A method for determining the injection ratio of a mixture of enhanced oil recovery and carbon sequestration

Abstract

The present invention discloses a method for determining the injection ratio of a mixture for improving recovery and carbon fixation. In order to achieve a win-win situation in deep coalbed methane recovery and coal-based carbon fixation, based on the basic understanding that an increase in the CO2 ratio increases the breakthrough time and reduces the injection capacity, while an increase in the N2 ratio reduces the breakthrough time and improves the injection capacity, a functional relationship R=f(c) between different injection ratios of CO2 and N2 mixtures and normalized recovery and a functional relationship C=f(c) between different injection ratios of CO2 and N2 mixtures and normalized coal-based carbon fixation are established. 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 weighting the recovery and coal-based carbon fixation. The principle of the present invention is simple, fast, reliable, and has strong on-site 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 improving recovery and carbon sequestration. Background Art

[0002] Unconventional natural gas is a dual-attribute energy source. Its recovery rate is typically low due to the low permeability of the reservoir and its high adsorption capacity. Consequently, production enhancement methods such as permeability enhancement and adsorption displacement have attracted widespread attention. Among these, the environmentally friendly and economically viable CO2 / N2 mixture production enhancement technology has strong applicability, overcoming the unfavorable factors such as early breakthrough and sudden drop in injectivity caused by the injection of highly mobile N2 and high-affinity CO2.

[0003] Existing methods for determining the injection ratio of CO2 and N2 mixtures mostly use theoretical analysis, numerical calculation, engineering analogy and other methods. However, their main purpose is to improve the recovery rate and increase the carbon storage capacity from the perspective of single purposes, without considering the synergistic effect of the two, resulting in unnecessary waste of resources. Summary of the Invention

[0004] In response to 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 recovery and carbon sequestration, which can achieve a win-win situation of increased production and carbon sequestration, has a simple principle, is fast and accurate, and has strong applicability and scalability.

[0005] In order to solve the above technical problems, the present invention adopts the following technical solutions:

[0006] The present invention provides a method for determining the injection ratio of a mixture of enhanced recovery and carbon sequestration, comprising the following steps:

[0007] S1. Determine the basic parameters of the coalbed methane reservoir, fluid parameters and production parameters; basic reservoir parameters include pressure, temperature, permeability, porosity, density, thickness, and elastic modulus; fluid parameters include dynamic viscosity, Lagmuir adsorption volume constant, pressure constant, and adsorption expansion coefficient; production parameters include well spacing and gas production rate;

[0008] 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;

[0009] S3. After model verification, the proportion of CO2 in the CO2 and N2 mixture is set to c, where c is 0.0 to 1.0 and the interval is a, with a total of n mixture injection schemes;

[0010] S4. According to the proportion of CO2 in different mixtures, establish n numerical calculation models for gas injection production increase of the mixture, that is, establish a numerical calculation model for gas injection production increase when the proportion of CO2 c is 0.0 to a numerical calculation model for gas injection production increase when the proportion of CO2 c is 0.0+(n)a;

[0011] S5. Determine the corresponding coalbed methane recovery and coal-based carbon sequestration for each of the n experimental factors, obtain the maximum coalbed methane recovery and coal-based carbon sequestration, and normalize the recovery and coal-based carbon sequestration corresponding to different CO2 proportions c, i.e., current recovery / maximum recovery, current coal-based carbon sequestration / maximum coal-based carbon sequestration;

[0012] S6. Based on the normalized values ​​of coalbed methane recovery and coal-based carbon sequestration 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 sequestration C=g(c);

[0013] S7. Draw the graphs of the functions R = f(c) and C = g(c) to determine the optimal ratio interval. The specific method is as follows:

[0014] S7-1. Establish a coordinate system with the mixture concentration c as the horizontal axis and normalize the recovery amount;

[0015] S7-2. Plot R=f(c) and C=g(c) obtained by fitting in step 6 in the coordinate system established in S7-1. Draw the function graph of R=f(c) and C=g(c). The CO2 ratio corresponding to the two maximum values ​​is the optimal ratio range.

[0016] S8. Determine the optimal ratio of CO2 and N2 mixture injection. The specific determination method is as follows:

[0017] 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;

[0018] S8-2. According to the actual working conditions, the coalbed methane recovery and coal-based carbon sequestration weights W1 and W2 are used to determine the mixture ratio, i.e., the maximum value corresponding to C+R=W1*f(c)+W2*g(c) is the optimal mixture ratio c;

[0019] S8-3. After plotting C+R=W1*f(c)+W2*g(c), since the increasing gradient a may be too large, resulting in a poor smoothness or low verifiability 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;

[0020] S8-4. 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 should be determined based on the higher recovery or carbon sequestration amount.

[0021] 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 6000 days.

[0022] Preferably, in step S3, the increasing gradient a of the proportion c of CO2 is 0.1.

[0023] Preferably, in step S3, the total number n of CO2 and N2 mixture injection schemes is ≥10.

[0024] 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.

[0025] 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 larger weights W1 and W2 corresponding to a higher recovery amount or carbon sequestration amount should be determined.

[0026] Preferably, in step 8-3, the incremental gradient is reset to a', and the calculation formula of a' is as follows:

[0027] a'=a-0.01(i-1) In formula (1), i is the number of repetitions of steps S3 to S8.

[0028] The beneficial effects of the present invention are: the present invention aims at the difficult problem of how to achieve 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 the functional relationship R=f(c) between different injection ratios of CO2 and N2 mixtures and the normalized recovery and the 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 weight of the recovery and the coal-based carbon fixation. BRIEF DESCRIPTION OF THE DRAWINGS

[0029] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for use in the embodiments or the description of the prior art. 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 any creative work.

[0030] Figure 1 A flow chart of a method for determining the injection ratio of a mixture of enhanced oil recovery and carbon sequestration provided by the present invention;

[0031] Figure 2 This is a numerical calculation model diagram of conventional / gas injection production enhancement and carbon fixation provided by the present invention;

[0032] Figure 3 This is a verification diagram of the gas production rate model provided by the present invention;

[0033] Figure 4 This is a schematic diagram of the yield increase-carbon sequestration effect provided by the present invention;

[0034] Figure 5 The present invention provides the normalized recovery R=f(c), normalized carbon sequestration C=g(c) function graph and C+R=W1*f(c)+W2*g(c) curve under different CO2 proportions. DETAILED DESCRIPTION

[0035] The following will clearly and completely describe the technical solutions in the embodiments of the present invention in conjunction with the accompanying drawings. 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 making creative efforts are within the scope of protection of the present invention.

[0036] For example, determining the production increase ratio for gas injection in a mixture in a specific area of ​​the Qinshui Basin in Shanxi Province is crucial. The 3# coal seam in the Qinshui Basin boasts stable thickness and high gas content, making it one of China's most valuable coalbed methane development areas and a testing ground for various production enhancement methods. Conventional coalbed methane extraction typically utilizes vertical wells spaced 300 to 500 meters apart. The initial reservoir CH4 pressure, CO2 pressure, N2 pressure, temperature, and permeability are 5.24 MPa, 0.15 MPa, 0.15 MPa, 305.5 K, and 0.68 mD, respectively.

[0037] like Figure 1 As shown, this embodiment provides a method for determining the injection ratio of a mixture of enhanced recovery and carbon sequestration, and the specific steps are:

[0038] Step S1: Determine basic reservoir parameters, fluid parameters, and production parameters through laboratory testing, field observation, and literature review. The basic reservoir parameters are shown in Table 1, and the fluid flow parameters and production parameters are shown in Table 2.

[0039] Table 1 Basic reservoir parameters;

[0040] category Numerical 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 Penetration 0.68 mD elastic modulus 2.2 GPa density 1400 <![CDATA[kg·m -3 ]]>

[0041] Table 2 Fluid flow parameters;

[0042]

[0043]

[0044] 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 validity of the model, see Figure 3 , determine the conventional extraction yield R0 after 6000 days of extraction;

[0045] Step S3: After the rationality of the model is verified, the CO2 / N2 mixture ratio c is set, with the value of c ranging from 0.0 to 1.0 and the interval being 0.1, for a total of 10 CO2 / N2 mixture injection schemes;

[0046] Step S4: Establish 10 numerical calculation models for gas injection production increase based on the proportion of CO2 in different mixtures, i.e., establish a numerical calculation model for gas injection production increase when the proportion of CO2 is 0.0, a numerical calculation model for gas injection production increase when the proportion of CO2 is 1.0, and a numerical calculation model for gas injection production increase when the proportion of CO2 is 0.7. Figure 4 ;

[0047] Step S5: Determine the corresponding coalbed methane recovery and coal-based carbon fixation for the 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.

[0048] Table 3 shows the corresponding recovery amount, coal-based carbon sequestration amount and normalized value for different CO2 proportions in the mixture c;

[0049]

[0050]

[0051] Step S6: Parameter fitting is performed based on the normalized values ​​of coalbed methane recovery and coal-based carbon sequestration under different CO2 ratios to establish a 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 sequestration C = 1.09-0.98 / (c / 0.52) 3.87 The fitting goodness of the two functions are 99.2% and 98.2% respectively.

[0052] Step S7, plotting the function graphs of R=f(c) and C=g(c) to determine the optimal ratio interval;

[0053] Plot the same abscissa and ordinate functions in the same coordinate system, e.g. Figure 5 As shown in the figure, the CO2 ratio corresponding to the two maximum values ​​is the optimal ratio range.

[0054] Step S8, determining the optimal ratio of CO2 and N2 mixture injection;

[0055] The recovery R corresponding to different CO2 ratios c was compared with the conventional extraction recovery R0, and it was determined that the different mixed gas injection schemes were all greater than the conventional extraction;

[0056] According to the actual working conditions, the weights W1 and W2 of coalbed methane recovery and coal-based carbon sequestration are 0.9 and 0.1 respectively; the corresponding values ​​of C+R=W1*f(c)+W2*g(c) are shown in Table 4;

[0057] Table 4

[0058] 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

[0059] 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;

[0060] After the optimal mixture injection concentration determined by the present invention was adopted on-site, the recovery rate and carbon fixation rate were greatly improved, and the participating gas content was 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, and the carbon fixation cost and profit. The role of the potential injection concentration range demonstrates the reliability and scalability of this method.

[0061] Obviously, those skilled in the art may make various changes and modifications to the present invention without departing from the spirit and scope of the present invention. Thus, if such changes and modifications fall within the scope of the claims and their equivalents, the present invention is intended to include such changes and modifications.

Claims

1. A method for determining the injection ratio of a mixture of enhanced recovery and carbon sequestration, characterized in that: The following steps are involved: S1. Determine the basic parameters of the coalbed methane reservoir, fluid parameters and production parameters; basic reservoir parameters include pressure, temperature, permeability, porosity, density, thickness, and elastic modulus; fluid parameters include dynamic viscosity, Lagmuir adsorption volume constant, pressure constant, and adsorption expansion coefficient; 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 model verification, the proportion of CO2 in the CO2 and N2 mixture is set to c, where c is 0.0 to 1.0 and the interval is a, with a total of n mixture injection schemes; S4. According to the proportion of CO2 in different mixtures, establish n numerical calculation models for gas injection production increase of the mixture, that is, establish a numerical calculation model for gas injection production increase when the proportion of CO2 c is 0.0 to a numerical calculation model for gas injection production increase when the proportion of CO2 c is 0.0+(n)a; S5. Determine the corresponding coalbed methane recovery and coal-based carbon sequestration for each of the n experimental factors, obtain the maximum coalbed methane recovery and coal-based carbon sequestration, and normalize the recovery and coal-based carbon sequestration corresponding to different CO2 proportions c, i.e., current recovery / maximum recovery, current coal-based carbon sequestration / maximum coal-based carbon sequestration; S6. Based on the normalized values ​​of coalbed methane recovery and coal-based carbon sequestration 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 sequestration C=g(c); S7. Draw the graphs of the functions 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. Plot R=f(c) and C=g(c) obtained by fitting in step 6 in the coordinate system established in S7-1. Draw the function graph of R=f(c) and C=g(c). The CO2 ratio corresponding to the two maximum values ​​is the optimal ratio range. 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 volume and the coal-based carbon sequestration weights W1 and W2 are used to determine the mixture ratio, i.e., the maximum value corresponding to C+R=W1*f(c)+W2*g(c) is the optimal mixture ratio c; S8-3. After plotting C+R=W1*f(c)+W2*g(c), since the increasing gradient a may be too large, resulting in a poor smoothness or low verifiability 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), the one with the larger weights W1 and W2 corresponding to the higher recovery or carbon sequestration should be determined; In step S3, the CO2 proportion c is increased by a gradient a of 0.1; 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 sequestration should be determined; In step 8-3, reset the incremental gradient to a', and the calculation formula for a' is as follows: a'=a-0.01(i-1) Formula (1) i is the number of repetitions of steps S3 to S8.

2. The method for determining the injection ratio of a mixture of enhanced oil recovery and carbon sequestration according to claim 1, wherein: 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 6000 days.

3. The method for determining the injection ratio of a mixture of enhanced oil recovery and carbon sequestration according to claim 1, wherein: In step S3, the total number n of CO2 and N2 mixture injection schemes is ≥10.

4. The method for determining the injection ratio of a mixture of enhanced oil recovery and carbon sequestration according to claim 1, wherein: 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 reservoir temperature, the model and actual reservoir parameters are consistent, the extraction wells and injection wells are arranged diagonally, the simulation time is 6000 days, and the forced well closure threshold is CH4 gas production rate / N2+CO2 gas production rate = 2.

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