• Energy Research

Transverse and longitudinal dispersion in gravity stable, favourable viscosity ratio flows are investigated and compared with earlier data obtained for miscible fluids and for tracer flow. Data from laboratory measurements of longitudinal dispersion in low viscosity ratio (8.63×10(-)(4)) and high density contrast (471 kg m(-3)) displacements are compared with literature data for more modest viscosity ratios and density differences and with earlier theoretical analysis. The longitudinal dispersivity was reduced by a factor of 2 for flows influenced by gravity. This reduction was relatively insensitive to the magnitude of the density contrast and the flow rate, for Peclet numbers less than 100 and found to be consistent with earlier theoretical predictions. Additional transverse dispersion data was obtained for fluids with a density contrast of 225 kg m(-3) and a matched viscosity ratio over a range of Peclet numbers (1

Transverse and longitudinal dispersion in gravity stable, favourable viscosity ratio flows are investigated and compared with earlier data obtained for miscible fluids and for tracer flow. Data from laboratory measurements of longitudinal dispersion in low viscosity ratio (8.63×10(-)(4)) and high density contrast (471 kg m(-3)) displacements are compared with literature data for more modest viscosity ratios and density differences and with earlier theoretical analysis. The longitudinal dispersivity was reduced by a factor of 2 for flows influenced by gravity. This reduction was relatively insensitive to the magnitude of the density contrast and the flow rate, for Peclet numbers less than 100 and found to be consistent with earlier theoretical predictions. Additional transverse dispersion data was obtained for fluids with a density contrast of 225 kg m(-3) and a matched viscosity ratio over a range of Peclet numbers (1

Abstract We describe the development, testing, and first application of a rapid method for estimating the CO2 storage potential associated with CO2 enhanced oil recovery in both secondary and tertiary modes. The new method builds on various published empirical models for predicting incremental oil recovery (and hence CO2 storage) in solvent floods. It improves the representation of reservoir heterogeneity caused by depositional layering and fracturing. This is then combined with material balance to make site-specific estimates of the CO2 storage potential. We cross-checked predictions from the new method against historical field data for major onshore CO2 floods with satisfactory results considering the very approximate nature of the estimation. We then applied the method to a selection of offshore oil reservoirs and found that, generally, the larger the remaining oil, which is a function of initial size and current recovery factor, the greater the CO2 storage potential. We also modelled the case of continued injection after ceasing oil production at, or after, CO2 breakthrough and observed that, as expected, the amount of CO2 stored at breakthrough depends on how early this occurs, which is affected by reservoir heterogeneity, whereas continued injection is limited by the headroom between current reservoir pressure and fracture pressure. The overall storage is the result of the interplay between these two mechanisms. In the studied fields/reservoirs, we demonstrated that large amounts of CO2 can be stored in terms of absolute mass and that storage of these quantities would represent significant abatement of the emissions generated by burning the incremental oil. The new method can be used as a screening tool to identify and rank candidate oil fields for combined CO2 enhanced oil recovery and storage in regional, national, or corporate portfolios.

Abstract We describe the development, testing, and first application of a rapid method for estimating the CO2 storage potential associated with CO2 enhanced oil recovery in both secondary and tertiary modes. The new method builds on various published empirical models for predicting incremental oil recovery (and hence CO2 storage) in solvent floods. It improves the representation of reservoir heterogeneity caused by depositional layering and fracturing. This is then combined with material balance to make site-specific estimates of the CO2 storage potential. We cross-checked predictions from the new method against historical field data for major onshore CO2 floods with satisfactory results considering the very approximate nature of the estimation. We then applied the method to a selection of offshore oil reservoirs and found that, generally, the larger the remaining oil, which is a function of initial size and current recovery factor, the greater the CO2 storage potential. We also modelled the case of continued injection after ceasing oil production at, or after, CO2 breakthrough and observed that, as expected, the amount of CO2 stored at breakthrough depends on how early this occurs, which is affected by reservoir heterogeneity, whereas continued injection is limited by the headroom between current reservoir pressure and fracture pressure. The overall storage is the result of the interplay between these two mechanisms. In the studied fields/reservoirs, we demonstrated that large amounts of CO2 can be stored in terms of absolute mass and that storage of these quantities would represent significant abatement of the emissions generated by burning the incremental oil. The new method can be used as a screening tool to identify and rank candidate oil fields for combined CO2 enhanced oil recovery and storage in regional, national, or corporate portfolios.

SignificanceUnderstanding the role of international trade in driving pressures on freshwater resources is key to meeting challenges at the water–energy nexus. A coupled trade and hydrological model is used to examine pressures on freshwater resources associated with energy production across the global economy. While the electric and gas sectors induce freshwater consumption predominantly within countries where demand originates (91% and 81%, respectively), the petroleum sector exhibits a high international footprint (56%). Critical geographic areas and economic sectors are identified, providing focus for resource-management actions to ensure energy and freshwater security. Our analysis demonstrates the importance of broadening the discourse on energy policy to address issues including freshwater scarcity, the role of international trade, and wider environmental and societal considerations.

SignificanceUnderstanding the role of international trade in driving pressures on freshwater resources is key to meeting challenges at the water–energy nexus. A coupled trade and hydrological model is used to examine pressures on freshwater resources associated with energy production across the global economy. While the electric and gas sectors induce freshwater consumption predominantly within countries where demand originates (91% and 81%, respectively), the petroleum sector exhibits a high international footprint (56%). Critical geographic areas and economic sectors are identified, providing focus for resource-management actions to ensure energy and freshwater security. Our analysis demonstrates the importance of broadening the discourse on energy policy to address issues including freshwater scarcity, the role of international trade, and wider environmental and societal considerations.

Abstract During tertiary miscible gas injection direct contact between gas and oil can be prevented by water surrounding residual oil. The principal aim of our study is to assess the importance of this waterblocking phenomenon in multicomponent gas injection. We study this process using a multicomponent pore-scale model. Light components in the gas dissolve in the water and diffuse through the water to reach the oil. This causes the oil to swell. Eventually the oil swells sufficiently to contact the gas directly. However, components in the oil can diffuse into the gas, causing the oil to shrink and preventing the contact. We apply our model to a variety of first-contact and multiple-contact miscible gas/oil systems from published field studies. Due to the low solubility of hydrocarbons in water, oil swelling and shrinkage can prevent direct contact for many days to years. We show that increasing the miscibility of injected gas, by, for instance, moving from a multi-contact miscible to a first-contact miscible displacement increases the time taken to achieve direct gas/oil contact. This leads to an extended two-phase region in the reservoir, even for a thermodynamically miscible gas flood.