A gas reservoir reserve calculation method, device, system and storage medium

Abstract

The application provides a gas reservoir reserve calculation method, device and system and a storage medium, and belongs to the field of oil and gas development. The method comprises the following steps: obtaining an initial dynamic reserve value and a deliverability equation coefficient, and importing gas storage well production data and reservoir parameters; obtaining a predicted wellhead pressure by analyzing the wellhead pressure through the gas storage well production data, the reservoir parameters, the initial dynamic reserve value and the deliverability equation coefficient; calculating an error value of the wellhead pressure through the predicted wellhead pressure and the gas storage well production data, obtaining a target dynamic reserve value according to the calculation result, and taking the target dynamic reserve value as a gas reservoir reserve calculation result. The application reduces the influence on the prediction of the dynamic reserve of the gas storage, solves the error caused by the approximate deviation factor, has a faster fitting speed, and improves the prediction accuracy of the dynamic reserve.

Description

TECHNICAL FIELD

[0001] The present application mainly relates to the technical field of oil and gas development, and particularly relates to a gas reservoir reserve calculation method, device, system and storage medium. BACKGROUND

[0002] Most of the underground gas storage are converted from depleted gas reservoirs or weak edge water gas reservoirs. During the injection-production operation, gas and water are in contact all the time. The seepage characteristics of the two-phase mutual displacement in the gas-water transition zone formed by the periodic operation have a certain influence on the injection-production capacity of the gas storage and the calculation of the gas storage reserves. At present, the gas reservoir reserve calculation method is relatively mature. Shi et al. calculated the gas reservoir reserves by fitting the dynamic production data with the material balance method. Luo et al. established a gas reservoir reserve calculation method for super-deep natural fractured tight sandstone gas reservoirs and analyzed the main influencing factors of dynamic reserve evaluation. Okoro et al. calculated the gas reservoir reserves by using the decline curve.

[0003] However, the existing gas reservoir reserve calculation method cannot be completely applied to the water-producing gas storage. Lai et al. established a CO2 reserve calculation method for depleted wet / dry gas reservoirs based on the material balance principle and considering the periodicity of CO2 injection-production. However, the formation pressure data used in this method is difficult to obtain in actual production. Cheng Shiqing et al. combined the gas reservoir material balance equation with the binomial productivity equation and solved the bottom hole flowing pressure by simultaneous equations, which was fitted with the bottom hole flowing pressure curve in the actual production process to calculate the single well dynamic reserve. This method avoids solving the formation pressure and fully considers the change of the bottom hole pressure, but ignores the water production situation and the fitting method is time-consuming. Xu Bingxiang et al. established a water-producing gas well material balance equation and described the process of solving the dynamic reserve of the gas well by the water-gas two-phase material balance equation. However, this method only considers the water production of the gas reservoir and cannot be completely applied to the dynamic reserve evaluation of the multi-injection-production cycle water-producing gas storage. Therefore, how to calculate more accurate reserves combined with the injection-production cycle characteristics of the water-producing and gas storage is a difficult problem to be solved. SUMMARY

[0004] The technical problem solved by the present application is to provide a gas reservoir reserve calculation method, device, system and storage medium to solve the problems of the prior art.

[0005] The technical scheme for solving the above technical problem is as follows: a gas reservoir reserve calculation method, comprising the following steps:

[0006] S1: obtaining an initial dynamic reserve value and a productivity equation coefficient, and importing gas storage well production data and reservoir parameters;

[0007] S2: analyzing the wellhead pressure by the gas storage well production data, the reservoir parameters, the initial dynamic reserve value and the productivity equation coefficient to obtain a predicted wellhead pressure;

[0008] S3: Calculate the error value of the wellhead pressure using the predicted wellhead pressure and the gas well production data of the gas storage facility, obtain the target dynamic reserve value based on the calculation result, and use the target dynamic reserve value as the gas reservoir reserve calculation result.

[0009] Another technical solution of the present invention to solve the above-mentioned technical problems is as follows: A gas reservoir storage calculation device, comprising:

[0010] The data acquisition module is used to obtain the initial dynamic reserve value and production capacity equation coefficients, and to import the gas well production data and reservoir parameters of the gas storage facility.

[0011] The pressure analysis module is used to analyze the wellhead pressure using the gas well production data of the gas storage facility, the reservoir parameters, the initial dynamic reserve value, and the production capacity equation coefficients, and to obtain the predicted wellhead pressure.

[0012] The calculation result acquisition module is used to calculate the error value of the wellhead pressure using the predicted wellhead pressure and the gas well production data of the gas storage facility, obtain the target dynamic reserve value based on the calculation result, and use the target dynamic reserve value as the gas reservoir reserve calculation result.

[0013] Based on the above-mentioned method for calculating gas reservoir reserves, the present invention also provides a gas reservoir reserve calculation system.

[0014] Another technical solution of the present invention to solve the above-mentioned technical problems is as follows: a gas reservoir reserve calculation system, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the gas reservoir reserve calculation method as described above.

[0015] Based on the above-mentioned method for calculating gas reservoir reserves, the present invention also provides a computer-readable storage medium.

[0016] Another technical solution of the present invention to solve the above-mentioned technical problems is as follows: a computer-readable storage medium storing a computer program, which, when executed by a processor, implements the gas reservoir storage calculation method as described above.

[0017] The beneficial effects of this invention are as follows: By analyzing the wellhead pressure using gas well production data, reservoir parameters, initial dynamic reserve values, and production capacity equation coefficients, the predicted wellhead pressure is obtained. The error value of the wellhead pressure is calculated using the predicted wellhead pressure and gas well production data of the gas storage facility. Based on the calculation results, the target dynamic reserve value is obtained, and the target dynamic reserve value is used as the gas reservoir reserve calculation result. This reduces the impact on the prediction of dynamic reserves of the gas storage facility, solves the error caused by the approximation deviation factor, has a faster fitting speed, and improves the prediction accuracy of dynamic reserves. Attached Figure Description

[0018] Figure 1 A schematic flowchart illustrating the gas reservoir reserve calculation method provided in an embodiment of the present invention;

[0019] Figure 2 A block diagram of a gas reservoir storage calculation device provided in an embodiment of the present invention. Detailed Implementation

[0020] The principles and features of the present invention are described below with reference to the accompanying drawings. The examples given are only for explaining the present invention and are not intended to limit the scope of the present invention.

[0021] Figure 1 This is a flowchart illustrating a method for calculating gas reservoir reserves provided in an embodiment of the present invention.

[0022] like Figure 1 As shown, a method for calculating gas reservoir reserves includes the following steps:

[0023] S1: Obtain the initial dynamic reserve value and production capacity equation coefficients, and import the gas well production data and reservoir parameters of the gas storage facility;

[0024] S2: Analyze the wellhead pressure using the gas well production data of the gas storage facility, the reservoir parameters, the initial dynamic reserve value, and the production capacity equation coefficients to obtain the predicted wellhead pressure;

[0025] S3: Calculate the error value of the wellhead pressure using the predicted wellhead pressure and the gas well production data of the gas storage facility, obtain the target dynamic reserve value based on the calculation result, and use the target dynamic reserve value as the gas reservoir reserve calculation result.

[0026] It should be understood that the gas well production data of the gas storage facility and the reservoir parameters are obtained; the initial dynamic reserve value and the production capacity equation coefficients are set.

[0027] In the above embodiments, the predicted wellhead pressure is obtained by analyzing the wellhead pressure using gas well production data, reservoir parameters, initial dynamic reserve values, and production capacity equation coefficients. The error value of the wellhead pressure is calculated by comparing the predicted wellhead pressure with the gas well production data of the gas storage facility. Based on the calculation results, the target dynamic reserve value is obtained and used as the gas reservoir reserve calculation result. This reduces the impact on the prediction of dynamic reserves of the gas storage facility, solves the error caused by the approximation deviation factor, has a faster fitting speed, and improves the prediction accuracy of dynamic reserves.

[0028] Optionally, as an embodiment of the present invention, the process of S2 includes:

[0029] The bottom-hole pressure is obtained by calculating the bottom-hole pressure using the gas well production data of the gas storage facility, the reservoir parameters, the initial dynamic reserve value, and the production capacity equation coefficients.

[0030] The predicted wellhead pressure is obtained by calculating the production data of the gas well in the gas storage facility and the wellhead pressure of the bottom hole pressure.

[0031] It should be understood that most underground gas storage facilities are converted from depleted or weakly marginal water gas reservoirs. Unlike gas reservoirs, gas storage facilities involve a complex production model that combines gas injection and production. If gas reservoir reserve evaluation methods are directly applied to gas storage facilities, the calculation results may contain errors. During injection and production operations, gas and water are constantly in contact. The seepage characteristics of the two-phase alternating displacement in the gas-water transition zone formed by cyclical operation have a certain impact on the injection and production capacity of the gas storage facility and the evaluation of its reserves. Therefore, it is necessary to establish a water production material balance equation.

[0032] In the above embodiments, the bottom-hole pressure is obtained by calculating the bottom-hole pressure using gas well production data, reservoir parameters, initial dynamic reserves, and production capacity equation coefficients. The wellhead pressure is then calculated by combining the gas well production data and the bottom-hole pressure to obtain the predicted wellhead pressure. This reduces the impact on the prediction of dynamic reserves in the gas storage facility, solves the error caused by the approximation deviation factor, has a faster fitting speed, and improves the prediction accuracy of dynamic reserves.

[0033] Optionally, as an embodiment of the present invention, the gas well production data of the gas storage facility includes cumulative water production, cumulative gas injection volume, deviation coefficient under current formation pressure, and daily gas production; the reservoir parameters include the original formation pressure; and the production capacity equation coefficients include the exponential production capacity equation coefficients and the permeability index.

[0034] The process of calculating the bottom-hole pressure using the gas well production data of the gas storage facility, the reservoir parameters, the initial dynamic reserve value, and the production capacity equation coefficients includes:

[0035] The bottom hole pressure is calculated using the first formula, the cumulative water production, the cumulative gas injection volume, the daily gas production, the original formation pressure, the initial dynamic reserve value, the seepage index, and the coefficients of the exponential productivity equation. The first formula is:

[0036]

[0037] Where, p wf p is the bottom hole pressure. i Z represents the original formation pressure. i Z is the deviation coefficient under preset formation pressure. R G is the deviation coefficient under the current formation pressure. p To accumulate gas production, G in G represents the cumulative gas injection volume, G represents the initial dynamic storage value, and B represents the cumulative gas injection volume. w W is the water volume coefficient. p To accumulate water production, Bgi q is the gas volume coefficient. g Where C is the daily gas production, n is the coefficient of the exponential capacity equation, and n is the seepage index.

[0038] It should be understood that the bottom hole pressure is calculated using the basic reservoir parameters of the gas well in the gas storage facility (i.e., the cumulative water production, the cumulative gas injection volume, the daily gas production, the original formation pressure, the initial dynamic reserve value, the seepage index, and the coefficients of the exponential production capacity equation), as follows:

[0039]

[0040] or

[0041]

[0042] In the formula, W p To accumulate water production, m 3 B gi Let m be the volume index of the gas under the original conditions. 3 / m 3 ;

[0043] B g Let m be the volume coefficient of the gas at a certain moment. 3 / m 3 B w Let m be the volume index of water at a certain moment. 3 / m 3 G p To accumulate gas production, 10 4 m 3 G in To accumulate the gas injection volume, 10 4 m 3 G represents the dynamic reserves of the gas well, 10 4 m 3 ;p i Z represents the original formation pressure, in MPa; R Z is the deviation coefficient under formation pressure; i The deviation coefficient under the original formation pressure; A is the laminar flow coefficient of the binomial productivity equation, MPa / (10 4 m 3 ·d -1 B is the turbulence coefficient of the binomial capacity equation, MPa / (10). 4 m 3 ·d -1 ) 2 C is the coefficient of the exponential capacity equation, 10 4 (m 3 ·d -1 ) / MPa 2n n is the seepage index; qg Daily gas production, m 3 ;p wf The bottom hole pressure is MPa.

[0044] Specifically, based on the principle of mass balance, the cumulative gas injection and cumulative gas production of the gas storage facility are taken into account to obtain the gas mass balance equation, as follows:

[0045]

[0046] Water equation:

[0047]

[0048] In the formula, W p To accumulate water production, m 3 B gi Let m be the volume index of the gas under the original conditions. 3 / m 3 B g Let m be the volume coefficient of the gas at a certain moment. 3 / m 3 B w Let m be the volume index of water at a certain moment. 3 / m 3 S wi The initial water saturation; S w Let V be the water saturation at a certain moment; V be the total pore volume, 10 4 m 3 G p To accumulate gas production, 10 4 m 3 G in To accumulate the gas injection volume, 10 4 m 3 G represents the dynamic reserves of the gas well, 10 4 m 3 .

[0049] From equation (2), we get the following formula:

[0050]

[0051] Substituting equation (3) into equation (1), we get the following formula:

[0052]

[0053] in,

[0054]

[0055] Substituting equations (5) and (6) into equation (4), equation (4) can be simplified to:

[0056]

[0057] Where p R is the formation pressure, MPa; p i is the original formation pressure, MPa; Z R is the deviation factor at formation pressure, and Z i is the deviation factor at original formation pressure.

[0058] S2: Establish the material balance-production capacity equation

[0059] The formation pressure is usually difficult to measure during actual construction. To avoid using formation pressure data, the following relationship is derived from the material balance equation (7):

[0060]

[0061] Then the formation pressure can be obtained by solving the right side of Equation (8). However, Z R and B w in Equation (8) are unknowns related to p R . To solve this problem, an alternating iteration algorithm is used to solve for the formation pressure p R , Z R and B w . The specific solution steps are as follows:

[0062] Step1: Initialize p R0 ;

[0063] Step2: Solve for Z R0 and B R according to p w ;

[0064] Step3: Substitute the solved Z R and B w into Equation (8) to calculate p R ;

[0065]

[0065]

[0065] Step4: Calculate the absolute error err0 = |p R - p R0 | between p R and p R0 ;

[0066] Step5: If err0 < err, exit the loop; if err0 > err, assign p R to p R0 , and repeat Step2, Step3, and Step4.

[0067] The Z R can be obtained through the above alternating iteration algorithm.and B w Then, substitute equation (8) into the capacity equation. The capacity equation can be divided into a binomial capacity equation, as shown in the following formula:

[0068]

[0069] And the exponential capacity equation, the formula is as follows:

[0070]

[0071] After substituting, we get the following formula:

[0072]

[0073] or

[0074]

[0075] Where A is the laminar flow coefficient of the binomial capacity equation, MPa / (10 4 m 3 ·d -1 B is the turbulence coefficient of the binomial capacity equation, MPa / (10). 4 m 3 ·d -1 ) 2 C is the coefficient of the exponential capacity equation, 10 4 (m 3 ·d -1 ) / MPa 2n n is the seepage index; q g Daily gas production, m 3 ;p wf The bottom hole pressure is MPa.

[0076] In the above embodiments, the bottom hole pressure is obtained by calculating the bottom hole pressure using the first formula, cumulative water production, cumulative gas injection, daily gas production, original formation pressure, initial dynamic reserve value, seepage index, and coefficients of the exponential production capacity equation. This eliminates the need for formation pressure data, reduces the difficulty of data acquisition, has a faster fitting speed, and improves the prediction accuracy of dynamic reserves.

[0077] Optionally, as an embodiment of the present invention, the gas storage well production data includes daily gas production, and the process of calculating the gas storage well production data and the wellhead pressure of the bottom hole pressure to obtain the predicted wellhead pressure includes:

[0078] The predicted wellhead pressure is obtained by calculating the wellhead pressure relative to the bottom hole pressure using the second formula, which is:

[0079]

[0080] in,

[0081] Where, p h To predict wellhead pressure, p wf d is the bottom hole pressure, d is the wellbore inner diameter, and q is the bottom hole pressure. g Daily gas production Let S be the average temperature of the wellbore, S be a dimensionless quantity, and f be the coefficient of friction. r is the average deviation coefficient of the wellbore. g Let H be the relative density of the gas inside the wellbore, H be the length of the wellbore, Re be the Reynolds number, and ε be the roughness of the pipe inside the wellbore.

[0082] It should be understood that the wellhead pressure is calculated using the bottom hole pressure:

[0083]

[0084] in,

[0085]

[0086] In the formula, p h Wellhead pressure, MPa; The average temperature of the wellbore is K; R is the average deviation coefficient of the wellbore; H is the length of the wellbore, in meters; r g ρ is the relative density of the gas inside the wellbore; d is the inner diameter of the wellbore, in meters.

[0087]

[0088] In the formula, R e ε is the Reynolds number; ε is the roughness of the pipes inside the injection / production well, in meters (m).

[0089] Specifically, the bottom hole flowing pressure is obtained, and then converted into wellhead pressure using the wellhead pressure calculation formula, as follows:

[0090]

[0091] in

[0092]

[0093] p h Wellhead pressure, MPa; The average temperature of the wellbore is K; R is the average deviation coefficient of the wellbore; H is the length of the wellbore, in meters; r g ρ is the relative density of the gas inside the wellbore; d is the inner diameter of the wellbore, in meters.

[0094]

[0095] In the formula, Re ε is the Reynolds number; ε is the roughness of the pipes inside the injection / production well, in meters (m).

[0096] In equations (11) and (12), G p G in p i W p and q g Z is a known quantity. i Can be made by T i and p i Calculated using the Standing-Katz chart. B gi It can be determined by the formation temperature T and Z i and p i The calculation is then performed. The wellhead pressure obtained from equation (13) is then fitted to the actual wellhead pressure, allowing the calculation of the unknown parameters G, A, and B, or C and n, in equations (11) or (12). This method can evaluate the dynamic reserves of the water-producing gas reservoir and determine the coefficients of the binomial or exponential production capacity equations for gas wells.

[0097] In the above embodiments, the predicted wellhead pressure is obtained by calculating the gas well production data and bottom hole pressure of the gas storage facility. This can not only evaluate the dynamic reserves of the water-producing gas storage facility, but also determine the coefficients of the binomial or exponential production capacity equation of the gas well, thereby improving the prediction accuracy of dynamic reserves.

[0098] Alternatively, as an embodiment of the present invention,

[0099] The gas well production data of the gas storage facility includes the actual wellhead pressure. In step S3, the process of calculating the error value of the wellhead pressure using the predicted wellhead pressure and the gas well production data of the gas storage facility, and obtaining the target dynamic reserve value based on the calculation result, includes:

[0100] S31: Calculate the difference between the predicted wellhead pressure and the actual wellhead pressure to obtain the wellhead pressure error value;

[0101] S32: Determine whether the wellhead pressure error value is less than the preset error value. If not, proceed to S33. If yes, use the initial dynamic reserve value as the target dynamic reserve value.

[0102] S33: Update the initial dynamic reserve value and the production capacity equation coefficients according to the wellhead pressure error value, and then return to step S1.

[0103] Preferably, the preset error value can be 0.0001.

[0104] Specifically, the absolute error err (i.e., the wellhead pressure error) between the calculated wellhead pressure (i.e., the predicted wellhead pressure) and the actual producing wellhead pressure (i.e., the actual wellhead pressure) is calculated; when err < 0.0001, the dynamic reserve value (i.e., the initial dynamic reserve value) and the production capacity equation coefficients are output; otherwise, the dynamic reserve value (i.e., the initial dynamic reserve value) and the production capacity equation coefficients are updated.

[0105] In the above embodiments, the error value of wellhead pressure is calculated by predicting wellhead pressure and gas well production data of gas storage, and the target dynamic reserve value is obtained based on the calculation results. This reduces the impact on the prediction of dynamic reserves of gas storage, solves the error caused by the approximation deviation factor, has a faster fitting speed, and improves the prediction accuracy of dynamic reserves.

[0106] Optionally, as another embodiment of the present invention, the material balance-production capacity equation is one of the commonly used methods for calculating gas well reserves. However, the approximation deviation factor and neglect of the influence of gas well water production significantly increase the error in reserve calculation during the solution process. Furthermore, this method also suffers from the drawback of time-consuming pressure fitting. To address these problems, the present invention is proposed. Specifically, the factors of water production and cumulative gas production are introduced into the material balance equation to reduce their impact on the prediction of dynamic gas reserves. Then, an alternating iterative algorithm is used to solve the formation pressure and deviation factor in the material balance equation to address the error caused by the approximation deviation factor. Finally, a particle swarm optimization algorithm is used to fit actual production data to calculate the dynamic reserves of the gas storage facility, exhibiting a faster fitting speed. Experiments show that the proposed method can effectively improve the fitting speed and provides a more reasonable and accurate evaluation of the dynamic reserves of water-producing gas storage facilities.

[0107] Optionally, as another embodiment of the present invention, the present invention will use a particle swarm optimization algorithm to fit the predicted wellhead pressure and the actual production data (i.e., the actual wellhead pressure) to obtain the predicted dynamic reserves of the gas storage facility.

[0108] Particle swarm optimization (PSO) uses massless particles to simulate birds in a flock. These particles have only two attributes: velocity (v) and position (x), where velocity represents speed and position represents direction. The optimal individual value is found as the current global optimum G for the entire particle swarm. best All particles in the swarm are determined based on their current individual extreme value P. best The current global optimal solution G shared by the entire particle swarm best To adjust your speed and position, the specific steps are described below:

[0109] Step 1: Initialize the particle swarm: Set the maximum velocity range to prevent exceeding the maximum range. The position information constitutes the entire search space. We randomly initialize the velocity and position within the velocity range and search space, and set the swarm size.

[0110] Step 2: Individual Extreme Values ​​and Global Optimal Solution: Individual extreme values ​​are the best historical position information found for each particle. A global optimal solution is found from these individual historical optimal solutions and compared with the historical optimal solutions. The best one is selected as the current historical optimal solution.

[0111] Step 3: Update speed and location:

[0112] v id =ω×v id +c1r1(p id -x id )+c2r2(p gd -x id (16)

[0113] x id =x id +v id (17)

[0114] Where ω is the inertia weight, a non-negative number, which adjusts the search range of the solution space; c1 and c2 are acceleration constants, which adjust the maximum learning step size; and r1 and r2 are random numbers in the range [0,1].

[0115] Step 4: Termination condition: Stop if the deviation between two adjacent generations is within a specified range or the maximum number of iterations is reached.

[0116] At this point, the globally optimal particle of the population is the dynamic reserve and production capacity equation coefficient that achieves the best fit between the calculated wellhead pressure and the measured wellhead pressure.

[0117] Optionally, as another embodiment of the present invention, firstly, the water production rate and the cumulative amount of gas injected and produced in the gas storage facility are introduced into the material balance equation to reduce their impact on the prediction of dynamic gas storage capacity. Then, an alternating iterative algorithm is used to solve for formation pressure and deviation factors in the material balance equation to address errors caused by approximate deviation factors. Finally, a particle swarm optimization algorithm is used to fit actual production data to calculate the dynamic gas storage capacity, exhibiting a relatively fast fitting speed.

[0118] Figure 2 This is a block diagram of a gas reservoir storage calculation device provided in an embodiment of the present invention.

[0119] Alternatively, as another embodiment of the present invention, such as Figure 2 As shown, a gas reservoir storage calculation device includes:

[0120] The data acquisition module is used to obtain the initial dynamic reserve value and production capacity equation coefficients, and to import the gas well production data and reservoir parameters of the gas storage facility.

[0121] The pressure analysis module is used to analyze the wellhead pressure using the gas well production data of the gas storage facility, the reservoir parameters, the initial dynamic reserve value, and the production capacity equation coefficients, and to obtain the predicted wellhead pressure.

[0122] The calculation result acquisition module is used to calculate the error value of the wellhead pressure using the predicted wellhead pressure and the gas well production data of the gas storage facility, obtain the target dynamic reserve value based on the calculation result, and use the target dynamic reserve value as the gas reservoir reserve calculation result.

[0123] Optionally, as an embodiment of the present invention, the pressure analysis module is specifically used for:

[0124] The bottom-hole pressure is obtained by calculating the bottom-hole pressure using the gas well production data of the gas storage facility, the reservoir parameters, the initial dynamic reserve value, and the production capacity equation coefficients.

[0125] The predicted wellhead pressure is obtained by calculating the production data of the gas well in the gas storage facility and the wellhead pressure of the bottom hole pressure.

[0126] Optionally, as an embodiment of the present invention, the gas well production data of the gas storage facility includes cumulative water production, cumulative gas injection volume, deviation coefficient under current formation pressure, and daily gas production; the reservoir parameters include the original formation pressure; and the production capacity equation coefficients include the exponential production capacity equation coefficients and the permeability index.

[0127] The pressure analysis module is specifically used for:

[0128] The bottom hole pressure is calculated using the first formula, the cumulative water production, the cumulative gas injection volume, the daily gas production, the original formation pressure, the initial dynamic reserve value, the seepage index, and the coefficients of the exponential productivity equation. The first formula is:

[0129]

[0130] Where, p wf p is the bottom hole pressure. i Z represents the original formation pressure. i Z is the deviation coefficient under preset formation pressure. R G is the deviation coefficient under the current formation pressure. p To accumulate gas production, G in G represents the cumulative gas injection volume, G represents the initial dynamic storage value, and B represents the cumulative gas injection volume. w W is the water volume coefficient. p To accumulate water production, B giq is the gas volume coefficient. g Where C is the daily gas production, n is the coefficient of the exponential capacity equation, and n is the seepage index.

[0131] Optionally, another embodiment of the present invention provides a gas reservoir reserve calculation system, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the gas reservoir reserve calculation method described above. This system can be a computer or similar system.

[0132] Optionally, another embodiment of the present invention provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the gas reservoir reserve calculation method as described above.

[0133] It should be noted that, in this document, relational terms such as "first" and "second" are used only to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus.

[0134] Those skilled in the art will clearly understand that, for the sake of convenience and brevity, the specific working process of the above-described apparatus and unit can be referred to the corresponding process in the foregoing method embodiments, and will not be repeated here.

[0135] In the several embodiments provided in this application, it should be understood that the disclosed apparatus and methods can be implemented in other ways. For example, the apparatus embodiments described above are merely illustrative. For instance, the division of units is only a logical functional division, and in actual implementation, there may be other division methods. For example, multiple units or components may be combined or integrated into another system, or some features may be ignored or not executed.

[0136] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of the embodiments of the present invention, depending on actual needs.

[0137] Furthermore, the functional units in the various embodiments of the present invention can be integrated into one processing unit, or each unit can exist physically separately, or two or more units can be integrated into one unit. The integrated unit can be implemented in hardware or as a software functional unit.

[0138] If the integrated unit is implemented as a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of this invention, in essence, or the part that contributes to the prior art, or all or part of the technical solution, can be embodied in the form of a software product. This computer software product is stored in a storage medium and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute all or part of the steps of the methods of the various embodiments of this invention. The aforementioned storage medium includes various media capable of storing program code, such as USB flash drives, portable hard drives, read-only memory (ROM), random access memory (RAM), magnetic disks, or optical disks.

[0139] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method for calculating gas reservoir reserves, characterized in that, Includes the following steps: S1: Obtain the initial dynamic reserve value and production capacity equation coefficients, and import the gas well production data and reservoir parameters of the gas storage facility; S2: Analyze the wellhead pressure using the gas well production data of the gas storage facility, the reservoir parameters, the initial dynamic reserve value, and the production capacity equation coefficients to obtain the predicted wellhead pressure; The gas well production data of the gas storage facility includes the actual wellhead pressure; S31: Calculate the difference between the predicted wellhead pressure and the actual wellhead pressure to obtain the wellhead pressure error value; S32: Determine whether the wellhead pressure error value is less than the preset error value. If not, proceed to S33. If yes, use the initial dynamic reserve value as the target dynamic reserve value and use the target dynamic reserve value as the gas reservoir reserve calculation result. S33: Update the initial dynamic reserve value and the production capacity equation coefficients according to the wellhead pressure error value, and return to step S1 after updating; The gas well production data of the gas storage facility includes cumulative water production, cumulative gas injection volume, deviation coefficient under current formation pressure, and daily gas production. The reservoir parameters include the original formation pressure. The productivity equation coefficients include the exponential productivity equation coefficients and the permeability index. The bottom hole pressure is obtained by calculating the cumulative water production, cumulative gas injection volume, daily gas production, original formation pressure, initial dynamic reserves, seepage index, and coefficients of the exponential production capacity equation using the first formula: Where, p wf p is the bottom hole pressure. i Z represents the original formation pressure. i Z is the deviation coefficient under preset formation pressure. R G is the deviation coefficient under the current formation pressure. p To accumulate gas production, G in G represents the cumulative gas injection volume, G represents the initial dynamic storage value, and B represents the cumulative gas injection volume. w W is the water volume coefficient. p To accumulate water production, B gi q is the gas volume coefficient. g denoted as daily gas production, C is the coefficient of the exponential capacity equation, and n is the seepage index; The predicted wellhead pressure is obtained by calculating the bottom hole pressure and the daily gas production using the second formula, which is: in, Where, p h To predict wellhead pressure, p wf d is the bottom hole pressure, d is the wellbore inner diameter, and q is the bottom hole pressure. g Daily gas production Let S be the average temperature of the wellbore, S be a dimensionless quantity, and f be the coefficient of friction. r is the average deviation coefficient of the wellbore. g Let H be the relative density of the gas inside the wellbore, H be the length of the wellbore, Re be the Reynolds number, and ε be the roughness of the pipe inside the wellbore.

2. A gas reservoir reserve calculation device, characterized in that, include: The data acquisition module is used to obtain the initial dynamic reserve value and production capacity equation coefficients, and to import the gas well production data and reservoir parameters of the gas storage facility. The pressure analysis module is used to analyze the wellhead pressure using the gas well production data of the gas storage facility, the reservoir parameters, the initial dynamic reserve value, and the production capacity equation coefficients, and to obtain the predicted wellhead pressure. The gas well production data of the gas storage facility includes the actual wellhead pressure; It also includes a calculation result acquisition module, which is specifically used for: S31: Calculate the difference between the predicted wellhead pressure and the actual wellhead pressure to obtain the wellhead pressure error value; S32: Determine whether the wellhead pressure error value is less than the preset error value. If not, proceed to S33. If yes, use the initial dynamic reserve value as the target dynamic reserve value and use the target dynamic reserve value as the gas reservoir reserve calculation result. S33: Update the initial dynamic reserve value and the production capacity equation coefficients according to the wellhead pressure error value, and return to step S1 after updating; The pressure analysis module is specifically used for: The gas well production data of the gas storage facility includes cumulative water production, cumulative gas injection volume, deviation coefficient under current formation pressure, and daily gas production. The reservoir parameters include the original formation pressure. The productivity equation coefficients include the exponential productivity equation coefficients and the permeability index. The bottom hole pressure is obtained by calculating the cumulative water production, cumulative gas injection volume, daily gas production, original formation pressure, initial dynamic reserves, seepage index, and coefficients of the exponential production capacity equation using the first formula: Where, p wf p is the bottom hole pressure. i Z represents the original formation pressure. i Z is the deviation coefficient under preset formation pressure. R G is the deviation coefficient under the current formation pressure. p To accumulate gas production, G in G represents the cumulative gas injection volume, G represents the initial dynamic storage value, and B represents the cumulative gas injection volume. w W is the water volume coefficient. p To accumulate water production, B gi q is the gas volume coefficient. g denoted as daily gas production, C is the coefficient of the exponential capacity equation, and n is the seepage index; The predicted wellhead pressure is obtained by calculating the bottom hole pressure and the daily gas production using the second formula, which is: in, Where, p h To predict wellhead pressure, p wf d is the bottom hole pressure, d is the wellbore inner diameter, and q is the bottom hole pressure. g Daily gas production Let S be the average temperature of the wellbore, S be a dimensionless quantity, and f be the coefficient of friction. r is the average deviation coefficient of the wellbore. g Let H be the relative density of the gas inside the wellbore, H be the length of the wellbore, Re be the Reynolds number, and ε be the roughness of the pipe inside the wellbore.

3. A gas reservoir reserve calculation system, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the gas reservoir reserve calculation method as described in claim 1.

4. A computer-readable storage medium storing a computer program, characterized in that, When the computer program is executed by the processor, the gas reservoir reserve calculation method as described in claim 1 is implemented.

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