Gas well production system transient simulation method and system

Abstract

The embodiment of the invention provides a transient simulation method and system for a gas well production system, and belongs to the technical field of oil-gas field development. The method comprises the following steps: constructing a gas-liquid two-phase transient flow model in an oil pipe of a gas well based on production state parameters, wherein the gas-liquid two-phase transient flow model is used for simulating the flow condition of fluid in a shaft of a target gas well; a gas well inflow and outflow coupling model used for simulating the dynamic change process in the gas well is constructed; constructing a corresponding non-constant flow model based on a gas-liquid two-phase transient flow model in an oil pipe and the gas well inflow and outflow coupling model; performing numerical solution on the non-constant flow model by adopting a finite difference method to obtain a transient change rule of each dynamic parameter when liquid accumulation occurs in the gas well; and constructing a corresponding gas well hydrops process transient model based on the transient change rule of each dynamic parameter. According to the scheme, reliable theoretical basis and technical support are provided for accurately predicting the liquid accumulation time of the gas well and optimizing the drainage gas production process, and therefore the stable production capacity and management efficiency of the gas well are remarkably improved.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development technology, and specifically to a transient simulation method for a gas well production system. Background Technology

[0002] With the continuous development of oil and gas fields, the problem of fluid accumulation in gas wells has become one of the important factors restricting the stable production of gas wells. During the gas well production process, as gas production decreases, the gas cannot continuously and effectively carry the liquid out of the wellbore, causing the liquid to gradually accumulate inside the wellbore. This fluid accumulation phenomenon increases the pressure loss inside the wellbore, further reduces the bottom hole flowing pressure, inhibits the formation's gas production capacity, and forms a vicious cycle, ultimately causing the gas well to be shut down by the accumulated fluid. In order to maintain the long-term efficient production of gas wells, accurately judging the state of fluid accumulation in gas wells and the timing of its occurrence, and taking effective drainage and gas production technology measures, has become a key technical problem that urgently needs to be solved in the oil and gas production field.

[0003] In existing technologies, droplet inversion models and liquid film inversion models are widely used to characterize the critical conditions for fluid accumulation in wellbores. These models typically determine the boundary conditions for fluid accumulation in gas wells through theoretical calculations and have some reference value. However, these methods have shortcomings in the following aspects: 1) Insufficient dynamic description of the flow process: Existing models mainly focus on whether the wellbore reaches the critical condition of liquid accumulation, but it is difficult to accurately reflect the liquid flow state before and after liquid accumulation and the transient changes of the gas-liquid phase in the wellbore.

[0004] 2) Lack of comprehensive coupling analysis: Current research focuses on flow models within a single wellbore, but fails to couple multiple dynamic parameters such as bottom hole pressure, fluid level, and annular pressure, thus failing to fully describe the interaction between gas well fluid flow and bottom hole gas production characteristics.

[0005] 3) Limited accuracy: The prediction results of liquid accumulation are highly dependent on input parameters (such as the physical characteristics of the gas well, temperature and pressure, etc.), while the existing methods are not very adaptable to complex conditions with multiple parameters, and the prediction results have errors.

[0006] 4) Lack of practical operational guidance: Most models remain at the theoretical analysis stage and fail to form solutions adapted to actual gas well conditions, resulting in the inability to optimize liquid accumulation treatment measures in a timely manner.

[0007] In summary, current technical solutions for gas well fluid accumulation problems suffer from insufficient dynamic description, incomplete coupling analysis, and weak application adaptability, making it difficult to meet the actual needs of stable gas well production. Therefore, there is an urgent need for a transient model of the gas well production system that can accurately describe the fluid accumulation process, dynamically couple changes in key parameters, and possess high adaptability, providing theoretical support for optimizing drainage and gas production processes. Summary of the Invention

[0008] The purpose of this invention is to provide a transient simulation method and system for gas well production systems, so as to at least solve the problems of insufficient dynamic description, incomplete coupling analysis and poor application adaptability of current technical solutions for gas well liquid accumulation.

[0009] To achieve the above objectives, the first aspect of the present invention provides a transient simulation method for a gas well production system. The method includes: collecting design production state parameters of a target gas well; constructing a gas-liquid two-phase transient flow model in the tubing of the gas well based on the production state parameters to simulate the fluid flow within the wellbore of the target gas well; constructing a gas well inflow-outflow coupling model to simulate the dynamic changes within the gas well based on the fluid flow within the wellbore coupled with dynamic parameters; constructing a corresponding unsteady flow model based on the gas-liquid two-phase transient flow model in the tubing and the gas well inflow-outflow coupling model; numerically solving the unsteady flow model using the finite difference method to obtain the transient change law of each dynamic parameter when liquid accumulation occurs in the gas well; and constructing a corresponding transient model of the gas well liquid accumulation process based on the transient change law of each dynamic parameter.

[0010] Optionally, the transient two-phase flow model in the oil pipe includes: a transient flow model and an annular flow control model; the transient flow model includes multiple model groups composed of multiple physical dependent variables; the model groups include: mass conservation models for each phase, momentum conservation models for the mixture, liquid phase holdup relationship models, and multiple state models; the method further includes: solving each model group to obtain the corresponding dependent variables.

[0011] Optionally, the plurality of physical dependent variables include any one or more of the following: wellbore pressure, liquid phase apparent velocity, gas phase apparent velocity, liquid phase holdup, liquid phase density, gas phase density, liquid viscosity, and gas viscosity.

[0012] Optionally, the mass conservation model for each phase is:

[0013]

[0014] Among them, when At that time, it is the gas phase; when At that time, it is in the liquid phase; For time; For distance; for Phase density; for Stalemate rate; for Phase apparent velocity, ; This is the mass flow rate per unit volume. It is 0 when there is no external flow injection. However, if it is at the bottom of the tubing, in addition to formation production, there is also casing gas inflow, so it is not 0.

[0015] Optionally, the momentum conservation model for the mixture includes:

[0016] in, Thermodynamic pressure; The gradient of total pressure loss; , which is the pressure gradient generated by potential energy; Let be the density of the mixture, and ; The angle between the oil pipe and the horizontal plane; It is the acceleration due to gravity; , where is the gradient of frictional pressure loss; The density of the non-slip mixture is, and ; Let be the velocity of the mixture, and It is the two-phase friction factor.

[0017] Optionally, the state models include: a gas phase density state model, a liquid phase density state model, a gas phase viscosity state model, and a liquid phase viscosity state model, each of which is represented as follows:

[0018]

[0019]

[0020]

[0021] in, This refers to the gas phase density. The density of the liquid phase; This refers to the viscosity of the gas phase. The viscosity is the liquid phase viscosity. For real gas deviation factor; The specific gravity of natural gas; These are preset constant values; K, Y, and T are fitting parameters; This is a temperature-dependent function.

[0022] Optionally, the rules for determining each fitting parameter are as follows:

[0023]

[0024]

[0025] Where M is the molar mass of the gas; T is the temperature.

[0026] Optionally, the annular flow control model represents the variation of wellhead pressure with respect to time and the overall mass balance model in the annulus; wherein, the variation of wellhead pressure with respect to time and the overall mass balance model in the annulus are:

[0027] in, This represents the gas density under standard conditions. This represents the gas volumetric flow rate under standard conditions. The specific gravity of natural gas; Absolute temperature; The gas density at a given temperature and pressure; This is the real gas deviation factor.

[0028] Optionally, the step of constructing a gas well inflow-outflow coupling model to simulate the dynamic changes within the gas well based on the fluid flow within the target gas well shaft and coupled with dynamic parameters includes: coupling corresponding dynamic parameters based on the fluid flow within the target gas well shaft to construct models of the time-varying state parameters of each well, representing the dynamic changes within the gas well; and obtaining the gas well inflow-outflow coupling model based on the time-varying model of the state parameters of each well. The state parameters of each well include any one or more of the following: bottom hole pressure, tubing fluid level position, annular fluid level position, annular wellhead pressure, tubing, and the flow rate of liquid or gas passing between the tubing and the annulus.

[0029] Optionally, after obtaining the unsteady flow model, the method further includes: adding boundary conditions to the unsteady flow model, wherein the boundary conditions include: bottom hole boundary conditions, used to limit the relationship between bottom hole pressure and reservoir fluid inflow; wellhead boundary conditions, used to limit the relationship between annular wellhead pressure and gas-liquid flow; and fluid surface boundary conditions, including: boundary conditions for the position of the fluid surface inside the tubing, which depend on the gas-liquid boundary point and the gas-liquid two-phase flow characteristics; and boundary conditions for the position of the fluid surface in the annulus, determined by combining the gas-liquid distribution in the annulus and the annular pressure gradient.

[0030] Optionally, the finite difference method is used to numerically solve the unsteady flow model to obtain the transient change law of each dynamic parameter when liquid accumulation occurs in the gas well. This includes: initializing the time step and the total simulation time, and initializing the initial and boundary conditions of the gas-liquid two-phase flow in the wellbore; in the unsteady flow model, the wellhead gas flow rate, tubing pressure distribution, and wellhead oil pressure are calculated based on the initial wellhead pressure; the real-time bottom hole flowing pressure is determined based on the real-time wellhead gas flow rate, tubing pressure distribution, and wellhead oil pressure, and it is determined whether the real-time bottom hole flowing pressure is less than the formation pressure; if the real-time bottom hole flowing pressure is less than the formation pressure, the gas production change is simulated; if the real-time bottom hole flowing pressure is less than the formation pressure, it is determined that there is no gas / liquid production; the values ​​of each dynamic parameter at the current moment are determined based on the simulated gas production change, which serve as the transient change law of each dynamic parameter.

[0031] Optionally, the dynamic parameters include: casing pressure, fluid production, and gas production; the construction of the corresponding transient model of the gas well fluid accumulation process based on the transient change law of each dynamic parameter includes: continuously judging whether the real-time bottom hole flowing pressure is less than the formation pressure during the total simulation time, until the total simulation time is completed or the wellhead gas production is 0, stopping the solution, and plotting the change of each dynamic parameter over time during the current total simulation time as the transient model of the gas well fluid accumulation process.

[0032] A second aspect of the present invention provides a transient simulation system for a gas well production system. The system includes: a data acquisition unit for acquiring design production state parameters of a target gas well and constructing a transient gas-liquid two-phase flow model in the tubing of the gas well based on the production state parameters to simulate the fluid flow within the wellbore of the target gas well; a coupling unit for coupling dynamic parameters based on the fluid flow within the wellbore of the target gas well to construct a gas well inflow-outflow coupling model to simulate the dynamic changes within the gas well; a model construction unit for constructing a corresponding unsteady flow model based on the transient gas-liquid two-phase flow model in the tubing and the gas well inflow-outflow coupling model; a solution unit for numerically solving the unsteady flow model using the finite difference method to obtain the transient change law of each dynamic parameter when liquid accumulation occurs in the gas well; and an output unit for constructing a corresponding transient model of the gas well liquid accumulation process based on the transient change law of each dynamic parameter.

[0033] A third aspect of the present invention provides a computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the aforementioned transient simulation method for a gas well production system.

[0034] A fourth aspect of the present invention provides an electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program to implement the above-described transient simulation method for a gas well production system.

[0035] The fifth aspect of the present invention provides a computer program product, including a computer program that, when executed by a processor, implements the transient simulation method for a gas well production system described above.

[0036] Through the above technical solution, this invention constructs a transient two-phase flow model of gas and liquid within the well tubing by collecting the design production state parameters of the target gas well, thereby accurately describing the dynamic flow characteristics of the fluid within the wellbore. By coupling the fluid flow within the wellbore with key dynamic parameters, a coupled inflow-outflow model is further established to fully characterize the dynamic changes within the gas well. Based on these two models, a non-steady flow model is proposed, and numerical solutions are obtained using the finite difference method to capture the transient changes in dynamic parameters such as pressure, liquid level, and flow rate when liquid accumulation occurs in the gas well. This method achieves a comprehensive and accurate simulation of the gas well liquid accumulation process, solving the problems of insufficient dynamic description and incomplete coupling analysis in existing technologies. Finally, by constructing a transient model of the gas well liquid accumulation process, a reliable theoretical basis and technical support are provided for accurately predicting the gas well liquid accumulation time and optimizing drainage and gas production processes, thereby significantly improving the stable production capacity and management efficiency of gas wells.

[0037] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0038] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings: Figure 1 This is a flowchart of the steps of a transient simulation method for a gas well production system provided in one embodiment of the present invention; Figure 2 This is a schematic diagram of the gas well A tubing string result provided by one embodiment of the present invention; Figure 3 This is a transient oil pressure change curve at the wellhead of gas well A provided by one embodiment of the present invention; Figure 4 This is a transient change curve of the casing pressure at the wellhead of gas well A provided by one embodiment of the present invention; Figure 5 This is a transient change curve of the production rate of gas well A provided in one embodiment of the present invention; Figure 6This is a transient change curve of gas production of gas well A provided in one embodiment of the present invention; Figure 7 This is a transient change curve of the liquid-gas ratio in gas well A provided by one embodiment of the present invention; Figure 8 This is a system structure diagram of a transient simulation system for a gas well production system provided in one embodiment of the present invention. Detailed Implementation

[0039] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0040] Figure 1 This is a flowchart of a transient simulation method for a gas well production system provided in one embodiment of the present invention. Figure 1 As shown, this invention provides a transient simulation method for a gas well production system, the method comprising: Step S10: Collect the design production state parameters of the target gas well, and construct a gas-liquid two-phase transient flow model in the tubing of the gas well based on the production state parameters to simulate the fluid flow in the wellbore of the target gas well.

[0041] Specifically, the transient two-phase flow model in the oil pipe includes: a transient flow model and an annular flow control model; the transient flow model includes multiple model groups composed of multiple physical dependent variables; the model groups include: mass conservation models for each phase, momentum conservation models for mixtures, liquid phase holdup relationship models, and multiple state models; the method further includes: solving each model group to obtain the corresponding dependent variables.

[0042] Furthermore, the plurality of physical dependent variables include any one or more of the following: wellbore pressure, liquid phase apparent velocity, gas phase apparent velocity, liquid phase holdup, liquid phase density, gas phase density, liquid viscosity, and gas viscosity.

[0043] Specifically, the mass conservation model for each phase is as follows:

[0044]

[0045] Among them, when At that time, it is the gas phase; when At that time, it is in the liquid phase; For time; For distance; for Phase density; for Stalemate rate; for Phase apparent velocity, ; This is the mass flow rate per unit volume. It is 0 when there is no external flow injection. However, if it is at the bottom of the tubing, in addition to formation production, there is also casing gas inflow, so it is not 0.

[0046] Furthermore, the momentum conservation model for the mixture includes:

[0047] in, Thermodynamic pressure; The gradient of total pressure loss; , which is the pressure gradient generated by potential energy; Let be the density of the mixture, and ; The angle between the oil pipe and the horizontal plane; It is the acceleration due to gravity; , where is the gradient of frictional pressure loss; The density of the non-slip mixture is, and ; Let be the velocity of the mixture, and ; It is the two-phase friction factor.

[0048] In this embodiment of the invention, to accurately simulate the fluid flow within a gas wellbore, the method first collects the design production state parameters of the target gas well. These parameters include key data affecting fluid flow during gas well production, such as wellbore pressure, temperature, and flow rate. Based on these parameters, a transient gas-liquid two-phase flow model within the tubing is constructed to describe the gas-liquid two-phase flow behavior within the gas wellbore.

[0049] Specifically, the model is mainly divided into two parts: transient flow model and annular flow control model.

[0050] 1) Transient flow model: The transient flow model is the core of the description of gas-liquid flow in the wellbore, and it is established based on multiple physical dependent variables (such as pressure in the wellbore, apparent velocity of liquid and gas phases, liquid phase holdup, etc.).

[0051] The transient flow model contains multiple model groups: Mass conservation model for each phase: describes the distribution of mass of the gas and liquid phases over time and space.

[0052] Momentum conservation model for mixtures: simulates the kinematic characteristics of gas-liquid mixtures, including potential energy, momentum, and frictional pressure loss.

[0053] Liquid phase holdup model: characterizes the volume ratio of gas and liquid phases in the wellbore.

[0054] Multiple state models: Define the relationship between physical parameters such as gas and liquid phase density, viscosity and pressure and temperature.

[0055] Through the collaborative calculations of these model groups, the dynamic characteristics of fluids within the wellbore can be comprehensively and accurately described.

[0056] 2) Annular Flow Control Model: The flow control of the fluid in the annulus is an important supplement to this model, taking into account the fluid exchange characteristics between the tubing and the annulus. The annular flow control model describes the time-varying laws of pressure, liquid volume, and fluid exchange within the annulus, providing more comprehensive support for overall flow analysis.

[0057] Furthermore, the state models include: a gas phase density state model, a liquid phase density state model, a gas phase viscosity state model, and a liquid phase viscosity state model, each of which is represented as follows:

[0058]

[0059]

[0060]

[0061] in, This refers to the gas phase density. The density of the liquid phase; This refers to the viscosity of the gas phase. The viscosity is the liquid phase viscosity. For real gas deviation factor; The specific gravity of natural gas; These are preset constant values; K, Y, and T are fitting parameters; This is a temperature-related function. The rules for determining the fitting parameters are as follows:

[0062]

[0063]

[0064] Where M is the molar mass of the gas; T is the temperature.

[0065] Furthermore, when the pressure fluctuates within the tubing, corresponding fluctuations will occur in the annulus. When the pressure inside the tubing decreases, gas from the annulus will enter the tubing, and vice versa. Assume that the annulus only experiences flow with the tubing and not with the reservoir. When there is a certain amount of fluid in the well, there will also be fluid in the annulus. The volume of fluid in the annulus is given by the following formula:

[0066] in: The total volume of the annulus is constant. ; : Annular gas volume .

[0067] Assuming the casing length and tubing length are equal, therefore, It can be represented as:

[0068] in: The cross-sectional area of ​​the annulus is constant. ; The number of units in which the production tubing is divided; : Length of each unit . We can obtain

[0069] gas volume Cross-sectional area of ​​the annulus Distance from ground to liquid surface The product of:

[0070] The annular liquid mass balance equation is:

[0071] here This indicates the mass flow rate of liquid flowing into or out of the oil pipe from the annulus through the pipe foot. (Item) This represents the current change in the mass of the liquid accumulated in the annulus. This is taken into account the liquid phase density. Since it is a constant (not a function of time), then Therefore, formula (3) becomes:

[0072] For the gas mass balance equation in the annulus, if there is no liquid in the annulus during the outflow process, then gas flows out; conversely, the same applies when oil flows into the annulus from the tubing. This can be expressed by equation (5):

[0073] here, This represents the mass flow rate of gas flowing from the annulus into the oil pipe; This indicates the current mass change of the gas accumulated in the annulus.

[0074] Formula (4) can be written in the following form:

[0075] Due to mass flow Volumetric flow rate With density The product of and , therefore, the liquid mass flow rate is For a constant liquid density, equation (6) becomes:

[0076] Similarly, equation (5) concerning the gas phase can be written in the form of equation (8):

[0077] in: Gas density under standard conditions ; : Gas volumetric flow rate under standard conditions .

[0078] Using the properties of derivatives Expanding and substituting into equation (8), we get:

[0079] Applying time to both sides of formula (1) Differentiating, we get:

[0080] Substituting equation (6) into equation (10), we obtain the following relationship:

[0081] Substituting equation (11) into equation (9), we can obtain

[0082] Applying the chain rule to the last term on the right-hand side of equation (12), we can obtain:

[0083] Pressure in the above formula The value is actually the average pressure of the air column in the annulus. The simplified form of equation (13) is appropriate.

[0084]

[0085] The density of a gas can be obtained from the real gas law. Calculation formula:

[0086] in: :pressure, ; Natural gas density ( ); Absolute temperature ; Real gas deviation factor; : Gas density at a given temperature and pressure .

[0087] For the pressure on both sides of equation (15) Taking the derivative, we get:

[0088] Using equation (14), equation (13) can be rewritten as follows: form:

[0089] Equation (17) is the differential equation of the annular wellhead pressure with respect to time. Combining equations (16) and (17) yields the overall mass balance equation in the annulus, as shown in equation (18).

[0090]

[0091] This application uses the pipe flow method to calculate the flow rate of gas or liquid flowing between the casing and the tubing.

[0092] Step S20: Based on the fluid flow conditions inside the target gas well shaft and coupled dynamic parameters, construct a gas well inflow-outflow coupled model to simulate the dynamic changes within the gas well.

[0093] Specifically, dynamic parameters are coupled based on the fluid flow within the target gas wellbore to construct models of the state parameters within each well over time, representing the dynamic changes within the gas well. A gas well inflow-outflow coupling model is obtained based on the coupling of these models of state parameters within each well over time. The state parameters within each well include any one or more of the following: bottom hole pressure, fluid level position within the tubing, fluid level position in the annulus, annulus wellhead pressure, tubing, and the flow rate of liquid or gas passing between the tubing and the annulus.

[0094] In this embodiment of the invention, based on the flow characteristics of the fluid within the target gas wellbore, it is first necessary to model the state parameters within each well and study their variation over time. Specifically, the state parameters within each well include the following aspects: 1) Bottom hole pressure of gas well: Bottom hole pressure is an important parameter describing the formation's gas production capacity and fluid flow. Its dynamic changes directly affect the inflow rate and stable production status of the gas well.

[0095] 2) Fluid level position in tubing: Changes in fluid level position are key to judging the process of fluid accumulation in the wellbore. By monitoring the rise or fall of the fluid level over time, the dynamic characteristics of gas-liquid distribution can be understood.

[0096] 3) Annular liquid level position: The accumulation state of liquid in the annulus affects gas-liquid exchange, and the dynamic changes of the annular liquid level play an important role in the overall fluid balance of the gas well.

[0097] 4) Annular wellhead pressure: Annular wellhead pressure reflects the flow resistance and flow balance of gas and liquid inside the annulus, and its dynamic changes have a direct impact on the inflow and outflow process of gas wells.

[0098] 5) Fluid flow rate between tubing and annulus: The flow rate of liquid or gas between tubing and annulus describes the interaction between the two and is an important component of dynamic parameter coupling.

[0099] Based on the aforementioned dynamic parameters, time-varying state models are established to describe the dynamic processes within the gas well. By monitoring and calculating the time-varying patterns of each parameter, a parameter-time function is constructed to capture dynamic characteristics. The state models describe the dynamic changes in pressure, fluid level, and flow rate using analytical or numerical methods, providing a foundation for subsequent coupled analysis. The gas well inflow-outflow coupled model is constructed based on the time-varying patterns of each state parameter, obtaining the gas well inflow-outflow coupled model through model coupling. The core of the coupled model lies in linking key parameters such as bottom hole pressure, fluid level, and fluid flow rate to establish a unified model that comprehensively describes the dynamic behavior of the gas well. The coupled model comprehensively considers the tubing, annulus, and the fluid interactions between them, characterizing the overall changes during the gas well production process. Through real-time coupling and solving of dynamic parameters, this model can effectively simulate the inflow-outflow process of the gas well, especially providing crucial prediction and optimization support under conditions of fluid accumulation or production fluctuations.

[0100] In one possible implementation, under initial conditions At any given moment, the tubing and annulus are under initial pressure conditions for natural gas. When the wellhead is opened, gas and liquid produced in the formation flow into the tubing. Therefore, under initial conditions, the bottomhole flowing pressure in the wellbore is equal to the formation pressure, and there is no fluid flow within or between the tubing and casing, or between the wellbore and the formation. A coordinate axis is established with the bottom of the well as the origin and the vertical upward direction as the positive direction. The oil layer is located at... The quality source is located there, and there is no fluid backflow into the formation from the wellbore. At what moment, the apparent velocities of the liquid and gas phases in the tubing and For a given production value, in At any given time, the liquid phase holdup is 0 at any position in the tubing, that is:

[0101] exist At any given moment, only the pressure gradient caused by gravity is considered in the tubing, neglecting pressure losses due to friction and acceleration. The initial pressure in the tubing is the pressure of the static gas column at the bottom of the well, i.e.:

[0102] exist At any given moment, only the pressure gradient generated by gravity is considered in the surrounding air, while the pressure loss caused by friction and acceleration is ignored.

[0103] Step S30: Construct a corresponding non-steady flow model based on the gas-liquid two-phase transient flow model in the tubing and the gas well inflow-outflow coupling model.

[0104] Specifically, after obtaining the unsteady flow model, the method further includes: adding boundary conditions to the unsteady flow model, wherein the boundary conditions include: bottom hole boundary conditions, used to limit the relationship between bottom hole pressure and reservoir fluid inflow; wellhead boundary conditions, used to limit the relationship between annular wellhead pressure and gas-liquid flow; and liquid surface boundary conditions, including: boundary conditions for the position of the liquid surface inside the tubing, which depend on the gas-liquid boundary point and the gas-liquid two-phase flow characteristics; and boundary conditions for the position of the liquid surface in the annulus, which are determined by combining the gas-liquid distribution in the annulus and the annular pressure gradient.

[0105] In this invention, the non-steady flow model is based on a gas-liquid two-phase transient flow model and combined with a gas well inflow-outflow coupling model to uniformly describe the fluid dynamics between the tubing and the annulus. This model comprehensively considers various dynamic parameters (such as pressure, liquid level, flow rate, etc.) and their distribution patterns in time and space, and can accurately reflect the non-steady flow behavior within the gas well.

[0106] Furthermore, to ensure that the unsteady flow model is applicable to actual gas well conditions, appropriate boundary conditions must be added to the model to guarantee the rationality and accuracy of the flow simulation. These boundary conditions include: 1) Bottom-hole boundary conditions: Bottom-hole boundary conditions describe the dynamic characteristics of reservoir fluid inflow into the bottom of the well. By limiting the relationship between bottom-hole pressure and reservoir production, the influence of bottom-hole flowing pressure on formation gas production capacity can be accurately simulated, especially under conditions of fluid accumulation or pressure changes, to predict the bottom-hole fluid inflow rate.

[0107] 2) Wellhead Boundary Conditions: Wellhead boundary conditions are used to constrain the relationship between annular wellhead pressure and gas-liquid flow. They can describe the fluid flow characteristics at the wellhead (such as gas production and liquid production) and the dynamic behavior of gas-liquid two-phase separation, thereby controlling the wellhead production status.

[0108] 3) Liquid Surface Boundary Conditions: Boundary conditions for the liquid surface position within the tubing: These boundary conditions, combined with the gas-liquid two-phase flow characteristics and the gas-liquid boundary point, restrict the dynamic changes in the liquid surface position within the tubing. They accurately characterize the liquid distribution within the gas well, providing a reference for liquid accumulation assessment.

[0109] 4) Boundary conditions of the annular fluid level: By analyzing the gas-liquid distribution and pressure gradient within the annulus, the dynamic variation law of the annular fluid level is determined. This is of great significance for understanding the annular fluid accumulation state and its impact on gas well flow.

[0110] These boundary conditions work together to provide the necessary constraints for the non-steady flow model, enabling the model to accurately adapt to different operating conditions, such as fluctuations in gas production, changes in wellhead pressure, and dynamic adjustments in the gas-liquid ratio.

[0111] In one possible implementation, wellhead pressure The apparent velocity of the liquid phase at the wellhead is assumed to remain constant over time. A positive result means there is liquid being produced at the wellhead. If the entire wellbore... If the gas can carry the liquid to the product, then the normal production conditions cannot be achieved.

[0112] Assume the apparent velocity at the bottom tubing inlet is given by the following rule:

[0113] in: Bottom-of-well production index ; Bottom hole flowing pressure ,and ; Formation static pressure, ; : Cross-sectional area of ​​the oil pipe Alternatively, it can be given via the liquid-to-gas ratio (LGR):

[0114] in: Formation liquid-to-gas ratio; Natural gas formation volume factor. Throughout the production process, the bottom hole flowing pressure is constantly changing. At any given moment, the bottom hole flowing pressure... It is nothing more than greater than the formation pressure. There are two possibilities: either the pressure is less than the formation pressure.

[0115] like If the well-killing fluid is injected into the formation in reverse, then because it is a shale oil and gas reservoir, it is assumed that oil, casing fluid, or natural gas will not flow back.

[0116] like Then, the inflow dynamic prediction method is used to calculate the gas production of the formation.

[0117] Step S40: The finite difference method is used to numerically solve the unsteady flow model to obtain the transient change law of each dynamic parameter when liquid accumulation occurs in the gas well.

[0118] Specifically, the time step and total simulation time are initialized, and the initial and boundary conditions for the gas-liquid two-phase flow in the wellbore are initialized. In the unsteady flow model, the wellhead gas flow rate, tubing pressure distribution, and wellhead oil pressure within the current time step are calculated based on the initial wellhead pressure. The real-time bottom hole flowing pressure is determined based on the real-time wellhead gas flow rate, tubing pressure distribution, and wellhead oil pressure, and it is determined whether the real-time bottom hole flowing pressure is less than the formation pressure. If the real-time bottom hole flowing pressure is less than the formation pressure, the gas production change is simulated. If the real-time bottom hole flowing pressure is less than the formation pressure, it is determined that there is no gas / liquid production. The values ​​of each dynamic parameter at the current moment are determined based on the simulated gas production change, which serves as the transient change law of each dynamic parameter.

[0119] In this embodiment of the invention, a reasonable time step and total simulation time are set according to the simulation requirements. The time step determines the solution accuracy and computational efficiency, and a trade-off must be made between stability and accuracy. The initial state of the gas-liquid two-phase flow in the wellbore is set, including the initial pressure distribution, liquid level position, and gas-liquid flow velocity. At the same time, boundary conditions such as bottom hole pressure, wellhead pressure, and liquid level position are added to ensure that the model matches the actual working conditions.

[0120] Furthermore, within the current time step, based on the initial wellhead pressure, the wellhead gas flow rate, tubing pressure distribution, and wellhead oil pressure are calculated. This step characterizes the dynamic characteristics of the wellhead, reflecting the gas well's production capacity. Combining the current pressure distribution and oil pressure, the real-time bottomhole flowing pressure is calculated and compared with the formation pressure: if the real-time bottomhole flowing pressure is less than the formation pressure, the formation can continue to produce gas, and the current gas production change needs to be simulated. If the real-time bottomhole flowing pressure is higher than the formation pressure, the formation cannot produce gas, and it is determined that there is no gas or liquid production.

[0121] Furthermore, based on the simulated changes in gas production, the values ​​of various dynamic parameters at the current moment are determined, including pressure, liquid level, and flow rate. The current calculation results are used as the initial conditions for the next time step, and the process is iterated continuously until the total simulation time ends. Through iterative calculations over all time steps, the transient change patterns of various dynamic parameters (such as bottom hole pressure, wellhead gas flow rate, and liquid level) when liquid accumulation occurs in the gas well are finally obtained.

[0122] In one possible implementation, the dynamic simulation of the production process requires a comprehensive understanding of the time-varying parameters, including wellbore bottom pressure, tubing fluid level, annular fluid level, annular wellhead pressure, and the flow rates of liquid or gas passing through the tubing and between the tubing and the annulus. To obtain the transient changes of these parameters, this study employs the finite difference method to solve the equations describing the non-steady flow of the production process. The solution steps are described below, following the steps of the production process. The specific simulation calculation steps are as follows: 1) Select an appropriate time step and total simulation time; 2) Calculate the outflow rate of gas from the wellhead, the oil pressure at the wellhead, and the pressure distribution in the tubing within this time step based on the initial value of the wellhead oil pressure; 3) Determine if the bottomhole flowing pressure is less than the formation pressure. If it is less than the formation pressure, calculate the formation gas production, fluid production, and annular gas flow into the tubing. , , Formation pressure, gas production capacity, and production capacity can be set to change at a certain time as needed (simulating different liquid holdup rates at different cross sections), either increasing or decreasing, simulating possible changes that may occur after a period of formation production, such as a decrease in formation pressure leading to a decrease in gas production, or an increase in liquid production; if the pressure is greater than the formation pressure, there will be no production.

[0123] 4) If the total calculation time is less than If the total calculation time is greater than or equal to the specified time, then continue. If the total calculation time is greater than or equal to the specified time, then stop the calculation and exit. If the gas production at the wellhead is zero, it indicates that liquid accumulation has occurred and the well is being crushed. Then stop the calculation and exit. Based on the new gas and liquid flow rate of each section of the tubing and the new wellhead oil pressure jump to (2), calculate the flow situation of the next time step. 5) Plot the changes in oil casing pressure and gas and liquid production over time during the simulation period.

[0124] Step S50: Construct the corresponding transient model of the gas well liquid accumulation process based on the transient change law of each dynamic parameter.

[0125] Specifically, the dynamic parameters include: casing pressure, fluid production, and gas production. The construction of the corresponding transient model of the gas well fluid accumulation process based on the transient change law of each dynamic parameter includes: continuously judging whether the real-time bottom hole flowing pressure is less than the formation pressure during the total simulation time until the total simulation time is completed or the wellhead gas production is 0, stopping the solution, and plotting the change of each dynamic parameter over time during the current total simulation time as the transient model of the gas well fluid accumulation process.

[0126] In this embodiment of the invention, the pressure within the tubing and casing is a crucial indicator describing the fluid behavior within a gas well. Changes in tubing and casing pressure reflect the fluid flow state and the amount of liquid accumulation within the wellbore. A decrease in fluid production may be an early signal of liquid accumulation, and the trend in production rate as liquid accumulation occurs is an important basis for judging the state of liquid accumulation. A decrease in gas production directly indicates a weakening of the gas well's flow capacity; when a gas well is choked by liquid accumulation, the wellhead gas production will eventually drop to zero.

[0127] Furthermore, during the total simulation time, the bottom hole flowing pressure is monitored in real time to determine whether it is lower than the formation pressure by solving for dynamic parameters. If the bottom hole flowing pressure is lower than the formation pressure, it indicates that the formation can continue to produce gas; otherwise, it indicates that gas production in the gas well is suppressed or stopped. During the simulation, when the gas production at the wellhead is 0, the model determines that the gas well has entered a state of fluid accumulation and terminates the solution. This dynamic stopping mechanism effectively saves computational resources and provides the precise moment when fluid accumulation occurs. After the simulation is completed, graphs showing the changes in casing pressure, fluid production, and gas production over time are plotted. These graphs visually demonstrate the temporal evolution of various dynamic parameters within the gas well, serving as an important component of the transient model of the fluid accumulation process. Through the graphical representation of simulation data, the transient model can reveal the changing patterns of various dynamic parameters during the fluid accumulation process, especially the significant changes before and after fluid accumulation, providing support for the study of fluid accumulation mechanisms.

[0128] Example: Taking a gas well A as an example, the tubing configuration is as follows: Figure 2 As shown, the transient fluid accumulation process in the wellbore after a decrease in formation pressure is simulated as follows: Figures 3-7 As shown. Figure 3 The curve shows the transient change in oil pressure at the wellhead of gas well A. Figure 4 This is the transient change curve of the casing pressure at the wellhead of gas well A. Figure 5 This is the transient change curve of the production rate of gas well A. Figure 6 This is the transient change curve of gas production from gas well A. Figure 7 Transient change curve of liquid-gas ratio in gas well A.

[0129] Figure 8 This is a system structure diagram of a transient simulation system for a gas well production system provided in one embodiment of the present invention. Figure 8As shown, this invention provides a transient simulation system for a gas well production system. The system includes: a data acquisition unit for acquiring design production state parameters of the target gas well and constructing a transient gas-liquid two-phase flow model in the tubing of the gas well based on the production state parameters to simulate the fluid flow within the wellbore; a coupling unit for coupling dynamic parameters based on the fluid flow within the target gas well to construct a gas well inflow-outflow coupling model to simulate the dynamic changes within the gas well; a model construction unit for constructing a corresponding unsteady flow model based on the transient gas-liquid two-phase flow model in the tubing and the gas well inflow-outflow coupling model; a solution unit for numerically solving the unsteady flow model using the finite difference method to obtain the transient change law of each dynamic parameter when liquid accumulation occurs in the gas well; and an output unit for constructing a corresponding transient model of the gas well liquid accumulation process based on the transient change law of each dynamic parameter.

[0130] A third aspect of the present invention provides a computer-readable storage medium storing instructions that, when executed on a computer, cause the computer to perform the aforementioned transient simulation method for a gas well production system.

[0131] A fourth aspect of the present invention provides an electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program to implement the above-described transient simulation method for a gas well production system.

[0132] The fifth aspect of the present invention provides a computer program product, including a computer program that, when executed by a processor, implements the transient simulation method for a gas well production system described above.

[0133] Those skilled in the art will understand that all or part of the steps in the methods of the above embodiments can be implemented by a program instructing related hardware. This program is stored in a storage medium and includes several instructions to cause a microcontroller, chip, or processor to execute all or part of the steps of the methods described in the various embodiments of the present invention. The aforementioned storage medium includes various media capable of storing program code, such as a USB flash drive, a portable hard drive, a read-only memory (ROM), a random access memory (RAM), a magnetic disk, or an optical disk.

[0134] The optional embodiments of the present invention have been described in detail above with reference to the accompanying drawings. However, the embodiments of the present invention are not limited to the specific details described above. Within the scope of the technical concept of the embodiments of the present invention, various simple modifications can be made to the technical solutions of the embodiments of the present invention, and these simple modifications all fall within the protection scope of the embodiments of the present invention. It should also be noted that the various specific technical features described in the above specific embodiments can be combined in any suitable manner without contradiction. To avoid unnecessary repetition, the embodiments of the present invention will not further describe the various possible combinations.

[0135] Furthermore, various different embodiments of the present invention can be combined in any way, as long as they do not violate the spirit of the embodiments of the present invention, they should also be regarded as the content disclosed by the embodiments of the present invention.

Claims

1. A transient simulation method for a gas well production system, characterized in that, The method includes: Collect the design production state parameters of the target gas well, and construct a gas-liquid two-phase transient flow model in the tubing of the gas well to simulate the fluid flow in the wellbore of the target gas well. Based on the fluid flow conditions within the target gas well shaft coupled with dynamic parameters, a coupled gas well inflow and outflow model is constructed to simulate the dynamic changes within the gas well. A corresponding non-steady flow model is constructed based on the transient two-phase flow model of gas and liquid in the tubing and the inflow-outflow coupling model of the gas well. The finite difference method was used to numerically solve the unsteady flow model to obtain the transient change law of each dynamic parameter when liquid accumulation occurs in the gas well; A transient model of the gas well liquid accumulation process is constructed based on the transient change law of each dynamic parameter.

2. The method according to claim 1, characterized in that, The transient two-phase flow model of gas and liquid in the oil pipe includes: Transient flow models and annular flow control models; The transient flow model comprises multiple model groups, each consisting of multiple physical dependent variables. The model group includes: Mass conservation models for each phase, momentum conservation models for mixtures, liquid phase holdup models, and multiple state models; The method further includes: Solve each model group to obtain the corresponding dependent variable.

3. The method according to claim 2, characterized in that, The plurality of physical dependent variables include: Any one or more of the following: wellbore pressure, liquid phase apparent velocity, gas phase apparent velocity, liquid phase holdup, liquid phase density, gas phase density, liquid viscosity, and gas viscosity.

4. The method according to claim 2, characterized in that, The mass conservation model for each phase is as follows: Among them, when At that time, it is the gas phase; when At that time, it is in the liquid phase; For time; For distance; for Phase density; for Stalemate rate; for Phase apparent velocity, ; This is the mass flow rate per unit volume. It is 0 when there is no external flow injection. However, if it is at the bottom of the tubing, in addition to formation production, there is also casing gas inflow, so it is not 0.

5. The method according to claim 2, characterized in that, The momentum conservation model for the mixture includes: in, Thermodynamic pressure; The gradient of total pressure loss; , which is the pressure gradient generated by potential energy; Let be the density of the mixture, and ; The angle between the oil pipe and the horizontal plane; It is the acceleration due to gravity; , where is the gradient of frictional pressure loss; The density of the non-slip mixture is, and ; Let be the velocity of the mixture, and ; It is the two-phase friction factor.

6. The method according to claim 2, characterized in that, The state model includes: The gas phase density state model, liquid phase density state model, gas phase viscosity state model, and liquid phase viscosity state model are each represented as follows: in, This refers to the gas phase density. The density of the liquid phase; This refers to the viscosity of the gas phase. The viscosity is the liquid phase viscosity. For real gas deviation factor; The specific gravity of natural gas; This is a preset constant value; K, Y, and T are the fitting parameters; This is a temperature-dependent function.

7. The method according to claim 6, characterized in that, The rules for determining each fitting parameter are as follows: Where M is the molar mass of the gas; T represents temperature.

8. The method according to claim 2, characterized in that, The annular flow control model represents the variation of wellhead pressure with time and the overall mass balance model in the annulus; wherein... The variation law of wellhead pressure with respect to time and the overall mass balance model in the annulus are as follows: in, This represents the gas density under standard conditions. This represents the gas volumetric flow rate under standard conditions. The specific gravity of natural gas; Absolute temperature; The gas density at a given temperature and pressure; This is the real gas deviation factor.

9. The method according to claim 1, characterized in that, The gas well inflow-outflow coupling model, which is constructed based on the fluid flow conditions within the target gas wellbore and coupled with dynamic parameters, is used to simulate the dynamic changes within the gas well. This model includes: Based on the fluid flow conditions inside the target gas well, corresponding dynamic parameters are coupled to construct models of the state parameters inside each well over time, which serve as the dynamic change process inside the gas well. A coupled inflow and outflow model for gas wells is obtained based on the time-dependent relationship of state parameters within each well; where, The condition parameters in each well include: Any one or more of the following: bottom hole pressure of the gas well, fluid level position in the tubing, fluid level position in the annulus, annulus wellhead pressure, tubing, and the flow rate of liquid or gas passing between the tubing and the annulus.

10. The method according to claim 9, characterized in that, After obtaining the nonsteady flow model, the method further includes: Add boundary conditions to the non-steady flow model, wherein, The boundary conditions include: Bottom-hole boundary conditions are used to limit the relationship between bottom-hole pressure and reservoir fluid inflow. Wellhead boundary conditions are used to constrain the relationship between annular wellhead pressure and gas-liquid flow. Liquid surface boundary conditions include: The boundary conditions for the liquid level position inside the tubing depend on the gas-liquid interface and the gas-liquid two-phase flow characteristics. The boundary conditions for the position of the annular liquid surface are determined by combining the gas-liquid distribution within the annulus and the annular pressure gradient.

11. The method according to claim 1, characterized in that, The finite difference method is used to numerically solve the unsteady flow model to obtain the transient changes of various dynamic parameters when liquid accumulation occurs in the gas well, including: Initialize the time step and total simulation time, and initialize the initial and boundary conditions for the gas-liquid two-phase flow in the wellbore; In the non-steady flow model, the wellhead gas flow rate, tubing pressure distribution, and wellhead oil pressure are calculated within the current time step based on the initial wellhead pressure. The real-time bottom hole flowing pressure is determined based on the real-time wellhead gas flow rate, tubing pressure distribution, and wellhead oil pressure, and it is then determined whether the real-time bottom hole flowing pressure is less than the formation pressure. If the real-time bottom hole pressure is less than the formation pressure, then simulate the change in gas production. If the real-time bottom hole pressure is less than the formation pressure, it is determined that there is no gas / liquid production. The values ​​of each dynamic parameter at the current moment are determined based on the simulated changes in gas production, which serve as the transient change patterns of each dynamic parameter.

12. The method according to claim 11, characterized in that, The dynamic parameters include: Oil casing pressure, fluid production rate, and gas production rate; The transient model of the gas well liquid accumulation process, constructed based on the transient change laws of each dynamic parameter, includes: During the total simulation time, the real-time bottom hole flowing pressure is continuously checked to see if it is less than the formation pressure until the total simulation time is completed or the wellhead gas production is 0. The solution is then stopped, and the changes of each dynamic parameter over time during the current total simulation time are plotted as a transient model of the gas well liquid accumulation process.

13. A transient simulation system for a gas well production system, characterized in that, The system includes: The acquisition unit is used to acquire the design production state parameters of the target gas well, and to construct a two-phase transient gas-liquid flow model in the tubing of the gas well to simulate the fluid flow in the wellbore of the target gas well based on the production state parameters. The coupling unit is used to couple dynamic parameters based on the fluid flow in the target gas well shaft to construct a gas well inflow-outflow coupling model for simulating the dynamic changes in the gas well. The model building unit is used to build a corresponding non-steady flow model based on the gas-liquid two-phase transient flow model in the tubing and the gas well inflow-outflow coupling model. The solution unit is used to numerically solve the unsteady flow model using the finite difference method to obtain the transient change law of each dynamic parameter when liquid accumulation occurs in the gas well; The output unit is used to construct a transient model of the gas well liquid accumulation process based on the transient change law of each dynamic parameter.

14. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores instructions that, when executed on a computer, cause the computer to perform the transient simulation method for a gas well production system as described in any one of claims 1-12.

15. An electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the transient simulation method for a gas well production system as described in any one of claims 1-12.

16. A computer program product, comprising a computer program, characterized in that, When the computer program is executed by a processor, it implements the transient simulation method for a gas well production system according to any one of claims 1-12.

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