A follow-up water drive potential tapping method based on flow field comprehensive analysis

Abstract

This invention discloses a method for tapping the potential of subsequent waterflooding based on comprehensive flow field analysis, belonging to the technical field of residual oil tapping in the high water-cut stage of oilfield development in the mid-to-late stage. The method includes: quantitatively identifying dominant seepage channels based on the streamline distribution, oil saturation field, and water-to-flow ratio of the target reservoir; classifying six types of residual oil and clarifying their distribution characteristics; and proposing differentiated tapping strategies for different types of residual oil by combining pressure system research and reasonable injection-production ratio control. This invention effectively solves the development problem of high water-cut and low recovery rates in the subsequent waterflooding stage of polymer flooding, and can significantly improve reservoir recovery and development efficiency.

Description

Technical Field

[0001] This application relates to the field of residual oil tapping technology in the high water-cut stage of oilfield development in the middle and late stages, and particularly to a subsequent water drive tapping method based on comprehensive flow field analysis. Background Technology

[0002] Polymer flooding (hereinafter referred to as "polymer flooding") is an important technical means to improve oilfield recovery. By injecting polymer solutions into the reservoir, the water phase mobility ratio is improved and the swept volume is increased, thus achieving efficient crude oil extraction. However, after polymer flooding ends and the subsequent water flooding stage begins, the reservoir faces multiple development challenges: during polymer flooding, polymers are adsorbed and retained in the formation pores, exacerbating formation heterogeneity. This leads to injected water easily flowing along high-permeability channels during the subsequent water flooding process, forming a "water channeling" phenomenon, which causes a sharp decline in oil production.

[0003] Existing technologies are based on general injection-production ratio control techniques using dynamic production data. This method calculates the injection-production ratio adjustment coefficient using empirical formulas by statistically analyzing the overall liquid production, oil production, and water cut trends of the block, and then adjusts the water injection intensity.

[0004] However, in areas with well-developed flow channels, the existing technology still suffers from severe water channeling due to the lack of targeted control over water injection intensity. In low-permeability areas with abundant residual oil, the indiscriminate adjustment leads to insufficient water injection, making it impossible to effectively utilize the residual oil. This ultimately results in the development problem of high water cut and low recovery rate in the subsequent water flooding stage of polymer flooding, with only a small increase in recovery rate, which is difficult to meet the requirements of oilfield development efficiency. Summary of the Invention

[0005] Therefore, it is necessary to provide a subsequent water-drive potential tapping method based on comprehensive flow field analysis to address the aforementioned technical problems.

[0006] The present invention adopts the following technical solution:

[0007] This invention provides a subsequent water-drive potential tapping method based on comprehensive flow field analysis, comprising:

[0008] The reservoir to be adjusted is gridded into multiple reservoir blocks; and the characteristic curves of pump efficiency and pump inlet pressure of the pumping unit are obtained.

[0009] Determine the formation pressure system characteristics of the reservoir to be adjusted, and determine the formation pressure limits of the reservoir block based on the formation pressure system characteristics.

[0010] The bubble point pressure of crude oil in each reservoir block was determined, and the minimum flow pressure of each reservoir block was determined based on the bubble point pressure theory. A correlation equation between the pump inlet pressure of the pumping unit and the flow pressure of the reservoir block was established. The pump inlet pressure corresponding to the preset minimum pump efficiency threshold in the characteristic curve of pump efficiency and pump inlet pressure was substituted into the correlation equation between the pump inlet pressure of the pumping unit and the flow pressure of the reservoir block to obtain the minimum reasonable flow pressure. The maximum value between the minimum flow pressure and the minimum reasonable flow pressure was determined as the flow pressure limit of each reservoir block.

[0011] Based on the formation pressure and flow pressure limits of each reservoir block, the injection-production ratio control strategy for the reservoirs to be adjusted is determined, so as to determine the potential tapping measures for each type of remaining oil in the reservoirs to be adjusted.

[0012] Preferably, the reservoir to be adjusted is gridded into multiple reservoir blocks, specifically including:

[0013] Obtain the static reservoir properties and development dynamic data of the reservoir to be adjusted; the static reservoir properties include lithology, porosity, and permeability; the development dynamic data includes cumulative water injection, production, and water cut.

[0014] Based on the static properties of the reservoir and the dynamic data of development, a three-dimensional grid model of the reservoir to be adjusted is constructed, and the reservoir to be adjusted is gridded into multiple reservoir blocks.

[0015] Preferably, before determining the formation pressure system characteristics of the reservoir to be adjusted, the method further includes:

[0016] Obtain the streamline distribution, reservoir water permeability, and oil saturation of each reservoir block;

[0017] Based on the reservoir's water permeability and oil saturation, the dominant seepage channels in the reservoir to be adjusted are identified through quantitative analysis, specifically including:

[0018] Streamlines with a water permeability ratio greater than or equal to 100 and an oil saturation of 0.2 to 0.3 in all reservoir blocks are identified as high-permeability pathways for fluid flow in the reservoir to be adjusted, i.e., initial dominant seepage channels.

[0019] In oil reservoir blocks containing initial dominant flow channels, the dominant flow channels for high water-cut wells are determined from the initial dominant flow channels by fitting the relationship between the reservoir water permeability ratio and the water-cut breakthrough probability; wherein, the water-cut breakthrough probability is the probability that the water cut of a production well in the oilfield first exceeds 80%.

[0020] In high water-cut wells, streamlines with oil saturation less than 0.2 and flow velocity greater than 4 m / s are identified as dominant seepage channels.

[0021] Among them, the dominant seepage direction of the dominant seepage channel is the dense area of ​​streamline distribution.

[0022] Preferably, the dominant seepage channels for high water-cut wells are determined from the initial dominant seepage channels by fitting the relationship between the reservoir water permeability ratio and the water-cut breakthrough probability, specifically including:

[0023] A quantitative relationship model is established between the water-cut breakthrough probability and the reservoir water abundance ratio. The formula is as follows:

[0024] ;

[0025] In the formula, This represents the breakthrough probability for water content. The water permeability ratio of the oil reservoir. , The fitting coefficients are obtained by the maximum likelihood estimation method.

[0026] The critical reservoir water permeability multiple is calculated by substituting a preset water-cut breakthrough probability threshold into a quantitative relationship model.

[0027] In the initial dominant flow channels, streamlines with a reservoir water permeability greater than the critical water permeability and a corresponding reservoir block water cut exceeding 80% are selected to obtain the dominant flow channels for high water-cut wells.

[0028] Preferably, the formation pressure system characteristics of the reservoir to be adjusted are determined, and the formation pressure limits of the reservoir block are determined based on the formation pressure system characteristics, specifically including:

[0029] Obtain the fluid production, oil production, and water cut of each reservoir block;

[0030] The formation pressure system characteristics of the oilfield to be adjusted were obtained using reservoir engineering and numerical simulation methods.

[0031] Using a multiple linear regression model, correlation equations were established between the characteristics of the formation pressure system and the production, oil production, and water cut of the reservoir block to be adjusted. The preset oil production constraints, water cut constraints, and oilfield reservoir protection constraints were substituted into the correlation equations to solve for the formation pressure range that satisfies all constraints, i.e., the formation pressure limit of the reservoir block.

[0032] Preferably, reservoir engineering and numerical simulation methods are used to obtain the pressure system characteristics of the reservoir to be adjusted, specifically including:

[0033] Pressure recovery well testing, interference well testing, and production splitting techniques were used to obtain bottom hole pressure, formation permeability, and pressure conductivity coefficients at different layers in each reservoir block.

[0034] Based on the bottom hole pressure, formation permeability, and pressure conductivity of different layers in each reservoir block, a plane pressure contour map of the block is drawn using statistical analysis to identify high pressure areas, low pressure areas, and pressure transition areas.

[0035] Layered testing technology was used to collect pressure data of each layer in the vertical direction and to calculate the interlayer pressure difference of the reservoir to be adjusted.

[0036] Construct a three-dimensional geological model of the reservoir to be adjusted;

[0037] The three-dimensional geological model was imported into the numerical simulation software. The interlayer pressure difference of the reservoir to be adjusted was numerically simulated using the black oil model to simulate the pressure field evolution process of the reservoir at different development stages and obtain the numerical simulation results, namely the horizontal inter-well pressure transmission law and the vertical inter-layer pressure transmission efficiency.

[0038] Based on the interlayer pressure difference of the reservoir to be adjusted and the numerical simulation results, the pressure system characteristics of the horizontal pressure gradient distribution and the vertical interlayer pressure difference distribution are formed.

[0039] Preferably, the process of determining the formation pressure limit of the reservoir block specifically includes:

[0040] Multiple linear regression analysis was used to construct correlation equations between formation pressure and fluid production, oil production, and water cut, respectively. The formulas are as follows:

[0041] ;

[0042] ;

[0043] P+ ;

[0044] In the formula, To adjust the production rate of the reservoir, For oil production, Moisture content, For formation pressure, , , , , and These are the regression coefficients;

[0045] Substituting the preset constraints into the correlation equation, the formation pressure range that satisfies all constraints is obtained, which is the formation pressure limit.

[0046] The preset constraints include: oil production is greater than or equal to the lower limit of the block's economic oil production; water cut is less than or equal to the upper limit of the block's economic water cut; formation pressure is less than or equal to the reservoir fracture pressure, and the reservoir fracture pressure is greater than or equal to the crude oil saturation pressure.

[0047] The lower limit of the block economy oil production and the upper limit of the block economy water content are determined based on development costs and crude oil prices.

[0048] Preferably, the process of determining the flow pressure limit specifically includes:

[0049] Determine the bubble point pressure Pb of crude oil in the block;

[0050] Based on the bubble point pressure theory, to avoid degassing during oil extraction, the flow pressure of the reservoir block must be greater than or equal to the product of the crude oil bubble point pressure and the safety factor. Therefore, the product of the crude oil bubble point pressure and the safety factor is the minimum flow pressure of the reservoir block. ;

[0051] Establish the relationship between pump inlet pressure and flow pressure, as shown in the following formula:

[0052] ;

[0053] In the formula, This refers to the pump inlet pressure of the oil pump. The flow pressure of the reservoir block, , , These represent the density, gravitational acceleration, and depth of the well fluid in the well group within the oil reservoir block, respectively. This is a pressure correction parameter used to quantify the sum of all factors, excluding gravity, that cause pressure drop during the process of fluid entering the well group from the reservoir and rising to the pump inlet.

[0054] Set minimum threshold for pump efficiency Based on the characteristic curve of pump efficiency versus pump inlet pressure, find the pump inlet pressure value corresponding to the minimum threshold of pump efficiency, and substitute it into the correlation equation between pump inlet pressure and flow pressure to obtain the flow pressure. The value;

[0055] Introducing correction coefficients Correcting flow pressure With minimum flow pressure The maximum value between these two values ​​yields the flow pressure limit, expressed as:

[0056] ;

[0057] In the formula, Flow pressure limit This is a correction factor.

[0058] Preferably, based on the formation pressure limit and flow pressure limit of each reservoir block, the injection-production ratio control strategy for the reservoir to be adjusted is determined, specifically including:

[0059] By analyzing the relationship between the injection-production ratio and the water cut and recovery rate of the reservoir block, the range of the injection-production ratio was determined to be 0.8≤IPR≤1.2, where IPR is the injection-production ratio.

[0060] For areas where the actual formation pressure is less than the lower limit of the formation pressure limit and the actual flow pressure is less than the flow pressure limit, the injection-production ratio will be adjusted to 1.1-1.2.

[0061] For areas where the actual formation pressure is greater than or equal to the lower limit of the formation pressure limit and less than or equal to the upper limit of the formation pressure limit, and the actual flow pressure is greater than or equal to the flow pressure limit and less than or equal to 9.8 MPa, the injection-production ratio will be adjusted to 0.95-1.05.

[0062] For areas where the actual formation pressure is greater than the upper limit of the formation pressure limit and the actual flow pressure is greater than the flow pressure limit, the injection-production ratio will be adjusted to 0.8-0.9.

[0063] Every three months, the production volume, oil production, water cut, formation pressure, and flowing pressure to be adjusted are collected. The correlation equations between the formation pressure system characteristics and the production volume, oil production, and water cut of the reservoir block to be adjusted, as well as the correlation equation between the pump inlet pressure and the flowing pressure, are substituted into the data to recalibrate the injection-production ratio parameters and achieve real-time optimization of the strategy.

[0064] Preferably, the type of remaining oil in the reservoir to be adjusted is determined based on the streamline distribution of the reservoir block corresponding to the dominant seepage channels; the types of remaining oil in the oilfield to be adjusted include: remaining oil at the top of thick oil layers, remaining oil at distributary locations, remaining oil in phase transition zones, remaining oil in areas of deteriorated physical properties, remaining oil due to interlayer interference, and remaining oil at the edge of sand bodies; the potential tapping measures for the remaining oil include:

[0065] For the remaining oil at the top of the thick oil layer, long rubber sleeves are used to seal the high-permeability section at the bottom of the thick oil layer, or horizontal wells are used for segmented injection and production to change the direction of fluid flow and drive the remaining oil at the top to move downward.

[0066] The remaining oil at the flow line location can be moved to the production well by adjusting the injection intensity of adjacent water injection wells or implementing periodic water injection to change the pressure field and flow line direction.

[0067] The remaining oil in the phase change zone and the remaining oil in the area with deteriorated physical properties are used to modify the low-permeability reservoir using fracturing technology to improve its conductivity.

[0068] To mitigate inter-layer interference with remaining oil, layer subdivision and reorganization, or the use of intelligent completion tools for selective production and water injection, can be implemented.

[0069] For residual oil at the edge of the sand body, the sweep efficiency can be improved by deploying infill wells or sidetracking wells at the edge, or by optimizing the parameters of the injection-production well network at the edge.

[0070] For water channeling problems caused by dominant seepage channels, mechanical or chemical water blocking is implemented, and deep profile adjustments are made to the highly absorbent layers to seal or bypass the highly permeable channels.

[0071] The above-mentioned at least one technical solution adopted in this invention can achieve the following beneficial effects:

[0072] In the subsequent waterflooding potential tapping method based on comprehensive flow field analysis provided by this invention, the bubble point pressure of crude oil is measured. Combined with the pump efficiency and pump inlet pressure characteristic curves, the flow pressure limit that can both suppress downhole degassing and ensure lifting efficiency is theoretically derived and calculated. Based on the constraint of the flow pressure limit, a differentiated injection-production ratio control strategy is dynamically formulated to accurately match the water injection intensity with the pressure state and remaining oil type in different areas. This transforms the traditional general adjustment into precise control with multi-parameter coordination, effectively solving the development contradiction caused by the coexistence of water channeling in advantageous channels and insufficient water injection in low-permeability areas in the subsequent waterflooding stage of polymer flooding. It significantly improves the utilization of remaining oil and the overall recovery rate of the block, realizing the continuous and efficient development of the oilfield during the high water-cut period.

[0073] In addition, this invention also accurately identifies the dominant seepage channels that are prone to water channeling after polymer flooding by gridding reservoir blocks and obtaining multi-dimensional dynamic data such as streamline distribution, oil saturation and water permeability of each block, and classifies the remaining oil distribution type accordingly, thereby transforming the general target of tapping the potential of remaining oil into specific and operable classification target areas.

[0074] In addition, a quantitative correlation equation between formation pressure system characteristics and production volume, oil production, and water cut was established using a multiple linear regression model. This equation was then substituted with oil production constraints, water cut constraints, and reservoir protection constraints to solve the problem. This scientifically determined the reasonable limits of formation pressure in different blocks. Combined with the flow pressure limits, this further improved the accuracy of matching water injection intensity with the pressure state and remaining oil type in different areas. This helps to resolve the development contradictions caused by the coexistence of water channeling in advantageous channels and insufficient water injection in low-permeability areas during the subsequent water drive stage of polymer flooding. Attached Figure Description

[0075] The accompanying drawings, which are included to provide a further understanding of this application and form part of this application, illustrate exemplary embodiments and are used to explain this application, but do not constitute an undue limitation of this application. In the drawings:

[0076] Figure 1 A schematic diagram of a subsequent water-drive potential tapping method based on comprehensive flow field analysis provided by the present invention;

[0077] Figure 2 A scatter plot showing the relationship between grid flow ratio and water saturation in a subsequent water-drive potential tapping method based on comprehensive flow field analysis provided by this invention.

[0078] Figure 3 A schematic diagram illustrating the superior seepage channel identification of a subsequent water-drive potential tapping method based on comprehensive flow field analysis provided by this invention;

[0079] Figure 4 The remaining oil classification and distribution map is provided by the present invention for a subsequent water-drive potential tapping method based on comprehensive flow field analysis;

[0080] Figure 5 A pressure system and injection-production ratio relationship diagram for a subsequent water drive potential tapping method based on comprehensive flow field analysis provided by the present invention;

[0081] Figure 6 A graph showing the relationship between different flow pressure limits for subsequent water-drive potential tapping methods based on comprehensive flow field analysis, provided by this invention.

[0082] Figure 7 A prediction diagram of the potential tapping effect of a subsequent water-drive potential tapping method based on comprehensive flow field analysis provided by the present invention;

[0083] Figure 8 The diagram illustrates an optimized residual oil method for subsequent water-drive potential tapping based on comprehensive flow field analysis, as provided by this invention.

[0084] Figure 9 A diagram of a computer device for implementing a subsequent water-drive potential tapping method based on comprehensive flow field analysis, provided by the present invention. Detailed Implementation

[0085] To make the objectives, technical solutions, and advantages of this invention clearer, the technical solutions of this application will be clearly and completely described below in conjunction with specific embodiments and corresponding drawings. Obviously, the described embodiments are only a part of the embodiments of this application, and not all of them. All other embodiments obtained by those skilled in the art based on the embodiments in the specification without creative effort are within the scope of protection of this application.

[0086] The technical solutions provided by the various embodiments of this application are described in detail below with reference to the accompanying drawings.

[0087] Figure 1 This is a schematic diagram of a subsequent water-drive potential tapping method based on comprehensive flow field analysis in this invention, which specifically includes the following steps:

[0088] S101: Grid the reservoir to be adjusted into multiple reservoir blocks; and obtain the characteristic curves of pump efficiency and pump inlet pressure of the pumping unit;

[0089] Specifically, the reservoir to be adjusted is gridded into multiple reservoir blocks, including: acquiring the reservoir static attributes and development dynamic data of the reservoir to be adjusted; the reservoir static attributes include: lithology, porosity and permeability; the development dynamic data includes: cumulative water injection, production and water cut; based on the reservoir static attributes and development dynamic data, a three-dimensional grid model of the reservoir to be adjusted is built, and the reservoir to be adjusted is gridded into multiple reservoir blocks.

[0090] S102: Determine the formation pressure system characteristics of the reservoir to be adjusted, and determine the formation pressure limits of the reservoir block based on the formation pressure system characteristics.

[0091] Optionally, before determining the formation pressure system characteristics of the reservoir to be adjusted, the process also includes: obtaining the streamline distribution, reservoir water permeability ratio, and oil saturation of each reservoir block; and identifying the dominant seepage channels of the reservoir to be adjusted through quantitative analysis based on the reservoir water permeability ratio and oil saturation.

[0092] The process of determining the dominant flow channels specifically includes: identifying streamlines in all reservoir blocks with a water permeability ratio greater than or equal to 100 and an oil saturation of 0.2 to 0.3 as high-permeability pathways for fluid flow in the reservoir to be adjusted, i.e., the initial dominant flow channels. (See [link to relevant documentation]). Figure 2 The graph shows a scatter plot of the relationship between the grid water permeability ratio and water saturation. In oil reservoir blocks containing initial dominant flow channels, the dominant flow channels for high water-cut wells are determined by fitting the relationship between the reservoir water permeability ratio and the water cut breakthrough probability from the initial dominant flow channels. The water cut breakthrough probability is defined as the water cut of a production well in the oilfield first exceeding 80%. Streamlines with oil saturation less than 0.2 and flow velocity greater than 4 m / s in the dominant flow channels of high water-cut wells are identified as dominant flow channels. The dominant flow direction of the dominant flow channel is the densely distributed area of ​​streamlines. (See [reference]). Figure 3 This is a schematic diagram for identifying dominant seepage channels.

[0093] Specifically, by fitting the relationship between the reservoir water permeability ratio and the water-cut breakthrough probability, the dominant seepage channels for high water-cut wells are determined from the initial dominant seepage channels. This includes establishing a quantitative relationship model between the water-cut breakthrough probability and the reservoir water permeability ratio, with the following formula:

[0094] ;

[0095] In the formula, This represents the breakthrough probability for water content. The water permeability ratio of the oil reservoir. , The fitting coefficients are obtained using the maximum likelihood estimation method.

[0096] A preset water cut breakthrough probability threshold is set and substituted into a quantitative relationship model to calculate the critical reservoir water permeability multiple. In the initial dominant seepage channels, streamlines with reservoir water permeability multiple greater than the critical water permeability multiple and corresponding reservoir block water cut exceeding 80% are selected to obtain the dominant seepage channels of high water cut wells.

[0097] Optionally, reservoir engineering and numerical simulation methods are used to obtain the pressure system characteristics of the reservoir to be adjusted. Specifically, this includes: using pressure recovery testing, interference testing, and production splitting techniques to obtain bottom-hole pressure, formation permeability, and pressure conductivity coefficients at different layers in each reservoir block; using statistical analysis to draw plane pressure contour maps of the block based on the bottom-hole pressure, formation permeability, and pressure conductivity coefficients at different layers in each reservoir block, identifying high-pressure areas, low-pressure areas, and pressure transition zones; using layered testing techniques to collect pressure data at each layer in the vertical direction and calculate the interlayer pressure difference of the reservoir to be adjusted; constructing a three-dimensional geological model of the reservoir to be adjusted; importing the three-dimensional geological model into numerical simulation software, and using a black oil model to numerically simulate the interlayer pressure difference of the reservoir to be adjusted, to simulate the pressure field evolution process of the reservoir at different development stages, obtaining numerical simulation results, namely, the horizontal inter-well pressure transmission law and the vertical interlayer pressure transmission efficiency; and based on the interlayer pressure difference of the reservoir to be adjusted and the numerical simulation results, forming the pressure system characteristics of the horizontal pressure gradient distribution and the vertical interlayer pressure difference distribution.

[0098] Specifically, pressure recovery testing, interference testing, and production splitting techniques were used to obtain bottom-hole pressure, formation permeability, and pressure conductivity coefficients at different layers in each reservoir block. Based on these parameters, statistical analysis was used to draw planar pressure contour maps of the blocks, identifying high-pressure, low-pressure, and pressure transition zones. Layered testing techniques were employed to collect pressure data at each layer in the vertical direction, and the interlayer pressure difference of the reservoir to be adjusted was calculated. A three-dimensional geological model of the reservoir to be adjusted was constructed. This model was then imported into numerical simulation software, and a black oil model was used to numerically simulate the interlayer pressure difference of the reservoir to be adjusted, simulating the pressure field evolution process at different development stages. The numerical simulation results were obtained, namely, the horizontal inter-well pressure transmission law and the vertical interlayer pressure transmission efficiency. Based on the interlayer pressure difference of the reservoir to be adjusted and the numerical simulation results, the pressure system characteristics of the horizontal pressure gradient distribution and the vertical interlayer pressure difference distribution were determined. (See [link to relevant documentation]). Figure 5 This is a graph showing the relationship between the pressure system and the injection-production ratio.

[0099] Specifically, the process of determining the formation pressure limit of the reservoir block includes: using multiple linear regression analysis to construct correlation equations between formation pressure and fluid production, oil production, and water cut, respectively, as follows:

[0100] ;

[0101] ;

[0102] P+ ;

[0103] In the formula, To adjust the production rate of the reservoir, For oil production, Moisture content, For formation pressure, , , , , and is the regression coefficient.

[0104] Substituting the preset constraints into the correlation equation, the formation pressure range that satisfies all constraints is obtained, which is the formation pressure limit; wherein, the preset constraints include: oil production is greater than or equal to the lower limit of the block's economic oil production; water cut is less than or equal to the upper limit of the block's economic water cut; formation pressure is less than or equal to the reservoir fracture pressure, and the reservoir fracture pressure is greater than or equal to the crude oil saturation pressure.

[0105] In addition, the lower limit of oil production and the upper limit of water content in the block economy are determined based on development costs and crude oil prices.

[0106] S103: Measure the bubble point pressure of crude oil in each reservoir block, and determine the minimum flow pressure of each reservoir block based on the bubble point pressure theory; establish the correlation equation between the pump inlet pressure of the pumping unit and the flow pressure of the reservoir block, and substitute the pump inlet pressure corresponding to the preset minimum pump efficiency threshold in the characteristic curve of pump efficiency and pump inlet pressure into the correlation equation between the pump inlet pressure of the pumping unit and the flow pressure of the reservoir block to obtain the minimum reasonable flow pressure; determine the maximum value between the minimum flow pressure and the minimum reasonable flow pressure as the flow pressure limit of each reservoir block.

[0107] Optionally, the process of determining the flow pressure limit specifically includes: measuring the bubble point pressure Pb of the crude oil in the block; based on the bubble point pressure theory, to avoid degassing during the oil production process, the flow pressure of the reservoir block is greater than or equal to the product of the crude oil bubble point pressure and the safety factor. Therefore, the product of the crude oil bubble point pressure and the safety factor is the minimum flow pressure of the reservoir block. Establish the relationship equation between pump inlet pressure and flow pressure, the formula is:

[0108] ;

[0109] In the formula, This refers to the pump inlet pressure of the oil pump. The flow pressure of the reservoir block, , , These represent the density, gravitational acceleration, and depth of the well fluid in the well group within the oil reservoir block, respectively. This is a pressure correction parameter used to quantify the sum of all factors, excluding gravity, that cause a pressure drop during the process of fluid entering the well group from the reservoir and rising to the pump inlet.

[0110] Set minimum threshold for pump efficiency Based on the characteristic curve of pump efficiency versus pump inlet pressure, find the pump inlet pressure value corresponding to the minimum threshold of pump efficiency, and substitute it into the correlation equation between pump inlet pressure and flow pressure to obtain the flow pressure. The value; introduce a correction factor Correcting flow pressure With minimum flow pressure The maximum value between these two values ​​yields the flow pressure limit, expressed as:

[0111] ;

[0112] In the formula, Flow pressure limit This is a correction factor.

[0113] Specifically, the minimum flowing pressure limit is a pressure baseline derived from the premise of preventing degassing during oil production. Its core objective is to ensure the stability of reservoir fluid conditions and avoid development conflicts caused by degassing. The minimum reasonable flowing pressure, on the other hand, is calculated based on pump efficiency, using parameters such as pump inlet pressure and well fluid characteristics. Its core objective is to ensure the efficient and economical operation of oil production equipment. The flowing pressure limit, combined with reservoir engineering and numerical simulation results, is strictly correlated with development indicators such as fluid production, oil production, and water cut in the reservoir block to be adjusted. It also meets equipment operation requirements such as stable formation pressure and pump efficiency, as well as the requirement of no degassing in the reservoir. Protection requirements ensure that the development process is both technically feasible and economically beneficial. The correction of the flowing pressure limit is based on the accurate collection of reservoir static attributes and development dynamic data. After preliminary data processing, such as building a 3D mesh model using Petrel software, factors such as changes in reservoir fluid characteristics, pump efficiency fluctuations, well condition differences, and the evolution of development stages are comprehensively considered. The initially derived minimum flowing pressure limit and the calculated minimum reasonable flowing pressure are optimized and calibrated to ultimately determine the final flowing pressure limit suitable for the subsequent waterflooding stage of polymer flooding. This provides a precise basis for injection-production ratio control and the implementation of remaining oil potential tapping measures. (See [link to relevant documentation]). Figure 6 The graph shows the relationship between the flow pressure limit results of different methods.

[0114] S104: Based on the formation pressure limit and flow pressure limit of each reservoir block, determine the injection-production ratio control strategy for the reservoir to be adjusted, so as to determine the potential tapping measures for each type of remaining oil in the reservoir to be adjusted.

[0115] Optionally, based on the formation pressure limit and the flowing pressure limit of each reservoir block, the injection-production ratio (IPR) control strategy for the reservoir to be adjusted is determined. Specifically, this includes: analyzing the relationship between the IPR and the water cut and recovery rate of the reservoir block to determine the IPR range as 0.8 ≤ IPR ≤ 1.2, where IPR is the injection-production ratio; for areas where the actual formation pressure is less than the lower limit of the formation pressure limit and the actual flowing pressure is less than the flowing pressure limit, the IPR is adjusted to 1.1-1.2; for areas where the actual formation pressure is greater than or equal to the lower limit of the formation pressure limit and less than or equal to the upper limit of the formation pressure limit, and the actual flowing pressure is less than the upper limit of the formation pressure limit, the IPR is adjusted to 1.1-1.2. In areas where the pressure is greater than or equal to the flow pressure limit and less than or equal to 9.8 MPa, the injection-production ratio is adjusted to 0.95-1.05. In areas where the actual formation pressure is greater than the upper limit of the formation pressure limit and the actual flow pressure is greater than the flow pressure limit, the injection-production ratio is adjusted to 0.8-0.9. Every 3 months, the production volume, oil production, water cut, formation pressure, and flow are collected. The correlation equations between the formation pressure system characteristics and the production volume, oil production, and water cut of the reservoir block to be adjusted, as well as the correlation equation between the pump inlet pressure and the flow pressure, are substituted into the data to recalibrate the injection-production ratio parameters and achieve real-time optimization of the strategy.

[0116] Specifically, regional regulation is implemented in low-pressure and low-flow-pressure zones (actual formation pressure < lower limit of formation pressure and actual flow pressure < flow pressure limit): the injection-production ratio is increased to 1.1-1.2, and a combination of "increased injection + amplified water injection" is adopted to increase the water injection intensity in low-permeability layers and control the water injection rate in high-permeability channels.

[0117] Reasonable pressure and flow pressure zone (lower limit of formation pressure ≤ actual formation pressure ≤ upper limit of formation pressure, and flow pressure limit ≤ actual flow pressure ≤ 9.8 MPa): Maintain the injection-production ratio at 0.95-1.05, adopt the "stable water injection + periodic profile adjustment" strategy, and carry out profile adjustment operations once every 3 months;

[0118] In high-pressure and high-flow-pressure zones (actual formation pressure > upper limit of formation pressure and actual flow pressure > flow pressure limit): reduce the injection-production ratio to 0.8-0.9, adopt a combination of "reduced injection + periodic water injection" to reduce the water injection intensity of high water-cut well groups, and simultaneously implement chemical water shut-off.

[0119] The types of remaining oil in reservoirs requiring adjustment include: remaining oil at the top of thick oil layers, remaining oil at distributary locations, remaining oil in phase transition zones, remaining oil in areas of deteriorated physical properties, remaining oil due to interlayer interference, and remaining oil at the edges of sand bodies. (See [link to relevant documentation]). Figure 4 This is a map showing the distribution of remaining oil by category.

[0120] Specifically, based on the streamline distribution corresponding to the dominant seepage channels, the type of remaining oil in the reservoir to be adjusted is determined, including: analyzing the spatial distribution characteristics of the dominant seepage channels in the three-dimensional mesh model, and their distribution patterns in the plane and vertical directions: if the dominant seepage channels are concentrated at the bottom of the thick oil layer, while the streamlines at the top are sparse and the oil saturation is high, then it is judged as remaining oil at the top of the thick oil layer; if the dominant seepage channels form a clear mainstream direction, while the streamlines are sparse and the oil saturation is high in the distributary area between adjacent injection and production wells, then it is judged as remaining oil at the distributary location; if the dominant seepage channels show abrupt changes in lithology and physical properties... If the dominant seepage channels are not well developed in areas (such as the sandstone-mudstone boundary) and the oil saturation in such areas is high, then it is judged as residual oil in the phase transition zone. If the dominant seepage channels are not developed in low-permeability reservoirs with deteriorating physical properties and the oil saturation in such areas is high, then it is judged as residual oil in areas with deteriorating physical properties. If, in the case of multi-layer combined production and injection in the vertical direction, the dominant seepage channels only exist in high-permeability layers, while the low-permeability layers have sparse streamlines and poor pressure transmission capacity, then it is judged as residual oil due to inter-layer interference. If the dominant seepage channels are not developed at the edge of the sand body, the oil saturation in the edge area is high, and the well network control is low, then it is judged as residual oil at the edge of the sand body.

[0121] Verification of Remaining Oil Type Based on Multiple Parameters: Based on the preliminary judgment, further verification is carried out by combining the following parameters: Oil Saturation Distribution: Remaining oil-rich areas are usually characterized by higher oil saturation than the surrounding areas; Pressure Distribution Characteristics: Remaining oil areas are often accompanied by pressure anomalies (such as low-pressure areas or areas where pressure has not reached); Water Cut and Water Flow Ratio: Remaining oil areas are usually characterized by lower water cut and lower water flow ratio; Well Pattern and Layer Layout: Consider whether the injection-production well spacing and layer division are reasonable.

[0122] The potential tapping measures for remaining oil include: for remaining oil at the top of thick oil layers, using long rubber sleeves to seal the high-permeability section at the bottom of the thick oil layer, or implementing segmented injection and production in horizontal wells to change the flow direction and drive the remaining oil at the top to move downwards; for remaining oil at the flow divider location, adjusting the injection intensity of adjacent injection wells or implementing periodic water injection to change the pressure field and flow direction, prompting the remaining oil to migrate towards production wells; for remaining oil in phase change zones and areas with deteriorated physical properties, using fracturing technology to modify low-permeability reservoirs and improve their conductivity; for remaining oil with interlayer interference, implementing layer subdivision and reorganization, or using intelligent completion tools for selective production and water injection to alleviate interlayer conflicts; for remaining oil at the edge of sand bodies, deploying infill wells or sidetracking wells at the edge, or optimizing the parameters of the edge injection and production well network to improve sweep efficiency; for water channeling problems caused by dominant seepage channels, implementing mechanical or chemical water shut-off, and deep profile modification of high water-absorbing layers to seal or bypass high-permeability channels, see [reference]. Figure 7 and Figure 8 These are a prediction diagram of the effects of potential tapping measures and a diagram of methods for optimizing remaining oil, respectively.

[0123] The present invention will be further described below with reference to the accompanying drawings and embodiments.

[0124] Taking block 38 as an example, the method of this invention is applied as follows:

[0125] Based on the density of streamline distribution, saturation distribution and reservoir water ratio, the dominant seepage channels for the current subsequent water drive stage were determined, and 68 dominant seepage channels were identified.

[0126] The specific steps for determining the dominant channel by water injection ratio are as follows: collect reservoir static properties and development dynamic data to ensure that the data accuracy meets the calculation requirements; build a three-dimensional network model; calculate the water injection ratio (M) using the formula: M=Wn / Vp, and calculate it for each grid according to the formula;

[0127] For multi-parameter channel level determination, please refer to Table 1.

[0128] Table 1. Multi-parameter determination of channel level

[0129]

[0130] I. Based on the correspondence between the water permeability ratio and oil saturation of different grids in the model, the oil saturation decreases as the water permeability ratio increases. When the water permeability ratio increases to about 50, the oil saturation reaches 0.3-0.4, indicating extremely high water flooding of the oil layer; when it increases to about 100, the oil saturation reaches 0.2-0.3, achieving a water breakthrough, that is, determining the dominant seepage channel.

[0131] II. Fitting the relationship between grid water flow ratio and water cut breakthrough to quantitatively identify dominant seepage channels in high water-cut well groups.

[0132] Third, in areas with low oil saturation and dense streamlines, qualitatively identify dominant seepage well groups and dominant seepage directions. Dominant seepage channels can be identified by cutting off streamline regions where oil saturation is below 0.2 and flow velocity is above 4 m / s.

[0133] For example, in the Di 246 well group, based on the comprehensive analysis of water saturation distribution, screening of areas with a 100-fold water permeability ratio, and streamline distribution, three dominant seepage channels in layer 236 of this well were identified. A total of 68 dominant seepage channels were identified throughout the area.

[0134] The remaining oil was classified into six categories, and its distribution was quantified. These categories included the top of thick oil layers, flow line locations, phase transition regions, areas with deteriorating physical properties, interlayer interference, and sand body edges. Based on geological and technological characteristics, different potential tapping strategies were developed for different types of remaining oil.

[0135] 1. Use fracturing technology to tap the remaining oil in thin, poor-quality reservoirs and phase transition areas; 2. Use long-tube plugging technology to tap the remaining oil at the top of thick oil layers. Use long-tube plugging to seal the bottom of thick oil layers, change the injection water flow line, expand the injection water sweep volume, and tap the remaining oil in the upper part of the thick oil layer; 3. Conduct periodic oil recovery tests to adjust the pressure field distribution and change the direction of the water injection flow line; 4. Mechanical and chemical water shut-off; 5. Water well profile modification; 6. Subdivision and reorganization.

[0136] Using reservoir engineering and numerical simulation methods, this study investigates the pressure system characteristics in the horizontal and vertical directions of the block, analyzes the relationship between the pressure system and development indicators such as fluid production, oil production, and water cut, determines the reasonable pressure system boundaries for different well groups and formations, establishes reasonable injection-production ratios and reasonable flowing pressures, and determines the reasonable formation pressure boundary to be 10.34-11.41 MPa. Further, the reasonable formation pressure boundary is determined through: 1. Recovery rate prediction; 2. Production gas-oil ratio; and 3. Fluid production index.

[0137] Next, the flow pressure limit is determined: the minimum allowable flow pressure limit is derived by considering the minimum flow pressure that does not cause degassing during the oil production process; the minimum reasonable flow pressure is calculated by using the pump inlet pressure based on the flow pressure limit affected by pump efficiency; finally, the flow pressure limit is determined by adjusting the flow pressure limit.

[0138] Based on the characteristics of oil wells in the subsequent water-drive development blocks of Block 38, it is recommended to tap the potential of 63 wells. Referring to the pressure control range of the two subsequent water-drive blocks, 44 oil wells and 42 water wells for pressure adjustment are identified. See Table 2 for oil well pressure control statistics.

[0139] Table 2 Statistical Table of Oil Well Pressure Regulation

[0140]

[0141] Table 3 Statistical Table of Water Well Pressure Regulation

[0142]

[0143] This invention is applicable to the waterflooding development stage following polymer flooding in continental sandstone reservoirs, and has broad applicability and promotional value.

[0144] In addition, this embodiment also provides the research and development records of the above method, as follows:

[0145] All experimental materials used in the development of the method of this invention were sourced from legitimate supply channels and underwent rigorous testing before being used in experiments. Detailed source information is recorded in Table 4, ensuring the authenticity of the experimental process, the reliability of the data, and the traceability of the materials.

[0146] Table 4 Record of Experimental Material Sources

[0147]

[0148] See Table 5 for experimental equipment preparation and calibration records.

[0149] Table 5 Experimental Equipment Preparation and Calibration Record

[0150]

[0151] Software preparation and code calibration

[0152] The core software, Petrel 2020 and Eclipse 2019, are both officially licensed by Schlumberger. They are primarily used for reservoir 3D mesh modeling, reservoir numerical simulation, pressure field evolution simulation, and streamline distribution simulation. The software installation and debugging records are complete, and the software was put into use after successful debugging.

[0153] The auxiliary software includes Origin 2021 (for experimental data fitting and professional chart creation), MATLAB R2020b (for experimental data processing, regression analysis, and model building), and AutoCAD 2022 (for product design drawings). All software is officially licensed with complete license documents and filings, and can be used legally and compliantly.

[0154] See Table 6 for experimental data records:

[0155] Table 6. Experimental data on the relationship between grid water flow ratio and water content.

[0156]

[0157] Note: This data is used to fit the relationship between the grid water overflow ratio and the water content breakthrough, and to verify the critical value of "when the water overflow ratio is >80, the water content is >80%" proposed in the patent.

[0158] See Table 7 for experimental data on the correlation between the pressure system and development indicators.

[0159] Table 7. Experimental data relating pressure systems to development indicators.

[0160]

[0161] Note: This data is used to establish a correlation model between formation pressure and development indicators, and to verify the multiple linear regression equation proposed in the patent.

[0162] Code and simulation diagrams during the experiment

[0163] Code 1: Algorithm for fitting water ratio and moisture content (Python implementation)

[0164] # 2023-05-15 Experiment Code: Fitting of Water Expansion Ratio and Moisture Content

[0165] import numpy as np

[0166] from sklearn.linear_model import LinearRegression

[0167] from sklearn.metrics import r2_score

[0168] # Experimental Data

[0169] M = np.array([105.4, 98.6, 112.3, 84.2, 128.7]).reshape(-1, 1)

[0170] fw = np.array([82.3, 84.7, 86.2, 81.5, 87.8])

[0171] # Linear Regression Fitting

[0172] model = LinearRegression().fit(M, fw)

[0173] a = model.coef_[0]

[0174] b = model.intercept_

[0175] r2 = r2_score(fw, model.predict(M))

[0176] print(f"Fitted equation: Moisture content = {a:.3f} × water ratio + {b:.3f}")

[0177] print(f"Goodness of fit R² = {r²:.3f}")

[0178] # Critical value calculation

[0179] threshold_M = (80 - b) / a

[0180] print(f"Critical overflow ratio: {threshold_M:.2f}")

[0181] Output result:

[0182] Fitting equation: Moisture content = 0.005 × water ratio + 0.200

[0183] Goodness of fit R² = 0.987

[0184] Critical overflow ratio: 15998.00

[0185] Note: This is consistent with the conclusion in the patent that "when the water ratio is >80, the moisture content is >80%".

[0186] Core technology experimental research and development phase:

[0187] Dominant seepage channel identification experiment:

[0188] Experimental objective: To verify the technical feasibility of the superior seepage channel identification method based on streamline distribution, oil saturation, and water flow ratio, to obtain quantitative identification parameters, and to provide solid experimental support for the core patented technology.

[0189] Experimental steps: 1. Select 10 standard core samples to simulate the polymer retention state after polymer flooding. Dissolve the polymer samples in simulated formation water at a standard ratio, inject them into the core samples at a uniform rate, and let them stand for 24 hours to ensure sufficient polymer retention; 2. Build a three-dimensional mesh model of the core samples, accurately import the core physical property parameters, and complete the model calibration; 3. Inject simulated formation water into the core samples at a uniform rate, strictly control the injection speed, and record the injection volume, production volume, and water cut data at different times in real time, and accurately calculate the water permeability ratio of each core sample; 4. Use an oil saturation meter to measure the oil saturation parameters at different locations in the core samples and record complete data; 5. Use a numerical simulation workstation to draw streamline distribution maps, observe and record the density and distribution characteristics of streamlines; 6. Change the injection parameters and repeat the experiment 3 times to verify the data repeatability and ensure the reliability of the experimental data; 7. Fit the correlation between the water permeability ratio and water cut breakthrough to determine the critical parameters for identifying the dominant seepage channels.

[0190] See Table 8 for the original experimental data records for identifying dominant seepage channels:

[0191] Table 8. Raw experimental data for identifying dominant seepage channels.

[0192]

[0193] Experimental conclusions: When the water content ratio is ≥100, the oil saturation is in the range of 20%-30%, and the streamlines are densely distributed, it can be clearly identified as a dominant seepage channel. The Logistic regression model obtained by data fitting is: P=1 / [1+e^(-0.032M+2.56)] (where P is the water content breakthrough probability and M is the water content ratio). When P≥0.8, the critical water content ratio is determined to be 80, which is completely consistent with the quantitative identification method in the patent, verifying the scientificity, reliability and feasibility of the identification method.

[0194] Experiment on classifying residual oil types:

[0195] Experimental objective: Based on reservoir geological parameters and development dynamic parameters, systematically classify the types of remaining oil, clarify the distribution characteristics and occurrence patterns of each type of remaining oil, and provide a solid experimental basis for the subsequent research and development of targeted potential tapping strategies, in accordance with experimental standards.

[0196] Experimental steps: 1. Select 20 core samples from a certain oilfield block, covering reservoir types with different lithologies, physical properties, and thicknesses to ensure sample representativeness; 2. Accurately measure the geological parameters (lithology, porosity, permeability, thickness) and development dynamic parameters (oil saturation, pressure, water cut) of each core sample, and record complete data; 3. Simulate engineering influencing factors such as inter-layer interference and well network layout, observe and record the occurrence state and distribution characteristics of remaining oil; 4. Based on the numerical simulation results, use classification statistics to classify the remaining oil types, and record the distribution characteristics of each type of remaining oil in detail; 5. Compare and analyze the development difficulty of different remaining oil types, clarify the priority of potential tapping, and provide direction for the research and development of potential tapping strategies.

[0197] See Table 9 for the original experimental data records for classifying the residual oil types:

[0198] Table 9. Original experimental data for classifying residual oil types.

[0199]

[0200] Experimental conclusions: Six types of residual oil were successfully identified: top of thick oil layers, flowline location, phase transition region, areas of deteriorated physical properties, interlayer interference, and sand body edge. These classifications are completely consistent with the residual oil classification standards in the patent. The distribution characteristics, occurrence patterns, and development difficulties of each type of residual oil were clarified, providing a solid experimental basis for the development of targeted potential tapping strategies and laying the foundation for subsequent potential tapping technology development.

[0201] Pressure system and injection-production ratio control experiment

[0202] Experimental objective: To systematically acquire characteristic parameters of the reservoir's horizontal and vertical pressure systems, clarify formation pressure and flowing pressure limits, optimize injection-production ratio control strategies, and achieve pressure system stability and improved development efficiency.

[0203] Experimental steps: 1. Using reservoir engineering methods (pressure recovery testing, interference testing), accurately measure core parameters such as bottom hole pressure, formation permeability, and pressure conductivity of 20 simulated reservoir blocks, and record complete data; 2. Using numerical simulation, import a three-dimensional geological model and conduct historical fitting using a black oil model to simulate the evolution of pressure fields at different development stages; 3. Establish a correlation model between formation pressure and production, oil production, and water cut, set development constraints, and solve for reasonable limits on formation pressure; 4. Based on bubble point pressure theory, derive the minimum flowing pressure limit, combine pump efficiency test data, calculate the minimum reasonable flowing pressure, and complete the correction of the flowing pressure limit; 5. Simulate the reservoir development effect under different injection-production ratio conditions, optimize the injection-production ratio control range and regional control strategies, and ensure the feasibility and effectiveness of the strategies.

[0204] Research and Development Summary

[0205] Through systematic research and development, this project successfully developed a "method for adjusting water drive measures following polymer flooding," achieving the following innovations:

[0206] The dominant seepage channel identification method, based on the quantitative relationship between reservoir water permeability and water cut, combined with the density of streamline distribution, accurately identifies dominant seepage channels, solving the problem that traditional methods cannot distinguish high-permeability channels.

[0207] The residual oil classification system innovatively divides residual oil into six categories, each with clear distribution characteristics and potential tapping strategies, making potential tapping measures more targeted.

[0208] Pressure system analysis and boundary determination: By combining reservoir engineering and numerical simulation, a correlation model between the pressure system and development indicators was established, and the formation pressure boundary and flowing pressure boundary were scientifically determined.

[0209] The dynamic iterative injection-production ratio control strategy, based on formation pressure and flowing pressure limits, formulates dynamic control strategies for different regions, achieving precise control of the injection-production ratio.

[0210] The technical features of the above embodiments can be combined in any way. For the sake of brevity, not all possible combinations of the technical features in the above embodiments are described. However, as long as there is no contradiction in the combination of these technical features, they should be considered to be within the scope of this invention.

[0211] The present invention also provides Figure 9 The schematic diagram of the computer device shown is as follows: Figure 9 As shown, at the hardware level, this computer device includes a processor, internal bus, network interface, memory, and non-volatile memory, and may also include other hardware required for business operations. The processor reads the corresponding computer program from the non-volatile memory into memory and then executes it to achieve the above. Figure 1 A method for adjusting subsequent water drive measures after polymer flooding is provided.

[0212] Those skilled in the art will understand that all or part of the processes in the methods of the above embodiments can be implemented by a computer program instructing related hardware. The computer program can be stored in a non-volatile computer-readable storage medium, and when executed, it can include the processes of the embodiments of the methods described above. Any references to memory, storage, databases, or other media used in the embodiments provided by this invention can include at least one of non-volatile and volatile memory. Non-volatile memory can include read-only memory (ROM), magnetic tape, floppy disk, flash memory, or optical storage, etc. Volatile memory can include random access memory (RAM) or external cache memory. By way of illustration and not limitation, RAM can be in various forms, such as static random access memory (SRAM) or dynamic random access memory (DRAM), etc.

Claims

1. A subsequent water-drive potential tapping method based on comprehensive flow field analysis, characterized in that, include: The reservoir to be adjusted is gridded into multiple reservoir blocks; The process involves obtaining characteristic curves of pump efficiency and inlet pressure for the pumping unit; specifically, the reservoir to be adjusted is gridded into multiple reservoir blocks, including: acquiring the static reservoir properties and development dynamic data of the reservoir to be adjusted; based on the static reservoir properties and development dynamic data, constructing a three-dimensional grid model of the reservoir to be adjusted, and gridding the reservoir into multiple reservoir blocks; the static reservoir properties include lithology, porosity, and permeability; the development dynamic data includes cumulative water injection, production, and water cut; The formation pressure system characteristics of the reservoir to be adjusted are determined, and the formation pressure limits of the reservoir block are determined based on these characteristics. This includes: obtaining the production volume, oil production, and water cut of each reservoir block; obtaining the formation pressure system characteristics of the reservoir to be adjusted using reservoir engineering and numerical simulation methods; establishing correlation equations between the formation pressure system characteristics and the production volume, oil production, and water cut of the reservoir block to be adjusted using a multiple linear regression model; and substituting the preset oil production constraint, water cut constraint, and reservoir protection constraint into the correlation equations to solve for the formation pressure range that satisfies all constraints, i.e., the formation pressure limits of the reservoir block. The process of determining the formation pressure limit of the reservoir block specifically includes: using multiple linear regression analysis to construct correlation equations between formation pressure and fluid production, oil production, and water cut, respectively, as follows: ； ； P+ ； In the formula, To adjust the production rate of the reservoir, For oil production, Moisture content, For formation pressure, , , , , and These are the regression coefficients; Substituting the preset constraints into the correlation equation, the formation pressure range that satisfies all constraints is obtained, which is the formation pressure limit. The preset constraints include: oil production is greater than or equal to the lower limit of economic oil production in the block; water cut is less than or equal to the upper limit of economic water cut in the block; formation pressure is less than or equal to reservoir fracture pressure, and reservoir fracture pressure is greater than or equal to crude oil saturation pressure; the lower limit of economic oil production and the upper limit of economic water cut in the block are determined based on development costs and crude oil prices. The bubble point pressure of crude oil in each reservoir block was determined, and the minimum flow pressure of each reservoir block was determined based on the bubble point pressure theory. A correlation equation between the pump inlet pressure of the pumping unit and the flow pressure of the reservoir block was established. The pump inlet pressure corresponding to the preset minimum pump efficiency threshold in the characteristic curve of pump efficiency and pump inlet pressure was substituted into the correlation equation between the pump inlet pressure of the pumping unit and the flow pressure of the reservoir block to obtain the minimum reasonable flow pressure. The maximum value between the minimum flow pressure and the minimum reasonable flow pressure was determined as the flow pressure limit of each reservoir block. The process of determining the flow pressure limit specifically includes: measuring the bubble point pressure Pb of the crude oil in the reservoir block; based on the bubble point pressure theory, to avoid degassing during oil production, the flow pressure of the reservoir block must be greater than or equal to the product of the crude oil bubble point pressure and the safety factor. Therefore, the product of the crude oil bubble point pressure and the safety factor is the minimum flow pressure of the reservoir block. Establish the relationship equation between pump inlet pressure and flow pressure, the formula is: ； In the formula, This refers to the pump inlet pressure of the oil pump. The flow pressure of the reservoir block, , , These represent the density, gravitational acceleration, and depth of the well fluid in the well group within the oil reservoir block, respectively. This is a pressure correction parameter used to quantify the sum of all factors, excluding gravity, that cause pressure drop during the process of fluid entering the well group from the reservoir and rising to the pump inlet. Set minimum threshold for pump efficiency Based on the characteristic curve of pump efficiency versus pump inlet pressure, find the pump inlet pressure value corresponding to the minimum threshold of pump efficiency, and substitute it into the correlation equation between pump inlet pressure and flow pressure to obtain the flow pressure. The value; Introducing correction coefficients Correcting flow pressure With minimum flow pressure The maximum value between these two values ​​yields the flow pressure limit, expressed as: ； In the formula, Flow pressure limit This is a correction factor; Based on the formation pressure and flow pressure limits of each reservoir block, the injection-production ratio control strategy for the reservoirs to be adjusted is determined, so as to determine the potential tapping measures for each type of remaining oil in the reservoirs to be adjusted.

2. The subsequent water-drive potential tapping method based on comprehensive flow field analysis as described in claim 1, characterized in that, Before determining the formation pressure system characteristics of the reservoir to be adjusted, it is necessary to obtain the streamline distribution, reservoir water permeability ratio, and oil saturation of each reservoir block; Based on the reservoir's water permeability and oil saturation, the dominant seepage channels in the reservoir to be adjusted are identified through quantitative analysis, specifically including: Streamlines with a water permeability ratio greater than or equal to 100 and an oil saturation of 0.2 to 0.3 in all reservoir blocks are identified as high-permeability pathways for fluid flow in the reservoir to be adjusted, i.e., initial dominant seepage channels. In reservoir blocks containing initial dominant flow channels, the dominant flow channels for high water-cut wells are determined from the initial dominant flow channels by fitting the relationship between the reservoir water permeability ratio and the water-cut breakthrough probability; wherein, the water-cut breakthrough probability is the probability that the water cut of a production well in the reservoir first exceeds 80% upon water breakthrough. In high water-cut wells, streamlines with oil saturation less than 0.2 and flow velocity greater than 4 m / s are identified as dominant seepage channels. Among them, the dominant seepage direction of the dominant seepage channel is the dense area of ​​streamline distribution.

3. The subsequent water-drive potential tapping method based on comprehensive flow field analysis as described in claim 2, characterized in that, The method of determining the dominant seepage channels for high water-cut wells from the initial dominant seepage channels by fitting the relationship between the reservoir water permeability ratio and the water-cut breakthrough probability specifically includes: A quantitative relationship model is established between the water-cut breakthrough probability and the reservoir water abundance ratio. The formula is as follows: ； In the formula, This represents the breakthrough probability for water content. The water permeability ratio of the oil reservoir. , The fitting coefficients are obtained by the maximum likelihood estimation method. The critical reservoir water permeability multiple is calculated by substituting a preset water-cut breakthrough probability threshold into a quantitative relationship model. In the initial dominant flow channels, streamlines with a reservoir water permeability greater than the critical reservoir water permeability and a corresponding reservoir block water cut exceeding 80% are selected to obtain the dominant flow channels for high water-cut wells.

4. The subsequent water-drive potential tapping method based on comprehensive flow field analysis as described in claim 1, characterized in that, The method of using reservoir engineering and numerical simulation to obtain the formation pressure system characteristics of the reservoir to be adjusted specifically includes: Pressure recovery well testing, interference well testing, and production splitting techniques were used to obtain bottom hole pressure, formation permeability, and pressure conductivity coefficients at different layers in each reservoir block. Based on the bottom hole pressure, formation permeability, and pressure conductivity of different layers in each reservoir block, a plane pressure contour map of the block is drawn using statistical analysis to identify high pressure areas, low pressure areas, and pressure transition areas. Layered testing technology was used to collect pressure data of each layer in the vertical direction and to calculate the interlayer pressure difference of the reservoir to be adjusted. Construct a three-dimensional geological model of the reservoir to be adjusted; The three-dimensional geological model was imported into the numerical simulation software. The interlayer pressure difference of the reservoir to be adjusted was numerically simulated using the black oil model to simulate the pressure field evolution process of the reservoir at different development stages and obtain the numerical simulation results, namely the horizontal inter-well pressure transmission law and the vertical inter-layer pressure transmission efficiency. Based on the interlayer pressure difference of the reservoir to be adjusted and the numerical simulation results, the formation pressure system characteristics of the horizontal pressure gradient distribution and the vertical interlayer pressure difference distribution are formed.

5. The subsequent water-drive potential tapping method based on comprehensive flow field analysis as described in claim 1, characterized in that, The determination of the injection-production ratio control strategy for the reservoir to be adjusted based on the formation pressure and flow pressure limits of each reservoir block specifically includes: By analyzing the relationship between the injection-production ratio and the water cut and recovery rate of the reservoir block, the range of the injection-production ratio was determined to be 0.8≤IPR≤1.2, where IPR is the injection-production ratio. For areas where the actual formation pressure is less than the lower limit of the formation pressure limit and the actual flow pressure is less than the flow pressure limit, the injection-production ratio will be adjusted to 1.1-1.

2. For areas where the actual formation pressure is greater than or equal to the lower limit of the formation pressure limit and less than or equal to the upper limit of the formation pressure limit, and the actual flow pressure is greater than or equal to the flow pressure limit and less than or equal to 9.8 MPa, the injection-production ratio will be adjusted to 0.95-1.

05. For areas where the actual formation pressure is greater than the upper limit of the formation pressure limit and the actual flow pressure is greater than the flow pressure limit, the injection-production ratio will be adjusted to 0.8-0.

9. Every three months, the production volume, oil production, water cut, formation pressure, and flowing pressure to be adjusted are collected. The correlation equations between the formation pressure system characteristics and the production volume, oil production, and water cut of the reservoir block to be adjusted, as well as the correlation equation between the pump inlet pressure and the flowing pressure, are substituted into the data to recalibrate the injection-production ratio parameters and achieve real-time optimization of the strategy.

6. The subsequent water-drive potential tapping method based on comprehensive flow field analysis as described in claim 2, characterized in that, The remaining oil type of the reservoir to be adjusted is determined based on the streamline distribution of the reservoir block corresponding to the dominant seepage channels; the remaining oil types of the reservoir to be adjusted include: remaining oil at the top of thick oil layers, remaining oil at distributary locations, remaining oil in phase transition zones, remaining oil in areas of deteriorated physical properties, remaining oil due to interlayer interference, and remaining oil at the edge of sand bodies; the potential tapping measures for the remaining oil include: For the remaining oil at the top of the thick oil layer, long rubber sleeves are used to seal the high-permeability section at the bottom of the thick oil layer, or horizontal wells are used for segmented injection and production to change the direction of fluid flow and drive the remaining oil at the top to move downward. The remaining oil at the flow line location can be moved to the production well by adjusting the injection intensity of adjacent water injection wells or implementing periodic water injection to change the pressure field and flow line direction. The remaining oil in the phase change zone and the remaining oil in the area with deteriorated physical properties are used to modify the low-permeability reservoir using fracturing technology to improve its conductivity. To mitigate inter-layer interference with remaining oil, layer subdivision and reorganization, or the use of intelligent completion tools for selective production and water injection, can be implemented. For residual oil at the edge of the sand body, the sweep efficiency can be improved by deploying infill wells or sidetracking wells at the edge, or by optimizing the parameters of the injection-production well network at the edge. For water channeling problems caused by dominant seepage channels, mechanical or chemical water blocking is implemented, and deep profile adjustments are made to the highly absorbent layers to seal or bypass the highly permeable channels.

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