Gas well pressure recovery correction method for pressure abnormity caused by hydrops

Abstract

The invention belongs to the technical field of petroleum logging, and discloses a gas well pressure recovery correction method for pressure abnormity caused by liquid accumulation. Before well shut-in, a steel wire is put into a pressure gauge to test the flowing pressure gradient and the accumulated water height, a release suspension device is used for testing well shut-in pressure recovery data, and the steel wire is put into the pressure gauge to test the static pressure gradient and the accumulated water height at the end of well shut-in. In the pressure recovery test period, the pressure gauge cannot be placed in the middle of the stratum, the water accumulation height rises due to gas-liquid separation in a shaft, and the pressure recovery curve tends to descend, correction is carried out, and the pressure recovery curve capable of reflecting the real pressure change of the stratum is obtained.

Description

Technical Field

[0001] The present invention belongs to the technical field of petroleum logging, and the present invention relates to a pressure recovery correction method for a gas well with abnormal pressure caused by liquid accumulation, and specifically to a shut-in recovery pressure correction method for a high-pressure gas well with abnormal pressure caused by liquid accumulation in the wellbore. Background Art

[0002] When a high-pressure gas well is shut in for a pressure recovery test, the test instrument should be placed in the middle of the gas formation according to the standard. However, due to some reasons, such as the wellbore condition and the test process, the electronic pressure gauge used for the pressure recovery test often cannot be lowered to the middle of the gas formation and is placed at a certain depth in the upper part of the gas formation. For example: ① For high-pressure gas wells, when the wellhead blowout preventer cannot guarantee long-term pressure resistance, a pressure gauge is lowered into the well using a test wire before and after shutting in the well to test the flow pressure and static pressure gradient data. During the shut-in period, the pressure gauge is placed above the formation for testing using a de-stuck suspension device. The wellhead blowout preventer is not used to ensure safety during the test. ② For remote gas wells, the well test vehicle or movable drum cannot be placed at the well site. The de-stuck suspension test method is also adopted to avoid damage or loss of the equipment. When using a de-stuck suspension device, in order to ensure the stability of the de-stuck suspension device, the perforation position and the tubing or casing coupling position should be avoided. It is generally placed in the upper part of the deep middle formation (see Figure 1 ; Place the pressure gauge above the middle of the formation to test the pressure recovery data during the shut-in period, without using a blowout preventer at the wellhead. ).

[0003] When the fluid in the wellbore of the gas well is a mixture of gas and water, the accumulated water at the bottom of the well is carried upward by the air flow and out of the wellhead when the well is opened for production (see Figure 2 :Before shutting in the well, use a steel wire to lower the pressure gauge to test the pressure gradient data of the entire wellbore and the height of water accumulation before shutting in the well. ).

[0004] When the well is shut in for pressure recovery testing, the gas flow carrying the liquid mixture in the wellbore stops flowing, and the heavy liquid component will flow to the bottom of the well, forming liquid accumulation at the bottom of the well, and the gas will flow above the liquid accumulation (see Figure 3 :At the end of the well closure, a pressure gauge is run through the wire to test the pressure gradient data of the entire wellbore and the water accumulation height at the end of the well closure. ).

[0005] If the test instrument is not placed in the middle of the gas layer and does not enter the liquid interface, but is always in the gas, the pressure recovery curve will show a pressure drop phenomenon (see Figure 4 :The tested pressure recovery curve shows a downward trend. ), which affects the judgment of formation pressure and the interpretation of formation physical parameters. Summary of the invention

[0006] In order to overcome the deficiencies of the prior art, the present invention provides a correction method for gas well pressure recovery caused by fluid accumulation, through which the abnormal gas well shut-in recovery pressure caused by phase changes in the wellbore is corrected to ensure the accuracy of the test pressure.

[0007] The above object of the present invention is achieved through the following technical solutions:

[0008] A method for correcting the pressure recovery of a gas well caused by abnormal pressure due to liquid accumulation is a method for correcting the abnormal pressure recovery data of the gas well caused by gas-liquid separation in the wellbore after the well is shut in because the pressure gauge cannot be lowered to the middle of the formation; the method comprises the following steps:

[0009] 1. Calculate the average gas gradient in the wellbore using the gas pressure gradient data in the wellbore before shutting in;

[0010] Second, the average gas gradient in the wellbore is calculated using the gas pressure gradient data in the wellbore at the end of the well shut-in period;

[0011] 3. Using the gas pressure gradient data G in the wellbore before shut-in Dh气1 Calculate the height of water accumulated in the wellbore before the wellbore is shut in;

[0012] 4. Using the gas pressure gradient data G at the end of the well shut-in period Dh气2 Calculate the height of accumulated water in the wellbore after the well is shut down;

[0013] 5. Establish a linear equation for the change of gas pressure gradient data in the wellbore and shut-in time, and calculate the pressure gradient rate constant: Among them, G Dh气1 is the gas pressure gradient data in the wellbore before shutting in; G Dh Gas 2 is the gas pressure gradient data at the end of well shut-in; B is the pressure gradient rate constant;

[0014] 6. Establish a linear equation for the change of water accumulation height in the wellbore and the time of shut-in, and calculate the water accumulation rate constant;

[0015] 7. The pressure in the middle of the formation in the wellbore is composed of three parts: the pressure at the measuring point + the pressure of the gas column between the measuring point and the water accumulation height + the pressure generated by the water accumulation height;

[0016] The gas pressure gradient rate constant and water accumulation rate are used to calculate the gas column pressure between the measuring point and the water accumulation height at any time.

[0017] The water accumulation density and water accumulation rate constant are used to calculate the pressure generated by water accumulation in the wellbore at any time;

[0018] Test process: Before shutting in the well, use a steel wire to insert a pressure gauge to test the flow pressure gradient and water accumulation height, use a de-stuck suspension device to test the shut-in pressure recovery data, and at the end of shut-in, use a steel wire to insert a pressure gauge to test the static pressure gradient and water accumulation height.

[0019] Furthermore, the gas pressure gradient data in the wellbore before shutting in the step 1 is obtained by performing a pressure gradient test using a steel wire to lower a pressure gauge before shutting in the well, and measuring the gas pressure gradient data G in the wellbore before shutting in the well. Dh气1 , G Dh气1 The value varies with the depth and phase state in the wellbore.

[0020] Further, the gas pressure gradient data in the wellbore at the end of the well shut-in in step 2 is measured by using a steel wire to run a pressure gauge again in the well shut-in state to measure the gas pressure gradient data G in the wellbore at the end of the well shut-in. Dh气2 .

[0021] Furthermore, the specific steps of the pressure recovery correction method for a gas well with abnormal pressure due to liquid accumulation are as follows:

[0022] (a) Before shutting in the well, a pressure gradient test is performed by lowering a pressure gauge using a steel wire to measure the gas pressure gradient data G in the wellbore before shutting in the well. Dh气1 , G Dh气1 The value changes with the depth and phase state of the wellbore. Since the density of gas and liquid is quite different, the inflection point of the pressure gradient change in the wellbore is the gas-water interface, from which the phase state of the fluid in the wellbore and the depth of the water surface can be determined. Assuming that the height of the water in the wellbore before the wellbore is shut in is ΔH0, the water density is Generally speaking, when the gas has a strong enough liquid-carrying capacity, there is no liquid accumulation in the wellbore, so the height of water accumulation in the wellbore before the wellbore is shut in is ΔH0 = 0;

[0023] (b) After the pressure profile test is completed before shutting in the well, the pressure gauge is lowered to the designed test depth H using the unstuck suspension device. 测 After that, shut in the well for pressure recovery test, measure the pressure data within the complete shut-in time Δt; use the fishing head to pull out the pressure gauge;

[0024] (c) In the shut-in state, the pressure gauge is lowered by the steel wire to perform the pressure gradient test at the end of the shut-in period to obtain the gas pressure gradient data G at the end of the shut-in period. Dh气2 , because the density of gas and liquid is quite different, the inflection point of the pressure gradient change in the wellbore is the gas-water interface, from which the phase state of the fluid in the wellbore and the depth of the water surface can be determined, and the water accumulation height ΔH after the well is shut in for Δt time can be calculated. t , the pressure generated by the water height at time Δt is: where p 积水 is the water height ΔH at time Δt t The pressure generated; ΔH t is the water accumulation height after the well is shut down for Δt time;

[0025] (d) Assuming that the water accumulation height ΔH is positively correlated with the well shut-in time Δt, let A be the water accumulation rate constant, m / h, ΔH0 be the water accumulation height in the wellbore before well shut-in, ΔH t is the water accumulation height after the well is shut down for Δt time, then ΔH t =AΔt+ΔH0; then Where A is the water accumulation rate constant, ΔH0 is the height of water accumulation in the wellbore before the wellbore is shut in, and ΔH t is the water accumulation height after the well is shut down for Δt time, where Δt is the shut-in time;

[0026] (e) The height of water accumulation at any time Δti is: ΔH i =AΔti+ΔH0;

[0027]

[0028] ΔH i is the water accumulation height at any time Δti, ΔH0 is the water accumulation height in the wellbore before the wellbore is shut in, Δt is the shut-in time, and ΔH t is the water accumulation height after the well is shut down for Δt time, and Δti is any time when the well is shut down;

[0029] (f) The shut-in pressure recovery test time is Δt, the water accumulation height during the shut-in period is ΔH, and the water accumulation height at any Δti time within Δt is ΔH i , then the pressure generated by the water accumulation height at any time during the shut-in period is p 积水i =9.8×10 -3 ΔH i ; where ΔH i is the water accumulation height at any time Δti, p 积水i is the water accumulation height ΔH at any time Δti during the well shut-in period i The pressure generated;

[0030] (g) The shut-in pressure recovery test time is Δt, and the gas pressure gradient data in the wellbore before shutting in is G Dh气1 , the gas pressure gradient data at the end of well shut-in is G Dh气2 , assuming that the gas pressure gradient data G Dh气 is positively correlated with the shut-in time Δt. Let B be the pressure gradient rate constant, MPa / mh, then G Dh气2 =BΔt+G Dh气1 ;but

[0031]

[0032] Where B is the pressure gradient rate constant, G Dh气1 Gas pressure gradient data in the wellbore before shutting in, G Dh气2 Gas pressure gradient data at the end of well shut-in, Δt is the well shut-in time;

[0033] (h) Then the gas pressure gradient at any time Δti is: G Dh气i =BΔti+G Dh气1 ;

[0034]

[0035]

[0036] Among them, G Dh气1 Gas pressure gradient data in the wellbore before shutting in, G Dh气2 Gas pressure gradient data at the end of well shut-in, B is the pressure gradient rate constant, Δti is any time of well shut-in; G Dh气i is the gas pressure gradient at any time Δti; Δt is the shut-in time;

[0037] (i) The depth of the pressure gauge is H 测 , test depth H 测 The pressure at position P 测 ; The depth of the oil layer is H 中 , the deep pressure in the oil layer is P 中 ; The gas pressure gradient data in the gas phase state in the wellbore is G Dh气 , then the deep pressure in the oil layer during the test is:

[0038] p 中 =p 测 +G Dh气 (H 中 -H 测 -ΔH)+9.8×10 -3 ΔH

[0039] Among them, P 中 is the deep pressure in the oil layer, p 测 For the test depth H 测 Pressure at position, G Dh气 is the gas pressure gradient data, H 中 The oil layer is medium-deep, H 测 is the test depth to which the pressure gauge is lowered by the unstuck device, and ΔH is the water accumulation height during the well shut-in period;

[0040] Then at any time Δti within the time Δt:

[0041] P 中i =P 测i +G Dh气i [H 中 -H 测 -ΔH i ]+9.8×10 -3 ΔH i ;

[0042] Among them, P中i is the deep pressure in the reservoir at any time Δti, P 测i Test depth H for any Δti time 测 Pressure at position, G Dh气i is the gas pressure gradient at any time Δti, H 中 The oil layer is medium-deep, H 测 ΔH is the test depth of the pressure gauge lowered by the card remover i is the water accumulation height at any time Δti;

[0043] (j) Thus, the corrected pressure data can be obtained:

[0044] P 中i =P 测i +G Dh气i (H 中 -H 测 )-(G Dh气i -9.8×10 -3 )·ΔH i

[0045] in:

[0046]

[0047]

[0048] Among them, P 中i is the deep pressure in the reservoir at any time Δti, P 测i Test depth H for any Δti moment 测 Pressure at position, G Dh气i is the gas pressure gradient at any time Δti, H 中 The oil layer is medium-deep, H 测 ΔH is the test depth of the pressure gauge lowered by the card remover i is the water accumulation height at any time Δti; G Dh气1 Gas pressure gradient data in the wellbore before shutting in, G Dh气2 Gas pressure gradient data at the end of well shut-in, Δti is any time of well shut-in; Δt is the well shut-in time; ΔH0 is the water accumulation height in the wellbore before well shut-in, ΔH t is the water accumulation height after the well is shut down for Δt time.

[0049] Since the test instrument was not lowered to the middle of the gas layer, the test pressure was abnormal due to the separation of heavy liquid and gas in the wellbore after the well was shut in. The abnormal pressure data needed to be corrected. Correction purpose: ① Correct the test data to the middle of the gas layer; ② Eliminate the influence of wellbore liquid accumulation on the test data.

[0050] The beneficial effects of the present invention compared with the prior art are:

[0051] Using the correction algorithm provided by the present invention, during the pressure recovery test, the pressure gauge cannot be placed in the middle of the formation, and due to the increase in water accumulation height caused by gas-liquid separation in the wellbore, the pressure recovery curve shows a downward trend. Correction is performed to obtain a pressure recovery curve that can reflect the actual pressure changes of the formation. BRIEF DESCRIPTION OF THE DRAWINGS

[0052] Figure 1 This is the process diagram for the gas well unstuck suspension test (the water accumulation height increases during the well shut-in period).

[0053] Figure 2 It is a test diagram of the gas-liquid phase distribution in the wellbore and the flow pressure gradient of the entire wellbore before shutting in the well.

[0054] Figure 3 It is a test diagram of the gas-liquid phase distribution in the wellbore and the static pressure gradient of the entire wellbore at the end of the well shut-in period.

[0055] Figure 4 It is a schematic diagram of the pressure recovery curve dropping in the later stage.

[0056] Figure 5 It is a pressure recovery curve diagram after correction by the correction method provided by the present invention. DETAILED DESCRIPTION

[0057] The present invention is described in detail below by specific examples, but the protection scope of the present invention is not limited. Unless otherwise specified, the experimental methods used in the present invention are all conventional methods, and the experimental equipment, materials, reagents, etc. used can be obtained from commercial channels.

[0058] Example 1

[0059] Before shutting in the well, the pressure gradient test in the whole wellbore is carried out by using a steel wire to insert a pressure gauge to obtain the water accumulation height ΔH0 in the wellbore before shutting in and the gas pressure gradient data G in the wellbore before shutting in. Dh气1 ;

[0060] Use the card-free hanging device to lower the pressure gauge to the designed test depth H. 测 Shut in the well for pressure recovery test, measure the pressure data within the complete shut-in time Δt, and then pull out the pressure gauge;

[0061] Use the steel wire to run the pressure gauge to test the pressure gradient in the entire wellbore at the end of the well shut-in period, and obtain the gas pressure gradient data G at the end of the well shut-in period. Dh气2 , water height ΔH t ;

[0062] Assuming that the change of water accumulation height in the wellbore is linearly related to time, the relationship equation is established: ΔH t =AΔt+ΔH0, calculate the water accumulation rate: Where A is the water accumulation rate constant, ΔH0 is the height of water accumulation in the wellbore before the wellbore is shut in, and ΔH t is the water accumulation height after the well is shut down for Δt time, where Δt is the shut-in time;

[0063] Assuming that the change of gas pressure gradient in the wellbore is linearly related to time, the relationship equation is established: G Dh气2 =BΔt+G Dh气1 , find the pressure gradient rate constant: Where B is the pressure gradient rate constant, G Dh气1 Gas pressure gradient data in the wellbore before shutting in, G Dh气2 Gas pressure gradient data at the end of well shut-in, Δt is the well shut-in time;

[0064] Build a pressure gauge at a depth of H 测 , test depth H 测 The pressure at position P 测 ; The depth of the oil layer is H 中 , the deep pressure in the oil layer is P 中 ; The pressure gradient in the gas phase in the wellbore is G Dh气 , parameter relationship equation:

[0065] p 中 =p 测 +G Dh气 (H 中 -H 测 -ΔH)+9.8×10 -3 ΔH

[0066] Among them, P 中 is the deep pressure in the oil layer, p 测 For the test depth H 测 Pressure at position, G Dh气 is the gas pressure gradient data, H 中 The oil layer is medium-deep, H 测 is the test depth to which the pressure gauge is lowered by the unstuck device, and ΔH is the water accumulation height during the well shut-in period;

[0067] 7 Then at any time Δti of shut-in, the pressure correction formula is:

[0068] P 中i =P 测i +G Dh气i (H 中 -H 测 )-(G Dh气i -9.8×10 -3 )·ΔH i

[0069] in:

[0070]

[0071]

[0072] Among them, P 中i is the deep pressure in the reservoir at any time Δti, P 测i Test depth H for any Δti time 测 Pressure at position, G Dh气i is the gas pressure gradient at any time Δti, H 中 The oil layer is medium-deep, H 测 ΔH is the test depth of the pressure gauge lowered by the card remover i is the water accumulation height at any time Δti; G Dh气1 Gas pressure gradient data in the wellbore before shutting in, G Dh气2 Gas pressure gradient data at the end of well shut-in, Δti is any time of well shut-in; Δt is the well shut-in time; ΔH0 is the water accumulation height in the wellbore before well shut-in, ΔH t is the water accumulation height after the well is shut down for Δt time.

[0073] This can be used to correct the pressure data tested. The data results are as follows: Figure 5 shown.

[0074] The above-described embodiments are only preferred embodiments of the present invention, but not all feasible embodiments of the present invention. For those skilled in the art, any obvious changes made thereto without departing from the principles and spirit of the present invention should be considered to be included in the scope of protection of the claims of the present invention.

Claims

1. A method for correcting the pressure recovery of a gas well due to abnormal pressure caused by liquid accumulation. Its characteristic is that A method for correcting abnormal gas well pressure recovery data caused by gas-liquid separation in the wellbore after shutting in the well because the pressure gauge cannot be lowered to the middle of the formation; before shutting in the well, a pressure gauge is lowered by a steel wire to test the flow pressure gradient and the height of water accumulation, a de-stuck suspension device is used to test the shut-in pressure recovery data, and at the end of shut-in, a pressure gauge is lowered by a steel wire to test the static pressure gradient and the height of water accumulation.

2. A method for correcting pressure recovery of a gas well due to abnormal pressure caused by liquid accumulation as claimed in claim 1, Its characteristics are: Its characteristics are: The average gas gradient in the wellbore is calculated using the gas pressure gradient data in the wellbore before shut-in.

3. A method for correcting pressure recovery of a gas well due to abnormal pressure caused by liquid accumulation as claimed in claim 1, Its characteristics are: The average gas gradient in the wellbore is calculated using the gas pressure gradient data in the wellbore at the end of the well shut-in period.

4. A method for correcting pressure recovery of a gas well due to abnormal pressure caused by liquid accumulation as claimed in claim 1, Its characteristics are: Using the gas pressure gradient data G in the wellbore before shutting in D h 气1 Calculate the height of water accumulated in the wellbore before the well is shut down.

5. A method for correcting pressure recovery of a gas well due to abnormal pressure caused by liquid accumulation as claimed in claim 1, Its characteristics are: Using the gas pressure gradient data G at the end of the well shut-in period D h 气2 Calculate the height of accumulated water in the wellbore after the well is shut down.

6. A method for correcting pressure recovery of a gas well due to abnormal pressure caused by liquid accumulation as claimed in claim 1, Its characteristics are: A linear equation is established for the change of gas pressure gradient data in the wellbore and the shut-in time, and the pressure gradient rate constant is calculated: Among them, G D h 气1 is the gas pressure gradient data in the wellbore before shutting in; G D h gas 2 is the gas pressure gradient data at the end of well shut-in; B is the pressure gradient rate constant.

7. A method for correcting pressure recovery of a gas well due to abnormal pressure caused by liquid accumulation as claimed in claim 1, Its characteristics are: A linear equation for the change of water accumulation height in the wellbore and the shut-in time was established, and the water accumulation rate constant was calculated.

8. A method for correcting pressure recovery of a gas well due to abnormal pressure caused by liquid accumulation as claimed in claim 1, Its characteristics are: The pressure in the middle of the formation in the wellbore is composed of three parts: the pressure at the measuring point + the pressure of the gas column between the measuring point and the water accumulation height + the pressure generated by the water accumulation height; The gas pressure gradient rate constant and water accumulation rate are used to calculate the gas column pressure between the measuring point and the water accumulation height at any time. The water accumulation density and water accumulation rate constant are used to calculate the pressure generated by water accumulation in the wellbore at any time.

9. A method for correcting pressure recovery in a gas well due to abnormal pressure caused by liquid accumulation as claimed in any one of claims 1 to 8, Its characteristics are: The specific steps are as follows: (a) Before shutting in the well, a pressure gradient test is performed by lowering a pressure gauge using a steel wire to measure the gas pressure gradient data G in the wellbore before shutting in the well. Dh气1 , G Dh气1 The value changes with the depth and phase state in the wellbore. Since the density difference between gas and liquid is large, the inflection point of the pressure gradient change in the wellbore is the gas-water interface, from which the phase state of the fluid in the wellbore and the depth of the water surface can be determined. Assume that the height of water accumulation in the wellbore before the wellbore is shut in is ΔH. 0 , the water density is Generally speaking, if the gas has a strong enough liquid-carrying capacity, there is no liquid accumulation in the wellbore, so the height of water accumulation in the wellbore before the wellbore is shut in is ΔH 0 =0; (b) After the pressure profile test is completed before shutting in the well, the pressure gauge is lowered to the designed test depth H using the unstuck suspension device. 测 After that, shut in the well for pressure recovery test, measure the pressure data within the complete shut-in time Δt; use the fishing head to pull out the pressure gauge; (c) In the shut-in state, the pressure gauge is lowered by the steel wire to perform the pressure gradient test at the end of the shut-in period to obtain the gas pressure gradient data G at the end of the shut-in period. Dh气2 , because the density of gas and liquid is quite different, the inflection point of the pressure gradient change in the wellbore is the gas-water interface, from which the phase state of the fluid in the wellbore and the depth of the water surface can be determined, and the water accumulation height ΔH after the well is shut in for Δt time can be calculated. t , the pressure generated by the water height at time Δt is: where p 积水 is the water height ΔH at time Δt t The pressure generated; ΔH t is the water accumulation height after the well is shut down for Δt time; (d) Assuming that the water accumulation height ΔH is positively correlated with the well shut-in time Δt, let A be the water accumulation rate constant, m / h, ΔH 0 ΔH is the height of water accumulation in the wellbore before the wellbore is shut in. t is the water accumulation height after the well is shut down for Δt time, then ΔH t =AΔt+ΔH 0 ;but Where A is the water accumulation rate constant, ΔH 0 ΔH is the height of water accumulation in the wellbore before the wellbore is shut in. t is the water accumulation height after the well is shut down for Δt time, where Δt is the shut-in time; (e) The height of water accumulation at any time Δti is: ΔH i =AΔti+ΔH 0 ; ΔH i is the water height at any time Δti, ΔH 0 is the height of water in the wellbore before the wellbore is shut in, Δt is the shut-in time, ΔH t is the water accumulation height after the well is shut down for Δt time, and Δti is any time when the well is shut down; (f) The shut-in pressure recovery test time is Δt, the water accumulation height during the shut-in period is ΔH, and the water accumulation height at any Δti time within Δt is ΔH i , then the pressure generated by the water accumulation height at any time during the shut-in period is p 积水i =9.8×10 -3 ·ΔH i ; where ΔH i is the water accumulation height at any time Δti, p 积水i is the water accumulation height ΔH at any time Δti during the well shut-in period i The pressure generated; (g) The shut-in pressure recovery test time is Δt, and the gas pressure gradient data in the wellbore before shutting in is G Dh气1 , the gas pressure gradient data at the end of well shut-in is G Dh气2 , assuming that the gas pressure gradient data G Dh气 is positively correlated with the shut-in time Δt. Let B be the pressure gradient rate constant, MPa / mh, then G Dh气2 =BΔt+G Dh气1 ;but Where B is the pressure gradient rate constant, G Dh气1 Gas pressure gradient data in the wellbore before shutting in, G Dh气2 Gas pressure gradient data at the end of well shut-in, Δt is the well shut-in time; (h) Then the gas pressure gradient at any time Δti is: G Dh气i =BΔti+G Dh气1 ; Among them, G Dh气1 Gas pressure gradient data in the wellbore before shutting in, G Dh气2 Gas pressure gradient data at the end of well shut-in, B is the pressure gradient rate constant, Δti is any time of well shut-in; G Dh气i is the gas pressure gradient at any time Δti; Δt is the shut-in time; (i) The depth of the pressure gauge is H 测 , test depth H 测 The pressure at position P 测 ; The depth of the oil layer is H 中 , the deep pressure in the oil layer is P 中 ; The gas pressure gradient data in the gas phase state in the wellbore is G Dh气 , then the deep pressure in the oil layer during the test is: p 中 =p 测 +G Dh气 (H 中 -H 测 -ΔH)+9.8×10 -3 ·ΔH Among them, P 中 is the deep pressure in the oil layer, p 测 For the test depth H 测 Pressure at position, G Dh气 is the gas pressure gradient data, H 中 The oil layer is medium-deep, H 测 is the test depth to which the pressure gauge is lowered by the unstuck device, and ΔH is the water accumulation height during the well shut-in period; Then at any time Δti within the time Δt: P 中i =P 测i +G Dh气i [H 中 -H 测 -ΔH i ]+9.8×10 -3 ·ΔH i ; Among them, P 中i is the deep pressure in the reservoir at any time Δti, P 测i Test depth H for any Δti time 测 Pressure at position, G Dh气i is the gas pressure gradient at any time Δti, H 中 The oil layer is medium-deep, H 测 ΔH is the test depth of the pressure gauge lowered by the card remover i is the water accumulation height at any time Δti; (j) Thus, the corrected pressure data can be obtained: P 中i =P 测i +G Dh气i (H 中 -H 测 )-(G Dh气i -9.8×10 -3 )·ΔH i in: Among them, P 中i is the deep pressure in the reservoir at any time Δti, P 测i Test depth H for any Δti time 测 Pressure at position, G Dh气i is the gas pressure gradient at any time Δti, H 中 The oil layer is medium-deep, H 测 ΔH is the test depth of the pressure gauge lowered by the card remover i is the water accumulation height at any time Δti; G Dh气1 Gas pressure gradient data in the wellbore before shutting in, G Dh气2 Gas pressure gradient data at the end of well shut-in, Δti is any time of well shut-in; Δt is the well shut-in time; ΔH 0 ΔH is the height of water accumulation in the wellbore before the wellbore is shut in. t is the water accumulation height after the well is shut down for Δt time.

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