Gas storage injection and production well mouth lifting prediction method, system, equipment and medium

Abstract

The invention discloses a gas storage injection and production well wellhead lifting prediction method, system and device and a medium, and relates to the technical field of storage well shaft integrity. The method comprises the steps that the thermal expansion coefficient of a target pipe column in the injection and production period of an injection and production well with wellhead lifting to be predicted is determined; according to the cementing strength of the injection and production well with the uplifted wellhead to be predicted, the free casing length of the injection and production well with the uplifted wellhead to be predicted is predicted, and the cementing strength is the cementing strength between a cement sheath cementing surface and a sleeve; and according to the thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath and the length of the free casing, predicting the wellhead lifting height of the injection-production well of which the wellhead lifting is to be predicted. According to the method, the thermal expansion coefficient and the cementing strength of the target tubular column are determined, the factors of temperature and cementing strength are added in the subsequent wellhead lifting height determination process to achieve accurate prediction of wellhead lifting, risks and hidden dangers caused by wellhead lifting are prevented in time, and a wellhead lifting prevention and control method is provided; and safe operation of the gas injection and recovery well is ensured.

Description

Technical Field

[0001] This invention relates to the field of wellbore integrity technology for gas storage wells, and in particular to a method, system, equipment, and medium for predicting wellhead lift in gas storage injection and production wells. Background Technology

[0002] Currently, the construction of gas storage facilities in China is at its peak. However, some gas storage wells have experienced wellhead uplift during operation after commissioning, seriously affecting the safe and stable operation of these wells. In early 2021, a gas storage facility in China experienced wellhead uplift during gas production, with a maximum uplift of 12 cm and an average uplift height of 3.86 cm. After well Su49 was shut down, the uplift dropped from 8.5 cm to 2 cm. However, the mechanism and impact patterns of wellhead uplift in gas storage facilities are not well understood, making it difficult to predict and warn of wellhead uplift during well operation and management, and hindering the development of targeted preventative measures.

[0003] With the increasing importance of wellbore safety monitoring and early warning in the operation of gas storage wells, predicting wellhead lift is crucial. Currently, domestic research mainly focuses on offshore high-temperature gas wells and heavy oil thermal recovery wells, indicating that the length of the free section of the casing significantly affects the wellhead lift. Accurately calculating the length of the free section is key to predicting the wellhead lift. However, cementing in gas storage wells generally returns to the surface. During production, factors such as temperature stress and geostress may cause partial cement sheath failure, leading to the loss of cement sheath constraint on the casing and resulting in free casing. During rapid gas production in gas storage, the high-temperature gas produced heats the wellbore. Under the influence of temperature changes from gas injection and production, ordinary casing expands and elongates under thermal stress. Uneven deformation between the tubing string and the cement sheath weakens the cement sheath-wellbore bonding surface. Under prolonged, multi-cycle loading, this may further lead to debonding of the casing and cement sheath, turning the casing string into free casing, causing wellhead lift due to thermal expansion. Currently, there is a lack of methods for predicting and preventing wellhead uplift mechanisms in gas storage injection and production wells, making it difficult to accurately predict wellhead uplift patterns. There is an urgent need to strengthen our understanding and propose targeted measures for the prevention and control of wellhead uplift. Summary of the Invention

[0004] The technical problem to be solved by this invention is to address the shortcomings of existing technologies. Specifically, it provides a method, system, equipment, and medium for predicting wellhead lift in gas storage injection and production wells, as detailed below:

[0005] 1) In a first aspect, the present invention provides a method for predicting wellhead uplift in gas storage injection and production wells, the specific technical solution of which is as follows:

[0006] Determine the target tubing thermal expansion coefficient during the injection and production period of the injection-production well for which wellhead uplift is to be predicted. The target tubing thermal expansion coefficient includes the thermal expansion coefficient of the casing and the thermal expansion coefficient of the cement sheath.

[0007] The free casing length of the injection-production well to be predicted to rise is predicted based on the bonding strength of the wellhead to be predicted. The bonding strength is the bonding strength between the cement sheath bonding surface and the sleeve.

[0008] The wellhead lift height of the injection-production well to be predicted is determined based on the thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the length of the free casing.

[0009] The beneficial effects of the wellhead lift prediction method for gas storage injection and production wells provided by this invention are as follows:

[0010] The thermal expansion coefficient and bonding strength of the target tubing string were determined. In the subsequent process of determining the wellhead lift, the factors of temperature and bonding strength were incorporated to achieve accurate prediction of wellhead lift, timely prevention of risks and hidden dangers caused by wellhead lift, and proposed prevention and control methods for wellhead lift to ensure the safe operation of injection and production gas wells.

[0011] Based on the above solution, the present invention can be further improved as follows.

[0012] Furthermore, the thermal expansion coefficient of the target tubing is determined as follows:

[0013] The gas flow relationship and the law of conservation of energy determine the target temperature of the tubing corresponding to the target gas flow velocity of the injection-production well to be predicted to rise at the wellhead. Based on the correspondence between the gas flow velocity, the tubing temperature and the thermal expansion coefficient of the tubing, the target thermal expansion coefficient of the tubing corresponding to the target temperature at the target gas flow velocity is determined.

[0014] Furthermore, the process of predicting the wellhead lift height of the injection-production well to be predicted is as follows:

[0015] The thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the target lift height corresponding to the free casing length are determined by the correspondence between the thermal expansion coefficient of the tubing string, the free casing length, and the lift height. The target lift height is then determined as the wellhead lift height of the injection-production well to be predicted for wellhead lift.

[0016] Furthermore, it also includes:

[0017] Based on the wellhead lift height of the injection-production well to be predicted, the critical flow rate at the wellhead is controlled.

[0018] 2) Secondly, the present invention also provides a wellhead lift prediction system for gas storage injection and production wells, the specific technical solution of which is as follows:

[0019] The determination module is used to: determine the target tubing thermal expansion coefficient during the injection and production period of the injection and production well for which wellhead uplift is to be predicted, wherein the target tubing thermal expansion coefficient includes the thermal expansion coefficient of the casing and the thermal expansion coefficient of the cement sheath;

[0020] The calculation module is used to: predict the free casing length of the injection-production well to be predicted to rise based on the bonding strength of the wellhead to be predicted, wherein the bonding strength is the bonding strength between the cement sheath bonding surface and the sleeve.

[0021] The prediction module is used to predict the wellhead lift height of the injection-production well to be predicted based on the thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the length of the free casing.

[0022] Based on the above solution, the present invention can be further improved as follows.

[0023] Furthermore, the thermal expansion coefficient of the target tubing is determined as follows:

[0024] The gas flow relationship and the law of conservation of energy determine the target temperature of the tubing corresponding to the target gas flow velocity of the injection-production well to be predicted to rise at the wellhead. Based on the correspondence between the gas flow velocity, the tubing temperature and the thermal expansion coefficient of the tubing, the target thermal expansion coefficient of the tubing corresponding to the target temperature at the target gas flow velocity is determined.

[0025] Furthermore, the process of predicting the wellhead lift height of the injection-production well to be predicted is as follows:

[0026] The thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the target lift height corresponding to the free casing length are determined by the correspondence between the thermal expansion coefficient of the tubing string, the free casing length, and the lift height. The target lift height is then determined as the wellhead lift height of the injection-production well to be predicted for wellhead lift.

[0027] Furthermore, it also includes:

[0028] The control module is used to control the critical flow rate at the wellhead based on the wellhead lift height of the injection-production well to be predicted.

[0029] 3) In a third aspect, the present invention also provides an electronic device, the electronic device including a processor coupled to a memory, the memory storing at least one computer program, the at least one computer program being loaded and executed by the processor to enable the electronic device to perform any of the above methods.

[0030] 4) In a fourth aspect, the present invention also provides a computer-readable storage medium storing at least one computer program, which is loaded and executed by a processor to enable a computer to implement any of the above methods.

[0031] It should be noted that the beneficial effects of the technical solutions of the second to fourth aspects of the present invention and their corresponding possible implementations can be found in the above description of the technical effects of the first aspect and its corresponding possible implementations, and will not be repeated here. Attached Figure Description

[0032] Other features, objects, and advantages of the invention will become more apparent from the following detailed description of non-limiting embodiments with reference to the accompanying drawings:

[0033] Figure 1 This is one of the flowcharts illustrating a method for predicting wellhead lift in a gas storage injection-production well according to an embodiment of the present invention;

[0034] Figure 2 This is a second schematic flowchart of a method for predicting wellhead lift in a gas storage injection-production well according to an embodiment of the present invention.

[0035] Figure 3 This is a schematic diagram of heat transfer during the gas injection and production process of a gas storage well, which is a method for predicting wellhead lift in a gas storage injection and production well according to an embodiment of the present invention.

[0036] Figure 4 This is a schematic diagram of the wellbore structure of a gas storage injection-production well, which is part of a method for predicting wellhead lift in a gas storage injection-production well according to an embodiment of the present invention.

[0037] Figure 5 This is a schematic diagram of the wellbore temperature field distribution of a gas storage injection-production well under different gas production rates, which is an embodiment of the present invention for predicting wellhead lift of a gas storage injection-production well according to a gas storage wellhead lifting method.

[0038] Figure 6 This is a diagram showing the cementing quality test results of a gas storage injection-production well, based on a gas storage wellhead lift prediction method according to an embodiment of the present invention.

[0039] Figure 7 This is one of the schematic diagrams showing the damage distribution at the lowest end of the cement sheath in a gas storage injection-production well after 300 cycles in a stress range of 7-18 MPa, as part of a gas storage wellhead lift prediction method according to an embodiment of the present invention.

[0040] Figure 8 This is the second schematic diagram of the damage distribution at the lowest end of the cement sheath in a gas storage injection-production well after 300 cycles in a stress range of 7-18 MPa, as part of a gas storage wellhead lift prediction method according to an embodiment of the present invention.

[0041] Figure 9 This is a schematic diagram comparing the measured and simulated wellhead rise height of a gas storage injection-production well under different gas injection and production conditions, which is an embodiment of the present invention for predicting wellhead rise in a gas storage injection-production well according to an embodiment of the present invention.

[0042] Figure 10 This is a structural framework diagram of an electronic device according to the present invention. Detailed Implementation

[0043] To make the objectives, technical solutions, and advantages of the present invention clearer, the embodiments of the present invention will be described in further detail below with reference to the accompanying drawings.

[0044] like Figure 1 Figure 2 as well as Figure 3 As shown in the figure, a method for predicting wellhead lift in a gas storage injection-production well according to an embodiment of the present invention includes the following steps:

[0045] S1, determine the target tubing thermal expansion coefficient during the injection and production period of the injection and production well for which wellhead uplift is to be predicted. The target tubing thermal expansion coefficient includes the thermal expansion coefficient of the casing and the thermal expansion coefficient of the cement sheath.

[0046] S2, predict the free casing length of the injection-production well to be predicted to rise based on the bonding strength of the wellhead to be predicted, wherein the bonding strength is the bonding strength between the cement sheath bonding surface and the sleeve.

[0047] S3, predict the wellhead lift height of the injection-production well to be predicted based on the thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the length of the free casing.

[0048] The beneficial effects of the wellhead lift prediction method for gas storage injection and production wells provided by this invention are as follows:

[0049] The thermal expansion coefficient and bonding strength of the target tubing string were determined. In the subsequent process of determining the wellhead lift, the factors of temperature and bonding strength were incorporated to achieve accurate prediction of wellhead lift, timely prevention of risks and hidden dangers caused by wellhead lift, and proposed prevention and control methods for wellhead lift to ensure the safe operation of injection and production gas wells.

[0050] The process for determining the coefficient of thermal expansion of the target focus is as follows:

[0051] The basic parameter inputs mainly include the well structure of the gas storage, the number of casing openings, the outer diameter of the cement sheath, the inner and outer diameters and depth of the casing in each opening, and the thermal properties (specific heat and thermal conductivity) of the casing, cement sheath and annular protective fluid.

[0052] Prediction of tubing temperature field during injection and production:

[0053] ① Gas flow continuity equation: used to calculate the gas flow velocity at different well depths during injection and production.

[0054]

[0055] In the formula: ρ g The density of the gas is kg / m³. 3 ;v g A is the gas flow velocity, in m / s; g The cross-sectional area of ​​the unit cell is m. 2 , where z is the depth of the gas, in meters.

[0056] ② Quantitative conservation equations are used to calculate the pressure field distribution of gas in the injection-production string at different times during the injection-production process:

[0057]

[0058] In the formula: p g λ is the gas pressure, MPa; g Let r be the coefficient of friction of the gas. pi The diameter of the injection / production tubing is represented by r. ao This indicates the outer diameter of the annular sleeve. Since the density and viscosity of the gas are very low, the frictional resistance between the gas and the sleeve wall is very small and can be ignored.

[0059] ③ Energy conservation equation for injected and extracted gases:

[0060]

[0061] In the formula: u g For the internal energy of the gas, J; h e For gas specific enthalpy, J; β g The gas Joule-Thomson effect coefficient is given in °C / MPa; c g Specific heat of gas, J / (kg·℃); T e Formation temperature, °C, T g For the geothermal gradient, U bg The combined heat transfer coefficient, r, represents the combined heat transfer coefficient of the injection and production tubing. ai U represents the inner diameter of the annular bushing. ge This represents the overall heat transfer coefficient of the annular bushing.

[0062] ④ Energy conservation equations for the annular protective fluid, casing, cement sheath, and formation:

[0063]

[0064] In the formula: ρ e The density of the formation is kg / m³. 3 ;k e C is the thermal conductivity of the formation, ℃ / (W·m);e ρ is the specific heat capacity of the formation, J / (kg·℃); r is the distance from the formation to the production casing, m.

[0065] By combining the above equations, the temperature field at each time step in the entire gas injection and production process can be solved using the finite difference method.

[0066] The methods for determining the length of the free sleeve include:

[0067] ① Interpret the degree of bonding between the cement sheath and the casing through well logging, and evaluate the length of the free casing;

[0068] ② Determine the outcome through numerical simulation:

[0069] Specifically, ① the stress characteristic equations of the casing-cement sheath-formation system assembly are as follows:

[0070]

[0071] This system of equations contains p1 and p. p p2, r p And C, five unknowns, The internal friction angle of the cement ring, r i Representing different radii, B is an empirical number. u f Indicates wellbore displacement, u ce Indicates the displacement of the cement ring, u cp Indicates the displacement of the tubing, u ca This represents the casing displacement, given the casing internal pressure p0 and the initial stress p after cement solidification of the casing-cement sheath-formation system assembly. c Under the condition of far-field stress p3 in the formation, a program written in Fortran can be used to model and solve the stress state, displacement magnitude, and elastic-plastic interface radius of the cement sheath at various points of the casing during the pressurization stage.

[0072] ② The bonding strength between the cement ring and the sleeve was tested through indoor tests. When the shear force on the cement ring is greater than its bonding strength, the cement ring will debond.

[0073] The process of predicting the wellhead lift height of the injection-production well to be predicted is as follows:

[0074] When the free casing is subjected to thermal stress, the entire casing string will undergo axial strain, leading to wellhead lift. The predictive model for wellhead lift can be expressed as:

[0075]

[0076] In the formula, H is the wellhead lift height, m; L is the length of the free casing, m; k cas and k cem, respectively, are the coefficients of thermal expansion of the casing and cement sheath, in °C / m; T is the temperature, in °C, and ΔT represents the difference between the predicted temperature and the formation temperature.

[0077] Furthermore, the thermal expansion coefficient of the target tubing is determined as follows:

[0078] The gas flow relationship and the law of conservation of energy determine the target temperature of the tubing corresponding to the target gas flow velocity of the injection-production well to be predicted to rise at the wellhead. Based on the correspondence between the gas flow velocity, the tubing temperature and the thermal expansion coefficient of the tubing, the target thermal expansion coefficient of the tubing corresponding to the target temperature at the target gas flow velocity is determined.

[0079] Furthermore, the process of predicting the wellhead lift height of the injection-production well to be predicted is as follows:

[0080] The thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the target lift height corresponding to the free casing length are determined by the correspondence between the thermal expansion coefficient of the tubing string, the free casing length, and the lift height. The target lift height is then determined as the wellhead lift height of the injection-production well to be predicted for wellhead lift.

[0081] Furthermore, it also includes:

[0082] Based on the wellhead lift height of the injection-production well to be predicted, the critical flow rate at the wellhead is controlled.

[0083] Through computational simulation, the predicted value of wellhead uplift in injection-production wells can be obtained. Combined with the temperature field calculations during the gas injection and production process in previous steps, the critical injection-production gas flow rate, temperature, and pressure conditions for wellhead uplift can be obtained. For injection-production wells that have not yet experienced wellhead uplift or have only experienced a small uplift, prevention and control measures can be taken by real-time monitoring of the wellhead temperature and controlling the difference between the critical wellhead flow rate and the production pressure to not exceed the critical value that may cause wellhead uplift. For injection-production wells that have already experienced wellhead uplift and have experienced a large uplift, production should be stopped in a timely manner, the wellhead fallback should be monitored, and secondary cementing of the cement sheath should be carried out by perforating and injecting ultrafine cement into the free casing section with poor cementing quality to ensure the safe operation of the injection-production gas well.

[0084] Example 1 mainly includes methods for predicting the temperature field of the tubing string during injection and production, methods for predicting the length of the free casing, methods for predicting wellhead lift in injection and production wells, and methods for preventing and controlling wellhead lift.

[0085] Among them, the tubing temperature field prediction system during injection and production is the core of this invention. It mainly realizes the accurate calculation of the temperature field of the wellbore structure combination such as casing, cement sheath and annular protective fluid during the gas well injection and production process; it mainly includes the gas continuity equation, momentum equation and heat transfer equation.

[0086] Free casing includes casing above the cement surface and casing with poor bonding with the cement sheath that can shift. Its length can be predicted in two ways: ① interpret the bonding degree between the cement sheath and the casing through well logging to evaluate the length of the free casing; ② make a judgment through numerical simulation: numerically simulate the stress distribution of casing-cement sheath-formation under injection and production disturbance, and theoretically judge the bonding state and failure of the cement sheath.

[0087] The wellhead lift prediction method for injection and production wells calculates the cumulative elongation based on the temperature field and the free casing length using the principles of thermoelastic mechanics.

[0088] The main methods for preventing and controlling wellhead uplift include: predicting the critical production conditions for uplift, monitoring the wellhead temperature, triggering an alarm when the critical temperature is reached, and adjusting the gas production flow rate to be lower than the critical flow rate.

[0089] This embodiment uses the SSL-1 well in a gas storage facility as an example to verify the influencing factors of wellhead uplift and the accuracy of the model. The wellbore structure of the SSL-1 well is designed with multiple casing openings. The outer diameter of the cement sheath and the inner and outer diameters and depth of the casing for each opening are as follows: Figure 4 As shown. The thermophysical parameters (specific heat, thermal conductivity) of the casing, cement sheath, and annulus protective fluid are taken as 880, 1880, 4200 J / kg*℃, 15, 1.28, and 0.52 J / kg*℃, respectively. The completed well depth is 5008 m, the maximum well deviation depth is 3532.7 m, the formation temperature is 154℃, and the current formation pressure is 29.54 MPa. Table 1 shows the average gas production rate of the SSL-1 well in a gas storage facility during winter.

[0090] Table 1

[0091] Average gas extraction rate (10,000 cubic meters / day) Mean pressure (MPa) Average outlet gas temperature (°C) 68.42 30.81 65.4

[0092] ① Calculation of gas flow velocity at different well depths during injection and production:

[0093] The gas flow velocity at different well depths is calculated using the continuity equation for gas flow:

[0094]

[0095] In the formula: ρ g The density of the gas is kg / m³. 3 It can be calculated using the classic PR equation; v g Gas velocity, m / s; (converted based on the measured gas extraction rate of 680,000 cubic meters / day) A g The cross-sectional area of ​​the injection / production pipe is m. 2 .

[0096] ② Simulation of the pressure field distribution of gas in the injection / production tubing during injection and production:

[0097] The quantitative conservation equation is used to calculate the pressure field distribution of gas in the injection-production string during the injection-production process:

[0098]

[0099] In the formula: p g λ represents the gas pressure, in MPa; the measured wellhead pressure is 30 MPa. g Let be the friction coefficient of the gas. Since the density and viscosity of the gas are very small, the frictional resistance between the gas and the pipe wall is very small and can be ignored. pi This refers to the inner diameter of the injection / production tubing.

[0100] ③ Energy conservation of injected and extracted gases

[0101]

[0102] Where: β g The gas Joule-Thomson effect coefficient is 3.67℃ / MPa; c g Specific heat of gas, 126 J / (kg·℃); T g Let T be the temperature of the gas, in °C; under initial conditions, the gas temperature is the same as the ambient temperature, and the gas temperature at the bottom of the well is equal to the formation temperature. b The temperature of the tubing string, in °C, is also a variable that needs to be solved in this patent. Under initial conditions, it is the same as the formation ambient temperature; T e Let be the formation temperature, in °C. The formation temperature under initial conditions can be calculated from the geothermal gradient.

[0103] ④ Energy conservation equations for the annular protective fluid, casing, cement sheath, and formation:

[0104]

[0105] In the formula: ρ e The density of the formation is 2360 kg / m³; k e The thermal conductivity of the formation is 1.26 W / (m℃); c e ρ is the specific heat capacity of the formation, 2050 J / (kg·℃); r is the distance from the formation to the production casing, in meters.

[0106] Based on the winter gas production data of SSL-1 over the past five years, and using the average gas production rate and a tubing temperature field prediction model during injection and production, the wellbore temperature field distribution under different gas production rates can be calculated. The figure shows that the wellbore temperature distribution increases with increasing gas production rate. Although the increased gas production rate reduces the heat exchange time between the gas and the wellbore, the increased mass flow rate also increases the heat exchange.

[0107] According to such Figure 5 as well as Figure 6The cementing quality test results shown indicate that the length of the free casing is approximately 280m.

[0108] When the free casing is subjected to thermal stress, the entire casing string will undergo axial strain, leading to wellhead lift. The predictive model for wellhead lift can be expressed as:

[0109]

[0110] In the formula, H is the wellhead lift height, in meters; L is the length of the free casing, i.e., 280 meters; k cas and k cem , respectively, represent the coefficients of thermal expansion of the casing and cement sheath, in °C / m; T represents temperature, in °C. The coefficient of thermal expansion of N80 steel pipe is 12 × 10⁻⁶ / ℃, and the coefficient of thermal expansion of oil well cement is 10 × 10⁻⁶ / ℃.

[0111] Based on the temperature field prediction results of the injection and production tubing and the ambient temperature, the wellhead lift caused by the free casing at different gas production rates can be calculated as follows: Figure 7 , Figure 8 as well as Figure 9 As shown.

[0112] ⑤ Prevention and control of wellhead rise

[0113] Through calculation and simulation, the predicted value of wellhead lift can be obtained. Combined with the calculation of the temperature field during the gas injection and production process in the previous steps, the critical gas injection and production flow rate at which wellhead lift occurs can be obtained.

[0114] For injection-production wells that have not yet experienced wellhead uplift or have only experienced a small uplift, prevention and control measures can be taken by real-time monitoring of the wellhead temperature and controlling the critical flow rate and production pressure difference at the wellhead to not exceed the critical value that may cause wellhead uplift. For injection-production wells that have experienced wellhead uplift and have experienced a large uplift, production should be stopped in a timely manner, the wellhead fallback should be monitored, and secondary cementing of the cement sheath should be carried out by perforating and injecting ultrafine cement into the free casing section with poor cementing quality to ensure the safe operation of the injection-production gas well.

[0115] This invention establishes a wellbore temperature field prediction model during the gas production process and studies the shear stress changes between the tubing string and the cement sheath. This provides a theoretical basis for clarifying the wellhead lift mechanism and influencing law of gas storage wells under alternating stress, thereby achieving accurate prediction of wellhead lift, preventing wellhead lift, and preventing and controlling wellhead lift in injection and production wells. It can provide guidance for the integrity evaluation and management of gas storage wells, timely prevent and control the risks and hidden dangers caused by wellhead lift, and ensure the safe operation of gas storage injection and production wells.

[0116] This invention also provides a wellhead lift prediction system for gas storage injection and production wells, the specific technical solution of which is as follows:

[0117] The determination module is used to: determine the target tubing thermal expansion coefficient during the injection and production period of the injection and production well for which wellhead uplift is to be predicted, wherein the target tubing thermal expansion coefficient includes the thermal expansion coefficient of the casing and the thermal expansion coefficient of the cement sheath;

[0118] The calculation module is used to: predict the free casing length of the injection-production well to be predicted to rise based on the bonding strength of the wellhead to be predicted, wherein the bonding strength is the bonding strength between the cement sheath bonding surface and the sleeve.

[0119] The prediction module is used to predict the wellhead lift height of the injection-production well to be predicted based on the thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the length of the free casing.

[0120] Furthermore, the thermal expansion coefficient of the target tubing is determined as follows:

[0121] The gas flow relationship and the law of conservation of energy determine the target temperature of the tubing corresponding to the target gas flow velocity of the injection-production well to be predicted to rise at the wellhead. Based on the correspondence between the gas flow velocity, the tubing temperature and the thermal expansion coefficient of the tubing, the target thermal expansion coefficient of the tubing corresponding to the target temperature at the target gas flow velocity is determined.

[0122] Furthermore, the process of predicting the wellhead lift height of the injection-production well to be predicted is as follows:

[0123] The thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the target lift height corresponding to the free casing length are determined by the correspondence between the thermal expansion coefficient of the tubing string, the free casing length, and the lift height. The target lift height is then determined as the wellhead lift height of the injection-production well to be predicted for wellhead lift.

[0124] Furthermore, it also includes:

[0125] The control module is used to control the critical flow rate at the wellhead based on the wellhead lift height of the injection-production well to be predicted.

[0126] In the above embodiments, although the steps are numbered S1, S2, etc., they are only specific embodiments given by the present invention. Those skilled in the art can adjust the execution order of S1, S2, etc. according to the actual situation, which is also within the protection scope of the present invention. It can be understood that in some embodiments, some or all of the above embodiments may be included.

[0127] It should be noted that the beneficial effects of the wellhead lift prediction system for gas storage injection-production wells provided in the above embodiments are the same as those of the wellhead lift prediction method for gas storage injection-production wells described above, and will not be repeated here. Furthermore, the system provided in the above embodiments is only illustrated by the division of the above functional modules. In practical applications, the above functions can be assigned to different functional modules as needed, that is, the system can be divided into different functional modules according to the actual situation to complete all or part of the functions described above. In addition, the system and method embodiments provided in the above embodiments belong to the same concept, and their specific implementation process is detailed in the method embodiments, and will not be repeated here.

[0128] like Figure 10 As shown, an electronic device 300 according to an embodiment of the present invention includes a processor 320 coupled to a memory 310. The memory 310 stores at least one computer program 330, which is loaded and executed by the processor 320 to enable the electronic device 300 to implement any of the above-mentioned methods. Specifically:

[0129] The electronic device 300 can vary considerably due to differences in configuration or performance. It may include one or more processors 320 (Central Processing Units, CPUs) and one or more memories 310. The memories 310 store at least one computer program 330, which is loaded and executed by the processors 320 to enable the electronic device 300 to implement the wellhead lift prediction method for gas storage injection-production wells provided in the above embodiments. Of course, the electronic device 300 may also have wired or wireless network interfaces, a keyboard, and input / output interfaces for input and output. It may also include other components for implementing device functions, which will not be elaborated upon here.

[0130] An embodiment of the present invention provides a computer-readable storage medium storing at least one computer program, which is loaded and executed by a processor to enable a computer to implement any of the above-described methods.

[0131] Alternatively, the computer-readable storage medium may be a read-only memory (ROM), a random access memory (RAM), a compact disc read-only memory (CD-ROM), magnetic tape, a floppy disk, and an optical data storage device, etc.

[0132] In an exemplary embodiment, a computer program product or computer program is also provided, which includes computer instructions stored in a computer-readable storage medium. A processor of an electronic device reads the computer instructions from the computer-readable storage medium and executes the computer instructions, causing the electronic device to perform any of the methods described above.

[0133] It should be noted that the terms "first," "second," etc., used in the specification and claims of this application are used to distinguish similar objects and represent a limitation on a specific order or sequence. Where appropriate, the order of use for similar objects can be interchanged so that the embodiments of this application described herein can be implemented in an order other than that shown or described.

[0134] Those skilled in the art will recognize that this invention can be implemented as a system, method, or computer program product. Therefore, this disclosure can be specifically implemented in the following forms: it can be entirely hardware, entirely software (including firmware, resident software, microcode, etc.), or a combination of hardware and software, generally referred to herein as a "circuit," "module," or "system." Furthermore, in some embodiments, this invention can also be implemented as a computer program product in one or more computer-readable media containing computer-readable program code.

[0135] Any combination of one or more computer-readable media may be used. A computer-readable medium can be a computer-readable signal medium or a computer-readable storage medium. A computer-readable storage medium can be, for example, but not limited to, an electrical, magnetic, optical, electromagnetic, infrared, or semiconductor system, apparatus, or device, or any combination thereof. More specific examples (a non-exhaustive list) of computer-readable storage media include: an electrical connection having one or more wires, a portable computer disk, a hard disk, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), optical fiber, portable compact disk read-only memory (CD-ROM), optical storage device, magnetic storage device, or any suitable combination thereof. In this document, a computer-readable storage medium can be any tangible medium that contains or stores a program that can be used by or in connection with an instruction execution system, apparatus, or device.

[0136] Although embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Those skilled in the art can make changes, modifications, substitutions and variations to the above embodiments within the scope of the present invention.

Claims

1. A method for predicting wellhead lift in gas storage injection and production wells, characterized in that, include: Determine the target tubing thermal expansion coefficient during the injection and production period of the injection-production well for which wellhead uplift is to be predicted. The target tubing thermal expansion coefficient includes the thermal expansion coefficient of the casing and the thermal expansion coefficient of the cement sheath. The free casing length of the injection-production well to be predicted to rise is predicted based on the bonding strength of the wellhead to be predicted. The bonding strength is the bonding strength between the cement sheath bonding surface and the sleeve. The wellhead lift height of the injection-production well to be predicted is determined based on the thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the length of the free casing.

2. The method for predicting wellhead lift in a gas storage injection-production well according to claim 1, characterized in that, The method for determining the thermal expansion coefficient of the target tubing is as follows: The gas flow relationship and the law of conservation of energy determine the target temperature of the tubing corresponding to the target gas flow velocity of the injection-production well to be predicted to rise at the wellhead. Based on the correspondence between the gas flow velocity, the tubing temperature and the thermal expansion coefficient of the tubing, the target thermal expansion coefficient of the tubing corresponding to the target temperature at the target gas flow velocity is determined.

3. The method for predicting wellhead lift in a gas storage injection-production well according to claim 1, characterized in that, The process of predicting the wellhead lift height of the injection-production well to be predicted is as follows: The thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the target lift height corresponding to the free casing length are determined by the correspondence between the thermal expansion coefficient of the tubing string, the free casing length, and the lift height. The target lift height is then determined as the wellhead lift height of the injection-production well to be predicted for wellhead lift.

4. The method for predicting wellhead lift in a gas storage injection-production well according to claim 1, characterized in that, Also includes: Based on the wellhead lift height of the injection-production well to be predicted, the critical flow rate at the wellhead is controlled.

5. A wellhead lift prediction system for gas storage injection and production wells, characterized in that, include: The determination module is used to: determine the target tubing thermal expansion coefficient during the injection and production period of the injection and production well for which wellhead uplift is to be predicted, wherein the target tubing thermal expansion coefficient includes the thermal expansion coefficient of the casing and the thermal expansion coefficient of the cement sheath; The calculation module is used to: predict the free casing length of the injection-production well to be predicted to rise based on the bonding strength of the wellhead to be predicted, wherein the bonding strength is the bonding strength between the cement sheath bonding surface and the sleeve. The prediction module is used to predict the wellhead lift height of the injection-production well to be predicted based on the thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the length of the free casing.

6. The wellhead lift prediction system for gas storage injection and production wells according to claim 5, characterized in that, The method for determining the thermal expansion coefficient of the target tubing is as follows: The gas flow relationship and the law of conservation of energy determine the target temperature of the tubing corresponding to the target gas flow velocity of the injection-production well to be predicted to rise at the wellhead. Based on the correspondence between the gas flow velocity, the tubing temperature and the thermal expansion coefficient of the tubing, the target thermal expansion coefficient of the tubing corresponding to the target temperature at the target gas flow velocity is determined.

7. A wellhead lift prediction system for gas storage injection and production wells according to claim 5, characterized in that, The process of predicting the wellhead lift height of the injection-production well to be predicted is as follows: The thermal expansion coefficient of the casing, the thermal expansion coefficient of the cement sheath, and the target lift height corresponding to the free casing length are determined by the correspondence between the thermal expansion coefficient of the tubing string, the free casing length, and the lift height. The target lift height is then determined as the wellhead lift height of the injection-production well to be predicted for wellhead lift.

8. A wellhead lift prediction system for gas storage injection and production wells according to claim 5, characterized in that, Also includes: The control module is used to control the critical flow rate at the wellhead based on the wellhead lift height of the injection-production well to be predicted.

9. An electronic device, characterized in that, The electronic device includes a processor coupled to a memory storing at least one computer program, which is loaded and executed by the processor to enable the electronic device to perform the method as described in any one of claims 1 to 4.

10. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores at least one computer program, which is loaded and executed by a processor to enable the computer to perform the method as described in any one of claims 1 to 4.

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