Deepwater high-permeability gas well abnormal pressure recovery well testing data correction method

Abstract

The invention relates to the technical field of oil and gas exploitation, in particular to a deepwater high-permeability gas well abnormal pressure recovery well testing data correction method which comprises the steps that test data are analyzed, and the pressure recovery data abnormity reason is the comprehensive influence of much temperature drop and reservoir high permeability; acquiring pressure data at the upper pressure gauge and the lower pressure gauge to construct a pressure profile model, and acquiring temperature data at the upper pressure gauge and the lower pressure gauge to construct temperature profile models at different moments at the pressure gauges; constructing a temperature and pressure coupling model according to the pressure profile model and the temperature profile model; correcting the data of the lower pressure gauge point by point to pressure recovery data in the middle of the reservoir by using a temperature and pressure coupling model; and reversely correcting the pressure recovery data corrected to the middle part of the reservoir back to the lower pressure gauge point by point. According to the method, the pressure recovery data of the abnormal slow descending trend can be corrected to the normal slow ascending trend, and the method is used for well testing interpretation and analysis to obtain stratum and shaft parameters.

Description

Technical Field

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

[0002] Pressure recovery test is the main means for exploration wells and production wells to obtain the flow capacity of underground fluids in the formation, and to obtain formation parameters and characteristic parameters of wellbore accessories. It has an irreplaceable position in obtaining formation coefficient, permeability, formation temperature and pressure, and skin coefficient parameters. Under normal circumstances, the pressure recovery data shows a monotonically increasing curve with a rapid increase at the beginning and then gradually slowing down. The DST test of deepwater high-permeability gas wells is difficult, has high requirements for equipment performance, and has high single test costs. As an important achievement data, pressure recovery test data will cause huge economic losses if the data is unqualified.

[0003] Well A, a deepwater high-permeability gas well in the western South China Sea, encountered a buried hill granite reservoir. The water depth of the well is 1833m, the middle of the reservoir is 2883m, the test pressure gauge depth is 2662m, and the distance from the reservoir is 221m. Well logging interpretation shows that the area is a fracture-pore type reservoir with an effective thickness of 85.2m, a porosity of 9.3%, and a gas saturation of 82.6%. The core data of the well wall confirms the characteristic of reservoir fracture development. The initial DST test of Well A has a total of four working systems, and the test gas production is 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 pollution was gradually relieved. The first shut-in (downhole test valve shut-in) lasted for 24.5 hours, and then the gas production was 77×104m3 / d for 3 hours, and then the well was shut down again for 7 hours (wellhead shut-in). The second opening and three-level working system, gas production 26×10 4 m 3 / d to 65×10 4 m 3 / d. The production capacity test process 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 the well was shut in (normally a slow upward trend), with a total decrease of 0.01MPa ( Figure 3 ), resulting in the missing of pressure derivative curve in the double logarithmic curve of well test interpretation ( Figure 2), the abnormal pressure data is difficult to interpret through well testing. The pressure change trends of the four pressure gauges in the A well DST test (two upper pressure gauges at 2642m and two lower pressure gauges at 2663m) are consistent, which excludes the possibility of pressure gauge failure. In addition, the well test has two shut-in sections (the first section closes the downhole test valve and the second section shuts the wellhead), and the pressure change trends of the two sections are consistent. After communicating with the on-site personnel, no natural gas leakage was found after the well was shut down, thus excluding the possibility of leakage after the well was shut down.

[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 either cannot solve the problem of abnormal pressure 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 abnormal pressure or require high costs for retesting, the present invention provides a method for correcting abnormal pressure recovery well test data of deepwater high permeability gas wells.

[0006] In order to solve the above technical problems, the technical solution adopted by the present invention is: a method for correcting abnormal pressure recovery well test data of deepwater high permeability gas wells, comprising the following steps:

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

[0008] S2: Obtain pressure data at the upper pressure gauge and the lower pressure gauge, and construct a pressure profile model of the pressure gauge at different time and different temperature gradients according to the pressure data at the upper pressure gauge and the lower pressure gauge; obtain temperature data at the upper pressure gauge and the lower pressure gauge, and construct a temperature profile model of the pressure gauge at different time according to the 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 comprises the following steps:

[0013] S21: Obtaining 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 expression of the pressure gradient is 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 a plurality of 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 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, in K; M is the number of gas moles, in mol; Z in is the well depth at the entrance, in m; Z out is the well depth at the exit, 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 mud line, and its unit is W / (m 2 ·K); k e is the formation heat transfer coefficient, its unit is W / (m 2 ·k); f(t) is the dimensionless transient heat transfer function, dimensionless; p is the wellbore pressure, its unit is Pa; θ is the wellbore inclination angle, its unit is degree; z is the depth based on the mudline, its unit is m.

[0021] Preferably, in step S3, after constructing the pressure profile model and the temperature profile model, it is also necessary to establish the continuity equation, the motion equation and the energy equation for solving; the temperature-pressure coupling model is solved in a semi-analytical manner 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, in 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, in meters.

[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] In the formula, 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 maximum, and its unit is MPa.

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

[0037] a. The bottom temperature of deepwater gas wells is low. After the well is shut in, the temperature inside the pipe 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, and soon approaches the reservoir static pressure, and then recovers slowly;

[0039] c. When the pressure recovery rate due to formation recharge is lower than the rate at which the pressure is affected by temperature drop, the pressure gauge will show a slow downward trend.

[0040] Preferably, after step S5, step S6 is also included: performing well test interpretation on the corrected pressure recovery data, and finally obtaining formation parameters and wellbore parameters by analyzing the corrected pressure data, wherein 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.

[0041] Compared with the prior art, the beneficial effects of the present invention are as follows: the method of the present invention utilizes the measured temperature data and pressure data of the upper pressure gauge and the lower pressure gauge to respectively establish a temperature profile model and a pressure profile model, and obtains a temperature-pressure coupling model at different times by coupling the temperature profile model with the pressure profile model. The lower pressure gauge data is corrected point by point to the middle of the reservoir through the temperature-pressure coupling model, and the pressure recovery data with an abnormally slow downward trend can be corrected to a normal slowly rising trend, and can be used for well test interpretation and analysis to obtain formation and wellbore parameters. BRIEF DESCRIPTION OF THE DRAWINGS

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

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

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

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

[0046] The technical solution of the present invention is further described in detail below through specific embodiments and in conjunction with the accompanying drawings:

[0047] Example 1

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

[0049] S1: Analyze the test data and find that the abnormal reason for the pressure recovery data is the combined effect of large temperature drop and high reservoir permeability;

[0050] S2: Obtain pressure data at the upper pressure gauge and the lower pressure gauge, and construct a pressure profile model of the pressure gauge at different time and different temperature gradients according to the pressure data at the upper pressure gauge and the lower pressure gauge; obtain temperature data at the upper pressure gauge and the lower pressure gauge, and construct a temperature profile model of the pressure gauge at different time according to the temperature data at the upper pressure gauge and the lower pressure gauge;

[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 of a deepwater high-permeability gas well are a, b, and c, the abnormal reason for the pressure recovery data is the combined effect of the large temperature drop and the high permeability of the reservoir;

[0055] a. The bottom temperature of deepwater gas wells is low. After the well is shut in, the temperature inside the pipe 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, and soon approaches 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 the pressure is affected by temperature drop, the pressure gauge will show a slow downward trend.

[0058] In one embodiment, the bottom temperature of Well A is as low as 2℃~5℃, the geothermal gradient is as high as 6℃ / 100m, and the temperature at the pressure gauge drops from 85℃ to 73℃ after shutting in the well. The reservoir permeability of the well is 160mD, and the pressure reaches the peak after only 9 minutes of shutting in and then begins to decline. The above two factors work together to make the pressure change characteristics of the deepwater high-permeability gas well during the shut-in recovery period a, b and c.

[0059] Example 2

[0060] This embodiment 2 is similar to embodiment 1, except that, in step S2, constructing a pressure profile model at different temperature gradients at different times 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 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.

[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] Among them, 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:

[0067]

[0068] For the stratigraphic section, For the atmosphere and seawater sections, A is calculated using the atmosphere and seawater 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, in K; M is the number of gas moles, in mol; Z in is the well depth at the entrance, in m; Z out is the well depth at the exit, 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 mud line, and its unit is W / (m 2 ·K); k e is the formation heat transfer coefficient, its unit is W / (m 2·k); f(t) is the dimensionless transient heat transfer function, dimensionless; p is the wellbore pressure, its unit is Pa; θ is the wellbore inclination angle, its unit is degree; z is the depth based on the mudline, its 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 in a semi-analytical manner 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, in 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, in meters.

[0081] Among them, due to the high test production of the well, it is difficult to convert the flow pressure data during the production capacity test stage. 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 As shown), the normal pressure recovery value corrected 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] In the formula, 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 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 maximum, 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 recovery data, the corrected lower pressure gauge pressure data returns to normal, the flow phase of the pressure derivative curve is complete, and an obvious downward "concave" fracture feature is presented, which is consistent with the fracture formation characteristics (such as Figure 4 The formation parameters and wellbore parameters (as shown in Table 1 below) are finally obtained 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.

[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 clearly illustrating the present invention, and are not intended to limit the embodiments of the present invention. For those skilled in the art, other different forms of changes or modifications can be made based on the above description. It is not necessary and impossible to list all the embodiments here. Any modifications, equivalent substitutions and improvements made within the spirit and principles of the present invention should be included in the protection scope 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 in that: The following steps are involved: S1: Analyze the test data and find that the abnormal reason for the pressure recovery data is the combined effect of large temperature drop and high reservoir permeability; S2: Obtain pressure data at the upper pressure gauge and the lower pressure gauge, and construct a pressure profile model of the pressure gauge at different time and different temperature gradients according to the pressure data at the upper pressure gauge and the lower pressure gauge; obtain temperature data at the upper pressure gauge and the lower pressure gauge, and construct a temperature profile model of the pressure gauge at different time according to the 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 a pressure gauge under different temperature gradients at different times includes the following steps: S21: Obtaining 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 recovery 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 recovery test data of deepwater high permeability gas wells according to claim 1 is 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 heat transfer model of the atmosphere and seawater sections; where T out is the gas temperature at the outlet, K; T eout is the gas temperature at the outlet of the previous section, in K; M is the number of gas moles, in mol; Zi n is the well depth at the entrance, in m; Z out is the well depth at the exit, 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 mud line, and its unit is W / (m 2 ·K); k e is the formation heat transfer coefficient, its unit is W / (m 2 ·k); f(t) is the dimensionless transient heat transfer function, dimensionless; p is the wellbore pressure, its unit is Pa; θ is the wellbore inclination angle, its unit is degree; z is the depth based on the mudline, its unit is m.

5. 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 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 solving; the temperature-pressure coupling model is solved in a semi-analytical manner 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.

6. The method for correcting abnormal pressure recovery test data of deepwater high permeability gas wells according to claim 5 is 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, in 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 recovery test data of deepwater high permeability gas wells according to claim 3 is 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, in meters.

8. The method for correcting abnormal pressure recovery test data of deepwater high permeability gas wells 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 ) In the formula, 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 maximum, and its unit is MPa.

9. The method for correcting abnormal pressure recovery test data of deepwater high permeability gas wells according to claim 1, characterized in that: In step S1, when the pressure change characteristics during the shut-in recovery of a deepwater high-permeability gas well are a, b, and c, the abnormal reason for the pressure recovery data is the combined effect of a large temperature drop and high reservoir permeability; a. The bottom temperature of deepwater gas wells is low. After the well is shut in, the temperature inside the pipe 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, and soon approaches 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 the pressure is affected by temperature drop, the pressure gauge will show a slow downward trend.

10. The method for correcting abnormal pressure recovery test data of deepwater high permeability gas wells according to any one of claims 1 to 9, characterized in that: After step S5, step S6 is also included: performing 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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