Bibliography - Thomas R. Elliot

1. Bandilla, K. W., Benjamin Court, Thomas R. Elliot, and Michael Celia, February 2012: Comparison of Brine Production Scenarios for Geologic Carbon Sequestration Operations. Carbon Management Technology Conference, doi:10.7122/151250-MS
   [ Abstract ]

   Large volumes of CO₂ will have to be stored in the subsurface for carbon capture and geological sequestration to have a significant impact on the reduction of carbon emissions. Injection of large volumes of CO₂ into deep saline formations can lead to significant pressure increases within that formation. The increased pressure can be a limiting factor for injection rates; it can also drive vertical brine migration through leakage pathways (e.g., abandoned wells) that could contaminate sources of drinking water. Production of brine from the injection formation can reduce the pressure increase while also limiting the spatial extent of the pressure increase. The impact of brine extraction is investigated using a hypothetical injection domain conditioned by parameters from the Illinois Basin. The domain contains one injection well and encompasses several aquifers connected through diffusive brine leakage. A vertically-integrated approach is used to model the injection formation and overlying aquifers. A set of production scenarios illustrates the impact of brine production on injection rates and vertical brine movement. The scenarios include production with surface disposal and production with reinjection into overlying formations (with and without desalinization). The results show that brine production can reduce the pressure buildup in the injection formation, leading to an increase in injectivity and a concomitant reduction in fresh water contamination risk by reducing the area of potential impact. While reinjection of brine into an overlying aquifer solves the disposal problem, it also reduces the effectiveness of brine production by increasing the pressure. Injection of a smaller amount of more concentrated brine resulting from desalinization reduces the impact of reinjection and acts as an additional source of fresh water, but increases the cost of the injection operation. Based on the results from these numerical experiments pressure management through brine production should be considered for industrial-scale CO₂ injection operations, as it increases injectivity and reduces the size of the area of potential impact. However, the brine disposal problem needs to be solved for brine production to be a useful endeavor.

2. Elliot, Thomas R., and Michael Celia, 2012: Potential restrictions for CO₂ sequestration sites due to shale and tight gas production. Environmental Science and Technology, Washington, DC, American Chemical Society, (February 21, 2012), doi:10.1021/es2040015 1-16
   [ Abstract ]

   Carbon Capture and Geological Sequestration is the only available technology that both allows continued use of fossil fuels in the power sector and reduces significantly the associated CO₂ emissions. Geological sequestration requires a deep permeable geological formation into which captured CO₂ can be injected, and an overlying impermeable formation, called a caprock, that keeps the buoyant CO₂ within the injection formation. Shale formations typically have very low permeability and are considered to be good caprock formations. Production of natural gas from shale and other tight formations involves fracturing the shale with the explicit objective to greatly increase the permeability of the shale. As such, shale gas production is in direct conflict with the use of shale formations as a caprock barrier to CO₂ migration. We have examined the locations in the United States where deep saline aquifers, suitable for CO₂ sequestration, exist, as well as the locations of gas production from shale and other tight formations. While estimated sequestration capacity for CO₂ sequestration in deep saline aquifers is large, up to 80% of that capacity has areal overlap with potential shale-gas production regions and, therefore, could be adversely affected by shale and tight gas production. Analysis of stationary sources of CO₂ shows a similar effect: about two-thirds of the total emissions from these sources are located within 20 miles of a deep saline aquifer, but shale and tight gas production could affect up to 85% of these sources. These analyses indicate that co-location of deep saline aquifers with shale and tight gas production could significantly affect the sequestration capacity for CCS operations. This suggests that a more comprehensive management strategy for subsurface resource utilization should be developed.

3. Gor, Gennady Y., Thomas R. Elliot, and Jean Hervé Prévost, 2012: Effects of thermal stresses on caprock integrity during CO₂ storage. International Journal of Greenhouse Gas Control, Elsevier Ltd., 12, doi:10.1016/j.ijggc.2012.11.020 300-309
   [ Abstract ]

   Subsurface fluid injection results in a pore pressure increase, which induces geomechanical stresses. Additionally, if there exists a difference between the ambient formation temperature and the temperature of injected fluid, thermal stresses can develop. Herein we study the effect of CO₂ injection temperature on caprock integrity using coupled thermo-poromechanical multi-phase simulations. Calculations show that when CO₂ is injected within several years at a temperature below the ambient value in the formation, the stresses above the horizontal injection well lead to tensile or shear failure of the caprock. We study the sensitivity of resulting stresses to the injection temperature, caprock density and initial in situ stresses. We also show that the caprock failure can lead to propagating fractures, which may serve as pathways for CO₂ leakage. Based on the results of our simulations we estimate the rate of fracture propagation and study the effect of caprock permeability on this rate. Our results show that injection of CO₂ at temperature close to the ambient value in the aquifer significantly reduces the risk of caprock fracturing and, therefore, of possible leakage.

4. Court, Benjamin, Thomas R. Elliot, J.A. Dammel, Thomas A. Buscheck, J. Rohmer, and Michael Celia, 2011: Promising synergies to address water, sequestration, legal, and public acceptance issues associated with large-scale implementation of CO₂ sequestration. The Journal for Mitigation and Adaption Strategies for Global Change, Springer, doi:10.1007/s11027-011-9314-x
   [ Abstract ]

   Stabilization of CO₂ atmospheric concentrations requires practical strategies to address the challenges posed by the continued use of coal for baseload-electricity production. Over the next two decades, CO₂ capture and sequestration (CCS) demonstration projects would need to increase several orders of magnitude across the globe in both size and scale. This task has several potential barriers which will have to be accounted for. These barriers include those that have been known for a number of years including safety of subsurface sequestration, pore-space competition with emerging activities like shale gas production, legal and regulatory frameworks, and public acceptance and technical communication. In addition water management is a new challenge that should be actively and carefully considered across all CCS operations. A review of the new insights gained on these previously and newly identified challenges, since the IPCC special report on CCS, is presented in this paper. While somewhat daunting in scope, some of these challenges can be addressed more easily by recognizing the potential advantageous synergies that can be exploited when these challenges are dealt with in combination. For example, active management of water resources, including brine in deep subsurface formations, can provide the additional cooling-water required by the CO₂ capture retrofitting process while simultaneously reducing sequestration leakage risk and furthering efforts toward public acceptance. This comprehensive assessment indicates that water, sequestration, legal, and public acceptance challenges ought to be researched individually, but must also be examined collectively to exploit the promising synergies identified herein. Exploitation of these synergies provides the best possibilities for successful large-scale implementation of CCS.

5. Court, Benjamin, Michael Celia, Jan M. Nordbotten, and Thomas R. Elliot, 2010: Active and Integrated Management of Water Resources Throughout CO₂ Capture and Sequestration Operations. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   Most projected climate change mitigation strategies will require a significant expansion of CO₂ Capture and Sequestration (CCS) in the next two decades. Four major categories of challenges are being actively researched: CO₂ capture cost, geological sequestration safety, legal and regulatory barriers, and public acceptance. Herein we propose an additional major challenge category across all CCS operations: water management. For example a coal-fired power plant retrofitted for CCS requires twice as much cooling water as the original plant. This increased demand may be accommodated by brine extraction and treatment, which would concurrently function as large-scale pressure management and a potential source of freshwater. At present the interactions among freshwater extraction, CO₂ injection, and brine management are being considered too narrowly -in the case of freshwater almost completely overlooked- in the technical and regulatory CCS community. This paper presents an overview of each of these challenges and potential integration opportunities. Active management of CCS operations through an integrated approach -including brine production, treatment, use for cooling, and partial reinjection- can address challenges simultaneously with several synergistic advantages. The paper also considers the related potential impacts of pore space competition (with future groundwater use, gas storage and shale gas) on CCS expansion. Freshwater and brine must become key decision making inputs throughout CCS operations, building on existing successful industrial-scale integrations.

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