Grantee Research Project Results
2011 Progress Report: A Hierarchical Modeling Framework for Geological Storage of Carbon Dioxide
EPA Grant Number: R834385Title: A Hierarchical Modeling Framework for Geological Storage of Carbon Dioxide
Investigators: Celia, Michael A.
Institution: Princeton University
EPA Project Officer: Aja, Hayley
Project Period: December 1, 2009 through November 30, 2013
Project Period Covered by this Report: September 1, 2010 through August 31,2011
Project Amount: $870,009
RFA: Integrated Design, Modeling, and Monitoring of Geologic Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water (2009) RFA Text | Recipients Lists
Research Category: Drinking Water , Water
Objective:
The project has four general goals and objectives to: (1) develop and enhance a set of analytical and numerical computational tools for simulation of CO2 injection, migration, and possible leakage, (2) develop a "hierarchical modeling framework" within which different computational tools can be combined to produce effective hybrid models, (3) provide guidance on level of model complexity for different scenarios, and (4) provide simple-to-use web-based interfaces for different versions of the codes we develop.
Progress Summary:
Objectives 1 and 2:
We continue to expand our ‘simplified’ models to include additional processes. In 2011, we published a paper (Gasda, et al., 2011) in which appropriate upscaled expressions for large‐scale dissolution, enhanced by convective mixing, can be incorporated into our vertically integrated models. In a manuscript that currently is under revision (Gasda, et al., 2012), we added the capability to move away from the sharp interface assumption and include a capillary transition zone. The examples in the paper show the relative importance of all of the important physical processes we have included into the vertically integrated models: large‐scale two‐phase flow of CO2 and brine, residual (capillary) trapping of CO2, dissolution trapping of CO2, and impacts of a capillary transition zone. With these developments, we demonstrate how ‘simplified’ models, whose only assumption is vertical pressure equilibrium, can effectively represent all of these important large‐scale transport and trapping mechanisms. These models also can include both diffuse and concentrated leakage pathways for both CO2 and brine.
We also continue to develop a local analytical correction for interface upconing and pressure drawdown in the vicinity of a leaky fault zone or set of fractures. We have expanded our conceptualization of the fault zone to include three different regions – a central core zone and a damage zone on either side of the core zone. The core is expected to be a low‐permeability feature while the damage zones are higher permeability. This multi‐region approach requires some re‐derivation of our analytical solutions, but the material now is almost complete and we expect to begin writing a manuscript soon.
We have started to investigate a new concept involving CO2 injection based on the idea that water management might need to be considered in conjunction with CO2 management.
This is motivated by the need for additional water at power plants that have capture facilities, the need for pressure control in the injection formation to manage the area of review, the synergistic reduction in leakage potential with active pressure control, and the possible surface use of the produced water and the heat carried with it. These ideas are explored in one of our recent paper (Court et al., 2011). The idea of pressure control seems especially important, given that large‐scale implementation of CCS will most likely lead to spatially extensive regions of elevated pressures (above threshold pressures used to define the area of review) and significant overlap in areas of review among neighboring injection operations (see, for example, the preliminary results in Bandilla et al. (2012)). Broad discussions of the overall concept can be found in Court et al. (2011, 2012b) and Court (2011), and additional technical details can be found in Buscheck et al. (2012).
Figure 1: Simulations of Illinois Basin, using our Vertical Equilibrium models, with total injection of about 140 Mt CO2/yr. Left image shows CO2 plumes, middle image is pressure increase with noactive management, right image is pressure increase with active management of pressure.
A second concept that we have branched into is the potential conflict between shale gas production and use of shale as a caprock for CCS operations. A short manuscript describing our initial analysis is Elliot and Celia (2012), where simple areal analysis of shale gas production and potential CO2 sequestration sites are compared and overlap regions are identified. We see that about 60% of the areal locations identified for potential CO2 sequestration overlap with existing or projected shale and tight gas production, with the overlap area corresponding to about 80% of the storage capacity. While this analysis ignores the vertical dimension, which we recognize can modify significantly the final measure of interference, this still calls attention to the possible conflict in subsurface usage and the concomitant reduction in potential CO2 storage capacity.
Figure 2: Overlap of saline basins identified by NATCARB as ideal storage formations, overlain with the EIA identified tight and shale gas basins, which could be used for unconventional gas production. The gas basins overlap over 60% of the targeted saline formations within the contiguous continental United States.
Objective 3:
We have analyzed and described the conditions under which two important assumptions can be made: (i) the assumption of vertical equilibrium, and (ii) the assumption of a sharp interface. The first is based on the strongly buoyant fluids having sufficient time to segregate by buoyancy; as such, it is a time‐scale argument. The second is based on the length scale of the capillary transition zone, which is related directly to the local capillary pressure – saturation relationship. As such, it is a length‐scale argument. In the paper of Court et al. (2012a), we present details of these arguments, and show the conditions under which these assumptions appear to be reasonable. We also look at the range of parameter values used in CO2 sequestrations simulations reported in the literature and see a very wide range of implied capillary transition zones. These have potentially important implications for behavior of numerical models and the kinds of results that can be obtained. Additional information can also be found in Court (2011).
We also published two papers focusing on leakage estimation using a particular location in the Alberta Basin for a hypothetical injection operation. In Celia et al. (2011) we look at the parameters that are important to estimate leakage along old wells, and in Nogues et al. (2012) we relate the most important parameters describing the uncertainty in leaky well properties to maximum probable leakage values.
Objective 4:
We held a workshop in Princeton in December 2010 focused on model complexity and the role of simplified models. The workshop included academics, representatives from industry, and representatives from the EPA. Two days of lively discussions and presentations focused on how simple modeling can be done while still capturing the essential features of the underlying processes. There appeared to be general consensus among this international group that was summed up by one participant who said that “ninety percent of our learning is achieved through simple models.”
The most significant accomplishments during this reporting period are:
(1) We now have a simplified vertical equilibrium model that can simulate multi‐phase flows, dissolution including convective mixing, capillary trapping, and leakage. Application to realistic injection sites shows its utility.
(2) We have identified conditions under which the assumption of vertical equilibrium is appropriate, based on time‐scale analysis. We have also identified the conditions under which the sharp‐interface assumption is appropriate, based on length‐ scale analysis associated with the capillary transition zone. We have also shown that when these assumptions are valid, there is excellent match between our models and full three‐ dimensional models like the industry standard Eclipse.
(3) We have expanded our studies to include active management of brine in injection formations, motivated in part by the need to control pressure buildup in the formation. Corollary benefits include reduction in potential leakage for both CO2 and brine, and possible surface use of water and/or heat associated with the extracted brine.
(4) We performed a first analysis the spatial overlap between areas where hydraulic fracturing of shale is or might take place and areas identified as suitable for CO2 storage. The areal overlap is about 60%, with that overlap corresponding to close to 80% of the storage capacity for CO2 injection. This overlap can reduce potential CO2 storage capacity because fractured shales are unlikely to be suitable caprocks for CO2 storage operations.
Future Activities:
We will continue to work on all four objectives, and we also will continue to pursue new and interesting directions as they arise. Two examples that already have arisen in this work are the idea of active management through brine extraction and the analysis of competition for subsurface resources between shale gas and CO2 storage. We also hope to be able to interact more with our partners at EPA, especially in Athens.
Journal Articles on this Report : 8 Displayed | Download in RIS Format
Other project views: | All 25 publications | 18 publications in selected types | All 18 journal articles |
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Type | Citation | ||
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Buscheck TA, Sun YW, Chen MJ, Hao Y, Wolery TJ, Bourcier WL, Court B, Celia MA, Friedmann SJ, Aines RD. Active CO2 reservoir management for carbon storage: analysis of operational strategies to relieve pressure buildup and improve injectivity. International Journal of Greenhouse Gas Control 2012;6:230-245. |
R834385 (2011) R834385 (2012) R834385 (Final) |
Exit Exit Exit |
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Celia MA, Nordbotten JM, Court B, Dobossy M, Bachu S. Field-scale application of a semi-analytical model for estimation of CO2 and brine leakage along old wells. International Journal of Greenhouse Gas Control 2011;5(2):257-269. |
R834385 (2010) R834385 (2011) R834385 (2012) R834385 (Final) |
Exit Exit Exit |
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Court B, Bandilla KW, Celia MA, Buscheck TA, Nordbotten JM, Dobossy M, Janzen A. Initial evaluation of advantageous synergies associated with simultaneous brine production and CO2 geological sequestration. International Journal of Greenhouse Gas Control 2012;8:90-100. |
R834385 (2011) R834385 (2012) R834385 (Final) |
Exit Exit Exit Exit |
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Court B, Bandilla KW, Celia MA, Janzen A, Dobossy M, Nordbotten JM. Applicability of vertical‐equilibrium and sharp‐interface assumptions in CO2 sequestration modeling. International Journal of Greenhouse Gas Control 2012;10:134-147. |
R834385 (2011) R834385 (2012) R834385 (Final) |
Exit Exit Exit Exit |
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Elliot TR, Celia MA. Potential restrictions for CO2 sequestration sites due to shale and tight gas production. Environmental Science & Technology 2012;46(7):4223-4227. |
R834385 (2011) R834385 (2012) R834385 (Final) |
Exit Exit |
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Gasda SE, Nordbotten JM, Celia MA. Vertically-averaged approaches for CO2 migration with solubility trapping. Water Resources Research 2011;47(5):W05528. |
R834385 (2010) R834385 (2011) R834385 (2012) R834385 (Final) |
Exit Exit Exit Exit |
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Gasda SE, Nordbotten JM, Celia MA. Application of simplified models to CO2 migration and immobilization in large-scale geological systems. International Journal of Greenhouse Gas Control 2012;9:72-84. |
R834385 (2011) R834385 (2012) R834385 (Final) |
Exit Exit Exit |
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Nogues JP, Court B, Dobossy M, Nordbotten JM, Celia MA. A methodology to estimate maximum probable leakage along old wells in a geological sequestration operation. International Journal of Greenhouse Gas Control 2012;7:39-47. |
R834385 (2011) R834385 (2012) R834385 (Final) |
Exit Exit |
Progress and Final Reports:
Original AbstractThe perspectives, information and conclusions conveyed in research project abstracts, progress reports, final reports, journal abstracts and journal publications convey the viewpoints of the principal investigator and may not represent the views and policies of ORD and EPA. Conclusions drawn by the principal investigators have not been reviewed by the Agency.