A method for obtaining formation pressure in foam flooding

Abstract

The present invention provides a method for obtaining formation pressure in foam drive, and relates to the technical field of oil and gas production. The present invention collects foam injection and production parameters such as foaming agent injection amount, foaming agent concentration, gas flow rate, gas volume, foaming agent relative density and gas relative density, calculates foam generation rate, foam density and foam flow volume, and generates a comprehensive adjustment factor, uses average foam density, average foam flow rate and average friction coefficient to construct a pressure difference calculation model, and determines the pressure drop in the wellbore pipe section by section, sets a pressure drop threshold, and uses the adjustment factor to adjust the pressure drop exceeding the threshold, calculates the wellhead pressure based on the optimized pressure difference calculation model, and determines the formation pressure in combination with the pressure drop in each section of the pipe. The present invention realizes accurate control and optimization of the formation wellbore pressure in the foam drive process by calculating foam parameters, constructing a pressure difference model, adjusting the pressure drop section by section and determining the formation pressure, and ensures efficient, safe and economical operation.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas exploitation, and in particular to a method for obtaining formation pressure by foam drive. Background Art

[0002] Foam flooding is a technology used to enhance oil recovery. It improves fluid flow in oil reservoirs by injecting bubbles with foaming agents. The core of modern foam flooding technology lies in the performance optimization of foaming agents. It is widely used in low permeability reservoirs because it can effectively improve fluid flow. In heavy oil production, foam flooding can reduce the tension of the oil-water interface, improve the fluidity of heavy oil, and greatly improve the efficiency of oil and gas production.

[0003] In the prior art, publication number CN110924913B discloses a method and device for obtaining formation pressure by foam drive, which comprises dividing a wellbore into a plurality of wellbore units of the same length; obtaining foam injection and production parameters; and based on the foam injection and production parameters, starting from the wellhead of the wellbore, calculating the upper pressure and the lower pressure of each wellbore unit section by section in the following manner until the lower pressure of the last wellbore unit is calculated, and taking the lower pressure of the last wellbore unit as the foam drive formation pressure.

[0004] Insufficient existing technology:

[0005] The existing technology relies on parameter averaging, which may lead to inaccurate results, especially when foam properties and wellbore conditions are complex and changeable. In addition, the existing technology usually relies on manual measurement and preset parameters, lacks the support of real-time data collection, resulting in data lag and increased errors, limiting its application in dynamic adjustment.

[0006] Secondly, the existing methods need to perform repeated iterations when calculating the wellbore pressure drop section by section, which not only increases the complexity and time cost of the calculation, but also may lead to insufficient control of pressure changes. In addition, the lack of a comprehensive adjustment mechanism to deal with situations where the actual pressure drop exceeds expectations makes it difficult for traditional methods to maintain accuracy and efficiency under complex geological conditions.

[0007] Therefore, it is necessary to provide a method for obtaining formation pressure during foam flooding to solve the above problem.

[0008] The above information disclosed in this Background section is only for enhancement of understanding of the background of the present disclosure and therefore it may contain information that does not constitute the prior art that is already known to one of ordinary skill in the art. Summary of the invention

[0009] The object of the present invention is to provide a method for obtaining formation pressure in foam drive to solve the problems raised in the above background technology.

[0010] To achieve the above object, the present invention provides the following technical solutions:

[0011] A method for obtaining formation pressure in foam flooding, the specific steps comprising:

[0012] Step 1: installing a distributed sensor network in a formation wellbore for collecting foam injection and production parameters, the parameters including foaming agent concentration, gas flow rate, gas volume, foaming agent relative density and gas relative density;

[0013] Step 2: Calculate the foam generation rate, foam density and foam flow volume according to the collected foam injection and production parameters, and use the calculated foam generation rate, foam density and foam flow volume to comprehensively generate an adjustment factor;

[0014] Step 3: constructing a pressure difference calculation model, wherein the parameters required for constructing the pressure difference calculation model include average foam density, average foam flow rate and average friction coefficient;

[0015] Step 4: Determine the pressure drop in the wellbore section by section using the pressure difference calculation model, set a pressure drop threshold in each section of the wellbore, and use the adjustment factor to adjust the pressure drop in the wellbore that exceeds the pressure drop threshold;

[0016] Step 5: Calculate the wellhead pressure based on the optimized pressure difference calculation model, and determine the formation pressure by combining the pressure drop in each section of the wellbore;

[0017] Furthermore, foam injection and production parameters are collected, including foaming agent concentration, gas flow rate, gas volume, foaming agent relative density and gas relative density, based on the formula:

[0018]

[0019] Q g =A*v

[0020] V g =Q g *Δt

[0021] Among them, V t represents the total volume of the injected foaming agent, Δt represents the total injection time, C d Indicates the concentration of foaming agent, m d Indicates the mass of the foaming agent, Q g represents the gas flow rate, A represents the cross-sectional area of ​​the wellbore, v represents the gas flow rate, V g Indicates the volume of gas;

[0022] The relative density of the foaming agent and the relative density of the gas are calculated using the ratio method, based on the following formula:

[0023]

[0024] Among them, ρ d Represents the relative density of the foaming agent, ρ solution represents the density of the foaming agent, ρ water represents the density of water, ρ g Represents the relative density of the gas, ρ gas represents the density of the gas, ρ air Indicates the density of air.

[0025] Furthermore, the foam generation rate, foam density and foam flow volume are calculated based on the following formula:

[0026]

[0027] Among them, s d represents the foam generation rate, V s represents the volume of foam generated, ρ f Indicates the foam density, h g represents the foam flow volume, P s represents standard atmospheric pressure, Z represents the compression factor, R represents the gas constant, and T represents the temperature inside the cylinder.

[0028] Furthermore, the adjustment factor is comprehensively generated based on the formula:

[0029]

[0030] Among them, X c represents the adjustment factor, and A represents the cross-sectional area of ​​the wellbore.

[0031] Furthermore, a pressure difference calculation model is constructed based on the following method:

[0032] The pressure difference model is constructed by calculating the average foam density, average foam flow rate and average friction coefficient to evaluate the friction pressure drop caused by foam flow in the wellbore. Sample points are collected in the wellbore, and the foam density, foam flow rate and friction coefficient of each point are calculated. The average value of the calculation results of the three parameters is taken for calculation. The formula is:

[0033]

[0034] Among them, ρ avg , l avg 、f avg Respectively represent the average foam density, average foam flow rate, and average friction coefficient. represents the foam density at the i-th sampling point, l i represents the foam flow rate at the ith sampling point, represents the foam generation rate at the i-th sampling point, represents the gas flow rate at the i-th sampling point, fi Represents the friction coefficient of the i-th sampling point, N represents the number of sampling points, i is the index of the sampling point, and i ranges from 1 to N;

[0035] The pressure difference calculation model is constructed using the calculated average foam density, average foam flow rate and average friction coefficient. The formula is as follows:

[0036]

[0037] Where P represents the average friction pressure drop, L represents the total length of the wellbore, and D represents the inner diameter of the wellbore.

[0038] Furthermore, the friction pressure drop of the wellbore is determined section by section using the pressure difference calculation model, based on the following method:

[0039] The wellbore is divided into K sections from the wellhead to the bottom of the well, and the parameters of each section are determined. The friction pressure drop of each section is calculated using the Darcy-Waisbach equation, and the gravity pressure drop of each section is calculated. The gravity pressure drop depends on the height change of the wellbore and the angle of the wellhead. The total pressure drop of each section is equal to the sum of the friction pressure drop of each section and the gravity pressure drop of each section. The formula is:

[0040]

[0041] ΔG j =ρ j *g*ΔL j sin(θ j )

[0042] ΔW j =ΔP j +ΔG j

[0043] Among them, ΔP j represents the friction pressure drop of the jth segment, f j represents the friction coefficient of the jth segment, ΔL j represents the length of the wellbore in the jth section, ΔD j represents the cross-sectional area of ​​the wellhead at the jth segment, ρ j represents the foam density of the jth segment, l j represents the foam flow rate of the jth segment, ΔG j represents the gravitational pressure drop of the jth segment, g represents the gravitational acceleration, θ j Represents the angle of the j-th section of the wellbore, ΔW j represents the total pressure drop of the jth segment, j∈[1,K].

[0044] Furthermore, the adjustment factor is used to adjust the pressure drop in the tube that exceeds the pressure drop threshold, and the logic is as follows:

[0045]

[0046] ΔW j ′=X c *ΔW j ifΔW j ≥M

[0047] ΔW j ′=1*ΔW j ifΔW j <M

[0048] Among them, E j Indicates the logic value for judging whether the total voltage drop of the jth segment exceeds the voltage drop threshold. j = 0, indicating that the total pressure drop of the jth segment does not exceed the pressure drop threshold, and an adjustment factor of 1 is required for adjustment, and M represents the pressure drop threshold; when E j =1, indicating that the total pressure drop of the jth segment exceeds the pressure drop threshold, and the factor X needs to be adjusted c Adjustment; ΔW j ′ represents the total pressure drop of the jth section after adjustment.

[0049] Furthermore, the wellhead pressure is calculated, and the formation pressure is determined by combining the pressure drop in each section of the wellbore. The formula is:

[0050] P wellhead =ρ f *g*L

[0051]

[0052] Among them, P wellhead represents the wellhead pressure, ρ f represents the foam density, g represents the acceleration of gravity, L represents the total length of the wellbore, and P total represents the formation pressure, and K represents the total number of sections in the wellbore.

[0053] Compared with the prior art, the present invention has the following beneficial effects:

[0054] By collecting foam injection and production parameters in real time, such as daily foaming agent injection volume, foaming agent concentration, gas flow rate, etc., this real-time data collection method greatly improves the accuracy and timeliness of data, avoids the errors caused by traditional methods that rely on manual measurement and preset parameters, and generates a comprehensive adjustment factor by calculating the foam generation rate, foam density and foam flow volume, which can dynamically adjust the parameters in the pressure difference calculation model to make it more in line with the actual situation, thereby significantly improving the accuracy of the calculation results;

[0055] A pressure drop threshold is set in each section of the wellbore, and the pressure drop in the pipe that exceeds the threshold is adjusted using an adjustment factor. This method can more finely and accurately control the pressure change in the wellbore, avoiding the complexity and increase in calculation time caused by the step-by-step update and iterative calculation in the prior art. By constructing and optimizing the pressure difference calculation model, the present invention can determine the pressure drop in the wellbore section by section and calculate the wellhead pressure, and finally accurately determine the formation pressure. Compared with traditional methods, this method is more systematic and optimized, more adaptable to complex wellbore conditions and changes in foam characteristics, and significantly improves the accuracy and efficiency of the overall calculation;

[0056] The present invention realizes higher-precision and more efficient foam drive formation pressure acquisition through real-time data acquisition, comprehensive adjustment factors and optimized calculation models. BRIEF DESCRIPTION OF THE DRAWINGS

[0057] Figure 1 It is a schematic diagram of the overall method flow of the present invention. DETAILED DESCRIPTION

[0058] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with specific embodiments.

[0059] It should be noted that, unless otherwise defined, the technical terms or scientific terms used in the present invention should be understood by people with ordinary skills in the field to which the present invention belongs. The words "first", "second" and similar words used in the present invention do not indicate any order, quantity or importance, but are only used to distinguish different components. "Include" or "comprise" and similar words mean that the elements or objects appearing before the word include the elements or objects listed after the word and their equivalents, without excluding other elements or objects. "Connect" or "connected" and similar words are not limited to physical or mechanical connections, but may include electrical connections, whether direct or indirect. "Up", "down", "left", "right" and the like are only used to indicate relative positional relationships. When the absolute position of the described object changes, the relative positional relationship may also change accordingly.

[0060] Example:

[0061] See also Figure 1 , a method for obtaining formation pressure of foam flooding, the specific steps comprising:

[0062] Step 1: installing a distributed sensor network in a formation wellbore for collecting foam injection and production parameters, the parameters including foaming agent concentration, gas flow rate, gas volume, foaming agent relative density and gas relative density;

[0063] Step 2: Calculate the foam generation rate, foam density and foam flow volume according to the collected foam injection and production parameters, and use the calculated foam generation rate, foam density and foam flow volume to comprehensively generate an adjustment factor;

[0064] Step 3: constructing a pressure difference calculation model, wherein the parameters required for constructing the pressure difference calculation model include average foam density, average foam flow rate and average friction coefficient;

[0065] Step 4: Determine the pressure drop in the wellbore section by section using the pressure difference calculation model, set a pressure drop threshold in each section of the wellbore, and use the adjustment factor to adjust the pressure drop in the wellbore that exceeds the pressure drop threshold;

[0066] Step 5: Calculate the wellhead pressure based on the optimized pressure difference calculation model, and determine the formation pressure by combining the pressure drop in each section of the wellbore;

[0067] It should be noted that the collection of foam injection and production parameters can provide accurate basic data for the calculation of foam drive formation pressure. The accurate collection and calculation of these data not only improves the control accuracy of the foam drive process, but also effectively avoids the errors caused by inaccurate parameters in traditional methods, thereby improving the overall accuracy of formation pressure acquisition. The important parameters of the flow and distribution characteristics of the foaming agent in the formation are evaluated by the relative density of the foaming agent, which helps to understand the behavior of the foaming agent in the formation, such as fluidity, diffusivity and interaction with formation fluids, so as to more accurately evaluate the effect of foam drive; the key parameters of the flow characteristics of gas in the wellbore and formation are evaluated by the relative density of gas, which helps to understand the behavior of gas in the formation, such as buoyancy, diffusivity and interaction with formation fluids, so as to optimize the gas injection strategy and improve the effect of foam drive.

[0068] Therefore, it is necessary to collect foam injection parameters, which include foaming agent concentration, gas flow rate, gas volume, foaming agent relative density and gas relative density, based on the following formula:

[0069]

[0070] Q g =A*v

[0071] V g =Q g *Δt

[0072] Among them, V t represents the total volume of the injected foaming agent, Δt represents the total injection time, C d Indicates the concentration of foaming agent, m d Indicates the mass of the foaming agent, Q g represents the gas flow rate, A represents the cross-sectional area of ​​the wellbore, v represents the gas flow rate, V gIndicates the volume of gas;

[0073] The relative density of the foaming agent and the relative density of the gas are calculated using the ratio method, based on the following formula:

[0074]

[0075] Among them, ρ d Represents the relative density of the foaming agent, ρ solution represents the density of the foaming agent, ρ water represents the density of water, ρ g Represents the relative density of the gas, ρ gas represents the density of the gas, ρ air represents the density of air; in the above formula, the relative density of the foaming agent can be obtained by dividing the density of the foaming agent solution by the density of water, and this ratio indicates how many times the density of the foaming agent solution is the density of water; the relative density of the gas can be obtained by dividing the density of the injected gas by the density of air, and this ratio indicates how many times the density of the injected gas is the density of air.

[0076] It should be noted that the foam generation rate is a key parameter to measure the efficiency of foam formation in the formation, which directly affects the stability of the foam and the oil recovery effect. A high foam generation rate usually means that the foam can cover and displace the oil in the formation more effectively, and the foam density is an important parameter for evaluating the flow characteristics and stability of the foam in the formation. The greater the foam density, the stronger the foam stability and oil recovery ability are usually. Finally, the foam flow volume is a key parameter for evaluating the flow ability and coverage of the foam in the formation. The appropriate foam flow volume can ensure that the foam is evenly distributed in the formation. Calculating these parameters helps to fully understand the formation, characteristics and flow behavior of the foam, thereby improving the efficiency of oil field development.

[0077] Therefore, it is necessary to calculate the foam generation rate, foam density and foam flow volume, based on the formula:

[0078]

[0079]

[0080] Among them, s d represents the foam generation rate, V s represents the volume of foam generated, ρ f Indicates the foam density, h g represents the foam flow volume, P s represents standard atmospheric pressure, Z represents the compression factor, R represents the gas constant, and T represents the temperature inside the cylinder.

[0081] It should be noted that the adjustment factor combines multiple information such as foam generation rate, density and flow volume, and can comprehensively evaluate the behavioral characteristics of foam in the formation. The adjustment factor can be used to optimize the foam flooding injection parameters and strategies, thereby improving the efficiency and effectiveness of foam flooding. The adjustment factor can also be used to optimize the subsequent pressure difference model, which can reduce the waste of foaming agents and gases, thereby reducing production costs and improving economic benefits.

[0082] Therefore, it is necessary to generate the adjustment factor comprehensively, based on the formula:

[0083]

[0084] Among them, X c represents the adjustment factor, A represents the cross-sectional area of ​​the wellbore; in the above formula, the foam generation rate s d Used to adjust some practical factors in the foam generation process, such as the formulation of the foaming agent, injection rate and environmental conditions; foam density ρ f It is used to judge the mass and stability of foam. The larger the foam density, the greater the mass of the foam, and the stronger the coverage and oil displacement capacity of the formation. The foam flow volume affects the oil displacement efficiency of the foam in the formation. The larger the foam flow volume, the wider the coverage of the foam in the formation and the more significant the oil displacement effect. The wellbore cross-sectional area A is used to calculate the lateral range of foam propagation in the wellbore. The larger the wellbore cross-sectional area, the more uniform the distribution of the foam in the wellbore, which helps to carry out foam flooding more effectively.

[0085] It should be noted that the pressure difference calculation model is constructed by combining the Darcy-Waisbach equation with the average foam density, average foam flow rate and average friction coefficient. The Darcy-Waisbach equation is a classic fluid mechanics formula used to calculate the pressure drop when the fluid flows in a pipeline. This equation comprehensively considers the density, flow rate, pipeline characteristics and friction factors of the fluid. It is a commonly used tool in engineering practice. This method can be used to optimize the flow parameters of the foam in the wellbore, reduce friction losses, and improve the overall efficiency of foam flooding. The average foam density, flow rate and friction coefficient can be calculated to comprehensively evaluate the flow of foam in the wellbore, and the friction pressure drop caused by the foam flow can be accurately evaluated, thereby optimizing the foam flow efficiency in the wellbore and improving the overall effect of the foam flooding process.

[0086] Therefore, it is necessary to construct a pressure difference calculation model based on the following method:

[0087] The pressure difference model is constructed by calculating the average foam density, average foam flow rate and average friction coefficient to evaluate the friction pressure drop caused by foam flow in the wellbore. Sample points are collected in the wellbore, and the foam density, foam flow rate and friction coefficient of each point are calculated. The average value of the calculation results of the three parameters is taken for calculation. The formula is:

[0088]

[0089] Among them, ρ avg , l avg 、f avg Respectively represent the average foam density, average foam flow rate, and average friction coefficient. represents the foam density at the i-th sampling point, l i represents the foam flow rate at the ith sampling point, represents the foam generation rate at the i-th sampling point, represents the gas flow rate at the i-th sampling point, f i Represents the friction coefficient of the i-th sampling point, N represents the number of sampling points, i is the index of the sampling point, and i ranges from 1 to N;

[0090] The pressure difference calculation model is constructed using the calculated average foam density, average foam flow rate and average friction coefficient. The formula is as follows:

[0091]

[0092] Where P represents the average friction pressure drop, L represents the total length of the wellbore, and D represents the inner diameter of the wellbore.

[0093] It should be noted that determining the segment-by-segment calculation model of the wellbore friction pressure drop plays a vital role in optimizing the foam flooding process. Dividing the wellbore from the wellhead to the bottom of the well and calculating the friction pressure drop and gravity pressure drop of each segment separately can help to comprehensively and accurately evaluate the energy loss and pressure change during the foam flow process. The friction pressure drop of each segment is calculated by the Darcy-Waisbach equation, and the gravity pressure drop is calculated in combination with the height change of each segment and the wellbore angle, which can fully reflect the actual pressure drop of each segment.

[0094] Therefore, it is necessary to use the pressure difference calculation model to determine the friction pressure drop of the wellbore section by section, based on the following method:

[0095] The wellbore is divided into K sections from the wellhead to the bottom of the well, and the parameters of each section are determined. The friction pressure drop of each section is calculated using the Darcy-Waisbach equation, and the gravity pressure drop of each section is calculated. The gravity pressure drop depends on the height change of the wellbore and the angle of the wellhead. The total pressure drop of each section is equal to the sum of the friction pressure drop of each section and the gravity pressure drop of each section. The formula is:

[0096]

[0097] ΔG j =ρ j *g*ΔL j sin(θ j )

[0098] ΔW j =ΔP j +ΔG j

[0099] Among them, ΔP j represents the friction pressure drop of the jth segment, f j represents the friction coefficient of the jth segment, ΔL j represents the length of the wellbore in the jth section, ΔD j represents the cross-sectional area of ​​the wellhead at the jth segment, ρ j represents the foam density of the jth segment, l j represents the foam flow rate of the jth segment, ΔG j represents the gravitational pressure drop of the jth segment, g represents the gravitational acceleration, θ j Represents the angle of the j-th section of the wellbore, ΔW j represents the total pressure drop of the jth segment, j∈[1,K].

[0100] It should be noted that by judging whether the total pressure drop of each section exceeds the set pressure drop threshold, the area with excessive pressure loss can be identified in time, and necessary adjustments can be made through the adjustment factor. This can avoid potential risks caused by excessive pressure, such as equipment damage or system instability, thereby ensuring the safe operation of the entire foam flooding system, and adjusting the sections that exceed the pressure drop threshold can effectively reduce unnecessary energy losses and improve energy utilization efficiency. This not only helps to reduce operating costs, but also improves the flow efficiency of foam in the wellbore, thereby improving the overall effect of foam flooding.

[0101] Therefore, it is necessary to use the adjustment factor to adjust the pressure drop in the pipe that exceeds the pressure drop threshold. The logic is as follows:

[0102]

[0103] ΔW j ′=X c *ΔW j ifΔW j ≥M

[0104] ΔW j ′=1*ΔW j ifΔW j <M

[0105] Among them, E j Indicates the logic value for judging whether the total voltage drop of the jth segment exceeds the voltage drop threshold. j = 0, indicating that the total pressure drop of the jth segment does not exceed the pressure drop threshold, and an adjustment factor of 1 is required for adjustment, and M represents the pressure drop threshold; when E j =1, indicating that the total pressure drop of the jth segment exceeds the pressure drop threshold, and the factor X needs to be adjustedc Adjustment; ΔW j ′ represents the total pressure drop of the jth section after adjustment.

[0106] It should be noted that by accurately evaluating the wellhead pressure and formation pressure, we can fully understand the pressure drop distribution in the wellbore, optimize the foam injection strategy, improve production efficiency, prevent system risks, and ultimately achieve the best economic benefits and technical level of oil field development.

[0107] Therefore, it is necessary to calculate the wellhead pressure and determine the formation pressure by combining the pressure drop in each section of the wellbore. The formula is:

[0108] P wellhead =ρ f *g*L

[0109]

[0110] Among them, P wellhead represents the wellhead pressure, ρ f represents the foam density, g represents the acceleration of gravity, L represents the total length of the wellbore, and P total represents the formation pressure, K represents the total number of sections in the wellbore; in the above formula, P wellhead With P total Combined, the pressure drop distribution in the wellbore can be fully evaluated, taking into account both the static pressure caused by gravity and the friction pressure drop in each section of the pipe, ensuring a comprehensive understanding of the pressure situation. The final formation pressure P total It is a key parameter in the foam flooding process, which directly affects the diffusion of foam in the formation and the oil recovery efficiency.

[0111] The above formulas are all dimensionless and numerical calculations. The formula is a formula for the most recent real situation obtained by collecting a large amount of data and performing software simulation. The preset parameters in the formula are set by technicians in this field according to actual conditions.

[0112] The above embodiments may be implemented in whole or in part by software, hardware, firmware or any other combination thereof. When implemented by software, the above embodiments may be implemented in whole or in part in the form of a computer program product. Those skilled in the art may appreciate that the units and algorithm steps of each example described in conjunction with the embodiments disclosed herein may be implemented by electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are performed by hardware or software methods depends on the specific application and design constraints of the technical solution.

[0113] The units described as separate components may or may not be physically separated, and the components shown as units may or may not be physical units, and may be located in one place or distributed on multiple network units. Some or all of the units may be selected according to actual needs to achieve the purpose of the solution of this embodiment.

[0114] The above description is only a specific implementation manner of the present application, but the protection scope of the present application is not limited thereto. Any technician familiar with the technical field can easily think of changes or substitutions within the technical scope disclosed in the present application, which should be included in the protection scope of the present application.

Claims

1. A method for obtaining formation pressure in foam flooding, characterized in that: The specific steps include: Step 1: installing a distributed sensor network in a formation wellbore for collecting foam injection and production parameters, the parameters including foaming agent concentration, gas flow rate, gas volume, foaming agent relative density and gas relative density; Step 2: Calculate the foam generation rate, foam density and foam flow volume according to the collected foam injection and production parameters, and use the calculated foam generation rate, foam density and foam flow volume to comprehensively generate an adjustment factor; Step 3: constructing a pressure difference calculation model, wherein the parameters required for constructing the pressure difference calculation model include average foam density, average foam flow rate and average friction coefficient; Step 4: Determine the pressure drop in the wellbore section by section using the pressure difference calculation model, set a pressure drop threshold in each section of the wellbore, and use the adjustment factor to adjust the pressure drop in the wellbore that exceeds the pressure drop threshold; Step 5: Calculate the wellhead pressure based on the optimized pressure difference calculation model, and determine the formation pressure by combining the pressure drop in each section of the wellbore; Collect foam injection parameters, including foaming agent concentration, gas flow, gas volume, foaming agent relative density and gas relative density, based on the formula: Q g =A*v V g =Q g *Δt Among them, V t represents the total volume of the injected foaming agent, Δt represents the total injection time, C d Indicates the concentration of foaming agent, m d Indicates the mass of the foaming agent, Q g represents the gas flow rate, A represents the cross-sectional area of ​​the wellbore, v represents the gas flow rate, V g Indicates the volume of gas; The relative density of the foaming agent and the relative density of the gas are calculated using the ratio method, based on the following formula: Among them, ρ d Represents the relative density of the foaming agent, ρ solution represents the density of the foaming agent, ρ water represents the density of water, ρ g Represents the relative density of the gas, ρ gas represents the density of the gas, ρ air Indicates the density of air; The calculation formula for foam generation rate, foam density and foam flow volume is: Among them, s d represents the foam generation rate, V s represents the volume of foam generated, ρ f Indicates the foam density, h g represents the foam flow volume, P s represents standard atmospheric pressure, Z represents the compression factor, R represents the gas constant, and T represents the temperature inside the cylinder; The adjustment factor is generated comprehensively, based on the formula: Among them, X c represents the adjustment factor, and A represents the cross-sectional area of ​​the wellbore.

2. A method for obtaining formation pressure during foam flooding according to claim 1, characterized in that: The pressure difference calculation model is constructed based on the following method: The pressure difference model is constructed by calculating the average foam density, average foam flow rate and average friction coefficient to evaluate the friction pressure drop caused by foam flow in the wellbore. Sample points are collected in the wellbore, and the foam density, foam flow rate and friction coefficient of each point are calculated. The average value of the calculation results of the three parameters is taken for calculation. The formula is: Among them, ρ avg , l avg 、f avg Respectively represent the average foam density, average foam flow rate, and average friction coefficient. represents the foam density at the i-th sampling point, l i represents the foam flow rate at the ith sampling point, represents the foam generation rate at the i-th sampling point, represents the gas flow rate at the i-th sampling point, f i Represents the friction coefficient of the i-th sampling point, N represents the number of sampling points, i is the index of the sampling point, and i ranges from 1 to N; The pressure difference calculation model is constructed using the calculated average foam density, average foam flow rate and average friction coefficient. The formula is as follows: Where P represents the average friction pressure drop, L represents the total length of the wellbore, and D represents the inner diameter of the wellbore.

3. The method for obtaining formation pressure during foam flooding according to claim 1, characterized in that: The friction pressure drop of the wellbore is determined section by section using the pressure difference calculation model, based on the following method: The wellbore is divided into K sections from the wellhead to the bottom of the well, and the parameters of each section are determined. The friction pressure drop of each section is calculated using the Darcy-Waisbach equation, and the gravity pressure drop of each section is calculated. The gravity pressure drop depends on the height change of the wellbore and the angle of the wellhead. The total pressure drop of each section is equal to the sum of the friction pressure drop of each section and the gravity pressure drop of each section. The formula is: ΔG j =ρ j *g*ΔL j sin(θ j ) ΔW j =ΔP j +ΔG j Among them, ΔP j represents the friction pressure drop of the jth segment, f j represents the friction coefficient of the jth segment, ΔL j represents the length of the wellbore in the jth section, ΔD j represents the cross-sectional area of ​​the wellhead at the jth segment, ρ j represents the foam density of the jth segment, l j represents the foam flow rate of the jth segment, ΔG j represents the gravitational pressure drop of the jth segment, g represents the gravitational acceleration, θ j Represents the angle of the j-th section of the wellbore, ΔW j represents the total pressure drop of the jth segment, j∈[1,K].

4. A method for obtaining formation pressure during foam flooding according to claim 3, characterized in that: The adjustment factor is used to adjust the pressure drop in the pipe that exceeds the pressure drop threshold. The logic is as follows: ΔW j ′ =X c *ΔW j ifΔW j ≥M ΔW j ′=1*ΔW j ifΔW j <M Among them, E j Indicates the logic value for judging whether the total voltage drop of the jth segment exceeds the voltage drop threshold. j = 0, indicating that the total pressure drop of the jth segment does not exceed the pressure drop threshold, and an adjustment factor of 1 is required for adjustment, and M represents the pressure drop threshold; when E j =1, indicating that the total pressure drop of the jth segment exceeds the pressure drop threshold, and the factor X needs to be adjusted c Adjustment; ΔW j ′ represents the total pressure drop of the jth section after adjustment.

5. A method for obtaining formation pressure during foam flooding according to claim 4, characterized in that: Calculate the wellhead pressure and determine the formation pressure by combining the pressure drop in each section of the wellbore. The formula is: P wellhead =ρ f *g*L Among them, P wellhead represents the wellhead pressure, ρ f represents the foam density, g represents the acceleration of gravity, L represents the total length of the wellbore, and P total represents the formation pressure, and K represents the total number of sections in the wellbore.

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