Method for simulating dynamic liquid accumulation and yield change of gas well

Abstract

The invention provides a method for simulating dynamic liquid accumulation and yield change of a gas well. The method comprises the steps that S01, a productivity equation is obtained through calculation and fitting according to production history or pilot production data; s02, diagnosing whether the well accumulates liquid or not according to the pressure distribution curve of the liquid column and the fluid in the oil pipe; s03, calculating the critical liquid carrying capacity of the gas well under the current condition; s04, the wellbore liquid accumulation height increment and the liquid accumulation height of the next time step length and the bottomhole flowing pressure increment and the bottomhole flowing pressure of the next time step length are calculated; s05, the formation pressure of the next time step is calculated; s06, according to the formation pressure and the flowing bottomhole pressure, the formation gas production rate under the current step is calculated; and S07, repeating the steps S02 to S05 to obtain the values of the gas well liquid accumulation height, the gas production rate, the formation pressure and the flowing bottomhole pressure changing along with the time, so as to realize dynamic prediction. According to the method, the future gas well liquid accumulation height and yield change can be predicted; a lifting process scheme in the full life cycle of the gas well can be formulated, and the future production trend of the gas well is defined.

Description

Technical Field

[0001] The present invention relates to the technical field of gas field development, and in particular to the prediction of dynamic liquid accumulation height and production of a gas wellbore, and specifically to a method for simulating dynamic liquid accumulation and production changes of a gas well. Background Art

[0002] During the development process of gas reservoirs at home and abroad, water production from the formation exists to varying degrees. During the production process, gas and liquid flow out of the formation and are produced on the ground through the wellbore. In the early stage of production, the gas well has a high gas production, and the gas and liquid phases flow upward in an annular flow. The liquid is carried in two ways: droplets entrained in the gas core and liquid film attached to the pipe wall. As the formation pressure decreases, the gas production of the gas well decreases, resulting in the reversal of the flow of liquid (droplets / liquid film) in the wellbore, which cannot be brought out of the ground, resulting in liquid accumulation. Liquid accumulation in the wellbore causes a significant increase in the wellbore pressure gradient, thereby increasing the decline in production, seriously affecting the final recovery rate of the gas well. Therefore, accurately predicting the time of liquid accumulation in gas wells and taking timely water drainage and gas production process measures are of great significance to maintaining stable production of low-yield gas wells.

[0003] At present, the research on gas well liquid accumulation is mainly focused on the diagnosis of liquid accumulation and the prediction of liquid accumulation height. The determination of liquid accumulation height is mostly carried out with the help of relevant test parameters of the wellbore / wellhead at a certain time or period of the gas well. The formation pressure is a point value (assuming it is a constant value). Because it relies on the current relevant test parameters, it is impossible to predict the future gas well liquid accumulation height and production changes.

[0004] Therefore, it is of great significance to study a method that can predict future changes in gas well liquid loading height and production. Summary of the invention

[0005] The purpose of the present invention is to solve at least one of the above-mentioned deficiencies in the prior art. For example, one of the purposes of the present invention is to clarify the future production dynamics of the gas well and formulate a lifting process plan within the entire life cycle. The second purpose of the present invention is to provide a method for predicting the unsteady production state of the gas well by coupling the gas well reservoir production capacity and the unsteady phase pipe flow of the wellbore.

[0006] In order to achieve the above object, the present invention provides a method for simulating dynamic liquid loading and production changes in a gas well, comprising the following steps:

[0007] S01 calculates and fits the production capacity equation based on production history or trial production data;

[0008] S02 diagnoses whether the well is filled with liquid according to the pressure distribution curves of the liquid column and the fluid in the oil pipe. If the two pressure distribution curves have no intersection, there is no liquid accumulation. If there is an intersection, there is liquid accumulation. The depth value corresponding to the intersection is the depth of the liquid level in the wellbore. The fluid pressure distribution curve is the pressure distribution curve along the wellbore of the gas well;

[0009] S03 compares the current gas well production, and gradually increases or decreases the liquid production using a trial algorithm until the current gas well production is consistent with the critical liquid-carrying gas volume under the calculated standard condition, and the corresponding liquid production volume calculated by the trial algorithm is the critical liquid-carrying gas volume under the current condition;

[0010] S04 calculates the current amount of liquid accumulated in the wellbore according to the critical liquid carrying capacity of the gas well and the amount of liquid flowing into the bottom of the well from the formation, calculates the increment of the wellbore liquid accumulation height at the next time step according to the current amount of liquid accumulated in the wellbore and the inner diameter of the oil pipe, and then calculates the wellbore liquid accumulation height at the next time step, calculates the increment of the bottomhole flowing pressure at the next time step according to the bottomhole flowing pressure at the current time step, and then calculates the bottomhole flowing pressure at the next time step;

[0011] S05 obtains the formation pressure of the next time step according to the material balance equation, actual reservoir modeling results or historical matching empirical formula;

[0012] S06 calculates the formation gas production at the current step through the production capacity equation according to the formation pressure and the bottom hole flow pressure;

[0013] S07 repeats S02 to S05 to obtain the values ​​of the liquid accumulation height, gas production, formation pressure and bottom hole flow pressure of the gas well changing with time, so as to realize dynamic prediction.

[0014] Optionally, the data include reservoir data, fluid physical property parameters, gas well production data and wellbore structure data.

[0015] Optionally, the pressure distribution of the liquid column in the oil pipe is calculated by using a static liquid column pressure drop calculation model with the pressure at the pipe shoe as an initial value.

[0016] Optionally, according to the calculation result of the production capacity equation, the pressure at the pipe shoe is calculated downward along the casing annulus according to a static gas column pressure drop calculation model.

[0017] Optionally, the pressure distribution of the fluid in the oil pipe is calculated downward using the gas-liquid two-phase flow equation with the wellhead oil pressure as the initial value.

[0018] Optionally, the critical liquid carrying capacity of the gas well is calculated based on a liquid film model, and the liquid film model is a relationship between the vertical pipeline interface shear stress and the dimensionless liquid film thickness calculated according to a dimensionless expression of the annular flow interface shear stress. The interface shear stress that changes with the dimensionless liquid film thickness has a minimum value, which is the critical shear stress value of liquid accumulation.

[0019] Optionally, the calculation of the critical liquid carrying capacity of the gas well also requires the calculation of the gas-liquid interface friction factor, the critical liquid carrying flow rate and the critical liquid carrying gas capacity.

[0020] Optionally, the calculation of the liquid accumulation height of the gas well at the next time step is to calculate the current amount of liquid flowing from the formation to the bottom of the well according to the gas volume and the gas-liquid ratio.

[0021] Optionally, the gas well liquid accumulation height at the next time step is the initial wellbore liquid accumulation height plus an increment of the wellbore liquid accumulation height at the next time step.

[0022] Optionally, the amount of liquid currently accumulated in the wellbore in the calculation of the increment of the wellbore liquid accumulation height at the next time step is the critical liquid carrying capacity of the gas well under current conditions minus the amount of liquid currently flowing into the bottom of the well from the formation.

[0023] Optionally, the bottom hole flow pressure increment of the next time step is the difference between the pressure value at the initial liquid level height of the wellbore and the pressure value at the liquid accumulation height of the wellbore in the next time step.

[0024] Optionally, the bottom hole flow pressure of the next time step is the sum of the bottom hole flow pressure of the previous time step and the bottom hole flow pressure increment of the next time step.

[0025] Optionally, the material balance equation calculates the dynamic reserves based on the cumulative gas production, water invasion, cumulative water production, natural gas volume coefficient, natural gas volume system in the original state and water volume coefficient.

[0026] Optionally, the formation pressure is calculated by establishing a material balance equation based on the cumulative gas production over the years and the formation pressure, and combining the current cumulative gas production of the gas well to calculate the current formation pressure.

[0027] Optionally, the production capacity equation calculates the formation gas production based on the fitting coefficient, the formation pressure and the bottom hole flowing pressure.

[0028] Compared with the prior art, the beneficial effects of the present invention include at least one of the following:

[0029] 1) The present invention is coupled with the formation pressure and can calculate the real-time dynamic value.

[0030] 2) The present invention realizes the prediction of future gas well liquid accumulation height and production changes.

[0031] 3) The present invention can formulate a lifting process plan for the entire life cycle of a gas well and clarify the future production dynamics of the gas well. BRIEF DESCRIPTION OF THE DRAWINGS

[0032] The above and other objects and / or features of the present invention will become more apparent through the following description in conjunction with the accompanying drawings, in which:

[0033] Figure 1 The pressure distribution of the liquid column and the pressure distribution diagram of the fluid in an exemplary embodiment of the present invention are shown.

[0034] Figure 2A A graph showing the relationship between the vertical pipe interface shear stress and the dimensionless liquid film thickness in an exemplary embodiment of the present invention is shown.

[0035] Figure 2B for Figure 2A Grayscale image of .

[0036] Figure 3 A schematic diagram of a dynamic prediction calculation process in an exemplary embodiment of the present invention is shown.

[0037] Figure 4A A diagram showing the liquid loading diagnosis result of a gas well fluid model in an embodiment of the present invention is shown.

[0038] Figure 4B for Figure 4A Grayscale image of .

[0039] Figure 5A A diagram showing the height of fluid accumulation in a well in an embodiment of the present invention is shown.

[0040] Figure 5B for Figure 5A Grayscale image of .

[0041] Fig. 6A The graph showing the change of formation fluid production and wellbore fluid carrying capacity over time in an embodiment of the present invention is shown.

[0042] Figure 6B for Fig. 6A Grayscale image of .

[0043] Figure 7 A graph showing the change of wellbore liquid accumulation height over time in an embodiment of the present invention is shown. DETAILED DESCRIPTION

[0044] Hereinafter, the method for simulating dynamic liquid loading and production change of a gas well according to the present invention will be described in detail in conjunction with exemplary embodiments.

[0045] Exemplary Embodiments

[0046] This exemplary embodiment provides a method for simulating dynamic liquid loading and production changes in a gas well, comprising the following steps:

[0047] S01: Calculate and fit the production capacity equation based on production history or trial production data.

[0048] The data described in this embodiment includes reservoir data, fluid physical property parameters, gas well production data and wellbore structure data, and the production capacity equation is obtained by calculation and fitting based on production history or test production data.

[0049] S02: Diagnose whether the well is filled with liquid based on the pressure distribution curves of the liquid column and the fluid in the oil pipe. If there is no intersection between the two pressure distribution curves, there is no liquid accumulation. If there is an intersection, there is liquid accumulation. The depth value corresponding to the intersection is the depth of the liquid level in the wellbore. The fluid pressure distribution curve is the pressure distribution curve along the wellbore of the gas well.

[0050] In this embodiment, the gas production is calculated according to the production capacity equation, and the pressure P at the pipe shoe is calculated according to the static gas column pressure drop calculation model along the casing annulus downward. tb , pressure at the tube shoe P tb The result calculated by the capacity equation is equal to the pressure P at the tube shoe. tb The static liquid column pressure drop calculation model is used to calculate the pressure distribution of the liquid column in the oil pipe from the initial value upward. The static liquid column pressure drop calculation model adopts the Hasan model, such as Figure 1 As shown by line B; the wellhead oil pressure P t The pressure distribution of the fluid in the oil pipe is calculated downward using the gas-liquid two-phase flow equation as the initial value. The gas-liquid two-phase flow equation here is the Beggs-Brill model, such as Figure 1 The two curves are plotted in the same coordinate system. If there is no intersection, the well does not accumulate liquid. Line A is the pressure distribution along the wellbore of the gas well. Line A is the pressure distribution along the wellbore under the pure gas column above the liquid surface, and line B is the pressure distribution along the wellbore under the pure liquid column below the liquid surface. If there is an intersection, the well accumulates liquid, and the depth value corresponding to the intersection is the depth of the liquid level in the wellbore. Figure 1 As shown in Dh.

[0051] S03: Compare the current gas well production and use a trial algorithm to gradually increase or decrease the liquid production until the current gas well production is consistent with the critical liquid-carrying gas volume under the calculated standard conditions. The corresponding liquid production calculated by the trial algorithm is the critical liquid-carrying volume of the gas well under the current conditions.

[0052] In this embodiment, the critical liquid carrying flow rate of the gas well is calculated based on the liquid film model. The relationship between the vertical pipeline interface shear stress and the dimensionless liquid film thickness is calculated according to the dimensionless expression (1) of the annular flow interface shear stress, as follows: Figure 2A and Figure 2B As shown, from Figure 2A It can be seen that when the apparent flow rate of the liquid phase is small, the interfacial shear stress that varies with the dimensionless liquid film thickness has a minimum value. The liquid film model based on the minimum shear stress believes that at this time, the liquid film in the annular flow begins, and liquid accumulates in the pipeline. The corresponding dimensionless liquid film thickness is the critical liquid film thickness; Figure 2B for Figure 2A Grayscale image of .

[0053]

[0054] Where τ1 is the shear stress on the gas-liquid interface, N / m; ρG , ρ L They are respectively the gas phase and liquid phase densities, kg / m 3 ; δ L is the dimensionless liquid film thickness, m; C L is the liquid phase Blasius coefficient, which is 16 for laminar flow and 0.046 for turbulent flow; v SL，film is the apparent velocity corresponding to the liquid phase flow rate of the liquid film; d is the inner diameter of the oil pipe, m; μ L is the liquid viscosity, Pa.s; μ G is the gas phase viscosity, Pa.s; θ is the angle between the pipeline axis and the vertical direction, rad.

[0055] The interfacial shear stress that changes with the dimensionless liquid film thickness has a minimum value, which is the critical shear stress value τ1 of the effusion. The critical liquid-carrying flow rate is solved according to the Wallis annular flow interfacial shear stress formula (2):

[0056]

[0057] Among them, δ avgL is the average dimensionless liquid film thickness, m; υ SG is the gas phase apparent velocity, m / s; f1 is the gas-liquid interface friction factor.

[0058] The calculation of the gas-liquid interface friction factor f1 refers to the relationship (3) given by Shekhar et al.:

[0059] f1=0.005[1+340(cosθ)δ avgL ] (3)

[0060] Among them, δ avgL is the average dimensionless liquid film thickness, θ is the angle between the pipeline axis and the vertical direction, rad.

[0061] Critical liquid-gas volume Q under standard conditions sc Calculate according to formula (4):

[0062]

[0063] Among them, SG is the gas phase apparent velocity, m / s; Z is the natural gas deviation factor; T is the temperature, K; A is the cross-sectional area of ​​the oil pipe, m 2 ; p is pressure, MPa.

[0064] Compared with the current gas well production, the trial algorithm is used to gradually increase or decrease the liquid production until the current gas well production is consistent with the critical liquid-carrying gas volume under standard conditions calculated by formula (4). The corresponding liquid production calculated by the trial algorithm is the liquid carrying volume Q0 of the gas well under current conditions.

[0065] S04: Calculate the current amount of liquid accumulated in the wellbore according to the critical liquid carrying capacity of the gas well and the amount of liquid flowing from the formation to the bottom of the wellbore, calculate the increment of the wellbore liquid accumulation height for the next time step according to the current amount of liquid accumulated in the wellbore and the inner diameter of the oil pipe, and then calculate the wellbore liquid accumulation height for the next time step, calculate the increment of the bottomhole flowing pressure for the next time step according to the bottomhole flowing pressure of the current time step, and then calculate the bottomhole flowing pressure for the next time step. Calculate the increment of the bottomhole flowing pressure for the next time step according to the increment of the liquid accumulation height, and the bottomhole flowing pressure for the next time step is the sum of the bottomhole flowing pressure for the previous time step and the increment of the bottomhole flowing pressure for the next time step.

[0066] In this embodiment, the change in the liquid accumulation height of the gas well is calculated by calculating the current liquid volume Qc flowing from the formation to the bottom of the well according to formula (5):

[0067] Q C =R G ×q g (5)

[0068] Among them, R G is the gas-liquid ratio, q g is the gas volume, m 3 .

[0069] According to formula (6), calculate the current liquid volume Q accumulated in the wellbore L :

[0070] Q L =Q0-Q C (6)

[0071] According to formula (7), the increment of wellbore liquid accumulation height Δh0, m in the current time step is:

[0072]

[0073] Among them, Q L is the amount of liquid in the wellbore, m 3 ; Q0 is the liquid carrying capacity of the gas well, m 3 ; D is the inner diameter of the oil pipe, m.

[0074] In this embodiment, the height of the liquid accumulation in the wellbore at the next time step is h1=h0+Vh0, wherein h0 is the initial height of the liquid accumulation in the wellbore.

[0075] The bottom hole pressure of the current time step is calculated based on the production capacity equation, and the pressures when the liquid level is h0 and h1 are calculated respectively. According to the formula P = P0 + ρgh, the pressures when the liquid level is h0 and h1 are calculated based on the bottom hole pressure; the pressure difference between h0 and h1 is the bottom hole pressure increment ΔP for the next step. wf , the bottom hole pressure of the next time step is P wf1, the bottom hole pressure of the next time step is the bottom hole pressure of the previous time step plus the bottom hole pressure increment of the next time step.

[0076] S05: Calculate the formation pressure for the next time step based on the material balance equation, actual reservoir modeling results or historical fitting empirical formula. Assuming the current formation pressure is P1, calculate the dynamic reserve G1 through P1, compare the dynamic reserve G1 with the actual dynamic reserve G, and if it is within the error range, output P1 as the current formation pressure of the gas well; if the error is too large, increase or decrease P1, and repeat the above steps until the result is within the error range.

[0077] In this embodiment, the formation pressure can be calculated by the material balance equation of formula (8), or by the actual reservoir modeling results or the historical matching empirical formula to obtain the formation pressure P at the next time step. R1 .

[0078]

[0079] Among them, G is the dynamic reserve (gas storage capacity), 10 8 m 3 ; G p is the cumulative gas production, 10 8 m 3 ; B gi W is the volume coefficient of natural gas in the original state; p is the cumulative water production, 10 4 m 3 ; W e is the water intrusion, 10 4 m 3 ; B g is the volume coefficient of natural gas; B w is the volume coefficient of water.

[0080] S06: Calculate the formation gas production at the current step through the production capacity equation according to the formation pressure and bottom hole flow pressure.

[0081] The calculated formation pressure P R1 and bottom hole pressure P wf1 Substitute into the production capacity equation and calculate the gas production q at the current time step sc1 .

[0082] S07: Repeat S02 to S05 to obtain the values ​​of the liquid accumulation height, gas production, formation pressure and bottom hole flow pressure of the gas well changing with time, so as to realize dynamic prediction.

[0083] In this embodiment, the calculation process for simulating the dynamic liquid accumulation and production change of the gas wellbore is as follows: Figure 3As shown in the figure. It can be seen from the figure that according to the basic data, it is first determined whether the wellbore is filled with liquid. According to the calculated pressure distribution curves of the liquid column and the fluid in the oil pipe, if they do not intersect within the working well depth range, there is no liquid accumulation in the wellbore; at the same time, the pressure distribution curve along the wellbore can be obtained, which is the pressure distribution curve of the fluid in the oil pipe. If the pressure distribution curves of the liquid column and the fluid in the oil pipe intersect within the working well depth range, there is liquid accumulation in the wellbore, and the depth value corresponding to the intersection of the two pressure distribution curves is the depth of the liquid level of the wellbore liquid accumulation. According to the initial liquid accumulation height, the current amount of liquid flowing from the formation to the bottom of the well and the current amount of liquid accumulated in the wellbore, the height of the wellbore liquid accumulation in the next time step can be calculated. According to the formation pressure and the bottom hole flow pressure, the gas production in the current time step can be calculated. The time step can be in units of days or months as required. Repeating S02~S05 operations can realize the dynamic acquisition of the wellbore liquid accumulation height, gas production, formation pressure and bottom hole flow pressure values, and realize dynamic prediction.

[0084] In order to better understand the above exemplary embodiments of the present invention, they are further described below with reference to specific examples.

[0085] Example 1

[0086] In this example, the method of the present invention is described by taking the Wei 202H13-5 well as an example.

[0087] Wellhead oil pressure 2.45MPa, formation pressure 25MPa, initial gas production 4.55×104m 3 / d, water output 2.2m 3 / d, flow pressure 4.7MPa, gas production index 174.1m 3 / (d.MPa), formation production gas-liquid ratio 20681Sm 3 / m 3 .

[0088] According to the well test data, the gas well productivity equation is determined:

[0089] P r 2 -P wf 2 =Aq 2 +Bq (9)

[0090]

[0091]

[0092] Where Pr is the reservoir pressure (here the reservoir pressure is equal to the formation pressure), MPa; P wf is the bottom hole flowing pressure, MPa; q is the formation gas production, m 3 / d; A and B are binomial fitting coefficients; h is the effective thickness of the reservoir, m; re is the radius of the oil well supply (drainage) edge, m; r w is the borehole radius, m; β is the turbulent velocity coefficient, kPa / (m 3 / d) 2 ; S is the skin coefficient, which is related to the well completion method, bottom hole pollution or production increase measures, and can be obtained from the pressure recovery curve; is the natural gas deviation factor under average temperature conditions; K is the gas reservoir permeability; T is the temperature, K; γ g is the relative density of gas; is the viscosity of natural gas at average temperature.

[0093] The A obtained by fitting is 0.00368MPa 2 / (10 3 m 3 / d) 2 , B is 13.08352MPa 2 / (10 3 m 3 / d).

[0094] Gas Well Liquid Loading Diagnosis

[0095] (1) Assuming that there is pure gas in the casing annulus, calculate the tubing shoe pressure P based on the casing pressure tb ;

[0096] (2) Based on the tube shoe pressure P tb , calculate the pressure distribution B of the gas-liquid two-phase flow in the liquid accumulation section upward along the oil pipe;

[0097] (3) Based on oil pressure P t , wellhead production conditions, calculate the pressure distribution A of the flowing gas-liquid two-phase flow downward along the oil pipe;

[0098] (4) Find the intersection of line A and line B, that is, the depth h of the liquid surface in the oil pipe.

[0099] In this example, Jingwei 202H13-5 (2020 / 12 / 23) actually has no liquid accumulation at this time. The gas well liquid accumulation diagnosis confirms that there is no liquid accumulation. FIG. 4A to FIG. 5B As shown, Figure 4A The middle is the critical liquid-carrying velocity and the actual velocity diagnosed by the liquid film model under the current state of the gas well. It can be seen that the two slightly intersect near 2500m, confirming that the gas well has no liquid accumulation or slight liquid accumulation; Figure 4B for Figure 4A Grayscale image of . Figure 5A The bottom-liquid surface pressure distribution curve is Figure 1 Curve B in Figure 5A The wellhead-liquid surface pressure distribution curve is Figure 1 Curve A in Figure 5AIt can be seen that within the working well depth range, the two pressure distribution curves do not intersect, and there is no liquid accumulation in the wellbore; Figure 5B for Figure 5A Grayscale image of .

[0100] When the gas well production is slightly lower than the critical flow rate for carrying liquid, although there is a liquid accumulation section at the bottom of the well, the gas can still carry a certain amount of liquid out of the wellhead under the pressure difference between the dynamic liquid surface and the wellhead. The carried liquid flow rate can be calculated based on the pressure difference and gas production.

[0101] (1) Determine the bottom hole flow pressure P based on the gas well inflow dynamics and gas production wf ;

[0102] (2) Determine the pressure at the dynamic liquid surface based on the bottom hole flow pressure and liquid accumulation depth;

[0103] (3) Based on the pressure difference between the dynamic liquid surface and the wellhead, the two-phase flow calculation model and trial algorithm are used to reversely estimate the liquid carrying capacity under a certain gas production rate.

[0104] In this example, there is no liquid accumulation on the first day of the well, so the bottom liquid is basically carried out by the gas, and the liquid carrying volume is 2.8375m 3 Then, assuming that the formation pressure decreases, the liquid holdup increases, causing the gas volume to further decrease, the liquid holdup further increases, the oil pressure continues to decrease, or the wellbore pipeline is blocked, causing the wellhead pressure to increase. Since the gas volume is not enough to carry out all the liquid, the liquid carrying volume is less than the liquid production volume, resulting in part of the liquid being retained at the bottom of the well, and then liquid accumulation in the wellbore. Fig. 6A and Figure 6B This is a graph showing the change in formation fluid production and wellbore fluid volume over time from the 1st day to the 21st day. Fig. 6A It can be seen that on the first day, the formation liquid production is equal to the wellbore liquid carrying capacity, indicating that there is no liquid accumulation in the wellbore at this time. From the second day, it is assumed that the formation pressure decreases, the liquid holding rate increases, resulting in a further decrease in gas volume. The liquid holding rate further increases, the oil pressure continues to decrease, or the wellbore pipeline is blocked, resulting in an increase in wellhead pressure. Since the gas volume is not enough to carry out all the liquid, the liquid carrying capacity is less than the liquid production, resulting in a part of the liquid being retained at the bottom of the well, and then liquid accumulation in the wellbore; Figure 6B for Fig. 6A Grayscale image of .

[0105] Assuming that the production gas-liquid ratio is relatively constant, the "binomial" or "exponential" formula is used to describe the reservoir's ability to supply gas and liquid to the wellbore, and the IPR curve is used to calculate the change in liquid accumulation height in the reaction gas well.

[0106] The gas-liquid carrying capacity of the wellbore is calculated in the horizontal section-wellhead, and the pressure loss of the gas-liquid mixture in the whole process of wellbore flow is considered. The gas production and liquid production of the gas well under the conditions of formation pressure and wellhead pressure are calculated based on the "node analysis method".

[0107] In this example, the well carrying capacity is equal to the reservoir supply. There is no liquid accumulation in the wellbore on the first day. From the second day on, the gas volume is not enough to carry out all the liquid, resulting in the liquid carrying volume being less than the liquid output, causing part of the liquid to accumulate at the bottom of the well, and the liquid accumulation height is 46m. Figure 7 As shown in the figure, the change of liquid accumulation height in this well from the 1st day to the 21st day, from Figure 7 It can be seen from the figure that there is no liquid accumulation on the first day, and the liquid accumulation height is 0. After the second day, the formation pressure decreases, the liquid holdup increases, resulting in a decrease in gas volume. The liquid holdup further increases, the oil pressure continues to decrease, or the wellbore pipeline is blocked, resulting in an increase in wellhead pressure. Since the gas volume is not enough to carry out all the liquid, the liquid carrying volume is less than the liquid production, resulting in a part of the liquid being retained at the bottom of the well, and then liquid accumulation in the wellbore. The accumulated liquid first gathers at the heel end and then gradually fills the entire horizontal section. Figure 7 The dot on the middle curve represents the root end of the horizontal gas wellbore.

[0108] Although the present invention has been described above in conjunction with the exemplary embodiments and the accompanying drawings, it should be apparent to those skilled in the art that various modifications may be made to the above-described embodiments without departing from the spirit and scope of the claims.

Claims

1. A method for simulating dynamic liquid loading and production changes in a gas well, characterized in that: The method comprises the following steps: S01 calculates and fits the production capacity equation based on production history or trial production data; S02 diagnoses whether the well is filled with liquid according to the pressure distribution curves of the liquid column and the fluid in the oil pipe. If the two pressure distribution curves have no intersection, there is no liquid accumulation. If there is an intersection, there is liquid accumulation. The depth value corresponding to the intersection is the depth of the liquid level in the wellbore. The fluid pressure distribution curve is the pressure distribution curve along the wellbore of the gas well; S03 compares the current gas well production, and gradually increases or decreases the liquid production using a trial algorithm until the current gas well production is consistent with the critical liquid-carrying gas volume under the calculated standard condition, and the corresponding liquid production volume calculated by the trial algorithm is the critical liquid-carrying gas volume under the current condition; S04 calculates the current amount of liquid accumulated in the wellbore according to the critical liquid carrying capacity of the gas well and the amount of liquid flowing into the bottom of the well from the formation, calculates the increment of the wellbore liquid accumulation height at the next time step according to the current amount of liquid accumulated in the wellbore and the inner diameter of the oil pipe, and then calculates the wellbore liquid accumulation height at the next time step, calculates the increment of the bottomhole flowing pressure at the next time step according to the bottomhole flowing pressure at the current time step, and then calculates the bottomhole flowing pressure at the next time step; S05 obtains the formation pressure of the next time step according to the material balance equation, actual reservoir modeling results or historical matching empirical formula; S06 calculates the formation gas production at the current step through the production capacity equation according to the formation pressure and the bottom hole flow pressure; S07 repeats S02 to S05 to obtain the values ​​of the liquid accumulation height, gas production, formation pressure and bottom hole flow pressure of the gas well changing with time, so as to realize dynamic prediction.

2. The method according to claim 1, characterized in that The data include reservoir data, fluid physical property parameters, gas well production data and wellbore structure data.

3. The method according to claim 1, characterized in that The pressure distribution of the liquid column in the oil pipe is calculated by using the static liquid column pressure drop calculation model with the pressure at the pipe shoe as the initial value.

4. The method according to claim 3, characterized in that: According to the calculation result of the production capacity equation, the pressure at the pipe shoe is calculated downward along the casing annulus according to the static gas column pressure drop calculation model.

5. The method according to claim 1, characterized in that The pressure distribution of the fluid in the oil pipe is calculated downward using the gas-liquid two-phase flow equation with the wellhead oil pressure as the initial value.

6. The method according to claim 1, characterized in that The critical liquid carrying capacity of the gas well is calculated based on a liquid film model. The liquid film model is a relationship between the vertical pipeline interface shear stress and the dimensionless liquid film thickness calculated according to a dimensionless expression of the annular flow interface shear stress. The interface shear stress that changes with the dimensionless liquid film thickness has a minimum value, which is the critical shear stress value of liquid accumulation.

7. The method according to claim 1, characterized in that The calculation of the critical liquid carrying capacity of the gas well also requires the calculation of the gas-liquid interface friction factor, the critical liquid carrying velocity and the critical liquid carrying gas capacity.

8. The method according to claim 1, characterized in that The calculation of the liquid accumulation height of the gas well at the next time step is to calculate the current liquid volume flowing into the bottom of the well from the formation according to the gas volume and the gas-liquid ratio.

9. The method according to claim 8, characterized in that The gas well liquid accumulation height in the next time step is the initial wellbore liquid accumulation height plus the wellbore liquid accumulation height increment in the next time step.

10. The method according to claim 1, characterized in that The amount of liquid currently accumulated in the wellbore in the calculation of the increment of the wellbore liquid accumulation height at the next time step is the critical liquid carrying capacity of the gas well under the current conditions minus the amount of liquid currently flowing into the bottom of the well from the formation.

11. The method according to claim 1, characterized in that: The bottom hole flow pressure increment for the next time step is the difference between the pressure value at the initial liquid level height of the wellbore and the pressure value at the liquid accumulation height of the wellbore for the next time step.

12. The method according to claim 1, characterized in that The bottom hole flow pressure of the next time step is the sum of the bottom hole flow pressure of the previous time step and the bottom hole flow pressure increment of the next time step.

13. The method according to claim 1, characterized in that The material balance equation calculates the dynamic reserves based on the cumulative gas production, water invasion, cumulative water production, natural gas volume coefficient, natural gas volume system in the original state and the volume coefficient of water.

14. The method according to claim 1, characterized in that The formation pressure is calculated by establishing a material balance equation through the cumulative gas production over the years and the formation pressure, and combining the current cumulative gas production of the gas well to calculate the current formation pressure.

15. The method according to claim 1, characterized in that The production capacity equation calculates the formation gas production based on the fitting coefficient, the formation pressure and the bottom hole flowing pressure.

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