Shale gas well effusion prediction method and equipment based on energy model and storage medium

Abstract

The invention discloses a shale gas well effusion prediction method and device and a storage medium, and the prediction method comprises the steps: collecting historical production characteristic data, critical effusion state data, well bore structure characteristic data, fluid characteristic data and oil casing size data of a typical well, and calculating wellhead energy and P < output > according to gas production rate Qg and liquid production rate Ql during actual production; calculating the bottom hole flowing pressure pwf according to the gas production rate Qg and the liquid production rate (1 + 5%) Ql during actual production, calculating the inlet energy P < in >, and calculating the energy factor beta according to the formula that beta = P < in > / P < out >-1; each typical well obtains a corresponding energy factor beta, and an expression of a standard energy factor beta * is solved; p < in > and P < out > of the predicted well are calculated, and if P < in > > (1 + beta *) P < out >, no liquid is accumulated; if P is in lt; if (1 + beta *) P < output >, effusion exists; if P < in > = (1 + beta *) P < out >, determining the critical state. The method is wide in application range and particularly suitable for predicting the wellbore liquid accumulation of the shale gas well with the high liquid-gas ratio.

Description

Technical Field

[0001] The present invention relates to the technical field of petroleum and natural gas shale gas exploitation, and in particular to a shale gas well liquid accumulation prediction method, device and computer-readable storage medium based on an energy model. Background Art

[0002] In the process of shale gas extraction, a large amount of fracturing fluid is used, resulting in a long liquid production time in shale gas wells. Since shale gas wells have a large range of liquid and gas production, if the gas velocity or formation energy is too low, liquid will accumulate at the bottom of the well and form liquid accumulation. Due to the particularity of shale gas production, conventional gas well liquid carrying theories and methods are difficult to adapt, and a liquid accumulation prediction method based on the production law of shale gas wells is needed.

[0003] Most of the existing gas well liquid accumulation prediction models are based on the droplet or liquid film theory, namely the droplet model carrying the droplet in the center of the gas flow and the liquid film model carrying the liquid film on the pipe wall. Both models require that the gas-liquid two-phase pipe flow in the wellbore is annular (fog) flow, but field tests and simulations show that the gas-liquid two-phase pipe flow in a large number of shale gas wells is not annular (fog) flow, especially in gas wells with large liquid volume or high liquid-gas ratio, annular (fog) flow does not appear in the wellbore. The vertical or inclined wellbore may mainly exist in the form of slug flow, which does not meet the conditions of the droplet / liquid film model.

[0004] At present, the prediction of liquid accumulation in shale gas still uses the liquid accumulation prediction method of conventional natural gas wells, and there is a lack of a method suitable for predicting liquid accumulation in the wellbore of shale gas wells with a high liquid-to-gas ratio. Summary of the invention

[0005] The technical problem to be solved by the present invention is that the current prediction of liquid accumulation in shale gas still uses the liquid accumulation prediction method of conventional natural gas wells, and there is a lack of a method suitable for predicting liquid accumulation in the wellbore of shale gas wells with a high liquid-to-gas ratio.

[0006] The first object of the present invention is to provide a shale gas well liquid accumulation prediction method based on an energy model, comprising:

[0007] S1. Collect historical production characteristic data, critical liquid loading state data, wellbore structure characteristic data, fluid characteristic data and oil casing size data of typical wells;

[0008] S2. According to the historical production characteristics data of typical wells and the critical liquid accumulation state data, the actual production gas production Q g And liquid production Q l Calculate wellhead energy and P 出 ;

[0009] S3. According to the optimal pipe flow calculation method of the block, according to the actual gas production Q g And liquid production (1+5%) Q l Calculate the bottom hole pressure pwf , and calculate the inlet energy P 入 , and according to β=P 入 / P 出 -1 calculates the energy factor β;

[0010] S4. Each typical well obtains its corresponding energy factor β according to steps S1-S3, and obtains an expression of a standard energy factor β* according to all the obtained energy factors β;

[0011] S5. Calculate the wellhead gas superficial velocity v according to the wellhead oil pressure, temperature, liquid production, gas production and pipe string size of a certain production state of the predicted well sg , liquid superficial velocity v sl , and calculate the liquid holdup H as follows L :

[0012]

[0013] Where g is the acceleration due to gravity, m / s 2 ;σ is the surface tension, N / m; ρ l is the density of the liquid; ρ g is the density of the gas; θ is the inclination angle of the pipeline;

[0014] S6. According to the liquid holdup H L Calculate the actual gas-liquid flow rate v at the wellhead g 、v l , calculate the outlet energy P of the predicted well 出 ;

[0015] S7. Calculate the bottom hole pressure p according to the predicted wellhead pressure using the multiphase pipe flow calculation method or the annular air column pressure calculation method wf Considering a 5% increase in liquid production, calculate the apparent gas-liquid flow rate at the bottom of the well and the liquid holdup at the bottom of the well according to formula (18), and then calculate the real gas-liquid flow rate at the bottom of the well, and finally calculate the total inlet energy P 入 ;

[0016] S8. Based on the above calculation of P 出 , β* and P 入 , if P 入 >(1+β*)P 出 , there is no effusion; if P 入 <(1+β*)P 出 , there is effusion; if P 入 =(1+β*)P 出 , then the critical state.

[0017] As a possible design, the production characteristic data include gas production, liquid production, wellhead oil pressure, wellhead temperature and wellhead casing pressure.

[0018] As a possible design, the critical liquid accumulation state data includes gas production, liquid production, wellhead oil pressure, wellhead temperature and wellhead casing pressure corresponding to the critical liquid accumulation state.

[0019] As a possible design, the wellbore structural characteristic data include well inclination, sounding depth, vertical depth, guide tube, surface casing size and depth, oil layer casing size and depth.

[0020] As a possible design, the fluid characteristic data includes the viscosity of shale gas, the density of shale gas, the volume coefficient of shale gas, the viscosity of produced water, and the density of produced water.

[0021] As a possible design, the tubing size reports the tubing size and depth, and the production casing size and depth.

[0022] As a possible design, the total inlet energy P 入 Obtained by the following formula,

[0023] P 入 =P P1 +P E1 (15)

[0024] in:

[0025]

[0026] Where: P P1 is the pressure energy, P E1 is the kinetic energy, subscripts 1 and 2 represent the inlet and outlet respectively; p wh is the wellhead pressure; p wf is the bottom hole pressure, Q g , Q l is the local volume flow rate of gas and liquid; ρ is the density; v is the true flow velocity of gas and liquid; m is the mass flow rate; g is the acceleration of gravity.

[0027] As a possible design, the total outlet energy P 出 Obtained by the following formula,

[0028] P 出 =P P2 +P E2 +P h2 (1)

[0029] Where P P2 is the pressure energy, P E2 is kinetic energy, P h2 for potential;

[0030] in,

[0031]

[0032]

[0033]

[0034] In the formula, subscripts 1 and 2 represent the inlet and outlet respectively; p wh is the wellhead pressure; p wf is the bottom hole pressure, Q g , Q l is the local volume flow rate of gas and liquid; ρ is the density; v is the real flow rate of gas and liquid; m is the mass flow rate; g is the gravitational acceleration; H 垂深 It is the vertical height difference between entrance and exit.

[0035] As a possible design, when the typical wells collected are all in the same area, the standard energy factor β* is the average value of all energy factors β.

[0036] As a possible design, the bottom hole pressure p wf Obtained from wellhead casing pressure, wellhead oil pressure and formation pressure.

[0037] Bottom hole pressure p wf The same calculation method and formula as the above bottom hole flowing pressure is used to obtain the formation pressure through wellbore testing.

[0038] The second object of the present invention is to provide a shale gas well liquid accumulation prediction device based on an energy model, comprising a processor and a memory;

[0039] The memory stores computer-executable instructions;

[0040] The processor executes the computer-executable instructions stored in the memory, so that the processor executes the aforementioned shale gas well liquid accumulation prediction method.

[0041] The third object of the present invention is to provide a computer-readable storage medium, in which computer-executable instructions are stored. When the computer-executable instructions are executed by a processor, they are used to implement the above-mentioned shale gas well liquid accumulation prediction method.

[0042] The beneficial effects of the present invention are:

[0043] The present invention proposes for the first time an energy-based liquid accumulation prediction method, which meets the needs of shale gas well liquid accumulation prediction and solves the problem of shale gas well liquid accumulation prediction. It can guide the determination of the timing of process intervention and avoid unreasonable timing of shale gas process intervention, which increases production costs or affects the production efficiency of shale gas wells.

[0044] The prediction method disclosed in the present invention has a wide application range, and is particularly suitable for the prediction of liquid accumulation in the wellbore of a shale gas well with a high liquid-gas ratio. BRIEF DESCRIPTION OF THE DRAWINGS

[0045] In order to more clearly illustrate the technical solutions of the exemplary embodiments of the present invention, the following briefly introduces the drawings required for use in the embodiments. It should be understood that the following drawings only illustrate certain embodiments of the present invention and should not be regarded as limiting the scope. For those of ordinary skill in the art, other relevant drawings can be obtained based on these drawings without creative work. In the drawings:

[0046] Figure 1 This is a flow chart for predicting liquid accumulation in a shale gas well in an embodiment of the present invention. DETAILED DESCRIPTION

[0047] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with embodiments and drawings. The exemplary embodiments of the present invention and their description are only used to explain the present invention and are not intended to limit the present invention.

[0048] It should be noted that when an element is referred to as being "fixed to" or "disposed on" another element, it can be directly on the other element or indirectly on the other element. When an element is referred to as being "connected to" another element, it can be directly connected to the other element or indirectly connected to the other element.

[0049] In addition, the terms "first" and "second" are used for descriptive purposes only and should not be understood as indicating or implying relative importance or implicitly indicating the number of the indicated technical features. Therefore, the features defined as "first" and "second" may explicitly or implicitly include one or more of the features. In the description of the present invention, the meaning of "multiple" is two or more, unless otherwise clearly and specifically defined. The meaning of "several" is one or more, unless otherwise clearly and specifically defined.

[0050] In the description of the present invention, it is necessary to understand that the directions or positional relationships indicated by the terms "up", "down", "front", "back", "left", "right", etc. are based on the directions or positional relationships shown in the accompanying drawings, and are only for the convenience of describing the present invention and simplifying the description, rather than indicating or implying that the device or element referred to must have a specific direction, be constructed and operated in a specific direction, and therefore cannot be understood as a limitation on the present invention.

[0051] In the description of the present invention, it should be noted that, unless otherwise clearly specified and limited, the terms "installed", "connected", and "connected" should be understood in a broad sense, for example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection or an electrical connection; it can be a direct connection or an indirect connection through an intermediate medium, it can be the internal connection of two elements or the interaction relationship between two elements. For ordinary technicians in this field, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0052] Example 1

[0053] The existing shale gas well liquid accumulation prediction model still uses the conventional natural gas well liquid accumulation prediction method, which is mostly based on the droplet or liquid film theory, that is, the droplet model carrying the central droplet of the gas flow and the liquid film model carrying the wall liquid film. Both models require that the gas-liquid two-phase pipe flow in the wellbore is annular (fog) flow, but field tests and simulations show that the gas-liquid two-phase pipe flow in a large number of shale gas wells is not annular (fog) flow, especially in gas wells with large liquid volume or high liquid-gas ratio, annular (fog) flow does not appear in the wellbore. The vertical or inclined wellbore section may mainly exist in the form of slug flow, which does not meet the conditions of the droplet / liquid film model and is not suitable for the prediction of liquid accumulation in the wellbore of shale gas wells with high liquid-gas ratio.

[0054] In view of the above limitations of the existing shale gas well bore liquid loading prediction model, the present invention provides a shale gas well liquid loading prediction method based on an energy model, such as Figure 1 As shown, the following steps are included:

[0055] S1. Collect historical production characteristic data, critical liquid loading state data, wellbore structure characteristic data, fluid characteristic data and oil casing size data of typical wells;

[0056] Among them, production characteristic data include but are not limited to gas production, liquid production, wellhead oil pressure, wellhead temperature and wellhead casing pressure.

[0057] The critical liquid accumulation state data include but are not limited to the gas production, liquid production, wellhead oil pressure, wellhead temperature and wellhead casing pressure corresponding to the critical liquid accumulation state. The wellbore structure characteristic data include but are not limited to well inclination, depth measurement, vertical depth, guide tube, surface casing size and depth, oil layer casing size and depth. The fluid characteristic data include but are not limited to the viscosity of shale gas, the density of shale gas, the volume coefficient of shale gas, the viscosity of produced water, and the density of produced water. The oil casing size includes but is not limited to the oil pipe size and depth, the production casing size and depth.

[0058] S2. According to the historical production characteristics data of typical wells and the critical liquid accumulation state data, the actual production gas production Q g And liquid production Q l Calculate wellhead energy and P出 ;

[0059] Total export energy P 出 The total wellhead energy (calculated using true velocity) is calculated according to the wellhead oil pressure and gas and liquid production, including potential energy, pressure energy and kinetic energy, as the total wellhead energy P at the historical well outlet. 出 ,

[0060] P 出 =P P2 +P E2 +P h2 (1)

[0061] Where P P2 is the pressure energy, P E2 is kinetic energy, P h2 for potential;

[0062] in,

[0063]

[0064]

[0065]

[0066] In the formula, subscripts 1 and 2 represent the inlet and outlet respectively; p wh is the wellhead pressure; p wf is the bottom hole pressure, Q g , Q l is the local volume flow rate of gas and liquid; ρ is the density; v is the real flow rate of gas and liquid; m is the mass flow rate; g is the gravitational acceleration; H 垂深 The vertical height difference between the entrance and exit. The above units are all SI units.

[0067] S3. According to the optimal pipe flow calculation method of the block, according to the actual gas production Q g And liquid production (1+5%) Q l Calculate the bottom hole pressure p wf , and calculate the inlet energy P 入 , and according to β=P 入 / P 出 -1 calculates the energy factor β;

[0068] The preferred pipe flow calculation method for the block is: Hagedorn & Brown model pipe flow calculation method.

[0069] Bottom hole pressure p wf The calculation formula is as follows:

[0070] The bottom hole flow pressure is calculated based on the wellhead production casing pressure parameters, and the coordinate z is taken as positive along the well axis downward, and the wellhead z = 0. The well inclination θ is the angle with the horizontal direction. For the annulus, it is approximately considered as a static gas column, and the gas does not flow (v = 0). The friction term and kinetic energy term in the pressure drop gradient equation are both zero. The total pressure drop gradient of the static gas column is the gravity pressure drop gradient, that is,

[0071]

[0072] In the above formula, the gas density is

[0073]

[0074] Where: ρ——gas density, kg / m 3 ;

[0075] M g ——Natural gas apparent molecular weight = 28.97γ g , kg / kmol;

[0076] γ g ——Relative density of natural gas, dimensionless quantity;

[0077] R——Universal gas constant=0.008315MPa.m 3 / (kmol.K);

[0078] p——pressure, MPa;

[0079] T——temperature, K;

[0080] Z——Gas deviation coefficient, dimensionless quantity.

[0081] Substituting equation (6-2) into equation (6-1), we get

[0082]

[0083] Separate variables and integrate

[0084]

[0085] Since T, p, and Z vary with the depth of the well, in order to facilitate direct integration, the average temperature and average pressure of the wellbore are used to calculate the average Z value, and the integration yields

[0086]

[0087] Right now

[0088]

[0089] Where: p ws ——Flow pressure at the tubing shoe of the gas well, MPa;

[0090] p c ——Casing pressure at the wellhead of the gas well, MPa;

[0091] H——Depth from wellhead to the middle of gas layer, m.

[0092] ——Average temperature of the wellbore gas column = (T wh +T ws ) / 2, K;

[0093] ——Average deviation coefficient of wellbore gas column;

[0094] s——exponent, dimensionless.

[0095]

[0096] Therefore, the minimum flow pressure at the tubing shoe is

[0097]

[0098] Wellhead oil pressure-flow pressure prediction method

[0099] Hagedorn and Brown (1965) proposed a pressure drop relationship for two-phase vertical ascending pipe flow under various flow patterns based on the assumed pressure gradient model and the back calculation of liquid holdup based on a large amount of field test data. This pressure drop relationship does not require flow pattern discrimination and is applicable to the flow conditions of water-producing gas wells. Since the pressure drop gradient caused by the change in kinetic energy is very small and can be ignored, the total pressure drop gradient equation is:

[0100]

[0101] Where: g , L , m ——Density of gas phase, liquid phase, gas-liquid mixture, kg / m 3 ;

[0102] ρ m =ρ L H L +ρ g (1-H L ) (12)

[0103] H L ——Liquid holdup rate;

[0104] g——acceleration due to gravity, m / s 2 ;

[0105] A——pipe flow cross-sectional area = πD 2 / 4,m 2 ;

[0106] D——inner diameter of the pipe, m;

[0107] G m ——Mass flow rate of gas-liquid mixture, kg / s;

[0108] G m =G g +G L =A(v SL ρ L +v SG ρ g ) (13)

[0109] G g , G L ——Gas phase and liquid phase mass flow rate, kg / s;

[0110] v SG 、v SL ——Surface velocity of gas and liquid phase, v SG =q g / A,v SL =q L / A, m / s;

[0111] q g ,q L ——Volume flow rate of gas and liquid phase, m 3 / s;

[0112] Two-phase friction coefficient f m The Jain formula is used for calculation, where the two-phase Reynolds number is determined by the following formula

[0113]

[0114] Where:

[0115] μ g , μ L , μ m ——Viscosity of gas, liquid phase and mixture, Pa.s;

[0116] v m ——Mixture flow rate = v SL +v SG , m / s;

[0117] ρ ns ——Density of mixture without slippage, kg / m 3 ;

[0118] λ L ——No slippage liquid retention rate = v SL / v m .

[0119] Inlet energy P 入 The calculation formula is as follows:

[0120] P 入 =P P1 +P E1 (15)

[0121] in:

[0122]

[0123] In the formula, subscripts 1 and 2 represent the inlet and outlet respectively; p wh is the wellhead pressure; p wf is the bottom hole pressure, Q g , Q l is the local volume flow rate of gas and liquid; ρ is the density; v is the real flow rate of gas and liquid; m is the mass flow rate; g is the gravitational acceleration; H 垂深 The vertical height difference between the entrance and exit. The above units are all SI units.

[0124] S4. Obtain the corresponding energy factor β for each typical well according to steps S1-S3, obtain the characteristic value of the standard energy factor β* according to all the obtained energy factors β, or fit the energy factor relationship by the least square method according to the production data and the tubing size;

[0125] S5. Calculate the wellhead gas superficial velocity v according to the wellhead oil pressure, temperature, liquid production, gas production and pipe string size of a certain production state of the predicted well sg , liquid superficial velocity v sl ,

[0126] v sg =q g / A,v sl =q L / A, m / s;

[0127] q g ,q L ——Volume flow rate of gas and liquid phase, m 3 / s;

[0128] The liquid holdup H is calculated as follows: L :

[0129]

[0130] Where g is the acceleration due to gravity, m / s 2 ;σ is the surface tension, N / m; ρ l is the density of the liquid; ρ g is the density of the gas; θ is the pipeline inclination; the above units are all in SI unit system.

[0131] S6. According to the liquid holdup H L Calculate the actual gas-liquid flow rate v at the wellhead g 、v l , calculate the outlet energy P of the predicted well 出 ;

[0132]

[0133]

[0134] In the formula, v sg is the gas superficial velocity, v sl Liquid superficial velocity, m / s; H L is the liquid holdup rate.

[0135] S7. Considering a 5% increase in liquid production, the bottom hole pressure p is calculated based on the predicted wellhead pressure using the multiphase pipe flow calculation method or the annular air column pressure calculation method. wf , calculate the apparent gas-liquid flow rate at the bottom of the well and the liquid holdup at the bottom of the well according to formula (18), and then calculate the real gas-liquid flow rate at the bottom of the well. Finally, calculate the total inlet energy P according to formulas (15) to (16): 入 ;

[0136] The calculation method of wellhead pressure according to multiphase pipe flow or annular air column pressure is the same as the above-mentioned bottom hole flow pressure calculation method, which will not be repeated here. The calculation method of bottom hole gas-liquid superficial velocity is the same as the calculation method of wellhead gas-liquid superficial velocity, which will not be repeated here.

[0137] S8. Based on the above calculation of P 出 , β* and P 入 , if P 入 >(1+β*)P 出 , there is no effusion; if P 入 <(1+β*)P 出 , there is effusion; if P 入 =(1+β*)P 出 , then the critical state.

[0138] The following example illustrates

[0139] A method for predicting liquid loading in a shale gas well based on an energy model comprises the following steps:

[0140] S1. Six typical shale gas wells that have been in production for many years are selected as research objects. The downhole liquid accumulation situation during the production cycle of shale gas wells is fitted using the liquid accumulation prediction energy model and judgment method. The actual liquid accumulation situation of the six shale gas wells (each well contains 3 subcritical liquid accumulation state data) during the whole life cycle and the calculation results of the energy factor β are shown in Table 1.

[0141] Table 1 Energy factor β of typical shale gas wells

[0142] hashtag A B C D E F average value Energy factor β -0.090 -0.080 -0.085 -0.100 -0.083 -0.092 -0.088

[0143] The energy factor values ​​of each well of the typical shale gas well S2.6 are close in size, and the production characteristics and pay layer characteristics of the shale gas wells in the same block are similar. Therefore, the average value can be taken as the energy factor of the shale gas well in this block, that is, β*=-0.088. This value is a constant and may also be fitted as an expression of production data. Specifically, the energy factor relationship is fitted according to the production data and the tubing size using the least squares method.

[0144] S3. Using the basic data of the predicted wells, the production data and β calculation results of the predicted liquid-filled wells are shown in Table 2.

[0145] Table 2 Production data and β calculation results of predicted liquid loading wells

[0146]

[0147]

[0148]

[0149] S4. When verifying the accuracy of the liquid accumulation prediction energy model and judgment method, taking into account the influence of factors such as changes in the production system of each well, the error of the β* value is allowed to be 5%, that is, β* = -0.083 ~ -0.093. The liquid accumulation prediction results of the liquid accumulation prediction energy model are compared with the actual liquid accumulation situation of shale gas wells. The results are as follows: the liquid accumulation prediction results of the liquid accumulation prediction energy model are consistent with the actual liquid accumulation situation of shale gas wells, with an accuracy rate of 91.67%.

[0150] According to if P 入 >(1+β*)P 出 , there is no effusion; if P 入 <(1+β*)P 出 , there is effusion; then P 入 / P 出 -1>β*, no effusion; P 入 / P 出 -1<β*, then there is effusion.

[0151] Example 2

[0152] This embodiment provides a shale gas well liquid accumulation prediction device based on an energy model, including a processor and a memory, wherein the memory 301 and the processor 302 are interconnected via a bus 303 .

[0153] The memory stores computer executable instructions.

[0154] The processor executes the computer execution instructions stored in the memory, so that the processor executes the shale gas well liquid accumulation prediction method described in Example 1.

[0155] For example, the memory may include, but is not limited to, random access memory (RAM), read only memory (ROM), flash memory, first input first output (FIFO) and / or first in last out (FILO), etc. Specifically, the processor may include one or more processing cores, such as a 4-core processor, an 8-core processor, etc. The processor may be implemented in at least one hardware form of DSP (Digital Signal Processing), FPGA (Field-Programmable Gate Array), and PLA (Programmable Logic Array). At the same time, the processor may also include a main processor and a coprocessor. The main processor is a processor for processing data in the awake state, also known as a CPU (Central Processing Unit); the coprocessor is a low-power processor for processing data in the standby state.

[0156] Example 3

[0157] This embodiment provides a computer-readable storage medium, in which computer-executable instructions are stored. When the computer-executable instructions are executed by a processor, they are used to implement the shale gas well liquid accumulation prediction method described in Example 1.

[0158] Example 4

[0159] This embodiment may also provide a computer program product, including a computer program, which, when executed by a processor, implements the shale gas well liquid accumulation prediction method as described in Example 1.

[0160] The specific implementation methods described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific implementation method of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A shale gas well liquid loading prediction method based on energy model, characterized in that: The prediction method comprises: S1. Collect historical production characteristic data, critical liquid loading state data, wellbore structure characteristic data, fluid characteristic data and oil casing size data of typical wells; S2. According to the historical production characteristics data of typical wells and the critical liquid loading state data, the actual gas production Q g And liquid production Q l Calculate wellhead energy and P 出 ; S3. According to the optimal pipe flow calculation method of the block, according to the actual gas production Q g And liquid production (1+5%) Q l Calculate the bottom hole pressure p wf , and calculate the inlet energy P 入 , and according to β=P 入 / P 出 -1 calculates the energy factor β; S4. Each typical well obtains its corresponding energy factor β according to steps S1-S3, and obtains an expression of a standard energy factor β* according to all the obtained energy factors β; S5. Calculate the wellhead gas superficial velocity v according to the wellhead oil pressure, temperature, liquid production, gas production and pipe string size of a certain production state of the predicted well sg , liquid superficial velocity v sl , and calculate the liquid holdup H as follows L : Where g is the acceleration due to gravity, m / s 2 ;σ is the surface tension, N / m; ρ l is the density of the liquid; ρ g is the density of the gas; θ is the inclination angle of the pipeline; S6. According to the liquid holdup H L Calculate the actual gas-liquid flow rate v at the wellhead g 、v l , calculate the outlet energy P of the predicted well 出 ; S7. Calculate the bottom hole pressure p according to the predicted wellhead pressure using the multiphase pipe flow calculation method or the annular air column pressure calculation method wf Considering a 5% increase in liquid production, calculate the apparent gas-liquid flow rate at the bottom of the well and the liquid holdup at the bottom of the well according to formula (18), and then calculate the real gas-liquid flow rate at the bottom of the well, and finally calculate the total inlet energy P 入 ; S8. Based on the above calculation of P 出 , β* and P 入 , if P 入 >(1+β*)P 出 , there is no effusion; if P 入 <(1+β*)P 出 , there is effusion; if P 入 =(1+β*)P 出 , then the critical state.

2. The method for predicting liquid accumulation in shale gas wells based on energy model according to claim 1, characterized in that: The production characteristic data include gas production, liquid production, wellhead oil pressure, wellhead temperature and wellhead casing pressure.

3. The method for predicting liquid accumulation in shale gas wells based on energy model according to claim 1, characterized in that: The critical liquid accumulation state data include gas production, liquid production, wellhead oil pressure, wellhead temperature and wellhead casing pressure corresponding to the critical liquid accumulation state.

4. The method for predicting liquid accumulation in shale gas wells based on energy model according to claim 1, characterized in that: The wellbore structural characteristic data include well inclination, sounding depth, vertical depth, guide tube, surface casing size and depth, oil layer casing size and depth.

5. The method for predicting liquid accumulation in shale gas wells based on energy model according to claim 1, characterized in that: The fluid characteristic data include the viscosity of shale gas, the density of shale gas, the volume coefficient of shale gas, the viscosity of produced water and the density of produced water.

6. The method for predicting liquid accumulation in shale gas wells based on energy model according to claim 1, characterized in that: The tubing and casing size report includes tubing size and depth, production casing size and depth.

7. The method for predicting liquid accumulation in shale gas wells based on energy model according to claim 1, characterized in that: The total inlet energy P 入 Obtained by the following formula, P 入 =P P1 +P E1 (15) in: Where: P P1 is the pressure energy, P E1 is the kinetic energy, subscripts 1 and 2 represent the inlet and outlet respectively; p wh is the wellhead pressure; p wf is the bottom hole pressure, Q g , Q l is the local volume flow rate of gas and liquid; ρ is the density; v is the true flow velocity of gas and liquid; m is the mass flow rate; g is the acceleration due to gravity.

8. The method for predicting liquid accumulation in shale gas wells based on energy model according to claim 1, characterized in that: The total outlet energy P 出 Obtained by the following formula, P 出 =P P2 +P E2 +P h2 (1) Where P P2 is the pressure energy, P E2 is kinetic energy, P h2 for potential; in, In the formula, subscripts 1 and 2 represent the inlet and outlet respectively; p wh is the wellhead pressure; p wf is the bottom hole pressure, Q g , Q l is the local volume flow rate of gas and liquid; ρ is the density; v is the real flow rate of gas and liquid; m is the mass flow rate; g is the gravitational acceleration; H 垂深 It is the vertical height difference between entrance and exit.

9. A shale gas well liquid accumulation prediction device based on energy model, characterized in that: including a processor and a memory; The memory stores computer-executable instructions; The processor executes the computer-executable instructions stored in the memory, so that the processor executes the shale gas well liquid accumulation prediction method according to any one of claims 1 to 8.

10. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores computer-executable instructions, which, when executed by a processor, are used to implement the shale gas well liquid accumulation prediction method according to any one of claims 1 to 8.

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