Myeong H. Noh

Implications of Coupling Fractional Flow and Geochemistry for CO2 Injection in Aquifers

The geochemical changes caused by CO2 injection into aquifers include acidification and carbonation of the native brine and potential mineral dissolution and precipitation reactions driven by the aqueous composition changes. The latter are important for evaluating the potential CO2 storage capacity in the form of minerals and can also influence the performance of the injection well. The theories of geochemical flows and of fractional flow provide useful insight into several aspects of CO2 sequestration. This paper gives the mathematical formalism of combined geochemical and multi-phase flow. If local equilibrium applies, the theory leads to graphical solution, from which it is easy to see when and under what conditions mineralization will occur during the injection. The theory also illustrates the influence of post-injection flow on mode of CO2 trapping (hydrodynamic, solubility, mineral, residual saturation). We also show that co-injection of water significantly alters the mode of trapping. Introduction Carbon dioxide sequestration was first discussed in the late 1970s. However, serious research and development in CO2 sequestration only began in the early 1990s. The technical literature28 about CO2 disposal in aquifers includes feasibility studies in The Netherlands and in the Alberta Basin, Canada. A field test is being performed in the North Sea in the Sleipner Vest project, which is the first CO2 sequestration project in a brine-bearing formation. Sequestering CO2 in geologic formations offers numerous advantages, including: (1) The experience of the oil industry can directly provide the technology to enable the commercialization of this approach. (2) Several collateral economic benefits are possible, for example, enhancing oil and gas recovery while storing CO2. (3) Suitable geologic formations, including oil, gas, brine, and coal formations are relatively easy to find. (4) The regulatory infrastructure associated with the injection into oil and gas formations and deep aquifers is well established. (5) Geologic analogs such as natural CO2 reservoirs prove that geologic structures can sequester CO2 for a very long time. (6) Public acceptance for geologic sequestration should grow as technological advances lead to innovative methods for creating permanent mineral sinks for CO2. Carbon dioxide can be sequestered in geologic formations by three principal mechanisms. (1) CO2 can be trapped as a gaseous phase or supercritical fluid under a low-permeability caprock, similar to what occurs in natural gas reservoirs (hydrodynamic trapping). (2) Dissolution into an aqueous phase (solubility trapping). (3) CO2 can react with the minerals and the organic matter in geologic formations to become a part of the solid (mineral trapping). Formation of carbonate minerals such as calcite or siderite and the adsorption onto coal are other examples of the mineral trapping. Mineral trapping will create stable repositories of CO2 that decrease mobile hazards such as leakage to the surface. An additional form of storage -as a residual gas saturation -is also studied in this and a companion paper. Here CO2 remains as a gaseous phase, such as hydrodynamic trapping, but it is immobile because the gas is trapped by capillary forces. In this study, the immobile gas trapping is called the residual saturation trapping. Siliciclastic aquifers should have greater potential for the mineral trapping of CO2 compared to carbonate aquifers. Depending on whether the basic aluminosilicate minerals, such as feldspars, zeolites, illites, chlorites and smectites, contain an alkali or alkaline earth cation, two types of mineral trapping can be considered. Na/K-bearing minerals result in the development of bicarbonate brines. Fe/Ca/Mg-bearing minerals result in the precipitation of siderite, calcite or

Simulating CO2 Storage in Deep Saline Aquifers

This chapter presents the results of compositional reservoir simulation of a prototypical CO 2 storage project in a deep saline aquifer. The objective of the investigation was to better understand and quantify estimates of the most important CO 2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO 2 injection followed by 10 3 -10 5 years of natural gradient flow were done. The impact of several parameters was reviewed, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO 2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.

Reservoir Simulation of CO2 Storage in Deep Saline Aquifers

We present the results of compositional reservoir simulation of a prototypical CO2 sequestration project in a deep saline aquifer. The objective was to better understand and quantify estimates of the most important CO2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO2 injection followed by 10 to 10 years of natural gradient flow were done. The impact of several parameters was studied, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.

Simulating CO 2 Storage in Deep Saline Aquifers

This chapter presents the results of compositional reservoir simulation of a prototypical CO 2 storage project in a deep saline aquifer. The objective of the investigation was to better understand and quantify estimates of the most important CO 2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO 2 injection followed by 10 3 -10 5 years of natural gradient flow were done. The impact of several parameters was reviewed, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO 2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.

Chapter 13 – Simulating CO2 Storage in Deep Saline Aquifers

This chapter presents the results of compositional reservoir simulation of a prototypical CO 2 storage project in a deep saline aquifer. The objective of the investigation was to better understand and quantify estimates of the most important CO 2 storage mechanisms under realistic physical conditions. Simulations of a few decades of CO 2 injection followed by 10 3 -10 5 years of natural gradient flow were done. The impact of several parameters was reviewed, including average permeability, the ratio of vertical to horizontal permeability, residual gas saturation, salinity, temperature, aquifer dip angle, permeability heterogeneity and mineralization. The storage of CO 2 in residual gas emerges as a potentially very significant issue meriting further study. Under some circumstances this form of immobile storage can be larger than storage in brine and minerals.