Variable flow rate adjustment method and system based on seepage theory calculation

Abstract

The embodiment of the present application provides a variable flow degree adjustment method and system based on seepage theory calculation, and belongs to the technical field of oil reservoir development. The method comprises the following steps: calculating the seepage velocity of each well based on water injection-oil production working condition information; identifying the well group to be adjusted in terms of variable flow degree based on the spatial and / or temporal difference characteristics of the seepage velocity of each well; calculating the front water saturation in each well group to be adjusted in terms of variable flow degree based on the water injection-oil production working condition information, and obtaining the water drive front position in each well group to be adjusted in terms of variable flow degree based on the front water saturation calculation; and determining and executing the adjustment scheme of each well group to be adjusted in terms of variable flow degree based on the water drive front position. The present application can effectively improve the water drive development effect, increase the water injection swept volume, overcome the low development efficiency problem caused by unreasonable well spacing or the formation of dominant channels in the prior art, and thus realize more efficient oil reservoir development and resource utilization.

Description

Technical Field

[0001] This invention relates to the field of reservoir development technology, specifically to a method for adjusting the flow rate based on seepage theory calculations and a system for adjusting the flow rate based on seepage theory calculations. Background Technology

[0002] In the development of terrestrial sedimentary reservoirs, the reservoirs change rapidly and exhibit strong horizontal and vertical heterogeneity. This complexity leads to significant differences in the effectiveness of waterflooding, particularly the problem of low waterflood sweep efficiency. Due to limited development, most reservoirs are still in the water injection stage, with relatively rich remaining oil and low overall water cut in some blocks. However, the heterogeneity of horizontal sweep efficiency results in significant water injection directionality, with water flow concentrated in certain dominant channels. This leads to the coexistence of low-liquidity wells and high-water-cut wells within the well area, resulting in low oil production rates and affecting the overall development effect.

[0003] Existing technologies attempt to address these issues through variable flow rate (VFR) design, particularly in certain blocks where VFR development based on existing well networks has yielded promising results. This method improves water injection effectiveness by adjusting the flow rate during the injection process to increase the water drive sweep range. However, in practical applications, existing VFR development schemes still face several significant challenges, limiting their widespread adoption and further improvement in effectiveness. Firstly, excessively large well spacing is a common problem. Excessive well spacing typically leads to low inter-well connectivity and significantly reduced water injection efficiency. In such cases, the injected water cannot effectively drive the remaining oil in the reservoir, resulting in low development efficiency. Furthermore, with excessively large well spacing, the injected reagents are prone to diffusion and loss within the channels due to the longer seepage paths, drastically reducing reagent effectiveness and increasing development costs and complexity. On the other hand, excessively small well spacing is also not ideal. Insufficient well spacing can lead to insufficient reserves controlled by a single well, especially when injection wells are located in pure aqueous phase zones or near dominant channels, where the effect of VFR adjustment is even more limited. These areas may have been overdeveloped or have significant water flow advantages, causing the injected water to concentrate mainly in these channels and fail to effectively reach the entire reservoir, thus reducing the overall effectiveness of water injection development.

[0004] Therefore, while existing methods for adjusting solubility have achieved some success in certain situations, they still have many shortcomings. To address these issues, a more refined and scientific method for adjusting solubility is urgently needed. Summary of the Invention The purpose of this invention is to provide a method and system for adjusting flow rate based on seepage theory, so as to at least solve the problems of low precision and insufficient accuracy of existing flow rate adjustment methods.

[0005] To achieve the above objectives, the first aspect of the present invention provides a method for adjusting the mobility based on seepage theory calculations. The method includes: collecting water injection-oil production condition information of each well group in a target oil production area, and calculating the seepage velocity of each well based on the water injection-oil production condition information; identifying well groups to be adjusted based on the spatial and / or temporal differences in the seepage velocity of each well; calculating the water front saturation in each well group to be adjusted based on the water injection-oil production condition information, and calculating the water drive front position in each well group to be adjusted based on the water front saturation; and determining and executing the adjustment scheme for each well group to be adjusted based on the water drive front position.

[0006] Optionally, the water injection-oil production condition information includes: historical oil production information of each well group and current oil production information of each well group.

[0007] Optionally, the historical oil production information of each well group includes: formation information before water injection and formation information within a preset time after water injection; the current oil production information of each well group includes formation information under the current condition; wherein, the formation information includes: flow rate of produced fluid, formation pressure, bottom hole pressure, formation permeability, oil layer thickness, supply radius of the current area, oil well radius, and fluid viscosity.

[0008] Optionally, the calculation rule for the seepage velocity of each well is as follows:

[0009] in, The seepage velocity; Formation permeability; and These are formation pressure and bottom hole pressure, respectively. For fluid viscosity; and These are the supply radius and oil well radius of the current area, respectively; This represents the radial distance of the fluid flow.

[0010] Optionally, the water injection-oil production condition information also includes the current reservoir parameters of each well group; wherein, the reservoir parameters include: reservoir temperature, connectivity coefficient, permeability variation coefficient, crude oil viscosity, formation water salinity, formation pressure coefficient, injection-production intensity, the proportion of wells that are effective during the water injection stage, distance from the oil-water boundary, and the degree of recovery of recoverable reserves.

[0011] Optionally, before identifying well groups to be adjusted for flow rate variation based on the spatial and / or temporal differences in the seepage velocity of each well, the method further includes: comparing each reservoir parameter with a preset reservoir parameter threshold; when the magnitude relationship between each reservoir parameter and the preset reservoir parameter threshold satisfies the judgment rule of the corresponding reservoir parameter, the corresponding well group is selected as a candidate judgment well group; within each candidate judgment well group, well groups to be adjusted for flow rate variation are identified based on the spatial and / or temporal differences in the seepage velocity of each well.

[0012] Optionally, based on the temporal differences in seepage velocities of each well, well groups to be adjusted for varying mobility are identified. This includes: performing seepage velocity calculations once for each well within the corresponding time interval based on formation information before water injection, formation information within a preset time after water injection, and formation information under the current state, to obtain the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state for the corresponding well; within each well group, well groups to be adjusted for varying mobility are identified based on the magnitude relationship between the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state.

[0013] Optionally, within each well group, the identification of well groups to be adjusted for flow rate variation is performed based on the relationship between the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state. This includes: within each well group, traversing the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state for each well. If the relationship between the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state is an increasing relationship, and the difference between the seepage velocity before water injection and the seepage velocity within a preset time after water injection is greater than a first difference threshold, and the difference between the seepage velocity within a preset time after water injection and the seepage velocity under the current state is greater than a second difference threshold, then the corresponding well is determined to have a dominant channel; the well group corresponding to the well with the dominant channel is marked as a well group to be adjusted for flow rate variation.

[0014] Optionally, based on the spatial differences in the seepage velocity of each well, the identification of well groups to be adjusted for varying mobility is performed, including: within each well group, taking the injection well in the corresponding well group as the center, calculating the standard deviation of the seepage velocity of each well group based on the seepage velocity of each well; when the standard deviation of the seepage velocity of the corresponding well group is greater than the preset standard deviation threshold, the well group corresponding to the location of the corresponding oil production well is marked as the well group to be adjusted for varying mobility.

[0015] Optionally, the step of calculating the standard deviation of the seepage velocity for each well group based on the seepage velocity of each well includes: calculating the average seepage velocity of the corresponding well group based on the seepage velocity of each well within the well group; calculating the difference between the seepage velocity of each well and the average seepage velocity, and performing a sum of squares calculation on the calculated difference to obtain the variance of the seepage velocity of the corresponding well group; and taking the square root of the variance of the seepage velocity of the corresponding well group as the standard deviation of the seepage velocity of the corresponding well group.

[0016] Optionally, the step of calculating the frontal water saturation of each well group to be adjusted based on the water injection-oil production operating condition information includes: constructing a relationship curve between water cut and water saturation in the corresponding block of each well group to be adjusted based on the relative permeability information of the target area in the water injection-oil production operating condition information; determining the bound water saturation point on the relationship curve between water cut and water saturation; drawing a tangent to the relationship curve between water cut and water saturation based on the bound water saturation point, and taking the water saturation value corresponding to the tangent point as the frontal water saturation of the corresponding well group to be adjusted.

[0017] Optionally, the location of the water drive front in each well group to be adjusted for mobility variation is calculated based on the water saturation of the front, including: determining the seepage area in each displacement direction within each well group based on the layout information between each well in the water injection-oil production operating conditions information; based on the determined seepage area in each displacement direction within each well group, and based on the reservoir difference information at the working face in the water injection-oil production operating conditions information, determining the total water volume in each displacement direction within the corresponding area area of ​​each well group, with the water injection well as the center; and determining the location of the water drive front in each well group to be adjusted for mobility variation based on the water saturation of the front, the seepage area in each displacement direction within each well group, and the total water volume in each displacement direction of each well group.

[0018] Optionally, based on the layout information between wells in the water injection-oil production operating conditions, the seepage area in each displacement direction within each well group is determined, including: calculating the water flow cross-sectional area of ​​each well within each well group based on the water flow cross-sectional area calculation model; wherein, the water flow cross-sectional area calculation model is:

[0019] Let be the cross-sectional area of ​​the water passage of the nth well; The angle between the nth well and its adjacent previous well, with the injection well as the vertex of the angle; The angle between the nth well and its next adjacent well, with the injection well as the vertex of the angle; The preset area coefficient; To utilize thickness; The radius of the water drive front is denoted as ; the cross-sectional area of ​​the water passage of each well is taken as the seepage area in the displacement direction of the corresponding well in the corresponding well group.

[0020] Optionally, the reservoir difference information of the working face includes any one or more of the following: reservoir physical property differences, connectivity, water absorption profile, and effectiveness of water injection.

[0021] Optionally, based on the determined seepage area in each displacement direction within each well group, and based on the reservoir difference information at the working face in the water injection-oil production condition information, the total water volume in each displacement direction within the corresponding area is determined with the water injection well as the center within each well group. This includes: determining the water injection volume distribution rule in each well group with the water injection well as the center to each displacement direction based on the reservoir difference information at the working face; and distributing the total water injection volume of the water injection wells based on the water injection volume distribution rule to obtain the total water volume in each displacement direction within the corresponding area.

[0022] Optionally, the water drive front position in each well group to be adjusted for different mobility is determined based on the water saturation at the front edge of each well group, the seepage area in each displacement direction of each well group, and the total water volume in each displacement direction of each well group. This includes: calculating the total water volume in each displacement direction of each well group based on the water saturation at the front edge of each well group, the seepage area in each displacement direction of each well group, and the water production ratio of each well, and determining the position where the water volume is less than a preset water volume threshold as the water drive front position of the corresponding well group to be adjusted for different mobility.

[0023] Optionally, the adjustment scheme for each well group to be adjusted based on the water drive front position includes: if the seepage velocity of each well in the well group is within a preset seepage velocity range, and the difference between the water drive front position and half the distance between the corresponding well and the injection well is less than a preset well distance difference threshold, then the corresponding well group to be adjusted does not need to be adjusted; if the seepage velocity of each well in the well group is less than the lower limit of the preset seepage velocity range, and the distance between the water drive front position and the corresponding well is greater than a first preset distance threshold, then a new well deployment adjustment needs to be performed; if the seepage velocity of each well in the well group is greater than the upper limit of the preset seepage velocity range, and the distance between the water drive front position and the corresponding well is less than a second preset distance threshold, then a displacement agent viscosity adjustment needs to be performed.

[0024] A second aspect of the present invention provides a flow rate adjustment system based on seepage theory calculations. The system includes: a data acquisition unit for acquiring water injection-oil production condition information of each well group in a target oil production area, and calculating the seepage velocity of each well based on the water injection-oil production condition information; an identification unit for identifying well groups to be adjusted based on the spatial and / or temporal differences in the seepage velocity of each well; a processing unit for calculating the water front saturation in each well group to be adjusted based on the water injection-oil production condition information, and calculating the water drive front position in each well group to be adjusted based on the water drive front position; and an execution unit for determining and executing the adjustment scheme for each well group to be adjusted based on the water drive front position.

[0025] Optionally, based on the water injection-oil production operating condition information, calculating the frontal water saturation in each well group to be adjusted for flow rate variation includes: constructing a relationship curve between water cut and water saturation in the corresponding block of each well group to be adjusted for flow rate variation based on the relative permeability information of the target area in the water injection-oil production operating condition information; determining the bound water saturation point on the relationship curve between water cut and water saturation; drawing a tangent line to the relationship curve between water cut and water saturation based on the bound water saturation point, and taking the water saturation value corresponding to the tangent point as the frontal water saturation in the corresponding well group to be adjusted for flow rate variation.

[0026] On the other hand, the present invention provides a computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the above-described method for adjusting the flow rate based on seepage theory.

[0027] Through the above technical solution, this invention achieves a refined method for adjusting the flow rate by collecting and analyzing water injection-oil production condition information of each well group in the target oil production area. First, the seepage velocity of each well is calculated, and based on the spatial and temporal differences in seepage velocity, the well groups requiring flow rate adjustment are accurately identified. Next, the location of the water drive front is determined by calculating the water saturation at the water drive front, providing a scientific basis for flow rate adjustment. Finally, based on the location of the water drive front, a targeted flow rate adjustment plan is formulated and implemented. Through this series of steps, this solution can effectively improve water drive development performance, increase water injection swept volume, and overcome the low development efficiency problems caused by unreasonable well spacing or the formation of dominant channels in existing technologies, thereby achieving more efficient reservoir development and resource utilization.

[0028] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0029] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings: Figure 1 This is a flowchart of the steps of a variable flow rate adjustment method based on seepage theory calculation provided by one embodiment of the present invention; Figure 2 This is a schematic diagram of the injection-production well angle provided in one embodiment of the present invention; Figure 3 This is a schematic diagram of the calculation results of the water drive leading edge provided in one embodiment of the present invention; Figure 4 This is a schematic diagram of the relative permeability curve of oil and water in well R105 provided by one embodiment of the present invention; Figure 5 This is a plan view of the calculation results of the seepage velocity of the R5 well group provided by one embodiment of the present invention; Figure 6 This is a plan view of the calculation results of the seepage velocity of the R11 well group provided by one embodiment of the present invention; Figure 7 This is a diagram showing the calculation results of the seepage velocity of the R11 well group and the results of the well network reconstruction provided by one embodiment of the present invention; Figure 8 This is a schematic diagram of the seepage velocity calculation parameters for well group S provided in one embodiment of the present invention; Figure 9 This is a plan view of the calculation results of the seepage velocity of the R5 well group provided by one embodiment of the present invention; Figure 10 This is a schematic diagram of the production curve of well group S provided in one embodiment of the present invention; Figure 11 This is a system structure diagram of a flow rate adjustment system based on seepage theory calculation provided by one embodiment of the present invention. Detailed Implementation

[0030] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0031] Figure 1 This is a flowchart of a method for adjusting the flow rate based on seepage theory, provided by one embodiment of the present invention. Figure 1 As shown, this invention provides a method for adjusting the fluviality based on seepage theory calculations, the method comprising: Step S10: Collect water injection-oil production condition information of each well group in the target oil production area, and calculate the seepage velocity of each well based on the water injection-oil production condition information.

[0032] Specifically, the water injection-oil production information includes: historical oil production information of each well group and current oil production information of each well group.

[0033] Furthermore, the historical oil production information of each well group includes: formation information before water injection and formation information within a preset time after water injection; the current oil production information of each well group includes formation information under the current condition; wherein, the formation information includes: flow rate of produced fluid, formation pressure, bottom hole pressure, formation permeability, oil layer thickness, supply radius of the current area, oil well radius, and fluid viscosity.

[0034] Furthermore, the calculation rules for the seepage velocity of each well are as follows:

[0035] in, The seepage velocity; Formation permeability; and These are formation pressure and bottom hole pressure, respectively. For fluid viscosity; and These are the supply radius and oil well radius of the current area, respectively; This represents the radial distance of the fluid flow.

[0036] In this embodiment of the invention, the collection of water injection-oil production condition information includes historical oil production information and current oil production information for each well group. Historical oil production information covers formation information before water injection and formation information for a preset period after water injection. This data reflects the production status of the well group at different development stages, providing a basis for calculating the seepage velocity. Current oil production information includes formation information under the current conditions, such as the flow rate of the produced fluid, formation pressure, bottom hole pressure, formation permeability, oil layer thickness, supply radius, well radius, and fluid viscosity. This information directly affects the calculation results of the seepage velocity.

[0037] According to Darcy's law, the seepage velocity of a fluid in a porous medium can be expressed as: ; By conducting detailed analysis of the formation information of each well group, the seepage velocity of each well can be calculated. Furthermore, the spatial and temporal differences in these velocities can help identify well groups requiring flow rate adjustments, providing crucial data support for optimizing water injection-oil production operations.

[0038] Furthermore, during normal production, the flow is considered to be steady. , The seepage velocity formula can be obtained.

[0039] make:

[0040]

[0041]

[0042] .

[0043] When calculating the seepage velocity of each well, the seepage velocity per unit flow rate is first calculated based on formation permeability and reservoir thickness, combined with the geological characteristics and physical parameters between wells. Secondly, considering the differences between historical and current oil production information, the actual seepage changes after water injection can be accurately assessed by comparing formation information before and after water injection. This method provides a clearer understanding of the impact of water injection on seepage velocity and the actual performance of each well group under water injection-oil production conditions.

[0044] Based on the solution of this invention, by comprehensively analyzing historical and current stratigraphic information, the actual development status of each well group can be more accurately assessed, thereby taking into account the specific circumstances of each well group when formulating water injection plans and avoiding unnecessary waste of resources.

[0045] By identifying well groups with significant differences in seepage velocity, targeted adjustments to the flow rate can be made to optimize the direction and intensity of water injection, thereby improving water drive sweep efficiency and ultimately increasing the overall oil recovery rate.

[0046] By calculating seepage rates based on actual data, potential development problems can be anticipated, such as the formation of ineffective water injection zones or the emergence of dominant water flow channels, allowing for timely intervention to reduce risks and uncertainties during development. More scientific water injection and oil recovery schemes can lower development costs, reduce ineffective water injection and reagent waste, thereby improving the economic efficiency of the oilfield.

[0047] Step S20: Identify the well group to be adjusted based on the spatial and / or temporal differences in the seepage velocity of each well.

[0048] Specifically, the water injection-oil production condition information also includes the current reservoir parameters of each well group; wherein, the reservoir parameters include: reservoir temperature, connectivity coefficient, permeability variation coefficient, crude oil viscosity, formation water salinity, formation pressure coefficient, injection-production intensity, the proportion of oil wells that are effective during the water injection stage, distance from the oil-water boundary, and the degree of recovery of recoverable reserves.

[0049] Furthermore, before identifying well groups to be adjusted for varying mobility based on the spatial and / or temporal differences in the seepage velocity of each well, the method further includes: comparing each reservoir parameter with a preset reservoir parameter threshold for the corresponding reservoir parameter; when the magnitude relationship between each reservoir parameter and the preset reservoir parameter threshold for the corresponding reservoir parameter satisfies the judgment rule for the corresponding reservoir parameter, the corresponding well group is selected as a candidate judgment well group; within each candidate judgment well group, well groups to be adjusted for varying mobility are identified based on the spatial and / or temporal differences in the seepage velocity of each well.

[0050] In this embodiment of the invention, to improve the efficiency of well group identification, the method further incorporates current reservoir parameters for initial screening. Reservoir parameters include reservoir temperature, connectivity coefficient, permeability variation coefficient, crude oil viscosity, formation water salinity, formation pressure coefficient, injection-production intensity, the proportion of wells effective during water injection, distance from the oil-water boundary, and the degree of recovery of recoverable reserves. These data are compared with preset reservoir parameter thresholds to screen well groups that meet the judgment rules, serving as candidate well groups. This effectively avoids subsequent refined judgment of all well groups, thus greatly improving the overall identification efficiency. Within the selected candidate well groups, further refined analysis is performed based on the differences in seepage velocity among each well, ultimately identifying the well groups that truly require flow rate adjustment. This method avoids ineffective water injection, reduces resource waste, and accurately determines the areas requiring adjustment, ensuring the effectiveness and relevance of the adjustment plan.

[0051] In one possible implementation, there are many dynamic and static parameters for the block. Ten parameters are preferred, namely, permeability variation coefficient, reservoir temperature, connectivity coefficient, crude oil viscosity, formation water salinity, formation pressure coefficient, and injection-production intensity, which are the main controlling factors. Based on field practice, the parameter range for blocks where flow rate adjustment is implemented is determined. The water drive effect is evaluated based on block production data. When there are differences in development effects within a block, evaluation can be conducted by zone or layer (system) as needed. Specific parameter ranges are shown in Table 1.

[0052] Table 1 Recommended reservoir parameter ranges for variable mobility design

[0053] Furthermore, based on the temporal differences in seepage velocities of each well, well groups to be adjusted for varying mobility are identified. This includes: performing seepage velocity calculations once for each well within the corresponding time interval based on formation information before water injection, formation information within a preset time after water injection, and formation information under the current state, to obtain the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state for the corresponding well; within each well group, well groups to be adjusted for varying mobility are identified based on the magnitude relationship between the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state.

[0054] Furthermore, within each well group, the identification of well groups to be adjusted for varying mobility is based on the relationship between the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state. This includes: within each well group, traversing the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state for each well. If the relationship between the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state is an increasing relationship, and the difference between the seepage velocity before water injection and the seepage velocity within a preset time after water injection is greater than a first difference threshold, and the difference between the seepage velocity within a preset time after water injection and the seepage velocity under the current state is greater than a second difference threshold, then the corresponding well is determined to have a dominant channel; the well group corresponding to the well with the dominant channel is marked as a well group to be adjusted for varying mobility.

[0055] In this embodiment of the invention, the solution calculates the seepage velocity within corresponding time intervals based on formation information for each well before water injection, within a preset time period after water injection, and in the current state. Using this data, the seepage velocity of each well in different time periods can be obtained, including the seepage velocity before water injection, the seepage velocity within the preset time period after water injection, and the seepage velocity in the current state. These changes in seepage velocity can reflect the water drive effect of the reservoir at different development stages and the impact of the water injection process on the well group.

[0056] Furthermore, after obtaining the seepage velocity data, the next step is to analyze the magnitude relationship between these seepage velocities within each well group. Specifically, by traversing the seepage velocity data of each well, it is determined whether the seepage velocity over three time periods shows a sequentially increasing trend. If the difference between the seepage velocity before water injection and the seepage velocity within a preset time after water injection is greater than a first difference threshold, and the difference between the seepage velocity within the preset time after water injection and the current seepage velocity is greater than a second difference threshold, then it can be determined that the well has a dominant water flow channel. This dominant channel usually means that water injection is mainly concentrated in a certain direction or at certain well points, while the water drive effect in other areas is poor. The well groups corresponding to the wells with dominant water flow channels are marked as well groups to be adjusted for flow rate variation. Through this identification method, flow rate variation can be adjusted in a targeted manner, thereby optimizing the water drive effect, avoiding ineffective water injection, and improving the overall efficiency of reservoir development.

[0057] Based on this invention, by analyzing the changes in seepage velocity over different time periods, it is possible to accurately identify which well groups have dominant water flow channels, thus requiring adjustments to the flow rate. This method ensures the accuracy and reliability of the identification by comparing historical and current data. After identifying well groups with dominant water flow channels, targeted adjustments can be made to improve water drive sweep efficiency, ensure uniform water injection distribution, and increase oil recovery. By identifying problematic well groups in advance, water injection and chemical application in ineffective areas can be avoided, reducing resource waste and lowering development costs. Through dynamic monitoring of seepage velocity, this method can promptly identify problems in reservoir development and make rapid adjustments, ensuring the flexibility and adaptability of reservoir development strategies.

[0058] Furthermore, based on the spatial differences in the seepage velocity of each well, the well group to be adjusted for flow rate variation is identified, including: within each well group, taking the injection well in the corresponding well group as the center, calculating the standard deviation of the seepage velocity of each well group based on the seepage velocity of each well; when the standard deviation of the seepage velocity of the corresponding well group is greater than the preset standard deviation threshold, the well group corresponding to the location of the corresponding oil production well is marked as the well group to be adjusted for flow rate variation.

[0059] Furthermore, the step of calculating the standard deviation of the seepage velocity for each well group based on the seepage velocity of each well includes: calculating the average seepage velocity of the corresponding well group based on the seepage velocity of each well within the well group; calculating the difference between the seepage velocity of each well and the average seepage velocity, and performing a sum of squares calculation on the calculated difference to obtain the variance of the seepage velocity of the corresponding well group; and taking the square root of the variance of the seepage velocity of the corresponding well group as the standard deviation of the seepage velocity of the corresponding well group.

[0060] In this embodiment of the invention, firstly, within each well group, taking the injection well as the center, the standard deviation of the seepage velocity of each well is calculated based on the seepage velocity of each well. The standard deviation of the seepage velocity is an important indicator for measuring the dispersion of the seepage velocity of each well within the well group. By calculating the standard deviation, the uniformity of the seepage velocity within the well group can be quantified. When the standard deviation of the seepage velocity of the well group is greater than a preset standard deviation threshold, it indicates that the seepage velocity difference within the well group is large, and there is a situation of concentrated water flow or uneven water injection. At this time, the well group corresponding to the location of the corresponding oil production well is designated as the well group to be adjusted for flow rate variation.

[0061] Furthermore, when calculating the standard deviation of seepage velocity, it is first necessary to calculate the average seepage velocity of each well in the well group. Then, by calculating the difference between the seepage velocity of each well and this average value, and summing the squares of these differences, the variance of the seepage velocity is obtained. Finally, by taking the square root of the variance, the standard deviation of the seepage velocity for the corresponding well group is obtained. The larger this standard deviation is, the more significant the difference in seepage velocity within the well group, that is, the more uneven the water injection effect of the well group.

[0062] Based on the present invention, by calculating the standard deviation of seepage velocity, well groups with uneven water flow, ineffective water injection zones, or dominant water flow channels can be effectively identified. This identification method can significantly improve the accuracy of flow rate adjustment, ensuring the necessity and effectiveness of the adjustment. After identifying well groups with large differences in seepage velocity, flow rate adjustments can be made in a targeted manner to improve water injection uniformity, enhance water drive sweep effect, and thus improve overall oil recovery. By avoiding ineffective water injection operations in uneven well groups, resource waste is reduced, development costs are lowered, and the economic benefits of reservoir development are improved. This method provides a simple and effective dynamic adjustment capability, enabling real-time monitoring and adjustment of water injection strategies as changes occur during the development process, ensuring continuous and efficient reservoir development.

[0063] Step S30: Based on the water injection-oil production operating condition information, calculate the water saturation of the leading edge in each well group to be adjusted for flow rate change, and calculate the position of the water drive leading edge in each well group to be adjusted for flow rate change based on the water saturation of the leading edge.

[0064] Specifically, the step of calculating the frontal water saturation of each well group to be adjusted based on the water injection-oil production operating conditions information includes: constructing a relationship curve between water cut and water saturation in the corresponding block of each well group to be adjusted based on the relative permeability information of the target area in the water injection-oil production operating conditions information; determining the bound water saturation point on the relationship curve between water cut and water saturation; drawing a tangent line to the relationship curve between water cut and water saturation based on the bound water saturation point, and taking the water saturation value corresponding to the tangent point as the frontal water saturation of the corresponding well group to be adjusted.

[0065] In this embodiment of the invention, during reservoir development, flow rate adjustment design is a key means to improve water drive sweep efficiency and optimize oilfield production. By accurately calculating the frontal water saturation, well groups requiring adjustment can be effectively identified, thereby achieving more efficient reservoir development. This method, based on water injection-production operating condition information, constructs a relationship curve between water cut and water saturation to calculate the frontal water saturation within each well group requiring flow rate adjustment, providing a scientific basis for optimizing water injection strategies.

[0066] First, based on the water injection-oil production operating conditions of the target area, relative permeability information is extracted, and a relationship curve between water cut (fw) and water saturation (Sw) is constructed. This curve, obtained through experimental measurements, reflects the seepage characteristics between the water and oil phases in the reservoir. Accurate construction of this curve is crucial for subsequent saturation calculations. After constructing the curve, the bound water saturation (Swc) point is determined. Bound water saturation is the critical saturation level at which the water phase in the reservoir is bound by capillary forces and cannot flow; it corresponds to a key point on the curve. By marking this point on the curve, tangent operations can be performed. Then, a tangent is drawn to the water cut and water saturation curves at the bound water saturation point to find the water saturation value corresponding to the tangent point. This tangent point reflects the leading edge position where the water phase begins to effectively advance during water drive; the water saturation value at this position is considered the leading edge water saturation in the well group to be adjusted for flow rate variation.

[0067] Specifically, the rule for determining the bound water saturation (Swc) point is as follows: Based on core relative permeability data, plot the relationship curve between water cut (fw) and water saturation (Sw). This curve reflects the variation law of water phase seepage in the reservoir. Analyzing the shape of the relationship curve, it is usually observed that when the water saturation is low, the relative permeability of the water phase is very low (close to zero), and the curve is relatively flat in this region. As the water saturation increases, the relative permeability of the water phase gradually increases, and the curve begins to rise. In the curve, find the inflection point where the relative permeability of the water phase begins to rise significantly. This inflection point usually marks the transition of the water phase from a bound state (non-flowing) to the point where it begins to flow. Based on the inflection point of the curve, determine the corresponding water saturation value, which is the bound water saturation (Swc). This point represents the critical saturation level in the reservoir where the water phase is bound by capillary forces and cannot flow. To ensure the accuracy of the bound water saturation point, it can be combined with actual production data or verified through multiple experiments, and Swc can be appropriately corrected if necessary.

[0068] Further, the slope of the tangent at the Swc point is determined through mathematical calculations or by using drawing tools. This step can be achieved by calculating the derivative of the curve at the Swc point. The derivative value is the slope of the tangent. At the Swc point, a tangent line is drawn using the calculated tangent slope. The point where the tangent line is tangent to the curve is the Swc point, indicating that at this saturation level, the water phase begins to transition from a bound state to a flowable state. Extending the tangent line along the direction of the curve, another intersection point is found; this intersection point is the tangent point. The tangent point represents the leading edge position where the water phase begins to effectively advance in the reservoir. The water saturation value corresponding to the tangent point is read; this value is the leading edge water saturation.

[0069] Based on the present invention, the accuracy of the calculation of the front water saturation is ensured by constructing a water cut and water saturation relationship curve based on experimental data, providing a reliable parameter basis for reservoir development. Determining the front water saturation using the tangent method accurately identifies the advancement position of the water drive front, avoiding errors that may occur in traditional methods and improving the accuracy of well group identification. After identifying the front position, the water injection strategy can be adjusted according to the actual situation to avoid the formation of dominant water flow channels, achieve uniform displacement, and thus improve water drive sweep efficiency and oil recovery rate. Precise adjustment of the flow rate avoids ineffective water injection operations, reduces resource waste, lowers oilfield development costs, and improves economic benefits.

[0070] Furthermore, the location of the water drive front in each well group to be adjusted for mobility variation is calculated based on the water saturation of the front, including: determining the seepage area in each displacement direction within each well group based on the layout information between each well in the water injection-oil production operating conditions; based on the determined seepage area in each displacement direction within each well group, and based on the reservoir difference information at the working face in the water injection-oil production operating conditions, determining the total water volume in each displacement direction within the corresponding area area of ​​each well group, with the water injection well as the center; and determining the location of the water drive front in each well group to be adjusted for mobility variation based on the water saturation of the front, the seepage area in each displacement direction within each well group, and the total water volume in each displacement direction of each well group.

[0071] Furthermore, based on the well layout information in the water injection-oil production operating conditions, the seepage area in each displacement direction within each well group is determined, including: calculating the water flow cross-sectional area of ​​each well within each well group based on the water flow cross-sectional area calculation model; wherein, the water flow cross-sectional area calculation model is:

[0072] Let be the cross-sectional area of ​​the water passage of the nth well; The angle between the nth well and its adjacent previous well, with the injection well as the vertex of the angle; The angle between the nth well and its next adjacent well, with the injection well as the vertex of the angle; The preset area coefficient; To utilize thickness; The radius of the water drive front is denoted as ; the cross-sectional area of ​​the water passage of each well is taken as the seepage area in the displacement direction of the corresponding well in the corresponding well group.

[0073] In this embodiment of the invention, the seepage area in the displacement direction can be obtained by calculating the cross-sectional area of ​​the water flow in each well. The calculation model for the cross-sectional area of ​​the water flow considers factors such as the well-to-well angle, the activated thickness, the radius of the water drive front, and the well spacing difference coefficient. These parameters collectively determine the seepage area of ​​each well, thereby affecting the analysis and optimization of the water drive effect.

[0074] In one possible implementation, during water injection development in a specific oilfield, a well group comprises five production wells and one water injection well. To optimize the water drive sweep effect of this well group, the seepage area is calculated based on the layout information of water injection well #1 and the relative positions of each production well. This includes the following steps: 1) Obtain the inter-well angle information: Determine the angle between water injection well #1 and adjacent oil production wells (#2, #3, #4, #5). According to the measurement, the angles are α1 and α5, respectively.

[0075] 2) Calculate the inter-well angles: Calculate the angles αi and αj between water injection well #1 and each oil production well, such as... Figure 2 As shown, the angle between the water injection well and the oil production well is a key parameter in the displacement direction.

[0076] 3) Calculate the cross-sectional area of ​​the water passage: The calculation model for the cross-sectional area of ​​the water passage is as follows, such as... Figure 3 The cross-sectional area β of each well is calculated as the well spacing difference coefficient (with a value between 0.2 and 0.4).

[0077] 4) Determine the seepage area: The calculated cross-sectional area of ​​the water passage is used as the seepage area in the corresponding well direction within the well group. These seepage areas determine the water drive sweep effect in each direction.

[0078] Furthermore, the reservoir difference information of the working face includes any one or more of the following: reservoir physical property differences, connectivity, water absorption profile, and effectiveness of water injection.

[0079] Furthermore, based on the determined seepage area in each displacement direction within each well group, and based on the reservoir difference information at the working face in the water injection-oil production condition information, the total water volume in each displacement direction within the corresponding area is determined with the water injection well as the center within each well group. This includes: determining the water injection volume distribution rule in each well group with the water injection well as the center to each displacement direction based on the reservoir difference information at the working face; and distributing the total water injection volume of the water injection wells based on the water injection volume distribution rule to obtain the total water volume in each displacement direction within the corresponding area.

[0080] In this embodiment of the invention, reservoir differences such as reservoir physical properties, connectivity between well groups, water absorption profiles, and water injection effectiveness are used to determine the water injection volume allocation rules for each displacement direction. Reservoir differences can include parameters such as reservoir permeability, porosity, and reservoir thickness, changes in which directly affect water drive efficiency. Furthermore, connectivity between well groups also affects water flow paths and injection effects, thus requiring comprehensive consideration. Based on this reservoir differences, a reasonable water injection volume allocation rule is formulated. Centered on the injection well, the total water injection volume is rationally allocated to each direction according to the geological conditions. This ensures that the water injection volume distribution matches the reservoir conditions, thereby enabling uniform water drive in different directions and avoiding the formation of dominant water flow channels. Next, based on the determined seepage area of ​​each well group and combined with the water injection volume allocation rule, the total water volume seeping into the two-phase zone in each seepage direction is calculated. By accurately calculating the total water volume in each direction, the entire reservoir area of ​​the well group can be effectively covered, thereby maximizing water drive sweep efficiency.

[0081] Based on the present invention, by comprehensively considering reservoir variation information, water injection volume can be allocated more scientifically, avoiding flow deviation during water injection and achieving uniformity and effectiveness. A reasonable water injection volume allocation rule ensures full utilization of the water drive sweep area in each direction, reducing the existence of unswept areas and improving the overall oil recovery rate. By accurately calculating the total water volume in each seepage direction, potential problem areas can be identified in advance, avoiding development risks caused by uneven water injection and ensuring the stability of oilfield development. Reducing ineffective water injection lowers development costs, extends the economic life of the oilfield, and thus significantly improves the economic benefits of the oilfield.

[0082] Furthermore, the water-drive front position in each well group to be adjusted for varying mobility is determined based on the water saturation at the front edge of each well group, the seepage area in each displacement direction of each well group, and the total water volume in each displacement direction of each well group. This includes: calculating the total water volume in each displacement direction of each well group based on the water saturation at the front edge of each well group, the seepage area in each displacement direction of each well group, and the water production ratio of each well, and determining the position where the water volume is less than the preset water volume threshold as the water-drive front position of the corresponding well group to be adjusted for varying mobility.

[0083] In this embodiment of the invention, the water drive front position can be scientifically determined based on the water saturation at the front of each well group to be adjusted for mobility variation, the seepage area in each displacement direction, and the total water volume of each well group in each displacement direction, thereby guiding the implementation of mobility variation adjustment. Specifically, firstly, by calculating the water saturation at the front of each well group to be adjusted for mobility variation, and combining this with the seepage area in each displacement direction, the degree of advancement of the water phase in different directions is understood. Then, based on the water production ratio of each well, the total water volume in each direction is calculated to determine the position where the water volume in each displacement direction is less than a preset water volume threshold. This position is the location of the water drive front, marking the actual advancement boundary of the water phase in the reservoir.

[0084] Based on the present invention, by combining multi-dimensional data such as front water saturation, seepage area, and total water volume, the waterflood front can be located more accurately, avoiding development deviations caused by misjudgment of the front location. Precise waterflood front location helps to formulate more reasonable water injection strategies, optimize the waterflood sweep range, and maximize recovery. Early identification and location of the waterflood front can avoid ineffective areas during water injection, thereby reducing potential risks and resource waste during development.

[0085] Step S40: Determine and execute the adjustment scheme for each well group to be adjusted based on the position of the water drive front.

[0086] Specifically, if the seepage velocity of each well in the well group is within the preset seepage velocity range, and the difference between the water drive front position and half the distance between the corresponding well and the injection well is less than the preset well distance difference threshold, then the corresponding well group to be adjusted for flow rate change does not need to be adjusted; if the seepage velocity of each well in the well group is less than the lower limit of the preset seepage velocity range, and the distance between the water drive front position and the corresponding well is greater than the first preset distance threshold, then new well deployment adjustment needs to be performed; if the seepage velocity of each well in the well group is greater than the upper limit of the preset seepage velocity range, and the distance between the water drive front position and the corresponding well is less than the second preset distance threshold, then displacement agent viscosity adjustment needs to be performed.

[0087] In this embodiment of the invention, a preliminary assessment is first performed by monitoring the seepage velocity and water drive front position of each well within each well group. If the seepage velocity of each well within the well group is within a preset seepage velocity range, and the difference between the water drive front position and half the well distance between the corresponding well and the injection well is less than a preset well distance difference threshold, then the water drive condition of the well group is considered normal, and no flow rate adjustment is required. However, when the seepage velocity deviates from the preset range, adjustments need to be made according to the specific circumstances.

[0088] Scenario 1: If the seepage velocity of each well in the well group is less than the lower limit of the preset seepage velocity range, and the distance between the water drive front and the corresponding well is greater than the first preset distance threshold, it indicates that the water injection effect is poor and the water drive coverage area is small. In this case, it is necessary to adjust the deployment of new wells. The deployment of new wells should be considered in areas with large thickness and large single-control reserves to reduce the injection-production well spacing and ensure the economic benefits and development effect of the new wells.

[0089] Scenario 2: If the seepage velocity of each well in the well group exceeds the upper limit of the preset seepage velocity range, and the distance between the water drive front and the corresponding well is less than the second preset distance threshold, it indicates that the water drive effect is too strong, a dominant water flow channel may have formed, and water injection breakthrough may have occurred in a local area. In this case, it is necessary to increase the water injection sweep volume and improve the water injection effect by adjusting the mobility. Specific measures include increasing the viscosity of the displacing agent or decreasing the viscosity of the displaced agent, reducing the mobility ratio, thereby controlling the water flow velocity and improving the water injection utilization efficiency.

[0090] In one possible implementation, during water injection development in an oilfield, after a prolonged period of production, it was discovered that water injection performance was poor in certain areas. This was manifested in low well fluid volume and production rates, with seepage velocities significantly lower than the preset lower limit of the seepage velocity range. Further geological exploration and production data analysis revealed that the water drive front in this area was far from the wells, indicating insufficient water injection coverage and preventing effective displacement of remaining oil, thus impacting overall oil production.

[0091] Detailed geological modeling and well logging data analysis revealed the existence of a thick, highly permeable sand body with significant single-control reserves in the area. The reservoir characteristics indicate that deploying new wells here would effectively cover untouched remaining oil-bearing areas and improve oil recovery. Corresponding new well deployment strategy: Based on the above analysis, it was decided to deploy one new water injection well and one new oil production well within this sand body area. The specific location design for the new well is as follows: Injection well location: New injection wells are placed in the area with the thickest reservoir to ensure that the injected water is evenly distributed throughout the reservoir and to maximize the water drive effect.

[0092] Oil well location: New oil wells are located close to water injection wells. Considering the large reserves per well, the location of oil wells also takes into account the dip angle of the reservoir and the direction of fluid flow to ensure maximum extraction of remaining oil and optimize well spacing to improve economic efficiency.

[0093] Example 1: R-block variable flow rate unadjusted well pattern design: 1) Evaluation of the water drive effect and various indicators of the high-permeability R block (Table 2) shows that there are significant differences in liquid volume and water content along the source direction and across the source direction. Combined with the water absorption profile analysis, it is determined that the water drive effect of the well group varies greatly, and there are local dominant channels.

[0094] Table 2 Statistical Results of Main Controlling Factors

[0095] 2) The water drive control rate of the R5 well group reached over 90%, with all five oil wells showing varying degrees of effectiveness. The seepage velocities were calculated before water injection, 5 years after water injection, and 10 years after water injection; the results are shown in Table 4. Figure 5 The results show that the seepage velocity increased after water injection into the existing production wells, forming a dominant channel, while the new wells remained almost unchanged, with current seepage velocities ranging from 1.5 to 7.4 m / d and exhibiting significant directionality. The calculated range is 5, and the standard deviation is 2.6, indicating a substantial difference and confirming the need for flow rate adjustment in the well group. Relevant calculation parameters are available in [link to relevant calculations]. Figure 4 Table 3. Wherein, fw: This is the water fraction, representing the proportion of the water phase in the waterflood process. It typically increases with increasing water saturation (Sw), and at higher water saturation, fw approaches 1. kro: This is the relative permeability to oil, representing the relative permeability of the oil phase in the reservoir during multiphase flow. kro typically decreases with increasing water saturation (Sw) because the increased proportion of the water phase suppresses oil flow. krw: This is the relative permeability to water, representing the relative permeability of the water phase in the reservoir during multiphase flow. krw typically increases with increasing water saturation (Sw); as the proportion of the water phase in the reservoir increases, the water phase flows more easily within the reservoir.

[0096] Table 3 Calculation parameters of seepage velocity in well group R5

[0097] Table 4 Calculation results of seepage velocity in well group R5

[0098] 3) Based on the production of each well, the water drive front of each well was calculated, taking into account the potential for sudden surges caused by inter-well conflicts. The results are shown in Table 5. Based on the injection-production well spacing, the location of the water drive front, and the current production, the well network of this well group is relatively reasonable and does not require adjustment.

[0099] Table 5 Calculation results of water drive leading edge position

[0100] Example 2: R11 well group variable mobility adjustment well network design: 1) The water drive effect and various indicators of the R11 well group and the R5 well group are the same (Table 2). The production characteristics are that the liquid volume and water content are significantly different. Based on the water intake profile analysis, it is determined that the water drive effect of the well groups is significantly different, and there are local dominant channels.

[0101] 2) The water drive control rate of the R11 well group reached over 80%, affecting all 5 oil wells to varying degrees. This well had a relatively long water injection period. The seepage rates were calculated before the final stage of water injection, 2 years after water injection, and 5 years after water injection. The results are as follows: Figure 6 Table 7 shows the results. As can be seen, due to long-term water injection, the original production wells have dominant channels, with significant differences between wells. The seepage velocity within the well group varies from 0.2 to 9.9 m / d, exhibiting clear directionality with a standard deviation of up to 3.9, indicating substantial variation. This confirms that the well group requires flow rate adjustment. Relevant calculation parameters are shown in [Table 7]. Figure 4 Table 6.

[0102] Table 6 Calculation parameters of seepage velocity in well group R11

[0103] Table 7 Calculation results of seepage velocity in well group R11

[0104] 3) Based on the production of each well, and considering the potential for sudden surges due to inter-well conflicts, the water drive front of each well was calculated. The results are shown in Table 8. The results show that the calculated water drive front positions for wells R6-07, R6-K7, and R7-6 are relatively small. Well R6-K7 has a shorter production time and will not be adjusted for now. Wells R6-07 and R7-6 have poor water injection effects, and the current well network cannot meet the requirements for flow rate adjustment. Additionally, well R7-07 is experiencing problems. Considering the reservoir development at this location, as well as production capacity and economic benefits, three more wells will be designed to be side-drilled between R7-6 and R6-K7, and between R7-07 and R6-K7. Figure 7 ).

[0105] Table 8 Calculation results of water drive leading edge position

[0106] Example 3: S-well group's variable flow rate unadjusted well network design and the effect of variable flow rate implementation: 1) The water drive effect and various indicators of a medium-high permeability S block were evaluated (Table 9). It was found that the planar heterogeneity was strong and the dominant channels were well developed. The whole area had high water content and dominant channels were generally present.

[0107] Table 9 Statistical Results of Main Controlling Factors

[0108] 2) The water drive control rate of the S well group reached over 85%, corresponding to 4 oil wells, all of which were effective to varying degrees. The seepage velocities were calculated before water injection, 5 years after water injection, 10 years after water injection, and after adjusting for flow rate variation. The results are shown in Table 11. Figure 9 The results show that after water injection, the seepage velocity in the original production wells increased, forming a dominant channel with obvious directionality. The calculated standard deviation was 10.5, a significant difference, necessitating adjustments to the flow rate. Relevant calculation parameters are available in [link to relevant calculations]. Figure 8 Table 10.

[0109] Table 10 Calculation parameters of seepage velocity in Well S group

[0110] Table 11 Calculation results of seepage velocity in well group S

[0111] 3) Based on the production of each well, and considering the potential for sudden surges due to inter-well conflicts, the water drive front of each well was calculated. The results are shown in Table 12. Based on the injection-production well spacing, the location of the water drive front, and the current production, the well network of this well group is relatively reasonable and does not require adjustment. Table 12 Calculation results of water drive leading edge position

[0112] 4) After adjusting the flow rate, the standard deviation of the seepage velocity decreased to 7.4. As can be seen from the production curve, the output steadily increased, the water content decreased significantly, and the effect of increasing oil production and controlling water was obvious. Figure 10 ).

[0113] Figure 11 This is a system structure diagram of a variable flow rate adjustment system based on seepage theory calculations provided in one embodiment of the present invention. Figure 11 As shown, this invention provides a flow rate adjustment system based on seepage theory calculations. The system includes: a data acquisition unit for acquiring water injection-oil production condition information of each well group in the target oil production area, and calculating the seepage velocity of each well based on the water injection-oil production condition information; an identification unit for identifying well groups to be adjusted based on the spatial and / or temporal differences in the seepage velocity of each well; a processing unit for calculating the water front saturation in each well group to be adjusted based on the water injection-oil production condition information, and calculating the water drive front position in each well group to be adjusted based on the water front saturation; and an execution unit for determining and executing the adjustment scheme for each well group to be adjusted based on the water drive front position.

[0114] Preferably, calculating the frontal water saturation of each well group to be adjusted based on the water injection-oil production operating condition information includes: constructing a relationship curve between water cut and water saturation in the corresponding block of each well group to be adjusted based on the relative permeability information of the target area in the water injection-oil production operating condition information; determining the bound water saturation point on the relationship curve between water cut and water saturation; drawing a tangent line to the relationship curve between water cut and water saturation based on the bound water saturation point, and taking the water saturation value corresponding to the tangent point as the frontal water saturation of the corresponding well group to be adjusted.

[0115] The present invention also provides a computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the above-described method for adjusting flow rate based on seepage theory.

[0116] Those skilled in the art will understand that all or part of the steps in the methods of the above embodiments can be implemented by a program instructing related hardware. This program is stored in a storage medium and includes several instructions to cause a microcontroller, chip, or processor to execute all or part of the steps of the methods described in the various embodiments of the present invention. The aforementioned storage medium includes various media capable of storing program code, such as a USB flash drive, a portable hard drive, a read-only memory (ROM), a random access memory (RAM), a magnetic disk, or an optical disk.

[0117] The optional embodiments of the present invention have been described in detail above with reference to the accompanying drawings. However, the embodiments of the present invention are not limited to the specific details described above. Within the scope of the technical concept of the embodiments of the present invention, various simple modifications can be made to the technical solutions of the embodiments of the present invention, and these simple modifications all fall within the protection scope of the embodiments of the present invention. It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. To avoid unnecessary repetition, the embodiments of the present invention will not further describe the various possible combinations.

[0118] Furthermore, various different embodiments of the present invention can be combined in any way, as long as they do not violate the spirit of the embodiments of the present invention, they should also be regarded as the content disclosed by the embodiments of the present invention.

Claims

1. A method for adjusting the fluviality based on seepage theory, characterized in that, The method includes: Within the target area, well groups are divided, water injection-oil production condition information of each well group is collected, and the seepage velocity of each well is calculated based on the water injection-oil production condition information. Based on the spatial and / or temporal differences in the seepage velocity of each well, the well group to be adjusted for varying mobility is identified. Based on the water injection-oil production operating condition information, the water saturation of the leading edge in each well group to be adjusted for flow rate is calculated, and the position of the water drive leading edge in each well group to be adjusted for flow rate is calculated based on the water saturation of the leading edge. Based on the location of the water drive front, the adjustment schemes for each well group to be adjusted for different flow rates are determined and implemented.

2. The method according to claim 1, characterized in that, The water injection-oil production operating condition information includes: Historical oil production information and current oil production information for each well group.

3. The method according to claim 2, characterized in that, The historical oil production information of each well group includes: formation information before water injection and formation information within a preset time after water injection; The current oil production information for each well group includes formation information under its current condition; among which, Formation information includes: produced fluid flow rate, formation pressure, bottom hole pressure, formation permeability, reservoir thickness, current supply radius, well radius, and fluid viscosity.

4. The method according to claim 3, characterized in that, The calculation rules for the seepage velocity of each well are as follows: in, The seepage velocity; Formation permeability; and These are formation pressure and bottom hole pressure, respectively. For fluid viscosity; and These are the supply radius and oil well radius of the current area, respectively; This represents the radial distance of the fluid flow.

5. The method according to claim 2, characterized in that, The water injection-oil production operating condition information also includes the current reservoir parameters of each well group; among which... The reservoir parameters include: reservoir temperature, connectivity coefficient, permeability variation coefficient, crude oil viscosity, formation water salinity, formation pressure coefficient, injection-production intensity, the proportion of wells that are effective during the water injection stage, distance from the oil-water boundary, and the degree of recovery of recoverable reserves.

6. The method according to claim 5, characterized in that, Before identifying the well group to be adjusted for varying mobility based on the spatial and / or temporal differences in seepage velocities of each well, the method further includes: Each reservoir parameter is compared with the preset reservoir parameter threshold. When the magnitude relationship between each reservoir parameter and the preset reservoir parameter threshold satisfies the judgment rule of the corresponding reservoir parameter, the corresponding well group is selected as a candidate judgment well group. Within each candidate well group, well groups to be adjusted for varying mobility are identified based on the spatial and / or temporal differences in the seepage velocity of each well.

7. The method according to claim 3, characterized in that, Based on the temporal differences in seepage velocities among the wells, the well groups to be adjusted for varying mobility are identified, including: Based on the formation information before water injection, the formation information within a preset time after water injection, and the formation information under the current state, the seepage velocity calculation is performed once within the corresponding time interval for each well to obtain the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state for the corresponding well. Within each well group, the well group to be adjusted for varying mobility is identified based on the relationship between the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state.

8. The method according to claim 7, characterized in that, Within each well group, the well group to be adjusted for varying mobility is identified based on the relationship between the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current condition. This includes: Within each well group, the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state are traversed. The magnitude of the seepage velocity before water injection, the seepage velocity within a preset time after water injection, and the seepage velocity under the current state are in an increasing relationship. If the difference between the seepage velocity before water injection and the seepage velocity within a preset time after water injection is greater than the first difference threshold, and the difference between the seepage velocity within a preset time after water injection and the seepage velocity under the current state is greater than the second difference threshold, then it is determined that the corresponding well has an advantageous channel. Well groups with dominant channels are designated as well groups to be adjusted for flow rate variation.

9. The method according to claim 2, characterized in that, Based on the spatial differences in seepage velocity among the wells, the identification of well groups to be adjusted for varying mobility is performed, including: Within each well group, taking the injection well in the corresponding well group as the center, the standard deviation of the seepage velocity of each well group is calculated based on the seepage velocity of each well. When the standard deviation of the seepage velocity of the corresponding well group is greater than the preset standard deviation threshold, the well group corresponding to the oil production well location is marked as the well group to be adjusted for flow rate variation.

10. The method according to claim 9, characterized in that, The calculation of the standard deviation of the seepage velocity for each well group based on the seepage velocity of each well includes: Based on the seepage velocity of each well in the well group, calculate the average seepage velocity of the corresponding well group; Calculate the difference between the seepage velocity of each well and the average seepage velocity, and perform a sum of squares calculation on the calculated difference to obtain the variance of the seepage velocity of the corresponding well group; Take the square root of the variance of the seepage velocity of the corresponding well group as the standard deviation of the seepage velocity of the corresponding well group.

11. The method according to claim 1, characterized in that, The calculation of the fore-edge water saturation in each well group to be adjusted for flow rate variation based on the water injection-oil production operating information includes: Based on the relative permeability information of the target area in the water injection-oil production operating conditions information, the relationship curve between water cut and water saturation in the corresponding block of each well group to be adjusted for flow rate variation is constructed. The bound water saturation point is determined on the curve relating moisture content and water saturation. Based on the relationship curve between bound water saturation point and water cut and water saturation, the water saturation value corresponding to the tangent point is taken as the front water saturation of the corresponding well group to be adjusted for flow rate variation.

12. The method according to claim 11, characterized in that, The waterdrive front locations within each well group requiring flow rate adjustment are obtained based on the water saturation calculation at the front, including: Based on the layout information between wells in the water injection-oil production operating conditions information, the seepage area in each displacement direction within each well group is determined; Based on the determined seepage area in each displacement direction within each well group, and based on the reservoir difference information at the working face in the water injection-oil production condition information, the total water volume in each displacement direction within the corresponding area is determined with the water injection well as the center in each well group. The water drive front position in each well group to be adjusted for varying mobility is determined based on the water saturation at the front edge, the seepage area in each displacement direction within each well group, and the total water volume in each displacement direction within each well group.

13. The method according to claim 12, characterized in that, Based on the layout information between wells in the water injection-oil production operating conditions, the seepage area in each displacement direction within each well group is determined, including: Based on the cross-sectional area calculation model, the cross-sectional area of ​​water flow for each well within each well group is calculated; among which, The calculation model for the cross-sectional area of ​​the water passage is as follows: Let be the cross-sectional area of ​​the water passage of the nth well; The angle between the nth well and its adjacent previous well, with the injection well as the vertex of the angle; The angle between the nth well and its next adjacent well, with the injection well as the vertex of the angle; The preset area coefficient; To utilize thickness; The radius of the water drive leading edge; The cross-sectional area of ​​each well is taken as the seepage area in the displacement direction of the corresponding well in the corresponding well group.

14. The method according to claim 12, characterized in that, The reservoir heterogeneity information of the working face includes: Any one or more of the following: reservoir physical property differences, connectivity, water absorption profile, and effectiveness of water injection.

15. The method according to claim 12, characterized in that, Based on the determined seepage area in each displacement direction within each well group, and taking into account the reservoir differences at the working face in the water injection-oil production operating conditions, the total water volume in each displacement direction within the corresponding area region of each well group, centered on the water injection well, is determined, including: Based on the reservoir differences at the working face, determine the water injection volume distribution rules within each well group, centered on the injection well and extending to each displacement direction; Based on the aforementioned water injection allocation rule, the total water injection volume of the injection well is allocated to obtain the total water volume in each displacement direction within the corresponding area.

16. The method according to claim 12, characterized in that, The location of the water drive front in each well group to be adjusted for varying mobility is determined based on the water saturation at the front, the seepage area in each displacement direction within each well group, and the total water volume in each displacement direction. This includes: Based on the water saturation at the leading edge of each well group to be adjusted for different mobility, the seepage area in each displacement direction within each well group, and the water production ratio of each well, the total water volume of each well group in each displacement direction is calculated, and the position where the water volume is less than the preset water volume threshold is determined as the water drive leading edge position of the corresponding well group to be adjusted for different mobility.

17. The method according to claim 1, characterized in that, The adjustment scheme for each well group to be adjusted based on the location of the water drive front includes: If the seepage velocity of each well in the well group is within the preset seepage velocity range, and the difference between the water drive front position and half the well distance between the corresponding well and the injection well is less than the preset well distance difference threshold, then the corresponding well group to be adjusted for flow rate adjustment does not need to be adjusted. If the seepage velocity of each well in the well group is less than the lower limit of the preset seepage velocity range, and the distance between the water drive front and the corresponding well is greater than the first preset distance threshold, then a new well deployment adjustment needs to be performed. If the seepage velocity of each well in the well group is greater than the upper limit of the preset seepage velocity range, and the distance between the water drive front and the corresponding well is less than the second preset distance threshold, then the displacement agent viscosity adjustment needs to be performed.

18. A fluviality adjustment system based on seepage theory calculations, characterized in that, The system includes: The data acquisition unit is used to collect water injection-oil production condition information of each well group in the target oil production area, and to calculate the seepage velocity of each well based on the water injection-oil production condition information. The identification unit is used to identify well groups to be adjusted based on the spatial and / or temporal differences in the seepage velocity of each well. The processing unit is used to calculate the water saturation of the leading edge in each well group to be adjusted based on the water injection-oil production condition information, and to calculate the position of the water drive leading edge in each well group to be adjusted based on the water saturation of the leading edge. The execution unit is used to determine and execute the adjustment scheme of each well group to be adjusted based on the position of the water drive front.

19. The system according to claim 18, characterized in that, Based on the aforementioned water injection-oil production operating condition information, the calculation of the fore-edge water saturation in each well group to be adjusted for flow rate variation includes: Based on the relative permeability information of the target area in the water injection-oil production operating conditions information, the relationship curve between water cut and water saturation in the corresponding block of each well group to be adjusted for flow rate variation is constructed. The bound water saturation point is determined on the curve relating moisture content and water saturation. Based on the relationship curve between bound water saturation point and water cut and water saturation, the water saturation value corresponding to the tangent point is taken as the front water saturation of the corresponding well group to be adjusted for flow rate variation.

20. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores instructions that, when executed on a computer, cause the computer to perform the flow rate adjustment method based on seepage theory calculations as described in any one of claims 1-17.

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