A quantitative assessment method for wellbore integrity risk of carbon dioxide injection wells

Abstract

The present invention relates to the technical field of wellbore risk assessment, and in particular to a method for quantitatively assessing the wellbore integrity risk of a carbon dioxide injection well, comprising: constructing a hierarchical model for injection well integrity assessment; determining the weight coefficient of each risk indicator; evaluating each risk indicator separately; calculating the total risk level score and determining the risk level. The present invention can comprehensively consider a variety of risk factors and achieve a detailed assessment of wellbore integrity through the determination of a hierarchical model and weight coefficients. The acquisition of real-time data and parameter correction ensure the accuracy and timeliness of the evaluation results. In addition, the method can identify high-risk areas in advance, achieve early warning and timely governance, and effectively solve the problem of low evaluation accuracy caused by the high subjectivity of the integrity analysis and evaluation method in the prior art, which makes it impossible to conduct a more objective quantitative evaluation of the wellbore integrity risk.

Description

Technical Field

[0001] The present invention relates to the technical field of wellbore risk assessment, and in particular to a method for quantitatively assessing the wellbore integrity risk of a carbon dioxide injection well. Background Art

[0002] With the profound environmental and social impacts of global climate change and the growing international focus on reducing greenhouse gas emissions, carbon dioxide capture, utilization, and storage (CCUS) has emerged as a key technology for achieving a low-carbon economy. The oil and gas industry, as a crucial component of the energy mix, faces the challenge of transformation and upgrading, needing to improve energy efficiency while reducing environmental impact. Technological advancements and innovations have provided new tools for the traditional energy industry, enabling green development and environmental protection while ensuring energy security. The guidance of policies and regulations, coupled with market and investor preference for environmentally friendly technologies, has driven the development and application of CCUS technology. Against this backdrop, the development of a quantitative assessment method for wellbore integrity risk in CO2 injection wells is not only crucial for improving the safety and economic benefits of CCUS projects, but also a crucial practice in responding to global emission reduction trends and achieving sustainable development goals.

[0003] Integrity failures were common during early development in CCUS pilot areas, including risks such as annular pressure buildup, wellhead lift, casing damage, and gas leaks. The integrity assessment process for domestic and international companies primarily relies on obtaining wellbore parameters through wellbore pressure testing or engineering logging, followed by manual qualitative analysis for integrity risk assessment. Overall, current integrity analysis and assessment methods still suffer from significant subjectivity, hindering a more objective and quantitative assessment of wellbore integrity risks, which in turn affects the standardization of integrity assessments. Summary of the Invention

[0004] To this end, the present invention provides a method for quantitatively evaluating the wellbore integrity risk of a carbon dioxide injection well, so as to overcome the problem of low evaluation accuracy caused by the high subjectivity of the integrity analysis and evaluation methods in the prior art, which makes it impossible to conduct a more objective quantitative evaluation of the wellbore integrity risk.

[0005] To achieve the above objectives, the present invention provides a method for quantitatively evaluating the wellbore integrity risk of a carbon dioxide injection well, comprising:

[0006] Based on the on-site production conditions in the CCUS pilot area, a hierarchical model for injection well integrity assessment was constructed, and several risk indicators were identified;

[0007] Determine the weight coefficient of each risk indicator through the hierarchical analysis method;

[0008] Evaluate each risk indicator separately;

[0009] Calculate the total risk rating based on the evaluation results of each risk indicator and the weight coefficient of each risk indicator, and determine the risk level based on the total risk rating and several preset standard rating ranges;

[0010] Among them, several risk indicators include downhole tool strength, pipe corrosion risk, residual strength of oil casing, thread corrosion risk, gas tree sealing, casing thread airtightness and cement sheath sealing. The standard rating range includes the first rating range, the second rating range, the third rating range and the fourth rating range. The risk levels include slight risk, medium risk, relatively serious risk and serious risk.

[0011] The evaluation of the airtightness of the casing thread includes obtaining in real time a first interference contact pressure caused by the casing thread make-up, a second interference contact pressure caused by the internal pressure, and the working internal pressure of the test area; correcting the first interference contact pressure according to the first interference contact pressure and a preset standard pressure range; and calculating a quantitative evaluation value of the casing thread airtightness according to the corrected first interference contact pressure, the second interference contact pressure, and the working internal pressure of the test area;

[0012] Among them, the evaluation of cement sheath sealing includes real-time acquisition of the formation temperature, injection pressure difference and actual high-quality cemented section length in the well, correction of the cement sheath bonding index according to the formation temperature and the preset standard temperature range, calculation of the minimum sealing length of the cement sheath according to the corrected cement sheath bonding index and injection pressure difference, and calculation of the quantitative evaluation value of the cement sheath sealing according to the minimum sealing length of the cement sheath and the actual high-quality cemented section length.

[0013] Furthermore, the hierarchical model of injection well integrity evaluation is constructed based on the on-site production conditions of the CCUS pilot area, including:

[0014] A three-level hierarchical model for injection well integrity evaluation was established based on the on-site production conditions in the CCUS pilot area. The target layer is the injection well integrity risk; the criterion layer is the strength, corrosion, and sealing that affect wellbore integrity; and the solution layer is the oil casing strength, downhole tool strength, pipe corrosion, thread corrosion, gas tree sealing, casing thread sealing, and cement sheath sealing.

[0015] Furthermore, the weight coefficients of each risk indicator are determined by the hierarchical analysis method, including:

[0016] The 1-9 scale comparison method is used to compare the risk indicators at the scheme level and the criterion level respectively to form a comparison matrix. The weight coefficient of each risk indicator is determined by calculating the maximum eigenvalue and corresponding eigenvector of the comparison matrix.

[0017] Furthermore, the evaluation of downhole tool strength includes:

[0018] The tubing string was modeled using Wellcat software, and a pressure profile was established according to production conditions. A force calibration was performed according to the operating conditions in the test area to obtain the maximum pressure differential, maximum force, rated pressure bearing capacity, and rated tensile pressure bearing capacity of the tool. The quantitative evaluation value of the downhole tool strength was calculated based on the obtained results.

[0019] Furthermore, the evaluation of the residual strength of the oil casing includes:

[0020] A mechanical model was established based on the tubing structure and geological parameters of the test area. Mechanical verification and analysis of alternating water and gas injection conditions were carried out according to the CCUS Phase I industrialization construction plan. The standard safety factor was obtained by verification using the original design tubing parameters. The current safety factor was obtained by verification using the parameters of the current tubing after corrosion and thinning. The quantitative evaluation value of the residual strength of the oil casing was calculated based on the standard safety factor and the current safety factor.

[0021] Furthermore, the evaluation of pipe corrosion risk and thread corrosion risk includes:

[0022] Obtain carbon dioxide partial pressure, temperature, corrosion product film and flow rate in real time during production operations, and calculate the quantitative evaluation value of pipe corrosion risk based on the obtained results;

[0023] The thread corrosion rate, corrosion depth and corrosion area during the production process are obtained in real time, and the thread corrosion risk quantitative evaluation value is calculated based on the obtained results.

[0024] Furthermore, the evaluation of the sealing performance of the gas tree includes:

[0025] Obtain the wellhead pressure of the gas injection condition and the rated pressure bearing capacity of the gas tree in the test area, and calculate the quantitative evaluation value of the gas tree sealing performance based on the obtained results.

[0026] Furthermore, correcting the first interference contact pressure according to the first interference contact pressure and a preset standard pressure range includes:

[0027] Adjusting the first interference contact pressure according to the first interference contact pressure that is less than the minimum value of the preset standard pressure range and the standard pressure range;

[0028] The first interference contact pressure is adjusted according to the first interference contact pressure being greater than the maximum value of the preset standard pressure range and the standard pressure range being reduced.

[0029] Furthermore, the cement sheath bonding index is corrected according to the formation temperature and the preset standard temperature range, including:

[0030] Adjusting the cement sheath bonding index according to the formation temperature being less than the minimum value of the preset standard temperature range and the standard temperature range being increased;

[0031] The cement sheath bonding index is adjusted according to the formation temperature being greater than the maximum value of the preset standard temperature range and the standard temperature range being reduced.

[0032] Furthermore, the overall risk level score is calculated based on the evaluation results of each risk indicator and the weight coefficient of each risk indicator, including:

[0033] The quantitative evaluation value of casing thread sealing, the quantitative evaluation value of cement ring sealing, the quantitative evaluation value of downhole tool strength, the quantitative evaluation value of oil casing residual strength, the quantitative evaluation value of pipe corrosion risk, the quantitative evaluation value of thread corrosion risk and the quantitative evaluation value of gas tree sealing are multiplied by the corresponding weight coefficients and summed to obtain the total risk level score.

[0034] Compared with existing technologies, the present invention offers the advantage of comprehensively considering multiple risk factors through a hierarchical model and the determination of weight coefficients, enabling a detailed assessment of wellbore integrity. Real-time data acquisition and parameter correction ensure the accuracy and timeliness of evaluation results. Furthermore, this method can identify high-risk areas in advance, enabling early warning and timely remediation, thereby reducing the likelihood of risk occurrence and management costs, improving the economic benefits and safety of CCUS projects, and effectively addressing the problem of low evaluation accuracy caused by the high subjectivity of existing integrity analysis and evaluation methods, which prevents a more objective quantitative assessment of wellbore integrity risks.

[0035] Furthermore, by quantifying the integrity risk of injection wells, factors that may impact wellbore safety can be more accurately identified and assessed. The determination of weighting coefficients enhances objectivity and transparency in the decision-making process. This not only helps optimize resource allocation and mitigate potential risks, but also improves the overall safety and efficiency of CCUS projects.

[0036] Furthermore, these corrections ensure that the interference contact pressure of the casing threads and the cement sheath bond index remain within an optimized range, thereby improving wellbore sealing and integrity. This enhances adaptability to downhole operating conditions and ensures adequate sealing performance under diverse conditions. Furthermore, this helps prevent downhole equipment damage or failure caused by excessive or insufficient pressure, reducing operational risks and enhancing the safety of CCUS projects. Real-time monitoring and timely adjustments enable more precise control of wellbore integrity, ensuring long-term, stable CCUS operations.

[0037] Furthermore, through risk identification and prioritization, we can identify the contribution of various risk factors to the overall risk level, help determine the priority of risk management, and through quantitative assessment, improve the efficiency and effectiveness of risk management, reduce reliance on qualitative judgments, help take preventive measures, reduce the possibility of accidents, thereby ensuring operational safety and extending the service life of the wellbore. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] Figure 1 This is a flow chart of the method for quantitatively evaluating the wellbore integrity risk of a carbon dioxide injection well in this embodiment;

[0039] Figure 2 Schematic diagram of the injection well integrity assessment hierarchical model of this embodiment;

[0040] Figure 3 The determination logic diagram for correcting the first interference contact pressure in this embodiment;

[0041] Figure 4 This is the decision logic diagram for correcting the cement sheath bonding index in this embodiment. DETAILED DESCRIPTION

[0042] In order to make the objects and advantages of the present invention more clearly understood, the present invention is further described below in conjunction with embodiments; it should be understood that the specific embodiments described herein are merely used to explain the present invention and are not intended to limit the present invention.

[0043] The preferred embodiments of the present invention are described below with reference to the accompanying drawings. It should be understood by those skilled in the art that these embodiments are only used to explain the technical principles of the present invention and are not intended to limit the scope of protection of the present invention.

[0044] It should be noted that, in the description of the present invention, terms such as "up", "down", "left", "right", "inside", and "outside" indicating directions or positional relationships are based on the directions or positional relationships shown in the accompanying drawings. This is only for the convenience of description and does not indicate or imply that the device or element must have a specific orientation, be constructed and operated in a specific orientation. Therefore, it cannot be understood as a limitation on the present invention.

[0045] Furthermore, it should be noted that, in the description of the present invention, unless otherwise expressly specified or limited, the terms "mounted," "connected," and "connected" should be understood in a broad sense. For example, they may refer to fixed connections, detachable connections, or integral connections; mechanical connections or electrical connections; direct connections or indirect connections through an intermediate medium; and internal communication between two components. Those skilled in the art will understand the specific meanings of the above terms in the present invention based on specific circumstances.

[0046] See also Figure 1 As shown, it is a flow chart of the method for quantitatively evaluating the wellbore integrity risk of a carbon dioxide injection well in this embodiment;

[0047] This embodiment provides a method for quantitatively evaluating the wellbore integrity risk of a carbon dioxide injection well, comprising:

[0048] Based on the on-site production conditions in the CCUS pilot area, a hierarchical model for injection well integrity assessment was constructed, and several risk indicators were identified;

[0049] Determine the weight coefficient of each risk indicator through the hierarchical analysis method;

[0050] Evaluate each risk indicator separately;

[0051] Calculate the total risk rating based on the evaluation results of each risk indicator and the weight coefficient of each risk indicator, and determine the risk level based on the total risk rating and several preset standard rating ranges;

[0052] Among them, several risk indicators include downhole tool strength, pipe corrosion risk, residual strength of oil casing, thread corrosion risk, gas tree sealing, casing thread airtightness and cement sheath sealing. The standard rating range includes the first rating range, the second rating range, the third rating range and the fourth rating range. The risk levels include slight risk, medium risk, relatively serious risk and serious risk.

[0053] The evaluation of the airtightness of the casing thread includes obtaining in real time a first interference contact pressure caused by the casing thread make-up, a second interference contact pressure caused by the internal pressure, and the working internal pressure of the test area; correcting the first interference contact pressure according to the first interference contact pressure and a preset standard pressure range; and calculating a quantitative evaluation value of the casing thread airtightness according to the corrected first interference contact pressure, the second interference contact pressure, and the working internal pressure of the test area;

[0054] Among them, the evaluation of cement sheath sealing includes real-time acquisition of the formation temperature, injection pressure difference and actual high-quality cemented section length in the well, correction of the cement sheath bonding index according to the formation temperature and the preset standard temperature range, calculation of the minimum sealing length of the cement sheath according to the corrected cement sheath bonding index and injection pressure difference, and calculation of the quantitative evaluation value of the cement sheath sealing according to the minimum sealing length of the cement sheath and the actual high-quality cemented section length.

[0055] Through a hierarchical model and the determination of weight coefficients, a comprehensive consideration of multiple risk factors can be achieved, enabling a detailed assessment of wellbore integrity. Real-time data acquisition and parameter correction ensure the accuracy and timeliness of the evaluation results. Furthermore, this method can identify high-risk areas in advance, enabling early warning and timely remediation, thereby reducing the likelihood of risk occurrence and management costs, improving the economic benefits and safety of CCUS projects. This effectively addresses the problem of low evaluation accuracy in existing integrity analysis and evaluation methods, which is often due to the high subjectivity of these methods and the resulting inability to provide a more objective and quantitative assessment of wellbore integrity risks.

[0056] Please continue reading Figure 2 As shown, it is a schematic diagram of the injection well integrity evaluation hierarchical model of this embodiment;

[0057] Specifically, the hierarchical model for injection well integrity evaluation based on the on-site production conditions in the CCUS pilot area includes:

[0058] A three-level hierarchical model for injection well integrity assessment was established based on field production conditions in the Daqing CCUS pilot area. The target layer represents injection well integrity risk; the criterion layer includes three factors affecting wellbore integrity: strength, corrosion, and sealing; and the solution layer includes seven risk indicators: tubing and casing strength, downhole tool strength, tubing corrosion, thread corrosion, Christmas tree sealing, casing thread sealing, and cement sheath sealing.

[0059] Specifically, the weight coefficients of each risk indicator determined by the hierarchical analysis method include:

[0060] By comparing the seven risk indicators of CO2 injection wellbore safety risk, the 1-9 scale comparison method was used to compare the bottom layer and middle layer factors in pairs, forming a comparison matrix, as shown in Tables 1-5;

[0061] Table 1 Comparison of wellbore integrity risk factor scales

[0062] scale meaning i is the same as j i / j=1 i is slightly stronger than j i / j=3 i is stronger than j i / j=5 i is much stronger than j i / j=7 i is much stronger than j i / j=9 i is between the above levels than j i / j=2, 4, 6, 8, 10 i is slightly weaker than j, weak, very weak, extremely weak i / j=1 / 3, 1 / 5, 1 / 7, 1 / 9

[0063] Table 2 Strength judgment matrix

[0064] Criterion layer (strength) Oil casing strength Downhole tool strength Oil casing strength 1 3 Downhole tool strength 1 / 3 1

[0065] Table 3 Corrosion judgment matrix

[0066] Standard layer (erosion) Pipe corrosion Thread corrosion Pipe corrosion 1 1 / 7 Thread corrosion 7 1

[0067] Table 4 Sealing judgment matrix

[0068]

[0069] Table 5 Wellbore integrity risk judgment matrix

[0070]

[0071] By calculation, the maximum eigenvalue of the strength judgment matrix is ​​λ=2, and the eigenvector corresponding to the maximum eigenvalue is W MAX =(0.9487, 0.3162) T ;

[0072] The maximum eigenvalue of the corrosion judgment matrix is ​​λ=2, and the eigenvector corresponding to the maximum eigenvalue is W MAX =(0.1414, 0.9899) T ;

[0073] The maximum eigenvalue of the sealing judgment matrix is ​​λ = 3.0858, and the eigenvector corresponding to the maximum eigenvalue is W MAX =(0.1352, 0.9048, 0.4038) T ;

[0074] The maximum eigenvalue of the wellbore integrity risk judgment matrix is ​​λ = 3.0037, and the eigenvector corresponding to the maximum eigenvalue is W MAX =(0.1640, 0.4629, 0.8711) T .

[0075] The weights corresponding to each factor are as follows:

[0076] Table 6 Risk indicator weights

[0077] Risk Indicators Weight Oil casing strength 0.0822 Downhole tool strength 0.0274 Pipe corrosion 0.0386 Thread corrosion 0.2705 Gas tree sealing 0.0560 Casing thread sealing 0.1652 Cement sheath sealing 0.3600

[0078] By quantifying the integrity risk of injection wells, factors that may impact wellbore safety can be more accurately identified and assessed. The determination of weighting coefficients enhances objectivity and transparency in the decision-making process. This not only helps optimize resource allocation and mitigate potential risks, but also improves the overall safety and efficiency of CCUS projects.

[0079] Specifically, the evaluation of downhole tool strength includes:

[0080] Common downhole tools used in gas wells include production packers and downhole safety valves.

[0081] Production packer strength: reasons related to the packer itself, influence of wellbore and formation stress, and influence of operation and construction.

[0082] Strength of downhole safety valve: reasons of downhole safety valve itself, influence of pressure in pipeline, and influence of operation.

[0083] For the strength of downhole tools, Wellcat software was used to model the string, establish a pressure profile according to the production conditions, and perform calibration according to the test area conditions. The results of the mechanical calibration showed that the maximum pressure difference the tool was subjected to was B C1 , Maximum force B C2 , the rated pressure bearing capacity of the tool is B1, the rated tensile pressure bearing capacity is B2, and the quantitative evaluation value R2 of the downhole tool strength is calculated as follows:

[0084]

[0085] Specifically, the evaluation of the residual strength of oil casing includes:

[0086] During post-cement oil and gas well production, the primary factors influencing the residual strength of casing are external squeeze forces, followed by axial tension and internal pressure. When the external squeeze forces acting on the casing exceed its collapse strength at that point, the casing will collapse and fail. Furthermore, factors such as the cement sheath's elastic modulus, Poisson's ratio, thickness, in-situ stress nonuniformity, and perforation can all enhance or weaken the casing's collapse strength.

[0087] Based on the test area string structure and geological parameters, a mechanical model was established. According to the CCUS Phase I industrial construction plan, a mechanical verification analysis of the water-gas alternating injection working condition was carried out. The safety factor A0 was obtained by verification based on the original design string parameters as the full score standard. The current safety factor A was obtained by verification based on the current string parameters after corrosion and thinning. C , the quantitative evaluation value R1 of the residual strength of oil casing is calculated as follows:

[0088]

[0089] Specifically, the evaluation of pipe corrosion risk and thread corrosion risk includes:

[0090] Obtain carbon dioxide partial pressure, temperature, corrosion product film, and flow rate during the production process in real time. Multiply the obtained results by the corresponding weights and sum them to calculate the quantitative evaluation value of pipe corrosion risk. The corresponding weights are determined based on the specific requirements of the production process.

[0091] During oil and gas production, Christmas trees often suffer from severe corrosion, significantly impacting on-site operations. Analysis of mixed water samples from the block, corrosive media content, material physical and chemical properties, and corrosion product analysis reveals that pipe corrosion is related to the following factors: carbon dioxide partial pressure, temperature, corrosion product film, and flow rate.

[0092] For the carbon dioxide corrosion resistance of the selected pipes, the carbon dioxide downhole corrosion rate was measured on site. Then, according to the four-level classification method of corrosion severity in the NACE SP 0775 standard, its quantitative evaluation R3 was divided into four levels, as shown in Table 7:

[0093] Table 7 Evaluation standards for corrosion resistance of pipes

[0094]

[0095] In the case where the casing string connection part is not properly buckled or the string is subjected to excessive tensile and bending loads, extremely small gaps will be formed at locations such as the torque shoulder surface, and concentration cells will form inside and outside the gap, causing local corrosion.

[0096] The corrosion rate, corrosion depth, and corrosion area of ​​the threads during the production process are obtained in real time. The obtained results are multiplied by the corresponding weights and summed to calculate the quantitative evaluation value of the thread corrosion risk. The corresponding weights are determined based on the specific requirements of the production process. For the thread crevice corrosion risk, the electrochemical corrosion simulation test results are used. According to the four-level classification method of corrosion severity in the NACE SP 0775 standard, its quantitative evaluation R4 is divided into four levels, as shown in Table 8:

[0097] Table 8 Evaluation standards for thread corrosion resistance

[0098]

[0099] Specifically, the evaluation of the sealing performance of the gas tree includes:

[0100] When characterizing the integrity of oil and gas wells, the Christmas tree seal is divided into two aspects: internal leakage and external leakage.

[0101] External pipe leakage: This can be classified into three main types: seepage, puncture, and open welds. The leak points and manifestations of different types of leakage are as follows: Seepage: Annular space, production decline, unstable pressure, and inability to pump down the liquid level; top screw seals, white crystalline solids, water seepage, and oil stains. Puncture: Large flange steel rings, oil stains, and mist-like water leakage; Clamp steel rings, oil stains, and water seepage. Open welds: Surface casing and production casings, shaking, upward movement, and rising during hot washing.

[0102] Internal leakage in pipes: Research has revealed that valve discs and valve seats are common locations for internal leakage. The main causes of internal leakage in valve discs and valve seats are twofold: first, manufacturing factors, primarily reflecting whether parameters such as size (mm), surface roughness (dimensionless), flatness (mm), and parallelism (mm) match standard parameters; second, load-bearing capacity, primarily reflecting whether the maximum load-bearing pressure (MPa) exceeds the material's tensile strength (MPa) and yield strength (MPa).

[0103] For the sealing of the Christmas tree, the wellhead pressure of the gas injection condition in the test area is E C , the rated pressure bearing capacity of the gas tree is E0, and the quantitative evaluation value R5 of the gas tree sealing performance is calculated as follows:

[0104]

[0105] Specifically, the evaluation of the airtightness of the casing thread includes obtaining in real time a first interference contact pressure caused by the casing thread make-up, a second interference contact pressure caused by the internal pressure, and the working internal pressure of the test area; correcting the first interference contact pressure according to the first interference contact pressure and a preset standard pressure range; and calculating a quantitative evaluation value of the casing thread airtightness according to the corrected first interference contact pressure, the second interference contact pressure, and the working internal pressure of the test area;

[0106] Compared with water flooding, the injection pressure of carbon dioxide flooding is higher, which increases the risk of casing damage. Therefore, the process of converting water flooding to carbon dioxide flooding faces an extremely high risk of wellbore integrity failure. Old water flooding wells have been in service for many years and all use round thread buckles. The strength and sealing performance of casing after conversion to carbon dioxide injection wells are unclear. Therefore, round thread buckles are one of the important factors affecting the casing airtightness. At the same time, factors such as casing damage, surface defects and the resistance to crevice corrosion of the joints must also be considered.

[0107] For the casing thread sealing, the interference contact pressure caused by the make-up is determined to be G1, and the interference contact pressure caused by the internal pressure is determined to be G2. The sum of the two is used as the thread sealing pressure bearing capacity index. The working internal pressure of the test area is G C , then the casing thread sealing quantitative evaluation value R6 is calculated as follows:

[0108]

[0109] Please continue reading Figure 3 As shown, it is a decision logic diagram for correcting the first interference contact pressure in this embodiment;

[0110] Wherein, correcting the first interference contact pressure according to the first interference contact pressure and a preset standard pressure range includes:

[0111] Adjusting the first interference contact pressure according to the first interference contact pressure that is less than the minimum value of the preset standard pressure range and the standard pressure range;

[0112] The first interference contact pressure is adjusted according to the first interference contact pressure being greater than the maximum value of the preset standard pressure range and the standard pressure range being reduced.

[0113] Specifically, the evaluation of cement sheath sealing performance includes obtaining the formation temperature, injection pressure difference, and actual high-quality bonded section length in real time in the well, correcting the cement sheath bonding index according to the formation temperature and the preset standard temperature range, and calculating the minimum cement sheath sealing length based on the corrected cement sheath bonding index and injection pressure difference. The quantitative evaluation value of the cement sheath sealing performance is calculated based on the minimum cement sheath sealing length and the actual high-quality bonded section length.

[0114] There are three main factors that affect the sealing performance of cement sheath, namely the degree of cement bonding, the length of the bonding section and the corrosion of cement sheath.

[0115] Based on the independently developed full-scale high-temperature and high-pressure cement sheath sealing integrity evaluation device, the simulation function of the full-scale, full-temperature range, and full-pressure system is realized, and in conjunction with the independently developed 8-sector cementing quality detector, an evaluation test of the cement sheath sealing capacity with different cementing indices is carried out. The experimental results show that the cement sheath sealing capacity is linearly related to the cement sheath height. When the cementing quality is excellent, the cement sheath sealing capacity of 0.2m, 0.6m, and 1m heights is 1.8MPa, 2.4MPa, and 3.7MPa, respectively. With the increase of the cement sheath bonding index, the cement sheath sealing capacity shows a linear increasing trend. The breakthrough pressures of cement sheaths with bonding indices of 0.21, 0.42, 0.61, and 0.82 are 0.7MPa, 1.6MPa, 2.3MPa, and 2.9MPa, respectively.

[0116] The calculation formula for the minimum sealing length of cement sheath is as follows:

[0117] h= <h2 style=";text-align:left;direction:ltr">f-0.02-1.3B<h2 style=";text-align:left;direction:ltr"> I

[0118] 0.027+2.5B I ;

[0119] Where, f is the injection pressure difference, MPa; B I is the cement sheath bonding index; h is the minimum sealing length (m).

[0120] Based on the on-site formation data and injection condition data of the test area, it was calculated that the minimum isolation length for safe operation of the wells in the test area under the condition of 4F18 cementing quality and 19MPa injection pressure is 7.5m; the minimum isolation length for safe operation of the wells in the test area under the condition of high-quality cementing quality and 20MPa injection pressure is 8.2m.

[0121] The corrosion risk is mainly due to the micro-gaps generated in the cement sheath under the action of alternating temperature and pressure loads. Carbon dioxide extends along the micro-gaps, creating a carbon dioxide corrosion environment, causing the cement sheath to fail in sealing, further exacerbating the risk of cement sheath sealing failure.

[0122] To explore the corrosion expansion patterns of cement sheaths in perforated holes due to carbon dioxide, a small-scale cement sheath sealing evaluation device was developed to simulate the carbon dioxide phase under on-site formation temperature and pressure conditions, and cement sheath corrosion expansion tests with different corrosion times were conducted. Cement sheath specimens were subjected to corrosion tests using supercritical carbon dioxide for corrosion times of 2, 5, 7, 14, 21, and 28 days. The experimental results showed that after three months of corrosion, there was no significant corrosion expansion, and the corrosion expansion range reached its maximum in June, after which it almost stopped expanding. The expansion depth reached a maximum of 16.84 mm at six months.

[0123] The actual high-quality bonding section length is set as H C (m), and finally the quantitative evaluation value R7 of cement sheath sealing is calculated as follows:

[0124]

[0125] Among them, the correction of cement sheath bonding index according to the formation temperature and the preset standard temperature range includes:

[0126] Please continue reading Figure 4 As shown, it is a decision logic diagram for correcting the cement sheath bonding index in this embodiment;

[0127] Adjusting the cement sheath bonding index according to the formation temperature being less than the minimum value of the preset standard temperature range and the standard temperature range being increased;

[0128] The cement sheath bonding index is adjusted according to the formation temperature being greater than the maximum value of the preset standard temperature range and the standard temperature range being reduced.

[0129] Real-time monitoring and quantitative analysis of key parameters can more accurately identify and assess potential risk points to wellbore integrity. This not only facilitates preventative measures to improve wellbore safety and reliability, but also provides clearer guidance for maintenance decisions and optimizes the scheduling of maintenance and repair work through quantitative assessment values.

[0130] During the evaluation process, the first interference contact pressure is corrected by comparing it with a preset standard pressure range. If the measured first interference contact pressure is lower than the minimum value of the standard range, the pressure is adjusted upward to ensure it reaches at least the lower limit of the standard pressure range. Conversely, if the first interference contact pressure is greater than the maximum value of the standard range, it is adjusted downward to ensure it does not exceed the upper limit. A similar strategy is adopted for correcting the cement sheath bond index: the bond index is adjusted upward or downward based on the comparison of the actual formation temperature with the preset standard temperature range. This correction ensures that the evaluation parameters remain within a safe and effective operating range, thereby improving the accuracy and reliability of the evaluation.

[0131] This correction ensures that the casing thread interference contact pressure and the cement sheath bond index are within an optimized range, thereby improving wellbore sealing and integrity. This enhances adaptability to downhole operating conditions and ensures adequate sealing performance under diverse conditions. Furthermore, it helps prevent downhole equipment damage or failure caused by excessive or insufficient pressure, reducing operational risks and enhancing the safety of CCUS projects. Real-time monitoring and timely adjustments enable more precise control of wellbore integrity, ensuring long-term and stable CCUS operations.

[0132] Specifically, the total risk level score is calculated based on the evaluation results of each risk indicator and the weight coefficient of each risk indicator, including:

[0133] The casing thread sealing quantitative evaluation value, cement sheath sealing quantitative evaluation value, downhole tool strength quantitative evaluation value, casing residual strength quantitative evaluation value, pipe corrosion risk quantitative evaluation value, thread corrosion risk quantitative evaluation value and gas tree sealing quantitative evaluation value are multiplied by the corresponding weight coefficients and summed to obtain the total risk level score ZF;

[0134] Where, ZF = 0.0822 × R1 + 0.0274 × R2 + 0.0386 × R3 + 0.2705 × R4 + 0.0560 × R5 + 0.1652 × R6 + 0.3600 × R7;

[0135] During the risk quantification process, each independent wellbore integrity factor (including casing thread tightness, cement sheath tightness, downhole tool strength, residual strength of oil casing and tubing, pipe corrosion risk, thread corrosion risk, and Christmas tree tightness) is first quantitatively evaluated in detail to obtain a quantitative evaluation value. Subsequently, the quantitative evaluation value of each factor is multiplied by its corresponding weight coefficient, determined using the analytic hierarchy process. Finally, these products are summed to obtain a comprehensive overall risk rating score, which comprehensively reflects the risk level of wellbore integrity.

[0136] Through risk identification and prioritization, we can identify the contribution of various risk factors to the overall risk level, help determine the priority of risk management, and through quantitative assessment, improve the efficiency and effectiveness of risk management, reduce reliance on qualitative judgments, help take preventive measures, reduce the possibility of accidents, thereby ensuring operational safety and extending the service life of the wellbore.

[0137] Wellbore safety risk level classification:

[0138] Based on the on-site production conditions in the Daqing CCUS pilot area, the risks posed by wellbore integrity factors are divided into four levels: slight, moderate, severe, and severe, as shown in Table 9:

[0139] Table 9 Wellbore integrity quantitative scores and risk levels

[0140] Risk Level Completeness Quantitative Score slight 0.8-1.0 (excluding 0.8) medium 0.6-0.8 (excluding 0.6) More serious 0.4-0.6 (excluding 0.4) serious 0-0.4

[0141] For example, a. Residual strength of oil casing

[0142] Using WELLCAT mechanical analysis software, a string model was established based on the well logging results, with a wall thickness of 6m at the weak point at 145 meters. A mechanical verification analysis of the injection well casing strength was conducted, and the minimum safety factor for the entire well was 1.629, with the risk point located at the wellhead. The evaluation value, R1 = 1.6 / 1.629 = 0.982, was calculated using the quantitative evaluation formula for the residual strength of the oil casing.

[0143] b. Downhole tool strength

[0144] This well is a general injection well and there is no packer or safety valve in the well. The quantitative evaluation of downhole tool strength takes the highest evaluation value R2=1;

[0145] c. Pipe corrosion risk

[0146] The well uses J-55 ordinary carbon steel pipes. The gas inside the pipe string is high-concentration carbon dioxide. The corrosion simulation evaluation experiment was carried out using the coupon weight loss method. The corrosion rate was calculated to be 0.04mm / a. Substituting it into the calculation formula, the quantitative score of carbon dioxide corrosion resistance of the pipe was obtained as R3=1, as shown in Table S1;

[0147] Table S1 Casing corrosion simulation evaluation test results

[0148]

[0149] d. The casing threads of this well are made of J-55 ordinary carbon steel. The gas inside the pipe string is all high-concentration carbon dioxide. The corrosion process was simulated using ECE software, and the corrosion rate was measured to be 0.0283mm / a. Substituting this into the calculation formula, the quantitative score of carbon dioxide corrosion resistance of the pipe was obtained as R4=1;

[0150] e. The model of the gas tree of this well is ZQ65 / 35-FF. According to the production conditions of the YSL test area with a wellhead pressure of 22 MPa, the quantitative evaluation value of the gas tree sealing performance is calculated to be R5 = 0.37;

[0151] f. The casing of this well adopts API long round thread. Calculation parameters: Long round thread size table E S=137.246mm, round thread casing coupling size W = 160.02mm, d = outer diameter - 2 × wall thickness = 139.7-2 × 9.17 = 121.36mm, refer to API 5B standard hand-tightening pitch number N = 3, p = 3.175mm (long round thread has 8 threads per inch, pitch is 25.4mm / 8 = 3.175mm), T d =0.0625 (the taper of the circular thread is 1 / 16), Young's modulus E=210;

[0152] Interference contact pressure caused by make-up:

[0153]

[0154] (Unit: MPa), is within the preset standard pressure range (15.273MPa-18.667MPa) and does not require correction;

[0155] Interference contact pressure caused by internal pressure:

[0156] (unit: MPa);

[0157] The sum of the two is used as the thread seal pressure bearing capacity index. The working internal pressure of the test area is GC = 22MPa, and the casing thread sealing quantitative evaluation value R6 = 0.205;

[0158] g. Cement sheath cementing quality evaluation

[0159] Based on logging data from Well 11Y68-58 in the Yushulin Oilfield, cement sheath bonding testing results show that the longest high-quality continuous cement sheath section above the perforation section is 168 meters long, located at a well depth of 1490-1628 meters. Under high-quality cementing conditions, the minimum isolation length for safe operation at an injection pressure of 20 MPa in the YSL test area is 8.2 meters. The dynamic evaluation value of the cement sheath sealing performance, R7, was calculated based on the quantitative evaluation formula for cement sheath sealing performance, and since (0≤R7≤1), the maximum value of R7 is 1.

[0160] h. Based on the quantitative scores of the seven risk factors, substituting them into the wellbore risk numerical evaluation formula, the risk value B is calculated as 0.0807 + 0.0274 + 0.0386 + 0.2705 + 0.0207 + 0.0034 + 0.36 = 0.8013. According to the risk level, it is classified as a low-risk well.

[0161] Thus far, the technical solutions of the present invention have been described in conjunction with the preferred embodiments shown in the accompanying drawings. However, it will be readily understood by those skilled in the art that the scope of protection of the present invention is obviously not limited to these specific embodiments. Without departing from the principles of the present invention, those skilled in the art may make equivalent changes or substitutions to the relevant technical features, and the technical solutions after such changes or substitutions will fall within the scope of protection of the present invention.

[0162] The foregoing description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Those skilled in the art will readily appreciate that the present invention is susceptible to various modifications and variations. Any modifications, equivalent substitutions, or improvements made within the spirit and principles of the present invention are intended to be within the scope of protection of the present invention.

Claims

1. A method for quantitatively evaluating the wellbore integrity risk of a carbon dioxide injection well, characterized in that: include: Based on the on-site production conditions in the CCUS pilot area, a hierarchical model for injection well integrity assessment was constructed, and several risk indicators were identified; Determine the weight coefficient of each risk indicator through the hierarchical analysis method; Evaluate each risk indicator separately; Calculate the total risk level score based on the evaluation results of each risk indicator and the weight coefficient of each risk indicator, and determine the corresponding risk levels based on the total risk level score and the preset standard level score ranges; Among them, several risk indicators include downhole tool strength, pipe corrosion risk, residual strength of oil casing, thread corrosion risk, gas tree sealing, casing thread airtightness and cement sheath sealing. The standard rating range includes the first rating range, the second rating range, the third rating range and the fourth rating range. The risk levels include slight risk, medium risk, relatively serious risk and serious risk. The evaluation of the airtightness of the casing thread includes obtaining in real time a first interference contact pressure caused by the casing thread make-up, a second interference contact pressure caused by the internal pressure, and the working internal pressure of the test area; correcting the first interference contact pressure according to the first interference contact pressure and a preset standard pressure range; and calculating a quantitative evaluation value of the casing thread airtightness according to the corrected first interference contact pressure, the second interference contact pressure, and the working internal pressure of the test area; The evaluation of cement sheath sealing performance includes real-time acquisition of the formation temperature, injection pressure difference, and actual length of high-quality bonded sections in the well; correction of the cement sheath bonding index based on the formation temperature and the preset standard temperature range; calculation of the minimum cement sheath sealing length based on the corrected cement sheath bonding index and injection pressure difference; and calculation of the quantitative evaluation value of cement sheath sealing performance based on the minimum cement sheath sealing length and the actual length of the high-quality bonded sections. The hierarchical model for injection well integrity evaluation based on the field production of the CCUS pilot area includes: Based on the on-site production conditions in the CCUS pilot area, a three-level hierarchical model for injection well integrity assessment was established. The target layer is injection well integrity risk; the criterion layer is strength, corrosion, and sealing factors affecting wellbore integrity; and the solution layer is tubing and casing strength, downhole tool strength, tubing corrosion, thread corrosion, Christmas tree sealing, casing thread sealing, and cement sheath sealing. The weight coefficients of each risk indicator determined by the hierarchical analysis method include: The 1-9 scale comparison method is used to compare the risk indicators at the scheme level and the criterion level in pairs to form a comparison matrix. The weight coefficient of each risk indicator is determined by calculating the maximum eigenvalue and corresponding eigenvector of the comparison matrix. Evaluation of downhole tool strength includes: Use Wellcat software to build a model for the tubing string, establish a pressure profile based on production conditions, and perform a force check based on the test area conditions to obtain the maximum pressure differential, maximum force, rated pressure bearing capacity, and rated tensile pressure bearing capacity of the tool. Quantitative evaluation values ​​for downhole tool strength are calculated based on the obtained results. The evaluation of the residual strength of oil casing includes: A mechanical model was established based on the test area's tubing structure and geological parameters. A mechanical analysis of alternating water and gas injection conditions was conducted according to the CCUS Phase I industrialization construction plan. The standard safety factor was derived using the original design tubing parameters. The current safety factor was derived using the current tubing parameters after corrosion and thinning. A quantitative evaluation of the remaining strength of the tubing and casing was calculated based on the standard and current safety factors. The evaluation of pipe corrosion risk and thread corrosion risk includes: Obtain carbon dioxide partial pressure, temperature, corrosion product film and flow rate in real time during production operations, and calculate the quantitative evaluation value of pipe corrosion risk based on the obtained results; Obtain the thread corrosion rate, corrosion depth, and corrosion area in real time during production operations, and calculate the thread corrosion risk quantitative evaluation value based on the obtained results; The evaluation of the sealing performance of the gas tree includes: Obtain the wellhead pressure of the gas injection condition and the rated pressure bearing capacity of the gas tree in the test area, and calculate the quantitative evaluation value of the gas tree sealing performance based on the obtained results.

2. The method for quantitatively evaluating the wellbore integrity risk of carbon dioxide injection wells according to claim 1, characterized in that: Correcting the first interference contact pressure according to the first interference contact pressure and a preset standard pressure range includes: Adjusting the first interference contact pressure according to the first interference contact pressure that is less than the minimum value of the preset standard pressure range and the standard pressure range; The first interference contact pressure is adjusted according to the first interference contact pressure being greater than the maximum value of the preset standard pressure range and the standard pressure range being reduced.

3. The method for quantitatively evaluating the wellbore integrity risk of carbon dioxide injection wells according to claim 2, characterized in that: Correction of cement sheath bonding index based on formation temperature and preset standard temperature range includes: Adjusting the cement sheath bonding index according to the formation temperature being less than the minimum value of the preset standard temperature range and the standard temperature range being increased; The cement sheath bonding index is adjusted according to the formation temperature being greater than the maximum value of the preset standard temperature range and the standard temperature range being reduced.

4. The method for quantitatively evaluating the wellbore integrity risk of carbon dioxide injection wells according to claim 3, characterized in that: The total risk level score is calculated based on the evaluation results of each risk indicator and the weight coefficient of each risk indicator, including: The quantitative evaluation value of casing thread sealing, the quantitative evaluation value of cement ring sealing, the quantitative evaluation value of downhole tool strength, the quantitative evaluation value of oil casing residual strength, the quantitative evaluation value of pipe corrosion risk, the quantitative evaluation value of thread corrosion risk and the quantitative evaluation value of gas tree sealing are multiplied by the corresponding weight coefficients and summed to obtain the total risk level score.

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