A method for predicting the pressure of produced gas at the outlet of an oilfield with reduced pressure and increased production

Abstract

The present invention discloses a method for predicting the pressure of produced gas and liquid at the outlet of an oil field for reducing pressure and increasing production. The method comprises: collecting oil field production data and preprocessing the data; establishing a visualized flow simulation test of an oil, gas and water three-phase wellbore based on the preprocessed data, and analyzing the changing law of the flow state in the wellbore; constructing a liquid holdup calculation model for the oil, gas and water three-phase flow according to the result of the wellbore multiphase flow test; calculating the physical property parameters of CO2 at different temperatures and pressures according to the phase change of CO2 flowing along the wellbore; establishing a wellbore pressure drop prediction model based on the constructed liquid holdup calculation model and the calculated physical property parameters of CO2; inputting the real-time collected oil well production data into the established wellbore pressure drop prediction model for real-time prediction. The method of the present invention can improve the prediction accuracy of the produced gas and liquid pressure at the outlet of an oil field, more accurately grasp the changing trend of the gas-liquid pressure, and improve the safety and stability of production.

Description

Technical Field

[0001] The invention relates to the technical field of oilfield exploitation, and in particular to a method for predicting the pressure of produced gas and fluid at an oilfield outlet for reducing pressure and increasing production. Background Art

[0002] In the oilfield production process, gas-liquid pressure is a crucial parameter. It is directly related to the production efficiency of the oil well, the safe operation of the equipment and the overall economic benefits. Especially in high gas-liquid ratio oil wells using special production technology, the change of gas-liquid pressure is more complex and difficult to predict. This complexity is mainly due to the multiphase flow characteristics inside the oil well and the interaction of various factors in the production process.

[0003] In the oilfield production process, there is a significant time lag effect. That is, some data changes in the previous step will cause changes in the gas-liquid pressure in the subsequent step after a certain period of time. This lag effect increases the uncertainty and risk in the production process. For example, in the heating step, if the flow rate and temperature are too high, it may cause a sharp rise in gas-liquid pressure in the subsequent steps, causing damage to the equipment, and even leading to production interruptions or safety accidents. Therefore, how to accurately predict and control the gas-liquid pressure at the outlet of the oil well has become a technical problem that needs to be solved in the current oilfield production.

[0004] In view of the importance of predicting gas-liquid pressure during oilfield production, the present invention proposes a method for predicting the produced gas-liquid pressure at an oilfield outlet for reducing pressure and increasing production. Summary of the invention

[0005] The purpose of the present invention is to solve the problems in the prior art of insufficient prediction accuracy, difficulty in reflecting production changes in real time and failure to fully consider the time difference effect, and to propose a method for predicting the pressure of produced gas and hydraulic pressure at the outlet of an oilfield for reducing pressure and increasing production.

[0006] In order to achieve the above object, the present invention adopts the following technical scheme: a method for predicting the pressure of produced gas and hydraulic fluid at the outlet of an oil field for reducing pressure and increasing production, comprising the following steps: Step S1, collecting oilfield production data and preprocessing the data; Step S2, based on the preprocessed data, establish a visualized flow simulation test of the oil, gas and water three-phase wellbore to analyze the changing law of the flow state in the wellbore; Step S3, constructing a liquid holdup calculation model for oil, gas and water three-phase flow according to the results of the wellbore multiphase flow test; Step S4, calculating the physical property parameters of CO2 at different temperatures and pressures according to the phase change of CO2 flowing along the wellbore; Step S5, establishing a wellbore pressure drop prediction model based on the constructed liquid holdup calculation model and the calculated CO2 physical property parameters; Step S6, inputting the real-time collected oil well production data into the established wellbore pressure drop prediction model to perform real-time prediction.

[0007] Furthermore, in step S1, the following sub-steps are also included: S1-1, collecting oilfield production data through field sensors, data recording systems, and historical databases, wherein the collected oilfield production data includes flow rate, temperature, oil well depth, tubing inner diameter, casing inner diameter, oil pressure, casing pressure, flow pressure, bottom hole temperature, daily liquid production, daily oil production, water content, and daily gas production in the heating step; S1-2, preprocessing the collected data, including data cleaning, data formatting and data synchronization. The data cleaning is used to remove noise and outliers, the data formatting is used to ensure that the data format is consistent with the model input requirements, and the data synchronization is used to ensure that all relevant data are aligned at the same time point.

[0008] Furthermore, in step S2, the following sub-steps are also included: S2-1, design a visualized flow simulation test device, which includes a visualized oil pipe flow channel, a compressor, a gas storage tank, a gas flow meter, a water storage tank, a plunger pump, a liquid flow meter, a gas-liquid mixing section, and a bottom hole pressure gauge; S2-2, according to the pre-processed oil field production data, set test parameters, conduct simulation tests, and record flow phenomena and data under different parameters, wherein the test parameters include gas phase apparent velocity, liquid phase apparent velocity, and water content; S2-3, observe the flow state of the three phases of oil, gas and water in the visualized oil pipe flow channel, and analyze the changing law of the flow phenomenon under different parameters. The flow state includes the flow pattern transition and the influence of gas disturbance on the interaction between oil and water phases. The changing law includes the converted gas velocity, the converted liquid velocity and the inlet volume water content.

[0009] Furthermore, in step S3, the following sub-steps are also included: S3-1, in the wellbore multiphase flow test, the dimensionless number is introduced to transform the test low pressure to the high pressure of the actual working condition. The dimensionless number is expressed by the following formula: ; in, represents the gas phase velocity number, represents the liquid phase velocity number, and are the densities of gas and liquid respectively, is the acceleration due to gravity, is the gas-liquid interfacial tension; S3-2, based on the test data, analyze the relationship between liquid holdup and gas phase velocity coefficient, liquid phase velocity coefficient and water content; S3-3, based on the relationship obtained by analysis, the liquid holdup calculation model is modified to establish a liquid holdup prediction model suitable for oil, gas and water three-phase flow. The specific formula is: ; in, represents the liquid holdup rate, Indicates the moisture content, , , , , are the coefficients to be fitted.

[0010] Furthermore, in step S4, the following sub-steps are also included: S4-1, calculate the solubility of CO2 in crude oil by the following formula: ; in, is the solubility of CO2 in crude oil, is the density of crude oil, is the molar content of CO2, is the molar mass of crude oil, is the density of carbon dioxide; S4-2, calculate the solubility of CO2 in water by the following formula: ; in, represents the solubility of CO2 in water, is a constant, a, b, c are coefficients related to temperature T, and p represents pressure; S4-3, judging the phase of CO2 according to the critical temperature and pressure of CO2 and the temperature and pressure conditions in the wellbore, wherein the phase includes gaseous state, liquid state and supercritical state; S4-4, for CO2 in different phases, the density of CO2 is calculated using the modified PR state equation. The specific formula is: ; in, and is the coefficient related to the eccentricity factor of CO2, R is the gas constant, M is the relative molecular weight of CO2, T is the temperature, and p is the pressure; S4-5, use the CO2 viscosity calculation model established on the basis of the PR equation to calculate the viscosity of CO2. The specific formula is: ; in, , , , , It is a coefficient related to the physical parameters of CO2 and temperature and pressure.

[0011] Furthermore, in step S5, the following sub-steps are also included: S5-1, integrating the liquid holdup calculation model and CO2 physical property parameters obtained in the previous step, wherein the CO2 physical property parameters include solubility, density and viscosity; S5-2, according to the characteristics of wellbore multiphase flow, a pressure drop equation is constructed, the pressure drop equation includes gravity drop, friction drop and acceleration drop, and the specific formula is: ; in, is the rate of change of pressure drop with well depth, is the mixing velocity, d is the flow tube diameter, g is the gravitational acceleration, is the friction factor, is the density of the mixture, is the gas phase density, is the liquid density, is the liquid holdup rate.

[0012] Furthermore, in step S6, the following sub-steps are also included: S6-1, preparing input parameters according to the requirements of the wellbore pressure drop prediction model, wherein the preparation includes converting the data collected in real time into a specific format or unit required by the model; S6-2, inputting the prepared input parameters into the wellbore pressure drop prediction model, calling the model to perform real-time prediction, and calculating the real-time wellbore pressure drop value; S6-3, outputting the prediction results in different forms, including digital display, chart display, and report generation.

[0013] The beneficial effects brought about by the technical solution provided by the present invention include at least: The present invention collects oilfield production data and pre-processes the data; based on the pre-processed data, a visualized flow simulation test of an oil-gas-water three-phase wellbore is established to analyze the changing law of the flow state in the wellbore; according to the result of the wellbore multiphase flow test, a liquid holdup calculation model of the oil-gas-water three-phase flow is constructed; according to the phase change of CO2 flowing along the wellbore, the physical property parameters of CO2 at different temperatures and pressures are calculated; based on the constructed liquid holdup calculation model and the calculated physical property parameters of CO2, a wellbore pressure drop prediction model is established; and the oil well production data collected in real time is input into the established wellbore pressure drop prediction model for real-time prediction.

[0014] The method of the present invention establishes an accurate prediction model by comprehensively considering various factors in the oil well production process, which can significantly improve the prediction accuracy of the gas-liquid pressure at the oil field outlet, allowing oil field managers to more accurately grasp the changing trend of the gas-liquid pressure.

[0015] The method of the present invention can ensure the smooth operation of oil well production by predicting and controlling the gas-liquid pressure in real time. When it is predicted that the gas-liquid pressure may exceed the safe range, the production parameters can be automatically adjusted, thereby effectively avoiding production accidents and improving the safety and stability of production.

[0016] The method of the present invention can improve oil recovery efficiency while ensuring production safety by optimizing production parameters, reduce unnecessary energy consumption and emissions, reduce production costs, and improve the economic benefits of the oil field. BRIEF DESCRIPTION OF THE DRAWINGS

[0017] In order to more clearly illustrate the technical solutions and advantages in the embodiments of the present invention or the prior art, the drawings required for use in the embodiments or the prior art descriptions are briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0018] Figure 1 A flow chart of a method provided by an embodiment of the present invention. DETAILED DESCRIPTION

[0019] In order to further explain the technical means and effects adopted by the present invention to achieve the predetermined invention purpose, the following is a detailed description of the method for predicting the pressure of the produced gas and hydraulic pressure at the outlet of an oil field for reducing pressure and increasing production, its specific implementation method, structure, features and effects proposed by the present invention in conjunction with the accompanying drawings and preferred embodiments. In the following description, different "one embodiment" or "another embodiment" does not necessarily refer to the same embodiment. In addition, specific features, structures, or characteristics in one or more embodiments may be combined in any suitable form.

[0020] Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs.

[0021] The following examples are for illustrative purposes only and are not intended to limit the scope of the present invention.

[0022] The specific scheme of the method for predicting the pressure of produced gas at the outlet of an oilfield with reduced pressure and increased production provided by the present invention is described in detail below with reference to the accompanying drawings.

[0023] Example See also Figure 1, which shows a method flow chart of a method for predicting the pressure of produced gas and hydraulic fluid at the outlet of an oilfield for reducing pressure and increasing production provided by an embodiment of the present invention, the method comprising the following steps: Step S1, collecting oilfield production data and preprocessing the data; Wherein step S1 also includes the following sub-steps: S1-1, collecting oilfield production data through field sensors, data recording systems, and historical databases, wherein the collected oilfield production data includes flow rate, temperature, oil well depth, tubing inner diameter, casing inner diameter, oil pressure, casing pressure, flow pressure, bottom hole temperature, daily liquid production, daily oil production, water content, and daily gas production in the heating step; S1-2, preprocessing the collected data, including data cleaning, data formatting and data synchronization. The data cleaning is used to remove noise and outliers, the data formatting is used to ensure that the data format is consistent with the model input requirements, and the data synchronization is used to ensure that all relevant data are aligned at the same time point.

[0024] It should be noted that the field sensors are installed at key locations of oil wells to monitor the production parameters of oil wells in real time. The data recording system is used to record the production data of oil wells, including historical data and real-time data, and store them in a database. The historical database stores the past production data of oil wells, which helps to understand the production patterns and trends of oil wells.

[0025] Flow rate and temperature in the heating step: reflect the thermodynamic state of the oil well during the production process, which helps to understand the flow characteristics and pressure drop law of the oil well; well depth, tubing inner diameter, and casing inner diameter of the oil well: determine the geometric characteristics of the oil well, which helps to calculate the wellbore pressure drop and fluid flow state; oil pressure, casing pressure, and flowing pressure: reflect the pressure distribution and changes of the oil well during the production process; bottom hole temperature: an important factor affecting the physical properties and flow state of the fluid; daily liquid production, daily oil production, and water content: reflect the production capacity and fluid composition of the oil well, which helps to understand the production performance of the oil well and adjust the production strategy; daily gas production: reflects the injection amount of CO2 and the output capacity of the oil well.

[0026] Data cleaning: Noise is caused by sensor failure and data transmission errors and needs to be removed through data cleaning. Outliers are caused by measurement errors, equipment failures or extreme production conditions and will have a negative impact on the model, so they need to be removed.

[0027] Data formatting: Different models require data input in different formats. During the data preprocessing stage, the data needs to be formatted into the format required by the model, including adjustment of data type, data range, and data accuracy.

[0028] Data synchronization: Since the data comes from different sensors and recording systems, there may be temporal inconsistencies. In order to ensure the accuracy of the model, all relevant data need to be aligned at the same point in time.

[0029] Step S2: Based on the preprocessed data, a visualization flow simulation test of the oil, gas and water three-phase wellbore is established to analyze the changing law of the flow state in the wellbore; Wherein step S2 also includes the following sub-steps: S2-1, design a visualized flow simulation test device, which includes a visualized oil pipe flow channel, a compressor, a gas storage tank, a gas flow meter, a water storage tank, a plunger pump, a liquid flow meter, a gas-liquid mixing section, and a bottom hole pressure gauge; S2-2, according to the pre-processed oil field production data, set test parameters, conduct simulation tests, and record flow phenomena and data under different parameters, wherein the test parameters include gas phase apparent velocity, liquid phase apparent velocity, and water content; S2-3, observe the flow state of the three phases of oil, gas and water in the visualized oil pipe flow channel, and analyze the changing law of the flow phenomenon under different parameters. The flow state includes the flow pattern transition and the influence of gas disturbance on the interaction between oil and water phases. The changing law includes the converted gas velocity, the converted liquid velocity and the inlet volume water content.

[0030] It should be noted that the visualized oil pipe flow channel is used to simulate the flow environment in the wellbore, and the flow state of the three-phase oil, gas and water can be clearly observed; the compressor, gas tank, and gas flow meter are used to provide and control the gas phase flow to ensure that the gas phase conditions in the test are consistent with the actual situation; the water tank, plunger pump, and liquid flow meter are used to provide and control the liquid phase flow to ensure that the liquid phase conditions in the test are consistent with the actual situation; the gas-liquid mixing section is used in the gas-liquid mixing section. The gas phase and the liquid phase are mixed to form the initial conditions for the three-phase flow of oil, gas and water; the bottom hole pressure gauge is used to monitor and record the bottom hole pressure during the test to evaluate the impact of the flow state on the wellbore pressure.

[0031] Flow patterns include pure oil flow: near the bottom of the well, since the pressure in the wellbore is higher than the saturation pressure, the gas dissolves in the oil, and only the oil phase flows at this time; bubble flow: when the pressure in the wellbore is slightly lower than the saturation pressure, part of the gas separates from the oil and exists in the oil in the form of small bubbles; slug flow: as the gas volume expands and combines with each other, a flow pattern of one section of gas and one section of oil appears in the wellbore, which is called slug flow. At this time, the expansion energy of the gas is well utilized and has a great lifting force on the oil; circulation: as the oil and gas continue to rise, the gas plunger continues to lengthen and eventually breaks through the center of the oil pipe, forming a circulation with a continuous gas flow in the middle and the oil flowing in a ring along the pipe wall; mist flow: as the oil and gas continue to move upward, the gas volume continues to increase, and eventually the gas column completely occupies the entire cross-section of the oil pipe, and the oil is evenly dispersed in the gas column in the form of very small droplets, forming a mist flow.

[0032] The influence of gas disturbance on the interaction between oil and water phases: When the converted gas velocity is greater than a certain value, the gas disturbance makes the distribution of oil droplets in the mixed liquid phase tend to be consistent and the particle size becomes smaller, the effective viscosity of the oil-water mixture decreases, and the friction resistance with the tube wall decreases, thereby slowing down the rate of increase of the pressure gradient, which helps to improve the flow state of the oil-water two phases and reduce the flow resistance.

[0033] Reduced gas velocity: The increase in reduced gas velocity will lead to an increase in pressure gradient, but the growth rate will slow down. The greater the reduced gas velocity, the more obvious the phase reversal phenomenon between the oil and water phases, that is, the more significant the transition of the continuous phase from oil to water near the phase transition point.

[0034] Reduced liquid velocity: The increase in reduced liquid velocity will lead to a monotonically increasing change in the pressure gradient. Under different reduced gas velocities, the pressure gradient shows a curve change trend with the change in reduced liquid velocity. The smaller the reduced gas velocity, the smaller the effect of the reduced liquid velocity on the increase in pressure gradient.

[0035] Inlet volume water content: At high converted liquid velocity, the change trend of the pressure gradient is complex, reflecting the complexity of the three-phase flow. At higher gas velocity, the pressure gradient will show a peak characteristic. The inlet volume water content in the liquid phase corresponding to the peak value fluctuates slightly around 40%, which can be determined as the phase transition point between the oil and water phases in the three-phase flow.

[0036] Step S3, constructing a liquid holdup calculation model for oil, gas and water three-phase flow according to the results of the wellbore multiphase flow test; Wherein step S3 also includes the following sub-steps: S3-1, in the wellbore multiphase flow test, the dimensionless number is introduced to transform the test low pressure to the high pressure of the actual working condition. The dimensionless number is expressed by the following formula: ; in, represents the gas phase velocity number, represents the liquid phase velocity number, and are the densities of gas and liquid respectively, is the acceleration due to gravity, is the gas-liquid interfacial tension; S3-2, based on the test data, analyze the relationship between liquid holdup and gas phase velocity coefficient, liquid phase velocity coefficient and water content; S3-3, based on the relationship obtained by analysis, the liquid holdup calculation model is modified to establish a liquid holdup prediction model suitable for oil, gas and water three-phase flow. The specific formula is: ; in, represents the liquid holdup rate, Indicates the moisture content, , , , , are the coefficients to be fitted.

[0037] It should be noted that the dimensionless number is a quantity that describes a physical system. It is a combination of several physical quantities. The dimensions of these physical quantities cancel each other out during the combination process, thus becoming a constant pure number without units. It is a pure number without any physical units and can be compared and analyzed under different physical systems and conditions.

[0038] The relationship between liquid holdup and gas phase velocity coefficient: when the liquid phase conversion velocity is constant, the liquid holdup will decrease with the increase of the gas phase velocity coefficient; when the liquid phase conversion velocity is high, the liquid holdup decreases faster with the increase of the gas phase velocity coefficient; when the liquid phase conversion velocity is low, the liquid holdup decreases slower with the increase of the gas phase velocity coefficient.

[0039] The relationship between liquid holdup and liquid phase velocity coefficient: when the gas phase converted velocity is constant, the liquid holdup will increase with the increase of the liquid phase velocity coefficient. The increase of liquid phase velocity will cause more liquid to flow in the pipeline, thereby increasing the liquid holdup.

[0040] Relationship between liquid holdup and water content: When the water content is high or low (greater than 80% or less than 20%), the slippage rate between the oil phase and the water phase is small, and the liquid holdup is close to the water content; when the water content is in the medium range (20% to 80%), the slippage rate between the oil phase and the water phase is large, and the difference between the liquid holdup and the water content is large. As the total liquid phase flow rate increases, the liquid holdup will be closer to the water content.

[0041] Step S4, calculating the physical property parameters of CO2 at different temperatures and pressures according to the phase change of CO2 flowing along the wellbore; Wherein step S4 also includes the following sub-steps: S4-1, calculate the solubility of CO2 in crude oil by the following formula: ; in, is the solubility of CO2 in crude oil, is the density of crude oil, is the molar content of CO2, is the molar mass of crude oil, is the density of carbon dioxide; S4-2, calculate the solubility of CO2 in water by the following formula: ; in, represents the solubility of CO2 in water, is a constant, a, b, c are coefficients related to temperature T, and p represents pressure; S4-3, judging the phase of CO2 according to the critical temperature and pressure of CO2 and the temperature and pressure conditions in the wellbore, wherein the phase includes gaseous state, liquid state and supercritical state; S4-4, for CO2 in different phases, the density of CO2 is calculated using the modified PR state equation. The specific formula is: ; in, and is the coefficient related to the eccentricity factor of CO2, R is the gas constant, M is the relative molecular weight of CO2, T is the temperature, and p is the pressure; S4-5, use the CO2 viscosity calculation model established on the basis of the PR equation to calculate the viscosity of CO2. The specific formula is: ; in, , , , , It is a coefficient related to the physical parameters of CO2 and temperature and pressure.

[0042] It should be noted that solubility refers to the maximum amount of solute (CO2) that can be dissolved in solvent (water or crude oil). For CO2, its solubility in water and crude oil will be affected by temperature, pressure and solvent properties.

[0043] Density refers to the mass of a substance per unit volume. For CO2, its density will change with changes in temperature, pressure and phase. Under different temperature and pressure conditions, CO2 may exist in gas, liquid or supercritical state. The density in each phase is different. Changes in density will affect the flow behavior and storage efficiency of CO2.

[0044] Viscosity is a physical quantity that measures the resistance to fluid flow and reflects the interaction force between molecules within the fluid. For CO2, viscosity is affected by temperature, pressure and phase state. During oil and gas production, changes in CO2 viscosity will affect its flow rate and permeability in porous media, thereby affecting storage and production efficiency.

[0045] The unit is , The unit is , The unit is The unit of is, The unit is , the unit of p is MPa, and the unit of T is K.

[0046] K, a, b, and c in the formula are coefficients related to temperature T, which are obtained by fitting experimental data. The solubility is affected by both temperature and pressure. The actual temperature and pressure conditions in the wellbore need to be considered during calculation.

[0047] The critical temperature and pressure of CO2 are fixed (31.1°C and 7.38 MPa, respectively), while the temperature and pressure conditions in the wellbore may vary with depth. The phase of CO2 needs to be judged based on the actual conditions of the wellbore. CO2 in different phases has different physical properties.

[0048] The PR state equation is a commonly used state equation used to describe the behavior of real gases. The deformed PR state equation is improved for a specific gas (CO2).

[0049] Step S5: establishing a wellbore pressure drop prediction model based on the constructed liquid holdup calculation model and the calculated CO2 physical property parameters; Wherein, in step S5, the following sub-steps are also included: S5-1, integrating the liquid holdup calculation model and CO2 physical property parameters obtained in the previous step, wherein the CO2 physical property parameters include solubility, density and viscosity; S5-2, according to the characteristics of wellbore multiphase flow, a pressure drop equation is constructed, the pressure drop equation includes gravity drop, friction drop and acceleration drop, and the specific formula is: ; in, is the rate of change of pressure drop with well depth, is the mixing velocity, d is the flow tube diameter, g is the gravitational acceleration, is the friction factor, is the density of the mixture, is the gas phase density, is the liquid density, is the liquid holdup rate.

[0050] It should be noted that the liquid holdup calculation model is used to predict the proportion of liquid in the wellbore under given conditions; the solubility of CO2 determines the content of CO2 in the liquid, and the density and viscosity of CO2 affect the flow characteristics of CO2.

[0051] Characteristics of multiphase flow in a wellbore: In a wellbore, the fluid is usually not a single phase, but a mixture of gas and liquid. The interaction and mutual conversion between these phases make the flow in the wellbore very complicated.

[0052] Gravity drop: The pressure drop caused by the gravity of the fluid in the wellbore, which is related to the density of the fluid and the height of the wellbore; Friction drop: The pressure drop caused by the friction between the fluid and the wellbore wall or the inside of the fluid during the flow process, which is related to the flow rate, density, viscosity of the fluid and the roughness of the wellbore; Acceleration drop: The pressure drop caused by the change in fluid velocity during the flow process, which is related to the acceleration and density of the fluid.

[0053] Step S6, inputting the real-time collected oil well production data into the established wellbore pressure drop prediction model to perform real-time prediction; Wherein, in step S6, the following sub-steps are also included: S6-1, preparing input parameters according to the requirements of the wellbore pressure drop prediction model, wherein the preparation includes converting the data collected in real time into a specific format or unit required by the model; S6-2, inputting the prepared input parameters into the wellbore pressure drop prediction model, calling the model to perform real-time prediction, and calculating the real-time wellbore pressure drop value; S6-3, outputting the prediction results in different forms, including digital display, chart display, and report generation.

[0054] It should be noted that the data collected in real time is converted into the specific format or unit required by the model: the data collected in real time comes from different sensors and devices and has different formats and units. In order to input the data into the wellbore pressure drop prediction model, it is necessary to convert it into the specific format or unit required by the model.

[0055] Digital display: The forecast results can be directly displayed to operators or engineers in digital form, so that they can quickly understand the wellbore pressure drop; Graphic display: Displaying the forecast results through line charts, bar charts or scatter charts can help operators understand the changing trends and patterns of the data more intuitively; Report generation: Generate a report containing the forecast results for reference by management or relevant departments. The report can include detailed data analysis, forecast results and possible suggestions or action plans.

[0056] In this way, a method for predicting the pressure of produced gas at the outlet of an oilfield with reduced pressure and increased production can achieve real-time prediction of the pressure of produced gas at the outlet of the oilfield, providing strong technical support for the operation of reducing pressure and increasing production in the oilfield.

[0057] The embodiments described above are only used to illustrate the technical solutions of the present application, rather than to limit them. Although the present application has been described in detail with reference to the aforementioned embodiments, a person skilled in the art should understand that the technical solutions described in the aforementioned embodiments may still be modified, or some of the technical features may be replaced by equivalents. Such modifications or replacements do not deviate the essence of the corresponding technical solutions from the spirit and scope of the technical solutions of the embodiments of the present application, and should all be included in the protection scope of the present application.

Claims

1. A method for predicting the pressure of produced gas at the outlet of an oilfield for reducing pressure and increasing production, characterized in that: The method includes: Step S1, collecting oilfield production data and preprocessing the data; Step S2, based on the preprocessed data, establish a visualized flow simulation test of the oil, gas and water three-phase wellbore to analyze the changing law of the flow state in the wellbore; Step S3, constructing a liquid holdup calculation model for oil, gas and water three-phase flow according to the results of the wellbore multiphase flow test; Step S4, calculating the physical property parameters of CO2 at different temperatures and pressures according to the phase change of CO2 flowing along the wellbore; Step S5, establishing a wellbore pressure drop prediction model based on the constructed liquid holdup calculation model and the calculated CO2 physical property parameters; Step S6, inputting the real-time collected oil well production data into the established wellbore pressure drop prediction model to perform real-time prediction.

2. The method for predicting the pressure of produced gas at the outlet of an oilfield for reducing pressure and increasing production as claimed in claim 1, characterized in that: Wherein step S1 also includes the following sub-steps: S1-1, collecting oilfield production data through field sensors, data recording systems, and historical databases, wherein the collected oilfield production data includes flow rate, temperature, oil well depth, tubing inner diameter, casing inner diameter, oil pressure, casing pressure, flow pressure, bottom hole temperature, daily liquid production, daily oil production, water content, and daily gas production in the heating step; S1-2, preprocessing the collected data, including data cleaning, data formatting and data synchronization. The data cleaning is used to remove noise and outliers, the data formatting is used to ensure that the data format is consistent with the model input requirements, and the data synchronization is used to ensure that all relevant data are aligned at the same time point.

3. The method for predicting the pressure of produced gas at the outlet of an oilfield for reducing pressure and increasing production as claimed in claim 1, characterized in that: Wherein, in step S2, the following sub-steps are also included: S2-1, design a visualized flow simulation test device, which includes a visualized oil pipe flow channel, a compressor, a gas storage tank, a gas flow meter, a water storage tank, a plunger pump, a liquid flow meter, a gas-liquid mixing section, and a bottom hole pressure gauge; S2-2, according to the pre-processed oil field production data, set test parameters, conduct simulation tests, and record flow phenomena and data under different parameters, wherein the test parameters include gas phase apparent velocity, liquid phase apparent velocity, and water content; S2-3, observe the flow state of the three phases of oil, gas and water in the visualized oil pipe flow channel, and analyze the changing law of the flow phenomenon under different parameters. The flow state includes the flow pattern transition and the influence of gas disturbance on the interaction between oil and water phases. The changing law includes the converted gas velocity, the converted liquid velocity and the inlet volume water content.

4. The method for predicting the pressure of produced gas at the outlet of an oilfield for reducing pressure and increasing production as claimed in claim 1, characterized in that: Wherein step S3 also includes the following sub-steps: S3-1, in the wellbore multiphase flow test, the dimensionless number is introduced to transform the test low pressure to the high pressure of the actual working condition. The dimensionless number is expressed by the following formula: ； in, represents the gas phase velocity number, represents the liquid phase velocity number, and are the densities of gas and liquid respectively, is the acceleration due to gravity, is the gas-liquid interfacial tension; S3-2, based on the test data, analyze the relationship between liquid holdup and gas phase velocity coefficient, liquid phase velocity coefficient and water content; S3-3, based on the relationship obtained by analysis, the liquid holdup calculation model is modified to establish a liquid holdup prediction model suitable for oil, gas and water three-phase flow. The specific formula is: ； in, represents the liquid holdup rate, Indicates the moisture content, , , , , are the coefficients to be fitted.

5. The method for predicting the pressure of produced gas at the outlet of an oilfield for reducing pressure and increasing production as claimed in claim 1, characterized in that: Wherein step S4 also includes the following sub-steps: S4-1, calculate the solubility of CO2 in crude oil by the following formula: ； in, is the solubility of CO2 in crude oil, is the density of crude oil, is the molar content of CO2, is the molar mass of crude oil, is the density of carbon dioxide; S4-2, calculate the solubility of CO2 in water by the following formula: ； in, represents the solubility of CO2 in water, is a constant, a, b, c are coefficients related to temperature T, and p represents pressure; S4-3, judging the phase of CO2 according to the critical temperature and pressure of CO2 and the temperature and pressure conditions in the wellbore, wherein the phase includes gaseous state, liquid state and supercritical state; S4-4, for CO2 in different phases, the density of CO2 is calculated using the modified PR state equation. The specific formula is: ； in, and is the coefficient related to the eccentricity factor of CO2, R is the gas constant, M is the relative molecular weight of CO2, T is the temperature, and p is the pressure; S4-5, use the CO2 viscosity calculation model established on the basis of the PR equation to calculate the viscosity of CO2. The specific formula is: ； in, , , , , It is a coefficient related to the physical parameters of CO2 and temperature and pressure.

6. The method for predicting the pressure of produced gas at the outlet of an oilfield for reducing pressure and increasing production as claimed in claim 1, characterized in that: Wherein, in step S5, the following sub-steps are also included: S5-1, integrating the liquid holdup calculation model and CO2 physical property parameters obtained in the previous step, wherein the CO2 physical property parameters include solubility, density and viscosity; S5-2, according to the characteristics of wellbore multiphase flow, a pressure drop equation is constructed, the pressure drop equation includes gravity drop, friction drop and acceleration drop, and the specific formula is: ； in, is the rate of change of pressure drop with well depth, is the mixing velocity, d is the flow tube diameter, g is the gravitational acceleration, is the friction factor, is the density of the mixture, is the gas phase density, is the liquid density, is the liquid holdup rate.

7. The method for predicting the pressure of produced gas at the outlet of an oilfield for reducing pressure and increasing production as claimed in claim 1, characterized in that: Wherein, in step S6, the following sub-steps are also included: S6-1, preparing input parameters according to the requirements of the wellbore pressure drop prediction model, wherein the preparation includes converting the data collected in real time into a specific format or unit required by the model; S6-2, inputting the prepared input parameters into the wellbore pressure drop prediction model, calling the model to perform real-time prediction, and calculating the real-time wellbore pressure drop value; S6-3, outputting the prediction results in different forms, including digital display, chart display, and report generation.

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