• Energy Research

AbstractWhen 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.

AbstractWhen 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.

Abstract An area in the Southern Perth Basin has been selected as a potentially suitable site for CO 2 injection and storage as a part of the South West Hub Project (SW Hub), due to its proximity to major CO 2 emission sources and the presence of potentially suitable geology. This 3D modelling study attempts to assess the geomechanical stability of faults and intact host rocks during CO 2 injection at the SW Hub. The stratigraphy and fault structure of the 3D model are based on the architecture of an E–W cross section in a pre-existing 3D geological model that represents a comprehensive synthesis of seismic, stratigraphic and structural data. In the models, the rocks and faults are simulated as Mohr–Coulomb elastic–plastic materials, and their geomechanical and hydrological properties are based on experimental data from the Harvey-1 drill core samples and also information from literature. A series of models are performed to assess five injection scenarios with injection rates of 1–5 million tonnes per year over a period of 20 years. The results show that the simulated CO 2 injection scenarios would not lead to fault reactivation or breach the overlying Yalgorup or Eneabba Shale formations in the area. Some small smooth uplifts are recorded as a result of injection. In the models assuming weak faults, average ground surface uplifts are 0.4–1.8 cm for the injection rates of 1–5 million tonnes per year, over an area of approximately 2.5 km radius around the hypothetical injection site. Uplifts are marginally smaller when assuming strong faults.

Abstract An area in the Southern Perth Basin has been selected as a potentially suitable site for CO 2 injection and storage as a part of the South West Hub Project (SW Hub), due to its proximity to major CO 2 emission sources and the presence of potentially suitable geology. This 3D modelling study attempts to assess the geomechanical stability of faults and intact host rocks during CO 2 injection at the SW Hub. The stratigraphy and fault structure of the 3D model are based on the architecture of an E–W cross section in a pre-existing 3D geological model that represents a comprehensive synthesis of seismic, stratigraphic and structural data. In the models, the rocks and faults are simulated as Mohr–Coulomb elastic–plastic materials, and their geomechanical and hydrological properties are based on experimental data from the Harvey-1 drill core samples and also information from literature. A series of models are performed to assess five injection scenarios with injection rates of 1–5 million tonnes per year over a period of 20 years. The results show that the simulated CO 2 injection scenarios would not lead to fault reactivation or breach the overlying Yalgorup or Eneabba Shale formations in the area. Some small smooth uplifts are recorded as a result of injection. In the models assuming weak faults, average ground surface uplifts are 0.4–1.8 cm for the injection rates of 1–5 million tonnes per year, over an area of approximately 2.5 km radius around the hypothetical injection site. Uplifts are marginally smaller when assuming strong faults.

AbstractMethodologies for the basin-scale evaluation of industrial-scale CO2 geological storage in saline aquifers can include the use of analytical tools, generic reservoir simulations, as well as basin-specific flow modelling studies. The selection of appropriate tools is dependent on the scale of investigation. Comparison of the results from these methods for the assessment of basin-scale CO2 geological storage in the Gippsland and Otway basins in Australia suggests that, at this scale, a combination of analytical tools in the form of equations for calculating injection pressure, radius of impact and storage capacity with generic numerical simulations may provide useful first-order predictions for storage capacity and injectivity. However, the development of multiple resources (petroleum, groundwater, coal) in the Gippsland Basin and regional compartmentalisation in the Otway Basin necessitates an additional, coarsely discretised basin-scale numerical model.

AbstractMethodologies for the basin-scale evaluation of industrial-scale CO2 geological storage in saline aquifers can include the use of analytical tools, generic reservoir simulations, as well as basin-specific flow modelling studies. The selection of appropriate tools is dependent on the scale of investigation. Comparison of the results from these methods for the assessment of basin-scale CO2 geological storage in the Gippsland and Otway basins in Australia suggests that, at this scale, a combination of analytical tools in the form of equations for calculating injection pressure, radius of impact and storage capacity with generic numerical simulations may provide useful first-order predictions for storage capacity and injectivity. However, the development of multiple resources (petroleum, groundwater, coal) in the Gippsland Basin and regional compartmentalisation in the Otway Basin necessitates an additional, coarsely discretised basin-scale numerical model.

Abstract The experience from CO2 injection at pilot projects (Frio, Ketzin, Nagaoka, US Regional Partnerships) and existing commercial operations (Sleipner, Snohvit, In Salah, acid-gas injection) demonstrates that CO2 geological storage in saline aquifers is technologically feasible. Monitoring and verification technologies have been tested and demonstrated to detect and track the CO2 plume in different subsurface geological environments. By the end of 2008, approximately 20 Mt of CO2 had been successfully injected into saline aquifers by existing operations. Currently, the highest injection rate and total storage volume for a single storage operation are approximately 1 Mt CO2/year and 25 Mt, respectively. If carbon capture and storage (CCS) is to be an effective option for decreasing greenhouse gas emissions, commercial-scale storage operations will require orders of magnitude larger storage capacity than accessed by the existing sites. As a result, new demonstration projects will need to develop and test injection strategies that consider multiple injection wells and the optimisation of the usage of storage space. To accelerate large-scale CCS deployment, demonstration projects should be selected that can be readily employed for commercial use; i.e. projects that fully integrate the capture, transport and storage processes at an industrial emissions source.

Abstract The experience from CO2 injection at pilot projects (Frio, Ketzin, Nagaoka, US Regional Partnerships) and existing commercial operations (Sleipner, Snohvit, In Salah, acid-gas injection) demonstrates that CO2 geological storage in saline aquifers is technologically feasible. Monitoring and verification technologies have been tested and demonstrated to detect and track the CO2 plume in different subsurface geological environments. By the end of 2008, approximately 20 Mt of CO2 had been successfully injected into saline aquifers by existing operations. Currently, the highest injection rate and total storage volume for a single storage operation are approximately 1 Mt CO2/year and 25 Mt, respectively. If carbon capture and storage (CCS) is to be an effective option for decreasing greenhouse gas emissions, commercial-scale storage operations will require orders of magnitude larger storage capacity than accessed by the existing sites. As a result, new demonstration projects will need to develop and test injection strategies that consider multiple injection wells and the optimisation of the usage of storage space. To accelerate large-scale CCS deployment, demonstration projects should be selected that can be readily employed for commercial use; i.e. projects that fully integrate the capture, transport and storage processes at an industrial emissions source.