Basin-scale hydrogeologic impacts of CO2 storage: Capacity and regulatory implications

https://doi.org/10.1016/j.ijggc.2009.07.002Get rights and content

Abstract

Industrial-scale injection of CO2 into saline formations in sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration aquifers. In this paper, we discuss how such basin-scale hydrogeologic impacts (1) may reduce current storage capacity estimates, and (2) can affect regulation of CO2 storage projects. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO2 storage projects (sites) in a core injection area most suitable for long-term storage. Each project is assumed to inject five million tonnes of CO2 per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO2–brine flow processes and the large-scale groundwater flow patterns in response to CO2 storage. The far-field pressure buildup predicted for this selected sequestration scenario support recent studies in that environmental concerns related to near- and far-field pressure buildup may be a limiting factor on CO2 storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO2, may have to be revised based on assessments of pressure perturbations and their potential impacts on caprock integrity and groundwater resources. Our results suggest that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrogeologic response may be affected by interference between individual storage sites. We also discuss some of the challenges in making reliable predictions of large-scale hydrogeologic impacts related to CO2 sequestration projects.

Introduction

Geologic carbon sequestration (GCS) in deep formations (e.g., saline aquifers, oil and gas reservoirs, and coalbeds) has drawn increasing consideration as a promising method to mitigate CO2 emissions and associated climate change (IPCC, 2005). The amounts of CO2 that would need to be injected and stored underground to make a noticeable impact on atmospheric emissions are very large. Releases of anthropogenic CO2 into the atmosphere is currently almost 30 Gt (billion metric tonnes) per year. At typical in situ densities of stored CO2, the corresponding fluid volume would be about eight times larger than the current annual world oil production. This means that geologic storage of 15% of the anthropogenic CO2 emissions would require a fluid-handling system larger than that in place for world oil production.

By far the greatest storage capacity is in saline aquifers (Dooley et al., 2004, IPCC, 2005), and our discussion will focus primarily on CO2 storage in saline formations. Injection of CO2 into deep saline aquifers will impact subsurface volumes much larger than the CO2 plumes themselves. An industrial-scale CO2 storage project for a large coal-fired power plant of 1000 MW generation capacity will generate, over a typical lifetime, a subsurface plume with linear dimensions of 10 km or more, while pressurization of more than 0.1 MPa would likely occur over basin-scale regions with dimensions of 100 km and more (Pruess et al., 2003). Such large-scale pressure changes may have environmental impacts on shallow groundwater resources, i.e., causing water table rise, increasing rates of discharge into lakes or streams, and/or mixing of displaced native brine into drinking water aquifers (Bergman and Winter, 1995). The level of impact depends mainly on the magnitude and extent of pressure buildup in a deep storage formation and the hydraulic communication with overlying freshwater aquifers (Birkholzer et al., 2009).

One scenario where freshwater aquifers could be impacted is CO2 injection into the deep (downdip) saline part of an extensive formation that holds potable groundwater in its shallow updip part (Nicot, 2008). Freshwater resources may also be affected if high-permeability conduits such as conductive faults and abandoned boreholes provide local conduits for pressure perturbation and brine migration. In addition, the sealing layers that separate deep storage formations from overlying freshwater aquifers may pinch out at some distance from injection sites, have higher local breaches due to erosional channels, and/or may be degraded geomechanically because of overpressure in the storage formations. All these would allow for increased interlayer communication. Finally, land-surface deformation or uplift is expected in response to large-scale pressure increases, which may change surface and subsurface flow patterns, even without a direct hydraulic impact of brine displacement. The reverse effect, land subsidence in response to groundwater withdrawal (e.g., for water supply and agriculture) or oil production, is a common problem throughout the United States (USGS, 1999).

Concerns about large-scale pressure buildup and brine migration caused by industrial-scale CO2 sequestration, and their possible environmental impacts, have been raised as early as in the 1990s (van der Meer, 1992, Bergman and Winter, 1995, Gunter et al., 1996). Since then, less emphasis has been placed on evaluating large-scale pressure changes and understanding the fate of native brines displaced by injected CO2. Most research on geologic storage of CO2 has instead focused on evaluating the hydrogeologic conditions under which the injected volumes of CO2 can be safely stored, addressing issues such as the long-term efficiency of structural trapping of CO2 under sealing units and the possibility of CO2 leakage through faults and boreholes. The same focus has been seen in risk assessment efforts (e.g., Stenhouse et al., 2006, Pawar et al., 2006, Oldenburg et al., 2008, Oldenburg et al., 2009, Viswanathan et al., 2008, Stauffer et al., 2009), as well as in discussions on and recommendations for regulatory and permitting frameworks. Meanwhile, estimates of regional storage capacity for CO2 sequestration have been based on simple calculations of the fraction of total reservoir pore space available for safe trapping of CO2 (Bradshaw et al., 2007, Bachu et al., 2007, USDOE, 2008), making the underlying assumption of “open” formations from which native brine can easily escape laterally and make room for injected CO2. Moreover, the field experiments of CO2 storage to date have primarily been quite small and were conducted to improve our understanding of CO2 injectivity and migration patterns, and to test methods of monitoring and modeling of CO2 migration (e.g., the Frio experiment as described in Hovorka et al., 2006). Because the injected fluid volumes have been so small, on the order of several thousand to several ten-thousand tonnes of CO2, pressure buildup was not significant.

Only recently have researchers paid more attention to evaluating the large-scale pressure responses expected for future industrial-scale carbon sequestration, in part on the basis of modeling studies for hypothetical sequestration scenarios. A simulation study of CO2 injection into compartmentalized saline formations (Zhou et al., 2008) suggests small storage capacity because strong pressurization occurs and geomechanical damage must be avoided. van der Meer and Egberts (2008) and van der Meer and Yavuz (2008) introduced the concept of “total affected space” defined as the region affected by CO2 plume migration and brine pressurization. Both studies point out that the storage capacity in bounded reservoirs is limited by a yet-to-be-defined maximum allowable pressure increase and the compressibility of the fluids and pore space in the affected area. Birkholzer et al. (2009) modeled CO2 migration and pressure response in an idealized, laterally open groundwater system, comprising a sequence of laterally extensive aquifers and aquitards (sealing units) that extend from the deep saline storage formation to the uppermost freshwater aquifers. Based on the results from a variety of sensitivity cases, the authors concluded that the hydraulic characteristics of sealing units strongly affect the lateral and vertical volumes affected by pressure buildup.

Nicot (2008) employed a single-phase flow model to simulate the regional-scale brine flow processes in response to hypothetical future CO2 sequestration in the Texas Gulf Coast Basin, approximating the injection of CO2 by adding equivalent volumes of saline water. Built on a calibrated regional-scale groundwater flow model, the single-phase flow model reasonably represents the far-field procceses and basin-scale impacts, without accounting for local two-phase CO2–brine flow, variable density effects, and CO2 compressibility effects (Nicot et al., 2008a). Yamamoto et al. (2009) reported on a high-performance multi-million gridblock model capable of evaluating local CO2–brine flow processes together with large-scale groundwater patterns, applied to a possible future CO2 storage scenario in the Tokyo Bay, Japan. The above model results suggest that the basin-scale hydrogeologic impacts related to pressure buildup and brine migration may affect the way CO2 storage projects will be regulated. These impacts may in fact be the limiting factor determining the CO2 sequestration capacity in large sedimentary basins.

In this paper, we elaborate on the issue of large-scale pressure buildup limitations on storage capacity and ensuing regulatory aspects, using the Illinois Basin in the midwest United States as an illustrative example. The Illinois Basin, a deep saline sedimentary basin of roughly 155,000 km2 encompassing most of Illinois, southwestern Indiana, and western Kentucky in the United States (Fig. 1), hosts a significant number of large stationary CO2 emitters (MGSC, 2005, NETL, 2009). If mitigation of climate change via carbon capture and storage is seriously attempted in the United States, the Illinois Basin will be one of the most important target regions for geologic storage of carbon dioxide in the United States. Extensive site characterization has been completed and a large-scale field project is ongoing to demonstrate the suitablity of the regionally extensive Mount Simon Sandstone as a storage formation. We developed a regional-scale three-dimensional (3-D) model for the Illinois Basin that captures both the local-scale CO2–brine flow processes and the large-scale groundwater flow patterns in response to a hypothetical future carbon sequestration scenario, which involves twenty individual CO2 storage sites in a core injection area most suitable for long-term storage.

Section 2 introduces briefly the geologic and numerical models and describes selected prediction results. A comprehensive paper with focus on the model development and detailed results is being published concurrently (Zhou et al., submitted for publication). In Section 3, the model results are used to demonstrate that CO2 storage capacity of a given basin, estimated using the effective pore volume available for safe trapping of CO2, might have to be revised down based on assessment of pressure buildup and its potential hydrogeologic impacts on freshwater aquifers. Section 4 discusses some of the challenges in making reliable predictions of large-scale hydrogeologic impacts of CO2 sequestration projects and makes tentative suggestions for better understanding and constraining the processes and parameters driving brine pressurization. Section 5 finally demonstrates the importance of understanding large-scale pressure and brine migration patterns for regulating CO2 storage projects.

While the model development is based on the best information currently available, we caution that the Illinois Basin study discussed here is preliminary, that some simplifications had to be made in the model design, and that considerable uncertainty regarding the large-scale geological model needs to be acknowledged. Further site characterization efforts are underway, and model predictions of hydrogeologic impacts may change as more details for future storage scenarios are being developed. Readers should view this paper as an attempt to illustrate the important implications of basin-scale impacts of CO2 sequestration, using a realistic but not necessarily accurate example that may be representative of many other sedimentary basins worldwide.

Section snippets

Illinois Basin modeling example

The Illinois Basin region has annual CO2 emissions of slightly over 300 Mt (million metric tonnes) from stationary sources, primarily from large coal-fired power plants (USDOE, 2008). The primary target for CO2 storage in the region is the Mount Simon Sandstone, a deep saline aquifer of high permeability, porosity, and sufficient thickness, with proven regional seals (MGSC, 2005). With a large estimated storage capacity (USDOE, 2008), the Mount Simon Formation is expected to host multiple

Capacity implications

High-level estimates of regional or global storage capacity for CO2 sequestration in saline formations have typically been based on simple calculations of the fraction of the total reservoir pore space available for safe storage of CO2 (Bradshaw et al., 2007, USDOE, 2008). Such capacity assessments start with delineating reservoirs in a basin or region suitable for deep geologic storage (sufficient depth and injectivity), followed by calculating the total storage capacity as a fixed fraction of

Prediction uncertainties

From the standpoint of fluid dynamics, brine pressurization and migration is a much simpler process than two-phase flow of CO2–brine mixtures. The challenge for predictive modeling is not in fundamental process issues, but rather in obtaining a sufficiently detailed and realistic characterization of large subsurface volumes, in order to be able to place meaningful and reliable limits on quantities and pathways for pressure buildup and brine migration. The propagation of pressure changes in a

Implications for the evolving regulatory framework in the United States

While the regulatory environment for geologic carbon sequestration projects is still evolving, it is clear that one aspect of permitting is the protection of valuable groundwater resources. Since groundwater quality can be affected by intrusion of CO2 as well as by brine intrusion, the permitting requirements will need to include some assessment of CO2 leakage risk as well as some assessment of large-scale pressure buildup and associated potential for brine migration. The United States

Summary and conclusions

We evaluated regional-scale brine pressurization and migration related to a hypothetical future carbon sequestration scenario in the Illinois Basin in the midwest United States. The area hosts a significant number of large stationary CO2 emitters and will be one of the most important regions for geologic storage of carbon dioxide in the United States. A regional-scale 3-D simulation model was developed for the Illinois Basin to capture both the local-scale CO2–brine flow processes and the

Acknowledgments

The authors wish to thank Curtis Oldenburg of Lawrence Berkeley National Laboratory for a careful review of the manuscript and the suggestion of improvements. Thanks are also due to Edward Mehnert, Hannes Leetaru, and other colleagues at the Illinois State Geological Survey for their substantial contributions in developing the Illinois Basin model. This work was funded by the Assistant Secretary for Fossil Energy, Office of Sequestration, Hydrogen, and Clean Coal Fuels, National Energy

References (43)

  • L.G.H. van der Meer

    Investigations regarding the storage of carbon dioxide in aquifers in The Netherlands

    Energy Convers. Manage.

    (1992)
  • H. Yamamoto et al.

    Numerical investigation concerning the impact of CO2 geologic storage on regional groundwater flow

    Int. J. Greenhouse Gas Control

    (2009)
  • Q. Zhou et al.

    A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

    Int. J. Greenhouse Gas Control

    (2008)
  • M. Bergman et al.

    Disposal of carbon dioxide in aquifers in the U.S.

    Energy Convers. Manage.

    (1995)
  • Birkholzer, J.T., Zhou, Q., Zhang, K., Jordan, P., Rutqvist, J., Tsang, C.F., 2008. Research Project on CO2 Geological...
  • J.J. Dooley et al.

    A first-order global geological CO2-storage potential supply curve and its application in a global integrated assessment model

  • C. Doughty et al.

    Site characterization for CO2 geologic storage and vice versa: the Frio brine pilot, Texas, USA as a case study

    Environ. Geol.

    (2008)
  • S.D. Hovorka et al.

    Measuring permanence of CO2 storage in saline formations: the Frio experiment

    Environ. Geosci.

    (2006)
  • IPCC (Intergovernmental Panel on Climate Change), 2005. IPCC Special Report on Carbon Dioxide Capture and Storage....
  • ISWS (Illinois State Water Survey) and Hittman Associates, 1973. Feasibility Study on Desalting Brackish Water from the...
  • MGSC (Midwest Geological Sequestration Consortium), 2005. An Assessment of Geological Carbon Sequestration Options in...
  • Cited by (230)

    View all citing articles on Scopus
    View full text