Quantitative analysis method for blockage degree of carbonate gas reservoir

Abstract

The invention relates to the field of oil and gas reservoirs, and discloses a quantitative analysis method for the blockage degree of a carbonate gas reservoir, which comprises the following steps: acquiring reservoir and fluid interpretation parameters of the carbonate gas reservoir; identifying carbonate rock gas reservoir blockage characteristics; calculating an ideal accumulative gas production rate, and subtracting the ideal accumulative gas production rate from the real accumulative gas production rate to obtain a lost gas production rate so as to represent the total blockage degree of the gas reservoir; the actual reservoir yield and the theoretical reservoir yield are calculated, the difference between the theoretical reservoir yield and the actual reservoir yield is obtained, and the reservoir loss daily gas production rate is obtained to represent the reservoir blockage degree; and calculating the theoretical wellbore yield and the actual wellbore yield, and obtaining the wellbore loss daily gas production according to the difference between the theoretical wellbore yield and the actual wellbore yield so as to represent the wellbore blockage degree. According to the method, the yields in the theoretical state and the actual state are analyzed respectively, the parameters capable of representing the blockage degree of the reservoir and the wellbore are obtained, and quantitative analysis of the blockage degree of the wellbore and the reservoir of the carbonate gas reservoir is achieved.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas reservoirs, and in particular to a quantitative analysis method for the blockage degree of carbonate gas reservoirs. Background Art

[0002] During the development of carbonate gas reservoirs, long-term precipitation of inorganic substances such as iron compounds, barium sulfate, calcium carbonate, magnesium carbonate, and silicon dioxide, and the shedding of a small amount of organic matter will cause serious blockage of the wellbore and reservoir throat, affecting the production of gas wells.

[0003] For different degrees of gas well blockage, corresponding carbonate gas well production increase measures and production dynamic evaluation will be carried out subsequently. Therefore, the analysis results of the gas well blockage degree will have an important impact on the final gas well production.

[0004] In the prior art, if a blockage is found at the wellhead of a gas well, it is determined that there is a blockage in the carbonate gas reservoir. However, it is impossible to accurately identify the reservoir blockage and quantify the degree of blockage of the carbonate gas reservoir wellbore and reservoir. As a result, subsequent carbonate gas well production increase measures and production dynamic evaluation cannot be accurately carried out, ultimately affecting the production output of the gas well. Summary of the invention

[0005] To this end, the present invention provides a quantitative analysis method for the blockage degree of carbonate gas reservoirs, which effectively solves the technical problem that the prior art cannot accurately identify reservoir blockage and quantitatively analyze the blockage degree of carbonate gas reservoir wellbores and reservoirs, resulting in the inability to accurately carry out subsequent carbonate gas well production increase measures and production dynamic evaluation, ultimately affecting the production output of the gas wells.

[0006] In order to solve the above technical problems, the present invention specifically provides the following technical solutions: a quantitative analysis method for the blockage degree of carbonate gas reservoirs, comprising the following steps:

[0007] Step 100, regularly performing pressure recovery test on the gas well to obtain carbonate gas reservoir reservoir and fluid interpretation parameters;

[0008] Step 200, performing phased comparative analysis on carbonate gas reservoir reservoir and fluid interpretation parameters, identifying carbonate gas reservoir blockage characteristics according to the comparative results, and dividing the entire stage into a pre-blockage stage and a post-blockage stage based on the carbonate gas reservoir blockage characteristics;

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

[0010] Step 400, based on the carbonate gas reservoir and fluid interpretation parameters, the ideal reservoir permeability and the actual reservoir production are calculated, the theoretical reservoir production is calculated according to the ideal reservoir permeability, and the theoretical reservoir production and the actual reservoir production are subtracted to obtain the reservoir loss daily gas production to characterize the reservoir blockage degree;

[0011] Step 500, using the carbonate gas reservoir reservoir and fluid interpretation parameters in the pre-blockage stage and the post-blockage stage, respectively calculate the theoretical wellbore production and the actual wellbore production, and subtract the theoretical wellbore production from the actual wellbore production to obtain the wellbore loss daily gas production to characterize 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 carbonate gas reservoir reservoir and fluid interpretation parameters.

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

[0014] Furthermore, 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 drawn, and the carbonate gas reservoir and fluid interpretation parameters are compared and analyzed in stages in chronological order to obtain the change state of the carbonate gas reservoir and fluid interpretation parameters;

[0015] The blockage characteristics of the carbonate gas reservoir are identified according to the change state of the carbonate gas reservoir reservoir and fluid interpretation parameters, the gas production curve, the oil pressure curve and the wellhead state of the gas well.

[0016] Furthermore, the blockage characteristics of the carbonate gas reservoir include sudden changes in the gas production curve and the oil pressure curve at the same time, the overall downward trend of the gas production curve, an increase in the skin coefficient, a decrease in the permeability of the partition, and blockages carried out at the wellhead of the gas well.

[0017] Furthermore, the calculation process of 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] Where P wf is the bottom hole flowing pressure, P o is the oil pressure, ρ is the density of the mixed fluid, g is the acceleration of gravity, and H is the depth from the wellhead to the bottom of the well;

[0021] The calculated bottom hole pressure Pwf Substitute the following formula to calculate the average formation pressure:

[0022]

[0023] Where P is the average formation pressure, P e The formation pressure interpreted for the buildup test, r e is the zone radius interpreted by the pressure buildup test, r w is the wellbore radius;

[0024] Rock compression test and formation water high-pressure physical property test are carried out, and the test parameters obtained based on the rock compression test and formation water high-pressure physical property 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 gas reservoir, C p is the rock compression coefficient, S wc is the water phase saturation, C w is the water phase compression coefficient. The rock compression coefficient, water phase saturation and water phase compression coefficient are all test parameters obtained from rock compression test and formation water high pressure physical property test.

[0027] Substitute the data before the plugging stage into the following linear relationship between cumulative gas production and average formation pressure to calculate the well-controlled dynamic reserves G. Substitute the data after the plugging stage and the calculated well-controlled dynamic reserves G into the linear relationship to reversely calculate the ideal cumulative gas production G without considering the impact of plugging. p :

[0028]

[0029] Where Z is the deviation factor under the average formation pressure, ΔP is the production pressure difference, and 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] Furthermore, the calculation process of the theoretical reservoir production and the actual reservoir production includes the following steps:

[0031] Conduct core overburden pressure porosity test, and obtain the relationship between permeability and pressure based on the core overburden pressure porosity test:

[0032] K a =K ∞ EXP[-α(P i -P)];

[0033] In the formula, K a K is the ideal reservoir permeability considering strain but not reservoir blockage, ∞ is the original permeability value of the reservoir, α is the sensitivity coefficient, P i is the original formation pressure, P is the average formation pressure;

[0034] Substitute the average formation pressure P into the above formula to calculate the ideal reservoir permeability considering strain but not considering reservoir blockage, and substitute the ideal reservoir permeability considering strain but not considering reservoir blockage into the following formula to calculate the theoretical reservoir production without considering the influence of skin factor by partition coupling:

[0035]

[0036] In the formula, Q a is the theoretical reservoir production without considering the effect of skin factor, h is the reservoir thickness, μ is the fluid viscosity, P e The formation pressure interpreted by the pressure buildup test, P wf is the bottom hole flowing pressure, k ai is the ideal reservoir permeability of the i-th zone considering strain but not reservoir blockage, r i is the partition radius of the ith zone, r i-1 is the partition radius of the (i-1)th zone;

[0037] Substitute the zone permeability interpreted by the pressure recovery test into the following formula to calculate the actual reservoir production without considering the influence of the skin factor:

[0038]

[0039] In the formula, Q s is the actual reservoir production without considering the effect of skin factor, k si Permeability of zone i interpreted for the pressure buildup test.

[0040] Furthermore, the calculation process of the theoretical wellbore production and the actual wellbore production includes the following steps:

[0041] Substitute the skin coefficient interpreted from the pressure recovery test before plugging into the following formula to calculate the theoretical wellbore production:

[0042]

[0043] In the formula, Q F is the theoretical wellbore production without considering wellbore blockage, h is the reservoir thickness, μ is the fluid viscosity, P e The formation pressure interpreted by the pressure buildup test, P wf is the bottom hole flowing pressure, k siis the permeability of zone i interpreted by the pressure buildup test, r i is the partition radius of the ith zone, r i-1 is the partition radius of the (i-1)th zone, r e is the zone radius interpreted by the pressure buildup test, r w is the wellbore radius, S F Skin factor interpreted for pressure recovery well test in the pre-plugging stage;

[0044] Substitute the skin coefficient interpreted from the post-plugging pressure recovery test into the following formula to calculate the actual wellbore production:

[0045]

[0046] In the formula, Q B To take into account the actual wellbore production of wellbore plugging, S B Skin factor interpreted for post-plugging stage pressure recovery test.

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

[0048] In the present invention, the influence of reservoir and fluid micro-compressibility is taken into consideration, starting from the influence of wellbore blockage and reservoir physical property changes on gas well production, the production under theoretical state and actual state is analyzed respectively, and parameters that can characterize the degree of reservoir and wellbore blockage are obtained, so as to realize quantitative analysis of the blockage degree of wellbore and reservoir in carbonate gas reservoir, so as to facilitate the subsequent corresponding carbonate gas well production increase measures and production dynamic evaluation. BRIEF DESCRIPTION OF THE DRAWINGS

[0049] In order to more clearly illustrate the implementation methods of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for the implementation methods or the description of the prior art. Obviously, the drawings in the following description are only exemplary, and for ordinary technicians in this field, other implementation drawings can be derived from the provided drawings without creative work.

[0050] Figure 1 A flow chart of a method for quantitatively analyzing the blockage degree of a carbonate gas reservoir provided by an embodiment of the present invention;

[0051] Figure 2 This is a table of interpretation parameters for the pressure recovery well test of Well B10 in a carbonate gas reservoir in a certain block at different production times;

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

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

[0054] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0055] like Figure 1 As shown, the present invention provides a method for quantitatively analyzing the blockage degree of carbonate gas reservoirs, comprising the following steps:

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

[0057] Step 200, performing phased comparative analysis on carbonate gas reservoir reservoir and fluid interpretation parameters, identifying carbonate gas reservoir blockage characteristics according to the comparative results, and dividing the entire stage into a pre-blockage stage and a post-blockage stage based on the carbonate gas reservoir blockage characteristics;

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

[0059] Step 400, based on the carbonate gas reservoir and fluid interpretation parameters, the ideal reservoir permeability and the actual reservoir production are calculated, the theoretical reservoir production is calculated according to the ideal reservoir permeability, and the theoretical reservoir production and the actual reservoir production are subtracted to obtain the reservoir loss daily gas production to characterize the reservoir blockage degree;

[0060] Step 500, using the carbonate gas reservoir reservoir and fluid interpretation parameters in the pre-blockage stage and the post-blockage stage, respectively calculate the theoretical wellbore production and the actual wellbore production, and subtract the theoretical wellbore production from the actual wellbore production to obtain the wellbore loss daily gas production to characterize the degree of wellbore blockage.

[0061] In the present invention, the influence of reservoir and fluid micro-compressibility is taken into consideration, starting from the influence of wellbore blockage and reservoir physical property changes on gas well production, the production under theoretical state and actual state is analyzed respectively, and parameters that can characterize the degree of reservoir and wellbore blockage are obtained, so as to realize quantitative analysis of the blockage degree of wellbore and reservoir in carbonate gas reservoir, so as to facilitate the subsequent corresponding carbonate gas well production increase measures and production dynamic evaluation.

[0062] 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 carbonate gas reservoir reservoir and fluid interpretation parameters.

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

[0064] Among them, the reservoir and fluid interpretation parameters of carbonate gas reservoirs include skin coefficient, formation coefficient, formation pressure, partition radius, and partition permeability.

[0065] Take the B10 well in a carbonate gas reservoir in a certain block as an example. After a period of production, the obstruction was removed from the wellbore. During the production process of the B10 well, a pressure recovery test was conducted on the gas well every 2 months for 3 times in the early stage. After that, a pressure recovery test was conducted on the gas well every 6 months for a total of 2 times. The test results were interpreted. The interpretation parameters are as follows: Figure 2 shown.

[0066] In step 200, during the production process of the gas well, the gas production and oil pressure of the gas well are measured and a gas production curve and an oil pressure curve are drawn, and the carbonate gas reservoir and fluid interpretation parameters are compared and analyzed in stages in chronological order to obtain the change state of the carbonate gas reservoir and fluid interpretation parameters;

[0067] The blockage characteristics of carbonate gas reservoirs are identified based on the changing states of reservoir and fluid interpretation parameters, gas production curves, oil pressure curves and gas wellhead conditions.

[0068] Generally, the blockage characteristics of carbonate gas reservoirs are manifested when the following performances are observed in the changing states of reservoir and fluid interpretation parameters, gas production curve, oil pressure curve and gas wellhead status: the gas production curve and oil pressure curve change suddenly at the same time, the gas production curve shows an overall downward trend, the skin coefficient increases, the zone permeability decreases, and blockages are carried out at the gas wellhead.

[0069] Taking the carbonate gas reservoir B10 well as an example, the identification and analysis of the blockage characteristics of carbonate gas reservoirs are carried out. Figure 2 It can be seen that the skin coefficient test showed a significant increase at 15 months, and the permeability interpretation results decreased significantly. A small amount of blockage was carried out by the wellhead production. The blockage was taken out from the wellbore and was measured to be inorganic substances 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 change suddenly between 9 months and 15 months, which can be divided into two stages. The production data from 0 to 9 months is the pre-blocking stage, and the 15-month test data is the post-blocking stage.

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

[0072] Firstly, the well-controlled dynamic reserves are calculated based on the reservoir and fluid interpretation parameters of the carbonate gas reservoir, and the ideal cumulative gas production is calculated based on the well-controlled dynamic reserves to obtain the real cumulative gas production. The lost gas production is obtained by subtracting the ideal cumulative gas production from the real cumulative gas production, and the lost gas production is used to characterize the total blockage degree of the gas reservoir.

[0073] The calculation process of 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] Where P wf is the bottom hole flowing pressure, P o is the oil pressure, ρ is the density of the mixed fluid, g is the acceleration of gravity, and H is the depth from the wellhead to the bottom of the well;

[0077] The calculated bottom hole pressure P wf Substitute the following formula to calculate the average formation pressure:

[0078]

[0079] Where P is the average formation pressure, Pe The formation pressure interpreted for the buildup test, r e is the zone radius interpreted by the pressure buildup test, r w is the wellbore radius;

[0080] Rock compression test and formation water high-pressure physical property test are carried out, and the test parameters obtained based on the rock compression test and formation water high-pressure physical property test are substituted into the following formula to calculate the comprehensive compression coefficient of the gas reservoir:

[0081]

[0082] 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. The rock compression coefficient, water phase saturation and water phase compression coefficient are all test parameters obtained from rock compression test and formation water high pressure physical property test.

[0083] Substitute the data before the plugging stage into the following linear relationship between cumulative gas production and average formation pressure to calculate the well-controlled dynamic reserves G. Substitute the data after the plugging stage and the calculated well-controlled dynamic reserves G into the linear relationship to reversely calculate the ideal cumulative gas production G without considering the impact of plugging. p :

[0084]

[0085] Where Z is the deviation factor under the average formation pressure, ΔP is the production pressure difference, and 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.

[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 comprehensive compression coefficient of the gas reservoir obtained through the above steps, taking the carbonate gas reservoir B10 well as an example.

[0087] Using four sets of test data from the 0th month, 2nd month, 4th month, and 9th month (data before plugging), the linear fitting relationship between average formation pressure and cumulative gas production is established as follows:

[0088]

[0089] When the average formation pressure P approaches 0, the cumulative gas production G pThe trend towards the well-controlled dynamic reserves G shows that the well-controlled dynamic reserves G of the gas well before plugging is 4.48 billion cubic meters;

[0090] The ideal cumulative gas production G in the linear relationship p As an unknown quantity, the test data of the 15th month (data after the blockage stage) is substituted into the linear relationship to obtain the ideal cumulative gas production G corresponding to different times without considering the blockage effect. p 318.15 million cubic meters;

[0091] The ideal cumulative gas production without considering the impact of blockage is deducted from the actual cumulative gas production of 295.68 million cubic meters of production data in the 15th month (see Figure 3 ), we obtained the gas production loss of 22.4629 million cubic meters under the combined influence of wellbore and reservoir blockage in the corresponding production stage, and used this data to represent the total blockage degree of the gas reservoir.

[0092] Afterwards, the ideal reservoir permeability and actual reservoir production were calculated based on the carbonate gas reservoir and fluid interpretation parameters. The theoretical reservoir production was calculated based on the ideal reservoir permeability. The theoretical reservoir production was subtracted from the actual reservoir production to obtain the reservoir loss daily gas production, and the loss daily gas production was used to characterize the degree of reservoir blockage.

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

[0094] Conduct core overburden pressure porosity test, and obtain the relationship between permeability and pressure based on the core overburden pressure porosity test:

[0095] K a =K ∞ EXP[-α(P i -P)];

[0096] In the formula, K a K is the ideal reservoir permeability considering strain but not reservoir blockage, ∞ is the original permeability value of the reservoir, α is the sensitivity coefficient, P i is the original formation pressure, P is the average formation pressure;

[0097] Substitute the average formation pressure P into the above formula to calculate the ideal reservoir permeability considering strain but not considering reservoir blockage, and substitute the ideal reservoir permeability considering strain but not considering reservoir blockage into the following formula to calculate the theoretical reservoir production without considering the influence of skin factor by partition coupling:

[0098]

[0099] In the formula, Q ais the theoretical reservoir production without considering the effect of skin factor, h is the reservoir thickness, μ is the fluid viscosity, P e The formation pressure interpreted for the pressure buildup test, Pw f is the bottom hole flowing pressure, ka i is the ideal reservoir permeability of the i-th zone considering strain but not reservoir blockage, r i is the partition radius of the ith zone, r i-1 is the partition radius of the (i-1)th zone;

[0100] Substitute the zone permeability interpreted by the pressure recovery test into the following formula to calculate the actual reservoir production without considering the influence of the skin factor:

[0101]

[0102] In the formula, Q s is the actual reservoir production without considering the effect of skin factor, k si Permeability of zone i interpreted for the pressure buildup test.

[0103] Through the above steps, the theoretical reservoir production without considering the influence of the skin coefficient and the actual reservoir production without considering the influence of the skin coefficient are obtained in turn. The theoretical reservoir production and the actual reservoir production are subtracted to obtain the daily gas production due to reservoir loss.

[0104] Taking the carbonate gas reservoir B10 well as an example, the ideal reservoir permeability and reservoir loss daily gas production data obtained through the above steps considering strain but not considering reservoir blockage are as follows: Figure 4 As shown, the reservoir blockage degree is characterized by the value of reservoir loss daily gas production. It can be seen that the reservoir blockage degree increases greatly between the 9th month and the 15th month.

[0105] Finally, the theoretical wellbore production and actual wellbore production were calculated based on the carbonate gas reservoir reservoir and fluid interpretation parameters. The difference between the theoretical wellbore production and the actual wellbore production was used to obtain the wellbore loss daily gas production, and the wellbore loss daily gas production was used to characterize the degree of wellbore blockage.

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

[0107] Substitute the skin coefficient interpreted from the pressure recovery test before plugging into the following formula to calculate the theoretical wellbore production:

[0108]

[0109] In the formula, Q F is the theoretical wellbore production without considering wellbore blockage, h is the reservoir thickness, μ is the fluid viscosity, P e The formation pressure interpreted by the pressure buildup test, P wfis the bottom hole flowing pressure, k si is the permeability of zone i interpreted by the pressure buildup test, r i is the partition radius of the ith zone, r i-1 is the partition radius of the (i-1)th zone, r e is the zone radius interpreted by the pressure buildup test, r w is the wellbore radius, S F Skin factor interpreted for pressure recovery well test in the pre-plugging stage;

[0110] Substitute the skin coefficient interpreted from the post-plugging pressure recovery test into the following formula to calculate the actual wellbore production:

[0111]

[0112] In the formula, Q B To take into account the actual wellbore production of wellbore plugging, S B Skin factor interpreted for post-plugging stage pressure recovery test.

[0113] Through the above steps, the theoretical wellbore production and the actual wellbore production are obtained in turn, and the daily gas production loss of the wellbore is obtained by subtracting the theoretical wellbore production from the actual wellbore production.

[0114] Taking the carbonate gas reservoir B10 well as an example, the daily gas production data of wellbore loss obtained through the above steps are as follows: Figure 4 As shown, the degree of wellbore blockage is characterized by the value of the daily gas production loss of the wellbore. It can be seen that the degree of wellbore blockage changes slightly between the 2nd month, 4th month, and 9th month, and increases greatly between the 9th month and the 15th month.

[0115] The present invention takes into account the influence of reservoir and fluid micro-compressibility, analyzes the influence of wellbore pollution and reservoir physical property changes on gas well production, and realizes quantitative characterization of the blockage degree of carbonate gas reservoir wellbore and reservoir.

[0116] The above embodiments are only exemplary embodiments of the present application and are not intended to limit the present application. The protection scope of the present application is defined by the claims. Those skilled in the art may make various modifications or equivalent substitutions to the present application within the essence and protection scope of the present application, and such modifications or equivalent substitutions shall also be deemed to fall within the protection scope of the present application.

Claims

1. A quantitative analysis method for the blockage degree of carbonate gas reservoirs, characterized in that: The following steps are involved: Step 100, regularly performing pressure recovery test on the gas well to obtain carbonate gas reservoir reservoir and fluid interpretation parameters; Step 200, performing phased comparative analysis on carbonate gas reservoir reservoir and fluid interpretation parameters, identifying carbonate gas reservoir blockage characteristics according to the comparative results, and dividing the entire stage into a pre-blockage stage and a post-blockage stage based on the carbonate gas reservoir blockage characteristics; Step 300, calculating the well-controlled dynamic reserves based on the carbonate gas reservoir reservoir and fluid interpretation parameters, and obtaining the ideal cumulative gas production according to the well-controlled dynamic reserves calculation, obtaining the real cumulative gas production, and obtaining the lost gas production by subtracting the ideal cumulative gas production from the real cumulative gas production to characterize the total blockage degree of the gas reservoir; Step 400, based on the carbonate gas reservoir and fluid interpretation parameters, the ideal reservoir permeability and the actual reservoir production are calculated, the theoretical reservoir production is calculated according to the ideal reservoir permeability, and the theoretical reservoir production and the actual reservoir production are subtracted to obtain the reservoir loss daily gas production to characterize the reservoir blockage degree; Step 500, using the carbonate gas reservoir reservoir and fluid interpretation parameters in the pre-blockage stage and the post-blockage stage, respectively calculate the theoretical wellbore production and the actual wellbore production, and subtract the theoretical wellbore production from the actual wellbore production to obtain the wellbore loss daily gas production to characterize the degree of wellbore blockage.

2. The method for quantitatively analyzing the blockage degree of carbonate gas reservoirs according to claim 1, characterized in that: 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 carbonate gas reservoir reservoir and fluid interpretation parameters.

3. The method for quantitatively analyzing the blockage degree of carbonate gas reservoirs according to claim 2, characterized in that: The carbonate gas reservoir reservoir and fluid interpretation parameters include skin coefficient, formation coefficient, formation pressure, partition radius, and partition permeability.

4. The method for quantitatively analyzing the blockage degree of carbonate gas reservoirs according to claim 3, characterized in that: 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 drawn, and the carbonate gas reservoir and fluid interpretation parameters are compared and analyzed in stages in chronological order to obtain the change state of the carbonate gas reservoir and fluid interpretation parameters; The blockage characteristics of the carbonate gas reservoir are identified according to the change state of the carbonate gas reservoir reservoir and fluid interpretation parameters, the gas production curve, the oil pressure curve and the wellhead state of the gas well.

5. The method for quantitatively analyzing the blockage degree of carbonate gas reservoirs according to claim 4, characterized in that: The blockage characteristics of carbonate gas reservoirs include sudden changes in the gas production curve and the oil pressure curve at the same time, the overall downward trend of the gas production curve, an increase in the skin coefficient, a decrease in the permeability of each zone, and blockages carried out from the wellhead of the gas well.

6. The method for quantitatively analyzing the blockage degree of carbonate gas reservoirs according to claim 4, characterized in that: The calculation process of the ideal cumulative gas production includes the following steps: Substitute the oil pressure data into the following formula to calculate the bottom hole flowing pressure: P wf =P o +10 -3 ρgH; Where P wf is the bottom hole flowing pressure, P o is the oil pressure, ρ is the density of the mixed fluid, g is the acceleration of gravity, and H is the depth from the wellhead to the bottom of the well; The calculated bottom hole pressure P wf Substitute the following formula to calculate the average formation pressure: Where P is the average formation pressure, P e The formation pressure interpreted for the buildup test, r e is the zone radius interpreted by the pressure buildup test, r w is the wellbore radius; Rock compression test and formation water high-pressure physical property test are carried out, and the test parameters obtained based on the rock compression test and formation water high-pressure physical property test are substituted into the following formula to calculate the comprehensive compression coefficient of the gas reservoir: 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. The rock compression coefficient, water phase saturation and water phase compression coefficient are all test parameters obtained from rock compression test and formation water high pressure physical property test. Substitute the data before the plugging stage into the following linear relationship between cumulative gas production and average formation pressure to calculate the well-controlled dynamic reserves G. Substitute the data after the plugging stage and the calculated well-controlled dynamic reserves G into the linear relationship to reversely calculate the ideal cumulative gas production G without considering the impact of plugging. p : Where Z is the deviation factor under the average formation pressure, ΔP is the production pressure difference, and 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.

7. The method for quantitatively analyzing the blockage degree of carbonate gas reservoirs according to claim 6, characterized in that: The calculation process of the theoretical reservoir production and the actual reservoir production includes the following steps: Conduct core overburden pressure porosity test, and obtain the relationship between permeability and pressure based on the core overburden pressure porosity test: K a =K ∞ EXP[-α(P i -P)]; In the formula, K a K is the ideal reservoir permeability considering strain but not reservoir blockage, ∞ is the original permeability value of the reservoir, α is the sensitivity coefficient, P i is the original formation pressure, P is the average formation pressure; Substitute the average formation pressure P into the above formula to calculate the ideal reservoir permeability considering strain but not considering reservoir blockage, and substitute the ideal reservoir permeability considering strain but not considering reservoir blockage into the following formula to calculate the theoretical reservoir production without considering the influence of skin factor by partition coupling: In the formula, Q a is the theoretical reservoir production without considering the effect of skin factor, h is the reservoir thickness, μ is the fluid viscosity, P e The formation pressure interpreted by the pressure buildup test, P wf is the bottom hole flowing pressure, k ai is the ideal reservoir permeability of the i-th zone considering strain but not reservoir blockage, r i is the partition radius of the ith zone, r i-1 is the partition radius of the (i-1)th zone; Substitute the zone permeability interpreted by the pressure recovery test into the following formula to calculate the actual reservoir production without considering the influence of the skin factor: In the formula, Q s is the actual reservoir production without considering the effect of skin factor, k si Permeability of zone i interpreted for the pressure buildup test.

8. The method for quantitatively analyzing the blockage degree of carbonate gas reservoirs according to claim 7, characterized in that: The calculation process of the theoretical wellbore production and the actual wellbore production includes the following steps: Substitute the skin coefficient interpreted from the pressure recovery test before plugging into the following formula to calculate the theoretical wellbore production: In the formula, Q F is the theoretical wellbore production without considering wellbore blockage, h is the reservoir thickness, μ is the fluid viscosity, P e The formation pressure interpreted by the pressure buildup test, P wf is the bottom hole flowing pressure, k si is the permeability of zone i interpreted by the pressure buildup test, r i is the partition radius of the ith zone, r i-1 is the partition radius of the (i-1)th zone, r e is the zone radius interpreted by the pressure buildup test, r w is the wellbore radius, S F Skin factor interpreted for pressure recovery well test in the pre-plugging stage; Substitute the skin coefficient interpreted from the post-plugging pressure recovery test into the following formula to calculate the actual wellbore production: In the formula, Q B To take into account the actual wellbore production of wellbore plugging, S B Skin factor interpreted for post-plugging stage pressure recovery test.

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