Method for correcting abnormal pressure of buried hill gas well based on temperature influence

Abstract

The present application relates to a kind of based on temperature influence correction buried hill gas well abnormal pressure method, comprising: step A. obtaining abnormal well pressure gauge data;Step B. calculate the temperature field of wellbore after shut-in with time variation;Step C. the telescopic effect of pipe column is calculated by pipe column;Step D. according to the result of step B and the pressure gauge data obtained in step A, the density of gas in pipe column is calculated by gas state equation, the telescopic pressure compensation value of pipe column is calculated by gas density;Step E. the pressure of the top section of pressure gauge to reservoir is calculated by the gas density calculated in step D, plus the pressure compensation value obtained in step D, and the pressure of pressure gauge pressure recovery section can be converted to the top of reservoir;Step F. according to the pressure of the top of reservoir obtained by step E, the abnormal pressure recovery section pressure data of pressure gauge is corrected, and the normal trend pressure gauge data is obtained.The present application can obtain normal pressure gauge data after correction of buried hill abnormal pressure gas well, so as to realize the accurate evaluation of buried hill reservoir.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field exploration and development technology, specifically to a method for correcting abnormal pressure in buried hill gas wells based on temperature effects. Background Technology

[0002] Currently, buried hill reservoir testing suffers from anomalies in downhole pressure data (pressure recovery tests show a downward trend), and a lack of key sections reflecting reservoir and fracture flow characteristics. Conventional well test interpretation methods cannot handle this type of pressure data. It is necessary to identify the main controlling factors affecting downhole pressure data in bedrock buried hill reservoir open-hole testing, optimize the testing and data acquisition scheme, and establish methods for correcting anomaly test data to obtain accurate buried hill reservoir and production capacity assessments through well testing.

[0003] Numerous factors can cause pressure anomalies during the pressure recovery phase, such as wellbore fluid accumulation, phase changes, interference from adjacent wells, temperature effects, and water hammer. Based on buried hill testing data, we know that the production pressure differential is small and the geothermal gradient is large. Furthermore, research indicates that pressure curve anomalies during pressure recovery testing are relatively unaffected by reservoir type, pore type, and fluid type. Excluding process-related factors, the primary cause of downhole pressure data anomalies in buried hill reservoir open-hole testing is the influence of formation temperature.

[0004] Current methods for correcting abnormal pressures have limitations when processing pressure anomaly data from buried hill reservoirs. Due to process and safety considerations, some downhole pressure gauges cannot be installed in the reservoir. Generally, the reservoir temperature is considered constant, and anomalies showing a downward trend in pressure gauge readings are usually corrected by applying pressure reduction to the reservoir. However, for pressure anomaly data from buried hill reservoirs, the Cullender and Smith methods, which iteratively calculate bottomhole static pressure using segmented wellbore measurements, have poor correction effects and cannot correct the downward pressure trend during the pressure recovery phase. In recent years, many scholars have made corresponding improvements to the Cullender and Smith methods, but these are not suitable for correcting abnormal pressures in buried hills and cannot correct the pressure recovery curve to a normal upward trend. Another correction method is to divide the pressure difference between the upper and lower pressure gauges by the depth difference to obtain the pressure gradient, and then use this pressure gradient to represent the wellbore pressure gradient and apply it to the reservoir for pressure correction. This method can correct some abnormal wells and has good correction effects, but the simple calculation is not accurate enough and cannot meet the correction needs of all pressure anomaly data from buried hill reservoirs.

[0005] Therefore, the current abnormal pressure correction method is not applicable to the abnormal pressure correction of buried hills. It is necessary to construct an abnormal pressure correction method for buried hill gas wells based on the influence of temperature to correct the pressure gauge data, and use the corrected pressure data to complete the well test, thereby achieving accurate evaluation of the buried hill reservoir. Summary of the Invention

[0006] This invention provides a method for correcting abnormal pressure in buried hill gas wells based on temperature effects, which is used to correct abnormal pressure data in buried hill gas wells to obtain normal pressure gauge data.

[0007] This invention relates to a method for correcting abnormal pressure in buried hill gas wells based on the influence of temperature, comprising the following steps:

[0008] A. Obtain abnormal well pressure gauge data;

[0009] B. Calculate the temperature field over time after the well is shut in;

[0010] C. Calculate the expansion / contraction amount ΔL of the tubing using the expansion / contraction effect of the tubing;

[0011] D. Based on the results of step B and the pressure gauge data obtained in step A, calculate the density of the gas in the tubing using the gas state equation, and calculate the tubing expansion and contraction pressure compensation value ΔP using the gas density;

[0012] E. Calculate the pressure from the pressure gauge to the top of the reservoir using the gas density calculated in step D, and add the pressure compensation value ΔP to convert the pressure of the pressure gauge recovery section to the top of the reservoir;

[0013] F. Based on the abnormal pressure recovery section pressure data of the reservoir top pressure correction pressure gauge obtained in step E, obtain the pressure gauge data of the normal trend.

[0014] The well test described in this invention determines the distribution range of the reservoir fluid system, reservoir permeability, and production capacity by observing changes and recovery processes in downhole fluid pressure.

[0015] This invention relates to a method for correcting abnormal pressure in buried hill gas wells based on temperature. First, pressure gauge data is acquired, and a wellbore temperature field is established using a mathematical model. Then, the obtained temperature and pressure data are used to calculate the gas density from the pressure gauge to the reservoir according to the gas state equation. Simultaneously, the tubing stretching amount ΔL and the pressure compensation value ΔP are calculated through the stretching effect. Based on the gas density and the pressure compensation value ΔP, the pressure gauge pressure can be converted to the reservoir pressure. Finally, the pressure gauge pressure is corrected using the reservoir pressure to obtain normal pressure gauge data.

[0016] Existing correction methods cannot ensure that abnormal pressure correction in buried hill gas wells meets well testing requirements. However, the abnormal pressure correction method for buried hill gas wells based on temperature effects, as proposed in this invention, can obtain normal pressure data to complete well testing and achieve accurate buried hill reservoir and production capacity assessments.

[0017] Furthermore, the abnormal well mentioned in step A is a well in which the pressure data shows an abnormal downward trend during the pressure recovery phase, and the pressure gauge data includes the pressure data and temperature data of the pressure gauge.

[0018] Furthermore, the calculation method for the temperature field changing over time after well shut-in in step B is as follows:

[0019]

[0020] Where ρ is the density of the medium, and c p Let T be the mass constant-pressure heat capacity, T be the medium temperature, t be the shut-in time, Z be the axial coordinate, r be the radial coordinate, and k be the thermal conductivity of the medium. This is the radial partial differential of temperature; the other partial differential equations are similar.

[0021] Initial conditions: The initial conditions after well shut-in are the downhole temperature field distribution at the time of well shut-in.

[0022] Boundary conditions:

[0023] Sea level boundary conditions: Assume the top boundary of the wellbore heat exchange zone is insulated;

[0024] Bottom boundary conditions: Bottom-hole node temperature equals the original formation temperature;

[0025] Boundary conditions at infinity: The temperature of the strata and seawater at an infinite distance from the wellbore remains constant.

[0026] Furthermore, the expansion / contraction effect described in step C refers to the expansion / contraction of the tubing string due to stress during the test. In buried hill wells with abnormal pressure, tubing expansion / contraction can occur when using insert packers, and this expansion / contraction is primarily affected by temperature effects (thermal expansion and contraction). The calculation method for tubing expansion / contraction ΔL is: ΔL = βLΔT

[0027] Where: β is the thermal expansion coefficient of the oil pipe, L is the length of the oil pipe, and ΔT is the overall temperature change of the oil pipe.

[0028] Furthermore, the gas state equation in step D is: Where ρ is the gas density, P is the pressure, M is the gas molar mass, Z is the gas deviation factor, R is the gas constant, and T is the gas temperature. The calculation method for the tubing expansion and contraction pressure compensation value ΔP is: ΔP = ρgΔL, where ρ is the gas density and g is the acceleration due to gravity.

[0029] Furthermore, the method for calculating the pressure at the top of the reservoir described in step E is as follows: the pressure gauge is used to divide the reservoir into n segments, and the height of each segment is Δh.

[0030] Section 1: P1=P+ρ1gΔh

[0031] Section 2: P2=P1+ρ2gΔh

[0032] ...

[0033] The nth segment is the top segment of the reservoir: P n =P n-1 +ρ n gΔh+ΔP

[0034] Where P1···P n The pressure within the wellbore at each depth from segment 1 to segment n, ρ1···ρ n Let P be the density of the gas in the wellbore at each depth from segment 1 to segment n, P be the pressure measured by the pressure gauge, g be the acceleration due to gravity, and ΔP be the pressure compensation value.

[0035] Specifically, the gas density and pressure mentioned in steps D and E are data that change with time and depth. In step D, the gas density used to calculate the pressure compensation value ΔP is ρ1.

[0036] Furthermore, the method for calculating the pressure data of the abnormal pressure recovery section of the reservoir top pressure correction pressure gauge as described in step F:

[0037] P 矫 (t)=P 原 (t=0)+P 储 (t)-P 储 (t=0)

[0038] In the formula, P 矫 (t) represents the calibrated pressure gauge data, P 原 (t=0) represents the initial pressure of the pressure gauge at the moment the calibration begins, P 储 This represents the pressure at the top of the reservoir.

[0039] The beneficial effects of this invention include:

[0040] (1) The method proposed in this invention can determine the temperature field change of the wellbore after shutting in, and can be used to understand the rock structure inside the wellbore of deep water drilling, as well as the heat transfer between deep rocks.

[0041] (2) It can also obtain the extension length of the tubing string, which is of great significance for tailpipe cementing operations.

[0042] (3) It can correct abnormal pressure in buried hill gas wells and obtain a normal trend pressure recovery curve for well test analysis, thereby achieving accurate evaluation of buried hill reservoirs. Attached Figure Description

[0043] Figure 1 This is a flowchart of the method for correcting abnormal pressure in buried hill gas wells based on temperature effects, according to the present invention.

[0044] Figure 2 This is a graph showing the pressure curves of the upper and lower pressure gauges during the pressure recovery phase of a gas well in Qianshan.

[0045] Figure 3 This is a graph showing the temperature curves of the upper and lower pressure gauges during the pressure recovery phase of a gas well in Qianshan.

[0046] Figure 4 This is a schematic diagram of the temperature field of a gas well in Qianshan.

[0047] Figure 5 This is a comparison chart of the pressure curve after correction and the original pressure curve during the pressure recovery phase of a gas well in Qianshan. Detailed Implementation

[0048] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of this application, and not all of the embodiments. The components of the embodiments of this application described and shown in the accompanying drawings can be arranged and designed in various different configurations. Therefore, the following detailed description of the embodiments of this application provided in the accompanying drawings is not intended to limit the scope of the claimed application, but merely represents selected embodiments of this application. All other embodiments obtained by those skilled in the art based on the embodiments of this application without inventive effort are within the scope of protection of this application.

[0049] like Figure 1 As shown, the present invention provides a method for correcting abnormal pressure in buried hill gas wells based on temperature effects, comprising the following steps:

[0050] A. Obtain abnormal well pressure gauge data;

[0051] B. The temperature field changing over time after the wellbore is shut in, based on the aforementioned calculation.

[0052] C. Calculate the expansion / contraction amount ΔL of the tubing using the expansion / contraction effect of the tubing;

[0053] D. Calculate the density of the gas in the tubing based on the results of step B and the gas state equation, and calculate the tubing expansion and contraction pressure compensation value ΔP using the gas density;

[0054] E. Calculate the pressure from the pressure gauge to the top of the reservoir using the gas density calculated in step D, and add the pressure compensation value ΔP to convert the pressure of the pressure gauge recovery section to the top of the reservoir;

[0055] F. Based on the abnormal pressure recovery section pressure data of the reservoir top pressure correction pressure gauge obtained in step E, obtain the pressure gauge data of the normal trend.

[0056] This invention relates to a method for correcting abnormal pressure in buried hill gas wells based on temperature. First, pressure gauge data is acquired, and a wellbore temperature field is established using a mathematical model. Then, the obtained temperature and pressure data are used to calculate the gas density from the pressure gauge to the reservoir according to the gas state equation. Simultaneously, the tubing stretching amount ΔL and the pressure compensation value ΔP are calculated through the stretching effect. Based on the gas density and the pressure compensation value ΔP, the pressure gauge pressure can be converted to the reservoir pressure. Finally, the pressure gauge pressure is corrected using the reservoir pressure to obtain normal pressure gauge data.

[0057] Existing correction methods cannot ensure that abnormal pressure correction in buried hill gas wells meets well testing requirements. However, the abnormal pressure correction method for buried hill gas wells based on temperature effects, as proposed in this invention, can obtain normal pressure data to complete well testing and achieve accurate buried hill reservoir and production capacity assessments.

[0058] In step A, the abnormal well is a well whose pressure data shows an abnormality (decreasing trend) during the pressure recovery phase, and the pressure gauge data includes pressure and temperature data from the pressure gauge. Various data acquisition methods can be implemented with reference to "Oilfield Well Testing Technical Specification SY / T 6172-2022" and "Natural Gas Well Testing Technical Specification SY / T 5440-2019".

[0059] Step B describes the calculation of the temperature field changing over time after well shut-in:

[0060]

[0061] Where ρ is the density of the medium, and c p Let T be the mass constant-pressure heat capacity, T be the medium temperature, t be the shut-in time, Z be the axial coordinate, r be the radial coordinate, and k be the thermal conductivity of the medium. This is the radial partial differential of temperature; the other partial differential equations are similar.

[0062] Initial conditions: The initial conditions after well shut-in are the downhole temperature field distribution at the time of well shut-in.

[0063] Boundary conditions:

[0064] Sea level boundary conditions: Assume the top boundary of the wellbore heat exchange zone is insulated;

[0065] Bottom boundary conditions: Bottom-hole node temperature equals the original formation temperature;

[0066] Boundary conditions at infinity: The temperature of the strata and seawater at an infinite distance from the wellbore remains constant.

[0067] The well shaft is considered as a two-dimensional plane and meshed, with the radial (horizontal) direction as the r-axis and the axial (vertical) direction as the z-axis. The origin can be arbitrarily chosen, such as the central axis of the well shaft, the intersection of the left and right boundaries with the top or bottom surface, etc. The following discrete equations are obtained by solving the above problem using finite difference:

[0068]

[0069] The above equation is the heat transfer equation between the grid at coordinate (i, j) and the surrounding 4 grids from time n to time n+1 after shutting in the well. The center point of each grid represents the temperature of the grid. Substituting the initial and boundary conditions, the temperature at any point and time can be obtained, that is, the temperature field of the wellbore.

[0070] in

[0071]

[0072] The thermal conductivity k at the grid boundary is the harmonic average of the two grids on either side:

[0073]

[0074]

[0075] In the formula, the superscript represents time, and the subscript represents coordinates. For example, (i-1, j) and (i+1, j) are the adjacent points of (i, j) in the horizontal direction, (i-1 / 2, j) and (i+1 / 2, j) are the grid boundaries in the horizontal direction of (i, j). T is the temperature, k is the thermal conductivity, ΔZ is the vertical length of the grid, Δr is the horizontal length of the grid, Δt is the time step, ρ is the density, c is the heat capacity, and r is the thermal conductivity. i+1,j -r i,j Z is the horizontal distance between point (i+1, j) and point (i, j). i,j -Z i,j-1 Let be the vertical distance between point (i, j) and point (j, j-1).

[0076] The expansion and contraction effect described in step C refers to the expansion and contraction of the tubing string caused by stress during the test. In buried hill wells with abnormal pressure, tubing expansion and contraction can occur when using insert packers, and this expansion and contraction is mainly affected by temperature effects (thermal expansion and contraction).

[0077] Specific calculation method: Take the grid temperature data representing the tubing in the temperature field obtained in step B. The following formula is the tubing expansion and contraction length of the wellbore as a function of the shut-in time after shut-in:

[0078]

[0079] In the formula, β is the thermal expansion coefficient of the tubing, m is the number of tubing grids, ΔZ is the longitudinal length of the grid, and T is the grid temperature.

[0080] The gas law in step D is: Where ρ is the gas density, P is the pressure, M is the gas molar mass, Z is the gas deviation factor, R is the gas constant, and T is the gas temperature.

[0081] The buried hill anomalous gas well has two pressure gauges, upper and lower. Considering that the difference in gas molar mass and gas deviation factor between the lower pressure gauge and the top of the reservoir is very small at the same time, the M / Z value of the gas between the two pressure gauges is used to represent the wellbore gas to simplify the calculation. The following is the calculation of the M / Z value using data from the upper and lower pressure gauges. The value varies with the shut-in time, along with the pressure gauge temperature and pressure data.

[0082]

[0083] In the formula: ΔP is the pressure difference between the upper and lower pressure gauges, P 上 P 下 These are the pressures of the upper and lower pressure gauges, T. 上 T 下 The temperatures of the upper and lower pressure gauges are respectively, ρ 上 ρ 下 These represent the gas densities at the depths of the upper and lower pressure gauges, respectively. Here, ρ is the average density, g is the gravitational acceleration, and H is the depth difference between the upper and lower pressure gauges.

[0084] If the distance from the pressure gauge to the top of the reservoir is x meters, divide it into x segments (rounded down), with each segment having a height Δh = 1m. (In step C, ΔZ = 1m is used uniformly; the value can be chosen independently, with smaller values ​​resulting in higher accuracy.) Calculate the gas density of each segment from top to bottom:

[0085]

[0086] In the formula: ρ1···ρ x Let T1 represent the gas density from segment 1 to segment x, and T1···T2· ... x Let be the grid temperature of the gas in the tubing from the first segment to the xth segment in the temperature field obtained in step C, where temperature, density, pressure and M / Z value all change with shut-in time.

[0087] All of the above formulas require iterative calculations. Taking the calculation of ρ1 as an example:

[0088] (1) First, take an initial value a (to save calculation steps and get closer to the result, the gas density at the pressure gauge can be taken);

[0089] (2) Calculation

[0090] (3) If the difference between a and b meets the precision (e.g., |ab|<0.00001), then b is the final result; otherwise, let a = b and return to step (2).

[0091] Calculation method for tubing expansion and contraction pressure compensation value ΔP:

[0092] ΔP(t)=ρ1(t)gΔL(t) (6)

[0093] Where ρ is the gas density, g is the gravitational acceleration, and L is the extension / retraction length of the oil pipe.

[0094] Similar to step D, step E describes the calculation of the reservoir top pressure P. x Method:

[0095]

[0096] In the formula: P1···P x The pressure at depths from segment 1 to segment x, ρ1···ρ x ρ is the density of the gas in segments 1 to x, g is the acceleration due to gravity, and ΔP is the pressure compensation value for the expansion and contraction of the tubing.

[0097] Step F involves correcting the abnormal pressure recovery section pressure data of the pressure gauge using the reservoir top pressure. The calculation method is as follows:

[0098] P 下矫 (t)=P 下 (t=0)+P x (t)-P x (t=0) (8)

[0099] In the formula: P 下矫 To correct the pressure of the pressure gauge, P 下 The original pressure gauge pressure, P x This represents the pressure at the top of the reservoir.

[0100] The following description, based on test data from a gas well in Qianshan, further illustrates the present invention:

[0101] In a specific embodiment, the method of correcting abnormal pressure in buried hill gas wells based on temperature effects according to the present invention is adopted, and the steps are as follows:

[0102] A. A gas well in a buried hill reservoir was tested using open-hole completion. The test section ranged from 2828.8m to 2936m, with a total thickness of 107.2m. A pressure recovery test was conducted after the first shut-in, lasting 24.8 hours. Storage pressure gauges on the test string acquired downhole pressure change data during the test period, with the upper gauge at 2641.74m and the lower gauge at 2662.48m. The pressure changes of the upper and lower gauges over time are shown below. Figure 2 As shown, the temperature changes of the upper and lower pressure gauges over time are as follows: Figure 3 As shown, the temperature and pressure of the lower pressure gauge are both greater than those of the upper pressure gauge.

[0103] B. Based on formula (2), the temperature field of the gas well can be calculated, and the temperature field for any shut-in time can be obtained, such as Figure 4 The figure shows the temperature field 12 hours after the well was shut in.

[0104] C. Using the temperature data from the pressure gauge at the top of the reservoir obtained in step B, let ΔZ1~ΔZ 165 =1m, ΔZ 166 =1.32m. Based on formula (3), the tubing expansion and contraction amount is calculated. The tubing shrinks by a total of 0.70333m during the entire shut-in test.

[0105] D. Using the temperature and pressure data of the upper and lower pressure gauges obtained in step A, calculate the M / Z value based on formula (4), and let Δh1~Δh 165 =1m, Δh 166 =1.32m, the gas density from the pressure gauge to the top of the reservoir is calculated iteratively using formula (5), and the tubing expansion pressure compensation value ΔP is calculated based on formula (6). At the last moment of the shut-in test, ΔP = 0.17898psi.

[0106] E. Let Δh1~Δh 165 =1m, Δh 166 =1.32m. Using the pressure data of the pressure gauge obtained in step A and the gas density and pressure compensation value obtained in step D, the pressure at the top of the reservoir is calculated based on formula (7).

[0107] F. Using the pressure data from the pressure gauge obtained in step A and the pressure at the top of the reservoir obtained in step E, the corrected pressure recovery stage pressure data is finally obtained based on formula (8). If the pressure data fluctuates greatly, smoothing can be performed, such as using the smooth function in MATLAB software. Figure 5 This is a comparison chart of the final corrected results and the original pressure gauge data. Using the corrected pressure data, well test analysis can be performed to help achieve accurate evaluation of buried hill reservoirs.

[0108] The embodiments described above merely illustrate specific implementation methods of this application, and while the descriptions are detailed and specific, they should not be construed as limiting the scope of protection of this application. It should be noted that those skilled in the art can make relevant modifications and improvements without departing from the concept of the technical solution of this application, and these modifications and improvements all fall within the scope of protection of this application.

Claims

1. A method for correcting abnormal pressure in buried hill gas wells based on temperature effects, characterized by the following steps: A. Obtain abnormal well pressure gauge data; B. Calculate the temperature field over time after the well is shut in; C. Calculate the expansion and contraction of the tubing using the expansion and contraction effect. ; D. Based on the results of step B and the pressure gauge data obtained in step A, calculate the density of the gas in the tubing using the gas state equation, and then calculate the tubing expansion and contraction pressure compensation value using the gas density. ; E. Calculate the pressure from the pressure gauge to the top of the reservoir using the gas density calculated in step D, and add the pressure compensation value. This allows the pressure in the pressure gauge recovery section to be converted to the top of the reservoir; F. Based on the abnormal pressure recovery section pressure data of the reservoir top pressure correction pressure gauge obtained in step E, obtain the pressure gauge data of the normal trend; In step A, the abnormal well is a well whose pressure data shows an abnormal downward trend during the pressure recovery phase. The pressure gauge data includes the pressure data and temperature data of the pressure gauge. Step B involves calculating the temperature field over time after well shut-in, including the following methods: Constructing the two-dimensional heat transfer equation for the wellbore: ； in, For the density of the medium, c p Let T be the mass constant-pressure heat capacity, T be the medium temperature, t be the shut-in time, Z be the axial coordinate, r be the radial coordinate, and k be the thermal conductivity of the medium. For the radial partial derivative of temperature; Initial conditions: Boundary conditions: Sea level boundary conditions: ; Bottom boundary conditions: T f The original temperature of the strata; Boundary conditions at infinity: ; The expansion and contraction effect described in step C is the expansion and contraction of the tubing string caused by the force applied during the test. When using an insert packer in a buried hill with abnormal pressure, the tubing string will expand and contract, and the expansion and contraction is mainly affected by the temperature effect. tubular expansion and contraction Calculation method: ; Where: β is the coefficient of thermal expansion of the tubing, and L is the length of the tubing. This represents the overall temperature change of the tubular column. The gas state equation in step D is: , in, Let P be the gas density, M be the gas molar mass, Z be the gas deviation factor, R be the gas constant, and T be the gas temperature. Both gas density and pressure change with time and depth; Tube string expansion pressure compensation value Calculation method: ； Where g is the acceleration due to gravity; where, The average gas density, ； Among them, P 上 P 下 These are the pressures of the upper and lower pressure gauges, T. 上 T 下 These represent the temperatures of the upper and lower pressure gauges, respectively, and H represents the depth difference between the upper and lower pressure gauges. The pressure gauge is x meters from the top of the reservoir. Divide this into x segments, each segment having a height of x. =1m, calculate the gas density of each segment from top to bottom: ； In the formula: The gas density is from segment 1 to segment x. Let be the grid temperature of the gas in the tubing from the first segment to the xth segment in the temperature field obtained in step C, where temperature, density, pressure and M / Z value all change with shut-in time; Step E: Method for calculating the pressure at the top of the reservoir: The pressure gauge is used to divide the reservoir into n segments, with each segment having a height gauge of... : ； in The pressure within the wellbore at each depth from segment 1 to segment n. Let P be the density of the gas inside the wellbore at each depth from segment 1 to segment n, P be the pressure measured by the pressure gauge, and g be the acceleration due to gravity. This is the pressure compensation value; The calculation method for the abnormal pressure recovery section pressure data of the pressure gauge through reservoir top pressure correction in step F is as follows: ； In the formula, For the corrected pressure gauge data, The pressure of the original pressure gauge at the start of the calibration. This refers to reservoir pressure.

Images