Condensate gas reservoir horizontal well reverse condensation multiphase flow pseudo-pressure determination method and device

Abstract

The invention discloses a condensate gas reservoir horizontal well reverse condensation multiphase flow pseudo-pressure determination method. The method comprises the following steps: determining relative permeability of a gas phase and an oil phase under different pressures based on well flow component data of a condensate gas reservoir horizontal well; determining the gas phase relative permeability under irreducible water saturation based on the relative permeability curve of the condensate gas reservoir horizontal well; correcting the gas phase relative permeability under different pressures and the gas phase relative permeability under irreducible water saturation based on a capillary number effect and a high-speed non-Darcy effect generated by the seepage velocity of condensate gas in the condensate gas well; and based on the oil phase relative permeability under the different pressures, the corrected gas phase relative permeability under the different pressures and the corrected gas phase relative permeability under the irreducible water saturation, utilizing a three-region pseudo-pressure equation to determine the pseudo-pressure of the three regions of the condensate gas well. The pseudo-pressure of the condensate gas reservoir can be calculated more accurately, and a necessary basis is provided for subsequent productivity evaluation and reasonable and efficient development of the condensate gas reservoir.

Description

Technical Field

[0001] This invention relates to the field of oil and gas reservoir development technology, and in particular to a method and apparatus for determining the pseudo-pressure of reverse condensate multiphase flow in horizontal wells of condensate gas reservoirs. Background Technology

[0002] Compared with conventional two-phase flow of oil and gas, multiphase flow in condensate gas reservoirs is more complex and special: (1) During the flow process, heat and mass transfer occur continuously in the multiphase flow of condensate gas reservoirs, and the volume fraction of gas and liquid phases changes continuously, resulting in continuous changes in flow pattern and making it difficult to accurately describe the flow state; (2) The seepage of condensate gas reservoirs is affected by a variety of factors, including porous media, wettability, adsorption, velocity, etc. These factors are coupled with each other, making the seepage dynamics more complex; (3) Most condensate gas reservoirs have edge and bottom water. Due to the presence of the water phase, the system flow will be transformed into three-phase flow of oil-gas-water, which increases the difficulty of production dynamic analysis and actual production.

[0003] Under normal circumstances, the distribution of oil and gas in condensate gas reservoirs can be determined by the following principles: when the formation pressure is higher than the dew point pressure, no condensate oil is precipitated in the reservoir, and it is a dry gas distribution; when the formation pressure is higher than the dew point pressure and the bottom hole flowing pressure is lower than the dew point pressure, condensate oil is precipitated in the near-wellbore zone and gradually accumulates, resulting in a decrease in gas phase permeability and a decrease in production capacity, and the reservoir exhibits a two-phase distribution of oil and gas and a dry gas distribution; when the formation pressure is lower than the dew point pressure, the entire reservoir is a two-phase distribution of oil and gas.

[0004] The continuous precipitation, accumulation, and flow of condensate oil are significant characteristics of condensate gas reservoir seepage, differing from conventional dissolved gas drive two-phase flow and exhibiting unique oil and gas distribution characteristics. For example... Figure 1 The diagram illustrates the distribution principle and flow characteristics of oil and gas in the three zones of a current mainstream condensate gas reservoir. Zone I is a two-phase flow region of oil and gas, where the production gas-oil ratio is constant. The single-phase gas entering Zone I has the same composition as the fluid from the production well, and the production capacity loss of condensate gas wells mainly comes from this zone. Zone II is a non-flowing region of condensate oil, where the condensate oil saturation is below the critical condensate flow saturation, thus exhibiting a net accumulation state. Zone III is a single-phase gas flow region where no condensate oil is precipitated, and its composition remains unchanged, equivalent to the original state.

[0005] The pseudo-pressure of anti-condensate multiphase flow in horizontal wells of traditional condensate gas reservoirs is determined using a two-phase pseudo-pressure function equation based on the current mainstream three-zone oil and gas distribution principle and flow characteristics of condensate gas reservoirs. Summary of the Invention

[0006] The inventors of this application have discovered that the current mainstream principles and flow characteristics of oil and gas distribution in the three zones of condensate gas reservoirs do not fully consider the influence of velocity factors during the seepage process of condensate gas, and neglect the effects generated by high-speed fluid flow. This effect will cause changes in the seepage dynamics of condensate gas reservoirs and affect the determination of the pseudo-pressure of anti-condensate multiphase flow in horizontal wells of condensate gas reservoirs.

[0007] During the seepage process of condensate gas, the seepage velocity gradually increases as the seepage area decreases, reaching its maximum at the bottom of the well. From the far end of the formation to the bottom of the well, the pressure drop loss gradually increases, forming a pressure loss zone near the bottom of the well. Therefore, although the average formation pressure is higher than the dew point pressure during production, the increased pressure drop near the bottom of the well results in the bottom-hole flowing pressure being lower than the dew point pressure, causing condensate oil to still precipitate from the reservoir and accumulate near the bottom of the well, forming a highly saturated condensate oil zone. This zone is characterized by: lower pressure, higher condensate oil saturation, higher interfacial tension, and higher flow velocity. Figure 2 and Figure 3 The diagrams show the changes in pressure and saturation during the condensate gas seepage process. In the diagrams, 'r' represents the radius; a smaller radius indicates the direction closer to the wellbore. Figure 2 It can be seen that there is a pressure drop funnel near the bottom of the well, and the pressure drop becomes more significant once the pressure falls below the dew point pressure; from Figure 3 It can be seen that the condensate oil saturation near the bottom of the well is much higher than that in the middle of the formation, and the high condensate oil saturation will cause the condensate gas seepage to exhibit some characteristics that are different from those of dry gas seepage.

[0008] Therefore, the near-wellbore zone acts as a bottleneck in the seepage process, and changes in the seepage state and oil and gas distribution are all due to its influence. In the near-wellbore region, the changes in condensate oil saturation and the relative permeability of the condensate oil and gas phases are more drastic than in the middle and far reaches of the formation, causing a qualitative change in the overall seepage dynamics. Therefore, a thorough understanding of the seepage characteristics in the near-wellbore zone and a comprehensive consideration of the influence of high-speed near-wellbore flow on the well test response in determining the pseudo-pressure of horizontal well reverse condensate multiphase flow in condensate gas reservoirs are crucial for the correct analysis of the seepage dynamics of condensate gas reservoirs.

[0009] In view of the above problems, the present invention proposes a method and apparatus for determining the pseudo-pressure of reverse condensate multiphase flow in horizontal wells of condensate gas reservoirs in order to overcome or at least partially solve the above problems.

[0010] This invention provides a method for determining the pseudo-pressure of reverse condensate multiphase flow in horizontal wells of condensate gas reservoirs, including:

[0011] Based on the well fluid composition data of horizontal wells in condensate gas reservoirs, the relative permeability of the gas phase and the relative permeability of the oil phase under different pressures were determined; based on the phase permeability curves of horizontal wells in condensate gas reservoirs, the relative permeability of the gas phase under bound water saturation was determined.

[0012] Based on the capillary number effect and high-speed non-Darcy effect generated by the seepage velocity of condensate gas in the condensate gas well, the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation are corrected.

[0013] The pseudo-pressure of the three zones of the condensate gas well is determined using a three-zone pseudo-pressure equation based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation. The three zones include an oil-gas two-phase flow zone, a condensate oil non-flow zone, and a single-phase gas flow zone.

[0014] In some optional embodiments, determining the relative permeability of the gas phase and the relative permeability of the oil phase at different pressures based on well fluid composition data from horizontal wells in condensate gas reservoirs includes:

[0015] Based on the well fluid composition data of condensate gas wells, the first relationship expression of the ratio of oil phase relative permeability to gas phase relative permeability under different pressures is determined by the phase equilibrium calculation model.

[0016] Based on the relative permeability curves of the condensate gas wells, a second relationship between oil phase relative permeability and oil saturation and a third relationship between gas phase relative permeability and oil saturation were obtained by fitting the curves.

[0017] A fourth relationship between pressure and oil saturation is determined based on the first, second, and third relationship expressions.

[0018] The fifth relationship between pressure and relative permeability in the gas phase is determined based on the second and fourth relationship expressions.

[0019] The sixth relation expression is determined based on the third and fourth relation expressions.

[0020] In some optional embodiments, the first relationship expression for determining the ratio of oil phase relative permeability to gas phase relative permeability at different pressures based on the well fluid composition data of the condensate gas well according to the phase equilibrium calculation model includes:

[0021] The density and viscosity of the oil and gas phases under different pressures were determined based on the well fluid composition data of the condensate gas well.

[0022] Based on the density and viscosity of the oil and gas phases under different pressures, a first relationship expression is determined for the ratio of the relative permeability of the oil phase to the relative permeability of the gas phase under different pressures.

[0023] In some optional embodiments, determining the density and viscosity of the oil and gas two phases at different pressures based on the well fluid composition data of the condensate gas well includes:

[0024] Based on the well fluid composition data of the condensate gas well, the mass and compressibility factor of the oil and gas two phases are determined according to the flash calculation method.

[0025] Based on the mass and compressibility factor of the oil and gas two phases, the density of the oil and gas two phases is determined using the following equation of state:

[0026]

[0027] Where, ρ g Where m is the gas phase density. V Let P be the mass of the gas phase, R be the pressure, R be the ideal gas constant, T be the thermodynamic temperature, and Z be the mass of the gas phase. V It is the gas phase compressibility factor;

[0028] ρ o Let m be the density of the oil phase. L For oil phase quality, Z L Oil phase compressibility factor;

[0029] The viscosity of the oil and gas phases is determined using the following formula:

[0030]

[0031] Where, μ g The viscosity of the gas phase;

[0032] μ o The viscosity is the viscosity of the oil phase.

[0033] In some optional embodiments, the first relationship expression for determining the ratio of the relative permeability of the oil phase to the relative permeability of the gas phase at different pressures, based on the density and viscosity of the oil and gas phases at different pressures, includes:

[0034] Based on the density, viscosity, and mole fraction of the oil and gas phases under different pressures, the first relationship between the ratio of relative permeability of the oil phase to the relative permeability of the gas phase under different pressures is determined using the following steady-state theoretical formula:

[0035]

[0036] Among them, K ro K represents the relative permeability of the oil phase. rg The relative permeability of the gas phase.

[0037] ρ o Let ρ be the density of the oil phase. g The density of the gas phase.

[0038] V o L is the mole fraction of the oil phase. g This represents the mole fraction of the gas phase.

[0039] In some optional embodiments, the correction of the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation based on the capillary number effect and high-velocity non-Darcy effect generated by the seepage velocity of condensate gas in the condensate gas well includes:

[0040] Based on the Corey relative permeability function or interpolation function, the gas phase relative permeability under different pressures and the gas phase relative permeability under the bound water saturation are corrected to obtain the first gas phase relative permeability correction data and the second gas phase relative permeability correction data under the capillary number effect.

[0041] The first correction coefficient for high-speed non-Darcy effect is obtained based on the non-Darcy factor formula and the relative permeability of the gas phase under different pressures; the second correction coefficient for high-speed non-Darcy effect is obtained based on the non-Darcy factor formula and the relative permeability of the gas phase under the bound water saturation.

[0042] Based on the first gas phase relative permeability correction data and the first correction coefficient, the corrected gas phase relative permeability under different pressures under the coupling effect is determined; based on the second gas phase relative permeability correction data and the second correction coefficient, the corrected gas phase relative permeability under the bound water saturation under the coupling effect is determined.

[0043] In some optional embodiments, the step of correcting the gas-phase relative permeability under different pressures and the gas-phase relative permeability under the bound water saturation based on the Corey relative permeability function to obtain first and second gas-phase relative permeability correction data under the capillary number effect includes:

[0044] The number of capillaries is determined using the following formula:

[0045]

[0046] Among them, v g Let μ be the gas percolation velocity. g Where is the gas phase viscosity, σ is the oil-gas interfacial tension, and N is the gas phase viscosity. c Capillary number;

[0047] Based on the relative permeability of the gas phase and the capillary number, the corrected data for the relative permeability of the gas phase under the capillary number effect is determined using the following formula:

[0048]

[0049] Among them, S g For gas phase saturation, N c S is the number of capillaries. rg This represents the residual saturation of the gas phase.

[0050] ng The Corey index, with a value between 0 and 1;

[0051] If K rg * K represents the relative permeability of the gas phase under different pressures. rg (S g N c This indicates the corrected relative permeability data of the first gas phase under the capillary number effect;

[0052] If K rg * K represents the relative permeability of the gas phase at bound water saturation. rg (S g N c The ) represents the corrected data for the relative permeability of the second gas phase under the capillary number effect.

[0053] In some optional embodiments, the step of correcting the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation based on the interpolation function to obtain the first and second corrected relative permeability data under the capillary number effect includes:

[0054] The number of capillaries is determined using the following formula:

[0055]

[0056] Among them, v g Let μ be the gas percolation velocity. g σ is the gas viscosity, Nc is the oil-gas interfacial tension, and Nc is the capillary number.

[0057] Based on the relative permeability of the gas phase and the capillary number, the corrected data for the relative permeability of the gas phase under the capillary number effect is determined using the following formula:

[0058] k rα (S g N c )=f g (N c )k rg(base) +[1-f g (N c )]k rg(misc)

[0059] Among them, S g For gas phase saturation, N c Capillary number;

[0060] f g (N c ) is a correction factor, whose value is between 0 and 1;

[0061] krg(misc) This represents the relative permeability of the gas phase at a high capillary number.

[0062] If k rg(base) k represents the relative permeability of the gas phase under different pressures. ra (S g N c This indicates the corrected relative permeability data of the first gas phase under the capillary number effect;

[0063] If k rg(base) k represents the relative permeability of the gas phase at bound water saturation. ra (S g N c The ) represents the corrected data for the relative permeability of the second gas phase under the capillary number effect.

[0064] In some optional embodiments, the first correction coefficient for high-speed non-Darcy effect is obtained based on the non-Darcy factor formula and the relative permeability of the gas phase under different pressures; the second correction coefficient for high-speed non-Darcy effect is obtained based on the non-Darcy factor formula and the relative permeability of the gas phase under the bound water saturation, including:

[0065] The correction factor for high-speed non-Darcy effect is determined using the following formula:

[0066]

[0067] Where μ is the gas phase viscosity, ρ is the gas phase density, v is the seepage velocity, and β is the gas phase viscosity. * This is the gas phase turbulence coefficient;

[0068] If k is the relative permeability of the gas phase under different pressures, F ND This represents the first correction factor under high-speed non-Darcy effect conditions;

[0069] If k is the relative permeability of the gas phase under bound water saturation, F ND This represents the second correction factor under high-speed non-Darcy effect conditions.

[0070] In some optional embodiments, determining the corrected relative permeability of the gas phase at different pressures under the coupling effect based on the first corrected relative permeability data and the first correction coefficient; and determining the corrected relative permeability of the gas phase under the bound water saturation under the coupling effect based on the second corrected relative permeability data and the second correction coefficient, includes:

[0071] Based on the corrected gas-phase relative permeability data and correction coefficients, the corrected gas-phase relative permeability under the coupling effect is determined using the following formula:

[0072]

[0073] If FND k is the first correction factor. rx For the first gas phase relative permeability correction data, then The corrected relative permeability of the gas phase under different pressures due to the coupling effect;

[0074] If F ND k is the second correction factor. rx For the corrected relative permeability data of the second gas phase, then This represents the corrected relative gas-phase permeability under the bound water saturation due to the coupling effect.

[0075] In some optional embodiments, the determination of the pseudo-pressure of the three zones of the condensate gas well using a three-zone pseudo-pressure equation based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation includes:

[0076] Substituting the densities and viscosities of the oil and gas phases, the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation into the three-zone pseudo-pressure equation, where:

[0077] The pseudo-pressure equation for the oil-gas two-phase flow region is:

[0078]

[0079] Among them, P wf ρ is the bottom hole flowing pressure in the oil-gas two-phase flow region, and p is the critical pressure between the oil-gas two-phase flow region and the non-flowing condensate oil region.

[0080] The pseudo-pressure equation for the non-flowing region of condensate oil is:

[0081]

[0082] Among them, P wf ρ is the bottom hole flowing pressure in the oil-gas two-phase flow region, p* is the critical pressure between the oil-gas two-phase flow region and the condensate non-flow region, and p is the critical pressure between the condensate non-flow region and the single-phase gas flow region.

[0083] The pseudo-pressure equation for the single-phase gas flow region is:

[0084]

[0085] Where, k rg (S wi P represents the corrected relative permeability of the gas phase at bound water saturation. wfP is the bottomhole flowing pressure in the oil-gas two-phase flow region, p* is the critical pressure between the oil-gas two-phase flow region and the condensate non-flow region, and P is the bottomhole flowing pressure in the oil-gas two-phase flow region. dew is the critical pressure between the non-flowing region of condensate oil and the single-phase gas flow region, and p is the far-well pressure of the single-phase gas flow region.

[0086] In the pseudo-pressure equations of the above three regions, K ro K represents the relative permeability of the oil phase under different pressures. rg This represents the corrected relative permeability of the gas phase under different pressures.

[0087] ρ o Let ρ be the density of the oil phase. g The density of the gas phase.

[0088] μ g Let μ be the viscosity of the gas phase. o The viscosity is the viscosity of the oil phase.

[0089] This invention also provides a device for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir, comprising:

[0090] The relative permeability determination unit is used to determine the relative permeability of the gas phase and the relative permeability of the oil phase under different pressures based on the well fluid composition data of horizontal wells in condensate gas reservoirs; and to determine the relative permeability of the gas phase under bound water saturation based on the relative permeability curves of horizontal wells in condensate gas reservoirs.

[0091] A gas phase relative permeability correction unit is used to correct the gas phase relative permeability under different pressures and the gas phase relative permeability under the bound water saturation based on the capillary number effect and high-speed non-Darcy effect generated by the seepage velocity of condensate gas in the condensate gas well.

[0092] The pseudo-pressure determination unit determines the pseudo-pressure of the three zones of the condensate gas well based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under the bound water saturation using a three-zone pseudo-pressure equation. The three zones include the oil-gas two-phase flow zone, the condensate oil non-flow zone, and the single-phase gas flow zone.

[0093] This invention also provides a computer storage medium storing computer-executable instructions, which, when executed by a processor, implement the aforementioned method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir.

[0094] This invention also provides a computer device, including: a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, it implements the above-described method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir.

[0095] This invention also provides a computer program product, which includes a computer program that, when executed by a processor, implements the above-described method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir.

[0096] The beneficial effects of the above-mentioned technical solutions provided by the embodiments of the present invention include at least the following: based on the capillary number effect and high-speed non-Darcy effect generated by the seepage velocity of condensate gas in condensate gas wells, the relative permeability of the gas phase under different predetermined pressures and the relative permeability of the gas phase under the bound water saturation are corrected, the influence of the high-speed flow effect in the near-wellbore area of ​​the actual condensate gas reservoir on the seepage state of the entire gas reservoir is considered, and the influence of the capillary number effect and the high-speed non-Darcy effect on the relative permeability of the gas phase is comprehensively considered, and further, a more accurate data basis is provided for the determination of the pseudo-pressure;

[0097] Based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation, the pseudo-pressure of the three zones of the condensate gas well is determined using a three-zone pseudo-pressure equation. This method is applicable to the pseudo-pressure calculation of horizontal wells in condensate gas reservoirs under multiphase flow characteristics that fully consider the influence of near-wellbore high-velocity effects, and provides a necessary basis for subsequent production capacity evaluation and rational and efficient development of condensate gas reservoirs.

[0098] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the written description, claims, and drawings.

[0099] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Attached Figure Description

[0100] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0101] Figure 1 Distribution diagram of hydrocarbon distribution principle and flow characteristics in three main condensate gas reservoirs;

[0102] Figure 2 This is a schematic diagram showing the changes in pressure and saturation during the seepage of condensate gas.

[0103] Figure 3 This is a schematic diagram showing the change in saturation during the seepage of condensate gas.

[0104] Figure 4This is a flowchart of the method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir according to Embodiment 1 of the present invention;

[0105] Figure 5 This is a schematic diagram of the velocity stripping effect coupling analysis caused by high-speed flow in Embodiment 1 of the present invention;

[0106] Figure 6 This is a flowchart of the method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir in Embodiment 2 of the present invention;

[0107] Figure 7 This is a schematic diagram showing the density changes of the oil and gas two phases under different pressures in Embodiment 1 of the present invention.

[0108] Figure 8 This is a schematic diagram showing the viscosity data changes of the oil and gas phases under different pressures in Embodiment 1 of the present invention.

[0109] Figure 9 This is a schematic diagram showing the change in the ratio of relative permeability of the oil phase to the relative permeability of the gas phase under different pressures in Embodiment 1 of the present invention.

[0110] Figure 10 The data are the relative permeability of the oil phase and the relative permeability of the gas phase at different oil saturation levels in Embodiment 2 of the present invention.

[0111] Figure 11 This illustrates the effect of velocity on the relative permeability of the gas phase under different conditions in Embodiment 2 of the present invention.

[0112] Figure 12 This illustrates the effect of velocity on pseudo-pressure under different conditions in Embodiment 2 of the present invention.

[0113] Figure 13 This is a schematic diagram of the structure of the pseudo-pressure determination device for anti-condensate multiphase flow in a horizontal well of a condensate gas reservoir in an embodiment of the present invention. Detailed Implementation

[0114] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0115] To address the problem in existing technologies where the determination of pseudo-pressure in horizontal wells of condensate gas reservoirs using reverse condensate multiphase flow fails to consider the capillary number effect and high-velocity non-Darcy effect generated by condensate gas seepage velocity on the relative permeability of the gas phase, thus making it impossible to accurately determine the pseudo-pressure, this invention provides a method for determining pseudo-pressure in horizontal wells of condensate gas reservoirs using reverse condensate multiphase flow. This method is applicable to pseudo-pressure calculations under the multiphase flow characteristics of horizontal wells in condensate gas reservoirs that fully consider the influence of near-wellbore high-velocity effects, providing a necessary basis for targeted evaluation of condensate gas reservoir productivity.

[0116] Example 1

[0117] This invention provides a method for determining the pseudo-pressure of reverse condensate multiphase flow in horizontal wells of condensate gas reservoirs, the process of which is as follows: Figure 4 As shown, it includes the following steps:

[0118] Step S101: Determine the relative permeability of the gas phase and the relative permeability of the oil phase under different pressures based on the well fluid composition data of the horizontal well in the condensate gas reservoir; determine the relative permeability of the gas phase under the bound water saturation based on the relative permeability curve of the horizontal well in the condensate gas reservoir.

[0119] Step S102: Based on the capillary number effect and high-speed non-Darcy effect generated by the seepage velocity of condensate gas in the condensate gas well, the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation are corrected.

[0120] Step S103: Based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation, the pseudo-pressure of the three zones of the condensate gas well is determined using the three-zone pseudo-pressure equation. The three zones include the oil-gas two-phase flow zone, the condensate oil non-flow zone, and the single-phase gas flow zone.

[0121] In some optional embodiments, step S101 determines the relative permeability of the gas phase and the relative permeability of the oil phase under different pressures based on the well fluid composition data of the horizontal well in the condensate gas reservoir, including:

[0122] 1) Based on the well fluid composition data of condensate gas wells, the first relationship expression of the ratio of oil phase relative permeability to gas phase relative permeability under different pressures is determined by the phase equilibrium calculation model.

[0123] The two-phase flow of oil and gas in condensate gas reservoirs is described by a phase equilibrium calculation model. This step includes: S1: Determining the density and viscosity of the two-phase flow of oil and gas under different pressures based on the well fluid composition data of condensate gas wells;

[0124] Based on the well fluid composition data of condensate gas wells, the mass and compressibility factor of the oil and gas two phases are determined by flash evaporation calculation method; specifically, the mole fraction, molar composition, molar density and compressibility factor of the oil and gas two phases are obtained by flash evaporation calculation method, and the mass of the oil and gas two phases is determined based on the mole fraction, molar composition and molar density of the oil and gas two phases.

[0125] Based on the mass and compressibility factor of the oil and gas two phases, the density of the oil and gas two phases is determined using the following equation of state:

[0126]

[0127] Where, ρ g Where m is the gas phase density. V Let P be the mass of the gas phase, R be the pressure, R be the ideal gas constant, T be the thermodynamic temperature, and Z be the mass of the gas phase. V It is the gas phase compressibility factor;

[0128] ρ o Let m be the density of the oil phase. L For oil phase quality, Z L R is the oil phase compressibility factor, and R is the ideal liquid constant.

[0129] The gas phase viscosity is determined using the following natural gas viscosity formula:

[0130]

[0131] Where, μ g The viscosity of the gas phase;

[0132] The oil phase viscosity is determined using the following crude oil viscosity formula:

[0133]

[0134] Where, μ o The viscosity is the viscosity of the oil phase.

[0135] S2: Based on the density and viscosity of the oil and gas phases under different pressures, determine the first relationship expression of the ratio of the relative permeability of the oil phase to the relative permeability of the gas phase under different pressures.

[0136] Based on the density, viscosity, and mole fraction of the oil and gas phases under different pressures, the first relationship between the ratio of relative permeability of the oil phase to the relative permeability of the gas phase under different pressures is determined using the following steady-state theoretical formula:

[0137]

[0138] Among them, K ro K represents the relative permeability of the oil phase. rg The relative permeability of the gas phase.

[0139] ρ o Let ρ be the density of the oil phase. g The density of the gas phase.

[0140] V o L is the mole fraction of the oil phase. g This represents the mole fraction of the gas phase.

[0141] 2) Based on the relative permeability curves of condensate gas wells, the second relationship between oil phase relative permeability and oil saturation and the third relationship between gas phase relative permeability and oil saturation were obtained by fitting the curves respectively.

[0142] Based on core experimental data, a second relationship between relative permeability of the oil phase and oil saturation, and a third relationship between relative permeability of the gas phase and oil saturation can be obtained by fitting.

[0143] 3) Based on the first, second, and third relational expressions, a fourth relational expression between pressure and oil saturation is determined; subsequently, a fifth relational expression between pressure and relative gas phase permeability, and a sixth relational expression between pressure and relative oil phase permeability are obtained. To more clearly illustrate the conversion relationships between these expressions, the following description uses p to represent pressure and K... ro K represents the relative permeability of the oil phase. rg S represents the relative permeability of the gas phase. o This indicates that it contains saturation:

[0144] Based on the above-determined p and The first relation expression, K ro With S o The second relation expression, K rg With S o The third relation expression can be fitted to obtain p and S o The fourth relation expression; based on p and S o The fourth relation expression and K rg With S o The third relation expression can be fitted to obtain p and K rg The fifth relation expression; based on p and S o The fourth relation expression and K ro With S o The second relation expression can be fitted to obtain p and K ro The sixth relation is expressed.

[0145] In some optional embodiments, step S101 determines the relative permeability of the gas phase under bound water saturation based on the relative permeability curve of the horizontal well in the condensate gas reservoir. Specifically, the relationship between bound water saturation and relative permeability of the gas phase is fitted based on the core experimental data of the horizontal well in the condensate gas reservoir.

[0146] In some optional embodiments, step S102 corrects the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation based on the capillary number effect and the high-velocity non-Darcy effect generated by the seepage velocity of the condensate gas in the condensate gas well, including:

[0147] High-speed flow near the wellbore of condensate gas creates both a capillary number effect and turbulent flow, manifesting as a high-speed non-Darcy effect. These two effects have opposite effects on the relative permeability of the gas phase: the high capillary number effect increases relative permeability (a "positive effect"), while the non-Darcy effect decreases relative permeability (a "negative effect"). These two effects are not independent but coupled. Figure 5 The figure shows a coupled analysis of the velocity stripping effect caused by high-speed flow. Therefore, it is necessary to correct the relative permeability of the gas phase based on the capillary number effect and the high-speed non-Darcy effect.

[0148] Specifically, 1) Based on the Corey relative permeability function or interpolation function, the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation are corrected to obtain the first and second corrected data of the relative permeability of the gas phase under the capillary number effect.

[0149] The capillary number is the ratio of viscous force to surface tension, and is determined using the following formula:

[0150]

[0151] Among them, v g Let μ be the gas percolation velocity. g Where is the gas phase viscosity, σ is the oil-gas interfacial tension, and N is the gas phase viscosity. c Capillary number;

[0152] As defined, capillary number reflects the combined effects of velocity, viscosity, and interfacial tension. The capillary number effect on condensate gas-liquid two-phase flow is primarily reflected in the change in relative permeability of the gas phase. This significant influence necessitates a complete departure between conventional methods and the flow models and relative permeability calculation methods. Representative models and methods can be categorized into two types:

[0153] The first type is the relative permeability function that considers the number of capillaries, namely the Corey relative permeability function. Based on the relative permeability of the gas phase and the number of capillaries, the corrected data for the relative permeability of the gas phase under the capillary number effect is determined by the following formula:

[0154]

[0155] Among them, S g For gas phase saturation, N cS is the number of capillaries. rg This represents the residual saturation of the gas phase.

[0156] n g The Corey index, with a value between 0 and 1;

[0157] If K rg * K represents the relative permeability of the gas phase under different pressures. rg (S g N c This indicates the corrected relative permeability data of the first gas phase under the capillary number effect;

[0158] If K rg * K represents the relative permeability of the gas phase at bound water saturation. rg (S g N c The ) represents the corrected data for the relative permeability of the second gas phase under the capillary number effect.

[0159] The second category involves determining the corrected gas-phase relative permeability data under the capillary number effect using the following interpolation function based on gas-phase relative permeability and capillary number:

[0160] k rα (S g N c )=f g (N c )k rg(base) +[1-f g (N c )]k rg(misc)

[0161] Among them, S g For gas phase saturation, N c Capillary number;

[0162] f g (N c ) is a correction factor, whose value is between 0 and 1;

[0163] k rg(misc) This represents the relative permeability of the gas phase under high capillary number conditions, measured through core displacement experiments.

[0164] If k rg(base) k represents the relative permeability of the gas phase under different pressures. ra (S g N c This indicates the corrected relative permeability data of the first gas phase under the capillary number effect;

[0165] If k rg(base) k represents the relative permeability of the gas phase at bound water saturation.ra (S g N c The ) represents the corrected data for the relative permeability of the second gas phase under the capillary number effect.

[0166] 2) Based on the non-Darcy factor formula and the relative permeability of the gas phase under different pressures, the first correction coefficient under the high-speed non-Darcy effect is obtained; based on the non-Darcy factor formula and the relative permeability of the gas phase under the bound water saturation, the second correction coefficient under the high-speed non-Darcy effect is obtained.

[0167] To reflect the impact of the high-speed non-Darcy effect on the two-phase flow of oil and gas, it is necessary to correlate it with the flow velocity and permeability. A growth factor is used to simulate the effect of the non-Darcy effect, and the correction coefficient under the high-speed non-Darcy effect is determined using the following formula:

[0168]

[0169] Where μ is the gas phase viscosity, ρ is the gas phase density, v is the seepage velocity, and β is the gas phase viscosity. * This is the gas phase turbulence coefficient;

[0170] If k is the relative permeability of the gas phase under different pressures, F ND This represents the first correction factor under high-speed non-Darcy effect conditions;

[0171] If k is the relative permeability of the gas phase under bound water saturation, F ND This represents the second correction factor under high-speed non-Darcy effect conditions.

[0172] 3) Determine the corrected relative permeability of the gas phase under different pressures based on the first corrected relative permeability data of the gas phase and the first correction coefficient; determine the corrected relative permeability of the gas phase under the bound water saturation under the coupling effect based on the second corrected relative permeability data of the gas phase and the second correction coefficient.

[0173] The influence of gas-phase relative permeability should be considered in conjunction with the combined effects of capillary number effect and non-Darcy effect, and a gas-phase relative permeability value that takes into account coupling effect should be introduced. The corrected relative permeability of the gas phase under coupling effect is determined using the following formula:

[0174]

[0175] Where, if F ND k is the first correction factor. rx For the first gas phase relative permeability correction data, then The corrected relative permeability of the gas phase under different pressures due to the coupling effect;

[0176] If F NDk is the second correction factor. rx For the corrected relative permeability data of the second gas phase, then This represents the corrected relative gas-phase permeability under the bound water saturation due to the coupling effect.

[0177] In some optional embodiments, step S103, which determines the pseudo-pressure of the three zones of the condensate gas well using a three-zone pseudo-pressure equation based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation, includes:

[0178] Substituting the densities and viscosities of the oil and gas phases, the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation into the three-zone pseudo-pressure equation, where:

[0179] The pseudo-pressure equation for the oil-gas two-phase flow region is:

[0180]

[0181] Among them, P wf ρ is the bottom hole flowing pressure in the oil-gas two-phase flow region, and p is the critical pressure between the oil-gas two-phase flow region and the non-flowing condensate oil region.

[0182] The pseudo-pressure equation for the non-flowing region of condensate oil is:

[0183]

[0184] Among them, P wf ρ is the bottom hole flowing pressure in the oil-gas two-phase flow region, p* is the critical pressure between the oil-gas two-phase flow region and the condensate non-flow region, and p is the critical pressure between the condensate non-flow region and the single-phase gas flow region.

[0185] The pseudo-pressure equation for the single-phase gas flow region is:

[0186]

[0187] Where, k rg (S wi P represents the corrected relative gas-phase permeability under bound water saturation due to the coupling effect; wf P is the bottomhole flowing pressure in the oil-gas two-phase flow region, p* is the critical pressure between the oil-gas two-phase flow region and the condensate non-flow region, and P is the bottomhole flowing pressure in the oil-gas two-phase flow region. dew is the critical pressure between the non-flowing region of condensate oil and the single-phase gas flow region, and p is the far-well pressure of the single-phase gas flow region.

[0188] In the pseudo-pressure equations of the above three regions, K roK represents the relative permeability of the oil phase under different pressures. rg The corrected relative permeability of the gas phase under different pressures due to the coupling effect.

[0189] ρ o Let ρ be the density of the oil phase. g The density of the gas phase.

[0190] μ g Let μ be the viscosity of the gas phase. o The viscosity is the viscosity of the oil phase.

[0191] In the method described in this embodiment, the effects of the capillary number effect and the high-velocity non-Darcy effect caused by the condensate gas seepage velocity on the relative permeability of the gas phase are considered, and the relative permeability of the gas phase is corrected, thereby comprehensively considering the impact of the high-velocity effect in the near-wellbore area on the seepage dynamics of the entire condensate gas reservoir. Then, the two-phase pseudo-pressure function considering the high-velocity effect is obtained by numerical integration method, which solves the problem that the existing pseudo-pressure calculation method does not fully consider the impact of near-wellbore high-velocity flow on well test response, and provides data support and necessary basis for subsequent production capacity evaluation and rational and efficient development of condensate gas reservoirs.

[0192] Example 2

[0193] Embodiment 2 of the present invention provides a process for determining the pseudo-pressure of reverse condensation multiphase flow based on an actual gas reservoir, the process is as follows: Figure 6 The above includes:

[0194] Step S201: Determine the density and viscosity of the oil and gas two phases under different pressures based on the well fluid composition data of the condensate gas well. For example... Figure 7 The figure shows the density data of the oil and gas two phases under different pressures. Figure 8 Viscosity data for the oil and gas phases under different pressures;

[0195] Step S202: Based on the density and viscosity of the oil and gas phases under different pressures, determine the first relationship expression for the ratio of the relative permeability of the oil phase to the relative permeability of the gas phase under different pressures. For example... Figure 9 The figure shows the ratio of relative permeability of the oil phase to the relative permeability of the gas phase under different pressures.

[0196] Step S203: Based on the relative permeability curves of condensate gas wells, the second relationship between oil phase relative permeability and oil saturation, and the third relationship between gas phase relative permeability and oil saturation are obtained by fitting the curves respectively. For example... Figure 10 The figure shows the relative permeability data of the oil phase and the relative permeability data of the gas phase at different oil saturation levels. K in the figure... ro K represents the relative permeability of the oil phase. rg S represents the relative permeability of the gas phase. o This indicates that it contains saturation;

[0197] Step S204: Based on the above relationship expressions, determine the fifth relationship expression between pressure and relative permeability of the gas phase, and the sixth relationship expression between pressure and relative permeability of the oil phase;

[0198] Step S205: Determine the relative permeability of the gas phase under bound water saturation based on the relative permeability curve of the horizontal well in the condensate gas reservoir;

[0199] Step S206: Based on the Corey relative permeability function or interpolation function, correct the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under bound water saturation to determine the corrected data of the relative permeability of the gas phase under the capillary number effect; the specific operation is the same as step S102 in Example 1, and will not be repeated here.

[0200] Step S207: Determine the correction coefficients for the relative permeability of the gas phase under different pressures under high-speed non-Darcy effect, and the correction coefficients for the relative permeability of the gas phase under the bound water saturation under high-speed non-Darcy effect, based on the non-Darcy factor formula; the specific operation is as described in step S102 of Example 1, and will not be repeated here.

[0201] Step S208: Based on the corrected gas-phase relative permeability data under the capillary number effect and the correction coefficient under the high-speed non-Darcy effect, determine the corrected gas-phase relative permeability under different pressures under the coupling effect, and the corrected gas-phase relative permeability under the bound water saturation under the coupling effect; such as Figure 11 The figure shows the effect of velocity on the relative permeability of the gas phase under different pressures, under the original condition, under the condition of only considering the capillary number effect, and under the condition of comprehensively considering the capillary number effect and the high-speed non-Darcy effect. It can be seen that under the condition of comprehensively considering the capillary number effect and the non-Darcy effect, the relative permeability of the gas phase is higher than the relative permeability value without considering the coupling effect, but lower than the relative permeability value under the condition of only considering the capillary number effect.

[0202] Step S209: Based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures due to the coupling effect, and the corrected relative permeability of the gas phase under the bound water saturation due to the coupling effect, the pseudo-pressure of the three zones of the condensate gas well is determined using a three-zone pseudo-pressure equation. For example... Figure 12 The figure shows the effect of velocity on pseudo-pressure under the original condition, considering only the capillary number effect, and considering both the capillary number effect and the high-speed non-Darcy effect. It can be seen that under the condition of considering both the capillary number effect and the non-Darcy effect, the pseudo-pressure value is higher than the phase permeability value without considering the coupling effect, but lower than the phase permeability value under the condition of considering only the capillary number effect.

[0203] In the above method of this embodiment, the capillary number effect and non-Darcy effect are first considered to correct the relative permeability of the gas phase, so as to comprehensively analyze the multiphase flow characteristics. Then, the two-phase pseudo-pressure function considering the high-velocity effect is obtained by numerical integration method. For the anti-condensate multiphase flow of horizontal wells in actual condensate gas reservoirs, this method is more accurate. This method has a wide range of application prospects in determining the pseudo-pressure calculation of anti-condensate multiphase flow in horizontal wells of condensate gas reservoirs, and has strong reference significance for subsequent production capacity evaluation of condensate gas reservoirs.

[0204] Based on the same inventive concept, embodiments of the present invention also provide a device for determining the pseudo-pressure of reverse condensate multiphase flow in horizontal wells of condensate gas reservoirs. This device can be installed in a computer device with data processing capabilities, and its structure is as follows: Figure 13 As shown, it includes: a relative permeability determination unit 10, a gas phase relative permeability correction unit 20, and a pseudo-pressure determination unit 30.

[0205] The relative permeability determination unit 10 is used to determine the relative permeability of the gas phase and the relative permeability of the oil phase under different pressures based on the well fluid composition data of horizontal wells in condensate gas reservoirs; and to determine the relative permeability of the gas phase under the bound water saturation based on the relative permeability curves of horizontal wells in condensate gas reservoirs.

[0206] The gas phase relative permeability correction unit 20 is used to correct the gas phase relative permeability under different pressures and the gas phase relative permeability under the bound water saturation based on the capillary number effect and high-speed non-Darcy effect generated by the seepage velocity of condensate gas in the condensate gas well.

[0207] The pseudo-pressure determination unit 30 determines the pseudo-pressure of the three zones of the condensate gas well based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under the bound water saturation.

[0208] This invention also provides a computer storage medium storing computer-executable instructions, which, when executed by a processor, implement the aforementioned method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir.

[0209] This invention also provides a computer device, including: a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, it implements the above-described method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir.

[0210] This invention also provides a computer program product, which includes a computer program that, when executed by a processor, implements the above-described method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir.

[0211] Regarding the condensate gas reservoir horizontal well reverse condensate multiphase flow pseudo-pressure determination device in the above embodiments, the specific operation of each module has been described in detail in the embodiments of the relevant method, and will not be elaborated here.

[0212] It should be understood that the specific order or hierarchy of steps in the disclosed process is an example of an exemplary method. Based on design preferences, it should be understood that the specific order or hierarchy of steps in the process may be rearranged without departing from the scope of this disclosure. The appended method claims provide elements of various steps in an exemplary order and are not intended to limit the specific order or hierarchy described.

[0213] In the detailed description above, various features are combined together in a single embodiment to simplify this disclosure. This approach to disclosure should not be construed as reflecting an intention that embodiments of the claimed subject matter require more features than are explicitly stated in each claim. Rather, as reflected in the appended claims, the invention is presented with fewer features than all of the features in a single disclosed embodiment. Therefore, the appended claims are hereby explicitly incorporated into the detailed description, with each claim representing a separate preferred embodiment of the invention.

[0214] Those skilled in the art will also understand that the various illustrative logic blocks, modules, circuits, and algorithm steps described in conjunction with the embodiments herein can be implemented as electronic hardware, computer software, or a combination thereof. To clearly illustrate the interchangeability between hardware and software, the various illustrative components, blocks, modules, circuits, and steps described above are generally described in terms of their functionality. Whether such functionality is implemented as hardware or software depends on the specific application and the design constraints imposed on the overall system. Those skilled in the art can implement the described functionality in alternative ways for each specific application; however, such implementation decisions should not be construed as departing from the scope of this disclosure.

[0215] The steps of the methods or algorithms described in conjunction with the embodiments herein can be directly embodied in hardware, software modules executed by a processor, or a combination thereof. The software modules can reside in RAM memory, flash memory, ROM memory, EPROM memory, EEPROM memory, registers, hard disks, removable disks, CD-ROMs, or any other form of storage medium well known in the art. An exemplary storage medium is connected to the processor, enabling the processor to read information from and write information to the storage medium. Of course, the storage medium can also be a component of the processor. The processor and storage medium can reside in an ASIC. The ASIC can reside in a user terminal. Alternatively, the processor and storage medium can exist as discrete components in the user terminal.

[0216] For software implementation, the techniques described in this application can be implemented using modules (e.g., procedures, functions, etc.) that perform the functions described in this application. This software code can be stored in memory units and executed by a processor. The memory units can be implemented within the processor or outside the processor; in the latter case, they are communicatively coupled to the processor via various means, as is well known in the art.

[0217] The foregoing description includes examples of one or more embodiments. It is certainly impossible to describe all possible combinations of components or methods in order to describe the above embodiments, but those skilled in the art will recognize that further combinations and arrangements of the various embodiments are possible. Therefore, the embodiments described herein are intended to cover all such changes, modifications, and variations that fall within the scope of the appended claims. Furthermore, the term "comprising" as used in the specification or claims is interpreted in a manner similar to the term "including," as interpreted when used as a conjunction in the claims. Additionally, the use of any term "or" in the specification of the claims is intended to mean "non-exclusive or."

Claims

1. A method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir, characterized in that, include: The relative permeability of the gas phase and the relative permeability of the oil phase under different pressures were determined based on the well fluid composition data of horizontal wells in condensate gas reservoirs. The relative permeability of the gas phase under bound water saturation was determined based on the relative permeability curves of horizontal wells in condensate gas reservoirs. Based on the capillary number effect and high-speed non-Darcy effect generated by the seepage velocity of condensate gas in the condensate gas well, the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation are corrected. The pseudo-pressure of the three zones of the condensate gas well is determined using a three-zone pseudo-pressure equation based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation. The three zones include an oil-gas two-phase flow zone, a condensate oil non-flow zone, and a single-phase gas flow zone.

2. The method as described in claim 1, characterized in that, The determination of relative permeability of the gas phase and relative permeability of the oil phase under different pressures based on well fluid composition data of horizontal wells in condensate gas reservoirs includes: Based on the well fluid composition data of condensate gas wells, the first relationship expression of the ratio of oil phase relative permeability to gas phase relative permeability under different pressures is determined by the phase equilibrium calculation model. Based on the relative permeability curves of the condensate gas wells, a second relationship between oil phase relative permeability and oil saturation and a third relationship between gas phase relative permeability and oil saturation were obtained by fitting the curves. A fourth relationship between pressure and oil saturation is determined based on the first, second, and third relationship expressions. The fifth relationship between pressure and relative permeability in the gas phase is determined based on the second and fourth relationship expressions. The sixth relation expression is determined based on the third and fourth relation expressions.

3. The method as described in claim 2, characterized in that, The first relationship expression, based on the well fluid composition data of the condensate gas well and determined by the phase equilibrium calculation model, regarding the ratio of oil phase relative permeability to gas phase relative permeability at different pressures, includes: The density and viscosity of the oil and gas phases under different pressures were determined based on the well fluid composition data of the condensate gas well. Based on the density and viscosity of the oil and gas phases under different pressures, a first relationship expression is determined for the ratio of the relative permeability of the oil phase to the relative permeability of the gas phase under different pressures.

4. The method as described in claim 3, characterized in that, The determination of the density and viscosity of the oil and gas two phases under different pressures based on the well fluid composition data of the condensate gas well includes: Based on the well fluid composition data of the condensate gas well, the mass and compressibility factor of the oil and gas two phases are determined according to the flash calculation method. Based on the mass and compressibility factor of the oil and gas two phases, the density of the oil and gas two phases is determined using the following equation of state: Where, ρ g Where m is the gas phase density. V Let P be the mass of the gas phase, R be the pressure, R be the ideal gas constant, T be the thermodynamic temperature, and Z be the mass of the gas phase. V It is the gas phase compressibility factor; ρ o Let m be the density of the oil phase. L For oil phase quality, Z L Oil phase compressibility factor; The viscosity of the oil and gas phases is determined using the following formula: Where, μ g The viscosity of the gas phase; μ o The viscosity is the viscosity of the oil phase.

5. The method as described in claim 3, characterized in that, The first relationship expression for determining the ratio of relative permeability of the oil phase to relative permeability of the gas phase under different pressures, based on the density and viscosity of the oil and gas phases at different pressures, includes: Based on the density, viscosity, and mole fraction of the oil and gas phases under different pressures, the first relationship between the ratio of relative permeability of the oil phase to the relative permeability of the gas phase under different pressures is determined using the following steady-state theoretical formula: Among them, K ro K represents the relative permeability of the oil phase. rg The relative permeability of the gas phase. ρ o Let ρ be the density of the oil phase. g The density of the gas phase. V o L is the mole fraction of the oil phase. g This represents the mole fraction of the gas phase.

6. The method as described in claim 1, characterized in that, The capillary number effect and high-velocity non-Darcy effect, based on the seepage velocity of condensate gas in the condensate gas well, are used to correct the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation, including: Based on the Corey relative permeability function or interpolation function, the gas phase relative permeability under different pressures and the gas phase relative permeability under the bound water saturation are corrected to obtain the first gas phase relative permeability correction data and the second gas phase relative permeability correction data under the capillary number effect. The first correction coefficient for high-speed non-Darcy effect is obtained based on the non-Darcy factor formula and the relative permeability of the gas phase under different pressures; the second correction coefficient for high-speed non-Darcy effect is obtained based on the non-Darcy factor formula and the relative permeability of the gas phase under the bound water saturation. Based on the first gas phase relative permeability correction data and the first correction coefficient, the corrected gas phase relative permeability under different pressures under the coupling effect is determined; based on the second gas phase relative permeability correction data and the second correction coefficient, the corrected gas phase relative permeability under the bound water saturation under the coupling effect is determined.

7. The method as described in claim 6, characterized in that, The correction of gas-phase relative permeability under different pressures and under bound water saturation based on the Corey relative permeability function yields first and second gas-phase relative permeability correction data under the capillary number effect, respectively, including: The number of capillaries is determined using the following formula: Among them, v g Let μ be the gas percolation velocity. g Where is the gas phase viscosity, σ is the oil-gas interfacial tension, and N is the gas phase viscosity. c Capillary number; Based on the relative permeability of the gas phase and the capillary number, the corrected data for the relative permeability of the gas phase under the capillary number effect is determined using the following formula: Among them, S g For gas phase saturation, N c S is the number of capillaries. rg This represents the residual saturation of the gas phase. n g The Corey index, with a value between 0 and 1; If K rg * K represents the relative permeability of the gas phase under different pressures. rg (S g N c This indicates the corrected relative permeability data of the first gas phase under the capillary number effect; If K rg * K represents the relative permeability of the gas phase at bound water saturation. rg (S g N c The ) represents the corrected data for the relative permeability of the second gas phase under the capillary number effect.

8. The method as described in claim 6, characterized in that, The process of correcting the relative permeability of the gas phase under different pressures and the relative permeability of the gas phase under the bound water saturation based on the interpolation function yields the first and second corrected relative permeability data under the capillary number effect, respectively, including: The number of capillaries is determined using the following formula: Among them, v g Let μ be the gas percolation velocity. g σ is the gas viscosity, Nc is the oil-gas interfacial tension, and Nc is the capillary number. Based on the relative permeability of the gas phase and the capillary number, the corrected data for the relative permeability of the gas phase under the capillary number effect is determined using the following formula: k rα (S g ,N c )=f g (N c )k rg(base) +[1-f g (N c )]k rg(misc) Among them, S g For gas phase saturation, N c Capillary number; f g (N c ) is a correction factor, whose value is between 0 and 1; k rg(misc) This represents the relative permeability of the gas phase at a high capillary number. If k rg(base) k represents the relative permeability of the gas phase under different pressures. ra (S g N c This indicates the corrected relative permeability data of the first gas phase under the capillary number effect; If k rg(base) k represents the relative permeability of the gas phase at bound water saturation. ra (S g N c The ) represents the corrected data for the relative permeability of the second gas phase under the capillary number effect.

9. The method as described in claim 6, characterized in that, The first correction coefficient under the high-speed non-Darcy effect is obtained based on the non-Darcy factor formula and the relative gas-phase permeability under different pressures. Based on the non-Darcy factor formula and the relative gas-phase permeability under the bound water saturation, a second correction coefficient for high-speed non-Darcy effect is obtained, including: The correction factor for high-speed non-Darcy effect is determined using the following formula: Where μ is the gas phase viscosity, ρ is the gas phase density, v is the seepage velocity, and β is the gas phase viscosity. * This is the gas phase turbulence coefficient; If k is the relative permeability of the gas phase under different pressures, F ND This represents the first correction factor under high-speed non-Darcy effect conditions; If k is the relative permeability of the gas phase under bound water saturation, F ND This represents the second correction factor under high-speed non-Darcy effect conditions.

10. The method as described in claim 6, characterized in that, The corrected relative permeability of the gas phase under different pressures is determined based on the first corrected relative permeability data of the gas phase and the first correction coefficient; Based on the second gas-phase relative permeability correction data and the second correction coefficient, the corrected gas-phase relative permeability under the bound water saturation under the coupling effect is determined, including: Based on the corrected gas-phase relative permeability data and correction coefficients, the corrected gas-phase relative permeability under the coupling effect is determined using the following formula: If F ND k is the first correction factor. rx For the first gas phase relative permeability correction data, then The corrected relative permeability of the gas phase under different pressures due to the coupling effect; If F ND k is the second correction factor. rx For the corrected relative permeability data of the second gas phase, then This represents the corrected relative gas-phase permeability under the bound water saturation due to the coupling effect.

11. The method as described in claim 1, characterized in that, The pseudo-pressure of the condensate gas well in the three zones is determined using a three-zone pseudo-pressure equation based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation. This includes: Substituting the densities and viscosities of the oil and gas phases, the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under bound water saturation into the three-zone pseudo-pressure equation, where: The pseudo-pressure equation for the oil-gas two-phase flow region is: Among them, P wf ρ is the bottom hole flowing pressure in the oil-gas two-phase flow region, and p is the critical pressure between the oil-gas two-phase flow region and the non-flowing condensate oil region. The pseudo-pressure equation for the non-flowing region of condensate oil is: Among them, P wf ρ is the bottom hole flowing pressure in the oil-gas two-phase flow region, p* is the critical pressure between the oil-gas two-phase flow region and the condensate non-flow region, and p is the critical pressure between the condensate non-flow region and the single-phase gas flow region. The pseudo-pressure equation for the single-phase gas flow region is: Where, k rg (S wi P represents the corrected relative permeability of the gas phase at bound water saturation. wf P is the bottomhole flowing pressure in the oil-gas two-phase flow region, p* is the critical pressure between the oil-gas two-phase flow region and the condensate non-flow region, and P is the bottomhole flowing pressure in the oil-gas two-phase flow region. dew is the critical pressure between the non-flowing region of condensate oil and the single-phase gas flow region, and p is the far-well pressure of the single-phase gas flow region. In the pseudo-pressure equations of the above three regions, K ro K represents the relative permeability of the oil phase under different pressures. rg This represents the corrected relative permeability of the gas phase under different pressures. ρ o Let ρ be the density of the oil phase. g The density of the gas phase. μ g Let μ be the viscosity of the gas phase. o The viscosity is the viscosity of the oil phase.

12. A device for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir, characterized in that, include: The relative permeability determination unit is used to determine the relative permeability of the gas phase and the relative permeability of the oil phase under different pressures based on the well fluid composition data of horizontal wells in condensate gas reservoirs. The relative permeability of the gas phase under bound water saturation was determined based on the relative permeability curves of horizontal wells in condensate gas reservoirs. A gas phase relative permeability correction unit is used to correct the gas phase relative permeability under different pressures and the gas phase relative permeability under the bound water saturation based on the capillary number effect and high-speed non-Darcy effect generated by the seepage velocity of condensate gas in the condensate gas well. The pseudo-pressure determination unit determines the pseudo-pressure of the three zones of the condensate gas well based on the relative permeability of the oil phase under different pressures, the corrected relative permeability of the gas phase under different pressures, and the corrected relative permeability of the gas phase under the bound water saturation using a three-zone pseudo-pressure equation. The three zones include the oil-gas two-phase flow zone, the condensate oil non-flow zone, and the single-phase gas flow zone.

13. A computer storage medium, characterized in that, The computer storage medium stores computer-executable instructions, which, when executed by a processor, implement the method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir as described in any one of claims 1-11.

14. A computer device, characterized in that, include: A memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor, when executing the program, implements the method for determining the pseudo-pressure of reverse condensate multiphase flow in a horizontal well of a condensate gas reservoir as described in any one of claims 1-11.

15. A computer program product, characterized in that, The computer program product includes a computer program that, when executed by a processor, implements the pseudo-pressure determination method for reverse condensate multiphase flow in horizontal wells of condensate gas reservoirs as described in any one of claims 1-11.

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