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Basin-scale modeling can be informative with respect to issues that may be faced in the future 

with multiple injection projects using the same storage reservoir in a given basin. The work of 

Birkholzer, Zhou and others (referred to as the authors herein) is illustrative in this regard in that 

it utilizes an actual but not yet fully characterized basin framework. In assessing the pressure 

field and brine migration potential developed as part of this work, it has to be clearly noted, 

however, that a spacially concentrated and certainly arbitrary injection scenario was required to 

generate the perturbations resulting in the model outcomes. The scenario was designed to create 

these perturbations and in itself is a far-end member of the range of scenarios that might be 

utilized. Certain assumptions also had to be made regarding increases in seal permeability to 

generate the model results and these assumptions need significant refinement. As such, this is 

acceptable as a modeling exercise and as a guide to future studies but not as a predictable 

outcome or even a generalized outcome, and in fact the authors call for further strategies for 

pressure monitoring and the improvement of predictive models. Although the authors highlight 

far-field impacts, it is premature for U.S. EPA to consider any basin-scale mandates other than 

intensive data collection and assessment, including support for improvement in basin-scale 

simulation models that are indicators of large-scale hydrologic impacts. This work must be taken 

as an indicator of a research need, given the hypothetical concentration of twenty large storage 

projects in a limited area, not of the need for developing any specific basin-scale regulations as 

part of the current Class VI development process. The latter approach would be 

counterproductive in that it may negate: (1) the development of multiple initial projects essential 

to more definitively define the very safeguards that groundwater protection strategies are 

designed to achieve, and (2) suppress the realization of more appropriate injection scenarios 

(rate, period, and placement) that would yield more realistic results than the inputs selected for 

the author’s modeling. 

Support of this position is found in the authors work. They cite a Darcy flow velocity across the 

top model boundary, averaged over the model domain, of 0.47 mm/year at 50 years of injection 

and an average Darcy velocity across the lateral boundaries of about half that value. The authors 

then go on to state: “The lateral migration distances of saline water associated with these 

boundary flows do not constitute a concern for the groundwater resources in overlying aquifers 

or neighboring basins.” The authors also note that current groundwater withdrawal practices in 

the northern Illinois Basin are pulling saline water toward some water wells, and that “these 

impacts dwarf the predicted environmental consequences of the hypothetical CO2 storage 

scenario studied...”. 

New data are being developed as a result of currently funded sequestration deployment testing. 

An example of the impacts of incompletely known chosen parameters can be seen in the 

discussion of hydraulic diffusivity. Recent work in the Illinois Basin indicates that the porosity 

value chosen for the modeling is low relative to higher porosity values obtained from recent 

drilling in the model injection area, thus recent data would tend to reduce the pressure-affected 

region outside of the injection area. The authors narrate a sensitivity case that, they state, would 

reduce the region from 190 km to only 60 km in radius, but would also be dependent on lower 

permeability and greater compressibility, as well as the higher porosity. Again, initial storage 

project development must occur to better define key parameters. 

Further, it is also important to recognize that the discussion of the capacity assessments for the 

basin compared to the 50-year, 5,000 Mt perturbation in the model confuses the sequestration 

resource with basin capacity and the numbers in the DOE atlas are resources, not capacity. There 

is no expectation that the early DOE resource assessments would represent actual capacity. The 
authors statement that these resource estimates are subject to “an implicit assumption that the 

storage capacity is not constrained by pressure buildup and brine migration...” is incorrect, and 

researchers involved with creating these estimates would be unlikely to agree with this 

assumption. These are not undue criticisms of the work, simply an indication that definitions 

need to be refined and common terminology needs to become more widespread. The authors 

conclude that in a basin with multiple storage sites, industrial-scale storage projects are needed to 

supply valuable data “to reliably estimate the expected pressure impacts of later projects”. That 

is certainly where we must go to answer key questions while acknowledging that the state of 

understanding of modeling basin-scale sequestration impacts is in its early stages and is 

premature for rule making at this time. 
Letter ID: 0337  

Commenter: Robert J. Finley  

Organization: Illinois State Geological Survey  

Letter ID: 0337 Comment ID: 28002 Letter Lines: 17 to 82  

Comment Code: 2220 2.2.2. Basin‐Scale Hydrologic Impacts of CO2 Storage (seeking comment)  

Comment: Basin‐scale modeling can be informative with respect to issues that may be faced  

in the future with multiple injection projects using the same storage reservoir  

in a given basin. The work of Birkholzer, Zhou and others (referred to as the  

authors herein) is illustrative in this regard in that it utilizes an actual but  

not yet fully characterized basin framework. In assessing the pressure field and  

brine migration potential developed as part of this work, it has to be clearly  

noted, however, that a spacially concentrated and certainly arbitrary injection  

scenario was required to generate the perturbations resulting in the model  

outcomes. The scenario was designed to create these perturbations and in itself  

is a far‐end member of the range of scenarios that might be utilized. Certain  

assumptions also had to be made regarding increases in seal permeability to  

generate the model results and these assumptions need significant refinement. As  

such, this is acceptable as a modeling exercise and as a guide to future studies  

but not as a predictable outcome or even a generalized outcome, and in fact the  

authors call for further strategies for pressure monitoring and the improvement  

of predictive models. Although the authors highlight far‐field impacts, it is  

premature for U.S. EPA to consider any basin‐scale mandates other than intensive  

data collection and assessment, including support for improvement in basin‐scale  

simulation models that are indicators of large‐scale hydrologic impacts. This  

work must be taken as an indicator of a research need, given the hypothetical  

concentration of twenty large storage projects in a limited area, not of the  

need for developing any specific basin‐scale regulations as part of the current  

Class VI development process. The latter approach would be counterproductive in  

that it may negate: (1) the development of multiple initial projects essential  

to more definitively define the very safeguards that groundwater protection  

strategies are designed to achieve, and (2) suppress the realization of more  

appropriate injection scenarios (rate, period, and placement) that would yield  

more realistic results than the inputs selected for the author’s modeling.  

Support of this position is found in the authors work. They cite a Darcy flow  

velocity across the top model boundary, averaged over the model domain, of 0.47  

mm/year at 50 years of injection and an average Darcy velocity across the  
lateral boundaries of about half that value. The authors then go on to state:  

"The lateral migration distances of saline water associated with these boundary  

flows do not constitute a concern for the groundwater resources in overlying  

aquifers or neighboring basins." The authors also note that current groundwater  

withdrawal practices in the northern Illinois Basin are pulling saline water  

toward some water wells, and that "these impacts dwarf the predicted  

environmental consequences of the hypothetical CO2 storage scenario studied...".  

New data are being developed as a result of currently funded sequestration  

deployment testing. An example of the impacts of incompletely known chosen  

parameters can be seen in the discussion of hydraulic diffusivity. Recent work  

in the Illinois Basin indicates that the porosity value chosen for the modeling  

is low relative to higher porosity values obtained from recent drilling in the  

model injection area, thus recent data would tend to reduce the pressure‐  

affected region outside of the injection area. The authors narrate a sensitivity  

case that, they state, would reduce the region from 190 km to only 60 km in  

radius, but would also be dependent on lower permeability and greater  

compressibility, as well as the higher porosity. Again, initial storage project  

development must occur to better define key parameters. Further, it is also  

important to recognize that the discussion of the capacity assessments for the  

basin compared to the 50‐year, 5,000 Mt perturbation in the model confuses the  

sequestration resource with basin capacity and the numbers in the DOE atlas are  

resources, not capacity. There is no expectation that the early DOE resource  

assessments would represent actual capacity. The authors statement that these  

resource estimates are subject to "an implicit assumption that the storage  

capacity is not constrained by pressure buildup and brine migration..." is  

incorrect, and researchers involved with creating these estimates would be  

unlikely to agree with this assumption. These are not undue criticisms of the  

work, simply an indication that definitions need to be refined and common  

terminology needs to become more widespread. The authors conclude that in a  

basin with multiple storage sites, industrial‐scale storage projects are needed  

to supply valuable data "to reliably estimate the expected pressure impacts of  

later projects". That is certainly where we must go to answer key questions  

while acknowledging that the state of understanding of modeling basin‐scale  

sequestration impacts is in its early stages and is premature for rule making at  

this time.  

Individual Response: EPA agrees with the commenter regarding the need for comprehensive site

characterization and data review of large‐scale saline formations. The final GS rule requires owners or

operators of GS wells to delineate the AoR for GS sites using computational fluid flow models designed

for the specific site conditions and injection regime (e.g., current injection activities). Periodic revisions

and recalibrations of the models must be conducted as described in the approved AoR and corrective

action plan required at 146.84. The final rule also requires monitoring of the plume and the pressure
front throughout the injection phase (146.90). For additional information regarding EPA’s requirements

for AoR delineation for GS projects, see the responses to comments on the proposed rule in the

rulemaking docket.

EPA acknowledges the need for improvement/validation of predictive models before considering basin‐

scale mandates, and will continue to collect and review data on early GS projects as part of its adaptive

rulemaking approach. EPA recognizes that inter‐state and even international cooperation may be

necessary where multiple injection operations may interact, but has no plans or authority to develop a

basin‐wide regulatory process. The final GS rule focuses on permitting of individual GS wells and

therefore does not include requirements for basin‐scale evaluations. EPA notes, however that the GS

rule, at §146.82(b), requires that the Director notify representatives of all states, tribes, and territories

in the AoR to inform them of the permit application and offer them an opportunity to be involved in any

relevant activities, such as development of the required project‐specific plans.

Regarding the comment that the paper presents a spatially concentrated and arbitrary injection

scenario, EPA notes that, considering the large volumes that need to be sequestered to make a

contribution to climate change mitigation and the volumes that are produced from large stationary

sources, it may be unrealistic to assume that storage sites can be placed so far from each other that

their pressure envelopes would never overlap. The spatial pattern of GS projects used in LBNL’s work

was developed by placing the 20 storage sites into the center area of the example basin where the

geological conditions were most favorable for CO2 storage.

Regarding the assumption about seal permeability, the base simulation case in the basin‐scale model

used vertical permeability of seal of 1.0 × 10‐18 m2. A sensitivity case was studied in Birkholzer et al.

(2009) assuming a seal permeability of 1.0 × 10‐20 m2. A higher seal permeability allows for pressure

attenuation in the storage formation caused by slow diffuse brine migration into the seals. The two

simulation cases reflect the range of seal properties available for the example basin, from core scale

measurements and regional scale estimates (Zhou et al., 2009).

Regarding capacity, while EPA acknowledges differences in terminology (e.g., the resource estimates

provided in USDOE (2008) correspond to effective capacities in the definition given in CSLF (2008) and

the USDOE capacity estimates correspond to the CSLF practical capacities) the point Birkholzer and Zhou

(2009) are trying to make is that the practice of estimating resource (or effective capacity) via efficiency

factors does not include pressure and brine migration constraints.