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Abstract

Deep saline aquifers are potential reservoirs for commercial scale CO₂ geologic sequestration (GS) due to their large storage capacity and wide availability.  These reservoirs are regional in scale with no conventional stratigraphic or structural traps.  The fate of supercritical CO₂ injected in saline aquifers depends on hydrodynamics and phase trapping.  This paper examines hydrodynamic trapping, and the question of whether basinward flow of groundwater can counteract updip CO₂ movement after injection ends, and render the gas immobile.  After injection pressure dissipates, the important flow mechanisms are viscous flow of groundwater (imposed by compaction and gravity) and buoyant flow of CO₂ (imposed by the density contrast between injected CO₂ and the formation fluid). 

Hydrodynamic trapping theory is reviewed and its application to GS is discussed.  The same methods developed for oil and gas can be used to identify possible hydrodynamic traps for pools of CO₂ post injection.  Examples are given of deep basin aquifer dynamics and regional groundwater flow gradients as they relate to GS.  In a dipping aquifer, groundwater flow and buoyant CO₂ flow may be in the same direction (immature compacting basin) or the opposite direction (mature basin).  The mature basin scenario is optimum for GS, as long-term updip CO₂ movement will be reduced by saline aquifer flow.  Analytic expressions are used to investigate trapping potential, and to estimate the rate of buoyant CO₂ movement after injection ends in a mature basin example with groundwater flow down the dip.  Key inputs such as hydraulic gradient, dip, and density contrast were varied to assess their relative influence.  The results demonstrate that, post injection, it is possible for pooled CO₂ to be hydrodynamically trapped under field conditions.  CO₂ could also be displaced downdip in aquifers with high hydraulic gradients (~ 0.02) and low dips (~ 0.25 degrees).  In the more likely case of a low to average hydraulic gradient (~ 0.0004 to 0.003), and dip greater than ~ 0.25 degrees, buoyancy dominates, and the CO₂ is generally displaced in the updip direction at rates of approximately one to one hundred feet per year.  This can lead to significant displacement over the long time scales desired for GS.  Therefore, in a mature basin, groundwater flow alone will usually be insufficient to counteract buoyancy, and phase trapping or hydrodynamic trapping will be needed to ultimately immobilize the CO₂. 

Introduction

Geologic sequestration of CO₂ (GS) is a process where the gas is compressed and injected in deep underground reservoirs where temperature and pressures are such that it will be in a supercritical state.  This technology is seen as an enabler for hydrocarbon use and is actively being considered to reduce greenhouse gas emissions from coal fired power plants, refineries, and unconventional oil production (e.g. oil sands and shales). Suitable reservoirs may include depleted hydrocarbon fields, enhanced oil recovery projects, deep coal bed seams, or deep saline aquifers.  NETL (2009) estimates that the maximum CO₂ storage capacity of saline aquifers is 12,600 gigatonnes.  In comparison, the maximum capacity for unmineable coal seams and depleted oil and gas fields is estimated to be 180 and 140 gigatonnes respectively.  Projects that combine GS with enhanced oil or gas recovery have a clear economic incentive.  However, an important factor is that hydrocarbon fields and deep unmineable coal bed seams may not be available near sources of CO₂.  In such cases, deep saline aquifers are good candidate reservoirs for commercial scale GS projects due to their large storage capacity and wide availability.  The waters in these aquifers have a high concentration of dissolved salts (greater than 10,000 milligrams/liter total dissolved solids) and have no beneficial use.