A method for correcting abnormal pressure buildup test data of a deepwater high-permeability gas well

Abstract

The present application relates to the technical field of oil and gas exploitation, more particularly, to a deepwater high-permeability gas well abnormal pressure buildup test data correction method, the method comprises the following steps: analyzing test data to obtain the reason for pressure buildup data abnormality as the combined influence of temperature drop and high-permeability reservoir; obtaining pressure data at the upper and lower pressure gauges to construct a pressure profile model, and obtaining temperature data at the upper and lower pressure gauges to construct a temperature profile model at different time points at the pressure gauges; constructing a temperature-pressure coupling model according to the pressure profile model and the temperature profile model; using the temperature-pressure coupling model to correct the data of the lower pressure gauge point by point to the pressure buildup data at the middle part of the reservoir; and correcting the pressure buildup data at the middle part of the reservoir point by point back to the lower pressure gauge. The method of the present application can correct the pressure buildup data with an abnormal slow downward trend to a normal slow upward trend, and is used for well test interpretation and analysis to obtain formation and wellbore parameters.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas extraction, and more particularly to a method for correcting abnormal pressure recovery well test data of a deepwater high-permeability gas well. Background Art

[0002] Pressure buildup testing is the primary method used in exploratory and production wells to determine the flow capacity of subsurface fluids within the formation and to determine formation parameters and wellbore accessory characteristics. It plays an irreplaceable role in determining formation coefficients, permeability, formation temperature and pressure, and skin coefficient. Under normal circumstances, pressure buildup data exhibits a monotonically increasing curve, with an initial rapid increase followed by a gradual slowing down. DST testing of deepwater, high-permeability gas wells is challenging, requiring high equipment performance and high test costs. Pressure buildup test data is crucial, and failure to meet quality standards can result in significant financial losses.

[0003] Well A, a deepwater, high-permeability gas well in the western South China Sea, encountered a buried-hill granite reservoir. The well is located at a water depth of 1833 m, with the central reservoir at 2883 m. The pressure gauge was tested at a depth of 2662 m, 221 m from the reservoir. Well logging interpretation indicates a fracture-pore reservoir with an effective thickness of 85.2 m, a porosity of 9.3%, and a gas saturation of 82.6%. Core data from the well confirm the presence of fractures in the reservoir. Initial DST testing of Well A involved a four-stage operation system, resulting in a gas production of 26.2 × 10 4 m 3 / d to 129.4×10 4 m 3 / d, the production differential pressure decreased from 0.23MPa to 0.11MPa. As the test production increased, the production differential pressure decreased, indicating that the reservoir contamination was gradually relieved. The first shut-in (downhole test valve shut-in) lasted for 24.5 hours, followed by 3 hours of production at a gas production rate of 77×104m3 / d, and then the well was shut-in again for 7 hours (wellhead shut-in). The second opening and three-level working system produced 26×10 4 m 3 / d to 65×10 4 m 3 / d. The productivity test of Well A went smoothly, but an abnormality occurred during the shut-in pressure recovery phase. The downhole pressure gauge data showed a slow downward trend 9 minutes after shutting in (normally a slow upward trend), with a total decrease of 0.01 MPa ( Figure 3 ), resulting in the missing of pressure derivative curve in the double logarithmic curve of well test interpretation ( Figure 2), making this abnormal pressure data difficult to interpret through well testing. During the DST test of Well A, the pressure trends of the four downhole pressure gauges (two upper pressure gauges at 2642m and two lower pressure gauges at 2663m) were consistent, ruling out the possibility of pressure gauge failure. Furthermore, the well was tested in two shut-in sections (the first section involved closing the downhole test valve, and the second section involved shutting the wellhead). The pressure trends in both sections were consistent, and communication with on-site personnel confirmed that no natural gas leaks were detected after the well was shut in, thus ruling out the possibility of leakage after well closure.

[0004] There are three common processing methods for the above abnormal pressure data: (1) Considering the impact of bottom hole liquid accumulation on the measured value at the pressure gauge, the measured pressure value is corrected for liquid accumulation. (2) Considering the impact of temperature change on the position of the pressure gauge, the wire expansion and contraction amount is corrected. (3) Lower the pressure gauge to the middle of the reservoir and re-perform the DST test. Combined with the actual test data calculation and analysis of the well, in method (1), the test process is high in gas production and no water production, there should be no obvious liquid accumulation in the well, and there is no basis for correction. In method (2), the correction range of the wire expansion and contraction amount is limited, and the pressure data still shows a downward trend. In method (3), the pressure gauge is lowered to the middle of the reservoir for re-testing, which will incur additional costs. Existing processing methods are either difficult to solve the problem of pressure anomalies or require huge costs for re-testing. Summary of the Invention

[0005] In order to overcome the problem that the above-mentioned processing methods for abnormal pressure data in the prior art are difficult to solve the problem of pressure abnormality or require high costs for retesting, the present invention provides a method for correcting abnormal pressure recovery test data of deepwater high permeability gas wells.

[0006] To solve the above technical problems, the present invention adopts a technical solution: a method for correcting abnormal pressure recovery test data of a deepwater high permeability gas well, comprising the following steps:

[0007] S1: Analyze the test data and find that the abnormal pressure recovery data is caused by the combined effects of large temperature drop and high reservoir permeability;

[0008] S2: Obtaining pressure data at the upper pressure gauge and the lower pressure gauge, and constructing pressure profile models of the pressure gauges at different time points and different temperature gradients based on the obtained pressure data at the upper pressure gauge and the lower pressure gauge; obtaining temperature data at the upper pressure gauge and the lower pressure gauge, and constructing temperature profile models of the pressure gauges at different time points based on the obtained temperature data at the upper pressure gauge and the lower pressure gauge;

[0009] S3: constructing a temperature-pressure coupling model according to the pressure profile model and the temperature profile model;

[0010] S4: using the temperature-pressure coupling model to correct the data of the lower pressure gauge point by point to the pressure recovery data at the middle of the reservoir;

[0011] S5: The pressure recovery data corrected to the middle of the reservoir is back-calibrated point by point to the lower pressure gauge.

[0012] Preferably, in step S2, constructing a pressure profile model at the pressure gauge under different temperature gradients at different times includes the following steps:

[0013] S21: Calculating the pressure difference between the upper pressure gauge and the lower pressure gauge at the same time;

[0014] S22: Divide the pressure difference by the vertical depth difference between the upper pressure gauge and the lower pressure gauge to obtain the pressure gradient between the upper pressure gauge and the lower pressure gauge at a certain moment when the shut-in pressure is restored.

[0015] Preferably, the pressure gradient is expressed as follows:

[0016]

[0017] Where G1t(i) is the pressure gradient between the upper and lower pressure gauges at a certain moment, and its unit is MPa / 100m; P 上 t(i) is the pressure value at the upper pressure gauge at a certain moment, and its unit is MPa; P 下 t(i) is the pressure value at the lower pressure gauge at a certain moment, and its unit is MPa; H 上 is the vertical depth of the upper pressure gauge, in m, H 下 is the vertical depth of the lower pressure gauge, in m.

[0018] Preferably, in step S2, constructing the temperature profile model at different times at the pressure gauge specifically includes discretizing the wellbore into multiple small sections and calculating the gas temperature at the outlet of each section:

[0019]

[0020] For the stratigraphic section, For the atmosphere and seawater sections, A is calculated using the atmosphere and seawater section heat transfer model; where T out is the gas temperature at the outlet, K; T eout is the gas temperature at the outlet of the previous section, its unit is K; M is the number of moles of gas, its unit is mol; Z in is the well depth at the entrance, in m; Z out is the well depth at the outlet, in m; v m is the fluid velocity in the wellbore, and its unit is m / s; T inis the gas temperature at the inlet, K; T ein is the gas temperature at the inlet and outlet of the previous section, in K; c p is the specific heat capacity of the fluid, its unit is J / (kg·K); D i is the Joule-Thomson effect coefficient, dimensionless; g is the acceleration due to gravity, its unit is m / s 2 ; r to is the outer radius of the oil pipe, in m; U to is the total heat transfer coefficient of the wellbore below the mudline, and its unit is W / (m 2 ·K); k e is the formation heat transfer coefficient, and its unit is W / (m 2 ·k); f(t) is the dimensionless transient heat transfer function, which is dimensionless; p is the wellbore pressure, whose unit is Pa; θ is the wellbore inclination angle, whose unit is degree; z is the depth based on the mudline, whose unit is m.

[0021] Preferably, in step S3, after constructing the pressure profile model and the temperature profile model, it is necessary to establish the continuity equation, the motion equation and the energy equation for solution; the temperature-pressure coupling model is solved semi-analytically using a numerical calculation method, that is, the equation group is discretized by difference, and the Gaussian elimination method is used to iteratively solve the parameters of each node.

[0022] Preferably, the temperature-pressure coupling model is constructed as follows:

[0023] Continuity equation

[0024]

[0025] equations of motion

[0026]

[0027] Energy equation

[0028]

[0029] Boundary conditions: T wh =C1,p wh =C2; where v wh is the wellhead fluid velocity, its unit is m 3 / s;T wh is the wellhead temperature, its unit is K; p wh is the wellhead pressure, its unit is Pa; ρ is the fluid density, its unit is kg·m -3 ; t is time, its unit is s; v is fluid velocity, its unit is m / s; p2 is the pressure drop loss in the wellbore, its unit is Pa; f is the wellbore friction factor, dimensionless; d is the wellbore outer diameter, its unit is cm; C vis the constant pressure specific heat of the wellbore fluid, its unit is J / (kg·℃); T is the temperature of the fluid in the wellbore, its unit is K; T e is the fluid temperature outside the wellbore, and its unit is K.

[0030] Preferably, in step S4, during the shut-in pressure recovery period, at a certain moment, the pressure gradient G2t(i) from the lower pressure gauge to the middle of the reservoir is approximately G1t(i), and the pressure in the middle of the reservoir satisfies the following formula:

[0031]

[0032] Where, P 储 t(i) is the reservoir center pressure at a certain moment, in MPa; H 储 is the vertical depth of the middle part of the reservoir, and its unit is m.

[0033] Preferably, in step S5, the pressure recovery data corrected to the middle of the reservoir is back-calibrated to the lower pressure gauge, and the corrected normal pressure recovery value at the lower pressure gauge satisfies the following formula:

[0034] P′ 下 t(i)=P 储 t(i)-P 储 t(p max )+P 下 t(p max )

[0035] Where P′ 下 t(i) is the corrected pressure value of the lower pressure gauge, in MPa; P 下 t(p max ) is the maximum value of the pressure recovery of the lower pressure gauge, and its unit is MPa; P 储 t(p max ) is the pressure value in the middle of the reservoir corresponding to the moment when the pressure of the lower pressure gauge recovers to the highest level, and its unit is MPa.

[0036] Preferably, in step S1, when the pressure change characteristics during the shut-in recovery period of the deepwater high-permeability gas well are a, b, and c, the abnormal pressure recovery data is caused by the combined effects of a large temperature drop and high reservoir permeability;

[0037] a. The bottom temperature of deepwater gas wells is low. After shutting in the well, the temperature inside the tubing string drops, and the gas static pressure gradient increases, causing the measured pressure at the pressure gauge to drop.

[0038] b. The pressure of a high-permeability gas well recovers rapidly at the initial stage of shut-in, quickly approaching the reservoir static pressure, and then recovers slowly;

[0039] c、When the rate of formation supply pressure recovery is less than the rate of pressure affected by temperature drop, the pressure gauge shows a slow downward trend.

[0040] Preferably, after the step S5, it further comprises a step S6: well test interpretation on the corrected pressure recovery data, and finally obtaining formation parameters and wellbore parameters through analysis on the corrected pressure data, the formation parameters including reservoir static pressure, physical property, deliverability, channeling coefficient and elastic storage ratio, and the wellbore parameters including well storage coefficient and skin factor.

[0041] Compared with the prior art, the method has the beneficial effects that: the method of the application uses the upper pressure gauge, the measured temperature data and pressure data of the lower pressure gauge to respectively establish a temperature profile model and a pressure profile model, obtains a temperature pressure coupling model at different times through coupling of the temperature profile model and the pressure profile model, and corrects the lower pressure gauge data point by point to the middle part of the reservoir through the temperature pressure coupling model, so that the pressure recovery data with an abnormal slow downward trend can be corrected to a normal slow upward trend, and used for well test interpretation and analysis to obtain formation and wellbore parameters. BRIEF DESCRIPTION OF DRAWINGS

[0042] Figure 1 is a flow chart of the method for correcting abnormal pressure recovery well test data of a water high-permeability gas well of the application;

[0043] Figure 2 is a pressure gradient calculated by the temperature curve at different times of the pressure gauge and the temperature pressure coupling model;

[0044] Figure 3 is a comparison chart of the lower pressure gauge pressure data before and after correction;

[0045] Figure 4 is a comparison chart of the well test interpretation double logarithmic curves before and after correction of the pressure recovery data. DETAILED DESCRIPTION

[0046] The technical solutions of the application will be further described in detail below with specific embodiments and in combination with the drawings:

[0047] Embodiment 1

[0048] As shown in 1, a method for correcting abnormal pressure recovery well test data of a deepwater high-permeability gas well, comprising the following steps:

[0049] S1: analyzing test data to obtain the reason for abnormal pressure recovery data as the combined effects of temperature drop and high permeability of the reservoir;

[0050] S2: Obtain pressure data at the upper and lower pressure gauges, and construct pressure profile models at the pressure gauges at different time points and different temperature gradients based on the obtained pressure data at the upper and lower pressure gauges; obtain temperature data at the upper and lower pressure gauges, and construct temperature profile models at the pressure gauges at different time points based on the obtained temperature data at the upper and lower pressure gauges;

[0051] S3: Construct a temperature-pressure coupling model based on the pressure profile model and the temperature profile model;

[0052] S4: Using the temperature-pressure coupling model, the data of the lower pressure gauge is corrected point by point to the pressure recovery data in the middle of the reservoir;

[0053] S5: The pressure recovery data corrected to the middle of the reservoir is back-calibrated point by point to the lower pressure gauge.

[0054] It should be noted that in step S1, when the pressure change characteristics during the shut-in recovery period of a deepwater high-permeability gas well are a, b, and c, the abnormal pressure recovery data is caused by the combined effects of a large temperature drop and high reservoir permeability;

[0055] a. The bottom temperature of deepwater gas wells is low. After shutting in the well, the temperature inside the tubing string drops, and the gas static pressure gradient increases, causing the measured pressure at the pressure gauge to drop.

[0056] b. The pressure of a high-permeability gas well recovers rapidly at the initial stage of shut-in, quickly approaching the reservoir static pressure, and then recovers slowly;

[0057] c. When the pressure recovery rate due to formation recharge is lower than the rate at which pressure is affected by temperature drop, the pressure gauge will show a slow downward trend.

[0058] In one implementation, Well A experienced a bottomhole temperature as low as 2°C to 5°C, a geothermal gradient as high as 6°C / 100m, and a pressure gauge temperature that dropped from 85°C to 73°C after shutting in. The reservoir permeability of the well was 160 mD, and the pressure peaked after only nine minutes of shut-in before beginning to decline. These two factors combined to produce the pressure variations characteristically described by a, b, and c during the shut-in recovery period of a deepwater, high-permeability gas well.

[0059] Example 2

[0060] This embodiment 2 is similar to embodiment 1, except that, in step S2, constructing a pressure profile model at different times and different temperature gradients at the pressure gauge includes the following steps:

[0061] S21: Calculate the pressure difference between the upper pressure gauge and the lower pressure gauge at the same time;

[0062] S22: Divide the vertical depth difference between the upper pressure gauge and the lower pressure gauge by the pressure difference to obtain the pressure gradient between the upper pressure gauge and the lower pressure gauge at a certain moment when the shut-in pressure is restored.

[0063] Preferably, the expression of the pressure gradient is as follows:

[0064]

[0065] Where G1t(i) is the pressure gradient between the upper and lower pressure gauges at a certain moment, and its unit is MPa / 100m; P 上 t(i) is the pressure value at the pressure gauge at a certain moment, and its unit is MPa; P 下 t(i) is the pressure value at the pressure gauge at a certain moment, and its unit is MPa; H 上 is the vertical depth of the upper pressure gauge, in m, H 下 It is the vertical depth of the lower pressure gauge, and its unit is m.

[0066] In step S2, constructing the temperature profile model at different times at the pressure gauge specifically includes discretizing the wellbore into multiple small segments and calculating the gas temperature at the outlet of each segment:

[0067]

[0068] For the stratigraphic section, For the atmosphere and seawater sections, A is calculated using the atmosphere and seawater section heat transfer model; where T out is the gas temperature at the outlet, K; T eout is the gas temperature at the outlet of the previous section, its unit is K; M is the number of moles of gas, its unit is mol; Z in is the well depth at the entrance, in m; Z out is the well depth at the outlet, in m; v m is the fluid velocity in the wellbore, and its unit is m / s; T in is the gas temperature at the inlet, K; T ein is the gas temperature at the inlet and outlet of the previous section, in K; c p is the specific heat capacity of the fluid, its unit is J / (kg·K); D i is the Joule-Thomson effect coefficient, dimensionless; g is the acceleration due to gravity, its unit is m / s 2 ; r to is the outer radius of the oil pipe, in m; U to is the total heat transfer coefficient of the wellbore below the mudline, and its unit is W / (m 2 ·K); k e is the formation heat transfer coefficient, and its unit is W / (m 2·k); f(t) is the dimensionless transient heat transfer function, which is dimensionless; p is the wellbore pressure, whose unit is Pa; θ is the wellbore inclination angle, whose unit is degree; z is the depth based on the mudline, whose unit is m.

[0069] In addition, in step S3, after constructing the pressure profile model and the temperature profile model, it is necessary to establish the continuity equation, the motion equation, and the energy equation for solution; the temperature-pressure coupling model is solved semi-analytically using numerical calculation methods, that is, the equation group is discretized by difference, and the Gaussian elimination method is used to iteratively solve the parameters of each node.

[0070] Among them, the temperature-pressure coupling model is constructed as follows:

[0071] Continuity equation

[0072]

[0073] equations of motion

[0074]

[0075] Energy equation

[0076]

[0077] Boundary conditions: T wh =C1,p wh =C2; where v wh is the wellhead fluid velocity, its unit is m 3 / s;T wh is the wellhead temperature, its unit is K; p wh is the wellhead pressure, its unit is Pa; ρ is the fluid density, its unit is kg·m -3 ; t is time, its unit is s; v is fluid velocity, its unit is m / s; p2 is the pressure drop loss in the wellbore, its unit is Pa; f is the wellbore friction factor, dimensionless; d is the wellbore outer diameter, its unit is cm; C v is the constant pressure specific heat of the wellbore fluid, its unit is J / (kg·℃); T is the temperature of the fluid in the wellbore, its unit is K; T e is the fluid temperature outside the wellbore, and its unit is K.

[0078] In addition, in step S4, during the shut-in pressure recovery period, at a certain moment, the pressure gradient G2t(i) from the pressure gauge to the middle of the reservoir is approximately G1t(i), and the pressure in the middle of the reservoir satisfies the following formula:

[0079]

[0080] Where, P 储t(i) is the reservoir center pressure at a certain moment, in MPa; H 储 is the vertical depth of the middle part of the reservoir, and its unit is m.

[0081] Among them, due to the high test production of the well, it is difficult to convert the flow pressure data during the productivity test phase. In order to reduce the error caused by the flow pressure conversion, in step S5, the pressure recovery data corrected to the middle of the reservoir is back-calibrated to the lower pressure gauge (such as Figure 3 The normal pressure recovery value after correction at the lower pressure gauge satisfies the following formula:

[0082] P′ 下 t(i)=P 储 t(i)-P 储 t(p max )+P 下 t(p max )

[0083] Where P′ 下 t(i) is the corrected pressure value of the lower pressure gauge, and its unit is MPa; P 下 t(p max ) is the maximum value of the pressure restored by the lower pressure gauge, and its unit is MPa; P 储 t(p max ) is the pressure value in the middle of the reservoir corresponding to the moment when the pressure of the lower pressure gauge recovers to the highest level, and its unit is MPa.

[0084] Example 3

[0085] Example 3 is similar to Examples 1 and 2, except that after step S5, it further includes step S6: performing a well test interpretation on the corrected pressure buildup data. The corrected lower pressure gauge pressure data returns to normal, the flow phase of the pressure derivative curve is complete, and it shows an obvious downward "concave" fracture feature, which is consistent with the fracture formation characteristics (such as Figure 4 The corrected pressure data are analyzed to obtain formation and wellbore parameters (Table 1 below). Formation parameters include reservoir static pressure, physical properties, production capacity, crossflow coefficient, and elastic energy storage ratio. Wellbore parameters include well storage coefficient and skin coefficient.

[0086] Table 1 Comparison of well test interpretation results of pressure buildup data before and after correction

[0087]

[0088] Obviously, the above embodiments of the present invention are merely examples for the purpose of clearly illustrating the present invention, and are not intended to limit the embodiments of the present invention. Those skilled in the art will appreciate that other variations or modifications can be made based on the above description. It is not necessary and impossible to enumerate all embodiments here. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention shall be included within the scope of protection of the claims of the present invention.

Claims

1. A method for correcting abnormal pressure recovery test data of deepwater high permeability gas wells, characterized by: The following steps are involved: S1: Analyze the test data and find that the abnormal pressure recovery data is caused by the combined effects of large temperature drop and high reservoir permeability; S2: Obtaining pressure data at the upper pressure gauge and the lower pressure gauge, and constructing pressure profile models of the pressure gauges at different time points and different temperature gradients based on the obtained pressure data at the upper pressure gauge and the lower pressure gauge; obtaining temperature data at the upper pressure gauge and the lower pressure gauge, and constructing temperature profile models of the pressure gauges at different time points based on the obtained temperature data at the upper pressure gauge and the lower pressure gauge; S3: constructing a temperature-pressure coupling model according to the pressure profile model and the temperature profile model; S4: using the temperature-pressure coupling model to correct the data of the lower pressure gauge point by point to the pressure recovery data at the middle of the reservoir; S5: The pressure recovery data corrected to the middle of the reservoir is back-calibrated point by point to the lower pressure gauge.

2. The method for correcting abnormal pressure recovery test data of deepwater high permeability gas wells according to claim 1 is characterized in that: In step S2, constructing a pressure profile model at the pressure gauge under different temperature gradients at different times includes the following steps: S21: Calculating the pressure difference between the upper pressure gauge and the lower pressure gauge at the same time; S22: Divide the pressure difference by the vertical depth difference between the upper pressure gauge and the lower pressure gauge to obtain the pressure gradient between the upper pressure gauge and the lower pressure gauge at a certain moment when the shut-in pressure is restored.

3. The method for correcting abnormal pressure buildup test data of deepwater high permeability gas wells according to claim 2 is characterized in that: The expression of the pressure gradient is as follows: Where G1t(i) is the pressure gradient between the upper and lower pressure gauges at a certain moment, and its unit is MPa / 100m; P 上 t(i) is the pressure value at the upper pressure gauge at a certain moment, and its unit is MPa; P 下 t(i) is the pressure value at the lower pressure gauge at a certain moment, and its unit is MPa; H 上 is the vertical depth of the upper pressure gauge, in m, H 下 is the vertical depth of the lower pressure gauge, in m.

4. The method for correcting abnormal pressure buildup test data of a deepwater high permeability gas well according to claim 1, characterized in that: In step S2, constructing the temperature profile model at different times at the pressure gauge specifically includes discretizing the wellbore into multiple small sections and calculating the gas temperature at the outlet of each section: For the stratigraphic section, For the atmosphere and seawater sections, A is calculated using the atmosphere and seawater section heat transfer model; where T out is the gas temperature at the outlet, K; T eout is the gas temperature at the outlet of the previous section, its unit is K; M is the number of moles of gas, its unit is mol; Zi n is the well depth at the entrance, in m; Z out is the well depth at the outlet, in m; v m is the fluid velocity in the wellbore, and its unit is m / s; T in is the gas temperature at the inlet, K; T ein is the gas temperature at the inlet and outlet of the previous section, in K; c p is the specific heat capacity of the fluid, its unit is J / (kg·K); D i is the Joule-Thomson effect coefficient, dimensionless; g is the acceleration due to gravity, its unit is m / s 2 ; r to is the outer radius of the oil pipe, in m; U to is the total heat transfer coefficient of the wellbore below the mudline, and its unit is W / (m 2 ·K); k e is the formation heat transfer coefficient, and its unit is W / (m 2 ·k); f(t) is the dimensionless transient heat transfer function, which is dimensionless; p is the wellbore pressure, whose unit is Pa; θ is the wellbore inclination angle, whose unit is degree; z is the depth based on the mudline, whose unit is m.

5. The method for correcting abnormal pressure buildup test data of deepwater high permeability gas wells according to claim 1, characterized in that: In step S3, after constructing the pressure profile model and the temperature profile model, it is necessary to establish the continuity equation, the motion equation, and the energy equation for solution; the temperature-pressure coupling model is solved semi-analytically using numerical calculation methods, that is, the equation group is discretized by difference, and the Gaussian elimination method is used to iteratively solve the parameters of each node.

6. The method for correcting abnormal pressure buildup test data of a deepwater high permeability gas well according to claim 5, characterized in that: The temperature-pressure coupling model is constructed as follows: Continuity equation equations of motion Energy equation Boundary conditions: T wh =C1,p wh =C2; where v wh is the wellhead fluid velocity, its unit is m 3 / s;T wh is the wellhead temperature, its unit is K; p wh is the wellhead pressure, its unit is Pa; ρ is the fluid density, its unit is kg·m -3 ; t is time, its unit is s; v is fluid velocity, its unit is m / s; p2 is the pressure drop loss in the wellbore, its unit is Pa; f is the wellbore friction factor, dimensionless; d is the wellbore outer diameter, its unit is cm; C v is the constant pressure specific heat of the wellbore fluid, its unit is J / (kg·℃); T is the temperature of the fluid in the wellbore, its unit is K; T e is the fluid temperature outside the wellbore, and its unit is K.

7. The method for correcting abnormal pressure buildup test data of a deepwater high permeability gas well according to claim 3, characterized in that: In step S4, during the shut-in pressure recovery period, at a certain moment, the pressure gradient G2t(i) from the lower pressure gauge to the middle of the reservoir is approximately G1t(i), and the pressure in the middle of the reservoir satisfies the following formula: Where, P 储 t(i) is the reservoir center pressure at a certain moment, in MPa; H 储 is the vertical depth of the middle part of the reservoir, and its unit is m.

8. The method for correcting abnormal pressure buildup test data of a deepwater high permeability gas well according to claim 1, characterized in that: In step S5, the pressure recovery data corrected to the middle of the reservoir is back-calibrated to the lower pressure gauge, and the corrected normal pressure recovery value at the lower pressure gauge satisfies the following formula: P′ 下 t(i)=P 储 t(i)-P 储 t(p max )+P 下 t(p max ) Where P′ 下 t(i) is the corrected pressure value of the lower pressure gauge, in MPa; P 下 t(p max ) is the maximum value of the pressure recovery of the lower pressure gauge, and its unit is MPa; P 储 t(p max ) is the pressure value in the middle of the reservoir corresponding to the moment when the pressure of the lower pressure gauge recovers to the highest level, and its unit is MPa.

9. The method for correcting abnormal pressure buildup test data of a deepwater high permeability gas well according to claim 1, characterized in that: In step S1, when the pressure change characteristics during the shut-in recovery period of the deepwater high-permeability gas well are a, b, and c, the abnormal pressure recovery data is caused by the combined effects of a large temperature drop and high reservoir permeability; a. The bottom temperature of deepwater gas wells is low. After shutting in the well, the temperature inside the tubing string drops, and the gas static pressure gradient increases, causing the measured pressure at the pressure gauge to drop. b. The pressure of a high-permeability gas well recovers rapidly at the initial stage of shut-in, quickly approaching the reservoir static pressure, and then recovers slowly; c. When the pressure recovery rate due to formation recharge is lower than the rate at which pressure is affected by temperature drop, the pressure gauge will show a slow downward trend.

10. The method for correcting abnormal pressure buildup test data of a deepwater high permeability gas well according to any one of claims 1 to 9, characterized in that: After step S5, step S6 is also included: performing a well test interpretation on the corrected pressure recovery data, and finally obtaining formation parameters and wellbore parameters by analyzing the corrected pressure data. The formation parameters include reservoir static pressure, physical properties, production capacity, crossflow coefficient and elastic energy storage ratio, and the wellbore parameters include well storage coefficient and skin coefficient.

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