Method for calculating component content of oil-gas composite system based on multi-component mass transfer partition

Abstract

The invention relates to the technical field of unconventional oil and gas development, in particular to a method for calculating the component content of an oil and gas composite system based on multi-component mass transfer zoning. According to the technical scheme, the utilization rate of CO2 in composite gas in the dynamic mass transfer process and the burying and storing amount of CO2 in a stratum are calculated in a zoning mode, and the molar content ratio of all components in crude oil is combined; according to the method, the mole number of other components is deduced, the application prospect and development potential of oil reservoir composite gas drive are rapidly judged, and the difference between the mixed phase and the immiscible phase of the composite gas under the oil reservoir condition is revealed by comparing the content of CO2 and intermediate hydrocarbon in the oil phase of the CO2-hydrocarbon gas composite gas mixed phase and immiscible phase transition zone; by increasing the relation between the water saturation of the grid and the solubility of CO2 in water, the grid dynamic partition mathematical model established by the technical scheme can be expanded to oil-gas-water three phases, and the method has wide application value in the fields of oil and gas reservoir gas injection recovery efficiency improvement and CO2 burying.

Description

Technical Field

[0001] The present invention relates to the technical field of unconventional oil and gas development, and in particular to a method for calculating the component contents of an oil and gas composite system based on multi-component mass transfer zoning. Background Art

[0002] Xinjiang's low-permeability conglomerate reservoirs are rich in reserves and have great potential for oil and gas development. However, the current natural productivity of fractured horizontal wells is low and the production declines rapidly. Field test results show that gas injection can significantly improve reservoir recovery, but due to the limitation of carbon sources, the feasibility of large-scale CO2 flooding is poor, and single gas flooding is difficult to meet the needs of Xinjiang's low-permeability reservoirs to supplement formation energy with gas injection. Considering the high saturation pressure of the reservoir, severe degassing in the early stage of exhaustion production, and the wellhead produced gas being a hydrocarbon gas with a high CH4 content, it is urgent to carry out an adaptability evaluation of the CO2-hydrocarbon gas composite technology. The research on the oil-increasing mechanism of the composite system of CO2-hydrocarbon gas and crude oil is mainly carried out through indoor experiments and numerical simulations. Indoor experiments are complicated to operate and are not suitable for field applications; numerical modeling requires a large amount of geological data and a long simulation time; while reservoir fluids are easy to obtain. By studying the dynamic mass transfer process of the composite gas-crude oil system, the application prospects and development potential of the composite gas flooding of the reservoir can be quickly judged.

[0003] Although the existing technology provides a dynamic mass transfer theory of injected gas-crude oil, the oil-increasing mechanism of the CO2-hydrocarbon gas-crude oil composite system is still unclear. There are few studies on combining the mass transfer of oil and gas components to calculate the content of various components in the oil and gas composite system, and it is impossible to accurately calculate the dynamic utilization rate and dynamic storage capacity of CO2 during the composite gas injection process. Summary of the invention

[0004] The purpose of the present invention is to provide a method for calculating the component content of an oil-gas composite system based on multi-component mass transfer zoning, so as to solve the problem that the oil-increasing mechanism of the CO2-hydrocarbon gas-crude oil composite system is still unclear in the prior art, there is little research on calculating the content of various components in the oil-gas composite system in combination with the mass transfer of oil and gas components, and the dynamic utilization rate and dynamic storage capacity of CO2 during the composite gas injection process cannot be accurately calculated.

[0005] To achieve the above object, the present invention provides a method for calculating the component content of an oil-gas composite system based on multi-component mass transfer zoning, and the method for calculating the component content of an oil-gas composite system based on multi-component mass transfer zoning comprises the following steps:

[0006] S1: Obtain the well fluid composition from the original well fluid composition report to obtain experimental data;

[0007] S2: Based on the well flow data, using the Winprop module of CMG software, the original well flow is divided into 5-8 pseudo-components according to the principle of similar properties of components, and the fluid phase fitting is carried out for the divided pseudo-components;

[0008] S3: Import fluid parameters, establish a capillary model, match the minimum miscible pressure of injected gas with field data, and simulate the displacement front movement of CO2, hydrocarbon gas and composite gas;

[0009] S4: Based on the one-dimensional capillary model, the distribution diagram of the parameters of each component in the oil and gas mass transfer process is output, the mass transfer of the components in the immiscible or miscible transition zone of the composite gas and crude oil during the CO2-hydrocarbon gas mixed injection process is analyzed, the utilization rate of CO2 in the composite gas and the storage capacity of CO2 in the formation during the dynamic mass transfer process are calculated by partition, and the molar number of other components is deduced based on the molar content ratio of each component in the crude oil.

[0010] Wherein, in step S1, the experimental data include data of fluid high pressure physical property experiment, single degassing experiment, gas injection expansion experiment, and constant quality expansion experiment.

[0011] Among them, in step S2, the fluid phase state fitting needs to add a separator test, a two-phase flash test and a viscosity fitting test in sequence.

[0012] Among them, in step S2, when performing fluid phase fitting on the divided pseudo-components, the fitting parameters are saturation pressure, gas-oil ratio, formation temperature-pressure volume coefficient, surface crude oil density, formation crude oil density and formation oil viscosity. The error of parameter fitting should be controlled within 5% to ensure that the calculation requirements of numerical simulation are met.

[0013] Wherein, in step S3, the relative error of matching the minimum miscible pressure of the injected gas with the field data is within 5%.

[0014] Among them, in step S3, the injection gas displacement front moves. Under the condition of the same injection amount, the front movement distances of different injection media at the same time should be compared. By comparing the fluidity of CO2, hydrocarbon gas and composite gas, the influence of CO2 on the flow capacity of the composite system can be judged.

[0015] The specific steps of step S4 are as follows:

[0016] Taking the injection well end of a one-dimensional capillary tube as the starting point and the production well end as the end point, the grid distance is dimensionless along the injection and production direction, and the relationship between the molar content of each component in the oil phase and the dimensionless distance is output;

[0017] Based on the original composition of the well flow, by comparing the contents of CO2 and CH4 in the oil phase and the changes in oil saturation in the one-dimensional fine tube grid, the mass transfer changes of oil and gas components are divided into three regions, namely the gas phase region, the co-flow region and the oil phase region.

[0018] In the one-dimensional capillary model, a mathematical model of dynamic grid partitioning is established based on the grid attributes to quickly calculate the number of CO2 moles in different partitions.

[0019] The injection displacement pressure of the capillary model was changed to 20 MPa, and the mass transfer of immiscible oil and gas components during gas injection was simulated. The molar number of CO2 was calculated using the dynamic partition mathematical model, and the molar number of other components was deduced based on the molar content ratio of each component in crude oil.

[0020] The gas injection displacement pressure of the capillary model was changed to 35 MPa, and the mass transfer of components in the transition zone of composite gas-crude oil was simulated. The molar number of CO2 was calculated using the grid dynamic partition mathematical model, and the molar number of other components was deduced based on the molar content ratio of each component in crude oil.

[0021] A comprehensive comparison of the CO2 and intermediate hydrocarbon contents in the oil phase of the CO2-hydrocarbon composite gas miscible phase and the immiscible phase transition zone reveals the differences between the composite gas miscible phase and the immiscible phase under reservoir conditions.

[0022] In step S4, the established mathematical model of dynamic grid partitioning is as follows:

[0023] n=w*Ahφρ[S g +(1-S g )m in-oil ] / M

[0024] Where n is the number of moles of CO2; w is the molar ratio of CO2 in the oil phase, %; A is the area of ​​a single grid of one-dimensional capillary tube, cm 2 ; h is the height of a single grid of one-dimensional capillary tube, cm; φ is the porosity of the capillary model; ρ is the supercritical CO2 density, g / cm 3 ; S g is the grid gas saturation; m in-oil is the solubility of CO2 in crude oil; M is the molar mass of CO2, g / mol.

[0025] The present invention discloses a method for calculating the component contents of an oil and gas composite system based on multi-component mass transfer zoning. The method calculates the utilization rate of CO2 in the composite gas and the storage amount of CO2 in the formation during the dynamic mass transfer process by zoning through the technical solution. Combined with the molar content ratio of each component in the crude oil, the molar number of other components is deduced, and the application prospect and development potential of composite gas drive in the reservoir are quickly determined. The method also reveals the difference between the composite gas miscible phase and the immiscible phase under reservoir conditions by comparing the CO2-hydrocarbon gas composite gas miscible phase and the CO2 intermediate hydrocarbon content in the oil phase in the immiscible transition zone. The mathematical model of grid dynamic zoning established by the present invention can be expanded to the three phases of oil-gas-water by increasing the relationship between the grid water saturation and the solubility of CO2 in water. The mathematical model has a wide range of application value in the fields of gas injection to enhance oil and gas recovery and CO2 storage in oil and gas reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0026] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0027] Figure 1 It is a flow chart of the steps of a method for calculating the component contents of an oil-gas composite system based on multi-component mass transfer zoning provided by the present invention.

[0028] Figure 2 It is a flow chart of the steps of the multi-component mass transfer partition calculation method provided by the present invention.

[0029] Figure 3 It is a three-dimensional schematic diagram of the one-dimensional capillary model provided by the present invention.

[0030] Figure 4 It is a schematic diagram of the results of simulating the minimum miscible pressure of different injected gases and crude oil by the capillary provided by the present invention.

[0031] Figure 5 It is a schematic diagram of the relationship between the oil saturation distribution of the capillary tube model with different gas injection media 0.42PV injection volume provided by the present invention and the displacement front of the gas injection medium.

[0032] Figure 6 It is a schematic diagram of the relationship between the molar content of each component in the oil phase and the dimensionless distance under the condition of CO2-hydrocarbon composite gas injection non-miscible phase provided by the present invention.

[0033] Figure 7 It is a schematic diagram of the relationship between the molar content of each component in the oil phase and the dimensionless distance in the CO2-hydrocarbon gas composite gas mixed phase transition zone provided by the present invention.

[0034] Figure 8 It is a comparison curve diagram of CO2 and intermediate hydrocarbon content in the oil phase of the transition zone between the mixed phase (35MPa) and the immiscible phase (20MPa) of the CO2-hydrocarbon gas composite gas provided by the present invention. DETAILED DESCRIPTION

[0035] Embodiments of the present invention are described in detail below, examples of which are shown in the accompanying drawings, wherein the same or similar reference numerals throughout represent the same or similar elements or elements having the same or similar functions. The embodiments described below with reference to the accompanying drawings are exemplary and are intended to be used to explain the present invention, and should not be construed as limiting the present invention.

[0036] See also Figures 1 to 8The present invention provides a method for calculating the component content of an oil-gas composite system based on multi-component mass transfer zoning. The method for calculating the component content of an oil-gas composite system based on multi-component mass transfer zoning comprises the following steps:

[0037] S1: Obtain the well fluid composition from the original well fluid composition report to obtain experimental data;

[0038] S2: Based on the well flow data, using the Winprop module of CMG software, the original well flow is divided into 5-8 pseudo-components according to the principle of similar properties of components, and the fluid phase fitting is carried out for the divided pseudo-components;

[0039] S3: Import fluid parameters, establish a capillary model, match the minimum miscible pressure of injected gas with field data, and simulate the displacement front movement of CO2, hydrocarbon gas and composite gas;

[0040] S4: Based on the one-dimensional capillary model, the distribution diagram of the parameters of each component in the oil and gas mass transfer process is output, the mass transfer of the components in the immiscible or miscible transition zone of the composite gas and crude oil during the CO2-hydrocarbon gas mixed injection process is analyzed, the utilization rate of CO2 in the composite gas and the storage capacity of CO2 in the formation during the dynamic mass transfer process are calculated by partition, and the molar number of other components is deduced based on the molar content ratio of each component in the crude oil.

[0041] In this embodiment, the utilization rate of CO2 in the composite gas and the storage amount of CO2 in the formation in the dynamic mass transfer process are calculated by partitioning through the technical solution. Combined with the molar content ratio of each component in the crude oil, the molar number of other components is deduced, and the application prospect and development potential of the composite gas drive in the reservoir are quickly judged. By comparing the CO2 and intermediate hydrocarbon content in the oil phase of the CO2-hydrocarbon composite gas mixed phase and the immiscible transition zone, the difference between the composite gas mixed phase and the immiscible phase under reservoir conditions is revealed. By increasing the relationship between the grid water saturation and the solubility of CO2 in water, the grid dynamic partitioning mathematical model established by the technical solution can be extended to the oil-gas-water three-phase, which has a wide range of application value in the field of gas injection to enhance recovery and CO2 storage in oil and gas reservoirs.

[0042] Among them, the WinProp module is used to simulate the phase characteristics of fluids, and simulate the interaction between underground oil and gas reservoir fluids and injected fluids based on the equation of state (EOS). The data obtained can be used in CMG's numerical simulator to further improve the understanding of the oil and gas reservoir development process. In particular, WinProp can accurately characterize the oil and gas reservoir fluid system through fitting calculations or laboratory PVT experiments, miscible phase research, and ground separator facility simulations. These data help to better understand the interaction between the oil and gas reservoir production fluid and the fluid being studied.

[0043] Furthermore, the specific content of step S1 is: sorting out the composition of the original well flow, obtaining the data of the fluid high-pressure physical property experiment, the single degassing experiment, the gas injection expansion experiment, and the constant quality expansion experiment; in particular, the data of the composition of the original well flow is shown in Table 1. The fluid high-pressure physical property experiment data includes the crude oil volume coefficient, the single degassing experiment data includes the saturation pressure, gas-oil ratio, surface oil density, formation oil density and formation oil viscosity, the gas injection expansion experiment data includes the crude oil saturation pressure and expansion coefficient, and the constant quality expansion experiment data includes the relative volume of crude oil under different pressures.

[0044] Table 1 Composition data of original well flow

[0045]

[0046] Furthermore, the specific content of step S2 is: based on the well flow data, using the CMG software Winprop module, according to the principle of similar properties of the components, the original well flow is divided into 5-8 pseudo-components, and the fluid phase fitting is carried out on the divided pseudo-components; in particular, according to the principle of similar properties of the components, the numerical simulation operation speed of the composite gas drive of the fractured horizontal well should be considered at the same time, and finally the original well flow is divided into 5 pseudo-components, namely: 0.04% CO2, 0.26% N2, 35.24% CH4, 42.38% C2-C6 and 22.08% C7+, as shown in Table 2.

[0047] Table 2 Molar composition of pseudo-components

[0048]

[0049] Among them, a single degassing experiment fitting was carried out for the divided pseudo-components, and the separator test (saturation pressure, gas-oil ratio and crude oil volume coefficient fitting) and two-phase flash test (formation oil density and surface oil density fitting) were added in sequence, and finally the viscosity fitting test was added. In view of the characteristics of high saturation pressure, high gas-oil ratio and low viscosity of the block reservoir, the fitting degree of saturation pressure and gas-oil ratio was focused on. The fitting error of key parameters was less than 1%, and the fitting error of other parameters was within 5%, which met the requirements of numerical simulation calculations, as shown in Table 3.

[0050] Table 3 Fluid phase fitting results

[0051]

[0052] Furthermore, the specific contents of step S3 are: importing fluid parameters, establishing a capillary model, matching the minimum miscible pressure of injected gas with field data, and simulating the displacement front movement of CO2, hydrocarbon gas and composite gas.

[0053] The slim tube model is 20 m long, with a model grid of 50×1×1, a step size of 0.4 m in the X direction, and 0.003545 m in the Y and Z directions; the average porosity of the model is 0.35, and the average permeability is 1100 mD. A gas injection well is set at the initial end of the slim tube model, and a production well is set at the end. Figure 3 shown.

[0054] The temperature of the capillary model was set to 77°C, and the gas was injected at a rate of 4.42 cm 3 / h is injected from the initial end to simulate the change of oil recovery factor under different displacement pressures, and the relationship between displacement pressure and oil recovery factor is obtained. Taking 90% recovery factor as the limit, the pressure corresponding to the intersection of the fitting curves is defined as the minimum miscibility pressure of the injected gas by fitting the data points before and after the limit.

[0055] Reference Figure 4 The results of the capillary simulation of the minimum miscibility pressure of injected gas-crude oil show that the minimum miscibility pressure of injected CO2 is 23.3MPa, with a relative error of 2.08% from the field test results; the minimum miscibility pressure of injected hydrocarbon gas is 40.1MPa, with a relative error of 2.82% from the field test results. The error of the minimum miscibility pressure of a single gas medium meets the simulation requirements, and the predicted minimum miscibility pressure of a 1:1 composite gas of CO2-hydrocarbon gas is 33.6MPa, which is less than the original formation pressure of the reservoir and meets the requirements of miscible displacement.

[0056] Reference Figure 5 , the relationship between the oil saturation distribution of the capillary model with different gas injection media 0.42PV injection volume and the displacement front of the gas injection medium. It can be found that with the same gas injection volume, the gas injection medium is changed, the movement distance of the gas drive front in the capillary model is different, and the distribution of oil saturation in the stage is also different. The movement distance of the CO2 displacement front is 10.4m, and the oil saturation of the front is 0.48; the composite gas displacement front distance is 9.6m, and the oil saturation of the front is 0.52; the hydrocarbon gas displacement front distance is 8.8m, and the oil saturation of the front is 0.55. The results show that under the same gas injection volume conditions in the immiscible process, the movement distance of the CO2 displacement front is 1.18 times that of the hydrocarbon gas, and the movement distance of the composite gas displacement front is 1.09 times that of the hydrocarbon gas, indicating that CO2 has better fluidity than hydrocarbon gas, and can improve the flow capacity of the composite system, which shows the application potential of composite gas drive in the target reservoir.

[0057] Furthermore, the specific steps of step S4 are as follows:

[0058] S41: With the injection well end of the one-dimensional capillary tube as the starting point and the production well end as the end point, the grid distance is dimensionless along the injection and production direction, and a relationship diagram between the molar content of each component in the oil phase and the dimensionless distance is output;

[0059] S42: Based on the original composition of the well flow, by comparing the contents of CO2 and CH4 in the oil phase and the changes in oil saturation in the one-dimensional fine tube grid, the mass transfer changes of oil and gas components are divided into three regions, namely the gas phase region, the co-flow region and the oil phase region;

[0060] S43: In the one-dimensional capillary model, a mathematical model of dynamic grid partitioning is established based on the grid properties to quickly calculate the number of CO2 moles in different partitions;

[0061] S44: Changing the injection displacement pressure of the capillary model to 20 MPa, simulating the mass transfer of immiscible oil and gas components during injection, calculating the molar number of CO2 using a dynamic partitioning mathematical model, and deriving the molar number of other components based on the molar content ratio of each component in crude oil;

[0062] S45: Change the gas injection displacement pressure of the capillary model to 35MPa, simulate the mass transfer of components in the transition zone of composite gas-crude oil miscible phase, calculate the molar number of CO2 using the grid dynamic partition mathematical model, and deduce the molar number of other components based on the molar content ratio of each component in crude oil;

[0063] S46: Comprehensive comparison of CO2 and intermediate hydrocarbon contents in the oil phase of the CO2-hydrocarbon composite gas miscible phase and the immiscible phase transition zone, revealing the differences between the composite gas miscible phase and the immiscible phase under reservoir conditions.

[0064] In this embodiment, the gas phase area is close to the injection well end, the pressure in the area is high, and only the CO2 phase exists, which belongs to the miscible phase area; affected by the CO2 injection, the grid oil saturation is 0, the crude oil is completely displaced, and the CO2 in the gas phase area exists in a free state. The co-flow area is located between the injection well end and the production well end, and there are two phases of oil and gas in the area, which belongs to the immiscible phase area; as the CO2 front continues to contact with the crude oil, the oil recovery efficiency gradually increases, and the oil saturation gradually decreases, but it is always greater than 0. At this time, CO2 exists in a free state and dissolved state in the two-phase co-flow area. The oil phase area is close to the production well end, the injected gas has not yet contacted the crude oil, and only the crude oil phase exists, the oil saturation remains unchanged, and the CO2 molar content in the oil phase is 0.

[0065] In particular, the mathematical model of dynamic grid partitioning is established as follows:

[0066] n=w*Ahφρ[S g +(1-S g )m in-oil ] / M

[0067] Where n is the number of moles of CO2; w is the molar ratio of CO2 in the oil phase, %; A is the area of ​​a single grid of one-dimensional capillary tube, cm 2 ; h is the height of a single grid of one-dimensional capillary tube, cm; φ is the porosity of the capillary model; ρ is the supercritical CO2 density, g / cm 3 ; Sg is the grid gas saturation; m in-oil is the solubility of CO2 in crude oil; M is the molar mass of CO2, g / mol.

[0068] In particular, the basic parameters required for the calculation of the mathematical model of dynamic grid partitioning are shown in Table 4.

[0069] Table 4 Basic parameters for partition calculation

[0070]

[0071] In particular, the injection displacement pressure of the capillary model was changed to 20 MPa to simulate the mass transfer of immiscible oil and gas components during injection. Figure 6 The relationship between the molar content of each component in the oil phase and the dimensionless distance under the condition of CO2-hydrocarbon gas composite gas injection. It can be found that in the gas phase area, CO2 (25.8%), CH4 (13.8%), intermediate hydrocarbons (7.6%) and C7+ components (52.8%) exist in the oil phase. The gas phase area ranges from 0 to 4 m, with a total of 10 grids. The calculated molar number of CO2 in the gas phase area is 0.0462 mol, the calculated molar number of CH4 in the gas phase area is 0.0247 mol, the molar number of intermediate hydrocarbons is 0.0136 mol, and the molar number of C7+ is 0.0946 mol. In the two-phase co-flow area, the oil and gas components are in a dynamic mass transfer process. The two-phase co-flow area ranges from 4 to 13.6 m, with a total of 24 grids. The dimensionless distance of the one-dimensional capillary is 0.5102, corresponding to the 25th grid (10m) in the one-dimensional capillary, the gas saturation is 0.43, the molar content of CO2 in the oil phase accounts for CO2 (20.5%), CH4 (16.9%), intermediate hydrocarbons (35.2%) and C7+ components (27.4%) in the oil phase. The calculated molar number of CO2 in this grid is 0.0022mol, the calculated molar number of CH4 in this grid is 0.0018mol, the molar number of intermediate hydrocarbons is 0.0037mol, and the molar number of C7+ is 0.0029mol. From the gas phase area to the two-phase co-flow area, the heavy hydrocarbon component (C7+) of crude oil is gradually extracted into the gas phase, and the molar number of C7+ in a single grid decreases from 0.0095mol to 0.0029mol, the molar content of hydrocarbon components in the oil phase decreases, and the gas phase is continuously enriched. On the right side of the two-phase region, the injected gas enters the pure oil flow region through diffusion, and CH4 (27.3%), intermediate hydrocarbons (42.3%) and C7+ components (29.9%) exist in the oil phase. The injected gas diffused into the oil phase reduces the density and viscosity of the crude oil. Compared with the original well flow, the CH4 molar content of the oil phase in the pure oil flow region decreases by 7.9%, the intermediate hydrocarbon content remains almost unchanged, and the C7+ component molar content increases by 7.8%, which may be caused by the degassing of crude oil when the capillary model pressure is less than the saturation pressure.

[0072] In particular, the injection displacement pressure of the capillary model was changed to 35 MPa to simulate the mass transfer of components in the transition zone of composite gas-crude oil miscible phase. Figure 7 The relationship between the molar content of each component in the oil phase and the dimensionless distance in the CO2-hydrocarbon gas composite gas mixed phase transition zone. It can be found that in the gas phase area, CO2 (44.6%), CH4 (38.6%), intermediate hydrocarbons (8.9%) and C7+ components (7.9%) exist in the oil phase. The gas phase area ranges from 0 to 6 m, with a total of 15 grids. The calculated molar number of CO2 in the gas phase area is 0.1198 mol, the calculated molar number of CH4 in the gas phase area is 0.1037 mol, the molar number of intermediate hydrocarbons is 0.0239 mol, and the molar number of C7+ is 0.0212 mol. In the two-phase co-flow area, the oil and gas components are in a dynamic mass transfer process. The two-phase co-flow area ranges from 6 to 10.8 m, with a total of 12 grids. The molar content of CO2 in the oil phase decreases from 44.6% to 0%, the molar content of CH4 decreases from 38.6% to 15.9%, and the molar content of intermediate hydrocarbons increases from 8.9% to 40.8%, indicating that after the composite gas displacement, the crude oil has a stronger ability to dissolve CO2 than CH4, and the composite gas can significantly reduce the intermediate hydrocarbon content of the crude oil and increase the fluidity of the crude oil. Since the target reservoir crude oil is light oil, the composite gas has a weak effect on the extraction of the heavy components (C7+) of light oil.

[0073] Reference Figure 8 The figure is a comparison curve of CO2 and intermediate hydrocarbon content in the oil phase of the transition zone between the mixed phase (35MPa) and the immiscible phase (20MPa) of the CO2-hydrocarbon gas composite gas. By comparing the two-phase co-flow area of ​​the composite gas miscible drive and the immiscible drive, it is found that the two-phase co-flow area under the miscible pressure condition (miscible co-flow area < immiscible co-flow area) is smaller, indicating that the intense oil and gas component mass transfer process is completed in a short time, and then the injected gas and crude oil are mixed, and finally a single-phase flow is formed. By comparing the oil phase components in the transition zone between the miscible and immiscible phases, it is found that the molar number of CO2 in the gas phase area in the miscible phase stage (0.1198mol) is 2.56 times that in the immiscible phase stage (0.0462mol), indicating that under the high pressure conditions of the reservoir, the oil and gas miscibility is conducive to increasing the utilization rate of CO2 in the composite gas and increasing the storage capacity of CO2 in the reservoir.

[0074] What is disclosed above is only a preferred embodiment of the present invention, and it certainly cannot be used to limit the scope of rights of the present invention. Ordinary technicians in this field can understand that all or part of the processes of the above embodiment and equivalent changes made according to the claims of the present invention still fall within the scope of the invention.

Claims

1. A method for calculating the component content of an oil-gas composite system based on multi-component mass transfer zoning, characterized in that: The steps include: S1: Obtain the well fluid composition from the original well fluid composition report to obtain experimental data; S2: Based on the well flow data, using the Winprop module of CMG software, the original well flow is divided into 5-8 pseudo-components according to the principle of similar properties of components, and the fluid phase fitting is carried out for the divided pseudo-components; S3: Import fluid parameters, establish a capillary model, match the minimum miscible pressure of injected gas with field data, and simulate the displacement front movement of CO2, hydrocarbon gas and composite gas; S4: Based on the one-dimensional capillary model, the distribution diagram of the parameters of each component in the oil and gas mass transfer process is output, the mass transfer of the components in the immiscible or miscible transition zone of the composite gas and crude oil during the CO2-hydrocarbon gas mixed injection process is analyzed, the utilization rate of CO2 in the composite gas and the storage capacity of CO2 in the formation during the dynamic mass transfer process are calculated by partition, and the molar number of other components is deduced based on the molar content ratio of each component in the crude oil.

2. The method for calculating the component content of an oil-gas composite system based on multi-component mass transfer zoning according to claim 1, characterized in that: In step S1, the experimental data include data of a fluid high-pressure physical property experiment, a single degassing experiment, a gas injection expansion experiment, and a constant-quality expansion experiment.

3. The method for calculating the component content of the oil-gas composite system based on multi-component mass transfer zoning according to claim 2, characterized in that: In step S2, the fluid phase state fitting needs to add a separator test, a two-phase flash test and a viscosity fitting test in sequence.

4. The method for calculating the component content of an oil-gas composite system based on multi-component mass transfer zoning according to claim 3, characterized in that: In step S2, when performing fluid phase fitting on the divided pseudo-components, the fitting parameters are saturation pressure, gas-oil ratio, formation temperature-pressure volume coefficient, surface crude oil density, formation crude oil density and formation oil viscosity. The error of parameter fitting should be controlled within 5% to ensure that the computational requirements of numerical simulation are met.

5. The method for calculating the component content of the oil-gas composite system based on multi-component mass transfer zoning according to claim 3, characterized in that: In step S3, the relative error of matching the minimum miscible pressure of the injected gas with the field data is within 5%.

6. The method for calculating the component contents of an oil-gas composite system based on multi-component mass transfer zoning according to claim 3, characterized in that: In step S3, the injection gas displacement front moves. Under the condition of the same injection amount, the front movement distances of different injection media at the same time should be compared. By comparing the fluidity of CO2, hydrocarbon gas and composite gas, the influence of CO2 on the flow capacity of the composite system can be determined.

7. The method for calculating the component contents of an oil-gas composite system based on multi-component mass transfer zoning according to claim 3, characterized in that: The specific steps of step S4 are as follows: Taking the injection well end of a one-dimensional capillary tube as the starting point and the production well end as the end point, the grid distance is dimensionless along the injection and production direction, and the relationship between the molar content of each component in the oil phase and the dimensionless distance is output; Based on the original composition of the well flow, by comparing the contents of CO2 and CH4 in the oil phase and the changes in oil saturation in the one-dimensional fine tube grid, the mass transfer changes of oil and gas components are divided into three regions, namely the gas phase region, the co-flow region and the oil phase region. In the one-dimensional capillary model, a mathematical model of dynamic grid partitioning is established based on the grid attributes to quickly calculate the number of CO2 moles in different partitions. The injection displacement pressure of the capillary model was changed to 20 MPa, and the mass transfer of immiscible oil and gas components during gas injection was simulated. The molar number of CO2 was calculated using the dynamic partition mathematical model, and the molar number of other components was deduced based on the molar content ratio of each component in crude oil. The gas injection displacement pressure of the capillary model was changed to 35 MPa, and the mass transfer of components in the transition zone of composite gas-crude oil was simulated. The molar number of CO2 was calculated using the grid dynamic partition mathematical model, and the molar number of other components was deduced based on the molar content ratio of each component in crude oil. A comprehensive comparison of the CO2 and intermediate hydrocarbon contents in the oil phase of the CO2-hydrocarbon composite gas miscible phase and the immiscible phase transition zone reveals the differences between the composite gas miscible phase and the immiscible phase under reservoir conditions.

8. The method for calculating the component contents of an oil-gas composite system based on multi-component mass transfer partitioning according to claim 7, characterized in that: In step S4, the established grid dynamic partitioning mathematical model is as follows: n=w*Ahφρ[S g +(1-S g )m in-oil ] / M Where n is the number of moles of CO2; w is the molar ratio of CO2 in the oil phase, %; A is the area of ​​a single grid of one-dimensional capillary tube, cm 2 ; h is the height of a single grid of one-dimensional capillary tube, cm; φ is the porosity of the capillary model; ρ is the supercritical CO2 density, g / cm 3 ; S g is the grid gas saturation; m in-oil is the solubility of CO2 in crude oil; M is the molar mass of CO2, g / mol.

Images