A method and system for determining the timing of oil well water plugging operation

Abstract

The present invention relates to the field of petroleum engineering technology, and in particular, to a method and system for determining the timing of water plugging operations in oil wells. The method comprises the following steps: collecting historical production data of oil wells, water injection data of water injection wells connected to the oil wells, and geological data of the block where the oil wells are located; using geological modeling software to construct a three-dimensional geological model; establishing an oil-water two-phase flow model on the basis of the three-dimensional geological model; simulating the movement of oil and water in different time periods of the oil-water two-phase flow model to predict the advancement of the water drive front; evaluating the current flooding status of the oil well based on the predicted advancement of the water drive front, and if the oil well enters the high flooding stage, determining whether it is economically feasible to plug the oil well, and if it is economically feasible, implementing water plugging operations. The method can predict the response of the oil well and locate the most severely flooded area in the oil well, avoiding unnecessary comprehensive adjustments to the entire oil well network, and reducing operating costs and production interference.

Description

Technical Field

[0001] The present invention relates to the technical field of oil engineering, and more particularly to a method and system for determining the timing of water shutoff operations in oil wells. Background Art

[0002] As an oil well produces, water in the reservoir gradually accumulates towards the oil well, resulting in an increase in the water cut of the oil well, which is known as the water flooding phenomenon. Water flooding not only reduces the oil production efficiency of the oil well but also increases production costs because treating and separating the produced water requires additional energy consumption and expenses. In addition, severe water flooding may lead to premature shutdown of the oil well. Therefore, accurately predicting the development trend of water flooding and taking water shutoff measures in advance are crucial for maintaining the stable production of the oil well and extending the life cycle of the oil well. In recent years, the progress of geological modeling software, the improvement of high-performance computing capabilities, and the application of big data analysis technology have provided new opportunities for oil well management. The dynamic changes in injection wells and production wells, such as injection pressure, injection volume, pumping rate of the production well, bottom hole pressure, etc., will affect the fluid distribution and movement in the reservoir. If the model cannot accurately reflect these changes, the prediction results will deviate. Traditional reservoir simulation simplifies the influence of injection-production conditions, resulting in a deviation between the model and the actual production situation. Therefore, a method and system for determining the timing of water shutoff operations in oil wells are provided. Summary of the Invention

[0003] The purpose of the present invention is to provide a method and system for determining the timing of water shutoff operations in oil wells to solve the problem of deviation between the model and the actual production situation caused by simplifying the influence of injection-production conditions, such as the dynamic changes of injection-production wells, capillary pressure effects, etc., as mentioned in the above background art.

[0004] To achieve the above object, the present invention provides a method for determining the timing of water shutoff operations in oil wells, including the following steps:

[0005] S1. Collect the historical production data of the oil well, the injection water data of the injection well connected to the oil well, and the geological data of the block where the oil well is located;

[0006] S2. Define the initial oil-water conditions and boundary conditions based on the collected historical production data of the oil well, the injection water data of the injection well connected to the oil well, and the geological data of the block where the oil well is located, and use geological modeling software to construct a three-dimensional geological model;

[0007] S3. Based on the three-dimensional geological model, establish an oil-water two-phase flow model. Input the historical production data of the oil well, the injection water data of the injection well connected to the oil well, and the geological data of the block where the oil well is located into the oil-water two-phase flow model to determine whether the oil-water two-phase flow model holds. During this process, determine which parameters affect the model results, and then preferentially adjust these parameters. Iteratively adjust the parameters repeatedly until a satisfactory result is achieved;

[0008] Among them, the oil-water two-phase flow model includes the mass conservation equation of oil-phase flow, the mass conservation equation of water-phase flow, the momentum conservation equation of oil phase, and the momentum conservation equation of water phase;

[0009] Introduce the influence of injection-production conditions into the mass conservation equations of oil-phase flow and water-phase flow for optimization. The optimized oil-water two-phase flow model is as follows:

[0010] The injection-production conditions include injection-production ratio, injection well distance, and injection method;

[0011]

[0012] q w,adjusted = q w ×(1 + R)×e -αd ×g(t)

[0013] g(t) = Asin(ωt) + B

[0014] Among them, q o,adjusted is the optimized oil-phase source-sink term; R is the injection-production ratio; α is an empirical constant; d is the distance between injection and production wells; q w,adjusted is the optimized water-phase source-sink term; g(t) is a time function; A is the amplitude; ω is the angular frequency; t is the time; B is the offset;

[0015] The optimized mass conservation equation of oil-phase flow:

[0016]

[0017] The optimized mass conservation equation of water-phase flow:

[0018]

[0019] S4. Use the time-lapse simulation method to simulate the oil-water movement in different time periods of the oil-water two-phase flow model and predict the advancement of the water drive front;

[0020] S5. Evaluate the current water flooding status of the oil well according to the predicted advancement of the water drive front. If it enters the high water flooding stage, then judge whether it is economically feasible to plug the water for this oil well. If it is economically feasible, implement the water plugging operation.

[0021] As a further improvement of this technical solution, in S1, the historical production data includes production volume and water cut; the injection water data of the injection well corresponding to the oil well includes injection volume, injection pressure, and geological data; the geological data of the block where the oil well is located includes geological structure map, core data, logging data, fluid properties of the oil well, and capillary pressure;

[0022] As a further improvement of this technical solution, the specific steps of S2 are as follows:

[0023] S21. Divide the research area into multiple cells based on geological data;

[0024] S22. Assign corresponding geological attributes to each grid, and use Kriging interpolation method to estimate the attribute values of the positions that are not directly measured;

[0025] S23. Define the fluid type in the oil well, and perform fluid initialization and set the boundary conditions of the model; set the initial fluid distribution and pressure conditions, and at the same time, set the boundary conditions of the model;

[0026] S24. Integrate the above information using geological modeling software to generate a complete three-dimensional geological model.

[0027] As a further improvement of this technical solution, in S22, the specific method for using the Kriging interpolation method to estimate the attribute values of the positions that are not directly measured is as follows:

[0028]

[0029] where λ i is the proportion of the i-th observation point in predicting the attribute value of the unknown point u 0 ; C(u 0 , u i ) is the covariance of the observed values between the predicted unknown point u 0 and the observation point u i ; σ 2 is the small error; u 0 is the predicted unknown point; u i is the position of the i-th observation point; u j is the position of the j-th observation point.

[0030] As a further improvement of this technical solution, the fluid initialization in S23 includes initializing saturation and initializing pressure, and the boundary conditions include closed boundary, constant pressure boundary, and constant flow boundary. The specific methods are as follows:

[0031] Initializing saturation:

[0032]

[0033] So S(x) = 1 - S w (x)

[0034] where S w (x) is the initial aqueous phase saturation at position x; S w is the initial aqueous phase saturation in the water-saturated zone; Ω w is the spatial region occupied by the aqueous phase; Ω o is the spatial region occupied by the oil phase; S o (x) is the initial oil phase saturation at position x;

[0035] Initial pressure:

[0036] P(x) = P ref + ρ·g·z

[0037] where P(x) is the initial pressure at position x; P ref is the reference pressure; ρ is the density of the fluid; g is the acceleration due to gravity; z is the depth;

[0038] Closed boundary: q(x b ) = 0;

[0039] Constant pressure boundary: P(x b ) = P b ;

[0040] Constant flow boundary: q(x b ) = q b ;

[0041] where q(x b ) is the fluid flow rate at the boundary x b ; P(x b ) is the pressure at the boundary x b ; P b is the set boundary pressure value; q b is the set boundary flow rate value.

[0042] As a further improvement of this technical solution, in step S3, the specific method for establishing the oil-water two-phase flow model is as follows:

[0043] Mass conservation equation for oil phase flow:

[0044]

[0045] where φ is the porosity; S o is the saturation of the oil phase; ρ o is the density of the oil phase; is the net inflow or outflow rate of the fluid per unit volume; u o is the average velocity of the oil phase; q ois the source-sink term of the oil phase;

[0046] Mass conservation equation for water phase flow:

[0047]

[0048] where S w is the water saturation; ρ w is the density of the water phase; u w is the average velocity of the water phase; q w is the source-sink term of the water phase;

[0049] Momentum conservation equation for the oil phase:

[0050]

[0051] where k ro is the relative permeability of the oil phase; μ o is the dynamic viscosity of the oil phase; k is the absolute permeability; p o is the pressure of the oil phase; g is the acceleration due to gravity; λ o is the effective mobility of the oil phase; p c is the capillary pressure;

[0052] Momentum conservation equation for the oil phase:

[0053]

[0054] where k rw is the relative permeability of the water phase; μ w is the dynamic viscosity of the water phase; p w is the pressure of the water phase; λ ω is the effective mobility of the water phase;

[0055] As a further improvement of this technical solution, the advancement of the water drive front in S4 includes the moving speed, direction and water saturation distribution of the oil-water interface. By analyzing the moving speed, direction and water saturation distribution of the oil-water interface, the specific position of the water drive front is determined.

[0056] As a further improvement of this technical solution, the specific method for determining the specific position of the water drive front by analyzing the moving speed, direction and water saturation distribution of the oil-water interface is as follows:

[0057] Moving speed of the oil-water interface:

[0058]

[0059] where v avg is the moving speed of the oil-water interface; d 1 is the first position of the oil-water interface; d 2is the second position of the oil-water interface; t 1 is the first time; t 2 is the second time;

[0060] Water saturation distribution:

[0061]

[0062] where, Δx and Δy are the sizes of the spatial grid; is the water saturation at the next time step; is the water saturation at the current time step; Δt is the time step; is the injection water volume at the (k + 1)-th time step; is the produced water volume at the (k + 1)-th time step; is the water volume flowing into or out of adjacent grid cells at the (k + 1)-th time step;

[0063] Specific position of the water drive front:

[0064]

[0065] where, L f (t) is the position of the water drive front at time T; S w (x, T) is the distribution function of water saturation; x is the spatial position; T is the time; S w,threshold is the water saturation threshold; is the operation of taking the maximum value among all spatial positions x.

[0066] As a further improvement of this technical solution, the specific method for judging whether it is economically feasible to plug the water in the oil well in S5 is as follows:

[0067] Residual oil distribution prediction:

[0068] S r (i, j) = S o (i, j) - S w (i, j)

[0069] where, S r (i, j) is the residual oil saturation; S o (i, j) is the oil saturation; S w (i, j) is the water saturation;

[0070] V r (i, j) = φ(i, j)·Δx·Δy·S r (i, j)

[0071] where, V r (i, j) is the volume of residual oil; φ(i, j) is the porosity;

[0072] Water plugging cost:

[0073] C = (C chem + C labor ) + (V lost ·P)

[0074] Wherein, C is the total cost; C chem is the chemical agent cost; C labor is the labor cost; V lost is the reduced production; P is the crude oil price;

[0075] Expected revenue:

[0076] R = ∑ (i,j) ΔV r (i,j)·P

[0077] Wherein, R is the expected revenue; ∑ (i,j) ΔV r (i,j) is the recoverable crude oil volume;

[0078] Net present value:

[0079] NPV = R - C

[0080] Wherein, NPV is the net present value.

[0081] On the other hand, the present invention provides a system for determining the timing of oil well water plugging operation, including a memory, a processor, and a computer program stored in the memory and executable on the processor, and the processor executes the computer program to implement the method for determining the timing of oil well water plugging operation according to any one of the above.

[0082] Compared with the prior art, the beneficial effects of the present invention:

[0083] 1. In the method and system for determining the timing of oil well water plugging operation, an advanced geological modeling software is used to construct a three-dimensional geological model, which can more accurately reflect the actual situation of the oil well, improve the accuracy of water plugging prediction, and use the time-lapse simulation method to predict the changes in the two-phase flow of oil and water in different time periods, so as to predict the advancement of the water drive front;

[0084] 2. In the method and system for determining the timing of oil well water plugging operation, the influence of injection-production conditions is introduced into the two-phase flow model of oil and water, making the model closer to the actual working conditions, improving the accuracy and reliability of prediction, and more accurately predicting the response of the oil well and locating the most severely watered area in the oil well, so as to implement water plugging operations targeted, avoiding unnecessary overall adjustments to the entire oil well or oil well network, and reducing operation costs and production interference. Description of the Drawings

[0085] Figure 1 This is the overall method flowchart of the present invention. Specific embodiments

[0086] Next, the technical solutions in the embodiments of the present invention will be clearly and completely described in conjunction with the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only a part of the embodiments of the present invention, rather than all embodiments. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without creative efforts shall fall within the protection scope of the present invention.

[0087] Embodiment 1: Please refer to Figure 1 As shown, this embodiment provides a method for determining the timing of water plugging operation in an oil well, including the following steps:

[0088] S1. Collect the historical production data of the oil well, the injection water data of the injection well connected to the oil well, and the geological data of the block where the oil well is located;

[0089] Among them, the historical production data includes production and water cut; the temperature is the fluid temperature in the oil well, which is obtained by measuring with a downhole thermometer; the production is the daily production of the oil well, including the production of crude oil, natural gas and water; the pressure is the bottom hole static pressure and flowing pressure of the oil well, which reflects the energy state of the oil reservoir and is obtained by testing with a downhole pressure gauge; the water cut is the percentage of water in the fluid produced by the oil well, which is obtained by fluid laboratory analysis or on-site measurement;

[0090] The injection water data of the injection well connected to the oil well includes injection volume, injection pressure and geological data; the injection volume is the daily injection volume of the injection well, which is used to maintain the oil reservoir pressure or drive the crude oil in the oil reservoir and is recorded by the flowmeter of the injection well; the injection pressure is the wellhead pressure or bottom hole pressure of the injection well, which reflects the difficulty of water injection and the pressure condition of the oil reservoir and is obtained by the wellhead pressure gauge or downhole pressure sensor; the water quality analysis mainly analyzes the content of impurities in the injection water, such as minerals, dissolved gases and microorganisms. The water quality analysis is generally carried out in the laboratory by chemical and physical analysis of the samples;

[0091] The geological data of the oil well block include geological structure maps, core data, logging data, oil well fluid properties, and capillary pressure; the geological structure map can show the three-dimensional structure of the reservoir and is generated by seismic exploration and geological interpretation; the core data are rock samples taken from the well, providing information on the physical and chemical properties of the reservoir rocks, and are also analyzed in the laboratory, specifically including the color structure, mineral composition, chemical composition, porosity and permeability, saturation, and in-situ stress of the rocks; the logging data refer to the data on the physical properties of underground rock formations obtained by various logging instruments lowered into the well during the drilling process, and these data include the resistivity, natural gamma ray intensity, acoustic velocity, density, etc. of the formation; the oil well fluid properties include the physical and chemical properties of crude oil, natural gas, and formation water, and are obtained through laboratory analysis. Among them, the physical properties of crude oil include color, density, viscosity, pour point, wax content, solubility, etc., and the chemical properties of crude oil include chemical composition, calorific value, and fraction composition; the physical properties of natural gas include density, compressibility, solubility, and flow rate, and the chemical properties of natural gas include main components, impurities, and calorific value; the physical properties of formation water include density and conductivity, and the chemical properties of formation water include chemical composition, pH value, hardness, and solubility; the capillary pressure can describe the movement characteristics of the oil-water interface in the rock pores, affect the oil-water distribution, and is obtained through laboratory rock sample tests.

[0092] S2. Define the initial oil-water conditions and boundary conditions based on the collected historical production data, injection water data, and geological data of the oil well, and use geological modeling software to construct a three-dimensional geological model. The specific steps are as follows:

[0093] S21. Based on the geological data, divide the study area into multiple cells; specifically, select an appropriate cell scale according to the collected data, select an appropriate geographic coordinate system to ensure that all data are within the same framework, use professional geological modeling software to generate cells according to the selected size and shape, and assign the collected data to each cell. Among them,

[0094] S22. Assign corresponding geological attributes to each grid and use Kriging interpolation method to calculate the attribute values at positions that are not directly measured.

[0095] The property values include porosity, permeability, and saturation, which means assigning geological properties to each cell in a three-dimensional grid. This step is based on existing drilling data, logging curves, and other geological information. However, since it is impossible to directly measure at every grid point, Kriging interpolation technology is needed to estimate the property values at unmeasured locations. Kriging interpolation is a geostatistical method that not only considers the spatial correlation but also takes into account the variability and uncertainty of the data, thus providing a more accurate interpolation result. By analyzing the property values of known points and their spatial distribution, Kriging interpolation can predict the geological properties of unknown points and at the same time give the variance of the prediction, which is used to evaluate the uncertainty of the prediction.

[0096] In S22, the specific method of using Kriging interpolation to estimate the property values at unmeasured locations is as follows:

[0097]

[0098] Among them, λ i is the weight of the i-th observation point in predicting the property value of the unknown point u 0 . The magnitude of the weight reflects the contribution degree of this observation point to the predicted value, and it is usually related to the distance between the observation point and the predicted point and the spatial correlation of the property values; C(u 0 , u i ) is the covariance of the observed values between the predicted unknown point u 0 and the observation point u i . The covariance reflects the strength of the linear relationship between the property values of two points. A positive value indicates a positive correlation, a negative value indicates a negative correlation, and zero indicates no correlation; σ 2 is the small error, which reflects the random variation or measurement error in the observed data that cannot be explained by the spatial structure; u 0 is the predicted unknown point; u i is the location of the i-th observation point; u j is the location of the j-th observation point.

[0099] The core function of Kriging interpolation is to predict the property values of unobserved points based on the existing observed point data, such as rock porosity, permeability, etc. By calculating the weights of each observation point for the predicted point, an optimal linear unbiased predicted value can be obtained. In addition to predicting the property values of unknown points, Kriging interpolation can also provide the variance or standard error of the predicted value, which helps to evaluate the uncertainty of the prediction result.

[0100] S23. Define the fluid types in the oil well, which are oil and water in this embodiment, and perform fluid initialization and set the boundary conditions of the model; set the initial fluid distribution and pressure conditions, and at the same time set the boundary conditions of the model;

[0101] Among them, fluid initialization includes initializing saturation and initializing pressure. Boundary conditions include closed boundaries, constant-pressure boundaries, and constant-flow boundaries. A closed boundary is a boundary that does not allow fluid to enter or exit; a constant-pressure boundary is a condition where the pressure remains constant on the boundary; a constant-flow boundary is a condition where the flow rate remains constant on the boundary. The specific methods are as follows:

[0102] Initializing saturation, initializing saturation is to specify the distribution of the aqueous phase and the oil phase in the oil well when the model starts running:

[0103]

[0104] S o (x) = 1 - S w (x)

[0105] Among them, S w (x) is the initial aqueous-phase saturation at position x; S w is the initial aqueous-phase saturation in the water-saturated zone; Ω w is the spatial region occupied by the aqueous phase; Ω o is the spatial region occupied by the oil phase; S o (x) is the initial oil-phase saturation at position x;

[0106] Initial pressure:

[0107] P(x) = P ref + ρ·g·z

[0108] Among them, P(x) is the initial pressure at position x; P ref is the reference pressure; ρ is the density of the fluid; g is the acceleration due to gravity; z is the depth;

[0109] The setting of the initial pressure takes into account the influence of gravity, ensuring that the model can correctly reflect the pressure gradient generated inside the oil well due to depth differences. This setting is crucial for predicting the fluid flow direction, velocity, and the movement of the oil-water interface because the fluid flow is driven by the pressure gradient. By specifying the reference pressure P ref and considering the influence of depth z, the model can more realistically simulate the pressure distribution inside the oil well;

[0110] Closed boundary: q(x b ) = 0; The closed boundary condition ensures that a specific boundary in the model does not allow fluid to enter or exit, which can prevent the model results from being improperly affected by the boundary conditions;

[0111] Constant-pressure boundary: P(x b ) = P b ; Setting the boundary condition of a constant pressure, such as the wellhead pressure or the natural pressure at the edge of the oil well, helps to simulate the response of the oil well under a specific pressure;

[0112] Constant flow boundary: q(x b ) = q b ; The constant flow boundary condition is used to simulate the response of an oil well at a specific flow rate, such as setting a constant water injection rate in a water injection well;

[0113] Among them, q(x b ) is the fluid flow rate at the boundary x b ; P(x b ) is the pressure at the boundary x b ; P b is the set boundary pressure value; q b is the set boundary flow rate value.

[0114] S24. Integrate the above information using geological modeling software to form a complete three-dimensional geological model; including the geological structure of the oil well, lithology distribution, porosity, permeability, etc. The geological modeling software is Petrel, which is widely used in the oil and gas industry to process and interpret various geological and geophysical data, thereby constructing a detailed three-dimensional geological model. Petrel provides an integrated working environment, enabling geologists, geophysicists, and engineers to collaborate and improve reservoir understanding and development efficiency.

[0115] S3. Based on the three-dimensional geological model, establish an oil-water two-phase flow model. Input the historical production data of the oil well, the injection water data of the injection well connected to the oil well, and the geological data of the block where the oil well is located into the oil-water two-phase flow model to determine whether the oil-water two-phase flow model is valid. During this process, determine which parameters affect the model results, and then preferentially adjust these parameters, and repeatedly iterate and adjust the parameters until a satisfactory result is achieved; In S3, the specific method for establishing the oil-water two-phase flow model is as follows:

[0116] Mass conservation equation for oil-phase flow:

[0117]

[0118] Among them, φ is the porosity, representing the proportion of the pore space in the total volume of the porous medium; S o is the saturation of the oil phase, indicating the proportion of the pore space occupied by the oil phase; ρ o is the density of the oil phase; is the net inflow or outflow rate of the fluid per unit volume, representing the rate of change of the fluid mass flux with space, that is, the net inflow or outflow rate of the fluid per unit volume. For the oil phase or water phase, this helps to describe the flow of the fluid in the porous medium, including how the fluid accumulates or disperses at different spatial positions; u o is the average velocity of the oil phase, representing the average flow velocity of the oil phase in the porous medium; q o is the source-sink term of the oil phase; When qo When q > 0, it represents the injection (source) of the oil phase. When q o < 0, it represents the production (sink) of the oil phase;

[0119] The mass conservation equation for water phase flow:

[0120]

[0121] where S w is the saturation of the water phase; ρ w is the density of the water phase; u w is the average velocity of the water phase; q w is the source-sink term of the water phase;

[0122] The momentum conservation equation for the oil phase:

[0123]

[0124] where k ro is the relative permeability of the oil phase, which describes the degree of reduction in the actual permeability of the oil phase and the water phase relative to the absolute permeability in the porous medium; μ o is the dynamic viscosity of the oil phase; k is the absolute permeability, indicating the ability of the porous medium to allow fluid flow; p o is the pressure of the oil phase, representing the pressure distribution of the fluid in the porous medium; g is the acceleration due to gravity; λ o is the effective mobility of the oil phase; p c is the capillary pressure, indicating that there is an additional pressure difference between the oil phase and the water phase due to surface tension in the porous medium;

[0125] The momentum conservation equation for the oil phase:

[0126]

[0127] where k rw is the relative permeability of the water phase; μ w is the dynamic viscosity of the water phase; p w is the pressure of the water phase; λ ω is the effective mobility of the water phase.

[0128] The influence of injection-production conditions is introduced into the mass conservation equation of oil phase flow and the mass conservation equation of water phase flow for optimization. The optimized oil-water two-phase flow model is as follows:

[0129] The injection-production conditions include injection-production ratio, injection well spacing, and injection method;

[0130] where the injection-production ratio is the ratio of injection volume to production volume of oil, which affects the advancing speed of water flooding and the maintenance of reservoir pressure; in the model, the source-sink terms qo and q can be adjusted wTo reflect the injection-production ratio. For example, if the injection volume increases, it will cause q w to increase, while the decrease in oil production will cause q o to decrease, which will affect the pressure balance and fluid flow in the oil well.

[0131] The injection-production well spacing affects the swept area of water flooding. An overly large well spacing may lead to a decrease in water flooding efficiency; a shorter injection-production well spacing may cause the injected water to flow too quickly from the injection well to the production well, resulting in so-called "water channeling" and reducing the oil sweep efficiency. In the model, the effect of the injection-production well spacing can be reflected by adjusting the spatial distribution of q o and q w and considering the change in the pressure gradient between the injection and production wells.

[0132] The injection methods include edge injection, area injection, point injection, etc. Different injection methods will affect the shape and advancing speed of the water flooding front; in the model, different injection methods can be reflected by adjusting the variation law of q w with time. For example, cyclic injection will introduce cyclic variations in q w , which will affect the pressure and fluid distribution in the oil well.

[0133]

[0134] q w,adjusted = q w ×(1 + R)×e -αd ×g(t)

[0135] g(t)= Asin(ωt)+ B

[0136] where q o,adjusted is the optimized oil-phase source-sink term; R is the injection-production ratio, which defines the ratio of the injection volume to the production volume. If R > 1, it means the injection volume is greater than the production volume, and vice versa; α is an empirical constant used to describe the attenuation degree of the injection-production well spacing on the flow efficiency. Generally, as d increases, the flow efficiency of the fluid from the injection well to the production well will decrease. The larger α is, the more significant the negative impact of the distance on the efficiency; d is the distance between the injection and production wells, that is, the average distance between the injection well and the production well. This distance affects the injection efficiency and the pressure distribution in the oil well; q w,adjusted is the optimized water-phase source-sink term; g(t) is a time function; A is the amplitude, which describes the amplitude of the fluctuation of the water-phase source-sink term in the cyclic injection mode; ω is the angular frequency, which determines the speed of the cyclic change, that is, the frequency of cyclic injection; t is time; B is the offset, which represents the base value of the water-phase source-sink term without cyclic change;

[0137] The mass conservation equation for the optimized oil-phase flow:

[0138]

[0139] Mass conservation equation for optimized aqueous phase flow:

[0140]

[0141] By carefully simulating injection and production conditions, the well dynamics can be better understood, including fluid flow paths, pressure change trends, and oil-water saturation distributions, providing a basis for subsequent prediction of the waterflood front advance;

[0142] S4. Use the time-lapse simulation method to simulate the oil-water movement in the oil-water two-phase flow model at different time periods and predict the advance of the waterflood front; the advance of the waterflood front includes the movement speed, direction, and water saturation distribution of the oil-water interface. By analyzing the movement speed, direction, and water saturation distribution of the oil-water interface, determine the specific position of the waterflood front.

[0143] The specific method for determining the specific position of the waterflood front by analyzing the movement speed, direction, and water saturation distribution of the oil-water interface is as follows:

[0144] Movement speed of the oil-water interface:

[0145]

[0146] where v avg is the movement speed of the oil-water interface; d 1 is the first position of the oil-water interface; d 2 is the second position of the oil-water interface; t 1 is the first time; t 2 is the second time;

[0147] By comparing the positions (d1 and d2) of the oil-water interface at two different times (t1 and t2), this formula can obtain the interface movement speed, which is a key parameter for understanding the waterflood effect and well dynamics;

[0148] Water saturation distribution:

[0149]

[0150] where Δx and Δy are the sizes of the spatial grid; is the water saturation at the next time step; is the water saturation at the current time step; Δt is the time step; is the water injection volume at the (k + 1)th time step; is the water production volume at the (k + 1)th time step; is the water volume flowing into or out of the adjacent grid cell at the (k + 1)th time step;

[0151] This equation is based on the principle of mass conservation and is used to calculate the change of water saturation over time. It takes into account the injected water volume, the produced water volume, and the water volume exchange between adjacent grid cells. By solving this equation, the water saturation distribution at each point in the oil well can be obtained;

[0152] The specific position of the water flood front:

[0153]

[0154] where, L f (t) is the position of the water flood front at time T. Here, "position" usually refers to the distance along the flow direction of the oil well, which can be the horizontal distance or the vertical depth, depending on the geometric structure and flow direction of the oil well; S w (x, T) is the distribution function of water saturation, x is the spatial position; T is the time; is a variable that depends on the spatial position x and time T. x can be one-dimensional, two-dimensional, or three-dimensional spatial coordinates, depending on the complexity of the oil well model; S w,threshold is the water saturation threshold. When the water saturation S w (x, T) exceeds this threshold, it can be considered that this position has been affected by water flooding and is within the coverage of the water flood front. The selection of this threshold depends on the specific oil well conditions and production objectives and usually needs to be determined through experiments or experience; is the operation of taking the maximum value among all spatial positions x, which is the farthest point where the water saturation first exceeds the threshold, that is, the exact position of the water flood front.

[0155] This formula is used to determine the specific position of the water flood front at any time T. The water flood front refers to the forefront where the water saturation exceeds a certain threshold S w,threshold . By finding the maximum value of the water saturation among all spatial positions x that satisfy the condition, the farthest advancing boundary during the water flooding process can be clearly indicated.

[0156] Assume that on the 200th day and the 300th day of oilfield development, the positions of the oil-water interface are recorded as d1 = 1500m and d2 = 1750m respectively, and the time points are t1 = 200 days and t2 = 300 days;

[0157] Calculation of the oil-water interface movement speed:

[0158] Water saturation distribution: Assume Δx = 10m and Δy = 10m, Δt = 1 day, and the water saturation threshold S w,threshold = 0.7;

[0159] Assume that at the 300th day, the water saturation S at the grid position x = 3000m w(3000, 300) = 0.75, and it is the position where the water saturation exceeds the threshold S for the first time among all positions. w,threshold The position where...

[0160] Position of the water drive front: At the 300th day, the position L f (300) is 3000 m.

[0161] Through the above steps, the specific position of the water drive front in the reservoir can be accurately determined, providing a decision-making basis for the oilfield development strategy.

[0162] S5. Evaluate the current water flooding status of the oil well according to the predicted advancement of the water drive front. If it enters the high water flooding stage, then determine whether it is economically feasible to plug the water in this oil well. If it is economically feasible, then implement the water plugging operation.

[0163] Water plugging of an oil well requires first determining whether it has entered the high water flooding stage. Determining whether it has entered the high water flooding stage is based on whether the water cut is higher than the predetermined threshold and whether the water drive front is rapidly approaching or has reached near the oil well. The water cut is the most direct indicator reflecting the water flooding degree of the oil well. A sharp increase in the water cut, especially a significant increase in a short period of time, is usually a signal of entering the high water flooding stage. At the same time, by increasing the judgment criterion of the water drive front, a rapidly advancing water drive front may indicate an accelerated water flooding in the oil well area, especially when the water drive front advances rapidly along the main permeation path. Once it is determined that the oil well has entered the high water flooding stage and the economic evaluation shows that the cost-benefit ratio of the water plugging operation is reasonable, then implement the water plugging operation. For the production interval with high water cut, use chemical agents, mechanical devices, etc. to reduce the water flowing into the wellbore. In some cases, it may be necessary to recomplete the well or sidetrack a new wellbore to avoid severely water flooded areas and find new oil layers or improve the oil-water flow direction.

[0164] Among them, the specific method for determining whether it is economically feasible to plug the water in this oil well is as follows:

[0165] Prediction of remaining oil distribution:

[0166] S r (i, j) = S o (i, j) - S w (i, j)

[0167] Among them, S r (i, j) is the remaining oil saturation; S o (i, j) is the oil saturation; S w (i, j) is the water saturation;

[0168] V r (i, j) = φ(i, j)·Δx·Δy·S r (i, j)

[0169] Among them, V r (i,j) is the volume of remaining oil; φ(i,j) is the porosity;

[0170] Identifying the distribution of remaining oil can help engineers determine the optimal development plan, such as selecting appropriate injection well locations or adjusting the layout of production wells;

[0171] Water shutoff cost:

[0172] C = (C chem + C labor ) + (V lost ·P)

[0173] Among them, C is the total cost; C chem is the chemical agent cost; C labor is the labor cost; V lost is the reduced production; P is the crude oil price; among them, C chem + C labor is the direct cost; V lost ·P is the indirect cost;

[0174] Expected revenue:

[0175] R = ∑ (i,j) ΔV r (i,j)·P

[0176] Among them, R is the expected revenue; ∑ (i,j) ΔV r (i,j) is the recoverable crude oil volume;

[0177] Net present value:

[0178] NRV = R - C

[0179] Among them, NPV is the net present value.

[0180] If the net present value NPV is positive, it indicates that the water shutoff measure is economically feasible; otherwise, it is not. This can not only help them better understand the physical processes within the reservoir but also evaluate the feasibility of development strategies at the economic level, thus enabling more informed investment decisions. Through this method, the overall efficiency and economic benefits of oilfield development can be improved.

[0181] Suppose well A has a remaining oil volume of 10000 m 3 before water shutoff, the additional recoverable volume after water shutoff is 1000 m 3 , the crude oil price is 60 yuan per barrel (assuming 1 m 3 = 6.2898 barrels), the water shutoff cost is 100000 for chemical agents and 50000 for labor, and the production reduction due to water shutoff is 200 m 3

[0182] Residual oil volume: 10,000 m 3

[0183] Chemical agent cost: 100,000 yuan

[0184] Labor cost: 50,000 yuan

[0185] Crude oil price: 60 yuan / barrel

[0186] Reduced production: 200 m 3

[0187] Expected revenue: R = 1000 m3 × 6.2898 × 60 = 3,773,882

[0188] Total cost: C = 150,000 + (200 m 3 × 6.2898 × 60) = 2,753,883

[0189] Calculate the net present value: NPV = 3,773,882 - 2,753,883 = 1,020,000

[0190] Since the net present value NPV is positive, it indicates that water plugging is economically feasible and the expected revenue is greater than the cost.

[0191] Example 2: This example provides a system for determining the timing of water plugging operations in oil wells, including a memory, a processor, and a computer program stored in the memory and executable on the processor. The processor executes the computer program to implement the method for determining the timing of water plugging operations in oil wells described in any one of the above.

[0192] The above shows and describes the basic principles, main features, and advantages of the present invention. Those skilled in the art should understand that the present invention is not limited by the above embodiments. The above embodiments and the descriptions in the specification are only preferred examples of the present invention and are not used to limit the present invention. Without departing from the spirit and scope of the present invention, the present invention will have various changes and improvements, and these changes and improvements all fall within the scope of the present invention claimed.

Claims

1. A method for determining the timing of oil well water plugging operation, characterized in that: The following steps are involved: S1. Collect historical production data of oil wells, injection water data of water injection wells connected to the oil wells, and geological data of the block where the oil wells are located; S2. Based on the collected historical production data of the oil wells, the injected water data of the water injection wells connected to the oil wells, and the geological data of the block where the oil wells are located, define the initial oil and water conditions and boundary conditions, and use geological modeling software to construct a three-dimensional geological model; S3. On the basis of the three-dimensional geological model, an oil-water two-phase flow model is established. The historical production data of the oil wells, the injection water data of the water injection wells connected to the oil wells, and the geological data of the block where the oil wells are located are input into the oil-water two-phase flow model to determine whether the oil-water two-phase flow model is established. In this process, which parameters have an impact on the model results are determined, and then these parameters are adjusted first. The parameters are adjusted repeatedly and iteratively until satisfactory results are achieved. The oil-water two-phase flow model includes the mass conservation equation of the oil phase flow, the mass conservation equation of the water phase flow, the momentum conservation equation of the oil phase and the momentum conservation equation of the water phase; The influence of injection and production conditions is introduced into the mass conservation equation of oil phase flow and the mass conservation equation of water phase flow for optimization. The optimized oil-water two-phase flow model is as follows: Injection-production conditions include injection-production ratio, injection well spacing, and injection method; q w,adjusted =q w ×(1+R)×e -αd ×g(t) g(t)=Asin(ωt)+B Among them, q o,adjusted is the optimized oil source and sink term; R is the injection-production ratio; α is the empirical constant; d is the distance between the injection and production wells; q w,adjusted is the optimized water source and sink term; g(t) is the time function; A is the amplitude; ω is the angular frequency; t is the time; B is the offset; The mass conservation equation of the optimized oil phase flow is: The optimized mass conservation equation for water phase flow is: S4. Use the time-lapse simulation method to simulate the movement of oil and water in different time periods of the oil-water two-phase flow model and predict the advancement of the water flooding front; S5. Evaluate the current water flooding status of the oil well based on the predicted advancement of the water drive front. If the oil well enters the high water flooding stage, determine whether water plugging is economically feasible. If it is economically feasible, implement water plugging operations.

2. The method for determining the timing of oil well water plugging operation according to claim 1, characterized in that: In S1, the historical production data includes production and water content; the injected water data of the water injection wells connected to the oil wells include injection volume, injection pressure and geological data; the geological data of the block where the oil wells are located include geological structure maps, core data, logging data, oil well fluid properties and capillary pressure.

3. The method for determining the timing of oil well water plugging operation according to claim 2, characterized in that: The specific steps of S2 are as follows: S21. Divide the study area into multiple cells based on geological data; S22, assigning corresponding geological attributes to each grid, and using Kriging interpolation method to estimate the attribute values ​​of the locations that are not directly measured; S23, defining the fluid type in the oil well, initializing the fluid and setting the boundary conditions of the model; setting the initial fluid distribution and pressure conditions, and setting the boundary conditions of the model; S24. Use geological modeling software to integrate the above information and generate a complete three-dimensional geological model.

4. The method for determining the timing of oil well water plugging operation according to claim 3, characterized in that: In S22, the specific method of estimating the attribute value of the location not directly measured by the Kriging interpolation method is as follows: Among them, λ i is the proportion of the i-th observation point in predicting the attribute value of the unknown point u0; C(u0,u i ) is the predicted unknown point u0 and the observed point u i The covariance of the observations between 2 is a small error; u0 is the unknown point of prediction; u i is the position of the i-th observation point; u j is the position of the jth observation point.

5. The method for determining the timing of oil well water plugging operation according to claim 4, characterized in that: The fluid initialization in S23 includes initialization saturation and initialization pressure, and the boundary conditions include closed boundary, constant pressure boundary and constant flow boundary. The specific method is as follows: Initialize saturation: S o (x)=1-S w (x) Among them, S w (x) is the initial water phase saturation at position x; S w is the initial water phase saturation in the water saturated zone; Ω w is the spatial area occupied by the water phase; Ω o is the spatial area occupied by the oil phase; S o (x) is the initial oil phase saturation at position x; Initial pressure: P(x)=P ref +ρ·g·z Where P(x) is the initial pressure at position x; P ref is the reference pressure; ρ is the density of the fluid; g is the acceleration due to gravity; z is the depth; Closed boundary: q(x b )=0; Constant pressure boundary: P(x b )=P b ; Constant current boundary: q(x b )=q b ; Among them, q(x b ) is on the boundary x b Fluid flow rate at; P(x b ) is on the boundary x b The pressure at b is the set boundary pressure value; q b is the set boundary flow value.

6. The method for determining the timing of oil well water plugging operation according to claim 5, characterized in that: In S3, the specific method for establishing the oil-water two-phase flow model is as follows: The mass conservation equation for oil phase flow is: Where φ is the porosity; S o is the saturation of the oil phase; ρ o is the density of the oil phase; is the net inflow or outflow rate of fluid per unit volume; u o Average velocity of the oil phase; q o is the source and sink term of the oil phase; The mass conservation equation for water phase flow is: Among them, S w is the saturation of the water phase; ρ w is the density of the water phase; u w is the average velocity of the water phase; q w is the source and sink term of the water phase; Momentum conservation equation for the oil phase: Among them, k ro is the relative permeability of the oil phase; μ o is the dynamic viscosity of the oil phase; k is the absolute permeability; p o is the pressure of the oil phase; g is the acceleration due to gravity; λ o is the effective fluidity of the oil phase; p c is the capillary pressure; Momentum conservation equation for the oil phase: Among them, k rw is the relative permeability of the water phase; μ w is the dynamic viscosity of the water phase; p w is the pressure of the water phase; ω is the effective fluidity of the water phase.

7. The method for determining the timing of oil well water plugging operation according to claim 6, characterized in that: The advancement of the water flooding front in S4 includes the moving speed, direction and water saturation distribution of the oil-water interface. The specific position of the water flooding front is determined by analyzing the moving speed, direction and water saturation distribution of the oil-water interface.

8. The method for determining the timing of oil well water plugging operation according to claim 7, characterized in that: By analyzing the movement speed, direction and water saturation distribution of the oil-water interface, the specific method for determining the specific position of the water flooding front is as follows: Movement speed of oil-water interface: Among them, v avg is the moving speed of the oil-water interface; d1 is the first position of the oil-water interface; d2 is the second position of the oil-water interface; t1 is the first time; t2 is the second time; Water saturation distribution: Among them, Δx and Δy are the sizes of the spatial grid; is the water saturation at the next time step; is the water saturation of the current time step; Δt is the time step; is the amount of water injected at the k+1th time step; is the water output at the k+1th time step; is the amount of water flowing in or out from the adjacent grid cell at the k+1th time step; Specific location of the water drive front: Among them, L f (t) is the position of the water drive front at time T; S w (x,T) is the distribution function of water saturation; x is the spatial position; T is the time; S w,threshold is the water saturation threshold; is the operation of taking the maximum value among all spatial positions x.

9. The method for determining the timing of oil well water plugging operation according to claim 8, characterized in that: The specific method for judging whether water plugging of the oil well is economically feasible in S5 is as follows: Remaining oil distribution prediction: S r (i,j)=S o (i,j)-S w (i,j) Among them, S r (i, j) is the residual oil saturation; S o (i,j) is the oil saturation; S w (i,j) is water saturation; V r (i,j)=φ(i,j)·Δx·Δy·S r (i,j) Among them, V r (i,j) is the volume of remaining oil; φ(i,j) is the porosity; Water plugging cost: C=(C chem +C labor +(V lost ·P) Among them, C is the total cost; C chem C is the cost of chemicals; labor V is labor cost; lost is the reduced output; P is the crude oil price; C chem +C labor is the direct cost; V lost P is the indirect cost; Expected Returns: R=∑ (i,j) ΔV r (i,j)·P Where R is the expected return; ∑ (i,j) ΔV r (i,j) is the amount of recoverable crude oil; Net Present Value: NPV=RC Among them, NPV is net present value; If the net present value NPV is a positive number, it means that the water plugging measures are economically feasible, otherwise they are not feasible.

10. A system for determining the timing of an oil well water plugging operation, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that: The processor executes a computer program to implement the method for determining the timing of an oil well water plugging operation as described in any one of claims 1-9.

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