Shale condensate gas reservoir yield prediction method and machine readable storage medium

Abstract

The invention discloses a shale condensate gas reservoir yield prediction method and a machine readable storage medium. The method comprises the steps that gas reservoir parameters, horizontal well parameters and a bottom hole flowing pressure mapping table of a shale condensate gas reservoir are obtained; a condensate oil saturation mapping table is obtained, and a condensate oil saturation fitting model is determined according to the gas reservoir parameters and the condensate oil saturation mapping table; determining condensate gas fluid physical property parameters according to the gas reservoir parameters and the pressure variables; determining oil-gas phase relative permeability parameters according to the gas condensate saturation fitting model and the oil-gas phase relative permeability model; determining the original geological reserves of the gas reservoir according to the gas reservoir parameters and the horizontal well parameters; and determining the ground daily gas production rate and the ground daily oil production rate corresponding to each day in the preset production time according to the gas reservoir yield iteration model. According to the shale condensate gas reservoir yield prediction method, the condensate oil precipitation influence and the shale gas reservoir fractured horizontal well multi-linear flow coupling mechanism are comprehensively considered, and the prediction accuracy is high.

Description

Technical Field

[0001] The present invention belongs to the technical field of gas reservoir development, and particularly relates to a method for predicting the production of a shale condensate gas reservoir and a machine-readable storage medium. Background Art

[0002] During the development of a shale condensate gas reservoir, it has the dual characteristics of a shale gas reservoir and a condensate gas reservoir. The shale gas reservoir usually needs to be transformed by multi-stage fracturing of horizontal wells to have exploitation value, and it has the dual-linear flow characteristics of linear flow within the transformed area and linear flow outside the transformed area; as the pressure of the condensate gas reservoir drops, retrograde condensation occurs, and both condensate gas and condensate oil phases will appear in the formation.

[0003] At present, the methods for predicting the gas production of a shale condensate gas reservoir include numerical simulation method and analytical model method. Among them, the numerical simulation method requires the establishment of an accurate geological model and a large number of parameters. The reliability of the geological model and the accuracy of the selection of reservoir and fluid physical property parameters directly affect its prediction accuracy, and it takes a long time, consuming a lot of time and effort, and cannot be used in time for the rapid prediction of the production of new wells; the analytical model method has the advantage of quickly predicting the production, but the rationality and reliability of the model are the key points to be concerned about. If the established model fails to characterize its gas production mechanism, the prediction result will deviate far from the actual situation, that is, the prediction accuracy of the production of the shale condensate gas reservoir is low and the prediction precision is poor. Summary of the Invention

[0004] In view of the above defects or deficiencies, the present invention provides a method for predicting the production of a shale condensate gas reservoir and a machine-readable storage medium, aiming to solve the technical problems of low prediction accuracy and poor prediction precision of the production of the shale condensate gas reservoir.

[0005] To achieve the above object, the present invention provides a method for predicting the production of a shale condensate gas reservoir, and the method for predicting the production of a shale condensate gas reservoir includes:

[0006] Obtain the gas reservoir parameters, horizontal well parameters and bottom-hole flowing pressure mapping table of the shale condensate gas reservoir, wherein the bottom-hole flowing pressure mapping table is used to characterize the mapping relationship between the bottom-hole flowing pressure and the preset production time;

[0007] Obtain the condensate oil saturation mapping table, and determine the condensate oil saturation fitting model according to the gas reservoir parameters and the condensate oil saturation mapping table, wherein the condensate oil saturation mapping table is used to characterize the mapping relationship between the condensate oil saturation and the pressure variable;

[0008] Determine the condensate gas fluid physical property parameters according to the gas reservoir parameters and the pressure variable;

[0009] Determine the relative permeability parameters of the oil and gas phases according to the condensate oil saturation fitting model and the relative permeability model of the oil and gas phases;

[0010] Determine the original geological reserves of the gas reservoir according to the gas reservoir parameters and horizontal well parameters;

[0011] Determine the daily gas production and daily oil production on the ground corresponding to each day in the preset production time according to the bottom-hole flowing pressure mapping table, condensate gas fluid physical property parameters, oil-gas phase relative permeability parameters, original geological reserves of the gas reservoir and the gas reservoir production iteration model; wherein, the gas reservoir production iteration model is used to determine the production gas-oil ratio inside and outside the fracturing reform area, the conversion coefficient of natural gas bottom-hole production and wellhead production, the pressure propagation distance parameter, the pseudo-pressure difference parameter, the average formation pressure parameter of the pressure sweep range, the propagation duration of the pressure in the fracturing reform area to the midpoint of the fracturing crack, the cumulative gas supply and cumulative oil supply from outside the fracturing reform area to inside the fracturing reform area during the preset production time, and the daily gas supply and daily oil supply corresponding to each day.

[0012] In the embodiment of the present invention, the gas reservoir parameters include the original formation pressure, the dew point pressure of the condensate gas, the critical flow pressure of the condensate oil, the reservoir porosity, the pore compressibility, the water compressibility, the original water saturation, the production gas-oil ratio when the average formation pressure is higher than the dew point pressure, the underground condensate oil density, the underground condensate oil viscosity and the surface condensate oil density;

[0013] The horizontal well parameters include the horizontal well length, the half-length of the fracture, the fracture height, the number of fracturing fracture segments, the original permeability of the fracturing reform area and the permeability stress sensitivity coefficient in the fracturing reform area;

[0014] The condensate gas fluid physical property parameters include the condensate gas viscosity, the underground condensate gas density and the surface natural gas density;

[0015] The oil-gas phase relative permeability parameters include the relative permeability of the oil phase and the relative permeability of the gas phase;

[0016] Determining the daily gas production and daily oil production on the ground corresponding to each day in the preset production time according to the bottom-hole flowing pressure mapping table, condensate gas fluid physical property parameters, oil-gas phase relative permeability parameters, original geological reserves of the gas reservoir and the gas reservoir production iteration model includes:

[0017] Determine the production gas-oil ratio in the fracturing reform area and the production gas-oil ratio outside the pressure reform area respectively according to the production gas-oil ratio when the average formation pressure is higher than the dew point pressure, the average formation pressure and the production gas-oil ratio formula;

[0018] Determine the conversion coefficient of natural gas bottom-hole production and wellhead production according to the surface condensate oil density, the surface natural gas density, the production gas-oil ratio in the fracturing reform area, the production gas-oil ratio outside the pressure reform area and the production conversion coefficient formula;

[0019] Determine the pressure propagation distance in the fracturing and reconstruction area according to the preset production time, reservoir porosity, average permeability in the fracturing and reconstruction area, original permeability in the fracturing and reconstruction area, permeability stress sensitivity coefficient in the fracturing and reconstruction area, average formation pressure in the fracturing and reconstruction area, average comprehensive compressibility coefficient in the fracturing and reconstruction area, pore compressibility coefficient, water compressibility coefficient, gas compressibility coefficient corresponding to the average formation pressure in the fracturing and reconstruction area, original water saturation, condensate oil saturation fitting model, bottom-hole flowing pressure mapping table, horizontal well length, number of fracturing fracture segments, gas-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing and reconstruction area, oil-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing and reconstruction area, condensate gas viscosity at the average formation pressure in the fracturing and reconstruction area, underground condensate oil viscosity, and the first pressure propagation distance formula;

[0020] Determine the pseudo-pressure difference in the fracturing and reconstruction area according to the gas-phase original permeability at the original water saturation, original formation pressure, average formation pressure in the fracturing and reconstruction area, upper dew point pressure of condensate gas, critical flow pressure of condensate oil, bottom-hole flowing pressure mapping table, underground condensate oil density, underground condensate oil viscosity, oil-phase relative permeability, gas-phase relative permeability, underground condensate gas density, underground natural gas viscosity, and the first pseudo-pressure difference formula;

[0021] Determine the daily surface gas production and daily surface oil production corresponding to each day in the preset production time according to the number of fracturing fracture segments, initial permeability in the fracturing and reconstruction area, half-length of the fracture, height of the fracture, pressure propagation distance in the fracturing and reconstruction area, conversion coefficient of bottom-hole production and wellhead production in the fracturing and reconstruction area, pseudo-pressure difference in the fracturing and reconstruction area, production gas-oil ratio in the fracturing and reconstruction area, surface daily gas production formula, and surface daily oil production formula;

[0022] In the embodiment of the present invention, the surface daily gas production formula is set as:

[0023]

[0024] In the formula, q g,sc is the surface daily gas production, n f is the number of fracturing fracture segments, k srvi is the original permeability in the fracturing and reconstruction area, L f is the half-length of the fracture, h f is the height of the fracture, x is the pressure propagation distance in the fracturing and reconstruction area, E srv is the conversion coefficient of bottom-hole production and wellhead production in the fracturing and reconstruction area, (ψ srv -ψ wf ) is the pseudo-pressure difference in the fracturing and reconstruction area;

[0025] The surface daily oil production formula is set as:

[0026]

[0027] where q o,sc is the daily oil production on the ground, and R go,srv is the produced gas-oil ratio in the fracturing reform area.

[0028] In the embodiment of the present invention, the formula for the produced gas-oil ratio is set as:

[0029]

[0030] where R go is the produced gas-oil ratio, R god is the produced gas-oil ratio when the average formation pressure is higher than the dew point pressure, p ave is the average formation pressure, p d is the dew point pressure of the condensate gas, a R2 , a R1 , a R0 are respectively the polynomial fitting coefficients of ln(R go ) and ln(p ave ) in the rectangular coordinate;

[0031] And the formula for the production conversion coefficient is set as:

[0032]

[0033] where E is the conversion coefficient of the bottom-hole production and the wellhead production, ρ o,sc is the density of the surface condensate oil, and ρ g,sc is the density of the surface natural gas.

[0034] In the embodiment of the present invention, the formula for the first pressure propagation distance is set as:

[0035]

[0036] where

[0037] C t,srv = C p + S wi C w + S o,srv C o + (1 - S wi - S o,srv )C g,srv ,

[0038] where x is the pressure propagation distance in the fracturing reform area, t is the preset production time, φ is the reservoir porosity, k srv is the average permeability of the fracturing reform area, k srvi is the original permeability of the fracturing reform area, C ksrv is the permeability stress sensitivity coefficient in the fracturing reform area, p srvis the average formation pressure in the fracturing and reconstruction area, C t,srv is the average comprehensive compressibility in the fracturing and reconstruction area, C p is the pore compressibility, C w is the water compressibility, C o is the oil compressibility, C g,srv is the gas compressibility corresponding to the average formation pressure in the fracturing and reconstruction area, S wi is the original water saturation, S o,srv is the condensate oil saturation corresponding to the average formation pressure in the fracturing and reconstruction area, p i is the original formation pressure, p wf is the bottom-hole flowing pressure, L H is the horizontal well length, n f is the number of fracturing fracture segments, k rg,srv is the gas-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing and reconstruction area, k ro,srv is the oil-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing and reconstruction area, μ rg,srv is the condensate gas viscosity corresponding to the average formation pressure in the fracturing and reconstruction area, μ o is the underground condensate oil viscosity.

[0039] In the embodiment of the present invention, the first pseudo-pressure difference formula is set as:

[0040]

[0041] , where ψ srv -ψ wf is the condensate gas pseudo-pressure difference in the fracturing and reconstruction area, k rg (S wi ) is the original gas-phase permeability under the irreducible water, p * is the critical flow pressure of the condensate oil, ρ o is the underground condensate oil density, k ro is the oil-phase permeability, ρ g is the density of the underground condensate gas, μ g is the underground natural gas viscosity, k rg is the gas-phase permeability, k rg (S wi ) is the original gas-phase permeability under the irreducible water.

[0042] In the embodiment of the present invention, the gas reservoir parameters further include the reservoir temperature, the original permeability of the reservoir outside the fracturing and reconstruction area in the direction of the fracturing fracture extension, and the reservoir thickness;

[0043] The horizontal well parameters further include the horizontal well spacing and the permeability stress sensitivity coefficient outside the fracturing and reconstruction area;

[0044] The physical property parameters of the condensate gas fluid further include the condensate gas deviation factor;

[0045] Determining the daily surface gas production and daily surface oil production corresponding to each day in the preset production time according to the bottom-hole flowing pressure mapping table, the physical property parameters of the condensate gas fluid, the relative permeability parameters of the oil and gas phases, the original geological reserves of the gas reservoir, and the gas reservoir production iteration model further includes:

[0046] Determining the propagation duration of the pressure in the fracturing reform area to the midpoint of the fracturing fracture according to the preset production time, the pressure propagation distance in the fracturing reform area, the horizontal well length, and the number of fracturing fracture segments;

[0047] Determining the pressure propagation distance outside the fracturing reform area according to the preset production time, the reservoir porosity, the average permeability of the reservoir outside the fracturing reform area in the extension direction of the fracturing fracture, the original permeability of the reservoir outside the fracturing reform area in the extension direction of the fracturing fracture, the permeability stress sensitivity coefficient outside the fracturing reform area, the horizontal well spacing, the fracture half-length, the average formation pressure outside the fracturing reform area, the average comprehensive compressibility coefficient outside the fracturing reform area, the pore compressibility coefficient, the water compressibility coefficient, the gas compressibility coefficient corresponding to the average formation pressure outside the fracturing reform area, the original water saturation, the condensate oil saturation fitting model, the gas-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure outside the fracturing reform area, the oil-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure outside the fracturing reform area, the condensate gas viscosity corresponding to the average formation pressure outside the fracturing reform area, the underground condensate oil viscosity, and the second pressure propagation distance formula;

[0048] Determining the pseudo-pressure difference outside the fracturing reform area according to the original gas-phase permeability at the original water saturation, the original formation pressure, the average formation pressure outside the fracturing reform area, the average formation pressure inside the fracturing reform area, the upper dew point pressure of the condensate gas, the critical flow pressure of the condensate oil, the underground condensate oil density, the underground condensate oil viscosity, the oil-phase relative permeability, the gas-phase relative permeability, the underground condensate gas density, and the underground natural gas viscosity;

[0049] Determining the daily gas supply and daily oil supply from the outside of the fracturing reform area to the inside of the fracturing reform area corresponding to each day in the preset production time according to the original permeability of the reservoir outside the fracturing reform area in the extension direction of the fracturing fracture, the horizontal well length, the fracture height, the pressure propagation distance outside the fracturing reform area, the conversion coefficient of the bottom-hole production and wellhead production outside the fracturing reform area, the pseudo-pressure difference outside the fracturing reform area, the propagation duration of the pressure in the fracturing reform area to the midpoint of the fracturing fracture, the daily gas supply formula, and the daily oil supply formula;

[0050] Determine the average formation pressure in the fracture-affected area outside the fracture stimulation area according to the horizontal well length, reservoir thickness, pressure propagation distance outside the fracture stimulation area, reservoir porosity, original water saturation, original formation pressure, condensate gas deviation factor corresponding to the original formation pressure, reservoir temperature, standard condition pressure, standard condition temperature, standard condition natural gas deviation factor, water compressibility, average formation pressure in the pressure-affected area outside the fracture stimulation area, underground condensate oil density, condensate oil saturation fitting model, condensate gas deviation factor corresponding to the average formation pressure, cumulative supply condensate gas volume from outside the fracture stimulation area to inside the fracture stimulation area, and the material balance equation outside the fracture stimulation area.

[0051] In the embodiment of the present invention, the material balance equation outside the fracture stimulation area is set as:

[0052]

[0053] In the formula, G w,out,v is the original geological reserve of condensate gas in the pressure-affected area outside the fracture stimulation area, h is the reservoir thickness, y is the pressure propagation distance outside the fracture stimulation area, Z i is the condensate gas deviation factor corresponding to the original formation pressure, T is the reservoir temperature, p sc is the standard condition pressure, T sc is the standard condition temperature, Z sc is the standard condition natural gas deviation factor, p out is the average formation pressure in the pressure-affected area outside the fracture stimulation area, ρ o is the underground condensate oil density, S o is the condensate oil saturation, Z w is the condensate gas deviation factor corresponding to the average formation pressure, R is the universal gas constant, G w,out→srv is the cumulative supply condensate gas volume from outside the fracture stimulation area to inside the fracture stimulation area.

[0054] In the embodiment of the present invention, the condensate oil saturation fitting model is set as:

[0055]

[0056] Determine the relative permeability parameters of the oil and gas phases according to the condensate oil saturation fitting model and the oil-gas phase relative permeability model, including:

[0057] Determine the relative permeability of the oil phase according to the condensate oil saturation fitting model and the oil-phase relative permeability model, and determine the relative permeability of the gas phase according to the condensate oil saturation fitting model and the gas-phase relative permeability model. Among them, the oil-phase relative permeability model is set as:

[0058]

[0059] The gas-phase relative permeability model is set as:

[0060]

[0061] In the formula, S o is the condensate oil saturation, p is the pressure variable, p d is the upper dew point pressure of the condensate gas, a s4 , a s3 , a s2 , a s1 , a s0 are the fitting coefficients of the polynomial relationship between the condensate oil saturation and the pressure variable respectively, k ro is the relative permeability of the oil phase, k ro ∞ is the maximum relative permeability of the oil phase, S oc is the critical flow saturation of the condensate oil, n o is the relative permeability exponent of the oil phase, k rg is the relative permeability of the gas phase, k rg ∞ is the maximum relative permeability of the gas phase, S wi is the initial water saturation, n g is the relative permeability exponent of the gas phase.

[0062] In the embodiment of the present invention, the gas reservoir parameters further include the relative density of the condensate gas. The condensate gas fluid property parameters determined according to the gas reservoir parameters and the pressure variable include:

[0063] Determine the condensate gas deviation factor according to the pressure variable and the condensate gas deviation factor formula. Among them, the condensate gas deviation factor formula is set as:

[0064] Z = a z4 p 4 + a z3 p 3 + a z2 p 2 + a z1 p + a z0 ;

[0065] Determine the isothermal compressibility of the condensate gas according to the pressure variable, the condensate gas deviation factor and the isothermal compressibility formula of the condensate gas. Among them, the isothermal compressibility formula of the condensate gas is set as:

[0066]

[0067] Determine the viscosity of the condensate gas according to the pressure variable and the condensate gas viscosity formula. Among them, the condensate gas viscosity formula is set as:

[0068] μ g = a μ3 p 3 + a μ2 p 2 + aμ1 p + a μ0 ;

[0069] Determine the underground condensate gas density according to the pressure variable, condensate gas deviation factor and condensate gas density formula, where the condensate gas density formula is set as:

[0070]

[0071] In the formula, Z is the condensate gas deviation factor, a z4 、a z3 、a z2 、a z1 、a z0 are respectively the fitting coefficients of the polynomial relationship between the condensate gas deviation factor and the pressure variable, C g is the isothermal compressibility coefficient of the condensate gas, μ g is the viscosity of the condensate gas, a μ3 、a μ2 、a μ1 、a μ0 are respectively the fitting coefficients of the polynomial relationship between the condensate gas viscosity and the pressure variable, ρ g is the underground condensate gas density, γ g is the relative density of the condensate gas, and T is the reservoir temperature.

[0072] In the embodiment of the present invention, the gas reservoir parameters further include the molecular weight of condensate oil. Determining the original geological reserves of the gas reservoir according to the gas reservoir parameters and the horizontal well parameters includes:

[0073] Determine the original geological reserves of the condensate gas in the fracturing reform area and the original geological reserves of the condensate gas outside the fracturing reform area respectively according to the condensate gas deviation factor formula, the first condensate gas original geological reserves formula, and the second condensate gas original geological reserves formula. Among them, the first condensate gas original geological reserves formula is set as:

[0074]

[0075] The second condensate gas original geological reserves formula is set as:

[0076]

[0077] Determine the original geological reserves of the natural gas within the well control range of the gas reservoir according to the original geological reserves of the condensate gas in the fracturing reform area, the original geological reserves of the condensate gas outside the fracturing reform area, and the natural gas original geological reserves formula. Among them, the natural gas original geological reserves formula is set as:

[0078]

[0079] Determine the original geological reserves of condensate oil within the well control range of the gas reservoir according to the formulas for the original geological reserves of natural gas and condensate oil within the well control range of the gas reservoir. Among them, the formula for the original geological reserves of condensate oil is set as:

[0080]

[0081] In the formula, G w,srv is the original geological reserves of condensate gas in the fracturing reform area, G w,out is the original geological reserves of condensate gas outside the fracturing reform area, G w is the sum of the original geological reserves of condensate gas in the fracturing reform area and the original geological reserves of condensate gas outside the fracturing reform area, G g is the original geological reserves of natural gas within the well control range of the gas reservoir, N c is the original geological reserves of condensate oil within the well control range of the gas reservoir, L f is the half-length of the fracture, L H is the length of the horizontal well, L is the horizontal well spacing, h is the reservoir thickness, φ is the reservoir porosity, p i is the original formation pressure, p sc is the standard condition pressure, T sc is the standard condition temperature, Z sc is the deviation coefficient of natural gas under standard conditions, Z i is the deviation coefficient of condensate gas corresponding to the original formation pressure, R god is the production gas-oil ratio when the average formation pressure is higher than the dew point pressure, V sckm is the ground volume corresponding to 1 kmol of natural gas, ρ o，sc is the density of surface condensate oil, M o is the molecular weight of condensate oil.

[0082] To achieve the above object, the present invention also provides a machine-readable storage medium, on which instructions are stored for causing a machine to execute the shale condensate gas reservoir production prediction method described above.

[0083] Through the above technical solutions, the shale condensate gas reservoir production prediction method and the machine-readable storage medium provided by the embodiments of the present invention have the following beneficial effects:

[0084] In the technical solution of the present invention, the shale condensate gas reservoir production prediction method is used to predict and calculate the production of fractured horizontal wells in the shale condensate gas reservoir. The shale condensate gas reservoir production prediction method comprehensively considers the influence of condensate oil precipitation and the multi-linear flow coupling mechanism of fractured horizontal wells in the shale gas reservoir to quickly and accurately predict the production of fractured horizontal wells in the shale condensate gas reservoir, with high prediction accuracy and greatly improving the production prediction precision.

[0085] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. BRIEF DESCRIPTION OF THE DRAWINGS

[0086] The drawings are used to provide a further understanding of the embodiments of the present invention, and constitute a part of the specification. Together with the following detailed description, they are used to explain the embodiments of the present invention, but do not constitute a limitation to the embodiments of the present invention. For those of ordinary skill in the art, without creative efforts, other drawings can also be obtained based on the structures shown in these drawings. In the drawings:

[0087] Figure 1 is a schematic flow chart of a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0088] Figure 2 is a fitting curve graph showing the change of condensate oil saturation with pressure variables in a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0089] Figure 3 is a fitting curve graph showing the change of condensate gas deviation factor with pressure variables in a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0090] Figure 4 is a fitting curve graph showing the change of condensate gas isothermal compressibility with pressure variables in a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0091] Figure 5 is a fitting curve graph showing the change of condensate gas viscosity with pressure variables in a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0092] Figure 6 is a fitting curve graph showing the change of condensate gas density with pressure variables in a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0093] Figure 7 is a relative permeability curve graph of oil and gas phases in a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0094] Figure 8 is a fitting graph of the natural logarithm of the produced gas-oil ratio and the natural logarithm of the average formation pressure in a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0095] Figure 9 is a pressure dynamic curve graph of a fractured horizontal well in a shale condensate gas reservoir in a method for predicting the production of a shale condensate gas reservoir according to an embodiment of the present invention;

[0096] Figure 10It is the dynamic curve graph of the daily gas production on the ground in the shale condensate gas reservoir production prediction method according to an embodiment of the present invention;

[0097] Figure 11 It is the dynamic curve graph of the daily oil production on the ground in the shale condensate gas reservoir production prediction method according to an embodiment of the present invention. Detailed implementation manners

[0098] The following details the specific implementation manners of the present invention with reference to the accompanying drawings. It should be understood that the specific implementation manners described herein are only used to illustrate and explain the present invention, and are not used to limit the present invention.

[0099] The following describes the shale condensate gas reservoir production prediction method of the present invention with reference to the drawings.

[0100] Refer to Figure 1 , which is the flow schematic diagram of the shale condensate gas reservoir production prediction method of the present invention. The shale condensate gas reservoir production prediction method includes:

[0101] Step S10: Obtain the reservoir parameters, horizontal well parameters and bottom-hole flowing pressure mapping table of the shale condensate gas reservoir. Among them, the bottom-hole flowing pressure mapping table is used to characterize the mapping relationship between the bottom-hole flowing pressure and the preset production time;

[0102] Step S20: Obtain the condensate oil saturation mapping table, and determine the condensate oil saturation fitting model according to the reservoir parameters and the condensate oil saturation mapping table. Among them, the condensate oil saturation mapping table is used to characterize the mapping relationship between the condensate oil saturation and the pressure variable;

[0103] Step S30: Determine the condensate gas fluid physical property parameters according to the reservoir parameters and the pressure variable;

[0104] Step S40: Determine the relative permeability parameters of the oil and gas phases according to the condensate oil saturation fitting model and the relative permeability model of the oil and gas phases;

[0105] Step S50: Determine the original geological reserves of the gas reservoir according to the reservoir parameters and the horizontal well parameters;

[0106] Step S60: Determine the daily gas production and daily oil production on the ground corresponding to each day in the preset production time according to the bottom-hole flowing pressure mapping table, the condensate gas fluid physical property parameters, the relative permeability parameters of the oil and gas phases, the original geological reserves of the gas reservoir and the gas reservoir production iteration model; among them, the gas reservoir production iteration model is used to determine the production gas-oil ratio, the conversion coefficient of the bottom-hole gas production of natural gas to the wellhead production, the pressure propagation distance parameter, the pseudo-pressure difference parameter, the average formation pressure parameter of the pressure wave propagation range, the propagation duration of the pressure in the fracture stimulation area to the midpoint of the fracture, the cumulative gas supply and cumulative oil supply from the outside of the fracture stimulation area to the inside of the fracture stimulation area during the preset production time, and the daily gas supply and daily oil supply corresponding to each day.

[0107] Specifically, in the embodiments of the present invention, a certain shale condensate gas reservoir is developed by multi - stage fracturing of multiple horizontal wells. The multiple horizontal wells are evenly distributed, and the multi - stage fracturing fractures are also evenly distributed. Production is carried out according to the set bottom - hole flowing pressure dynamic data to predict the production of a fractured horizontal well in the shale condensate gas reservoir. The reservoir parameters, horizontal well parameters, bottom - hole flowing pressure mapping table, and condensate oil saturation mapping table of the shale condensate gas reservoir are obtained, as shown in Table 1, Table 2, Table 3, and Table 4. Table 1 is the reservoir parameter table of the shale condensate gas reservoir, Table 2 is the horizontal well parameter table, Table 3 is the bottom - hole flowing pressure mapping table, and Table 4 is the condensate oil saturation mapping table.

[0108] Gas reservoir parameters Value Unit <![CDATA[Original formation pressure p i > 31.45 MPa <![CDATA[Dew point pressure p of condensate gas d > 27.54 MPa <![CDATA[Critical flow pressure p of condensate oil * > 20 MPa Reservoir temperature T 342.65 K Reservoir porosity φ 0.045 Decimal <![CDATA[Original permeability k of the reservoir outside the fracturing reform area in the direction of fracturing crack extension yi > <![CDATA[5×10 -5 > mD Reservoir thickness h 25 m <![CDATA[Pore compressibility coefficient C p > 0.001 <![CDATA[MPa -1 > <![CDATA[Compressibility coefficient C of water w > 0.00045 <![CDATA[MPa -1 > <![CDATA[Oil compressibility C o > 0.0004 <![CDATA[MPa -1 > <![CDATA[Original water saturation S wi > 0.2 Decimal <![CDATA[Relative density γ of condensate gas g > 0.723 Dimensionless <![CDATA[Production gas-oil ratio R when the average formation pressure is higher than the dew point pressure god > 1450 <![CDATA[m 3 / m 3 > <![CDATA[Underground condensate oil density ρ o (take a constant)]]> 400 <![CDATA[kg / m 3 > <![CDATA[Underground condensate oil viscosity μ o (Take a constant)]]> 1 mPa·s <![CDATA[Density ρ of surface condensate oil o，sc > 776.8 <![CDATA[kg / m 3 > <![CDATA[Condensate molecular weight M o > 135.88 kg / kmol

[0109] Table 1 Reservoir Parameter Table

[0110] Horizontal well parameters Value Unit <![CDATA[Horizontal well length L H > 1363 m Horizontal well spacing L 300 m <![CDATA[Fracture half-length L f > 100 m <![CDATA[Fracture height (less than or equal to reservoir thickness) h f > 25 m <![CDATA[Number of fracturing fracture segments n f > 20 Dimensionless <![CDATA[Original permeability k of the fracturing reform area srvi > <![CDATA[1.27×10 -4 > mD <![CDATA[Permeability stress sensitivity coefficient C in the fracturing reform area ksrv > 0.003 <![CDATA[MPa -1 > <![CDATA[Permeability stress sensitivity coefficient C outside the fracturing reform area ky > 0.001 <![CDATA[MPa -1 >

[0111] Table 2 Horizontal Well Parameter Table

[0112]

[0113]

[0114] Table 3 Bottom - Hole Flowing Pressure Mapping Table

[0115] Pressure variable p, MPa <![CDATA[Condensate oil saturation S o , decimal]]> 27.54 0 25 0.024 20 0.0526 15 0.0665 10 0.0645 5 0.0476

[0116] Table 4 Condensate Oil Saturation Mapping Table

[0117] Based on the isothermal depletion experiment data of condensate gas, the data of condensate oil saturation varying with the pressure variable are statistically analyzed and Table 4 is generated. Based on the data of condensate oil saturation varying with the pressure variable in Table 4, the polynomial fitting method is used to fit the condensate oil saturation fitting model. The condensate oil saturation fitting model is set as:

[0118]

[0119] In the formula, S o is the condensate oil saturation, p is the pressure variable, p d is the dew - point pressure of the condensate gas, a s4 , a s3 , a s2 , a s1 , a s0 are the fitting coefficients of the polynomial relationship between the condensate oil saturation and the pressure variable, and the units are Mpa -4 , Mpa -3 , Mpa -2 , Mpa -1 , dimensionless.

[0120] And, a fitting curve graph showing the change of condensate oil saturation with the pressure variable is generated based on the condensate oil saturation fitting model, and is substituted into the condensate oil saturation fitting model: Figure 2 as shown in

[0121]

[0122] wherein,

[0123] a s4 =-2.8800×10 -7 MPa -4 、a s3 =1.6759×10 -5 MPa -3 、a s2 =-6.4091×10 -4 MPa -2 、a s1 =1.0657×10 -2 MPa -1 、

[0124] a s0 =8.3786×10 -3 .

[0125] In the embodiment of the present invention, the gas reservoir parameters include the original formation pressure, the dew point pressure of the condensate gas, the critical flow pressure of the condensate oil, the reservoir porosity, the pore compressibility coefficient, the water compressibility coefficient, the original water saturation, the production gas-oil ratio when the average formation pressure is higher than the dew point pressure, the underground condensate oil density, the underground condensate oil viscosity, and the surface condensate oil density; the horizontal well parameters include the horizontal well length, the half-length of the fracture, the height of the fracture, the number of fracture segments, the original permeability in the fracture stimulation area, and the permeability stress sensitivity coefficient in the fracture stimulation area; the condensate gas fluid physical property parameters include the condensate gas deviation coefficient, the isothermal compressibility coefficient of the condensate gas, the condensate gas viscosity, the underground condensate gas density, and the surface natural gas density;

[0126] The gas reservoir parameters further include the relative density of the condensate gas. In step S30, the condensate gas fluid physical property parameters are determined according to the gas reservoir parameters and the pressure variable, including:

[0127] In step S31, the condensate gas deviation coefficient is determined according to the pressure variable and the condensate gas deviation coefficient formula, wherein the condensate gas deviation coefficient formula is set as:

[0128] Z = a z4 p 4 + a z3 p 3 + a z2 p 2 + a z1 p + a z0 ,

[0129] where Z is the condensate gas deviation coefficient, and a z4 , a z3 , a z2 , a z1 , a z0 are the fitting coefficients of the polynomial relationship between the condensate gas deviation coefficient and the pressure variable, with units of MPa -4 , MPa -3 , MPa -2 , MPa -1 , dimensionless respectively.

[0130] Specifically, according to the relative density of condensate gas γ g = 0.723 and the reservoir temperature T = 69.5 °C, by applying the Dranchuk-Abou-Kassem method, the condensate gas deviation coefficient Z at different pressure variables can be obtained. Using the polynomial fitting method, the relationship between the condensate gas deviation coefficient and pressure change is fitted, that is, the condensate gas deviation coefficient formula. And, based on the condensate gas deviation coefficient formula, a fitting curve graph showing the change of the condensate gas deviation coefficient with the pressure variable as shown in Figure 3 is generated. Substitute it into the condensate gas deviation coefficient formula:

[0131] Z = -4.0670×10 -7 p 4 + 2.2299×10 -5 p 3 + 2.3836×10 -4 p 2 - 1.8847×10 -2 p + 1.0028,

[0132] where a z4 = -4.067×10 -5 MPa -4 , a z3 = 2.2299×10 -5 MPa -3 , a z2 = 2.3836×10 -5 MPa -2 , a z1 = -1.8847×10 -2 MPa -1 , a z0 = 1.0028.

[0133] And, substitute the original formation pressure p i into the condensate gas deviation coefficient formula to calculate the value of the condensate gas deviation coefficient Z i at the original formation pressure, where p i = 31.45 MPa, Z i= 0.9416。

[0134] Step S32, determine the isothermal compressibility coefficient of condensate gas according to the pressure variable, the deviation coefficient of condensate gas, and the isothermal compressibility coefficient formula of condensate gas. Among them, the isothermal compressibility coefficient formula of condensate gas is set as:

[0135]

[0136] In the formula, C g is the isothermal compressibility coefficient of condensate gas;

[0137] Specifically, substitute the deviation coefficients of condensate gas under different pressure variables into the isothermal compressibility coefficient formula of condensate gas to calculate the isothermal compressibility coefficients of condensate gas corresponding to different pressure variables at the reservoir temperature. And, based on the isothermal compressibility coefficient formula of condensate gas, generate a fitting curve graph showing the variation of the isothermal compressibility coefficient of condensate gas with the pressure variable as Figure 4 shown.

[0138] Step S33, determine the viscosity of condensate gas according to the pressure variable and the viscosity formula of condensate gas. Among them, the viscosity formula of condensate gas is set as:

[0139] μ g = a μ3 p 3 + a μ2 p 2 + a μ1 p + a μ0 ,

[0140] In the formula, μ g is the viscosity of condensate gas, a μ3 , a μ2 , a μ1 , a μ0 are the fitting coefficients of the polynomial relationship between the viscosity of condensate gas and the pressure variable, and the units are (mPa·s)·MPa -3 , (mPa·s)·MPa -2 , (mPa·s)·MPa -1 , mPa·s respectively;

[0141] Specifically, use the experimental measurement method, the chart method, or the Lee-Gonzalez-Eakin semi-empirical correlation method to determine the viscosity μ g of condensate gas corresponding to different pressures at the reservoir temperature, and use the polynomial fitting method to fit the relationship between the viscosity of condensate gas and the pressure, that is, the viscosity formula of condensate gas. And, based on the viscosity formula of condensate gas, generate a fitting curve graph showing the variation of the viscosity of condensate gas with the pressure variable as Figure 5 shown, and substitute it into the viscosity formula of condensate gas:

[0142] μ g = -3.6743×10-7 p 3 +2.5496×10 -5 p 2 +5.2097×10 -5 p + 1.2322×10 -2 ,

[0143] wherein, a μ3 = 3.6743×10 -7 (mPa·s)·MPa -3 、a μ2 = 2.5496×10 -5 (mPa·s)·MPa -2 、a μ1 = 5.2097×10 -5 (mPa·s)·MPa -1 、a μ0 = 1.2322×10 -2 mPa·s.

[0144] Step S34, determine the underground condensate gas density according to the pressure variable, the condensate gas deviation factor and the condensate gas density formula, wherein the condensate gas density formula is set as:

[0145]

[0146] In the formula, ρ g is the underground condensate gas density, γ g is the relative density of the condensate gas, and T is the reservoir temperature;

[0147] Specifically, calculate the underground condensate gas density corresponding to different pressure variables at the reservoir temperature, and generate a fitting curve graph showing the change of the condensate gas density with the pressure variable as Figure 6 shown.

[0148] And, substitute the standard temperature T sc (equal to 293.15K), the standard pressure p sc (equal to 0.101325MPa) and the condensate gas deviation factor Z sc (equal to 1) under standard conditions into the condensate gas density formula, and the ground natural gas density ρ g,sc value under the standard temperature and standard pressure can be calculated as:

[0149]

[0150] In the embodiments of the present invention, the oil-gas phase relative permeability parameters include the oil-phase relative permeability and the gas-phase relative permeability;

[0151] Step S40. Determining the relative permeability parameters of the oil and gas phases according to the condensate saturation fitting model and the relative permeability model of the oil and gas phases includes:

[0152] Determining the relative permeability of the oil phase according to the condensate saturation fitting model and the relative permeability model of the oil phase, and determining the relative permeability of the gas phase according to the condensate saturation fitting model and the relative permeability model of the gas phase. Among them, the relative permeability model of the oil phase is set as:

[0153]

[0154] The relative permeability model of the gas phase is set as:

[0155]

[0156] In the formula, S o is the condensate saturation, p is the pressure variable, p d is the dew point pressure of the condensate gas, a s4 , a s3 , a s2 , a s1 , a s0 are respectively the fitting coefficients of the polynomial relationship between the condensate saturation and the pressure variable, k ro is the relative permeability of the oil phase, k ro ∞ is the maximum relative permeability of the oil phase, S oc is the critical flow saturation of the condensate oil, n o is the relative permeability index of the oil phase, k rg is the relative permeability of the gas phase, k rg ∞ is the maximum relative permeability of the gas phase, S wi is the original water saturation, n g is the relative permeability index of the gas phase.

[0157] Specifically, applying the Corey relative permeability model of the oil phase, that is, the relative permeability model of the oil phase, the maximum relative permeability of the condensate oil phase k ro = 0.6, the critical flow saturation of the condensate oil S oc = 0.0526, the relative permeability index of the oil phase n o = 2, calculating the relative permeability data of the oil phase at different condensate saturations in the shale condensate gas reservoir, applying the Corey relative permeability model of the gas phase, that is, the relative permeability model of the gas phase, the maximum relative permeability of the gas phase k rg = 1, the original water saturation S wi = 0.2, the relative permeability index of the gas phase n g= 1.5, calculate the gas-phase relative permeability data at different condensate saturations in the shale condensate gas reservoir, and generate the oil and gas phase relative permeability curve as shown in Figure 7 Figure.

[0158] In the embodiment of the present invention, the gas reservoir parameters further include the molecular weight of condensate oil. Step S50, determining the original geological reserves of the gas reservoir according to the gas reservoir parameters and the horizontal well parameters includes:

[0159] Step S51, respectively determine the original geological reserves of condensate gas in the fracturing reform area and the original geological reserves of condensate gas outside the fracturing reform area according to the condensate gas deviation coefficient formula, the first condensate gas original geological reserve formula, and the second condensate gas original geological reserve formula. Among them, the first condensate gas original geological reserve formula is set as:

[0160]

[0161] The second condensate gas original geological reserve formula is set as:

[0162]

[0163] Step S52, determine the original geological reserves of natural gas within the well control range of the gas reservoir according to the original geological reserves of condensate gas in the fracturing reform area, the original geological reserves of condensate gas outside the fracturing reform area, and the natural gas original geological reserve formula. Among them, the natural gas original geological reserve formula is set as:

[0164]

[0165] Step S53, determine the original geological reserves of condensate oil within the well control range of the gas reservoir according to the original geological reserves of natural gas within the well control range of the gas reservoir and the condensate oil original geological reserve formula. Among them, the condensate oil original geological reserve formula is set as:

[0166]

[0167] In the formula, G w,srv is the original geological reserves of condensate gas in the fracturing reform area, G w,out is the original geological reserves of condensate gas outside the fracturing reform area, G w is the sum of the original geological reserves of condensate gas in the fracturing reform area and the original geological reserves of condensate gas outside the fracturing reform area, G g is the original geological reserves of natural gas within the well control range of the gas reservoir, N c is the original geological reserves of condensate oil within the well control range of the gas reservoir, L f is the half-length of the fracture, L H is the length of the horizontal well, L is the horizontal well spacing, h is the reservoir thickness, φ is the reservoir porosity, p iis the original formation pressure, p sc is the standard condition pressure equal to 0.101325 MPa, T sc is the standard condition temperature equal to 293.15 K, Z sc is the standard condition natural gas deviation factor, dimensionless, take 1; Z i is the condensate gas deviation factor corresponding to the original formation pressure, R god is the produced gas-oil ratio when the average formation pressure is higher than the dew point pressure, V sckm is the surface volume corresponding to 1 kmol of natural gas equal to 24.055 m 3 / kmol, ρ o，sc is the surface condensate oil density, M o is the molecular weight of the condensate oil.

[0168] Specifically, the original geological reserves of condensate gas in the shale condensate gas reservoir include the original geological reserves of condensate gas within the fracturing and reconstruction area and the original geological reserves of condensate gas outside the fracturing and reconstruction area. The original geological reserves of condensate gas within the fracturing and reconstruction area of the shale condensate gas reservoir can be calculated by the first original geological reserves formula of condensate gas, and the original geological reserves of condensate gas outside the fracturing and reconstruction area of the shale condensate gas reservoir can be calculated by the second original geological reserves formula of condensate gas. The original geological reserves G of condensate gas within the well control range of the shale condensate gas reservoir w is the sum of the original geological reserves of condensate gas inside and outside the reconstruction area, that is, G w = G w,srv + G w,out , the original geological reserves of natural gas within the well control range of the shale condensate gas reservoir can be calculated by the original geological reserves formula of natural gas, and the original geological reserves of condensate oil within the well control range of the shale condensate gas reservoir can be calculated by the original geological reserves formula of condensate oil. Substitute the corresponding parameters into the first original geological reserves formula of condensate gas, the second original geological reserves formula of condensate gas, the original geological reserves formula of natural gas and the original geological reserves formula of condensate oil respectively:

[0169]

[0170] The original geological reserves G of condensate gas within the well control range of the shale condensate gas reservoir w is the sum of the original geological reserves of condensate gas inside and outside the reconstruction area, which is 1.03785×10 8 m 3 ,

[0171]

[0172] In the embodiment of the present invention, in step S60, determining the daily surface gas production and daily surface oil production corresponding to each day in the preset production time according to the bottom hole flowing pressure mapping table, condensate gas fluid physical property parameters, oil-gas phase relative permeability parameters, original geological reserves of the gas reservoir and the gas reservoir production iteration model includes:

[0173] Step S601: Determine the gas-oil ratio in the fracturing reconstruction area and the gas-oil ratio outside the pressure reconstruction area respectively according to the production gas-oil ratio, average formation pressure and production gas-oil ratio formula when the average formation pressure is higher than the dew point pressure;

[0174] Specifically, calculate the gas-oil ratio in the fracturing reconstruction area and outside the fracturing reconstruction area. The gas-oil ratio is a function of the average formation pressure. The production gas-oil ratio formula is set as:

[0175]

[0176] In the formula, R go is the gas-oil ratio, m 3 / m 3 ; R god is the gas-oil ratio when the average formation pressure is higher than the dew point pressure, m 3 / m 3 ; p ave is the average formation pressure, MPa; a R2 , a R1 , a R0 are the polynomial fitting coefficients of ln(R go ) and ln(p ave ) in the rectangular coordinate, dimensionless.

[0177] Moreover, when the average formation pressure p ave takes the average formation pressure p srv in the fracturing reconstruction area, the obtained gas-oil ratio is the gas-oil ratio R go,srv in the fracturing reconstruction area of the shale gas well; when the average formation pressure p ave takes the average formation pressure p out outside the fracturing reconstruction area, the obtained gas-oil ratio is the gas-oil ratio R go,out outside the fracturing reconstruction area of the shale gas well;

[0178] Moreover, as Figure 8 shown, Figure 8 is the fitting graph of the natural logarithm of the gas-oil ratio and the natural logarithm of the average formation pressure. Among them, a R2 =-0.1291, a R1 =-0.1062, a R0 =9.0397. Substitute the corresponding parameters into the production gas-oil ratio formula:

[0179]

[0180] Step S602: Determine the conversion coefficient of the bottom-hole gas production to the wellhead gas production based on the density of surface condensate oil, the density of surface natural gas, the production gas-oil ratio within the fracturing and stimulation zone, the production gas-oil ratio outside the pressure transformation zone, and the production conversion coefficient formula.

[0181] Specifically, calculate the conversion coefficient of the bottom-hole gas production to the wellhead gas production according to the production conversion coefficient formula, and the production conversion coefficient formula is set as:

[0182]

[0183] In the formula, E is the conversion coefficient of the bottom-hole production to the wellhead production, m 3 / kg; R go is the production gas-oil ratio, m 3 / m 3 ; ρ o,sc is the density of surface condensate oil, kg / m 3 ; ρ g,sc is the density of surface natural gas, kg / m 3 .

[0184] Moreover, when the production gas-oil ratio R og takes the production gas-oil ratio R go,srv within the fracturing and stimulation zone, the obtained conversion coefficient of the bottom-hole production to the wellhead production is the conversion coefficient E srv of the bottom-hole production to the wellhead production within the fracturing and stimulation zone of the shale gas well; when the production gas-oil ratio R og takes the production gas-oil ratio R go,out outside the pressure transformation zone, the obtained conversion coefficient of the bottom-hole production to the wellhead production is the conversion coefficient E out of the bottom-hole production to the wellhead production outside the fracturing and stimulation zone of the shale gas well;

[0185] Furthermore, substitute the density ρ o,sc of surface condensate oil and the density ρ g,sc of surface natural gas into the production conversion coefficient formula:

[0186]

[0187] Step S603: Determine the pressure propagation distance in the fracturing and reconstruction area according to the preset production time, reservoir porosity, average permeability of the fracturing and reconstruction area, original permeability of the fracturing and reconstruction area, permeability stress sensitivity coefficient in the fracturing and reconstruction area, average formation pressure in the fracturing and reconstruction area, average comprehensive compressibility coefficient in the fracturing and reconstruction area, pore compressibility coefficient, water compressibility coefficient, gas compressibility coefficient corresponding to the average formation pressure in the fracturing and reconstruction area, original water saturation, condensate oil saturation fitting model, bottom-hole flowing pressure mapping table, horizontal well length, number of fracturing fracture segments, gas-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing and reconstruction area, oil-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing and reconstruction area, condensate gas viscosity corresponding to the average formation pressure in the fracturing and reconstruction area, underground condensate oil viscosity, and the first pressure propagation distance formula;

[0188] Specifically, taking days as the time measurement unit, substitute the corresponding parameters into the first pressure propagation distance formula to calculate the pressure propagation distance x in the fracturing and reconstruction area at different production times. The first pressure propagation distance formula is set as:

[0189]

[0190] Among them,

[0191] C t,srv = C p + S wi C w + S o,srv C o +(1 - S wi - S o,srv )C g,srv ,

[0192] In the formula, x is the pressure propagation distance in the fracturing and reconstruction area, t is the preset production time, φ is the reservoir porosity, k srv is the average permeability of the fracturing and reconstruction area, k srvi is the original permeability of the fracturing and reconstruction area, C ksrv is the permeability stress sensitivity coefficient in the fracturing and reconstruction area, p srv is the average formation pressure in the fracturing and reconstruction area, C t,srv is the average comprehensive compressibility coefficient in the fracturing and reconstruction area, C p is the pore compressibility coefficient, C w is the water compressibility coefficient, C o is the oil compressibility coefficient, C g,srv is the gas compressibility coefficient corresponding to the average formation pressure in the fracturing and reconstruction area, S wi is the original water saturation, S o,srv is the condensate oil saturation corresponding to the average formation pressure in the fracturing and reconstruction area, p iis the original formation pressure, p wf is the bottom-hole flowing pressure, L H is the horizontal well length, n f is the number of fracturing fracture segments, k rg,srv is the gas-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing transformation area, k ro,srv is the oil-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing transformation area, μ rg,srv is the condensate gas viscosity at the condensate oil saturation corresponding to the average formation pressure in the fracturing transformation area, μ o is the underground condensate oil viscosity.

[0193] Step S604, determine the pseudo-pressure difference in the fracturing transformation area according to the gas-phase original permeability, original formation pressure, average formation pressure in the fracturing transformation area, condensate gas upper dew point pressure, condensate oil critical flow pressure, bottom-hole flowing pressure mapping table, underground condensate oil density, underground condensate oil viscosity, oil-phase relative permeability, gas-phase relative permeability, underground condensate gas density, underground natural gas viscosity and the first pseudo-pressure difference formula;

[0194] Specifically, substitute the corresponding parameters into the first pseudo-pressure difference formula to calculate the pseudo-pressure difference in the fracturing transformation area at different production times. The first pseudo-pressure difference formula is set as:

[0195]

[0196] In the formula, ψ srv -ψ wf is the condensate gas pseudo-pressure difference in the fracturing transformation area, (kg / m 3 )·MPa / (mPa·s); k rg (S wi ) is the gas-phase original permeability under irreducible water, dimensionless; p i is the original formation pressure, MPa; p srv is the average formation pressure in the fracturing transformation area, i.e., the SRV area, MPa; p d is the upper dew point pressure of the condensate gas, MPa; p * is the pressure corresponding to the critical flow of the condensate oil, MPa; p wf is the bottom-hole flowing pressure, MPa; ρ o is the underground condensate oil density (constant here), kg / m 3 ; μ o is the viscosity of the underground condensate oil (constant here), mPa·s; k ro is the oil-phase permeability, dimensionless; ρ g is the density of the underground condensate gas, kg / m 3 ; μ g is the viscosity of the underground natural gas, mPa·s; k rgis the gas-phase permeability, dimensionless; k rg (S wi ) is the original gas-phase permeability under the irreducible water, dimensionless. Moreover, when calculating the pseudo-pressure difference of the condensate gas in the fracturing treatment area on the first day, the average formation pressure p in the fracturing treatment area, i.e., the SRV area srv is equal to the original formation pressure p i .

[0197] Step S605, determine the daily gas production and daily oil production on the ground corresponding to each day during the preset production time according to the number of fracturing fracture segments, the initial permeability of the fracturing treatment area, the half-length of the fracture, the fracture height, the pressure propagation distance in the fracturing treatment area, the conversion coefficient of the bottom-hole production and the wellhead production in the fracturing treatment area, the pseudo-pressure difference in the fracturing treatment area, the produced gas-oil ratio in the fracturing treatment area, the formula for the daily gas production on the ground and the formula for the daily oil production on the ground;

[0198] Specifically, substitute the corresponding parameters into the formula for the daily gas production on the ground to calculate the daily gas production on the ground of the fractured horizontal well in the shale condensate gas reservoir at different production times, and substitute the corresponding parameters into the formula for the daily oil production on the ground to calculate the daily oil production on the ground of the fractured horizontal well in the shale condensate gas reservoir at different production times. The formula for the daily gas production on the ground is set as:

[0199]

[0200] In the formula, q g,sc is the daily gas production on the ground, L f is the half-length of the fracture, h f is the fracture height, E srv is the conversion coefficient of the bottom-hole production and the wellhead production in the fracturing treatment area, (ψ srv -ψ wf ) is the pseudo-pressure difference in the fracturing treatment area;

[0201] The formula for the daily oil production on the ground is set as:

[0202]

[0203] In the formula, q o,sc is the daily oil production on the ground, R go,srv is the produced gas-oil ratio in the fracturing treatment area.

[0204] Step S606, determine the cumulative gas production on the ground according to the daily gas production on the ground and the formula for the cumulative gas production, and determine the cumulative oil production on the ground according to the daily oil production on the ground and the formula for the cumulative oil production;

[0205] Specifically, substitute the corresponding parameters into the formula for the cumulative gas production on the ground to calculate the cumulative gas production on the ground of the fractured horizontal well in the shale condensate gas reservoir at different production times, and substitute the corresponding parameters into the formula for the cumulative oil production on the ground to calculate the cumulative oil production on the ground of the fractured horizontal well in the shale condensate gas reservoir at different production times. The formula for the cumulative gas production on the ground is set as:

[0206]

[0207] In the formula, G p is the cumulative gas production, m 3 ; q g,sc is the daily gas production on the ground of the gas well, m 3 / d;

[0208] The formula for the cumulative oil production on the ground is set as:

[0209]

[0210] In the formula, N p is the cumulative oil production, m 3 ; q o,sc is the daily oil production on the ground of the gas well, m 3 / d;

[0211] Furthermore, substitute the cumulative gas production on the ground, the cumulative oil production on the ground, and the corresponding parameters into the formula for the cumulative hydrocarbon production well stream volume of the fractured horizontal well in the shale condensate gas reservoir at different production times (the volume after conversion to the gas phase). The formula for the cumulative hydrocarbon production well stream volume is set as:

[0212]

[0213] In the formula, G wp is the cumulative hydrocarbon production well stream volume (the volume after conversion to the gas phase), m 3 ; G p is the cumulative gas production, m 3 ; V sckm is the ground volume corresponding to 1 kmol of natural gas, equal to 24.055 m 3 / kmol; N p is the cumulative oil production, m 3 ; ρ o,sc is the density of the surface condensate oil, kg / m 3 ; M o is the molecular weight of the condensate oil, kg / kmol.

[0214] In the embodiment of the present invention, the gas reservoir parameters further include reservoir temperature, the original permeability of the reservoir outside the fracturing reform area in the direction of fracturing fracture extension, and reservoir thickness; the horizontal well parameters further include horizontal well spacing and permeability stress sensitivity coefficient outside the fracturing reform area; the condensate gas fluid physical property parameters further include condensate gas deviation coefficient; step S60, determining the daily gas production and daily oil production on the ground corresponding to each day in the preset production time according to the bottom-hole flowing pressure mapping table, condensate gas fluid physical property parameters, oil-gas phase relative permeability parameters, original geological reserves of the gas reservoir, and gas reservoir production iteration model further includes:

[0215] Step S607, determining the propagation duration of the pressure in the fracturing reform area to the midpoint of the fracturing fracture according to the preset production time, the pressure propagation distance in the fracturing reform area, the horizontal well length, and the number of fracturing fracture segments;

[0216] Specifically, the time t 1 corresponding to the pressure in the fracturing reform area of the shale condensate gas well propagating to the midpoint of the fracturing fracture, that is, the time when the fluid starts to be supplied from the outside of the fracturing reform area of the shale condensate gas reservoir to the inside of the fracturing reform area, calculates the pressure propagation distance x in the fracturing reform area equal to L H / (2n f ) with the corresponding time, and is expressed by the propagation duration formula. The propagation duration formula is set as:

[0217]

[0218] In the formula, t 1 is the time corresponding to the pressure in the fracturing reform area of the shale condensate gas well propagating to the midpoint of the fracturing fracture, d; t is the preset production time, d; x is the pressure propagation distance of the linear flow between fractures, m; L H is the horizontal well length, m; n f is the number of fracturing fracture segments, dimensionless; q o,sc is the daily oil production on the ground of the gas well, m 3 / d.

[0219] Step S608: Determine the pressure propagation distance outside the fracturing reform area according to the preset production time, reservoir porosity, average permeability of the reservoir outside the fracturing reform area in the direction of fracturing crack extension, original permeability of the reservoir outside the fracturing reform area in the direction of fracturing crack extension, permeability stress sensitivity coefficient outside the fracturing reform area, horizontal well spacing, fracture half-length, average formation pressure outside the fracturing reform area, average comprehensive compressibility outside the fracturing reform area, pore compressibility, water compressibility, gas compressibility corresponding to the average formation pressure outside the fracturing reform area, original water saturation, condensate oil saturation fitting model, gas-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure outside the fracturing reform area, oil-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure outside the fracturing reform area, condensate gas viscosity corresponding to the average formation pressure outside the fracturing reform area, underground condensate oil viscosity, and the second pressure propagation distance formula.

[0220] Specifically, when the preset production time is greater than the time t corresponding to the pressure in the fracturing reform area of the shale condensate gas well propagating to the midpoint of the fracturing crack 1 After that, i.e., t > t 1 , the pressure wave begins to propagate outside the fracturing reform area. The second pressure propagation distance formula is used to calculate the pressure propagation distance y outside the fracturing reform area at different production times. The second pressure propagation distance formula is set as:

[0221]

[0222] Where

[0223] C t,out = C p + S wi C w + S o,out C o +(1 - S wi - S o,out )C g,out ,

[0224] In the formula, y is the pressure propagation distance outside the fracturing reform area, m; t is the production time, d; φ is the porosity, decimal; k y is the average permeability of the shale reservoir outside the fracturing reform area in the direction of fracturing crack extension, mD; k yi is the original permeability of the shale reservoir outside the fracturing reform area in the direction of fracturing crack extension, mD; C ky is the permeability stress sensitivity coefficient outside the fracturing reform area, MPa -1 ; L is the horizontal well spacing, m; L f is the fracture half-length, m; p out is the average formation pressure outside the fracturing reform area, MPa; p srvis the average formation pressure in the fracturing transformation area, i.e., the SRV area, MPa; C t,out is the average comprehensive compressibility outside the fracturing transformation area, MPa -1 ; C p is the pore compressibility, MPa -1 ; C w is the compressibility of water, MPa -1 ; C g,out is the gas compressibility corresponding to the average formation pressure outside the fracturing transformation area, MPa -1 ; S wi is the irreducible water saturation, decimal; S o,out is the condensate oil saturation corresponding to the average formation pressure outside the fracturing transformation area, decimal; k rg,out is the gas-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure outside the fracturing transformation area, dimensionless; k ro,out is the oil-phase relative permeability at the condensate oil saturation corresponding to the average formation pressure outside the fracturing transformation area, dimensionless; μ g,out is the viscosity of the condensate gas corresponding to the average formation pressure outside the fracturing transformation area, mPa·s; μ o is the viscosity of the underground condensate oil (constant here), mPa·s.

[0225] Step S609, determine the pseudo-pressure difference outside the fracturing transformation area according to the gas-phase original permeability, original formation pressure, average formation pressure outside the fracturing transformation area, average formation pressure in the fracturing transformation area, dew point pressure of the condensate gas, critical flow pressure of the condensate oil, density of the underground condensate oil, viscosity of the underground condensate oil, oil-phase relative permeability, gas-phase relative permeability, density of the underground condensate gas, and viscosity of the underground natural gas;

[0226] Specifically, substitute the corresponding parameters into the second pseudo-pressure difference formula to calculate the pseudo-pressure difference outside the fracturing transformation area at different production times. The second pseudo-pressure difference formula is set as:

[0227]

[0228] In the formula, ψ out -ψ srv is the pseudo-pressure difference of the condensate gas, (kg / m 3 )·MPa / (mPa·s); k rg (S wi ) is the gas-phase original permeability under irreducible water, dimensionless; C ky is the permeability stress sensitivity coefficient outside the fracturing transformation area, MPa -1 ; p i is the original formation pressure, MPa; p out is the average formation pressure of the gas reservoir outside the fracturing transformation area, MPa; p srvis the average formation pressure in the fracturing transformation area, i.e., the SRV area, MPa; p d is the upper dew point pressure of the condensate gas, MPa; p * is the pressure corresponding to the critical flow of the condensate oil, MPa; ρ o is the density of the underground condensate oil (a constant is taken here), kg / m 3 ; μ o is the viscosity of the underground condensate oil (a constant is taken here), mPa·s; k ro is the oil-phase permeability, dimensionless; ρ g is the density of the underground condensate gas, kg / m 3 ; μ g is the viscosity of the underground natural gas, mPa·s; k rg is the gas-phase permeability, dimensionless; k rg (S wi ) is the original gas-phase permeability under the irreducible water, dimensionless. And when the production time is less than or equal to the time t 1 corresponding to the pressure in the fracturing transformation area of the shale condensate gas well propagating to the midpoint of the fracturing fracture, i.e., t ≤ t 1 , when calculating the pseudo-pressure difference of the condensate gas outside the fracturing transformation area, the average formation pressure p out outside the fracturing transformation area is equal to the original formation pressure p i .

[0229] Step S610, determine the daily gas supply and daily oil supply from outside the fracturing transformation area to inside the fracturing transformation area corresponding to each day during the preset production time according to the original permeability of the reservoir outside the fracturing transformation area in the direction of the fracturing fracture extension, the horizontal well length, the fracture height, the pressure propagation distance outside the fracturing transformation area, the conversion coefficient of the bottom-hole production and the wellhead production outside the fracturing transformation area, the pseudo-pressure difference outside the fracturing transformation area, the propagation duration of the pressure in the fracturing transformation area to the midpoint of the fracturing fracture, the daily gas supply formula and the daily oil supply formula;

[0230] Specifically, substitute the corresponding parameters into the daily gas supply formula to calculate the daily gas supply from outside the fracturing transformation area to inside the fracturing transformation area of the shale condensate gas reservoir at different production times, and substitute the corresponding parameters into the daily oil supply formula to calculate the daily oil supply from outside the fracturing transformation area to inside the fracturing transformation area of the shale condensate gas reservoir at different production times. The daily gas supply formula is set as:

[0231]

[0232] The daily oil supply formula is set as:

[0233]

[0234] In the formula, q gsrv,scis the daily gas supply from the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area, that is, the daily surface gas production corresponding to the flow from the outside of the fracturing reconstruction area to the SRV area, m 3 / d; k yi is the original permeability of the shale reservoir outside the fracturing reconstruction area in the direction of the fracture extension, mD; L H is the horizontal well length, m; h f is the fracture height (equal to the reservoir thickness), m; y is the pressure propagation distance outside the fracturing reconstruction area, m; E out is the conversion coefficient of the bottom-hole production to the wellhead production outside the fracturing reconstruction area, m 3 / kg; ψ out -ψ srv is the pseudo-pressure difference of the condensate gas, (kg / m 3 )·MPa / (mPa·s); t 1 is the time corresponding to the pressure in the fracturing reconstruction area of the shale condensate gas well propagating to the midpoint of the fracture, d; q osrv,sc is the daily oil supply from the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area, that is, the daily surface oil production corresponding to the flow from the outside of the fracturing reconstruction area to the SRV area, m 3 / d; R go,out is the produced gas-oil ratio outside the fracturing reconstruction area, dimensionless.

[0235] Step S611, determine the cumulative gas supply from the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area according to the daily gas supply and the cumulative gas supply formula corresponding to each day in the preset production time in the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area, and determine the cumulative oil supply from the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area according to the daily oil supply and the cumulative oil supply formula corresponding to each day in the preset production time in the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area;

[0236] Specifically, substitute the corresponding parameters into the cumulative gas supply formula to calculate the cumulative gas supply from the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area of the shale condensate gas reservoir during the preset production time, and substitute the corresponding parameters into the cumulative oil supply formula to calculate the cumulative oil supply from the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area of the shale condensate gas reservoir during the preset production time. The cumulative gas supply formula is set as:

[0237]

[0238] In the formula, G g,out→srv is the cumulative gas supply from the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area, m 3 ; q gsrv,sc is the daily gas supply from the outside of the fracturing reconstruction area to the inside of the fracturing reconstruction area, m 3 / d;

[0239] The cumulative oil supply formula is set as:

[0240]

[0241] In the formula, N o,out→srv is the cumulative oil supply from the outside of the fracturing reform area to the inside of the fracturing reform area, m 3 ; q osrv,sc is the daily oil supply from the outside of the fracturing reform area to the inside of the fracturing reform area, m 3 / d;

[0242] Moreover, substitute the cumulative gas supply, cumulative oil supply and corresponding parameters into the second cumulative hydrocarbon production well stream volume formula to calculate the cumulative hydrocarbon production well stream volume (volume after conversion to gas phase) of the fractured horizontal well in the shale condensate gas reservoir at different production times. The second cumulative hydrocarbon production well stream volume formula is set as:

[0243]

[0244] In the formula, G w,out→srv is the cumulative condensate gas volume supplied from the outside of the fracturing reform area to the inside of the fracturing reform area (volume after conversion to gas phase), m 3 ; G g,out→srv is the cumulative gas supply from the outside of the fracturing reform area to the inside of the fracturing reform area, m 3 ; V sckm is the ground volume corresponding to 1 kmol of natural gas, equal to 24.055 m 3 / kmol; N o,out→srv is the cumulative oil supply from the outside of the fracturing reform area to the inside of the fracturing reform area, m 3 ; ρ o,sc is the ground condensate oil density, kg / m 3 ; M o is the molecular weight of the condensate oil, kg / kmol.

[0245] Step S612: Determine the average formation pressure in the pressure propagation range outside the fracturing area according to the horizontal well length, reservoir thickness, pressure propagation distance outside the fracturing reform area, reservoir porosity, original water saturation, original formation pressure, condensate gas deviation factor corresponding to the original formation pressure, reservoir temperature, standard condition pressure, standard condition temperature, standard condition natural gas deviation factor, water compressibility, average formation pressure in the pressure affected range outside the fracturing reform area, underground condensate oil density, condensate oil saturation fitting model, condensate gas deviation factor corresponding to the average formation pressure, cumulative condensate gas volume supplied from the outside of the fracturing reform area to the inside of the fracturing reform area, and the material balance equation outside the fracturing reform area;

[0246] Specifically, by applying the material balance equation outside the fracturing reform area of the shale condensate gas reservoir and using the Newton iteration method, the numerical value of the average formation pressure p out in the pressure propagation range outside the fracturing area at different production times can be obtained. The material balance equation outside the fracturing reform area is set as:

[0247]

[0248] In the formula, G w,out,v is the original geological reserve of condensate gas in the pressure affected area outside the fracturing reform area, h is the reservoir thickness, y is the pressure propagation distance outside the fracturing reform area, Z i is the deviation coefficient of condensate gas corresponding to the original formation pressure, T is the reservoir temperature, p sc is the standard condition pressure equal to 0.101325 MPa, T sc is the standard condition temperature equal to 293.15 K, Z sc is the dimensionless deviation coefficient of natural gas under standard conditions, taken as 1; p out is the average formation pressure in the pressure affected area outside the fracturing reform area, ρ o is the underground condensate oil density, S o is the condensate oil saturation, Z w is the deviation coefficient of condensate gas corresponding to the average formation pressure, R is the universal gas constant equal to 0.008314 MPa·m 3 / (kmol·K), G w,out→srv is the cumulative supply volume of condensate gas from the area outside the fracturing reform area to the area inside the fracturing reform area.

[0249] Furthermore, when the pressure variable is greater than or equal to the upper dew point pressure of the condensate gas, that is, when p≥p d , S o =0, the material balance equation outside the fracturing reform area of the shale condensate gas reservoir can be simplified to the first simplified formula, and the first simplified formula is set as:

[0250]

[0251] The first simplified formula is an implicit function equation, and the average formation pressure of the gas reservoir outside the fracturing reform area can be obtained by the Newton-Ralph method. To simplify the notation, p is used instead of p out , and the iterative equation is generated as:

[0252]

[0253] Among them, the first F function in the iterative equation is set as:

[0254]

[0255] Taking the derivative of both sides of the first F function with respect to the pressure variable p gives the first F' function:

[0256]

[0257] And the corresponding iterative step is to arbitrarily select a pressure and use (p i +p d) / 2 as the initial value p of the average formation pressure of the gas reservoir outside the fracturing transformation area old , calculate the initial value Z of the deviation factor at pressure p old according to the condensate gas deviation factor formula w,old , and then substitute the gas reservoir parameters, the original geological reserve G of the condensate gas outside the fracturing transformation area (SRV area) w,out and the cumulative supply volume of condensate gas from outside the fracturing transformation area to inside the fracturing transformation area at the previous moment (converted to the volume after gas phase conversion) G w,out→srv into the first F function and the first F' function to calculate the F function and its derivative value F'; substitute the corresponding parameters into the material balance equation outside the fracturing transformation area and perform Newton iteration to obtain the calculated value p of the average formation pressure new ; use this calculated value p new as the initial value p old , repeat the above iteration steps until the error between the calculated value and the initial value is less than the precision error, then this calculated value is the average formation pressure of the gas reservoir outside the fracturing transformation area

[0258] When the pressure variable is less than or equal to the upper dew point pressure of the condensate gas, that is, when p < p d , substitute the condensate oil saturation fitting model into the material balance equation outside the fracturing transformation area of the shale condensate gas reservoir. To simplify the notation, use p instead of p out , and generate the first transformation formula, which is set as follows

[0259]

[0260] The first transformation formula is an implicit function equation, and the average formation pressure of the gas reservoir outside the fracturing transformation area can be obtained by the Newton-Ralph method. Substitute it into the above iteration equation. At this time, the second F function in the iteration equation is set as

[0261]

[0262] Take the derivative of both sides of the second F function with respect to the pressure variable p to obtain the second F' function

[0263]

[0264] And the corresponding iteration steps are to arbitrarily select a pressure and use p d / 2 as the initial value p of the average formation pressure of the gas reservoir outside the fracturing transformation area old , calculate the initial value Z of the deviation factor at pressure p old according to the condensate gas deviation factor formula w,old , and then substitute the gas reservoir parameters, the fitting coefficients of the polynomial relationship between the condensate oil saturation and pressure determined by fitting the condensate oil saturation fitting model (including a s4 , a s3, a s2 , a s1 and a s0 ), the original geological reserve G of condensate gas in the pressure propagation range outside the fracturing transformation area (SRV area) w,out,v and the cumulative supply volume of condensate gas from the outside of the fracturing transformation area to the inside of the fracturing transformation area at the previous moment (the volume after conversion to the gas phase) G w,out→srv Substitute into the second F function and the second F' function to calculate the F function and its derivative value F'; substitute the required parameters into the iteration equation for Newton iteration to obtain the calculated value p of the average formation pressure new ; Take this calculated value p new as the initial value p old , repeat the above iteration steps until the error between the calculated value and the initial value is less than the precision error, then this calculated value is the average formation pressure of the gas reservoir outside the fracturing transformation area.

[0265] Step S613, determine the average formation pressure in the fracturing affected area in the fracturing transformation area according to the number of fracturing fracture segments, fracture half-length, reservoir thickness, pressure propagation distance in the fracturing transformation area, reservoir porosity, original water saturation, original formation pressure, condensate gas deviation coefficient corresponding to the original formation pressure, reservoir temperature, standard condition pressure, standard condition temperature, standard condition natural gas deviation coefficient, water compressibility, average formation pressure in the fracturing transformation area, underground condensate oil density, condensate oil saturation fitting model, condensate gas deviation coefficient corresponding to the average formation pressure, universal gas constant, cumulative produced hydrocarbon well flow volume, cumulative supply volume of condensate gas from the outside of the fracturing transformation area to the inside of the fracturing transformation area, and the material balance equation in the fracturing transformation area;

[0266] Specifically, applying the material balance equation in the fracturing transformation area and using the Newton iteration method, the numerical value of the average formation pressure psrv in the fracturing transformation area at different production times can be obtained. The material balance equation in the fracturing transformation area is set as:

[0267]

[0268] In the formula, G w,srv,v is the original geological reserve of condensate gas in the pressure affected area in the fracturing transformation area (SRV area), m 3 ; n f is the number of fracturing fracture segments, dimensionless; L f is the fracture half-length, m; h is the gas reservoir thickness, m; x is the pressure propagation distance of linear flow between fractures, m; φ is the gas reservoir porosity, decimal; S wi is the original water saturation, decimal; p i is the original formation pressure, MPa; Z i is the condensate gas deviation coefficient corresponding to the original formation pressure, dimensionless; T is the reservoir temperature of the shale condensate gas reservoir, K; p scis the standard condition pressure, equal to 0.101325 MPa; T sc is the standard condition temperature, equal to 293.15 K; Z sc is the deviation factor of natural gas under standard conditions, dimensionless, generally taken as 1; C w is the compressibility factor of formation water, MPa -1 ; p srv is the average formation pressure in the fracturing reform area, MPa; ρ o is the density of underground condensate oil, kg / m 3 ; S o is the condensate oil saturation, in decimals; T is the reservoir temperature of the shale condensate gas reservoir, K; Z w is the deviation factor of condensate gas corresponding to the average formation pressure of the gas reservoir, dimensionless; R is the universal gas constant, equal to 0.008314 MPa·m 3 / (kmol·K); G wp is the cumulative produced hydrocarbon well stream volume (volume after conversion to gas phase), m 3 ; G w,out→srv is the cumulative supplied condensate gas volume from outside the fracturing reform area to the fracturing reform area (volume after conversion to gas phase), m 3 .

[0269] Furthermore, when the pressure variable is greater than or equal to the dew point pressure of condensate gas, i.e., when p ≥ p d , S o = 0, the material balance equation in the fracturing reform area of the shale condensate gas reservoir can be simplified to the second simplified formula, and the second simplified formula is set as:

[0270]

[0271] The second simplified formula is an implicit function equation, and the average formation pressure of the gas reservoir in the fracturing reform area can be obtained by the Newton-Ralph method. To simplify the notation, p is used instead of p srv , substituting into the above iterative equation. At this time, the third F function in the iterative equation is set as:

[0272]

[0273] Taking the derivative of both sides of the third F function with respect to the pressure variable p to obtain the third F' function:

[0274]

[0275] And the corresponding iterative step is to arbitrarily select a pressure and take (p i + p d ) / 2 as the initial value p old of the average formation pressure in the fracturing reform area, and calculate the pressure p according to the condensate gas deviation factor formulaold Initial value Z of deviation coefficient w,old , and then substitute the gas reservoir parameters, the original geological reserves G of condensate gas within the pressure propagation range in the fracturing reform area (SRV area), w,srv,v the cumulative supply volume of condensate gas from outside the fracturing reform area to the inside of the fracturing reform area at the previous moment (volume after conversion to gas phase) G w,out→srv , and the cumulative hydrocarbon production well stream volume at the previous moment (volume after conversion to gas phase) G wp into the third F function and the third F' function to calculate the F function and its derivative value F'; substitute the required parameters into the material balance equation in the fracturing reform area and perform Newton iteration to obtain the calculated value p of the average formation pressure new ; use this calculated value p new as the initial value p old , repeat the above iteration steps until the error between the calculated value and the initial value is less than the precision error, then this calculated value is the average formation pressure of the gas reservoir in the fracturing reform area.

[0276] When the pressure variable is less than or equal to the dew point pressure of condensate gas, that is, when p < p d , substitute the condensate oil saturation fitting model into the material balance equation in the fracturing reform area of the shale condensate gas reservoir. To simplify the notation, use p instead of p srv , and generate the second transformation formula, which is set as follows:

[0277]

[0278] The second transformation formula is an implicit function equation, and the average formation pressure of the gas reservoir in the fracturing reform area can be obtained by the Newton-Ralph method. Substitute it into the above iteration equation. At this time, the fourth F function in the iteration equation is set as:

[0279]

[0280] Take the derivative of both sides of the fourth F function with respect to the pressure variable p to obtain the fourth F' function:

[0281]

[0282] And the corresponding iteration step is to arbitrarily select a pressure and use p wf as the initial value p of the average formation pressure in the fracturing reform area old , calculate the initial value Z of the deviation coefficient under the pressure p old according to the condensate gas deviation coefficient formula w,old , and then substitute the gas reservoir parameters, the fitting coefficients of the polynomial relationship between the condensate oil saturation and pressure determined by fitting the condensate oil saturation fitting model (including a s4 , a s3 , a s2, a s1 and a s0 ), the original geological reserve G of condensate gas in the pressure propagation range in the fracturing reform area (SRV area) w,srv,v , the cumulative supply volume of condensate gas (volume after conversion to gas phase) from outside the fracturing reform area to the fracturing reform area at the previous moment G w,out→srv and the cumulative produced hydrocarbon well fluid volume (volume after conversion to gas phase) at the previous moment G wp Substitute into the fourth F function and the fourth F' function of the formula to calculate the F function and its derivative value F'; substitute the required parameters into the iterative equation for Newton iteration to obtain the calculated value p of the average formation pressure new ; take this calculated value p new as the initial value p old , repeat the above iterative steps until the error between the calculated value and the initial value is less than the precision error, then this calculated value is the average formation pressure of the gas reservoir in the fracturing reform area

[0283] In the embodiment of the present invention, by cycling through the iterative steps S601 to step S613 to determine the pressure and production dynamic data of the fractured horizontal well in the shale condensate gas reservoir, according to the bottom-hole flowing pressure mapping table, in the order of the preset production time, given the bottom-hole flowing pressure of any day, calculate and determine the average formation pressure within and outside the pressure propagation range in the fracturing reform area on that day, and generate a Figure 9 shown pressure dynamic curve of the fractured horizontal well in the shale condensate gas reservoir, and, the daily gas production and daily oil production dynamic curves of this shale condensate gas well at different production times are respectively as Figure 10 and Figure 11 shown. After this shale condensate gas well has produced for 5000 days, the cumulative produced natural gas volume of the shale condensate gas reservoir is 0.4372×10 8 m 3 , the cumulative produced condensate oil volume is 2.3144×10 4 m 3 , converted to mass unit is 1.7978×10 4 t. According to step S52, the original geological reserve of natural gas within the well control range of the shale condensate gas reservoir is calculated to be 0.94795×10 8 m 3 , and according to step S53, the geological reserve of condensate oil within the well control range of the shale condensate gas reservoir is calculated to be 5.0784×10 4 t. It can be calculated that the recovery degrees of natural gas and condensate oil of this shale condensate gas well after producing for 5000 days are 46.12% and 35.4% respectively

[0284] The shale condensate gas reservoir production prediction method according to the embodiments of the present invention is applicable to gas wells with long horizontal sections and multi-stage fracturing in strongly stress-sensitive shale condensate gas reservoirs, so as to predict and calculate the production of fractured horizontal wells in shale condensate gas reservoirs. The shale condensate gas reservoir production prediction method comprehensively considers the influence of condensate oil precipitation and the multi-linear flow coupling mechanism of fractured horizontal wells in shale gas reservoirs. By coupling the linear flow pressure propagation formula (the first pressure propagation distance formula) in the fracturing transformation area, the linear flow pressure propagation formula (the second pressure propagation distance formula) outside the fracturing transformation area, the gas phase productivity formulas (surface daily gas production formulas) inside and outside the fracturing transformation area, the material balance equation outside the fracturing transformation area and the material balance equation inside the fracturing transformation area, it can quickly and accurately predict the production of fractured horizontal wells in shale condensate gas reservoirs, with high prediction accuracy and greatly improving the production prediction precision.

[0285] Specifically, the stress-sensitive effect of permeability is considered in determining the pressure propagation inside and outside the fracturing transformation area, the mechanism of permeability stress-sensitive effect and multi-zone distribution of condensate oil is considered in determining the gas phase productivity inside and outside the fracturing transformation area, and the influence of dynamic change of controlled reserves, pore shrinkage, bound water swelling, condensate oil precipitation, fluid production and supply is comprehensively considered in the material balance equations inside and outside the fracturing transformation area. The shale condensate gas reservoir production prediction method according to the embodiments of the present invention only needs to input gas reservoir parameters and horizontal well parameters, and repeatedly uses the pressure propagation formulas (the first pressure propagation formula and the second pressure propagation formula) inside and outside the fracturing transformation area to calculate the pressure propagation distance, repeatedly uses the gas phase productivity formulas (surface daily gas production formulas) inside and outside the fracturing transformation area to calculate the daily gas production, and repeatedly uses the material balance equations inside and outside the fracturing transformation area to calculate the average formation pressure. Given the pre-set dynamic data of bottom-hole flowing pressure (bottom-hole flowing pressure mapping table), that is, the bottom-hole flowing pressure is known every day, the dynamic data of daily gas production and daily oil production can be predicted, which is simple and easy to operate and has high prediction accuracy.

[0286] In addition, the present invention also provides a machine-readable storage medium, on which instructions are stored for enabling a machine to execute the shale condensate gas reservoir production prediction method according to the above description. And the specific steps of the shale condensate gas reservoir production prediction method refer to the above embodiments. Since the machine-readable storage medium adopts all the technical solutions of the above embodiments, it at least has all the beneficial effects brought by the technical solutions of the above embodiments, which will not be elaborated here one by one.

[0287] In the description of this specification, the descriptions referring to the terms "one embodiment", "some embodiments", "example", "specific example", or "some examples", etc. mean that the specific features, structures, materials, or characteristics described in connection with the embodiment or example are included in at least one embodiment or example of the present invention. In this specification, the schematic representations of the above terms do not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials, or characteristics described may be combined in any one or more embodiments or examples in a suitable manner. In addition, without contradiction, those skilled in the art can combine and combine the different embodiments or examples described in this specification and the features of different embodiments or examples.

[0288] Although the embodiments of the present invention have been shown and described above, it can be understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Those of ordinary skill in the art can make changes, modifications, substitutions, and variations to the above embodiments within the scope of the present invention.

Claims

1. A method for predicting the production of shale condensate gas reservoirs, characterized in that: The shale condensate gas reservoir production prediction method comprises: Obtaining a gas reservoir parameter, a horizontal well parameter, and a bottom hole flowing pressure mapping table of a shale condensate gas reservoir, wherein the bottom hole flowing pressure mapping table is used to characterize a mapping relationship between the bottom hole flowing pressure and a preset production time; Acquire a condensate oil saturation mapping table, and determine a condensate oil saturation fitting model according to the gas reservoir parameters and the condensate oil saturation mapping table, wherein the condensate oil saturation mapping table is used to characterize a mapping relationship between condensate oil saturation and a pressure variable; Determining the physical property parameters of the condensate gas fluid according to the gas reservoir parameters and the pressure variable; Determining oil-gas phase relative permeability parameters according to the condensate oil saturation fitting model and the oil-gas phase relative permeability model; Determine the original geological reserves of the gas reservoir according to the gas reservoir parameters and the horizontal well parameters; The surface daily gas production and surface daily oil production corresponding to each day in the preset production time are determined according to the bottom hole flow pressure mapping table, the condensate gas fluid physical property parameters, the oil and gas phase relative permeability parameters, the original geological reserves of the gas reservoir and the gas reservoir production iteration model; wherein the gas reservoir production iteration model is used to determine the production gas-oil ratio inside the fracturing transformation area and outside the pressure transformation area, the conversion coefficient between the natural gas bottom hole production and the wellhead production, the pressure propagation distance parameter, the pseudo-pressure difference parameter, the average formation pressure parameter of the pressure sweep range, the propagation time of the pressure in the fracturing transformation area to the midpoint of the fracturing crack, the cumulative gas supply and the cumulative oil supply from the outside of the fracturing transformation area to the fracturing transformation area during the preset production time, and the daily gas supply and daily oil supply corresponding to each day.

2. The method for predicting the production of shale condensate gas reservoirs according to claim 1, characterized in that: The gas reservoir parameters include original formation pressure, upper dew point pressure of condensate gas, critical flow pressure of condensate oil, reservoir porosity, pore compressibility coefficient, water compressibility coefficient, original water saturation, production gas-oil ratio when average formation pressure is higher than dew point pressure, underground condensate oil density, underground condensate oil viscosity and surface condensate oil density; The horizontal well parameters include horizontal well length, fracture half-length, fracture height, number of fracture sections, original permeability of the fractured zone, and stress sensitivity coefficient of permeability in the fractured zone; The condensate gas fluid physical property parameters include condensate gas viscosity, underground condensate gas density and surface natural gas density; The oil-gas phase relative permeability parameters include oil phase relative permeability and gas phase relative permeability; The determining of the surface daily gas production and surface daily oil production corresponding to each day in the preset production time according to the bottom hole flow pressure mapping table, the condensate gas fluid physical property parameters, the oil and gas phase relative permeability parameters, the gas reservoir original geological reserves and the gas reservoir production iteration model comprises: According to the production gas-oil ratio when the average formation pressure is higher than the dew point pressure, the average formation pressure and the production gas-oil ratio formula, the production gas-oil ratio in the fracturing stimulation area and the production gas-oil ratio outside the pressure stimulation area are determined respectively; The conversion coefficient between the bottom hole production and the wellhead production of natural gas is determined based on the surface condensate density, the surface natural gas density, the production gas-oil ratio in the fracturing zone, the production gas-oil ratio outside the pressure fracturing zone and the production conversion coefficient formula; Determine the pressure propagation distance in the fracturing zone according to the preset production time, the reservoir porosity, the average permeability of the fracturing zone, the original permeability of the fracturing zone, the permeability stress sensitivity coefficient in the fracturing zone, the average formation pressure in the fracturing zone, the average comprehensive compression coefficient in the fracturing zone, the pore compression coefficient, the water compression coefficient, the natural gas compression coefficient corresponding to the average formation pressure in the fracturing zone, the original water saturation, the condensate saturation fitting model, the bottom hole flowing pressure mapping table, the horizontal well length, the number of fracturing fracture sections, the gas phase relative permeability at the condensate saturation corresponding to the average formation pressure in the fracturing zone, the oil phase relative permeability at the condensate saturation corresponding to the average formation pressure in the fracturing zone, the condensate gas viscosity corresponding to the average formation pressure in the fracturing zone, the underground condensate viscosity and the first pressure propagation distance formula; Determine the pseudo-pressure difference in the fracturing zone according to the original permeability of the gas phase at the original water saturation, the original formation pressure, the average formation pressure in the fracturing zone, the upper dew point pressure of the condensate gas, the critical flow pressure of the condensate oil, the bottom hole flow pressure mapping table, the underground condensate oil density, the underground condensate oil viscosity, the oil phase relative permeability, the gas phase relative permeability, the underground condensate gas density, the underground natural gas viscosity and the first pseudo-pressure difference formula; The surface daily gas production and the surface daily oil production corresponding to each day in the preset production time are determined according to the number of fracturing crack sections, the initial permeability of the fracturing transformation area, the half-length of the crack, the height of the crack, the pressure propagation distance in the fracturing transformation area, the conversion coefficient between the bottom hole production and the wellhead production in the fracturing transformation area, the pseudo-pressure difference in the fracturing transformation area, the production gas-oil ratio in the fracturing transformation area, the surface daily gas production formula and the surface daily oil production formula.

3. The method for predicting the production of shale condensate gas reservoirs according to claim 2, characterized in that: The formula for the daily surface gas production is: In the formula, q g,sc is the daily gas production on the ground, n f is the number of fracture segments, k srvi is the original permeability of the fracturing zone, L f is the crack half length, h f is the fracture height, x is the pressure propagation distance in the fracturing zone, E srv is the conversion coefficient between bottom hole production and wellhead production in the fracturing zone, (ψ srv -ψ wf ) is the pseudo pressure difference in the fracturing stimulation area; The formula for the daily oil production on the ground is set as: In the formula, q o,sc is the daily oil production on the ground, R go,srv It is the gas-oil ratio produced in the fracturing zone.

4. The method for predicting the production of shale condensate gas reservoirs according to claim 3, characterized in that: The production gas-oil ratio formula is set as: In the formula, R go is the production gas-oil ratio, R god is the gas-oil ratio of production when the average formation pressure is higher than the dew point pressure, p ave is the average formation pressure, p d is the upper dew point pressure of condensate gas, a R2 、a R1 、a R0 ln(R go ) and ln(p ave ) polynomial fit coefficients in rectangular coordinates; And the output conversion coefficient formula is set as: Where, E is the conversion coefficient between bottom hole production and wellhead production, ρ o,sc is the surface condensate density, ρ g,sc is the density of ground natural gas.

5. The method for predicting the production of shale condensate gas reservoirs according to claim 4, characterized in that: The first pressure propagation distance formula is set as: in, C t,srv =C p +S wi C w +S o,srv C o +(1-S wi -S o,srv )C g,srv , Where x is the pressure propagation distance in the fracturing zone, t is the preset production time, is the reservoir porosity, k srv is the average permeability of the fracturing zone, k srvi is the original permeability of the fracturing zone, C ksrv is the stress sensitivity coefficient of permeability in the fracturing zone, p srv is the average formation pressure in the fracturing zone, C t,srv is the average comprehensive compression coefficient in the fracturing zone, C p is the pore compression coefficient, C w is the water compressibility coefficient, C o is the oil compressibility coefficient, C g,srv is the natural gas compression coefficient corresponding to the average formation pressure in the fracturing zone, S wi is the initial water saturation, S o,srv is the condensate oil saturation corresponding to the average formation pressure in the fracturing zone, p i is the original formation pressure, p wf is the bottom hole flowing pressure, L H is the horizontal well length, n f is the number of fracture segments, k rg,srv is the gas phase relative permeability at the condensate oil saturation corresponding to the average formation pressure in the fracturing zone, k ro,srv is the relative permeability of the oil phase at the condensate oil saturation corresponding to the average formation pressure in the fracturing zone, μ g,srv is the condensate gas viscosity corresponding to the average formation pressure in the fracturing zone, μ o is the viscosity of underground condensate oil.

6. The method for predicting the production of shale condensate gas reservoirs according to claim 5, characterized in that: The first pseudo pressure difference formula is set as: ， In the formula, ψ srv -ψ wf is the pseudo pressure difference of condensate gas in the fracturing zone, k rg (S wi ) is the original permeability of the gas phase under bound water, p * is the critical flow pressure of condensate oil, ρ o is the underground condensate density, k ro is the oil phase permeability, ρ g is the density of underground condensate gas, μ g is the underground natural gas viscosity, k rg is the gas phase permeability, k rg (S wi ) is the original permeability of the gas phase under bound water.

7. The method for predicting the production of shale condensate gas reservoirs according to claim 6, characterized in that: The gas reservoir parameters also include reservoir temperature, original permeability of the reservoir outside the fracturing zone in the extension direction of the fracturing cracks, and reservoir thickness; The horizontal well parameters also include the horizontal well spacing and the permeability stress sensitivity coefficient outside the fracturing transformation area; The condensate gas fluid physical property parameters also include a condensate gas deviation coefficient; The determining of the surface daily gas production and surface daily oil production corresponding to each day in the preset production time according to the bottom hole flow pressure mapping table, the condensate gas fluid physical property parameters, the oil and gas phase relative permeability parameters, the gas reservoir original geological reserves and the gas reservoir production iteration model also includes: Determine the propagation time of the pressure in the fracturing transformation area to the midpoint of the fracturing fracture according to the preset production time, the pressure propagation distance in the fracturing transformation area, the length of the horizontal well, and the number of fracturing fracture sections; Determine the pressure propagation distance outside the fracturing zone according to the preset production time, the reservoir porosity, the average permeability of the reservoir outside the fracturing zone in the extension direction of the fracturing cracks, the original permeability of the reservoir outside the fracturing zone in the extension direction of the fracturing cracks, the permeability stress sensitivity coefficient outside the fracturing zone, the horizontal well spacing, the fracture half-length, the average formation pressure outside the fracturing zone, the average comprehensive compression coefficient outside the fracturing zone, the pore compression coefficient, the water compression coefficient, the natural gas compression coefficient corresponding to the average formation pressure outside the fracturing zone, the original water saturation, the condensate saturation fitting model, the gas phase relative permeability at the condensate saturation corresponding to the average formation pressure outside the fracturing zone, the oil phase relative permeability at the condensate saturation corresponding to the average formation pressure outside the fracturing zone, the condensate gas viscosity corresponding to the average formation pressure outside the fracturing zone, the underground condensate viscosity and the second pressure propagation distance formula; Determine the pseudo pressure difference outside the fracturing zone according to the original permeability of the gas phase at the original water saturation, the original formation pressure, the average formation pressure outside the fracturing zone, the average formation pressure inside the fracturing zone, the upper dew point pressure of the condensate gas, the critical flow pressure of the condensate oil, the underground condensate oil density, the underground condensate oil viscosity, the oil phase relative permeability, the gas phase relative permeability, the underground condensate gas density, and the underground natural gas viscosity; Determine the daily gas supply and daily oil supply corresponding to each day from the outside of the fracturing zone to the inside of the fracturing zone during the preset production time according to the original permeability of the reservoir outside the fracturing zone in the extension direction of the fracturing crack, the length of the horizontal well, the height of the crack, the pressure propagation distance outside the fracturing zone, the conversion coefficient between the bottom hole production outside the fracturing zone and the wellhead production, the pseudo pressure difference outside the fracturing zone, the propagation time of the pressure inside the fracturing zone to the midpoint of the fracturing crack, the daily gas supply formula and the daily oil supply formula; The average formation pressure of the fracturing range outside the fracturing zone is determined according to the horizontal well length, the reservoir thickness, the pressure propagation distance outside the fracturing zone, the reservoir porosity, the original water saturation, the original formation pressure, the condensate gas deviation coefficient corresponding to the original formation pressure, the reservoir temperature, the standard pressure, the standard temperature, the standard natural gas deviation coefficient, the water compressibility coefficient, the average formation pressure of the pressure sweep range outside the fracturing zone, the underground condensate oil density, the condensate oil saturation fitting model, the condensate gas deviation coefficient corresponding to the average formation pressure, the cumulative volume of condensate gas supplied from the outside of the fracturing zone to the inside of the fracturing zone, and the material balance equation outside the fracturing zone.

8. The method for predicting the production of shale condensate gas reservoirs according to claim 7, characterized in that: The material balance equation outside the fracturing zone is set as: In the formula, G w,out,v is the original geological reserves of condensate gas within the pressure range outside the fracturing zone, h is the reservoir thickness, y is the pressure propagation distance outside the fracturing zone, and Z i is the condensate gas deviation coefficient corresponding to the original formation pressure, T is the reservoir temperature, p sc is the standard pressure, T sc is the standard temperature, Z sc is the standard natural gas deviation coefficient, p out is the average formation pressure within the pressure range outside the fracturing zone, ρ o is the underground condensate density, S o is the condensate saturation, Z w is the condensate gas deviation coefficient corresponding to the average formation pressure, R is the universal gas constant, G w,out→srv The cumulative volume of condensate gas supplied from outside the fracturing zone to inside the fracturing zone.

9. The method for predicting the production of shale condensate gas reservoirs according to claim 8, characterized in that: The gas reservoir parameters also include condensate oil molecular weight, and determining the original geological reserves of the gas reservoir according to the gas reservoir parameters and the horizontal well parameters includes: The original geological reserves of condensate gas in the fracturing zone and the original geological reserves of condensate gas outside the fracturing zone are determined respectively according to the condensate gas deviation coefficient formula, the first original geological reserves formula of condensate gas, and the second original geological reserves formula of condensate gas, wherein the first original geological reserves formula of condensate gas is set to: The formula for the original geological reserves of the second condensate gas is: The original geological reserves of natural gas within the well control range of the gas reservoir are determined according to the original geological reserves of condensate gas within the fracturing and reconstruction area, the original geological reserves of condensate gas outside the fracturing and reconstruction area, and the original geological reserves formula of natural gas, wherein the original geological reserves formula of natural gas is set to: The original geological reserves of condensate oil within the well control range of the gas reservoir are determined according to the original geological reserves of natural gas and the original geological reserves of condensate oil within the well control range of the gas reservoir, wherein the original geological reserves formula of condensate oil is set as: In the formula, G w,srv is the original geological reserves of condensate gas in the fracturing zone, G w,out is the original geological reserves of condensate gas outside the fracturing zone, G w G is the sum of the original geological reserves of condensate gas in the fracturing zone and the original geological reserves of condensate gas outside the fracturing zone. g is the original geological reserves of natural gas within the well control range of the gas reservoir, N c is the original geological reserves of condensate oil within the well control range of the gas reservoir, L f is the crack half length, L H is the horizontal well length, L is the horizontal well spacing, h is the reservoir thickness, φ is the reservoir porosity, and p i is the original formation pressure, p sc is the standard pressure, T sc is the standard temperature, Z sc is the standard natural gas deviation coefficient, Z i is the condensate gas deviation coefficient corresponding to the original formation pressure, R god is the production gas-oil ratio when the average formation pressure is higher than the dew point pressure, V sckm is the ground volume corresponding to 1 kmol of natural gas, ρ o，sc is the density of ground condensate, M o is the molecular weight of condensate.

10. A machine-readable storage medium, characterized in that: The machine-readable storage medium stores instructions for causing a machine to execute the shale condensate gas reservoir production prediction method according to any one of claims 1 to 9.

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