A method for calculating productivity of tight gas reservoirs considering dynamic change of water saturation

Abstract

The application discloses a kind of considering the dynamic change of water saturation tight gas reservoir productivity calculation method.This application method is by selecting multiple core samples, combined with the geological data of research area, using the way of steady state method and seepage method, experimental measurement each core sample under different water saturation conditions Start-up pressure gradient and gas-water relative permeability, dynamic start-up pressure gradient empirical formula is established, according to the gas-water relative permeability of each core sample under different water saturation conditions, the gas-water ratio of each core sample is calculated, and based on the physical model of tight gas reservoir fracturing horizontal well and considering the mathematical model of one-way shale gas reservoir fracturing horizontal well, the productivity model of tight gas reservoir fracturing horizontal well considering gas-water two-phase is established, and the IPR curve considering the dynamic change of start-up pressure under different water saturation conditions is obtained.The application realizes the accurate calculation of the productivity of tight gas reservoir, and lays a foundation for the development of tight gas reservoir.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas seepage in oil and gas field development engineering, and particularly relates to a tight gas reservoir productivity calculation method considering dynamic change of water saturation. BACKGROUND

[0002] As an important unconventional resource, the tight gas reservoir has the characteristics of complex structure, dense lithology and high water saturation, and the flow mechanism is very complex. Gas-water two-phase flow often occurs in the development process of the tight gas reservoir, and the starting pressure gradient changes obviously in the gas-water two-phase flow process. The existence of the starting pressure gradient explains the reason why the gas-water two-phase flow in the tight gas reservoir does not conform to the traditional Darcy flow, and has a significant impact on the gas reservoir productivity. Therefore, the research on the influence of water saturation on the productivity of the tight gas reservoir is crucial to the development of the tight gas reservoir.

[0003] At present, for the productivity research of the tight gas reservoir, the technical personnel in the field have established the fractured horizontal well productivity model considering the stress sensitivity, the starting pressure gradient and other factors, and some people have established the tight gas reservoir productivity model considering the dynamic starting pressure gradient effect, and have researched the horizontal well semi-analytical equation considering the two-phase flow. At present, when the gas-water ratio is assumed to be constant in solving the gas-water two-phase productivity formula, but since the water-gas ratio changes constantly with the change of the water saturation, the dynamic water-gas ratio needs to be further considered in establishing the mathematical model.

[0004] In order to further study the seepage mechanism of the tight gas reservoir, the technical personnel in the field have also carried out a large number of laboratory researches. The experiment shows that the seepage curve is nonlinear at low flow rate. The starting pressure gradient, as an important part of the nonlinear flow of unconventional oil and gas reservoirs, widely exists in the gas-water two-phase flow. The existing research shows that the starting pressure gradient changes with the change of the permeability, and when the formation permeability decreases or the water saturation increases, the starting pressure gradient increases, and the empirical formula of the starting pressure gradient, the water saturation and the permeability is determined through the experimental research. Therefore, it is necessary to establish the relationship between the starting pressure gradient and the water saturation in the process of the gas-water two-phase flow in the tight gas reservoir, and analyze the change of the productivity under different water saturation conditions.

[0005] Therefore, it is necessary to establish a tight gas reservoir productivity calculation method considering the dynamic change of the water saturation, and fully consider the change of various flow mechanisms in the tight gas reservoir with the water saturation, so as to lay a foundation for accurate calculation of the productivity of the tight gas reservoir. SUMMARY

[0006] The present application aims at the problem that the influence of water saturation on the productivity of a tight gas reservoir cannot be accurately determined in the prior art, and provides a tight gas reservoir productivity calculation method considering dynamic changes of water saturation, the relationship between water saturation and gas-water ratio and dynamic threshold pressure gradient of the tight gas reservoir is obtained through indoor experiments, the dynamic inflow curve of the tight gas reservoir is accurately obtained, and the influence of water saturation on the productivity of the tight gas reservoir is comprehensively analyzed.

[0007] In order to achieve the above-mentioned purpose, the present application adopts the following technical solutions:

[0008] A tight gas reservoir productivity calculation method considering dynamic changes of water saturation comprises the following steps:

[0009] Step 1: Selecting a region where a tight gas reservoir is located as a research area, selecting multiple core samples in the research area, respectively measuring sample parameters of the core samples, configuring synthetic formation water as injection fluid according to geological data of the research area, and setting the temperature of the core samples;

[0010] Step 2: Combining a steady-state method and a percolation method, respectively measuring the threshold pressure gradient and the gas-water relative permeability of each core sample under different water saturation conditions, obtaining the dynamic threshold pressure gradient curve of each core sample, establishing an empirical formula of the dynamic threshold pressure gradient, and based on the gas-water relative permeability of each core sample under different water saturation conditions, combining basic parameters of the tight gas reservoir where each core sample is located, and calculating the gas-water ratio of each core sample under different water saturation conditions;

[0011] Step 3: Based on the structure of a fractured horizontal well of a tight gas reservoir, combining a mathematical model considering a one-way shale gas reservoir fractured horizontal well, and establishing a tight gas reservoir fractured horizontal well productivity model considering gas-water two phases;

[0012] In the tight gas reservoir fractured horizontal well productivity model considering gas-water two phases in step 3, a plane perpendicular to the fractured horizontal well is selected, the crack extension direction is set as the x-axis, the fractured horizontal well extension direction is set as the y-axis, a two-dimensional coordinate system is established, the formation pressure distribution around the crack when only considering gas phase flow and the formation pressure distribution around the crack when only considering water phase flow are obtained, the formation pressure around the crack when only considering gas phase flow is superimposed on the formation pressure around the crack when only considering water phase flow, and the pseudo-pressure of the formation around the crack is obtained Based on the interference between the fractures and the threshold pressure gradient, the pseudo-pressure distribution around any fracture is obtained, and the fluid flow in the fracture is simplified into two parts, one is the radial flow near the wellbore, and the other is the linear flow far from the wellbore, the radial flow near the wellbore is the plane radial flow, the flow equation of the fluid in the fracture is established based on the non-Darcy effect, and the productivity model of the fractured horizontal well in the tight gas reservoir considering gas-water two phases is obtained based on the pseudo-pressure distribution around any fracture and the flow equation of the fluid in the fracture.

[0013] In step 4, the productivity of the tight gas reservoir under different water saturation conditions is obtained by substituting the gas-water ratio and the threshold pressure gradient of each core sample under different water saturation conditions into the productivity model of the fractured horizontal well in the tight gas reservoir considering gas-water two phases, and the inflow performance curve under different water saturation conditions is obtained.

[0014] Preferably, in step 1, the sample parameters include the diameter, length, porosity and permeability of the rock sample.

[0015] Preferably, the salinity of the synthetic formation water is 46353 mg / L, and the pH value is 6.1, the components of the synthetic formation water include K + , Na + , Ca 2+ , Mg 2+ , Cl - , and HCO 3- , wherein the total concentration of K + and Na + is 12046 mg / L, the concentration of Ca 2+ is 5205 mg / L, the concentration of Mg 2+ is 391 mg / L, the concentration of Cl - is 26139 mg / L, and the concentration of HCO 3- is 1331 mg / L.

[0016] Preferably, in step 2, the dynamic threshold pressure gradient empirical formula is:

[0017]

[0018] In the formula, λ is the dynamic threshold pressure gradient, S w is the water saturation, and a and b are the fitting coefficients of the dynamic threshold pressure gradient.

[0019] The gas-water ratio calculation formula is:

[0020]

[0021] In the formula, Rwg is the gas-water ratio; K rw is the relative permeability of the water phase, K rg is the relative permeability of the gas phase; μ g is the viscosity of the gas phase, in units of Pa-s; μ w is the viscosity of the water phase, in units of Pa-s; B g is the volume factor of the gas phase; B w is the volume factor of the water phase.

[0022] Preferably, the base parameters of the tight gas reservoir include formation thickness, original bottom hole pressure, control radius, fracture half-length, fracture width, fracture permeability, length of the horizontal section of the fractured horizontal well, and formation temperature.

[0023] Preferably, in step 3, the tight gas reservoir fractured horizontal well productivity model considering gas-water two-phase flow is provided with a matrix, a fracture, and a fractured horizontal well, the fractured horizontal well is arranged at the center position of the tight gas reservoir fractured horizontal well productivity model considering gas-water two-phase flow, and the arrangement parameters of the fractured horizontal well include a horizontal section length L, a wellbore radius r w , the horizontal section of the fractured horizontal well is provided with N fractures, each fracture is equidistantly distributed on the horizontal section and penetrates the entire gas layer, and the arrangement parameters of the fracture include a half-length x f , a width w f , and a fracture permeability K f ;

[0024] In the tight gas reservoir fractured horizontal well productivity model considering gas-water two-phase flow, fluid flows from the matrix to the fracture and into the wellbore of the fractured horizontal well along the fracture, at this time, the production of the fractured horizontal well is equal to the sum of the production of each fracture in the gas layer, there are gas-water two-phase flows in the matrix, and there are non-Darcy fluids in the fracture.

[0025] Preferably, in the tight gas reservoir fractured horizontal well productivity model considering gas-water two-phase flow, a two-dimensional coordinate system is established by selecting a plane perpendicular to the fractured horizontal well, setting the fracture extension direction as the x-axis and the fractured horizontal well extension direction as the y-axis, and obtaining the formation pressure distribution around the fracture when only considering gas phase flow as:

[0026]

[0027] In the formula, p is the formation pressure, in units of Pa; μ g is the viscosity of the gas phase, in units of Pa-s; ρ gsc is the gas phase density under standard conditions, in units of kg / m 3 ; q gsc is the gas phase production under standard conditions, in units of kg / m 3 ; K rg is the relative permeability of the gas phase; K m is the formation permeability, in units of m2 ; h is the formation thickness, in m; p g is the gas phase density, in kg / m 3 ;

[0028] The formation pressure distribution around the fracture when only considering the water phase flow is:

[0029]

[0030] wherein μ w is the water phase viscosity, in Pa·s; p wsc is the water phase density at standard conditions, in kg / m 3 ; q wsc is the water phase production at standard conditions, in kg / m 3 ; K rw is the water phase relative permeability; p w is the water phase density, in kg / m 3 ;

[0031] wherein the conformal transformation is performed on the fractured horizontal well, and the transformation parameter u is:

[0032]

[0033] wherein X f is the fracture radius, in m; x is the horizontal coordinate of the location of the tight gas reservoir, y is the vertical coordinate of the location of the tight gas reservoir, and y0 is the vertical coordinate of the location of the fracture;

[0034] The formation pressure around the fracture when only considering the gas phase flow is superimposed with the formation pressure around the fracture when only considering the water phase flow to obtain the pseudo pressure of the formation around the fracture:

[0035]

[0036] wherein p0 is the initial pressure of the formation;

[0037] Based on the interference between the fractures and the starting pressure gradient, the pseudo pressure distribution around any fracture is:

[0038]

[0039] wherein p is the matrix boundary pseudo pressure, is the pseudo pressure of the outer boundary of the jth fracture; r e is the control radius; i is the sequence number of the fracture in the gas layer; R wg is the gas-water ratio; λ w is the water phase pressure starting gradient, j is the number of the fracture being calculated, and q gscfi ​is the gas phase production of the i-th fracture under standard conditions, with the unit of kg / m 3 ; d is the fracture spacing, N0 is the intermediate calculation parameter considering the number of fractures, when the total number of fractures N is odd, d=L / N, N0=(N-1) / 2, when the total number of fractures N is even, d=L / 2N, N0=N-1;

[0040] The flow of the fluid in the fracture is simplified into two parts, one part is the radial flow close to the wellbore, and the other part is the linear flow far away from the wellbore, the radial flow close to the wellbore is the plane radial flow, and the flow equation of the fluid in the fracture is established based on the non-Darcy effect, as shown in formula (7):

[0041]

[0042] In the formula, w f is the thickness of the plane radial flow, the flow radius of the plane radial flow is x f is the half fracture length, K fi is the permeability of the i-th fracture in the gas layer; beta is the turbulence coefficient, with the unit of m -1 ; r is the integral radius;

[0043] According to formula (6) and formula (7), the productivity model of the fractured horizontal well of the tight gas reservoir considering the gas-water two phases is obtained, as shown in formula (8):

[0044] Wherein,

[0045]

[0046] In the formula, A and B are both calculation coefficients of the gas phase production of the i-th fracture under standard conditions.

[0047] The present application has the beneficial effects that:

[0048] The present application provides a productivity calculation method of a tight gas reservoir considering dynamic changes of water saturation, fully considers the changes of gas-water ratio, starting pressure gradient and relative permeability in the gas-water two-phase flow process caused by the changes of water saturation, and is based on the seepage law of the tight gas reservoir under different water saturation conditions obtained by indoor experiments on core samples, combines the physical model of the fractured horizontal well of the tight gas reservoir with the mathematical model of the fractured horizontal well of the unidirectional shale gas reservoir, establishes the productivity model of the fractured horizontal well of the tight gas reservoir considering the gas-water two phases, and the inflow performance curve of the tight gas reservoir under different water saturation conditions can be obtained by using the productivity model of the fractured horizontal well of the tight gas reservoir considering the gas-water two phases, so that the influence of the water saturation on the productivity of the tight gas reservoir can be comprehensively analyzed, and the development of the tight gas reservoir is facilitated. BRIEF DESCRIPTION OF DRAWINGS

[0049] Figure 1 is a dynamic starting pressure gradient curve diagram of the core sample.

[0050] Figure 2 is a gas-water relative permeability change curve diagram of each core sample with water saturation.

[0051] Figure 3 is a structural schematic diagram of a fractured horizontal well productivity model of a tight gas reservoir considering gas-water two phases. In the diagram, (a) is a structural schematic diagram of a fractured horizontal well productivity model of a tight gas reservoir considering gas-water two phases when the total number of fractures N is odd; (b) is a structural schematic diagram of a fractured horizontal well productivity model of a tight gas reservoir considering gas-water two phases when the total number of fractures N is even.

[0052] Figure 4 is an IPR curve diagram of the core sample.

[0053] In the diagram, Core1 is the first core sample, Core2 is the second core sample, and Core3 is the third core sample. DETAILED DESCRIPTION

[0054] The present application will be further described in detail below in combination with the accompanying drawings and specific embodiments:

[0055] The present application proposes a tight gas reservoir productivity calculation method considering dynamic changes in water saturation, specifically including the following steps:

[0056] Step 1, select the area where the tight gas reservoir is located as the research area, and select three core samples in the research area in this embodiment. The diameter, length, porosity, and permeability of each core sample are measured, and the measurement results are shown in Table 1.

[0057] Table 1: Sample parameter table of core sample

[0058]

[0059] According to the geological data of the research area, configure synthetic formation water as the injection liquid and the experimental temperature of the core sample, and set the injection gas phase as nitrogen. The viscosities of the injection gas phase and the synthetic formation water are measured. In this embodiment, the salinity of the synthetic formation water is 46353 mg / L, the pH value is 6.1, and the main mineral is CaCl2. The components of the synthetic formation water include K + , Na + , Ca 2+ , Mg 2+ , Cl - , , and HCO 3- , wherein the total concentration of K + and Na + is 12046 mg / L, and the concentration of Ca2+ The concentration was 5205 mg / L, Mg 2+ The concentration was 391 mg / L, Cl - The concentration was 26139 mg / L, HCO3- 3- The concentration was 1331 mg / L.

[0060] Step 2: Using a combination of steady-state and seepage methods, the starting pressure gradient and relative gas-water permeability of each core sample under different water saturation conditions were measured experimentally to obtain the dynamic starting pressure gradient curves for each core sample, such as... Figure 1 As shown. By fitting the dynamic initiation pressure gradient curves of each core sample, an empirical formula for the dynamic initiation pressure gradient is established, as shown in formula (1):

[0061] In step 2, the empirical formula for the dynamic start-up pressure gradient is:

[0062]

[0063] In the formula, λ is the dynamic start-up pressure gradient, and S w The value represents water saturation. a and b are both dynamic start-up pressure gradient fitting coefficients; in this embodiment, a = 1 × 10⁻⁶. -10 k 1.320 b = 3.995k 0.038 , where k is the permeability of the core sample.

[0064] Therefore, the empirical formula for the dynamic start-up pressure gradient established in this embodiment is:

[0065]

[0066] In the formula, λ is the dynamic start-up pressure gradient, and S w denoted as water saturation, and k as the permeability of the core sample.

[0067] Experiments were conducted using the steady-state method to measure the relative gas-water permeability of each core sample under different water saturation conditions, such as... Figure 2 As shown in Table 2, the gas-water ratio of each core sample under different water saturation conditions is calculated using formula (2) in conjunction with the basic parameters of the tight gas reservoir.

[0068] Table 2 Basic parameters of tight gas reservoirs

[0069]

[0070]

[0071] Step 3, based on the structure of the fractured horizontal well in the tight gas reservoir, a fractured horizontal well productivity model considering gas-water two-phase in the tight gas reservoir is established based on the mathematical model considering one-way shale gas reservoir fracturing horizontal well, the fractured horizontal well productivity model considering gas-water two-phase in the tight gas reservoir is provided with a matrix, a fracture and a fractured horizontal well, the fractured horizontal well is arranged at the center position of the fractured horizontal well productivity model considering gas-water two-phase in the tight gas reservoir, and the arrangement parameters of the fractured horizontal well include a horizontal section length L, a wellbore radius r w , the horizontal section of the fractured horizontal well is provided with N fractures, each fracture is equidistantly distributed on the horizontal section and penetrates the whole gas layer, and the arrangement parameters of the fracture include a half-fracture length x f , a width w f and a fracture permeability K f , the fluid flows from the matrix to the fracture in the fractured horizontal well productivity model considering gas-water two-phase in the tight gas reservoir, and flows into the wellbore of the fractured horizontal well along the fracture, at this time, the production of the fractured horizontal well is equal to the sum of the production of each fracture in the gas layer, the gas-water two-phase exists in the matrix, the water phase starting pressure needs to be considered, and the non-Darcy fluid exists in the fracture, the gas-water two-phase flow needs to be considered.

[0072] In the fractured horizontal well productivity model considering gas-water two-phase in the tight gas reservoir, a plane perpendicular to the fractured horizontal well is selected, the fracture extension direction is set as an x-axis, the fractured horizontal well extension direction is set as a y-axis, and a two-dimensional coordinate system is established, as shown in Figure 3 .

[0073] When only considering gas phase flow, the formation pressure distribution around the fracture is:

[0074]

[0075] In the formula, p is the formation pressure, the unit is Pa; μ g is the gas phase viscosity, the unit is Pa·s; ρ gsc is the gas phase density under standard conditions, the unit is kg / m 3 ; q gsc is the gas phase production under standard conditions, the unit is kg / m 3 ; K rg is the gas phase relative permeability; K m is the formation permeability, the unit is m 2 ; h is the formation thickness, the unit is m; ρ g is the gas phase density, the unit is kg / m 3 .

[0076] When only considering water phase flow, the formation pressure distribution around the fracture is:

[0077]

[0078] In the formula, μ wviscosity of water phase, unit Pa·s; p wsc viscosity of water phase, unit Pa·s; p 3 viscosity of water phase, unit Pa·s; p wsc viscosity of water phase, unit Pa·s; p 3 viscosity of water phase, unit Pa·s; p rw viscosity of water phase, unit Pa·s; p w viscosity of water phase, unit Pa·s; p 3 .

[0079] wherein, the conformal transformation is carried out on the fractured horizontal well, and the transformation parameter u is:

[0080]

[0081] wherein, X f is the fracture radius, unit m; x is the horizontal coordinate of the location in the tight gas reservoir, y is the vertical coordinate of the location in the tight gas reservoir, and y0 is the vertical coordinate of the location of the fracture.

[0082] The formation pressure around the fracture when only considering the gas phase flow is superposed with the formation pressure around the fracture when only considering the water phase flow to obtain the pseudo pressure of the formation around the fracture :

[0083]

[0084] wherein, p0 is the initial pressure of the formation.

[0085] Based on the interference between the fractures and the starting pressure gradient, the pseudo pressure distribution around any fracture is:

[0086]

[0087] wherein, is the pseudo pressure of the matrix boundary, is the pseudo pressure of the outer boundary of the jth fracture; r e is the control radius; i is the fracture serial number in the gas layer; R wg is the gas-water ratio; λ w is the water phase pressure starting gradient, j is the serial number of the fracture being calculated, q gscfi is the gas phase production of the ith fracture under standard condition, unit kg / m 3 ; d is the fracture spacing, and N0 is the intermediate calculation parameter when the number of fractures is considered, when the total number of fractures N is odd, d=L / N, and N0=(N-1) / 2, when the total number of fractures N is even, d=L / 2N, and N0=N-1.

[0088] The flow of fluid in the fracture is simplified into two parts, one part is the radial flow near the wellbore, and the other part is the linear flow far from the wellbore, the radial flow near the wellbore is the plane radial flow, and the flow equation of the fluid in the fracture is established based on the non-Darcy effect, as shown in formula (7):

[0089]

[0090] In the formula, w f is the thickness of the plane radial flow, the flow radius of the plane radial flow is x f is the half fracture length, K fi is the permeability of the i-th fracture in the gas layer; β is the turbulence coefficient, with the unit of m -1 ; r is the integral radius.

[0091] According to formula (6) and formula (7), the compact gas reservoir fracturing horizontal well productivity model considering gas-water two-phase is obtained, and the compact gas reservoir fracturing horizontal well productivity model considering gas-water two-phase contains N N-phase equation groups, as shown in formula (8):

[0092]

[0093] Among them,

[0094]

[0095]

[0096] In the formula, A and B are both calculation coefficients of the gas phase production of the i-th fracture at standard conditions.

[0097] Step 4, using the compact gas reservoir fracturing horizontal well productivity model considering gas-water two-phase, by substituting the gas-water ratio and starting pressure gradient of each core sample under different water saturation conditions into the compact gas reservoir fracturing horizontal well productivity model considering gas-water two-phase, the compact gas reservoir fracturing horizontal well productivity model considering gas-water two-phase is solved by using matlab, and the IPR curve of each core sample is obtained, as shown in formula (9). Figure 4

[0098] Comparing the IPR curves of the three core samples, it is found that the IPR curves of the three core samples are quite different, Figure 4 The IPR curves of the three core samples from left to right correspond to the core sample permeability in turn, from Figure 4 ​It can be obtained that the greater the permeability of the core sample is, the higher the productivity is, and the smaller the permeability of the core sample is, the smaller the productivity is, under the premise of considering the dynamic threshold pressure gradient, when the initial water saturation of the core sample is the same, the smaller the permeability of the core sample is, the more obvious the influence of the threshold pressure gradient on the productivity is, and the greater the pressure difference required by the two-phase flow is, and it is found through comparison that the influence of the threshold pressure gradient on the core sample with the permeability of 0.264 mD is the greatest, but the influence of the dynamic threshold pressure gradient on the minimum threshold pressure difference is not obvious for the core samples with the permeability of 2.412 mD and 20.828 mD.

[0099] Therefore, in the actual production process, the threshold pressure gradient of the tight gas reservoir is utilized, and the reasonable control of the water saturation is helpful for the reasonable exploitation of the gas reservoir.

[0100] Of course, the above description is only for the preferred embodiments of the present application, and the present application is not limited to the above-described embodiments, and it should be noted that any person skilled in the art can make all equivalent substitutions and obvious modifications under the teaching of the present application, and all the substitutions and modifications fall within the scope of the present application, and should be protected by the present application.

Claims

1. A method for calculating the productivity of tight gas reservoirs considering dynamic changes in water saturation, characterized in that, Includes the following steps: Step 1: Select the area where the tight gas reservoir is located as the study area, select multiple core samples in the study area, measure the sample parameters of each core sample, prepare synthetic formation water as the injection fluid according to the geological data of the study area, and set the temperature of the core samples. Step 2: Combine the steady-state method and the seepage method to measure the starting pressure gradient and relative gas-water permeability of each core sample under different water saturation conditions, obtain the dynamic starting pressure gradient curve of each core sample, establish the empirical formula for the dynamic starting pressure gradient, and calculate the gas-water ratio of each core sample under different water saturation conditions based on the relative gas-water permeability of each core sample under different water saturation conditions and the basic parameters of the tight gas reservoir where each core sample is located. Step 3: Based on the structure of the fractured horizontal well in the tight gas reservoir, and combined with the mathematical model of the fractured horizontal well in the unidirectional shale gas reservoir, establish a production capacity model of the fractured horizontal well in the tight gas reservoir considering the gas and water two phases. In step 3, in the tight gas reservoir fractured horizontal well productivity model considering both gas and water phases, a plane perpendicular to the fractured horizontal well is selected, and the fracture extension direction is set as the x-axis and the fractured horizontal well extension direction as the y-axis to establish a two-dimensional coordinate system. This yields the formation pressure distribution around the fracture when only gas phase flow is considered and the formation pressure distribution around the fracture when only water phase flow is considered. The formation pressure around the fracture when only gas phase flow is considered and the formation pressure around the fracture when only water phase flow is considered are superimposed to obtain the pseudo-pressure of the formation around the fracture. Based on the interference between each fracture and the starting pressure gradient, the pseudo-pressure distribution around any fracture is obtained. The flow of fluid in the fracture is simplified into two parts: one part is radial flow near the wellbore and the other part is linear flow away from the wellbore. The radial flow near the wellbore is planar radial flow. Based on the non-Darcy effect, the flow equation of fluid in the fracture is established. Based on the pseudo-pressure distribution around any fracture and the flow equation of fluid in the fracture, the production capacity model of a fractured horizontal well in a tight gas reservoir considering gas and water phases is obtained. Step 4: Using the production capacity model of a fractured horizontal well in a tight gas reservoir considering gas and water two phases, the gas-water ratio and starting pressure gradient of each core sample under different water saturation conditions are substituted into the production capacity model of a fractured horizontal well in a tight gas reservoir considering gas and water two phases to obtain the production capacity of the tight gas reservoir under different water saturation conditions and obtain the inflow dynamic curves under different water saturation conditions.

2. The method for calculating the productivity of tight gas reservoirs considering dynamic changes in water saturation according to claim 1, characterized in that, In step 1, the sample parameters include the diameter, length, porosity, and permeability of the rock sample.

3. The method for calculating the productivity of tight gas reservoirs considering dynamic changes in water saturation according to claim 1, characterized in that, The synthetic formation water had a salinity of 46353 mg / L and a pH of 6.

1. The components of the synthetic formation water included potassium (K). + Na + Ca 2+ Mg 2+ Cl - , and HCO 3- , where K + and Na + The total concentration was 12046 mg / L, Ca 2+ The concentration was 5205 mg / L, Mg 2+ The concentration was 391 mg / L, Cl - The concentration was 26139 mg / L, HCO3- 3- The concentration was 1331 mg / L.

4. The method for calculating the productivity of tight gas reservoirs considering dynamic changes in water saturation according to claim 1, characterized in that, In step 2, the empirical formula for the dynamic start-up pressure gradient is: In the formula, λ is the dynamic start-up pressure gradient, and S w The value represents water saturation, and a and b are the fitting coefficients for the dynamic starting pressure gradient. The formula for calculating the air-to-water ratio is: In the formula, R wg For air-to-water ratio; K rw K represents the relative permeability of the aqueous phase. rg The relative permeability of the gas phase; μ g The viscosity is the gas phase viscosity, expressed in Pa·s; μ w B is the viscosity of the aqueous phase, expressed in Pa·s. g B is the volume coefficient of the gas phase; w is the volume coefficient of the aqueous phase.

5. The method for calculating the productivity of tight gas reservoirs considering dynamic changes in water saturation according to claim 1, characterized in that, The basic parameters of the tight gas reservoir include formation thickness, original bottom pressure, control radius, fracture half-fracture length, fracture width, fracture permeability, length of the horizontal section of the fractured horizontal well, and formation temperature.

6. The method for calculating the productivity of tight gas reservoirs considering dynamic changes in water saturation according to claim 1, characterized in that, In step 3, the production capacity model of the fractured horizontal well in the tight gas reservoir considering gas and water two-phase is equipped with a matrix, fractures, and a fractured horizontal well. The fractured horizontal well is located at the center of the production capacity model of the fractured horizontal well in the tight gas reservoir considering gas and water two-phase. The setting parameters of the fractured horizontal well include the horizontal section length L and the wellbore radius r. w The horizontal section of a fractured horizontal well contains N fractures, which are equidistantly distributed throughout the gas reservoir. The fracture configuration parameters include the half-fracture length x f Width w f and crack permeability K f ; In the production capacity model of a fractured horizontal well in a tight gas reservoir considering gas and water two phases, the fluid flows from the matrix to the fractures and flows into the wellbore of the fractured horizontal well along the fractures. At this time, the production capacity of the fractured horizontal well is equal to the sum of the production capacity of each fracture in the gas layer. There are gas and water two phases in the matrix and non-Darcy fluids in the fractures.

7. The method for calculating the productivity of tight gas reservoirs considering dynamic changes in water saturation according to claim 6, characterized in that, In the production capacity model of a fractured horizontal well in a tight gas reservoir considering both gas and water phases, a plane perpendicular to the fractured horizontal well is selected, and the fracture extension direction is set as the x-axis and the fractured horizontal well extension direction is set as the y-axis. A two-dimensional coordinate system is established, and the formation pressure distribution around the fracture is obtained when only gas phase flow is considered: In the formula, p is the formation pressure, in Pa; μ g ρ is the gas phase viscosity, in Pa·s. gsc The density of the gas phase under standard conditions is expressed in kg / m³. 3 ;q gsc This refers to the gas phase yield under standard conditions, expressed in kg / m³. 3 ;K rg K represents the relative permeability of the gas phase. m Formation permeability, in meters (m). 2 h represents the formation thickness in meters (m); ρ g This refers to the gas phase density, expressed in kg / m³. 3 ; The formation pressure distribution around the fracture, considering only water flow, is as follows: In the formula, μ w The viscosity of the aqueous phase is expressed in Pa·s; ρ wsc The density of the aqueous phase under standard conditions is expressed in kg / m³. 3 ;q wsc The aqueous phase yield is given under standard conditions, in kg / m³. 3 ;K rw ρ is the relative permeability of the aqueous phase. w This is the density of the aqueous phase, in kg / m³. 3 ; For fracturing horizontal wells, conformal mapping is performed, and the mapping parameter u is: In the formula, X f y is the radius of the fracture, in meters; x is the abscissa of the location of the tight gas reservoir, y is the ordinate of the location of the tight gas reservoir, and y0 is the ordinate of the location of the fracture. The pseudo-pressure of the formation around the fracture is obtained by superimposing the formation pressure considering only gas phase flow and the formation pressure considering only water phase flow. for: In the formula, p0 is the initial pressure of the formation; Based on the interference between each crack and the initiation pressure gradient, the pseudo-pressure distribution around any crack is obtained as follows: In the formula, For matrix boundary pseudo-pressure, Let r be the simulated pressure at the outer boundary of the j-th crack; e The control radius is represented by i; the fracture number within the gas layer is represented by R. wg The air-to-water ratio; λ w The gradient is set to the water phase pressure initiation gradient, j is the number of the currently calculated fracture, and q gscfi The gas phase production of the i-th fracture under standard conditions is expressed in kg / m³. 3 ; d is the crack spacing, N0 is the intermediate calculation parameter when considering the number of cracks. When the total number of cracks N is odd, d = L / N, N0 = (N-1) / 2. When the total number of cracks N is even, d = L / 2N, N0 = N-1. The flow of fluid in the fracture is simplified into two parts: radial flow near the wellbore and linear flow away from the wellbore. The radial flow near the wellbore is planar radial flow. Based on the non-Darcy effect, the flow equation of the fluid in the fracture is established as shown in equation (7): In the formula, w f Let be the thickness of the planar radial flow, and let be the flow radius of the planar radial flow. x f For half the seam length, K fi Let be the permeability of the i-th fracture within the gas layer; β is the turbulence coefficient, in m³. -1 r is the radius of integration; Based on formulas (6) and (7), the production capacity model of a fractured horizontal well in a tight gas reservoir considering both gas and water phases is obtained, as shown in formula (8): in, In the formula, A and B are both calculation coefficients for the gas phase production of the i-th fracture under standard conditions.

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