Method for simulating and calculating CO2 burying rate of exhausted gas reservoir

Abstract

The invention discloses a method for simulating and calculating the CO2 burying rate of an exhausted gas reservoir, which comprises the following steps: S1, acquiring rock core, formation water, methane and CO2 samples, and measuring the basic physical properties of each sample; s2, under the formation condition, the rock core is saturated with formation water and subjected to methane displacement till no water is discharged; s3, CO2 displacement is conducted on the rock core, and CO2 injection and extraction data in the process are recorded till the depletion state is achieved; s4, under the constant pressure condition, the rock core is subjected to standing treatment, and the basic physical property of the rock core subjected to standing treatment is measured; and S5, establishing a CO2 burying rate calculation model, and calculating the CO2 burying rate in combination with the parameters obtained in the steps. According to the method, the CO2 burying rate can be accurately calculated, and evaluation indexes and references are provided for the safety of CO2 geological storage.

Description

Technical Field

[0001] The present invention relates to the technical field of CO2 geological storage, and in particular to a method for simulating and calculating the CO2 storage rate of a depleted gas reservoir. Background Art

[0002] Natural gas, as a clean energy source, is in high demand. While CO2 storage technology is already well established in saline aquifers and oil reservoirs, research on CO2 storage in depleted gas reservoirs is limited in China, primarily due to a lack of laboratory experimental validation and field implementation cases.

[0003] Given that gas reservoirs in the middle and late stages of exploitation have large storage spaces and relatively good sealing security, and that CO2 has unique physicochemical properties such as high density, low viscosity, and strong diffusivity, injecting it into gas reservoirs can achieve both environmental and economic benefits. However, not all reservoirs are suitable for CO2 injection. During CO2 injection, it reacts with formation water and rock, causing dissolution and precipitation, which significantly affects reservoir permeability and poses a risk of CO2 leakage. Simulating the CO2 storage rate can provide an evaluation indicator and reference for the safety of CO2 geological storage. However, existing CO2 storage rate calculation methods do not take into account adsorption effects, rock-CO2-water reactions, and the separation of carbon dioxide and methane in gas reservoirs, resulting in inaccurate calculation results. Summary of the Invention

[0004] In view of the above problems, the present invention aims to provide a method for simulating and calculating the CO2 storage rate in depleted gas reservoirs.

[0005] The technical solutions of the present invention are as follows:

[0006] A method for simulating and calculating the CO2 burial rate in a depleted gas reservoir comprises the following steps:

[0007] S1: Obtain core, formation water, methane and CO2 samples, and measure the basic physical properties of each sample;

[0008] S2: Under formation conditions, the core is saturated with formation water and methane is displaced until no more water is produced;

[0009] S3: Flood the core with CO2 and record the CO2 injection and production data until the core is depleted;

[0010] S4: Under constant pressure conditions, the core is subjected to static treatment and the basic physical properties of the core after static treatment are measured;

[0011] S5: Establish a CO2 storage rate calculation model, and calculate the CO2 storage rate based on the parameters obtained in the above steps.

[0012] Preferably, in step S1, the steps of cleaning and drying the core are further included before testing the basic physical properties of the core.

[0013] Preferably, in step S1, the basic physical properties of the core include diameter, length, porosity, and permeability, and the basic physical properties of methane and CO2 include viscosity.

[0014] Preferably, in step S2 and step S3, the device used for displacement is a displacement device based on a gas separation membrane, which can separate methane and CO2 in the displaced gas through the gas separation membrane.

[0015] Preferably, the displacement device based on the gas separation membrane includes an injection system, a core clamping system, a vacuum system, a confining pressure system, a back pressure system, an output system and a data acquisition system;

[0016] The injection system includes an injection pump, a formation water injection unit, a methane injection unit, and a CO2 injection unit respectively connected to the injection pump and arranged in parallel, and the output ends of the formation water injection unit, the methane injection unit, and the CO2 injection unit are connected to the input end of the core support system;

[0017] The core clamping system is used to clamp the core, and the vacuum system, the confining pressure system and the back pressure system are respectively connected to the core clamping system;

[0018] The output system includes a four-way valve, the input end of the four-way valve is connected to the output end of the core clamping system, and the three output ends of the four-way valve are respectively connected to a methane collection device, a CO2 collection device, and a solution collection device. A gas separation membrane is provided on the inner wall of the pipeline between the four-way valve and the methane collection device and the CO2 collection device, and the gas separation membrane allows CO2 to flow in and inhibits methane from passing through;

[0019] The data acquisition system is used to collect pressure and flow rate change data during the displacement process.

[0020] Preferably, the data acquisition system further comprises a CT scanner and an X-ray detector arranged in the CT scanner, wherein the CT scanner is used to scan the core to obtain the pore throat diameter distribution curve and the three-dimensional reconstructed image of the core.

[0021] Preferably, in step S3, when the methane production rate is less than 5% of the CO2 production rate, it is considered to have reached the exhaustion state.

[0022] Preferably, in step S4, the pressure of the static treatment is 30-35 MPa, the temperature is 90-95° C., and the time is 3-4 days.

[0023] Preferably, in step S5, the CO2 storage rate calculation model includes a CO2 storage rate calculation model based on steady-state unidirectional flow and a CO2 storage rate calculation model based on unsteady-state multiphase flow;

[0024] The CO2 storage rate calculation model based on steady-state unidirectional flow is:

[0025]

[0026] Where: β is the CO2 storage rate, %; v1 is the volume of injected CO2, cm 3 ; v2 is the volume of CO2 produced, cm 3 ; d is the diameter of the core, cm; L is the length of the core, cm; φ1 is the porosity of the core after static treatment, dimensionless; P2 is the pressure under the target formation conditions, MPa; Z1 is the deviation coefficient under the surface conditions, dimensionless; T1 is the temperature under the surface conditions, K; Z2 is the deviation coefficient under the target formation conditions, dimensionless; T2 is the temperature under the target formation conditions, K; P1 is the pressure under the surface conditions, MPa;

[0027] The CO2 storage rate calculation model based on unsteady multiphase flow is:

[0028]

[0029] Where: β(t) is the CO2 storage rate under time t, %; v1(t) is the volume of CO2 injected under time t, cm 3 ; v2 is the volume of CO2 produced under time t, cm 3 ;k rg (S g ) is the relative permeability, 10 -3 μm 2 ; α is the stress sensitivity coefficient, MPa -1 ; σ eff (z,t) is the effective stress at reservoir depth z and time t, MPa; V L is the Langmuir volume, m 3 / kg; P(τ) is the pressure corresponding to the moment τ, MPa; P L is the Langmuir pressure, MPa; φ(z) is the core porosity at reservoir depth z, dimensionless; z is the reservoir depth, m; τ is the time integral variable, s; S g(z,t) is the stored CO2 saturation at reservoir depth z and time t, dimensionless; P(z,t) is the pressure at reservoir depth z and time t, MPa; Z(P(z,t),T(z,t)) is the deviation coefficient at pressure P(z,t) and temperature T(z,t), dimensionless; T(z,t) is the temperature at reservoir depth z and time t, K.

[0030] Preferably, the method further includes a step of evaluating whether the reservoir is suitable for CO2 geological storage based on the CO2 storage rate. The greater the CO2 storage rate, the more suitable the reservoir is for CO2 geological storage.

[0031] The beneficial effects of the present invention are:

[0032] The present invention establishes a CO2 storage rate calculation model based on steady-state unidirectional flow and a CO2 storage rate calculation model based on unsteady-state multiphase flow, which can accurately calculate the storage rate after considering the adsorption effect, rock-CO2-water reaction and separation of CO2 and methane. BRIEF DESCRIPTION OF THE DRAWINGS

[0033] 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.

[0034] Figure 1 Schematic diagram of the structure of a displacement device based on a gas separation membrane in a specific embodiment;

[0035] Figure 2 A schematic diagram of the inner wall of a pipeline provided with a MOF gas separation membrane in a specific embodiment;

[0036] Figure 3 Schematic diagram of calculation results of CO2 dissolution rate and effective storage rate in a specific embodiment;

[0037] Figure 4 Schematic diagram of CO2 porosity and permeability improvement results in a specific embodiment.

[0038] Numbers in the figure:

[0039] 1- injection pump, 2- first one-way valve, 3- second one-way valve, 4- fourth one-way valve, 5- third one-way valve, 6- first inlet control valve, 7- second inlet control valve, 8- third inlet control valve, 9- fourth inlet control valve, 10- first intermediate container, 11- second intermediate container, 12- third intermediate container, 13- fourth intermediate container, 14- first outlet control valve, 15- second outlet control valve, 16- third outlet control valve, 17- fourth outlet control valve, 18- five-way valve, 19- fifth one-way valve, 20- pressure gauge 1, 21- vacuum pump, 22- confining pressure pump, 23- seventh one-way valve, 24- sixth one-way valve, 25- three-way valve, 26- first 5. Intermediate container, 27. Pressure gauge 2, 28. Fifth inlet control valve, 29. Fifth outlet control valve, 30. Back pressure pump, 31. Pressure gauge 3, 32. CT scanner, 33. Temperature control device, 34. X-ray detector, 35. Core holder, 36. Pressure gauge 4, 37. Eighth one-way valve, 38. Outlet three-way valve, 39. Four-way valve, 40. Ninth one-way valve, 41. Tenth one-way valve, 42. Eleventh one-way valve, 43. Twelfth one-way valve, 44. Methane collection device, 45. CO2 collection device, 46. Solution collection device, 47. Computer processing system, 48. Electronic scale, 49. Gas flow meter 1, 50. Gas flow meter 2 5. DETAILED DESCRIPTION

[0040] The present invention is further described below with reference to the accompanying drawings and examples. It should be noted that, in the absence of conflict, the embodiments in this application and the technical features in the embodiments can be combined with each other. It should be noted that, unless otherwise specified, all technical and scientific terms used in this application have the same meanings as those commonly understood by those of ordinary skill in the art to which this application belongs. The use of similar words such as "include" or "comprising" in the present invention means that the elements or objects appearing before the word cover the elements or objects listed after the word and their equivalents, without excluding other elements or objects.

[0041] The present invention provides a method for simulating and calculating the CO2 burial rate in a depleted gas reservoir, comprising the following steps:

[0042] S1: Obtain core, formation water, methane, and CO2 samples, and measure the basic physical properties of each sample.

[0043] In a specific embodiment, the core is cleaned and dried before testing its basic physical properties. Optionally, the basic physical properties of the core include diameter, length, porosity, and permeability, and the basic physical properties of methane and CO2 include viscosity.

[0044] S2: Under formation conditions, the core is saturated with formation water and methane is displaced until no more water is produced.

[0045] S3: Perform CO2 flooding on the core and record the CO2 injection and production data during the process until the core reaches the depletion state.

[0046] In a specific embodiment, in steps S2 and S3, the device used for displacement is a gas separation membrane-based displacement device, which can separate methane and CO2 from the displaced gas through the gas separation membrane. Optionally, the gas separation membrane is a MOF gas separation membrane.

[0047] In the above embodiment, the methane and CO2 produced at the outlet are separated by a gas separation membrane, which can more accurately obtain the volumes of the produced methane and CO2, clarify the formation timing of the depleted gas reservoir, and provide more accurate storage parameters for subsequent calculation models.

[0048] In a specific embodiment, Figure 1-2 As shown, the displacement device based on gas separation membrane includes an injection system, a core clamping system, a vacuum system, a confining pressure system, a back pressure system, an output system and a data acquisition system;

[0049] The injection system includes an injection pump 1, a formation water injection unit, a methane injection unit and a CO2 injection unit respectively connected to the injection pump 1 and arranged in parallel, and the output ends of the formation water injection unit, the methane injection unit and the CO2 injection unit are connected to the input end of the core support system;

[0050] The core clamping system is used to clamp the core, and the vacuum system, the confining pressure system and the back pressure system are respectively connected to the core clamping system;

[0051] The output system includes a four-way valve 39, the input end of the four-way valve 39 is connected to the output end of the core clamping system, and the three output ends of the four-way valve 39 are respectively connected to a methane collection device 44, a CO2 collection device 45, and a solution collection device 46. A gas separation membrane is provided on the inner wall of the pipeline between the four-way valve 39 and the methane collection device 44 and the CO2 collection device 45, and the gas separation membrane allows CO2 to flow in and inhibits the passage of methane;

[0052] The data acquisition system is used to collect pressure and flow rate change data during the displacement process.

[0053] It should be noted that the gas separation membrane is provided on the inner wall of the pipeline between the four-way valve 39 and the methane collection device 44 and the CO2 collection device 45. Figure 2As shown, a gas separation membrane is set inside the pipeline, and then an outlet is set on the side wall. The suppressed methane is input to the methane collection device 44 from the outlet of the pipeline, and the CO2 allowed to pass is input to the CO2 collection device 45 from the outlet of the side wall.

[0054] In a specific embodiment, the formation water injection unit includes a first intermediate container 10, the methane injection unit includes a second intermediate container 11, and the CO2 injection unit includes a third intermediate container 12. The input ends of the first intermediate container 10, the second intermediate container 11, and the third intermediate container 12 are respectively connected to the injection pump 1. The pipeline connecting the first intermediate container 10 to the injection pump 1 is equipped with a first inlet control valve 6 and a first check valve 2, the pipeline connecting the second intermediate container 11 to the injection pump 1 is equipped with a second inlet control valve 7 and a second check valve 3, and the pipeline connecting the third intermediate container 12 to the injection pump 1 is equipped with a third inlet control valve 8 and a third check valve 5. Optionally, the injection system also includes a fourth intermediate container 13 for storing a core cleaning agent (petroleum ether). The pipeline connecting the fourth intermediate container 13 to the injection pump 1 is equipped with a fourth inlet control valve 9 and a fourth check valve 4. The output ends of the first intermediate container 10, the second intermediate container 11, the third intermediate container 12, and the fourth intermediate container 13 are connected to the five-way valve 18, and the connected pipelines are respectively provided with a first outlet control valve 14, a second outlet control valve 15, a third outlet control valve 16, and a fourth outlet control valve 17. The outlet end of the five-way valve 18 is connected to the core clamp 35 of the core clamping system, and the connected pipelines are provided with a fifth one-way valve 19 and a pressure gauge 20.

[0055] The vacuum system includes a vacuum pump 21, and the confining pressure system includes a confining pressure pump 22. The vacuum pump 21 and the confining pressure pump 22 are connected to the core clamp 35 through a three-way valve 25. A sixth one-way valve 24 is provided between the vacuum pump 21 and the three-way valve 25, and a seventh one-way valve 23 and a second pressure gauge 27 are provided between the confining pressure pump 22 and the three-way valve 25.

[0056] The back pressure system includes a connected back pressure pump 30 and a fifth intermediate container 26, wherein nitrogen is stored in the fifth intermediate container 26, a fifth inlet control valve 28 is provided between the fifth intermediate container 26 and the back pressure pump 30, and a fifth outlet control valve 29 and a pressure gauge 31 are provided between the fifth intermediate container 26 and the core clamp 35.

[0057] The output end of the backpressure system and the input end of the output system are connected to the core holder 35 via an outlet three-way valve 38. The connecting pipelines are equipped with an eighth one-way valve 37 and a fourth pressure gauge 36. A ninth one-way valve 40 is installed between the outlet three-way valve 38 and the four-way valve 39. A tenth one-way valve 41 and an eleventh one-way valve 42 are installed on the pipelines between the four-way valve 39 and the methane collection device 44 and the CO2 collection device 45, respectively. A twelfth one-way valve 43 is installed between the solution collection device 46 and the four-way valve 39.

[0058] The methane collecting device 44 and the CO2 collecting device 45 are respectively provided with a gas flow meter 1 49 and a gas flow meter 2 50 .

[0059] The data acquisition system includes a computer processing system 47, an electronic scale 48, and the aforementioned pressure gauge for collecting pressure and a gas flow meter for collecting flow.

[0060] In one specific embodiment, the data acquisition system further includes a CT scanner 32 and an X-ray detector 34 disposed within the CT scanner 32. The CT scanner is used to scan the core to obtain a pore-throat diameter distribution curve and a three-dimensional reconstructed image of the core. Optionally, in this embodiment, a temperature control device 33 for controlling the core temperature is disposed within the CT scanner 32.

[0061] In the above embodiment, the CT scanner 32 is provided to perform CT scanning on the core, obtaining a pore-throat diameter distribution curve and a 3D reconstructed image of the core. By comparing the pore-throat diameter distribution curve and the 3D reconstructed image before and after flooding, the effects of CO2 storage on the core can be more intuitively observed.

[0062] In a specific embodiment, the exhaustion state is considered to be reached when the methane production rate is less than 5% of the CO2 production rate.

[0063] S4: Under constant pressure conditions, the core is subjected to static treatment, and the basic physical properties of the core after static treatment are measured.

[0064] In a specific embodiment, the static treatment pressure is 30-35 MPa, the temperature is 90-95° C., and the time is 3-4 days.

[0065] S5: Establish a CO2 storage rate calculation model, and calculate the CO2 storage rate based on the parameters obtained in the above steps.

[0066] In a specific embodiment, the CO2 storage rate calculation model includes a CO2 storage rate calculation model based on steady-state unidirectional flow and a CO2 storage rate calculation model based on unsteady-state multiphase flow;

[0067] The CO2 storage rate calculation model based on steady-state unidirectional flow is:

[0068]

[0069] Where: β is the CO2 storage rate, %; v1 is the volume of injected CO2, cm 3 ; v2 is the volume of CO2 produced, cm 3 ; d is the diameter of the core, cm; L is the length of the core, cm; φ1 is the porosity of the core after static treatment, dimensionless; P2 is the pressure under the target formation conditions, MPa; Z1 is the deviation coefficient under the surface conditions, dimensionless; T1 is the temperature under the surface conditions, K; Z2 is the deviation coefficient under the target formation conditions, dimensionless; T2 is the temperature under the target formation conditions, K; P1 is the pressure under the surface conditions, MPa;

[0070] The CO2 storage rate calculation model based on unsteady multiphase flow is:

[0071]

[0072] Where: β(t) is the CO2 storage rate under time t, %; v1(t) is the volume of CO2 injected under time t, cm 3 ; v2 is the volume of CO2 produced under time t, cm 3 ;k rg (S g ) is the relative permeability, 10 -3 μm 2 ; α is the stress sensitivity coefficient, MPa -1 ; σ eff (z,t) is the effective stress at reservoir depth z and time t, MPa; V L is the Langmuir volume, m 3 / kg; P(τ) is the pressure corresponding to the moment τ, MPa; P L is the Langmuir pressure, MPa; φ(z) is the core porosity at reservoir depth z, dimensionless; z is the reservoir depth, m; τ is the time integral variable, s; S g (z,t) is the stored CO2 saturation at reservoir depth z and time t, dimensionless; P(z,t) is the pressure at reservoir depth z and time t, MPa; Z(P(z,t),T(z,t)) is the deviation coefficient at pressure P(z,t) and temperature T(z,t), dimensionless; T(z,t) is the temperature at reservoir depth z and time t, K.

[0073] In the above embodiment, the CO2 storage rate calculation model based on steady-state unidirectional flow shown in formula (1) takes into account the rock-CO2-water reaction and the separation of CO2 and methane. The CO2 storage rate calculation model based on unsteady multiphase flow shown in formula (2) not only takes into account the rock-CO2-water reaction and the separation of CO2 and methane, but also takes into account the adsorption effect. The CO2 storage rate calculation model based on unsteady multiphase flow is derived by the following steps:

[0074] First, based on the unsteady multiphase mass conservation equation, we can obtain:

[0075]

[0076] Where: is the net outflow mass of CO2 per unit volume of core, kg; φ is the porosity of the core, dimensionless; S g is the CO2 saturation of the storage, dimensionless; ρ g is the density of CO2, kg / m 3 ;q ads is the mass loss of CO2 due to adsorption, kg;

[0077] Gas phase flow rate v g Corrected by Darcy's law:

[0078]

[0079] Where: k is the absolute permeability, 10 -3 μm 2 ;μ g is the gas viscosity, mPa·s; is the pressure gradient, MPa / m;

[0080] Considering the adsorption of gas molecules by rocks, the Langmuir adsorption model is adopted, and the adsorption capacity per unit rock is:

[0081]

[0082] The cumulative adsorption amount is obtained by integrating the time:

[0083]

[0084] Considering the stress sensitivity effect, the effective stress coefficient σ is introduced eff , the local permeability is:

[0085]

[0086] Where: k0 is the basic permeability, 10 -3 μm 2 ;

[0087] The deviation coefficient Z is calculated using the Peng-Robinson equation of state, making it dependent on the local P(z,t) and T(z,t):

[0088] Z=Z(P(z,t),T(z,t)) (8)

[0089] Substituting equations (3)-(8) into the calculation model shown in equation (1), integrating the porosity φ longitudinally, and integrating the CO2 injection and production volumes (v1 and v2), pressure P, and temperature T over time, we can obtain the CO2 storage rate calculation model based on unsteady multiphase flow shown in equation (2).

[0090] In a specific embodiment, the method further includes evaluating the suitability of the reservoir for CO2 geological storage based on the CO2 sequestration rate. The greater the CO2 sequestration rate, the more suitable the reservoir is for CO2 geological storage. Optionally, the evaluation of the suitability of the reservoir for CO2 geological storage may also be conducted in combination with the dissolution rate and the permeability improvement value. The dissolution rate is calculated based on the core mass before and after flooding, and the permeability improvement value is calculated based on the core permeability before and after flooding.

[0091] In a specific embodiment, taking the W gas field as an example, the method for simulating and calculating the CO2 storage rate of a depleted gas reservoir according to the present invention is used to determine the core dissolution rate, porosity and permeability changes, and CO2 storage rate of the target reservoir before and after the reaction of the gas field, which specifically includes the following steps:

[0092] (1) Obtain target layer cores (three cores from the same well, the same layer, but different depths), and prepare formation water samples, methane samples, and CO2 samples. In this embodiment, the basic physical properties of the target layer cores are shown in Table 1:

[0093] Table 1 Basic physical properties of target layer cores

[0094] Serial number Core number Dry weight (g) Length (mm) Diameter (mm) Porosity <![CDATA[Permeability (10 -3 μm 2 )]]> 1 Z-11 61.8119 47.1 25.90 5.3461 0.0147 2 Z-23 48.1743 38.1 26.1 4.7748 0.0133 3 Z-9 56.6805 44.5 25.7 6.1415 0.0156

[0095] (2) petroleum ether solution, formation water sample, methane sample and CO2 sample are respectively placed in the first intermediate container, the second intermediate container, the third intermediate container and the fourth intermediate container, and a full-diameter core CT scanner and a computer processing system are used to perform a full-range scan of each section of the target layer core. The core cross-sectional image is processed by the computer processing system to finally obtain the initial core pore throat diameter distribution curve and the core three-dimensional reconstructed image;

[0096] (3) Vacuum the core and saturate the formation water: open the one-way valve of the vacuum system, use a vacuum pump to vacuum the core of the target layer for more than 5 hours, and close the one-way valve; open the one-way valve of the confining pressure system and keep the pressure constant at 35 MPa; open the inlet and outlet control valves and the one-way valve of the formation water injection unit, and keep the inlet pressure constant at 20 MPa to saturate the core with formation water for at least 30 minutes;

[0097] (4) Performing a methane displacement experiment to simulate the gas reservoir formation process: closing the valve opened in step (3), opening the inlet and outlet control valves and the one-way valve of the methane injection unit, and performing a methane displacement experiment at a constant injection rate of 0.1 mL / min to simulate the gas reservoir formation process until water no longer flows out of the outlet;

[0098] (5) Conducting a CO2 displacement experiment to form a depleted gas reservoir: Close the valve opened in step (4), open the inlet and outlet control valves and the one-way valve of the CO2 injection unit, and conduct a CO2 displacement experiment at a constant injection rate of 0.1 mL / min to simulate the gas reservoir development process. When the CH4 production rate is less than 5% of the CO2 production rate, the gas reservoir is considered to be depleted;

[0099] (6) Close all the outlet and inlet valves, keep the pressure constant for 3 days, and perform cross-sectional scanning using a full-diameter CT scanner to output the core pore throat diameter distribution curve and the core three-dimensional reconstructed image, as well as the porosity φ1;

[0100] (7) Take out the core and record the weight m1 at this time. The core dissolution rate is calculated and the results are shown in Table 2 and Figure 3 As shown:

[0101] Table 2 Calculation results of the dissolution rate of the target reservoir core

[0102] Serial number Core number Dry weight (g) Weight after reaction (g) Dissolution rate (%) 1 Z-11 61.8119 59.4699 3.7889 2 Z-23 48.1743 45.7846 4.9605 3 Z-9 56.6805 54.2864 4.2239

[0103] (8) A displacement experiment was conducted on the core. The volume of CO2 and CH4 produced was monitored by a gas flow meter. The permeability, porosity and permeability improvement values ​​after the reaction were calculated. The results are shown in Table 3 and Figure 4 As shown:

[0104] Table 3 Calculation results of permeability and porosity-permeability improvement values ​​of target reservoir cores

[0105]

[0106] (9) The volume of CO2 and CH4 produced was monitored by a gas flow meter, and the effective CO2 storage rate during the storage process was calculated using the CO2 storage rate calculation model shown in formula (1). The results are shown in Table 4 and Figure 3 As shown:

[0107] Table 4 Calculation results of effective CO2 storage rate of target reservoir core

[0108] Serial number Core number <![CDATA[Volume of CO2 injected (cm 3 )]]> <![CDATA[Volume of CO2 produced (cm 3 )]]> Effective storage rate (%) 1 Z-11 144.38 144.21 13.1496 2 Z-23 144.52 144.32 21.3782 3 Z-9 144.26 144.13 9.4198

[0109] The above-mentioned effective burial rate, dissolution rate, and permeability improvement values ​​indicate that the core dissolution rate of this layer is low after the reaction, indicating that the rock stability of this layer is good and suitable for CO2 geological storage. The effective burial rate also shows that different cores in this layer have good burial rates, further indicating that the reservoir in this layer is suitable for CO2 geological storage. In addition, the permeability improvement value shows that the permeability has been greatly improved after the reaction, which can be beneficial for improving the recovery rate of depleted gas reservoirs by injecting CO2.

[0110] It should be noted that since the W gas field is carbonate rock, its stress sensitivity and adsorption effect can be ignored. Therefore, in the above embodiment, the CO2 burial rate calculation model shown in formula (1) is used to calculate the effective burial rate of CO2 during the burial process; when the present invention calculates the burial rate of other reservoirs such as shale reservoirs, its adsorption effect is more obvious, and it is more appropriate to use the CO2 burial rate calculation model shown in formula (2) to calculate the effective burial rate of CO2 during the burial process.

[0111] In summary, the present invention can accurately calculate the effective CO2 storage rate before and after the reaction. Compared with the prior art, the present invention is a significant improvement.

[0112] The above description is merely a preferred embodiment of the present invention and does not constitute any form of limitation to the present invention. Although the present invention has been disclosed as a preferred embodiment as above, it is not intended to limit the present invention. Any technician familiar with this profession can make some changes or modifications to equivalent embodiments of the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modifications, equivalent changes and modifications made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention are still within the scope of the technical solution of the present invention.

Claims

1. A method for simulating and calculating the CO2 storage rate of a depleted gas reservoir, characterized in that: The following steps are involved: S1: Obtain core, formation water, methane and CO2 samples, and measure the basic physical properties of each sample; S2: Under formation conditions, the core is saturated with formation water and methane is displaced until no more water is produced; S3: Flood the core with CO2 and record the CO2 injection and production data until the core is depleted; S4: Under constant pressure conditions, the core is subjected to static treatment and the basic physical properties of the core after static treatment are measured; S5: Establish a CO2 storage rate calculation model, and calculate the CO2 storage rate based on the parameters obtained in the above steps.

2. The method for simulating and calculating the CO2 storage rate of a depleted gas reservoir according to claim 1, characterized in that: In step S1, the core is cleaned and dried before the basic physical properties of the core are tested.

3. The method for simulating and calculating the CO2 storage rate of a depleted gas reservoir according to claim 1, characterized in that: In step S1, the basic physical properties of the core include diameter, length, porosity, and permeability, and the basic physical properties of methane and CO2 include viscosity.

4. The method for simulating and calculating the CO2 sequestration rate of a depleted gas reservoir according to claim 1, characterized in that: In step S2 and step S3, the device used for displacement is a displacement device based on a gas separation membrane, which can separate methane and CO2 in the displaced gas through the gas separation membrane.

5. The method for simulating and calculating the CO2 sequestration rate of a depleted gas reservoir according to claim 4, characterized in that: The displacement device based on the gas separation membrane includes an injection system, a core clamping system, a vacuum system, a confining pressure system, a back pressure system, an output system and a data acquisition system; The injection system includes an injection pump, a formation water injection unit, a methane injection unit, and a CO2 injection unit respectively connected to the injection pump and arranged in parallel, and the output ends of the formation water injection unit, the methane injection unit, and the CO2 injection unit are connected to the input end of the core support system; The core clamping system is used to clamp the core, and the vacuum system, the confining pressure system and the back pressure system are respectively connected to the core clamping system; The output system includes a four-way valve, the input end of the four-way valve is connected to the output end of the core clamping system, and the three output ends of the four-way valve are respectively connected to a methane collection device, a CO2 collection device, and a solution collection device. A gas separation membrane is provided on the inner wall of the pipeline between the four-way valve and the methane collection device and the CO2 collection device, and the gas separation membrane allows CO2 to flow in and inhibits methane from passing through; The data acquisition system is used to collect pressure and flow rate change data during the displacement process.

6. The method for simulating and calculating the CO2 storage rate of a depleted gas reservoir according to claim 5, characterized in that: The data acquisition system further includes a CT scanner and an X-ray detector disposed in the CT scanner. The CT scanner is used to scan the rock core to obtain a pore throat diameter distribution curve and a three-dimensional reconstructed image of the rock core.

7. The method for simulating and calculating the CO2 storage rate of a depleted gas reservoir according to claim 1, characterized in that: In step S3, when the methane production rate is less than 5% of the CO2 production rate, it is considered to have reached the exhaustion state.

8. The method for simulating and calculating the CO2 storage rate of a depleted gas reservoir according to claim 1, characterized in that: In step S4, the pressure of the static treatment is 30-35 MPa, the temperature is 90-95° C., and the time is 3-4 days.

9. The method for simulating and calculating the CO2 storage rate of a depleted gas reservoir according to any one of claims 1 to 8, characterized in that: In step S5, the CO2 storage rate calculation model includes a CO2 storage rate calculation model based on steady-state unidirectional flow and a CO2 storage rate calculation model based on unsteady-state multiphase flow; The CO2 storage rate calculation model based on steady-state unidirectional flow is: Where: β is the CO2 storage rate, %; v1 is the volume of injected CO2, cm 3 ; v2 is the volume of CO2 produced, cm 3 ; d is the diameter of the core, cm; L is the length of the core, cm; φ1 is the porosity of the core after static treatment, dimensionless; P2 is the pressure under target formation conditions, MPa; Z1 is the deviation coefficient under ground conditions, dimensionless; T1 is the temperature under ground conditions, K; Z2 is the deviation coefficient under target formation conditions, dimensionless; T2 is the temperature under target formation conditions, K; P1 is the pressure under surface conditions, MPa; The CO2 storage rate calculation model based on unsteady multiphase flow is: Where: β(t) is the CO2 storage rate under time t, %; v1(t) is the volume of CO2 injected under time t, cm 3 ; v2 is the volume of CO2 produced under time t, cm 3 ;k rg (S g ) is the relative permeability, 10 -3 μm 2 ; α is the stress sensitivity coefficient, MPa -1 ; σ eff (z,t) is the effective stress at reservoir depth z and time t, MPa; V L is the Langmuir volume, m 3 / kg; P(τ) is the pressure corresponding to the moment τ, MPa; P L is the Langmuir pressure, MPa; φ(z) is the porosity of the core at the reservoir depth z, dimensionless; z is the reservoir depth, m; τ is the time integral variable, s; S g (z,t) is the stored CO2 saturation at reservoir depth z and time t, dimensionless; P(z,t) is the pressure at reservoir depth z and time t, MPa; Z(P(z,t),T(z,t)) is the deviation coefficient at pressure P(z,t) and temperature T(z,t), dimensionless; T(z,t) is the temperature at reservoir depth z and time t, in K.

10. The method for simulating and calculating the CO2 storage rate of a depleted gas reservoir according to any one of claims 1 to 9, characterized in that: It also includes a step of evaluating whether the reservoir is suitable for CO2 geological storage based on the CO2 storage rate. The greater the CO2 storage rate, the more suitable the reservoir is for CO2 geological storage.

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