A Multiphase CO2 Leakage Measurement Simulation System and Method along the Wellbore

Abstract

This invention provides a simulation system and method for measuring multiphase CO2 leakage along a wellbore. The wellbore simulation system simulates a CO2 wellbore; a wellbore temperature control system and a wellbore pressure control system regulate the temperature and pressure of CO2 within the wellbore simulation system, respectively; a CO2 phase change system inputs multiphase CO2 into the wellbore simulation system; a measurement system detects CO2 leakage parameters and cement sheath change parameters; and a processing device controls the CO2 phase change system to adjust the phase of CO2 entering the wellbore simulation system, controls the wellbore temperature control system and the wellbore pressure control system to adjust the wellbore temperature and pressure, and controls the CO2 phase change system, the wellbore temperature control system, and the wellbore pressure control system to adjust corrosion parameters. This invention enables the quantitative measurement of CO2 leakage parameter data and cement sheath change parameter data for arbitrary wellbore temperatures, wellbore pressures, and corrosion parameters at different CO2 phases.

Description

Technical Field

[0001] This invention relates to the field of oil and gas development, and in particular to a multiphase CO2 leakage measurement and simulation system and method along the wellbore. Background Technology

[0002] The world faces the significant challenge of controlling greenhouse gas emissions and addressing climate change. To address this challenge, CCS (Carbon Capture and Storage) / CCUS (Carbon Capture, Utilization and Storage) technologies have been widely developed. CCUS technology is an important emission reduction technology that primarily reduces atmospheric greenhouse gas levels by capturing CO2 emitted during industrial production processes and then using it for other purposes or storing it underground. The wellbore is the direct channel connecting the surface and the underground storage area in CCS / CCUS projects. During CO2 injection into the wellbore and geological storage, changes in wellbore temperature and pressure can cause microcracks or fissures in the cement sheath and its interface on the outside of the wellbore, leading to cement sheath seal integrity failure. Furthermore, CO2 corrodes the cement sheath, deteriorating its mechanical properties and accelerating the seal integrity failure process. Once the cement sheath seal integrity fails, CO2 leakage at the wellhead will occur, posing serious safety problems.

[0003] Existing experimental devices or methods for measuring CO2 leakage along the wellbore can only measure the sealing capacity of the first and second interfaces of the cement sheath separately, or measure the sealing of the cement sheath when fluid is injected. It is difficult to realize the analysis of CO2 fluid leakage along the wellbore under real-time detection and various types of temperature-pressure-corrosion coupling effects, in conjunction with CO2 conditions. Summary of the Invention

[0004] The present invention addresses the issue that existing devices and methods for measuring CO2 leakage along wellbore can only detect the sealing performance of the cement sheath, and do not detect leakage under the combined effects of CO2 multiphase states and various wellbore temperature-pressure-corrosion conditions in real time.

[0005] To address the aforementioned technical problems, the first aspect of this invention provides a multiphase CO2 leakage measurement simulation system along a wellbore, comprising: a wellbore simulation system, a wellbore temperature control system, a wellbore pressure control system, a CO2 phase change system, a measurement system, and processing equipment.

[0006] The wellbore simulation system is used to simulate a CO2 wellbore.

[0007] The wellbore temperature control system and the wellbore pressure control system are respectively used to adjust the temperature and pressure of CO2 in the wellbore simulation system;

[0008] The CO2 phase change system is connected to the wellbore simulation system via a pipeline and is used to input multiphase CO2 into the wellbore simulation system;

[0009] The measurement system is installed on the outer wall of the wellbore simulation system and is used to detect CO2 leakage parameters and cement sheath change parameters.

[0010] The processing equipment is connected to the wellbore temperature control system, the wellbore pressure control system, the CO2 phase change system, and the measurement system. It is used to control the CO2 phase change system to adjust the CO2 phase state entering the wellbore simulation system, control the wellbore temperature control system and the wellbore pressure control system to adjust the wellbore temperature and pressure, and control the CO2 phase change system, the wellbore temperature control system, and the wellbore pressure control system to adjust the corrosion parameters. This allows the measurement system to measure CO2 leakage parameter data and cement sheath change parameter data under each phase of CO2, wellbore temperature, wellbore pressure, and corrosion parameters.

[0011] In a further embodiment of the present invention, the wellbore simulation system includes: casing, cement sheath, insulation sleeve and stand;

[0012] The sleeve is used to simulate the full-size sleeve in actual engineering projects;

[0013] The cement ring is placed around the casing to simulate the environment around the casing under actual engineering conditions;

[0014] The insulation sleeve is installed on the outside of the cement ring to insulate the cement ring.

[0015] The stand is used to provide a platform for setting up the sleeve, the cement ring, and the insulation sleeve.

[0016] In a further embodiment of the present invention, the wellbore temperature control system includes: an electric heater and a temperature control module;

[0017] The electric heater is installed inside the casing of the wellbore simulation system and is used to regulate the wellbore temperature;

[0018] The temperature control module is electrically connected to the electric heater and the processing device, and is used to control the temperature of the electric heater according to the instructions of the processing device, and send the temperature of the electric heater to the processing device.

[0019] In a further embodiment of the present invention, the wellbore pressure control system includes: a pressure sensor, a high-pressure buffer tank, and an automatic pressure control pump;

[0020] The pressure sensor is installed on the wellbore simulation system and electrically connected to the processing device. It is used to measure the pressure of CO2 in the wellbore simulation system and send the pressure of CO2 in the wellbore to the processing device.

[0021] The high-pressure buffer tank is connected to the casing in the measuring wellbore simulation system via an automatic pressure control pump. The automatic pressure control pump is electrically connected to the processing equipment. The processing equipment is used to determine the adjustment command to the automatic pressure control pump based on the CO2 pressure in the wellbore and the target pressure. The automatic pressure control pump controls the high-pressure buffer tank to replenish or absorb CO2 in the casing of the measuring wellbore simulation system to adjust the wellbore pressure.

[0022] In a further embodiment of the present invention, the CO2 phase change system includes: a visualized supercritical CO2 chamber, a visualized liquid CO2 chamber, a visualized gaseous CO2 chamber, and a storage chamber;

[0023] The visualized supercritical CO2 chamber, visualized liquid CO2 chamber, and visualized gaseous CO2 chamber are used for storing and preparing supercritical CO2, liquid CO2, and gaseous CO2, respectively.

[0024] The storage chamber is connected to a visualized supercritical CO2 chamber, a visualized liquid CO2 chamber, a visualized gaseous CO2 chamber, and a wellbore simulation system;

[0025] The visualized supercritical CO2 chamber, visualized liquid CO2 chamber, and visualized gaseous CO2 chamber are also electrically connected to the processing equipment, and are used to discharge single-phase or mixed-phase CO2 into the storage chamber under the control of the processing equipment.

[0026] In a further embodiment of the present invention, a temperature sensor, a pressure sensor, and a magnetic stirrer are provided in the visualized supercritical CO2 chamber, the visualized liquid CO2 chamber, and the visualized gaseous CO2 chamber.

[0027] The temperature sensor and pressure sensor are electrically connected to the processing device and are used to collect the temperature and pressure of CO2 in the visualized supercritical CO2 chamber, the visualized liquid CO2 chamber and the visualized gaseous CO2 chamber.

[0028] The magnetic stirrer is used to stir the CO2 in the visualized supercritical CO2 chamber, the visualized liquid CO2 chamber, and the visualized gaseous CO2 chamber.

[0029] In a further embodiment of the present invention, the measurement system includes: a strain detection module, an acoustic wave detection module, a bubble detection module, a pressure detection module, a gas viscosity detection module, and a gas leakage measurement module;

[0030] The strain detection module is used to detect the strain of the cement ring.

[0031] The acoustic wave detection module is used to detect the acoustic wave information of the cement ring;

[0032] The bubble detection module is used to detect the CO2 leakage rate of the outer wall of the cement ring and whether there are bubbles in the CO2 on the outer wall of the cement ring.

[0033] The pressure detection module is used to detect the pressure of CO2 leaking from the outer wall of the cement ring;

[0034] The gas viscosity detection module is used to detect the viscosity of CO2 leaking from the outer wall of the cement ring;

[0035] The gas leakage measurement module is used to detect the gas composition on the outer wall of the cement ring and the total leakage of CO2.

[0036] In a further embodiment of the present invention, it further includes: a fluid circulation system, wherein the fluid circulation system includes: a CO2 gas source, valves, an air compressor, a pressure stabilizing pump, an electronic flow meter, and a pressure regulating valve;

[0037] The CO2 gas source is used to provide CO2 gas;

[0038] One end of the valve is connected to the output end of the CO2 gas source and is used to regulate the flow rate of the output CO2 gas;

[0039] One end of the air compressor is connected to the other end of the valve, and the other end of the air compressor is connected to one end of the pressure stabilizing pump, for compressing CO2 gas;

[0040] The other end of the pressure-stabilizing pump is connected to the CO2 phase change system, and is used to provide the CO2 phase change system with pressure-stabilized CO2;

[0041] One end of the electronic flow meter is connected to the output end of the wellbore simulation system, and the other end of the electronic flow meter is connected to one end of the pressure regulating valve. The other end of the pressure regulating valve is connected to the recovery end of the CO2 gas source. The electronic flow meter is used to control the flow rate of recovered CO2, and the pressure regulating valve is used to adjust the recovery pressure of CO2.

[0042] In a further embodiment of the present invention, the processing device is also used for:

[0043] The stability of the cement sheath is evaluated based on the changes in cement sheath parameters detected under various wellbore temperatures and pressures.

[0044] In a further embodiment of the present invention, the processing device is also used for:

[0045] The wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state are used as inputs, and the CO2 leakage pressure, CO2 leakage rate, and total CO2 leakage amount in the CO2 leakage parameters are used as outputs. A sample set is constructed based on the CO2 leakage parameters measured by the measurement system under various wellbore temperatures, wellbore pressures, corrosion parameters, and CO2 phase states.

[0046] A neural network model is trained using the sample set to obtain a leakage prediction model.

[0047] In a second embodiment of the present invention, a method for simulating and measuring multiphase CO2 leakage along a wellbore is provided, applicable to the processing equipment in any of the foregoing embodiments. The method includes:

[0048] The experimental conditions include CO2 phase state, wellbore temperature, wellbore pressure, and corrosion parameters, wherein the corrosion parameters include CO2 ratio and corrosion time.

[0049] The wellbore temperature control system operates according to the wellbore temperature under the experimental conditions.

[0050] The wellbore pressure control system operates according to the wellbore pressure under the experimental conditions.

[0051] The CO2 phase in the CO2 phase change system is controlled to enter the wellbore simulation system according to the CO2 phase state in the experimental conditions.

[0052] The proportion of CO2 entering the wellbore simulation system is controlled according to the CO2 ratio in the experimental conditions.

[0053] The experimental duration was controlled according to the corrosion time in the experimental conditions, and CO2 leakage parameter data and cement ring change parameter data were collected when the corrosion time was up.

[0054] By changing the experimental conditions, multiple sets of CO2 leakage parameter data and cement ring change parameter data were obtained under different experimental conditions.

[0055] As a further embodiment of the present invention, it also includes:

[0056] The wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state are used as inputs, and the CO2 leakage pressure, CO2 leakage rate, and total CO2 leakage amount in the CO2 leakage parameters are used as outputs. A sample set is constructed based on the CO2 leakage parameters measured by the measurement system under various wellbore temperatures, wellbore pressures, corrosion parameters, and CO2 phase states.

[0057] A neural network model is trained using the sample set to obtain a leakage prediction model.

[0058] A third aspect of the present invention provides a method for predicting multiphase CO2 leakage along a wellbore, comprising:

[0059] Obtain the actual wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state;

[0060] The actual wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state are input into the leakage prediction model to obtain the actual wellbore CO2 leakage pressure, CO2 leakage rate, and total CO2 leakage.

[0061] The leakage prediction model is trained using the method described in the foregoing embodiments.

[0062] A fourth aspect of the present invention provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program to implement the method described in any of the foregoing embodiments.

[0063] A fifth aspect of the present invention provides a computer-readable storage medium storing a computer program that, when executed by a processor of a computer device, implements the method described in any of the foregoing embodiments.

[0064] A sixth aspect of the present invention provides a computer program product comprising a computer program that, when executed by a processor of a computer device, implements the method described in any of the foregoing embodiments.

[0065] The multiphase CO2 leakage measurement simulation system and method provided by this invention can quantitatively measure CO2 leakage parameter data and cement sheath variation data under different phases of CO2 with arbitrary wellbore temperature, wellbore pressure, and corrosion parameters. The CO2 leakage parameter data under each phase of CO2, wellbore temperature, wellbore pressure, and corrosion parameters are fitted using neural networks and deep learning methods to establish an artificial intelligence-based leakage prediction model for predicting CO2 leakage parameters. Based on this model, the leakage parameters (leakage pressure, flow rate, and total leakage) of different phases of CO2 under arbitrary temperature, pressure, and corrosion conditions can be evaluated, which has important reference value for predicting the sealing integrity of CCS / CCUS wells.

[0066] To make the above and other objects, features and advantages of the present invention more apparent and understandable, preferred embodiments are described below in detail with reference to the accompanying drawings. Attached Figure Description

[0067] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0068] Figure 1 This diagram illustrates a structural schematic of a multiphase CO2 leakage measurement and simulation system along a wellbore according to an embodiment of the present invention.

[0069] Figure 2 A schematic diagram of a neural network model according to an embodiment of the present invention is shown;

[0070] Figure 3 This invention illustrates another structural schematic diagram of a multiphase CO2 leakage measurement and simulation system along a wellbore, according to an embodiment of the present invention.

[0071] Figure 4 A flowchart of a method for simulating the measurement of multiphase CO2 leakage along a wellbore according to an embodiment of the present invention is shown;

[0072] Figure 5 Another flowchart of the multiphase CO2 leakage measurement simulation method along the wellbore according to an embodiment of the present invention is shown;

[0073] Figure 6 A flowchart of the multiphase CO2 leakage prediction method along the wellbore according to an embodiment of the present invention is shown;

[0074] Figure 7 A structural diagram of the multiphase CO2 leakage prediction device along the wellbore according to an embodiment of the present invention is shown;

[0075] Figure 8 A structural diagram of a computer device according to an embodiment of the present invention is shown.

[0076] Explanation of symbols in the attached drawings:

[0077] 101. Wellbore simulation system;

[0078] 102. Wellbore temperature control system;

[0079] 103. Wellbore pressure control system;

[0080] 104. CO2 phase change system;

[0081] 105. Measurement system;

[0082] 106. Processing equipment;

[0083] 1. CO2 gas source;

[0084] 2. Valves;

[0085] 3. Air compressor;

[0086] 4. Pressure stabilizing pump;

[0087] 5. Visualization of the supercritical CO2 chamber;

[0088] 6. Visualization of the liquid CO2 chamber;

[0089] 7. Visualized gaseous CO2 chamber;

[0090] 8. Storage cavity;

[0091] 9. Electronic flow meter;

[0092] 10. Gas flow meter;

[0093] 11. Bubble detection device;

[0094] 12. Sleeve;

[0095] 13. Cement ring;

[0096] 14. Electric heater;

[0097] 15. Thermal insulation sleeve;

[0098] 16. Stand;

[0099] 17. Pressure detection module;

[0100] 18. Temperature control module;

[0101] 19. Strain detection module;

[0102] 20. Acoustic wave detection module;

[0103] 21. Gas viscosity detection module;

[0104] 22. High-pressure buffer tank;

[0105] 23. Processing equipment;

[0106] 24. Automatic pressure control pump;

[0107] 25. Valves;

[0108] 26. Pressure sensor;

[0109] 27. Safety valve;

[0110] 28. Electronic flow meter;

[0111] 29. Pressure regulating valve;

[0112] 30. First interface;

[0113] 31. Second interface;

[0114] 32. Gas leakage measurement module;

[0115] 33. Valves;

[0116] 701. Data Acquisition Unit;

[0117] 702. Prediction Unit;

[0118] 802. Computer equipment;

[0119] 804, Processor;

[0120] 806. Memory;

[0121] 808. Drive mechanism;

[0122] 810. Input / Output Module;

[0123] 812. Input devices;

[0124] 814. Output devices;

[0125] 816. Presentation equipment;

[0126] 818. Graphical User Interface;

[0127] 820. Network interface;

[0128] 822. Communication link;

[0129] 824. Communication bus. Detailed Implementation

[0130] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0131] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this invention are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of the invention described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover a non-exclusive inclusion; for example, a process, method, apparatus, product, or device that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or devices.

[0132] This specification provides the operational steps of the methods described in the embodiments or flowcharts, but based on conventional or non-inventive labor, more or fewer operational steps may be included. The order of steps listed in the embodiments is merely one possible execution order among many and does not represent the only possible execution order. In actual system or device products, the methods shown in the embodiments or drawings can be executed sequentially or in parallel.

[0133] It should be noted that the data involved in this application (including but not limited to data used for analysis, data stored, data displayed, etc.) are all information and data authorized by the user or fully authorized by all parties, and the acquisition, transmission, storage, use and processing of the relevant data comply with the relevant laws, regulations and standards of the relevant countries and regions.

[0134] It should be noted that in the embodiments of this application, certain software, components, models and other existing solutions in the industry may be mentioned. These should be regarded as exemplary and are only intended to illustrate the feasibility of implementing the technical solution of this application. However, they do not mean that the applicant has used or necessarily used the solution.

[0135] CO2 can be produced in gaseous, liquid, and supercritical states due to the influence of its own temperature and reservoir temperature and pressure. The different phases of CO2 exhibit different flow characteristics, leading to variations in leakage CO2 pressure, flow rate, and total leakage volume along the wellbore in CCS / CCUS projects under different CO2 phases, wellbore temperature, wellbore pressure, and corrosion parameters, resulting in varying wellhead risks. Existing devices and methods for measuring CO2 leakage along the wellbore can only detect the sealing performance of the cement sheath and do not monitor leakage under real-time conditions of multiple CO2 phases and various wellbore temperature-pressure-corrosion coupling effects. Therefore, developing a measurement device that can consider different wellbore temperature-pressure-corrosion parameter coupling conditions to measure gaseous, liquid, and supercritical CO2 leakage along the wellbore allows for the evaluation of the variation patterns of different CO2 leakage parameters under various environmental conditions.

[0136] In one embodiment of the present invention, a multiphase CO2 leakage measurement and simulation system along a wellbore is provided, such as... Figure 1 As shown, it includes: a wellbore simulation system 101, a wellbore temperature control system 102, a wellbore pressure control system 103, a CO2 phase change system 104, a measurement system 105, and processing equipment 106.

[0137] The wellbore simulation system 101 is used to simulate a CO2 wellbore. In specific implementation, the wellbore simulation system includes at least a casing and a cement sheath. The cement sheath is placed around the casing to simulate the environment around the casing under actual engineering conditions (such as the cement sheath and rock mass).

[0138] The wellbore temperature control system 102 and the wellbore pressure control system 103 are used to regulate the temperature and pressure of CO2 in the wellbore simulation system, respectively.

[0139] The CO2 phase change system 104 is connected to the wellbore simulation system 101 via a pipeline, and is used to input multiphase CO2 into the wellbore simulation system 101. The multiphase states described in this embodiment include supercritical state, liquid state, and gaseous state.

[0140] The measurement system 105 is installed on the outer wall of the wellbore simulation system 101 to detect CO2 leakage parameters and cement sheath change parameters.

[0141] In some real-time methods, CO2 leakage parameters include CO2 leakage rate, pressure of leaking CO2, and total amount of CO2 leaked.

[0142] In some real-time methods, the parameters of cement ring variation include cement ring strain and acoustic information of the cement ring.

[0143] When cement sheaths are subjected to external factors such as CO2 pressure, temperature, or corrosion, stress and strain occur, leading to the formation of microcracks or microfractures within the sheath. As strain accumulates, these cracks expand, causing cement sheath seal failure and increasing the risk of CO2 leakage along the wellbore. Therefore, the strain of the cement sheath is closely related to the leakage rate; the greater the strain, the higher the likelihood of cement sheath failure and the greater the leakage.

[0144] The acoustic information of a cement sheath reflects its internal porosity and crack condition. The presence of pores or cracks alters the propagation path and velocity of sound waves, leading to changes in signal attenuation and reflection characteristics. By analyzing these changes in acoustic information, the number and extent of crack propagation can be quantified.

[0145] The processing device 106 is connected to the wellbore temperature control system 102, the wellbore pressure control system 103, the CO2 phase change system 104, and the measurement system 105. It is used to control the CO2 phase change system 104 to adjust the CO2 phase state entering the wellbore simulation system 101, control the wellbore temperature control system 102 and the wellbore pressure control system 103 to adjust the wellbore temperature and wellbore pressure, and control the CO2 phase change system 104, the wellbore temperature control system 102 and the wellbore pressure control system 103 to adjust the corrosion parameters. The measurement system 105 measures the CO2 leakage parameter data and cement sheath change parameter data under the conditions of CO2 phase state, wellbore temperature, wellbore pressure and corrosion parameters.

[0146] In detail, under specific temperature and pressure conditions, the proportion of CO2 indirectly affects the formation of liquid, gaseous, and supercritical states; for example, a higher proportion may lead to a faster attainment of the supercritical state. Adjusting the CO2 proportion is a key control parameter for achieving stability and corrosivity in different phases. Corrosion parameters can be reflected by controlling the CO2 proportion and the experimental time (i.e., corrosion time).

[0147] By adjusting the CO2 phase, wellbore temperature, wellbore pressure, and corrosion parameters, it is possible to obtain CO2 leakage parameter data and cement sheath variation parameter data under different corrosion states. Corrosion state refers to the degree or phenomenon of corrosion exhibited by a material or device under certain conditions, such as corrosion pits, cracks, and oxide layers on the material surface. The corrosion state is the result of the effects of corrosion parameters. For example, under repeated temperature cycles, the corrosion state of the cement sheath will become more severe. Monitoring and controlling corrosion parameters can help prevent or delay the deterioration of the corrosion state.

[0148] This embodiment can achieve quantitative measurement of CO2 leakage parameter data and cement sheath variation parameter data under different phases of CO2, with arbitrary wellbore temperature, wellbore pressure and corrosion parameters. It has important reference value for predicting the sealing integrity of CCS / CCUS wells.

[0149] In some embodiments of the present invention, the processing equipment is also used to evaluate the stability of the cement sheath based on the cement sheath variation parameters detected under each wellbore temperature and wellbore pressure.

[0150] In practice, the stability evaluation of the cement ring is achieved through the following steps:

[0151] (1) Experimental preparation: Initialize the multiphase CO2 leakage measurement simulation system along the wellbore, including checking the integrity, sealing and insulation of the cement sheath in the wellbore simulation system, and setting up the wellbore temperature control system and the wellbore pressure control system to ensure that accurate temperature and pressure control can be achieved.

[0152] (2) Initial state recording of parameter measurement: Before the experiment begins, record the cement ring variation parameters (stress, strain and sound wave propagation parameters) under normal temperature and pressure conditions as baseline data.

[0153] (3) Univariate test of temperature and pressure: Univariate test of temperature change and pressure change is carried out respectively. The settings of the wellbore temperature control system and the wellbore pressure control system are gradually adjusted. The strain change of cement sheath under different temperature or pressure conditions is recorded by the measurement system, as well as the propagation speed and reflection of sound waves in cement sheath under different conditions, and the formation or expansion of pores and cracks are analyzed.

[0154] (4) Joint test under temperature-pressure cycle conditions: Under the coordinated control of the wellbore temperature control system and the wellbore pressure control system, a temperature-pressure coupling cycle is applied to simulate the actual temperature and pressure fluctuation in the wellbore. By monitoring the strain data in real time, the response of the cement sheath in the dynamic environment is captured, and the acoustic information of the cement sheath is monitored to monitor the crack propagation trend.

[0155] (5) Data Analysis: The stress, strain, and wave velocity data were normalized using processing equipment to analyze the effects of temperature and pressure on the stability of the cement ring. A performance evaluation model for the cement ring under different conditions was established, including quantitative descriptions of stability (whether cracks propagate) and adaptability (whether it can return to its original state).

[0156] (6) Results visualization and conclusions: Based on the analysis results, generate an evaluation report on the adaptability of cement ring to temperature-pressure changes, and summarize the stability limit of cement ring and its ability to adapt to different temperature and pressure cycling conditions.

[0157] In some embodiments of the present invention, the processing device is further used for:

[0158] The wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state are used as inputs, and the CO2 leakage pressure, CO2 leakage rate, and total CO2 leakage amount in the CO2 leakage parameters are used as outputs. A sample set is constructed based on the CO2 leakage parameters measured by the measurement system under various wellbore temperatures, wellbore pressures, corrosion parameters, and CO2 phase states.

[0159] A neural network model is trained using the sample set to obtain a leakage prediction model.

[0160] In one embodiment of this invention, a deep learning framework (PyTorch) is selected, and an input layer, hidden layer, and output layer are defined. The number of nodes in the input layer should equal the number of input features (temperature, pressure, corrosion conditions, CO2 phase). The output layer has three nodes (leakage pressure, leakage rate, total leakage amount), and the linear rectified function (ReLU) is selected as both the activation function and the loss function (mean squared error). The neural network model is as follows: Figure 2 As shown, in specific implementation, the number of hidden layers and nodes can be selected according to actual needs.

[0161] In this embodiment, when constructing the sample set, the collected data is preprocessed. After handling missing values ​​and outliers, the data is standardized or normalized to meet the input requirements of the neural network.

[0162] To improve the modeling accuracy of the leakage prediction model, the dataset is divided into a training set, a validation set, and a test set (typically in a 70:20:10 ratio). The leakage prediction model is trained using the training set. The model is then validated using the validation set; if validation fails, the neural network model structure is adjusted and retrained. Finally, the validated leakage prediction model is tested using the test set.

[0163] In this embodiment, the parameters of the input variables are external conditions that can be directly controlled during the experiment, which determine the performance of the cement sheath under specific environments. That is, wellbore temperature, wellbore pressure, and corrosion time have a direct impact on the behavior of CO2 leakage, while the phase state of CO2 (gaseous, liquid, or supercritical) further affects the fluid flow and the corrosive effect on the cement sheath. Through these input variables, the model can cover leakage behavior under various experimental conditions, and has good generalization and applicability.

[0164] Among the output variables, CO2 leakage pressure and CO2 leakage flow rate directly reflect the integrity of the cement ring seal, while the total leakage is a quantification of the overall leakage situation; these indicators are significantly affected by the input variables.

[0165] The reason why CO2 viscosity was not selected as the output variable in this embodiment is that although CO2 viscosity affects fluid flow characteristics, its change is relatively small in the supercritical state or gaseous state, and its direct impact on leakage behavior is weaker than that of pressure, flow rate and total volume.

[0166] This embodiment simplifies the model and improves training accuracy and efficiency by selecting appropriate input and output variables. It yields a relationship (reflected by the leakage prediction model) between CO2 leakage pressure, CO2 leakage rate, total CO2 leakage, and the temperature, pressure, corrosion parameters, and CO2 phase state of each wellbore, enabling the evaluation of the cement sheath.

[0167] In one embodiment of the present invention, as Figure 3 As shown, the wellbore simulation system includes: casing 12, cement sheath 13, insulation sleeve 15, and platform 16.

[0168] Sleeve 12 is used to simulate the full-size sleeve in actual engineering.

[0169] A cement ring 13 is placed around the casing 12 to simulate the environment around the casing under actual engineering conditions. In practice, an insulation layer is also provided on the outside of the cement ring 13 to provide a sealed space for the experiment.

[0170] The insulation sleeve 15 is set on the outside of the cement ring 13 to insulate the cement ring 13 and provide a sealed space for the experiment.

[0171] The stand 16 is used to provide a platform for setting up the sleeve 12, the cement ring 13, and the insulation sleeve 15.

[0172] In one embodiment of the present invention, as Figure 3 As shown, the wellbore temperature control system includes an electric heater 14 and a temperature control module 18.

[0173] An electric heater 14 is installed inside the casing of the wellbore simulation system to regulate the wellbore temperature. In one specific embodiment, the electric heater 14 employs a Peltier element, also known as a thermocouple or thermoelectric cooler, to utilize the thermoelectric effect for heating or cooling. When current passes through the Peltier element, a temperature difference is generated on its two surfaces; one surface generates heat, and the other cools. By controlling the direction and magnitude of the current, the temperature difference can be precisely controlled, thereby controlling the temperature.

[0174] The temperature control module 18 is electrically connected to the electric heater 14 and the processing device 23, and is used to control the temperature of the electric heater 14 according to the instructions of the processing device and send the temperature of the electric heater 14 to the processing device 23.

[0175] This embodiment uses processing equipment and a temperature control module to precisely control the temperature inside the wellbore cavity, thereby controlling the temperature state inside the casing.

[0176] In one embodiment of the present invention, the wellbore pressure control system includes: a pressure sensor 26, a high-pressure buffer tank 22, and an automatic pressure control pump 24.

[0177] Pressure sensor 26 is installed on the wellbore simulation system and electrically connected to processing device 23. It is used to measure the pressure of CO2 in the wellbore of the wellbore simulation system and send the pressure of CO2 in the wellbore to processing device 23.

[0178] The high-pressure buffer tank 22 is connected to the casing in the measuring well simulation system via the automatic pressure control pump 24. The automatic pressure control pump 24 is electrically connected to the processing device 23. The processing device 23 is used to determine whether the pressure in the well has reached the required pressure conditions for the experiment based on the CO2 pressure in the well and the target pressure. If it has not reached the required pressure conditions, it generates an adjustment command to the automatic pressure control pump 24. The automatic pressure control pump 24 controls the high-pressure buffer tank 22 to replenish or absorb CO2 in the casing of the measuring well simulation system to adjust the well pressure.

[0179] In one embodiment of the present invention, the wellbore pressure control system further includes: valve 25 and safety valve 27, used to control the pressure of the automatic pressure control pump 24 and prevent the automatic pressure control pump from being damaged due to excessive pressure.

[0180] In this embodiment, the high-pressure buffer tank 22 stores liquid CO2.

[0181] In one embodiment of the present invention, as Figure 3 As shown, the CO2 phase change system includes: a visualized supercritical CO2 chamber 5, a visualized liquid CO2 chamber 6, a visualized gaseous CO2 chamber 7, and a storage chamber 8.

[0182] The visualization chambers 5 (supercritical CO2), 6 (liquid CO2), and 7 (gaseous CO2) are used to store and prepare supercritical CO2, liquid CO2, and gaseous CO2, respectively, providing CO2 in different phases for the simulated wellbore.

[0183] Storage chamber 8 connects to visualization supercritical CO2 chamber 5, visualization liquid CO2 chamber 6, visualization gaseous CO2 chamber 7, and wellbore simulation system, and is used to store CO2 in single-phase or mixed-phase states.

[0184] The visualized supercritical CO2 chamber 5, the visualized liquid CO2 chamber 6, and the visualized gaseous CO2 chamber 7 are also electrically connected to the processing equipment 23, and are used to discharge single-phase or mixed-phase CO2 into the storage chamber 8 under the control of the processing equipment 23.

[0185] In some embodiments, temperature sensors, pressure sensors, and magnetic stirrers are provided in the visualized supercritical CO2 chamber 5, the visualized liquid CO2 chamber 6, and the visualized gaseous CO2 chamber 7.

[0186] Temperature and pressure sensors are electrically connected to a processing device for collecting the temperature and pressure of CO2 in the visualized supercritical CO2 chamber 5, the visualized liquid CO2 chamber 6, and the visualized gaseous CO2 chamber 7.

[0187] Magnetic stirrers are used to agitate the CO2 in the visualized supercritical CO2 chamber 5, the visualized liquid CO2 chamber 6, and the visualized gaseous CO2 chamber 7, thereby achieving uniform mixing of the samples and preventing stratification of multiphase CO2 in the experimental environment, thus ensuring the accuracy and consistency of experimental data. Uniform stirring is particularly important for simulating actual leaks because it can more realistically reproduce the flow state in the wellbore environment.

[0188] In one embodiment of the present invention, as Figure 3 As shown, the measurement system includes: strain detection module 19, acoustic wave detection module 20, bubble detection module 10 / 11, pressure detection module 17, gas viscosity detection module 21, and gas leakage measurement module 32.

[0189] The strain detection module 19 is used to detect the strain information of the cement sheath. In specific implementation, the strain detection module 19 is located on the outer wall of the wellbore simulation system. One end of the strain detection module 19 is connected to the cement sheath and the other end is connected to the processing equipment 23. It is used to detect the strain generated by the cement sheath under stress and display the strain status through a computer human-machine interface.

[0190] The acoustic wave detection module 20 is used to detect acoustic wave information of the cement sheath. In specific implementation, the acoustic wave detection module 20 is located on the outer wall of the wellbore simulation system. One end of the acoustic wave detection module 20 is connected to the cement sheath, and the other end is connected to the processing equipment 23. By analyzing the propagation speed and reflection of acoustic waves in the wellbore cement sheath, the development of porosity and microcracks can be reflected. The acoustic wave detection module 20 can perform density testing and microcrack analysis on the cement sheath, thus quantifying the changes in the physical and mechanical properties of the cement sheath to a certain extent.

[0191] The bubble detection module 10 / 11 is used to detect the CO2 leakage rate on the outer wall of the cement sheath and whether there are bubbles in the CO2 on the outer wall of the cement sheath. In one specific embodiment, the bubble detection module includes a gas flow meter 10 and a bubble detection device 11, located on the outer wall of the wellbore simulation system. The gas flow meter 10 is connected to the bubble detection device 11 and is used to detect the flow rate of CO2 on the outer wall of the cement sheath, reflecting the leakage rate, and simultaneously detecting the generation of bubbles. Monitoring the presence of bubbles in the gas flow is very important for preventing equipment performance degradation or damage.

[0192] The pressure detection module 17 is used to detect the pressure of leaked CO2 on the outer wall of the cement ring. In one specific embodiment, the pressure detection module 17 is a patch pressure sensor located on the outer wall of the cement ring (second interface for gas detection) to detect the pressure of leaked CO2.

[0193] The gas viscosity detection module 21 is used to detect the viscosity of CO2 leaking from the outer wall of the cement ring. In one specific embodiment, the gas viscosity detection module 21 is a capillary viscometer, located on the outer wall of the wellbore simulation system. One end of the capillary viscometer is connected to the cement ring, and the other end is connected to the treatment device 23, and it is used to detect the viscosity of the leaked CO2.

[0194] The gas leakage measurement module 32 is used to detect the gas composition and total CO2 leakage from the outer wall of the cement sheath. In one specific embodiment, the gas leakage measurement module 32 employs a spectral-based online dissolved gas monitoring device for oil. This type of device can analyze the dissolved gas content in real time. The device is located on the outer wall of the wellbore simulation system, with one end connected to the cement sheath and the other end connected to the processing equipment 23.

[0195] In one embodiment of the present invention, as Figure 3 As shown, it also includes: a fluid circulation system, wherein the fluid circulation system includes: a CO2 gas source 1, a valve 2, an air compressor 3, a pressure stabilizing pump 4, an electronic flow meter 28, and a pressure regulating valve 29.

[0196] CO2 source 1 is used to provide CO2 gas.

[0197] One end of valve 2 is connected to the output end of CO2 gas source 1 and is used to regulate the flow rate of output CO2 gas.

[0198] One end of the air compressor 3 is connected to the other end of the valve 2, and the other end of the air compressor 3 is connected to one end of the pressure stabilizing pump 4, for compressing CO2 gas.

[0199] The other end of the pressure-stabilizing pump 4 is connected to the CO2 phase change system and is used to provide the CO2 phase change system with stabilizing CO2.

[0200] One end of the electronic flow meter 28 is connected to the output end of the wellbore simulation system, and the other end of the electronic flow meter 28 is connected to one end of the pressure regulating valve 29. The other end of the pressure regulating valve 29 is connected to the recovery end of the CO2 gas source 1. The electronic flow meter 28 is used to control the flow rate of recovered CO2, and the pressure regulating valve 29 is used to adjust the recovery pressure of CO2.

[0201] During the experiment, the fluid circulation system introduced CO2 gas stored in the CO2 gas source into three visualized CO2 chambers at constant pressure through an air compressor and a pressure stabilizing pump, allowing CO2 of different phases to enter the storage chambers. The experiment was then conducted through a wellbore simulation system. After the experiment, the pressure of the CO2 gas could be regulated by a pressure regulating valve and the flow rate could be controlled by an electronic flow meter. Finally, the CO2 gas returned to the CO2 gas source, and the CO2 circulated throughout the pipeline.

[0202] In some embodiments, the fluid circulation system further includes an electronic flow meter 9, which is disposed between the storage chamber 8 and the wellbore simulation system inlet, for detecting the CO2 flow rate entering the wellbore simulation system.

[0203] In one embodiment of the present invention, a method for simulating the measurement of multiphase CO2 leakage along a wellbore is also provided, such as... Figure 4 As shown, it includes:

[0204] Step 401: Obtain experimental conditions, including CO2 phase, wellbore temperature, wellbore pressure, and corrosion parameters, including CO2 ratio and corrosion time.

[0205] In practice, the experimental conditions can be determined by the experimenter based on the actual situation.

[0206] Step 402: Control the wellbore temperature control system to operate according to the wellbore temperature conditions in the experiment.

[0207] Step 403: Control the wellbore pressure control system to operate according to the wellbore pressure in the experimental conditions.

[0208] Step 404: Based on the CO2 phase state in the experimental conditions, control the CO2 phase state in the CO2 phase change system to enter the wellbore simulation system.

[0209] Step 405: Control the proportion of CO2 entering the wellbore simulation system according to the CO2 ratio in the experimental conditions.

[0210] Step 406: Control the experimental duration according to the corrosion time in the experimental conditions, and collect CO2 leakage parameter data and cement ring change parameter data under the experimental conditions when the corrosion time is up.

[0211] Step 407: Change the experimental conditions to obtain CO2 leakage parameter data and cement ring change parameter data under multiple experimental conditions.

[0212] In some implementations, CO2 fluid can be measured under different temperature-pressure conditions: the wellbore temperature or pressure can be adjusted individually, or the wellbore thermometer and wellbore pressure can be coupled and adjusted. This allows for the acquisition of CO2 leakage parameter data and cement sheath variation parameter data under different temperature conditions, different pressure conditions, temperature cycles, pressure cycles, and temperature-pressure cycles.

[0213] Temperature conditions refer to a constant temperature value set during the experiment or measurement process, such as a fixed high or low temperature environment. Temperature cycling refers to the periodic change of temperature within a certain range, such as alternating heating and cooling, simulating the dynamic changes of temperature under actual working conditions, and examining the performance stability of cement rings or other systems under temperature fluctuations.

[0214] Pressure conditions refer to a constant pressure value set during an experiment or measurement, representing a static pressure environment. Pressure cycling refers to the periodic change of pressure within a certain range, including alternating processes of pressurization and depressurization, used to simulate the impact of pressure fluctuations on the system in actual wellbores or experimental equipment.

[0215] By analyzing the CO2 leakage parameter data and cement sheath variation parameter data measured in this embodiment, the adaptability and resistance of the cement sheath to CO2 under different temperature and pressure conditions can be evaluated, thereby providing a guarantee for the safe operation and long-term stability of oil and gas wells.

[0216] In some implementations, measurements of CO2 fluid in different phases can be achieved: the critical temperature of CO2 is 31.04°C, and the critical pressure is 7.38 MPa. When the temperature and pressure exceed these critical points, CO2 enters a supercritical state. These models are shown in Table 1.

[0217] Table 1

[0218]

[0219]

[0220] By setting the temperature and pressure of the visualized supercritical CO2 chamber 5, the visualized liquid CO2 chamber 6, and the visualized gaseous CO2 chamber 7, supercritical CO2, liquid CO2, and gaseous CO2 were stored and prepared to provide CO2 in different phases for the simulated wellbore. Gas experiments, supercritical state experiments, and liquid state experiments were conducted respectively to obtain the CO2 leakage along the wellbore under multiple modes.

[0221] In some implementation methods, measurements of CO2 under different corrosion states can be achieved. During the experiment, adjustments to corrosion parameters are primarily made by changing temperature, pressure, CO2 ratio, and corrosion time. Temperature significantly affects the corrosion rate; therefore, the experimental temperature can be adjusted by modifying the wellbore temperature control system. Pressure also affects the corrosion rate and can be adjusted by modifying the wellbore pressure control system. CO2 concentration also significantly affects the corrosion rate; the CO2 ratio can be changed by adjusting the CO2 gas flow rate or concentration. Under specific temperature and pressure conditions, the CO2 ratio indirectly influences the formation of liquid, gaseous, and supercritical states; for example, a higher ratio may lead to a faster attainment of the supercritical state. Adjusting the CO2 ratio is a key control parameter for achieving stability and corrosivity in different phase states. Corrosion time directly affects the degree of corrosion; the degree of corrosion can be adjusted by extending or shortening the corrosion time.

[0222] By injecting CO2 of different phases, temperatures, and pressures into a wellbore simulation system under varying corrosion conditions, the leakage of CO2 along the wellbore under a coupled temperature-pressure-corrosion environment was observed. Specifically, the corrosion state is the result of the effects of corrosion parameters; for example, the corrosion state of the cement sheath becomes more severe under repeated temperature cycles. The corrosion state refers to the degree or phenomenon of corrosion exhibited by a material or device under certain conditions, such as pitting, cracks, and oxide layers on the material surface. Monitoring and controlling corrosion parameters can help prevent or delay the deterioration of the corrosion state.

[0223] In practice, experimental measurement data can be transmitted to processing equipment via data transmission lines. The processing equipment performs real-time inversion and analysis of the experimental measurement data. By setting time intervals, the system can automatically track and scan the sample throughout the experiment without manual operation by the experimenter. After the experiment, all scanned measurement data are processed and calculated by the processing equipment to obtain the CO2 leakage situation along the wellbore during the experiment. At the same time, a real-time data table can be generated to observe the real-time CO2 leakage situation of the sample.

[0224] In one embodiment of the present invention, as Figure 3 As shown, a gas flow meter and a bubble detection device can be installed at the first gas detection interface 30 and the second gas detection interface 31 respectively to measure the leakage path of CO2.

[0225] In one embodiment of the present invention, as Figure 5 As shown, the simulation method for measuring multiphase CO2 leakage along the wellbore also includes:

[0226] Step 501: Construct a sample set based on the CO2 leakage parameters measured by the measurement system under various wellbore temperatures, wellbore pressures, corrosion parameters, and CO2 phase states.

[0227] Each sample in the sample set includes: wellbore temperature, wellbore pressure, corrosion time and CO2 phase, CO2 leakage pressure, CO2 leakage rate and total CO2 leakage in the CO2 leakage parameters.

[0228] The wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state are used as inputs, and the CO2 leakage pressure, CO2 leakage rate, and total CO2 leakage amount are used as outputs.

[0229] Step 502: Train a neural network model using the sample set to obtain a leakage prediction model.

[0230] Based on the obtained leakage prediction model, multiphase CO2 leakage along the wellbore can be predicted. Therefore, in one embodiment of the present invention, a method for predicting multiphase CO2 leakage along the wellbore is provided, such as... Figure 6 As shown, it includes:

[0231] Step 601: Obtain the actual wellbore temperature, wellbore pressure, corrosion time, and CO2 phase.

[0232] Step 602: Input the actual wellbore temperature, wellbore pressure, corrosion time and CO2 phase state into the leakage prediction model to obtain the actual wellbore CO2 leakage pressure, CO2 leakage rate and total CO2 leakage.

[0233] Furthermore, based on the predicted results of CO2 leakage pressure, CO2 leakage flow rate, and total CO2 leakage, the sealing performance of the cement ring is quantified; the stability and adaptability of the cement ring under different temperature, pressure, and corrosion conditions are judged; and an evaluation report is generated through data visualization, proposing suggestions for the optimized design of the cement ring.

[0234] Based on the same inventive concept, this invention also provides a multiphase CO2 wellbore leakage prediction device, as described in the following embodiments. Since the principle behind the multiphase CO2 wellbore leakage prediction device is similar to that of the multiphase CO2 wellbore leakage prediction method, the implementation of the multiphase CO2 wellbore leakage prediction device can refer to the multiphase CO2 wellbore leakage prediction method, and repeated details will not be elaborated further.

[0235] Specifically, such as Figure 7 As shown, the multiphase CO2 leakage prediction device along the wellbore includes:

[0236] The data acquisition unit 701 is used to acquire the actual wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state.

[0237] The prediction unit 702 inputs the actual wellbore temperature, wellbore pressure, corrosion time and CO2 phase state into the leakage prediction model to obtain the actual wellbore CO2 leakage pressure, CO2 leakage rate and total CO2 leakage.

[0238] To more clearly illustrate the technical solution of this invention, the following will use... Figure 3 The following is a detailed explanation using the multiphase CO2 leakage measurement simulation system along the wellbore as an example. The specific implementation process includes:

[0239] Pre-experimental preparation procedure:

[0240] a. First, a comprehensive initialization preparation is carried out for the multiphase CO2 leakage measurement simulation system along the wellbore. This includes checking the structural robustness, the sealing of the wellbore simulation system and the insulation of the insulation layer, as well as checking whether each measuring device, such as the CO2 gas source, safety valve, pressure regulating valve, and electronic flow meter, is ready. Any problem in any link will trigger the alarm shutdown mechanism.

[0241] b. Preparation of CO2 in different phases: Open CO2 gas source 1 and valve 2 above it. CO2 gas enters the visualized supercritical CO2 chamber 5, visualized liquid CO2 chamber 6 and visualized gaseous CO2 chamber 7 at constant pressure through air compressor 3 and pressure stabilizing pump 4. Set the temperature and pressure in the corresponding chambers through computer (e.g., processing equipment) to store and prepare a certain amount of supercritical CO2, liquid CO2 and gaseous CO2 fluid respectively. Then close valve 2.

[0242] Experimental measurement procedure:

[0243] c. Initial State Test: After closing the storage chamber 8, determining the phase state of the CO2 to be tested, and ensuring that the wellbore simulation system is a sealed environment, the wellbore temperature control system and wellbore pressure control system are used in the processing equipment 23 to control the heating / cooling and pressurization operations in the wellbore. The expected experimental temperature and pressure are set to realize the experiment under different temperature and pressure conditions, temperature cycle, pressure cycle, and temperature-pressure cycle conditions. The measurement system is opened to obtain the raw data and transmitted to the processing equipment for storage.

[0244] d. Real-time Experimental Testing: The CO2 gas source 1, valve 2, air compressor 3, pressure stabilizing pump 4, visualization supercritical CO2 chamber 5, and storage chamber 8 are opened. Supercritical CO2 enters the space between the cement sheath and casing annulus from the bottom of the wellbore simulation system. The temperature and pressure inside the casing have reached the requirements for the supercritical CO2 experiment. Temperature, pressure, and corrosion time (i.e., experimental time) are changed to adjust corrosion parameters. The processing equipment begins recording the experimental time and simultaneously opens the measurement system. Measurement intervals are set according to the experimental plan, and the measurement data is transmitted to the processing equipment 23. As CO2 is gradually pumped into the wellbore simulation system, valve 33 is opened to begin venting. The supercritical CO2 is controlled by electronic flow meter 28 and pressure regulating valve 29 to adjust the flow rate and pressure of the CO2 gas, allowing it to return to the CO2 gas source. The electronic flow meter 28 and pressure regulating valve 29 ensure that the flow rate and pressure of CO2 are controllable during the return process, guaranteeing the closed-loop operation and safety of the experimental system. This design also provides data support for leak analysis and recovery efficiency, improving the overall accuracy and reliability of the experiment.

[0245] The same principle applies to experiments with CO2 in other phases.

[0246] e. Data Processing: The processing equipment performs real-time inversion and analysis of experimental measurement data. This equipment can automatically track and scan the sample throughout the experiment by setting time intervals, eliminating the need for manual operation by the experimenter. It obtains information on CO2 leakage along the cement ring under the coupled effects of temperature, pressure, and corrosion during the CO2 experiment, evaluates the cement ring, and then generates a real-time data table to observe the real-time CO2 leakage of the sample.

[0247] The measurement process for carbon dioxide involves multiple steps under different temperature and pressure conditions.

[0248] Supercritical CO2: Supercritical carbon dioxide is prepared by adjusting the temperature and pressure of a visualized supercritical CO2 chamber. Then, the temperature and pressure within the casing of the wellbore simulation system are adjusted, and CO2 fluid is injected to regulate the concentration. Next, a wellbore temperature control system and a wellbore pressure control system are used to maintain stable temperature and pressure within the wellbore, and a measurement system is used for real-time monitoring. Under high-temperature and high-pressure conditions (supercritical CO2 state), the wellbore temperature control system and wellbore pressure control system need to monitor temperature and pressure changes in real time under dynamically changing high-temperature conditions, and adjust these systems to maintain stable CO2 concentration.

[0249] The impact of high temperature and high pressure on equipment performance must be considered when processing experimental data.

[0250] Liquid CO2: Liquid carbon dioxide is prepared by adjusting the temperature and pressure of a visualized liquid CO2 chamber. Then, the temperature and pressure within the casing of the wellbore simulation system are adjusted, and CO2 fluid is injected and its concentration is regulated. Next, the temperature and pressure within the wellbore are maintained stably using a wellbore temperature control system and a wellbore pressure control system, and monitored in real time using a measurement system.

[0251] Temperature and pressure control modules need to be calibrated to address instrument errors caused by low temperature and low pressure conditions.

[0252] Gaseous CO2: Liquid carbon dioxide is prepared by adjusting the temperature and pressure of the visualized gaseous CO2 chamber. Then, the temperature and pressure inside the casing of the wellbore simulation system are adjusted, and CO2 fluid is injected and its concentration is regulated. Next, the temperature and pressure inside the wellbore are maintained stably by a wellbore temperature control system and a wellbore pressure control system, and monitored in real time using a measurement system.

[0253] Experimental data processing requires adjustments and optimizations based on different conditions to obtain accurate measurement results. Continuous injection of CO2 fluid is maintained at a stable concentration, the measurement system continuously measures and captures leakage under dynamic conditions, the gas source dynamically absorbs CO2 gas, and experimental data is recorded and analyzed in real time.

[0254] This invention relates to a multiphase CO2 wellbore leakage measurement simulation system. This system injects CO2 of different phases, temperatures, and pressures into the annulus between the cement sheath and casing. Under varying environmental conditions, the system measures the flow rate, pressure, and viscosity of the leaking CO2 to evaluate parameters such as cement sheath stress, strain, and wave velocity under different temperature and pressure conditions, temperature cycles, pressure cycles, temperature-pressure cycles, and corrosion conditions. Finally, based on a neural network model and deep learning framework, a relationship model is established between temperature, pressure, corrosion conditions, CO2 phases, leakage pressure, leakage rate, and total leakage. A linear rectification function is selected as the activation function and loss function (mean squared error) to evaluate leakage parameters under arbitrary conditions, providing assurance for the safe operation and long-term stability of oil and gas wells. Furthermore, the multiphase CO2 wellbore leakage measurement simulation system can also provide technical support for the optimized design and long-term monitoring of oil and gas wells.

[0255] In one embodiment of the present invention, a computer device is also provided, such as... Figure 8 As shown, computer device 802 may include one or more processors 804, such as one or more central processing units (CPUs), each of which may implement one or more hardware threads. Computer device 802 may also include any memory 806 for storing information of any kind, such as code, settings, data, etc. Non-limitingly, for example, memory 806 may include any type of RAM, any type of ROM, flash memory, hard disk, optical disk, etc. More generally, any memory can use any technology to store information. Furthermore, any memory may provide volatile or non-volatile retention of information. Furthermore, any memory may represent a fixed or removable component of computer device 802. In one case, when processor 804 executes associated instructions stored in any memory or combination of memories, computer device 802 may perform any operation of the associated instructions. Computer device 802 also includes one or more drive mechanisms 808 for interacting with any memory, such as hard disk drive mechanisms, optical disk drive mechanisms, etc.

[0256] Computer device 802 may also include an input / output module 810 (I / O) for receiving various inputs (via input device 812) and providing various outputs (via output device 814). A specific output mechanism may include a presentation device 816 and an associated graphical user interface 818 (GUI). In other embodiments, the input / output module 810 (I / O), input device 812, and output device 814 may be omitted, and the device may function solely as a computer device within a network. Computer device 802 may also include one or more network interfaces 820 for exchanging data with other devices via one or more communication links 822. One or more communication buses 824 couple the components described above together.

[0257] Communication link 822 can be implemented in any way, such as via a local area network, a wide area network (e.g., the Internet), a point-to-point connection, or any combination thereof. Communication link 822 may include any combination of hardwired links, wireless links, routers, gateway functions, name servers, etc., governed by any protocol or combination of protocols.

[0258] This invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, performs the steps of the above-described method.

[0259] This invention also provides a computer-readable instruction, wherein when a processor executes the instruction, the program therein causes the processor to perform the method described in any of the foregoing embodiments.

[0260] It should be understood that, in various embodiments of the present invention, the order of the above-mentioned process numbers does not imply the order of execution. The execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of the present invention.

[0261] It should also be understood that, in the embodiments of the present invention, the term "and / or" is merely a description of the relationship between associated objects, indicating that three relationships can exist. For example, A and / or B can represent: A existing alone, A and B existing simultaneously, and B existing alone. Furthermore, in the present invention, the character " / " generally indicates that the preceding and following associated objects have an "or" relationship.

[0262] Those skilled in the art will recognize that the units and algorithm steps of the various examples described in conjunction with the embodiments disclosed in this invention can be implemented in electronic hardware, computer software, or a combination of both. To clearly illustrate the interchangeability of hardware and software, the components and steps of each example have been generally described in terms of functionality in the foregoing description. Whether these functions are implemented in hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementations should not be considered beyond the scope of this invention.

[0263] Those skilled in the art will clearly understand that, for the sake of convenience and brevity, the specific working processes of the systems, devices, and units described above can be referred to the corresponding processes in the foregoing method embodiments, and will not be repeated here.

[0264] In the embodiments provided by this invention, it should be understood that the disclosed systems, apparatuses, and methods can be implemented in other ways. For example, the apparatus embodiments described above are merely illustrative. For instance, the division of units is only a logical functional division, and in actual implementation, there may be other division methods. For example, multiple units or components may be combined or integrated into another system, or some features may be ignored or not executed. In addition, the mutual coupling or direct coupling or communication connection shown or discussed may be indirect coupling or communication connection through some interfaces, devices, or units, or may be electrical, mechanical, or other forms of connection.

[0265] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of the embodiments of the present invention, depending on actual needs.

[0266] Furthermore, the functional units in the various embodiments of the present invention can be integrated into one processing unit, or each unit can exist physically separately, or two or more units can be integrated into one unit. The integrated unit can be implemented in hardware or as a software functional unit.

[0267] If the integrated unit is implemented as a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of the present invention, in essence, or the part that contributes to the prior art, or all or part of the technical solution, can be embodied in the form of a software product. This computer software product is stored in a storage medium and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute all or part of the steps of the methods described in the various embodiments of the present invention. The aforementioned storage medium includes various media capable of storing program code, such as USB flash drives, portable hard drives, read-only memory (ROM), random access memory (RAM), magnetic disks, or optical disks.

[0268] Specific embodiments have been used to illustrate the principles and implementation methods of this invention. The descriptions of the embodiments above are only for the purpose of helping to understand the method and core ideas of this invention. At the same time, for those skilled in the art, there will be changes in the specific implementation methods and application scope based on the ideas of this invention. Therefore, the content of this specification should not be construed as a limitation of this invention.

Claims

1. A multiphase CO2 leakage measurement and simulation system along a wellbore, characterized in that, include: Wellbore simulation system, wellbore temperature control system, wellbore pressure control system, CO2 phase change system, measurement system and processing equipment; The wellbore simulation system is used to simulate a CO2 wellbore. The wellbore temperature control system and the wellbore pressure control system are respectively used to adjust the temperature and pressure of CO2 in the wellbore simulation system; The CO2 phase change system is connected to the wellbore simulation system via a pipeline and is used to input multiphase CO2 into the wellbore simulation system; The measurement system is installed on the outer wall of the wellbore simulation system and is used to detect CO2 leakage parameters and cement sheath change parameters. The processing equipment is connected to the wellbore temperature control system, the wellbore pressure control system, the CO2 phase change system, and the measurement system. It is used to control the CO2 phase change system to adjust the CO2 phase state entering the wellbore simulation system, control the wellbore temperature control system and the wellbore pressure control system to adjust the wellbore temperature and pressure, and control the CO2 phase change system, the wellbore temperature control system, and the wellbore pressure control system to adjust the corrosion parameters. This allows the measurement system to measure CO2 leakage parameter data and cement sheath change parameter data under each phase of CO2, wellbore temperature, wellbore pressure, and corrosion parameters.

2. The system as described in claim 1, characterized in that, The wellbore simulation system includes: casing (12), cement sheath (13), insulation sleeve (15) and stand (16); The sleeve (12) is used to simulate the full-size sleeve of an actual project; The cement ring (13) is set around the casing (12) to simulate the environment around the casing under actual engineering conditions; The insulation sleeve (15) is set on the outside of the cement ring (13) for insulating the cement ring (13); The stand (16) is used to provide a platform for setting up the sleeve (12), the cement ring (13), and the insulation sleeve (15).

3. The system as described in claim 1, characterized in that, The wellbore temperature control system includes: an electric heater (14) and a temperature control module (18); The electric heater (14) is installed inside the casing of the wellbore simulation system to regulate the wellbore temperature; The temperature control module (18) is electrically connected to the electric heater (14) and the processing device (23), and is used to control the temperature of the electric heater (14) according to the instructions of the processing device and send the temperature of the electric heater (14) to the processing device (23).

4. The system as described in claim 1, characterized in that, The wellbore pressure control system includes: a pressure sensor (26), a high-pressure buffer tank (22), and an automatic pressure control pump (24); The pressure sensor (26) is installed on the wellbore simulation system and electrically connected to the processing device (23) for measuring the pressure of CO2 in the wellbore of the wellbore simulation system and sending the pressure of CO2 in the wellbore to the processing device (23); The high-pressure buffer tank (22) is connected to the casing in the measuring wellbore simulation system via an automatic pressure control pump (24). The automatic pressure control pump (24) is electrically connected to the processing device (23). The processing device (23) is used to determine the adjustment command to the automatic pressure control pump (24) based on the CO2 pressure in the wellbore and the target pressure. The automatic pressure control pump (24) controls the high-pressure buffer tank (22) to replenish or absorb CO2 in the casing of the measuring wellbore simulation system to adjust the wellbore pressure.

5. The system as described in claim 1, characterized in that, The CO2 phase change system includes: a visualized supercritical CO2 chamber (5), a visualized liquid CO2 chamber (6), a visualized gaseous CO2 chamber (7), and a storage chamber (8); The visualized supercritical CO2 chamber (5), visualized liquid CO2 chamber (6), and visualized gaseous CO2 chamber (7) are used to store and prepare supercritical CO2, liquid CO2, and gaseous CO2, respectively. The storage chamber (8) is connected to the visualized supercritical CO2 chamber (5), the visualized liquid CO2 chamber (6), the visualized gaseous CO2 chamber (7), and the wellbore simulation system; The visualized supercritical CO2 chamber (5), visualized liquid CO2 chamber (6), and visualized gaseous CO2 chamber (7) are also electrically connected to the processing equipment (23) for discharging single-phase or mixed-phase CO2 into the storage chamber (8) under the control of the processing equipment (23).

6. The system as described in claim 5, characterized in that, Temperature sensors, pressure sensors, and magnetic stirrers are installed in the visualized supercritical CO2 chamber (5), visualized liquid CO2 chamber (6), and visualized gaseous CO2 chamber (7); The temperature sensor and pressure sensor are electrically connected to the processing device and are used to collect the temperature and pressure of CO2 in the visualized supercritical CO2 chamber (5), the visualized liquid CO2 chamber (6), and the visualized gaseous CO2 chamber (7); The magnetic stirrer is used to stir the CO2 in the visualized supercritical CO2 chamber (5), the visualized liquid CO2 chamber (6), and the visualized gaseous CO2 chamber (7).

7. The system as described in claim 2, characterized in that, The measurement system includes: a strain detection module (19), an acoustic wave detection module (20), a bubble detection module (10 / 11), a pressure detection module (17), a gas viscosity detection module (21), and a gas leakage measurement module (32); The strain detection module (19) is used to detect the strain information of the cement ring; The acoustic wave detection module (20) is used to detect the acoustic wave information of the cement ring; The bubble detection module (10 / 11) is used to detect the CO2 leakage rate of the outer wall of the cement ring and whether there are bubbles in the CO2 of the outer wall of the cement ring; The pressure detection module (17) is used to detect the pressure of CO2 leaking from the outer wall of the cement ring; The gas viscosity detection module (21) is used to detect the viscosity of CO2 leaked from the outer wall of the cement ring; The gas leakage measurement module (32) is used to detect the gas composition of the outer wall of the cement ring and the total leakage of CO2.

8. The system as described in claim 1, characterized in that, Also includes: A fluid circulation system, wherein the fluid circulation system includes: a CO2 gas source (1), a valve (2), an air compressor (3), a pressure stabilizing pump (4), an electronic flow meter (28), and a pressure regulating valve (29); The CO2 gas source (1) is used to provide CO2 gas; One end of the valve (2) is connected to the output end of the CO2 gas source (1) and is used to regulate the flow rate of the output CO2 gas; One end of the air compressor (3) is connected to the other end of the valve (2), and the other end of the air compressor (3) is connected to one end of the pressure stabilizing pump (4) for compressing CO2 gas; The other end of the pressure-stabilizing pump (4) is connected to the CO2 phase change system and is used to provide the CO2 phase change system with pressure-stabilized CO2. One end of the electronic flow meter (28) is connected to the output end of the wellbore simulation system, and the other end of the electronic flow meter (28) is connected to one end of the pressure regulating valve (29). The other end of the pressure regulating valve (29) is connected to the recovery end of the CO2 gas source (1). The electronic flow meter (28) is used to control the flow rate of recovered CO2, and the pressure regulating valve (29) is used to adjust the recovery pressure of CO2.

9. The system as described in claim 1, characterized in that, The processing equipment is also used for: The stability of the cement sheath is evaluated based on the changes in cement sheath parameters detected under various wellbore temperatures and pressures.

10. The system as claimed in claim 1, characterized in that, The processing equipment is also used for: The wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state are used as inputs, and the CO2 leakage pressure, CO2 leakage rate, and total CO2 leakage amount in the CO2 leakage parameters are used as outputs. A sample set is constructed based on the CO2 leakage parameters measured by the measurement system under various wellbore temperatures, wellbore pressures, corrosion parameters, and CO2 phase states. A neural network model is trained using the sample set to obtain a leakage prediction model.

11. A method for simulating the measurement of multiphase CO2 leakage along a wellbore, characterized in that, The processing apparatus applicable to any one of claims 1 to 10, the method comprising: The experimental conditions include CO2 phase state, wellbore temperature, wellbore pressure, and corrosion parameters, wherein the corrosion parameters include CO2 ratio and corrosion time. The wellbore temperature control system operates according to the wellbore temperature under the experimental conditions. The wellbore pressure control system operates according to the wellbore pressure under the experimental conditions. The CO2 phase in the CO2 phase change system is controlled to enter the wellbore simulation system according to the CO2 phase state in the experimental conditions. The proportion of CO2 entering the wellbore simulation system is controlled according to the CO2 ratio in the experimental conditions. The experimental duration was controlled according to the corrosion time in the experimental conditions, and CO2 leakage parameter data and cement ring change parameter data were collected when the corrosion time was up. By changing the experimental conditions, multiple sets of CO2 leakage parameter data and cement ring change parameter data were obtained under different experimental conditions.

12. The method as described in claim 11, characterized in that, Also includes: The wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state are used as inputs, and the CO2 leakage pressure, CO2 leakage rate, and total CO2 leakage amount in the CO2 leakage parameters are used as outputs. A sample set is constructed based on the CO2 leakage parameters measured by the measurement system under various wellbore temperatures, wellbore pressures, corrosion parameters, and CO2 phase states. A neural network model is trained using the sample set to obtain a leakage prediction model.

13. A method for predicting multiphase CO2 leakage along a wellbore, characterized in that, include: Obtain the actual wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state; The actual wellbore temperature, wellbore pressure, corrosion time, and CO2 phase state are input into the leakage prediction model to obtain the actual wellbore CO2 leakage pressure, CO2 leakage rate, and total CO2 leakage. The leakage prediction model is trained using the method described in claim 12.

14. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the method according to any one of claims 11 to 13.

15. A computer-readable storage medium storing a computer program, characterized in that, When the computer program is executed by the processor of a computer device, it implements the method of any one of claims 11 to 13.

16. A computer program product, the computer program product comprising a computer program, characterized in that, When the computer program is executed by the processor of the computer device, it implements the method of any one of claims 11 to 13.

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