A method and system for determining boundary conditions for foam drainage construction

Abstract

The application discloses a kind of foam drainage construction boundary condition determination method and system, comprising: constructing the wellbore multiphase flow model considering pressure field, temperature field and wellbore structure;Gas reservoir production characteristic model considering reservoir shale gas adsorption and desorption characteristics is constructed;According to the target gas well production parameters predicted by the wellbore multiphase flow model and the gas reservoir production characteristic model, a critical liquid carrying speed model is constructed, and the critical liquid carrying speed of the target gas well is predicted according to the critical liquid carrying speed model;According to the gas reservoir production characteristic model, the apparent gas flow rate of the target gas well is predicted;Based on the critical liquid carrying speed and the apparent gas flow rate, the wellbore fluid accumulation time and wellbore fluid accumulation characteristics of the target gas well are determined.The method given by the application considers the influence of multiphase flow law in wellbore on gas reservoir production performance and foam drainage construction effect, and through the application, foam drainage construction effect and subsequent injection system can be judged according to real-time wellbore fluid accumulation condition.

Description

Technical Field

[0001] This invention relates to the field of shale gas reservoir development technology, and in particular to a method and system for determining boundary conditions during foam drainage construction. Background Technology

[0002] Wellbore fluid accumulation is a common technical challenge in the development of unconventional gas reservoirs such as shale gas. It reduces the pressure difference between the bottom-hole flowing pressure and the formation pore pressure, leading to decreased gas well productivity and severely restricting the efficient exploration and development of shale gas reservoirs. Foam drainage technology, as one of the main means to solve the wellbore fluid accumulation problem, plays a crucial role in reducing the productivity loss caused by this issue through its reasonable construction process design.

[0003] To reduce the impact of wellbore fluid accumulation on shale gas well productivity and improve the construction efficiency of foam drainage technology, scholars both domestically and internationally have conducted a series of studies. Optimizing foam drainage technology involves two key issues: the appropriate timing of foam drainage construction and the appropriate dosage of chemicals used in foam drainage.

[0004] Regarding the timing of foam drainage operations, current methods primarily focus on studying the liquid accumulation state at the critical fluid-carrying velocity to determine whether foam drainage is necessary. However, judging wellbore liquid accumulation based solely on flow velocity only identifies the current production status and cannot predict the wellbore liquid accumulation state or the timing of foam drainage operations. Some scholars have conducted related research from the perspective of gas reservoir simulation, predicting dynamic changes in gas reservoir production capacity. However, these methods only consider the influence of gas reservoir seepage characteristics, resulting in relatively low prediction accuracy and neglecting the impact of multiphase flow patterns within the wellbore on gas reservoir production dynamics and the effectiveness of foam drainage operations. Summary of the Invention

[0005] This invention aims to at least partially solve one of the technical problems in the aforementioned technologies. To this end, a first aspect of this invention proposes a method for determining the boundary conditions in foam drainage construction, comprising:

[0006] Construct a multiphase flow model for the wellbore that considers the pressure field, temperature field, and wellbore structure;

[0007] Construct a gas reservoir production characteristic model that considers the adsorption and analysis characteristics of shale gas in the reservoir;

[0008] Based on the target gas well production parameters predicted by the wellbore multiphase flow model and the gas reservoir production characteristic model, a critical liquid carrying velocity model is constructed, and the critical liquid carrying velocity of the target gas well is predicted based on the critical liquid carrying velocity model.

[0009] Predict the apparent gas velocity of the target gas well based on the gas reservoir production characteristic model;

[0010] Based on the critical liquid-carrying velocity and the apparent gas velocity, the wellbore liquid accumulation time and wellbore liquid accumulation characteristics of the target gas well are determined.

[0011] Preferably, the construction of the wellbore multiphase flow model considering the pressure field, temperature field, and wellbore structure includes:

[0012] The wellbore is divided into several wellbore micro-units based on its depth;

[0013] The temperature at the lower end of the first wellbore micro-unit is calculated based on the temperature field equation.

[0014] Based on the set pressure drop and average temperature of the first wellbore micro-unit, the fluid properties of the first wellbore micro-unit are calculated, and the theoretical pressure drop of the first wellbore micro-unit is calculated by combining the two-phase drift velocity equation and the two-phase momentum-mass equation.

[0015] The set pressure drop of the first wellbore micro-unit is compared with the theoretical pressure drop;

[0016] When it is determined that the first wellbore micro-unit does not meet the micro-unit convergence requirement, the theoretical pressure drop is used as the new set pressure drop, and the theoretical pressure drop is iterated; when it is determined that the first wellbore micro-unit meets the micro-unit convergence requirement, the pressure drop solution for the next micro-unit is entered.

[0017] Repeat the above method until all wellbore micro-elements are solved, and obtain the wellbore multiphase flow model that considers the pressure field, temperature field and wellbore structure.

[0018] Preferably, the two-phase momentum-mass equation includes the gas-liquid phase mass conservation equation and the gas-liquid mixture momentum conservation equation; wherein,

[0019] The gas-liquid phase mass conservation equation includes:

[0020]

[0021]

[0022] Among them, E g Indicates the gas content at the interface; E l Indicates the liquid content at the interface; ρ g ρ represents the density of the gas phase. l This represents the density of the liquid phase; v g Indicates the velocity of the gas phase; v l The velocity of the liquid phase is represented by t; time is represented by s; and position in three-dimensional space is represented by s.

[0023] The momentum conservation equation for the gas-liquid mixture includes:

[0024]

[0025] E g +E l =1

[0026] ρ M =E g ρ g +E l ρ l

[0027] u M =E g u g +E l u l

[0028] u g =C0u M +u gr

[0029] Where A is the cross-sectional area of ​​the flow channel; f M ρ is the friction factor for wellbore flow. M U represents the density of the mixture. g Indicates gas phase velocity; u l Indicates the liquid phase velocity; u M Indicates the velocity of the mixture; u gr θ represents the drift velocity; p is the wellbore pressure; C0 is the distribution coefficient; g represents the gravitational acceleration; d represents the equivalent diameter; θ represents the well inclination angle.

[0030] Preferably, the expression for the distribution coefficient includes:

[0031]

[0032]

[0033]

[0034]

[0035]

[0036] Where C0 represents the distribution coefficient; f tp Indicates flow friction; Ra represents Reynolds number; D represents pipe diameter; β represents gas holdup; V sg V represents the critical velocity in the gas phase. sl Indicates the critical flow rate of the liquid phase; x represents the mass gas content; m g Indicates gas phase mass flow rate; m l Re represents the liquid phase mass flow rate; tp Represents the Reynolds number for two-phase flow; α represents the gas holdup at the cross section; ρ g ρ lThese represent the gas phase and liquid phase densities, respectively; C1 represents the annular flow coefficient.

[0037] Preferably, the two-phase drift velocity equation includes:

[0038]

[0039] Where σ represents surface tension.

[0040] Preferably, the temperature field equation includes:

[0041]

[0042]

[0043]

[0044] Among them, T fout Indicates the outlet fluid temperature of the wellbore micro-unit; T fin Indicates the inlet fluid temperature of the wellbore micro-unit; T eout Indicates the formation temperature at the wellbore micro-unit outlet; T ein Z represents the formation temperature at the wellbore micro-unit outlet. out Indicates the outlet well depth of the wellbore micro-unit; Z iu Indicates the inlet depth of the wellbore micro-unit; g t Represents the temperature gradient of a micro-unit in the wellbore; α J Represents the Joule-Thomson coefficient; A1 represents the relaxation factor; U to W represents the overall heat transfer coefficient. m Indicates mass flow rate; r to Indicates the outer diameter of the casing; K e C represents the thermal conductivity of the formation. p f(t) represents the specific heat capacity of a fluid at constant pressure; D ) represents a dimensionless time function; v m z represents the flow velocity of the mixture; z represents the well depth; p represents the wellbore pressure at the corresponding depth.

[0045] Preferably, when calculating the fluid property parameters of the first wellbore micro-unit based on the set pressure drop and average temperature, the calculation formulas for the fluid property parameters include:

[0046]

[0047] Where Z represents the gas compressibility coefficient; T r P represents the ratio of the absolute temperature of a gas in its actual state to its critical temperature. r Indicates comparative pressure;

[0048]

[0049] Where, σ w P represents the gas-water interfacial tension; T represents the wellbore pressure at the calculated depth; and T represents the wellbore temperature at the calculated depth.

[0050] Preferably, the gas reservoir production characteristic model consists of several equations, including the two-phase mass conservation equation, Darcy's law, auxiliary equations, heat transfer equations, and shale gas adsorption analytical equations.

[0051] Preferably, the two-phase mass conservation equation includes:

[0052]

[0053] Among them, S g Indicates gas phase saturation; S w Indicates water phase saturation; B g B represents the volume coefficient of the gas phase; w The volume coefficient of the aqueous phase; μ g μ represents the viscosity of the gas phase. w Indicates the viscosity of the aqueous phase; k rg k represents the relative permeability of the gas phase. rw p represents the relative permeability of the aqueous phase. g p represents the pressure in the gas phase. w The pressure of the aqueous phase is represented by Z; the gas compressibility coefficient is represented by q. gs Indicates gas phase flow rate; q ws This indicates the liquid phase flow rate.

[0054] Preferably, the auxiliary equations include: capillary force equation, saturation equation, gas-liquid two-phase relative permeability equation, porosity equation, and gas-liquid two-phase system coefficient equation; wherein,

[0055] The capillary force equation includes:

[0056] p cgw =p g -p w =p cgw (S w )

[0057] The saturation equation includes:

[0058] S g +S w =1

[0059] The gas-liquid two-phase relative permeability equation includes:

[0060] k rw =f(S) w )

[0061] k rg =f(S) g )

[0062] The porosity equation includes:

[0063]

[0064] The coefficient equations for the gas-liquid two-phase system include:

[0065]

[0066]

[0067] Where, ρ g ρ represents the gas phase density. w Indicates the density of the liquid phase; Indicates porosity; Indicates initial porosity; p cgw Indicates capillary pressure; C R p represents the rock compressibility coefficient. sc T represents the pressure under standard ground conditions. sc V represents the temperature under standard ground conditions; w V represents the velocity of the water phase; ws ρ represents the volume of the liquid phase. ws ρ represents the density of the liquid phase. w c represents the density of the aqueous phase. w Indicates the compressibility coefficient of the aqueous phase; Indicates the initial volume fraction of the liquid phase; Indicates the initial density of the gas phase; Indicates the initial density of the liquid phase; This indicates the initial pressure of the gas phase.

[0068] Preferably, the heat transfer equation includes:

[0069]

[0070] Where U represents the internal energy of the gas; ρ s c represents the density of shale; s The specific heat capacity of shale is represented by h; the enthalpy of the gas is represented by k. t ρ represents the thermal conductivity coefficient; T1 represents the temperature field of the wellbore; ρ represents the rock density; v represents the fluid velocity; and t represents time.

[0071] Preferably, the shale gas adsorption analytical equation includes:

[0072]

[0073] Among them, V LThe Langmuir concentration of the gas is represented by K(T); the adsorption equilibrium constant is represented by K(T).

[0074] K(T)=k0T -1 / 2 e -E / RT

[0075] Where k0 represents the pre-exponential constant; E is the characteristic adsorption energy.

[0076]

[0077]

[0078] Where C(p,T) represents the gas concentration in the microporous system at temperature T and pressure p; τ represents the adsorption time.

[0079] Preferably, the step of constructing a critical fluid-carrying velocity model based on the target gas well production parameters predicted by the wellbore multiphase flow model and the gas reservoir production characteristic model includes:

[0080] Determine the well type of the target gas well; wherein, the well type includes: vertical well, inclined well, and horizontal well;

[0081] The formula for calculating the critical fluid carrying rate is determined based on the gas well type.

[0082] Substituting the target gas well production parameters into the critical fluid carrying rate calculation formula, the critical fluid carrying rate model is obtained.

[0083] Preferably, the formula for calculating the critical fluid-carrying velocity of the vertical well includes:

[0084]

[0085] Among them, v vgc The critical fluid-carrying velocity of a vertical well is represented by σ; k represents an empirical coefficient obtained by fitting production data; d represents the droplet width; σ w ρ represents the interfacial tension between air and water; l ρ represents the density of a liquid. g represents the gas density; g represents the acceleration due to gravity.

[0086] Preferably, the formula for calculating the critical fluid-carrying velocity of the vertical well corresponding to the deviated well includes:

[0087]

[0088]

[0089] Among them, v cgc The critical fluid-carrying velocity of the deviated well is represented by σ; surface tension is represented by n; gas velocity correlation coefficient is represented by μ.a β represents the liquid viscosity; θ represents the droplet tilt angle; R represents the well inclination angle; and d represents the droplet width.

[0090] Preferably, the formula for calculating the critical fluid-carrying velocity of the vertical well corresponding to the horizontal well includes:

[0091]

[0092] Among them, v hgc This indicates the critical fluid-carrying velocity in a horizontal well.

[0093] Preferably, after determining the wellbore fluid accumulation time and characteristics of the target gas well, the method further includes: designing a foam drainage scheme based on the wellbore fluid accumulation time and characteristics, including:

[0094] Based on the formation temperature requirements and the temperature resistance characteristics of the agents, the foaming and drainage agents are divided into several types of treatment agents, each with a different temperature range.

[0095] An orthogonal experimental design was used to construct a bubble discharge-related test matrix; wherein, the parameters corresponding to the elements of the bubble discharge-related test matrix include: type of treatment agent, concentration of treatment agent, well inclination angle, hydrogen sulfide content, gas flow rate and maximum drainage volume;

[0096] The location of the liquid accumulation is calculated based on the wellbore multiphase flow model and the gas reservoir production characteristic model, and the volume of liquid accumulation in the target gas wellbore is also calculated.

[0097] The foaming treatment agent is selected based on the volume of the accumulated liquid and the foaming-drainage related test matrix.

[0098] Preferably, the calculation of the liquid accumulation location based on the wellbore multiphase flow model and the gas reservoir production characteristic model includes:

[0099] Based on the wellhead oil pressure data, the wellbore pressure distribution relationship under the target gas well liquid accumulation condition is calculated iteratively from the wellhead downwards to obtain the first distribution curve;

[0100] Treating the annulus as a pure gas column, based on the wellhead casing pressure data of the target gas well, and according to the temperature and pressure parameters of the gas in the wellbore, the pressure iteration method is used to iteratively calculate the bottom hole flowing pressure of the target gas well from the wellhead downwards.

[0101] Based on the bottom-hole flowing pressure and the temperature and pressure parameters of the formation water, the pressure distribution relationship of the wellbore is calculated iteratively from the bottom of the well upwards to obtain the second distribution curve;

[0102] The intersection of the first distribution curve and the second distribution curve is the location of the accumulated liquid.

[0103] A second aspect of the present invention also provides a system for determining the boundary conditions of foam drainage construction, the system being used to implement at least one of the methods described above.

[0104] Compared with the prior art, the beneficial effects of the present invention are:

[0105] 1. This invention provides a method for determining the boundary conditions of foam drainage construction, constructs a reservoir-wellbore integrated coupled production capacity prediction model and a critical liquid-carrying velocity calculation model, and proposes a new wellbore liquid accumulation discrimination method, which can predict the specific time of foam drainage construction in advance;

[0106] 2. The method presented in this invention establishes a model for predicting the characteristics of wellbore fluid accumulation and constructs an optimization design method for foam drainage formulation based on the volume of wellbore fluid accumulation. Based on the prediction results, the construction plan such as the injection system and intervention time of the foam drainage treatment agent can be optimized in advance.

[0107] 3. The method provided in this invention can determine the effectiveness of the foaming and drainage operation and the subsequent injection system based on the real-time wellbore fluid accumulation status.

[0108] Other features and advantages of the invention will be set forth in the following description, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the written description and the accompanying drawings.

[0109] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0110] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0111] Figure 1 A schematic diagram illustrating the method for determining boundary conditions in foam drainage construction;

[0112] Figure 2 This is a schematic diagram comparing the apparent velocity scatter plot and the critical liquid-carrying velocity scatter plot for the 47th weather phase given in Example 1.

[0113] Figure 3 This is a schematic diagram comparing the apparent velocity scatter plot and the critical liquid-carrying velocity scatter plot of the 95th weather phase given in Example 1.

[0114] Figure 4 This is a schematic diagram comparing the apparent velocity scatter plot and the critical liquid-carrying velocity scatter plot for the 142nd weather phase given in Example 1.

[0115] Figure 5The wellbore fluid accumulation depth curve calculated based on the reservoir-wellbore integrated coupling model is given in Example 1;

[0116] Figure 6 This is a schematic diagram of the change curve of wellbore fluid height over time after bubble drainage production, as given in Example 1.

[0117] Figure 7 The scatter plot shows the changes in critical liquid-carrying velocity and actual velocity with well depth after bubble drainage production, as given in Example 1.

[0118] Figure 8 This is a schematic diagram illustrating the method for calculating the depth of fluid accumulation in a wellbore, as shown in the example.

[0119] Figure 9 This is a schematic diagram comparing the apparent velocity scatter points and the critical liquid-carrying velocity scatter points of the 32nd weather phase given in Example 2.

[0120] Figure 10 This is a schematic diagram comparing the apparent velocity scatter points and the critical liquid-carrying velocity scatter points of the 86th weather phase given in Example 2.

[0121] Figure 11 This is a schematic diagram comparing the apparent velocity scatter points and the critical liquid-carrying velocity scatter points of the 128th weather phase given in Example 2.

[0122] Figure 12 The wellbore fluid accumulation depth curve calculated based on the reservoir-wellbore integrated coupling model is given in Example 2;

[0123] Figure 13 This is a schematic diagram of the change curve of wellbore fluid height over time after bubble drainage production, as given in Example 2.

[0124] Figure 14 The scatter plot shows the changes in critical fluid-carrying velocity and actual velocity with well depth after bubble drainage production, as given in Example 2. Detailed Implementation

[0125] The preferred embodiments of the present invention will be described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0126] Figure 1 The method for determining the construction boundary conditions of foam drainage provided by this invention includes:

[0127] Construct a multiphase flow model for the wellbore that considers the pressure field, temperature field, and wellbore structure;

[0128] Construct a gas reservoir production characteristic model that considers the adsorption and analysis characteristics of shale gas in the reservoir;

[0129] Based on the production parameters of the target gas well predicted by the wellbore multiphase flow model and the gas reservoir production characteristic model, a critical liquid carrying velocity model is constructed, and the critical liquid carrying velocity of the target gas well is predicted based on the critical liquid carrying velocity model.

[0130] Predict the apparent gas velocity of the target gas well based on the gas reservoir production characteristic model;

[0131] Based on the critical liquid-carrying velocity and the apparent gas velocity, the wellbore liquid accumulation time and characteristics of the target gas well are determined.

[0132] According to some embodiments of the present invention, a wellbore multiphase flow model considering pressure field, temperature field, and wellbore structure is constructed, the steps of which include:

[0133] According to the pressure iteration method, the wellbore is divided into n wellbore micro-units;

[0134] The temperature at the lower end of the wellbore micro-unit was calculated using the temperature field formula.

[0135] Assuming the pressure difference of the first wellbore micro-unit, the fluid physical property parameters are calculated based on the average temperature and average pressure of the micro-unit. Combined with the drift flow model and the mass conservation equation of the two phases, parameters such as gas phase velocity, liquid phase velocity, gas content, and liquid holdup are calculated.

[0136] Calculate the pressure drop of the micro-element using the momentum equation and compare it with the assumed value. If the requirement is met (the requirement here refers to the convergence of the micro-element, and the convergence condition is that the error between two consecutive iterations is less than 10), then... -5 If the voltage drop is not found, proceed to the solution of the next micro-element; otherwise, use the newly calculated voltage drop as the initial value and recalculate the voltage drop of the micro-element iteratively.

[0137] After the micro-unit converges, the thermodynamic parameters and the temperature at the bottom of the new micro-unit are calculated, and a new round of iteration is started until the depth to the bottom of the well is calculated.

[0138] The formulas and equations used in this process include:

[0139] 1. Two-phase momentum-mass equations, including: the mass conservation equation for the gas-liquid phase and the momentum conservation equation for the gas-liquid mixture; wherein, the mass conservation equation for the gas-liquid phase includes:

[0140]

[0141]

[0142] Among them, E g Indicates the gas content at the interface; E l Indicates the liquid content at the interface; ρ g ρ represents the density of the gas phase. l This represents the density of the liquid phase; v g Indicates the velocity of the gas phase; vl The velocity of the liquid phase is represented by t; time is represented by s; and space in three dimensions is represented by s.

[0143] The momentum conservation equations for gas-liquid mixtures include:

[0144]

[0145] E g +E l =1

[0146] ρ M =E g ρ g +E l ρ l

[0147] u M =E g u g +E l u l

[0148] u g =C0u M +u gr

[0149] Where A is the cross-sectional area of ​​the flow channel; f M ρ is the friction factor for wellbore flow. M U represents the density of the mixture. g Indicates gas phase velocity; u l Indicates the liquid phase velocity; u M Indicates the velocity of the mixture; u gr θ represents the drift velocity; p is the wellbore pressure; C0 is the distribution coefficient; g represents the gravitational acceleration; d represents the equivalent diameter; θ represents the well inclination angle.

[0150] The expression for the distribution coefficient C0 includes:

[0151]

[0152]

[0153]

[0154]

[0155]

[0156] Where C0 represents the distribution coefficient; f tp Indicates flow friction; Ra represents Reynolds number; D represents pipe diameter; β represents gas holdup; V sg V represents the critical velocity in the gas phase.sl Indicates the critical flow rate of the liquid phase; x represents the mass gas content; m g Indicates gas phase mass flow rate; m l Re represents the liquid phase mass flow rate; tp Represents the Reynolds number for two-phase flow; α represents the gas holdup at the cross section; ρ g ρ l These represent the gas phase and liquid phase densities, respectively; C1 represents the annular flow coefficient.

[0157] 2. Two-phase drift velocity equations, including:

[0158]

[0159] Where σ represents surface tension.

[0160] 3. Temperature field equations, including:

[0161]

[0162]

[0163]

[0164] Among them, T fout Indicates the outlet fluid temperature of the wellbore micro-unit; T fin Indicates the inlet fluid temperature of the wellbore micro-unit; T eout Indicates the formation temperature at the wellbore micro-unit outlet; T ein Z represents the formation temperature at the wellbore micro-unit outlet. out Indicates the outlet well depth of the wellbore micro-unit; Z in Indicates the inlet depth of the wellbore micro-unit; g t Represents the temperature gradient of a micro-unit in the wellbore; α J Represents the Joule-Thomson coefficient; A1 represents the relaxation factor; U to W represents the overall heat transfer coefficient. m Indicates mass flow rate; r to Indicates the outer diameter of the casing; K e C represents the thermal conductivity of the formation. p f(t) represents the specific heat capacity of a fluid at constant pressure; D ) represents a dimensionless time function; v m z represents the flow velocity of the mixture; z represents the well depth; p represents the wellbore pressure at the corresponding depth.

[0165] According to some embodiments of the present invention, when calculating the fluid property parameters of the first wellbore micro-unit based on the set pressure drop and average temperature, the calculation formulas for the fluid property parameters include:

[0166]

[0167] Where Z represents the gas compressibility coefficient; T r P represents the ratio of the absolute temperature of a gas in its actual state to its critical temperature. r Indicates comparative pressure;

[0168]

[0169] Where, σ w P represents the gas-water interfacial tension; T represents the wellbore pressure at the calculated depth; and T represents the wellbore temperature at the calculated depth.

[0170] According to some embodiments of the present invention, before predicting the target gas well production parameters based on the wellbore multiphase flow model and the gas reservoir production characteristic model, the method further includes: correcting the wellbore multiphase flow model and the gas reservoir production characteristic model based on actual production data, including:

[0171] By acquiring dynamic production data from gas wells through a real-time network data transmission system at the gas well production site, and utilizing a reservoir-wellbore coupled production capacity prediction model composed of a wellbore multiphase flow model and a gas reservoir production characteristic model, the model predicts the profiles of gas velocity, flow pattern, and pressure distribution within the wellbore as a function of well depth, based on actual production needs and at different time spans. The empirical coefficients of the prediction model are then corrected using real-time data to improve prediction accuracy. The process includes:

[0172] Using production logging results, wellhead production statistics, and formation fluid PVT experimental results, we obtained the original formation pore pressure, initial formation water saturation, geothermal gradient, reservoir porosity, reservoir permeability, well depth structural parameters, real-time wellhead production data, formation water density, gas production density, and formation water volume factor. The temperature and pressure fields within the wellbore were calculated using one-dimensional iterative methods, while the seepage field within the reservoir was solved using the two-dimensional finite difference method. A semi-implicit coupling method was used to solve the integrated reservoir-wellbore model simultaneously, and the corresponding prediction software was developed through FORTRAN programming. After correcting the empirical parameters in the coupled model using historical gas well production data, we obtained the relationship curves between gas production and time, and the relationship curves between gas velocity, liquid holdup, and flow pattern and well depth at different times. During the calculation, the bottomhole flowing pressure at the current moment was first calculated based on the initial and boundary conditions of the wellbore model. Using these as boundary conditions, the gas reservoir model at the current time step is calculated. If the model converges, the process proceeds to the next time step, and the wellhead gas-liquid flow rate calculated from the gas reservoir is transferred to the wellbore model. If the model does not converge, the time step is shortened, the wellbore model is recalculated to obtain the new bottomhole flowing pressure, and the gas reservoir model is solved until the coupled model at that time step fully converges. This iterative calculation is repeated until the predetermined total calculation time is reached.

[0173] According to some embodiments of the present invention, the gas reservoir production characteristic model considering the adsorption and analysis characteristics of shale gas is constructed, which consists of several equations including the two-phase mass conservation equation, Darcy's law, auxiliary equation, heat transfer equation and shale gas adsorption and analysis equation.

[0174] 1. Two-phase mass conservation equations, including:

[0175]

[0176] Among them, S g Indicates gas phase saturation; S w Indicates water phase saturation; B g B represents the volume coefficient of the gas phase; w The volume coefficient of the aqueous phase; μ g μ represents the viscosity of the gas phase. w Indicates the viscosity of the aqueous phase; k rg k represents the relative permeability of the gas phase. rw p represents the relative permeability of the aqueous phase. g p represents the pressure in the gas phase. w The pressure of the aqueous phase is represented by Z; the gas compressibility coefficient is represented by q. gs Indicates gas phase flow rate; q ws This indicates the liquid phase flow rate.

[0177] 2. Auxiliary equations, including: capillary force equation, saturation equation, relative permeability equation for gas-liquid two-phase system, porosity equation, and coefficient equation for gas-liquid two-phase system; among which,

[0178] Capillary force equations, including:

[0179] p cgw =p g -p w =p cgw (S w )

[0180] The saturation equation includes:

[0181] S g +S w =1

[0182] The relative permeability equations for gas-liquid two-phase systems include:

[0183] k rw =f(S) w )

[0184] k rg =f(S) g )

[0185] The above formula indicates that the relative permeability of the gas / liquid phase is a function of the gas / liquid saturation.

[0186] Porosity equations include:

[0187]

[0188] The coefficient equations for gas-liquid two-phase systems include:

[0189]

[0190]

[0191] Where, ρ g ρ represents the gas phase density. w Indicates the density of the liquid phase; Indicates porosity; Indicates initial porosity; p cgw Indicates capillary pressure; C R p represents the rock compressibility coefficient. sc T represents the pressure under standard ground conditions. sc V represents the temperature under standard ground conditions; w V represents the velocity of the water phase; ws ρ represents the volume of the liquid phase. ws ρ represents the density of the liquid phase. w c represents the density of the aqueous phase. w Indicates the compressibility coefficient of the aqueous phase; Indicates the initial volume fraction of the liquid phase; Indicates the initial density of the gas phase; Indicates the initial density of the liquid phase; This indicates the initial pressure of the gas phase.

[0192] 3. Heat transfer equations, including:

[0193]

[0194] Where U represents the internal energy of the gas; ρ s c represents the density of shale; s The specific heat capacity of shale is represented by h; the enthalpy of the gas is represented by k. t ρ represents the thermal conductivity coefficient; T1 represents the temperature field of the wellbore; ρ represents the rock density; v represents the fluid velocity.

[0195] 4. Shale gas adsorption analytical equations, including:

[0196] The extended Langmuir adsorption-desorption equation, which considers temperature and pressure effects, is used to describe the gas adsorption behavior in microporous systems. Its formula is as follows:

[0197]

[0198] Among them, VL The value represents the Langmuir concentration of the gas; K(T) represents the adsorption equilibrium constant.

[0199] K(T)=k0T -1 / 2 e -E / RT

[0200] Where k0 represents the pre-exponential constant; E is the characteristic adsorption energy; the diffusion process of gas in the shale microporous system is described by a quasi-steady-state non-equilibrium adsorption-desorption model, and the gas diffusion obeys Fick's first law, with the following equation form:

[0201]

[0202] Where C(p,T) represents the gas concentration in the microporous system at temperature T and pressure p; τ represents the adsorption time.

[0203] Therefore, the source and sink terms caused by desorption and diffusion in a microporous system can be expressed as:

[0204]

[0205] According to some embodiments of the present invention, a critical liquid carrying rate model is constructed based on the target gas well production parameters predicted by the wellbore multiphase flow model and the gas reservoir production characteristic model. The process includes: determining the gas well type of the target gas well (gas well types include: vertical wells, deviated wells, and horizontal wells); determining the critical liquid carrying rate calculation formula based on the gas well type; and substituting the target gas well production parameters into the critical liquid carrying rate calculation formula to obtain the critical liquid carrying rate model.

[0206] The formula for calculating the critical fluid-carrying velocity of a vertical well includes:

[0207]

[0208] Among them, v vgc The critical fluid-carrying velocity of a vertical well is represented by σ; k represents an empirical coefficient obtained by fitting production data; d represents the droplet width; σ w ρ represents the interfacial tension between air and water; l ρ represents the density of a liquid. g represents the gas density; g represents the acceleration due to gravity.

[0209] The formula for calculating the critical fluid-carrying velocity of a vertical well corresponding to an inclined well includes:

[0210]

[0211]

[0212] Among them, v cgcThe critical fluid-carrying velocity of the deviated well is represented by σ; surface tension is represented by n; gas velocity correlation coefficient is represented by μ. a β represents the liquid viscosity; θ represents the droplet tilt angle; R represents the well inclination angle; and d represents the droplet width.

[0213] The formula for calculating the critical fluid-carrying velocity for a vertical well corresponding to a horizontal well includes:

[0214]

[0215] Among them, v hgc This indicates the critical fluid-carrying velocity in a horizontal well.

[0216] Figures 2-4 The following are schematic diagrams, as given in Example 1, illustrating the apparent gas phase velocity and critical liquid-carrying velocity on days 47, 95, and 142, obtained from the reservoir-wellbore integrated coupling model (comprising a wellbore multiphase flow model and a gas reservoir production characteristic model) combined with the critical liquid-carrying velocity model. The horizontal axis represents velocity, and the vertical axis represents well depth. Through comparison... Figures 2 to 4 It can be seen that at 47 days, the apparent gas phase velocity is just greater than the critical fluid-carrying velocity; at 95 days, the two curves intersect, and the gas phase velocity is less than or equal to the critical fluid-carrying velocity; at 142 days, the gas phase velocity is less than the critical fluid-carrying velocity. Fluid accumulation in the wellbore occurs approximately after 47 days.

[0217] Figures 9-11 The following are schematic diagrams of the apparent gas phase velocity and critical fluid-carrying velocity on days 32, 86, and 128, as given in Example 2. The horizontal axis represents the velocity, and the vertical axis represents the well depth. A comparison shows that on day 32, the apparent gas phase velocity is greater than the critical fluid-carrying velocity; on day 86, the two curves intersect, and the gas phase velocity is less than or equal to the critical fluid-carrying velocity; on day 128, the gas phase velocity is less than the critical fluid-carrying velocity. Comparing these figures indicates that fluid accumulation in the wellbore occurs approximately after day 32.

[0218] According to some embodiments of the present invention, after determining the wellbore fluid accumulation time and wellbore fluid accumulation characteristics of the target gas well, the method further includes:

[0219] A foam drainage scheme is designed based on the duration and characteristics of fluid accumulation in the wellbore, including:

[0220] Based on the formation temperature requirements and the temperature resistance characteristics of the agents, the foaming and drainage agents are divided into several types of treatment agents, each with a different temperature range.

[0221] An orthogonal experimental design was used to construct a bubble discharge-related test matrix. The parameters corresponding to the elements of the bubble discharge-related test matrix include: type of treatment agent, concentration of treatment agent, well inclination angle, hydrogen sulfide content, gas flow rate, and maximum drainage volume.

[0222] The location of the liquid accumulation is calculated based on the multiphase flow model of the wellbore and the production characteristic model of the gas reservoir, and the volume of liquid accumulation in the target gas wellbore is also calculated.

[0223] The foaming treatment agent was selected based on the test matrix relating the accumulated liquid volume to the foaming drainage.

[0224] Figure 5 The wellbore fluid accumulation depth curve given in Example 1 is calculated based on the reservoir-wellbore integrated coupling model. The wellbore fluid accumulation height is 213m and the fluid volume is 423L. Based on the above data and the foam drainage related test matrix, the appropriate treatment agent can be selected. Figure 12 This is the wellbore fluid accumulation depth curve obtained according to Example 2 of this method.

[0225] According to some embodiments of the present invention, a method for designing a bubble extraction scheme includes:

[0226] Based on formation temperature requirements and product temperature resistance characteristics, the foaming and drainage agents are categorized into products with different temperature ranges. Foaming and drainage simulation tests were conducted on products with different temperature ranges. Using orthogonal experimental design, the effects of gas flow rate, foaming agent concentration, well inclination angle, formation water salinity, and hydrogen sulfide content on the maximum drainage volume were tested. Based on the test results, a matrix of relevant test results was constructed (treatment agent type, treatment agent concentration, treatment agent temperature resistance characteristics, well inclination angle, salinity, hydrogen sulfide content, gas flow rate, and maximum drainage volume) to facilitate interpolation and optimization calculations when selecting the appropriate treatment agent type and dosage.

[0227] According to some embodiments of the present invention, the design method of the bubble drainage scheme selects the bubble drainage treatment agent based on the test matrix related to the liquid volume and bubble drainage. The selection method includes: evaluating the relationship between the maximum drainage volume and dosage of different treatment agents, gas flow rate and cost.

[0228] The test ranges for each parameter in the example are: ① Concentration: 0.5%-5%; ② Temperature: 40℃-220℃; ③ Well inclination angle: 0°-90°; ④ Flow rate range: (0-10 6 m 3 / d) / Wellbore cross-sectional area; ⑤ Formation water salinity: 0-10 5 mg / L; ⑥ Hydrogen sulfide content: 0-60 g / m 3 Each factor can be set at different levels according to needs.

[0229] According to one embodiment of the present invention, the comprehensive performance of three treatment agents, YHS-1, YHS-2, and YHS-3, was evaluated. A seven-factor, three-level orthogonal experimental design was used. The seven factors correspond to the type of treatment agent, concentration, test temperature, well inclination angle, salinity, hydrogen sulfide content, and gas flow rate, respectively. The levels of each factor are: ① Concentration: 0.5%, 1%, 1.5%; ② Temperature: 150℃, 160℃, 170℃; ③ Well inclination angle: 30°, 60°, 90°; ④ Flow rate range: (10, 50, 100,000 m³ / day) / wellbore cross-sectional area; ⑤ Formation water salinity: 3, 5, 7 g / L; ⑥ Hydrogen sulfide content: 10, 20, 30 g / m³. 3 ⑦ Types: 1, 2, 3.

[0230] According to another embodiment of the present invention, the comprehensive performance of three treatment agents, YHS-1, YHS-2, and YHS-3, was evaluated. A seven-factor, three-level orthogonal experimental design was used. The seven factors correspond to the type of treatment agent, concentration, test temperature, well inclination angle, salinity, hydrogen sulfide content, and gas flow rate, respectively. The levels for each factor are: ① Concentration: 0.5%, 1%, 1.5%; ② Temperature: 70℃, 90℃, 110℃; ③ Well inclination angle: 30°, 60°, 90°; ④ Flow rate range: (0.5, 1, 20,000 m³ / day) / wellbore cross-sectional area; ⑤ Formation water salinity: 1, 3, 5 g / L; ⑥ Hydrogen sulfide content: 5, 10, 15 g / m³. 3 ⑦ Types: 1, 2, 3.

[0231] First, determine the product type based on the temperature range. Then, using the wellbore fluid accumulation as a constraint, select all possible combinations of reagent types and concentrations that meet the requirements. The specific optimization conditions are as follows: ① Required drainage volume × concentration × unit price = cost, take the minimum; ② Maximum drainage volume > wellbore fluid accumulation volume; ③ Temperature resistance > target formation temperature; ④ Well inclination angle > target well inclination angle; ⑤ Gas flow rate < gas flow rate under existing drainage conditions. Based on the above constraints, solve for the minimum cost combination that meets the above requirements.

[0232] According to some embodiments of the present invention, after determining the wellbore fluid accumulation time and characteristics, the method further includes: determining whether subsequent foam drainage measures are needed, and adjusting the subsequent production schedule, characterized in that:

[0233] By combining actual production data to calculate the wellbore fluid accumulation height, a curve showing the relationship between wellbore fluid volume and drainage time was obtained. Based on the trend of wellbore fluid volume change and cumulative drainage volume, the following scenarios were considered to determine whether further operations should be performed:

[0234] ①The continuous reduction of fluid accumulation in the wellbore to near zero indicates that the drainage operation was quite effective;

[0235] ② After the wellbore fluid level drops to a certain value and remains stable, and the cumulative drainage volume is completely greater than the initial design amount of foaming agent, it indicates that the current foaming effect does not meet the requirements. Based on the current wellbore fluid level, the amount of foaming agent should be redesigned.

[0236] ③ If there is no significant change in the fluid accumulation in the wellbore, it indicates that the foaming process has completely failed. The fluid accumulation in the wellbore is far greater than the foam carrying capacity of the foaming agent. A new foaming formula should be used or gas lift should be adopted.

[0237] Figure 6 Based on the curve of wellbore liquid height change over time after bubble drainage production given in Example 1, and combined with the critical liquid-carrying velocity calculation method, the fluid properties of the gas well after bubble drainage production and the formation temperature and pressure characteristics, the latest critical liquid-carrying velocity is calculated, and the gas production rate is adjusted accordingly. Figure 7 The graph shows the curves of the critical fluid-carrying velocity and the actual velocity after bubble drainage production in Example 1, which can be used to further predict the timing of subsequent bubble drainage intervention.

[0238] Figure 13 The figure shows the change curve of the wellbore fluid height over time after the foam drainage process, as given in Example 2. As can be seen from the figure, the wellbore fluid was completely drained in about 13 days, and the foam drainage treatment achieved a good effect. Figure 14 The curve of the critical fluid-carrying velocity after bubble drainage production as a function of well depth is given in Example 2. As can be seen from the figure, after bubble drainage, the timing of subsequent bubble drainage intervention can be further predicted based on this figure.

[0239] According to some embodiments of the present invention, a method for determining the wellbore fluid accumulation time includes:

[0240] Using days as the time unit, the simulation prediction period is first assumed. Based on this prediction period, the curves of the apparent gas velocity and critical fluid-carrying velocity in the wellbore as a function of depth at the current moment are calculated. Whether the two curves intersect or whether the critical fluid-carrying velocity is greater than the apparent gas velocity is used to determine if fluid accumulation has occurred in the wellbore. If fluid accumulation is found, the calculation period is adjusted using the bisection method, and the calculation is repeated for a new time period. If fluid accumulation does not occur in the first calculation, the prediction calculation period is expanded until fluid accumulation occurs in the first calculation within that period. Then, the calculation period is adjusted again using the bisection method for subsequent calculations.

[0241] Starting from the second calculation, if the error between the calculation time and the previous time is less than 1 day, then the last calculation time is the wellbore liquid accumulation time.

[0242] According to some embodiments of the present invention, a method for determining the characteristics of fluid accumulation in a wellbore includes:

[0243] Once the time of wellbore fluid accumulation is determined, a drainage plan can be prepared in advance. When the time is about one week away from the predicted occurrence of wellbore fluid accumulation, the wellbore fluid accumulation situation can be continuously corrected through dynamic production data, and the depth of wellbore fluid accumulation can be calculated.

[0244] The volume of fluid in the wellbore can be obtained by multiplying the depth of fluid accumulation in the wellbore by the cross-sectional area of ​​the wellbore.

[0245] According to some embodiments of the present invention, a method for calculating the depth of fluid accumulation in a wellbore includes:

[0246] Based on the wellhead oil pressure data, the wellbore pressure distribution relationship under the target gas well liquid accumulation condition is calculated iteratively from the wellhead downwards to obtain the first distribution curve;

[0247] Treating the annulus as a pure gas column, based on the wellhead casing pressure data of the target gas well, and according to the temperature and pressure parameters of the gas in the wellbore, the pressure iteration method is used to iteratively calculate the bottom hole flowing pressure of the target gas well from the wellhead downwards.

[0248] Based on the bottom-hole flowing pressure and the temperature and pressure parameters of the formation water, the pressure distribution relationship in the wellbore is calculated iteratively from the bottom of the well upwards to obtain the second distribution curve;

[0249] The intersection of the first and second distribution curves marks the location of the liquid accumulation.

[0250] Figure 8 The diagram below illustrates the method for calculating wellbore fluid accumulation depth in an embodiment. Point A represents the wellhead casing pressure, point B represents the bottom hole flowing pressure, point C represents the wellhead oil pressure, and point D represents the fluid accumulation point. Based on the pressure balance principle, the formula for calculating the bottom hole flowing pressure is as follows:

[0251] P B =P A +P 气 =P C +P D +P 液

[0252] Among them, P B P is the bottom hole flowing pressure; A P represents the wellhead casing pressure; Pgas represents the pressure of the pure gas column in the annulus of the casing and oil well .... C P is the wellhead oil pressure. D Pliquid is the pressure at the fluid accumulation point in the wellbore; Pliquid is the pressure of the fluid column.

[0253] Based on the integrated coupled model of wellbore multiphase flow model and gas reservoir production characteristic model, the semi-implicit solution algorithm provided when establishing the wellbore multiphase flow model is used to iteratively calculate the distribution relationship of wellbore pressure with well depth under liquid accumulation conditions, starting from the wellhead oil pressure at point C.

[0254] Using wellhead casing pressure data and assuming the annulus to be a pure gas column, the bottom hole flowing pressure is calculated from point A at the wellhead using the pressure iteration method based on the changes in temperature and pressure parameters of the gas inside the wellbore.

[0255] Starting from point B at the bottom of the well, the calculation is iterated upwards from the bottom of the well based on the changes in the temperature and pressure parameters of the formation water, until the curve intersects with the wellbore pressure distribution curve predicted by the integrated reservoir wellbore coupling model. The intersection point D is the location of the liquid accumulation.

[0256] According to some embodiments of the present invention, the pressure iteration algorithm process is as follows:

[0257] ① Determine the initial pressure P1, and calculate the depth increment ΔZ and the number of segments N;

[0258] ②The initial design calculates the pressure drop of the section as ΔP, and the pressure at the lower end is calculated using the following formula.

[0259] P 2设 =P1+ΔP 设

[0260] ③ Calculate the average pressure and average temperature of this section;

[0261] ④ Calculate the fluid property parameters and flow parameters at the mean pressure and mean temperature;

[0262] ⑤ Calculate the pressure gradient and pressure drop using the following formulas:

[0263]

[0264] ⑥ Calculate the end pressure using the following formula:

[0265] P 2计 =P1+ΔP 计

[0266] ⑦ Compare the error between the assumed value and the calculated value of the pressure increment. If the error does not meet the requirements, take P2 as the new assumed value and start calculating from step 2 until the requirements are met. Then, take the end pressure of the previous segment as the starting pressure of the next segment to start calculating the next segment.

[0267] The error calculation formula is as follows:

[0268]

[0269] The present invention also provides a foam drainage construction boundary condition determination system, used to implement at least one of the above-mentioned foam drainage construction boundary condition determination methods.

[0270] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0271] 1. This invention provides a method for determining the boundary conditions of foam drainage construction, constructs a reservoir-wellbore integrated coupled production capacity prediction model and a critical fluid-carrying velocity calculation model, and proposes a novel wellbore liquid accumulation discrimination method, which can predict the specific time of foam drainage construction in advance; 2. The method provided by this invention establishes a model for predicting wellbore liquid accumulation characteristics and constructs a foam drainage formulation optimization design method based on wellbore liquid volume, which can optimize the foam drainage treatment agent injection system and intervention time and other construction plans in advance based on the prediction results; 3. The method provided by this invention can judge the foam drainage construction effect and subsequent injection system based on the real-time wellbore liquid accumulation status.

[0272] Obviously, those skilled in the art can make various modifications and variations to this invention without departing from its spirit and scope. Therefore, if these modifications and variations fall within the scope of the claims of this invention and their equivalents, this invention also intends to include these modifications and variations.

Claims

1. A method of determining boundary conditions for foam drainage construction, wherein, include: Construct a multiphase flow model for the wellbore that considers the pressure field, temperature field, and wellbore structure; Construct a gas reservoir production characteristic model that considers the adsorption and analysis characteristics of shale gas in the reservoir; Based on the target gas well production parameters predicted by the wellbore multiphase flow model and the gas reservoir production characteristic model, a critical liquid carrying velocity model is constructed, and the critical liquid carrying velocity of the target gas well is predicted based on the critical liquid carrying velocity model. Predict the apparent gas velocity of the target gas well based on the gas reservoir production characteristic model; Based on the critical liquid-carrying velocity and the apparent gas velocity, the wellbore liquid accumulation time and wellbore liquid accumulation characteristics of the target gas well are determined; wherein... Construct a wellbore multiphase flow model that considers the pressure field, temperature field, and wellbore structure, including: The wellbore is divided into several wellbore micro-units based on its depth; The temperature at the lower end of the first wellbore micro-unit is calculated based on the temperature field equation. Based on the set pressure drop and average temperature of the first wellbore micro-unit, the fluid properties of the first wellbore micro-unit are calculated, and the theoretical pressure drop of the first wellbore micro-unit is calculated by combining the two-phase drift velocity equation and the two-phase momentum-mass equation. The set pressure drop of the first wellbore micro-unit is compared with the theoretical pressure drop; When it is determined that the first wellbore micro-unit does not meet the micro-unit convergence requirement, the theoretical pressure drop is used as the new set pressure drop, and the theoretical pressure drop is iterated; when it is determined that the first wellbore micro-unit meets the micro-unit convergence requirement, the pressure drop solution for the next micro-unit is entered. Repeat the above method until all wellbore micro-elements are solved, and obtain the wellbore multiphase flow model that considers the pressure field, temperature field and wellbore structure; The gas reservoir production characteristic model consists of several equations, including the two-phase mass conservation equation, Darcy's law, auxiliary equations, heat transfer equations, and shale gas adsorption analytical equations.

2. The method of claim 1, wherein, The two-phase momentum-mass equations include the gas-liquid phase mass conservation equation and the gas-liquid mixture momentum conservation equation; wherein... The gas-liquid phase mass conservation equation includes: wherein E g represents the interfacial gas fraction; E l represents the interfacial liquid fraction; p g represents the density of the gas phase; p l represents the density of the liquid phase; v g represents the velocity of the gas phase; v l represents the velocity of the liquid phase; t represents time; s represents the position in three-dimensional space; The momentum conservation equation for the gas-liquid mixture includes: where A is the flow passage cross-sectional area; f M is the wellbore flow friction factor; p M is the mixture density; u g represents the gas phase velocity; u l represents the liquid phase velocity; u M represents the mixture velocity; u gr represents the drift velocity; p is the wellbore pressure; C0 is the distribution coefficient; g represents the gravitational acceleration; d represents the equivalent diameter; and Q represents the inclination angle.

3. The method of claim 2, wherein, The expression for the distribution coefficient includes: wherein Co represents a distribution coefficient; f tp represents a flow friction; Ra represents a Reynolds number; D represents a pipe diameter; β represents a void fraction; V sg represents a gas phase critical flow velocity; V sl represents a liquid phase critical flow velocity; represents a mass void fraction; m g represents a gas phase mass flow rate; m l represents a liquid phase mass flow rate; Re tp represents a two-phase flow Reynolds number; α represents a cross-sectional void fraction; ρ g , ρ l respectively represent gas phase and liquid phase densities; C1 represents an annulus flow path coefficient.

4. The method of claim 3, wherein, The two-phase drift velocity equation includes: Where σ represents surface tension.

5. The method of claim 4, wherein, The temperature field equations include: wherein, represents the wellbore microcell outlet fluid temperature; represents the wellbore microcell inlet fluid temperature; represents the wellbore microcell outlet formation temperature; represents the wellbore microcell outlet formation temperature; represents the wellbore microcell outlet depth; represents the wellbore microcell inlet depth; represents the wellbore microcell temperature gradient; represents the Joule-Thomson coefficient; represents the relaxation factor; represents the overall heat transfer coefficient; represents the mass flow rate; represents the casing outside diameter; represents the formation thermal conductivity; represents the fluid specific heat at constant pressure; represents the dimensionless time function; represents the mixture flow rate; represents the depth; represents the wellbore pressure at the corresponding depth; wherein R represents the ideal gas constant; and T represents the wellbore temperature at the calculated depth.

6. The method of claim 1, wherein, When calculating the fluid property parameters of the first wellbore micro-unit based on its set pressure drop and average temperature, the calculation formulas for the fluid property parameters include: wherein Z represents the gas compressibility factor; T r represents the ratio of the absolute temperature of the gas in its actual state to its critical temperature; P r represents the reduced pressure; where σ w represents the gas-water interfacial tension; P represents the wellbore pressure at the calculated depth; and T represents the wellbore temperature at the calculated depth.

7. The method of claim 1, wherein, The two-phase mass conservation equation includes: where S g represents gas phase saturation; S w represents water phase saturation; B g represents gas phase volume factor; B w represents water phase volume factor; μ g represents gas phase viscosity; μ w represents water phase viscosity; k rg represents gas phase relative permeability; k rw represents water phase relative permeability; p g represents gas phase pressure; p w represents water phase pressure; Z represents gas compressibility factor; q gs represents gas phase flow rate; q ws represents liquid phase flow rate; k represents absolute permeability; γ g represents gas phase relative permeability; γ w represents water phase relative permeability; φ represents porosity.

8. The method of claim 7, wherein, The auxiliary equations include: capillary force equation, saturation equation, relative permeability equation for gas-liquid two-phase system, porosity equation, and coefficient equation for gas-liquid two-phase system; among which... The capillary force equation includes: The saturation equation includes: The gas-liquid two-phase relative permeability equation includes: The porosity equation includes: The coefficient equations for the gas-liquid two-phase system include: where, p g represents the gas phase density; p w represents the liquid phase density; represents the porosity; 0 represents the initial porosity; p cgw represents the capillary pressure; C R represents the rock compressibility; p sc represents the pressure at standard surface conditions; T sc represents the temperature at standard surface conditions; V w represents the water phase flow rate; V ws represents the liquid phase volume; p ws represents the liquid phase density; p w represents the water phase density; c w represents the water phase compressibility; represents the initial volume fraction of the liquid phase; represents the initial density of the gas phase; represents the initial density of the liquid phase; represents the initial pressure of the gas phase; V sc represents the gas volume at standard surface conditions.

9. The method of claim 8, wherein, The heat transfer equation includes: where U represents the gas internal energy; ρ s denotes the shale density; c s denotes the specific heat capacity of the shale; h denotes the gas enthalpy; k t denotes the thermal conductivity; denotes the temperature field of the wellbore; denotes the rock density; denotes the fluid flow rate; t denotes time; denotes the thermal conductivity.

10. The method of claim 9, wherein, The shale gas adsorption analytical equation includes: wherein, V L represents the Langmuir concentration of the gas; K T represents the adsorption equilibrium constant;​ wherein, k 0 represents a pre-exponential constant; E is the characteristic adsorption energy; wherein C p T represents the concentration of gas in the micropore system at temperature T, pressure p; τ represents the adsorption time; C represents the adsorption concentration; t represents the clock time.​​ 11. The method of claim 10, wherein, The step of constructing a critical fluid-carrying velocity model based on the target gas well production parameters predicted by the wellbore multiphase flow model and the gas reservoir production characteristic model includes: Determine the well type of the target gas well; wherein, the well type includes: vertical well, inclined well, and horizontal well; The formula for calculating the critical fluid carrying rate is determined based on the gas well type. Substituting the target gas well production parameters into the critical fluid carrying rate calculation formula, the critical fluid carrying rate model is obtained.

12. The method of claim 11, wherein, The formula for calculating the critical fluid-carrying velocity of the vertical well corresponding to the vertical well includes: wherein v vgc represents the critical liquid-carrying flow rate of a vertical well; k represents an empirical coefficient obtained according to production data; d represents the droplet width; σ w represents the gas-liquid interfacial tension; p l represents the liquid density; p g represents the gas density; and g represents the gravitational acceleration.

13. The method of claim 12, wherein, The formula for calculating the critical fluid-carrying velocity of the vertical well corresponding to the deviated well includes: where v cgc represents the critical liquid-carrying flow rate of the inclined well; represents the surface tension; n represents a gas flow rate correlation coefficient; μ a represents the liquid viscosity; β represents the liquid droplet inclination angle; θ represents the well inclination angle; R represents the ideal gas constant; and d represents the liquid droplet width.

14. The method of claim 13, wherein, The formula for calculating the critical fluid-carrying velocity of the vertical well corresponding to the horizontal well includes: where v hgc represents the critical liquid-carrying flow rate of the horizontal well.

15. The method of claim 1, wherein, After determining the wellbore fluid accumulation time and characteristics of the target gas well, the method further includes: designing a foam drainage scheme based on the wellbore fluid accumulation time and characteristics, including: Based on the formation temperature requirements and the temperature resistance characteristics of the agents, the foaming and drainage agents are divided into several types of treatment agents, each with a different temperature range. An orthogonal experimental design was used to construct a bubble discharge-related test matrix; wherein, the parameters corresponding to the elements of the bubble discharge-related test matrix include: type of treatment agent, concentration of treatment agent, well inclination angle, hydrogen sulfide content, gas flow rate and maximum drainage volume; The location of the liquid accumulation is calculated based on the wellbore multiphase flow model and the gas reservoir production characteristic model, and the volume of liquid accumulation in the target gas wellbore is also calculated. The foaming treatment agent is selected based on the volume of the accumulated liquid and the foaming-drainage related test matrix.

16. The method of claim 15, wherein, The calculation of the liquid accumulation location based on the wellbore multiphase flow model and the gas reservoir production characteristic model includes: Based on the wellhead oil pressure data, the wellbore pressure distribution relationship under the target gas well liquid accumulation condition is calculated iteratively from the wellhead downwards to obtain the first distribution curve; Treating the annulus as a pure gas column, based on the wellhead casing pressure data of the target gas well, and according to the temperature and pressure parameters of the gas in the wellbore, the pressure iteration method is used to iteratively calculate the bottom hole flowing pressure of the target gas well from the wellhead downwards. Based on the bottom-hole flowing pressure and the temperature and pressure parameters of the formation water, the pressure distribution relationship of the wellbore is calculated iteratively from the bottom of the well upwards to obtain the second distribution curve; The intersection of the first distribution curve and the second distribution curve is the location of the accumulated liquid.

17. A system for determining boundary conditions in foam drainage construction, wherein, The system is used to implement the method described in any one of claims 1-16.

Images