Browsing by Subject "Interfacial tension"
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Item Characterization of nanoparticle transport in flow through permeable media(2012-05) Metin, Cigdem; Nguyen, Quoc P.An aqueous nanoparticle dispersion is a complex fluid whose mobility in porous media is controlled by four key factors: the conditions necessary for the stability of nanoparticle dispersions, the kinetics of nanoparticle aggregation in an unstable suspension, the rheology of stable or unstable suspensions, and the interactions between the nanoparticles and oil/water interface and mineral surfaces. The challenges in controlling nanoparticle transport come from the variations of pH and ionic strength of brine, the presence of stationary and mobile phases (minerals, oil, water and gas), the geochemical complexity of reservoir rocks, and pore-network. The overall objective of this work is to achieve a better understanding of nanoparticle transport in porous media based on a systematic experimental and theoretical study of above factors. For this purpose, the critical conditions for the aqueous stability of nanoparticles are identified and fit by a theoretical model, which describes the interaction energy between silica nanoparticles. Above critical conditions nanoparticle aggregation becomes significant. A model for the aggregation kinetics is developed and validated by experiments. A mechanistic model for predicting the viscosity of stable and unstable silica nanoparticle dispersions over a wide range of solid volume fraction is developed. This model is based on the concept of effective maximum packing fraction. Adsorption experiments with silica nanoparticles onto quartz, calcite and clay surfaces and interfacial tension measurements provide insightful information on the interaction of the nanoparticles with minerals and decane/water interface. The extent of nanoparticle adsorption on mineral/water and decane/water interfaces is evaluated based on DLVO theory and Gibbs’ equation. Visual observations and analytical methods are used to understand the interaction of nanoparticles with clay. The characterization of nanoparticle behavior in bulk phases is built into an understanding of nanoparticle transport in porous media. In particular, the rheology of nanoparticle dispersions flowing through permeable media is compared with those determined using a rheometer. In the presence of residual oil, the retention of silica nanoparticles at water/oil interface during steady flow is investigated. The results from batch experiments of nanoparticle adsorption are used to explain the flow behavior of these nanoparticles in a glass bead pack at residual oil saturation.Item Development of High-Performance Surfactants for Difficult Oils(2007-12) Zhao, Ping; Pope, Gary A.Several novel surfactants have shown excellent performance in tests using several crude oils that have properties, such as high wax content, that make high oil recovery with surfactants very difficult. High carbon-number, internal olefin sulfonates, when used with appropriate co-surfactants, co-solvents and alkali, produced the type of phase behavior and ultra-low interfacial tension needed for almost 100% oil recovery from laboratory core experiments. These surfactants could be used at both low and high temperatures and showed low retention in cores. This work demonstrates how the performance of both surfactant-polymer and alkaline-surfactant-polymer floods can be dramatically improved at the same or lower costs associated with conventional surfactants and co-solvents and at a wider range of reservoir conditions viiiThe identification of high-performance surfactants suitable for high-temperature and/or paraffinic oil applications opens up the potential to recover a vast amounts of additional oil outside the range of conditions considered practical in the past. High carbon number internal olefin sulfonates gave good performance at low concentrations and were found to be compatible with both polymers and alkali such as sodium carbonate. The identification of high-performance surfactants suitable for high-temperature and/or paraffinic oil applications opens up the potential to recover a vast amount of additional oil outside the range of conditions considered practical in the past.Item Effects of surfactant partition coefficient and interfacial tension on the oil displacement in low-tension polymer flooding(2021-08-12) Liu, Mingyan (M.S. in engineering); Okuno, Ryosuke, 1974-Complex surfactant formulations have been applied to generate an ultra-low interfacial tension (IFT) (e.g., 10⁻³ mN/m) between the displacing water phase and the displaced oil phase in chemical enhanced oil recovery (CEOR), where the residual oil after waterflooding can be largely recovered as an oil bank. This thesis is concerned with a simpler, lower-cost CEOR, in which a sole additive of surface active solvent (SAS) makes low-tension displacement fronts in polymer flooding (e.g., 10⁻² mN/m) without involving ultra-low IFT microemulsion phase behavior. The main objective of this research is to technically verify such low-tension polymer (LTP) flooding for a secondary-mode oil displacement through a sandpack of 9.5 Darcy. Previous research found that 2-ethylhexanol-7PO-15EO (2-EH-7PO-15EO, or “7-15”) as SAS was able to reduce the IFT between polymer solution and reservoir oil from 15.8 mN/m to 0.025 mN/m. In this research, the effect of SAS partition coefficient on LTP flooding was studied as an additional factor for SAS optimization. In particular, the comparison between two SAS species, 2-EH-4PO-15EO (4-15) and 2-EH-7PO-25EO (7-25), was important, because they had similar IFT values, but markedly different partition coefficients. The IFT was 0.18 mN/m with 4-15 and 0.20 mN/m with 7-25; and the partition coefficients were 1.61 with 4-15 and 0.68 with 7-25 at the experimental temperature, 61°C. These two SAS species were compared in secondary-mode LTP flooding with a slug of 0.5 wt% SAS for 0.5 pore-volumes injected (PVI). The oil recovery factor at 1.0 PVI was 65% with 4-15 and 67% with 7-25. At 5.0 PVI, it was 74% with 4-15 and 84% with 7-25. Although these two SAS species gave similar IFT values, their oil-displacement efficiencies were quite different because 7-25 propagated more efficiently in the sandpack with the smaller partition coefficient. The smaller partition coefficient helped the SAS flow more efficiently in the aqueous phase with less retention in the remaining oil. Optimization of SAS likely requires taking a balance between lowering the partition coefficient and lowering the IFT. The SAS recovery at the effluent was 61% for the 4-15 SAS and 78% for the 7-25 SAS. The propagation of the 4-15 SAS was retarded approximately by 1.0 PVI in comparison to that of the 7-25 SAS. The adsorption of the 4-15 and 7-25 SAS was 0.019 mg/g sandpack and 0.020 mg/g sandpack, respectively. With a similar IFT reduction, the SAS with a smaller partition coefficient (i.e., 7-25) resulted in less retention, less retardation, and more oil production for a given amount of injection.Item Experimental evaluation of surface treated nanoparticles and their effect on wettability alteration of carbonate surfaces and oil-brine interfacial tension(2016-08) Alramadan, Hamdi Ahmed; DiCarlo, David Anthony, 1969-; Mohanty, Kishore KThe alteration of rock surface wettability and the reduction of oil/brine interfacial tension enhances oil recovery from the reservoir. Most of the carbonate rock reservoirs around the world are oil-wet and changing their wettability may enhance oil recovery. Moreover, nanoparticles have presented a promising potential in enhanced oil recovery applications. An experimental study of contact angle changes upon exposure to nanoparticles on carbonate surfaces that are dispersed in brine solution has been conducted using various nanoparticle solutions, some of which were in-house synthesized. Also, interfacial tension measurements and calculations were implemented using the pendant drop method to study the effect of the invading nanoparticles solution. Nanoparticle concentrations were varied and progress was monitored with time. Effects of nanoparticle size, grafting coverage and mixed chemicals as well as observations are discussed. Two hypotheses were proposed for the wettability alteration mechanisms.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.