An Adaptive Correction Method for Formation-Wellbore System State in Fractured-Void Gas Reservoirs

Abstract

This invention proposes an adaptive correction method for the state of the formation-wellbore system in fractured-vuggy gas reservoirs, belonging to the field of oil and gas field development. This method uses the measured wellhead pressure during gas well production as a feedback control signal, and treats formation pressure and bottomhole flowing pressure as system state variables. Within the same production time step, through state prediction, wellhead pressure deviation analysis, and correction criterion generation, it dynamically determines the dominant influence of formation pressure or bottomhole flowing pressure on wellhead pressure deviation, and adaptively selects the corresponding state variable for reverse correction iteration, achieving controlled convergence of wellhead pressure deviation. By introducing a state correction path selection mechanism based on wellhead pressure feedback, it avoids the numerical oscillations and non-physical convergence problems caused by blind iteration in traditional coupled calculation methods. Without the need for complex numerical simulation, it achieves stable calculation and dynamic correction of the pressure state of the formation-wellbore system in fractured-vuggy gas reservoirs, demonstrating high engineering applicability.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development engineering, specifically to an adaptive correction method for the state of a fractured-vuggy gas reservoir formation-wellbore system. This method is used to dynamically correct the formation pressure and bottom hole flowing pressure state during gas well production by introducing a wellhead pressure feedback control mechanism, thereby achieving controlled convergence of wellhead pressure deviation. Background Technology

[0002] Fractured-vuggy gas reservoirs primarily utilize fractures and dissolution cavities as storage spaces, exhibiting strong reservoir heterogeneity, complex flow channels, and unstable pressure response. During gas well production, as cumulative gas production increases, formation pressure continuously decreases, while the flow patterns of gas and associated water within the wellbore constantly change, resulting in significant dynamic fluctuations in wellhead pressure.

[0003] In existing technologies, the analysis of formation pressure, bottomhole flowing pressure, and wellhead pressure in fractured-vuggy gas reservoirs often employs step-by-step or coupled calculation methods. Within a given production time step, formation pressure is typically calculated first based on mass balance relationships, then bottomhole flowing pressure is calculated using formation pressure as a boundary condition, and finally, wellhead pressure is calculated using a wellbore pressure drop model. While these methods can reflect the pressure variation patterns of the formation-wellbore system to some extent, wellhead pressure is usually only used as a calculation result or checksum in the analysis, lacking a state correction decision-making mechanism based on wellhead pressure feedback.

[0004] When there is a deviation between the calculated wellhead pressure and the measured wellhead pressure, existing methods often correct it by adjusting overall parameters or blindly iterating, which makes it difficult to effectively distinguish the source of the deviation and easily causes numerical oscillations or non-physical convergence, thus affecting the stability and reliability of the pressure dynamic analysis results. Therefore, it is necessary to propose a state-adaptive correction method based on wellhead pressure feedback to achieve reasonable correction of the state of the formation-wellbore system in fractured-vuggy gas reservoirs. Summary of the Invention

[0005] The purpose of this invention is to provide an adaptive correction method for the state of the formation-wellbore system in fractured-vuggy gas reservoirs. By using wellhead pressure as a feedback control signal and formation pressure and bottom hole flowing pressure as system state variables, a correction criterion and correction path selection mechanism based on wellhead pressure deviation are constructed to achieve adaptive correction and stable convergence of the system state.

[0006] To achieve the above objectives, this invention provides an adaptive correction method for the state of a fractured-vuggy gas reservoir formation-wellbore system, the method comprising the following steps: S100, Control Target and Initial State Setting; S101. Obtain time-series data of the gas well during the production process, including Daily gas production within a day Daily water production Measured wellhead pressure The control objective is to minimize the deviation between the calculated wellhead pressure and the measured wellhead pressure, and the measured wellhead pressure is set as the control objective. As a feedback signal, it is used to generate subsequent state correction criteria; S102, Input the original formation pressure Formation temperature Dynamic reserves and capacity index Calculate the initial gas compressibility factor And obtain the initial ratio. ; S200, Update production time step state constraints; S201, in the same production time step Internally, based on daily gas production Update cumulative gas production Calculate the cumulative gas production ,in For the first The cumulative gas production of all gas wells in the world is expressed in tens of thousands of cubic meters. This cumulative gas production serves as a constraint input for predicting formation pressure state. S300, Formation pressure state prediction and nonlinear constraint solution of compressibility factor; S301, at the time step Internal, dynamic storage based on input With cumulative gas production Establish formation pressure With compressibility factor State constraints: ; in This represents the original formation pressure of the gas well, in MPa. The compressibility factor under original formation pressure, in decimal form; dynamic reserves. This represents the dynamic reserves of the gas well, expressed in tens of thousands of cubic meters. For gas well production The pressure of the earth's crust, measured in MPa; For gas well production The compressibility factor under geological pressure, expressed as a decimal. S302, The nested iteration is used to generate predicted values ​​of formation pressure state variables, due to the gas compressibility factor. Z With formation pressure P There is a nonlinear relationship between them at the time step. i The internal method employs a nested iterative approach to simultaneously solve for formation pressure. With the corresponding compression factor The solution method involves using any positive value as the initial conjecture for the compression factor. Update according to the following iterative relationship: ; ; in The (n+1)th iteration obtained The pressure between the top and bottom layers, measured in MPa. and This represents the compression factor for the nth and (n+1)th iterations, expressed as a decimal. Formation temperature, in Kelvin (K). This is a function for calculating the gas compressibility factor based on pressure and temperature. S303, when satisfied When considering the convergence condition, it is assumed that the first... The calculation of the formation pressure for the day is complete, among which The preset convergence threshold is used as the basis for determining the convergence value. , As the first The corresponding formation pressure and compressibility factor; S400, bottom hole flowing pressure state variable prediction; S401, at the time step Within, based on the formation pressure obtained in the current iteration As a wellbore pressure supply condition, combined with the production capacity index and daily gas production Calculating bottom hole flowing pressure based on the production capacity relationship in the form of square pressure. Production capacity relationship in the form of square pressure The formula for bottom hole flowing pressure is derived. The predicted value of the bottom hole flowing pressure state within the production time step is obtained. ; in For the first The calculated bottom hole pressure is given in MPa. For the first Daily gas production volume, expressed in 10,000 cubic meters per day; S500, system output calculation, wellhead pressure status output; S501, at the time step Inside, with the bottom hole flowing pressure As the boundary condition at the bottom of the wellbore, based on the daily gas production Daily water production Based on the wellbore geometric parameters and fluid properties, the pressure loss from the bottom of the well to the wellhead is calculated, and the theoretical wellhead pressure is obtained. ， The theoretical wellhead pressure is used as the system state output. S502. Divide the wellbore into several calculation segments along the wellbore axis from the bottom to the wellhead. Within each calculation segment, the total pressure drop of the wellbore is determined by gravity pressure drop. Frictional pressure drop and accelerate pressure drop It consists of three parts: ; in The density of the gas-liquid two-phase mixture is expressed in kg / m³. The apparent velocity of gas-water mixing is expressed in m / s. This refers to the inner diameter of the well shaft, in meters (m). The coefficient of friction is dimensionless. To calculate the segment length, the unit is meters. The unit for calculating the change in the velocity of the mixed phase within the section is m / s; S503. Accumulate the pressure drop of each calculated segment along the well depth direction to obtain the first segment. Wellhead pressure at each time step ,in For the first Calculate the wellhead pressure for the day; S600, state correction control based on wellhead pressure feedback, convergence criteria and time step advancement; the convergence condition includes at least the deviation constraint between the wellhead pressure and the measured wellhead pressure. S601, the theoretical wellhead pressure Measured wellhead pressure at the corresponding time step Compare and calculate the wellhead pressure deviation, when the formation pressure Gas compressibility factor Bottom hole flowing pressure and wellhead pressure When all preset convergence conditions are met, the time step is determined. i The calculation results are then used to advance to the next time step; S602. When the wellhead pressure deviation exceeds a preset threshold, a correction criterion is generated based on the direction, amplitude and trend of the wellhead pressure deviation to determine the dominant influence of formation pressure or bottom hole flowing pressure on the deviation. The corresponding state variables are selectively corrected and iterated in reverse to achieve adaptive adjustment of the system state and avoid non-physical convergence. Attached Figure Description

[0007] Figure 1 This is the technical roadmap for this method; Figure 2This is a schematic diagram comparing the bottom hole flowing pressure calculated using the method of this invention with the corresponding measured bottom hole flowing pressure; Figure 3 This is a schematic diagram comparing the wellhead pressure calculated using the method of this invention with the corresponding measured wellhead pressure. Detailed Implementation

[0008] This invention provides an adaptive correction method for the state of the formation-wellbore system in fractured-vuggy gas reservoirs. Figure 1 This is the technical roadmap for this method. For a fractured-vuggy gas well in China, the following steps are implemented: S100: A fractured-vuggy reservoir gas well in China was selected as the calculation object, and its production time series data, including the original formation pressure, was obtained. Formation temperature Dynamic reserves and capacity index And obtain the production time series and daily gas production during the gas well production process. Daily water production Measured wellhead pressure The pressure unit is MPa, and the gas volume unit is 10. 4 m³ / d, temperature unit is K; The measured wellhead pressure is used as a feedback control signal, and the control objective is determined to be minimizing the deviation between the calculated wellhead pressure and the measured wellhead pressure. S200: According to the production time sequence, with one day as a production time step. i Within the stated time step, the cumulative gas production is updated based on the daily gas production, establishing the relationship between the cumulative gas production and time, expressed as follows: ,in For the first The total gas production of all gas wells in the world, in units of 10. 4 m³, the cumulative gas production is used as an important constraint parameter for subsequent formation pressure state prediction, and is dynamically updated with each production time step throughout the calculation process; S300: At each production time step Within this context, based on cumulative gas production and dynamic reserves, a material balance constraint relationship is established for fractured-vuggy gas reservoirs. ,in This represents the original formation pressure of the gas well, in MPa. The compressibility factor under original formation pressure, in decimal form; dynamic reserves. This represents the dynamic reserves of the gas well, expressed in tens of thousands of cubic meters. For gas well production The pressure of the earth's crust, measured in MPa; For gas well productioni The compressibility factor under formation pressure is expressed as a decimal. Due to the significant nonlinear relationship between the gas compressibility factor and formation pressure, a nested iterative approach is used to solve for formation pressure and the gas compressibility factor within the production time step. Specifically, firstly, given an initial guess value for the gas compressibility factor, the corresponding formation pressure is calculated based on the mass balance relationship; then, based on the updated formation pressure, the gas compressibility factor is recalculated, and the above process is repeated until a preset convergence condition is met, thus determining the predicted formation pressure state value within that time step.

[0009] S400: During the production time step Within the current time step, the converged formation pressure is used as the wellbore pressure supply condition. Combined with the production capacity index and the daily gas production, the bottom hole flowing pressure state variables within the corresponding time step are calculated based on the production capacity relationship in the form of square pressure. Step 5: Within the same production time step, using the bottom flow pressure as the boundary condition of the wellbore bottom, and combining the daily gas production, daily water production and wellbore structural parameters, the wellbore is calculated in segments. Taking into account gravity pressure drop, friction pressure drop and acceleration pressure drop, the theoretical wellhead pressure under that time step is accumulated segment by segment and used as the system state output. Step 6: Compare the calculated theoretical wellhead pressure with the measured wellhead pressure at the corresponding time step to calculate the wellhead pressure deviation. When the wellhead pressure deviation exceeds a preset threshold, a correction criterion is generated based on the direction, amplitude, and trend of the wellhead pressure deviation, and a correction decision is made accordingly. The dominant influence of formation pressure or bottom hole flowing pressure on the deviation is determined, and the corresponding state variables are selectively subjected to reverse correction iteration.

[0010] When the wellhead pressure deviation, formation pressure, and bottomhole flowing pressure simultaneously meet the preset convergence conditions, the calculation results for that production time step are determined, and the process is advanced to the next production time step. If the convergence conditions are not met, the state prediction and adaptive correction process continues to be executed within the current production time step.

[0011] Step 7: Using the aforementioned state-adaptive correction method, the daily pressure dynamic response during gas well production is calculated to obtain the results of formation pressure, bottom hole flowing pressure, and wellhead pressure changes over time. The calculated wellhead pressure is then compared with the field-measured wellhead pressure; the trends are as follows: Figure 3 As shown; the calculated bottom hole flowing pressure is compared with the measured bottom hole flowing pressure, and the results are as follows. Figure 2 As shown in the figure. The results show that the method of the present invention can comprehensively consider dynamic reserve parameters and production parameters within the same calculation process, and realize adaptive correction of the formation-wellbore system state of fractured-vuggy gas reservoirs, verifying the applicability and effectiveness of the method in the dynamic pressure analysis of gas wells in fractured-vuggy gas reservoirs.

[0012] Compared with the prior art, the present invention has the following beneficial effects: (1) By introducing a unified state prediction and correction mechanism for formation pressure, bottom hole flowing pressure and wellhead pressure based on wellhead pressure feedback within the same production time step, the problem of independent pressure parameters and inconsistent results in the traditional step-by-step calculation method is avoided, and the coordinated update of the pressure state of the formation-wellbore system is realized; (2) The simultaneous satisfaction of multiple state variables with preset convergence conditions is used as the basis for advancing the production time step, and a feedback correction control process is introduced within the time step, which effectively avoids non-physical calculations and numerical oscillations that may occur during the calculation process, and improves the stability and reliability of the pressure dynamic analysis process; (3) The wellhead pressure is transformed from a simple calculation result or verification quantity into a feedback control signal. , and as one of the state correction constraints, the measured wellhead pressure can reverse the correction process of formation pressure and bottom hole flowing pressure, improving the consistency between the pressure dynamic analysis results and the actual production data; (4) By introducing an adaptive correction path selection mechanism based on wellhead pressure deviation, the dominant influence of formation pressure or bottom hole flowing pressure on deviation can be dynamically judged according to the deviation characteristics, avoiding numerical oscillation and non-physical convergence problems caused by blind overall iteration in traditional coupled calculation; (5) Without the need to introduce complex numerical simulation or high-dimensional parameter inversion, the unified calculation and adaptive correction of the pressure state of the fractured-vuggy gas reservoir formation-wellbore system are realized. The calculation efficiency is high, the engineering implementation difficulty is low, and it has strong engineering applicability and promotion value.

[0013] Finally, it should be noted that the above embodiments are only used to illustrate and not limit the technical solutions of the present invention. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art should understand that modifications or equivalent substitutions can still be made to the present invention without departing from the spirit and scope of the present invention. Any modifications or partial substitutions should be covered within the scope of the claims of the present invention.

Claims

1. A method for adaptive correction of the state of a fractured-vuggy gas reservoir formation-wellbore system, characterized in that, The method uses the measured wellhead pressure during gas well production as the feedback control signal. Within the same production time step, formation pressure and bottom hole flowing pressure are used as state variables characterizing the operating state of the formation-wellbore system. Through dynamic analysis of the wellhead pressure deviation, an adaptive formation-wellbore state correction path is selected to achieve controlled convergence of the wellhead pressure deviation. The minimization of the wellhead pressure deviation is used as the control objective. The formation pressure and bottom hole flowing pressure constitute the system state variable set, and the theoretical wellhead pressure is the state output. The method includes the following steps: S100, Control Target and Initial State Setting; S101. Obtain time-series data of the gas well during the production process, including Daily gas production within a day Daily water production Measured wellhead pressure The control objective is to minimize the deviation between the calculated wellhead pressure and the measured wellhead pressure, and the measured wellhead pressure is set as the control objective. As a feedback signal, it is used to generate subsequent state correction criteria; S102, Input the original formation pressure Formation temperature Dynamic reserves and capacity index Calculate the initial gas compressibility factor And obtain the initial ratio. ; S200, Update production time step state constraints; S201, in the same production time step Internally, based on daily gas production Update cumulative gas production Calculate the cumulative gas production ,in For the first The cumulative gas production of all gas wells in the world, in ten thousand cubic meters, is used as a constraint input for predicting formation pressure state. S300, Formation pressure state prediction and nonlinear constraint solution of compressibility factor; S301, at the time step Internal, dynamic storage based on input With cumulative gas production Establish formation pressure With compressibility factor State constraints: ； in This represents the original formation pressure of the gas well, in MPa. The compressibility factor under original formation pressure; dynamic reserves This represents the dynamic reserves of the gas well, expressed in tens of thousands of cubic meters. For gas well production The pressure of the earth's crust, measured in MPa; For gas well production The compressibility factor under the pressure of the earth's strata; S302, Nested iteration is used to generate predicted values ​​of formation pressure state variables, due to the gas compressibility factor. Z With formation pressure P There is a nonlinear relationship between them at the time step. i The internal method employs a nested iterative approach to simultaneously solve for formation pressure. With the corresponding compression factor The solution method involves using any positive value as the initial conjecture for the compression factor. Update according to the following iterative relationship: ； ； in The (n+1)th iteration obtained The pressure between the top and bottom layers, measured in MPa. and Let be the compression factor for the nth and (n+1)th iterations; Formation temperature, in Kelvin (K). This is a function for calculating the gas compressibility factor based on pressure and temperature. S303, when satisfied When considering the convergence condition, it is assumed that the first... The calculation of the formation pressure for the day is complete, among which The preset convergence threshold is used as the basis for determining the convergence value. , As the first The corresponding formation pressure and compressibility factor; S400, bottom hole flowing pressure state variable prediction; S401, at the time step Within, based on the formation pressure obtained in the current iteration As a wellbore pressure supply condition, combined with the production capacity index and daily gas production Calculating bottom hole flowing pressure based on the production capacity relationship in the form of square pressure. Production capacity relationship in the form of square pressure The formula for bottom hole flowing pressure is derived. The predicted value of the bottom hole flowing pressure state within the production time step is obtained. ; in For the first The calculated bottom hole pressure is given in MPa. For the first Daily gas production volume, expressed in 10,000 cubic meters per day; S500, system output calculation, wellhead pressure status output; S501, at the time step Inside, with the bottom hole flowing pressure As the boundary condition at the bottom of the wellbore, based on the daily gas production Daily water production Based on the wellbore geometric parameters and fluid properties, the pressure loss from the bottom of the well to the wellhead is calculated, and the theoretical wellhead pressure is obtained. ， The theoretical wellhead pressure is used as the system state output. S502. Divide the wellbore into several calculation segments along the wellbore axis from the bottom to the wellhead. Within each calculation segment, the total pressure drop of the wellbore is determined by gravity pressure drop. Frictional pressure drop and accelerate pressure drop It consists of three parts: ； in The density of the gas-liquid two-phase mixture is expressed in kg / m³. The apparent velocity of gas-water mixing is expressed in m / s. This refers to the inner diameter of the well shaft, in meters (m). The coefficient of friction is dimensionless. To calculate the segment length, the unit is meters. The unit for calculating the change in the velocity of the mixed phase within the section is m / s; The acceleration due to gravity is taken as 9.81 m / s². 2 , used to characterize the gravitational pressure difference generated by a fluid column under the action of a height difference; S503. Accumulate the pressure drop of each calculated segment along the well depth direction to obtain the first segment. Wellhead pressure at each time step ,in For the first Calculate the wellhead pressure for the day; S600, state correction control based on wellhead pressure feedback, convergence criteria and time step advancement; the convergence condition includes at least the deviation constraint between the wellhead pressure and the measured wellhead pressure. S601, the theoretical wellhead pressure Measured wellhead pressure at the corresponding time step Compare and calculate the wellhead pressure deviation, when the formation pressure Gas compressibility factor Bottom hole flowing pressure and wellhead pressure When all preset convergence conditions are met, the time step is determined. i The calculation results are then used to advance to the next time step; S602. When the wellhead pressure deviation exceeds a preset threshold, a correction criterion is generated based on the direction, amplitude and trend of the wellhead pressure deviation to determine the dominant influence of formation pressure or bottom hole flowing pressure on the deviation. The corresponding state variables are selectively corrected and iterated in reverse to achieve adaptive adjustment of the system state and avoid non-physical convergence.

2. The adaptive correction method for the formation-wellbore system state of a fractured-vuggy gas reservoir according to claim 1, characterized in that: The predicted formation pressure state is obtained by using a nested iterative solution of formation pressure and gas compressibility factor based on the material balance constraint relationship between cumulative gas production and dynamic reserves.

3. The adaptive correction method for the state of a fractured-vuggy gas reservoir formation-wellbore system according to claim 1, characterized in that: The theoretical wellhead pressure is obtained by using the bottom-hole flowing pressure as the boundary condition at the bottom of the wellbore and calculating the segmented pressure drop of the wellbore. The segmented pressure drop includes gravity pressure drop, friction pressure drop, and acceleration pressure drop.

4. The adaptive correction method for the state of a fractured-vuggy gas reservoir formation-wellbore system according to claim 1, characterized in that: The correction criteria include at least the absolute value of the wellhead pressure deviation, the trend of deviation change, and the evolution characteristics of the deviation within adjacent production time steps.

5. The adaptive correction method for the state of a fractured-vuggy gas reservoir formation-wellbore system according to claim 1, characterized in that: The dominant judgment is made by applying preset disturbances to the formation pressure and bottom hole flowing pressure respectively, calculating the sensitivity of the wellhead pressure deviation to the disturbances, and selecting the state variable with greater sensitivity as the priority correction target.

6. The adaptive correction method for the state of a fractured-vuggy gas reservoir formation-wellbore system according to claim 1, characterized in that: During the adaptive reverse correction iteration process, if the wellhead pressure deviation does not decrease or oscillates within a preset number of iterations, the correction step size is reduced or the correction path is switched to ensure convergence stability.

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