Method for simulating gas well dynamic liquid loading and production changes

Abstract

The application provides a method for simulating dynamic liquid accumulation and production change of a gas well, comprising the following steps: S01, calculating and fitting a deliverability equation according to production history or test production data; S02, diagnosing whether the well is accumulated with liquid according to pressure distribution curves of a liquid column and fluid in a tubing; S03, calculating a critical liquid carrying capacity of the gas well under current conditions; S04, calculating a liquid accumulation height increment and a liquid accumulation height of the wellbore at a next time step, and a bottom hole flowing pressure increment and a bottom hole flowing pressure at the next time step; S05, calculating a formation pressure at the next time step; S06, calculating a formation gas production at the current step according to the formation pressure and the bottom hole flowing pressure; and S07, repeating S02-S05 to obtain numerical values of the liquid accumulation height, the gas production, the formation pressure and the bottom hole flowing pressure of the gas well changing with time, and realizing dynamic prediction. The application realizes prediction of the future liquid accumulation height and production change of the gas well, can formulate a lifting process scheme in the whole life cycle of the gas well, and clearly defines future production dynamics of the gas well.

Description

Technical Field

[0001] This invention relates to the field of gas field development technology, and more particularly to the prediction of dynamic liquid accumulation height and production in gas wells. Specifically, it relates to a method for simulating dynamic liquid accumulation and production changes in gas wells. Background Technology

[0002] Formation water production exists to varying degrees in gas reservoirs both domestically and internationally during development. During production, gas and liquid phases flow from the formation and are extracted to the surface via the wellbore. In the early stages of production, gas well yields high gas output, and the gas and liquid phases flow upwards in a ring-like pattern. The liquid is carried in two ways: as droplets entrained in the gas core and as a liquid film adhering to the wellbore wall. As formation pressure decreases, gas well yields decline, causing the liquid (droplets / film) flow in the wellbore to reverse and fail to be carried to the surface, resulting in water accumulation. Wellbore water accumulation leads to a significant increase in the wellbore pressure gradient, thus amplifying the decline in production and severely impacting the final recovery rate of the gas well. Therefore, accurately predicting the timing of well water accumulation and promptly implementing drainage and gas production techniques are crucial for maintaining stable production in low-yield gas wells.

[0003] Current research on fluid accumulation in gas wells mainly focuses on diagnosing whether fluid accumulation occurs and predicting the fluid accumulation height. The determination of fluid accumulation height is often based on predictions using relevant test parameters from the wellbore / wellhead at a specific time or period. Formation pressure is assumed to be a fixed point value. Because this research relies on current test parameters, it cannot predict future changes in gas well fluid accumulation height and production.

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

[0005] The purpose of this invention is to address at least one of the aforementioned deficiencies in the prior art. For example, one objective of this invention is to formulate a lifting process plan throughout the entire life cycle in order to clarify the future production dynamics of a gas well. Another objective of this invention is to provide a method for predicting the unsteady production state of a gas well by coupling the reservoir production capacity of the gas well with the unsteady phase flow in the wellbore.

[0006] To achieve the above objectives, the present invention provides a method for simulating dynamic liquid accumulation and production changes in gas wells, comprising the following steps:

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

[0008] S02 diagnoses whether the well has accumulated fluid based on the pressure distribution curves of the liquid column and fluid in the tubing. If the two pressure distribution curves do not intersect, there is no fluid accumulation; if they intersect, there is fluid accumulation. The depth value corresponding to the intersection point is the depth of the fluid 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 uses a trial-and-error method to gradually increase or decrease the production rate until the current gas well production rate is consistent with the calculated critical liquid-carrying gas rate under standard conditions. The production rate proposed by the trial-and-error method is the critical liquid-carrying gas rate of the gas well under the current conditions.

[0010] S04 calculates the current amount of liquid accumulated in the wellbore based on the critical fluid carrying capacity of the gas well and the amount of liquid flowing from the formation into the bottom of the well. Based on the current amount of liquid accumulated in the wellbore and the inner diameter of the tubing, it calculates the increment of the wellbore liquid height in the next time step, and then calculates the wellbore liquid height in the next time step. Based on the bottom-hole flowing pressure in the current time step, it calculates the increment of the bottom-hole flowing pressure in the next time step, and then calculates the bottom-hole flowing pressure in the next time step.

[0011] S05 calculates the formation pressure at the next time step based on the material balance equation, actual reservoir modeling results, or historical fitting empirical formulas.

[0012] S06 calculates the formation gas production in the current step using the production capacity equation based on the formation pressure and bottom hole flowing pressure.

[0013] S07 repeats S02~S05 to obtain the values ​​of gas well liquid accumulation height, gas production, formation pressure and bottom hole flowing pressure as a function of time, so as to achieve dynamic prediction.

[0014] Alternatively, the data may include reservoir data, fluid properties, gas well production data, and wellbore structure data.

[0015] Alternatively, the pressure distribution of the liquid column in the tubing is calculated upwards using a static pressure drop calculation model with the pressure at the tubing shoe as the initial value.

[0016] Alternatively, based on the calculation results of the production capacity equation, the pressure at the pipe shoe can be calculated downwards along the annulus of the oil casing using a static air column pressure drop calculation model.

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

[0018] Alternatively, the critical liquid carrying capacity of the gas well is calculated based on a liquid film model. The liquid film model is based on the dimensionless expression of the interfacial shear stress of the annular flow to calculate the relationship between the interfacial shear stress of the vertical pipe and the dimensionless liquid film thickness. The interfacial shear stress that varies with the dimensionless liquid film thickness has a minimum value, which is the critical shear stress value for liquid accumulation.

[0019] Alternatively, the calculation of the critical liquid carrying capacity of the gas well may also require the calculation of the gas-liquid interface friction factor, the critical liquid carrying velocity, and the critical liquid carrying gas volume.

[0020] Alternatively, the calculation of the next time step gas well liquid accumulation height is based on the gas volume and gas-liquid ratio to calculate the current liquid volume flowing from the formation into the bottom of the well.

[0021] Alternatively, the next time step gas well fluid accumulation height is the initial fluid accumulation height in the wellbore plus the next time step fluid accumulation height increment.

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

[0023] Alternatively, the bottomhole flowing pressure increment at the next time step is the difference between the pressure value at the initial fluid level in the wellbore and the pressure value at the fluid accumulation height in the wellbore at the next time step.

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

[0025] Alternatively, the material balance equation can be used to calculate dynamic reserves based on cumulative gas production, water intrusion, cumulative water production, natural gas volume factor, and the volume factor of natural gas volume system and water under the original state.

[0026] Alternatively, the formation pressure can be calculated by establishing a material balance equation based on the cumulative gas production and formation pressure over the years, and then combining this equation with the current cumulative gas production of the gas well.

[0027] Alternatively, the production capacity equation can be used to calculate the formation gas production based on the fitting coefficient, formation pressure, and 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) This invention couples formation pressure and can calculate real-time dynamic values.

[0030] 2) This invention enables the prediction of future changes in gas well liquid accumulation height and production.

[0031] 3) This invention can formulate lifting process plans throughout the entire life cycle of a gas well and clarify the future production dynamics of the gas well. Attached Figure Description

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

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

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

[0035] Figure 2B for Figure 2A A grayscale image.

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

[0037] Figure 4A The diagram shows the diagnostic results of fluid accumulation in a gas well fluid model in an embodiment of the present invention.

[0038] Figure 4B for Figure 4A A grayscale image.

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

[0040] Figure 5B for Figure 5A A grayscale image.

[0041] Figure 6A The diagram shows the variation of formation fluid production and wellbore fluid carrying capacity over time in an embodiment of the present invention.

[0042] Figure 6B for Figure 6A A grayscale image.

[0043] Figure 7 The diagram shows the change in wellbore fluid height over time in an embodiment of the present invention. Detailed Implementation

[0044] The method for simulating dynamic liquid accumulation and production changes in gas wells according to the present invention will be described in detail below with reference to exemplary embodiments.

[0045] Exemplary embodiments

[0046] This exemplary embodiment provides a method for simulating dynamic liquid accumulation and production changes in gas wells, including the following steps:

[0047] S01: The production capacity equation is obtained by calculation and fitting based on production history or trial mining data.

[0048] The data described in this embodiment includes reservoir data, fluid property parameters, gas well production data, and wellbore structure data. The production capacity equation is calculated and fitted based on production history or trial production data.

[0049] S02: Diagnose whether the well has fluid accumulation based on the pressure distribution curves of the liquid column and fluid in the tubing. If the two pressure distribution curves do not intersect, there is no fluid accumulation; if they intersect, there is fluid accumulation. The depth value corresponding to the intersection point is the depth of the fluid 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 rate is calculated based on the production capacity equation, and the pressure P at the pipe shoe is calculated downwards along the annulus using the static gas column pressure drop calculation model. tb Pressure P at the shoe tube tb The result is equal to the calculation result of the production capacity equation, with the pressure P at the pipe shoe being equal to the result of the production capacity equation. tb The pressure distribution of the fluid column in the tubing is calculated using a hydrostatic pressure drop calculation model, with the Hasan model employed as the initial value. Figure 1 As shown by line B; with wellhead oil pressure P t The pressure distribution of the fluid in the tubing is calculated using the gas-liquid two-phase flow equation as the initial value. Here, the gas-liquid two-phase flow equation is the Beggs-Brill model, as follows: Figure 1 As shown by line A. Plot the two curves on the same coordinate system. If there is no intersection, the well does not accumulate fluid. Line A represents the pressure distribution along the wellbore of the gas well, while line B represents the pressure distribution along the wellbore below the pure gas column above the fluid surface. Line B represents the pressure distribution along the wellbore below the pure liquid column below the fluid surface. If there is an intersection, the well accumulates fluid, and the depth corresponding to the intersection point is the depth of the fluid accumulation surface in the wellbore. Figure 1 As shown in Dh.

[0051] S03: Compare the current gas well production rate and use a trial-and-error method to gradually increase or decrease the production rate until the current gas well production rate is consistent with the calculated critical liquid-carrying gas rate under standard conditions. The production rate proposed by the trial-and-error method is the critical liquid-carrying gas rate 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 shear stress at the vertical pipe interface and the dimensionless liquid film thickness is calculated according to the dimensionless expression of the annular flow interface shear stress (1). Figure 2A and Figure 2B As shown, from Figure 2A It can be seen that when the apparent flow velocity of the liquid phase is small, the interfacial shear stress varying with the dimensionless liquid film thickness has a minimum value. The liquid film model based on the minimum shear stress assumes that at this point, the liquid film begins to form in the annular flow, liquid accumulates in the pipe, and the corresponding dimensionless liquid film thickness is the critical liquid film thickness. Figure 2B for Figure 2A A grayscale image.

[0053]

[0054] Where τ1 is the shear stress at the gas-liquid interface, N / m; ρG , ρ L These are the densities of the gas phase and liquid phase, respectively, in kg / m³. 3 ;δ L C is the dimensionless liquid film thickness, in meters. L v is the Blasius coefficient for liquid phase, taken as 16 for laminar flow and 0.046 for turbulent flow; SL，film The apparent velocity corresponding to the liquid film flow rate; d is the inner diameter of the tubing, in meters; μ L The viscosity of the liquid phase is expressed in Pa·s and μ. G θ is the gas phase viscosity, Pa·s; θ is the angle between the pipe axis and the vertical direction, rad.

[0055] The interfacial shear stress that varies with the dimensionless liquid film thickness has a minimum value, which is the critical shear stress value τ1 for liquid accumulation. The critical liquid-carrying velocity can be calculated using the Wallis formula for interfacial shear stress in annular flow (2):

[0056]

[0057] Where, δ avgL The average dimensionless liquid film thickness is given in meters (m); υ SG ρ is the apparent velocity of the gas phase, m / s; f1 is the friction factor at the gas-liquid interface.

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

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

[0060] Where, δ avgL Let θ be the average dimensionless liquid film thickness, and θ be the angle between the pipe axis and the vertical direction, expressed in rad.

[0061] Critical liquid-carrying capacity Q under standard conditions sc Calculate according to equation (4):

[0062]

[0063] Among them, υ SG Z is the apparent velocity of the gas phase, m / s; T is the natural gas deviation factor; A is the temperature, K; and A is the cross-sectional area of ​​the oil pipe, m². 2 p represents pressure, in MPa.

[0064] Compared with the current gas well production, the production volume is gradually increased or decreased using a trial-and-error method until the current gas well production volume is consistent with the critical liquid-carrying gas volume under standard conditions calculated by equation (4). The production volume proposed by the corresponding trial-and-error method is the liquid-carrying volume Q0 of the gas well under the current conditions.

[0065] S04: Calculate the current fluid volume accumulated in the wellbore based on the gas well's critical fluid carrying capacity and the fluid volume flowing from the formation into the wellbore. Calculate the fluid height increment in the wellbore for the next time step based on the current fluid volume and the tubing inner diameter. Then calculate the fluid height in the wellbore for the next time step. Calculate the bottomhole flowing pressure increment for the next time step based on the bottomhole flowing pressure at the current time step. Finally, calculate the bottomhole flowing pressure increment for the next time step based on the fluid height increment. The bottomhole flowing pressure for the next time step is the sum of the bottomhole flowing pressure at 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 level in the gas well is calculated by calculating the current volume of liquid Qc flowing from the formation to the bottom of the well according to equation (5):

[0067] Q C =R G ×q g (5)

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

[0069] Calculate the current fluid volume Q in the wellbore according to equation (6). L :

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

[0071] According to equation (7), the increment of the wellbore fluid accumulation height Δh0, m at the current time step:

[0072]

[0073] Among them, Q L The volume of fluid in the wellbore, in m 3 Q0 represents the liquid carrying capacity of the gas well, in m³. 3 D is the inner diameter of the oil pipe, in meters.

[0074] In this embodiment, the next time step wellbore fluid accumulation height is h1 = h0 + Vh0, where h0 is the initial fluid accumulation height in the wellbore.

[0075] The bottomhole flowing pressure at the current time step is calculated based on the production capacity equation, specifically the pressures at fluid level heights h0 and h1. Using the formula P = P0 + ρgh, the pressures at fluid level heights h0 and h1 are calculated based on the bottomhole flowing pressure. The pressure difference between h0 and h1 is the bottomhole flowing pressure increment ΔP for the next time step. wf The bottom hole flowing pressure at the next time step is P. wf1The bottom hole pressure at the next time step is the bottom hole pressure at the previous time step plus the increment of the bottom hole pressure at the next time step.

[0076] S05: Calculate the formation pressure for the next time step based on the mass balance equation, actual reservoir modeling results, or historical fitting empirical formulas. Assuming the current formation pressure is P1, calculate the dynamic reserves G1 using P1. Compare the dynamic reserves G1 with the actual dynamic reserves G. If they are 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 using the mass balance equation (8), or it can be calculated using actual reservoir modeling results or historical fitting empirical formulas to obtain the formation pressure P at the next time step. R1 .

[0078]

[0079] Where G represents dynamic reserves (gas storage capacity), 10 8 m 3 G p To calculate the cumulative gas production, 10 8 m 3 B gi W is the volume factor of natural gas in its original state; p For cumulative water production, 10 4 m 3 W e For water intrusion, 10 4 m 3 B g B is the natural gas volume factor; w is the volume coefficient of water.

[0080] S06: Calculate the formation gas production rate for the current step using the production capacity equation based on the formation pressure and bottom hole flowing pressure.

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

[0082] S07: Repeat S02 to S05 to obtain the values ​​of gas well liquid accumulation height, gas production, formation pressure and bottom hole flowing pressure over time to achieve dynamic prediction.

[0083] In this embodiment, the calculation process for simulating dynamic liquid accumulation and production changes in the gas wellbore is as follows: Figure 3As shown in the figure, the first step, based on the basic data, is to determine whether there is fluid accumulation in the wellbore. According to the calculated pressure distribution curves of the fluid column and the fluid in the tubing, if they do not intersect within the working well depth range, there is no fluid accumulation in the wellbore. Simultaneously, the pressure distribution curve along the wellbore can be obtained, which is the pressure distribution curve of the fluid in the tubing. If the pressure distribution curves of the fluid column and the fluid in the tubing intersect within the working well depth range, there is fluid accumulation in the wellbore. The depth value corresponding to the intersection of the two pressure distribution curves is the fluid level depth in the wellbore. Based on the initial fluid height, the current amount of fluid flowing from the formation to the bottom of the well, and the current amount of fluid accumulated in the wellbore, the fluid height in the wellbore for the next time step can be calculated. The gas production rate for the current time step can be calculated based on the formation pressure and the bottom hole flowing pressure. The time step can be in days or months, etc., and the S02~S05 operations can be repeated to achieve dynamic acquisition of the fluid height, gas production rate, formation pressure, and bottom hole flowing pressure values, enabling dynamic prediction.

[0084] To better understand the exemplary embodiments of the present invention described above, further explanation is provided below with reference to specific examples.

[0085] Example 1

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

[0087] Wellhead oil pressure: 2.45 MPa; Formation pressure: 25 MPa; Initial gas production: 4.55 × 10⁴ m³. 3 / d, water production 2.2m 3 / d, flowing pressure 4.7MPa, gas production index 174.1m 3 / (d.MPa), formation gas-liquid ratio 20681Sm 3 / m 3 .

[0088] Based on well test data, determine the gas well productivity equation:

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

[0090]

[0091]

[0092] Where Pr is the reservoir pressure (here, reservoir pressure is equivalent to formation pressure), MPa; P wf q represents the bottom hole flowing pressure, in MPa; q represents the formation gas production, in m³. 3 / d; A and B are binomial fitting coefficients; h is the effective reservoir thickness in meters; re The radius of the oil well's supply (drainage) edge, in meters (m); r w β is the wellbore radius, in meters; β is the turbulence velocity coefficient, in kPa / (m²). 3 / d) 2 S is the skin coefficient, which is related to the well completion method, bottom hole contamination, or production enhancement measures, and can be obtained from the pressure recovery curve. γ is the natural gas deviation factor under average temperature conditions; K is the gas reservoir permeability; T is the temperature in K; g The relative density of the gas; The viscosity of natural gas is given under average temperature conditions.

[0093] The fitted value of A is 0.00368 MPa. 2 / (10 3 m 3 / d) 2 B is 13.08352 MPa 2 / (10 3 m 3 / d).

[0094] Diagnosis of fluid accumulation in gas wells

[0095] (1) Assuming the annulus is filled with pure gas, calculate the tubing shoe pressure P based on the casing pressure. tb ;

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

[0097] (3) Based on oil pressure P t 1. Wellhead production status, calculate the pressure distribution A of the gas-liquid two-phase flow along the tubing downwards;

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

[0099] In this example, well 202H13-5 (2020 / 12 / 23) did not actually have any liquid accumulation at that time. This was confirmed by a well liquid accumulation diagnosis. Figures 4A to 5B As shown, Figure 4A The middle part shows the critical liquid-carrying velocity and the actual velocity of the liquid film model diagnosis under the current state of the gas well. It can be seen that the two intersect slightly around 2500m, which confirms that the gas well has no liquid accumulation or only slight liquid accumulation. Figure 4B for Figure 4A A grayscale image. Figure 5A The bottom-to-fluid level pressure distribution curve is the... Figure 1 Curve B in the middle, Figure 5A The pressure distribution curve between the wellhead and the fluid level is... Figure 1 Curve A in the middle; from Figure 5AIt can be seen that within the working well depth range, the two pressure distribution curves do not intersect, indicating that there is no fluid accumulation in the wellbore; Figure 5B for Figure 5A A grayscale image.

[0100] When the gas well production is slightly below the critical flow rate for carrying liquid, even though there is a liquid accumulation zone at the bottom of the well, the gas can still carry a certain amount of liquid out of the wellhead due to the pressure difference between the dynamic liquid surface and the wellhead. The flow rate of the carried liquid can be calculated based on the pressure difference and gas production.

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

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

[0103] (3) Based on the pressure difference between the dynamic fluid surface and the wellhead, the liquid carrying capacity under a certain gas production rate is back-calculated using a two-phase flow calculation model and trial method.

[0104] In this example, the well did not accumulate fluid on day 1, so the fluid at the bottom of the well was basically carried out by the gas, with a fluid carrying volume of 2.8375 m³. 3 Then, assuming that the formation pressure decreases, the liquid holdup increases, leading to a further decrease in gas volume, a further increase in liquid holdup, and a continuous decrease in oil pressure, or that the wellbore pipeline is blocked, causing the wellhead pressure to rise, the gas volume is insufficient to carry out all the liquid, resulting in the liquid carrying volume being less than the liquid production volume, causing some liquid to remain at the bottom of the well, and thus liquid accumulation in the wellbore. Figure 6A and Figure 6B This is a graph showing the changes in formation fluid production and wellbore fluid carrying capacity of this well from day 1 to day 21 over time. Figure 6A It can be seen that on the first day, the formation fluid production is equal to the fluid carried in the wellbore, indicating that there is no fluid accumulation in the wellbore at this time. Starting from the second day, assuming that the formation pressure decreases, the fluid holdup increases, leading to a further decrease in gas volume and a further increase in fluid holdup, the oil pressure continues to decrease, or the wellbore pipeline is blocked, causing the wellhead pressure to increase. Since the gas volume is insufficient to carry out all the fluid, the fluid carried is less than the fluid production, resulting in some fluid remaining at the bottom of the well, and thus fluid accumulation in the wellbore. Figure 6B for Figure 6A A grayscale image.

[0105] Assuming a relatively constant gas-liquid ratio, the reservoir's ability to supply gas and liquid to the wellbore is described using a binomial or exponential formula, and the IPR curve is used to calculate the change in the liquid accumulation height of the gas well.

[0106] The gas-liquid carrying capacity of the wellbore is calculated in the horizontal section-wellhead, taking into account the pressure loss of the gas-liquid mixture during the entire flow process in the wellbore. Based on the "node analysis method", the gas production and liquid production of the gas well are calculated under the constraints of formation pressure and wellhead pressure.

[0107] In this example, the well's fluid-carrying capacity equals the reservoir's fluid supply. No fluid accumulates in the wellbore on day 1. Starting on day 2, due to insufficient gas to carry out all the fluid, the fluid-carrying capacity is less than the fluid supply, causing some fluid to deposit at the bottom of the well, resulting in fluid accumulation at a height of 46m. For example... Figure 7 The figure shows the change in fluid level in this well from day 1 to day 21. Figure 7 As can be seen, 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, which leads to a decrease in gas volume. The liquid holdup further increases, and the oil pressure continues to decrease. Alternatively, the wellbore pipeline may be blocked, causing the wellhead pressure to increase. Since the gas volume is insufficient to carry out all the liquid, the liquid carrying volume is less than the production volume, resulting in some liquid remaining at the bottom of the well, which in turn leads to liquid accumulation in the wellbore. The accumulated liquid preferentially gathers towards the heel end and then gradually fills the entire horizontal section. Figure 7 The dots on the curve represent the root end of the horizontal gas well shaft.

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

Claims

1. A method for simulating dynamic fluid accumulation and production changes in gas wells, characterized in that, The method includes the following steps: S01 calculates and fits the capacity equation based on production history or trial mining data; S02 diagnoses whether the well has accumulated fluid based on the pressure distribution curves of the liquid column and fluid in the tubing. If the two pressure distribution curves do not intersect, there is no fluid accumulation; if they intersect, there is fluid accumulation. The depth value corresponding to the intersection point is the depth of the fluid 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 uses a trial-and-error method to gradually increase or decrease the production rate until the current gas well production rate is consistent with the calculated critical liquid-carrying gas rate under standard conditions. The production rate proposed by the trial-and-error method is the critical liquid-carrying gas rate of the gas well under the current conditions. S04 calculates the current amount of liquid accumulated in the wellbore based on the critical fluid carrying capacity of the gas well and the amount of liquid flowing from the formation into the bottom of the well. Based on the current amount of liquid accumulated in the wellbore and the inner diameter of the tubing, it calculates the increment of the wellbore liquid height in the next time step, and then calculates the wellbore liquid height in the next time step. Based on the bottom-hole flowing pressure in the current time step, it calculates the increment of the bottom-hole flowing pressure in the next time step, and then calculates the bottom-hole flowing pressure in the next time step. S05 calculates the formation pressure at the next time step based on the material balance equation, actual reservoir modeling results, or historical fitting empirical formulas. S06 calculates the formation gas production in the current step using the production capacity equation based on the formation pressure and bottom hole flowing pressure. S07 repeats S02~S05 to obtain the values ​​of gas well liquid accumulation height, gas production, formation pressure and bottom hole flowing pressure as a function of time, so as to achieve dynamic prediction.

2. The method according to claim 1, characterized in that, The data includes reservoir data, fluid properties, 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 tubing is calculated upwards using a static pressure drop calculation model with the pressure at the tubing shoe as the initial value.

4. The method according to claim 3, characterized in that, Based on the calculation results of the aforementioned production capacity equation, the pressure at the pipe shoe is calculated downwards along the annulus of the oil casing using the static air column pressure drop calculation model.

5. The method according to claim 1, characterized in that, The pressure distribution of the fluid in the tubing is calculated downwards 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 the liquid film model. The liquid film model is based on the dimensionless expression of the interfacial shear stress of the annular flow to calculate the relationship between the interfacial shear stress of the vertical pipe and the dimensionless liquid film thickness. The interfacial shear stress that varies with the dimensionless liquid film thickness has a minimum value, which is the critical shear stress value for 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 volume.

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

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

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

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

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

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

14. The method according to claim 1, characterized in that, The formation pressure is calculated by establishing a material balance equation based on the cumulative gas production and formation pressure over the years, and then using this equation in conjunction with the current cumulative gas production of the gas well.

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

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