Extraction of Dissolved Methane in brines by CO2 Injection: Implication for CO2 Sequestration

Abstract

Abstract The solubility of CO2 in underground saline formations is considered to offer significant long-term storage capability to effectively sequester large amounts of anthropogenic CO2. Unlike EOR, geosequestration relies on longer time scales and involves significantly greater volumes of CO2. Many geosequestration studies assume that the initial brine state is one containing no dissolved hydrocarbons and therefore apply simplistic two component solubility models starting from a zero dissolved gas state. Many brine formations near hydrocarbons however tend to be close to saturation by methane. The introduction of excess CO2 in such systems results in an extraction of the methane into the CO2 rich phase which in turn, has implications for monitoring of any sequestration project and offers the possibly additional methane mobilization and recovery. Introduction While the presence of dissolved hydrocarbons, particularly methane in subsurface brines, is well known in petroleum engineering disciplines 1–8, much R&D work associated with CO2 geosequestration has tended to overlook the role of such dissolved gases as they relate to both the initial brine state and what might happen, as large volumes of CO2 are targeted for long-term dissolution. In the CO2 storage literature, long term dissolution is referred to as solubility trapping. CO2 storage capacity estimates are largely theoretically based and usually make no allowance for initial dissolved gas components. Instead it is customary to assume a zero initial solubility state with an equilibrium dissolved CO2 level that depends, for fixed salinities and temperatures, on pressure alone. A simple pressure dependence allows use of black-oil models or simple two component compositional models. One reason for neglecting the dissolved methane is that the relative solubility of methane tends to be 5 to 10 times smaller than that of carbon dioxide and that simple models do not allow for the calculation of component mass transfer between phases. One objective of this work is to consider the impact of initial dissolved hydrocarbons on the subsequent injection of large volumes of CO2. While hydrocarbons have lower solubilities in brine, the relatively vast volumes of brines that may exist mean that a substantial resource of dissolved hydrocarbons, particularly methane, may be present. In many cases the associated aquifers are generally orders of magnitude larger than any hydrocarbon accumulations that may exist. The presence of up dip hydrocarbons, or the existence of residual hydrocarbon phases, provides for further evidence for the presence of initial dissolved hydrocarbons in brine because, thermodynamically, equilibrium of component fugacities must exist at such brinehydrocarbon boundaries. CO2 is an extractive component which means it is capable, upon injection, of transferring or removing lighter components from subsurface host fluids. This extraction is essentially a multi-component mass-driven process in a two-phase system. Lighter components are extracted from one phase and appear in the other. In the case of CO2 and brines, the two phases are the brine (liquid) phase and a CO2 rich phase that may be supercritical (if pure CO2 at depths greater than 2,500 ft or 800 metres) or considered a vapour phase (if it contains significant methane). As will be demonstrated, CO2 is capable of extracting methane and other HC's from brines. Unlike a pure two-component system, multi-component behavior at constant temperature and salinity depends on both pressure and the total mole fractions of the components present. As such it requires at least a ternary (3-component) system to visualize, and model the mass-transfer process.