Method for determining shaft pressure distribution of tight gas reservoir horizontal well

Abstract

The invention discloses a tight gas reservoir horizontal well shaft pressure distribution determination method, which comprises the following steps of: 1, selecting a corresponding number of target gas wells, and acquiring production dynamic data and well deviation data of the target gas wells; 2, on the basis of original pressure test data, establishing a pressure gradient calculation model by utilizing regression analysis; 3, by means of the pressure gradient calculation model in the step 2, pressure gradients at different positions of the shaft are obtained after relevant parameters are input; according to the method, a multi-factor regression calculation model is established through actual measurement of flow pressure test data, and the calculation accuracy of wellbore pressure distribution is improved; and a simple method for accurately and rapidly analyzing and judging the liquid accumulation condition of the gas well shaft through production dynamic data is provided.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of gas field development, in particular to a method for determining wellbore pressure distribution of a horizontal well in a tight gas reservoir. BACKGROUND

[0002] In the development process of a tight gas reservoir, correctly obtaining the wellbore pressure distribution of a gas well is of great significance to determining a reasonable gas well working system and reasonable drainage measures.

[0003] The most direct method for obtaining the wellbore pressure distribution is to lower an electronic pressure gauge into the well through a wireline or a coiled tubing. However, the testing depth of the testing tool is affected by the inclination of the horizontal well, and the pressure gradient in the middle of the gas layer cannot be directly obtained. For example, a 60.3mm tubing test encounters resistance at a well inclination of 45° to 60°, and the pressure gradient of the last measuring point is used to convert the pressure in the middle of the gas layer, which has a certain error in calculation.

[0004] At present, in the literatures published at home and abroad, the main methods for determining the wellbore pressure distribution of a tight gas reservoir include an empirical model (such as the Hagedorn-Brown model and the Beggs-Brill model) and a theoretical model (such as the Ansari model and the Hasan-Kabir model). These models require fluid PVT parameters, liquid holdup, heat transfer coefficient, and friction coefficient, and the calculation process is relatively complex, which is difficult to apply in the field.

[0005] In addition, a cloud-based high-frequency wellhead pressure production data analysis method is disclosed in a Chinese patent with the publication number CN116455946A, which provides a method for calculating the bottom hole pressure in real time by using a vertical pipe flow model and a fourth-order Runge-Kutta method.

[0006] However, this method does not consider the flow in the inclined section, and the calculation process is complicated, which is difficult to apply in the field.

[0007] In addition, a method for obtaining the bottom hole flowing pressure of a coalbed methane well is disclosed in a Chinese patent with the publication number CN109446238A, which discloses a method for calculating the bottom hole flowing pressure after testing the dynamic liquid level by using a liquid level echo instrument. However, the dynamic liquid level testing data should be reliable, but the variable pressure gradient exists in the wellbore of a tight gas well, and it is not suitable for testing in the open well state. SUMMARY

[0008] The present application aims to provide a method for determining the wellbore pressure distribution of a horizontal well in a tight gas reservoir, which aims to improve the defects in the method for determining the wellbore pressure distribution of a tight gas reservoir, and to realize more accurate pressure distribution.

[0009] The present application is implemented as follows: a method for determining the wellbore pressure distribution of a horizontal well in a tight gas reservoir, comprising

[0010] Step one: select corresponding number of target gas well, and obtain production dynamic data and deviation data of target gas well;

[0011] Step two: on the basis of original pressure testing data, use regression analysis to establish pressure gradient calculation model;

[0012] Step three: use pressure gradient calculation model in step two, and input relevant parameters to obtain pressure gradient at different positions of wellbore.

[0013] Preferably, the data in step one includes flow pressure testing data, oil pressure, casing pressure, gas-liquid ratio, deviation angle, flow pressure gradient.

[0014] Preferably, the flow pressure testing data is from horizontal well, the oil pressure, casing pressure and gas-liquid ratio are data during gas well testing, and the deviation angle corresponds to different vertical depths.

[0015] Preferably, in step two, the deviation angle, gas-liquid ratio and oil-casing pressure below the build-up point are used as dependent variables, and the multivariate regression method is used to obtain the pressure gradient calculation model.

[0016] Preferably, the pressure gradient calculation model is as follows

[0017] M i =0.47-0.441·sin(90-θ)+0.006·ln(GLR)+0.011·ln(AP)+0.0124·P c .

[0018] Preferably, Mi is wellbore pressure gradient, MPa / 100m; θ is deviation angle, °; GLR is gas-liquid ratio, 10 4 m 3 / m 3 ; AP is oil-casing pressure difference, MPa; Pc is casing pressure, MPa.

[0019] Preferably, the following pressure calculation formula is used for iterative calculation to calculate the pressure P1 of next point

[0020] P i+1 =P i +M i ·ΔH / 100

[0021] Preferably, P i is pressure at i-th point in wellbore, MPa; P i+1 is pressure at i+1-th point in wellbore, MPa; M i is pressure gradient at i-th point in wellbore, MPa / 100m; ΔH is depth difference between i+1-th point and i-th point in wellbore, m; when i=n, P n represents middle pressure in gas layer, MPa.

[0022] Preferably, M i The pressure gradient at different positions of the wellbore is calculated based on the pressure gradient calculation model and the input parameters.

[0023] Preferably, the pressure P of the middle depth of the gas layer at the depth H is calculated based on the pressure calculation formula and analogy. n .

[0024] Compared with the prior art, the present application has the following beneficial effects: 1) a multi-factor regression calculation model is established by using the measured flow pressure test data, and the calculation accuracy of the wellbore pressure distribution is improved; 2) a simple and convenient method for accurately and quickly analyzing and judging the gas well wellbore liquid loading condition by using the production dynamic data is provided. BRIEF DESCRIPTION OF DRAWINGS

[0025] Figure 1 Flow chart for determining the wellbore pressure distribution of the horizontal well in the tight gas reservoir;

[0026] Figure 2 Schematic diagram of the calculation flow of the wellbore pressure distribution of the horizontal well in the tight gas reservoir;

[0027] Figure 3 Error diagram of the model predicted pressure gradient and the measured data;

[0028] Figure 4 Comparison diagram of the predicted pressure distribution and the measured results of the typical well. DETAILED DESCRIPTION

[0029] In the present application, unless otherwise explicitly specified and limited, the terms such as "mounting", "connection", "linking", "fixing" and the like should be understood in a broad sense, for example, can be fixed connection, or detachable connection, or integrated; can be mechanical connection, or electrical connection; can be directly connected, or indirectly connected through an intermediate medium; can be the internal communication of two elements or the interaction relationship between two elements. For those skilled in the art, the specific meanings of the above terms in the present application can be understood according to the specific circumstances.

[0030] The following will be further described in combination with the drawings and specific embodiments:

[0031] In order to solve the problems proposed in the background art, the present embodiment provides a method for determining the wellbore pressure distribution. The specific process is as follows:

[0032] 1) Obtain the production dynamic data and the inclination data of the target gas well

[0033] The flow pressure test data of 109 horizontal wells in the block and the oil pressure, casing pressure, gas-liquid ratio and well inclination angle corresponding to different vertical depths and flow pressure gradient during gas well testing were collated according to the well selection requirements in step 1), totaling 485 data points.

[0034] 2) Based on the historical pressure test data, the pressure gradient distribution in the wellbore was determined

[0035] According to the data regression requirements in step 2), the inclination angle, liquid-gas ratio and oil-casing pressure data below the build-up point were input parameters, and regression analysis was performed to establish the relationship with the pressure gradient, and the final pressure gradient calculation model is as follows:

[0036] M i = 0.47-0.441·sin(90-θ)+0.006·ln(GLR)+0.011·ln(ΔP)+0.0124·P c (1)

[0037] In the formula: M i is the wellbore pressure gradient, MPa / 100m; θ is the inclination angle, °; GLR is the gas-liquid ratio, 10 4 m 3 / m 3 ; AP is the oil-casing pressure difference, MPa; P c is the casing pressure, MPa.

[0038] The flow pressure gradient in the calculation model was compared with the measured flow pressure gradient, and the error graph is shown in Figure 2 . The results show that the average absolute error of the regression model is 0.035 MPa / 100m, and the root mean square error is 0.003 MPa / 100m, which has good precision for the block.

[0039] 3) Determine the pressure distribution in the wellbore

[0040] According to formula (1) established in step 2), the pressure gradient M i at different positions in the wellbore was calculated after inputting the parameters, the wellhead oil pressure was taken as P0, and P0 and M0 were substituted into formula (2) for iterative calculation to calculate the pressure P1 of the next point, and so on to finally calculate the pressure P n of the middle depth of the gas layer at a depth of H.

[0041] P i+1 = P i + M i · ΔH / 100 (2)

[0042] In the formula: P i is the pressure at the i-th point in the wellbore, MPa; P i+1 is the pressure at the i+1-th point in the wellbore, MPa; Mi P is the pressure gradient at the i-th point in the wellbore, MPa / 100 m; ΔH is the depth difference between the i+1-th point and the i-th point in the wellbore, m; when i = n, P n P is the pressure gradient at the i-th point in the wellbore, MPa / 100 m; ΔH is the depth difference between the i+1-th point and the i-th point in the wellbore, m; when i = n, P

[0043] The pressure gradient and pressure distribution calculation results of the DPX well are shown in FIG. 2, and the well flow pressure test operation is blocked at the inclination angle of 45° due to the resistance, and the subsequent pressure data cannot be obtained. The traditional method uses the pressure gradient before the last measuring point to convert the gas layer mid-pressure, but in the actual production process, the accumulation problem shows an increasing trend to the bottom of the well, that is, the test pressure gradient gradually increases. The model of the calculation method can predict the gradient below the resistance position, and improve the calculation accuracy of the bottom hole flowing pressure. In addition, the relative error of the pressure gradient before the last measuring point and the measured pressure gradient can be controlled within 1.1%, which verifies the accuracy of the present application. Figure 4

[0044] Table 1

[0045]

[0046]

[0047] The above is only a preferred embodiment of the present application and is not used to limit the present application. For those skilled in the art, the present application can have various modifications and changes. Any modification, equivalent replacement, improvement, etc. within the spirit and principles of the present application shall be included in the protection scope of the present application.​

Claims

1. A method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir, characterized in that, include Step 1: Select the appropriate number of target gas wells and obtain the production dynamics data and well deviation data of the target gas wells; Step 2: Based on the existing pressure test data, establish a pressure gradient calculation model using regression analysis; Step 3: Using the pressure gradient calculation model from Step 2, the pressure gradient at different locations in the wellbore is obtained after inputting relevant parameters.

2. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 1, characterized in that, The data in step one includes flow pressure test data, oil pressure, casing pressure, gas-liquid ratio, well inclination angle, and flow pressure gradient.

3. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 2, characterized in that, The flowing pressure test data comes from horizontal wells, while the oil pressure, casing pressure, and gas-liquid ratio are data from gas well tests. The well inclination angle corresponds to different vertical depths.

4. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 1, characterized in that, In step two, the well inclination angle, liquid-gas ratio, and oil-casing pressure data below the build-up point are used as dependent variables, and a multiple regression method is used to obtain the pressure gradient calculation model.

5. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 4, characterized in that, The pressure gradient calculation model is shown below. M i <0.47-0.441·sin(90-θ)+0.006·ln(GLR)+0.011·ln(AP)+0.0124·P c ...

6. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 5, characterized in that, M i θ is the wellbore pressure gradient, MPa / 100m; θ is the well inclination angle, °; GLR is the gas-liquid ratio, 10 4 m 3 / m 3 ΔP is the oil-casing pressure difference, MPa; Pc is the casing pressure, MPa.

7. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 6, characterized in that, Calculate the pressure P1 at the next point using the following pressure calculation formula through iterative calculation. P i+1 =P i +M i ·ΔH / 100。 8. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 7, characterized in that, P i P is the pressure at point i in the wellbore, in MPa; i+1 M is the pressure at point i+1 in the wellbore, in MPa; i P is the pressure gradient at point i in the wellbore, MPa / 100m; ΔH is the depth difference between point i+1 and point i in the wellbore, m; when i=n, P n This indicates the pressure in the middle of the gas layer, in MPa.

9. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 8, characterized in that, M i It is based on the pressure gradient calculation model, and the pressure gradient at different locations in the wellbore is calculated after inputting parameters.

10. The method for determining the pressure distribution in a horizontal wellbore of a tight gas reservoir according to claim 8, characterized in that, Based on the pressure calculation formula, the pressure P at the mid-depth of the gas layer at a depth of H can be calculated by analogy. n .

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