Changes

Carbon dioxide storage involves keeping the CO₂ secured deep underground in a geological [[reservoir]]. Carbon dioxide can be stored geologically in a variety of different options ([[:file:CO2StorageOptions.JPG|Figure 1]]). These include depleted oil and gas fields, enhanced oil recovery (EOR), deep saline formations, deep unmineable coal seams, enhanced coalbed methane recovery (ECBMR), and other opportunities such as salt caverns.<ref name=Cook_1998>Cook, P. J., 1998, Carbon dioxide—Putting it back where it came from: Australian Gas Journal, p. 40–41.</ref><ref name=Bachuandgunter_1999>Bachu, S., and W. D. Gunter, 1999, Storage capacity of CO₂ in geological media in sedimentary basins with application to the Alberta Basin, in P. Reimer, B. Eliasson, and A. Wokaun, eds., Greenhouse gas control technologies: Proceedings of the 4th International Conference on Greenhouse Gas Control Technologies, August 30–September 2, 1998, Interlaken, Switzerland, Elsevier, p. 195–200.</ref><ref name=Cooketal_2000>Cook, P. J., A. J. Rigg, and J. Bradshaw, 2000, Putting it back from where it came from: Is geological disposal of carbon dioxide an option for Australia: The Australian Petroleum Production and Exploration Association (APPEA) Journal, v. 40, no. 1, p. 654–666.</ref><ref name=IPCC_2005>Intergovernmental Panel on Climate Change (IPCC), 2005, IPCC special report on carbon dioxide capture and storage, prepared by Working Group III of the IPCC (B. Metz, O. Davidson, H. C. de Connick, M. Loos, and L. A. Meyer, eds): New York, Cambridge University Press, 442 p.</ref>

Carbon dioxide storage involves keeping the CO₂ secured deep underground in a geological [[reservoir]]. Carbon dioxide can be stored geologically in a variety of different options ([[:file:CO2StorageOptions.JPG|Figure 1]]). These include depleted oil and gas fields, enhanced oil recovery (EOR), deep saline formations, deep unmineable coal seams, enhanced coalbed methane recovery (ECBMR), and other opportunities such as salt caverns.<ref name=Cook_1998>Cook, P. J., 1998, Carbon dioxide—Putting it back where it came from: Australian Gas Journal, p. 40–41.</ref><ref name=Bachuandgunter_1999>Bachu, S., and W. D. Gunter, 1999, Storage capacity of CO₂ in geological media in sedimentary basins with application to the Alberta Basin, in P. Reimer, B. Eliasson, and A. Wokaun, eds., Greenhouse gas control technologies: Proceedings of the 4th International Conference on Greenhouse Gas Control Technologies, August 30–September 2, 1998, Interlaken, Switzerland, Elsevier, p. 195–200.</ref><ref name=Cooketal_2000>Cook, P. J., A. J. Rigg, and J. Bradshaw, 2000, Putting it back from where it came from: Is geological disposal of carbon dioxide an option for Australia: The Australian Petroleum Production and Exploration Association (APPEA) Journal, v. 40, no. 1, p. 654–666.</ref><ref name=IPCC_2005>Intergovernmental Panel on Climate Change (IPCC), 2005, IPCC special report on carbon dioxide capture and storage, prepared by Working Group III of the IPCC (B. Metz, O. Davidson, H. C. de Connick, M. Loos, and L. A. Meyer, eds): New York, Cambridge University Press, 442 p.</ref>

==Details==

==Details==

In any geological storage site, the injected CO₂ will ultimately be trapped by several of the mechanisms described above. The type of trapping that occurs, and when, is dependent on the dynamic [[flow behavior]] of the CO₂ and the time scale involved. With increasing time, the dominant storage mechanism will change and typically the storage security also increases. [[:file:CO2TrappingMechanisms.JPG|Figure 2]] shows how the initial storage mechanism will dominantly be physical structural and stratigraphic trapping of the immiscible-phase CO₂. With increasing time and migration, more CO₂ is trapped residually in the pore space or is dissolved in the formation water, increasing the storage security. Finally, mineral trapping may occur after the geochemical reaction of the dissolved CO₂ with the host rock mineralogy, permanently trapping the CO₂.

In any geological storage site, the injected CO₂ will ultimately be trapped by several of the mechanisms described above. The type of trapping that occurs, and when, is dependent on the dynamic [[flow behavior]] of the CO₂ and the time scale involved. With increasing time, the dominant storage mechanism will change and typically the storage security also increases. [[:file:CO2TrappingMechanisms.JPG|Figure 2]] shows how the initial storage mechanism will dominantly be physical structural and stratigraphic trapping of the immiscible-phase CO₂. With increasing time and migration, more CO₂ is trapped residually in the pore space or is dissolved in the formation water, increasing the storage security. Finally, mineral trapping may occur after the geochemical reaction of the dissolved CO₂ with the host rock mineralogy, permanently trapping the CO₂.

==Site characterization==

==Site characterization==

The final stage in a detailed site evaluation is the socioeconomic characterization ([[:file:SiteCharacterization.JPG|Figure 3]]). This includes economic modeling to establish such aspects as the likely capital and operating costs, as well as the cost per metric ton of CO₂ avoided. Risk and uncertainty analysis is crucial to establish whether a selected site can be classed as a safe and effective storage site for thousands of years. The design of a monitoring and verification program is dependent on the geological characteristics of the selected site and needs to be carefully evaluated to produce an optimum program both in terms of efficiency and cost.

The final stage in a detailed site evaluation is the socioeconomic characterization ([[:file:SiteCharacterization.JPG|Figure 3]]). This includes economic modeling to establish such aspects as the likely capital and operating costs, as well as the cost per metric ton of CO₂ avoided. Risk and uncertainty analysis is crucial to establish whether a selected site can be classed as a safe and effective storage site for thousands of years. The design of a monitoring and verification program is dependent on the geological characteristics of the selected site and needs to be carefully evaluated to produce an optimum program both in terms of efficiency and cost.

==Geological input to site characterization==

==Geological input to site characterization==

Data challenges are frequently encountered when trying to assess geological storage sites for CO₂ because either the basin under assessment has not been explored by the petroleum industry or, more typically, the site under investigation lies just off-structure and thus commonly outside the major structurally controlled hydrocarbon fields with their dense data sets. In addition, data challenges are also common because of incomplete data sets, data loss, or simple data deterioration with time. Two types of solutions can be considered to overcome the data challenges. The best but most costly solution is data acquisition. Paying several millions of dollars for drilling a well is common, whereas the acquisition and processing of seismic data are equally expensive. A far more cost-effective but also less accurate method of overcoming data challenges is to use [[outcrop]] and [[subsurface]] analog data sets to model the subsurface geology at the storage site. Analog data sets are useful in that they provide generic quantitative data of a range of parameters paramount to a specific geological setting. For example, analogs can be used to predict sand body and shale geometries, connectivities, and heterogeneities. They can also be used for providing ranges and distributions of porosities and permeabilities and for providing estimates on likely seal capacities. Analog data sets to characterize geological storage sites for CO₂ are currently the most affordable and accessible data sets for reservoir characterization.

Data challenges are frequently encountered when trying to assess geological storage sites for CO₂ because either the basin under assessment has not been explored by the petroleum industry or, more typically, the site under investigation lies just off-structure and thus commonly outside the major structurally controlled hydrocarbon fields with their dense data sets. In addition, data challenges are also common because of incomplete data sets, data loss, or simple data deterioration with time. Two types of solutions can be considered to overcome the data challenges. The best but most costly solution is data acquisition. Paying several millions of dollars for drilling a well is common, whereas the acquisition and processing of seismic data are equally expensive. A far more cost-effective but also less accurate method of overcoming data challenges is to use [[outcrop]] and [[subsurface]] analog data sets to model the subsurface geology at the storage site. Analog data sets are useful in that they provide generic quantitative data of a range of parameters paramount to a specific geological setting. For example, analogs can be used to predict sand body and shale geometries, connectivities, and heterogeneities. They can also be used for providing ranges and distributions of porosities and permeabilities and for providing estimates on likely seal capacities. Analog data sets to characterize geological storage sites for CO₂ are currently the most affordable and accessible data sets for reservoir characterization.

==Monitoring==

==Monitoring==

Nonseismic techniques, such as electrical properties, the monitoring of injection processes with changes in stress state, and detecting potential fracture processes through passive seismic measurements, may also be added to the monitoring array. Including geochemical and hydrodynamic sampling to ensure that the injected CO₂ has not leaked from its container and hence verify the integrity of seals is also important. Adding tracers to the injected CO₂, combined with sampling at surface localities, allows rapid detection of any seepage or leakage in the unlikely circumstance that this should occur. Near-surface and surface (soil, water well, and atmospheric) monitoring devices, including tracer and isotope analysis, can be deployed to determine the flux and composition of CO₂ and to distinguish anthropogenic and natural sources of CO₂ from injected CO₂.

Nonseismic techniques, such as electrical properties, the monitoring of injection processes with changes in stress state, and detecting potential fracture processes through passive seismic measurements, may also be added to the monitoring array. Including geochemical and hydrodynamic sampling to ensure that the injected CO₂ has not leaked from its container and hence verify the integrity of seals is also important. Adding tracers to the injected CO₂, combined with sampling at surface localities, allows rapid detection of any seepage or leakage in the unlikely circumstance that this should occur. Near-surface and surface (soil, water well, and atmospheric) monitoring devices, including tracer and isotope analysis, can be deployed to determine the flux and composition of CO₂ and to distinguish anthropogenic and natural sources of CO₂ from injected CO₂.

==Risks==

==Risks==

Induced seismicity is not expected to be a significant problem at geological CO₂ storage sites. Induced seismicity has been documented during hydrocarbon production, EOR, AGI, natural gas storage, and waste injection operations.<ref name=Wallrothetal_1996>Wallroth, T., A. J. Jupe, and R. H. Jones, 1996, Characterization of a fractured reservoir using microearthquakes induced by hydraulic injections: Marine and Petroleum Geology, v. 13, no. 4, p. 447–455.</ref><ref name=Maxwelletal_1998>Maxwell, S. C., R. P. Young, R. Bossu, A. J. Jupe, and J. Dangerfield, 1998, [https://www.onepetro.org/conference-paper/SPE-47276-MS Microseismic logging of the Ekofisk reservoir]: Proceedings of the 1998 Society of Petroleum Engineers/International Society for Rock Mechanics (ISRM) Eurock '98, July 8–10, Trondheim, Norway, SPE Paper No. 47276, 7 p.</ref><ref name=Jupeetal_2000>Jupe, A. J., R. Jones, S. Wilson, and J. Cowles, 2000, [https://www.onepetro.org/conference-paper/SPE-63131-MS The role of microearthquake monitoring in hydrocarbon reservoir management]: Society of Petroleum Engineers Annual Technical Conference and Exhibition, October 1–4, 2000, Dallas, SPE Paper No. 63131, 16 p.</ref> These induced seismic events have been caused by poor engineering practices such as the injection of the CO₂ at too high a pressure, which in turn can result in microfracturing of the reservoir rock and/or small movement along existing fracture lines. Note, however, that most of the recorded events have been of a very small magnitude and have caused no harm. Moreover, the risk of induced seismicity can be reduced through careful siting and placement of injection wells, adherence to proper pressure guidelines, and a sound understanding of the geomechanical properties of the storage reservoir. A range of technologies can be identified by a rigorous process of risk assessment and conformance to clearly identify performance criteria, which can be subsequently verified. These criteria are agreed in conjunction with the regulatory authorities to manage the project through all phases, addressing responsibilities and liabilities and providing assurance of safe storage to the satisfaction of the public at large.

Induced seismicity is not expected to be a significant problem at geological CO₂ storage sites. Induced seismicity has been documented during hydrocarbon production, EOR, AGI, natural gas storage, and waste injection operations.<ref name=Wallrothetal_1996>Wallroth, T., A. J. Jupe, and R. H. Jones, 1996, Characterization of a fractured reservoir using microearthquakes induced by hydraulic injections: Marine and Petroleum Geology, v. 13, no. 4, p. 447–455.</ref><ref name=Maxwelletal_1998>Maxwell, S. C., R. P. Young, R. Bossu, A. J. Jupe, and J. Dangerfield, 1998, [https://www.onepetro.org/conference-paper/SPE-47276-MS Microseismic logging of the Ekofisk reservoir]: Proceedings of the 1998 Society of Petroleum Engineers/International Society for Rock Mechanics (ISRM) Eurock '98, July 8–10, Trondheim, Norway, SPE Paper No. 47276, 7 p.</ref><ref name=Jupeetal_2000>Jupe, A. J., R. Jones, S. Wilson, and J. Cowles, 2000, [https://www.onepetro.org/conference-paper/SPE-63131-MS The role of microearthquake monitoring in hydrocarbon reservoir management]: Society of Petroleum Engineers Annual Technical Conference and Exhibition, October 1–4, 2000, Dallas, SPE Paper No. 63131, 16 p.</ref> These induced seismic events have been caused by poor engineering practices such as the injection of the CO₂ at too high a pressure, which in turn can result in microfracturing of the reservoir rock and/or small movement along existing fracture lines. Note, however, that most of the recorded events have been of a very small magnitude and have caused no harm. Moreover, the risk of induced seismicity can be reduced through careful siting and placement of injection wells, adherence to proper pressure guidelines, and a sound understanding of the geomechanical properties of the storage reservoir. A range of technologies can be identified by a rigorous process of risk assessment and conformance to clearly identify performance criteria, which can be subsequently verified. These criteria are agreed in conjunction with the regulatory authorities to manage the project through all phases, addressing responsibilities and liabilities and providing assurance of safe storage to the satisfaction of the public at large.

==See also==

==See also==

* [[Carbon dioxide (CO2) sequestration]]

* [[Carbon dioxide (CO2) sequestration]]

==References==

==References==

{{reflist}}

{{reflist}}

==External links==

==External links==