Evaluation method for the original geological reserves of undersaturated coalbed methane

Abstract

This application discloses a method for evaluating the original geological reserves of undersaturated coalbed methane, comprising: determining the reservoir physical properties, fluid physical properties, and fracturing fluid injection and flowback data of the undersaturated coalbed methane reservoir; obtaining the average formation pressure, cumulative gas production, cumulative water production, and average deviation coefficient of the coal reservoir during the production process of the undersaturated coalbed methane well; calculating the corrected apparent pressure of the undersaturated coalbed methane reservoir based on the reservoir physical properties, fluid physical properties, average formation pressure, and average deviation coefficient; calculating the equivalent cumulative gas production of the coalbed methane well based on the reservoir physical properties, fluid physical properties, total fracturing fluid injection, cumulative flowback of fracturing fluid during the flowback stage, cumulative gas production, cumulative water production, average formation pressure, and average deviation coefficient; and calculating the original geological reserves of undersaturated coalbed methane based on the corrected apparent pressure and the equivalent cumulative gas production of the coalbed methane well. The method is simple and clear, and easy to promote and apply.

Description

Technical Field

[0001] This application belongs to the technical field of undersaturated coalbed methane reservoirs, specifically relating to a method for evaluating the original geological reserves of undersaturated coalbed methane. Background Technology

[0002] Coalbed methane (CBM), as an important unconventional resource, can alleviate energy shortages, reduce coal mine safety accidents, and mitigate the greenhouse effect, attracting widespread attention globally. The original geological reserves of CBM are the material basis for CBM exploration and development, determining the scale of development and the choice of development methods. Accurately evaluating the original geological reserves of CBM has significant theoretical and practical implications for its efficient development.

[0003] Currently, there are two main methods for evaluating the original geological reserves of coalbed methane: static and dynamic. Static methods, based on the volumetric approach, offer relatively reliable results when the well-controlled area is known. However, the well-controlled area is generally difficult to obtain beforehand, posing a challenge to volumetric reserve calculations. Among dynamic methods, the material balance method is commonly used. However, current methods for calculating the pseudo-deviation coefficient of undersaturated coalbed methane require iterative determination of the well-controlled volume V, increasing computational complexity. Furthermore, existing methods for evaluating the original geological reserves of coalbed methane often neglect the effects of fracturing fluid injection and flowback.

[0004] Therefore, to date, there are few reports on methods that can directly evaluate the original geological reserves of undersaturated coalbed methane by linear fitting without iterative cycles and by taking into account the impact of fracturing fluid injection and flowback. Summary of the Invention

[0005] The purpose of this application is to provide a method for evaluating the original geological reserves of undersaturated coalbed methane. This method can evaluate the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs without iterative iteration. The method is simple, clear, and easy to promote and apply.

[0006] To achieve the above objectives, this application provides a method for evaluating the original geological reserves of undersaturated coalbed methane, the method comprising the following steps: Determine the reservoir physical properties, fluid physical properties, and fracturing fluid injection and flowback data for undersaturated coalbed methane reservoirs; To obtain the average formation pressure, cumulative gas production, cumulative water production, and average deviation coefficient of the coal reservoir in the production process of undersaturated coalbed methane wells; The corrected back pressure of the undersaturated coalbed methane reservoir is calculated based on the reservoir physical property parameters, fluid physical property parameters, average formation pressure of the coal reservoir during the production process, and average deviation coefficient. The equivalent cumulative gas production of a coalbed methane well is calculated based on the reservoir physical properties, fluid physical properties, total fracturing fluid injection, cumulative fracturing fluid flowback during the flowback stage, cumulative gas production during the production process, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient. The original geological reserves of undersaturated coalbed methane are calculated based on the corrected apparent pressure of the undersaturated coalbed methane reservoir and the equivalent cumulative gas production of the coalbed methane well.

[0007] In some embodiments, the step of obtaining the average deviation coefficient of an undersaturated coalbed methane well during the production process includes: Collect the measured average formation pressure of coal reservoirs and the corresponding cumulative gas production and cumulative water production of undersaturated coalbed methane wells during the production process; The average formation pressure of coal reservoirs is applied to an empirical / semi-empirical model, and the average deviation coefficient of coalbed methane under any formation pressure is obtained based on the relative density of coalbed methane and the reservoir temperature.

[0008] In some embodiments, the step of calculating the corrected apparent pressure of the undersaturated coalbed methane reservoir based on the reservoir physical properties, fluid physical properties, mean formation pressure of the coal reservoir during production, and mean deviation coefficient includes: The apparent pressure correction factor under the average formation pressure of the coal reservoir is calculated based on the reservoir physical property parameters, fluid physical property parameters, original coal reservoir pressure, critical desorption pressure, coalbed methane deviation coefficient under critical desorption pressure, average formation pressure of the coal reservoir, and the average deviation coefficient of the undersaturated coalbed methane reservoir. The corrected apparent pressure is calculated based on the apparent pressure correction factor, the average formation pressure of the coal reservoir, and the average deviation factor.

[0009] In some embodiments, the step of calculating the apparent pressure correction factor under the average formation pressure of the coal reservoir based on the reservoir physical properties, fluid physical properties, original coal reservoir pressure, critical desorption pressure, coalbed methane deviation coefficient under the critical desorption pressure, average formation pressure of the coal reservoir, and the average deviation coefficient of the undersaturated coalbed methane reservoir includes: Compare the average formation pressure and critical desorption pressure of coal reservoirs; When the average formation pressure of the coal reservoir is greater than or equal to the critical desorption pressure, the correction factor for the apparent pressure of the coalbed methane is calculated using the first formula. When the average formation pressure of the coal reservoir is less than the critical desorption pressure, the correction factor for the apparent pressure of the coalbed methane is calculated using the second formula.

[0010] In some implementations, the first formula is as follows (1): (1) The second formula is as follows: (2) (2) in, α This is a correction factor for the apparent pressure of coalbed methane, dimensionless; p sc The pressure under standard conditions is expressed in MPa, with a value of 0.101325. T Let K be the temperature of the coal reservoir. r ad The air-dried basis mass density of coal (bulk density of coal), t / m³ 3 ; V L Langmuir volume of coal on an air-dried basis, m 3 / t; p L Langmuir pressure for coal on an air-dried basis, in MPa; f i The original coal reservoir porosity is a decimal. S wi The original water saturation level is a decimal. Z sc This is the natural gas deviation coefficient under standard conditions, dimensionless, and has a value of 1. T sc The temperature under standard conditions is K, with a value of 293.15. p i The original coal reservoir pressure is given in MPa. p d The critical desorption pressure is given in MPa. Z d is the coalbed methane deviation coefficient at the critical desorption pressure, which is dimensionless; p The mean formation pressure of the coal reservoir is expressed in MPa. Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, which is dimensionless; C p The pore compressibility coefficient of the coal reservoir is given in MPa. -1 ; C w The isothermal compressibility coefficient of water is given in MPa. -1 ; C s The solubility coefficient of undersaturated coalbed methane in water is given in MPa. -1 ; C a is the coal matrix shrinkage coefficient, which is dimensionless.

[0011] In some embodiments, the step of calculating the equivalent cumulative gas production of a coalbed methane well based on reservoir physical parameters, fluid physical parameters, total fracturing fluid injection volume, cumulative fracturing fluid flowback volume during the flowback stage, cumulative gas production during the production process, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient includes: Substitute the reservoir physical properties, fluid physical properties, total fracturing fluid injection, cumulative fracturing fluid flowback during the flowback stage, cumulative gas production during the production process of the coalbed methane well, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient into the following formula to calculate the equivalent cumulative gas production corresponding to the measured average formation pressure and cumulative production of each coal reservoir.

[0012] in, G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; G p This represents the cumulative gas production during the production process of a coalbed methane well, 10 8 m 3 ; W p1 This represents the cumulative flowback volume of fracturing fluid during the flowback phase, 10 8 m 3 ; W p2 The cumulative water production during the production process, 10 8 m 3 ; W in This represents the total amount of fracturing fluid injected, 10 8 m 3 ; Z sc This is the natural gas deviation coefficient under standard conditions, dimensionless, and has a value of 1. T sc The temperature under standard conditions is K, with a value of 293.15. T Let K be the temperature of the coal reservoir. C s The solubility coefficient of coalbed methane in water, in MPa -1 ; Z is the average deviation coefficient under the average formation pressure of the coal reservoir, and is dimensionless; B w Let m be the volume index of water. 3 / m 3 ; p sc The pressure under standard conditions is expressed in MPa, with a value of 0.101325.

[0013] In some embodiments, the step of calculating the original geological reserves of undersaturated coalbed methane based on the corrected apparent pressure of the undersaturated coalbed methane reservoir and the equivalent cumulative gas production of the coalbed methane well includes: Plot multiple scatter points in the coordinate system with the equivalent cumulative gas production as the horizontal axis and the corrected back pressure as the vertical axis. Linear fitting was performed on multiple scatter points to obtain a linear fitting trend line of equivalent cumulative gas production - corrected apparent pressure; Determine the negative slope and ordinate intercept of the linear fitting trend line; The original geological reserves of undersaturated coalbed methane are calculated based on the negative slope and ordinate intercept of the linear fitting trend line.

[0014] In some implementations, the linear fitting trendline equation is:

[0015] in, N The ordinate intercept of the linearly fitted trend line is given in MPa. M The negative slope of the linearly fitted trend line is given by MPa / (10). 8 m 3 ); G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; p The mean formation pressure of the coal reservoir is expressed in MPa. Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, and it is dimensionless.

[0016] In some embodiments, the step of calculating the original geological reserves of undersaturated coalbed methane based on the negative slope and ordinate intercept of the linear fitting trend line includes: Substitute the negative slope, ordinate intercept, and equivalent cumulative gas production of the linear fitting trend line into the explicit undersaturated coalbed methane material balance equation to obtain the original geological reserves of undersaturated coalbed methane. The explicit mass balance equation for undersaturated coalbed methane is as follows:

[0017] in, α · p / Z To correct for rear-view pressure, MPa; G i This represents the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs, 10 8 m 3 ; G dThe coalbed methane reserves of undersaturated coalbed methane reservoirs at the critical desorption pressure, 10 8 m 3 ; Z d is the coalbed methane deviation coefficient at the critical desorption pressure, which is dimensionless; Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, which is dimensionless; G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; p The mean formation pressure of the coal reservoir is expressed in MPa. p d The critical desorption pressure is given in MPa.

[0018] In some embodiments, the original geological reserves of coalbed methane in the undersaturated coalbed methane reservoir can be calculated using the following formula:

[0019] in, G i This represents the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs, 10 8 m 3 ; N The ordinate intercept of the linearly fitted trend line is given in MPa. M The negative slope value of the linear fitting trend line is MPa / (10 8 m 3 ).

[0020] Using the above technical solution, when evaluating the original geological reserves of undersaturated coalbed methane, firstly, the reservoir physical properties, fluid physical properties, and fracturing fluid injection and flowback data of the undersaturated coalbed methane reservoir are determined; then, the average formation pressure, cumulative gas production, cumulative water production, and average deviation coefficient of the coal reservoir during the production process of the undersaturated coalbed methane well are obtained; based on the reservoir physical properties, fluid physical properties, average formation pressure, and average deviation coefficient of the coal reservoir during the production process, the undersaturated coalbed methane well is calculated. The evaluation method of this application involves several steps. First, the corrected apparent pressure of a saturated coalbed methane reservoir is calculated. Second, the equivalent cumulative gas production of the coalbed methane well is calculated based on the reservoir properties, fluid properties, total fracturing fluid injection, cumulative fracturing fluid flowback during the flowback stage, cumulative gas production, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient. Finally, the original geological reserves of the undersaturated coalbed methane are calculated based on the corrected apparent pressure and the equivalent cumulative gas production of the coalbed methane well. Using this evaluation method, only at least two measurements of the average coal reservoir pressure and corresponding cumulative gas and water production data are required during the production process. A linear fitting method is directly used, without iterative iterations, to evaluate the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs. The method is simple, clear, and easy to promote and apply.

[0021] Other features and advantages of the embodiments of this application will be described in detail in the following detailed description section. Attached Figure Description

[0022] The accompanying drawings are provided to further illustrate the embodiments of this application and form part of the specification. They are used together with the following detailed description to explain the embodiments of this application, but do not constitute a limitation on the embodiments of this application. For those skilled in the art, other drawings can be obtained based on the structures shown in these drawings without any inventive effort. In the drawings: Figure 1 This is a flowchart illustrating the method for evaluating the original geological reserves of undersaturated coalbed methane in this application. Figure 2 This is a linear fitting trend line of equivalent cumulative gas production - corrected apparent pressure in one embodiment of this application. Detailed Implementation

[0023] The specific embodiments of this application will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit this application.

[0024] The following description, with reference to the accompanying drawings, describes the method for evaluating the original geological reserves of undersaturated coalbed methane according to this application. This method is applicable to undersaturated coalbed methane reservoirs, and is particularly suitable for undersaturated coalbed methane reservoirs that have undergone large-scale hydraulic fracturing.

[0025] like Figure 1 As shown, this application provides a method for evaluating the original geological reserves of undersaturated coalbed methane. The method includes the following steps: S10: Determine the reservoir physical properties, fluid physical properties, and fracturing fluid injection and flowback data for undersaturated coalbed methane reservoirs; S20: Obtain the average formation pressure, cumulative gas production, cumulative water production, and average deviation coefficient of the coal reservoir during the production process of undersaturated coalbed methane wells; S30: Calculate the corrected back pressure of an undersaturated coalbed methane reservoir based on its reservoir physical property parameters, fluid physical property parameters, average formation pressure during production, and average deviation coefficient. S40: Calculate the equivalent cumulative gas production of a coalbed methane well based on the reservoir physical properties, fluid physical properties, total injection volume of fracturing fluid, cumulative flowback volume of fracturing fluid during the flowback stage, cumulative gas production during the production process of the coalbed methane well, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient. S50: Calculate the original geological reserves of undersaturated coalbed methane based on the corrected apparent pressure of the undersaturated coalbed methane reservoir and the equivalent cumulative gas production of the coalbed methane well.

[0026] In existing technologies, there are few reported methods for evaluating the original geological reserves of undersaturated coalbed methane (CBM) using linear fitting without iterative iteration and considering the effects of fracturing fluid injection and flowback. Therefore, this application proposes a new method for evaluating the original geological reserves of CBM based on the material balance principle of undersaturated CBM reservoirs, considering various gas occurrence modes (adsorption, ionization, and dissolution), matrix shrinkage caused by desorption, and the effects of fracturing fluid injection and flowback. Given the known physical properties of the coal reservoir, fluid properties, and fracturing fluid injection and flowback data, only at least two measurements of the average coal reservoir pressure and corresponding cumulative gas and water production are required during production. The method directly employs linear fitting without iterative iteration to evaluate the original geological reserves of CBM in undersaturated CBM reservoirs. The method is simple, clear, and easy to promote and apply.

[0027] The coal reservoir physical properties, fluid physical properties, and fracturing fluid injection and flowback data can be referenced in the following statistical table 1: Table 1. Statistical Table of Coal Reservoir Physical Properties, Fluid Physical Properties, and Fracturing Fluid Injection and Flowback Data

[0028] In some embodiments, the step of obtaining the average deviation coefficient of an undersaturated coalbed methane well during the production process includes: Collect the measured average formation pressure of coal reservoirs and the corresponding cumulative gas production and cumulative water production of undersaturated coalbed methane wells during the production process; The mean formation pressure applied to coal reservoirs is applied to an empirical / semi-empirical model, and the mean deviation coefficient of coalbed methane under any formation pressure is obtained based on the relative density of coalbed methane and reservoir temperature.

[0029] In this embodiment, the measured average formation pressure of the coal reservoir and the corresponding cumulative water production and cumulative gas production during the production process of undersaturated coalbed methane wells are collected, and the Dranchuk-Abou-Kassem method is applied based on the relative density of coalbed methane. c g and reservoir temperature T The average deviation coefficient of coalbed methane under any formation pressure can be obtained. Z The records are in Table 2.

[0030] Table 2. Measured Average Formation Pressure and Corresponding Cumulative Production in Undersaturated Coalbed Methane Wells During Production.

[0031] In some embodiments, the step of calculating the corrected apparent pressure of an undersaturated coalbed methane reservoir based on reservoir physical properties, fluid physical properties, mean formation pressure during production, and mean deviation coefficient includes: The apparent pressure correction factor under the average formation pressure of the coal reservoir is calculated based on the reservoir physical property parameters, fluid physical property parameters, original coal reservoir pressure, critical desorption pressure, coalbed methane deviation coefficient under critical desorption pressure, average formation pressure of the coal reservoir, and average deviation coefficient. The corrected apparent pressure is calculated based on the apparent pressure correction factor, the average formation pressure of the coal reservoir, and the average deviation factor.

[0032] In this embodiment, the coal reservoir physical properties and fluid physical properties, and the original coal reservoir pressure in Table 1 are used as references. p i Critical desorption pressure p d and the corresponding coalbed methane deviation coefficient Z d and the measured mean formation pressure of the coal reservoir in Table 2. p and the corresponding average deviation coefficient of coalbed methane Z Substitute the values ​​into the first formula (1) or the second formula (2) to calculate the apparent pressure correction coefficient for the average formation pressure of each measured coal reservoir. α And calculate the corrected apparent pressure. α · p / Z Add these to the last two columns of Table 2 to form Table 3.

[0033] Table 3 Dynamic Data of Coalbed Methane Wells - Including Apparent Pressure Correction Factor and Calculation Results of Corrected Apparent Pressure

[0034] In some embodiments, the step of calculating the apparent pressure correction factor at the mean formation pressure of the coal reservoir based on the reservoir physical properties, fluid physical properties, original coal reservoir pressure, critical desorption pressure, coalbed methane deviation coefficient at the critical desorption pressure, mean formation pressure of the coal reservoir, and mean deviation coefficient of the coal reservoir includes: Compare the average formation pressure and critical desorption pressure of coal reservoirs; When the average formation pressure of the coal reservoir is greater than or equal to the critical desorption pressure, the correction factor for the apparent pressure of coalbed methane is calculated using the first formula. When the average formation pressure of the coal reservoir is less than the critical desorption pressure, the correction factor for the apparent pressure of coalbed methane is calculated using the second formula.

[0035] The first formula is as follows: (1) (1) The second formula is as follows (2): (2) in, α This is a correction factor for the apparent pressure of coalbed methane, dimensionless; p sc The pressure under standard conditions is expressed in MPa, with a value of 0.101325. T Let K be the temperature of the coal reservoir. r ad The air-dried basis mass density of coal (bulk density of coal), t / m³ 3 ; V L Langmuir volume of coal on an air-dried basis, m 3 / t; p L Langmuir pressure for coal on an air-dried basis, in MPa; f i The original coal reservoir porosity is a decimal. S wi The original water saturation level is a decimal. Z sc This is the natural gas deviation coefficient under standard conditions, dimensionless, and has a value of 1. T sc The temperature under standard conditions is K, with a value of 293.15. p i The original coal reservoir pressure is given in MPa. p dThe critical desorption pressure is given in MPa. Z d is the coalbed methane deviation coefficient at the critical desorption pressure, which is dimensionless; p The mean formation pressure of the coal reservoir is expressed in MPa. Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, which is dimensionless; C p The pore compressibility coefficient of the coal reservoir is given in MPa. -1 ; C w The isothermal compressibility coefficient of water is given in MPa. -1 ; C s The solubility coefficient of undersaturated coalbed methane in water is given in MPa. -1 ; C a is the coal matrix shrinkage coefficient, which is dimensionless.

[0036] In some implementations, the step of calculating the equivalent cumulative gas production of a coalbed methane well based on reservoir physical parameters, fluid physical parameters, total fracturing fluid injection volume, cumulative fracturing fluid flowback volume during the flowback stage, cumulative gas production during the production process, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient includes: Substitute the reservoir physical properties, fluid physical properties, total fracturing fluid injection, cumulative fracturing fluid flowback during the flowback stage, cumulative gas production during the production process of the coalbed methane well, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient into the following formula to calculate the equivalent cumulative gas production corresponding to the measured average formation pressure and cumulative production of each coal reservoir. (3) in, G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; G p This represents the cumulative gas production during the production process of a coalbed methane well, 10 8 m 3 ; W p1 This represents the cumulative flowback volume of fracturing fluid during the flowback phase, 10 8 m 3 ; W p2 The cumulative water production during the production process, 10 8 m 3 ; W in This represents the total amount of fracturing fluid injected, 10 8 m 3; Z sc This is the natural gas deviation coefficient under standard conditions, dimensionless, and has a value of 1. T sc The temperature under standard conditions is K, with a value of 293.15. T Let K be the temperature of the coal reservoir. C s The solubility coefficient of coalbed methane in water, in MPa -1 ; Z is the average deviation coefficient under the average formation pressure of the coal reservoir, and is dimensionless; B w Let m be the volume index of water. 3 / m 3 ; p sc The pressure under standard conditions is expressed in MPa, with a value of 0.101325.

[0037] In this embodiment, the coal reservoir physical properties and fluid physical properties in Table 1, and the measured mean formation pressure of the coal reservoir in Table 2 are used. p and the corresponding average deviation coefficient of coalbed methane Z Substituting into formula (3), the equivalent cumulative gas production corresponding to the average formation pressure and cumulative production of each measured coal reservoir is calculated. G peq Add this information to the last column of Table 3 to form Table 4.

[0038] Table 4 Dynamic Data of Coalbed Methane Wells - Including Apparent Pressure Correction Factor, Corrected Apparent Pressure, and Calculation Results of Equivalent Cumulative Gas Production

[0039] In some implementations, the step of calculating the original geological reserves of undersaturated coalbed methane based on the corrected apparent pressure of the undersaturated coalbed methane reservoir and the equivalent cumulative gas production of the coalbed methane well includes: Plot multiple scatter points in the coordinate system with the equivalent cumulative gas production as the horizontal axis and the corrected back pressure as the vertical axis. Linear fitting was performed on multiple scatter points to obtain a linear fitting trend line of equivalent cumulative gas production - corrected apparent pressure; Determine the negative slope and ordinate intercept of the linear fitting trend line; The original geological reserves of undersaturated coalbed methane are calculated based on the negative slope of the linear fitting trend line and the intercept of the ordinate.

[0040] In some implementations, the linear fitting trendline equation is: (4) in, N The ordinate intercept of the linearly fitted trend line is given in MPa.M The negative slope of the linearly fitted trend line is given by MPa / (10). 8 m 3 ); G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; p The mean formation pressure of the coal reservoir is expressed in MPa. Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, and it is dimensionless.

[0041] In some implementations, the step of calculating the original geological reserves of undersaturated coalbed methane based on the negative slope and ordinate intercept of the linear fitting trend line includes: Substitute the negative slope, ordinate intercept, and equivalent cumulative gas production of the linear fitting trend line into the explicit undersaturated coalbed methane material balance equation to obtain the original geological reserves of undersaturated coalbed methane. The explicit mass balance equation for undersaturated coalbed methane is as follows: (5) in, α · p / Z To correct for rear-view pressure, MPa; G i This represents the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs, 10 8 m 3 ; G d The coalbed methane reserves of undersaturated coalbed methane reservoirs at the critical desorption pressure, 10 8 m 3 ; Z d is the coalbed methane deviation coefficient at the critical desorption pressure, which is dimensionless; Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, which is dimensionless; G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; p The mean formation pressure of the coal reservoir is expressed in MPa. p d The critical desorption pressure is given in MPa.

[0042] Based on the above formula (5), formula (5) can be rewritten as follows: ,in, N undersaturated coalbed methane reservoir α · p / Z ~ Gpeq The ordinate intercept of the linear trend line, in MPa; M undersaturated coalbed methane reservoir α · p / Z ~ G peq The negative slope of the linear trend line, MPa / (10 8 m 3 ).

[0043] by G peq With the horizontal axis as the base, α · p / Z Using the vertical axis as the ordinate, a scatter plot is drawn on a rectangular coordinate graph. A linear fit is then used to obtain the negative slope value of the resulting linear trend line. M Intercept value of the ordinate and the vertical axis N .

[0044] Furthermore, the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs can be calculated using the following formula: (6) in, G i This represents the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs, 10 8 m 3 ; N The ordinate intercept of the linearly fitted trend line is given in MPa. M The negative slope of the linearly fitted trend line is given by MPa / (10). 8 m 3 ).

[0045] Furthermore, to more clearly illustrate the method for evaluating the original geological reserves of undersaturated coalbed methane in this application, the following example uses a vertical coalbed methane well in an undersaturated coalbed methane reservoir. This vertical coalbed methane well underwent fracturing stimulation, with a total injection of 0.00003 (10 8 m 3 During the fracturing fluid flowback stage, a total of 0.000015 (10) fracturing fluids were flowed back. 8 m 3 Then, production began. During production, six average formation pressure tests were conducted, six sets of average formation pressure data for the coal reservoir were obtained, and the corresponding cumulative gas production and cumulative water production were collected. The original geological reserves of coalbed methane within the control area of ​​this coalbed methane well were calculated.

[0046] When evaluating the original geological reserves of this undersaturated coalbed methane reservoir, the reservoir physical property parameters, fluid physical property parameters, and fracturing fluid injection and flowback data of the undersaturated coalbed methane reservoir were first compiled and statistically analyzed, as shown in Table 5 below.

[0047] Table 5. Statistical Table of Coal Reservoir Physical Properties, Fluid Physical Properties, and Fracturing Fluid Injection and Flowback Data

[0048] Then, the measured average formation pressure of the coal reservoir and the corresponding cumulative water production and cumulative gas production during the production process of undersaturated coalbed methane wells were collected. The Dranchuk-Abou-Kassem method was then applied, based on the relative density of the coalbed methane... c g and reservoir temperature T The average deviation coefficient of coalbed methane under any formation pressure can be obtained. Z The records are in Table 6.

[0049] Table 6. Measured Average Formation Pressure and Corresponding Cumulative Production in Undersaturated Coalbed Methane Wells During Production.

[0050] Secondly, the reservoir physical properties and fluid physical properties of the undersaturated coalbed methane reservoirs in Table 5, as well as the original coal reservoir pressure, are then analyzed. p i Critical desorption pressure p d and the corresponding coalbed methane deviation coefficient Z d and the measured mean formation pressure of the coal reservoir in Table 6. p and the corresponding average deviation coefficient of coalbed methane Z Substitute the values ​​into the first formula (1) or the second formula (2) to calculate the apparent pressure correction coefficient for the average formation pressure of each measured coal reservoir. α And calculate the corrected apparent pressure. α · p / Z .

[0051] When the average formation pressure of the coal reservoir p Greater than or equal to the critical desorption pressure p d ,Right now p ≥ p d When calculating the apparent pressure of coalbed methane, the correction factor is calculated using the first formula (1). α Using data from day 361 as an example, this demonstrates the average formation pressure of the coal reservoir. p Not less than the critical desorption pressure p d At that time, depending on the pressure correction factor α and corrected visual pressure α · p / Z The calculation process is as follows:

[0052]

[0053] When the average formation pressure of the coal reservoir p Less than the critical desorption pressure p d ,Right now p < p d When calculating the apparent pressure of coalbed methane, the correction factor is calculated using the second formula (2). α Taking the data from day 786 as an example, when the average formation pressure of the coal reservoir... p Less than the critical desorption pressure p d At that time, depending on the pressure correction factor α and corrected back pressure α · p / Z The calculation process is as follows:

[0054]

[0055] The apparent pressure correction factor for all six sets of data was calculated using the method described above. α and corrected visual pressure α · p / Z The calculation results are added to the last two columns of Table 6 to form Table 7.

[0056] Table 7 Dynamic Data of Undersaturated Coalbed Methane Wells - Including Apparent Pressure Correction Factor and Corrected Apparent Pressure Calculation Results

[0057] Then, based on the above results, the reservoir physical properties, fluid physical properties, and fracturing fluid injection and flowback data of the undersaturated coalbed methane reservoir in Table 5, and the cumulative gas production, cumulative water production, and measured average formation pressure of the coalbed methane wells in Table 6 are compared. p and the corresponding coalbed methane deviation coefficient Z Substituting into the above formula (3), the equivalent cumulative gas production corresponding to the average formation pressure and cumulative production of each measured coal reservoir is calculated. G peq .

[0058] Taking the data from day 361 as an example, the equivalent cumulative gas production G peq The calculation process is as follows:

[0059] The equivalent cumulative gas production of all six sets of data was calculated using the method described above. G peq The calculation results are added to the last column of Table 7 to form Table 8.

[0060] Table 8 Dynamic Data of Undersaturated Coalbed Methane Wells - Including Apparent Pressure Correction Factor, Corrected Apparent Pressure, and Calculation Results of Equivalent Cumulative Gas Production

[0061] Finally, with G peq With the horizontal axis as the base, a·p / Z Plot a scatter plot in a rectangular coordinate system with the vertical axis as the y-axis, such as... Figure 2 As shown, linear fitting is used, and the function for linearly fitting the trend line is:

[0062] As can be seen from the above function, the negative slope value of the obtained linear fitting trend line is... M Intercept value of the ordinate and the vertical axis N They are 25.48003812 MPa / (10 8 m 3 ) and 9.97415895 MPa.

[0063] The original geological reserves of undersaturated coalbed methane calculated using formula (6) are 0.39144992 (10 8 m 3 ).

[0064]

[0065] In the description of this application, it should be understood that the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of technical features indicated. Therefore, a feature defined as "first" or "second" may explicitly or implicitly include at least one of that feature. In the description of this application, "multiple" means at least two, such as two, three, etc., unless otherwise explicitly specified.

[0066] In this application, unless otherwise expressly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection, an electrical connection, or a connection that allows communication between components; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components, unless otherwise expressly limited. Those skilled in the art can understand the specific meaning of the above terms in this application based on the specific circumstances.

[0067] In the description of this specification, the references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., refer to specific features, structures, materials, or characteristics described in connection with that embodiment or example, which are included in at least one embodiment or example of this application. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Moreover, without contradiction, those skilled in the art can combine and integrate the different embodiments or examples described in this specification, as well as the features of different embodiments or examples.

[0068] Although embodiments of this application have been shown and described above, it is understood that the above embodiments are exemplary and should not be construed as limiting this application. Those skilled in the art can make changes, modifications, substitutions and variations to the above embodiments within the scope of this application.

Claims

1. A method for evaluating the original geological reserves of undersaturated coalbed methane, characterized in that, The original geological reserve evaluation method includes the following steps: Determine the reservoir physical properties, fluid physical properties, and fracturing fluid injection and flowback data for undersaturated coalbed methane reservoirs; To obtain the average formation pressure, cumulative gas production, cumulative water production, and average deviation coefficient of the coal reservoir in the production process of undersaturated coalbed methane wells; The corrected back pressure of the undersaturated coalbed methane reservoir is calculated based on the reservoir physical property parameters, fluid physical property parameters, average formation pressure of the coal reservoir during the production process, and average deviation coefficient. The equivalent cumulative gas production of a coalbed methane well is calculated based on the reservoir physical properties, fluid physical properties, total fracturing fluid injection, cumulative fracturing fluid flowback during the flowback stage, cumulative gas production during the production process, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient. The original geological reserves of undersaturated coalbed methane are calculated based on the corrected apparent pressure of the undersaturated coalbed methane reservoir and the equivalent cumulative gas production of the coalbed methane well.

2. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 1, characterized in that, The step of obtaining the average deviation coefficient of an undersaturated coalbed methane well during the production process includes: Collect the measured average formation pressure of coal reservoirs and the corresponding cumulative gas production and cumulative water production of undersaturated coalbed methane wells during the production process; The average formation pressure of coal reservoirs is applied to an empirical / semi-empirical model, and the average deviation coefficient of coalbed methane under any formation pressure is obtained based on the relative density of coalbed methane and the reservoir temperature.

3. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 1, characterized in that, The step of calculating the corrected apparent pressure of an undersaturated coalbed methane reservoir based on its reservoir physical properties, fluid physical properties, mean formation pressure during production, and mean deviation coefficient includes: The apparent pressure correction factor under the average formation pressure of the coal reservoir is calculated based on the reservoir physical property parameters, fluid physical property parameters, original coal reservoir pressure, critical desorption pressure, coalbed methane deviation coefficient under critical desorption pressure, average formation pressure of the coal reservoir, and the average deviation coefficient of the undersaturated coalbed methane reservoir. The corrected apparent pressure is calculated based on the apparent pressure correction factor, the average formation pressure of the coal reservoir, and the average deviation factor.

4. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 3, characterized in that, The step of calculating the apparent pressure correction factor under the average formation pressure of the coal reservoir based on the reservoir physical property parameters, fluid physical property parameters, original coal reservoir pressure, critical desorption pressure, coalbed methane deviation coefficient under the critical desorption pressure, average formation pressure of the coal reservoir, and the average deviation coefficient of the coal reservoir includes: Compare the average formation pressure and critical desorption pressure of coal reservoirs; When the average formation pressure of the coal reservoir is greater than or equal to the critical desorption pressure, the correction factor for the apparent pressure of the coalbed methane is calculated using the first formula. When the average formation pressure of the coal reservoir is less than the critical desorption pressure, the correction factor for the apparent pressure of the coalbed methane is calculated using the second formula.

5. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 4, characterized in that, The first formula is as follows: (1) （1） The second formula is as follows: (2) （2） in, α This is a correction factor for the apparent pressure of coalbed methane, dimensionless; p sc The pressure under standard conditions is expressed in MPa, with a value of 0.101325. T Let K be the temperature of the coal reservoir. ρ ad The air-dried basis mass density of coal (bulk density of coal), t / m³ 3 ; V L Langmuir volume of coal on an air-dried basis, m 3 / t; p L Langmuir pressure for coal on an air-dried basis, in MPa; φ i The original coal reservoir porosity is a decimal. S wi The original water saturation level is a decimal. Z sc This is the natural gas deviation coefficient under standard conditions, dimensionless, and has a value of 1. T sc The temperature under standard conditions is K, with a value of 293.

15. p i The original coal reservoir pressure is given in MPa. p d The critical desorption pressure is given in MPa. Z d is the coalbed methane deviation coefficient at the critical desorption pressure, which is dimensionless; p The mean formation pressure of the coal reservoir is expressed in MPa. Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, which is dimensionless; C p The pore compressibility coefficient of the coal reservoir is given in MPa. -1 ; C w The isothermal compressibility coefficient of water is given in MPa. -1 ; C s The solubility coefficient of undersaturated coalbed methane in water is given in MPa. -1 ; C a is the coal matrix shrinkage coefficient, which is dimensionless.

6. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 1, characterized in that, The steps for calculating the equivalent cumulative gas production of a coalbed methane well based on the reservoir physical parameters, fluid physical parameters, total fracturing fluid injection volume, cumulative fracturing fluid flowback volume during the flowback stage, cumulative gas production during the production process, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient include: Substitute the reservoir physical properties, fluid physical properties, total fracturing fluid injection, cumulative fracturing fluid flowback during the flowback stage, cumulative gas production during the production process of the coalbed methane well, cumulative water production during the production process, average formation pressure of the coal reservoir, and average deviation coefficient into the following formula to calculate the equivalent cumulative gas production corresponding to the measured average formation pressure and cumulative production of each coal reservoir. in, G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; G p This represents the cumulative gas production during the production process of a coalbed methane well, 10 8 m 3 ; W p1 This represents the cumulative flowback volume of fracturing fluid during the flowback phase, 10 8 m 3 ; W p2 The cumulative water production during the production process, 10 8 m 3 ; W in This represents the total amount of fracturing fluid injected, 10 8 m 3 ; Z sc This is the natural gas deviation coefficient under standard conditions, dimensionless, and has a value of 1. T sc The temperature under standard conditions is K, with a value of 293.

15. T Let K be the temperature of the coal reservoir. C s The solubility coefficient of coalbed methane in water, in MPa -1 ; Z is the average deviation coefficient under the average formation pressure of the coal reservoir, and is dimensionless; B w Let m be the volume index of water. 3 / m 3 ; p sc The pressure under standard conditions is expressed in MPa, with a value of 0.101325.

7. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 1, characterized in that, The step of calculating the original geological reserves of undersaturated coalbed methane based on the corrected apparent pressure of the undersaturated coalbed methane reservoir and the equivalent cumulative gas production of the coalbed methane well includes: Plot multiple scatter points in the coordinate system with the equivalent cumulative gas production as the horizontal axis and the corrected back pressure as the vertical axis. Linear fitting was performed on multiple scatter points to obtain a linear fitting trend line of equivalent cumulative gas production - corrected apparent pressure; Determine the negative slope and ordinate intercept of the linear fitting trend line; The original geological reserves of undersaturated coalbed methane are calculated based on the negative slope and ordinate intercept of the linear fitting trend line.

8. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 7, characterized in that, The equation for the linear fitting trend line is: in, N The ordinate intercept of the linearly fitted trend line is given in MPa. M The negative slope of the linearly fitted trend line is given by MPa / (10). 8 m 3 ); G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; p The mean formation pressure of the coal reservoir is expressed in MPa. Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, and it is dimensionless.

9. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 7, characterized in that, The step of calculating the original geological reserves of undersaturated coalbed methane based on the negative slope and ordinate intercept of the linear fitting trend line includes: Substitute the negative slope, ordinate intercept, and equivalent cumulative gas production of the linear fitting trend line into the explicit undersaturated coalbed methane material balance equation to obtain the original geological reserves of undersaturated coalbed methane. The explicit mass balance equation for undersaturated coalbed methane is as follows: in, α · p / Z To correct for rear-view pressure, MPa; G i This represents the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs, 10 8 m 3 ; G d The coalbed methane reserves of undersaturated coalbed methane reservoirs at the critical desorption pressure, 10 8 m 3 ; Z d is the coalbed methane deviation coefficient at the critical desorption pressure, which is dimensionless; Z is the average deviation coefficient of coalbed methane under the average formation pressure of the coal reservoir, which is dimensionless; G peq The equivalent cumulative gas production of a coalbed methane well, 10 8 m 3 ; p The mean formation pressure of the coal reservoir is expressed in MPa. p d The critical desorption pressure is given in MPa.

10. The method for evaluating the original geological reserves of undersaturated coalbed methane according to claim 7, characterized in that, The original geological reserves of coalbed methane in the undersaturated coalbed methane reservoir can be calculated using the following formula: in, G i This represents the original geological reserves of coalbed methane in undersaturated coalbed methane reservoirs, 10 8 m 3 ; N The ordinate intercept of the linearly fitted trend line is given in MPa. M The negative slope value of the linear fitting trend line is MPa / (10 8 m 3 ).

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