The Experts below are selected from a list of 693 Experts worldwide ranked by ideXlab platform
Matthew D Jackson - One of the best experts on this subject based on the ideXlab platform.
-
multiphase streaming potential in sandstones saturated with gas brine and oil brine during drainage and imbibition
Geophysical Research Letters, 2011Co-Authors: Jan Vinogradov, Matthew D JacksonAbstract:[1] We have measured the streaming potential in Water-wet sandstones during both drainage and imbibition, and demonstrate that it behaves differently in oil/brine and gas/brine displacements. During drainage, the streaming potential remains significantly greater than zero at the Irreducible Water Saturation in oil/brine displacements, but falls to zero in gas/brine displacements. During imbibition, the streaming potential at partial Saturation in oil/brine displacements exceeds that measured at Saturation, but not in gas/brine experiments. Our results have application to streaming potential measurements in the vadose zone, hydrocarbon reservoirs, contaminated aquifers and during CO2 sequestration.
-
multiphase electrokinetic coupling insights into the impact of fluid and charge distribution at the pore scale from a bundle of capillary tubes model
Journal of Geophysical Research, 2010Co-Authors: Matthew D JacksonAbstract:[1] A bundle of capillary tubes model is used to investigate multiphase electrokinetic coupling during the flow of Water and an immiscible second phase such as air or oil. The charge on the surface of each capillary is assumed constant, and the impact of charge distribution at the pore scale is investigated by calculating the relative streaming potential coupling coefficient assuming that the diffuse part of the electrical double layer is (1) much less than the capillary radius (“thin”) and (2) comparable to the capillary radius (“thick”). The relative coupling coefficient generally decreases with decreasing Water Saturation, falling to zero at the Irreducible Water Saturation. In the limit of a thin double layer, the relative coupling coefficient at partial Saturation is independent of capillary size distribution and depends upon the wettability of the capillaries only if surface electrical conductivity is significant and the Irreducible Water Saturation is small. In the limit of a thick double layer, the relative coupling coefficient depends upon the capillary size distribution and wettability. If Water is the only phase that contains an excess of charge, the relative coupling coefficient can be described in terms of the Water relative permeability, relative electrical conductivity, and relative excess countercharge density transported by the Water. This latter quantity increases with decreasing Water Saturation in Water-wet models and decreases with decreasing Water Saturation in oil-wet models. It does not scale inversely with Water Saturation as has been assumed previously and depends upon the pore scale distribution of fluid and charge.
-
characterization of multiphase electrokinetic coupling using a bundle of capillary tubes model
Journal of Geophysical Research, 2008Co-Authors: Matthew D JacksonAbstract:[1] A simple bundle of capillary tubes model has been used to investigate electrokinetic coupling during the flow of Water and an immiscible second phase such as air or oil. It is shown that the total electrokinetic coupling is the sum of the individual phase contributions. The electrokinetic coupling depends on the capillary size distribution and wettability. When Water is the wetting phase and the second phase is nonpolar and does not contain an excess of charge, the relative coupling decreases with decreasing Water Saturation. Similar behavior has been observed in geologic porous media. However, when Water is not the wetting phase, the coupling increases with decreasing Water Saturation before falling sharply to zero at the Irreducible Water Saturation. This behavior has not been predicted before. If Water is the only phase that contains an excess of charge, then the electrokinetic coupling can be described in terms of the Water relative permeability and relative electrical conductivity. The model predictions suggest that multiphase electrokinetic coupling in geologic porous media depends on rock type and wettability and can be described in terms of commonly measured petrophysical properties. However, the predictions should be applied with caution because the pore space topology and pore occupancy of the model is very simple. Moreover, if the second phase is polar and contains an excess of charge, preliminary work suggests that the multiphase coupling can be significantly enhanced.
Fariborz Rashidi - One of the best experts on this subject based on the ideXlab platform.
-
experimental study of hot Water injection into low permeability carbonate rocks
Energy & Fuels, 2008Co-Authors: Behnam Sedaee Sola, Fariborz RashidiAbstract:Hot Water drive involves the flow of only two heated phases. The major mechanisms on hot Water injection are thermal expansion, viscosity reduction, wettability alteration, and oil/Water IFT reduction. In this study, hot Water injection experiments were carried out using unpreserved limestone and dolomite core samples obtained from the oil zones of heavy oil low-permeability reservoirs. These experiments were conducted at reservoir pressure but in various temperature ranges up to 500 °F using a wide variety of oils. The final oil recovery, residual oil Saturation, Irreducible Water Saturation, and pressure drop were compared in each experiment. The results of dynamic isothermal displacements were interpreted using numerical simulation method to obtain reliable relative permeabilities. Hence, the effects of temperature on oil/Water relative permeabilities were obtained for low-permeability carbonate rocks. Results show that it is possible to recover a high percent of oil using high-pressure/high-temperatur...
Zhe Yuan - One of the best experts on this subject based on the ideXlab platform.
-
experimental studies on effects of temperature on oil and Water relative permeability in heavy oil reservoirs
Scientific Reports, 2018Co-Authors: Yadong Qin, Pengcheng Liu, Fajun Zhao, Zhe YuanAbstract:A heavy-oil sample derived from a block of Venezuelan oil was used to investigate effects of temperature on relative permeability to oil and Water. Measurements of relative permeability were based on one-dimensional core-flow simulated systems using an unsteady-state technique at different temperatures, and then impact rules of temperature dependency were discussed. Both Water and heavy oil in cores were reconfigured under the consideration of actual reservoir conditions. Study results suggest that relative permeability is high to oil phase and is very low to Water phase, and fluid flow capability is extremely imbalanced between oil and Water. As temperature increases, Irreducible Water Saturation linearly increases, residual oil Saturation performs a nonlinear decrease, and Water Saturation exhibits a nonlinear increase at equal-permeability points. The Water-wettability of rocks is heightened and overall relative permeability curves shift to the right with increasing temperature; furthermore, two-phase flow area becomes wider and both oil and Water relative permeability increases apparently, but the increase ratio of Water is less than that of oil.
Behnam Sedaee Sola - One of the best experts on this subject based on the ideXlab platform.
-
experimental study of hot Water injection into low permeability carbonate rocks
Energy & Fuels, 2008Co-Authors: Behnam Sedaee Sola, Fariborz RashidiAbstract:Hot Water drive involves the flow of only two heated phases. The major mechanisms on hot Water injection are thermal expansion, viscosity reduction, wettability alteration, and oil/Water IFT reduction. In this study, hot Water injection experiments were carried out using unpreserved limestone and dolomite core samples obtained from the oil zones of heavy oil low-permeability reservoirs. These experiments were conducted at reservoir pressure but in various temperature ranges up to 500 °F using a wide variety of oils. The final oil recovery, residual oil Saturation, Irreducible Water Saturation, and pressure drop were compared in each experiment. The results of dynamic isothermal displacements were interpreted using numerical simulation method to obtain reliable relative permeabilities. Hence, the effects of temperature on oil/Water relative permeabilities were obtained for low-permeability carbonate rocks. Results show that it is possible to recover a high percent of oil using high-pressure/high-temperatur...
Panfeng Zhang - One of the best experts on this subject based on the ideXlab platform.
-
formation Water evaporation induced salt precipitation and its effect on gas production in high temperature natural gas reservoirs
Petroleum Exploration and Development, 2016Co-Authors: Liang Zhang, Yuan Zhuang, Panfeng ZhangAbstract:Abstract To study the pattern of formation Water evaporation and salt precipitation, based on the oil-gas-Water three phase thermodynamic equilibrium, the principle of salt dissolution/precipitation, and results of formation Water evaporation and salt precipitation experiment, a comprehensive salt precipitation model considering formation Water evaporation, precipitation of NaCl in Water, and reservoir porosity and permeability variations was established to analyze the salt precipitation and its influence factors during the development of high temperature gas reservoir, and some methods preventing and removing salt precipitation were proposed. The study results show that salt precipitation usually occurs in production well area during development of gas reservoir. When the initial formation Water Saturation is less than the Irreducible Water Saturation, the concentration of precipitated salt from production well area will be lower, and the influence of salt precipitation on reservoir can be ignored. When initial formation Water Saturation is higher than Irreducible Water Saturation, the flowing formation Water constantly carries NaCl to the well bore, leading to massive precipitation of NaCl in the production well area, damaging or even plugging the reservoir completely, and shortening the development life cycle of gas reservoir at last. The increase of reservoir temperature, formation Water salinity and reservoir porosity will intensify reservoir damage caused by salt precipitation. But the increase of production rate and reservoir permeability will reduce reservoir damage caused by salt precipitation. The results of this study can guide the prevention and removal of salt precipitation, enhancement of gas reservoir productive capacity and secondary development of high temperature gas reservoir.
-
Formation Water evaporation induced salt precipitation and its effect on gas production in high temperature natural gas reservoirs
'Elsevier BV', 2016Co-Authors: Guodong Cui, Liang Zhang, Yuan Zhuang, Shaoran Ren, Bo Ren, Bo Han, Panfeng ZhangAbstract:To study the pattern of formation Water evaporation and salt precipitation, based on the oil-gas-Water three phase thermodynamic equilibrium, the principle of salt dissolution/precipitation, and results of formation Water evaporation and salt precipitation experiment, a comprehensive salt precipitation model considering formation Water evaporation, precipitation of NaCl in Water, and reservoir porosity and permeability variations was established to analyze the salt precipitation and its influence factors during the development of high temperature gas reservoir, and some methods preventing and removing salt precipitation were proposed. The study results show that salt precipitation usually occurs in production well area during development of gas reservoir. When the initial formation Water Saturation is less than the Irreducible Water Saturation, the concentration of precipitated salt from production well area will be lower, and the influence of salt precipitation on reservoir can be ignored. When initial formation Water Saturation is higher than Irreducible Water Saturation, the flowing formation Water constantly carries NaCl to the well bore, leading to massive precipitation of NaCl in the production well area, damaging or even plugging the reservoir completely, and shortening the development life cycle of gas reservoir at last. The increase of reservoir temperature, formation Water salinity and reservoir porosity will intensify reservoir damage caused by salt precipitation. But the increase of production rate and reservoir permeability will reduce reservoir damage caused by salt precipitation. The results of this study can guide the prevention and removal of salt precipitation, enhancement of gas reservoir productive capacity and secondary development of high temperature gas reservoir. Key words: high temperature gas reservoir, Water evaporation and salt precipitation, production well area, formation Water Saturation, reservoir damag
