Salt mine sediment gap petroleum and brine migration simulation and parameter optimization evaluation method

Abstract

The invention discloses a salt mine sediment void petroleum and brine migration simulation and parameter optimization evaluation method, which comprises the following steps: obtaining physical characteristic parameters of salt mine sediment, petroleum and brine, the sediment parameters at least comprising void ratio and pore connectivity obtained through CT scanning; calculating an evaluation index based on a simulation result, and performing quantitative evaluation and feasibility screening on the migration process; if the optimal potential exists, parameter optimization and scheme iteration are further executed, and a simulation-evaluation-optimization closed loop is formed; and finally, checking the model through field test data. The method solves the problem that in the prior art, no means for simulating and evaluating the two-phase migration of the petroleum brine in the salt mine sediment gaps exist, the process can be quantitatively simulated, evaluated and optimized, and scientific, accurate and systematic technical support is provided for petroleum storage through the high-impurity salt mine sediment gaps.

Description

Technical Field

[0001] This invention relates to the field of simulation and evaluation of oil and salt mining, specifically to a method for simulating and optimizing the migration of oil and brine in the pores of salt mine sediment. Background Technology

[0002] In the field of large-scale salt cavern oil reserve simulation and evaluation technology, strategic oil reserves are crucial for ensuring national energy supply security. Some Western countries (the United States, France, and Germany) established large-scale salt cavern oil storage facilities in the 20th century, promoting the development of oil reserve technology. my country has also made rapid progress in the field of oil reserves, establishing various oil storage models (surface tanks, water-sealed chambers, and offshore tanks), which has played a positive role in ensuring national energy security. However, the geological characteristics of salt rocks in my country differ from those in Europe and the United States. The thin salt layers, numerous interlayers, and high levels of insoluble impurities pose challenges to the construction of salt cavern oil storage facilities. The process of creating water-soluble cavities generates a large amount of insoluble sediment and sludge.

[0003] In related fields, when it comes to oil storage in salt mines, for oil storage technologies under ordinary salt layer geological conditions, the main approach is to directly utilize the net brine space above the insoluble sediment in the salt cavern for oil storage, focusing on the stability and sealing of the salt cavern. However, for high-impurity salt mine formations, traditional methods do not fully consider the utilization of the insoluble sediment at the bottom of the salt cavern, resulting in a significant waste of oil storage space. In addressing issues related to oil and brine, the focus is typically on the injection and production operation of oil and brine in the net space above the salt cavern sediment. The assessment of oil storage capacity and injection-production efficiency mostly relies on field tests or experience-based estimation methods, with less emphasis on numerical simulation.

[0004] However, traditional oil storage technologies and assessment methods have significant shortcomings and are not applicable to the high-impurity salt rock geological conditions in my country. my country's salt rock geological conditions are unique, with numerous insoluble interlayers and a high concentration of insoluble impurities in the salt layers. When constructing salt caverns using the water-soluble method in high-impurity salt mine formations, sedimentary bodies are formed. Existing simulation technologies and evaluation methods do not consider utilizing the voids in these sedimentary bodies for oil storage. Furthermore, traditional methods have not addressed the flow of the oil-brine two-phase system within the sedimentary voids. If the oil and brine cannot flow effectively within these voids, it will severely impact the normal operation of oil storage facilities and the feasibility of oil storage in sedimentary voids. Simultaneously, there is a lack of simulation and evaluation methods for the migration of the oil-brine two-phase system within salt mine sedimentary voids. This makes it impossible to quantitatively evaluate this process, screen sediments suitable for oil storage, optimize parameters for oil injection and production in sedimentary voids, and ultimately fail to meet practical engineering requirements. Summary of the Invention

[0005] The purpose of this invention is to overcome the above-mentioned technical deficiencies and to propose a method for simulating and optimizing the migration of petroleum and brine in the pores of salt mine sediments.

[0006] To achieve the above-mentioned technical objectives, the present invention adopts the following technical solution: This invention provides a method for simulating and optimizing the migration of petroleum and brine in the voids of salt mine sediments, comprising: S1. Obtain physical property parameters of salt mine sediment media, petroleum and brine representing the target working conditions, wherein the physical property parameters of the sediment media include at least the porosity and pore connectivity obtained by CT scanning. S2. Based on the obtained physical property parameters of the sediment medium, construct a two-dimensional digital porous medium model or a three-dimensional digital porous medium model that can reflect its true pore geometry and connectivity. S3. In the two-dimensional digital porous media model or the three-dimensional digital porous media model, the initial fluid saturation state and boundary conditions are set, and the numerical method is used to simulate the migration process of the two-phase fluid of oil and brine during the oil injection and brine discharge or brine injection and oil production process. S4. Based on the simulation results, calculate the preset evaluation indicators, and output the quantitative evaluation conclusion and feasibility screening results of the two-phase transport process according to the calculation results of the evaluation indicators; if the simulated oil recovery rate under the optimal parameter combination is still far lower than the engineering target, it is determined that the salt mine sludge is not suitable for oil storage. The evaluation indicators include pore pressure difference, tortuosity of oil-brine interface, oil recovery rate, residual oil distribution, flow velocity and outlet water cut. S5. If there is potential for optimization, then perform parameter optimization and scheme iteration. The parameter optimization scheme includes: analyzing the optimal combination under different porosity, oil viscosity, brine type and injection-production rate conditions based on evaluation indicators, and proposing control measures such as injecting low viscosity oil or using on-site directional drilling to destroy the blockage area for the case of low recovery rate. Based on the optimization scheme, readjust the physical property parameters of the salt mine sediment medium, and establish a more realistic two-dimensional digital porous medium model or three-dimensional digital porous medium model for re-simulation and evaluation. S6. The measured data such as the oil recovery rate of sediment voids and the water cut at the outlet end obtained by the on-site oil injection and production test monitoring equipment are compared with the simulation evaluation results of step S4 to verify and correct the accuracy of the simulation model.

[0007] In some embodiments, the step of obtaining the physical property parameters of the salt mine sediment medium in step S1 further includes: S11. Select the target salt layer core and dissolve it in fresh water. Mix the insoluble material with the fine sediment particles from the brine outlet on site to prepare a medium that can represent the real underground sediment accumulation in terms of particle type and particle size. S12. Test the wetting angles of different types of particles in the sediment medium in the target oil and brine, and determine the overall wetting angle range of the sediment accumulation body by weighted summation.

[0008] In some embodiments, in step S1, multiple sets of sediment media with porosities of 30%, 40%, 50%, and 60% are configured, and parameters of petroleum with three different kinematic viscosities (high, medium, and low) and parameters of various types of brine are obtained for cross-comparison simulation experiments.

[0009] In some embodiments, the model construction step in step S2 further includes: analyzing CT scan images, using a random function and generating an initial digital model based on the porosity, then comparing the porosity connectivity of the generated model with the CT images, and continuously optimizing to ensure a high degree of consistency between the model and the real CT images. The final model is a millimeter-level micro-element, and its simulation results are extended to the actual work area range through integration.

[0010] In some embodiments, the specific boundary condition settings for the numerical simulation in step S3 include: Simulation of oil injection process: The initial state of the model is set as the sediment voids are filled with brine, and the oil injection rate calculated based on the on-site wellhead flow rate is applied to the upper boundary of the model. Oil production process simulation: The initial state of the model is set as if the sediment voids are filled with oil, and a brine injection rate is applied at the lower boundary of the model.

[0011] In some embodiments, the numerical simulation step in step S3 further includes: meshing the digital porous medium model, wherein the two-dimensional digital porous medium model uses a triangular mesh, the three-dimensional digital porous medium model uses a tetrahedral mesh, and the mesh is refined at locations with high porosity to improve computational accuracy.

[0012] In some embodiments, the numerical method in step S3 is to use the phase-field method to couple the Navier-Stokes equations and introduce the convection-diffusion equations for solution, so as to track the dynamic changes of the interface between oil and brine in the pores of sediment.

[0013] In some embodiments, in step S4, the pore pressure difference is used to determine the movement pattern and change process of the oil-water interface; the tortuosity of the oil-brine interface is used to reflect the complexity of the sediment pore structure and the ease of injection and production; the oil recovery rate is used to assess the feasibility of the brine injection oil production process, and the target recovery rate should exceed 90%; the residual oil distribution is used to assess the amount of oil remaining in the pores after oil production, and the target residual oil content should be less than 10%; the flow velocity is used to analyze the flow field changes and dominant flow channels inside the sediment pores; and the outlet water cut is used to evaluate the oil production situation and can be compared with the engineering field data.

[0014] In some embodiments, the optimization of the sediment pore structure in step S5 further includes: Based on simulation results of residual oil distribution and flow velocity, poorly connected or clogged areas that lead to reduced oil recovery are identified; and targeted physical modification schemes are proposed accordingly.

[0015] In some embodiments, the verification and optimization of the porosity of the sediment in step S4 further includes: comparing the simulated oil recovery rate with the target recovery rate; if the target is not achieved, systematically adjusting the porosity parameter in the model and repeating the simulation until the optimal porosity value that meets the engineering requirements is determined; the optimal value can be used to guide the preparation of the sediment accumulation body on site.

[0016] Compared with existing technologies, the beneficial effects of the simulation and parameter optimization evaluation method for oil and brine migration in salt mine slag voids provided by this invention are as follows: This method systematically obtains the physical property parameters of salt mine slag media, oil, and brine, constructs an accurate porous media model, conducts detailed two-phase flow numerical simulations, evaluates and optimizes the simulation results, and improves model accuracy through on-site data verification, forming a complete simulation and evaluation system for the regulation of two-phase oil and brine migration in salt mine slag voids. Compared with existing technologies, it solves the problem of lacking simulation and evaluation methods for oil and brine two-phase migration in salt mine slag voids, enabling quantitative simulation, evaluation, and optimization of this complex process. It provides scientific, accurate, and systematic technical support for utilizing salt mine slag voids for oil reserves, and can screen out slag geological bodies with development value in the early stages of projects, effectively reducing investment risks and improving project economic benefits. It has strong practicality and innovation. Attached Figure Description

[0017] Figure 1 This is a flowchart illustrating a method for simulating and optimizing the migration of petroleum and brine in the pores of salt mine sediment, provided in an embodiment of the present invention. Figure 2 This is a technical roadmap of two-phase flow of petroleum and brine in the voids of salt mine slag provided in an embodiment of the present invention, which shows the key parameters, operating modes and evaluation indicators that affect the two-phase flow. Figure 3 This is a schematic diagram illustrating the simulation results of a typical brine injection oil recovery process in an embodiment of the present invention, wherein, Figure 3 (a) to (d) show the dynamic evolution of the oil-brine interface during the process of brine (blue area) displacing oil (red area) at different times; Figure 3 (e) to (h) show the fluid velocity distribution at the corresponding time points, intuitively reflecting the formation and distribution of the dominant flow channels; Figure 4 This is a schematic diagram of the simulation results of the brine injection oil recovery process in a regular sediment medium in an embodiment of the present invention. The top row of images shows the dynamic evolution of the interface where brine displaces oil, and the bottom row of images shows the corresponding fluid velocity distribution. Figure 5 This is a schematic diagram of an oil injection and production site in the sediment voids provided in an embodiment of the present invention. Detailed Implementation

[0018] The technical solutions in the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings. The described embodiments are only possible technical implementations of the present invention, but are not limited thereto. Other embodiments obtained by those skilled in the art in conjunction with the embodiments of the present invention without creative effort are also within the protection scope of the present invention.

[0019] This application mainly adopts the methods of parameter acquisition, modeling, simulation, evaluation and optimization to achieve the effect of quantitative simulation, evaluation and optimization of the oil storage process in the voids of salt mine slag. The following is a further detailed description of this application.

[0020] Please refer to Figure 1 The method for simulating and optimizing the migration of petroleum and brine in the voids of salt mine slag provided in this application includes several main steps: obtaining physical property parameters, constructing a porous media model, numerical simulation of two-phase flow, evaluation and screening of simulation results, parameter optimization and scheme iteration, and on-site data verification. By executing these steps in sequence, the two-phase flow behavior of petroleum and brine in the voids of salt mine slag can be accurately and systematically simulated, evaluated and optimized, providing reliable technical support for actual engineering.

[0021] Specifically, the process of obtaining physical property parameters includes obtaining the physical property parameters of salt mine sediment media, petroleum, and brine.

[0022] First, let's examine how to obtain the physical properties of the salt mine sediment medium. The first step is to select a core sample from the target salt layer. This selection is crucial; the core sample must match the geological characteristics of the target cavity. For example, if the target cavity-forming salt layer contains gypsum and mudstone, the selected core sample must also contain these components. The selected core sample is then dissolved in fresh water to obtain the insoluble material. Large, thick interlayered core samples are crushed using a pressure device. Simultaneously, fine sediment particles obtained from the brine backwashing at the brine discharge point are collected. The insoluble material is mixed with these fine sediment particles. This process ensures that the prepared medium represents the actual underground sediment deposit in terms of particle type and size.

[0023] When preparing sediment, the location and thickness of the interlayers in the cavity salt layer should also be considered. If the interlayer is located in the upper middle part, the particles will be more fragmented after collapse; if it is located in the lower middle part, the particles will be more intact. During laboratory preparation, geometric similarity calculations should be performed based on the container size to determine a reasonable sediment particle size. If the subsequent simulation or test results are unsatisfactory, the sediment should be re-mixed.

[0024] For this medium, detailed physical property parameters are also required. The wetting angles of different types of particles in the sediment medium in the target oil and brine are tested using national standards, and then the overall wetting angle range of the sediment accumulation is determined through a weighted synthesis method. In addition, methods such as CT scanning are used to test the porosity, particle size distribution, and pore connectivity of the sediment accumulation. For a more comprehensive comparative study, multiple sets of sediment media with porosities of 30%, 40%, 50%, and 60% can be configured. Field tests have shown that the porosity of sediment generally exceeds 40%. Therefore, if the average porosity tested is below 40%, large sediment particles should be added during preparation to increase the porosity. Simultaneously, simulations and evaluations of the flow limit under low porosity (e.g., less than 40%) scenarios should be supplemented to define the applicable boundaries of this method. CT scanning is a relatively advanced technology; methods such as nuclear magnetic resonance imaging can also be used as alternatives, both of which can obtain structural information about the internal structure of the sediment medium.

[0025] Next, let's examine the acquisition of the physical characteristic parameters of the petroleum and brine. The kinematic viscosity of the injected petroleum was measured using national standards, and the petroleum was classified into three categories: low, medium, and high kinematic viscosity. Simultaneously, the density and kinematic viscosity of the brine (or fresh brine, fresh water) were measured. These parameters will be used in subsequent cross-simulation experiments, where petroleum of different viscosities (low, medium, and high viscosity) are displaced by different types of brine (brine, fresh brine, and fresh water) to determine the optimal combination of petroleum and brine types.

[0026] This section describes the combination logic and effects of each component in the process of obtaining physical property parameters. Through the acquisition of physical property parameters of the salt mine sediment medium, petroleum, and brine, we obtained the fundamental data required for model construction and simulation. Different parameters are interrelated; for example, the porosity and pore connectivity of the sediment medium affect the flow of petroleum and brine within it, while the kinematic viscosity of petroleum and the density and kinematic viscosity of brine also influence the two-phase flow transport process. Accurate acquisition of these parameters provides a reliable basis for subsequent modeling and simulation, making the simulation results closer to reality.

[0027] Specifically, the porous media model construction step involves constructing a two-dimensional or three-dimensional digital porous media model that reflects the true pore geometry and connectivity of the sediment medium based on the obtained physical property parameters of the sediment medium.

[0028] This step is crucial to ensuring the accuracy and reliability of all subsequent simulation, evaluation, and optimization results. By analyzing CT scan images, we can obtain the distribution patterns, characteristics, and connectivity of sediment pores. This embodiment primarily employs a statistical reconstruction method, utilizing MATLAB's random function interface to generate an initial two-dimensional or three-dimensional digital porous media model based on the ratio of pore area to the total sediment area (i.e., porosity). After model generation, its statistical characteristics, such as pore connectivity and porosity, are repeatedly compared and optimized with real CT images to ensure a high degree of consistency between the model and the real CT images. The model generated by this method is statistically equivalent to real sediment. In scenarios requiring higher fidelity, a direct reconstruction method based on CT images can also be used, directly converting CT data into a digital core model through image processing technology. The final model is a millimeter-scale micro-element, and its simulation results can be extended to the actual work area through integration. When generating the initial model, in addition to using MATLAB's random function interface, relevant libraries in Python can also be used, as long as a model meeting the requirements based on porosity can be generated.

[0029] Furthermore, based on the pore connectivity characteristics, the sediment model channel types can be divided into three categories: single channel, heterogeneous channel, and complex channel, for targeted simulation analysis.

[0030] This section describes the combination logic and effects of each component in the construction of the porous media model. Through analysis of CT scan images and the application of random functions, we transformed the physical properties of the sediment medium into a digital model. The comparison and optimization process between the model and real CT images ensured that the model accurately reflected the true pore geometry and connectivity of the sediment medium. The millimeter-level micro-element model can be extended to the actual working area through integration, enabling the simulation results to be applied to practical engineering projects and providing a suitable model foundation for subsequent two-phase flow numerical simulations.

[0031] Specifically, the two-phase flow numerical simulation step involves setting the initial fluid saturation state and boundary conditions in a two-dimensional or three-dimensional digital porous media model, and using numerical methods to simulate the migration process of the two-phase fluids of oil and brine during oil injection and brine drainage or brine injection for oil production.

[0032] First, the digital porous media model is meshed. Two-dimensional digital porous media models use triangular meshes, while three-dimensional digital porous media models use tetrahedral meshes. The mesh size is typically one ten-thousandth of the model's geometric size, and mesh refinement is applied to areas with high porosity to improve computational accuracy. This meshing method is chosen to better adapt to the model's geometry and fluid flow characteristics. Besides triangular and tetrahedral meshes, rectangular or hexahedral meshes can also be used in some cases, depending on the specific model and simulation requirements.

[0033] Then, the initial fluid saturation state and boundary conditions are set. In the oil injection process simulation, the initial state of the model is set as the sediment voids are filled with brine, and the oil injection rate calculated based on the on-site wellhead flow rate is applied to the upper boundary of the model. In the oil production process simulation, the initial state of the model is set as the sediment voids are filled with oil, and the brine injection rate is applied to the lower boundary of the model. Fresh water can also be used for displacement.

[0034] Finally, a numerical method is used to solve the problem. In this embodiment, the numerical method employs the phase-field method coupled with the Navier-Stokes equations and incorporates the convection-diffusion equations for solution. This method can accurately track the dynamic changes of the interface between oil and brine in the sediment voids, solve for the velocity and pressure fields, and ensure the convergence of the model calculations. Besides the phase-field method, other methods such as the VOF (Volume of Fluid) method can also be considered to simulate the two-phase flow process, but the phase-field method has certain advantages in handling dynamic interface changes.

[0035] This section describes the combined logic and effects of each component in the two-phase flow numerical simulation. Mesh generation is used to discretize the model, facilitating numerical calculations; different mesh types and refinement methods improve computational accuracy. The initial fluid saturation state and boundary conditions are determined based on actual oil injection and brine drainage or brine injection for oil recovery, making the simulation more realistic. The choice of numerical method determines the accuracy and reliability of the simulation. The phase-field method coupled with the Navier-Stokes equations and the introduction of convection-diffusion equations effectively tracks the dynamic changes at the interface of the two-phase flow and solves for flow field information. The various components work together to simulate the two-phase fluid transport process of oil and brine.

[0036] Specifically, the simulation result evaluation and feasibility screening stage is based on the simulation results, calculates the preset evaluation indicators, outputs quantitative evaluation conclusions on the two-phase migration process, and judges the oil storage suitability of the sediment geological body.

[0037] like Figure 2As shown in the figure, this is a technical roadmap for the two-phase flow of petroleum and brine in the pores of salt mine sediment provided in an embodiment of the present invention, illustrating the key parameters, operating modes, and evaluation indicators affecting the two-phase flow. This process mainly considers two categories of characteristics: the porous media characteristics of the sediment and the characteristics of the flowing media. Key parameters related to the porous media characteristics of the sediment include the sediment medium channel type and contact angle. The medium channels can be classified into three categories based on their complexity: single capillary channels, heterogeneous channels, and complex channels. The contact angle determines the wettability of the medium, categorized as oil-wetted media (0~90°), neutral media (90°), and water-wetted media (90~180°). These characteristics directly affect the distribution and flow behavior of the fluid in the pores. Regarding the characteristics of the flowing media, key parameters include the petroleum displacement medium and petroleum viscosity. The displacement medium can be saturated brine, light brine, or fresh water. Petroleum is classified into three levels based on its kinematic viscosity: low, medium, and high. The physical properties of these fluids themselves are important factors determining the transport efficiency. The above two categories of key parameters constitute the complete operating conditions for the petroleum-brine two-phase flow. This method simulates two core operating modes: the sediment-void oil storage process (i.e., oil injection and brine discharge) and the sediment-void oil production process (i.e., brine injection and oil recovery). To quantitatively evaluate the migration processes under these two modes, this invention establishes a set of evaluation indexes, including pore pressure difference, oil recovery rate, oil-brine interface morphology, residual oil distribution, flow velocity distribution, and outlet water cut. These indexes can comprehensively evaluate the simulated process and provide a basis for subsequent parameter optimization.

[0038] Based on the simulation results, pre-set evaluation indicators were calculated. The evaluation indicator system includes pore pressure difference, tortuosity of the oil-brine interface, oil recovery rate, residual oil distribution, flow velocity, and outlet water cut.

[0039] Pore ​​pressure differences are used to determine the movement pattern of the oil-water interface by monitoring the pressure difference curve. The tortuosity of the oil-brine interface reflects the complexity of the sediment pore structure; higher tortuosity indicates greater difficulty in injection and production. Oil recovery rate is used to assess the feasibility of the brine injection oil recovery process; the target recovery rate should exceed 90%. Residual oil distribution is used to assess the amount of oil remaining in the pores after oil recovery; the target residual oil content should be less than 10%. Flow velocity is used to analyze the flow field changes and dominant flow channels within the sediment pores. Water cut at the outlet is used to evaluate oil recovery and can be compared with data from the engineering field.

[0040] Figure 3 This is a simulation result of a typical brine injection oil recovery process in this embodiment, which specifically shows the dynamic evolution of the oil-brine interface and the velocity distribution of the internal flow field. Figure 3Figures (a) to (d) illustrate the process of brine (blue area) displacing oil (red area) at different times (0.20s, 2s, 3s, 4s). As can be seen from the figures, initially the sediment pores are filled with oil. With the injection of brine from the bottom, the oil-brine interface gradually moves upwards. Due to the heterogeneity of the pore structure, the interface exhibits an irregular fingering phenomenon, and oil in some areas is bypassed, forming isolated residual oil clumps (such as...). Figure 3 (d) The red area in the upper middle part). This visually reflects the tortuousness of the "petroleum-brine interface" and the final "residual oil distribution". Figure 3 Figures (e) to (h) show the fluid velocity distribution at the same moment. It can be seen that the fluid does not flow uniformly in all pores, but rather forms "dominant flow channels" (bright bands in the figure) with significantly higher velocities along specific paths. The formation and distribution of these channels determine the displacement efficiency and the affected area. By analyzing the "flow velocity," areas of blockage or poor flow can be identified. Combining the analysis of interface evolution and velocity distribution allows for a comprehensive assessment of oil recovery under specific operating conditions and provides a visual physical picture for optimizing injection and production parameters.

[0041] In contrast. Figure 4 This demonstrates a brine injection oil recovery process in a regularly arranged sediment medium. Figure 3 The pore structures of non-homogeneous materials differ. Figure 4 The sediment particles are arranged in a regular pattern, representing an idealized porous media model. Figure 4 The top row shows that as the brine (blue) is injected from the bottom, the displacement front edge (oil-brine interface) is relatively flat and moves upward in a piston-like manner. The flow around and fingering phenomena are significantly reduced, and the final residual oil (red) is less and its distribution is more predictable. Figure 4 The velocity distribution diagram at the bottom shows that the fluid forms multiple branching paths within regular pore channels, rather than forming a single dominant flow channel as is common in heterogeneous media. This can be compared to... Figure 3 and Figure 4 The simulation results show that this method can clearly reveal the key impact of the complexity of sediment pore structure (such as heterogeneity and connectivity) on oil recovery, residual oil distribution and fluid flow path, thus verifying the effectiveness of the present invention for refined simulation and evaluation of different types of sediment media.

[0042] Based on the calculation results of the above evaluation indicators, quantitative evaluation conclusions are output, and further parameter optimization schemes can be proposed. The quantitative evaluation conclusions output in this step not only include the assessment of migration efficiency, but also the feasibility judgment of whether the sedimentary geological body is suitable for oil storage. If, after parameter optimization, the simulated oil recovery rate is still extremely low and cannot meet the engineering economic requirements (such as a target recovery rate of 90%), then it can be concluded that the salt mine sedimentary body is not suitable for oil storage. In this way, this method can pre-screen suitable sedimentary geological bodies for oil storage before large-scale on-site construction, thereby effectively avoiding risks and reducing unnecessary on-site construction investment.

[0043] Specifically, the parameter optimization and scheme iteration phase is initiated when the evaluation and screening process determines that the target sediment has optimization potential. The aim is to improve oil storage efficiency by adjusting parameters and improving the scheme.

[0044] The parameter optimization scheme includes analyzing the optimal combination under different porosity, oil viscosity, brine type and injection-production rate conditions based on evaluation indicators, and proposing control measures such as injecting low viscosity oil or using on-site directional drilling to destroy the blockage area for working conditions with low recovery rate.

[0045] In some embodiments, the parameter optimization scheme described in step S4, in addition to analyzing the optimal parameter combination under different working conditions, further includes specific optimization of the sludge pore structure and porosity.

[0046] (1) Optimization of sediment pore structure: This optimization aims to improve the physical structure of the sediment medium to increase recovery rate. The specific steps are as follows: Identifying inefficient regions: Based on the analysis of two-phase flow numerical simulation results, especially the evaluation indicators of "residual oil distribution" and "flow velocity," key regions leading to reduced oil recovery can be identified. These regions are typically characterized by poor pore connectivity or blockage by fine particles.

[0047] Propose modification solutions: For the identified blockage areas, propose targeted physical modification solutions. For example, one could propose using in-situ directional drilling technology to actively disrupt these blockage areas, thereby improving the connectivity network of the entire sediment voids and creating smoother channels for oil flow.

[0048] (2) Verification and optimization of sediment porosity: This optimization involves adjusting the porosity, a key parameter, to achieve the project's target recovery rate. The specific steps are as follows: Result comparison: The simulated "oil recovery rate" is compared with the project's preset target recovery rate (e.g., 90%).

[0049] Systematic parameter adjustment: If the simulated recovery rate fails to reach the target value, the porosity parameter is systematically adjusted in the digital model. For example, the porosity can be adjusted in steps (such as 5% or 10%) within the range of 30% to 60%, and the simulation calculation can be repeated for each porosity value.

[0050] Determine the optimal value: Through the above cross-simulation, until an optimal porosity value that can meet the engineering recovery rate requirements is determined.

[0051] Guiding field practice: This optimal porosity value can be used to guide the preparation of sediment accumulations on site. For example, when the calculated optimal porosity is higher than the initial porosity of the sediment on site, the overall porosity can be effectively increased by adding large sediment particles during the preparation process, thus achieving the optimal state.

[0052] Through the refined evaluation and optimization of the pore structure and porosity of the sediment, this method can not only predict the oil storage effect, but also proactively propose improvement measures, forming a complete closed loop from "simulation-evaluation-optimization-guidance", providing more scientific and systematic technical support for using the pores of high-impurity salt mine sediment for oil storage.

[0053] By calculating pre-defined evaluation indicators, we can assess the two-phase transport process from multiple perspectives. Different evaluation indicators reflect different aspects of the two-phase transport process, complementing each other and providing a more comprehensive understanding of the entire process. Parameter optimization schemes proposed based on the calculation results of the evaluation indicators can be adjusted and optimized for different operating conditions, improving injection-production efficiency and oil storage capacity, thereby better achieving the goal of oil storage in the voids of salt mine sediment.

[0054] In a preferred embodiment, the on-site data verification step includes comparing measured data such as the recovery rate of sediment voids and the water cut at the outlet end, obtained through on-site injection-production test monitoring equipment, with the final results of the simulation evaluation to verify and correct the accuracy of the simulation model. Specifically, the morphological parameters of the on-site sediment can be obtained through analysis using techniques such as sonar and electrical resistivity tomography, and monitoring equipment such as flow meters, moisture content analyzers, and pressure gauges can be installed at the wellhead at the production end to acquire measured data in real time. Verification with on-site data allows the simulation model to more accurately reflect the actual situation and improves the predictive value of the model.

[0055] In a preferred embodiment, such as Figure 5As shown, the steps for on-site data verification include comparing measured data such as the recovery rate of sediment voids and the water cut at the outlet end, obtained through on-site injection-production test monitoring equipment, with the simulation evaluation results from the migration process evaluation and optimization stage, in order to verify and correct the accuracy of the simulation model. Specifically, the morphological parameters of the on-site sediment can be obtained through analysis using techniques such as sonar and electrical resistivity tomography, and monitoring equipment such as flow meters, moisture content analyzers, and pressure gauges can be installed at the wellhead at the production end to acquire measured data in real time. Verification with on-site data allows the simulation model to more accurately reflect the actual situation and improves the model's predictive value.

[0056] The implementation principle of this embodiment is as follows: This method systematically acquires the physical property parameters of salt mine sediment media, petroleum, and brine, constructs an accurate porous media model, conducts detailed two-phase flow numerical simulations, evaluates and optimizes the simulation results, and improves model accuracy through on-site data verification, forming a complete simulation and evaluation system for the two-phase transport and regulation of petroleum and brine in salt mine sediment pores. Compared with existing technologies, it solves the problem of lacking simulation and evaluation methods for the two-phase transport of petroleum and brine in salt mine sediment pores. It can quantitatively simulate, evaluate, and optimize this complex process, providing scientific, accurate, and systematic technical support for utilizing salt mine sediment pores for petroleum storage. Furthermore, it uses numerical simulation evaluation methods to screen effective underground sediment deposits, analyze their feasibility and effectiveness for oil storage, effectively reduce investment risks, and improve the economic benefits of the project, demonstrating strong practicality and innovation.

[0057] The above are all preferred embodiments of this application, and are not intended to limit the scope of protection of this application. Therefore, all equivalent changes made in accordance with the structure, shape and principle of this application should be covered within the scope of protection of this application.

Claims

1. A method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids, characterized in that, The method comprises the following steps: S1, obtaining physical property parameters of salt mine sediment medium, oil and brine representing target working conditions, wherein the physical property parameters of the sediment medium at least include porosity and pore connectivity obtained by CT scanning or other means; S2, based on the obtained physical property parameters of the sediment medium, a two-dimensional digital porous medium model or a three-dimensional digital porous medium model capable of reflecting the real pore geometry and connectivity thereof is constructed; S3, in the two-dimensional digital porous medium model or the three-dimensional digital porous medium model, an initial fluid saturation state and a boundary condition are set, and a numerical method is used to simulate the migration process of oil and brine two-phase fluid in the process of oil injection and brine displacement or brine injection and oil production; S4, based on the simulation results, a preset evaluation index is calculated, and according to the calculation results of the evaluation index, a quantitative evaluation conclusion, a feasibility screening result or a parameter optimization scheme of the two-phase migration process is output, if the simulated oil recovery under the optimal parameter combination is still far lower than the engineering target, it is determined that the salt mine sediment is not suitable for oil storage, so that the geological body without oil storage value is screened out, wherein the evaluation index includes pore pressure difference, oil-brine interface tortuosity, oil recovery, residual oil distribution, flow velocity and outlet water cut; S5, if the evaluation result of step S4 does not reach the ideal target but has optimization potential, parameter optimization and scheme iteration are performed, the parameter optimization scheme includes: based on the evaluation index, the best combination under different porosities, oil viscosities, brine types and injection-production rates is analyzed, and for the working condition with low recovery, injection of low-viscosity oil or use of on-site directional drilling to destroy the control measures of the blocked area are proposed, and based on the optimization scheme, the physical property parameters of the salt mine sediment medium are adjusted again, a two-dimensional digital porous medium model or a three-dimensional digital porous medium model more consistent with the actual situation is established, and simulation evaluation is performed again; S6, the measured data of sediment void oil recovery and outlet water cut obtained by the on-site injection-production test monitoring equipment are compared with the simulation evaluation results of step S4 to check and correct the accuracy of the simulation model.

2. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, The step of obtaining the physical property parameters of the salt mine sediment medium in step S1 further comprises: S11, selecting a target salt layer core for freshwater dissolution, and mixing the insoluble substances thereof with fine sediment particles of the on-site brine discharge port to prepare a medium which can represent the real sediment accumulation body in terms of particle type and particle size; S12, testing the wetting angle of different types of particles in the sediment medium in the target oil and brine, and determining the overall wetting angle range of the sediment accumulation body by weighted synthesis.

3. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, In step S1, multiple groups of sediment media with porosities of 30%, 40%, 50% and 60% are configured, and parameters of three different kinematic viscosities of oil and parameters of multiple types of brine are obtained for cross-comparison simulation test.

4. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, The step of model construction in step S2 further comprises: generating an initial digital model by analyzing the CT scan image, using a random function and according to the voidage, and then comparing the void connectivity of the generated model with the CT image, constantly optimizing to ensure high consistency between the model and the real CT image, and finally obtaining a millimeter-level microelement model, and the simulation result is expanded to the actual underground salt cavern cavity work area by integration, and the models of single-channel, heterogeneous channel and complex channel sedimentation voidage are constructed to simulate the numerical calculation model of the local sedimentation single-voidage channel, non-uniform voidage channel and complex voidage channel.

5. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, The specific boundary condition setting of the numerical simulation in step S3 comprises: Oil injection process simulation: the initial state of the model is set to be full of brine in the sedimentation voidage, and an oil injection rate calculated according to the field wellhead flow rate is applied to the upper boundary of the model; the brine discharge rate at the lower boundary is detected; Oil production process simulation: the initial state of the model is set to be full of oil in the sedimentation voidage, and a brine injection rate is applied to the lower boundary of the model; the oil production amount at the upper part of the sedimentation voidage is detected.

6. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, The step of numerical simulation in step S3 further comprises: grid division is performed on the digital porous medium model, wherein a triangular grid is used for a two-dimensional digital porous medium model, a tetrahedral grid is used for a three-dimensional digital porous medium model, and grid encryption is performed at positions with high void tortuosity to improve calculation accuracy.

7. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, The numerical method in step S3 is to use the phase field method coupled with the Navier-Stokes equation, and introduce a convection-diffusion equation to solve, so as to track the interface dynamic change law of oil and brine in the sedimentation voidage.

8. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, In step S4, the difference in pore pressure is used to judge the movement law and change process of the oil-water interface, the tortuosity of the oil-brine interface is used to reflect the complexity of the sedimentation voidage structure and the difficulty of injection and production, the oil recovery rate is used to evaluate the feasibility of the brine injection and oil production process, the target recovery rate should be more than 90%, the residual oil distribution is used to evaluate the amount of oil remaining in the voidage after oil production, the target residual oil content should be less than 10%, the flow velocity is used to analyze the flow field change and dominant flow channel in the sedimentation voidage, and the water cut at the outlet end is used to evaluate the oil production and can be compared with the engineering field data.

9. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, The optimization of the sedimentation voidage structure in step S5 further comprises: Based on the simulation results of the residual oil distribution and the flow velocity, the areas with poor connectivity or blocked are identified which lead to the decrease of the oil recovery rate; and a targeted physical modification scheme is proposed accordingly.

10. The method for simulation and parameter optimization evaluation of oil and brine migration in salt mine sediment voids according to claim 1, characterized in that, The checking and optimization of the sedimentation voidage in step S5 further comprise: comparing the simulated oil recovery rate with the target recovery rate; if the target is not reached, the voidage parameter in the model is adjusted systematically and the simulation is repeated until the optimal voidage value that can meet the engineering requirements is determined; the optimal value is used to guide the preparation of the sedimentation accumulation body in the field.

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