Plunger gas lift well hydrops measuring and calculating method based on wellhead production data

Abstract

The invention discloses a plunger gas lift well liquid accumulation measuring and calculating method based on wellhead production data, and aims to solve the problem of plunger well annulus liquid accumulation height measurement and calculation, so that the required data is less and the data is simple to obtain in the measurement and calculation, a unique corresponding value is measured and calculated for the plunger well annulus liquid accumulation height, and finally, the plunger gas lift well liquid accumulation amount is quantitatively measured and calculated. The method comprises the steps of obtaining to-be-processed data of a target gas well, calling a well shut-in stage liquid accumulation height model to obtain a liquid level state at the end of well shut-in, calling a well opening stage liquid accumulation height model to obtain a liquid level state at the beginning of well opening, and obtaining the liquid level state at the end of well opening. The method comprises the steps of calling a shaft total liquid accumulation amount change model to obtain the relation of the shaft total liquid accumulation amount between a well closing stage and a well opening stage, calling a comprehensive dynamic liquid level model, inputting to-be-processed data into the comprehensive dynamic liquid level model to obtain the annulus liquid accumulation amount, the shaft liquid accumulation amount and the single-cycle plunger liquid drainage amount, and therefore quantitative measurement and calculation are conducted on the plunger well annulus liquid accumulation amount.

Description

Technical Field

[0001] This invention relates to the field of natural gas extraction technology, and in particular to a method for calculating liquid accumulation in plunger gas lift wells based on wellhead production data. Background Technology

[0002] As gas wells continue to be produced and developed, the formation energy of the gas well will continue to decline, resulting in insufficient gas production. This makes it impossible to promptly drain the liquid from the wellbore, leading to liquid accumulation in the wellbore and causing a decrease in production or even shutdown. In the middle and later stages of gas well development, plunger lift is commonly used for drainage and gas production. Plunger lift is a special form of intermittent gas lift. It uses a plunger that moves up and down within the entire tubing string in a circulating manner to reduce gas cross-flow and liquid fallback, thereby improving gas lift efficiency. The plunger acts as a solid sealing interface, separating the lifted gas and the lifted liquid. By establishing a suitable production regime, the lower gas pressure pushes the accumulated liquid on the plunger to the wellhead. Therefore, accurately calculating the amount of liquid accumulated in the wellbore is crucial for optimizing the plunger lift process.

[0003] Currently, there is very little research on methods for determining wellbore fluid accumulation in plunger gas lift wells. Plunger lift is a special form of intermittent gas lift, which involves increasing the gas volume at the bottom of the well during shut-in, and then opening the well to allow the gas pressure to push up the plunger and drive the accumulated fluid above the plunger out of the wellhead. The plunger then falls back to the bottom of the well, and this process repeats. Therefore, field engineers often judge the increase or decrease of wellbore fluid accumulation by observing the change in the oil-casing pressure difference during multiple plunger cycles, but they cannot accurately quantify the amount of fluid accumulated in the tubing and annulus. In addition, field engineers usually set different production regimes with different well opening and closing times, allowing each regime to operate for a period of time, and then roughly obtain the amount of fluid accumulated in the plunger well by observing the production effect and drainage volume. The advantage of this method is its simplicity, but the disadvantages are that it is time-consuming and can easily damage the gas well if the production regime is not set properly. The published article "Establishment and Solution of Plunger Gas Lift Model Equations" solves all the motion parameters of the plunger by establishing plunger gas lift model equations, and can roughly calculate the amount of fluid accumulated by observing the motion state of the plunger, but this is not mentioned in the article. A method for determining the amount of fluid accumulated in a plunger wellbore is disclosed in an invention patent (patent publication number CN114996662B). This method primarily calculates the fluid height in the annulus between the tubing and casing, and then combines this with the amount of fluid accumulated during shut-in to determine the amount of fluid exiting the wellbore. However, this method, which calculates three unknowns only from the critical shut-in moment, leads to multiple corresponding values ​​for the annulus fluid height, causing the calculated amount of fluid in the wellbore to deviate from the actual situation. Summary of the Invention

[0004] To address the aforementioned technical problems, this invention provides a method for calculating fluid accumulation in plunger gas lift wells based on wellhead production data. This method solves the problems of existing methods for calculating the annular fluid accumulation height in plunger wells, which have multiple corresponding values, and the fact that existing methods require a large amount of data to calculate fluid accumulation in plunger gas lift wells, making the calculation complex and inaccurate.

[0005] To solve the above problems, the present invention adopts the following technical solution:

[0006] A method for calculating liquid accumulation in plunger gas lift wells based on wellhead production data includes the following steps:

[0007] S1, Obtain the data to be processed from the target gas well. The data to be processed includes wellbore structure data, wellhead oil pressure and casing pressure within a unit cycle of plunger movement, where the unit cycle is the plunger's upward and downward movement cycle during well opening and shut-in.

[0008] S2, call the well shut-in stage liquid height model, input the processed data into the well shut-in stage liquid height model to obtain the liquid level status at the end of well shut-in;

[0009] S3, call the well opening stage liquid height model, input the processed data into the well opening stage liquid height model to obtain the liquid level status at the beginning of well opening;

[0010] S4, call the total wellbore fluid volume change model, input the processed data into the total wellbore fluid volume change model to obtain the relationship between the total wellbore fluid volume between the shut-in and open stages;

[0011] S5, call the integrated dynamic liquid level model, input the data to be processed into the integrated dynamic liquid level model to obtain the annular liquid accumulation, wellbore liquid accumulation and single-cycle plunger discharge volume, thereby quantitatively calculating the annular liquid accumulation in the plunger well. The integrated dynamic liquid level model is constructed by combining three models: the liquid accumulation height model during the shut-in stage, the liquid accumulation height model during the well opening stage, and the wellbore total liquid accumulation change model.

[0012] Furthermore, the fluid height model during the shut-in stage is constructed based on the relationship between the annular fluid height and the tubing fluid height at the last moment of the shut-in stage. It includes a shut-in tubing pressure converted to bottom hole pressure model, a shut-in casing pressure converted to bottom hole pressure model, and a model showing the equality of shut-in tubing and shut-in casing pressures.

[0013] Furthermore, the well opening stage fluid accumulation height model is constructed based on the relationship between the annular fluid accumulation height and the tubing fluid accumulation height at the initial moment of wellhead follow-through during the well opening stage. It includes a well opening tubing pressure converted to bottom hole pressure model, a well opening casing pressure converted to bottom hole pressure model, and a model showing the equality of well opening tubing and well opening casing pressures.

[0014] Furthermore, the total wellbore fluid volume change model is constructed based on the change in total wellbore fluid volume at the last moment of the shut-in stage and the initial moment of wellhead follow-through during the opening stage. It includes the wellhead stage fluid volume model, the shut-in stage fluid volume model, the wellhead plunger discharge volume model, and the total wellbore fluid volume change model.

[0015] Furthermore, the specific calculation formula for the shut-in tubing pressure converted to bottom hole pressure model is as follows:

[0016]

[0017] The specific calculation formula for the well shut-in casing pressure converted to bottom hole pressure model is as follows:

[0018]

[0019] The specific calculation formula for the model of the pressure equality between the shut-in tubing and the shut-in casing is as follows:

[0020] p wf_t_shut =p wf_c_shut ;

[0021] Where, p wf_t_shut The bottom hole pressure is calculated from the tubing pressure at the final moment of the shut-in phase; p wf_c_shut The casing pressure converted to bottom hole pressure at the final moment of the shut-in phase; p t_shut p represents the tubing pressure at the final moment of the well shut-in phase. c_shut The casing pressure at the final moment of the shut-in phase; γ g The relative density of natural gas is given; methane is taken as 0.56; L t This refers to the depth of the tubing. The system average temperature is given in K. h is the system average deviation factor. l_t_shut The height of fluid buildup in the tubing during the shut-in phase; h l_c_shut ρ represents the annular fluid accumulation height during the shut-in phase. w Let g be the density of the liquid; g is the acceleration due to gravity, taken as 9.8 m / s². 2 .

[0022] Furthermore, the specific calculation formula for the wellbore pressure-to-bottom hole pressure conversion model is as follows:

[0023]

[0024] The specific calculation formula for the wellbore casing pressure to bottom hole pressure conversion model is as follows:

[0025]

[0026] The specific calculation formula for the pressure equality model between the well-opening tubing and the well-opening casing is as follows:

[0027] p wf_t_open =p wf_c_open ;

[0028] Where, p wf_t_open The bottom hole pressure is calculated from the tubing pressure at the initial moment of wellhead follow-through during the well opening phase; p wf_c_open The bottom hole pressure is calculated from the casing pressure at the initial moment of wellhead follow-through during the well opening phase; p t_open p represents the tubing pressure at the initial moment of wellhead follow-through during the well opening phase. c_open h is the casing pressure at the initial moment of wellhead follow-through during the well opening phase; l_t_open h is the height of fluid buildup in the tubing during the well opening phase. l_c_open This refers to the height of fluid accumulation in the annulus during the well opening phase.

[0029] Furthermore, the specific calculation formula for the fluid accumulation model during the well opening stage is as follows:

[0030] V w_open =h l_t_open A t +h l_c_open (A c -A t ), where A t Let A be the cross-sectional area of ​​the oil pipe. c h is the cross-sectional area of ​​the casing. l_t_open and h l_c_open These are the fluid levels in the tubing and casing, respectively.

[0031] The specific calculation formula for the fluid accumulation model during the well shut-in stage is as follows:

[0032] V w_shut =h l_t_shut A t +h l_c_shut (A c -A t ), where h l_t_shut and h l_c_shut These are the fluid levels in the tubing and casing, respectively.

[0033] The specific calculation formula for the wellhead plunger fluid discharge volume model is as follows:

[0034] V w_load =[h l_t_shut -(L t -L p A t Where Lp is the depth of the plunger retainer and Lt is the depth of the tubing;

[0035] The specific calculation formula for the model of total fluid volume change in the wellbore is as follows:

[0036] V w_shut =V w_open +Vw_load .

[0037] Furthermore, the unit cycle refers to one cycle of plunger upward and downward movement during well opening and shut-in, including six states: ① gas rising above the plunger during the well opening stage, producing gas at the wellhead; ② liquid column rising above the plunger during the well opening stage, producing water at the wellhead; ③ liquid discharge from the plunger at the wellhead during the well opening stage; ④ plunger descending in the gas column during the well shut-in stage; ⑤ plunger descending in the liquid column during the well shut-in stage; ⑥ plunger settling into the locking device.

[0038] This invention extracts the plunger movement state at key moments of plunger movement, namely the last moment of the shut-in phase and the initial moment of wellhead follow-through in the open phase, thereby calculating the amount of liquid accumulation. This reduces the amount of data required for the calculation, simplifies data acquisition, and provides a unique corresponding value for the liquid accumulation height in the annulus of the plunger well. Ultimately, it quantitatively calculates the amount of liquid accumulation in the plunger gas lift well, providing a reliable basis for the subsequent formulation of plunger production systems. Attached Figure Description

[0039] Figure 1 This is a flowchart of a method for calculating the liquid accumulation in a plunger gas lift well based on wellhead production data, as proposed in this application.

[0040] Figure 2 A schematic diagram of a single operating cycle of a plunger in a plunger-driven gas lift well, which is proposed in this application, for calculating the liquid accumulation in a plunger-driven gas lift well based on wellhead production data.

[0041] Figure 3 A schematic diagram of the plunger motion state at the final moment of the shut-in stage of a plunger gas lift well liquid accumulation calculation method based on wellhead production data proposed in this application.

[0042] Figure 4 This application proposes a method for calculating liquid accumulation in a plunger gas lift well based on wellhead production data. The diagram illustrates the plunger motion state at the initial moment of wellhead follow-through during the well opening stage. Detailed Implementation

[0043] The technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this application, and not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the scope of protection of this application.

[0044] like Figure 1 As shown, this application discloses a method for calculating the liquid accumulation in a plunger gas lift well based on wellhead production data, including the following steps:

[0045] Step S1: Obtain the data to be processed from the target gas well. The data to be processed includes wellbore structure data, wellhead oil pressure and casing pressure within a unit cycle of plunger movement, where the unit cycle is the plunger's upward and downward movement cycle during well opening and shut-in.

[0046] Specifically, this step involves acquiring wellhead oil pressure and casing pressure data in real time through sensors, instruments, and a control system, and collecting this data within a complete plunger movement cycle. Simultaneously, it ensures the acquisition of relevant wellbore structure parameters for subsequent model calculations. This data serves as input for model building and quantitative calculation of fluid accumulation in plunger gas lift wells. The wellbore structure parameters are crucial data describing the well's internal structure and shape, including well depth, well diameter, tubing and casing diameters, and plunger locking device depth. Changes in wellhead oil pressure and casing pressure reflect the dynamics of fluid flow during the plunger's upward and downward movement. This data is used to build various models, helping to predict fluid accumulation height and plunger discharge volume. It is important to emphasize that a unit cycle refers to a complete cycle of the plunger's upward and downward movement. Within this cycle, the plunger rises from the bottom of the well to the wellhead and then descends from the wellhead back to the bottom, encompassing the entire upward and downward movement of the plunger. Figure 2 The diagram illustrates a single operating cycle of the plunger in a plunger gas lift well. A single complete operating cycle of the plunger's upward and downward movements during well opening and shut-in is subdivided into six states: ① Well opening stage: gas rises above the plunger, producing gas at the wellhead; ② Well opening stage: liquid column rises above the plunger, producing water at the wellhead; ③ Well opening stage: liquid discharges from the plunger to the wellhead for follow-through; ④ Well shut-in stage: the plunger descends within the gas column; ⑤ Well shut-in stage: the plunger descends within the liquid column; ⑥ Plunger placement in the locking device. The cycle defines the basic unit of the plunger gas lift process, ensuring sufficient data is collected within a complete cycle to provide comprehensive motion characteristics.

[0047] Step S2: Call the well shut-in stage liquid height model and input the processed data into the well shut-in stage liquid height model to obtain the liquid level status at the end of well shut-in.

[0048] This step involves calculating the fluid levels in the tubing and casing based on pressure data and relevant parameters at the end of the well shut-in phase, thus obtaining the fluid level status at the end of the shut-in. This data will become one of the inputs to the integrated dynamic fluid level model in subsequent steps, used for further calculations and analysis.

[0049] Specifically, the model for the relationship between annular fluid accumulation and tubing fluid accumulation at the final moment of well shut-in is constructed using three models: a tubing pressure-to-bottom-hole pressure conversion model, a casing pressure-to-bottom-hole pressure conversion model, and a model establishing the equality of tubing and casing pressures. For example... Figure 3As shown, this represents the plunger movement state at the final moment of the shut-in phase. The tubing pressure-to-bottom-hole pressure model describes the equivalent pressure at the bottom of the tubing, considering gas characteristics, well depth, fluid level, system average temperature, and a conversion factor. Therefore, the equivalent pressure at the bottom of the tubing is a comprehensive reflection of the gas and fluid states within the tubing. Similarly, the casing pressure-to-bottom-hole pressure model describes the equivalent pressure at the bottom of the casing, also considering gas characteristics, well depth, fluid level, system average temperature, and a conversion factor. Therefore, the equivalent pressure at the bottom of the casing reflects the comprehensive gas and fluid states within the casing. Furthermore, the tubing and casing pressure equality model indicates that at the shut-in moment, the equivalent pressures at the bottom of the tubing and casing are equal. This is because the tubing and casing are connected, allowing free exchange of fluid between them, thus revealing the relationship between the annular fluid accumulation height and the tubing fluid accumulation height.

[0050] The specific calculation formula for the shut-in tubing pressure converted to bottom hole pressure model is as follows:

[0051]

[0052] The specific calculation formula for the shut-in casing pressure converted to bottom hole pressure model is as follows:

[0053]

[0054] The specific calculation formula for the relationship between the pressure in the shut-in tubing and the shut-in casing is as follows:

[0055] p wf_t_shut =p wf_c_shut ;

[0056] Where, p wf_t_shut The bottom hole pressure is calculated from the tubing pressure at the final moment of the shut-in phase; p wf_c_shut The casing pressure converted to bottom hole pressure at the final moment of the shut-in phase; p t_shut p represents the tubing pressure at the final moment of the well shut-in phase. c_shut The casing pressure at the final moment of the shut-in phase; γ g The relative density of natural gas is given; methane is taken as 0.56; L t This refers to the depth of the tubing. The system average temperature is given in K. h is the system average deviation factor. l_t_shut The height of fluid buildup in the tubing during the shut-in phase; h l_c_shut ρ represents the annular fluid accumulation height during the shut-in phase. w Let g be the density of the liquid; g is the acceleration due to gravity, taken as 9.8 m / s². 2 .

[0057] By analyzing the oil pressure and casing pressure data at the final moment of well shut-in, the actual pressure data at the bottom of the tubing and casing at the shut-in point were obtained. A model for the equivalent pressure at the bottom of the tubing and casing was established. By calling the fluid height model during the shut-in phase, the actual data were converted into equivalent bottom-hole pressures. It was emphasized that at the shut-in point, the equivalent pressures at the bottom of the tubing and casing are equal due to the connectivity between the tubing and casing, thus allowing for the determination of fluid level changes. In summary, by integrating these three model formulas, especially the model for the equal pressure relationship between the tubing and casing, the relationship between the annular fluid height and the tubing fluid height can be obtained by inputting the data to be processed.

[0058] Step S3: Call the well opening stage liquid accumulation height model and input the processed data into the well opening stage liquid accumulation height model to obtain the liquid level status at the beginning of well opening;

[0059] The fluid level model constructed during the well opening phase refers to establishing the relationship between the annular fluid accumulation height and the tubing fluid accumulation height at the initial moment of wellhead follow-through. In this step, by establishing tubing and casing pressure models for the well opening phase, these pressure data are correlated with the fluid level data. This correlation considers the pressure system state at the initial moment of well opening, providing a more accurate and comprehensive basis for fluid level calculation. Because it incorporates pressure system data from the initial moment of well opening, this model can more accurately determine the fluid level and avoid multiple possible solutions. Specifically, this includes models for converting well opening tubing pressure to bottom hole pressure, models for converting well opening casing pressure to bottom hole pressure, and models for the equality of well opening tubing and casing pressures. Figure 4 As shown, the plunger motion state at the initial wellhead flow stage during well opening is illustrated. The equivalent pressure models at the bottom of the tubing and casing describe the pressure states at the bottom of the tubing and casing at the well opening time, respectively, considering gas characteristics, well depth, fluid level, system average temperature, and conversion factors, reflecting the comprehensive state of gas and fluid within the tubing. Simultaneously, the tubing and casing pressure equality model indicates that the equivalent pressures at the bottom of the tubing and casing are equal at the well opening time because they are connected, allowing free fluid exchange, thus obtaining the relationship between the annular fluid accumulation height and the tubing fluid accumulation height. The combined construction of these three models forms the fluid level model for the well opening stage, helping to understand the changes in the fluid state at the well opening time in plunger gas lift wells.

[0060] Specifically, the calculation formula for the wellbore pressure converted to bottom hole pressure using the well tubing pressure model is as follows:

[0061]

[0062] The specific calculation formula for the wellbore pressure conversion model is as follows:

[0063]

[0064] The specific calculation formula for the pressure equality model between the well tubing and the well casing during well opening is as follows:

[0065] p wf_t_open =p wf_c_open ;

[0066] Where, p wf_t_open The bottom hole pressure is calculated from the tubing pressure at the initial moment of wellhead follow-through during the well opening phase; p wf_c_open The bottom hole pressure is calculated from the casing pressure at the initial moment of wellhead follow-through during the well opening phase; p t_open p represents the tubing pressure at the initial moment of wellhead follow-through during the well opening phase. c_open h is the casing pressure at the initial moment of wellhead follow-through during the well opening phase; l_t_open h is the height of fluid buildup in the tubing during the well opening phase. l_c_open This refers to the height of fluid accumulation in the annulus during the well opening phase.

[0067] By analyzing the oil pressure and casing pressure data at the initial wellhead flow start-up, the actual pressure data at the bottom of the tubing and casing at the wellhead were obtained. A model for the converted pressure at the bottom of the tubing and casing was established, transforming the actual data into converted bottomhole pressures. It was emphasized that at the wellhead start-up, the converted pressures at the bottom of the tubing and casing are equal due to the connectivity between the tubing and casing. Therefore, the relationship of fluid level changes can be obtained. In summary, by combining these three model formulas and inputting the data to be processed, the relationship between the annular fluid accumulation height and the tubing fluid accumulation height can be obtained. This series of model descriptions helps to comprehensively understand the evolution of the fluid state in plunger gas lift wells at the wellhead start-up, providing an important basis for precise fluid level control and optimized production strategies.

[0068] It's important to note that during well opening, the liquid level model formula primarily describes the process of initiating gas injection. The key objective at this stage is to initiate gas injection and improve production capacity and efficiency. Therefore, the well opening model focuses on gas injection initiation and liquid level rise control. Conversely, during well shut-in, the liquid level model formula primarily describes the well shut-in operation. The key objective here is to control liquid discharge, prevent liquid backflow to the bottom of the well, and ensure effective well shut-in. Thus, both the well opening and shut-in models involve the same physical process: the flow of gas and liquid in the wellbore. However, their actual application contexts and objectives are completely different, necessitating separate modeling. Therefore, the model is viewed as a general description adaptable to different operational needs, while specific parameters and application contexts determine their practical significance at different stages. This design makes the model more versatile and capable of serving the needs of plunger gas lift wells under different operational conditions.

[0069] Step S4: Construct a model for the change in total wellbore fluid volume. Input the processed data into the model to obtain the relationship between the total wellbore fluid volume during the shut-in and open stages.

[0070] This step describes the change in total wellbore fluid volume between the shut-in and open phases. In this model, we will use the previously established level and pressure models, along with data from both the shut-in and open-out phases, as inputs to calculate the change in total wellbore fluid volume.

[0071] The purpose of constructing a model for the change in total wellbore fluid volume at the final moment of the shut-in phase and the initial moment of wellhead follow-through during the well opening phase is to quantitatively describe the fluid level changes in plunger gas lift wells at different stages, particularly the changes in fluid discharge and accumulation during shut-in operations. Therefore, the model is based on the physical processes of plunger gas lift wells, considering the rise and fall of fluid in the tubing and casing, as well as the plunger discharge process. Specifically, during well opening, the fluid rises, causing changes in the tubing and casing fluid levels. Therefore, the fluid volume during the well opening phase is related to the fluid level changes. During well shut-in, the fluid falls, causing changes in the tubing and casing fluid levels. Simultaneously, during the shut-in process, the plunger moves upward, resulting in fluid discharge. Therefore, the fluid volume during the shut-in phase is related to both fluid level changes and plunger discharge. The model integrates the fluid level changes and the impact of plunger discharge during both the well opening and shut-in phases, comprehensively describing the change in total wellbore fluid volume by considering factors such as fluid rise, fall, and discharge.

[0072] Specifically, the wellbore total fluid volume variation model is constructed from four models: the well opening stage fluid volume model, the well shut-in stage fluid volume model, the wellhead plunger discharge volume model, and the wellbore total fluid volume variation model. The well opening stage fluid volume model considers the fluid level changes at the bottom of the tubing and inside the casing during the well opening stage, and the fluid volume is obtained by multiplying the fluid level by the corresponding cross-sectional area. The well shut-in stage fluid volume model considers the drop in fluid within the wellbore during the shut-in stage, including fluid level changes in the tubing and casing, and the fluid volume is obtained by multiplying the fluid level by the corresponding cross-sectional area. The wellhead plunger discharge volume model describes the amount of fluid discharged by the wellhead plunger when it rapidly reaches the wellhead after well opening, considering the influence of fluid level changes and plunger discharge depth. The wellbore total fluid volume variation model integrates the well opening stage fluid volume and the wellhead plunger discharge volume, indicating that the well shut-in stage fluid volume is the sum of the well opening stage fluid volume and the wellhead plunger discharge volume.

[0073] The specific calculation formula for the fluid accumulation model during the well opening stage is as follows:

[0074] V w_open =h l_t_open A t +h l_c_open (A c -A t This model describes the amount of fluid accumulated at the bottom of the tubing during the well opening phase, where A t Let A be the cross-sectional area of ​​the oil pipe. c h is the cross-sectional area of ​​the casing. l_t_open and hl_c_open These are the fluid levels in the tubing and casing, respectively.

[0075] The specific calculation formula for the fluid accumulation model during the shut-in stage is as follows:

[0076] V w_shut =h l_t_shut A t +h l_c_shut (A c -A t This model describes the amount of fluid accumulated in the wellbore during the shut-in phase, where h l_t_shut and h l_c_shut These are the fluid levels in the tubing and casing, respectively.

[0077] The specific calculation formula for the wellhead plunger fluid discharge rate model is as follows:

[0078] V w_load =[h l_t_shut -(L t -L p A t The model describes the changes in fluid discharge from the wellhead plunger, where Lp is the depth of the plunger catcher and Lt is the tubing depth.

[0079] The specific calculation formula for the model of total fluid volume change in the wellbore is as follows:

[0080] V w_shut =V w_open +V w_load The model states that the fluid accumulation during the shut-in phase is the sum of the fluid accumulation during the well opening phase and the fluid discharge from the wellhead plunger, ignoring the influence of formation fluid entering the wellbore during the rapid arrival of the plunger at the wellhead.

[0081] In summary, by constructing this model of total wellbore fluid volume variation, the effects of fluid level changes and plunger discharge during the well opening and shut-in processes of a plunger gas lift well are systematically considered. This provides a comprehensive framework capable of describing the changes in wellbore fluid volume throughout the entire well opening and shut-in process of a plunger gas lift well.

[0082] Step S5: Construct a comprehensive dynamic liquid level model. The comprehensive dynamic liquid level model is constructed by combining three models: the liquid accumulation height model during the shut-in stage, the liquid accumulation height model during the well opening stage, and the total liquid accumulation change model in the wellbore. Input the data to be processed into the comprehensive dynamic liquid level model to obtain the annular liquid accumulation, the wellbore liquid accumulation, and the single-cycle plunger discharge volume, thereby quantitatively calculating the annular liquid accumulation in the plunger well.

[0083] When constructing a comprehensive dynamic fluid level model for a plunger gas lift well, three models were combined: a fluid height model during the shut-in phase, a fluid height model during the well opening phase, and a model showing the change in total fluid volume in the wellbore. This comprehensive model provides a quantitative calculation of annular fluid accumulation in plunger wells, enabling a more accurate understanding of fluid level changes within the well and yielding data on annular fluid volume, wellbore fluid volume, and plunger discharge volume.

[0084] First, the well shut-in stage fluid height model is based on the pressure and fluid level data of the tubing and casing during the well shut-in stage. This model describes the fluid level change pattern after the plunger shuts in, considering the relationship between the tubing and casing pressures, as well as the fluid level evolution over time. Second, the well opening stage fluid height model is based on the pressure and fluid level data of the tubing and casing during the well opening stage. This model considers the fluid level change pattern after the plunger opens in, and also considers the influence of pressure between the tubing and casing on the fluid level, but this time it is the change under the well opening condition. Third, the wellbore total fluid volume change model considers the relationship between the total wellbore fluid volume changes between the well shut-in and well opening stages. This model combines the relationship between the fluid volume during the well shut-in stage, the fluid volume during the well opening stage, and the plunger discharge volume, describing the trend of the total wellbore fluid volume change at different stages. When these three models are combined to construct a comprehensive dynamic fluid level model, the wellhead production data to be processed is input into this model. This yields more accurate data on annular fluid volume, wellbore fluid volume, and single-cycle plunger discharge volume. These data not only help to understand the changing patterns of fluid levels in plunger wells, but also provide a reliable quantitative basis for well operation and management.

[0085] The advantage of this integrated dynamic level model lies in its consideration of level changes beyond a single stage. It interconnects the relationships between well shut-in, well opening, and level changes, simplifying the study of the pressure balance system and establishing a simpler, faster method for calculating accumulated fluid volume. This means less data is required, data acquisition is easier, and the calculation process is simple and quick. This facilitates the development of subsequent plunger production protocols, making well management and production adjustments more convenient. Furthermore, it incorporates the plunger pressure system at the initial wellhead flow stage during well opening, effectively solving the problem of multiple solutions in existing plunger well annular fluid height calculations. This means the method can more accurately determine the level, avoiding the multiple solutions that may occur in existing methods, and improving the reliability and accuracy of level calculations.

[0086] In summary, this plunger gas lift well fluid accumulation calculation method is based on the actual well shut-in and well opening processes during the operational cycle. By integrating data from the shut-in and well opening stages, as well as wellbore structural information, a systematic model is constructed to quantitatively calculate the annular fluid accumulation in plunger wells. First, step S1 acquires key data from the target gas well, including wellbore structural information and wellhead oil pressure and casing pressure data during the plunger's movement cycle. This data forms the basis for subsequent analysis and calculations, ensuring sufficient information to understand the changes in well fluid level. Next, steps S2 and S3 focus on the fluid level during the shut-in and well opening stages, respectively. In S2, a fluid level model for the shut-in stage is constructed, considering the fluid level changes after the plunger shuts in; while in S3, a fluid level model for the well opening stage is established, considering the fluid level changes after the plunger opens. The goal of these two steps is to provide a basis for calculating the fluid level at each stage, in order to understand the fluid level in the well during different operational phases. In step S4, a model of the total fluid volume change in the wellbore is constructed. By considering the relationship between the changes in the total fluid volume in the wellbore during the shut-in and open phases, as well as the discharge volume of the plunger, the change in the total fluid volume in the wellbore throughout the entire operational cycle is obtained. This step provides a more comprehensive basis for the fluid level changes throughout the entire cycle. Finally, in step S5, the aforementioned three models are integrated into a comprehensive dynamic fluid level model. This model combines the shut-in phase, the open phase, and the changes in the total fluid volume in the wellbore. By inputting the data to be processed, important data such as the annular fluid volume, the wellbore fluid volume, and the discharge volume of the plunger in each cycle are obtained. This comprehensive model provides comprehensive data on fluid level and volume, providing key support for the quantitative calculation of fluid level changes in plunger wells. In summary, this method, based on the actual operational cycle, achieves a comprehensive and accurate calculation of annular fluid accumulation in plunger wells by progressively constructing fluid level and fluid volume change models and integrating them into a comprehensive model. The key to this approach is integrating data and models from different stages to better understand and assess liquid level changes in plunger gas lift wells, providing a reliable data foundation for the management and optimization of oilfield engineering.

[0087] The above-disclosed embodiments are merely preferred embodiments of this application and should not be construed as limiting the scope of this application. Those skilled in the art will understand that all or part of the processes for implementing the above embodiments and equivalent variations made in accordance with the claims of this application are still within the scope of this application.

Claims

1. A method for calculating liquid accumulation in a plunger gas lift well based on wellhead production data, comprising the following steps: S1, Obtain the data to be processed from the target gas well. The data to be processed includes wellbore structure data, wellhead oil pressure and casing pressure within a unit cycle of plunger movement, where the unit cycle is the plunger's upward and downward movement cycle during well opening and shut-in. S2, call the well shut-in stage liquid height model, input the processed data into the well shut-in stage liquid height model to obtain the liquid level status at the end of well shut-in; S3, call the well opening stage liquid height model, input the processed data into the well opening stage liquid height model to obtain the liquid level status at the beginning of well opening; S4, call the total wellbore fluid volume change model, input the processed data into the total wellbore fluid volume change model to obtain the relationship between the total wellbore fluid volume between the shut-in and open stages; S5, call the integrated dynamic liquid level model, input the data to be processed into the integrated dynamic liquid level model to obtain the annular liquid accumulation, wellbore liquid accumulation and single-cycle plunger discharge volume, thereby quantitatively calculating the annular liquid accumulation in the plunger well. The integrated dynamic liquid level model is constructed by combining three models: the liquid accumulation height model during the shut-in stage, the liquid accumulation height model during the well opening stage, and the wellbore total liquid accumulation change model.

2. The method for calculating the accumulated fluid in a plunger gas lift well based on wellhead production data according to claim 1, characterized in that: The shut-in stage fluid height model is constructed based on the relationship between the annular fluid height and the tubing fluid height at the last moment of the shut-in stage. It includes a shut-in tubing pressure converted to bottom hole pressure model, a shut-in casing pressure converted to bottom hole pressure model, and a model showing the equality of shut-in tubing and shut-in casing pressures.

3. The method for calculating liquid accumulation in a plunger gas lift well based on wellhead production data according to claim 1, characterized in that: The well opening stage fluid accumulation height model is constructed based on the relationship between the annular fluid accumulation height and the tubing fluid accumulation height at the initial moment of wellhead follow-through during the well opening stage. It includes a well opening tubing pressure converted to bottom hole pressure model, a well opening casing pressure converted to bottom hole pressure model, and a model showing the equality of well opening tubing and well opening casing pressures.

4. The method for calculating liquid accumulation in a plunger gas lift well based on wellhead production data according to claim 1, characterized in that: The total wellbore fluid volume change model is constructed based on the change in total wellbore fluid volume at the last moment of the shut-in phase and the initial moment of wellhead follow-through during the opening phase. It includes the wellhead fluid volume model, the shut-in fluid volume model, the wellhead plunger discharge volume model, and the total wellbore fluid volume change model.

5. The method for calculating liquid accumulation in a plunger gas lift well based on wellhead production data according to claim 2, characterized in that, The specific calculation formula for the well shut-in tubing pressure converted to bottom hole pressure model is as follows: The specific calculation formula for the well shut-in casing pressure converted to bottom hole pressure model is as follows: The specific calculation formula for the model of the pressure equality between the shut-in tubing and the shut-in casing is as follows: p wf_t_shut =p wf_c_shut ; Where, p wf_t_shut The bottom hole pressure is calculated from the tubing pressure at the final moment of the shut-in phase; p wf_c_shut The casing pressure converted to bottom hole pressure at the final moment of the shut-in phase; p t_shut p represents the tubing pressure at the final moment of the well shut-in phase. c_shut The casing pressure at the final moment of the shut-in phase; γ g The relative density of natural gas is given; methane is taken as 0.56; L t This refers to the depth of the tubing. The system average temperature is given in K. h is the system average deviation factor; l_t_shut The height of fluid buildup in the tubing during the shut-in phase; h l_c_shut ρ represents the annular fluid accumulation height during the shut-in phase. w Let g be the density of the liquid; g is the acceleration due to gravity, taken as 9.8 m / s². 2 .

6. The method for calculating the accumulated fluid in a plunger gas lift well based on wellhead production data according to claim 3, characterized in that, The specific calculation formula for the wellbore pressure-to-bottom-hole pressure conversion model is as follows: The specific calculation formula for the wellbore casing pressure to bottom hole pressure conversion model is as follows: The specific calculation formula for the pressure equality model between the well-opening tubing and the well-opening casing is as follows: p wf_t_open =p wf_c_open ; Where, p wf_t_open The bottom hole pressure is calculated from the tubing pressure at the initial moment of wellhead follow-through during the well opening phase; p wf_c_open The bottom hole pressure is calculated from the casing pressure at the initial moment of wellhead follow-through during the well opening phase; p t_open p represents the tubing pressure at the initial moment of wellhead follow-through during the well opening phase. c_open h is the casing pressure at the initial moment of wellhead follow-through during the well opening phase; l_t_open h is the height of fluid buildup in the tubing during the well opening phase. l_c_open This refers to the height of fluid accumulation in the annulus during the well opening phase.

7. The method for calculating liquid accumulation in a plunger gas lift well based on wellhead production data according to claim 4, characterized in that, The specific calculation formula for the fluid accumulation model during the well opening stage is as follows: V w_open =h l_t_open A t +h l_c_open (A c -A t ), where A t Let A be the cross-sectional area of ​​the oil pipe. c h is the cross-sectional area of ​​the casing. l_t_open and h l_c_open These are the fluid levels in the tubing and casing, respectively. The specific calculation formula for the fluid accumulation model during the well shut-in stage is as follows: V w_shut =h l_t_shut A t +h l_c_shut (A c -A t ), where h l_t_shut and h l_c_shut These are the fluid levels in the tubing and casing, respectively. The specific calculation formula for the wellhead plunger fluid discharge volume model is as follows: V w_load =[h l_t_shut -(L t -L p A t Where Lp is the depth of the plunger retainer and Lt is the depth of the tubing; The specific calculation formula for the model of total fluid volume change in the wellbore is as follows: V w_shut =V w_open +V w_load 。 8. A method for calculating liquid accumulation in a plunger gas lift well based on wellhead production data, as described in any one of claims 1-7, characterized in that, The unit cycle is a cycle of plunger movement during well opening and well closing, which includes 6 states, ① during the well opening stage, the gas in the upper part of the plunger rises and gas is produced at the wellhead; ② This is the stage where the liquid column above the plunger rises during the well opening phase, and water is produced at the wellhead; ③ This is the follow-through stage where the liquid above the plunger is discharged from the wellhead during the well opening phase; ④ is the stage where the plunger descends in the gas column during the shut-in phase; ⑤ is the stage where the plunger descends in the liquid column during the shut-in phase; ⑥ is the plunger placement and locking device.

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