Browsing by Author "Kumar, Saket"

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    A novel oil-in-water drilling mud formulated with extracts from Indian mango seed oil
    (2019-09-12) Kumar, Saket; Thakur, Aarti; Kumar, Nitesh; Husein, Maen M
    Abstract Drilling muds with less environmental impact are highly desired over conventional diesel-based mud systems, especially in light of the emerging strict environmental laws. In this article, a novel oil-in-water (O/W) emulsion drilling fluid formulated with a methyl ester extracted from Indian mango seed oil was evaluated. The effect of the weight percent of different constituents of the emulsion/suspension including the oil phase, bentonite, and polyanionic cellulose polymer on the rheology and the fluid loss was examined. The methyl ester oil phase/mud system displayed superior physical, chemical, rheological and filtration properties relative to the diesel and the mango seed oil. Eco-toxicity of the methyl ester and diesel (O/W) emulsion mud systems was assessed using the acute lethal concentration test. The Indian mango methyl ester (O/W) emulsion mud displayed much less impact on fish population. Flow characteristics collected from the flow model at 85 °C suggested excellent shear thinning behavior of the Indian mango methyl ester (IMME) (O/W) emulsion mud. Moreover, the IMME (O/W) emulsion displayed strong pseudoplastic behavior, an attractive feature in a drilling mud, with increasing clay content and polymer concentration. The methyl ester mud was thermally stable over a wide range of the constituent concentrations. Furthermore, a particle size analysis revealed that engineered drilling muds targeting suspension of particles with certain size range can be formulated by changing the volume fraction of the methyl ester in the mud system.
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    Effect of Temperature on Two-Phase Gas/Oil Relative Permeability in Unconsolidated Sand
    (2021-09-10) Kumar, Saket; Sarma, Hemanta; Maini, Brij; Kantzas, Apostolos; Mehta, Sudarshan
    Thermal Enhanced Oil Recovery (TEOR) for oil sands incurs simultaneous flow of oil and steam (mimics gaseous phase) with elevation in temperature. Many studies are reported for temperature effect on two-phase water/oil relative permeability despite knowing that steam or vapor is conventionally injected, mimicking the gaseous phase during heavy oil recovery. Thus, this requires the knowledge of temperature effect on two-phase gas/liquid relative permeability as well. Limited studies are reported in the standard literature regarding the temperature dependency of relative permeability in gas/liquid systems; still no census about it. Therefore, the temperature dependency of two-phase gas/liquid relative permeability was examined in this study using isothermal displacement tests at varying temperatures from 337 to 405 K (64 to 132 oC). This study employed Poly Alpha Olefin (PAO-100) as the oleic phase, deionized water as the immobile phase, and nitrogen gas as the displacing phase in a clean unconsolidated sandpack composed of silica particles under the overburden pressure of 1000 psi. We have used the clean silica sand and clean viscous oil (PAO-100) to understand the temperature effects on two-phase gas/oil relative permeability without changing the wettability. Furthermore, Johnson-Neumann-Bossler (JBN) method was opted to interpret the two-phase gas/liquid relative permeability from the displacement data, i.e., cumulative oil production and pressure drop across the sandpack.The observations made from the experimental study suggest that oil relative permeability was temperature-dependent, and gas relative permeability was temperature-independent. The residual oil saturation decreased with the increase in temperature and led to higher end-point relative permeability to gas. On the other hand, the end-point relative permeability to liquid decreased as the temperature elevated. Irreducible water saturation showed a temperature-sensitive behaviour, and it increased at higher temperatures. Moreover, the two-phase flow region became enlarged with the rise in temperature as both the relative permeability curves shift upwards, and a larger two-phase flow region was observed. These wider curves appeared at higher temperatures due to a reduction in oil viscosity (which enhanced the oil mobility) and improved the two-phase flow region, resulting in an increase in gas to liquid relative permeability ratio. However, it was tough to accept that if capillary force controls the fluid distribution in porous media, how a change in temperature leads to variation in characteristics parameters of relative permeability curves. Fundamentally, at residual oil saturation, the oil relative permeability becomes practically zero, but we have observed a higher than zero value for oil relative permeability in all the tests in this study from the JBN method. Therefore, we have re-interpreted the two-phase gas/oil relative permeability characteristic parameters using the history matching technique, where the relative permeability characteristics measured experimentally were tuned until the simulated production and pressure drops data matches the experimental data. It was observed from history matching optimization that residual oil saturation was one of the uncertain parameters estimated during the displacement test due to the higher viscosity of the oil and less volume of gas injection at a lower temperature. Hence, the measured end-point relative permeability to gas measured at residual oil saturation from JBN was also uncertain. This was the possible reason for the change in relative permeability characteristics with a temperature change. These results strongly suggest that temperature cannot affect the two-phase gas/oil relative permeability as long as the capillary control fluid distribution is maintained in porous media and no alteration in wettability occurs.