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As part of the CO2CRC Otway Residual Saturation and Dissolution Test, a series of field tests were conducted at their project site in Victoria, Australia, with the primary goal of developing and assessing methods for quantifying residual CO 2 saturation in a saline aquifer. This paper reports the outcome of one of these tests, a single-well “push–pull” tracer test that uses novel reactive esters (i.e., propylene glycol diacetate, triacetin and tripropionin). For this tracer test, the ester is injected (pushed) into the reservoir where residual saturation has been established using CO 2 , and maintained by pushing with CO 2 saturated water (to prevent changes in saturation due to CO 2 dissolution). The ester is partially hydrolysed by the formation water to yield multiple compounds (i.e., the corresponding alcohol and acid generated from the ester). During water production (pull) from the same well, these compounds will partition differentially between the residual supercritical carbon dioxide phase and water phase, leading to chromatographic separation. By modelling the concentration profiles of these tracers in production water samples and using the experimentally determined partition coefficients, we generate two consistent residual saturation estimates using two separate modelling techniques, one a simple finite difference simulation of the tracer velocity field and the other a standard multiphase simulation code. [ABSTRACT FROM AUTHOR]

Abstract: When a large volume of CO2 is injected into a geological formation this can lead to the mobilisation of substances of a chemical and physical nature. The purpose of this IEA GHG study[1] was to identify typical substances that could be mobilised during geosequestration and to evaluate potential tools for monitoring these substances. This project reviewed the scientific literature patent applications and industry publications relevant to the current monitoring of chemical and physical processes due to CO2-formation water-rock interactions from the deep subsurface through to the soil/water interface. Four major areas were identified for review: 1– physical effects, including pressure effects or displacement of fluids; 2 – geochemical effects, including dissolution of reservoir and seal rocks, as well as the potential for mobilisation of heavy metals; 3 – shallow/surface effects, potential nutrients/toxic compounds affecting soils and microbial communities, as well as groundwater quality; 4 –capture contaminant effects from coal fired plants and other point source emitters. The various processes have different degrees of impact in the three general monitoring domains: a) injection horizon (depleted hydrocarbon reservoir, saline formation), b) above-zone interval (zone directly overlying the seal of the storage interval), and c) shallow subsurface (potable groundwater aquifers, soil). Understanding these processes and mapping their distribution aids in the identification of potential monitoring tools and facilitates an assessment of their utility in a particular monitoring domain. Some tools already commonly deployed in other industries are highly applicable to the carbon storage industry; for example, downhole pressure gauges from the oil industry and water level loggers from the groundwater industry. In general, geophysical tools were found to be quite a mature method for identifying the presence of gas (hydrocarbons or CO2), but less so for observing mobilised substances and changes in salinity. Tools for measuring trace amounts of hydrocarbons in marine settings are able to be modified in order to be used for monitoring mobilised hydrocarbons entrained in capture emissions, from CO2/source rock interactions or ienhanced oil recovery processes, though many of the tools are not compound specific as yet. The aim of the project is to provide an understanding of the availability of conventional and novel tools for monitoring and verification (M&V) during CO2 injection. Some of these tools have been successfully employed in current carbon capture and storage (CCS) projects or in alternative applications, such as mineral exploration and ecological studies. [Copyright &y& Elsevier]

Partition (or distribution) coefficients determine the relative equilibrium concentrations of chemical constituents (or chemical tracers) in each of the phases of a multi-phase system under dilute conditions. The various fluid phases in a reservoir have differing transport properties (e.g. varying relative permeability) and to correctly interpret the behaviour of injected chemical tracers it is essential that accurate partition coefficients are known. In the context of carbon geosequestration or long-term storage of CO 2 , chemical tracers will be predominantly exposed to an environment consisting of supercritical CO 2 and formation water as the main fluid phases. To estimate/simulate the reservoir properties relevant to injected CO 2 tagged with chemical tracers, it is therefore necessary to incorporate high pressure/temperature CO 2 /water partition coefficients into any model/simulation. In this paper, we present a method to determine these partition coefficients for gaseous chemical tracers using a variation of the widely used EPICS (or equilibrium partitioning in a closed system) method. With this method, only the concentration in one phase (in this case, CO 2 ) needs to be measured. We then report these values for a series of representative chemical tracers (i.e. krypton, xenon, sulfur hexafluoride, perdeuterated methane and R134a) at pressure/temperature conditions that have been previously used at the CO2CRC's Otway CCS demonstration project in Victoria, Australia. These values were generally lower than the corresponding Henry's Law coefficients at comparable temperatures. Experiments also examined the impact of adding CH 4 to the system to mimic feedstock gas at the CO2CRC Otway project and provide data pertinent to scenarios where CO 2 is injected into depleted CH 4 gas fields. These values are compared with Henry's Law coefficients and another recently published set of high pressure/temperature partition coefficients. With computational simulations, we have shown that these differences are potentially significant and demonstrate their impact in three typical CO 2 geo-sequestration scenarios (i.e. injection into two types of aquifers and injection into a depleted reservoir with a gas cap). [ABSTRACT FROM AUTHOR]