A quantitative analysis method for the degree of blockage in carbonate gas reservoirs.

Abstract

This invention relates to the field of oil and gas reservoirs and discloses a quantitative analysis method for the degree of blockage in carbonate gas reservoirs. The method includes: obtaining reservoir and fluid interpretation parameters of the carbonate gas reservoir; identifying blockage characteristics of the carbonate gas reservoir; calculating the ideal cumulative gas production, and subtracting the ideal cumulative gas production from the actual cumulative gas production to obtain the lost gas production, which characterizes the total degree of blockage in the gas reservoir; calculating the actual reservoir production and the theoretical reservoir production, and subtracting the theoretical reservoir production from the actual reservoir production to obtain the reservoir's daily lost gas production, which characterizes the degree of reservoir blockage; calculating the theoretical wellbore production and the actual wellbore production, and subtracting the theoretical wellbore production from the actual wellbore production to obtain the wellbore's daily lost gas production, which characterizes the degree of wellbore blockage. In this invention, the production under theoretical and actual conditions is analyzed separately to obtain parameters that characterize the degree of blockage in the reservoir and wellbore, thus achieving a quantitative analysis of the degree of blockage in the wellbore and reservoir of carbonate gas reservoirs.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas reservoirs, in particular to a quantitative analysis method for the plugging degree of a carbonate rock gas reservoir. BACKGROUND

[0002] During the development of a carbonate rock gas reservoir, long-term precipitation of inorganic substances such as iron compounds, barium sulfate, calcium carbonate, magnesium carbonate and silicon dioxide, and a small amount of organic matter falling off, will all cause serious plugging of the wellbore and reservoir throat, and affect the production of the gas well.

[0003] For different plugging degrees of gas wells, subsequent carbonate rock gas well stimulation measures and production performance evaluation will be carried out, therefore, the analysis result of the plugging degree of the gas well will have an important influence on the final gas well production.

[0004] In the prior art, the plugging of the carbonate rock gas reservoir is judged by carrying out the plugging material at the wellhead, but the plugging of the reservoir cannot be accurately identified, and the plugging degree of the wellbore and the reservoir of the carbonate rock gas reservoir cannot be quantitatively analyzed, which leads to the fact that the subsequent carbonate rock gas well stimulation measures and production performance evaluation cannot be accurately carried out, and finally the production of the gas well is affected. SUMMARY

[0005] Therefore, the present application provides a quantitative analysis method for the plugging degree of a carbonate rock gas reservoir, which effectively solves the technical problem that in the prior art, the plugging of the reservoir cannot be accurately identified, and the plugging degree of the wellbore and the reservoir of the carbonate rock gas reservoir cannot be quantitatively analyzed, which leads to the fact that the subsequent carbonate rock gas well stimulation measures and production performance evaluation cannot be accurately carried out, and finally the production of the gas well is affected.

[0006] To solve the above technical problems, the present application specifically provides the following technical scheme: a quantitative analysis method for the plugging degree of a carbonate rock gas reservoir, comprising the following steps:

[0007] Step 100: periodically performing pressure buildup test on the gas well to obtain carbonate rock gas reservoir and fluid interpretation parameters;

[0008] Step 200: performing stage-by-stage comparative analysis on the carbonate rock gas reservoir and fluid interpretation parameters to identify the plugging characteristics of the carbonate rock gas reservoir according to the comparison result, and dividing the entire stage into a pre-plugging stage and a post-plugging stage based on the plugging characteristics of the carbonate rock gas reservoir;

[0009] Step 300: calculating the well-controlled dynamic reserves based on the carbonate rock gas reservoir and fluid interpretation parameters, and calculating the ideal cumulative gas production according to the well-controlled dynamic reserves, obtaining the real cumulative gas production, and obtaining the loss gas production by subtracting the ideal cumulative gas production from the real cumulative gas production, to represent the total plugging degree of the gas reservoir;

[0010] Step 400: Calculate the ideal reservoir permeability and actual reservoir production based on the reservoir and fluid interpretation parameters of the carbonate gas reservoir. Calculate the theoretical reservoir production based on the ideal reservoir permeability. Subtract the theoretical reservoir production from the actual reservoir production to obtain the daily gas production loss of the reservoir, which characterizes the degree of reservoir blockage.

[0011] Step 500: Calculate the theoretical wellbore production and actual wellbore production using the interpretation parameters of the carbonate gas reservoir and fluids before and after the blockage. Subtract the theoretical wellbore production from the actual wellbore production to obtain the daily gas production loss in the wellbore, which characterizes the degree of wellbore blockage.

[0012] Furthermore, in step 100, after each pressure recovery test of the gas well, the test data is fitted using the pressure recovery test interpretation chart to obtain the interpretation parameters of the carbonate gas reservoir and fluids.

[0013] Furthermore, the reservoir and fluid interpretation parameters of the carbonate gas reservoir include skin factor, formation factor, formation pressure, zone radius, and zone permeability.

[0014] Further, in step 200, the gas production and oil pressure of the gas well are measured and the gas production curve and oil pressure curve are plotted. The interpretation parameters of the carbonate gas reservoir and fluid are compared and analyzed in stages according to time sequence to obtain the change status of the interpretation parameters of the carbonate gas reservoir and fluid.

[0015] Based on the changes in the reservoir and fluid interpretation parameters of the carbonate gas reservoir, the gas production curve, the oil pressure curve, and the wellhead condition, the blockage characteristics of the carbonate gas reservoir were identified.

[0016] Furthermore, the blockage characteristics of the carbonate gas reservoir include sudden changes in both the gas production curve and the oil pressure curve, an overall downward trend in the gas production curve, an increase in the skin coefficient, a decrease in zoned permeability, and blockage material carried out from the wellhead.

[0017] Furthermore, the calculation process for the ideal cumulative gas production includes the following steps:

[0018] Substitute the oil pressure data into the following formula to calculate the bottom hole flowing pressure:

[0019] P wf =P o +10 -3 ρgH;

[0020] In the formula, P wf For the bottom hole flowing pressure, P o Where ρ is the oil pressure, g is the density of the mixed fluid, H is the acceleration due to gravity, and H is the depth from the wellhead to the bottom of the well.

[0021] The calculated bottom hole flowing pressure Pwf The average formation pressure is calculated by substituting the following formula:

[0022]

[0023] In the formula, P is the average formation pressure, P e is the formation pressure interpreted by the pressure buildup test, r e is the zonal radius interpreted by the pressure buildup test, r w is the wellbore radius;

[0024] Rock compression experiment test and formation water high-pressure physical property experiment test are performed, and the test parameters obtained based on the rock compression experiment test and the formation water high-pressure physical property experiment test are substituted into the following formula to calculate the comprehensive compression coefficient of the gas reservoir:

[0025]

[0026] In the formula, C c is the comprehensive compression coefficient of the gas reservoir, C p is the rock compression coefficient, S wc is the water phase saturation, C w is the water phase compression coefficient, and the rock compression coefficient, the water phase saturation, and the water phase compression coefficient are all test parameters obtained by the rock compression experiment test and the formation water high-pressure physical property experiment test;

[0027] The data of the stage before plugging are substituted into the following linear relationship formula of cumulative gas production and average formation pressure to calculate the well-controlled dynamic reserves G, and the data of the stage after plugging and the calculated well-controlled dynamic reserves G are substituted into the linear relationship formula to inversely calculate the ideal cumulative gas production G without considering the influence of plugging p :

[0028]

[0029] In the formula, Z is the deviation factor under the average formation pressure, ΔP is the production pressure difference, P i is the original formation pressure, Z i is the deviation factor under the original formation pressure, G p is the current cumulative gas production, and G is the well-controlled dynamic reserves.

[0030] Further, the calculation process of the theoretical reservoir production and the actual reservoir production includes the following steps:

[0031] Core pressure-confining porosity experiment is performed, and a relationship formula of permeability changing with pressure is obtained based on the core pressure-confining porosity experiment:

[0032] K a = K ∞ EXP[-α(P i -P)]

[0033] wherein K a is the ideal reservoir permeability considering strain and not reservoir plugging, K ∞ is the original reservoir permeability value, a is the sensitivity coefficient, P i is the original formation pressure, P is the average formation pressure;

[0034] The ideal reservoir permeability considering strain and not reservoir plugging is calculated by substituting the average formation pressure P into the above formula, and the ideal reservoir permeability considering strain and not reservoir plugging is substituted into the following formula to calculate the theoretical reservoir production without considering the influence of the skin factor:

[0035]

[0036] wherein Q a is the theoretical reservoir production without considering the influence of the skin factor, h is the reservoir thickness, μ is the fluid viscosity, P e is the formation pressure interpreted from the pressure buildup test, P wf is the bottom hole flowing pressure, k ai is the ideal reservoir permeability considering strain and not reservoir plugging of the i-th zone, r i is the zonal radius of the i-th zone, r i-1 is the zonal radius of the (i-1)-th zone;

[0037] The actual reservoir production without considering the influence of the skin factor is calculated by substituting the zonal permeability interpreted from the pressure buildup test into the following formula:

[0038]

[0039] wherein Q s is the actual reservoir production without considering the influence of the skin factor, k si is the i-th zone permeability interpreted from the pressure buildup test.

[0040] Further, the calculation process of the theoretical wellbore production, the actual wellbore production comprises the following steps:

[0041] The skin factor interpreted from the pressure buildup test before plugging is substituted into the following formula to calculate the theoretical wellbore production:

[0042]

[0043] wherein Q F is the theoretical wellbore production without considering the wellbore plugging, h is the reservoir thickness, μ is the fluid viscosity, P e is the formation pressure interpreted from the pressure buildup test, P wf is the bottom hole flowing pressure, k siis the permeability of the ith zone interpreted from the pressure buildup test, r i is the zonal radius of the ith zone, r i-1 is the zonal radius of the (i-1)th zone, r e is the zonal radius interpreted from the pressure buildup test, r w is the wellbore radius, S F is the skin factor interpreted from the pressure buildup test before the plugging;

[0044] The skin factor interpreted from the pressure buildup test after the plugging is substituted into the following formula to calculate the actual wellbore production:

[0045]

[0046] In the formula, Q B is the actual wellbore production considering the plugging of the wellbore, S B is the skin factor interpreted from the pressure buildup test after the plugging.

[0047] Compared with the prior art, the present application has the following beneficial effects:

[0048] In the present application, the influence of the reservoir and the fluid micro-compressibility is considered, the production in the theoretical state and the actual state is analyzed starting from the influence of the plugging of the wellbore and the change of the reservoir physical property on the production of the gas well, the parameter capable of representing the plugging degree of the reservoir and the wellbore is obtained, the quantitative analysis of the plugging degree of the carbonate rock gas reservoir wellbore and the reservoir is realized, so that the corresponding carbonate rock gas well stimulation measures and the production dynamic evaluation can be carried out subsequently. BRIEF DESCRIPTION OF DRAWINGS

[0049] In order to more clearly illustrate the embodiments of the present application or the technical solutions in the prior art, the drawings needed to be used in the following embodiment or prior art description will be briefly introduced. Obviously, the drawings in the following description are only exemplary, and other drawings can be obtained by the provided drawings without creative labor for those skilled in the art.

[0050] Figure 1 is the flowchart of the quantitative analysis method of the plugging degree of the carbonate rock gas reservoir provided by the embodiment of the present application;

[0051] Figure 2 is the interpretation parameter table of the pressure buildup test of the carbonate rock gas reservoir B10 well in a certain block at different production times;

[0052] Figure 3 is the data table of the average formation pressure, the gas reservoir comprehensive compression coefficient and the cumulative gas production of the carbonate rock gas reservoir B10 well in a certain block at different production times;

[0053] Figure 4The data of ideal reservoir permeability, reservoir loss daily gas production and wellbore loss daily gas production of B10 well of a carbonate gas reservoir in a certain block at different production times are obtained. DETAILED DESCRIPTION

[0054] The technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application. Obviously, the described embodiments are only a part of the embodiments of the present application, rather than all the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by those skilled in the art without creative work fall within the protection scope of the present application.

[0055] As shown in Figure 1 The present application provides a quantitative analysis method for plugging degree of carbonate gas reservoir, comprising the following steps:

[0056] Step 100, periodically performing pressure recovery well testing on the gas well to obtain carbonate gas reservoir and fluid interpretation parameters;

[0057] Step 200, performing stage-by-stage comparative analysis on the carbonate gas reservoir and fluid interpretation parameters to identify the plugging characteristics of the carbonate gas reservoir according to the comparative results, and dividing the whole stage into a pre-plugging stage and a post-plugging stage based on the plugging characteristics of the carbonate gas reservoir;

[0058] Step 300, calculating the well-controlled dynamic reserves based on the carbonate gas reservoir and fluid interpretation parameters, and calculating the ideal cumulative gas production according to the well-controlled dynamic reserves, obtaining the real cumulative gas production, and obtaining the loss gas production by subtracting the ideal cumulative gas production from the real cumulative gas production to represent the total plugging degree of the gas reservoir;

[0059] Step 400, calculating the ideal reservoir permeability and the actual reservoir production based on the carbonate gas reservoir and fluid interpretation parameters, calculating the theoretical reservoir production according to the ideal reservoir permeability, and obtaining the reservoir loss daily gas production by subtracting the actual reservoir production from the theoretical reservoir production to represent the plugging degree of the reservoir;

[0060] Step 500, calculating the theoretical wellbore production and the actual wellbore production by using the carbonate gas reservoir and fluid interpretation parameters of the pre-plugging stage and the post-plugging stage respectively, and obtaining the wellbore loss daily gas production by subtracting the actual wellbore production from the theoretical wellbore production to represent the plugging degree of the wellbore.

[0061] In the present application, the influence of reservoir and fluid micro-compressibility is considered, the influence of wellbore plugging and reservoir property change on gas well production is started, the production in the theoretical state and the actual state is analyzed respectively, the parameter capable of representing the degree of reservoir and wellbore plugging is obtained, the quantitative analysis of the degree of carbonate rock gas reservoir wellbore and reservoir plugging is realized, so as to facilitate the subsequent corresponding carbonate rock gas well stimulation measures and production dynamic evaluation.

[0062] In step 100, after each time the gas well is tested by the pressure recovery test, the test data is fitted by using the pressure recovery test interpretation chart to obtain the carbonate rock gas reservoir and fluid interpretation parameters.

[0063] The interpretation process principle of the pressure recovery test interpretation process is as follows: different reservoir and fluid parameters are input into an ideal model to obtain different production and pressure curves, the production and pressure curves are compiled into a chart, the actual production and pressure data of the gas well are tested, the actual production and pressure curves are compared with the production and pressure curves of the chart, and the reservoir and fluid parameters corresponding to the fitted chart curve can be approximately equivalent to the actual reservoir and fluid conditions.

[0064] The carbonate rock gas reservoir and fluid interpretation parameters include skin factor, formation factor, formation pressure, zonal radius and zonal permeability.

[0065] Taking the carbonate rock gas reservoir B10 well in a certain block as an example, the plugging material is taken out from the wellbore after the B10 well is produced for a period of time, during the production of the B10 well, the gas well is tested by the pressure recovery test every 2 months in the initial stage, for 3 times, then the gas well is tested by the pressure recovery test every half year, for 2 times, and the test results are interpreted, and the interpretation parameters are as shown in Figure 2

[0066] In step 200, the gas production and oil pressure of the gas well are measured during the production of the gas well, the gas production curve and the oil pressure curve are drawn, the carbonate rock gas reservoir and fluid interpretation parameters are compared and analyzed in time sequence, and the change state of the carbonate rock gas reservoir and fluid interpretation parameters is obtained.

[0067] According to the change state of the carbonate rock gas reservoir and fluid interpretation parameters, the gas production curve, the oil pressure curve and the gas well head state, the plugging characteristics of the carbonate rock gas reservoir are identified.

[0068] ​Carbonate gas reservoir blockage characteristics are generally observed when the following features are present in the reservoir and fluid interpretation parameters, gas production curve, oil pressure curve, and wellhead condition: sudden changes in both gas production and oil pressure curves, an overall downward trend in gas production curve, increased skin coefficient, decreased zoned permeability, and blockage material carried out by the wellhead.

[0069] Taking the B10 well in the carbonate gas reservoir as an example, this paper analyzes the identification characteristics of blockage in carbonate gas reservoirs. Figure 2 It can be seen that the skin coefficient increased significantly after 15 months of testing, the permeability interpretation results decreased significantly with each step, a small amount of blockage material was carried out during wellhead production, and the blockage material was taken out from the wellbore. The measured results showed that it was an inorganic substance such as iron compounds, barium sulfate, and calcium carbonate, indicating that the gas well has the typical characteristics of gas reservoir blockage.

[0070] The reservoir and fluid interpretation parameters of carbonate gas reservoirs changed abruptly between 9 and 15 months, which can be divided into two stages: the production data from 0 to 9 months represents the pre-blockage stage, and the test data from 15 months represents the post-blockage stage.

[0071] After identifying the blockage characteristics of carbonate gas reservoirs, it is necessary to calculate the relevant data in sequence and characterize the total blockage degree of the gas reservoir, the blockage degree of the reservoir, and the blockage degree of the wellbore.

[0072] First, the well-controlled dynamic reserves are calculated based on the reservoir and fluid interpretation parameters of the carbonate gas reservoir. Then, the ideal cumulative gas production is calculated based on the well-controlled dynamic reserves. The actual cumulative gas production is obtained. The difference between the ideal cumulative gas production and the actual cumulative gas production is used to obtain the lost gas production, which is used to characterize the total blockage degree of the gas reservoir.

[0073] The calculation process for the ideal cumulative gas production includes the following steps:

[0074] Substitute the oil pressure data into the following formula to calculate the bottom hole flowing pressure:

[0075] P wf =P o +10 -3 ρgH;

[0076] In the formula, P wf For the bottom hole flowing pressure, P o Where ρ is the oil pressure, g is the density of the mixed fluid, H is the acceleration due to gravity, and H is the depth from the wellhead to the bottom of the well.

[0077] The calculated bottom hole flowing pressure P wf Substitute the values ​​into the following formula to calculate the mean formation pressure:

[0078]

[0079] In the formula, P is the mean formation pressure, Pe For the formation pressure interpreted from the pressure recovery well test, r e The zoning radius r for interpreting pressure recovery well tests. w Where is the wellbore radius;

[0080] Rock compression tests and formation water high-pressure physical property tests were conducted. Based on the test parameters obtained from these tests, the overall compressibility coefficient of the gas reservoir was calculated using the following formula:

[0081]

[0082] In the formula, C c C is the overall compressibility coefficient of the gas reservoir. p S is the rock compressibility coefficient. wc C represents the water phase saturation. w The water phase compressibility coefficient, rock compressibility coefficient, water phase saturation, and water phase compressibility coefficient are all test parameters obtained from rock compression experiments and formation water high-pressure physical property experiments.

[0083] Substituting the data from the pre-blockage stage into the linear relationship between cumulative gas production and average formation pressure, the well-controlled dynamic reserves G are calculated. Then, substituting the data from the post-blockage stage and the calculated well-controlled dynamic reserves G into the linear relationship, the ideal cumulative gas production G, without considering the impact of blockage, is calculated in reverse. p :

[0084]

[0085] In the formula, Z is the deviation factor under average formation pressure, ΔP is the production pressure difference, and P i Z represents the original formation pressure. i G is the deviation factor under the original formation pressure. p G represents the current cumulative gas production, and G represents the well-controlled dynamic reserves.

[0086] The ideal cumulative gas production can be calculated through the above steps, such as... Figure 3 The figure shows the average formation pressure, cumulative gas production, and overall reservoir compressibility obtained through the above steps, taking the B10 well in the carbonate gas reservoir as an example.

[0087] Using four sets of test data from months 0, 2, 4, and 9 (data from the pre-blockage stage), a linear fit relationship between average formation pressure and cumulative gas production is established by substituting the data into the linear equation:

[0088]

[0089] When the average formation pressure P approaches 0, the cumulative gas production G pTending to well control dynamic reserves G, the well control dynamic reserves G of the gas well before plugging can be obtained as 4.48 billion cubic meters;

[0090] The ideal cumulative gas production G in the linear relationship is p As an unknown quantity, the ideal cumulative gas production G corresponding to different times without considering the influence of plugging can be obtained by substituting the test data of the 15th month (data after plugging) into the linear relationship. p The ideal cumulative gas production G is 3.1815 million cubic meters.

[0091] The ideal cumulative gas production without considering the influence of plugging is subtracted from the real cumulative gas production 2.9568 million cubic meters (see Figure 3 ) calculated from the production data of the 15th month, and the loss gas production 2246.29 thousand cubic meters corresponding to the combined influence of wellbore and reservoir plugging in the production stage is obtained, which represents the total plugging degree of the gas reservoir.

[0092] Then, the ideal reservoir permeability and the actual reservoir production are calculated based on the reservoir and fluid interpretation parameters of the carbonate gas reservoir, the theoretical reservoir production is calculated according to the ideal reservoir permeability, and the reservoir loss daily gas production is obtained by subtracting the actual reservoir production from the theoretical reservoir production, which represents the plugging degree of the reservoir.

[0093] Specifically, the calculation process of the theoretical reservoir production and the actual reservoir production includes the following steps:

[0094] The core pressure permeability experiment is carried out, and the permeability-pressure relationship is obtained based on the core pressure permeability experiment:

[0095] K a = K ∞ EXP[-α(P i -P)];

[0096] In the formula, K a is the ideal reservoir permeability considering strain and not considering reservoir plugging, K ∞ is the original reservoir permeability value, α is the sensitivity coefficient, P i is the original formation pressure, and P is the average formation pressure.

[0097] The average formation pressure P is substituted into the above formula to calculate the ideal reservoir permeability considering strain and not considering reservoir plugging, and the ideal reservoir permeability considering strain and not considering reservoir plugging is substituted into the following formula to calculate the theoretical reservoir production without considering the influence of skin factor:

[0098]

[0099] In the formula, Q aQ is the theoretical reservoir production without considering the influence of skin factor, h is the reservoir thickness, μ is the fluid viscosity, P is the formation pressure interpreted from pressure buildup test, and k is the ideal reservoir permeability considering strain without considering reservoir plugging. e P is the formation pressure interpreted from pressure buildup test. f Pwf is the bottom hole flowing pressure. i k is the ideal reservoir permeability considering strain without considering reservoir plugging. i ri is the sub-zone radius of the ith sub-zone. i-1 ri-1 is the sub-zone radius of the (i-1)th sub-zone.

[0100] The actual reservoir production without considering the influence of skin factor is calculated by substituting the sub-zone permeability interpreted from pressure buildup test into the following formula:

[0101]

[0102] Q is the actual reservoir production without considering the influence of skin factor, k is the ideal reservoir permeability considering strain without considering reservoir plugging, h is the reservoir thickness, μ is the fluid viscosity, P is the formation pressure interpreted from pressure buildup test, and Pwf is the bottom hole flowing pressure. s Q is the actual reservoir production without considering the influence of skin factor, k is the ideal reservoir permeability considering strain without considering reservoir plugging, h is the reservoir thickness, μ is the fluid viscosity, P is the formation pressure interpreted from pressure buildup test, and Pwf is the bottom hole flowing pressure. si ki is the ith sub-zone permeability interpreted from pressure buildup test.

[0103] The theoretical reservoir production without considering the influence of skin factor and the actual reservoir production without considering the influence of skin factor are obtained through the above steps, and the reservoir loss daily gas production is obtained by subtracting the actual reservoir production from the theoretical reservoir production.

[0104] The ideal reservoir permeability considering strain without considering reservoir plugging and the reservoir loss daily gas production data obtained through the above steps are shown in Table 1 and Table 2, respectively. Figure 4 The reservoir plugging degree is represented by the numerical value of the reservoir loss daily gas production, and it can be seen that the reservoir plugging degree is greatly improved between the 9th month and the 15th month.

[0105] Finally, the theoretical wellbore production and the actual wellbore production are calculated based on the carbonate gas reservoir and fluid interpretation parameters, and the wellbore loss daily gas production is obtained by subtracting the actual wellbore production from the theoretical wellbore production, which represents the wellbore plugging degree.

[0106] Specifically, the calculation process of the theoretical wellbore production and the actual wellbore production includes the following steps:

[0107] The skin factor interpreted from pressure buildup test before plugging is substituted into the following formula to calculate the theoretical wellbore production:

[0108]

[0109] Q is the theoretical wellbore production without considering the influence of wellbore plugging, h is the reservoir thickness, μ is the fluid viscosity, P is the formation pressure interpreted from pressure buildup test, and Pwf is the bottom hole flowing pressure. F Q is the theoretical wellbore production without considering the influence of wellbore plugging, h is the reservoir thickness, μ is the fluid viscosity, P is the formation pressure interpreted from pressure buildup test, and Pwf is the bottom hole flowing pressure. e P is the formation pressure interpreted from pressure buildup test. wfis the bottom hole flowing pressure, k si is the permeability of the ith zone from pressure buildup test interpretation, r i is the zonal radius of the ith zone, r i-1 is the zonal radius of the (i-1)th zone, r e is the zonal radius from pressure buildup test interpretation, r w is the wellbore radius, S F is the skin factor from pressure buildup test interpretation before plugging;

[0110] The skin factor from pressure buildup test interpretation after plugging is substituted into the following formula to calculate the actual wellbore production:

[0111]

[0112] In the formula, Q B is the actual wellbore production considering wellbore plugging, S B is the skin factor from pressure buildup test interpretation after plugging.

[0113] The theoretical wellbore production and the actual wellbore production are obtained in sequence through the above steps, and the difference between the theoretical wellbore production and the actual wellbore production is the wellbore loss daily gas production.

[0114] The wellbore loss daily gas production data obtained through the above steps for carbonate gas reservoir B10 well is shown in Table 1. Figure 4 The wellbore loss daily gas production data obtained through the above steps for carbonate gas reservoir B10 well is shown in Table 1.

[0115] The present application considers the influence of reservoir and fluid micro-compressibility, analyzes the influence of wellbore contamination and reservoir physical property change on gas well production, and realizes quantitative characterization of carbonate gas reservoir wellbore and reservoir plugging degree.

[0116] The above examples are only exemplary embodiments of the present application, and are not used to limit the present application, and the protection scope of the present application is defined by the claims. Those skilled in the art can make various modifications or equivalent replacements to the present application within the spirit and protection scope of the present application, and the modification or equivalent replacement is also regarded as falling within the protection scope of the present application.

Claims

1. A method for quantitatively analyzing the degree of plugging of a carbonate gas reservoir, characterized by, The method comprises the following steps: Step 100, periodically performing pressure buildup test on the gas well to obtain carbonate gas reservoir and fluid interpretation parameters; Step 200, performing stage-by-stage comparative analysis on the carbonate gas reservoir and fluid interpretation parameters to identify the carbonate gas reservoir plugging characteristics according to the comparative results, and dividing the entire stage into a pre-plugging stage and a post-plugging stage based on the carbonate gas reservoir plugging characteristics; Step 300, calculating the well-controlled dynamic reserves based on the carbonate gas reservoir and fluid interpretation parameters, and calculating the ideal cumulative gas production according to the well-controlled dynamic reserves, obtaining the real cumulative gas production, and calculating the lost gas production by subtracting the ideal cumulative gas production from the real cumulative gas production to represent the total plugging degree of the gas reservoir; The calculation process of the ideal cumulative gas production comprises the following steps: Substituting the oil pressure data into the following formula to calculate the bottom hole flowing pressure: ； where P wf is the bottom hole flowing pressure, P o is the oil pressure, p is the mixed fluid density, g is the gravitational acceleration, and H is the depth from the wellhead to the bottom hole. The calculated bottom hole flowing pressure P wf is substituted into the following equation to calculate the average formation pressure: ； where P is the average formation pressure, P e is the formation pressure from pressure buildup test interpretation, r e is the zonal radius from pressure buildup test interpretation, r w is the wellbore radius; Performing rock compression experiment test and formation water high pressure physical property experiment test, and substituting the test parameters obtained based on the rock compression experiment test and the formation water high pressure physical property experiment test into the following formula to calculate the comprehensive compression coefficient of the gas reservoir: ； In the formula, C c is the comprehensive compressibility of the gas reservoir, C p is the rock compressibility, S wc is the water phase saturation, C w is the water phase compressibility, and the rock compressibility, the water phase saturation, and the water phase compressibility are test parameters obtained through rock compression experiment testing and formation water high-pressure physical property experiment testing. The data of the stage before plugging is substituted into the linear relationship between cumulative gas production and average formation pressure to calculate the well-controlled dynamic reserves G, and then the data of the stage after plugging and the calculated well-controlled dynamic reserves G are substituted into the linear relationship to inversely calculate the ideal cumulative gas production G without considering the influence of plugging p : ； where Z is the deviation factor at average reservoir pressure, ΔP is the drawdown pressure, P i is the initial reservoir pressure, Z i is the deviation factor at initial reservoir pressure, G p is the current cumulative gas production, and G is the controlled dynamic reservoir volume. Step 400, calculating the ideal reservoir permeability and the actual reservoir production based on the carbonate gas reservoir and fluid interpretation parameters, calculating the theoretical reservoir production according to the ideal reservoir permeability, and calculating the reservoir lost daily gas production by subtracting the actual reservoir production from the theoretical reservoir production to represent the reservoir plugging degree; Step 500, calculating the theoretical wellbore production and the actual wellbore production using the carbonate gas reservoir and fluid interpretation parameters of the pre-plugging stage and the post-plugging stage respectively, and calculating the wellbore lost daily gas production by subtracting the actual wellbore production from the theoretical wellbore production to represent the wellbore plugging degree.

2. The quantitative analysis method of the plugging degree of the carbonate gas reservoir according to claim 1, wherein In step 100, after each pressure buildup test on the gas well, the test data is fitted using a pressure buildup test interpretation chart to obtain the carbonate gas reservoir and fluid interpretation parameters.

3. The quantitative analysis method of the plugging degree of the carbonate gas reservoir according to claim 2, wherein The carbonate gas reservoir and fluid interpretation parameters comprise a skin factor, a formation factor, a formation pressure, a zonal radius, and a zonal permeability.

4. The quantitative analysis method of the plugging degree of the carbonate gas reservoir according to claim 3, wherein In step 200, the gas production and oil pressure of the gas well are measured, and a gas production curve and an oil pressure curve are plotted, and the carbonate gas reservoir and fluid interpretation parameters are compared and analyzed in stages in time sequence to obtain the change state of the carbonate gas reservoir and fluid interpretation parameters; The carbonate gas reservoir plugging characteristics are identified according to the change state of the carbonate gas reservoir and fluid interpretation parameters, the gas production curve, the oil pressure curve, and the wellhead state of the gas well.

5. The quantitative analysis method of the plugging degree of the carbonate gas reservoir according to claim 4, wherein The plugging characteristics of the carbonate gas reservoir include sudden changes in gas production rate curve and oil pressure curve, overall downward trend of the gas production rate curve, increase of skin factor, decrease of zonal permeability, and carrying out of the plugging material by the gas well head. 6.The method according to claim 5, wherein the method comprises the following steps. The calculation process of the theoretical reservoir production and the actual reservoir production comprises the following steps. The core pressure-permeability experiment is performed, and the relationship between the permeability and the pressure is obtained based on the core pressure-permeability experiment. ； where K a is the ideal reservoir permeability that does not take into account the reservoir plugging, K ∞ is the original reservoir permeability value, and a is the sensitivity factor, P i is the original formation pressure, and P is the average formation pressure. The ideal reservoir permeability considering strain and not considering reservoir plugging is calculated by substituting the average formation pressure P into the above formula, and the ideal reservoir permeability considering strain and not considering reservoir plugging is substituted into the following formula to calculate the theoretical reservoir production without considering the influence of the skin factor: ； where Q a is the theoretical reservoir production without considering the skin factor, h is the reservoir thickness, μ is the fluid viscosity, P e is the formation pressure from pressure buildup test interpretation, P wf is the flowing bottomhole pressure, k ai is the ideal reservoir permeability of the ith zone considering strain and not reservoir plugging, r i is the zonal radius of the ith zone, r i-1 is the zonal radius of the (i-1)th zone; The actual reservoir production without considering the influence of the skin factor is calculated by substituting the zonal permeability obtained by the pressure buildup test interpretation into the following formula: ； where Q s is the actual reservoir production without skin factor effect, k si is the i-zone permeability from pressure buildup test interpretation. 7.The method according to claim 6, wherein the method comprises the following steps. The calculation process of the theoretical wellbore production and the actual wellbore production comprises the following steps. The theoretical wellbore production is calculated by substituting the skin factor obtained by the pressure buildup test interpretation before the plugging into the following formula: ； where Q F is the theoretical wellbore production without considering wellbore plugging, h is the reservoir thickness, μ is the fluid viscosity, P e is the formation pressure from pressure buildup test interpretation, P wf is the flowing bottomhole pressure, k si is the ith zone permeability from pressure buildup test interpretation, r i is the ith zone radius, r i-1 is the (i-1)th zone radius, r e is the zone radius from pressure buildup test interpretation, r w is the wellbore radius, S F is the skin factor from pressure buildup test interpretation before the plugging stage; The actual wellbore production is calculated by substituting the skin factor obtained by the pressure buildup test interpretation after the plugging into the following formula: ； where Q B S is the skin factor for the actual wellbore production considering wellbore plugging B S is the skin factor for the pressure buildup test interpretation after plugging.

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