Carbon dioxide (CO2) storage

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Carbon dioxide sequestration in geological media: State of the science
Series Studies in Geology
Chapter Geological input to selection and evaluation of CO2 geosequestration sites
Author John G. Kaldi, Catherine M. Gibson-Poole, Tobias H. D. Payenberg
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Figure 1 Options for the geological storage of CO2 (image courtesy of Cooperative Research Centre for Greenhouse Gas Technologies [CO2CRC]).[1]

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 (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.[2][3][4][5]

Details[edit]

The CO2 can be geologically stored in oil and gas fields once they have been depleted and are no longer producing or can be used to enhance oil recovery in fields that are still producing. The main advantages of storage in depleted oil and gas fields are that the containment potential of the site has been proven by the retention of hydrocarbons for millions of years and typically large amounts of geological and engineering data are available for detailed site characterization.[6][5] Possible drawbacks may be the physical size of the structural or stratigraphic trap (i.e., potential storage capacity may be limited), the possibility that pore-pressure depletion has led to pore collapse (which will reduce the potential storage capacity), and the timing of availability of depleted fields with respect to the source of CO2.[7][8][9] In EOR, the CO2 is used to incrementally increase the amount of oil extracted by either immiscible (not mixed) or miscible (mixed together) flooding, thus providing an economic benefit while additionally storing CO2. As with depleted oil and gas fields, the potential storage capacity may be limited because of the physical size of the field.[10][4][5]

The CO2 storage in coalbeds is very different from the storage in oil and gas fields or saline formations because the trapping mechanism is by adsorption as opposed to storage in rock pore space. The CO2 is preferentially adsorbed onto the coal micropore surface, displacing the existing methane (CH4).[11][7][5] The CO2 can be geologically stored in coalbeds that are considered economically unmineable or can be used to enhance coalbed methane recovery. Technical challenges for CO2 storage in coal seams include the ability to inject the CO2, caused by the typically low permeability characteristics of the coal cleat system (especially with increasing depth and coal maturity), and the economic viability, caused by the large number of wells that may need to be drilled.[11][7][5]

Saline formations are deep sedimentary rocks saturated with formation waters that are unsuitable for human consumption or agriculture. They have been identified by many studies as one of the best potential options for CO2 geological storage (e.g., Bachu[12] and Bradshaw et al.[8]). Possible drawbacks of saline formations are that the containment potential of the seal is commonly untested and limited amounts of data are commonly available for site characterization. However, their main advantages are that they are distributed widely over the world and their potential storage capacity is large.[13][14][15][5]

The main geological constraints for finding the right place to store CO2 include a porous and permeable reservoir rock overlain by an impermeable cap rock. Because the stored CO2 is less dense than the formation water, it will naturally rise to the top of the reservoir, and a trap is needed to ensure that it does not reach the surface. The CO2 can be trapped by several different mechanisms (such as structural or stratigraphic, hydrodynamic, residual gas, solubility, and mineral trapping), with the exact mechanism depending on the specific geological conditions. Structural or stratigraphic trapping relates to the free-phase (immiscible) CO2 that is not dissolved into formation water. When supercritical CO2 rises upward by buoyancy, it can be physically trapped in a structural or stratigraphic trap in exactly the same manner as a hydrocarbon accumulation. The nature of a structural or stratigraphic trap depends on the geometric arrangement of the reservoir and seal units. The CO2 can be hydrodynamically trapped in horizontal or dipping reservoirs with no defined structural closures when the dissolved and immiscible CO2 travels with the formation water for very long residence (migration) times of the order of thousands to millions of years.[16] Residual gas trapping occurs when the saturation of CO2 falls below a certain level and it becomes trapped in the pore spaces by capillary pressure forces and ceases to flow.[17][18][19] Solubility trapping relates to the CO2 dissolved into the formation water.[13] The time scale for complete dissolution is critically dependent on the vertical permeability and the geometry of the top seal but is predicted to occur on a scale of hundreds to thousands of years.[20] Mineral trapping results from the precipitation of new carbonate minerals following the interaction of the CO2 with the in-situ formation water and the minerals of the host rock.[21] This storage mechanism is the most permanent of the trapping types discussed because it renders the CO2 immobile.[16]

Figure 2 Schematic representation of the change of dominant trapping mechanisms and increasing CO2 storage security with time.[1]

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. 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[edit]

The subsurface behavior of CO2 is influenced by many variables, including reservoir and seal structural geometry, stratigraphic architecture, reservoir heterogeneity, relative permeability, faults and fractures, pressure and temperature conditions, mineralogical composition of the rock framework, and hydrodynamics and chemistry of the in-situ formation fluids.[22] The nature of geological variability means that each potential storage site needs to be assessed individually; however, a similar workflow can be applied to all site evaluations. The geological complexity of any potential CO2 storage site is best addressed by a multidisciplinary research effort, which can provide an integrated and comprehensive site evaluation for the geological storage of CO2.[23][24]

Figure 3 Site characterization methodology for the geological storage of CO2.[24]

Different levels of site characterization can be undertaken depending on the maturity of the project (Figure 3). Initially, a regional characterization process is needed to establish the potential of an area for CO2 geological storage before an actually site location is selected. Sedimentary basins across a state or country can be screened and ranked as to their overall suitability for CO2 storage, using criteria suggested by Bachu,[25] such as tectonic setting, basin size and depth, intensity of faulting, hydrodynamic and geothermal regimes, existing resources, and industry maturity. Once a basin has been identified as suitable, a regional assessment can be undertaken to locate possible storage sites[7][15][8] (Figure 3). The stratigraphy is reviewed to identify suitable rock combinations that may provide reservoir and seal pairs, and data gathered to assess five key factors: storage capacity (will it meet the volume requirements of currently identified CO2 sources, e.g., pore volume, area, and temperature or pressure?); injectivity potential (are the reservoir conditions viable for injection, e.g., permeability, porosity, and thickness?); site details (is the site economically and technically viable, e.g., onshore or offshore, distance from source, and depth to top reservoir?); containment (will the seal and trap work for CO2, e.g., seal capacity and thickness, trap type, and faults?); and existing natural resources (are there viable natural resources at the site that may be compromised, e.g., proven petroleum system, groundwater, coal, or other natural resource?).[7][15][8] These five factors provide a useful ranking scheme for describing the key elements of any potential CO2 geological storage site and can be used to compare and contrast the relative merits of one potential site over another site.

Once a preferred site has been selected, it can proceed to a detailed site evaluation,[23][24] the first step of which is the establishment of a structural and stratigraphic framework (Figure 3). A sequence-stratigraphic approach is adopted because it focuses on key surfaces that allow lithofacies distributions to be predicted. This is vital in understanding the likely distribution and connectivity of reservoirs and seals. Of the five key factors discussed above, the ones that require detailed geological assessment are injectivity, containment, and capacity. Injectivity issues include the geometry and connectivity of individual flow units, the nature of the heterogeneity within those units (i.e., the likely distribution and impact of baffles), and the physical quality of the reservoir in terms of porosity and permeability characteristics. Containment issues include the distribution and continuity of the seal, the seal capacity (maximum CO2 column height retention), CO2-water-rock interactions (potential for mineral trapping), potential migration pathways (structural trends, distribution and extent of intraformational seals, and formation water flow direction and rate), and the integrity of the reservoir and seal (fault and fracture stability and maximum sustainable pore fluid pressures). Potential CO2 storage capacity can be assessed geologically in terms of available pore volume; however, the efficiency of that storage capacity will be dependent on the rate of CO2 migration, the dip of the reservoir, the heterogeneity of the reservoir and the potential for fill-to-spill structural closures encountered along the migration path, and the long-term prospects of residual gas trapping, dissolution into the formation water, or precipitation into new minerals. The geologically calculated pore volume provides the basis for numerical flow simulations of CO2 injection and storage, which will give a more accurate assessment of how much of the available pore volume is actually used (sweep efficiency).

The engineering characterization phase continues on from the geoscience characterization (Figure 3). Short-term numerical simulation models of the injection phase are needed to provide data on the injection strategy required to achieve the desired injection rates (e.g., number of wells, well design, injection pattern). Postinjection-phase numerical simulations evaluate the long-term storage behavior, modeling the likely migration, distribution, and form of the CO2 in the subsurface. Coupled simulation models, such as geochemical reactive transport, can also be undertaken to further evaluate the CO2 storage potential of a site.

The final stage in a detailed site evaluation is the socioeconomic characterization (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[edit]

The ideal characterization of geological storage sites for CO2 requires a thorough integration of all geoscientific data. Data types change depending on the stage of characterization. Regional assessment requires low-resolution, long-range data sets, such as two-dimensional (2-D) seismic data and stratigraphic drill holes. However, site-specific assessment requires more detailed data such as high-density 2-D or 3-D seismic, core, and many wells and logs. These different types of data are commonly available from petroleum exploration and production.

The regional data sets should be reviewed to evaluate the structural configuration and regional distribution of lithofacies. This is best done using a large 2-D seismic data set complemented with available well-log control and petrophysical data. The aim during this phase is to identify reservoir units with appropriate storage properties (such as adequate porosity for storage of substantial volumes of CO2 and permeability for injectivity and subsequent dissemination into the pore system) overlain by suitably extensive and thick seals.

The high-density data sets are needed to evaluate the reservoir and seal geometries and architectures of the identified storage site in more detail. The aim of a full data set integration and interpretation is to assess the migration pathway of injected CO2 as well as to assess the potential storage volume. This is best done by building a detailed static 3-D reservoir model, which can be upscaled for dynamic fluid flow simulations. Various iterations of the dynamic simulations should be incorporated by an integrated team to better understand the geological effects on CO2 injection, migration, and storage.

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, and 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[edit]

In addition to the careful selection of the subsurface formation, a comprehensive monitoring system needs to be put in place to verify that the CO2 remains in the subsurface. Monitoring of the activities of stored CO2 includes an extensive range of established direct and remote sensing technologies, including petrophysical, geophysical, and geochemical methodologies deployed on the surface and in the borehole. These are used for repeated assessments from a reservoir, containment, wellbore integrity, near-surface, and atmospheric perspective.[26] Wellbore properties such as pressure, temperature, resistivity, and sonic responses can be recorded in injection and observation wells. Geophysical monitoring involves quantification of 3-D and seismic time-lapse imaging of the plume and its migration. This is done using an array of methodologies, including vertical seismic profile (VSP), microseismic data, electromagnetic imaging (EM), and gravity to track the movement of CO2 in the subsurface.[26] This process involves calibration with laboratory determination of in-situ geophysical properties associated with CO2 and developing predictive forward modeling of the behavior of CO2. Detailing results of such modeling and possible acquisition effects on seismic imaging are provided by Arts[27] who describe the injection of CO2 in the Utsira Sand at Sleipner (ongoing since 1996 with almost 10 million tonnes of CO2 injected to date).

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[edit]

Risks surrounding CO2 geosequestration are summarized by Bowden and Rigg.[28] Essentially, the main concerns relate to the potential for unanticipated CO2 leakage either caused by unanticipated CO2 movement up the wellbore or along an unexpected geological migration path or caused by induced or natural seismicity. The risks associated with CO2 storage, although considered very low, are characterized by a greater degree of uncertainty than those connected with CO2 transport and injection. This is because of the fact that once the CO2 enters the geological reservoir, its fate is transferred from mostly human control to a natural system. Although most of the existing knowledge of CO2 behavior in the subsurface exists from the long history of CO2 floods associated with EOR, the risks associated with large-scale storage are at a different scale. The quantities of CO2 stored for EOR floods are smaller, and the CO2 residence times are shorter than required for large-scale carbon geosequestration. For geosequestration of CO2, the risk of leakage depends on not only the likelihood of existence of potential leakage pathways (such as wells, faults, permeable zones in the seal, etc.), but also the likelihood that these potential pathways will intersect CO2 while it is in a mobile phase and finally the likelihood that the potential leakage pathway will leak.[29] As many containment risk assessments are benchmarked against an impact of 1% leakage over 1000 years,[5] the frequency, duration, and volume of potential leakage events need to be assessed for this time frame.[29]

Any geological CO2 storage project resulting in a catastrophic release of CO2 is highly unlikely. This is because the pressure of CO2 injected into a geological reservoir reduces as it moves away from the injection well and is diffused over large areas of the formation, thus avoiding large pressure buildups.[30] No record of a catastrophic CO2 release from a natural CO2 deposit to date (2009) is observed, and any potential release from a CO2 storage project should be preventable through careful site selection, operation, and monitoring. The critical geological input to minimize the risk of such occurrence is seal analysis and geomechanics. The CO2 column height calculations can be used to assess the safe storage volumes of CO2 at any storage site,[31] whereas geomechanical analysis of the faults can be used to assess the maximum sustainable pore fluid pressures at potential storage sites (Streit and Hillis, 2004). Understanding the rock fluid interaction potential between CO2 and contacted minerals is also important. The CO2 creates carbonic acid when it mixes with H2O, and the risk of whether this could potentially result in the chemical erosion of some seal lithologies leading to leakage needs to be addressed. In most instances, because of their low permeability and capillary properties, CO2 is unlikely to enter seals. Therefore, any potential reactions are likely to be limited to the base of the seal. In addition, because the pH buffering capabilities of the seal lithology are generally greater than the dissolution capabilities of carbonic acid, reactions are likely to be mineral precipitation instead of dissolution, thus leading to seal capacity enhancement instead of degradation.[32]

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.[33][34][35] 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[edit]

References[edit]

  1. ↑ 1.0 1.1 Kaldi, J. G., C. M. Gibson-Poole, and T. H. D. Payenberg, 2009, Geological input to selection and evaluation of CO2 geosequestration sites, in M. Grobe, J. C. Pashin, and R. L. Dodge, eds., Carbon dioxide sequestration in geological media—State of the science: AAPG Studies in Geology 59, p. 5–16.
  2. ↑ Cook, P. J., 1998, Carbon dioxide—Putting it back where it came from: Australian Gas Journal, p. 40–41.
  3. ↑ 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.
  4. ↑ 4.0 4.1 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.
  5. ↑ 5.0 5.1 5.2 5.3 5.4 5.5 5.6 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.
  6. ↑ Holloway, S., and D. Savage, 1993, The potential for aquifer disposal of carbon dioxide in the United Kingdom: Energy Conversion and Management, v. 34, no. 9–11, p. 925–932.
  7. ↑ 7.0 7.1 7.2 7.3 7.4 Bradshaw, J., and A. J. Rigg, 2001, The GEODISC program: Research into geological sequestration of CO2 in Australia: Environmental Geosciences, v. 8, no. 3, p. 166–176.
  8. ↑ 8.0 8.1 8.2 8.3 Bradshaw, J., B. E. Bradshaw, G. Allinson, A. J. Rigg, V. Nguyen, and L. Spencer, 2002, The potential for geological sequestration of CO2 in Australia: Preliminary findings and implications for new gas field development: The Australian Petroleum Production and Exploration Association (APPEA) Journal, v. 42, no. 1, p. 25-46.
  9. ↑ Streit, J. E., and A. F. Siggins, 2005, Predicting, monitoring and controlling geomechanical effects of CO2 injection, in E. S. Rubin, D. W. Keith, and C. F. Gilboy, eds., Greenhouse gas control technologies: Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies: Oxford, Elsevier, v. 1, p. 643–651.
  10. ↑ Islam, M. R., and A. Chakma, 1993, Storage and utilization of CO2 in petroleum reservoirs—A simulation study: Energy Conversion and Management, v. 34, no. 9–11, p. 1205–1212.
  11. ↑ 11.0 11.1 Gunter, W. D., T. Gentzis, B. A. Rottenfusser, and R. J. H. Richardson, 1997, Deep coalbed methane in Alberta, Canada: A fuel resource with the potential of zero greenhouse gas emissions: Energy Conversion and Management, v. 38, supplemental, p. S217–S222.
  12. ↑ Bachu, S., 2000, Sequestration of CO2 in geological media: Criteria and approach for site selection in response to climate change: Energy Conversion and Management, v. 41, no. 9, p. 953–970.
  13. ↑ 13.0 13.1 Koide, H., Y. Tazaki, Y. Noguchi, S. Nakayama, M. Iijima, K. Ito, and Y. Shindo, 1992, Subterranean containment and long-term storage of carbon dioxide in unused aquifers and in depleted natural gas reservoirs: Energy Conversion and Management, v. 33, no. 5–8, p. 619–626.
  14. ↑ Hendriks, C. A., and K. Blok, 1993, Underground storage of carbon dioxide: Energy Conversion and Management, v. 34, no. 9–11, p. 949–957.
  15. ↑ 15.0 15.1 15.2 Rigg, A. J., G. Allinson, J. Bradshaw, J. Ennis-King, C. M. Gibson-Poole, R. R. Hillis, S. C. Lang, and J. E. Streit, 2001, The search for sites for geological sequestration of CO2 in Australia: A progress report on GEODISC: The Australian Petroleum Production and Exploration Association (APPEA) Journal, v. 41, no. 1, p. 711–725.
  16. ↑ 16.0 16.1 Bachu, S., W. D. Gunter, and E. H. Perkins, 1994, Aquifer disposal of CO2: Hydrodynamic and mineral trapping: Energy Conversion and Management, v. 35, no. 4, p. 269–279.
  17. ↑ Ennis-King, J., and L. Paterson, 2001, Reservoir engineering issues in the geological disposal of carbon dioxide, in D. J. Williams, R. A. Durie, P. McMullan, C. A. J. Paulson, and A. Y. Smith, eds., Greenhouse gas control technologies: Proceedings of the 5th International Conference on Greenhouse Gas Control Technologies: Cairns, CSIRO Publishing, p. 290–295.
  18. ↑ Holtz, M. H., 2002, Residual gas saturation to aquifer influx: A calculation method for 3-D computer reservoir model construction: Society of Petroleum Engineers Gas Technology Symposium, April 30–May 2, 2002, Calgary, Alberta, Canada, SPE Paper No. 75502, 10 p.
  19. ↑ Flett, M. A., R. M. Gurton, and I. J. Taggart, 2005, Heterogeneous saline formations: Long-term benefits for geo-sequestration of greenhouse gases, in E. S. Rubin, D. W. Keith, and C. F. Gilboy, eds., Greenhouse gas control technologies: Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies: Oxford, Elsevier, v. 1, p. 501–509.
  20. ↑ Ennis-King, J., and L. Paterson, 2002, Engineering aspects of geological sequestration of carbon dioxide: Society of Petroleum Engineers Asia Pacific Oil and Gas Conference and Exhibition, October 8–10, 2002, Melbourne, Australia, SPE Paper No. 77809, 13 p.
  21. ↑ Gunter, W. D., E. H. Perkins, and T. J. McCann, 1993, Aquifer disposal of CO2-rich gases: Reaction design for added capacity: Energy Conversion and Management, v. 34, no. 9–11, p. 941–948.
  22. ↑ Root, R. S., 2007, Geological evaluation of the Eocene Latrobe Group in the offshore Gippsland Basin for CO2 geosequestration: Ph.D. thesis, University of Adelaide, Adelaide, Australia, 265 p.
  23. ↑ 23.0 23.1 Gibson-Poole, C. M., R. S. Root, S. C. Lang, J. E. Streit, A. L. Henning, C. J. Otto, and J. R. Underschultz, 2005, Conducting comprehensive analyses of potential sites for geological CO2 storage, in E. S. Rubin, D. W. Keith, and C. F. Gilboy, eds., Greenhouse gas control technologies: Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies: Oxford, Elsevier, v. 1, p. 673–681.
  24. ↑ 24.0 24.1 24.2 Gibson-Poole, C. M., 2009, Site characterization for geological storage of carbon dioxide: Examples of potential sites from northwest Australia: Unpublished Ph.D. thesis, University of Adelaide, Adelaide, Australia, 258 p.
  25. ↑ Bachu, S., 2003, Screening and ranking of sedimentary basins for sequestration of CO2 in geological media in response to climate change: Environmental Geology, v. 44, no. 3, p. 277–289.
  26. ↑ 26.0 26.1 Dodds, K., D. Sherlock, M. Urosevic, D. Etheridge, D. de Vries, and S. Sharma, 2006, Developing a monitoring and verification scheme for a pilot project, Otway Basin, Australia, in N. A. Rokke, O. Bolland, and J. Gale, eds., Greenhouse gas control technologies: Proceedings of the 8th International Conference on Greenhouse Gas Control Technologies: Trondheim, Norwegian University of Science and Technology (NTNU), SINTEF Technology (SINTEF), and International Energy Agency (IEA) Greenhouse Gas RampD Program, 6 p.
  27. ↑ Arts, R. J., R. A. Chadwick, O. Eiken, S. Dortland, M. Trani, and L. G. H. van der Meer, 2009, Acoustic and elastic modeling of seismic time-lapse data from the Sleipner CO2 storage operation, in M. Grobe, J. C. Pashin, and R. L. Dodge, eds., Carbon dioxide sequestration in geological media—State of the science: AAPG Studies in Geology 59, p. 391–403.
  28. ↑ Bowden, A. R., and A. J. Rigg, 2004, Assessing risk in CO2 storage projects: The Australian Petroleum Production and Exploration Association (APPEA) Journal, v. 44, no. 1, p. 677–702.
  29. ↑ 29.0 29.1 Rigg, A., A. Bowden, M. N. Watson, 2006, Risk assessment of long-term containment of CO2 in geological storage projects: Abstracts volume, AAPG International Conference and Exhibition, November 5–8, 2006, Perth, Australia, v. 16, p. 117.
  30. ↑ Streit, J. E., and R. R. Hillis, 2002, Estimating fluid pressures that can induce reservoir failure during hydrocarbon depletion: Society of Petroleum Engineers/International Society for Rock Mechanics (ISRM) Rock Mechanics Conference, October 2002, Irving, Texas, SPE Paper No. 78226, 7 p.
  31. ↑ Daniel, R. F., and J. G. Kaldi, 2009, Evaluating seal capacity of cap rocks and intraformational barriers for CO2 containment, in M. Grobe, J. C. Pashin, and R. L. Dodge, eds., Carbon dioxide sequestration in geological media—State of the science: AAPG Studies in Geology 59, p. 335–345.
  32. ↑ Watson, M. N., R. F. Daniel, P. R. Tingate, and C. M. Gibson-Poole, 2005, CO2-related seal capacity enhancement in mudstones: Evidence from the pine lodge natural CO2 accumulation, Otway Basin, Australia, in M. Wilson, T. Morris, J. Gale, and K. Thambimuthu, eds., Greenhouse gas control technologies: Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies: Oxford, Elsevier, v. 2, part 2, p. 2313–2316.
  33. ↑ 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.
  34. ↑ Maxwell, S. C., R. P. Young, R. Bossu, A. J. Jupe, and J. Dangerfield, 1998, 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.
  35. ↑ Jupe, A. J., R. Jones, S. Wilson, and J. Cowles, 2000, 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.

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