Mixture injection proportion determination method for increasing recovery amount and carbon sequestration amount

Abstract

The invention discloses a mixture injection proportion determination method for improving recovery amount and carbon sequestration amount, and aims to solve the win-win problem of the recovery amount and the coal-based carbon sequestration amount of deep coal bed gas based on the basic cognition that the breakthrough time is prolonged by increasing the proportion of CO2, the injection capacity is reduced, the breakthrough time is shortened by increasing the proportion of N2, and the injection capacity is improved. The method comprises the following steps: establishing a function relationship R = f (c) between different injection proportions of a CO2 and N2 mixture and a normalized recovery amount and different injection proportions of the CO2 and N2 mixture and a normalized coal-based carbon sequestration amount C = f (c), determining an optimal CO2 and N2 mixture proportion interval according to a maximum recovery amount and a maximum coal-based carbon sequestration amount, and further determining an optimal CO2 and N2 mixture proportion according to the weight of the recovery amount and the weight of the coal-based carbon sequestration amount. The method is simple in principle, rapid, reliable and high in field applicability.

Description

Technical Field

[0001] The present invention relates to the technical field of development and utilization of mineral resources and greenhouse gas emission reduction, and in particular to a method for determining the injection ratio of a mixture for increasing recovery and carbon fixation. Background Art

[0002] Unconventional natural gas is an unconventional energy with dual properties. The recovery rate is usually low due to the low permeability of the reservoir and its own high adsorption. Therefore, permeability enhancement, adsorption replacement and other production increase methods have received extensive attention. Among them, the CO2 and N2 mixture production increase technology, which is environmentally friendly and economically feasible, has strong applicability and can overcome the unfavorable factors such as early breakthrough and sudden drop in injection capacity caused by the injection of high-mobility N2 and high-affinity CO2.

[0003] my country has huge reserves of deep unconventional natural gas geological resources (the reserves at burial depths of 1000-1500m and 1500-2000m are 1.06×1013m 3 、1.19×1013m 3 , together they account for 61.4% of the total resources). However, my country's deep coal seams have significant "three highs and two lows" characteristics, which seriously restricts the exploration, development and utilization of coalbed methane. Large CO2 emission sources such as coal-fired power plants and coal chemical plants are mostly located near the main coal production areas. Sealing nearby can significantly reduce transportation costs, increase the recovery rate of coal seam CH4, ensure stable storage of coal seam CO2, and achieve a win-win situation of increasing production and fixing carbon.

[0004] Existing methods for determining the injection ratio of CO2 and N2 mixtures mostly use theoretical analysis, numerical calculation, engineering analogy and other methods, but their main purpose is to improve the recovery rate, increase carbon storage and other single purposes, without considering the synergistic effect of the two, resulting in unnecessary waste of resources. Summary of the invention

[0005] In view of the above-mentioned technical deficiencies, the purpose of the present invention is to provide a method for determining the injection ratio of a mixture to increase the recovery and carbon fixation amount, which can achieve a win-win situation of increased production and carbon fixation, has a simple principle, is fast and accurate, and has strong applicability and scalability.

[0006] In order to solve the above technical problems, the present invention adopts the following technical solutions:

[0007] The present invention provides a method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation, comprising the following steps:

[0008] S1. Determine the basic parameters of coalbed methane reservoir, fluid parameters and production parameters; the basic parameters of reservoir include pressure, temperature, permeability, porosity, density, thickness, elastic modulus; the fluid parameters include dynamic viscosity, Lagmuir adsorption volume constant, pressure constant, adsorption expansion coefficient; the production parameters include well spacing and gas production rate;

[0009] S2. Establish a conventional extraction numerical model based on actual working conditions, compare it with the field measured gas production data to verify the effectiveness of the model, and determine the conventional extraction recovery R0 after N days of production;

[0010] S3. After the model is verified, the proportion of CO2 in the CO2 / N2 mixture is set to c, where c is 0.0 to 1.0, with an interval of a, and a total of n mixture injection schemes;

[0011] S4. According to the proportion of CO2 in different mixtures, n numerical calculation models for increasing production by gas injection of the mixture are established, that is, a numerical calculation model for increasing production by gas injection when the proportion of CO2 is c 0.0 is established to a numerical calculation model for increasing production by gas injection when the proportion of CO2 is c 0.0+(n)a;

[0012] S5. Determine the corresponding coalbed methane recovery and coal-based carbon fixation for n experimental factors, obtain the maximum coalbed methane recovery and coal-based carbon fixation, and normalize the recovery and coal-based carbon fixation corresponding to different CO2 proportions c, i.e., current recovery / maximum recovery, current coal-based carbon fixation / maximum coal-based carbon fixation;

[0013] S6. According to the normalized values ​​of coalbed methane recovery and coal-based carbon fixation under the proportion of CO2 in the mixture, parameter fitting is performed to establish the functional relationship between the proportion of CO2 in the mixture and the normalized recovery R=f(c) and the proportion of CO2 in the mixture and the normalized coal-based carbon fixation C=g(c);

[0014] S7. Draw the function graphs of R=f(c) and C=g(c) to determine the optimal ratio interval. The specific method is as follows:

[0015] S7-1. Establish a coordinate system, taking the mixture concentration c as the horizontal coordinate, and normalize the recovery amount;

[0016] S7-2, plotting R=f(c) and C=g(c) obtained by fitting in step 6 in the coordinate system established in S7-1, and plotting the function graphs of R=f(c) and C=g(c). The CO2 ratios corresponding to the two maximum values ​​are the optimal ratio intervals;

[0017] S8. Determine the optimal ratio of CO2 and N2 mixture injection. The specific determination method is as follows:

[0018] S8-1. Compare the recovery volume R corresponding to different CO2 proportions c with the conventional extraction recovery volume R0 to screen the potential CO2 proportion c;

[0019] S8-2. According to the actual working conditions, the coalbed methane recovery and coal-based carbon fixation weights W1 and W2 are used to determine the mixture ratio, that is, the maximum value corresponding to C+R=W1*f(c)+W2*g(c) is the optimal mixture ratio c;

[0020] S8-3, after drawing C+R=W1*f(c)+W2*g(c), since the increasing gradient a may be too large, resulting in low smoothness or low confirmability of the curve, it is necessary to further reset the increasing gradient to a', and repeat steps S3 to S8 until the maximum value is easily determined to be the optimal mixture ratio c;

[0021] S8-4. When there are multiple optimal mixture ratios c corresponding to the maximum value of C+R=W1*f(c)+W2*g(c), they should be determined based on the higher recovery or carbon fixation corresponding to the larger weights W1 and W2.

[0022] Preferably, in step S2, the error rate between the simulated recovery rate and the actual recovery rate should be less than 10%, and the number of extraction days N is 6000d.

[0023] Preferably, in step S3, the increasing gradient a of the proportion c of CO2 is 0.1.

[0024] Preferably, in step S3, the total number n of CO2 and N2 mixture injection schemes is ≥10.

[0025] Preferably, in step S5, the injection pressure of the CO2 and N2 mixture in the numerical simulation scheme is not less than 2.5 times the reservoir pressure, the injection temperature is the initial temperature of the reservoir, the model and actual reservoir parameters are consistent, the extraction wells and injection wells are arranged diagonally, the simulation time is 6000d, and the forced well closure threshold is CH4 gas production rate / N2+CO2 gas production rate = 2.

[0026] Preferably, in step S8, when there are multiple optimal mixture ratios c corresponding to the maximum value of C+R=W1*f(c)+W2*g(c), the one with the larger weights W1 and W2 corresponding to the higher recovery or carbon fixation should be determined.

[0027] Preferably, in step 8-3, the incremental gradient is reset to a', and the calculation formula of a' is as follows:

[0028] a'=a-0.01(i-1) Formula (1)

[0029] i is the number of repetitions of steps S3 to S8.

[0030] The beneficial effects of the present invention are as follows: the present invention aims at achieving a win-win situation of deep coalbed methane recovery and coal-based carbon fixation, based on the basic understanding that increasing the CO2 ratio increases the breakthrough time and reduces the injection capacity, while increasing the N2 ratio reduces the breakthrough time and improves the injection capacity. By establishing a functional relationship R=f(c) between different injection ratios of CO2 and N2 mixtures and the normalized recovery, and different injection ratios of CO2 and N2 mixtures and the normalized coal-based carbon fixation C=f(c), the optimal CO2 and N2 mixture ratio range is determined according to the maximum recovery and the maximum coal-based carbon fixation, and the optimal CO2 and N2 mixture ratio is further determined by the weights of the recovery and the coal-based carbon fixation. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0032] Figure 1 A flow chart of a method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation provided by the present invention;

[0033] Figure 2 A numerical calculation model diagram of conventional / gas injection production enhancement and carbon fixation provided by the present invention;

[0034] Figure 3 A verification diagram of the gas production rate model provided by the present invention;

[0035] Figure 4 A schematic diagram of the production increase-carbon fixation effect provided by the present invention;

[0036] Figure 5 The invention provides the normalized recovery R=f(c), normalized carbon fixation C=g(c) function graph and C+R=W1*f(c)+W2*g(c) curve under different CO2 proportions. DETAILED DESCRIPTION

[0037] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0038] Taking the determination of the gas injection production increase ratio of a certain area in the Qinshui Basin of Shanxi Province as an example, the thickness of the 3# coal seam in the Qinshui Basin is stable and the gas content is high. It is one of the most valuable coalbed methane development areas in China and also a test site for various production increase methods. Ordinary coalbed methane extraction generally uses vertical gas wells with a spacing of 300 to 500m. The initial CH4 pressure, CO2 pressure, N2 pressure, temperature and permeability of the reservoir are 5.24MPa, 0.15MPa, 0.15MPa, 305.5K, and 0.68mD, respectively.

[0039] like Figure 1 As shown, this embodiment provides a method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation, and the specific steps are:

[0040] Step S1, determining basic reservoir parameters, fluid parameters and production parameters through laboratory testing, field observation, literature review, etc.: the basic reservoir parameters are shown in Table 1, and the fluid flow parameters and production parameters are shown in Table 2;

[0041] Table 1 Basic reservoir parameters;

[0042] category Numeric unit <![CDATA[Initial CH4 pressure]]> 5.24 MPa <![CDATA[Initial CO2 pressure]]> 0.15 MPa <![CDATA[Initial N2 pressure]]> 0.15 MPa temperature 305.5 K Permeability 0.68 mD Elastic modulus 2.2 GPa density 1400 <![CDATA[kg·m -3 ]]>

[0043] Table 2 Fluid flow parameters;

[0044]

[0045]

[0046] Step S2: Establish a conventional extraction numerical model based on actual working conditions, see Figure 2 , and compared with the field measured gas production data to verify the effectiveness of the model, see Figure 3 , determine the conventional extraction yield R0 after 6000 days of extraction;

[0047] Step S3: After the rationality of the model is verified, the CO2 / N2 mixture ratio c is set, where c is 0.0-1.0 with an interval of 0.1, and a total of 10 CO2 / N2 mixture injection schemes are set;

[0048] Step S4, according to the proportion of CO2 in different mixtures, 10 gas injection production increase numerical calculation models are established, that is, a gas injection production increase numerical calculation model with a CO2 proportion c of 0.0 is established... A gas injection production increase numerical calculation model with a CO2 proportion c of 1.0 is established, and a gas injection production increase numerical calculation model with a CO2 proportion c of 0.7 is established. Figure 4 ;

[0049] Step S5, determine the corresponding coalbed methane recovery and coal-based carbon fixation for 10 experimental factors (different concentrations), obtain the maximum coalbed methane recovery and coal-based carbon fixation, and normalize the recovery and coal-based carbon fixation corresponding to different CO2 proportions c in the mixture, i.e., current recovery / maximum recovery, current coal-based carbon fixation / maximum coal-based carbon fixation.

[0050] Table 3 shows the corresponding recovery, coal-based carbon fixation and normalized value for different CO2 proportions in the mixture c;

[0051]

[0052] Step S6: According to the normalized values ​​of coalbed methane recovery and coal-based carbon fixation under different CO2 ratios, parameter fitting is performed to establish the functional relationship between different injection ratios of CO2 and N2 mixtures and normalized recovery (R=0.53+1.52c-1.54c) 2 +0.39c 3 Different injection ratios of CO2 and N2 mixtures and normalized coal-based carbon fixation C = 1.09-0.98 / (c / 0.52) 3.87 The fitting goodness of the two functions are 99.2 and 98.2% respectively.

[0053] Step S7, draw the function graphs of R=f(c), C=g(c) to determine the optimal ratio interval;

[0054] Plot the same abscissa and ordinate plotting function in the same coordinate system, e.g. Figure 5 As shown, the CO2 ratio corresponding to the two maximum values ​​is the optimal ratio range.

[0055] Step S8, determining the optimal ratio of CO2 and N2 mixture injection;

[0056] The recovery R corresponding to different CO2 ratios c is compared with the conventional extraction recovery R0, and it is determined that different mixed gas injection schemes are all greater than conventional extraction;

[0057] According to the actual working conditions, the weights W1 and W2 of coalbed methane recovery and coal-based carbon fixation are 0.9 and 0.1 respectively; the corresponding values ​​of C+R=W1*f(c)+W2*g(c) are shown in Table 4;

[0058] Table 4

[0059] c 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 C+R 0.481 0.635 0.706 0.781 0.856 0.953 0.955 0.959 0.948 0.932 0.909

[0060] Draw the C+R=W1*f(c)+W2*g(c) curve with concentration c as the horizontal axis, such as Figure 5 , the optimal injection concentration was determined to be 0.70;

[0061] After the optimal mixture injection concentration determined by the present invention is adopted on-site, the recovery rate and carbon fixation rate are greatly improved, and the participating gas content is greatly reduced, achieving a win-win situation of increased production and carbon fixation. At the same time, the optimal mixture injection concentration can be adjusted on-site according to the gas production cost and profit, carbon fixation cost and profit. The role of the potential injection concentration range shows the reliability and scalability of this method.

[0062] Obviously, those skilled in the art can make various changes and modifications to the present invention without departing from the spirit and scope of the present invention. Thus, if these modifications and variations of the present invention fall within the scope of the claims of the present invention and their equivalents, the present invention is also intended to include these modifications and variations.

Claims

1. A method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation, characterized in that: The following steps are involved: S1. Determine the basic parameters of coalbed methane reservoir, fluid parameters and production parameters; the basic parameters of reservoir include pressure, temperature, permeability, porosity, density, thickness, elastic modulus; the fluid parameters include dynamic viscosity, Lagmuir adsorption volume constant, pressure constant, adsorption expansion coefficient; the production parameters include well spacing and gas production rate; S2. Establish a conventional extraction numerical model based on actual working conditions, compare it with the field measured gas production data to verify the effectiveness of the model, and determine the conventional extraction recovery R0 after N days of production; S3. After the model is verified, the proportion of CO2 in the CO2 / N2 mixture is set to c, where c is 0.0 to 1.0, with an interval of a, and a total of n mixture injection schemes; S4. According to the proportion of CO2 in different mixtures, n numerical calculation models for increasing production by gas injection of the mixture are established, that is, a numerical calculation model for increasing production by gas injection when the proportion of CO2 is c 0.0 is established to a numerical calculation model for increasing production by gas injection when the proportion of CO2 is c 0.0+(n)a; S5. Determine the corresponding coalbed methane recovery and coal-based carbon fixation for n experimental factors, obtain the maximum coalbed methane recovery and coal-based carbon fixation, and normalize the recovery and coal-based carbon fixation corresponding to different CO2 proportions c, i.e., current recovery / maximum recovery, current coal-based carbon fixation / maximum coal-based carbon fixation; S6. According to the normalized values ​​of coalbed methane recovery and coal-based carbon fixation under the proportion of CO2 in the mixture, parameter fitting is performed to establish the functional relationship between the proportion of CO2 in the mixture and the normalized recovery R=f(c) and the proportion of CO2 in the mixture and the normalized coal-based carbon fixation C=g(c); S7. Draw the function graphs of R=f(c) and C=g(c) to determine the optimal ratio interval. The specific method is as follows: S7-1, establish a coordinate system; S7-2, plotting R=f(c) and C=g(c) obtained by fitting in step 6 in the coordinate system established in S7-1, and plotting the function graphs of R=f(c) and C=g(c). The CO2 ratios corresponding to the two maximum values ​​are the optimal ratio intervals; S8. Determine the optimal ratio of CO2 and N2 mixture injection. The specific determination method is as follows: S8-1. Compare the recovery volume R corresponding to different CO2 proportions c with the conventional extraction recovery volume R0 to screen the potential CO2 proportion c; S8-2. According to the actual working conditions, the coalbed methane recovery and coal-based carbon fixation weights W1 and W2 are used to determine the mixture ratio, that is, the maximum value corresponding to C+R=W1*f(c)+W2*g(c) is the optimal mixture ratio c; S8-3, after drawing C+R=W1*f(c)+W2*g(c), since the increasing gradient a may be too large, resulting in low smoothness or low confirmability of the curve, it is necessary to further reset the increasing gradient to a', and repeat steps S3 to S8 until the maximum value is determined to be the optimal mixture ratio c; S8-4. When there are multiple optimal mixture ratios c corresponding to the maximum value of C+R=W1*f(c)+W2*g(c), they should be determined based on the higher recovery or carbon fixation corresponding to the larger weights W1 and W2.

2. The method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation according to claim 1, characterized in that: In step S2, the error rate between the simulated recovery rate and the actual recovery rate should be less than 10%, and the number of extraction days N is 6000d.

3. The method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation as claimed in claim 1, characterized in that: In step S3, the CO2 proportion c has an increasing gradient a of 0.

1.

4. The method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation as claimed in claim 1, characterized in that: In step S3, the total number of CO2 and N2 mixture injection schemes n≥10.

5. The method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation as claimed in claim 1, characterized in that: In step S5, in the numerical simulation scheme, the injection pressure of the CO2 and N2 mixture is not less than 2.5 times the reservoir pressure, the injection temperature is the initial temperature of the reservoir, the model and the actual reservoir parameters are consistent, the extraction wells and injection wells are arranged diagonally, the simulation time is 6000d, and the forced well closure threshold is CH4 gas production rate / N2+CO2 gas production rate = 2.

6. The method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation as claimed in claim 1, characterized in that: In step S8, when there are multiple optimal mixture ratios c corresponding to the maximum value of C+R=W1*f(c)+W2*g(c), the one with the larger weights W1 and W2 corresponding to the higher recovery or carbon fixation should be determined.

7. The method for determining the injection ratio of a mixture of enhanced recovery and carbon fixation as claimed in claim 1, characterized in that: In step 8-3, reset the incremental gradient to a', and the calculation formula of a' is as follows: a'=a-0.01(i-1) Formula (1) i is the number of repetitions of steps S3 to S8.

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