Tight sandstone gas reservoir water-producing gas well classification method

Abstract

The invention discloses a tight sandstone gas reservoir water-producing gas well classification method. The method comprises the steps that the wellbore liquid accumulation height of a water-producing gas well applied to the tight sandstone gas reservoir is obtained, and the wellbore liquid accumulation height is obtained by conducting gas well liquid level testing on the water-producing gas well; classifying the water-producing gas wells on the basis of the wellbore liquid accumulation height, and determining primary classification results of the water-producing gas wells and secondary classification parameters corresponding to the primary classification results; classifying the water-producing gas wells by adopting the secondary classification parameters to obtain secondary classification results of the water-producing gas wells; and determining a drainage gas recovery control strategy corresponding to the secondary classification result. According to the invention, the technical problem that a gas well classification method for the water-producing gas well according to the water-producing characteristic parameters and the development of production countermeasures are not involved in the prior art is solved.

Description

Technical Field

[0001] The invention relates to the technical field of natural gas development, and in particular to a method for classifying water-producing gas wells in tight sandstone gas reservoirs. Background Art

[0002] Gas well classification is an important method for achieving fine management of gas wells in gas field development. By classifying and analyzing gas wells with the same production characteristics, the production status of gas wells can be quickly analyzed, effective production countermeasures can be taken in time, and accurate management of gas wells can be achieved to increase production. The classification characteristic parameters used in related technologies are mainly gas production, pressure, predicted final cumulative gas production (EUR) and rate of return. Their goals are to clarify the final cumulative gas production (EUR) of gas wells or evaluate the development benefits of gas wells. Without combining gas well drainage and gas production measures, they cannot be used to classify water-producing gas wells and cannot guide the formulation of production countermeasures for water-producing gas wells.

[0003] To address the above-mentioned problems, no effective solution has been proposed yet. Summary of the invention

[0004] The embodiment of the present invention provides a method for classifying water-producing gas wells in a tight sandstone gas reservoir, so as to at least solve the technical problem in the related art that a method for classifying water-producing gas wells according to water production characteristic parameters and developing production countermeasures are not involved.

[0005] According to one aspect of an embodiment of the present invention, a method for classifying water-producing gas wells in tight sandstone gas reservoirs is provided, comprising: obtaining a wellbore liquid accumulation height of a water-producing gas well applied to a tight sandstone gas reservoir, wherein the wellbore liquid accumulation height is obtained by performing a gas well liquid surface test on the water-producing gas well; classifying the water-producing gas wells based on the wellbore liquid accumulation height, determining a primary classification result of the water-producing gas wells, and a secondary classification parameter corresponding to the primary classification result; classifying the water-producing gas wells using the secondary classification parameter to obtain a secondary classification result of the water-producing gas wells; and determining a water drainage and gas production control strategy corresponding to the secondary classification result.

[0006] Optionally, the wellbore liquid accumulation height of the water-producing gas well applied to the tight sandstone gas reservoir is obtained, wherein the wellbore liquid accumulation height is obtained by performing a gas well liquid surface test on the water-producing gas well; based on the wellbore liquid accumulation height, the water-producing gas well is classified to determine the primary classification result of the water-producing gas well and the secondary classification parameters corresponding to the primary classification result; the water-producing gas well is classified using the secondary classification parameters to obtain the secondary classification result of the water-producing gas well; and the water drainage and gas production control strategy corresponding to the secondary classification result is determined.

[0007] Optionally, determining the secondary classification parameters corresponding to the primary classification result includes: when the primary classification result is that the water-producing gas well belongs to a non-liquid accumulation well, determining the secondary classification parameters corresponding to the non-liquid accumulation well includes: the water-gas ratio, average daily gas production, critical liquid carrying flow rate and critical water-gas ratio of the water-producing gas well, wherein the water-gas ratio is the ratio of the average daily water production of the water-producing gas well to the average daily gas production, the critical liquid carrying flow rate is obtained by processing using a preset critical liquid carrying flow rate model based on the inner diameter of the gas well tubing and the high-pressure physical properties of the fluid, and the critical water-gas ratio is the water-gas ratio of the wellbore of the water-producing gas well when the dispersed phase in the form of liquid droplets is converted into the liquid phase.

[0008] Optionally, the adopting of corresponding secondary classification parameters to classify the water-producing gas wells and determine the secondary classification results of the water-producing gas wells includes: when the water-gas ratio is less than the critical water-gas ratio and the average daily gas production is greater than the critical liquid-carrying flow rate, determining the non-liquid-filled well as a first type of non-liquid-filled well; when the water-gas ratio is greater than the critical water-gas ratio and the average daily gas production is greater than the critical liquid-carrying flow rate, determining the non-liquid-filled well as a second type of non-liquid-filled well, wherein the liquid content in the first type of non-liquid-filled well is less than the liquid content in the second type of non-liquid-filled well; when the water-gas ratio is greater than the critical water-gas ratio and the average daily gas production is less than the critical liquid-carrying flow rate, determining the non-liquid-filled well as a third type of non-liquid-filled well, wherein the liquid content in the second type of non-liquid-filled well is less than the liquid content in the third type of non-liquid-filled well.

[0009] Optionally, determining the drainage and gas production control strategy corresponding to the secondary classification result includes: determining a first non-liquid-filled strategy corresponding to the first type of non-liquid-filled wells, wherein the first non-liquid-filled strategy includes monitoring the daily gas production of the water-producing gas wells; when the daily gas production drops to the critical liquid-carrying flow rate, using a foam drainage method to perform gas production treatment on the first type of non-liquid-filled wells; determining a second non-liquid-filled strategy corresponding to the second type of non-liquid-filled wells, wherein the second non-liquid-filled strategy includes monitoring the daily gas production and daily water production of the water-producing gas wells; in the case where the daily gas production decreases, or when the daily gas production change is less than a predetermined change threshold and the monomer water production increases, determining a preset plurality of drainage and gas production methods. The first target gas production method among the multiple water drainage gas production methods; adopting the first target gas production method to perform gas production treatment on the second type of non-liquid-filled wells; determining the third non-liquid-filled strategy corresponding to the third type of non-liquid-filled wells, wherein the third non-liquid-filled strategy includes obtaining the oil pressure differential and the casing pressure differential of the third type of non-liquid-filled wells; when the oil pressure differential increases and the casing pressure differential increases, determining the second target gas production method among the multiple water drainage gas production methods; adopting the second target gas production method to perform gas production treatment on the third type of non-liquid-filled wells, wherein the casing pressure differential is the flow pressure in the third type of non-liquid-filled well minus the pressure of the liquid column and the gas column in the casing, and the oil pressure differential is the flow pressure in the third type of non-liquid-filled well minus the pressure of the oil-gas mixed liquid column in the well, friction resistance and slip loss.

[0010] Optionally, the critical liquid carrying flow model is obtained based on droplet theory, and includes at least one of the following: Turner model, Li Min model, Cloeman model, Nosseir model.

[0011] Optionally, determining the secondary classification parameters corresponding to the primary classification result includes: when the primary classification result is that the water-producing gas well belongs to a liquid accumulation well, determining the secondary classification parameters corresponding to the liquid accumulation well includes: the liquid accumulation height of the wellbore, the average daily water production, the first liquid accumulation height, the second liquid accumulation height, the third liquid accumulation height, and the forced drainage threshold, wherein the first liquid accumulation height is the liquid accumulation height applicable when plunger drainage is adopted, the second liquid accumulation height is the liquid accumulation height applicable when plunger-assisted drainage is adopted, the third liquid accumulation height is the liquid accumulation height applicable when pumping equipment is forcedly discharged, the first liquid accumulation height is less than the second liquid accumulation height, the second liquid accumulation height is less than the third liquid accumulation height, the plunger-assisted drainage is a method of combining plunger drainage and foam drainage, and the forced drainage threshold is the predetermined daily water production of the pumping equipment.

[0012] Optionally, the corresponding secondary classification parameters are used to classify the water-producing gas wells to determine the secondary classification results of the water-producing gas wells, including: when the average daily water production is less than the forced discharge threshold and the wellbore liquid accumulation height is less than the first liquid accumulation height, the liquid accumulation well is classified to determine that the liquid accumulation well is a first type of liquid accumulation well; when the average daily water production is less than the forced discharge threshold and the wellbore liquid accumulation height is greater than the first liquid accumulation height and less than the second liquid accumulation height, the liquid accumulation well is classified to determine that the liquid accumulation well is a second type of liquid accumulation well, wherein the liquid content in the first type of liquid accumulation well is less than the liquid content in the second type of liquid accumulation well.

[0013] Optionally, the use of corresponding secondary classification parameters to classify the water-producing gas wells and determine the secondary classification results of the water-producing gas wells includes: when the average daily water production is less than the strong discharge threshold, and the wellbore liquid accumulation height is greater than the second liquid accumulation height and less than the third liquid accumulation height, classifying the liquid accumulation well to determine that the liquid accumulation well is a third type of liquid accumulation well, wherein the liquid content in the second type of liquid accumulation well is less than the liquid content in the third type of liquid accumulation well; when the average daily water production is less than the strong discharge threshold and the wellbore liquid accumulation height is greater than the third liquid accumulation height, classifying the liquid accumulation well to determine that the liquid accumulation well is a fourth type of liquid accumulation well, wherein the liquid content in the third type of liquid accumulation well is less than the liquid content in the fourth type of liquid accumulation well; when the average daily water production is greater than the strong discharge threshold, classifying the liquid accumulation well to determine that the liquid accumulation well is a fifth type of liquid accumulation well, wherein the liquid content in the fourth type of liquid accumulation well is less than the liquid content in the fifth type of liquid accumulation well.

[0014] Optionally, determining the drainage and gas production control strategy corresponding to the secondary classification result includes: determining a first liquid accumulation strategy corresponding to the first type of liquid accumulation well, wherein the first liquid accumulation strategy includes adopting a foam drainage method, and the first type of liquid accumulation well performs gas production processing; determining a second liquid accumulation strategy corresponding to the second type of liquid accumulation well, wherein the second liquid accumulation strategy includes adopting a plunger drainage method, and the second type of liquid accumulation well performs gas production processing.

[0015] Optionally, determining the drainage and gas production control strategy corresponding to the secondary classification result includes: determining a third liquid accumulation strategy corresponding to the third category of liquid accumulation wells, wherein the third liquid accumulation strategy includes adopting the plunger drainage method to perform gas production on the third category of liquid accumulation wells to obtain the plunger gas production of the third category of liquid accumulation wells; when the plunger gas production is lower than a preset switching threshold, using a compressor to perform gas production on the third category of liquid accumulation wells; determining a fourth liquid accumulation strategy corresponding to the fourth category of liquid accumulation wells, wherein the fourth liquid accumulation strategy includes adopting the gas lift drainage and gas production method to drain the fourth category of liquid accumulation wells; when the fourth category of liquid accumulation wells are drained, the fourth category of liquid accumulation wells are subjected to gas production; determining a fifth liquid accumulation strategy corresponding to the fifth category of liquid accumulation wells, wherein the fifth liquid accumulation strategy includes adopting the forced drainage and pumping method to perform gas production on the fifth category of liquid accumulation wells.

[0016] In an embodiment of the present invention, the wellbore liquid accumulation height of a water-producing gas well applied to a tight sandstone gas reservoir is obtained, wherein the wellbore liquid accumulation height is obtained by testing the gas well liquid surface of the water-producing gas well; based on the wellbore liquid accumulation height, the water-producing gas well is classified, and the primary classification result of the water-producing gas well and the secondary classification parameters corresponding to the primary classification result are determined; the water-producing gas well is classified using the secondary classification parameters to obtain the secondary classification result of the water-producing gas well; and the drainage and gas production control strategy corresponding to the secondary classification result is determined. The purpose of improving the accuracy of classifying water-producing gas wells and then carrying out corresponding production countermeasures for different water-producing gas wells is achieved, and the technical effect of increasing the production of water-producing gas wells is achieved, thereby solving the technical problem in the related art that a gas well classification method is established according to water production characteristic parameters and production countermeasures are carried out for water-producing gas wells. BRIEF DESCRIPTION OF THE DRAWINGS

[0017] The drawings described herein are used to provide a further understanding of the present invention and constitute a part of this application. The exemplary embodiments of the present invention and their descriptions are used to explain the present invention and do not constitute an improper limitation of the present invention. In the drawings:

[0018] Figure 1 is a flow chart of an optional method for classifying water-producing gas wells in tight sandstone gas reservoirs provided according to an embodiment of the present invention;

[0019] Figure 2 It is a schematic flow chart of an optional tight sandstone gas reservoir water-producing gas well classification device provided according to an embodiment of the present invention;

[0020] Figure 3 It is a schematic diagram of an optional tight sandstone gas reservoir water-producing gas well classification device provided according to an embodiment of the present invention. DETAILED DESCRIPTION

[0021] In order to enable those skilled in the art to better understand the scheme of the present invention, the technical scheme in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work should fall within the scope of protection of the present invention.

[0022] It should be noted that the terms "first", "second", etc. in the specification and claims of the present invention and the above-mentioned drawings are used to distinguish similar objects, and are not necessarily used to describe a specific order or sequence. It should be understood that the data used in this way can be interchanged where appropriate, so that the embodiments of the present invention described herein can be implemented in an order other than those illustrated or described herein. In addition, the terms "including" and "having" and any variations thereof are intended to cover non-exclusive inclusions, for example, a process, method, system, product or device that includes a series of steps or units is not necessarily limited to those steps or units that are clearly listed, but may include other steps or units that are not clearly listed or inherent to these processes, methods, products or devices.

[0023] Gas well classification is an important method to achieve fine management of gas wells in gas field development. By classifying and analyzing gas wells with the same production characteristics, clarifying the common production laws of gas wells, and establishing gas well classification standards, we can quickly analyze the production status of gas wells, take effective production countermeasures in time, and achieve precise management of gas wells.

[0024] In the field of gas reservoir engineering, gas well classification mainly considers indicators such as the open-flow rate of the gas well, the production at a certain stage, the gas production per unit pressure drop, and the final cumulative gas production. In a related technology disclosed in "Gas Well Classification Method Based on Production Data Feature Analysis" Petroleum Drilling and Production Technology 2021, the residual pressure of the gas well, the current gas production, the amount of gas replenishment in the closed-well formation, the current water production, the standard deviation of the water-gas ratio and other indicators are considered, and the linear discriminant analysis method is used to establish a gas well classification method based on production data analysis, but it does not involve adaptive production countermeasures for gas wells to increase production.

[0025] In another related technology, two reservoir physical parameters, namely energy storage coefficient and formation coefficient, are used statically, and four parameters, namely cumulative gas production during the stable production period, average daily gas production during the stable production period, average daily gas production and gas production per unit pressure drop, are used dynamically. The orthogonal matrix method is used to establish a gas well classification standard, and the impact of relevant characteristics of water-producing gas wells on production is not considered.

[0026] The invention patent "Shale Gas Well Classification Method, Device, Equipment and Storage Medium" with application publication number CN114077855A discloses a method for classifying gas wells based on the relative positions of cumulative production, wellhead pressure curve and benchmark relationship curve. It does not involve characteristic parameters such as liquid accumulation height, water production, water-gas ratio, critical liquid carrying flow rate, etc., and does not involve a water-producing gas well classification method to guide the formulation of production strategies for gas wells.

[0027] The patent "Method and device for determining the final cumulative production of gas wells" with application publication number CN109252855A discloses a method for classifying gas wells in a target area based on a comprehensive classification coefficient, test production during production testing, average daily gas production in the first year of production, and internal rate of return of the gas wells.

[0028] The classification characteristic parameters used in the above methods are mainly gas production, pressure, predicted final cumulative gas production (EUR) and rate of return. Their goals are to clarify the final cumulative gas production (EUR) of gas wells or to evaluate the development benefits of gas wells. They are not combined with gas well drainage and gas production measures, and cannot be used to classify water-producing gas wells, nor can they guide the formulation of production strategies for water-producing gas wells, and fail to provide support for the production increase of water-producing wells.

[0029] In response to the above problems, an embodiment of the present invention provides a method embodiment for classifying water-producing gas wells in tight sandstone gas reservoirs. It should be noted that the steps shown in the flowchart in the accompanying drawings can be executed in a computer system such as a set of computer executable instructions, and although a logical order is shown in the flowchart, in some cases, the steps shown or described may be executed in an order different from that shown here.

[0030] Figure 1 FIG. 1 is a flow chart of a method for classifying water-producing gas wells in a tight sandstone gas reservoir according to an embodiment of the present invention. Figure 1 As shown, the method comprises the following steps:

[0031] Step S102, obtaining a wellbore liquid accumulation height of a water-producing gas well in a tight sandstone gas reservoir, wherein the wellbore liquid accumulation height is obtained by performing a gas well liquid level test on the water-producing gas well;

[0032] It can be understood that the liquid level test of the water-producing gas well is performed to obtain the wellbore liquid accumulation height of the water-producing gas well. The wellbore liquid accumulation height is conducive to the preliminary characterization of the liquid content of the water-producing gas well.

[0033] Optionally, there are many ways to test the liquid level in a gas well. For example, one way is to use a pressure gauge to test the liquid level. A pressure gauge is placed in the gas well oil pipe to test the pressure at different depths. The height of the accumulated liquid is determined by plotting the relationship between pressure and depth and finding the pressure gradient change point. Another way is to use an echo sounder to test the liquid level. The height of the accumulated liquid is determined by using the reflection principle of the echo at the gas-water interface.

[0034] Step S104, classifying the water-producing gas wells based on the wellbore liquid accumulation height, and determining the primary classification results of the water-producing gas wells and the secondary classification parameters corresponding to the primary classification results;

[0035] It can be understood that based on the above-mentioned wellbore liquid accumulation height, the above-mentioned water-producing gas wells are classified, and the liquid content of the water-producing gas wells is preliminarily perceived to determine the primary classification results of the water-producing gas wells. According to the above-mentioned primary classification results, the secondary classification parameters corresponding to the primary classification results are determined. It should be noted that different primary classification results will correspond to secondary classification parameters, which are used to refine the classification of water-producing gas wells, thereby achieving refined control and increasing the production of water-producing gas wells.

[0036] In an optional embodiment, determining the secondary classification parameters corresponding to the above-mentioned primary classification results includes: when the above-mentioned primary classification result is that the above-mentioned water-producing gas well belongs to a non-liquid accumulation well, determining the secondary classification parameters corresponding to the above-mentioned non-liquid accumulation well includes: the water-gas ratio of the above-mentioned water-producing gas well, the average daily gas production, the critical liquid carrying flow rate and the critical water-gas ratio, wherein the above-mentioned water-gas ratio is the ratio of the average daily water production of the above-mentioned water-producing gas well to the average daily gas production, the above-mentioned critical liquid carrying flow rate is obtained by processing based on the inner diameter of the gas well tubing and the high-pressure physical properties of the fluid using a preset critical liquid carrying flow rate model, and the above-mentioned critical water-gas ratio is the water-gas ratio of the wellbore of the above-mentioned water-producing gas well from the existence of a liquid droplet-like dispersed phase to the existence of a liquid.

[0037] It can be understood that the primary classification results can be divided into liquid-filled wells or non-liquid-filled wells. When the primary classification result is that the water-producing gas well belongs to the non-liquid-filled well, the secondary classification parameters corresponding to the non-liquid-filled well are determined to include: the water-gas ratio of the water-producing gas well, the average daily gas production, the critical liquid-carrying flow rate and the critical water-gas ratio.

[0038] In an optional embodiment, the above critical liquid carrying flow model is obtained based on the droplet theory, and includes at least one of the following: Turner model, Li Min model, Cloeman model, Nosseir model.

[0039] It can be understood that the above critical liquid carrying flow model can be set according to specific needs. The Turner model, Li Min model, Cloeman model, Nosseir model, etc. are obtained based on the critical liquid carrying flow calculation method of the wellbore droplet model. The above droplet theory means that when the gas wellbore is dominated by annular mist flow, the droplets in the center of the wellbore are distributed in the form of discrete phases. At this time, the droplets are subject to three forces: buoyancy, gravity, and natural gas flow drag. When these three forces are balanced or the combined force is directed toward the wellhead, the droplets can be carried above the wellhead. When the combined force of the three forces is balanced, the minimum drag and buoyancy required to carry the droplets are corresponding, and then combined with parameters such as gas flow rate, gas-liquid surface tension, and pipe diameter to establish a critical liquid carrying flow calculation method to evaluate the minimum gas production required for the gas well to carry liquid autonomously.

[0040] It should be noted that the critical liquid-carrying flow model is a public model, which includes a variety of setting parameters. The above-mentioned multiple setting parameters are adjusted based on the type of gas field where the water-producing gas well is located and the gas field area to obtain the critical liquid-carrying flow model applicable to the gas field. The above-mentioned critical water-gas ratio is determined based on the critical liquid-carrying flow model with preset parameters. The corresponding condition is that the water-gas ratio is less than the critical water-gas ratio. The critical liquid-carrying flow model is still used and exists as a dispersed phase in the form of liquid droplets. The corresponding condition is that the water-gas ratio is greater than the critical water-gas ratio, the proportion of liquid in the wellbore increases significantly, and the liquid in the wellbore no longer exists as a dispersed phase in the form of liquid droplets. At this time, the critical liquid-carrying flow model is no longer applicable, and the relationship between the average daily gas production of the water-producing gas well and the critical liquid-carrying flow cannot be used as a basis for evaluating gas well liquid accumulation.

[0041] In an optional embodiment, determining the secondary classification parameters corresponding to the above-mentioned primary classification results includes: in the case where the above-mentioned primary classification result is that the above-mentioned water-producing gas well belongs to a liquid accumulation well, determining the secondary classification parameters corresponding to the above-mentioned liquid accumulation well includes: the above-mentioned wellbore liquid accumulation height, the average daily water production, the first liquid accumulation height, the second liquid accumulation height, the third liquid accumulation height, and the forced discharge threshold, wherein the above-mentioned first liquid accumulation height is the liquid accumulation height applicable when plunger drainage is adopted, the above-mentioned second liquid accumulation height is the liquid accumulation height applicable when plunger assisted drainage is adopted, the above-mentioned third liquid accumulation height is the liquid accumulation height applicable when water pumping equipment is forcedly discharged, the above-mentioned first liquid accumulation height is smaller than the above-mentioned second liquid accumulation height, the above-mentioned second liquid accumulation height is smaller than the above-mentioned third liquid accumulation height, the above-mentioned plunger assisted drainage is a method of combining plunger drainage and foam drainage, and the above-mentioned forced discharge threshold is the predetermined daily water production of the above-mentioned water pumping equipment.

[0042] It can be understood that for liquid-filled wells with greater liquid content than non-liquid-filled wells, the corresponding secondary classification parameters are also different. When the primary classification result is that the water-producing gas well is a liquid-filled well, the secondary classification parameters corresponding to the liquid-filled well include: wellbore liquid accumulation height, average daily water production, first liquid accumulation height, second liquid accumulation height, third liquid accumulation height, and forced discharge threshold.

[0043] Optionally, the first liquid accumulation height may be the maximum liquid accumulation height applicable when plunger drainage is adopted, the second liquid accumulation height may be the maximum liquid accumulation height applicable when plunger-assisted drainage is adopted, and the third liquid accumulation height may be the maximum liquid accumulation height applicable when pumping equipment is used for forced drainage. The maximum liquid accumulation height is obtained by setting, and may also be a height of a predetermined ratio.

[0044] Optionally, the forced discharge threshold is a predetermined daily water production of the pumping equipment, which may be a variety of predetermined values, for example, the forced discharge threshold is a minimum daily water production of the pumping equipment.

[0045] Step S106, using the secondary classification parameters to classify the water-producing gas wells to obtain secondary classification results of the water-producing gas wells;

[0046] It can be understood that after classifying the water-producing gas wells using the corresponding secondary classification parameters, the secondary classification results are obtained, which is conducive to the refined classification of the water-producing gas wells and the support for the accuracy of the production countermeasure control.

[0047] In an optional embodiment, the above-mentioned water-producing gas wells are classified using corresponding secondary classification parameters to determine the secondary classification results of the water-producing gas wells, including: when the water-gas ratio is less than the critical water-gas ratio and the average daily gas production is greater than the critical liquid-carrying flow rate, the non-liquid-filled well is determined to be a first-category non-liquid-filled well; when the water-gas ratio is greater than the critical water-gas ratio and the average daily gas production is greater than the critical liquid-carrying flow rate, the non-liquid-filled well is determined to be a second-category non-liquid-filled well, wherein the liquid content in the first-category non-liquid-filled well is less than the liquid content in the second-category non-liquid-filled well; when the water-gas ratio is greater than the critical water-gas ratio and the average daily gas production is less than the critical liquid-carrying flow rate, the non-liquid-filled well is determined to be a third-category non-liquid-filled well, wherein the liquid content in the second-category non-liquid-filled well is less than the liquid content in the third-category non-liquid-filled well.

[0048] It can be understood that the second classification result is determined according to the secondary classification parameters corresponding to the first classification result. For non-liquid-filled wells, they are divided into three categories according to the liquid content from low to high. The first category of non-liquid-filled wells has the least liquid content, and the third category of non-liquid-filled wells has the most liquid content. When the water-gas ratio is less than the critical water-gas ratio and the average daily gas production is greater than the critical liquid-carrying flow rate, the non-liquid-filled well is determined to be a first category of non-liquid-filled well. When the water-gas ratio is greater than the critical water-gas ratio and the average daily gas production is greater than the critical liquid-carrying flow rate, the non-liquid-filled well is determined to be a second category of non-liquid-filled well. When the water-gas ratio is greater than the critical water-gas ratio and the average daily gas production is less than the critical liquid-carrying flow rate, the non-liquid-filled well is determined to be a third category of non-liquid-filled well. Through the above processing, the non-liquid-filled wells are further classified according to the water-gas ratio, average daily gas production, critical liquid-carrying flow rate and critical water-gas ratio of water-producing gas wells.

[0049] In an optional embodiment, the above-mentioned use of corresponding secondary classification parameters to classify the above-mentioned water-producing gas wells and determine the secondary classification results of the above-mentioned water-producing gas wells includes: when the above-mentioned average daily water production is less than the above-mentioned strong discharge threshold value, and the above-mentioned wellbore liquid accumulation height is less than the above-mentioned first liquid accumulation height, classifying the above-mentioned liquid accumulation wells and determining that the above-mentioned liquid accumulation wells are first-class liquid accumulation wells; when the above-mentioned average daily water production is less than the above-mentioned strong discharge threshold value, and the above-mentioned wellbore liquid accumulation height is greater than the above-mentioned first liquid accumulation height and less than the above-mentioned second liquid accumulation height, classifying the above-mentioned liquid accumulation wells and determining that the above-mentioned liquid accumulation wells are second-class liquid accumulation wells, wherein the liquid content in the above-mentioned first-class liquid accumulation wells is less than the liquid content in the above-mentioned second-class liquid accumulation wells;

[0050] It can be understood that the liquid accumulation wells are classified from low to high according to the liquid content, the first type of liquid accumulation wells have the least liquid content, the fifth type of liquid accumulation wells have the lowest liquid content, and so on. When the average daily water production is less than the forced drainage threshold, and the wellbore liquid accumulation height is less than the first liquid accumulation height, the liquid accumulation well is classified and determined to be a first type of liquid accumulation well. When the average daily water production is less than the forced drainage threshold, the wellbore liquid accumulation height is greater than the first liquid accumulation height, and less than the second liquid accumulation height, the liquid accumulation well is classified and determined to be a second type of liquid accumulation well.

[0051] In an optional embodiment, when the above-mentioned average daily water production is less than the above-mentioned forced discharge threshold value, the above-mentioned wellbore liquid accumulation height is greater than the above-mentioned second liquid accumulation height and less than the above-mentioned third liquid accumulation height, the above-mentioned liquid accumulation well is classified and determined to be a third-category liquid accumulation well, wherein the liquid content in the above-mentioned second-category liquid accumulation well is less than the liquid content in the above-mentioned third-category liquid accumulation well; when the above-mentioned average daily water production is less than the above-mentioned forced discharge threshold value, and the above-mentioned wellbore liquid accumulation height is greater than the above-mentioned third liquid accumulation height, the above-mentioned liquid accumulation well is classified and determined to be a fourth-category liquid accumulation well, wherein the liquid content in the above-mentioned third-category liquid accumulation well is less than the liquid content in the above-mentioned fourth-category liquid accumulation well; when the above-mentioned average daily water production is greater than the above-mentioned forced discharge threshold value, the above-mentioned liquid accumulation well is classified and determined to be a fifth-category liquid accumulation well, wherein the liquid content in the above-mentioned fourth-category liquid accumulation well is less than the liquid content in the above-mentioned fifth-category liquid accumulation well.

[0052] It can be understood that when the average daily water production is less than the strong discharge threshold, the wellbore liquid accumulation height is greater than the second liquid accumulation height, and less than the third liquid accumulation height, the liquid accumulation well is classified and determined to be a third-category liquid accumulation well. When the average daily water production is less than the strong discharge threshold, and the wellbore liquid accumulation height is greater than the third liquid accumulation height, the liquid accumulation well is classified and determined to be a fourth-category liquid accumulation well. When the average daily water production is greater than the strong discharge threshold, the liquid accumulation well is classified and determined to be a fifth-category liquid accumulation well. Through the above processing, the liquid accumulation wells are further classified according to the wellbore liquid accumulation height, the average daily water production, the first liquid accumulation height, the second liquid accumulation height, the third liquid accumulation height, and the strong discharge threshold.

[0053] Step S108, determining the drainage and gas production control strategy corresponding to the above-mentioned secondary classification result;

[0054] It can be understood that the purpose of classifying water-producing gas wells is to implement targeted control strategies for refined management and to increase the production of water-producing gas wells.

[0055] In an optional embodiment, the above-mentioned determination of the drainage and gas production control strategy corresponding to the above-mentioned secondary classification result includes: determining the first non-liquid-filled strategy corresponding to the above-mentioned first type of non-liquid-filled wells, wherein the above-mentioned first non-liquid-filled strategy includes monitoring the daily gas production of the above-mentioned water-producing gas wells; when the above-mentioned daily gas production drops to the critical liquid-carrying flow rate, using the foam drainage method to perform gas production treatment on the above-mentioned first type of non-liquid-filled wells; determining the second non-liquid-filled strategy corresponding to the above-mentioned second type of non-liquid-filled wells, wherein the above-mentioned second non-liquid-filled strategy includes monitoring the above-mentioned daily gas production and daily water production of the above-mentioned water-producing gas wells; when any of the above-mentioned daily gas production decreases, or when the above-mentioned daily gas production change is less than the predetermined change threshold, and the monomer water production increases, determining the preset multiple drainage strategies. The first target gas production method in the gas production method; adopting the above-mentioned first target gas production method to perform gas production treatment on the above-mentioned second type of non-liquid-filled wells; determining the third non-liquid-filled strategy corresponding to the above-mentioned third type of non-liquid-filled wells, wherein the above-mentioned third non-liquid-filled strategy includes obtaining the oil pressure differential and casing pressure differential of the above-mentioned third type of non-liquid-filled wells; when the above-mentioned oil pressure differential increases and the casing pressure differential increases, determining the second target gas production method in the above-mentioned multiple water drainage gas production methods; adopting the above-mentioned second target gas production method to perform gas production treatment on the above-mentioned third type of non-liquid-filled wells, wherein the above-mentioned casing pressure differential is the flow pressure in the above-mentioned third type of non-liquid-filled wells minus the pressure of the liquid column and the gas column in the casing, and the above-mentioned oil pressure differential is the flow pressure in the above-mentioned third type of non-liquid-filled wells minus the pressure of the oil-gas mixed liquid column in the well, friction resistance and slip loss.

[0056] It can be understood that there are corresponding strategies for the first, second, and third types of non-liquid-filled wells. The first non-liquid-filled strategy corresponding to the first type of non-liquid-filled wells is mainly based on monitoring, monitoring the daily gas production of the above-mentioned water-producing gas wells. When it is monitored that the daily gas production has dropped to the critical liquid-carrying flow rate, it is deemed that drainage and gas production treatment is required, and the foam drainage method in the drainage and gas production method is selected to carry out gas production treatment for the first type of non-liquid-filled wells. The first type of non-liquid-filled wells have a small amount of liquid. Even if drainage and gas production treatment is required, the foam drainage method is preferred for gas production. It should be noted that the foam drainage method has the advantages of simple equipment, quick results, and low cost, but its drainage capacity is weak, and it is suitable for water-producing gas wells with less liquid content.

[0057] The second non-liquid accumulation strategy corresponding to the second type of non-liquid accumulation wells needs to monitor the daily production and daily water production. The production performance is large water-gas ratio, the critical liquid carrying flow model is no longer applicable, the gas well production is high, the gas well has a strong liquid carrying capacity, and the daily gas production and liquid carrying capacity decrease when the daily gas production and decrease, or the daily gas production and stable but the daily water production increases, the daily gas production change is less than the predetermined change threshold, and the monomer water production increases. When any of the following situations occurs, liquid accumulation is likely to occur. When it is determined that liquid accumulation occurs, the first target gas production method is selected from a variety of drainage gas production methods to treat the second type of non-liquid accumulation wells. It should be noted that when it is determined that liquid accumulation occurs, it is necessary to select drainage gas production methods as needed, not limited to the foam drainage method.

[0058] The third non-liquid-filled strategy corresponding to the third type of non-liquid-filled wells requires monitoring of the casing pressure differential and oil pressure differential of the third type of non-liquid-filled wells. The production performance of the third type of non-liquid-filled wells is large water-gas ratio, small gas production, and large water production. They are on the verge of liquid accumulation. When the casing pressure differential and oil pressure differential increase, it is deemed that liquid accumulation is certain. Among the various water drainage gas production methods, the second target gas production method is selected as needed to treat the third type of non-liquid-filled wells.

[0059] In an optional embodiment, the above-mentioned determination of the drainage and gas production control strategy corresponding to the above-mentioned secondary classification result includes: determining the first liquid accumulation strategy corresponding to the above-mentioned first type of liquid accumulation well, wherein the above-mentioned first liquid accumulation strategy includes adopting a foam drainage method, and the above-mentioned first type of liquid accumulation well performs gas production treatment; determining the second liquid accumulation strategy corresponding to the above-mentioned second type of liquid accumulation well, wherein the above-mentioned second liquid accumulation strategy includes adopting a plunger drainage method, and the above-mentioned second type of liquid accumulation well performs gas production treatment.

[0060] It can be understood that different strategies correspond to the first to fifth types of liquid accumulation wells, which are used to control and increase production accordingly. The first type of liquid accumulation well has the least liquid content among the liquid accumulation wells and is the lightest type of liquid accumulation. The first type of liquid accumulation countermeasure can be to use the foam drainage method for gas production. The second type of liquid accumulation strategy corresponding to the second type of liquid accumulation well requires a stronger drainage capacity, and the plunger drainage method is used to carry out gas production for the second type of liquid accumulation well.

[0061] In an optional embodiment, the above-mentioned determination of the drainage and gas production control strategy corresponding to the above-mentioned secondary classification result includes: determining the third liquid accumulation strategy corresponding to the above-mentioned third category of liquid accumulation wells, wherein the above-mentioned third liquid accumulation strategy includes adopting the above-mentioned plunger drainage method, and performing gas production treatment on the above-mentioned third category of liquid accumulation wells to obtain the plunger gas production volume of the above-mentioned third category of liquid accumulation wells; when the above-mentioned plunger gas production volume is lower than a preset switching threshold, using a compressor to perform gas production treatment on the above-mentioned third category of liquid accumulation wells; determining the fourth liquid accumulation strategy corresponding to the above-mentioned fourth category of liquid accumulation wells, wherein the above-mentioned fourth liquid accumulation strategy includes adopting the gas lift drainage and gas production method to drain the above-mentioned fourth category of liquid accumulation wells; when the above-mentioned fourth category of liquid accumulation wells are drained, performing gas production treatment on the above-mentioned fourth category of liquid accumulation wells; determining the fifth liquid accumulation strategy corresponding to the above-mentioned fifth category of liquid accumulation wells, wherein the above-mentioned fifth liquid accumulation strategy includes adopting the forced drainage and water pumping method to perform gas production treatment on the above-mentioned fifth category of liquid accumulation wells.

[0062] It can be understood that the production performance of the third type of liquid accumulation wells is that the liquid has accumulated, and the liquid accumulation is serious, and the wellbore pressure drop loss is large. The plunger drainage method may not be able to fully cope with the situation. In spring and summer, it is necessary to determine whether to use a more powerful drainage method based on the plunger gas production of the third type of liquid accumulation wells. When the plunger gas production is monitored to be lower than the preset switching threshold, the compressor is used to perform gas production on the above-mentioned third type of liquid accumulation wells. It should be noted that compared with the plunger drainage method, compressor pumping can obtain a stronger pumping capacity to discharge the accumulated liquid in the wellbore. The production performance of the fourth type of liquid accumulation wells is that the gas wells are seriously liquid accumulated, or water flooding has occurred and cannot be produced independently. The production countermeasures are to carry out gas lift first, and then carry out drainage and gas production measures after the wellbore is drained. The corresponding fourth liquid accumulation strategy is to use the gas lift drainage method to drain the above-mentioned fourth type of liquid accumulation wells. After determining that the fourth type of liquid accumulation wells are drained, the fourth type of liquid accumulation wells are gas production. The production performance of the fifth type of liquid-impaired wells is that the gas wells produce a large amount of water. Conventional drainage and gas production measures have a small drainage volume and cannot meet the drainage demand. The fifth liquid-impaired strategy is mainly based on strong drainage measures such as jet pumps and mechanical pumping. The strong drainage and pumping method is used to carry out gas production treatment for the fifth type of liquid-impaired wells.

[0063] Optionally, the above-mentioned second type of liquid accumulation wells can also adopt the plunger drainage method combined with the foam drainage method to achieve plunger assisted drainage. It should be noted that the method is arranged from low to high in terms of drainage capacity as foam drainage method, plunger assisted drainage method and plunger drainage method. They can be selected as needed and the processing ratio of plunger and foam drainage can be adjusted.

[0064] Optionally, the compressor may be a synchronous rotary compressor.

[0065] Optionally, in the third liquid accumulation strategy, when the plunger gas production is detected to be lower than the preset switching threshold, a velocity column can be used to produce gas for the third type of liquid accumulation well. The velocity column is a small diameter column pipe inserted into the wellbore during natural gas well production, which is used to throttle and increase the speed of the fluid in the wellbore.

[0066] Through the above-mentioned steps S102 to S108, the accuracy of classifying water-producing gas wells can be improved, and the purpose of further implementing corresponding production strategies for different water-producing gas wells can be achieved, thereby achieving the technical effect of increasing the output of water-producing gas wells, and further solving the technical problem in the related technology of not involving establishing a gas well classification method based on water production characteristic parameters and developing production strategies for water-producing gas wells.

[0067] Based on the above embodiments and optional embodiments, the present invention proposes an optional implementation method, which classifies water-producing gas wells in tight sandstone gas reservoirs and provides production strategies to increase production for water-producing gas wells. Figure 2 This is a schematic diagram of a flow chart of an optional tight sandstone gas reservoir water-producing gas well classification device provided according to an embodiment of the present invention, which is specifically described below:

[0068] Step 1: According to the water production of the gas well in the gas field report or the dynamic monitoring water production data, determine whether the gas well produces water, that is, whether it is a water-producing gas well.

[0069] Step 2, obtain the gas well liquid surface data of the water-producing gas well to be classified, obtain the wellbore liquid accumulation height of the water-producing gas well, record it as Hw, and determine the minimum liquid accumulation height Hmin based on the current implementation status of the gas field production countermeasures.

[0070] Step 3, when the wellbore liquid accumulation height of the water-producing gas well is less than the minimum liquid accumulation height, that is, Hw is less than Hmin, the water-producing gas well is classified as a non-liquid accumulation well, and the non-liquid accumulation mark is denoted by WJ; when the wellbore liquid accumulation height of the water-producing gas well is greater than the minimum liquid accumulation height, that is, Hw is greater than Hmin, the gas well is classified as a liquid accumulation well, and the liquid accumulation mark is denoted by J.

[0071] Step 3-1, for wells without liquid accumulation, that is, gas wells with the first-level classification result of WJ, determine the gas production of water-producing gas wells, denoted as q, and the water-gas ratio of water-producing gas wells is denoted as Rwq, which is equal to the ratio of the average daily water production (unit: cubic meter / day) to the daily gas production (unit: ten thousand cubic meters / day). According to the study of the flow state of the gas field wellbore, determine the critical water-gas ratio applicable to the critical liquid carrying flow model, denoted as Rwqc. According to the critical liquid carrying flow model, gas well string size, wellhead oil pressure, fluid density and other parameters, the critical liquid carrying flow is determined and denoted as qcr. For wells without liquid accumulation, they can be further divided into the following three categories:

[0072] Step 3-1-1, when the water-gas ratio Rwq is less than the critical water-gas ratio Rwqc, and the average daily gas production q is greater than the critical liquid carrying rate qcr, the above-mentioned non-liquid-filled well is classified as the first type of non-liquid-filled well, recorded as WJⅠ type well.

[0073] Step 3-1-2, when the water-gas ratio Rwq is greater than the critical water-gas ratio Rwqc, and the average daily gas production q is greater than the critical liquid carrying flow rate qcr, the above-mentioned non-liquid-filled well is classified as the second type of non-liquid-filled well, recorded as a WJⅡ type well.

[0074] Step 3-1-3, when the water-gas ratio Rwq is greater than the critical water-gas ratio Rwqc, and the average daily gas production q is less than the critical liquid carrying rate qcr, the above-mentioned non-liquid-filled well is classified as the third type of non-liquid-filled well, recorded as WJⅢ type well.

[0075] Step 3-2, for liquid accumulation wells, that is, gas wells with the first-level classification result of Class J, the liquid accumulation height of the wellbore of the liquid accumulation well is recorded as Hw, the average daily water production is recorded as qw, the maximum liquid accumulation height applicable to the foam drainage method is the first liquid accumulation height, recorded as H1, the maximum liquid accumulation height applicable to the plunger drainage method is the second liquid accumulation height, recorded as H2, the maximum liquid accumulation height applicable to the plunger-assisted drainage method is the third liquid accumulation height, recorded as H3, and the minimum daily average water production applicable to large-volume strong drainage and gas production measures such as jet pumps and mechanical pumping (referred to as "strong drainage") is recorded as qmin. Among them, qw is the average daily water production in cubic meters / day, and H1, H2, H3 and qmin are determined in combination with the performance of the main drainage and gas production process equipment of the gas field and the production characteristics of the gas well. For example, the empirical values ​​of a certain gas field are 200 meters, 500 meters, 1000 meters and 15 cubic meters / day, respectively. For liquid accumulation wells, they can be further divided into the following five categories:

[0076] Step 3-2-1, when the average daily water production qw < the minimum average daily water production qmin, and the wellbore liquid accumulation height Hw < the first liquid accumulation height H1, the above-mentioned liquid accumulation well is classified as a first type of liquid accumulation well, recorded as a JⅠ type well.

[0077] Step 3-2-2, when the average daily water production qw < minimum average daily water production qmin, and the first liquid accumulation height H1 < wellbore liquid accumulation height Hw < second liquid accumulation height H2, the above liquid accumulation well is classified as the second type of liquid accumulation well, recorded as Class JⅡ.

[0078] Step 3-2-3, when the average daily water production qw < the minimum average daily water production qmin, and the second liquid accumulation height H2 < the wellbore liquid accumulation height Hw < the third liquid accumulation height H3, the above liquid accumulation well is classified as a third type of liquid accumulation well, recorded as Class JⅢ.

[0079] Step 3-2-4: When the daily average water production qw < the minimum daily average water production qmin, and the wellbore liquid accumulation height Hw > the third liquid accumulation height H3, the above liquid accumulation well is classified as the fourth type of liquid accumulation well, recorded as JⅣ type.

[0080] Step 3-2-5, when the average daily water production qw> the minimum average daily water production qmin, the above-mentioned liquid accumulation well is classified as the fifth type of liquid accumulation well, recorded as a JⅤ type well.

[0081] Step 4: According to the classification of water-producing gas wells in step 3, they are divided into 8 types: WJⅠ, WJⅡ, WJⅢ, JⅠ, JⅡ, JⅢ, JⅣ, and JⅤ. The production countermeasures for each type of gas well are specified, as follows:

[0082] Step 4-1: For WJⅠ wells, production monitoring is the main focus. When the production decreases to near the critical liquid carrying flow rate, foam drainage and gas recovery measures are carried out.

[0083] Step 4-2, for WJⅡ wells, the production strategy needs to monitor the changes in daily gas production and daily water production at the same time. When the daily gas production decreases, the liquid carrying capacity decreases, or when the daily gas production is stable and the daily water production increases, liquid accumulation is likely to occur. Select one of the multiple drainage gas production methods to perform gas production treatment on the WJⅡ well.

[0084] Step 4-3, for WJⅢ wells, the production performance is that liquid accumulation is imminent. Under the condition of monitoring the increase of oil pressure differential and casing pressure differential, one of the multiple drainage gas production methods is selected to treat the WJⅢ well.

[0085] Step 4-4: For JⅠ type wells, the production strategy is mainly based on foam drainage and gas recovery.

[0086] Step 4-5, for JⅡ type wells, the production countermeasures are to carry out plunger or plunger combined with foam drainage measures.

[0087] Step 4-6, for JⅢ wells, the production countermeasure is to first carry out the plunger drainage method. When the plunger drainage method fails or the production is reduced, the JⅢ wells are treated by using measures such as velocity tubing or synchronous compressor.

[0088] Step 4-7, for JⅣ type wells, the production strategy is to first carry out gas lift drainage method, and then carry out drainage and gas production measures after the wellbore is drained.

[0089] Steps 4-8: For JⅤ class wells, the production countermeasures are mainly strong drainage measures such as jet pumps and mechanical pumping.

[0090] The above optional implementation method achieves at least the following effects: the key characteristic parameters of the production of water-producing gas wells are used to divide the gas wells into 8 types, and the quantitative classification basis of each type is clarified. It is suitable for the optimization and evaluation of production countermeasures for large-scale water-producing gas wells, and timely and effectively guides the implementation of gas well production countermeasures. It can extend the continuous gas production of gas wells, increase the production of single wells, and enhance development benefits. It provides a basis for the refined and automated management of gas wells, which is conducive to increasing the production of water-producing gas wells and improving production efficiency.

[0091] It should be noted that the steps shown in the flowcharts of the accompanying drawings can be executed in a computer system such as a set of computer executable instructions, and that, although a logical order is shown in the flowcharts, in some cases, the steps shown or described can be executed in an order different from that shown here.

[0092] In this embodiment, a water-producing gas well classification device for a tight sandstone gas reservoir is also provided, and the device is used to implement the above-mentioned embodiments and preferred implementation modes, and the descriptions that have been made will not be repeated. As used below, the terms "module" and "device" can be a combination of software and / or hardware that implements a predetermined function. Although the devices described in the following embodiments are preferably implemented in software, the implementation of hardware, or a combination of software and hardware, is also possible and conceivable.

[0093] According to an embodiment of the present invention, there is also provided an embodiment of a device for implementing a method for classifying water-producing gas wells in tight sandstone gas reservoirs. Figure 3 Schematic diagram of a water-producing gas well classification device for a tight sandstone gas reservoir according to an embodiment of the present invention. Figure 3 As shown, the above-mentioned water-producing gas well classification device for tight sandstone gas reservoirs includes: a detection module 302, a primary classification module 304, a secondary classification module 306, and a determination module 308. The device is described below.

[0094] The detection module 302 is used to obtain the wellbore liquid accumulation height of the water-producing gas well applied to the tight sandstone gas reservoir, wherein the wellbore liquid accumulation height is obtained by performing a gas well liquid level detection test on the water-producing gas well;

[0095] The primary classification module 304 is connected to the detection module 302 and is used to classify the water-producing gas wells based on the wellbore liquid accumulation height, and determine the primary classification results of the water-producing gas wells and the secondary classification parameters corresponding to the primary classification results;

[0096] The secondary classification module 306 is connected to the primary classification module 304 and is used to classify the water-producing gas wells using the secondary classification parameters to obtain secondary classification results of the water-producing gas wells.

[0097] The determination module 308 is connected to the secondary classification module 306 and is used to determine the drainage and gas production control strategy corresponding to the secondary classification result.

[0098] In a device for classifying water-producing gas wells in tight sandstone gas reservoirs provided by an embodiment of the present invention, a detection module 302 is used to obtain the wellbore liquid accumulation height of the water-producing gas wells applied to the tight sandstone gas reservoir, wherein the wellbore liquid accumulation height is obtained by performing a gas well liquid surface test on the water-producing gas wells; a primary classification module 304 is connected to the detection module 302, and is used to classify the water-producing gas wells based on the wellbore liquid accumulation height, and determine the primary classification results of the water-producing gas wells, as well as the secondary classification parameters corresponding to the primary classification results; a secondary classification module 306 is connected to the primary classification module 304, and is used to classify the water-producing gas wells using the secondary classification parameters, and obtain the secondary classification results of the water-producing gas wells; a determination module 308 is connected to the secondary classification module 306, and is used to determine the water drainage and gas production control strategy corresponding to the secondary classification results. The purpose of improving the accuracy of classifying water-producing gas wells and then formulating corresponding production strategies for different water-producing gas wells is achieved, and the technical effect of increasing the output of water-producing gas wells is realized, thereby solving the technical problem that the relevant technology does not involve establishing a gas well classification method according to water production characteristic parameters and developing production strategies for water-producing gas wells.

[0099] It should be noted that the above modules can be implemented by software or hardware. For example, for the latter, it can be implemented in the following ways: the above modules can be located in the same processor; or the above modules can be located in different processors in any combination.

[0100] It should be noted that the detection module 302, the primary classification module 304, the secondary classification module 306, and the determination module 308 correspond to steps S102 to S108 in the embodiment, and the examples and application scenarios implemented by the modules and the corresponding steps are the same, but are not limited to the contents disclosed in the above embodiment. It should be noted that the modules as part of the device can be run in a computer terminal.

[0101] It should be noted that the optional or preferred implementation of this embodiment can refer to the relevant description in the embodiment, which will not be repeated here.

[0102] The above-mentioned tight sandstone gas reservoir water-producing gas well classification device can also include a processor and a memory. The detection module 302, the primary classification module 304, the secondary classification module 306, the determination module 308, etc. are all stored in the memory as program units, and the processor executes the above-mentioned program units stored in the memory to realize the corresponding functions.

[0103] The processor includes a kernel, which retrieves the corresponding program unit from the memory. There can be one or more kernels. The memory may include non-permanent memory in a computer-readable medium, random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM, and the memory includes at least one storage chip.

[0104] An embodiment of the present invention provides a non-volatile storage medium on which a program is stored. When the program is executed by a processor, a method for classifying water-producing gas wells in tight sandstone gas reservoirs is implemented.

[0105] An embodiment of the present invention provides an electronic device, which includes a processor, a memory, and a program stored in the memory and executable on the processor. When the processor executes the program, the following steps are implemented: obtaining the wellbore liquid accumulation height of a water-producing gas well applied to a tight sandstone gas reservoir, wherein the wellbore liquid accumulation height is obtained by performing a gas well liquid surface test on the water-producing gas well; based on the wellbore liquid accumulation height, classifying the water-producing gas well, determining the primary classification result of the water-producing gas well, and the secondary classification parameters corresponding to the primary classification result; using the secondary classification parameters, classifying the water-producing gas well, obtaining the secondary classification result of the water-producing gas well; and determining the drainage and gas production control strategy corresponding to the secondary classification result. The device in this article may be a server, a PC, etc.

[0106] The present invention also provides a computer program product, which, when executed on a data processing device, is suitable for executing a program that initializes the following method steps: obtaining the wellbore liquid accumulation height of a water-producing gas well applied to a tight sandstone gas reservoir, wherein the wellbore liquid accumulation height is obtained by conducting a gas well liquid surface test on the water-producing gas well; based on the wellbore liquid accumulation height, classifying the water-producing gas wells, determining the primary classification results of the water-producing gas wells, and the secondary classification parameters corresponding to the primary classification results; using the secondary classification parameters to classify the water-producing gas wells, obtaining the secondary classification results of the water-producing gas wells; and determining the water drainage and gas production control strategy corresponding to the secondary classification results.

[0107] Those skilled in the art will appreciate that embodiments of the present invention may be provided as methods, systems, or computer program products. Therefore, the present invention may take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware. Moreover, the present invention may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0108] The present invention is described with reference to flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to embodiments of the present invention. It should be understood that each process and / or block in the flowchart and / or block diagram, as well as the combination of processes and / or blocks in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1 A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0109] These computer program instructions may also be stored in a computer-readable memory capable of directing a computer or other programmable data processing device to operate in a specific manner, so that the instructions stored in the computer-readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 A process or multiple processes and / or boxes Figure 1 A function specified in one or more boxes.

[0110] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions for implementing the process. Figure 1 A process or multiple processes and / or boxes Figure 1 The steps for the functions specified in one or more boxes.

[0111] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0112] The memory may include non-permanent memory in a computer-readable medium, random access memory (RAM) and / or non-volatile memory in the form of read-only memory (ROM) or flash RAM. The memory is an example of a computer-readable medium.

[0113] Computer readable media include permanent and non-permanent, removable and non-removable media that can be implemented by any method or technology to store information. Information can be computer readable instructions, data structures, program modules or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technology, compact disk read-only memory (CD-ROM), digital versatile disk (DVD) or other optical storage, magnetic cassettes, magnetic tape disk storage or other magnetic storage devices or any other non-transmission media that can be used to store information that can be accessed by a computing device. As defined herein, computer readable media does not include temporary computer readable media (transitory media), such as modulated data signals and carrier waves.

[0114] It should also be noted that the terms "include", "comprises" or any other variations thereof are intended to cover non-exclusive inclusion, so that a process, method, commodity or device including a series of elements includes not only those elements, but also other elements not explicitly listed, or also includes elements inherent to such process, method, commodity or device. In the absence of more restrictions, the elements defined by the sentence "comprises a ..." do not exclude the existence of other identical elements in the process, method, commodity or device including the elements.

[0115] It will be appreciated by those skilled in the art that embodiments of the present invention may be provided as methods, systems or computer program products. Therefore, the present invention may take the form of a complete hardware embodiment, a complete software embodiment or an embodiment combining software and hardware. Moreover, the present invention may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program codes.

[0116] The above are only embodiments of the present invention and are not intended to limit the present invention. For those skilled in the art, the present invention may have various modifications and variations. Any modification, equivalent substitution, improvement, etc. made within the spirit and principle of the present invention should be included in the scope of the claims of the present invention.

Claims

1. A method for classifying water-producing gas wells in tight sandstone gas reservoirs, characterized in that: include: Obtaining a wellbore liquid accumulation height of a water-producing gas well applied to a tight sandstone gas reservoir, wherein the wellbore liquid accumulation height is obtained by performing a gas well liquid level test on the water-producing gas well; Based on the wellbore liquid accumulation height, the water-producing gas wells are classified to determine the primary classification results of the water-producing gas wells and the secondary classification parameters corresponding to the primary classification results; Using the secondary classification parameters to classify the water-producing gas wells, and obtaining secondary classification results of the water-producing gas wells; Determine the drainage and gas production control strategy corresponding to the secondary classification result.

2. The method according to claim 1, characterized in that Determining the secondary classification parameters corresponding to the primary classification results includes: In the case that the primary classification result is that the water-producing gas well belongs to a non-liquid accumulation well, the secondary classification parameters corresponding to the non-liquid accumulation well are determined to include: the water-gas ratio, average daily gas production, critical liquid-carrying flow rate and critical water-gas ratio of the water-producing gas well, wherein the water-gas ratio is the ratio of the average daily water production of the water-producing gas well to the average daily gas production, the critical liquid-carrying flow rate is obtained by processing using a preset critical liquid-carrying flow rate model based on the inner diameter of the gas well tubing and the high-pressure physical properties of the fluid, and the critical water-gas ratio is the water-gas ratio of the wellbore of the water-producing gas well when the dispersed phase in the form of liquid droplets is converted into the liquid phase.

3. The method according to claim 2, characterized in that The adopting of the corresponding secondary classification parameters to classify the water-producing gas wells and determining the secondary classification results of the water-producing gas wells includes: When the water-gas ratio is less than the critical water-gas ratio and the average daily gas production is greater than the critical liquid-carrying flow rate, determining that the non-liquid-filled well is a first-type non-liquid-filled well; When the water-gas ratio is greater than the critical water-gas ratio and the average daily gas production is greater than the critical liquid-carrying flow rate, the non-liquid-filled well is determined to be a second-type non-liquid-filled well, wherein the liquid content in the first-type non-liquid-filled well is less than the liquid content in the second-type non-liquid-filled well; When the water-gas ratio is greater than the critical water-gas ratio and the average daily gas production is less than the critical liquid carrying rate, the non-liquid-filled well is determined to be a third-category non-liquid-filled well, wherein the liquid content in the second-category non-liquid-filled well is less than the liquid content in the third-category non-liquid-filled well.

4. The method according to claim 3, characterized in that The determining of the drainage and gas production control strategy corresponding to the secondary classification result includes: Determine a first non-liquid-loading strategy corresponding to the first type of non-liquid-loading wells, wherein the first non-liquid-loading strategy includes monitoring the daily gas production of the water-producing gas well; when the daily gas production drops to the critical liquid-carrying flow rate, use a foam drainage method to perform gas production treatment on the first type of non-liquid-loading wells; Determine a second non-liquid-filled strategy corresponding to the second type of non-liquid-filled wells, wherein the second non-liquid-filled strategy includes monitoring the daily gas production and the daily water production of the water-producing gas well; when the daily gas production decreases, or when the daily gas production change is less than a predetermined change threshold and the monomer water production increases, determine a first target gas production method among the preset multiple water drainage gas production methods; adopt the first target gas production method to perform gas production treatment on the second type of non-liquid-filled wells; Determine a third non-fluid-filled strategy corresponding to the third category non-fluid-filled well, wherein the third non-fluid-filled strategy includes obtaining the oil pressure differential and casing pressure differential of the third category non-fluid-filled well; determine a second target gas production method among the multiple water drainage gas production methods when the oil pressure differential increases and the casing pressure differential increases; use the second target gas production method to perform gas production on the third category non-fluid-filled well, wherein the casing pressure differential is the flow pressure in the third category non-fluid-filled well minus the pressures of the liquid column and the gas column in the casing, and the oil pressure differential is the flow pressure in the third category non-fluid-filled well minus the pressure of the oil and gas mixed liquid column in the well, friction resistance and slip loss.

5. The method according to claim 2, characterized in that: The critical liquid carrying flow model is obtained based on the droplet theory and includes at least one of the following: Turner model, Li Min model, Cloeman model, and Nosseir model.

6. The method according to claim 1, characterized in that Determining the secondary classification parameters corresponding to the primary classification results includes: When the primary classification result is that the water-producing gas well belongs to a liquid accumulation well, the secondary classification parameters corresponding to the liquid accumulation well are determined, including: the liquid accumulation height of the wellbore, the average daily water production, the first liquid accumulation height, the second liquid accumulation height, the third liquid accumulation height, and the forced discharge threshold, wherein the first liquid accumulation height is the liquid accumulation height applicable when plunger drainage is adopted, the second liquid accumulation height is the liquid accumulation height applicable when plunger-assisted drainage is adopted, the third liquid accumulation height is the liquid accumulation height applicable when pumping equipment is forcedly discharged, the first liquid accumulation height is less than the second liquid accumulation height, the second liquid accumulation height is less than the third liquid accumulation height, the plunger-assisted drainage is a method of combining plunger drainage with foam drainage, and the forced discharge threshold is the predetermined daily water production of the pumping equipment.

7. The method according to claim 6, characterized in that The adopting of the corresponding secondary classification parameters to classify the water-producing gas wells and determining the secondary classification results of the water-producing gas wells includes: When the average daily water production is less than the forced drainage threshold and the wellbore liquid accumulation height is less than the first liquid accumulation height, classifying the liquid accumulation well and determining that the liquid accumulation well is a first-class liquid accumulation well; When the average daily water production is less than the forced discharge threshold and the liquid accumulation height in the wellbore is greater than the first liquid accumulation height and less than the second liquid accumulation height, the liquid accumulation well is classified and determined to be a second-type liquid accumulation well, wherein the liquid content in the first-type liquid accumulation well is less than the liquid content in the second-type liquid accumulation well.

8. The method according to claim 7, characterized in that The adopting of the corresponding secondary classification parameters to classify the water-producing gas wells and determining the secondary classification results of the water-producing gas wells includes: When the average daily water production is less than the forced drainage threshold, and the wellbore liquid accumulation height is greater than the second liquid accumulation height and less than the third liquid accumulation height, the liquid accumulation well is classified to determine that the liquid accumulation well is a third type of liquid accumulation well, wherein the liquid content in the second type of liquid accumulation well is less than the liquid content in the third type of liquid accumulation well; When the average daily water production is less than the forced drainage threshold and the wellbore liquid accumulation height is greater than the third liquid accumulation height, the liquid accumulation well is classified to determine that the liquid accumulation well is a fourth type of liquid accumulation well, wherein the liquid content in the third type of liquid accumulation well is less than the liquid content in the fourth type of liquid accumulation well; When the average daily water production is greater than the forced drainage threshold, the liquid accumulation well is classified and determined to be a fifth type of liquid accumulation well, wherein the liquid content in the fourth type of liquid accumulation well is less than the liquid content in the fifth type of liquid accumulation well.

9. The method according to claim 7, characterized in that: The determining of the drainage and gas production control strategy corresponding to the secondary classification result includes: Determining a first liquid accumulation strategy corresponding to the first type of liquid accumulation well, wherein the first liquid accumulation strategy includes adopting a foam drainage method, and the first type of liquid accumulation well performs gas production processing; A second liquid accumulation strategy corresponding to the second type of liquid accumulation well is determined, wherein the second liquid accumulation strategy includes adopting a plunger drainage method, and the second type of liquid accumulation well performs gas production processing.

10. The method according to claim 8, characterized in that The determining of the drainage and gas production control strategy corresponding to the secondary classification result includes: Determine a third liquid accumulation strategy corresponding to the third type of liquid accumulation well, wherein the third liquid accumulation strategy includes adopting the plunger drainage method, performing gas production processing on the third type of liquid accumulation well, and obtaining the plunger gas production volume of the third type of liquid accumulation well; when the plunger gas production volume is lower than a preset switching threshold, adopting a compressor to perform gas production processing on the third type of liquid accumulation well; Determine a fourth liquid accumulation strategy corresponding to the fourth type of liquid accumulation well, wherein the fourth liquid accumulation strategy includes adopting a gas lift drainage gas production method to drain the fourth type of liquid accumulation well; when the fourth type of liquid accumulation well is drained, perform gas production on the fourth type of liquid accumulation well; A fifth liquid accumulation strategy corresponding to the fifth type of liquid accumulation well is determined, wherein the fifth liquid accumulation strategy includes adopting a forced drainage pumping method to perform gas production processing on the fifth type of liquid accumulation well.

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