Comprehensive Analysis of the Annulus Pressure Buildup in Wells with Sustained Gas Leakage Below the Liquid Level
Round 1
Reviewer 1 Report
Comments and Suggestions for AuthorsThis manuscript is very well written. The results are very interesting and align with theoretical trends my group has seen.
I have a few minor comments that could improve the quality of the work.
1. I would suggest limiting the term “A” annulus in the abstract and intro. Maybe describe how it is between the tubing and production casing and simply refer to it as the annulus thereafter since other annuli are not discussed?
2. I am not sold on the FTA analysis. As it is, it does not seem to fit with the rest of the work. The results of it seem obvious and could potentially be directly said and go straight into the experimental section.
3. if the authors do not agree with number 2 above, I would suggest adding more to the FTA analysis. For example, a sensitivity analysis of the probability weights would be interesting. Does that change the overall result?
4. Figure 3 indicates that 4 of the combinations have similar probability. Were the other 3 combinations investigated?
Author Response
This manuscript is very well written. The results are very interesting and align with theoretical trends my group has seen.
I have a few minor comments that could improve the quality of the work.
Comments 1: I would suggest limiting the term “A” annulus in the abstract and intro. Maybe describe how it is between the tubing and production casing and simply refer to it as the annulus thereafter since other annuli are not discussed?
Response 1:Firstly, we express our sincere gratitude for your recognition of our work and your valuable comments. Based on your esteemed feedback, we have revised the abstract to specify the annulus as the "A" annular space between the tubing and the production casing. Throughout the subsequent text, we have consistently used the term "annulus" to refer to this space, enhancing the readability and clarity of our paper.
We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
The following text in the main manuscript have been modified to reflect the above-mentioned changes：
During the process of natural gas development, the Sustained Casing Pressure (SCP) frequently occurs within the annulus of gas wells, specifically referring to the "A" annular space located between the tubing and the production casing in this paper.
Comments 2:I am not sold on the FTA analysis. As it is, it does not seem to fit with the rest of the work. The results of it seem obvious and could potentially be directly said and go straight into the experimental section.
Response 2:Thank you very much for your comment. The purpose of the FTA analysis was to illustrate that there are numerous causes leading to SCP in “A” annulus, with tubing damage being the most significant ones. This led to the focus of our work presented in this paper. As you correctly pointed out, the results are obvious to experts in this field. Therefore, based on your suggestion, we have removed the second part of the FTA analysis and directly proceeded to the experimental section. This adjustment also simplifies the overall structure of the paper and highlights the key points.
We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Comments 3:If the authors do not agree with number 2 above, I would suggest adding more to the FTA analysis. For example, a sensitivity analysis of the probability weights would be interesting. Does that change the overall result?
Response 3:Thank you very much for your comment. We agree with your second suggestion and have removed the FTA analysis from the second part of the original text. Once again, we appreciate your feedback.
Comments 4:Figure 3 indicates that 4 of the combinations have similar probability. Were the other 3 combinations investigated?
Response 4:Thank you very much for your comment. Firstly, we have removed the FTA analysis from the revised manuscript based on your suggestion. Regarding your question, in the original Figure 3, besides tubing damage, the other three failure events are leakage at the tubing threaded connection, leakage at the tubing hanger, and leakage at the packer. All these three leakage scenarios can be considered as gas leakage from the tubing into the annulus, resulting in annulus pressure. The leakage mechanisms can be referred to the experiments designed in this paper. Therefore, the experimental results presented in this paper can also provide reference for these three additional scenarios.
Author Response File: 
Author Response.pdf
Reviewer 2 Report
Comments and Suggestions for AuthorsThe problem considered in the paper is really relevant. The authors have done a great job. However, there are a number of the following comments and questions:
1. In the abstract of the paper, the authors use the term “A” annulus”, but it is not clear from the abstract what space they are talking about. It would be better to write specifically - the space between the tubing and the production casing or explain right in the abstract.
2. Table 2 refers to the annular space “B”, but it is not indicated in the figures and is not mentioned in the text.
3. The last paragraph of Part 2 talks about the main source of SCP in “A” Annulus originates from the tubing damage and leakage at the threaded connection of tubing, why do the authors not talk about events X3 and X4?
4. In Figure 4, in the transfer pipeline system after the heating pipe, there is a device that is not designated in any way (probably a thermometer?).
5. In Figure 4, the authors use the term "hole" although throughout the text it is "orifice".
6. How close are the parameters of the experiment in Table 4 to the real conditions at the field?
7. Leakage position in Table 4 - is it measured from the base of the apparatus? Authors should specify, otherwise it can be measured from the liquid level.
8. In Part 4 of the paper, different liquid levels are indicated in different experiments, but there is no justification for the choice of liquid level for the experiment? Justification or results of the experiment at different levels are required for each case under consideration.
9. The authors need to check all formulas and indicate the designations of the quantities. For example, the designation PA is missing in formula 5, as well as in other formulas (for example, 8 and 9) for some quantities.
10. At the end of Section 4.3, the cooling effect is mentioned, but will such an effect occur in a real well?
11. In the description under equation 14, vg is measured in m/s, but it is said that it is volume. Is this a typo?
12. Section 5.3 proposes a prediction model, but how does it consider the changing gas pressure above the liquid, which acts together with the hydrostatic pressure on the side of the annulus at the leakage orifice?
13. After equation 42, the text states that the “leakage orifice height, equivalent diameter of the leakage orifice” are initial data, but earlier in the paper it was said that these data are very difficult to determine in a real well. How do authors plan to determine them in a real well?
14. Section 5.4 compares the model values ​​with experimental data, but a comparison with data from a real well is required. Can this model work only for a laboratory apparatus?
15. If the leakage in the well is not only below the liquid level, but also above the liquid level, will the developed model be able to work just as well?
Author Response
The problem considered in the paper is really relevant. The authors have done a great job. However, there are a number of the following comments and questions:
Commonts 1：In the abstract of the paper, the authors use the term “A” annulus”, but it is not clear from the abstract what space they are talking about. It would be better to write specifically - the space between the tubing and the production casing or explain right in the abstract.
Response 1：Firstly, we are deeply grateful for your high praise of our paper's work, and we equally appreciate your valuable suggestions. As Reviewer #1 pointed out, we have provided a detailed explanation in the abstract regarding this issue, clarifying that the annulus “A” refers to the annular space between the tubing and the production casing, in order to facilitate a better understanding by the readers. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment. The following text in the main manuscript have been modified to reflect the above-mentioned changes. During the process of natural gas development, the Sustained Casing Pressure (SCP) frequently occurs within the annulus of gas wells, specifically referring to the "A" annular space located between the tubing and the production casing in this paper.
Commonts 2：Table 2 refers to the annular space “B”, but it is not indicated in the figures and is not mentioned in the text.
Response 2：Thank you very much for your comment. The annulus “B” refers to the annular space between the production casing and the technical casing, which is typically filled with a cement sheath. In fact, this paper focuses specifically on the SCP in annulus “A” and does not discuss other annuluses. Reviewer 1 has also pointed out this aspect. To avoid confusion for readers, we have taken Reviewer 1's suggestion and consistently used the term "annulus" to refer to annulus “A”, without discussing annulus “B”. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Commonts 3：The last paragraph of Part 2 talks about the main source of SCP in “A” Annulus originates from the tubing damage and leakage at the threaded connection of tubing, why do the authors not talk about events X3 and X4?
Response 3：Thank you very much for your comment. Since the results obtained from the Fault Tree Analysis (FTA) are actually obvious, we have removed the second part of the FTA based on Reviewer 1's suggestion in the revised manuscript. Regarding your question, X3 and X4 refer to leakage at the tubing hanger and leakage at the packer, respectively. Both of these leakage scenarios can be considered as gas leakage from the tubing into the annulus, resulting in annulus pressure. The leakage mechanisms can be referred to the experiments designed in this paper. Therefore, the experimental results presented in this paper can actually provide reference for these two scenarios as well. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Commonts 4：In Figure 4, in the transfer pipeline system after the heating pipe, there is a device that is not designated in any way (probably a thermometer?).
Response 4：Thank you for pointing out our mistake. As you correctly noted, the thermometer was missing from Figure 2 (referenced as Figure 4 in the original manuscript), and we have corrected it accordingly. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Commonts 5：In Figure 4, the authors use the term " hole " although throughout the text it is "orifice".
Response 5：Thank you for your comment. To maintain consistent terminology, we have revised the image you mentioned by changing "hole" to "orifice."
Commonts 6：How close are the parameters of the experiment in Table 4 to the real conditions at the field?
Response 6：Thank you for your comments. Currently, the widespread issue of abnormal annulus pressure in offshore/onshore production gas wells and injection-production wells of gas storage facilities poses a significant threat to wellbore integrity, characterized by its extensive coverage and high severity. For tubing leakage, logging tools are commonly utilized down-orifice in wells with annulus pressure to detect and identify these leakage. However, this process involves shutting down production and manipulating the tubing string, resulting in high costs and significant well control risks. Compared to down-orifice logging for leak detection, annulus pressure diagnosis at the wellhead offers advantages of lower risk and cost. Currently, there is limited analysis on the mechanisms of annulus pressure in gas wells, making it difficult to diagnose tubing leakage under annulus protection fluid at the wellhead. Addressing this critical issue, this paper presents simulation experiments on annulus pressure rise due to sub-liquid column leakage. Limited by experimental conditions, the maximum temperature used in this study was 120°C, which, while suitable for most injection-production wells in gas storage facilities, is relatively low compared to ultra-deep high-temperature and high-pressure wells. Additionally, due to limitations in the pressure rating of the air compressor, the pressure difference between the tubing and casing in this study was lower than that in actual down-orifice conditions. However, through these simulation experiments, we have gained insights into the migration patterns of leaked gas below the liquid level in the annulus under different operating conditions and developed a computational model for annulus pressure evolution after leakage. This model, based on gas fluid mechanics principles, can accommodate actual down-orifice high-temperature and high-pressure environments. In future research, we will conduct monitoring experiments on tubing leakage under real down-orifice high-temperature and high-pressure conditions to refine the model established in this paper and improve its accuracy. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Commonts 7：Leakage position in Table 4 - is it measured from the base of the apparatus? Authors should specify, otherwise it can be measured from the liquid level.
Response 7：Thank you for your comment. As you correctly pointed out, the leak locations listed in Table 1 (referenced as Table 4 in the original manuscript) are measured from the base of the equipment. To facilitate better understanding for readers, we should have indeed made a note of this. We apologize for our oversight and have included the clarification in the revised manuscript. Thank you once again for pointing out this issue. The following text in the main manuscript have been modified to reflect the above-mentioned changes. The factors that affect the pressure buildup in "A" annulus with sustained gas leakage in our experiments are shown in Table 4, along with the parameter ranges of each factor. Notably, leakage position refers to the distance of the leakage orifice from the base of the equipment.
Commonts 8：In Part 4 of the paper, different liquid levels are indicated in different experiments, but there is no justification for the choice of liquid level for the experiment? Justification or results of the experiment at different levels are required for each case under consideration.
Response 8：Thank you for your comment. Firstly, I would like to clarify that we have already addressed the impact of different liquid level heights on annulus pressure changes in the section of experimental results and analysis. When other conditions remain unchanged, a higher liquid level of the annulus protection fluid results in a smaller gas cap height, leading to a shorter annulus pressure recovery time. In the experiments investigating other influencing factors, we set the liquid level to 2 m for experiments with different tubing-casing pressure differentials, leak locations, and leak quantities. For experiments with different temperatures and leak diameters, the liquid level was set to 1.5 m. Although there were slight differences in the liquid level positions used when exploring different influencing factors, for each factor, we maintained a consistent liquid level to eliminate its impact on annulus pressure. Additionally, in all cases, the liquid level was positioned above the leakage orifice height to allow for a detailed analysis of the situation when a leak occurs below the liquid level. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Commonts 9：The authors need to check all formulas and indicate the designations of the quantities. For example, the designation PA is missing in formula 5, as well as in other formulas (for example, 8 and 9) for some quantities.
Response 9：Firstly, thank you for identifying the formula issue. We have made the necessary modifications to the parts you mentioned, and have also checked all formulas throughout the text to ensure their accuracy and quantities. Thank you again for your valuable question.
Commonts 10：At the end of Section 4.3, the cooling effect is mentioned, but will such an effect occur in a real well?
Response 10：Thank you very much for your comment. In actual wells, the newly injected annulus protection fluid has a relatively low temperature. As the wellbore depth increases and the formation temperature gradually rises, the temperature of the annulus protection fluid within the well will correspondingly increase. Although there is a steel tubing separating the annulus protection fluid from the natural gas, heat from the natural gas in the wellbore will inevitably transfer to the annulus protection fluid. However, the temperature of the annulus protection fluid will typically be lower than the temperature of the natural gas in the tubing at the same location. When natural gas leakage from the tubing into the annulus protection fluid, due to the relatively large volume and mass of the annulus protection fluid, as well as its high thermal capacity, it can effectively absorb and disperse this heat. This results in a relatively small difference in the annulus pressure rise curves caused by leakage of gas at different temperatures, which aligns with our experimental results. Therefore, it can be considered that the impact of leak gas temperature on the rise in annulus pressure at the wellhead is relatively low compared to other factors.
Commonts 11：In the description under equation 14, vg is measured in m/s, but it is said that it is volume. Is this a typo?
Response 11：Thank you very much for raising the issue. As you correctly pointed out, we have reviewed it and corrected the spelling error. The "vg" in the formula you mentioned refers to the "vertical upward velocity of a bubble". Additionally, we have reviewed all the formulas and symbols in the paper to avoid such oversights in the future. Thank you once again for discovering this typo.
Commonts 12：Section 5.3 proposes a prediction model, but how does it consider the changing gas pressure above the liquid, which acts together with the hydrostatic pressure on the side of the annulus at the leakage orifice?
Response 12：The migration process of the bubble is divided into two stages: the bubble below the liquid column and the bubble having reached the gas column at the wellbore. The annulus pressure at the wellbore is calculated for each stage, with the presence of bubbles reaching the wellbore determined by their displacement distance. The leakage flow rate is calculated based on the internal and external pressure ratio at the leakage point. Combining the mass conservation equation and the gas state equation, the impact of continuously generating and ascending bubbles in the annulus protection fluid on wellbore pressure, gas column volume, and the amount of gas substance contained is analyzed. Subsequently, the time required for bubble generation is calculated based on the aforementioned leakage flow rate, and this time is used as the calculation interval. This interval allows for the computation of annulus pressure at different time points. Then, it is determined whether there are bubbles in the liquid column that have reached the wellbore within this time period. The annulus pressure for each unit time is solved using the gas state equation for the annulus gas column at the wellbore, and the volumes of the gas column and liquid column at each time point are updated. The hydrostatic pressure at the leakage point in the annulus is recalculated and compared with the pressure inside the string at the leakage point: if it is less than this pressure, it indicates that leakage still exists, and the calculation proceeds to the next time step; if it is greater than or equal to this pressure, it indicates that the leakage has stopped, and the calculation ends at this point. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Commonts 13：After equation 42, the text states that the “leakage orifice height, equivalent diameter of the leakage orifice” are initial data, but earlier in the paper it was said that these data are very difficult to determine in a real well. How do authors plan to determine them in a real well?
Response 13：Thank you for your comment. In response to the current lack of understanding regarding the changes in annulus pressure after tubing leakage, especially those occurring below the liquid level, this paper conducted experiments on annulus pressure build-up due to tubing leakage. The focus was on analyzing the changes in annulus pressure caused by leakage below the annulus protection fluid level, and the study examined in detail the influence of various factors, including different pressure difference between the tubing and casing, liquid level heights, gas temperatures, leakage locations, leakage orifice diameters, and leakage quantities, on the rise in annulus pressure. The predictive model of the pressure buildup of the annulus developed in this paper aim to theoretically analyze the laws governing annulus pressure build-up in gas wells. As you mentioned in your next question, the existing models are proposed from a theoretical perspective, and further research is needed to obtain relevant leakage data from actual gas wells with annulus pressure to refine and improve the models. Since the issue of annulus pressure build-up in gas wells remains an unsolved problem worldwide, extensive research is still required. The research on the influence mechanisms of annulus pressure below the liquid level conducted in this paper is essential for diagnosing the tubing leakage form the ground. Through numerous laboratory experiments, we can gain a grasp of the annulus pressure rise rates and equilibrium pressures under different conditions, which can be helpful to field operators. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Commonts 14：Section 5.4 compares the model values ​​with experimental data, but a comparison with data from a real well is required. Can this model work only for a laboratory apparatus?
Response 14：Thank you for your comment. We agree that the model values should be compared with real well data, as you mentioned earlier. However, as previously stated, we currently do not have access to usable SCP gas well leakage data. Obtaining accurate information related to downhole leaks is challenging, and even if such information is obtained, its accuracy cannot be guaranteed. Despite this, we have made efforts to validate the model through laboratory experiments. Although laboratory equipment cannot fully replicate the complex environment of a real well, it can simulate the physical processes within the wellbore to a certain extent, providing strong support for model validation. By comparing laboratory data with model values, we can initially assess the reliability of the model and provide a foundation for subsequent practical applications. In future research, we hope to establish an indoor high-temperature and high-pressure simulated wellbore and conduct experiments on this basis to further refine our newly proposed model. Our goal is to continuously improve the accuracy of the model in actual wells and ultimately aim to completely solve the problem of diagnosing downhole tubing leaks from the surface. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Commonts 15：If the leakage in the well is not only below the liquid level, but also above the liquid level, will the developed model be able to work just as well?
Response 15：Thank you for your comment. As mentioned in the introduction of this paper, numerous scholars have proposed diagnostic methods for leaks above the liquid level (such as acoustic leak detection). However, it is still challenging to accurately identify leakage information below the liquid level. Therefore, the research objective of this paper is to conduct a detailed analysis of the changes in annulus pressure following leaks below the liquid level, providing a reference for the diagnosis and mitigation of this more complex leakage scenario. If the leak occurs above the liquid level, this model is no longer applicable because it is derived based on the migration process of bubbles generated by gas leaks in liquid. The model necessitates considering parameters such as bubble volume and quantity of matter to solve for annulus pressure at different time points. Without liquid, bubbles cannot be generated, so this model is only suitable for leaks below the liquid level. In our next research efforts, we will develop a pressurized annulus diagnostic system that integrates acoustic leak detection and the annulus pressure change detection proposed in this paper, enabling comprehensive diagnosis of leaks both above and below the liquid level. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Author Response File: Author Response.pdf
Reviewer 3 Report
Comments and Suggestions for AuthorsThe Manuscript under the Title ‘Comprehensive analysis of annulus pressure buildup in wells with sustained gas leakage below the liquid level” provides annular pressure build up analysis under the gas leakage condition below the liquid level. The approach employed in the manuscript is good, though it would have been better if the results obtained could be tested and validated with field-life scenario under different failure barrier conditions. My comments go thus.
1. The authors to give comprehensive state of art analysis of Global casing challenges and statistics.
2. Why the choice of leakage risks in the tubing instead of predominant leakage issues in the annular cement section due to cement cracks, channelling and improper cement bond between casings.
3. Detailed information of causes of leakage in the tubing would be appreciated in the introductory section.
4. Why the choice of FTA over FMEA in your analysis?
5. In Table 2, there should be a brief discussion on how the basic events probabilities were assigned using Ref [35] being mentioned.
Comments for author File: Comments.pdf
Author Response
The Manuscript under the Title ‘Comprehensive analysis of annulus pressure buildup in wells with sustained gas leakage below the liquid level” provides annular pressure build up analysis under the gas leakage condition below the liquid level. The approach employed in the manuscript is good, though it would have been better if the results obtained could be tested and validated with field-life scenario under different failure barrier conditions. My comments go thus.
Comments 1：The authors to give comprehensive state of art analysis of Global casing challenges and statistics.
Response 1：Thank you for your positive evaluation of our work. In the introduction, we provided statistics on SCP in annulus in gas wells globally. With the increasing demand for natural gas, the proliferation of gas wells has resulted in a prevalent occurrence of SCP, particularly in high-temperature and high-pressure (HTHP) gas wells. HTHP gas wells are defined as those with reservoir temperatures exceeding 150 °C, bottomorifice pressures surpassing 150 MPa, and wellhead pressures above 68.9 MPa, commonly found in regions such as the Junggar Basin, Tarim Basin, South China Sea, Gulf of Mexico, and Norwegian Continental Shelf. According to statistics from the Minerals Management Service (MMS), over 8000 gas wells in the Gulf of Mexico exhibit SCP, with more than 50% having SCP in the annulus between the tube and production casing. In the Tarim Basin of China, SCP in the annulus has been observed in over 90 wells across just two gas fields. In addition, the injection-production wells of gas storage are prone to micro-leakage in the tubing body and joints due to the alternating load under high-volume "strong extraction and injection”, resulting in SCP in ‘‘A’’ annulus during long-term service. According to oilfield statistics, the rate of pressure buildup in the annulus of Hutubi gas storage located in northwest China's Xinjiang Uygur Autonomous Region, while the Xiangguosi gas storage in the Sichuan Basin, China, has reported SCP in 30.7% of its wells, posing significant risks to well integrity and safety. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Comments 2：Why the choice of leakage risks in the tubing instead of predominant leakage issues in the annular cement section due to cement cracks, channelling and improper cement bond between casings
Response 2：Thank you for your comment. The primary reasons for selecting the study of tubing leakage risk in this paper are as follows. Firstly, based on field failure accident analysis, the risks associated with SCP in annulus “A” are greater compared to those of annulus “B” and “C”. Due to the pressure in annulus “A” near the wellbore, the tubing, casing, and wellhead equipment will endure additional upward forces. Once the annulus pressure becomes excessively severe, accidents are prone to occur. Within a certain oil company in China alone, there have been over five incidents of wellhead leakage or even tubing and casing extrusion due to SCP in annulus “A” in the past three years, resulting in severe consequences. Furthermore, there is currently limited analysis on the mechanisms of SCP in annulus “A” of gas wells both domestically and internationally, making it difficult to diagnose tubing leakage under annulus protection fluid. Conversely, there is extensive research on SCP in annulus “B” caused by cement bond failure between the cement sheath and casing, as you mentioned. Of course, the study of SCP in annulus “B” is also crucial for wellbore integrity. Based on the experiments conducted in this paper, we hope to further investigate these issues through the modification of devices and the construction of models in our subsequent research. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Comments 3：Detailed information of causes of leakage in the tubing would be appreciated in the introductory section.
Response 3：Thank you for your comment. Tubing leakage can be primarily categorized into body leakage and joint leakage. For body leakage, it is mainly due to localized corrosion of the tubing in the CO2 and H2S environment within the wellbore under complex loads, leading to perforation. Additionally, severe sand production in the wellbore can also result in erosion, especially on buckled tubing, causing perforation and subsequent tubing leakage. As for tubing joints, the main causes of leakage are localized corrosion or erosion wear, failure of thread compound in high-temperature environments, poor make-up quality in the field, or improper selection of thread types that cannot withstand periodic dynamic loads downhole (commonly occurring in injection and production wells of gas storage facilities). Actually, we have already briefly mentioned this in the first paragraph of the introduction. In the revised manuscript, we have provided a more detailed explanation to fulfill your requirements. We hope this response can satisfactorily address your comment. Thank you again for your valuable comment.
Comments 4：Why the choice of FTA over FMEA in your analysis?
Response 4：Thank you for your comment. When analyzing the causes of SCP in “A” annulus, the choice of Fault Tree Analysis (FTA) over Failure Modes and Effects Analysis (FMEA) is primarily based on the differences between their analytical methods and application domains. FTA is a top-down analytical approach that starts from an undesired top event (such as SCP in “A” annulus) and progressively analyzes all potential causes that may lead to this event. By constructing a fault tree, FTA connects the top event with the bottom events, clearly demonstrating the pathways and causes of the event's occurrence. This method is particularly suitable for analyzing failure modes in complex systems. Additionally, FTA can also perform quantitative analysis, calculating the probability of the top event occurring and the importance of bottom events, providing more precise data support for decision-making. In contrast, although FMEA is also an effective fault analysis method, it adopts a bottom-up approach by identifying each possible failure mode in a product, process, or system and analyzing the impact of these failures on the overall system performance. The focus of FMEA is on individual failure modes and their impacts, analyzing each component or process individually, assessing their risks, and proposing improvement measures. However, in the fault analysis of complex systems such as SCP in “A” annulus, FTA can more intuitively display the logical relationships and pathways of failure occurrences, making it easier to identify potential failure modes and causes.
Comments 5：In Table 2, there should be a brief discussion on how the basic events probabilities were assigned using Ref [35] being mentioned.
Response 5：Thank you for your comment. We utilized the parameters recommended in the Ref [35] for our calculations, but relying solely on these parameters may not yield highly accurate results. Furthermore, the causes of tubing failure have actually become a consensus among professionals, so there is no need to specifically conduct the FTA analysis to analyze the reasons behind the SCP in the “A” annulus. According to the suggestion of Reviewer 1, FTA analysis has been removed from the revised manuscript to streamline the article.
Author Response File: Author Response.pdf
