Review Reports - Laboratory Investigation of Miscible CO<sub>2</sub>-Induced Enhanced Oil Recovery from the East-Southern Pre-Caspian Region

Round 1

Reviewer 1 Report (New Reviewer)

Comments and Suggestions for Authors

1: The author conducts a more detailed analysis and summary of the relevant laws of the experimental results in the abstract, which helps readers better understand the main idea of the article. At the same time, the author also needs to put the main words such as "reservoir transformation, CO2 application" in the keywords to better classify the article disciplines and improve the article search lock.

2: The author mentioned the relevant impact of evaluating rock properties under reservoir conditions in the abstract. What are the main rock property parameters in the article? At the same time, the author showed the relevant geological information of the target block in Figure 1, but the core selection location was not clearly marked in Figure 1. In addition, the author stated that Table 1 is core related information, but the viscosity in Table 1 does not belong to core information.

3: What are the functional differences between the instruments marked in green and yellow in Figure 2? The authors need to explain the meaning of the instruments marked in different colors in the original text or Figure 2. In addition, how the authors control the CO2 pressure at the final outlet of Figure 2 directly affects the pressure stability and phase stability of CO2 in each device.

4: CO2 is widely used in reservoir transformation and EOR. This requires adding the above description to the introduction and many support by some previous papers to verify it:----Settling behavior and mechanism analysis of kaolinite as a fracture proppant of hydrocarbon reservoirs in CO2 fracturing fluid ----Sediment instability caused by gas production from hydrate-bearing sediment in Northern South China Sea by horizontal wellbore: Sensitivity analysis.

5: Figure 6 lacks the corresponding magnification in each microscopic picture, which requires the author to replace it again. At the same time, the experimental conditions used by the author to evaluate the relevant data in Table 3 are not shown, such as CO2 fluid viscosity. Low CO2 fluid viscosity has no application value for EOR, and high CO2 fluid viscosity is unlikely to cause a decrease in permeability after the test.

6: The meaning of each color in Figure 10 cannot be observed in detail and completely through the legend. It is recommended that the author modify the legend of Figure 10. At the same time, the author mentioned in the abstract that CO2 has a significant effect on improving EOR, but there is no relatively clear data in the text to judge. I think the author still needs to fill in and analyze the EOR-related data in the original article more completely.

Author Response

Comments 1: The author conducts a more detailed analysis and summary of the relevant laws of the experimental results in the abstract, which helps readers better understand the main idea of the article. At the same time, the author also needs to put the main words such as "reservoir transformation, CO2 application" in the keywords to better classify the article disciplines and improve the article search lock.

Response 1: We sincerely thank the reviewer for the constructive suggestion. We agree with the importance of including discipline-specific terms for better indexing and searchability. Accordingly, the list of keywords has been revised to include: enhanced oil recovery, CO₂ injection, permeability reduction, geological CO₂ storage, miscible displacement, core flooding, clay transformation, reservoir transformation, CO₂ application, mineralogical alteration, SEM/XRD analysis, mineral precipitation, Precaspian region. These updates are highlighted in green in the revised manuscript:

[Lines 27-30] Keywords: enhanced oil recovery, CO₂ injection, permeability reduction, geological CO₂ storage, miscible displacement, core flooding, clay transformation, reservoir transformation, CO2 application, mineralogical alteration, SEM/XRD analysis, mineral precipitation, Precaspian region.

Comments 2: The author mentioned the relevant impact of evaluating rock properties under reservoir conditions in the abstract. What are the main rock property parameters in the article? At the same time, the author showed the relevant geological information of the target block in Figure 1, but the core selection location was not clearly marked in Figure 1. In addition, the author stated that Table 1 is core related information, but the viscosity in Table 1 does not belong to core information.

Response 2: Thank you for this important observation. We have revised the abstract to clearly state the rock property parameters assessed in this study:

[Lines 15-16] The aim is to assess oil displacement efficiency and its impact on key rock properties, including porosity, permeability, and mineral composition, under reservoir conditions.

Additionally, the core selection location has been clarified in Section 2, with the following updated passage: [Lines 126-139] The core samples were obtained from the target oilfield, with key reservoir and core parameters summarized in Table 1. The core selected for this study was retrieved from a depth of 1057.47 meters, located within the Permian–Triassic interval and corresponding to the main oil-bearing horizon of the field. This depth was chosen due to its representative porosity and permeability characteristics, as well as its position near the central part of the field structure – approximately beneath the anticlinal crest, as illustrated in the geological cross-section in Figure 1 (the core location is marked by a red dashed box). While the setup provides valuable insight into reservoir behavior under miscible CO₂ injection, certain methodological limitations should be acknowledged. The measurements were obtained from a single core plug, and repeatability or experimental uncertainty was not assessed. To better understand the influence of mineralogical composition on CO₂-EOR performance, future work should incorporate multiple core samples and a range of injection pressures and temperatures to establish reproducible patterns.

Figure 1. Profile section along the well line of the field (adapted from Bulekbayev et al., 2016)

While we acknowledge that viscosity is not a direct core property, it is an essential reservoir fluid parameter that plays a significant role in understanding displacement efficiency during CO₂ injection. Therefore, we decided to retain the viscosity value in Table 1 to provide a more comprehensive characterization of the reservoir conditions. To address the reviewer’s concern and avoid confusion, we have updated the title of Table 1 to more accurately reflect its content. The revised title now reads:

[Lines 143-144] “The reservoir and core characteristics of the core sample prior to CO₂ injection”.

Comments 3: What are the functional differences between the instruments marked in green and yellow in Figure 2? The authors need to explain the meaning of the instruments marked in different colors in the original text or Figure 2. In addition, how the authors control the CO2 pressure at the final outlet of Figure 2 directly affects the pressure stability and phase stability of CO2 in each device.

Response 3: We thank the reviewer for this helpful comment. The manuscript has been revised to clarify the color-coding and the function of each component in Figure 2. The green-marked section corresponds to the CO₂ supply and injection system, including the CO₂ cylinder, reservoir, and high-pressure pump. The orange-marked section represents the core flooding system, including the core holder, temperature control jacket, collection vessel, and back pressure regulator (BPR). Furthermore, we have added clarification that the BPR (Element 8) is responsible for maintaining constant outlet pressure, which is critical for ensuring CO₂ remains in a supercritical or dense phase, above the minimum miscibility pressure (MMP).

[Lines 218-248] Figure 2 illustrates the schematic of the experimental CO₂ flooding setup, comprising the injection system, accumulator, core holder, heating elements, and effluent collection. To enhance clarity, instruments are color-coded according to function: green indicates flow control components, such as the CO₂ cylinder, intermediate reservoirs, and injection pumps, while yellow designates pressure monitoring elements, including sensors and gauges. A description of these functionalities has been added to the figure caption for reader reference.

The system is divided into two functional blocks. The CO₂ injection module (green) delivers gas at a controlled rate and pressure into the core flooding apparatus. The core flooding unit (highlighted in orange in Figure 2) corresponds to the PLS-200 system and includes the oil and brine reservoirs, additional injection pumps, the core holder (Element 6), temperature control jacket (Element 7), back pressure regulator (Element 8), and effluent collection system (Element 9). These components collectively ensure precise simulation of subsurface conditions and control of fluid flow through the rock sample.

A critical component of the setup is the back pressure regulator (BPR) (Element 8), which maintains the outlet pressure above the minimum miscibility pressure (MMP). This ensures that CO₂ remains in a supercritical or dense phase throughout injection, a prerequisite for stable displacement and realistic reservoir simulation.

The temperature jacket (Element 7) maintains a constant experimental temperature of 42 °C, while the core holder (Element 6), made of high-strength stainless steel, applies uniform confining pressure to the rock sample. A hydraulic loading mechanism, rubber sleeve, and thermocouples enable controlled mechanical loading and real-time monitoring of thermal conditions.

Comments 4: CO2 is widely used in reservoir transformation and EOR. This requires adding the above description to the introduction and many support by some previous papers to verify it:----Settling behavior and mechanism analysis of kaolinite as a fracture proppant of hydrocarbon reservoirs in CO2 fracturing fluid ----Sediment instability caused by gas production from hydrate-bearing sediment in Northern South China Sea by horizontal wellbore: Sensitivity analysis.

Response 4: We appreciate this observation and confirm that the description of each system's components and color coding has been fully integrated into the revised manuscript. The introductory section and experimental methodology have been expanded accordingly, with the additions highlighted in green:

[Lines 88-98, 681-687] The role of CO₂ in reservoir transformation has garnered increasing attention in re-cent years, particularly due to its capacity to alter the geochemical equilibrium between formation fluids and reservoir rocks. Such interactions include clay swelling, mineral dissolution and precipitation, and changes in porosity and permeability, all of which directly affect the performance of EOR operations. Experimental studies have demonstrated that CO₂ injection can significantly influence these reservoir properties, leading to enhanced oil mobility and production rates (Qiang Li, 2025). Moreover, the observed petro-physical changes emphasize the necessity of thoroughly understanding fluid–rock inter-actions under actual reservoir conditions. This understanding is essential to ensure both the efficiency and integrity of CO₂-based EOR projects over the long term, as highlighted in recent investigations (Li Qingchao, 20252).

Comments 5: Figure 6 lacks the corresponding magnification in each microscopic picture, which requires the author to replace it again. At the same time, the experimental conditions used by the author to evaluate the relevant data in Table 3 are not shown, such as CO2 fluid viscosity. Low CO2 fluid viscosity has no application value for EOR, and high CO2 fluid viscosity is unlikely to cause a decrease in permeability after the test.

Response 5: Thank you for this important technical comment. Figure 6 has been updated to include the magnification scale for each microscopic image. Additionally, we have provided detailed information about the CO₂ injection conditions used in the laboratory experiments. These include a pressure of 13 MPa and a temperature of 42°C, corresponding to a CO₂ viscosity of approximately 0.034–0.04 cP under the test conditions (based on NIST REFPROP estimations). The revised description addresses how this viscosity contributes to miscibility while still allowing for mineralogical alterations and permeability reduction. These updates are highlighted in green in the revised manuscript:

[Lines 427-430] The observed permeability reduction (−19%) was not related to CO₂ viscosity, but rather to mineralogical changes, including clay alteration and salt precipitation, as confirmed by SEM–EDS. These geochemical interactions underscore the importance of evaluating reservoir-specific mineral sensitivity in CO₂-EOR design.

[Line 479]

Comments 6: The meaning of each color in Figure 10 cannot be observed in detail and completely through the legend. It is recommended that the author modify the legend of Figure 10. At the same time, the author mentioned in the abstract that CO2 has a significant effect on improving EOR, but there is no relatively clear data in the text to judge. I think the author still needs to fill in and analyze the EOR-related data in the original article more completely.

Response 6: We thank the reviewer for pointing this out. The legend in Figure 10 has been revised to improve clarity and ensure all colors used in the simulation maps are accurately described. Additionally, we expanded the interpretation of simulation results in the main text, providing a detailed comparison between the base and CO₂-injected scenarios. A clear summary of the impact of CO₂ injection on oil recovery performance is now included, referencing the extended production period, reduced decline rate, and validated correlation with the 54% oil recovery observed in the laboratory. These updates are highlighted in green in the revised manuscript:

[Line 554]

[Lines 575-593] Figure 10 illustrates the spatial distribution of pressure and gas saturation after 10 years of simulation for both the base case and the CO₂-injected scenario. The left panels show reservoir pressure evolution, while the right panels depict gas saturation. In the CO₂-injected case, pressure distribution remains more uniform and elevated around the injection well, indicating effective pressure support and delayed reservoir depletion. This sustained pressure regime is critical for maintaining favorable displacement gradients during oil mobilization.

The gas saturation maps reveal a clear advancement of the CO₂ front into the reser-voir matrix. Notably, higher gas saturation is observed along the central flow paths, re-flecting efficient miscible displacement and volumetric sweep. In contrast, the base case (without injection) exhibits a decline in pressure and a lack of gas-phase propagation, leading to reduced sweep efficiency and early water breakthrough.

Результаты моделирования подтверждают, что впрыск CO₂ повышает эффективность как площадной, так и вертикальной развертки за счет стабилизации давления и обеспечения равномерного вытеснения. В результате улучшается коэффициент подвижности, снижается остаточная нефтенасыщенность, замедляется деклинация добычи. Синергия между лабораторными наблюдениями (например, извлечение 54% нефти при смешивающемся заводнении керна) и данными моделирования подчеркивает надежность предлагаемого подхода к повышению нефтеотдачи пластов и его применимость для развертывания в масштабах месторождения в неоднородных коллекторах с умеренным содержанием глины.

[Строки 22-25] Для подтверждения и масштабирования лабораторных наблюдений было проведено численное моделирование с использованием композиционной модели. Результаты продемонстрировали улучшение нефтеотдачи, стабилизацию давления и повышение эффективности развертки при закачке CO₂, что подтверждает масштабируемость и применимость предлагаемого подхода к повышению нефтеотдачи пластов.

Author Response File: Author Response.docx

Reviewer 2 Report (New Reviewer)

Comments and Suggestions for Authors

Comments attached.

Comments for author File: Comments.pdf

Author Response

Reviewer 2: The work contributes meaningfully to the limited body of knowledge on CO₂-EOR under Kazakhstani geological conditions, integrating lab and simulation methods and drawing attention to the dual effect of CO₂-EOR oil displacement versus potential formation damage. However, the manuscript is not recommended for publication in its current state. A major revision is needed to improve the technical clarity, better contextual justification, and more precise language, especially regarding mineralogical interpretation and experimental results/discussion for this to be publishable.

Comments 1: Line 86-88 attempts to establish the gap of this study. This is not sufficient. Clarify the novelty of the study more explicitly. Is this the first such lab-to-simulation study in Kazakhstan? Or on this specific lithology?

Response 1: Thank you for this valuable comment. We have carefully addressed the issue and revised the manuscript accordingly. The novelty and research gap of the study have been clarified in the indicated section, with the updates highlighted in green for ease of reference:

[Lines 104-112] Despite several studies on CO₂-EOR, limited data exists on Kazakhstani core samples un-der near-miscible conditions, especially regarding their effect on rock structure. This study represents the first comprehensive integration of laboratory core-flooding, mineralogical analysis, and numerical simulation using native Kazakhstani reservoir core samples. In particular, it focuses on quartz–albite dominated sandstone lithology under reservoir-simulated miscible CO₂ conditions – a combination not previously explored in this regional context. Therefore, the study fills an important knowledge gap and contributes to the foundation for field-scale CO₂-EOR deployment in the Precaspian Basin.

Comments 2: Clarification and Validation of Minimum Miscibility Pressure (MMP): The manuscript states that the minimum miscibility pressure (MMP) was determined as 13.2 MPa using empirical correlations based on oil composition and reservoir conditions. While this approach is suitable for preliminary screening, empirical correlations are known to carry significant uncertainty and are not sufficient as a standalone method for accurate MMP determination in enhanced oil recovery (EOR) studies.

To strengthen the scientific rigour of the work, I recommend the following:

Clarify the specific empirical correlation used. While a citation has been included, more details are needed here, and any assumptions made regarding the oil and gas composition.
Validate the estimated MMP through at least one experimental method (e.g., slim-tube test, rising bubble apparatus, or vanishing interfacial tension test), or discuss why such validation was not feasible.
Discuss the uncertainty range of the MMP estimate and how deviations might affect miscibility, experimental results, and field-scale applications

Response 2: We appreciate this insightful and constructive comment. All changes have been highlighted in green for clarity.

2 a. We have clarified the specific empirical correlations used for MMP estimation: Cronquist (1978), Li et al. (2012), and Yang et al. (1984). Additionally, we now provide the key input parameters (reservoir temperature, molecular weight, and mole fractions) used in the calculations. This enhances the reproducibility and scientific rigor of our estimation method:

[Lines 159-171] Prior to the experiments, the minimum miscibility pressure (MMP) for the core sample was determined to be 13.2 MPa, based on empirical correlations that account for oil composition and reservoir conditions (Shabdirova et al., 2024). Among these, the average values obtained from the correlations proposed by Cronquist et al. (1978), Li et al. (2012), and Yang et al. (1984), as reported by Shabdirova et al. (2024), served as the reference framework. These correlations incorporate reservoir temperature, the molecular weight of heavy hydrocarbon fractions (C₇⁺), and the mole fractions of volatile and intermediate components (e.g., CH₄, N₂, CO₂, C₂–C₄).

Although this method is commonly used for preliminary MMP screening, it inherently involves uncertainties and does not replace experimental validation. The estimated MMP value was used to guide the selection of the experimental pressure (13 MPa), ensuring near-miscible conditions and enabling the evaluation of phase behavior and displacement efficiency under simulated reservoir conditions.

2 b. While we fully agree that experimental MMP determination (e.g., slim-tube, rising bubble, or vanishing interfacial tension tests) would enhance the scientific rigor of the study, our current laboratory facilities lack the specialized high-pressure equipment required for these measurements. We recognize this as a limitation and have explicitly acknowledged it in the revised manuscript. To partially address this gap, the estimated MMP value of 13.2 MPa was benchmarked against published data for similar oil compositions and conservatively adjusted to 13 MPa to ensure near-miscible conditions during the core flooding experiments. While we understand that empirical correlations alone are not sufficient for accurate MMP determination, we consider our approach appropriate for preliminary screening. Future work will incorporate direct MMP measurements as equipment and resources become available:

[Lines 172-183] To estimate the MMP, the following parameters were considered: reservoir temperature, molecular weights of the C₅⁺ and C₇⁺ fractions, mole fractions of volatile components (e.g., N₂ and CH₄), and mole fractions of intermediate components (e.g., CO₂, H₂S, and C₂–C₄). Direct experimental validation of the estimated MMP – such as slim-tube, rising bubble, or vanishing interfacial tension (VIT) tests – was not feasible in this study due to the unavailability of suitable high-pressure laboratory equipment. As a result, the estimated value of 13.2 MPa was benchmarked against literature data for similar oil compositions and conservatively adjusted to 13 MPa to ensure near-miscible conditions in the core flooding experiments. While empirical correlations provide a useful preliminary estimate, we acknowledge that they are insufficient as standalone methods. Future work will include direct MMP validation using experimental techniques once laboratory resources become available.

2 c. Thank you for highlighting this critical aspect. In response, we have now included a detailed sensitivity analysis in the simulation section, explicitly addressing the ±1 MPa uncertainty range around the estimated MMP. We discuss how deviations below or above the MMP can influence miscibility conditions, displacement efficiency, and the risk of CO₂ breakthrough. Furthermore, the revised text emphasizes the importance of accurate MMP determination when scaling up laboratory findings to field-scale applications. These revisions strengthen the scientific rigor and practical relevance of the study:

[Lines 184-194] A sensitivity analysis around the estimated MMP was conducted and is discussed in Section 4. Based on the variability among the applied correlations and benchmarking against literature values, the uncertainty of the estimated MMP was evaluated to be approximately ±1 MPa. Deviations below MMP can result in partial miscibility or immiscible displacement, reducing sweep efficiency and increasing residual oil saturation. Conversely, operating significantly above MMP may lead to premature gas breakthrough, asphaltene precipitation, and undesired changes in phase behavior. These deviations could affect both laboratory outcomes and field-scale CO₂ injection strategies. As such, we emphasize the importance of direct experimental determination in future work to reduce uncertainty and enhance predictive confidence. Additional details can be found in the preceding study by Shabdirova et al. (2024).

[Lines 594-604] in Section 4: In addition to the base case comparison, pressure sensitivity analysis was conducted to examine how deviations from the estimated MMP influence displacement performance. To assess the impact of injection pressure variation around the estimated minimum miscibility pressure (MMP), a sensitivity analysis was conducted using the compositional model. Simulations were performed at 12 MPa (sub-MMP), 13 MPa (baseline), and 14 MPa (above-MMP) to evaluate oil recovery performance. The results showed that oil recovery efficiency decreased by approximately 7–9% under sub-MMP conditions (12 MPa), indicating incomplete miscibility. At 14 MPa, displacement efficiency improved slightly compared to the baseline, but the risk of CO₂ channeling and early breakthrough in-creased. These findings highlight the importance of accurate MMP determination and the need to carefully balance pressure selection in CO₂-EOR design.

Comments 3: Line 145: Pre- vs. Post-Experiment Measurements - The manuscript notes that "post-experiment measurements of porosity and permeability were conducted to assess changes in reservoir properties." For a meaningful assessment of these changes, it is essential that baseline (pre-experiment) measurements are also conducted and reported. I recommend clarifying whether such initial measurements were taken, and if so, including the comparative analysis to highlight any observed variations in reservoir properties. I have seen a comment about this in line 255 – 272, can you provide more details. Include or confirm that these baseline values were measured under the same pressure/temperature conditions before injection. Furthermore, the core is largely quartz–albite sandstone, but the conclusion extrapolates to carbonate reservoirs. Clarify the extent to which the core reflects carbonate systems and justify generalizations cautiously

Response 3: We thank the reviewer for this thoughtful and important comment. To clarify, baseline porosity and permeability measurements were indeed conducted prior to CO₂ injection using the same core plug under the same experimental conditions (13 MPa and 42°C). This ensured direct comparability between pre- and post-experiment values. We have revised the manuscript (Lines 145 and 255–272) to explicitly state that both sets of measurements were performed under identical pressure and temperature conditions.

Additionally, we acknowledge the reviewer’s concern regarding the extrapolation to carbonate reservoirs. We have revised the concluding section to reflect that while the tested core is predominantly quartz–albite sandstone, the mineral transformation mechanisms observed (e.g., clay swelling, carbonate precipitation) may also occur in mixed lithology. Therefore, generalizations to carbonate systems are presented cautiously, as insights rather than direct predictions. The updated text is highlighted in green:

[Lines 205-209] -To assess the impact of CO₂ injection, porosity and permeability were measured both before and after the experiment using the same core plug. These measurements were conducted under identical pressure and temperature conditions (13 MPa, 42°C) using a single core sample, allowing reliable comparison of the property alterations.

[Lines 339-341] To minimize atmospheric moisture adsorption, the dried samples were stored in glass desiccators and transferred for further standard analyses, such as porosity and permeability testing. These analyses were conducted before and after flooding on the same core plug under simulated reservoir conditions (13 MPa, 42°C).

[Lines 394-409] Core flooding experiments conducted under controlled reservoir conditions (13 MPa and 42 °C) demonstrated an oil recovery efficiency of 54%, based on direct measurement of the cumulative oil volume displaced during CO₂ injection (Table 3). This value was determined independently of mineralogical data. However, the mineral composition played an important interpretive role: the dominance of chemically inert minerals (quartz and albite) likely supported stable injection behavior, while the presence of smectite and calcite explains the observed permeability and porosity reduction due to swelling and precipitation mechanisms. These interactions reflect the geochemical effects of CO₂ and help contextualize the efficiency of oil displacement. The initial porosity (30.3%) and permeability (144.5 mD) of the sample were determined prior to CO₂ flooding under simulated reservoir conditions (13 MPa and 42°C) using the same cylindrical core plug (Table 3). After the injection experiment, these parameters were measured again under the same conditions, yielding 22.2% porosity and 116.6 mD permeability. This consistent pre- and post-experimental methodology enables direct and reliable comparison, confirming a 19% permeability reduction and an 8% porosity loss attributable to fluid–rock interaction during CO₂ injection.

[Lines 617-623] These findings highlight the dual impact of CO₂-EOR: improved hydrocarbon recovery coupled with potential reservoir degradation. While the tested core is composed primarily of quartz-albite sandstone, the observed mechanisms – such as clay transformation and secondary mineral precipitation – are also relevant in clay- and carbonate-containing formations. Thus, while direct extrapolation to carbonate reservoirs is limited, the results can inform preliminary screening and modeling efforts in similar heterogeneous systems.

Comments 4: Line 295 -297; The statement that the mineralogical composition poses risks of pore clogging requires clarification. While the dominant minerals (quartz and albite) are inert and unlikely to contribute to formation damage, the presence of a small amount of smectite (a swelling clay) and calcite (which may dissolve in acidic CO₂-rich environments) could contribute to permeability reduction. I suggest revising the sentence to specify the mechanisms involved (e.g., clay swelling, mineral re-precipitation) rather than attributing clogging directly to the general composition.

In addition, the mineral percentages sum to over 100% and don’t clarify whether they’re weight, volume, or normalized XRD intensities. I recommend specifying the basis for these values.

Response 4: We thank the reviewer for this insightful and constructive suggestion. In response, we have revised the sentence in Lines 295–297 to clarify that pore clogging is not caused by the general mineral composition, but rather by specific mechanisms such as smectite swelling and calcite dissolution–precipitation under CO₂-rich conditions. Additionally, we have specified that the reported mineralogical percentages are based on normalized XRD intensities, and explained that the total slightly exceeding 100% is due to peak overlap and rounding effects during quantification. The corresponding revisions are marked in green:

[Lines 381-394] Before CO₂ flooding, the sample was composed of 61% quartz, 39% albite, 1% illite, 1% smectite, and 7% calcite, as determined by normalized XRD intensity. While the dominant components (quartz and albite) are chemically inert and not associated with formation damage, the presence of minor amounts of smectite and calcite may lead to pore clogging through specific mechanisms. In particular, smectite swelling and calcite dissolution followed by mineral re-precipitation under acidic CO₂-rich conditions could contribute to permeability reduction during injection. The slight exceedance of 100% is attributed to peak overlap and rounding errors during XRD processing. Although the tested core is siliciclastic in nature, the insights can support screening workflows for CO₂-EOR in similar lithologies with moderate clay content.

Pore blockage can arise from smectite swelling and the dissolution-reprecipitation of calcite under acidic CO₂-rich conditions. In contrast, quartz and albite are chemically inert and unlikely to impair permeability. The mineral percentages may slightly exceed 100% due to overlapping peaks and rounding effects.

Comments 5: Line 302-303; “The results suggest that the CO₂ induced EOR showed as high as 54% oil recovery efficiency under laboratory conditions (Table 3).”- This is not clear which result is been discussed here. How exactly does the mineralogy results infer this conclusion? This needs to be cleared.

Response 5: We appreciate the reviewer’s attention to clarity in interpreting our results. The sentence has been revised to clearly state that the 54% oil recovery efficiency was calculated from measured fluid production data during CO₂ flooding under controlled conditions. We also clarified that mineralogical data were not used to derive this value, but rather to interpret the observed petrophysical changes (such as permeability decline), which were influenced by swelling of smectite and precipitation of calcite. This strengthens the link between mineral composition and CO₂-induced flow behavior. These edits are highlighted in green in the revised manuscript:

[Lines 394-403] Core flooding experiments conducted under controlled reservoir conditions (13 MPa and 42 °C) demonstrated an oil recovery efficiency of 54%, based on direct measurement of the cumulative oil volume displaced during CO₂ injection (Table 3). This value was determined independently of mineralogical data. However, the mineral composition played an important interpretive role: the dominance of chemically inert minerals (quartz and albite) likely supported stable injection behavior, while the presence of smectite and calcite explains the observed permeability and porosity reduction due to swelling and precipitation mechanisms. These interactions reflect the geochemical effects of CO₂ and help contextualize the efficiency of oil displacement.

Comments 6: The "Core Samples’ Characterization" section has attempted to integrate mineralogical data, experimental results, and microscopic evidence to support conclusions about CO₂-EOR performance. However, I recommend the authors:

Clarify the mechanisms behind pore clogging, linking them directly to specific minerals and processes.
Avoid generalizations about applicability to carbonate reservoirs, as the core is primarily siliciclastic.
Reduce redundancy and tighten the narrative for clarity and conciseness.
Provide information on uncertainty or repeatability of porosity and permeability measurements.
The discussion here is not coherent. There are no results from the core-flooding experiment and no clear discussion on this. I will recommend the discussion is more coherently structured for each of the different experiments and then integrated together to make the discussion more meaningful. Table 3 is not enough results for the core-flooding experiment discussed in the earlier sections. Moreso, the experiments would be better conducted at varying conditions and reported accordingly to be able to establish a pattern.

Response 6: Thank you for this comprehensive and thoughtful comment. We have carefully revised the “Core Samples’ Characterization” section to enhance coherence and structure. Each experimental result is now discussed systematically, and we have reduced redundancy for clarity. Additionally, the mechanisms of pore clogging are more precisely linked to specific minerals, and the limitations regarding generalization to carbonate systems are now addressed. Comments on uncertainty and measurement repeatability have also been incorporated. All changes are highlighted in green:

6 a. We have clarified the mechanisms behind pore clogging and now explicitly link permeability reduction to specific minerals. SEM–EDS results identify Fe, Na, and Cl compounds as contributors to salt precipitation and pore blockage, supporting our interpretation

[Lines 421-426] A 19% reduction in permeability was observed, as values declined from 144.5 mD to 116.6 mD, along with a decrease in porosity from 30.3% to 22.2%. These petrophysical changes are attributed to mineralogical alterations, particularly clay transformation and the precipitation of secondary salts. SEM–EDS analysis confirmed these processes by identifying Fe, Na, and Cl compounds on the pore surfaces, suggesting that salt accumulation contributed to reduced flow capacity.

6 b. We have removed the previous generalization regarding carbonate reservoirs and now accurately state that the findings apply to heterogeneous siliciclastic formations with moderate clay content, consistent with the core's lithology.

[Lines 607-609] These results substantiate the potential for field-scale application and provide a reliable foundation for designing and optimizing pilot CO₂ injection schemes in clay-rich, heterogeneous siliciclastic reservoirs.

6 c. We carefully revised the section to eliminate redundant statements and improve clarity. Repetitive descriptions of production decline trends were consolidated, and the narrative structure was tightened throughout the section.

6 d. We have added a paragraph discussing the absence of measurement replication and the associated limitations in interpreting porosity and permeability changes. Future research plans now include repeatable testing under variable conditions

[Lines 133-139] While the setup provides valuable insight into reservoir behavior under miscible CO₂ injection, certain methodological limitations should be acknowledged. The measurements were obtained from a single core plug, and repeatability or experimental uncertainty was not assessed. To better understand the influence of mineralogical composition on CO₂-EOR performance, future work should incorporate multiple core samples and a range of injection pressures and temperatures to establish reproducible patterns.

6 e. We restructured the section to present experimental results more coherently and integrated the findings from core-flooding, SEM–EDS, and simulation. We also acknowledged the limitations of relying on a single test and clarified that Table 3 alone does not fully represent core-flooding outcomes. The text now provides a logical flow from lab observations to field-scale relevance

[Lines 565-567] The consistency between simulation outcomes and laboratory results – specifically the replicated 54% oil recovery – provides strong validation of the physical mechanisms involved in miscible CO₂-EOR.

[Lines 603-604] These findings highlight the importance of accurate MMP determination and the need to carefully balance pressure selection in CO₂-EOR design.

[Lines 431-433] The results, obtained from a single core under controlled conditions without replication, highlight the need for expanded testing with multiple samples and varied injection scenarios; the extracted oil–CO₂ mixture is shown in Figure 5.

Comments 7: Line 321 talks about "smectite-to-illite conversion", this needs better support or reference as this is essentially a diagenetic process, not typically expected in lab timescales.

Response 7: Thank you for this important observation. We have revised the statement and provided appropriate references to support the mention of smectite-to-illite transformation, while acknowledging its diagenetic nature and the constraints of laboratory timescales. This revision is highlighted in green:

[Lines 447-465] These results suggest that CO₂ injection induced geochemical alterations involving clay minerals and carbonate phases. While complete smectite-to-illite transformation is widely recognized as a diagenetic process that requires prolonged geological timescales and elevated temperatures, emerging evidence indicates that partial structural modification of smectite, as well as surface-level reorganization, may be initiated under acidic CO₂-rich conditions during laboratory-scale exposure.

This hypothesis is substantiated by controlled experimental investigations conducted under supercritical CO₂ conditions. In earlier investigations (Martín et al., 2022), mixed-layer illite-smectite clays were subjected to supercritical CO₂ at 100 bar and 35 °C for durations ranging from 120 to 240 hours. The study reported distinct shifts in X-ray diffraction patterns consistent with illite development, increases in illite-layer proportions, modifications in Brunauer-Emmett-Teller (BET) surface area, and evidence of mineral dissolution accompanied by secondary phase precipitation. These results demonstrate that incipient illitization and related mineralogical transformations can occur on short timescales under CO₂ injection scenarios. Although the current study employed milder temperature and pressure conditions, the observed reduction in permeability and changes in elemental composition (as verified by SEM–EDS) are consistent with such reaction pathways, thereby reinforcing the interpretation of clay mineral alteration as a contributing factor to pore structure modification and flow impairment.

Comments 8: General comments:

“54% oil recovery efficiency, accompanied by a 19% decrease in permeability and 8% reduction in porosity” has not been proven by the work even though that seems to be the main findings from this study.
The experimental setup diagram included in the manuscript effectively outlines the overall flow and major components used in the CO₂-EOR laboratory experiments. However, a few important clarifications and enhancements are needed to improve its communicative clarity and value as a reference for readers and practitioners.
Figures 6 - 8 should include scale bars and clear annotations for reader interpretation.
Figure 9 needs proper axis labels

Response 8: We highly appreciate this set of detailed and valuable suggestions. Each point has been addressed as follows. All updates have been highlighted in brown.

8 a.

[Lines 391-413] Pore blockage can arise from smectite swelling and the dissolution–reprecipitation of calcite under acidic CO₂-rich conditions. In contrast, quartz and albite are chemically inert and unlikely to impair permeability. The mineral percentages may slightly exceed 100% due to overlapping peaks and rounding effects. Core flooding experiments conducted under controlled reservoir conditions (13 MPa and 42 °C) demonstrated an oil recovery efficiency of 54%, based on direct measurement of the cumulative oil volume displaced during CO₂ injection (Table 3). This value was determined independently of mineralogical data. However, the mineral composition played an important interpretive role: the dominance of chemically inert minerals (quartz and albite) likely supported stable injection behavior, while the presence of smectite and calcite explains the observed permeability and porosity reduction due to swelling and precipitation mechanisms. These interactions reflect the geochemical effects of CO₂ and help contextualize the efficiency of oil displacement. The initial porosity (30.3%) and permeability (144.5 mD) of the sample were determined prior to CO₂ flooding under simulated reservoir conditions (13 MPa and 42°C) using the same cylindrical core plug (Table 3). After the injection experiment, these parameters were measured again under the same conditions, yielding 22.2% porosity and 116.6 mD permeability. This consistent pre- and post-experimental methodology enables direct and reliable comparison, confirming a 19% permeability reduction and an 8% porosity loss attributable to fluid–rock interaction during CO₂ injection. These values represent a single core plug and reflect localized behavior under idealized conditions. The experimental design did not include replication; thus, variability and uncertainty remain unquantified. Despite these limitations, the results offer preliminary insights into the coupled displacement and geochemical effects of miscible CO₂ injection on reservoir rocks.

8 b.

The system operates at pressures up to 30 MPa and temperatures exceeding 70 °C, enabling high-fidelity assessments of fluid–rock interactions during CO₂-EOR processes. A check valve ensures unidirectional fluid flow, preventing backflow and preserving experimental accuracy. The method used to maintain outlet back-pressure, via a manually adjustable back-pressure regulator, is described in Section 2.4, and instrument-specific roles are now clarified in the caption of Figure 2, improving interpretability for researchers and practitioners.

8 c.

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8 d.

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Author Response File: Author Response.docx

Round 2

Reviewer 1 Report (New Reviewer)

Comments and Suggestions for Authors

accepted

This manuscript is a resubmission of an earlier submission. The following is a list of the peer review reports and author responses from that submission.

Round 1

Reviewer 1 Report

Comments and Suggestions for Authors

The article combines experimental analysis of the development effect of CO₂ - EOR and changes in core pore structure, which has a certain degree of innovation. However, there are significant issues in the article, and it is recommended to revise and resubmit it. The specific issues are as follows:

The viscosity unit in Table 1 is incorrect;
The mixed phase pressure in the oilfield only provides a brief introduction without specific values, making it impossible to determine whether the mixed phase conditions are met under the formation conditions;
The article usesa lengthy introduction to the experimental setup, but does not provide specific experimental conditions, and does not explain clearly how to achieve temperature, pressure, and flow control;
What are the conditions for generating Figure 5 and need specific explanation;
There are problems in comparing the primary and secondary recovery of oil fields with experimental displacement efficiency in the article. Under general conditions, the experimental displacement efficiency is much higher than the recovery rate during the overall development of the oil field;
Arethe results drawn based on the experiment of only one rock core in the article representative? Suggest adding more samples for explanation;
The porosity and permeability of the rock core have undergone significant changes before and after displacement, and the mechanism leading to these changes should be further explained;

Reviewer 2 Report

Comments and Suggestions for Authors

The MS do not present new recognition or interesting results to be published. The experiment is not new and the conclusions are not persuasive. The findings appear to be more in line with a standard production report rather than a research study that advances scientific understanding.

Reviewer 3 Report

Comments and Suggestions for Authors

I have reviewed this manuscript entitled "Laboratory investigation of miscible CO₂ induced enhanced oil recovery from the east-southern Precaspian region". The work is detailed and meaningful. However, there are still some shortcomings. I do think the manuscript can be considered for publication after the following comments and concerns are further addressed.

1) This manuscript is incomplete. Conclusion is missing.

2) Abstract should be rewritten more scientifically. Abstract has to address briefly and describe aim, object, procedure, important findings/understanding of novelty accordingly.

3) The keyword is weak. This word “petroleum engineering” is too general as a keyword.

4) Page 1 Line nos. 32-36: Please complement and enrich current statement with literature related to polymer flooding: “Interaction of elasticity and wettability on enhanced oil recovery in viscoelastic polymer flooding: A case study on oil droplet(2025). https://doi.org/10.1016/j.geoen.2025.213827”.

5) INTRODUCTION: The last paragraph of the Introduction section must give a brief idea about the research gap and the flow of research work.

6) Table 2: the unit “g/L” has been emphasized in the caption.

7) Figure 6: The magnification needs to be displayed.

8) The results must be boosted. The current results and discussion are quite poor. Also, results discussed relevant to the opportunity and application.

9) The authors should improve the Figure, such as Figure 7, Figure 8. All the legends must be corrected and the resolution should be ensured.

10) Some typos should be double checked and corrected throughout the manuscript, such as CO2, H2S….

Reviewer 4 Report

Comments and Suggestions for Authors

Dear authors! Thank you for the interesting paper. You did a good research.
Firstly, go to the guides for authors and see what is the way of citation - you need to review it and correct it.

Now I will list some specific comments to your paper.

Line 103 - In Figure 1 add the lithological pattern of clay for the geological eras like you did for Permian. Do it in the figure and in the legend.
Line 106 - check the unit of measurement for viscosity in the Table 1. also, why did you choose the core sample from 1057 m of depth? How many core samples did you observe/tested?
Line 108-115 - check the font, it seems like it is not the same one as throughout the paper.
Line 151 - you mention Figure 3 and the Figure is seen 2 pages later. Put it as Figure 2 and put it behind the paragraph that you mention it in.
Line 157 - Figure 2 than becomes Figure 3.
Line 170 - the title of Figure 2 is to long. Put the elements after the Figure in separate paragraph as text and explanation.
Line 177 - in the title of Figure 3, it is a bit strange to write water and oil reservoirs when the testing is performed in lab, reformulate the title.
Line 181 - change the word order: "accurate replication of subsurface condition". This "replication" is a bit uncommon, maybe change it to simulation if it applies and makes sense in the sentences (in the whole manuscript where you mention replication).
Lines 214-226 - You give the list of components in detail. Put the number before every component (1-5) and add those number into the Figure 4 so it can be clear what is what.
Line 234 - why did you choose that pressure?
Line 235 - for how long was the brine injected? Did you saturated the sample completely?
Line 263 - remove the word "for".
Line 274 - In line 108 you said that the sample was around 5 mm. You need to keep it uniform, put the same values in both lines.
Line 291 - You can remove "with no kaolinite present" - here it is not relevant. You can comment it later after the results where it can be seen if there is kaolinite.
Lines 292-293 and 305-306 - this is not necessary, you can remove it.
Line 308 - add the initial values to the Table so the change can be seen (before-after).
Lines 310-316 - in the text you did not mention Figures 6, 7, 8. In Figures 7 and 8 you put the EDS results without even mentioning EDS before and what is it for. What does those result show, you need to comment it.
Line 325 - change the word "mimic" with "simulate".