SPE 77697 Effect of Composition on Waterblocking for Multicomponent Gasfloods

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 porescale 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. Introduction Mass transfer across water barriers by molecular diffusion is an important process during oil recovery by gas injection. Miscible gas injection is typically applied after a waterflood in which case significant volumes of oil may be trapped within the pore-space in the form of ganglia surrounded by water (Fig. 1). In this case the injected gas may not come into direct contact with the oil and recovery will be reduced, as the gas will not be able to displace the oil trapped behind the water. Fig. 1. Schematic of waterblocking. After secondary displacement by water, a fraction of the oil remains in the field shielded by water. In tertiary recovery gas is injected to displace the oil. This effect has been observed mainly in the laboratory and is termed waterblocking. Depending upon the relative compositions of the oil and gas, gas components will diffuse into the oil and oil components will diffuse into the gas. If the first mechanism dominates then trapped oil droplets will swell and may ultimately rupture their retaining water barrier, enabling them to be swept away by the gas. If the second mechanism prevails then the oil droplets will shrink and the gas will be enriched with oil, although inevitably some oil will still be trapped by the water. Waterblocking during carbon dioxide (CO2) injection has been investigated theoretically by a number of authors. 10 This involves modeling the transfer of a single component (CO2) diffusing through the water into the trapped oil. These studies showed that the time-scales at the pore level over which CO2 diffuses through the water, swells the trapped oil and ruptures the surrounding water is relatively short (~1 day for a 100μm thick water film) mainly because of the high solubility of CO2 in water. Hence it appears that waterblocking is relatively unimportant for oil recovery via carbon dioxide injection over the time-scales of typical recovery schemes (~10 years). Carbon dioxide is not always available in sufficient quantities for gas injection, whereas many oil fields, located in remote parts of the world, produce large quantities of hydrocarbon gas for which there is no market. In these circumstances it is sometimes economic to mix the produced 2 B.R.Bijeljic, A.H.Muggeridge and M. J. Blunt 77697 gas with lighter components of the oil to the point where the mixture is miscible with the oil at reservoir temperature and pressure. This enriched gas is then re-injected into the reservoir. One of the best-known examples of this type of recovery scheme is the Prudhoe Bay field on the North slope of Alaska. Waterblocking in hydrocarbon gas injection is a far more complex problem because it involves multicomponent mass transfer. Light components in the gas diffuse into the oil, causing the oil to swell. In contrast, heavier components from the oil diffuse into the gas, shrinking the oil. It is possible that the water barrier never ruptures, meaning that mass transfer is controlled by the exceptionally slow dissolution of heavy hydrocarbon components, and over the life time of the reservoir thermodynamic equilibrium is never achieved. To understand the different time-scales involved we perform a simple scaling analysis to assess significance of waterblocking for different components. The time scale for CO2 diffusion through a water film of length Lw = 100 μm-500 μm and for typical reservoir conditions (P = 26MPa, T = 344K) is t ~ w i w i w S D L , , 2 ) ( ~ 10s-10s ~ minutes/hours, where Di,w is the diffusion coefficient in water and Si,w is the solubility in water (mol of component i / mol of solution). The diffusivity of CO2 is of the order of 10m/s 4 and the solubility of CO2 under these conditions is of the order of Si,w = 10. Typical flow rates in a reservoir setting are around 0.1-1m/day with well spacing between 100m and 1000m. A timescale of 60 minutes to reach equilibrium is equivalent to a mixing zone length of at most a few centimeters, meaning that in this case water blocking has no significant impact on field-scale recovery. If the injected gas were composed of light intermediate hydrocarbon components (say only of n-butane, C4, with a solubility of order 10 , an identical analysis gives t ~ 10s-10s ~ days. This gives a mixing length zone of 0.1 to several meters, which is still small in comparison with the well spacing. Under the same conditions, the time scale for diffusion of heavier hydrocarbon components e.g. octane (C8) is strikingly higher with t ~ 10s-10s ~ years, mostly due to their much lower solubility (of the order of 10, as estimated from the Solubility Data Series (SDS)). In this case the mixing zone length exceeds the well spacing. This implies that over a time-scale for gas to move from injection to production wells (around a year or so), gas and oil fail to reach thermodynamic equilibrium, resulting in poor recoveries. In this paper we shall describe a simple one-dimensional numerical model to investigate multicomponent mass transfer in waterblocking at the pore-scale. We shall then study the dynamics for a range of synthetic gas compositions injected into a reservoir containing an Indonesian crude oil, as well as applying our model to an injected gas and crude oil from North Alaska. We show that the rate of oil recovery and the way it is recovered (either by rupturing the water barrier or being vaporized into the displacing gas) is sensitive to the oil and gas compositions, the oil droplet size and the original thickness of the water barrier. We show cases where the time to reach equilibrium between gas and oil is sufficiently long to affect field-scale recoveries. We discuss for a range of firstcontact and multiple-contact miscible gas/oil systems how an increase in the miscibility of injected gas may lead to prolonged gas/oil contact. Mathematical Model We investigate the problem of a single oil droplet trapped within a dead-end rock pore by a water barrier at the pore throat. Injected gas passes through a pore above the water barrier (Fig. 2a). We represent this system simply as three regions composed of gas, water and oil separated from each other by a sharp interface (Fig. 2b).