The effect of drainage on the capillary retention of CO₂ in a layered permeable rock

Abstract

We examine the motion of a buoyant fluid injected into a water-saturated porous rock as it spreads along a thin inclined low-permeability barrier. We account for leakage of the fluid across the barrier once the current is sufficiently deep so that the pressure exceeds the capillary threshold. We show that at some distance from the source, the pressure decreases below this threshold, and all the remaining flux spreads laterally along the barrier. We examine the controls on the partitioning of the flow between the draining flux and the laterally spreading flux and also the controls on the lateral extent of the draining region for the case of an instantaneous release and a maintained release of fluid. We consider the implications of our work for the dispersal of CO 2 plumes which may be sequestered in deep saline aquifers. IntroductionThe injection of CO 2 into deep saline aquifers or depleted oil and gas fields has received considerable interest in the context of global warming and the related challenge of reducing anthropogenic carbon emissions into the atmosphere (Kumar et al. 2005;Nordbotten, Celia & Bachu 2005). In deep saline aquifers, CO 2 is supercritical and has a density of the order 20 %-40 % smaller than that of water, depending on the temperature and pressure. As a result, there is concern that the CO 2 will migrate through the subsurface and back to human environment, perhaps over time scales of tens to hundreds of years. In order to assess this risk, models are being developed to describe the migration of CO 2 plumes through the subsurface (Hesse et al. , 2007Mitchell & Woods 2006;Vella & Huppert 2006), and data are being collected from various field trials using seismic imaging to interpret the dispersal patterns in the field (Bickle et al. 2007). A significant challenge associated with the prediction of such CO 2 transport is the complexity of the subsurface strata through which the CO 2 migrates. This can lead to multiple and tortuous flow paths from the injection point to the surface, with the CO 2 being dispersed laterally over substantial distances but also reaching the surface through different flow paths over a range of different time scales. Data from the Sleipner field in Norway (Bickle et al. 2007) has shown that the gas spreads out in a pine tree-type pattern, spreading laterally beneath low-permeability layers while gradually migrating upwards as it leaks through these layers or fractures which cut across the layers.Some of the models which have been developed to describe the migration of plumes of CO 2 in the subsurface have assessed the buoyancy-driven dispersal through both †

CO2–brine–caprock interaction: Reactivity experiments on Eau Claire shale and a review of relevant literature

“…Several factors control the extent of such drying out of the caprock. First, as the initially dry CO 2 is transported through the reservoir sand from the injector, water will evaporate into the CO 2 and the water saturation will increase (Gaus et al, 2008); second, when the CO 2 phase reaches the caprock in a stagnant plume, significant fractions of residual water within the plume will be available (Suekane et al, 2005;Farcas and Woods, 2008); and third, capillary suction forces of water in the caprock may not be strong enough to hold the water from the caprock even for a strongly waterundersaturated CO 2 plume. As we are not aware of any reports that verify the drying-out phenomena from natural reservoirs or from laboratory experiments, we leave this as an open question for further discussions.…”

Impact of the capillary fringe in vertically integrated models for CO2 storage

“…[50] We point out these implications since it has been common to use this time rate of change as a simplified hysteresis model in the literature [Farcas and Woods, 2009;Hesse et al, 2008;Juanes et al, 2010;Kochina et al, 1983]. One study that accounts for the full hysteresis model in a sharp interface setting is reported by Juanes and Mac-Minn [2008].…”

Sinking inside the box

“…The trapping of fluid by capillary forces at the pore scale is known to be important (Farcas & Woods 2009), and the unexpectedly large increase in the flux across the interface when it can deform even slightly suggests another key difference, since diffuse miscible interfaces may be more readily deformed than sharp immiscible interfaces. This indicates a potentially serious drawback of the miscible experimental systems that are most readily used as analogues for CO 2 sequestration problems (e.g.…”