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Peer-Review Record

Mineral Precipitation in Fractures and Nanopores within Shale Imaged Using Time-Lapse X-ray Tomography

Minerals 2019, 9(8), 480; https://doi.org/10.3390/min9080480
Reviewer 1: Anonymous
Reviewer 2: Anonymous
Minerals 2019, 9(8), 480; https://doi.org/10.3390/min9080480
Received: 18 June 2019 / Revised: 2 August 2019 / Accepted: 6 August 2019 / Published: 7 August 2019
(This article belongs to the Section Mineral Geochemistry and Geochronology)

Round 1

Reviewer 1 Report

Review of ‘Mineral Precipitation in Fractures and Nanopores within Shale Imaged Using Time-Lapse X-ray Tomography’, by Godinho et al.


This paper reports the results of a series of 4-D (3-D plus time) X-ray tomography reaction experiments, where a shale sample was exposed to one side Na2SO4 solution, and the other BaCl2 solution. Diffusion from both sides leads to reaction to BaSO4 in the open spaces (pores and fractures) of the sample. This process is monitored with time lapse high resolution X-ray tomography, over a period of 44 hours. Image analysis indicates that precipitation starts in open fractures and depends on the orientation, and over time continues also in smaller, less favourably oriented fractures. Last precipitation occurs in the nanoporous matrix of the sample.


Major comments

The paper is well written, and clever use has been made of the double diffusion method to instill mineral precipitation. The X-ray images are clear, and due to near-perfect alignment the sub-voxel precipitation is easy to find back. However, I have two major comments:


1)     The characterization of the shale sample before the experiment needs be improved. It is mentioned that swelling will take or should have taken place in the sample upon wetting, but no swelling minerals are reported in the mineralogy.  Moreover, the sample still contains wide open fractures, visible in the tomography (not swollen shut), which suggests no swelling clays are present. If these samples were dry to begin with, then I would have some doubt these samples can have been fully wet after only 24h pre-exposure. Getting low-permeable and low porosity rocks wet and in full equilibrium is a long process: can easily take 3 weeks (Ferrari et al., 2014). What are the reasons for believing the sample is in equilibrium at the beginning of the experiment, and that it has been properly rinsed and dry within 2 hours after the experiment? Moreover, the He-porosity is reported to be 7% - this is so high I would assume this to be a dry sample, i.e. including any drying cracks that have formed (as I suspect are the main cracks visible in Figure 2). However, the permeability is as low as 10-17 m2 at room conditions – is this then on wet samples? Because of the long cracks visible in Figure 2 were present, it seems unlikely the sample would have such a low permeability.

 

2)     The microfractures, the most important transport pathways, are not well described. Are all microfractures present in the initial sample? Or are they formed during the wetting phase or during the reaction phase? The microstructural characterization of this paper has been taken from Ma et al, 2018 – reference 19 (has any new work been done?). I strongly suggest to read the review by (Ougier-Simonin et al., 2016), and obtain high resolution, well-focused SEM images of the initial microstructure. Is this microstructure representative for this shale? For all shales? Moreover, depending on the level of detail you want to go into in determining the origin of the microfractures, one could consider looking at the roughness of the fracture walls (Pluymakers et al., 2017). Intuitively, given that all fractures are parallel to the long axis of the sample (Figure 2, assuming we are looking at the sample edges on either side of the field of view) I imagine all these cracks all drying cracks that follow the bedding. That is also assuming the samples were dry before the contact with NaCl solution. If this is the case, it should be visible on higher resolution images. Given this, would we then expect similar fractures and thus similar reaction mechanisms as shown in Figure 5 in-situ?


Line-by-line comments

Line 22-24: very general, abstract would be more appealing if you would give specific implications and/or conclusions

Line 39: ‘high concentration in formation waters’ this could use a reference. I thought BaSO4 was quite specific to the geothermal industry, which usually doesn’t focus on organic-rich sedimentary rocks.

Line 48, 51: references 13 and 15 are insufficient for a geologically oriented paper, since Xray CT has not only been used to study ‘materials’, it has also been used in geosciences, and there are several review papers specifically for the geosciences (Cnudde & Boone, 2013; Fusseis et al., 2014; Renard, 2012).

Line 69: related to major comment 1: these are all non-swelling clays. From reference 19 I understand this has been determined by XRD – I assume with procedures suitable to identifying the different clay minerals (reference 19 is sadly also lacking this information). This needs to be included in this paper in order to be readable independently.

Line 71: the pore sizes range from 1 nm to 2 µm: reference 19 only deals with the pore sizes, not with the microfractures. The microfractures play a major role in this manuscript, and therefore warrant a better description, plus a proper SEM image. If you need inspiration on how to classify microfractures in shale, I can recommend the review by (Ougier-Simonin et al., 2016).

Line 75: for such a low porosity/permeability sample, a simple 24 hour soak doesn’t seem sufficient to fully wet a sample. Why would the air be driven out simply by soaking the sample? Residual air is also a problem in more porous samples. Or was the sample already wet? Many experimentalists experience wetting issues with shale, in (Ferrari et al., 2014) full wetting took 3 weeks for example.

Line 75: there is no swelling clay reported in the mineralogy, and the fractures are all open.

Figure 76-79/Figure 1: how large were the containers with solution, how much of the sample was covered, and how much of the sample was the space in which solution could react? Which part of this is imaged? A potential solution would be to make Figure 1 to scale.

Figure 1: if this an SEM picture, then why is the organic matter not fully black? Can you provide a higher resolution picture for the top image? It is very grainy. Is this a before or after image? It would be good to have an SEM image of the starting material here, if available. See (Pluymakers et al., 2018), Fig 8 for an example of a clay-rich shale with organic matter patches. I would expect something of similar quality here, focusing on the cracks and pores. Is the area around the microfracture from the top image also rich in OM? The grey shade seems to suggest it is

Line 91 / line 98-99: is this 80 seconds per projection or for the full 3D volume? If it is 80 seconds per projection, then why were there only 11 scans performed? Was the sample moved in between these scan times, or was it always kept in the Xray chamber?

Line 94: where was this volume located compared to the two solution containers? Does it include the edges of the sample? See also comment on Figure 1.

Line 102: as for the bath with NaCl solution (line 75), this simply seems very short compared to generic shale-fluid equilibration times. Do you have any evidence this was sufficient time-wise? Did you flush it, either with a pump or via flow-through?

Line 106-107: compliments for the alignment, it seems very accurate judging by the eye. But why did you resample? And why this interpolation method? Does this procedure affect the resolution? Looking at Figure 2 perhaps it did, since this is not as sharp as I would expect from a 1.6 µm voxel resolution. Or is this due to the low quality of the initial submitted figures?

Line 119: carbon coating means it becomes very difficult to be certain of the location of organic matter. The organic matter is the location of many of the micropores. Precipitation took place first in the largest microfractures, then in the smallest, then in the (porous?) matrix.  How did that affect your conclusions?

Line 128: observable barite depends on your measurement method. Do you have any idea how much barite needs to be precipitated in a single location before you can pick it up due to the density contrast with the matrix? Could it be barite precipitates uniformly in the nanoporous matrix first, but because of the small amounts, you only first can observe it in the macrofractures? i.e. that what you indicate as step 3 in your conclusion is actually step 1?

Figure 2: these images are very small. I suggest to give better resolution and bigger pictures, so you dob’t have to zoom to 600% to make the observations. What are the red arrows? It is not in the caption, the text says barite bands but to me it seems it might be the places where fractures appear blocked by barite precipitate? Difficult to see on this resolution. The captions mentions yellow, red and blue but there is none. There is green and two shades of purple.

Line 139: ‘transport has slowed’ How did you determine rates from these images? Percentage of white pixels over time or something like that?

Line 144: how did you obtain this rate? When and how is it measured? What exactly is the precipitation front? Do you mean it moves through the sample, or do you mean that the white band gets wider? Can you include a graph of rate vs time? What does it do, does it evolve linearly, exponentially? Does it speed up, slow down?  

Line 165: that a front is advanced by the presence of a crack oriented along the flow direction makes sense, but why would a crack (i.e. fast transport path) block or delay the propagation because of its orientation? That is counterintuitive.

Line 167: can you show the evidence for precipitation on barium-rich side? Without knowing which part of the sample we are looking at in Figure 2 it is difficult to judge this statement. From the image alone the logical interpretation is rather that the precipitation bands develop in the middle. If they develop closer to one side, does that then make sense with the speed you expect that the different species diffuse through the sample?

Line 169-170: please comment on the potential effect of drying procedure (i.e. line 102) before drawing conclusions on the crystal growth. Can you be certain that all the crystals you see here grew only during the experiment?

Figure 4: From the left picture it is unclear what the spatial relationship is between fracture 1 and 2. Please clarify.

Line 180-182: on what basis did you identify the phases here? Figure S3 is a false colour image of a CT scan, which carries density information only.

Line 190: precipitation mainly takes place on the sulphate rich side is in direct contradiction to line 167

Line 191-193: please comment on the detection limit and the presence of precipitate in nanopores, as well as how you can see this sweeping growth front. Please provide the rate calculation.

Line 249: please clarify how this explains horizontal fractures inhibiting the advance of growth

Line 251: it is not only difficult to extrapolate from a small sample (though worthwhile! Especially when you can base it on the mechanisms, as is done here), but also difficult to extrapolate from only 1 experiment. How repeatable do you think this experiment is? What are the key characteristics of this specific sample used that would make it representative for a larger batch of samples?

Figure 5: nice figure!

Line 264: given what you know about the mechanisms, if the first fractures formed have an aperture that is more than a few microns, do you then still expect clogging? Why? Given that hydrofracture commonly uses proppants of tens to hundreds of micrometers, I would expect initial fractures in a hydrofracture operation to be wider than what is seen in these samples.

Line 278: ‘contrarily to hydrocarbon exploration sites’ Technically speaking, that depends. This is only valid for those where shale is also reservoir rock. When shale is the seal on top of a HC reservoir low permeability is also desirable.

Line 280: In your Figure 2 blockage first occurs in the vertical fractures, not in the horizontal fractures. The front slows down – perhaps due to widespread precipitation? But there can still be transport, just in the horizontal direction, not vertical.

Line 287: Can you be certain precipitation would take place throughout the sample, leading to a 100% blockage? Moreover, would this also occur if there is also flow, not only diffusion?

Videos are very fast: better perhaps to just give the 5 pictures. Otherwise video is OK but slow down. Video 2 and 3 don’t work.

 

References

Cnudde, V., & Boone, M. N. (2013). High-resolution X-ray computed tomography in geosciences: A review of the current technology and applications. Earth-Science Reviews, 123, 1–17. https://doi.org/10.1016/j.earscirev.2013.04.003

Ferrari, A., Favero, V., Marschall, P., & Laloui, L. (2014). Experimental analysis of the water retention behaviour of shales. International Journal of Rock Mechanics and Mining Sciences, 72, 61–70. https://doi.org/10.1016/J.IJRMMS.2014.08.011

Fusseis, F., Xiao, X., Schrank, C., & De Carlo, F. (2014). A brief guide to synchrotron radiation-based microtomography in (structural) geology and rock mechanics. Journal of Structural Geology, 65, 1–16. https://doi.org/10.1016/j.jsg.2014.02.005

Ougier-Simonin, A., Renard, F., Boehm, C., & Vidal-Gilbert, S. (2016). Microfracturing and microporosity in shales. Earth-Science Reviews, 162, 198–226. https://doi.org/10.1016/j.earscirev.2016.09.006

Pluymakers, A., Kobchenko, M., & Renard, F. (2017). How microfracture roughness can be used to distinguish between exhumed cracks and in-situ flow paths in shales. Journal of Structural Geology, 94, 87–97. https://doi.org/10.1016/j.jsg.2016.11.005

Pluymakers, A., Liu, J., Kohler, F., Renard, F., & Dysthe, D. (2018). A high resolution interferometric method to measure local swelling due to CO<inf>2</inf>exposure in coal and shale. International Journal of Coal Geology, 187. https://doi.org/10.1016/j.coal.2018.01.007

Renard, F. (2012). Microfracturation in rocks: from microtomography images to processes. The European Physical Journal Applied Physics, 60(2), 24203. https://doi.org/10.1051/epjap/2012120093

 


Author Response

Review of ‘Mineral Precipitation in Fractures and Nanopores within Shale Imaged Using Time-Lapse X-ray Tomography’, by Godinho et al.

 

This paper reports the results of a series of 4-D (3-D plus time) X-ray tomography reaction experiments, where a shale sample was exposed to one side Na2SO4 solution, and the other BaCl2 solution. Diffusion from both sides leads to reaction to BaSO4 in the open spaces (pores and fractures) of the sample. This process is monitored with time lapse high resolution X-ray tomography, over a period of 44 hours. Image analysis indicates that precipitation starts in open fractures and depends on the orientation, and over time continues also in smaller, less favourably oriented fractures. Last precipitation occurs in the nanoporous matrix of the sample.

 

Major comments

The paper is well written, and clever use has been made of the double diffusion method to instill mineral precipitation. The X-ray images are clear, and due to near-perfect alignment the sub-voxel precipitation is easy to find back. However, I have two major comments:

Reply: Thank you for these kind comments. We really appreciate the dedication of the reviewer that helped us improving the manuscript. We have tried to attend to all reviewers concerns. We would like to note that the sample used in study is from a very well characterized formation that has been extensively studied and reported. We would also like to note that this experiment was extensively prepared in our laboratory before the experiment at the synchrotron so some of conditions used come from an empirical knowledge e.g. the wetting of the sample. Since much of the sample characterization can be found in the literature and is not the focus of this paper we would rather keep the focus on the analysis of in situ crystal growth. Nevertheless, we have added a substantial amount of details as requested by the reviewer.

1)     The characterization of the shale sample before the experiment needs be improved. It is mentioned that swelling will take or should have taken place in the sample upon wetting, but no swelling minerals are reported in the mineralogy.  Moreover, the sample still contains wide open fractures, visible in the tomography (not swollen shut), which suggests no swelling clays are present. If these samples were dry to begin with, then I would have some doubt these samples can have been fully wet after only 24h pre-exposure. Getting low-permeable and low porosity rocks wet and in full equilibrium is a long process: can easily take 3 weeks (Ferrari et al., 2014). What are the reasons for believing the sample is in equilibrium at the beginning of the experiment, and that it has been properly rinsed and dry within 2 hours after the experiment? Moreover, the He-porosity is reported to be 7% - this is so high I would assume this to be a dry sample, i.e. including any drying cracks that have formed (as I suspect are the main cracks visible in Figure 2). However, the permeability is as low as 10-17 m2 at room conditions – is this then on wet samples? Because of the long cracks visible in Figure 2 were present, it seems unlikely the sample would have such a low permeability.

Reply: Regarding swelling minerals. Our reported composition was measured by XRD, which did not detect any swelling minerals (within its resolution). However, smectitic minerals are possible in this shale type in amounts close to the resolution of XRD (Dowey and Taylor, 2019) and additionally organic matter (about 7.4% in this sample) could cause swelling. In any case swelling during the experiment was not observed so this is not an issue. We added this: “Movement within the sample due to swelling was not observed, which is confirmed by the ease of subtracting the starting dataset from the datasets at later experiment times”

Regarding the wetting time. A decision was made to leave the sample in fluid for only 24 hrs for 2 reasons. 1) to prevent extensive geochemical reactions that would change the nanostructure of the pores/matrix, i.e. dissolution of some minerals and precipitation of secondary mineral phases. The 3 weeks suggested by the reviewer would have an unpredictable impact on the results. 2) we tested the wetting of the sample in the lab by measuring the weight variation of the dried / wet sample and we also observed that fractures are filled with water within the first hour of contact with water (by scanning the wet sample in a lab-CT). We looked at the study by Ferrari 14 and found no evidence of the existence of fractures in the shale used in that study. Possibly the considerable amount of microfractures present in our sample makes the wetting much faster since the wet surface area for fluid penetration into the nanopores is orders of magnitude higher than if the fluid only flows into the nanopores from the bottom. Finally, we would say that if the sample was not wet than we would not have seen precipitation moving as a front across the entire diameter of the sample. Altogether, we agree with the reviewer that improper wetting would have conditioned our study, but our results suggest that the most of the nanopores were indeed wet. This was add to the text.

Regarding permeability measurements. The helium porosity was measured on a dry sample at room temperature and pressure with fractures open. Before the measurement, the sample was put in an oven at 60 °C for one week until the weight was not changing. These fractures account for 1.2 vol% of the sample and the other pores occupy the other 5.8% based on a 3D image measurement (Ma et al., 2019, Figure 3). However, the fractures are not connected to each other, and the main flow pathways consist of elongated pores between minerals at 6-50 nm (Ma et al., 2018, Figure 2).The permeability was measured at a pore pressure of 23 MPa (Ma et al. 2018, Figure 7) to simulate subsurface conditions. The microfractures are partially closed at this pressure (Ma et al 2018, Figure 7). Therefore, the permeability values are very low. Details were add in the methods.

2)     The microfractures, the most important transport pathways, are not well described. Are all microfractures present in the initial sample? Or are they formed during the wetting phase or during the reaction phase? The microstructural characterization of this paper has been taken from Ma et al, 2018 – reference 19 (has any new work been done?). I strongly suggest to read the review by (Ougier-Simonin et al., 2016), and obtain high resolution, well-focused SEM images of the initial microstructure. Is this microstructure representative for this shale? For all shales? Moreover, depending on the level of detail you want to go into in determining the origin of the microfractures, one could consider looking at the roughness of the fracture walls (Pluymakers et al., 2017). Intuitively, given that all fractures are parallel to the long axis of the sample (Figure 2, assuming we are looking at the sample edges on either side of the field of view) I imagine all these cracks all drying cracks that follow the bedding. That is also assuming the samples were dry before the contact with NaCl solution. If this is the case, it should be visible on higher resolution images. Given this, would we then expect similar fractures and thus similar reaction mechanisms as shown in Figure 5 in-situ?

Reply: Microfractures mainly parallel to the bedding are present in the starting samples with widths up to 72 μm. These fractures account for 1.2 vol% of the sample. The microstrucuture are fully characterized in 3D and the representativity has been quantified in detail in the our recent work, Ma et al. 2019. Shale samples at mm-scale are considered to be representative for microstrucutre studies in shale studies (Ma et al., 2016; Ma et al 2019, Figure 8; Saraji and Piri, 2015). This sample was selected as representative of this well characterized reservoir in terms of compositions and microstrucutre (Ma et al., 2018; Ma et al., 2019), and within the significant variability of microstructures of worldwide reservoirs this shale is fairly representative of typical pore microstructures found in shale gas reservoirs. For the purpose of our story the important is not how the fractures formed but that the fractures are there at time 0 and remain in place until time 44.3 hours (with or without barite).

Additional information about the microfractures has been added to the materials section and additional literature is cited.

 

Line-by-line comments

Line 22-24: very general, abstract would be more appealing if you would give specific implications and/or conclusions

Reply: We added a sentence with the most important conclusion of the paper. We would rather keep the abstract short, a format that is supported by this journal.

Line 39: ‘high concentration in formation waters’ this could use a reference. I thought BaSO4 was quite specific to the geothermal industry, which usually doesn’t focus on organic-rich sedimentary rocks.

Reply: In fact Ba (and also Sr and often Ra) are present in most organic rich formations, i.e. above average concentrations when compared to ground waters of organic poor formations, and this is valid not only for shale but also, for example, sandstones. That is because large divalent cations have a good affinity to organics so they get concentrated during maturation. Citations 8-11 describe the problem in detail.  

Line 48, 51: references 13 and 15 are insufficient for a geologically oriented paper, since Xray CT has not only been used to study ‘materials’, it has also been used in geosciences, and there are several review papers specifically for the geosciences (Cnudde & Boone, 2013; Fusseis et al., 2014; Renard, 2012).

Reply: Agreed. We replaced the citation.

Line 69: related to major comment 1: these are all non-swelling clays. From reference 19 I understand this has been determined by XRD – I assume with procedures suitable to identifying the different clay minerals (reference 19 is sadly also lacking this information). This needs to be included in this paper in order to be readable independently.

Reply: We have answered the concerns of the reviewer regarding non-swelling clays in point 1 (there were none identified by XRD, which is good for this study since we do not want swelling). We added to the text that the mineralogy was identified and quantified by XRD. We have no reason to believe that the cited publication19 in a relatively good journal (Scientific Reports) has used wrong procedures, plus the mineralogy is in agreement with other studies of the same shale reservoir, e.g. Saraji and Piri, 2015, Dowey and Taylor 2019.

Line 71: the pore sizes range from 1 nm to 2 µm: reference 19 only deals with the pore sizes, not with the microfractures. The microfractures play a major role in this manuscript, and therefore warrant a better description, plus a proper SEM image. If you need inspiration on how to classify microfractures in shale, I can recommend the review by (Ougier-Simonin et al., 2016).

Reply: A CT image of microfractures and large pores is added in Figure 1 and additional information about fractures was add and details about this quantification is available in our recent publication, L. Ma et al., 2019. The microfractures are < 80 um width and parallel to the beddings.

Line 75: for such a low porosity/permeability sample, a simple 24 hour soak doesn’t seem sufficient to fully wet a sample. Why would the air be driven out simply by soaking the sample? Residual air is also a problem in more porous samples. Or was the sample already wet? Many experimentalists experience wetting issues with shale, in (Ferrari et al., 2014) full wetting took 3 weeks for example.

Reply: The wetting is driven by capillary pressure. Our experience is that it helps if the initial contact with the fluid is done by gradually letting the pores soak the fluid from the bottom without digging the sample into the fluid. This prevents the formation of air bubbles in the fractures (on which surface tension would offer resistance to wetting). The sample was not wet before 24 hours. We have addressed this point as described in reply to point 1.

Line 75: there is no swelling clay reported in the mineralogy, and the fractures are all open.

Reply: The reviewer is correct. We have clarified the sentence.

Figure 76-79/Figure 1: how large were the containers with solution, how much of the sample was covered, and how much of the sample was the space in which solution could react? Which part of this is imaged? A potential solution would be to make Figure 1 to scale.

Reply: 5 ml containers (added to text). The entire cross section was exposed to the fluid. The round side of the sample was covered by tygon and heat shrinking tube, so the side of the sample was not exposed to the fluids.

Figure 1: if this an SEM picture, then why is the organic matter not fully black? Can you provide a higher resolution picture for the top image? It is very grainy. Is this a before or after image? It would be good to have an SEM image of the starting material here, if available. See (Pluymakers et al., 2018), Fig 8 for an example of a clay-rich shale with organic matter patches. I would expect something of similar quality here, focusing on the cracks and pores. Is the area around the microfracture from the top image also rich in OM? The grey shade seems to suggest it is

Reply: The bottom SEM image was taken using secondary electron (SE) detector, which gave a better view of the morphology. Therefore the organic matter is not fully black (pores are black). The top SEM was taken with backscatter electron (BSE) detector, which makes organic matter black. SE image is better for microstructure and pores quantification. The point of figure 1 is to give an immediate impression to readers that our sample contains microfractures and nanopores, as well as a complex matrix composed of nano/micron grains/pores with different minerals/organics. By no means have we intended to fully characterize the sample by 2D SEM images (full description exists in the literature). We now give several references that may have more appealing images than ours. Also the submitted image files have a higher quality that the images in the PDF.

Line 91 / line 98-99: is this 80 seconds per projection or for the full 3D volume? If it is 80 seconds per projection, then why were there only 11 scans performed? Was the sample moved in between these scan times, or was it always kept in the Xray chamber?

Reply: it is 80 seconds per scan (600 projection + dark and flat images). The sample has been moved in and out of the beamline during the waiting period. Nevertheless, the sample environment represented in Fig.1 was kept intact and since the heat shrinking tube gives rigidity to the setup, no mechanical disturbances in the fluid/pores were expected.

A decision was made to scan only every 5 hours from the moment the first crystals were observed. First because the changes in the sample were slow and second because continuous scanning (under high flux synchrotron radiation) is known to form bubbles in the fluid. Any deviation from 5 hours between scans was due to unexpected and uncontrollable problems with the synchrotron source.      

Line 94: where was this volume located compared to the two solution containers? Does it include the edges of the sample? See also comment on Figure 1.

Reply: Yes, it contains the full sample diameter. Since the field of view is 3 mm and the sample is 10 mm the edges of the sample that connect to the containers with the Ba and SO4 solutions are not imaged and are 3.5 mm away from the field of view. Info was add to text and caption, fig.1.

Line 102: as for the bath with NaCl solution (line 75), this simply seems very short compared to generic shale-fluid equilibration times. Do you have any evidence this was sufficient time-wise? Did you flush it, either with a pump or via flow-through?

Reply: The best evidence that most pores were wet and any air pockets to exist are very localized or within sizes bellow the resolution of the CT scans, is that the growth front is approximately homogeneous. If present, large air pockets at the growth front would have been detected as regions without growth, and if present outside the growth front they would possibly have disturbed diffusion (by delaying it) causing a very heterogeneous growth front (maybe it would not even be a front in some regions). We observed that the fractures are filled with fluid within the first hour inside the fluid and this helps distributing the fluid to the nanopores. Without such a distribution of fractures in the work of Ferrary 2014 wetting was much slower, we agree with the reviewer, with such shale types removing the air would have taken much longer. Longer wetting time would have been better to assure wetting but it would have been prejudicial due to undesired reactions that change the shale microstructure.

The following has been add to the text: Air bubbles that could have formed due to radiolysis or that may have remained trapped in the sample due to insufficient soaking time before the experiment were also not visible throughout the experiment. The presence of air trapped within the nanopores cannot be ruled out, however, since a continuous growth front throughout the diameter of the sample is clearly visible, we conclude that if present, the amount of air is minimum and unlikely to affect our interpretation of the results.”

Line 106-107: compliments for the alignment, it seems very accurate judging by the eye. But why did you resample? And why this interpolation method? Does this procedure affect the resolution? Looking at Figure 2 perhaps it did, since this is not as sharp as I would expect from a 1.6 µm voxel resolution. Or is this due to the low quality of the initial submitted figures?

Reply: Resampling is a necessary step after aligning a dataset with another rotation axis. Simply imagine that the 3D image uses a grid of cubes to represent an object. If that grid is rotated or translated than the information within each voxel is different even if the object is the same. Nevertheless, Lanczos interpolation uses an accurate algorithm to keep the overall virtual representation  of the object as similar as possible to the original, so that it has minimum impact on resolution and preserves the voxel size. 

This was clarified in text.

Line 119: carbon coating means it becomes very difficult to be certain of the location of organic matter. The organic matter is the location of many of the micropores. Precipitation took place first in the largest microfractures, then in the smallest, then in the (porous?) matrix.  How did that affect your conclusions?

Reply: Carbon coating doesn't affect the identification of organic matter as the carbon layer is only 12 nm thick, thus it does not affect our conclusions. The interaction volume at the energy used means we are probing 100’s of cubic nanometres penetrating into the material and thus this surface contribution is negligible. Carbon coatings are necessary to reduce electron discharges on samples with low conductivity. Note that we only conclude about pore/fracture sizes, not whether pore surfaces are coated or not since such coatings would not be resolvable by CT. Nevertheless, we are well aware that organic molecules adsorbed on the surface of pores are very likely to be present in shale and that may affect for example nucleation kinetics (see discussion in line 284, refs 34-35)

Line 128: observable barite depends on your measurement method. Do you have any idea how much barite needs to be precipitated in a single location before you can pick it up due to the density contrast with the matrix? Could it be barite precipitates uniformly in the nanoporous matrix first, but because of the small amounts, you only first can observe it in the macrofractures? i.e. that what you indicate as step 3 in your conclusion is actually step 1?

Reply:

We see no evidence of the scenario suggested by the reviewer. Note that growth is observed only in one direction. For example figure 2, shows growth in the nanopores always and only beyond the point of precipitation in the fractures. Additionally, we found no plausible support in the literature to justify such a scenario where nucleation would occur in the nanopores before in the micro fractures.

Our experience is that about 3 v/v% of barite can be detected in a nanoporous glass matrix. Nevertheless, the matrix of shale is so complex and heterogeneous that the quantification of barite from the voxel intensity is not possible, and the detection limit is expected to be higher than in glass. It is clear that bellow some volume fraction barite precipitates cannot be detected in the nanopores, and this is why our conclusions can only be derived from a time-lapse study and from seeing the evolution of intensity over time.

Figure 2: these images are very small. I suggest to give better resolution and bigger pictures, so you dob’t have to zoom to 600% to make the observations. What are the red arrows? It is not in the caption, the text says barite bands but to me it seems it might be the places where fractures appear blocked by barite precipitate? Difficult to see on this resolution. The captions mentions yellow, red and blue but there is none. There is green and two shades of purple.

Reply: Agreed. Full page width will be requested. Red arrows show the initial blockage of larger fractures. This has been add to the caption. Figure files have higher resolution than embedded figures.

Line 139: ‘transport has slowed’ How did you determine rates from these images? Percentage of white pixels over time or something like that?

Reply: The rate is calculated from the distance variation of the growth front. Note that this is not a typical growth rate in mol/mm2/h but rather the velocity of the growth front in um/h, which is discussed as a proxy to the growth rate. This is because we do not know the volume of nanopores/crystals in each voxel to calculate the growth rate.

To prevent confusion we changed “rate” to “velocity”.

Line 144: how did you obtain this rate? When and how is it measured? What exactly is the precipitation front? Do you mean it moves through the sample, or do you mean that the white band gets wider? Can you include a graph of rate vs time? What does it do, does it evolve linearly, exponentially? Does it speed up, slow down?  

Reply: The plot of rate (now called velocity) over time is now included in SI. For example in Figure 3, the growth front on the left side of the image is at the boundary between the green area and the black area. The 6 points were chosen randomly to avoid a biased measurement of the rate. The only criteria was that the all points where not nearing fractures.

Line 165: that a front is advanced by the presence of a crack oriented along the flow direction makes sense, but why would a crack (i.e. fast transport path) block or delay the propagation because of its orientation? That is counterintuitive.

Reply: We agree it is counter-intuitive if we consider only traditional precipitation mechanisms that are independent from pore/fracture size. That is also why our study is so interesting. However our hypothesis can explain this observation: as the sudden transition of precipitation mechanisms between nanopores and less confined fractures, which causes fast precipitation that block the fractures and prevents further diffusion across the fracture. We now explain it better in the discussion.

Line 167: can you show the evidence for precipitation on barium-rich side? Without knowing which part of the sample we are looking at in Figure 2 it is difficult to judge this statement. From the image alone the logical interpretation is rather that the precipitation bands develop in the middle. If they develop closer to one side, does that then make sense with the speed you expect that the different species diffuse through the sample?

Reply: We now add in figure 2 where are the Ba and SO4 rich sides as well as the growth direction. Possibly the reviewer’s confusion is due to our mistake in figure 3 that was 180 degrees rotated relatively to figure 2.  We have now rotated figure 3 and now in all figures the barium comes from bottom and sulphate from top.

Line 169-170: please comment on the potential effect of drying procedure (i.e. line 102) before drawing conclusions on the crystal growth. Can you be certain that all the crystals you see here grew only during the experiment?

Reply: We noticed that the drying procedure was not properly described. In fact in the final step the sample was not only rinsed with isopropanol but also left in isopropanol. We have corrected the drying procedure.

Since the crystals in figure 4 are from the surface of fractures, yes we are confident that they were not formed much longer after the last scan. It is natural that it took some time (difficult to estimate) to remove the aqueous solution from pores and fractures. Nevertheless, the drop in saturation and the inhibition effect of the organic solvents are expected to be sufficient to quench crystal growth within hours if not minutes.

Figure 4: From the left picture it is unclear what the spatial relationship is between fracture 1 and 2. Please clarify.

Reply: Fracture 1 is above fracture 2 with a layer of shale matrix between them. This was add to the caption.

Line 180-182: on what basis did you identify the phases here? Figure S3 is a false colour image of a CT scan, which carries density information only.

Reply: EDS identified Ba and S as the main components of crystals. We now include the spectrum in SI (figure S5).

Line 190: precipitation mainly takes place on the sulphate rich side is in direct contradiction to line 167

Reply: The reviewer’s quotation is wrong: this is the right quotation: Further precipitation takes place in thinner fractures and exclusively in the direction towards the high sulphate concentration”. There is no contradiction. Imagine a car full of candy that is moving from point “Ba” to point “SO4” in a straight road (where candy is a proxy to crystals as in line 190). Now imaging the car has left the trunk opened spilling candy on the road between the two points. Now imagine someone built a wall on the road, the car crashes and spills the candy. Which side of the wall were the candy spilled? The right answer is the Ba side just like, quoting line 167 (reviewed version): “Another example is shown in Figure S2 where pronounced precipitation took place on the barium rich side of the fracture.

Line 191-193: please comment on the detection limit and the presence of precipitate in nanopores, as well as how you can see this sweeping growth front. Please provide the rate calculation.

Reply: Unfortunately, the nature of the study is only qualitative. Defining a detection limit of barite on the complex nanostructure of shale (heterogeneous gray scale matrix) is quite challenging because each voxel has its own detection limit and its own correlation between amount of barite and intensity.

See answer to previous 1st point: Our experience is that about 3 v/v% of barite can be detected in a nanoporous glass matrix. Nevertheless, the matrix of shale is so complex and heterogeneous that the quantification of barite from the voxel intensity is not possible, and the detection limit is expected to be higher than in glass.

The rate graphic is now provided in SI (Figure S4).    

Line 249: please clarify how this explains horizontal fractures inhibiting the advance of growth

Reply: This is an important point worth clarifying so we provide additional explanation in text. For example, at the interphase between the nanoporous matrix and an horizontal fracture, if precipitation is somehow inhibited in the nanopores (by the mechanisms proposed in the text) when the growth front reaches the fracture the fluid will possibly have an SI above the SI that causes progressive precipitation in a non-confined environment. Consequently, at the interphase nanopores – fracture surface sudden fast precipitation may cause the clogging of flow paths, which would explain our observations.

Line 251: it is not only difficult to extrapolate from a small sample (though worthwhile! Especially when you can base it on the mechanisms, as is done here), but also difficult to extrapolate from only 1 experiment. How repeatable do you think this experiment is? What are the key characteristics of this specific sample used that would make it representative for a larger batch of samples?

Reply: The main reason to choose this sample is because it contains fractures and pores of different size and type. Would results be different in a rock with completely different pore structure? Maybe, but the relations between timing of precipitation events described in figure 5 should still be applicable, although we agree that more work would be useful to confirm our findings using the same technique that we present in our work.

We have unpublished results that suggest the experiment is repeatable for a shale with similar pore/fracture characteristics. We ran a second experiment during the same beamtime and the results are similar. Unfortunately, due to synchrotron failure we only have results for the beginning of the process. Also in preparation for the beamtime we ran similar experiments in a lab-CT scanner with similar results in the fractures (the larger ones that can be resolved). Unfortunately, lab-CT has not enough attenuation contrast to see changes in the nanopores.

Figure 5: nice figure!

Reply: Thank you

Line 264: given what you know about the mechanisms, if the first fractures formed have an aperture that is more than a few microns, do you then still expect clogging? Why? Given that hydrofracture commonly uses proppants of tens to hundreds of micrometers, I would expect initial fractures in a hydrofracture operation to be wider than what is seen in these samples.

Reply: Proppants are injected into the fractures while the system is under high pressure and the fractures are wide open. Once the hydraulic pressure is released and under the formation pressure it is likely that the fractures close over time. Actually, with the proppants inside the fracture the effective flow paths would be much smaller than the particles (i.e. space between proppant particles). In any case, even if the diffusion paths are wider than in this study then the fast clogging observed in this work may possibly be enhanced. We would rather not speculate in the text.

Line 278: ‘contrarily to hydrocarbon exploration sites’ Technically speaking, that depends. This is only valid for those where shale is also reservoir rock. When shale is the seal on top of a HC reservoir low permeability is also desirable.

Reply: Agreed. We meant shale formations under hydrocarbon exploration” (not the case where the reservoir is under the shale). The text was corrected.

Line 280: In your Figure 2 blockage first occurs in the vertical fractures, not in the horizontal fractures. The front slows down – perhaps due to widespread precipitation? But there can still be transport, just in the horizontal direction, not vertical.

Reply: Hypothetically yes, but possibly with a reduced impact on our observations. So, our results do not prove or reject such possibility within the timeframe of the experiment.

Line 287: Can you be certain precipitation would take place throughout the sample, leading to a 100% blockage? Moreover, would this also occur if there is also flow, not only diffusion?

Reply: We cannot be sure of this due to the restricted length of an experiment (beamtime allocation). Although, if our observations are extrapolated to the infinite, than that would be the result. The conditional form of the sentence has been added to the text. We would rather not speculate on the effect of flow since that adds another level of complexity, but potentially something interesting to study in the future.

Videos are very fast: better perhaps to just give the 5 pictures. Otherwise video is OK but slow down. Video 2 and 3 don’t work.

Reply: This is possibly an issue with the reviewer’s computer. The videos were checked and worked on different operating systems.

 

New References:

[13] Fusseis, F., Xiao, X., Schrank, C., & De Carlo, F. (2014). A brief guide to synchrotron radiation-based microtomography in (structural) geology and rock

[20] Ma, L.; Dowey, P. J.; Rutter, E.; Taylor, K. G.; Lee, P. D. (2019). A novel upscaling procedure for characterising heterogeneous shale porosity from nanometer-to millimetre-scale in 3D. Energy.

[21] Dowey, P.; Taylor, K. (2019). Diagenetic mineral development within the Upper Jurassic Haynesville-Bossier Shale, USA. Sedimentology.

[22] Saraji, S.; Piri, M. (2015). The representative sample size in shale oil rocks and nano-scale characterization of transport properties. International Journal of Coal Geology146, 42-54.

[23] Ma, L.; Taylor, K. G.; Lee, P. D.; Dobson, K. J.; Dowey, P. J.; Courtois, L. (2016). Novel 3D centimetre-to nano-scale quantification of an organic-rich mudstone: The Carboniferous Bowland Shale, Northern England. Marine and Petroleum Geology72, 193-205.

 


Reviewer 2 Report

This is a clearly written paper using high-speed micro-CT of shale to observe precipitation of barite over time. For the most part the work is clearly described and the discussion draws interesting, though preliminary, conclusions on the potential implications of the findings for fracking, carbon sequestration and related activities in these kinds of formations.

I would appreciate a short section added to the discussion on further work that might bolster the findings and confirm some of the conclusions drawn. I note that for future experiments that K-edge subtraction methods around the Ba K-edge at 37keV might be a useful technique to employ if the hardware permits and might be useful for looking at larger sample whilst enabling the Ba distribution to be unambiguously identified.

I have a number of minor clarifications and additions requested which are given in the annotated PDF attached.

Comments for author File: Comments.pdf

Author Response

Reviewer 2

This is a clearly written paper using high-speed micro-CT of shale to observe precipitation of barite over time. For the most part the work is clearly described and the discussion draws interesting, though preliminary, conclusions on the potential implications of the findings for fracking, carbon sequestration and related activities in these kinds of formations.

I would appreciate a short section added to the discussion on further work that might bolster the findings and confirm some of the conclusions drawn. I note that for future experiments that K-edge subtraction methods around the Ba K-edge at 37keV might be a useful technique to employ if the hardware permits and might be useful for looking at larger sample whilst enabling the Ba distribution to be unambiguously identified.

I have a number of minor clarifications and additions requested which are given in the annotated PDF attached.

Reply: That sure is a good suggestion, although the maximum energy possible at beamline i13 is 30 keV, so bellow the Ba Kedge. We added a paragraph on possible improvements of the method and it’s applicability including also the reviewer’s suggestion. We have also commented on the PDF comments and made the required corrections in the text.


Author Response File: Author Response.pdf

Round 2

Reviewer 1 Report

Mineral precipitation in fractures and nanopores within shale imaged using time-lapse X-ray  tomography by Godinho et al

To summarize, this paper reports the results of a series of 4-D (3-D plus time) X-ray tomography reaction experiments, where a shale sample was exposed to one side Na2SO4 solution, and the other BaCl2 solution. Diffusion from both sides leads to reaction to BaSO4 in the open spaces (pores and fractures) of the sample. This process is monitored with time lapse high resolution X-ray tomography, over a period of 44 hours. Image analysis indicates that precipitation starts in open fractures and depends on the orientation, and over time continues also in smaller, less favourably oriented fractures. Last precipitation occurs in the nanoporous matrix of the sample.

This is the second time I review the manuscript by Godinho et al. They have made significant improvements to the manuscript, and I only have some minor comments.

Minor comments:

Line 74: in this phrasing it implies it is this exact sample of which the porosity has been measured and found to be 7%. If this is not the case, I suggest to rephrase to ‘Helium porosity of similar samples indicate a 7% porosity at …’

Line 75: ‘at a constant pore fluid pressure of 23 MPa’, according to the reply to reviewers file and reference 19

Line 78: typo: ‘below’

Line 95: ‘3.5 mm distant from the edge of the sample’ this phrasing is still somewhat ambiguous, because which edge? However, looking at the Figure, and if the sample is 10 mm long, and the field of view 3 mm high, do you then simply mean that we are looking at the middle or central 3 mm of the sample?

Figure 1: thank you for the improved caption. Last small thing: would it be an idea to give figure 1b the correct aspect ratio, to avoid confusion? Figure b is now higher than it is wide, whereas the caption and the subsequent figures indicate it should be 3.5 mm wide and 3 mm high.

Line 126: isn’t the singular of indices index?

Line 143: I really like the answer to original comment line 128 by the authors in the ‘reply to reviewer’ file, and perhaps some words can be added here that summarize the following answer: ‘Our experience is that about 3 v/v% of barite can be detected in a nanoporous glass matrix. Nevertheless, the matrix of shale is so complex and heterogeneous that the quantification of barite from the voxel intensity is not possible, and the detection limit is expected to be higher than in glass. It is clear that bellow some volume fraction barite precipitates cannot be detected in the nanopores, and this is why our conclusions can only be derived from a time-lapse study and from seeing the evolution of intensity over time.’

Line 146: could you include here the thickness of the coating, as indicated in the reply to reviewers file?

Line 146: session=section I assume?

Line 154-167: From a reader point of view, it is not immediately clear why this paragraph is here. If it stays or goes or changes is to the author’s insights, but it might be worthwhile to smoothen the transition from the preceding text into this paragraph.

Line 171: Note that in the supplementary info the caption to the video 2 hasn’t been updated, and still reads yellow, red, blue

Line 172: typo, ‘magenta’

Line 185-188: the change from rate to velocity clarifies my earlier confusion, together with Figure S4. Could it be possible to improve Figure S4 even more by adding somewhere the points for which the velocity has been measured on Figure 2 or S2? Also, it would do more justice to Figure S4 to include in the description that not all parts of the front move with a positive velocity – only 3 of the lines in Figure S4 have a positive slope, and 2 even have a negative slope. Indicating the points used on Figure 2 and S2 would allow the reader to have an idea of which parts of the front move which way. Perhaps this would be good to include in the caption as well the following line from the reply to reviewers file: ‘The only criteria was that the all points where not nearing fractures.’

Line 208: is it a sliding colour scale from magenta to blue, or a discrete colour scale? Phrasing currently suggests discrete colour scale, which would then logically ask to add what the limits for each colour are.

Figure 3: can you add the blue and green arrow also on the microstructure? Now it is difficult to guide the eye towards which fracture is where and how they relate to the arrows.

Line 218: somewhat related, because I hope I am looking at the same fracture: perpendicular would imply an angle of approximately 90degrees to the growth direction. To me this is more 120 degrees.

Figure 4: I am still a bit confused about what or where is fracture 1 and what or where is fracture 2. In the left image, fracture 1 is at the top and fracture 2 at the bottom, but then I don’t see where the layer of shale matrix is between them? And what makes fracture 1 and 2 different, their aperture, their orientation? Or is it more that the coarse-grained precipitate on the top in the left image (fracture 1?) blocks access to the fine-grained precipitate on the bottom in the left image (fracture 2?)?

Line 316, 320: typo? I assume it should be ‘interface’

Line 318: ‘index’?

Line 316-320: OK, much clearer now. However, how do then the large crystals in the left image in Figure 4 fit in the story?

Video 4: how do you know what is calcite and what is gypsum? Also, what is the use of this video? Is it mentioned in the text?

FYI on the Videos: with a different player (Irfanview instead of VLC) the videos all play at a good speed – no idea why VLC didn’t work.  

Also, I much appreciate the mental image sketched by the candy truck J More science should be explained with candy!

Author Response

Minor comments:

Line 74: in this phrasing it implies it is this exact sample of which the porosity has been measured and found to be 7%. If this is not the case, I suggest to rephrase to ‘Helium porosity of similar samples indicate a 7% porosity at …’

Reply: Corrected as suggested by the reviewer.

Line 75: ‘at a constant pore fluid pressure of 23 MPa’, according to the reply to reviewers file and reference 19

Reply: Corrected

Line 78: typo: ‘below’

Reply: Corrected

Line 95: ‘3.5 mm distant from the edge of the sample’ this phrasing is still somewhat ambiguous, because which edge? However, looking at the Figure, and if the sample is 10 mm long, and the field of view 3 mm high, do you then simply mean that we are looking at the middle or central 3 mm of the sample?

Reply: We clarified the caption and text that the scan was centred on the vertical midpoint

Figure 1: thank you for the improved caption. Last small thing: would it be an idea to give figure 1b the correct aspect ratio, to avoid confusion? Figure b is now higher than it is wide, whereas the caption and the subsequent figures indicate it should be 3.5 mm wide and 3 mm high.

Reply: We have corrected the field of view box to scale

Line 126: isn’t the singular of indices index?

Reply: Corrected

Line 143: I really like the answer to original comment line 128 by the authors in the ‘reply to reviewer’ file, and perhaps some words can be added here that summarize the following answer:Our experience is that about 3 v/v% of barite can be detected in a nanoporous glass matrix. Nevertheless, the matrix of shale is so complex and heterogeneous that the quantification of barite from the voxel intensity is not possible, and the detection limit is expected to be higher than in glass. It is clear that bellow some volume fraction barite precipitates cannot be detected in the nanopores, and this is why our conclusions can only be derived from a time-lapse study and from seeing the evolution of intensity over time.’

Reply: We do not wish to advertise our ongoing work on glass but we added a sentence about the detection limit and v/v/% barite quantification:it is impossible to measure the detection limit of barite and to quantify precise volume fractions of barite from the intensity of a voxel since the porosity and matrix composition can vary within adjacent voxels so that the large amount of variables does not allow for quantitative calibration.”

 

Line 146: could you include here the thickness of the coating, as indicated in the reply to reviewers file?

Reply: The thickness was added to the text

Line 146: session=section I assume?

Reply: Corrected

Line 154-167: From a reader point of view, it is not immediately clear why this paragraph is here. If it stays or goes or changes is to the author’s insights, but it might be worthwhile to smoothen the transition from the preceding text into this paragraph.

Reply: This paragraph has been requested by another reviewer and we think it is useful to keep it. We agree that the place is inadequate so we moved the paragraph to the end of the results section.

Line 171: Note that in the supplementary info the caption to the video 2 hasn’t been updated, and still reads yellow, red, blue

Reply: Corrected

Line 172: typo, ‘magenta’

Reply: Corrected

Line 185-188: the change from rate to velocity clarifies my earlier confusion, together with Figure S4. Could it be possible to improve Figure S4 even more by adding somewhere the points for which the velocity has been measured on Figure 2 or S2? Also, it would do more justice to Figure S4 to include in the description that not all parts of the front move with a positive velocity – only 3 of the lines in Figure S4 have a positive slope, and 2 even have a negative slope. Indicating the points used on Figure 2 and S2 would allow the reader to have an idea of which parts of the front move which way. Perhaps this would be good to include in the caption as well the following line from the reply to reviewers file: ‘The only criteria was that the all points where not nearing fractures.’

Reply: We now specify the criteria in the text and added negative/positive slope to the caption as the reviewer suggested. Nevertheless, we cannot make assumptions about acceleration/deceleration of specific regions of the sample because what the graphic shows is a high variability. Within that variability the velocity is approximately constant (independently of the slope).

Line 208: is it a sliding colour scale from magenta to blue, or a discrete colour scale? Phrasing currently suggests discrete colour scale, which would then logically ask to add what the limits for each colour are.

Reply: The colour scale is not discrete but a linear gradient. We added that information to the figure caption.

Figure 3: can you add the blue and green arrow also on the microstructure? Now it is difficult to guide the eye towards which fracture is where and how they relate to the arrows.

Reply: Done.

Line 218: somewhat related, because I hope I am looking at the same fracture: perpendicular would imply an angle of approximately 90degrees to the growth direction. To me this is more 120 degrees.

Reply: We corrected how the orientation is described.

Figure 4: I am still a bit confused about what or where is fracture 1 and what or where is fracture 2. In the left image, fracture 1 is at the top and fracture 2 at the bottom, but then I don’t see where the layer of shale matrix is between them? And what makes fracture 1 and 2 different, their aperture, their orientation? Or is it more that the coarse-grained precipitate on the top in the left image (fracture 1?) blocks access to the fine-grained precipitate on the bottom in the left image (fracture 2?)?

Reply: Due to the brittleness of the sample it was impossible to locate the SEM cuts to the corresponding fracture in a CT image. Therefore, we do not know the aperture or orientation of the fractures. We have changed the figure caption to better describe the position of the fractures relative to each other.  

Line 316, 320: typo? I assume it should be ‘interface’

Reply: Corrected

Line 318: ‘index’?

Reply: Corrected

Line 316-320: OK, much clearer now. However, how do then the large crystals in the left image in Figure 4 fit in the story?

Reply: Large crystals are part 1) of the story (beginning of the paragraph). We now added a link in the story to the large crystals in figure 3.

Video 4: how do you know what is calcite and what is gypsum? Also, what is the use of this video? Is it mentioned in the text?

Reply: We now use it in the text and in the supporting information.

Basically, it is the time-lapse evidence of mineral replacement, which shows that the reaction is localized around calcite grains. Even though it is secondary to our story (so we have it only in SI) it is pretty cool that replacement reactions can be monitored so clearly over time.  

FYI on the Videos: with a different player (Irfanview instead of VLC) the videos all play at a good speed – no idea why VLC didn’t work.  

Also, I much appreciate the mental image sketched by the candy truck J More science should be explained with candy!

Reply: We fully agree :)

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