Evaluation method and system for injection capacity of cut-off control type saline water layer CO2 storage site

Abstract

The invention belongs to the technical field of carbon dioxide sequestration, and relates to a method and a system for evaluating the injection capacity of a CO2 sequestration site of a breaking control type saline water layer, and the method comprises the following steps: obtaining well test analysis data of an adjacent oil field; according to well testing analysis data, obtaining a skin coefficient-free oil production index; establishing a calculation formula of the skin-coefficient-free oil production index and the oil drainage radius, and determining a coefficient a of the calculation formula; according to the coefficient a, obtaining a calculation formula of a CO2 injection index, and inputting well testing analysis data into the calculation formula of the CO2 injection index to obtain the CO2 injection index; and determining the maximum allowable injection pressure difference, and calculating the injection capacity of the target CO2 sequestration layer according to the CO2 injection index and the maximum allowable injection pressure difference. The problem that the reliable injection capacity cannot be obtained due to the fact that the CO2 injection test is not carried out on the target storage site can be solved to a certain degree, and the CO2 injection scheme design is effectively supported.

Description

Technical Field

[0001] The present invention relates to a method and system for evaluating the injection capacity of a fault-controlled saline layer CO2 storage site, belonging to the technical field of carbon dioxide storage. Background Art

[0002] CO2 geological storage is one of the key technologies to achieve net-zero emissions. In recent years, the number of geological storage projects implemented in depleted oil and gas reservoirs and saline aquifers has increased both domestically and internationally. Among them, saline aquifers are considered ideal storage targets for large-scale carbon capture and storage (CCS) projects due to their widespread distribution, huge storage potential, and the potential for high-rate injection from a single well. These aquifers can meet the demand for rapid storage of large quantities of CO2 in a short period of time. Therefore, accurately assessing reservoir injection capacity and determining safe injection rates for individual wells, based on risk control, are crucial for designing efficient and economical injection schemes for saline aquifer CCS projects.

[0003] CO2 injectivity refers to the efficiency of injecting CO2 into a reservoir through a wellbore. It is typically defined as the injection rate at the maximum allowable injection pressure differential. This maximum pressure differential is typically the difference between the reservoir pressure and the caprock fracture pressure. The core evaluation metric is the injectivity index, which is the ratio of the injection rate to the difference between the bottomhole pressure and the reservoir pressure. Currently, the main methods for evaluating CO2 injectivity include analogy, the injectivity index method, and numerical simulation.

[0004] Analogy: This method evaluates target sites by analyzing the relationship between reservoir parameters (such as thickness and permeability) and single-well injection rates from existing CCS projects. However, this method lacks integration with actual test data from the target site and does not consider the maximum allowable injection pressure difference, limiting its applicability.

[0005] Injection index method: Usually requires actual injection test data at the target site. However, such test data is often lacking in the early design stage of a project.

[0006] Numerical simulation relies on reliable geological models and requires high levels of expertise and software proficiency. Its simulation results often reflect theoretical maximum annual injection rates and are difficult to directly guide the design of actual injection plans. Summary of the Invention

[0007] In response to the above problems, the purpose of the present invention is to provide a method and system for evaluating the injection capacity of a fault-controlled saline CO2 storage site, which can solve the problem that the target storage site cannot obtain a more reliable injection capacity due to the lack of CO2 injection testing, and effectively support the design of CO2 injection schemes.

[0008] To achieve the above-mentioned objectives, the present invention proposes the following technical solutions: a method for evaluating the injection capacity of a fault-controlled saline CO2 storage site, comprising the following steps: obtaining well test analysis data of an adjacent oil field; obtaining a skin-free coefficient oil production index based on the well test analysis data; establishing a calculation formula for the skin-free coefficient oil production index and the oil drainage radius, and determining the coefficient a of the calculation formula; obtaining a calculation formula for the CO2 injection index based on the coefficient a, and inputting the well test analysis data into the calculation formula for the CO2 injection index to obtain the CO2 injection index; determining a maximum allowable injection pressure difference, and calculating the injection capacity of the target CO2 storage layer based on the CO2 injection index and the maximum allowable injection pressure difference.

[0009] Furthermore, the well test analysis data and the target CO2 storage layer belong to the same formation of oil layer well test analysis data, including: oil layer permeability K o , effective thickness of oil layer h o , crude oil viscosity μ o , skin coefficient S, wellbore radius r w , oil leakage radius r e and oil recovery index P i_real .

[0010] Furthermore, the skin-free oil production index is obtained by i_real The calculation formula of the oil recovery index without skin coefficient is obtained by correction:

[0011] Pi _real-m =P i_real *((lnr e / r w -0.75+S) / (lnr e / r w -0.75))

[0012] Among them, Pi _real-m is the skin-free oil recovery index, P i_real It is the oil production index obtained from the well test report, but each layer or each test in the measured oil production index has a skin coefficient, so it is necessary to eliminate the influence of the skin coefficient on the oil production index. e is the oil production discharge radius; r w is the wellbore radius; S is the skin coefficient.

[0013] Furthermore, the calculation formulas for the skin-free coefficient oil recovery index and the oil drainage radius are as follows:

[0014] Pi _real-m =a*(K o h o / (μ o *(lnr e / r w-0.75))

[0015] Where a is the coefficient.

[0016] Furthermore, the calculation formulas for the skin-free coefficient oil recovery index and the oil drainage radius are as follows:

[0017] Pi _real-m =a*(K o h o / (μ o *(lnr e / r w -0.75))

[0018] Wherein, a is a coefficient; the calculation method of coefficient a is: the skinless coefficient oil production index and K o h o / (μ o *(lnr e / r w -0.75) to perform linear fitting, and calculate the slope of the fitted straight line, which is the coefficient a.

[0019] Furthermore, the calculation formula of the CO2 injection index is:

[0020] J v_real =a*(K c h c / (μ c *(lnr s / r w -0.75)))

[0021] Among them, J v_real is the CO2 injection index; K c is the permeability of the saline layer; h c is the effective thickness of the saline layer; μ c is the viscosity of CO2; r s is the CO2 injection sweep radius.

[0022] Furthermore, the calculation formula for the CO2 injection sweep radius is:

[0023] r s =r e *Sqrt((K c / μ c) / (K o / μ o ))*γ

[0024] Where γ is the pseudo-steady-state correction coefficient.

[0025] Furthermore, the method for determining the maximum allowable injection pressure difference is: taking 90% of the minimum effective horizontal principal stress as the maximum allowable injection pressure difference ΔP of the caprockcap The critical instability pressure increment is determined by the Mohr-Coulomb failure criterion, and 90% of the critical instability pressure increment is taken as the maximum allowable injection pressure difference ΔP of the fault. fault ; Compare the maximum allowable injection pressure difference of the caprock ΔP cap and the maximum allowable injection pressure difference ΔP fault , and take the minimum value between the two as the maximum allowable injection pressure difference of the target CO2 storage layer.

[0026] Furthermore, the calculation formula for the target CO2 storage layer injection capacity is:

[0027] Q v =J v_real *ΔP inj

[0028] Q m =Q v *ρ c

[0029] Among them, Q v is the volume injection capacity of the target CO2 storage layer; ΔP inj is the maximum allowable injection pressure difference; J v_real is the CO2 injection index; Q v is the mass injection capacity of the target CO2 storage layer; ρ c is the ground density of CO2.

[0030] The present invention also discloses a fault-controlled saline layer CO2 storage site injection capacity evaluation system, comprising: a data acquisition module for acquiring well test analysis data of adjacent oil fields; an oil production index correction module for obtaining a skin-free coefficient oil production index based on the well test analysis data; a linear fitting module for establishing a calculation formula for the skin-free coefficient oil production index and the oil drainage radius, and determining the coefficient a of the calculation formula; an injection index calculation module for obtaining a calculation formula for the CO2 injection index based on the coefficient a, and inputting the well test analysis data into the calculation formula for the CO2 injection index to obtain the CO2 injection index; an injection capacity calculation module for determining a maximum allowable injection pressure difference, and calculating the injection capacity of the target CO2 storage layer based on the CO2 injection index and the maximum allowable injection pressure difference.

[0031] The technical scheme of the present application has at least the following technical effects or advantages: the present application establishes a method for calculating a CO2 injection index through actual test data such as oilfield well testing, comprehensively considers the risks of cap rock rupture and fault instability, and calculates the injection capacity of a fault-controlled saline aquifer CO2 storage site by determining the maximum allowable injection pressure difference considering the risks of cap rock rupture and fault instability, which can solve the problem that a target storage site cannot obtain a reliable injection capacity due to the lack of CO2 injection testing, effectively supports CO2 injection scheme design, and provides reliable support for single-well injection rate design of a CO2 injection scheme. BRIEF DESCRIPTION OF DRAWINGS

[0032] Figure 1 is a flowchart of a fault-controlled saline aquifer CO2 storage site injection capacity evaluation method in an embodiment of the present application;

[0033] Figure 2 is a linear fitting graph of the oil production index and the drainage radius in an embodiment of the present application. DETAILED DESCRIPTION

[0034] In order for those skilled in the art to better understand the technical scheme of the present application, the present application is described in detail through specific embodiments. However, it should be understood that the specific embodiments are provided only to better understand the present application, and they should not be understood as limiting the present application. In the description of the present application, it should be understood that the terms used are only for the purpose of description, and should not be understood as indicating or implying relative importance.

[0035] In order to solve the problems in the prior art that the actual test data of the target site is not combined, the maximum allowable injection pressure difference is not considered, there is a lack of test data, and there is a high requirement for professional knowledge and software operation, the present application proposes a fault-controlled saline aquifer CO2 storage site injection capacity evaluation method and system, which fully utilizes the oil production test data of the target storage site and the adjacent area to solve the problem of insufficient evaluation basis data caused by the lack of injection testing of the target storage site. At the same time, the determination of the maximum allowable injection pressure difference not only considers the difference between the reservoir pressure and the cap rock rupture pressure, but also considers the difference between the reservoir pressure and the fault instability pressure, so as to form a fault-controlled saline aquifer CO2 injection capacity evaluation method based on risk control, and provide reliable support for single-well injection rate design of a CCS project injection scheme. The present application scheme is described in detail below with reference to the accompanying drawings.

[0036] The CO2 injection capacity in the prior art can be calculated by injection index and injection pressure difference, which is expressed as:

[0037] Qv = Jv * (P bh -P r )

[0038] Where Qv is the injection rate, m 3 / d; Jv is the injection index, m 3 / d / MPa;P bh is the bottom hole pressure, MPa; P r is the average reservoir pressure, MPa.

[0039] For target storage sites where CO2 injection testing has not been conducted, the actual CO2 injection parameters are lacking, making it impossible to directly obtain the CO2 injection index. However, neighboring oil fields often have a large amount of well test analysis data. The oil production index of the same formation in the neighboring oil fields can be used to estimate the CO2 injection index of the target storage site, thereby evaluating the CO2 injection capacity of the target storage site.

[0040] Example 1

[0041] This embodiment discloses a method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site. Figure 1 As shown, the following steps are included:

[0042] S1 obtains well test analysis data from nearby oil fields.

[0043] Well test analysis data for oil layers in the same formation as the target CO2 storage layer, including: oil layer permeability K o , effective thickness of oil layer h o , crude oil viscosity μ o , skin coefficient S, wellbore radius r w , oil leakage radius r e and oil recovery index P i_real Calculate the crude oil flow coefficient K based on the reservoir well test analysis data o h o / μ o .

[0044] S2 obtains the skin-free coefficient oil production index based on the well test analysis data.

[0045] According to traditional seepage mechanics theory, for a circular drainage or swept area shape, assuming that the isothermal pseudo-steady-state radial flow condition is satisfied at any time in a vertical well, the volumetric production index and volumetric injection index can be expressed as:

[0046] P i_theory =172.8*(K o h o / μ o )*(lnr e / r w -0.75+S)) -1

[0047] J v_theory =172.8*(Kc h c / μ c )*(lnr s / r w -0.75+S)) -1

[0048] Among them, P i_theory is the theoretical oil recovery index, m 3 / d / MPa,J v_theory Injecting index into theory, m 3 / d / MPa;K o is the reservoir permeability, mD; h o is the effective thickness of the oil layer, m; μ o is the crude oil viscosity, mPa.s; K c is the permeability of the saline layer, mD; h c is the effective thickness of the saline layer, m; μ c is the viscosity of CO2, mPa.s; r s is the injection sweep radius, m.

[0049] It can be seen that the oil production index reflects the effect of reservoir properties (permeability, thickness), fluid properties (fluid viscosity), drainage area and other parameters on the production capacity of the oil well, while the CO2 injection index of the saline layer is also controlled by reservoir properties (permeability, thickness), fluid properties (fluid viscosity), and swept area. Therefore, the actual oil production index Pi_real and the oil layer flow coefficient (K) of the same formation are established by analyzing the well test data of the adjacent oil fields. o h o / μ o ) and oil leakage radius (r e ) can be approximated as the relationship between the CO2 injection index and the flow coefficient of the saline layer in the same formation (K c h c / μ c ) and sweep radius (r s ), and then the flow coefficient (K c h c / μ c ) and sweep radius (r s ) parameter calculation of CO2 injection index Jv _real .

[0050] The oil production index without skin coefficient is calculated by the oil production index P i_real The calculation formula of the oil recovery index without skin coefficient is obtained by correction:

[0051] Pi _real-m =P i_real *((lnr e / r w-0.75 + S) / (lnr e / r w -0.75

[0052] Pi _real-m is the skin-free productivity index, m 3 / d / MPa, P i_real is the productivity index obtained from the well test report, but the measured productivity index has skin factor for each layer or each test, r e is the drainage radius of oil production, m; r w is the wellbore radius, m; S is the skin factor, P i_real is the actual productivity index, m 3 / d / MPa.

[0053] S3 establishes the calculation formula of the skin-free productivity index and the drainage radius of oil, and determines the coefficient a of the calculation formula. The calculation formula of the skin-free productivity index and the drainage radius of oil is:

[0054] Pi _real-m = a*(K o h o / (μ o *(lnr e / r w -0.75)

[0055] Wherein, a is the coefficient.

[0056] The calculation formula of the skin-free productivity index and the drainage radius of oil is:

[0057] Pi _real-m = a*(K o h o / (μ o *(lnr e / r w -0.75)

[0058] Wherein, a is the coefficient; the calculation method of the coefficient a is: linear fitting is performed on the skin-free productivity index and K o h o / (μ o *(lnr e / r w -0.75), the linear fitting result is shown in Figure 2 , the slope of the straight line after fitting is calculated, and the slope is the coefficient a.

[0059] S4 obtains the calculation formula of the CO2 injection index according to the coefficient a, and inputs the well test analysis data into the calculation formula of the CO2 injection index to obtain the CO2 injection index.

[0060] Determine the permeability K of each reservoir-caprock combination at the target storage site c , effective thickness h c 、CO2 viscosity μ c , calculate the CO2 flow coefficient (K c h c / μ c ), calculate the CO2 injection sweep radius r s .

[0061] The calculation formula for the CO2 injection sweep radius is:

[0062] r s =r e *Sqrt((K c / μ c) / (K o / μ o ))*γ

[0063] The calculation formula of CO2 injection index is:

[0064] J v_real =a*(K c h c / (μ c *(lnr s / r w -0.75)))

[0065] Among them, J v_real is the CO2 injection index; K c is the permeability of each reservoir-caprock combination of the target CO2 storage layer; h c is the effective thickness of the target CO2 storage layer; μ c is the viscosity of CO2; r s is the CO2 injection sweep radius, and γ is the pseudo-steady-state correction coefficient, which is generally 1 to 1.5, reflecting the difference between injection dynamics and production dynamics.

[0066] S5 determines the maximum allowable injection pressure difference, and calculates the injection capacity of the target CO2 storage layer based on the CO2 injection index and the maximum allowable injection pressure difference.

[0067] The method for determining the maximum allowable injection pressure difference is as follows: the maximum allowable injection pressure difference is used for the injection pressure difference, mainly considering the cap rock rupture risk and fault instability risk of the target storage site. The cap rock rupture risk mainly considers tensile rupture, and 90% of the minimum effective horizontal principal stress is taken as the maximum allowable cap rock injection pressure difference ΔP cap The critical instability pressure increment is determined by the Mohr-Coulomb failure criterion, and 90% of the critical instability pressure increment is taken as the maximum allowable injection pressure difference ΔP of the fault. fault ; Compare the maximum allowable injection pressure difference of the caprock ΔP cap and the maximum allowable injection pressure difference ΔPfault , take the minimum value between the two as the maximum allowable injection pressure difference ΔP of the target CO2 storage layer inj Generally speaking, the maximum allowable injection pressure difference of the fault is ΔP fault Mostly less than the maximum allowable injection pressure difference ΔP of the caprock cap , the maximum allowable injection pressure difference can be expressed as:

[0068] ΔP inj =min(ΔP cap ,ΔP fault )

[0069] Determine the CO2 injection index and the maximum allowable injection pressure difference ΔP based on the relevant parameters of the target storage site inj , calculate the volume injection capacity of the target CO2 storage layer, and calculate the mass injection capacity of the target CO2 storage layer in combination with the CO2 density.

[0070] The calculation formula for the target CO2 storage layer injection capacity is:

[0071] Q v =J v_real *ΔP inj

[0072] Q m =Q v *ρ c

[0073] Among them, Q v is the volume injection capacity of the target CO2 storage layer; ΔP inj is the maximum allowable injection pressure difference; J v_real is the CO2 injection index; Q v is the mass injection capacity of the target CO2 storage layer; ρ c is the ground density of CO2.

[0074] Example 2

[0075] Based on the same inventive concept, this embodiment uses the method of Example 1 to evaluate the injection capacity of a saline aquifer storage site A in the Pearl River Mouth Basin of the South China Sea, specifically comprising the following steps:

[0076] S1 obtains well test analysis data from nearby oil fields.

[0077] Due to the lack of CO2 injection test, the CO2 injection capacity was evaluated by well test analysis data from the adjacent B oil field. The well test analysis data of Well X in the B oil field were used to obtain 9 test results of 4 test layers, namely the permeability K o In the range of 650~7000mD, the effective thickness h o In the range of 4.3~8.8m; crude oil viscosity μ oIn the range of 2.7~11.1mPa.s; the skin coefficient S is in the range of 2.61~5.51, and the wellbore radius r w is 0.11m, oil leakage radius r e In the range of 708~1170m, the oil production index P i_real At 67~1095m 3 In the range of / d / Mpa, the crude oil flow coefficient K o h o / μ o 872~29870mD.m.(mPa.s) -1 within the range.

[0078] S2 obtains the skin-free oil production index based on the well test analysis data. In this embodiment, the skin-free oil production index Pi _real-m At 73~1190m 3 / d / MPa range.

[0079] S3 establishes a calculation formula for the skinless coefficient oil production index and the oil drainage radius, and determines the coefficient a of the calculation formula.

[0080] The skin-free oil recovery index and K o h o / (μ o *(lnr e / r w -0.75) to perform linear fitting and calculate the slope of the fitted line. The slope is the coefficient a, such as Figure 2 As shown, the coefficient a is 1.05.

[0081] S4 obtains a calculation formula for the CO2 injection index based on the coefficient a, and inputs the well test analysis data into the calculation formula for the CO2 injection index to obtain the CO2 injection index.

[0082] There are two sets of reservoir-caprock combinations in the target storage site. The parameters of reservoir-caprock combination 1 are: the reservoir depth is 1750m, the permeability K c The mean is 1280mD, the standard deviation is 300mD, it obeys the normal distribution, and the effective thickness is h c 140~200m, average thickness is 170m, uniform distribution, CO2 viscosity is μ c 0.04mPa.s, flow coefficient (K c h c / μ c )The average value is 5442537mD.m.(mPa.s) -1 , the standard deviation is 1413771mD.m.(mPa.s) -1 .

[0083] The parameters of reservoir-cap combination 2 are: the reservoir depth is 2100m, the permeability K c The mean is 875mD, the standard deviation is 260mD, and it obeys the normal distribution. The effective thickness is h c 180~230m, average thickness is 205m, uniform distribution, CO2 viscosity is μ c 0.043mPa.s, flow coefficient (K c h c / μ c )The average value is 4057480mD.m.(mPa.s) -1 , standard deviation is 1305147mD.m.(mPa.s) -1 .

[0084] Calculate the CO2 injection sweep radius r s :The average oil drainage radius of each target test layer is 905m, the average flow rate K o / μ o 1273mD.(mPa.s) -1 , the pseudo-steady-state correction coefficient γ is taken as 1, and the injection sweep radius r of reservoir-cap combination 1 is calculated s The injection sweep radius r of reservoir-cap combination 2 is 4579 m. s It is 3651m.

[0085] Calculation of CO2 injection index J v_real :Reservoir-cap combination 1 underestimates the injection index (P90) to 376183m 3 / d / MPa, and the best estimated injection index (P50) is 568351m 3 / d / MPa, overestimated injection index (P10) is 760518m 3 / d / MPa. The injection index (P90) of reservoir-cap combination 2 is underestimated to 281552m 3 / d / MPa, and the best estimated injection index (P50) is 465680m 3 / d / MPa, and the injection index (P10) is overestimated to be 649808m 3 / d / MPa.

[0086] S5 determines the maximum allowable injection pressure difference, and calculates the injection capacity of the target CO2 storage layer based on the CO2 injection index and the maximum allowable injection pressure difference.

[0087] The maximum allowable injection pressure difference ΔP of the reservoir-cap assembly 1 in this embodiment cap The maximum allowable injection pressure difference ΔP of reservoir-cap combination 2 is 5.43 MPa. cap The critical instability pressure increment is determined by the Mohr-Coulomb failure criterion, and 90% of the critical instability pressure increment is taken as the maximum allowable injection pressure difference ΔP of the fault.fault ; The maximum allowable injection pressure difference ΔP of the most fault of reservoir-cap combination 1 faul The maximum allowable injection pressure difference ΔP of the fault of reservoir-cap combination 2 is 3.32 MPa. faul The maximum allowable injection pressure difference of the caprock is 3.57 MPa. cap and the maximum allowable injection pressure difference ΔP fault , take the minimum value between the two as the maximum allowable injection pressure difference of the target CO2 storage layer. In this embodiment, the maximum allowable injection pressure difference ΔP inj It is 3.57MPa.

[0088] The target CO2 storage layer injection capacity is calculated using the target CO2 storage layer injection capacity calculation formula. The CO2 density is 1.873 kg / m 3 The underestimated injectivity (P90) of reservoir-cap combination 1 is 850,000 tons / year, the best-estimated injectivity (P50) is 1.29 million tons / year, and the overestimated injectivity (P10) is 1.73 million tons / year. The underestimated injectivity (P90) of reservoir-cap combination 2 is 640,000 tons / year, the best-estimated injectivity (P50) is 1.06 million tons / year, and the overestimated injectivity (P10) is 1.47 million tons / year.

[0089] Example 3

[0090] Based on the same inventive concept, this embodiment discloses a fault-controlled saline aquifer CO2 storage site injection capacity evaluation system, comprising:

[0091] Data acquisition module, used to obtain well test analysis data of nearby oil fields;

[0092] Oil production index correction module, used to obtain skin-free oil production index based on well test analysis data;

[0093] A linear fitting module is used to establish a calculation formula for the skin-free coefficient oil production index and the oil drainage radius, and to determine the coefficient a of the calculation formula;

[0094] An injection index calculation module is used to obtain a calculation formula for the CO2 injection index based on the coefficient a, and input the well test analysis data into the calculation formula for the CO2 injection index to obtain the CO2 injection index;

[0095] The injection capacity calculation module is used to determine the maximum allowable injection pressure difference and calculate the injection capacity of the target CO2 storage layer based on the CO2 injection index and the maximum allowable injection pressure difference.

[0096] It will be understood by those skilled in the art that embodiments of the present invention may be provided as methods, systems, or computer program products. Thus, the present invention may take the form of an entirely hardware embodiment, an entirely software embodiment, or an embodiment combining software and hardware. Furthermore, the present invention may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to magnetic disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0097] The present invention is described with reference to flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to embodiments of the present invention. It should be understood that each process and / or block in the flowcharts and / or block diagrams, as well as combinations of processes and / or blocks in the flowcharts and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowcharts and / or block diagrams. Figure 1 a process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0098] These computer program instructions may also be stored in a computer readable memory that can direct a computer or other programmable data processing device to work in a specific manner, so that the instructions stored in the computer readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 a process or multiple processes and / or boxes Figure 1 The function specified in one or more boxes.

[0099] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operational steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing the instructions executed on the computer or other programmable device for implementing the process. Figure 1 a process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0100] The above embodiments are only used to illustrate the technical solutions of the present invention and are not intended to limit them. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art should understand that the specific embodiments of the present invention can still be modified or replaced by equivalents, and any modifications or equivalent replacements that do not depart from the spirit and scope of the present invention should be included within the scope of protection of the claims of the present invention. The above contents are only specific embodiments of the present invention, but the scope of protection of the present invention is not limited thereto. Any person skilled in the art who is familiar with the technical field can easily think of changes or replacements within the technical scope disclosed by the present invention, which should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be based on the scope of protection of the claims.

Claims

1. A method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site, characterized in that: The following steps are involved: Obtain well test analysis data from nearby oil fields; Obtaining a skin-free oil recovery index based on the well test analysis data; Establishing a calculation formula for the skin-free coefficient oil production index and the oil drainage radius, and determining a coefficient a of the calculation formula; According to the coefficient a, a calculation formula for the CO2 injection index is obtained, and the well test analysis data is input into the calculation formula for the CO2 injection index to obtain the CO2 injection index; The maximum allowable injection pressure difference is determined, and the injection capacity of the target CO2 storage layer is calculated based on the CO2 injection index and the maximum allowable injection pressure difference.

2. The method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site according to claim 1, wherein: The well test analysis data and the target CO2 storage layer belong to the same formation as the oil layer well test analysis data, including: oil layer permeability K o , effective thickness of oil layer h o , crude oil viscosity μ o , skin coefficient S, wellbore radius r w , oil leakage radius r e and oil recovery index P i_real .

3. The method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site according to claim 2, wherein: The skin-free oil production index is obtained by i_real The calculation formula of the oil recovery index without skin coefficient is obtained by correction: Pi _real-m =P i_real *((lnr e / r w -0.75+S) / (lnr e / r w -0.75)) Among them, Pi _real-m is the skin-free oil recovery index, r e is the oil production discharge radius; r w is the wellbore radius; S is the skin coefficient.

4. The method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site according to claim 3, wherein: The calculation formulas for the skin-free oil production index and the oil drainage radius are: Pi _real-m =a*(K o h o / (μ o *(lnr e / r w -0.75)) Where a is the coefficient.

5. The method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site according to claim 4, wherein: The calculation formulas for the skin-free oil production index and the oil drainage radius are: Pi _real-m =a*(K o h o / (μ o *(lnr e / r w -0.75)) Where a is the coefficient; The calculation method of coefficient a is: the skinless coefficient oil production index and K o h o / (μ o *(lnr e / r w -0.75) to perform linear fitting, and calculate the slope of the fitted straight line, which is the coefficient a.

6. The method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site according to claim 5, wherein: The calculation formula of the CO2 injection index is: J v_real =a*(K c h c / (μ c * (lnr s / r w -0.75))) Among them, J v_real is the CO2 injection index; K c is the permeability of the saline layer; h c is the effective thickness of the saline layer; μ c is the viscosity of CO2; r s is the CO2 injection sweep radius.

7. The method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site according to claim 6, wherein: The calculation formula for the CO2 injection sweep radius is: r s =r e *Sqrt((K c / m c) / (K o / m o ))*c Where γ is the pseudo-steady-state correction coefficient.

8. The method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site according to claim 7, wherein: The method for determining the maximum allowable injection pressure difference is: Take 90% of the minimum effective horizontal principal stress as the maximum allowable injection pressure difference ΔP of the caprock cap ; The critical instability pressure increment is determined by the Mohr-Coulomb failure criterion, and 90% of the critical instability pressure increment is taken as the maximum allowable injection pressure difference ΔP of the fault. fault ; Compare the maximum allowable injection pressure difference of the caprock ΔP cap and the maximum allowable injection pressure difference ΔP fault , and take the minimum value between the two as the maximum allowable injection pressure difference of the target CO2 storage layer.

9. The method for evaluating the injection capacity of a fault-controlled saline aquifer CO2 storage site according to claim 7, wherein: The calculation formula for the target CO2 storage layer injection capacity is: Q v =J v_real *ΔP inj Q m =Q v *ρ c Among them, Q v is the volume injection capacity of the target CO2 storage layer; ΔP inj is the maximum allowable injection pressure difference; J v_real is the CO2 injection index; Q v is the mass injection capacity of the target CO2 storage layer; ρ c is the ground density of CO2.

10. A fault-controlled saline aquifer CO2 storage site injection capacity evaluation system, characterized by: include: Data acquisition module, used to obtain well test analysis data of nearby oil fields; An oil production index correction module, for obtaining a skin-free oil production index based on the well test analysis data; A linear fitting module is used to establish a calculation formula for the skin-free coefficient oil recovery index and the oil drainage radius, and to determine a coefficient a of the calculation formula; An injection index calculation module, configured to obtain a calculation formula for the CO2 injection index based on the coefficient a, and input the well test analysis data into the calculation formula for the CO2 injection index to obtain the CO2 injection index; The injection capacity calculation module is used to determine the maximum allowable injection pressure difference and calculate the injection capacity of the target CO2 storage layer based on the CO2 injection index and the maximum allowable injection pressure difference.

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