Quantitative Evaluation of CO2 Storage Potential in the Offshore Atlantic Lower Cretaceous Strata, Southeastern United States
Round 1
Reviewer 1 Report
This paper presents a quantitative assessment of CO2 storage potential in the Lower Cretaceous section on the outer continental shelf of the southeastern US. It is based on legacy industry 2D seismic data and three geophysical well logs. The paper presents very interesting results, and it is generally well written. I recommend publication of the manuscript with minor to moderate revisions. I did not check the mathematical calculations, but the methodology appears scientifically sound, and the co-authors have a very good research publication track record. The paper is well organized and the figures are well done. Most of my comments are relatively minor English usage corrections and are annotated on the attached manuscript.
I only noted several important issues to address.
1. Table 1, P10, P50, and P90 represent 10, 50. and 90 percent probability? Why is the 90% probability the highest saline formation efficiency? It appears that the probabilities are reversed (i.e. the values for P10 are actually the values for P90). Please check this throughout the paper. This mistake is repeated in Table 6 and Table 7. (Figures 8 and 9 appear to be drawn correctly with higher probabilities associated with lower CO2 storage capacities.)
2. Figure 6B. It would be good to comment on the updip seal along the coastline. It is not clear how this will work from the top Cretaceous map, since no closure is indicated on the map. A cartoon cross section would be helpful. The figure letters in the caption are incorrect.
My other comments are minor, including
1. Introduction lines 43-46 and Geologic Framework lines 91-95. Omit repeated sentences.
2. Include the complete reference for Almutairi 2018. University of South Carolina thesis?
3. There is no reference to the University of South Carolina in the Acknowledgements where most of this research was done.
Overall, this is a well written interesting manuscript that should be published with minor to moderate revisions.
Comments for author File: 
Comments.pdf
Author Response
Manuscript ID: 788650
Quantitative Evaluation of CO2 Storage Potential in the Offshore Atlantic Lower Cretaceous Strata, Southeastern United States.
by Dawod Almayahi, James H Knapp and Camelia Knapp
We would like to thank the reviewers for their thoughtful and constructive comments on our manuscript. We have examined them carefully and our responses are presented in detail below. In our response, each one of the reviewer comments is first presented using black typeface and then it is followed by our detailed response using red typeface; when relevant, the corresponding changes to the manuscript are also presented using italics.
Response to Reviewer 1 Comments
Point 1: Table 1, P10, P50, and P90 represent 10, 50. and 90 percent probability? Why is the 90% probability the highest saline formation efficiency? It appears that the probabilities are reversed (i.e. the values for P10 are actually the values for P90). Please check this throughout the paper. This mistake is repeated in Table 6 and Table 7. (Figures 8 and 9 appear to be drawn correctly with higher probabilities associated with lower CO2 storage capacities.)
Response 1: We agree that this may be a little confusing; there are two types of probabilistic analysis: exceedance probabilities and cumulative probabilities; cumulative probabilities are commonly used in this study. Exceedance probabilities are the opposite of cumulative probabilities. In the cumulative probabilities, P10 is the lowest, and P90 is the highest. However, in exceedance probabilities, P10 is the highest while P90 is the lowest. US DOE used Monte Carlo simulations to estimate saline formation storage efficiencies ranging from 4% to 5.5% at P10 and P90, respectively. We realized that the captions in figures 8 and 9 were incorrect, so they are now fixed (see figures 8 and 9).
Point 2: Figure 6B. It would be good to comment on the updip seal along the coastline. It is not clear how this will work from the top Cretaceous map, since no closure is indicated on the map. A cartoon cross section would be helpful. The figure letters in the caption are incorrect.
Response 2: A cartoon cross-section that you recommended is now added (see figure 6).
My other comments are minor, including
- Introduction lines 43-46 and Geologic Framework lines 91-95. Omit repeated sentences.
It is revised now.
- Include the complete reference for Almutairi 2018. University of South Carolina thesis?
The reference is now revised.
- There is no reference to the University of South Carolina in the Acknowledgements where most of this research was done.
Thank you for this comment, University of South Carolina is now added to the Acknowledgments.
Attached please find the revised version of the manuscript with tracking changes.
Author Response File: 
Author Response.doc
Reviewer 2 Report
see below comments.
The authors tries to evaluate CO2 Storage Potential in the Offshore Atlantic, Southeastern United States. Unfortunately, the innovation of the article is not enough either in terms of methods or in terms of understanding. The main problems are as follows:
(1) Whether the methods adopt DOE method or Goodman method modified later are highly uncertain, and the CO2 storage potential calculated by these methods is basically unreliable.
(2) How much CO2 can be storage in aquifer is not the author is given in table 3 7 parameters can be determined, one of the most important parameters in the table does not appear, is the current reservoir pressure, injection CO2 require formation is normally closed, if high formation pressure, injection rate will be very few, can not meet the storage requirements to seal the well, if the high pressure injection, Will induce an earthquake. If the formation is not sealed, CO2 can leak into the sea, causing damage to the Marine environment.
(3) It is suggested that the author carry out numerical simulation of injection pressure and injection volume of Marine sequestration, which can simulate the injection pressure field and injection velocity field with time.
(4) The CO2 storage depth of 800m suggested by the author is too shallow to be safe, and the minimum storage depth should be more than 1200m.
Author Response
Manuscript ID: 788650
Quantitative Evaluation of CO2 Storage Potential in the Offshore Atlantic Lower Cretaceous Strata, Southeastern United States.
by Dawod Almayahi, James H Knapp and Camelia Knapp
We would like to thank the reviewer 2 for their thoughtful and constructive comments on our manuscript. We have examined them carefully and our responses are presented in detail below. In our response, each one of the reviewer comments is first presented using black typeface and then it is followed by our detailed response using red typeface; when relevant, the corresponding changes to the manuscript are also presented using italics.
Point 1: Whether the methods adopt DOE method or Goodman method modified later are highly uncertain, and the CO2 storage potential calculated by these methods is basically unreliable.
Response 1: We agree with reviewer 2 we’ve disscused (see line 190-201 in revised version).
Line 190-201: “Some articles such as Teletzke et al. (2018) criticize the DOE method or Goodman method. However, the DOE method is the most comprehensive and well-documented storage method available at this time. The DOE method estimates carbon storage resources at the prospective scale in subsurface saline formations. This information plays an important role in establishing the scale of carbon capture and storage activities for governmental policy and commercial project decision-making. When calculating the storage efficiency terms, the DOE method accounts for a several parameters as presented in Gorecki et al. (2009); reservoir width, reservoir length, thickness, domain discretization, rock properties, porosity, permeability (lateral), permeability anisotropy, relative permeability, capillary pressure, reservoir properties, initial pressure, pressure gradient, initial temperature, temperature gradient, brine concentration, pore compressibility, operation properties, injection rate, injection period, and perforation.”
Point 2: How much CO2 can be storage in aquifer is not the author is given in table 3 7 parameters can be determined, one of the most important parameters in the table does not appear, is the current reservoir pressure, injection CO2 require formation is normally closed, if high formation pressure, injection rate will be very few, can not meet the storage requirements to seal the well, if the high pressure injection, Will induce an earthquake. If the formation is not sealed, CO2 can leak into the sea, causing damage to the Marine environment.
Response 2: The parameters are now added to table 3 and have been explained (see lines 339-346).
Lines 339-346: ”Chadwick et al. (2008) concluded that a generic case may be associated with injecting large quantities, reaching 400Mt, of CO2 into a single anticlinal aquifer structure. The effective size of the reservoir is a critical parameter to determine water displacement with high pressure leading to increased porosity of 20% or higher, which is a requirement for safe injection into porous strata. While the CO2 injection pressure significantly increases from 5 to 10 MPa in the injection zone, the effective storage capacity in the caprocks increases when the pressure of the injected CO2 exceeds the initial formation pressure (Liu et al., 2001) (Liu et al., 2001).”
Point 3: It is suggested that the author carry out numerical simulation of injection pressure and injection volume of Marine sequestration, which can simulate the injection pressure field and injection velocity field with time
Response 3: A numerical simulation model for monitoring injection in over 2x106 m3 of supercritical CO2 per day for 50 years in the southeastern United States (considering this study’s result), the SOSRA team at University of South Carolina and Oklahoma State University (Not released yet) concluded that the condition of the Cretaceous deposits of the South Georgia Embayment was successful in controlling the injected CO2 for long-term storage (see line 488-491).
Lines 488-491: ”Since the reservoir heterogeneity impacts the pressure distribution and the CO2 plume migration is significantly affected due to permeability, we suggest that reservoir R2 and seals S2 and S3 can provide additional protection for safe injection and storage in case unpredictable leakage occurs due to unexpected natural hazards.”
Point 4: The CO2 storage depth of 800m suggested by the author is too shallow to be safe, and the minimum storage depth should be more than 1200m.
Response 4: Various authors (Chadwick et al., 2008; Zhou et al., 2008; Gorecki et al., 2009; Goodman et al., 2011; U.S., 2015; Levine et al., 2016; Sanguinito et al., 2017) concluded that the storage of CO2 in saline formations is limited to sedimentary basins with vertical flow barriers and depths greater than 800 m. Porous and permeable sandstone and carbonate rocks are found in sedimentary basins. The 800 m cut-off (8 MPa) is a general attempt to find a depth where pressures and temperatures lead to high-density liquid CO2 or supercritical CO2, while this depth can vary a lot from place to place. In this study, from GOST GE-1 well, we found that the depths of the reservoirs are 1,860 m (R1), 2,125 m, and reservoir II is 2,350 m (see figures 5 and 6).
Attached please find the revised version of the manuscript with tracking changes.
Author Response File: Author Response.doc
Reviewer 3 Report
This is an interesting study is titled “Quantitative Evaluation of CO2 Storage Potential in the 2 Offshore Atlantic Lower Cretaceous Strata, Southeastern United States”. However, a few things need to be addressed and clarified to improve the quality of this manuscript and to show the important findings in this study:
Questions:
1. Reservoir temperature at depth varies at basin-scale and from one well to another even within the same field, and this would impact the CO2 storage potential of Lower Cretaceous Strata. Can the authors explain further why a single geothermal gradient value was assumed to be constant across the entire study area?
2. It has been recommended that for efficient CO2 storage in deep saline aquifers, a minimum of 2 overlying seals should be available for the reservoir storage unit to achieve optimum trapping and mitigate leakage. While this study shows alternating single reservoir and seal, and this brings up the potential problem of vertical migration of CO2 plume and leakage over time. Also, this study left an open-ended question as to which reservoir(s) should be the target for optimum CO2 storage within these strata to achieve long-term CO2 storage and mitigate potential leakage and CO2 migration. I suggest that the authors briefly discuss this to further improve the CO2 storage viability of the identified strata in this study.
There is potential for a long-term issue in the identified Lower Cretaceous Strata because the injected CO2 will react with brine to form carbonic acid and cause dissolutions in the dolomite formation which can induce leakage in the seals over time. Although good post-injection mineral trapping is expected in these strata, there’s still a concern with this aforementioned issue with the single overlying seals recommended in this study. If the Offshore Atlantic Lower Cretaceous Strata is considered by the industry as a potential CO2 storage site, Can the authors briefly comment on any possible issues (if any) that could compromise the caprock integrity of this site?.
Others:
I suggest that the authors improve the size of the scale and units in Figs. 4 and 5.
Author Response
Manuscript ID: 788650
Quantitative Evaluation of CO2 Storage Potential in the Offshore Atlantic Lower Cretaceous Strata, Southeastern United States.
by Dawod Almayahi, James H Knapp and Camelia Knapp
We would like to thank the reviewers for their thoughtful and constructive comments on our manuscript. We have examined them carefully and our responses are presented in detail below. In our response, each one of the reviewer comments is first presented using black typeface and then it is followed by our detailed response using red typeface; when relevant, the corresponding changes to the manuscript are also presented using italics.
Point 1: Reservoir temperature at depth varies at basin-scale and from one well to another even within the same field, and this would impact the CO2 storage potential of Lower Cretaceous Strata. Can the authors explain further why a single geothermal gradient value was assumed to be constant across the entire study area?
Response 1: The temperature, pressure, and core data are only available on the COST GE-1 well. Figure 7A demonstrates the depth and temperature relationship at COST GE-1. Table 5 demonstrates that the temperature values have been identified based on the depth of the reservoir across the study area. In the various depths, the temperature values within the reservoirs for the regional and local areas have been statistically processed and identified (see table 7).
Point 2: It has been recommended that for efficient CO2 storage in deep saline aquifers, a minimum of 2 overlying seals should be available for the reservoir storage unit to achieve optimum trapping and mitigate leakage. While this study shows alternating single reservoir and seal, and this brings up the potential problem of vertical migration of CO2 plume and leakage over time. Also, this study left an open-ended question as to which reservoir(s) should be the target for optimum CO2 storage within these strata to achieve long-term CO2 storage and mitigate potential leakage and CO2 migration. I suggest that the authors briefly discuss this to further improve the CO2 storage viability of the identified strata in this study.
Response 1: This point has been added and discussed in the Summary and Conclusions section (see line 488-491 in revised version).
Lines 488-491: ”Since the reservoir heterogeneity impacts the pressure distribution and the CO2 plume migration is significantly affected due to permeability, we suggest that reservoir R2 and seals S2 and S3 can provide additional protection for safe injection and storage in case unpredictable leakage occurs due to unexpected natural hazards.”
Point 3: There is potential for a long-term issue in the identified Lower Cretaceous Strata because the injected CO2 will react with brine to form carbonic acid and cause dissolutions in the dolomite formation which can induce leakage in the seals over time. Although good post-injection mineral trapping is expected in these strata, there’s still a concern with this aforementioned issue with the single overlying seals recommended in this study. If the Offshore Atlantic Lower Cretaceous Strata is considered by the industry as a potential CO2 storage site, Can the authors briefly comment on any possible issues (if any) that could compromise the caprock integrity of this site?.
Response 3: A numerical simulation model for monitoring injection in over 2x106 m3 of supercritical CO2 per day for 50 years in the southeastern United States (considering this study’s result), the SOSRA team at University of South Carolina and Oklahoma State University (Not released yet) concluded that the condition of the Cretaceous deposits of the South Georgia Embayment was successful in controlling the injected CO2 for long-term storage.
Point 4: I suggest that the authors improve the size of the scale and units in Figs. 4 and 5.
Response 4: Figures four and five have been improved.
Attached please find the revised version of the manuscript with tracking changes.
Author Response File: Author Response.doc
Round 2
Reviewer 2 Report
see below comments.
Reviewer 3 Report
The authors have addressed the issues raised and improved the manuscript quality.
