Water-driven gas reservoir CO2 storage amount calculation method based on material balance

Abstract

The invention discloses a water-driven gas reservoir CO2 storage amount calculation method based on material balance. Firstly, single well production dynamic data are processed, invalid data are deleted, and single well production time, daily output, cumulative output and formation pressure are calculated. And then calculating a deviation factor of natural gas in a gas well production process by utilizing a cube and association state equation, drawing a relation curve graph of quasi-comparison pressure and cumulative yield, and calculating dynamic reserves of a gas reservoir by utilizing a regression equation. And calculating the dissolved gas-water ratio of CO2 and the volume coefficient of the fluid by using a cube and association state equation. Different reservoir pressures and methane recovery rates are set, deviation factors, solubility and molar volumes of natural gas and CO2 are calculated by using a cube and association state equation, and finally the storage amount of CO2 under different formation pressures is calculated. The method has the advantages of being high in calculation speed, high in precision, wide in application range and the like, and real gas reservoir CO2 injection geological storage can be better guided.

Description

Technical Field

[0001] The present invention relates to the technical field of CO2 storage in gas reservoirs, and in particular to a method for calculating the CO2 storage capacity in water-driven gas reservoirs based on material balance. Background Art

[0002] CO2 capture, utilization and storage technology is an important technology to reduce carbon emissions and mitigate global warming. Gas reservoirs have good sealing properties and are one of the potential candidate sites for CO2 geological storage. In the process of CO2 injection and storage in water-driven gas reservoirs, it is necessary to accurately calculate the geological reserves of the gas reservoir, water intrusion, CO2 injection volume, and CO2 dissolution, so as to correctly calculate the storage volume of CO2 in the gas reservoir and evaluate the CO2 storage potential of water-driven gas reservoirs.

[0003] Existing numerical simulation methods have the disadvantages of complex calculations, high costs, and long time consumption. In addition, the commonly used gas deviation factor chart has a small scope of application, and the calculation accuracy of the empirical formula for dissolved gas-water ratio is low. Therefore, it is necessary to develop a water-drive gas reservoir material balance equation coupled with a cubic plus associative state equation model with multi-factor synergy, and to construct a calculation method for the geological reserves and CO2 storage capacity of water-drive gas reservoirs. This can achieve rapid and accurate calculation of the geological reserves and CO2 storage capacity of water-drive gas reservoirs, which is crucial for evaluating the geological storage potential of CO2 injection in water-drive gas reservoirs. Summary of the invention

[0004] In view of the above problems, the present invention aims to provide a method for calculating the CO2 storage capacity of water-driven gas reservoirs based on material balance. The method regards the depleted gas reservoir as a closed or open underground container for storing CO2, natural gas and formation water. The fluid in the container complies with the basic principle of material balance during the injection and extraction process, and the flow state of the fluid in the container is not considered. Considering the influence of the elastic expansion of rock and bound water on the material balance, the material balance equation of the gas reservoir is constructed in the form of volume balance, so as to realize the rapid and accurate calculation of the geological reserves and CO2 storage capacity of the water-driven gas reservoir.

[0005] A method for calculating the CO2 storage capacity of a water-flooded gas reservoir based on material balance is as follows:

[0006] Under the initial gas reservoir conditions, the gas reservoir volume is equal to the sum of the original gas volume and the original formation water volume. Under the current gas reservoir conditions, the gas reservoir volume is calculated by the remaining gas volume, the underground volume of injected carbon dioxide, the volume of bound water and rock expansion, the remaining formation water volume, and the volume of carbon dioxide dissolved in water. Assuming that the gas reservoir volume is in equilibrium before and after production, the following expression holds true:

[0007] G0+W0=ΔV1+ΔV2+ΔV3-ΔV4+W (1)

[0008] Where:

[0009] G0 is the original gas volume of the gas reservoir, m 3 ;

[0010] W0 is the original formation water volume of the gas reservoir, m 3 ;

[0011] ΔV1 is the remaining gas volume in the gas reservoir, m 3 ;

[0012] ΔV2 is the volume of bound water and rock expansion in the gas reservoir, m 3 ;

[0013] ΔV3 is the underground volume of carbon dioxide injected into the gas reservoir, m 3 ;

[0014] ΔV4 is the volume of carbon dioxide dissolved in water in the gas reservoir, m 3 ;

[0015] W is the remaining formation water volume in the gas reservoir, m 3 .

[0016] The original gas volume of natural gas in the gas reservoir is calculated using the following formula:

[0017] G0=GB g0 (2)

[0018] Where:

[0019] G is the original geological reserves of natural gas under ground conditions, m 3 ;

[0020] B g0 is the volume coefficient of the original natural gas, m 3 / m 3 .

[0021] The original formation water volume of the gas reservoir is calculated using the following formula:

[0022]

[0023] Where:

[0024] S w0 is the original water saturation of the gas reservoir;

[0025] S g0 is the original gas saturation of the gas reservoir.

[0026] The remaining gas volume in the gas reservoir is calculated using the following formula:

[0027] ΔV1=(GG B -G p )B g (4)

[0028] Where:

[0029] G B is the volume of the trapped gas, m 3 ;

[0030] G p is the volume of produced natural gas, m 3 ;

[0031] B g is the current volume coefficient of natural gas, m 3 / m 3 .

[0032] The bound water and rock expansion volume of gas reservoirs are calculated by the following formula:

[0033]

[0034] Where:

[0035] C f is the compression coefficient of rock, MPa -1 ;

[0036] C w Compression coefficient of bound water, MPa -1 ;

[0037] p0 is the original formation pressure, MPa;

[0038] p is the current formation pressure, MPa.

[0039] The underground volume of carbon dioxide injected into a gas reservoir is calculated as follows:

[0040]

[0041] Where:

[0042] G in is the volume of injected carbon dioxide, m 3 ;

[0043] B gCO2 is the current volume coefficient of carbon dioxide, m 3 / m 3 .

[0044] The volume of carbon dioxide dissolved in water in the gas reservoir is calculated using the following formula:

[0045]

[0046] Where:

[0047] B w is the volume coefficient of the current formation water, m 3 / m 3 ;

[0048] B w0 is the volume coefficient of the original formation water, m 3 / m 3 ;

[0049] W e is the cumulative water intrusion, m 3 ;

[0050] W p is the cumulative water production, m 3 ;

[0051] r CO2 is the dissolved gas-water ratio of CO2 at the current formation pressure.

[0052] The remaining formation water volume of the gas reservoir is expressed as:

[0053] W=W0 B w / B w0 +W e B w -W p B w (8)

[0054] The volume of gas in the gas reservoir can be expressed as a function of the deviation factor through the ideal gas state equation. Through mathematical transformation, the material balance equation considering CO2 injection and water invasion is as follows:

[0055]

[0056] Where:

[0057] Z is the deviation factor of the current natural gas;

[0058] Z0 is the deviation factor of the original natural gas;

[0059] Z CO2 is the deviation factor for carbon dioxide;

[0060] ω is the water intrusion volume coefficient.

[0061] The gas deviation factor is calculated using the cubic additive state equation, which is expressed as follows:

[0062]

[0063] Where:

[0064] b is the common volume parameter, cm 3 / mol;

[0065] R is the universal gas constant, 8.3145 MPa·cm 3 ·mol -1 ·K-1 ;

[0066] T is temperature, K;

[0067] T c is the critical temperature, K;

[0068] a0 and c1 are gravitational parameters.

[0069] To solve the deviation factor, you need to use the continuous iteration method or Newton iteration method. First, assume that the initial value of Z is 0.5, then use the above formula to calculate the new Z value, and repeat the iteration process until Z converges. The deviation factor obtained by solving the cubic plus associating state equation is used to calculate the volume of the fluid. The calculation formula is as follows:

[0070]

[0071] Where:

[0072] v is the molar volume of the fluid, m 3 / mol.

[0073] The dissolved gas-water ratio of CO2 is calculated using the following formula:

[0074]

[0075] Where:

[0076] v CO2 is the molar volume of CO2, m 3 / mol;

[0077] v W is the molar volume of formation water, m 3 / mol;

[0078] x CO2 is the mole fraction of CO2;

[0079] x W is the mole fraction of formation water.

[0080] The molar fractions of liquid CO2 and water are calculated using the mass conservation method:

[0081]

[0082] Where:

[0083] x i is the liquid phase mole fraction of CO2 / H2O;

[0084] z i is the supply mole fraction of CO2 / H2O;

[0085] K iis the equilibrium constant of CO2 / H2O;

[0086] L is the phase fraction of the liquid phase;

[0087] i represents a component.

[0088] The phase fraction of the liquid phase is calculated by solving the following equation using the continuous iteration method or the Newton iteration method:

[0089]

[0090] First, set the initial value of the liquid phase fraction L to 0.5, solve the above equation to obtain the new phase fraction L, and repeat this process until convergence.

[0091] The equilibrium constant is calculated by the fugacity coefficient, which is expressed as follows:

[0092]

[0093] Where:

[0094] is the fugacity coefficient of the liquid phase;

[0095] is the fugacity coefficient of the gas phase.

[0096] The expression of the fugacity coefficient of the cubic additive state equation is as follows:

[0097]

[0098] Where:

[0099] α is the parameter of the mixture gravity term;

[0100] k ij is the mixing rule binary interaction parameter;

[0101] i and j represent components.

[0102] The state equation parameters of the mixture are calculated using the van der Waals fluid mixing rules:

[0103]

[0104] The volume factor is calculated from the molar volume:

[0105]

[0106] Where:

[0107] B is the volume coefficient of the fluid, m 3 / m 3 ;

[0108] v SCis the molar volume of the fluid under ground conditions, m 3 / mol.

[0109] When the gas reservoir is in the production stage, equation (9) is simplified to the following equation:

[0110]

[0111] The intercept and slope of formula (20) are used to calculate the dynamic geological reserves of the gas reservoir.

[0112] According to the single well production dynamic data, a curve of the relationship between the simulated comparative pressure and the cumulative production is drawn to calculate the dynamic reserves of the gas reservoir. According to the cumulative production of methane, the storage capacity of CO2 under different formation pressures is calculated. The specific calculation process is as follows:

[0113] Step 1: Process the single well production dynamic data, delete invalid data, and calculate the single well production time, daily production, cumulative production and formation pressure;

[0114] Step 2: Calculate the deviation factor of natural gas under different formation pressure conditions during the production process of the gas well using the cubic additive state equation (10);

[0115] Step 3: Draw a curve of the relationship between the quasi-comparison pressure and the cumulative production, and use the least squares method to regress the linear relationship, and use the intercept and slope of the regression equation to calculate the dynamic reserves of the gas reservoir;

[0116] Step 4: Calculate the molar volume using the cubic additive state equation, calculate the dissolved gas-water ratio of CO2 using equations (11) to (18), calculate the molar volume of the fluid under ground conditions using the cubic additive state equation, and calculate the volume coefficient of the fluid using equation (19);

[0117] Step 5: Set different reservoir pressures and methane recovery rates, use the cubic-associative equation of state to calculate the deviation factor, solubility and molar volume of natural gas and CO2, and use formula (9) to calculate the storage capacity of CO2 under different formation pressures.

[0118] Beneficial effects:

[0119] Compared with the prior art, the present invention has the following beneficial effects:

[0120] 1. The method for calculating the CO2 storage capacity of water-driven gas reservoirs based on material balance proposed in the present invention has fast calculation speed, high accuracy, wide application range, and is more practical than existing methods.

[0121] 2. The CO2 storage capacity calculation method for water-driven gas reservoirs proposed in the present invention couples the cubic-associative state equation model, realizes the accurate calculation of the physical properties of natural gas, CO2 and formation water, and ensures the validity and practicability of the calculation results.

[0122] 3. The method for calculating the CO2 storage capacity of a water-driven gas reservoir proposed in the present invention takes into account the effects of water invasion and the dissolution of CO2 in formation water, and can more accurately reflect the CO2 storage process of a real gas reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0123] Figure 1 is a calculation flow chart of an embodiment of the present invention;

[0124] Figure 2 is a graph showing the relationship between the deviation factor and the pressure calculated in one embodiment of the present invention;

[0125] Figure 3 is a graph showing the relationship between the simulated comparative pressure and the cumulative production calculated by one embodiment of the present invention;

[0126] Figure 4 is a diagram showing the relationship between the dissolved gas-water ratio and the pressure calculated by one embodiment of the present invention;

[0127] Figure 5 is a relationship diagram between the volume coefficient of formation water and pressure calculated by one embodiment of the present invention;

[0128] Figure 6 is a graph showing the relationship between CO2 injection volume and pressure under different recovery factors calculated by an embodiment of the present invention;

[0129] Figure 7 is a graph showing the relationship between the CO2 injection rate and the pressure under the conditions of water intrusion and non-water intrusion calculated by one embodiment of the present invention;

[0130] Figure 8 This is a graph showing the relationship between the CO2 injection volume and pressure under conditions of presence or absence of dissolution calculated by an embodiment of the present invention. DETAILED DESCRIPTION

[0131] In order to make the purpose, technical solution and advantages of the present invention more clearly understood, the present invention will be further described below in conjunction with the accompanying drawings. It should be understood that the specific embodiments described herein are only used to explain the present invention and are not used to limit the present invention.

[0132] Example:

[0133] Figure 1 A flow chart of a method for calculating the CO2 storage capacity of a water-driven gas reservoir based on material balance provided in an embodiment of the present invention. Figure 1 This embodiment provides a method for calculating the CO2 storage capacity of a water-driven gas reservoir based on material balance, including:

[0134] Step 1: Process the single well production dynamic data and delete invalid data. Calculate the single well production time, daily production, cumulative production and formation pressure;

[0135] Step 2: Use the cubic additive state equation to calculate the deviation factor (Z) of natural gas under different formation pressures (p) during gas well production:

[0136]

[0137] Where:

[0138] Z is the deviation factor of natural gas;

[0139] b is the common volume parameter, cm 3 / mol;

[0140] R is the universal gas constant, 8.3145 MPa·cm 3 ·mol -1 ·K -1 ;

[0141] T is temperature, K;

[0142] T c is the critical temperature, K;

[0143] a0 and c1 are gravitational parameters;

[0144] p is the current formation pressure, MPa.

[0145] The iterative method is used to solve equation (1). Assuming that the initial value of Z is 0.5, the step-by-step iterative method is used to calculate the new Z value. When Z converges, the calculation is stopped. The calculation results of the relationship between the deviation factor and the pressure are as follows: Figure 2 shown.

[0146] Step 3: The measured reservoir temperature is 81°C, the original formation pressure (p0) is 12.16 MPa, the corresponding deviation factor (Z0) is 0.93, and the calculated p0 / Z0 is 13.06. Use the p / Z value calculated in step 2 to calculate p / Z / (p0 / Z0), and draw a relationship curve between p / Z / (p0 / Z0) and cumulative production based on the cumulative production in step 1 (see Figure 3 ), and perform linear regression to obtain the following equation:

[0147]

[0148] Where:

[0149] Z0 is the deviation factor of the original natural gas;

[0150] p0 is the original formation pressure, MPa

[0151] G p is the volume of produced natural gas, m 3 .

[0152] Step 4: Calculate the dynamic geological reserves of a single well using the material balance equation in the production stage. The material balance calculation formula is as follows:

[0153]

[0154] Where:

[0155] G is the original geological reserves of natural gas under ground conditions, m 3 ;

[0156] S w0 is the original water saturation of the gas reservoir;

[0157] S g0 is the original gas saturation of the gas reservoir;

[0158] B w is the volume coefficient of the current formation water, m 3 / m 3 ;

[0159] B w0 is the volume coefficient of the original formation water, m 3 / m 3 ;

[0160] r CO2 is the dissolved gas-water ratio of CO2 at the current formation pressure;

[0161] C f is the compression coefficient of rock, MPa -1 ;

[0162] C w Compression coefficient of bound water, MPa -1 ;

[0163] ω is the water intrusion volume coefficient.

[0164] Step 5: Combining equations (2) and (3), we can calculate ω to be 0 and G to be 9.79:

[0165] ω=0 (4)

[0166]

[0167] Step 6: Calculate the volume of the fluid using the deviation factor calculated from the cubic-associative equation of state:

[0168]

[0169] Where:

[0170] v is the molar volume of the fluid, m 3 / mol.

[0171] Step 7: Calculate the state equation parameters of the mixture using the van der Waals fluid mixing rules:

[0172]

[0173] Where:

[0174] α is the parameter of the mixture gravity term;

[0175] k ij is the mixing rule binary interaction parameter;

[0176] i and j represent components;

[0177] x is the liquid phase mole fraction of the component.

[0178] Step 8: Calculate the fugacity coefficient of the cubic additive associative equation of state:

[0179]

[0180] Where:

[0181] is the fugacity coefficient of the liquid phase.

[0182] Step 9: Calculate the equilibrium constant from the fugacity coefficient:

[0183]

[0184] Where:

[0185] is the fugacity coefficient of the gas phase;

[0186] K i is the equilibrium constant of CO2 / H2O.

[0187] Step 10: The phase fraction of the liquid phase is calculated by solving the following equation using the continuous iteration method or the Newton iteration method:

[0188]

[0189] Where:

[0190] z i is the supply mole fraction of CO2 / H2O;

[0191] L is the phase fraction of the liquid phase.

[0192] The iterative method is used to solve equation (11). First, the initial value of the liquid phase fraction L is set to 0.5, and the new phase fraction L is obtained by solving the above equation. This process is repeated until convergence.

[0193] Step 11: The mole fractions of liquid CO2 and water are calculated using the mass conservation method:

[0194]

[0195] Step 12: The dissolved gas-water ratio of CO2 is calculated using the following formula:

[0196]

[0197] Where:

[0198] v CO2 is the molar volume of CO2, m 3 / mol;

[0199] v W is the molar volume of formation water, m 3 / mol;

[0200] x CO2 is the mole fraction of CO2;

[0201] x W is the mole fraction of formation water.

[0202] Step 13: Calculate the volume coefficient of the fluid from the molar volume:

[0203]

[0204] Where:

[0205] B is the volume coefficient of the fluid, m 3 / m 3 ;

[0206] v SC is the molar volume of the fluid under ground conditions, m 3 / mol.

[0207] Step 14: Use the material balance equation to calculate the relationship between CO2 injection volume and formation pressure:

[0208]

[0209] Where:

[0210] G in is the volume of injected carbon dioxide, m 3 ;

[0211] Z CO2 is the deviation factor for carbon dioxide.

[0212] According to the method for calculating the CO2 storage capacity of water-driven gas reservoirs based on material balance, when the temperature is 81°C and the original formation pressure is 12.16 MPa, the calculated natural gas deviation factor and pressure are as follows: Figure 2 As shown, the relationship curve between p / Z / (p0 / Z0) and cumulative production is as follows Figure 3 As shown in the figure, the original geological reserves G were calculated to be 979 million cubic meters using the material balance equation.

[0213] The cubic additive state equation is used to calculate the deviation factors and molar volumes of CO2, CH4 and H2O at different pressures and the solubility of CO2 in the liquid phase. According to the method for calculating the CO2 storage capacity of water-flooded gas reservoirs based on material balance, the relationship between the dissolved gas-water ratio of CO2 and pressure is calculated as follows: Figure 4 As shown in the figure, the relationship between the volume coefficient of formation water and pressure is as follows Figure 5 shown.

[0214] Recovery factor is defined as cumulative production divided by geological reserves (G p / G). By setting different recovery factors to 30%, 50%, 70% and 90%, and under the condition of formation pressure of 3-50MPa, the relationship between CO2 injection volume and formation pressure is calculated as follows: Figure 6 As shown in Figure 2, as the formation pressure rises, the CO2 injection volume first increases rapidly and then slowly. As the recovery rate increases, the CO2 injection volume increases, mainly because the recovery rate is high and the storage volume of the reservoir increases. The recovery rate of the reservoir is set to 90%, and the relationship between the CO2 injection volume and the formation pressure under the conditions of considering water invasion and not considering water invasion is calculated as shown in Figure 2. Figure 7 As shown in Figure 2, as the pressure increases, the water invasion degree decreases, and more CO2 can be stored under the condition of water invasion. The relationship between the CO2 injection rate and the formation pressure under the conditions of considering CO2 dissolution and not considering CO2 dissolution is calculated respectively. Figure 8 As shown in the figure, the CO2 storage capacity is higher when CO2 is dissolved in formation water. Therefore, when calculating the CO2 storage capacity of water-driven gas reservoirs, it is necessary to consider the effects of gas reservoir recovery, water invasion and CO2 dissolution at the same time to accurately calculate the CO2 storage capacity of water-driven gas reservoirs.

[0215] In summary, the present invention provides a method for calculating the CO2 storage capacity of a water-driven gas reservoir based on material balance. First, the single well production dynamic data is processed, and invalid data is deleted, and the single well production time, daily production, cumulative production and formation pressure are calculated. Then, the cubic plus associated state equation is used to calculate the deviation factor of natural gas under different formation pressure conditions during the gas well production process, and a curve diagram of the relationship between the simulated pressure and the cumulative production is drawn. The linear relationship is regressed using the least squares method, and the dynamic reserves of the gas reservoir are calculated using the intercept and slope of the regression equation. The molar volume of the reservoir fluid and the dissolved gas-water ratio of CO2 are calculated using the cubic plus associated state equation, and the molar volume of the fluid under ground conditions is calculated using the cubic plus associated state equation, thereby calculating the volume coefficient of the fluid. Different reservoir pressures and methane recovery rates are set, and the deviation factors, solubility and molar volumes of natural gas and CO2 are calculated using the cubic plus associated state equation, and finally the CO2 storage capacity under different formation pressures is calculated. The proposed method for calculating the CO2 storage capacity of water-driven gas reservoirs based on material balance has the characteristics of fast calculation speed, high accuracy and wide application range, and can better guide the geological storage of CO2 injected into real gas reservoirs.

[0216] The above description does not limit the present invention in any form. Although the present invention discloses the effect of the implementation of the method as described in the above embodiment, the embodiment is not used to limit the present invention. Any technician familiar with the profession can make some changes or modify the above disclosed technical contents into equivalent embodiments without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments according to the technical essence of the present invention without departing from the content of the technical solution of the present invention are within the scope of the technical solution of the present invention.

Claims

1. A method for calculating the CO2 storage capacity of a water-flooded gas reservoir based on material balance, characterized in that: include: Process the single well production dynamic data and delete invalid data, calculate the single well production time, daily production, cumulative production and formation pressure, and use the cubic plus associative state equation to calculate the deviation factor of natural gas under different formation pressure conditions during the gas well production process; Draw a curve of the relationship between the quasi-comparison pressure and the cumulative production, and use the least squares method to regress the linear relationship, and use the intercept and slope of the regression equation to calculate the dynamic reserves of the gas reservoir; The cubic additive state equation is used to calculate the deviation factors and molar volumes of CO2, CH4 and H2O at different pressures and the solubility of CO2 in the liquid phase, and the dissolved gas-water ratio of CO2 and the volume coefficient of formation water are calculated. Different reservoir pressures and methane recovery rates were set, and the material balance equation was used to calculate the storage capacity of CO2 under different formation pressures.

2. A method for calculating CO2 storage capacity in a water-flooded gas reservoir based on material balance as claimed in claim 1, characterized in that: Process the single well production dynamic data, delete invalid data, calculate the single well production time, daily production, cumulative production and formation pressure, and use the cubic plus associative state equation to calculate the deviation factor of natural gas under different formation pressure conditions during the gas well production process: Where: Z is the deviation factor of natural gas; b is the common volume parameter, cm 3 / mol; R is the universal gas constant, 8.3145 MPa·cm 3 ·mol -1 ·K -1 ; T is temperature, K; T c is the critical temperature, K; a0 and c1 are gravitational parameters; p is the current formation pressure, MPa.

3. A method for calculating CO2 storage capacity in a water-flooded gas reservoir based on material balance as claimed in claim 1, characterized in that: Draw a curve of the relationship between the quasi-comparison pressure and the cumulative production, and use the least squares method to regress the linear relationship. Use the intercept and slope of the regression equation to calculate the dynamic reserves of the gas reservoir: Where: Z0 is the deviation factor of the original natural gas; p0 is the original formation pressure, MPa; G p is the volume of produced natural gas, m 3 ; G is the original geological reserves of natural gas under ground conditions, m 3 ; S w0 is the original water saturation of the gas reservoir; S g0 is the original gas saturation of the gas reservoir; B w is the volume coefficient of the current formation water, m 3 / m 3 ; B w0 is the volume coefficient of the original formation water, m 3 / m 3 ; r CO2 is the dissolved gas-water ratio of CO2 at the current formation pressure; C f is the compression coefficient of rock, MPa -1 ; C w Compression coefficient of bound water, MPa -1 ; ω is the water intrusion volume coefficient.

4. A method for calculating CO2 storage capacity in a water-flooded gas reservoir based on material balance as claimed in claim 1, characterized in that: The cubic additive state equation is used to calculate the deviation factors and molar volumes of CO2, CH4 and H2O at different pressures and the solubility of CO2 in the liquid phase, and the dissolved gas-water ratio of CO2 and the volume coefficient of formation water are calculated, including the following steps: The volume of the fluid is calculated using the deviation factor calculated from the cubic additive associative equation of state: Where: v is the molar volume of the fluid, m 3 / mol; The state equation parameters of the mixture are calculated using the van der Waals fluid mixing rules: Where: α is the parameter of the mixture gravity term; k ij is the mixing rule binary interaction parameter; i and j represent components; x is the liquid phase mole fraction of the component; Calculate the fugacity coefficient for the cubic additively associated equation of state: Where: is the fugacity coefficient of the liquid phase; Calculate the equilibrium constant from the fugacity coefficient: Where: is the fugacity coefficient of the gas phase; K i is the equilibrium constant of CO2 / H2O; The phase fraction of the liquid phase is calculated by solving the following equation using the continuous iteration method or the Newton iteration method: Where: z i is the supply mole fraction of CO2 / H2O; L is the phase fraction of the liquid phase; The molar fractions of liquid CO2 and water are calculated using the mass conservation method: The dissolved gas-water ratio of CO2 is calculated using the following formula: Where: v CO2 is the molar volume of CO2, m 3 / mol; v W is the molar volume of formation water, m 3 / mol; x CO2 is the mole fraction of CO2; x W is the mole fraction of formation water; Calculate the volume coefficient of a fluid from its molar volume: Where: B is the volume coefficient of the fluid, m 3 / m 3 ; v SC is the molar volume of the fluid under ground conditions, m 3 / mol.

5. The method for calculating the CO2 storage capacity of a water-flooded gas reservoir based on material balance as claimed in claim 1, characterized in that: Set different reservoir pressures and methane recovery rates, and use the material balance equation to calculate the storage capacity of CO2 under different formation pressures: Where: G in is the volume of injected carbon dioxide, m 3 ; Z CO2 is the deviation factor for carbon dioxide.

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