Method for quantitatively evaluating tight sandstone oil-gas migration based on multi-physics field simulation numerical simulation

Abstract

The invention provides a method for quantitatively evaluating tight sandstone oil-gas migration based on multi-physics field simulation numerical simulation, which comprises the following steps: comprehensively judging the reservoir forming period of a research area through a fluid inclusion uniform temperature experiment in combination with a Petromod basin numerical simulation result; on the basis of obtaining the reservoir forming period of the oil reservoir, determining the porosity, permeability and pore pressure of the reservoir forming period of the oil reservoir; on the basis of obtaining the porosity, the permeability and the pore pressure in the reservoir forming period of the oil reservoir, constructing a finite element plane model of the research area by utilizing Comsol multi-physics field simulation software, constructing a porosity, permeability and pore pressure interpolation function, and carrying out fluid migration by adopting a Rietz equation; and comparing the actual distribution condition of the oil reservoir in the research area with the peak convergence area of the fluid pressure field and the fluid velocity field obtained by simulation to judge a potential oil reservoir distribution area. The result obtained by the method provided by the invention is more accurate and more scientific than the result obtained by determining the upper limit of the well drilling burial depth of the favorable area only by experience in the past.

Description

Technical Field

[0001] The present invention belongs to the technical field of unconventional oil and gas exploration, and in particular, relates to a method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation. Background Art

[0002] Tight oil is an important unconventional oil and gas resource. China currently has large oil and gas resources in tight sandstone reservoirs and high recoverable resources. Analyzing the formation period and migration path of such oil and gas reservoirs plays a vital role in guiding the exploration of potential oil and gas reservoirs.

[0003] In recent years, many domestic oil and gas basins have conducted intensive exploration of tight sandstone reservoirs and discovered large-scale oil reservoirs. Tight sandstone reservoirs are spatially affected by sedimentary phases and geological structures, and the migration characteristics of oil and gas are still unclear. This series of problems restricts the next exploration plan of tight sandstone reservoirs. In the existing technology, most of the research on oil and gas migration is still in the stage of geochemical feature identification and logging identification. A few numerical simulation methods only consider a single physical field such as porosity or permeability, and the simulation results cannot truly reflect the law of oil and gas migration in tight sandstone. Therefore, there is an urgent need for an effective method based on multi-physical field numerical simulation analysis of oil and gas migration to guide further exploration. Summary of the invention

[0004] In response to the above problems, an embodiment of the present application provides a method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation.

[0005] The embodiment of the present application provides a method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physics field simulation numerical simulation, including: S101, comprehensively judging the reservoir formation period of the study area through fluid inclusion homogenization temperature experiment combined with the numerical simulation results of the Petromod basin; S103, determining the porosity, permeability and pore pressure of the study area during the reservoir formation period on the basis of obtaining the reservoir formation period of the study area; S105, constructing a finite element plane model of the study area using Comsol multi-physics field simulation software, constructing porosity, permeability and pore pressure interpolation functions, and using Richards equation for fluid migration; S107, judging the potential reservoir distribution area by comparing the actual distribution of the reservoir in the study area with the peak convergence area of ​​the fluid pressure field and the fluid velocity field obtained by simulation.

[0006] Wherein, in step S101, the fluid inclusion uniform temperature experiment includes:

[0007] (1) The rock sample is made into inclusion microscopic sections with both sides polished;

[0008] (2) Observe and photograph the prepared inclusion microscopic slices under a petrographic microscope. Observe the occurrence state, type, size, shape, distribution characteristics, and percentage of gas phase in the inclusions under the microscope to select appropriate inclusions for subsequent testing and analysis;

[0009] (3) Pretreatment of inclusion microsections including soaking and cleaning to make them suitable for microthermometry analysis;

[0010] (4) Use Linkam hot and cold stages to perform microscopic temperature measurement on fluid inclusion samples to obtain the uniform temperature of the fluid inclusions.

[0011] Among them, after the Linkam hot and cold stage is used to perform microscopic temperature measurement on the fluid inclusion sample to obtain the uniform temperature of the fluid inclusion, it also includes: drawing a uniform temperature distribution histogram according to the fluid inclusion uniform temperature experimental results, and analyzing to obtain the main temperature distribution range.

[0012] Among them, in step S101, the stratification data and lithology data of the oil reservoir well locations in the study area are input into the Petromod basin simulation software, and the geological evolution history of the oil reservoir well locations can be obtained by clicking "Run".

[0013] Wherein, step S101 also includes that the formation period of the oil reservoir in the study area is comprehensively judged by combining the fluid inclusion temperature experiment with the formation temperature evolution history obtained by the numerical simulation of the Petromod Basin.

[0014] Wherein, in step S103, the porosity, permeability and pore pressure of the oil reservoir in the study area during the reservoir formation period are obtained through the numerical simulation results of the Petromod basin.

[0015] Among them, in step S105, the finite element model of the study area is based on the actual research scope of the study area. Inputting it into the geometry module of the Comsol multi-physics field simulation software can directly construct the plane geometry of the study area, and then meshing is performed. The meshing method uses an extremely fine mapping grid, and finally click "Build Selected Object" to directly obtain the finite element model of the study area.

[0016] Among them, in step S105, the median values ​​of the porosity, permeability and pore pressure parameters obtained in step S103 are input into the interpolation function module of the Comsol multi-physics field simulation software, the interpolation method selects the nearest neighbor interpolation, and finally clicks "Build Selected Object" to generate the interpolation function of porosity, permeability and pore pressure.

[0017] Among them, step S105 also includes selecting the Richards equation module as the fluid simulation method, and clicking "Calculate" in the "Study" module to obtain changes in the pressure field and velocity field of fluid migration.

[0018] Among them, in step S107, the potential reservoir distribution area can be determined based on the actual distribution of the reservoir in the study area and the peak convergence area of ​​the fluid pressure field and the fluid velocity field obtained by simulation.

[0019] The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation in the embodiment of the present application has the following beneficial effects:

[0020] The present invention utilizes fluid inclusion homogenization temperature experiment and combines with the numerical simulation result of Petromod basin to comprehensively judge the reservoir formation period of the study area; on the basis of obtaining the reservoir formation period of the study area, the porosity, permeability and pore pressure of the reservoir in the study area during the reservoir formation period are determined; on the basis of obtaining the porosity, permeability and pore pressure of the reservoir in the study area during the reservoir formation period, Comsol multi-physics field simulation software is used to construct a finite element plane model of the study area, porosity, permeability and pore pressure interpolation functions are constructed, and the Richards equation is used for fluid migration; the potential reservoir distribution area can be judged according to the actual distribution of the reservoir in the study area and the peak convergence area of ​​the fluid pressure field and the fluid velocity field obtained by simulation, the simulation result can truly reflect the law of oil and gas migration in tight sandstone, and the obtained result is more accurate and scientific than the result of determining the upper limit of drilling depth in the favorable area only by experience in the past. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Figure 1 This is a schematic flow chart of a method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to an embodiment of the present application;

[0022] Figure 2 It is a schematic diagram of the temperature and pore pressure results of the simulation results in a specific embodiment of the present application;

[0023] Figure 3 A result schematic diagram of a finite element plane model of a simulation result in a specific embodiment of the present application;

[0024] Figure 4 A schematic diagram of the porosity and pore pressure results of the simulation results in a specific embodiment of the present application;

[0025] Figure 5 A schematic diagram of the fluid pressure field of the simulation results in a specific embodiment of the present application;

[0026] Figure 6 It is a schematic diagram of the result of the fluid velocity field in a specific embodiment of the present application. DETAILED DESCRIPTION

[0027] The present application is further described below in conjunction with the accompanying drawings and embodiments.

[0028] In the following introduction, the terms "first" and "second" are used for descriptive purposes only and should not be understood as indicating or implying relative importance. The following introduction provides multiple embodiments of the present invention, and different embodiments can be replaced or combined, so this application can also be considered to include all possible combinations of the same and / or different embodiments recorded. Therefore, if one embodiment includes features A, B, and C, and another embodiment includes features B and D, then this application should also be considered to include embodiments containing one or more of all other possible combinations of features A, B, C, and D, even though the embodiment may not be clearly recorded in the following text.

[0029] Embodiment 1

[0030] In the existing technology, most of the research on oil and gas migration is still at the stage of geochemical feature identification and logging identification. A few numerical simulation methods only consider a single physical field such as porosity or permeability. The simulation results cannot truly reflect the laws of oil and gas migration in tight sandstone.

[0031] like Figure 1 As shown, the present application provides a method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physics field simulation numerical simulation, including: S101, comprehensively judging the reservoir formation period of the study area through fluid inclusion homogenization temperature experiment combined with the numerical simulation results of the Petromod basin; S103, determining the porosity, permeability and pore pressure of the study area during the reservoir formation period on the basis of obtaining the reservoir formation period of the study area; S105, constructing a finite element plane model of the study area using Comsol multi-physics field simulation software, constructing porosity, permeability and pore pressure interpolation functions, and using Richards equation for fluid migration; S107, judging the potential reservoir distribution area by comparing the actual distribution of the reservoir in the study area with the peak convergence area of ​​the fluid pressure field and the fluid velocity field obtained by simulation.

[0032] This application uses Comsol multi-physics field simulation software to construct a finite element plane model of the study area, construct porosity, permeability and pore pressure interpolation functions, and use the Richards equation for fluid migration. The actual distribution of the reservoir is compared with the simulated fluid pressure field and fluid velocity field peak convergence area to determine the distribution of potential reservoirs. The results obtained through simulation can truly reflect the laws of oil and gas migration in tight sandstone. The results obtained are more accurate and scientific than the previous results of determining the upper limit of drilling depth in favorable areas based solely on experience.

[0033] Embodiment 2

[0034] In recent years, many domestic oil and gas basins have conducted intensive exploration of tight sandstone reservoirs and discovered large-scale oil reservoirs. Tight sandstone reservoirs are spatially affected by sedimentary phases and geological structures, and the migration characteristics of oil and gas are still unclear. This series of problems restricts the next exploration plan of tight sandstone reservoirs.

[0035] The present invention provides a method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation, which is specifically implemented as follows: Figure 2-6 As shown, the following steps are included:

[0036] S1: The homogenization temperature experiment of fluid inclusions is combined with the numerical simulation results of the Petromod Basin to comprehensively judge the reservoir formation period in the study area; the fluid inclusion temperature is obtained by the following steps:

[0037] (1) The rock sample is made into inclusion microscopic sections with both sides polished;

[0038] (2) Observe and photograph the prepared inclusion microscopic slices under a petrographic microscope. Observe the occurrence state, type, size, shape, distribution characteristics, and percentage of gas phase in the inclusions under the microscope to select appropriate inclusions for subsequent testing and analysis;

[0039] (3) Pre-treatment (soaking, cleaning) of the inclusion microscopic sections to make them suitable for microthermometry analysis;

[0040] (4) Use Linkam hot and cold stages to perform microscopic temperature measurement on fluid inclusion samples to obtain the uniform temperature of the fluid inclusions.

[0041] (5) Based on the results of the fluid inclusion uniform temperature experiment, a uniform temperature distribution histogram is drawn, and the main temperature distribution range is obtained by analysis.

[0042] (6) Input the stratification data and lithology data of the oil reservoir well location in the study area into the Petromod basin software and click to run to obtain the geological evolution history of the oil reservoir well location. The oil reservoir formation period in the study area is comprehensively judged by combining the fluid inclusion temperature experiment with the formation temperature evolution history obtained by numerical simulation using the Petromod multi-physics field simulation software.

[0043] S2: Based on the reservoir formation period of the study area, determine the porosity, permeability and pore pressure of the study area during the reservoir formation period:

[0044] The porosity, permeability and pore pressure during the reservoir formation period of the study area are obtained through the numerical simulation results of the Petromod Basin, which can be directly obtained in the “input” module of the Petromod Basin software to serve as the initial parameters for the subsequent construction of the interpolation function.

[0045] S3: Based on the porosity, permeability and pore pressure of the reservoir in the study area during its formation, the Comsol multi-physics simulation software was used to construct a finite element plane model of the study area, to construct porosity, permeability and pore pressure interpolation functions, and to use the Richards equation for fluid migration. Finally, the potential reservoir distribution area can be determined by comparing the actual distribution of the reservoir in the study area with the peak convergence area of ​​the fluid pressure field and fluid velocity field obtained by simulation:

[0046] (1) Based on the actual research scope of the study area, the plane geometry of the study area can be directly constructed by inputting it into the geometry module of the Comsol multi-physics field simulation software. Then, the meshing is performed using an extremely fine mapping mesh. Finally, the finite element model of the study area can be directly obtained by clicking "Build Selected Object".

[0047] (2) Input the median values ​​of the porosity, permeability and pore pressure parameters obtained in step S2 into the interpolation function module of the Comsol multi-physics field simulation software, select the nearest neighbor interpolation method, and finally click "Build Selected Objects" to generate the interpolation functions of porosity, permeability and pore pressure as the initial conditions for subsequent fluid simulation.

[0048] (3) Fluid simulation method Select the Richards equation module and click "Calculate" in the "Study" module to obtain the changes in the pressure field and velocity field of fluid migration. Comparing the actual distribution of oil reservoirs in the study area with the peak convergence area of ​​the fluid pressure field and fluid velocity field obtained by simulation can determine the distribution area of ​​potential oil reservoirs.

[0049] In this application, the stratification data and lithology data of the oil reservoir well locations in the study area are input into the Petromod basin software to obtain the geological evolution history of the oil reservoir well locations; the oil reservoir formation period is a comprehensive judgment of the formation temperature evolution history obtained by combining the fluid inclusion temperature experiment with the Petromod multi-physics field simulation software numerical simulation; the porosity, permeability and pore pressure of the oil reservoir in the study area during the accumulation period are obtained based on the Petromod basin numerical simulation, and the Comsol multi-physics field simulation software is used to construct a finite element plane model of the study area, construct porosity, permeability and pore pressure interpolation functions, and use the Richards equation for fluid migration; finally, the actual distribution of the oil reservoir in the study area is compared with the peak convergence area of ​​the fluid pressure field and fluid velocity field obtained by simulation to determine the potential oil reservoir distribution area, and the obtained results are more accurate and scientific than the previous results of determining the upper limit of the drilling depth in the favorable area based solely on experience.

[0050] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. For those skilled in the art, the present invention may have various modifications and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

Claims

1. A method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation, characterized in that: include: S101, through the fluid inclusion homogenization temperature experiment, combined with the numerical simulation results of the Petromod Basin, the reservoir formation period of the study area is comprehensively determined; S103, based on the obtained period of oil reservoir formation in the study area, determine the porosity, permeability and pore pressure of the oil reservoir in the study area during the period of oil reservoir formation; S105, based on the porosity, permeability and pore pressure of the oil reservoir in the study area during the accumulation period, a finite element plane model of the study area is constructed using Comsol multi-physics field simulation software, porosity, permeability and pore pressure interpolation functions are constructed, and the Richards equation is used to perform fluid migration; S107, the potential reservoir distribution area can be determined by comparing the actual distribution of the reservoirs in the study area with the peak convergence area of ​​the fluid pressure field and fluid velocity field obtained by simulation.

2. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to claim 1 is characterized in that: In step S101, the fluid inclusion uniform temperature experiment includes: (1) The rock sample is made into inclusion microscopic sections with both sides polished; (2) Observe and photograph the prepared inclusion microscopic slices under a petrographic microscope. Observe the occurrence state, type, size, shape, distribution characteristics, and percentage of gas phase in the inclusions under the microscope to select appropriate inclusions for subsequent testing and analysis; (3) Pretreatment of inclusion microsections including soaking and cleaning to make them suitable for microthermometry analysis; (4) Use Linkam hot and cold stages to perform microscopic temperature measurement on fluid inclusion samples to obtain the uniform temperature of the fluid inclusions.

3. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to claim 2 is characterized in that: The Linkam hot and cold stage is used to perform microscopic temperature measurement on the fluid inclusion sample to obtain the uniform temperature of the fluid inclusion, and then the method further includes: drawing a uniform temperature distribution histogram according to the uniform temperature experimental results of the fluid inclusion, and analyzing to obtain the main temperature distribution range.

4. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to any one of claims 1 to 3, characterized in that: In step S101, the well location stratification data and lithology data of the study area are input into the Petromod basin simulation software, and the geological evolution history of the well location of the reservoir can be obtained by clicking "Run".

5. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to any one of claims 1 to 3, characterized in that: In step S101, the oil reservoir formation period of the study area is comprehensively determined by combining the fluid inclusion temperature experiment with the formation temperature evolution history obtained by the numerical simulation of the Petromod Basin.

6. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to any one of claims 1 to 3, characterized in that: In step S103, the porosity, permeability and pore pressure of the oil reservoir in the study area during the reservoir formation period are obtained through the numerical simulation results of the Petromod basin.

7. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to any one of claims 1 to 3, characterized in that: In step S105, the finite element model of the study area is based on the actual research scope of the study area. Inputting it into the geometry module of the Comsol multi-physics field simulation software can directly construct the plane geometry of the study area, and then meshing is performed. The meshing method uses an extremely fine mapping grid. Finally, click "Build Selected Object" to directly obtain the finite element model of the study area.

8. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to any one of claims 1 to 3, characterized in that: In step S105, the median values ​​of the porosity, permeability and pore pressure parameters obtained in step S103 are input into the interpolation function module of the Comsol multi-physics field simulation software, the interpolation method is selected as the nearest neighbor interpolation, and finally "Build Selected Objects" is clicked to generate the interpolation functions of porosity, permeability and pore pressure.

9. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to any one of claims 1 to 3, characterized in that: Step S105 also includes selecting the Richards equation module for the fluid simulation method, and clicking "Calculate" in the "Study" module to obtain changes in the pressure field and velocity field of fluid migration.

10. The method for quantitatively evaluating tight sandstone oil and gas migration based on multi-physical field simulation numerical simulation according to any one of claims 1 to 3, characterized in that: In step S107, the potential reservoir distribution area is determined by comparing the actual distribution of the reservoirs in the study area with the peak convergence area of ​​the fluid pressure field and the fluid velocity field obtained by simulation.

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