A method suitable for diagnosing gas well liquid loading conditions

Abstract

The present application belongs to the technical field of petroleum chemical industry, and particularly relates to a method suitable for diagnosing liquid loading of gas well, which comprises: judging whether the gas well is liquid loading by critical flow rate method; judging whether the gas well is liquid loading by dynamic energy factor method; judging whether the gas well is liquid loading by pressure gradient method; judging whether the gas well is liquid loading by flow state method; judging whether the gas well is liquid loading by IPR method of water production gas well; judging whether the gas well is liquid loading by deliverability test method; and judging the degree of liquid loading of the gas well. The present application realizes accurate prediction of the dynamic of liquid loading of the gas well by studying the diagnosis technology of liquid loading of the gas well and complementarily verifying different methods, forms a set of targeted and high-compliance liquid loading diagnosis method of the gas well with multiple factors, provides technical support for determining the intervention time of drainage gas recovery measures and formulating scientific and reasonable drainage gas recovery measures, realizes the purposes of improving the liquid discharge capacity of the gas well and prolonging the stable production period of the gas field, and thus ensures normal and stable production of the gas well.

Description

Technical Field

[0001] This invention belongs to the field of petrochemical technology, specifically relating to a method for diagnosing liquid accumulation conditions in gas wells. Background Technology

[0002] With the continuous development of gas fields and the increase in the utilization of reserves, the amount of water produced by gas wells and the number of gas wells producing water are showing a continuous increasing trend. Problems such as liquid accumulation in gas well shafts and water production affecting normal production are gradually emerging, becoming the main reason for the decline in gas well production.

[0003] Currently, there are various methods for diagnosing or predicting fluid accumulation in gas wells. For example, Chinese patent CN115186739A discloses a gas well fluid accumulation diagnosis method based on neural networks, including the following steps: obtaining the oil pressure, casing pressure, gas production, and water production of the gas well; inputting the oil pressure, casing pressure, gas production, and water production of the gas well into a gas well fluid accumulation diagnosis model applying a neural network, and outputting a judgment result, which includes whether the gas well has fluid accumulation or not; the gas well fluid accumulation diagnosis model applying a neural network is obtained by increasing the number of neurons in the last hidden layer of a BP network model and adding a dropout structure to the output layer. Chinese patent CN116307050A discloses a gas well fluid accumulation prediction method based on gated recurrent neural units, which predicts the state of fluid accumulation in gas wells by converting the physical parameters in the gas well production conditions into a time series. Chinese patent CN110163442A discloses a gas well fluid accumulation prediction method based on ensemble learning, which includes the following steps: acquisition of raw gas well data, feature extraction and data preprocessing, design of base classifier, voting aggregation, and judgment of gas well fluid accumulation status.

[0004] Although numerous diagnostic or predictive methods for fluid accumulation in gas wells have emerged, they still have certain technical problems that need to be improved. For example, insufficient diagnostic or predictive accuracy can lead to the inability to effectively eradicate fluid accumulation in the wellbore, while the gas production of the problematic wells decreases, ultimately resulting in the inability of the gas wells to achieve normal and continuous production. Summary of the Invention

[0005] In response to the problems of wellbore fluid accumulation, reduced gas production, and inability to achieve normal and continuous production in some gas wells, this invention provides a method for diagnosing the fluid accumulation condition in gas wells.

[0006] This invention uses a multi-factor gas well liquid accumulation diagnosis method, combined with various drainage and gas production measures, to improve the accuracy of predicting the degree and timing of gas well liquid accumulation, thereby ensuring normal and stable gas well production.

[0007] The technical solution adopted by this invention to solve the technical problem is as follows:

[0008] This invention provides a method for diagnosing liquid accumulation conditions in gas wells, which specifically includes the following steps:

[0009] Step 1: Determine whether a gas well has liquid accumulation using the critical flow rate and critical velocity method;

[0010] Step 2: Use the kinetic energy factor method to determine if there is liquid accumulation in the gas well;

[0011] Step 3: Use the pressure gradient method to determine if there is liquid accumulation in the gas well;

[0012] Step 4: Use the flow regime method to determine if there is liquid accumulation in the gas well;

[0013] Step 5: Use the IPR method to determine if there is liquid accumulation in the gas well;

[0014] Step 6: Use the production capacity well test method to determine if there is liquid accumulation in the gas well;

[0015] Step 7: Determine the degree of liquid accumulation in the gas well.

[0016] In a preferred embodiment, in step one, the Turner critical flow rate method is used to determine whether the gas well has liquid accumulation; the Turner formula for calculating the critical flow rate is:

[0017]

[0018] Among them, v cr ρ represents the critical flow velocity for carrying liquid in a gas well, in m / s; σ represents the interfacial tension of the liquid, in N / m, where σ = 0.06 N / m for water and 0.02 N / m for condensate oil; ρ l ρ represents the density of a liquid, for water. l =1071kg / m 3 For condensate oil ρ l =721kg / m 3 ;ρ g Density of a gas, kg / m³ 3 ;

[0019] The density ρ of the gas g The calculation formula is:

[0020]

[0021] Where, γ g The gas density is represented by P; the wellbore pressure is represented by MPa; the wellbore temperature is represented by K; and the gas compressibility factor is represented by Z under the conditions of wellbore pressure P and wellbore temperature T.

[0022] The formula for calculating the critical flow rate is:

[0023]

[0024] Where, qcr This represents the critical fluid carrying capacity of a gas well, 10 4 m 3 / d; A represents the cross-sectional area of ​​the oil pipe, in meters. 2 ;

[0025] If the critical flow rate is greater than the actual gas production of the gas well, it indicates that the gas well is accumulating liquid.

[0026] In a preferred embodiment, step one involves using the Li Min critical flow rate method to determine whether the gas well has liquid accumulation; Li Min's formula for calculating the critical flow rate is:

[0027]

[0028] Among them, v cr ρ represents the critical flow velocity for carrying liquid in a gas well, in m / s; σ represents the interfacial tension of the liquid, in N / m, where σ = 0.06 N / m for water and 0.02 N / m for condensate oil; ρ l ρ represents the density of a liquid, for water. l =1071kg / m 3 For condensate oil ρ l =721kg / m 3 ;ρ g Density of a gas, kg / m³ 3 ;

[0029] The density ρ of the gas g The calculation formula is:

[0030]

[0031] Where, γ g The gas density is represented by P; the wellbore pressure is represented by MPa; the wellbore temperature is represented by K; and the gas compressibility factor is represented by Z under the conditions of wellbore pressure P and wellbore temperature T.

[0032] The formula for calculating the critical liquid carrying capacity is:

[0033]

[0034] Where, q cr This represents the critical fluid carrying capacity of a gas well, 10 4 m 3 / d; A represents the cross-sectional area of ​​the oil pipe, in meters. 2 ;

[0035] By calculating the critical liquid-carrying flow rate, if the critical liquid-carrying flow rate is greater than the actual gas production of the gas well, it indicates that the gas well has accumulated liquid.

[0036] In a preferred embodiment, the formula for calculating the gas well kinetic energy factor in step two is as follows:

[0037]

[0038] Where F represents the kinetic energy factor; V s ρ represents the gas velocity at the oil pipe shoe, in m / s; s This indicates the specific gravity of the gas as measured at the oil pipe shoe, in kg / m³. 3 Q represents daily gas production, in meters. 3 / d;γ g T represents the relative density of natural gas. s Represents downhole temperature, K; P s This indicates the flow pressure at the oil pipe shoe, in kg / cm². 2 D represents the diameter of the oil pipe, in meters; Z represents the diameter of the oil pipe. s P represents the flow pressure at the oil pipe shoe. s Compression factor under certain conditions.

[0039] By calculating the kinetic energy factor, if the kinetic energy factor is less than 8, it indicates that the gas well has accumulated liquid.

[0040] In a preferred embodiment, in step three, the pressure gradient of the gas well is calculated by using gas well pressure measurement data or by simulating the pressure distribution in the gas well shaft. The calculated pressure gradient of the gas well is then compared with the pressure gradient of a conventional gas well to determine whether the gas well has accumulated liquid. If the pressure gradient of the gas well shaft is greater than 0.02 MPa / 100m, it indicates that the gas well has accumulated liquid.

[0041] In a preferred embodiment, in step four, the flow state of the gas well is calculated to determine whether the gas well has liquid accumulation, with the judgment boundary being slug flow; if the flow state of the gas well is slug flow, it indicates that the gas well has liquid accumulation.

[0042] In a preferred embodiment, in step five, the IPR curve of the gas well is first solved according to the Vogel equation to predict the water production of the gas well under different bottom hole flowing pressures; then the minimum critical liquid-carrying flow rate of the gas well under wellhead conditions is calculated, and combined with the currently predicted water production q1, the minimum bottom hole flowing pressure required is calculated using the two-phase flow formula. The corresponding water production q2 is then found on the IPR curve. If the water production q2 is lower than the predicted water production q1, it indicates that the gas well has encountered difficulties in producing with liquid and has begun to accumulate liquid.

[0043] In a preferred embodiment, in step six, a curve relating gas well test production and pressure squares is plotted based on the well test data. The curve of a normal gas well is compared with the plotted curve relating gas well test production and pressure squares to determine whether the gas well has accumulated liquid. The curve of a normal gas well should be a straight line. If the curve of a gas well is curved, it indicates that the gas well has accumulated liquid.

[0044] As a preferred embodiment, in step six, the production capacity testing method includes the exponential production capacity testing method and the binomial production capacity testing method.

[0045] In a preferred embodiment, step seven involves calculating the liquid accumulation height in the gas well to determine the current degree of liquid accumulation.

[0046] The beneficial effects of this invention are:

[0047] This invention provides a method for diagnosing liquid accumulation in gas wells. By studying gas well liquid accumulation diagnosis technology and using different methods for complementary verification, it achieves accurate prediction of gas well liquid accumulation dynamics, forming a targeted and highly consistent multi-factor liquid accumulation diagnosis method for gas wells. This provides technical support for determining the timing of drainage and gas production measures and formulating scientific and reasonable drainage and gas production measures, thereby improving the liquid drainage capacity of gas wells and extending the stable production period of gas fields, thus ensuring normal and stable production of gas wells. Attached Figure Description

[0048] Figure 1 The main technical roadmap for a method for diagnosing liquid accumulation in gas wells provided by this invention is shown in the figure.

[0049] Figure 2 This represents the relationship between critical flow velocity and gas well production.

[0050] Figure 3 This represents the relationship between the critical flow velocity and the gas flow velocity.

[0051] Figure 4 IPR curves of water-producing gas wells under different bottom-hole flowing pressures.

[0052] Figure 5 This is a curve showing the relationship between well production and the square of pressure in a gas well, plotted based on well test data in the exponential productivity testing method.

[0053] Figure 6 This is a curve showing the relationship between well production and the square of pressure in a gas well, plotted based on well test data using the binomial productivity testing method.

[0054] Figure 7 This is the result of the calculation of the liquid accumulation height in the gas well. Detailed Implementation

[0055] The present invention will be further described in detail below with reference to the accompanying drawings.

[0056] This invention provides a method for diagnosing liquid accumulation conditions in gas wells, the main technical route of which is as follows: Figure 1 As shown, the details are as follows:

[0057] Step 1: Determine if there is liquid accumulation in the gas well using the critical flow rate (rate) method;

[0058] Step 2: Use the kinetic energy factor method to determine if there is liquid accumulation in the gas well;

[0059] Step 3: Use the pressure gradient method to determine if there is liquid accumulation in the gas well;

[0060] Step 4: Use the flow regime method to determine if there is liquid accumulation in the gas well;

[0061] Step 5: Use the IPR (Inflow Performance Relationship Curve) method to determine if there is liquid accumulation in the gas well;

[0062] Step 6: Use the production capacity well test method to determine if there is liquid accumulation in the gas well;

[0063] Step 7: Determine the degree of liquid accumulation in the gas well.

[0064] By calculating the liquid accumulation height in the gas well, the current degree of liquid accumulation in the gas well can be determined, providing a basis for taking corresponding drainage and gas production measures in the future.

[0065] The present invention provides a method for diagnosing liquid accumulation conditions in gas wells, the specific implementation process of which is as follows:

[0066] Step 1: Determine whether a gas well has liquid accumulation using the critical flow rate and critical velocity method;

[0067] By calculating the critical flow rate and critical velocity of a gas well, and comparing the actual gas production with the critical flow rate, it can be determined whether the gas well has liquid accumulation. If the actual gas production is less than the critical flow rate, it indicates that the gas well has liquid accumulation. The specific steps include:

[0068] S1.1: Turner's critical flow method;

[0069] The specific formula for Turner to calculate the critical flow velocity is as follows:

[0070]

[0071] Among them, v cr ρ represents the critical flow velocity for carrying liquid in a gas well, in m / s; σ represents the interfacial tension of the liquid, in N / m, where σ = 0.06 N / m for water and 0.02 N / m for condensate oil; ρ l ρ represents the density of a liquid, for water. l =1071kg / m 3 For condensate oil ρ l =721kg / m 3 ;ρ g Density of a gas, kg / m³ 3 .

[0072] The density ρ of the gas g The specific calculation formula is as follows:

[0073]

[0074] Where, γ g The gas density is represented by P; the wellbore pressure is represented by MPa; the wellbore temperature is represented by K; and the gas compressibility factor is represented by the wellbore pressure P and wellbore temperature T.

[0075] The formula for calculating the critical flow rate is as follows:

[0076]

[0077] Where, q cr This represents the critical flow rate for carrying liquid in a gas well, 10 4 m 3 / d; A represents the cross-sectional area of ​​the oil pipe, in meters. 2 .

[0078] If the critical flow rate is greater than the actual gas production of the gas well, it indicates that the gas well is accumulating liquid.

[0079] S1.2: Li Min's critical flow method;

[0080] The formula used by Li Min to calculate the critical flow velocity is as follows:

[0081]

[0082] Among them, v cr ρ represents the critical flow velocity for carrying liquid in a gas well, in m / s; σ represents the interfacial tension of the liquid, in N / m, where σ = 0.06 N / m for water and 0.02 N / m for condensate oil; ρ l ρ represents the density of a liquid, for water. l =1071kg / m 3 For condensate oil ρ l =721kg / m 3 ;ρ g Density of a gas, kg / m³ 3 .

[0083] The density ρ of the gas g The specific calculation formula is as follows:

[0084]

[0085] Where, γ g The gas density is represented by P; the wellbore pressure is represented by MPa; the wellbore temperature is represented by K; and the gas compressibility factor is represented by the wellbore pressure P and wellbore temperature T.

[0086] The formula for calculating the critical flow rate is as follows:

[0087]

[0088] Where, q cr This represents the critical flow rate for carrying liquid in a gas well, 10 4 m 3 / d; A represents the cross-sectional area of ​​the oil pipe, in meters. 2 .

[0089] If the critical flow rate is greater than the actual gas production of the gas well, it indicates that the gas well is accumulating liquid.

[0090] The relationship between critical flow velocity and gas well production is as follows: Figure 2 As shown, the relationship between the critical flow velocity and the gas flow velocity is as follows: Figure 3 As shown. According to Figure 2 and Figure 3 It can be seen that the gas well production is 4×10 4 m 3 At / d, compared with Coleman's critical flow method (Coleman, SBA New Look at Predicting Gas Well Load Up[J] JPT, Mar 1991.), Nosseir's critical flow method (Nosseir, MAA New Approach for Accurate Prediction of Loading in Gas Well Under Different Flowing Conditions[J]. spe37408), Wang Yizhong's critical flow method (Wang Yizhong, Liu Qingwen. A new method for calculating the minimum liquid-carrying critical flow rate of gas wells[J]. Daqing Petroleum Geology and Development, 2007, 26(6):82-85.), Peng Chaoyang's critical flow method (Peng Chaoyang, Research on the liquid-carrying critical flow rate of gas wells[J]. Xinjiang Petroleum Geology, 2010, 31(1):72-74.), Turner's critical flow method (Turner, RG Analysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Well[J]. JPT, Nov 1991 ... The critical flow rates calculated by the Turner critical flow rate method (1969) and the Li Min critical flow rate method (Li Min, Sun Lei, Li Shilun, et al. New view on continuous-removal liquids from gas wells[J]. spe70016) are very close to the baseline. Therefore, this invention selects the Turner critical flow rate method and the Li Min critical flow rate method to determine whether there is liquid accumulation in the gas well.

[0091] Step 2: Use the kinetic energy factor method to determine if there is liquid accumulation in the gas well;

[0092] By calculating the kinetic energy factor of the gas well and comparing it with the kinetic energy factor reference value (generally, the kinetic energy factor reference value is set to 8, but the kinetic energy factor reference value needs to be set according to the actual situation of the oilfield), it can be determined whether the gas well has liquid accumulation.

[0093] The kinetic energy factor of a gas well reflects the flow characteristics of the gas-water two-phase system within the tubing. The specific formula for calculating the kinetic energy factor of a gas well is as follows:

[0094]

[0095] Where F represents the kinetic energy factor; V s ρ represents the gas velocity at the oil pipe shoe, in m / s; s This indicates the specific gravity of the gas as measured at the oil pipe shoe, in kg / m³. 3 Q represents daily gas production, in meters. 3 / d;γ g T represents the relative density of natural gas. s Represents downhole temperature, K; P s This indicates the flow pressure at the oil pipe shoe, in kg / cm². 2 D represents the diameter of the oil pipe, in meters; Z represents the diameter of the oil pipe. s P represents the flow pressure at the oil pipe shoe. s Compression factor under certain conditions.

[0096] When the inner diameter of the tubing in a gas well is determined, the formation temperature and formation pressure change little in the short term. The liquid carrying capacity of the water-producing gas well is mainly related to the daily gas production and the relative density of natural gas. The kinetic energy factor of the gas well is mainly related to parameters such as gas production, relative density of natural gas, and flowing pressure.

[0097] Many oilfields use kinetic energy factors to determine whether there is fluid accumulation in the wellbore. Current research sets the kinetic energy factor at 8 as the standard for determining fluid accumulation, assuming that a kinetic energy factor less than 8 indicates fluid accumulation. However, whether this standard is applicable to a specific gas well needs to be verified using measured data. Therefore, it is necessary to conduct actual production dynamic analysis of the gas well and determine the fluid accumulation judgment standard for that well based on actual production dynamic data.

[0098] Step 3: Use the pressure gradient method to determine if there is liquid accumulation in the gas well;

[0099] Calculate the pressure gradient of the gas well by using the pressure measurement data of the gas well or simulating the pressure distribution in the gas wellbore (pressure gradient = (bottom hole pressure - wellhead pressure) * 100 / well depth), and compare the calculated pressure gradient of the gas well with the pressure gradient of a conventional gas well (the empirical value of the pure gas column pressure gradient is about 0.02 MPa / 100 m) to determine whether the gas well is liquid-loading. If the pressure gradient of the gas wellbore is greater than 0.02 MPa / 100 m, it indicates that the gas well is liquid-loading.

[0100] Step Four: Judge whether the gas well is liquid-loading by the flow regime method;

[0101] Judge whether the gas well is liquid-loading according to the calculated flow regime in the gas wellbore, and the judgment boundary is slug flow. If the flow regime in the gas wellbore is slug flow, it indicates that the gas well is liquid-loading.

[0102] Step Five: Judge whether the gas well is liquid-loading by the IPR method for gas wells with water production;

[0103] S5.1: Solve the IPR curve of the gas well with water production according to the Vogel equation to predict the gas well water production under different bottom hole flowing pressures, and the results are as Figure 4 shown;

[0104] S5.2: Calculate the minimum critical liquid-carrying flow rate of the gas well under wellhead conditions. Combine the currently predicted water production q1, and use the two-phase flow formula (Beggs-Brill method, A Study of Two-Phase Flow in Inclined Pipes, H.Dale Beggs, *SPE-AIME, U. of Tulsa) to calculate the required minimum bottom hole flowing pressure. Find the corresponding water production q2 on the IPR curve. If the water production q2 is lower than the predicted water production q1, that is, q2 < q1, it means that the gas well has difficulty in producing with liquid, and liquid-loading starts.

[0105] Step Six: Judge whether the gas well is liquid-loading by the productivity test method;

[0106] Draw a relationship curve between the productivity test production and the square of the pressure of the gas well according to the test well data, and compare the curve of the normal gas well with the relationship curve between the productivity test production and the square of the pressure of the drawn gas well to determine whether the gas well is liquid-loading. The curve of the normal gas well should be a straight line. If the gas well curve is bent, it indicates that the gas well is liquid-loading.

[0107] Among them, this productivity test method mainly includes two types, namely the exponential productivity test method and the binomial productivity test method; the relationship curve between the productivity test production and the square of the pressure of the gas well drawn in the exponential productivity test method is as Figure 5 shown (the regression equation is: y = 1.4833x - 0.4478, and the correlation coefficient is: R = 1.0000). The relationship curve between the productivity test production and the square of the pressure of the gas well drawn by the binomial productivity test method is as Figure 6 As shown (the regression equation is: y = 0.0289x + 0.9456, and the correlation coefficient is: R = 0.9961).

[0108] Step 7: Based on the gas well fluid accumulation judgment results obtained from any of Steps 1 to 6, analyze and judge the degree of gas well fluid accumulation;

[0109] By calculating the liquid accumulation height in the gas well, the current degree of liquid accumulation in the well can be determined, providing a basis for subsequent drainage and gas production measures. The calculation results for the liquid accumulation height in the gas well are as follows: Figure 7 As shown, the intersection of the static pressure gradient line and the multiphase pipe flow pressure line is the liquid accumulation depth point, and the height from the intersection point to the bottom of the well is the liquid accumulation height of the gas well.

[0110] The technical solutions of the present invention will be clearly and completely described below with reference to the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the scope of protection of the present invention.

[0111] Example 1

[0112] This invention utilizes the kinetic factor method, applicable to the diagnosis of liquid accumulation in gas wells, to determine whether a gas well has liquid accumulation. In conjunction with the project team and work area, based on the three nodes of formation-wellbore-surface, and combined with the gas well production dynamic curve and monitoring results, a set of diagnostic methods and procedures for problematic gas wells was summarized. Based on the causes of gas well anomalies and the applicable conditions of the measures, optimization suggestions for measures were proposed for 24 wells, of which 22 were implemented on-site, achieving an implementation rate of 92% and good results. Using the multi-factor liquid accumulation diagnosis and drainage measure optimization method for gas wells, targeted drainage assistance measures were proposed, resulting in a cumulative annual increase in gas production of approximately 6 million cubic meters per well, demonstrating considerable economic benefits.

[0113] This invention discloses a method for diagnosing liquid accumulation conditions in gas wells. Those skilled in the art can refer to this document and appropriately modify the process parameters to achieve the desired result. It is particularly important to note that all similar substitutions and modifications are obvious to those skilled in the art and are considered to be included in this invention. The product of this invention has been described through preferred embodiments, and those skilled in the art can clearly modify or appropriately alter and combine the product described herein without departing from the content, spirit, and scope of this invention to realize and apply the technology of this invention.

Claims

1. A method for diagnosing liquid accumulation conditions in gas wells, characterized in that, Includes the following steps: Step 1: Determine whether a gas well has liquid accumulation using the critical flow rate and critical velocity method; Step 2: Use the kinetic energy factor method to determine if there is liquid accumulation in the gas well; Step 3: Use the pressure gradient method to determine if there is liquid accumulation in the gas well; Step 4: Use the flow regime method to determine if there is liquid accumulation in the gas well; Step 5: Use the IPR method to determine if there is liquid accumulation in the gas well; Step 6: Use the production capacity well test method to determine if there is liquid accumulation in the gas well; Step 7: Determine the degree of liquid accumulation in the gas well.

2. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step one, the Turner critical flow method is used to determine whether the gas well has liquid accumulation; the Turner formula for calculating the critical flow velocity is: Among them, v cr ρ represents the critical fluid-carrying velocity of the gas well, in m / s; σ represents the interfacial tension of the liquid, in N / m, where σ = 0.06 N / m for water and 0.02 N / m for condensate oil; l ρ represents the density of a liquid, for water. l =1071kg / m 3 For condensate oil ρ l =721kg / m 3 ;ρ g Density of a gas, kg / m³ 3 ; The density ρ of a gas g The calculation formula is: Where, γ g The gas represents the relative density of natural gas; P represents the wellbore pressure (MPa); T represents the wellbore temperature (K); and Z represents the gas compressibility factor under the conditions of wellbore pressure P and wellbore temperature T. The formula for calculating the critical liquid carrying capacity is: Where, q cr This represents the critical fluid carrying capacity of a gas well, 10 4 m 3 / d; A represents the cross-sectional area of ​​the oil pipe, in meters. 2 ; By calculating the critical liquid-carrying flow rate, if the critical liquid-carrying flow rate is greater than the actual gas production of the gas well, it indicates that the gas well has accumulated liquid.

3. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step one, the Li Min critical flow rate method is used to determine whether the gas well has liquid accumulation; Li Min's formula for calculating the critical flow velocity is: Among them, v cr ρ represents the critical fluid-carrying velocity of the gas well, in m / s; σ represents the interfacial tension of the liquid, in N / m, where σ = 0.06 N / m for water and 0.02 N / m for condensate oil; l ρ represents the density of a liquid, for water. l =1071kg / m 3 For condensate oil ρ l =721kg / m 3 ;ρ g Density of a gas, kg / m³ 3 ; The density ρ of a gas g The calculation formula is: Where, γ g The gas represents the relative density of natural gas; P represents the wellbore pressure (MPa); T represents the wellbore temperature (K); and Z represents the gas compressibility factor under the conditions of wellbore pressure P and wellbore temperature T. The formula for calculating the critical liquid carrying capacity is: Where, q cr This represents the critical fluid carrying capacity of a gas well, 10 4 m 3 / d; A represents the cross-sectional area of ​​the oil pipe, in meters. 2 ; By calculating the critical liquid-carrying flow rate, if the critical liquid-carrying flow rate is greater than the actual gas production of the gas well, it indicates that the gas well has accumulated liquid.

4. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step two, the formula for calculating the gas well kinetic energy factor is: Where F represents the kinetic energy factor; V s ρ represents the gas velocity at the oil pipe shoe, in m / s; s This indicates the specific gravity of the gas as measured at the oil pipe shoe, in kg / m³. 3 Q represents daily gas production, in meters. 3 / d;γ g T represents the relative density of natural gas. s Represents downhole temperature, K; P s This indicates the flow pressure at the oil pipe shoe, in kg / cm². 2 D represents the diameter of the oil pipe, in meters; Z s P represents the flow pressure at the oil pipe shoe. s Compression factor under the given state; By calculating the kinetic energy factor, if the kinetic energy factor is less than 8, it indicates that the gas well has accumulated liquid.

5. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step three, the pressure gradient of the gas well is calculated by using gas well pressure measurement data or simulation calculation of the gas well shaft pressure distribution. The calculated pressure gradient of the gas well is compared with the pressure gradient of a conventional gas well to determine whether the gas well has liquid accumulation. If the gas well shaft pressure gradient is greater than 0.02 MPa / 100m, it indicates that the gas well has liquid accumulation.

6. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step four, based on the flow pattern of the gas wellbore, it is determined whether the gas well has liquid accumulation. The judgment boundary is slug flow. If the flow pattern of the gas wellbore is slug flow, it indicates that the gas well has liquid accumulation.

7. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step five, the IPR curve of the gas well is first solved according to the Vogel equation to predict the water production of the gas well under different bottom hole flowing pressures; then the minimum critical liquid-carrying flow rate of the gas well under the wellhead conditions is calculated, and combined with the currently predicted water production q1, the minimum required bottom hole flowing pressure is calculated using the two-phase flow formula. The corresponding water production q2 is found on the IPR curve. If the water production q2 is lower than the predicted water production q1, it indicates that the gas well has encountered difficulties in producing with liquid and has begun to accumulate liquid.

8. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step six, a curve relating well production and pressure squares is plotted based on the well test data. The curve of a normal gas well is compared with the plotted curve to determine whether the gas well has accumulated liquid. A normal gas well curve should be a straight line. If the gas well curve is curved, it indicates that the gas well has accumulated liquid.

9. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step six, the production capacity testing method includes the exponential production capacity testing method and the binomial production capacity testing method.

10. The method for diagnosing liquid accumulation conditions in gas wells according to claim 1, characterized in that, In step seven, the current degree of liquid accumulation in the gas well is determined by calculating the liquid accumulation height.

Images