commercial and nanopillar wicks are examined experimentally to assess the effects of micro and nanoscale capillary forces. By exerting a progressively higher heat flux on the wick, a maximum achievable mass flow was observed at the capillary limit. Through the balance of capillary and viscous forces, an ab initio analytical model is also presented to support the experimental data. Comparison of the capillary limit predicted by the analytical model and actual limit observed in experimental results are presented for three baseline wicks and two nanowicks.Item Effect of Capillary Heterogeneity on Buoyant Plumes: New Trapping Mechanism in Carbon Sequestration(2009-05) Saadatpoor, Ehsan; Bryant, Steven L.The modes of geologic storage of CO2 are usually categorized as structural, dissolution, residual, and mineral trapping. Here we argue that the heterogeneity intrinsic to sedimentary rocks gives rise to a fifth category of storage, which we call local capillary trapping. Capillary trapping occurs during buoyancy-driven migration of bulk phase CO2 within a saline aquifer. When the rising CO2 plume encounters a region (10-2 to 10+1 m) where capillary entry pressure is locally larger than average, CO2 accumulates beneath the region. This form of storage differs from structural trapping in that much of the accumulated saturation will not escape, should the integrity of the seal overlying the aquifer be compromised. Capillary trapping differs from residual trapping in that the accumulated saturation can be much larger than the residual saturation for the rock. We examine local capillary trapping in a series of numerical simulations. The essential feature is that drainage curves (capillary pressure versus saturation for CO2 displacing brine) are required to be consistent with permeabilities in a heterogeneous domain. In this work we accomplish this with the Leverett J-function, so that each grid block has its own drainage curve, scaled from a reference curve to the permeability and porosity in that block. We find that capillary heterogeneity controls the path taken by rising CO2. The displacement front is much more ramified than in a homogeneous domain, or in a heterogeneous domain with a single drainage curve. Consequently residual trapping is overestimated in simulations that ignore capillary heterogeneity. In the cases studied here, the reduction in residual trapping is compensated by local capillary trapping, which yields larger saturations held in a smaller volume of pore space. Moreover, the amount of CO2 phase remaining mobile after a leak develops in the caprock is smaller. Therefore the extent of immobilization in a heterogeneous formation exceeds that reported in previous studies of buoyancy-driven plume movement.Item Modeling the Effects of Capillary Pressure and the Manipulation of Viscous to Capillary Forces to Recover Residual Saturation Using the Pore N-Let Model(2008-08) Krishnan, Rahul; Lake, Larry W.The difficulty in recovering residual oil is created by (1) the reservoir pore geometry (length, number, and size of tubes and throats), (2) the fluid properties and interfaces, (3) viscous and capillary forces acting on the fluids, and (4) reservoir heterogeneity. This research is intended to expand the pore doublet model and use it to model flow in reservoirs. By first modeling scenarios of simple flow, a better idea of the nature of the pore doublet is gathered. Then the model is expanded to a pore n-let and used with experimental data on mercury injection with the intent of applying it to reservoir models. Further experiments are done with field data taken from the San Juan and Greensburg fields and the following conclusions are made. Capillary forces govern flow in small tubes while viscous forces govern flow in large tubes. Over a distribution of small and large tubes, increasing capillary number will cause larger tubes to flow faster and trap oil in smaller tubes quicker. A strong assumption is made that only large pores will trap oil, and small tubes will displace oil. This assumption leads to complete displacement of the trapped oil over a range of increasing capillary number. Capillary desaturation curves are produced from these calculations and qualitatively agree with curves produced in other work. Results show that displacing residual oil is heavily dependent on pore geometry and pore size distribution. Well sorted distributions caused low initial non-wetting residual saturation, but larger pores required a higher capillary number to remove trapped oil. In most cases, complete desaturation typically occurred over capillary number range of one order of magnitude. These experiments and conclusions are discussed in detail.Item Simulation study of surfactant transport mechanisms in naturally fractured reservoirs(2010-08) Abbasi Asl, Yousef; Pope, Gary A.; Mohanty, Kishore K.Surfactants both change the wettability and lower the interfacial tension by various degrees depending on the type of surfactant and how it interacts with the specific oil. Ultra low IFT means almost zero capillary pressure, which in turn indicates little oil should be produced from capillary imbibition when the surfactant reduces the IFT in naturally fractured oil reservoirs that are mixed-wet or oil-wet. What is the transport mechanism for the surfactant to get far into the matrix and how does it scale? Molecular diffusion and capillary pressure are much too slow to explain the experimental data. Recent dynamic laboratory data suggest that the process is faster when a pressure gradient is applied compared to static tests. A mechanistic chemical compositional simulator was used to study the effect of pressure gradient on chemical oil recovery from naturally fractured oil reservoirs for several different chemical processes (polymer, surfactant, surfactant-polymer, alkali-surfactant-polymer flooding). The fractures were simulated explicitly by using small gridblocks with fracture properties. Both homogeneous and heterogeneous matrix blocks were simulated. Microemulsion phase behavior and related chemistry and physics were modeled in a manner similar to single porosity reservoirs. The simulations indicate that even very small pressure gradients (transverse to the flow in the fractures) are highly significant in terms of the chemical transport into the matrix and that increasing the injected fluid viscosity greatly improves the oil recovery. Field scale simulations show that the transverse pressure gradients promote transport of the surfactant into the matrix at a feasible rate even when there is a high contrast between the permeability of the fractures and the matrix. These simulations indicate that injecting a chemical solution that is viscous (because of polymer or foam or microemulsion) and lowers the IFT as well as alters the wettability from mixed-wet to water-wet, produces more oil and produces it faster than static chemical processes. These findings have significant implications for enhanced oil recovery from naturally fractured oil reservoirs and how these processes should be optimized and scaled up from the laboratory to the field.