Method for determining water invasion stage of water production gas well and related device

Abstract

The invention discloses a method for determining a water invasion stage of a water production gas well and a related device. The method comprises the steps of determining the water saturation of a reservoir where the water-producing gas well is located according to the water-gas ratio and mine field production data of the water-producing gas well and a function relation, obtained through pre-inversion, between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio; and determining the water invasion stage of the water-producing gas well according to the reservoir water saturation and the gas-water two-phase relative permeability curve of the reservoir in the mine field. Production data and the flowing state of intruding water are associated, the water invasion stage and the water invasion characteristics of the water-producing gas well are determined, and the method is a key for pointedly providing water control technical countermeasures, prolonging the production cycle of the gas well, improving the remaining reserves of a water-flooded area and improving the economic benefits of a gas reservoir.

Description

Technical Field

[0001] This invention relates to the field of oil and gas exploration, and in particular to a method and related apparatus for determining the water invasion stage of a water-producing gas well. Background Technology

[0002] With increasing demand for natural gas and the continuous advancement of exploration and development to deeper levels, the geological conditions of gas reservoirs are becoming increasingly complex. Currently, more than three-quarters of conventional gas reservoirs contain active edge water / bottom water. During depletion-type development, formation water intrudes into the gas reservoir and flows into the wellbore under pressure differential. After water intrusion, the flow in the reservoir changes from single-phase gas to two-phase gas-water flow. Due to the hydrophilicity of the reservoir rocks, the gas phase permeability is significantly reduced, resulting in a substantial decrease in the production capacity of water-producing gas wells, affecting the stable production period and recovery rate of the gas reservoir. Identifying the water intrusion stage and characteristics of water-producing gas wells, the remaining gas phase flow potential in the reservoir, and determining the impact of water production on the production capacity of water-producing gas wells are crucial for developing targeted water control technologies, extending the production cycle of gas wells, increasing the remaining reserves in water-flooded areas, and improving the economic benefits of gas reservoirs.

[0003] Unfortunately, there is currently a lack of effective technical means to determine the stage of water intrusion, the characteristics of water intrusion, and the remaining flow potential of the gas phase after water intrusion in water-producing gas wells. Generally, mining operations determine whether water intrusion has occurred in gas-producing wells based on whether formation water is produced in surface production measurements. However, this macroscopic method cannot determine the true state of intrusive water in the reservoir where the water-producing gas well is located. Characterizing the stage of water intrusion and its characteristics in the underground reservoir based on the amount of water produced in surface measurements is inaccurate, leading to a certain degree of uncertainty in the subsequent development of water control strategies. In addition, regarding the quantification of the production capacity loss of water-producing gas wells, existing methods typically use the overall production capacity equation under two-phase flow conditions of gas and water in the water-producing gas well to calculate the water production q. w The gas phase productivity under the condition of 0 = 0 is not representative of the actual gas well productivity under conditions without water intrusion; it only represents the error in productivity calculations when water production is ignored versus considered. Furthermore, the gas-water two-phase pseudo-pressure function used in existing methods has a more complex integration process compared to the pure gas phase pseudo-pressure function, which is not conducive to field applications, especially for pseudo-pressure in the nonlinear flow of gas and water in low-permeability gas wells. It cannot utilize field data to obtain the initiation pressure term representing water flow in low-permeability reservoirs.

[0004] Therefore, for water-producing gas wells, it is necessary to propose a method to determine the water invasion stage of the well and the gas production and capacity loss after water invasion, so as to better serve engineering practice. Summary of the Invention

[0005] In view of the above problems, the purpose of this invention is to provide a method and related apparatus for determining the water invasion stage of a water-producing gas well.

[0006] In a first aspect, embodiments of the present invention provide a method for determining the water invasion stage of a water-producing gas well, comprising:

[0007] Based on the water-gas ratio of the water-producing gas well and the mine production data, as well as the pre-derived functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio, the water saturation of the reservoir where the water-producing gas well is located is determined.

[0008] Based on the reservoir water saturation and the gas-water two-phase interpenetration curve in the mining area, the water-producing gas well is determined to be in the water invasion stage.

[0009] The functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio is obtained in advance by inversion based on the flow equations of the water phase and gas phase of the water-producing gas well and the gas-water two-phase interpenetration curve of the reservoir.

[0010] In one embodiment, determining the water invasion stage of the producing gas well based on the reservoir water saturation and the gas-water two-phase interpermeability curve in the mining area includes:

[0011] In the gas-water two-phase permeability curve of the reservoir, the water saturation corresponding to the preset relative permeability value of the gas phase is determined as the first critical water saturation, and the water saturation corresponding to the preset relative permeability value of the water phase is determined as the second critical water saturation.

[0012] If the water saturation of the reservoir where the water-producing gas well is located is less than the first critical water saturation, then the water intrusion stage of the water-producing gas well is the water phase retention period.

[0013] If the water saturation of the reservoir where the water-producing gas well is located is greater than the first critical water saturation and less than the second critical water saturation, then the water invasion stage in which the water-producing gas well is located is the gas-water stalemate period.

[0014] If the water saturation of the reservoir where the water-producing gas well is located is greater than the second critical water saturation, then the water intrusion stage in which the water-producing gas well is located is the flooding period.

[0015] In one embodiment, determining the water intrusion stage of the water-producing gas well further includes:

[0016] Based on the reservoir water saturation and the gas-water two-phase interpenetration curve, determine the relative permeability of the water phase and the relative permeability of the gas phase corresponding to the reservoir water saturation.

[0017] Based on the reservoir water saturation, relative permeability of the water phase, relative permeability of the gas phase, and the morphology of the gas-water two-phase inter-permeability curve, the corresponding water invasion characteristics of the water-producing gas well are identified.

[0018] The water intrusion feature is used to represent any one or more of the following features:

[0019] Intrusive water accumulation area;

[0020] The scale of the intrusion;

[0021] The flow state of the intruding water;

[0022] The changing trends of relative permeability in the aqueous phase and relative permeability in the gas phase.

[0023] In one embodiment, the functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio is obtained in advance through inversion based on the flow equations of the water and gas phases of the water-producing gas well and the gas-water two-phase interpenetration curve of the reservoir, including:

[0024] Based on the flow equations of the water and gas phases in the water-gas well, the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio is obtained.

[0025] Based on the gas-water two-phase interpermeability curve of the reservoir, the ratio of the relative permeability of the gas and water phases to the ratio of the reservoir water saturation is calculated to obtain the functional relationship between the ratio of the relative permeability of the gas and water phases and the reservoir water saturation.

[0026] Based on the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio, and the functional relationship between the relative permeability ratio of the water and gas phases and the reservoir water saturation, the functional relationship between the reservoir water saturation and the water-gas ratio is obtained.

[0027] In one embodiment, the flow equations for the aqueous phase and the gas phase are as follows:

[0028]

[0029]

[0030] in:

[0031] q g —Daily gas production, 10 4 m 3 / d;

[0032] q w —Daily water production, m 3 / d;

[0033] K—Reservoir permeability, mD;

[0034] K rw —Relative permeability of the aqueous phase in gas-liquid two-phase flow;

[0035] K rg —Relative permeability of the gas phase in gas-liquid two-phase flow;

[0036] h—Reservoir thickness, m;

[0037] p R —Reservoir pressure, MPa;

[0038] p wf — Bottom hole flowing pressure, MPa;

[0039] ψ R —The corresponding reservoir pressure is p R Simulated pressure at time, MPa 2 / mPa.s;

[0040] ψ wf —The corresponding bottom hole flowing pressure is p wf Simulated pressure at time, MPa 2 / mPa.s;

[0041] μ w — Formation water viscosity, mPa·s;

[0042] B w — Formation water volume factor, m 3 / m 3 ;

[0043] r e —Well control radius, m;

[0044] r w —Wellbore radius, m;

[0045] S—epidermal coefficient;

[0046] D—Non-Darcy flow coefficient, d / 10 4 m 3 ;

[0047] T—Reservoir temperature, K;

[0048] μ g —Gas viscosity, mPa·s;

[0049] Z—Gas compressibility factor, dimensionless.

[0050] In one embodiment, the functional relationship between the relative permeability ratio of the water and air phases and the water-air ratio is as follows:

[0051]

[0052]

[0053] Among them, R wg For the water-to-air ratio, m 3 / 10 4 m3 ; It represents the ratio of the relative permeability of the water and air phases.

[0054] Secondly, embodiments of the present invention provide a method for determining the degree of production capacity loss of a water-producing gas well, including:

[0055] Based on the binomial production capacity equation of gas wells and the production data of the mining field, the first formation coefficient value is determined to characterize the gas phase flow capacity of the reservoir under the influence of water invasion in water-producing gas wells.

[0056] Determine the relative permeability of the gas phase in the water-producing gas well after water intrusion, and the relative permeability of the gas phase in the water-producing gas well before water intrusion;

[0057] Determine the value of the second formation coefficient used to characterize the gas phase flow capacity of water-producing gas wells in reservoirs before water invasion;

[0058] Determine the unobstructed flow rate of the water-producing gas well under the influence of water intrusion, and the unobstructed flow rate of the water-producing gas well before water intrusion;

[0059] Determine the degree of production loss of the water-producing gas well after water intrusion.

[0060] In one embodiment, determining the relative permeability of the gas phase in a water-producing gas well after water intrusion includes:

[0061] Based on the water-gas ratio of the water-producing gas well and the mine production data, as well as the pre-derived functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio, the water saturation of the reservoir where the water-producing gas well is located is determined.

[0062] Based on the water saturation of the reservoir where the water-producing gas well is located and the gas-water two-phase interpermeability curve, determine the relative gas phase permeability of the water-producing gas well after water intrusion, which corresponds to the water saturation of the reservoir.

[0063] The functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio is obtained in advance by inversion based on the flow equations of the water phase and gas phase of the water-producing gas well and the gas-water two-phase interpenetration curve of the reservoir.

[0064] In one embodiment, the functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio is obtained in advance through inversion based on the flow equations of the water and gas phases of the water-producing gas well and the gas-water two-phase interpenetration curve of the reservoir, including:

[0065] Based on the flow equations of the water and gas phases in the water-gas well, the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio is obtained.

[0066] Based on the gas-water two-phase interpermeability curve of the reservoir, the ratio of the relative permeability of the gas and water phases to the ratio of the reservoir water saturation is calculated to obtain the functional relationship between the ratio of the relative permeability of the gas and water phases and the reservoir water saturation.

[0067] Based on the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio, and the functional relationship between the relative permeability ratio of the water and gas phases and the reservoir water saturation, the functional relationship between the reservoir water saturation and the water-gas ratio is obtained.

[0068] In one embodiment, the flow equations for the aqueous phase and the gas phase are as follows:

[0069]

[0070]

[0071] in:

[0072] q g —Daily gas production, 10 4 m 3 / d;

[0073] q w —Daily water production, m 3 / d;

[0074] K—Reservoir permeability, mD;

[0075] K rw —Relative permeability of the aqueous phase in gas-liquid two-phase flow;

[0076] K rg —Relative permeability of the gas phase in gas-liquid two-phase flow;

[0077] h—Reservoir thickness, m;

[0078] p R —Reservoir pressure, MPa;

[0079] p wf — Bottom hole flowing pressure, MPa;

[0080] ψ R —The corresponding reservoir pressure is p R Simulated pressure at time, MPa 2 / mPa.s;

[0081] ψ wf —The corresponding bottom hole flowing pressure is p wf Simulated pressure at time, MPa 2 / mPa.s;

[0082] μ w— Formation water viscosity, mPa·s;

[0083] B w — Formation water volume factor, m 3 / m 3 ;

[0084] r e —Well control radius, m;

[0085] r w —Wellbore radius, m;

[0086] S—epidermal coefficient;

[0087] D—Non-Darcy flow coefficient, d / 10 4 m 3 ;

[0088] T—Reservoir temperature, K;

[0089] μ g —Gas viscosity, mPa·s;

[0090] Z—Gas compressibility factor, dimensionless.

[0091] In one embodiment, the degree of production loss of the water-producing gas well after water intrusion is calculated according to the following formula:

[0092]

[0093] Where F is the value of the degree of capacity loss; Q AOFi Q represents the unobstructed flow rate of the water-producing gas well before water intrusion. AOF The unobstructed flow rate of the water-producing gas well under the influence of water intrusion.

[0094] In one embodiment, the expression for the gas well binomial productivity equation is:

[0095]

[0096]

[0097]

[0098] in:

[0099] Kh — the first formation coefficient value, mD.m;

[0100] p R —The reservoir pressure, in MPa;

[0101] p wf —The bottom hole flowing pressure, MPa;

[0102] q g—The daily gas production, 10 4 m 3 / d;

[0103] —Average gas viscosity, taken The value of time, mPa·s;

[0104] —Gas average compressibility factor, taken as The value at time;

[0105] A' and B' are coefficients.

[0106] In one embodiment, determining the second formation coefficient value used to characterize the gas phase flow capacity of a water-producing gas well in a pre-water-invaded reservoir includes:

[0107] The loss of gas phase flow capacity in the reservoir is determined based on the relative permeability of the gas phase after water intrusion and the relative permeability of the gas phase before water intrusion.

[0108] The second formation coefficient value is determined based on the first formation coefficient value and the gas phase flow capacity loss value.

[0109] In one embodiment, the second formation coefficient value is calculated according to the following formula:

[0110]

[0111] in:

[0112] (Kh) i This is the value of the second stratigraphic coefficient;

[0113] This represents the loss of gas phase flow capacity in the reservoir.

[0114] K rgi The relative permeability of the gas phase in the water-producing gas well before water intrusion;

[0115] K rgn The relative permeability of the gas phase in the water-producing gas well after water intrusion.

[0116] Thirdly, embodiments of the present invention provide an apparatus for determining the water invasion stage of a water-producing gas well, comprising:

[0117] The water saturation determination module is used to determine the water saturation of the reservoir where the water-producing gas well is located based on the water-gas ratio of the water-producing gas well, the mine production data, and the pre-derived functional relationship between the water saturation and the water-gas ratio of the reservoir where the water-producing gas well is located.

[0118] The water invasion stage determination module is used to determine the water invasion stage of the water-producing gas well based on the reservoir water saturation and the gas-water two-phase interpermeability curve in the mine.

[0119] The inversion module, which is used to determine the functional relationship between the water saturation and the water-gas ratio of the reservoir where the water-producing gas well is located, is obtained in advance by inversion based on the flow equations of the water phase and gas phase of the water-producing gas well, as well as the gas-water two-phase interpenetration curve of the reservoir.

[0120] Fourthly, embodiments of the present invention provide an apparatus for determining the degree of production capacity loss of a water-producing gas well, comprising:

[0121] The first formation coefficient value determination module is used to determine the first formation coefficient value, which characterizes the gas phase flow capacity of the reservoir under the influence of water invasion, based on the gas well binomial production capacity equation and the mine production data.

[0122] The second formation coefficient value determination module is used to determine the relative gas phase permeability of the water-producing gas well after water invasion and the relative gas phase permeability of the water-producing gas well before water invasion; and to determine the second formation coefficient used to characterize the gas phase flow capacity of the water-producing gas well in the reservoir before water invasion.

[0123] An unobstructed flow rate determination module is used to determine the unobstructed flow rate of the water-producing gas well under the influence of water intrusion, and the unobstructed flow rate of the water-producing gas well before water intrusion.

[0124] The capacity loss determination module is used to determine the capacity loss value of the water-producing gas well after water intrusion.

[0125] Fifthly, embodiments of the present invention provide a computing 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 aforementioned method for determining the water intrusion stage of a water-producing gas well and the method for determining the degree of production capacity loss of the water-producing gas well.

[0126] In a sixth aspect, embodiments of the present invention provide a computer-readable storage medium storing a computer program that, when executed by a processor, implements the aforementioned method for determining the water intrusion stage of a water-producing gas well and the method for determining the degree of production capacity loss of a water-producing gas well.

[0127] The beneficial effects of the above-described technical solutions provided in the embodiments of the present invention include at least the following:

[0128] The method and related apparatus for determining the water invasion stage of a water-producing gas well provided in this embodiment of the invention, based on the water-gas ratio (obtained from daily water production and daily gas production) and other mine production data, inverts the reservoir water saturation, and determines the current water invasion stage of the water-producing gas well through the reservoir water saturation. That is, it links the surface production data with the flow state of the underground intruding water, inverts the true reservoir water saturation, and determines the water invasion stage.

[0129] Furthermore, based on the water invasion stage of the producing gas well and the current relative permeability of the water phase and gas phase, the characteristics of the invading water at this stage can be determined. Based on the determined water invasion stage and corresponding characteristics, targeted water control technologies can be proposed, providing technical support for extending the stable production period and recovery rate of gas wells.

[0130] The method and related apparatus for determining the degree of production capacity loss of water-producing gas wells provided in this invention determine the unobstructed flow rate of the water-producing gas well before and under the influence of water intrusion by calculating and determining the first formation coefficient value and the second formation coefficient value, thereby determining the degree of gas phase production capacity loss. For example, the second formation coefficient value, which characterizes the gas phase flow capacity of the water-producing gas well in the reservoir before water intrusion, is calculated based on the reservoir water saturation determined in the method for determining the water intrusion stage of the water-producing gas well in this invention embodiment. The method for determining the degree of production capacity loss of water-producing gas wells provided in this invention embodiment solves the problem that the calculation process of existing methods is too cumbersome and cannot restore the production capacity of the gas well before water intrusion. The physical meaning of the parameters in the formula is clear, and it can accurately make a quantitative evaluation of the degree of production capacity loss of the water-producing gas well.

[0131] 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

[0132] 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:

[0133] Figure 1 This is a flowchart illustrating the method for determining the water intrusion stage of a water-producing gas well in an embodiment of the present invention;

[0134] Figure 2 This is a flowchart of a method for determining the degree of production capacity loss of a water-producing gas well in an embodiment of the present invention;

[0135] Figure 3 This is a graph showing the variation trend of formation water volume factor with formation pressure in an embodiment of the present invention;

[0136] Figure 4 This is a graph showing the variation trend of formation water viscosity with formation pressure in an embodiment of the present invention;

[0137] Figure 5 This is a graph showing the trend of gas pseudo-pressure versus formation pressure in an embodiment of the present invention.

[0138] Figure 6 This is a well extraction curve diagram in an embodiment of the present invention;

[0139] Figure 7 This is a schematic diagram of the gas-water two-phase inter-permeability curve in an embodiment of the present invention, where the reservoir is a porous system.

[0140] Figure 8 This is a schematic diagram illustrating the relationship between the relative permeability ratio of water and gas phases in a porous reservoir and the water saturation of the reservoir in an embodiment of the present invention.

[0141] Figure 9 This is a schematic diagram of the gas-water two-phase interpenetration curve in a fractured reservoir system according to an embodiment of the present invention.

[0142] Figure 10 This is a schematic diagram illustrating the relationship between the relative permeability ratio of water and gas phases and the water saturation of the reservoir in a fractured system according to an embodiment of the present invention.

[0143] Figure 11 This is a schematic diagram of the water intrusion stages divided in the gas-water two-phase interpenetration curve in an embodiment of the present invention;

[0144] Figure 12 This is an apparatus for determining the water intrusion stage of a water-producing gas well in an embodiment of the present invention;

[0145] Figure 13 This is an apparatus for determining the degree of production capacity loss of a water-producing gas well in an embodiment of the present invention. Detailed Implementation

[0146] This embodiment provides a method and related apparatus for determining the water invasion stage of a water-producing gas well. Although exemplary embodiments of this disclosure are shown in the accompanying drawings, it should be understood that this disclosure can be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided to enable a more thorough understanding of this disclosure and to fully convey the scope of this disclosure to those skilled in the art.

[0147] This invention provides a method for determining the water intrusion stage of a water-producing gas well, referring to... Figure 1 As shown, the method includes the following steps:

[0148] S11. Based on the water-gas ratio of the water-producing gas well and the mine production data, as well as the pre-derived functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio, determine the water saturation of the reservoir where the water-producing gas well is located.

[0149] The functional relationship between the water saturation of the reservoir and the water-gas ratio in the aforementioned water-producing gas wells can be obtained in advance by inversion based on the flow equations of the water and gas phases of the water-producing gas wells and the gas-water two-phase interpenetration curves of the reservoir.

[0150] S12. Determine the water invasion stage of the water-producing gas well based on the reservoir water saturation and the gas-water two-phase interpenetration curve in the mining area.

[0151] In step S11 above, the water saturation of the reservoir where the water-producing gas well is located is determined based on the functional relationship between the water saturation and the water-gas ratio of the reservoir where the water-producing gas well is located, which is obtained through pre-inversion.

[0152] The functional relationship between reservoir water saturation and water-gas ratio is obtained by inversion using the following method:

[0153] In one embodiment, based on the flow equations for the water and gas phases of a water-gas well, the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio can be derived. The specific method is as follows:

[0154] In one embodiment, it is assumed that the reservoir is homogeneous and of uniform thickness, with isothermal gas-water two-phase flow, neglecting gravity and capillary pressure, and that there is no miscibility between the gas and water phases. Considering that the gas well mainly operates under quasi-steady flow conditions during long-term production, the flow equations for the water and gas phases can be expressed as follows:

[0155]

[0156]

[0157] The first equation above is the equation for water phase flow, and the second equation is the equation for gas phase flow.

[0158] in:

[0159] q g —Daily gas production, 10 4 m 3 / d;

[0160] q w —Daily water production, m 3 / d;

[0161] K—Reservoir permeability, mD;

[0162] K rw —Relative permeability of the aqueous phase in gas-liquid two-phase flow;

[0163] K rg —Relative permeability of the gas phase in gas-liquid two-phase flow;

[0164] h—Reservoir thickness, m;

[0165] p R —Reservoir pressure, MPa;

[0166] p wf — Bottom hole flowing pressure, MPa;

[0167] ψ R —The corresponding reservoir pressure is p R Simulated pressure at time, MPa 2 / mPa.s;

[0168] ψ wf —The corresponding bottom hole flowing pressure is p wf Simulated pressure at time, MPa 2 / mPa.s;

[0169] μ w — Formation water viscosity, mPa·s;

[0170] B w — Formation water volume factor, m 3 / m 3 ;

[0171] r e —Well control radius, m;

[0172] r w —Wellbore radius, m;

[0173] S—epidermal coefficient;

[0174] D—Non-Darcy flow coefficient, d / 10 4 m 3 ;

[0175] T—Reservoir temperature, K;

[0176] μ g —Gas viscosity, mPa·s;

[0177] Z—Gas compressibility factor, dimensionless.

[0178] The equation for the surface water-gas ratio of a water-producing gas well can be derived from Formulas 1 and 2. The expression for the water-gas ratio is as follows:

[0179]

[0180] Where R wg , Indicates the water-to-air ratio, m 3 / 10 4 m 3 .

[0181] In one embodiment, by further transforming Formula 3 above, the functional relationship between the relative permeability ratio of the water and air phases and the water-air ratio can be obtained. The expression for the functional relationship between the relative permeability ratio of the water and air phases and the water-air ratio is as follows:

[0182]

[0183] in It represents the ratio of the relative permeability of the water and air phases.

[0184] On the right side of equation 4, the main parameters of the mine can be determined as follows:

[0185] ①μ w B w

[0186] Based on the properties of formation water, the viscosity μ of formation water under different formation pressure conditions was determined experimentally. w and formation water volume factor B w Because formation water is a slightly compressible fluid, its viscosity μ w and formation water volume factor B w The variation range with formation pressure is limited. Formation water viscosity and formation water volume coefficient are plotted as scatter plots or fitted as variation curves with different formation pressures. Values ​​are then determined based on these scatter plots or variation curves during application.

[0187] ②ψ R ψ wff

[0188] The variation of gas pseudo-pressure ψ with formation pressure p is related to the gas PVT (the relationship between gas pressure P, volume V, and temperature T). A table or graph of the ψ-p relationship can be provided using common software or manual integration methods. In the high-pressure stage where the formation pressure exceeds a certain value, ψ-p exhibits a linear variation, i.e.:

[0189] ψ = ap + b (Formula 5);

[0190] Where a and b are constants.

[0191] Therefore, during the high-pressure stage, ψ R ~p R and ψ wf ~p wf The functional relationship is as follows:

[0192] ψ R =ap R +b (Formula 6);

[0193] ψ wf =ap wf +b (Formula 7);

[0194] Furthermore, using formulas 6 and 7, the relationship between the constant a and the reservoir pressure p is obtained. R and bottom hole flowing pressure p wf The relationship is as follows:

[0195]

[0196] In application, during the high-pressure stage, the 'a' value and the reservoir pressure 'p' are used. R and bottom hole flowing pressure p wf Determine the corresponding pseudo-pressure value.

[0197] In the low-pressure stage where the formation pressure is less than a certain value, there is no linear relationship between ψ and p. At this time, the relationship can be determined by the reservoir pressure p. R Bottom-hole flowing pressure p wf Determine ψ by referring to a diagram or table. R ψ wf .

[0198] ③r e r w

[0199] Well control radius r e Based on the well network deployment of the gas reservoir, a distance of 1 / 2 well spacing is generally taken, and the wellbore radius r w For example, based on experience, the value is taken as 0.1m.

[0200] ④S, D

[0201] The skin factor S is obtained using unsteady gauging tests on gas wells. For gas wells without unsteady gauging tests, values ​​from adjacent wells can be used as a reference. The non-Darcy factor D is obtained using shut-in unsteady gauging tests at different production rates, or values ​​from adjacent wells can be used as a reference.

[0202] In one embodiment, the inventors discovered that, based on the morphology of the gas-water two-phase interpermeability curve, a functional relationship between the relative permeability ratio of the water and gas phases and the reservoir water saturation can be obtained. The specific method is as follows:

[0203] Through indoor experiments, gas-water two-phase permeability curves for porous systems or fractured systems in different reservoirs can be obtained. Using these curves, the relative permeability ratio K between the gas and water phases at the same reservoir water saturation level can be calculated. rw / K rg And calculate K rw / K rg With the corresponding water saturation S w The ratio of water to air is used to obtain the relative permeability ratio K between the two phases. rw / K rg With reservoir water saturation S wThe inventors discovered that, regardless of whether the reservoir is a porous system or a fractured system, K... rw / K rg ~S w All are monotonically increasing and exhibit exponential function relationships, from which K can be obtained. rw / K rg ~S w The graph of the exponential function is shown below, and its expression is as follows:

[0204]

[0205] Where m and n are constants; S w This represents the water saturation level, a decimal.

[0206] Therefore, by combining Equations 4 and 9, the functional relationship between reservoir water saturation and water-gas ratio is derived as follows:

[0207]

[0208] Formula 4 can be used to determine a certain water-to-air ratio R. wg Corresponding K rw / K rg Then use K rw / K rg ~S w The corresponding water saturation S can be determined by the exponential function graph or formula 9. w Then, based on the determined water saturation S w Based on the gas-water two-phase interpenetration curve, the water saturation point S was determined. w The relative permeability of the gas phase K rg Relative permeability K of water phase rw In other words, for a given water-gas producing well, the water-gas ratio R... wg This allows us to determine the reservoir's water saturation, as well as the corresponding relative permeability values ​​for the water phase and the gas phase.

[0209] By establishing the relationship between the water-gas ratio and the reservoir water saturation and the ratio of the relative permeability of the water and gas phases, the mine production data can be directly correlated with the flow state of groundwater, providing support for accurately determining the reservoir water intrusion stage.

[0210] In step S12, the specific method for determining the water invasion stage of the water-producing gas well is as follows:

[0211] In one embodiment, the water intrusion stage of the producing gas well is pre-defined based on the gas-water two-phase interpermeability curve obtained experimentally. In the pre-obtained reservoir gas-water two-phase interpermeability curve, the reservoir water saturation corresponding to preset relative permeability values ​​of the gas phase and water phase is determined as the first critical water saturation and the second critical water saturation, respectively. For example, the preset relative permeability values ​​of the gas phase and water phase are set to 0.1. These preset relative permeability values ​​can be determined empirically, and this embodiment of the invention does not impose any limitations.

[0212] Based on the determined first critical water saturation, second critical water saturation, and the morphology of the gas-water two-phase interpenetration curve, the water-producing gas well is identified as having three water intrusion stages: the water phase retention period, the gas-water phase holding period, and the water flooding period. Within the water saturation range of the gas-water two-phase interpenetration curve, the water phase retention period corresponds to a saturation range where the water saturation is less than the first critical water saturation; the gas-water phase holding period corresponds to a saturation range where the water saturation is greater than the first critical water saturation but less than the second critical water saturation; and the water flooding period corresponds to a saturation range where the water saturation is greater than the second critical water saturation.

[0213] In one embodiment, if the water saturation of the reservoir where the water-producing gas well is located, as determined by step S11 above, is less than the first critical water saturation, it indicates that the water-producing gas well is in the water phase retention period; if the determined reservoir water saturation is greater than the first critical water saturation and less than the second critical water saturation, it indicates that the water-producing gas well is in the gas-water phase holding period; if the determined reservoir water saturation of the water-producing gas well is greater than the second critical water saturation, the water intrusion stage in which the water-producing gas well is located is the flooding period.

[0214] In one embodiment, after determining the water invasion stage of the producing gas well through the above steps, the water invasion characteristics of the producing gas well can be further identified based on the reservoir water saturation, relative permeability of the water phase, relative permeability of the gas phase, and the shape of the gas-water two-phase interpenetration curve. These water invasion characteristics can be described from aspects such as the accumulation area of ​​intrusive water in the reservoir, its formation scale, flow state, and permeability variation trend.

[0215] During the aqueous phase retention period, the relative permeability of the gas phase decreases rapidly with increasing water saturation. However, since the aqueous phase does not form a large-scale continuous phase, its relative permeability is much lower than that of the gas phase. During the gas-water phase holding period, the difference in relative permeability between the two phases is small. With increasing water saturation, the aqueous phase forms a large-scale continuous phase, representing a process of gas loss and water growth. After entering the water flooding period, the relative permeability of the aqueous phase rises rapidly with increasing water saturation, while the relative permeability of the gas phase is much lower. The gas phase is locked by water and gradually loses its mobility, becoming a discontinuous phase. Targeting the different stages of water intrusion and their corresponding characteristics in the producing gas wells is more conducive to proposing reasonable water control technologies and strategies.

[0216] This invention provides a method for determining the degree of production capacity loss of a water-producing gas well, referring to... Figure 2 As shown, the method includes the following steps:

[0217] S21. Based on the binomial production capacity equation of gas wells and the production data of the mining field, determine the first formation coefficient value used to characterize the gas phase flow capacity of the reservoir under the influence of water invasion in water-producing gas wells.

[0218] S22. Determine the relative permeability of the gas phase in the water-producing gas well after water intrusion, and the relative permeability of the gas phase in the water-producing gas well before water intrusion; determine the second formation coefficient value used to characterize the gas phase flow capacity of the water-producing gas well in the reservoir before water intrusion.

[0219] S23. Determine the unobstructed flow rate of the water-producing gas well under the influence of water intrusion, and the unobstructed flow rate of the water-producing gas well before water intrusion.

[0220] S24. Determine the degree of production loss of the water-producing gas well after water intrusion.

[0221] In step S21 above, the first formation coefficient value of the water-producing gas well under the influence of water intrusion is determined by the following method. In one embodiment, when the gas well flow reaches a pseudo-steady flow state, the relationship between its pressure and production is written in the form of a binomial (pressure squared), as shown below:

[0222]

[0223] in:

[0224] Kh — the first formation coefficient value, mD.m;

[0225] p R —The reservoir pressure, in MPa;

[0226] p wf —The bottom hole flowing pressure, MPa;

[0227] q g —The daily gas production, 10 4 m3 / d;

[0228] —Average gas viscosity, taken The value of time, mPa·s;

[0229] —Gas average compressibility factor, taken as The value at time.

[0230] In formula 11 above, let:

[0231]

[0232]

[0233]

[0234]

[0235] The relationship between parameters A and A', and the relationship between parameters B and B' are as follows:

[0236]

[0237]

[0238] Substituting formulas 12 and 13 into formula 11, formula 11 becomes:

[0239]

[0240]

[0241] Formula 18 is a commonly used binomial productivity equation for gas wells, and Formula 19 is the foundation of the steady-point productivity binomial method. The process of determining the first formation coefficient value using Formula 19, based on daily mine production data, is as follows:

[0242] (1) r was determined by well pattern density, PVT data and interpretation of instability testing. e r w , The parameter values ​​of S and D, and the method for determining these parameter values, have been described in the steps above for determining the water invasion stage of the producing gas well.

[0243] (2) Use formulas 14 and 15 to calculate parameters A' and B' respectively.

[0244] (3) The reservoir pressure p at the stable production point R Bottom-hole flowing pressure p wf and daily gas production q gSubstituting into Formula 19, we determine the first formation coefficient Kh, which characterizes the gas phase flow capacity of the reservoir under the influence of water intrusion in water-producing gas wells. The calculated value of the first formation coefficient Kh at this time represents the gas phase flow capacity of the reservoir after water intrusion for water-producing gas wells, because the actual reservoir contains two phases of gas and water, and the measured pressure and gas well production already include the influence of water intrusion.

[0245] In step S22, the second formation coefficient value of the water-producing gas well under the influence of water intrusion can be determined, for example, by the following method:

[0246] In one embodiment, assuming the initial water saturation of the reservoir is S wi The relative permeability of the gas phase (before water intrusion) is K. rgi That is, the starting value of the relative permeability of the gas phase, which is the reservoir water saturation S corresponding to a certain water-gas ratio after water production. wn The relative permeability of the gas phase below is K rgn Therefore, the degree of gas phase flow loss after water exposure in the reservoir is as follows:

[0247]

[0248] Where SH represents the loss of gas phase flow capacity in the reservoir (Kh). i This is the value of the second stratigraphic coefficient. K represents the loss of gas phase flow capacity in the reservoir. rgi K represents the original relative permeability of the gas phase in a water-producing gas well before water intrusion. rgn This represents the actual relative permeability of the gas phase in a water-producing gas well after water intrusion.

[0249] The first formation coefficient value Kh calculated in step S21 above, and the value determined in the aforementioned step of determining the water and gas stage of the water-producing well... Combining this with Formula 20, the second formation coefficient (Kh) can be calculated. i Second stratigraphic coefficient (Kh) i The calculation formula is as follows:

[0250]

[0251] First stratigraphic coefficient value (Kh) and second stratigraphic coefficient value (Kh) i , which represents the product of reservoir thickness h (in meters) and reservoir permeability K (in meters D), with units of mD.m.

[0252] In step S23, the main task is to determine the unobstructed flow rate of the water-producing gas well under the influence of water intrusion and before water intrusion.

[0253] For calculating the unobstructed flow rate of a water-producing gas well under the influence of water intrusion, in one embodiment, the unobstructed flow rate of the gas well is the bottom hole flowing pressure p.wf Given the gas production rate of a gas well at 1 atmosphere (0.101 MPa), based on formula 18 in step S21 above, the gas production rate of a water-producing gas well under the influence of water intrusion, i.e., the unobstructed flow rate Q, is derived. AOF The formula is:

[0254]

[0255] By substituting the parameter values ​​A' and B' determined in step S21 above, and the first formation coefficient value Kh, into formulas 16 and 17, parameter values ​​A and B are calculated. Then, the obtained A and B values ​​are substituted into formula 22 above to calculate the unobstructed flow rate of the water-producing gas well under the influence of water intrusion. In this embodiment of the invention, the unobstructed flow rate Q is calculated at this time. AOF For water-producing gas wells, the value represents the gas well's production capacity after water intrusion, because the actual reservoir consists of two phases of gas and water, and the measured pressure and gas well production already include the impact of water intrusion.

[0256] For calculating the unobstructed flow rate of a water-producing gas well before water intrusion, in one embodiment, the second formation coefficient value (Kh) determined in step S22 above is used. i Substituting the second formation coefficient value into Formulas 16 and 17, the coefficient A of the binomial productivity equation for the water-producing gas well before water invasion is determined. i and B i According to coefficient A i and B i Using Formula 22 (that is, replacing the coefficients A and B in Formula 22 with A) i and B i The unobstructed flow rate Q of the water-producing gas well before water intrusion was calculated. AOFi .

[0257] In step S24 above, in one embodiment, the degree of gas well productivity loss due to water intrusion can be calculated, for example, according to the following formula:

[0258]

[0259] Where F represents the degree of capacity loss.

[0260] In this embodiment of the invention, the calculation process for determining the loss of gas well productivity (unobstructed flow rate) caused by water intrusion is simple and does not involve complex gas-water two-phase pseudo-pressure integral calculations, which is convenient for engineering applications.

[0261] The following example, using a water-producing gas well in a deep Permian carbonate gas reservoir in a basin, illustrates the process of determining the water intrusion stage of the well and the loss of production capacity.

[0262] The parameters for the reservoir temperature system, gas properties, and formation water properties of this well are as follows:

[0263] Reservoir burial depth: 5165m;

[0264] Original formation pressure: 138.61 MPa;

[0265] Reservoir temperature: 138.6℃;

[0266] Relative density of natural gas: 0.612;

[0267] Gas molar composition: CH4 = 94.13%, CO2 = 5.54%, H2S = 0.16%, N2 = 0.17%;

[0268] Formation water specific gravity: 1.08;

[0269] Formation water salinity: 150,000 mg / L.

[0270] Based on formation temperature, pressure, and fluid properties, refer to Figure 3 , Figure 4 and Figure 5 As shown, the formation water volume factor B was calculated respectively. w Trend diagram of formation pressure p () Figure 3 ), formation water viscosity μ w Trend diagram of formation pressure p () Figure 4 ), and the trend of gas pseudo-pressure ψ with formation pressure p () Figure 5 ).from Figure 5 As can be seen from the figure, when the formation pressure p > 15 MPa, it is the high-pressure stage, and at this time, ψ ~ p shows a linear trend, as shown in the figure. When the formation pressure p ≤ 15 MPa, it is the low-pressure stage, and the relationship between ψ and p is not linear. The relationship can be determined based on the reservoir pressure p. R Bottom-hole flowing pressure p wf Determine ψ by referring to a diagram or table. R ψ wf .

[0271] The well was put into production on July 3rd of a certain year, and formation water was produced immediately upon commissioning. Its production curve is referenced... Figure 6 As shown, a production capacity evaluation of the well will be conducted in October of the following year, and the water invasion stage of the well will be determined. Static pressure data are taken from the static pressure test data of the well shut-in in September of the following year. The relevant data on daily gas and water production, reservoir pressure and bottom hole flowing pressure are taken from the data on October 16, shortly after the well shut-in. The specific values ​​are shown in Table 1.

[0272] Table 1. Data on stable production points of a certain well.

[0273]

[0274] Using formulas 14 and 15, calculate the values ​​of parameters A' and B'. The values ​​of each parameter in formulas 14 and 15 are as follows:

[0275] S = -3, D = 0.05(10 4 m 3 / d) -1 r e =2200m, r w =0.10m, (according to

[0276] Gas property calculation (The corresponding value at that time) (Calculated based on gas properties) (The value corresponding to the time).

[0277] Substituting the calculated parameter values ​​into formulas 14 and 15, we obtain A' = 2813.56 and B' = 22.51. Substituting the values ​​of A' and B' into formula 19, we get:

[0278]

[0279] Substituting the data from Table 1 into Formula 24, the first formation coefficient value Kh = 152.6 mD.m is calculated.

[0280] Substituting the obtained values ​​of A', B', and Kh into formulas 16 and 17, we calculate A = 18.44 and B = 0.1476. Substituting the values ​​of A and B into formula 18, we obtain the binomial productivity equation for this well:

[0281]

[0282] Using formula 22, the unobstructed flow rate of the well is calculated to be Q. AOF =265.1×10 4 m 3 / d.

[0283] The first formation coefficient value Kh calculated above represents the gas phase flow capacity in the reservoir after the water-producing gas well is affected by water intrusion, and the calculated unobstructed flow rate Q AOF This represents the gas phase production capacity of the water-producing gas well after it has been affected by water intrusion.

[0284] For wells that are not affected by water intrusion, the trend of gas pseudo-pressure ψ versus formation pressure p is shown in the diagram (refer to...). Figure 5 Using formula 8, the parameter a = 2864 was calculated. (Refer to...) Figure 3 and Figure 4 ,calculate B corresponding to time w =1.029, μ w= 0.316 mPa·s.

[0285] Through experiments, the gas-water two-phase interfacial permeability curve of the reservoir where the well is located was obtained as a porous system (refer to...). Figure 7 Furthermore, the relative permeability ratio K between the water and air phases was obtained. rw / K rg With reservoir water saturation S w The change curve, refer to Figure 8 As shown, Figure 8 Zhong K rw / K rg With S w The relationship between them is exponential.

[0286] In addition, embodiments of the present invention also provide gas-water two-phase interpermeability curves when the reservoir is a fractured system, with reference to... Figure 9 As shown, and the corresponding K when the reservoir is a fractured system. rw / K rg ~S w The change curve, refer to Figure 10 As shown. The inventors discovered that regardless of whether the reservoir is a porous system or a fractured system, K rw / K rg ~S w All exhibit an exponential function relationship, and the corresponding exponential function expressions are shown below. Figure 8 and Figure 10 As shown in the image.

[0287] In this embodiment of the invention, the reservoir where the well is located is a porous system, which must be utilized Figure 8 The water saturation of a reservoir is determined by the relationship between the relative permeability ratio of the water and gas phases in a porous system and the reservoir's water saturation. Figure 8 Determined K rw / K rg With S w The exponential function relationship between them (i.e., determining the constants m and n in Formula 9), and then determining the reservoir water saturation according to Formula 10, or calculating K first using Formula 4 based on the data in Table 1. rw / K rg =0.216, reuse Figure 8 The water saturation of the reservoir was determined, and the determined water saturation S of the reservoir was determined. w =0.476. Based on the obtained S... w Value, using Figure 7 Determine the actual relative permeability K of the gas phase in the water-producing gas well after water intrusion. rgn =0.105. From Figure 7 From this, we can know that the original gas phase relative permeability K before water intrusion was... rgi =0.6, from which we can determine K rgn / Krgi =0.175, combined with the first stratigraphic coefficient value Kh = 152.6 mD.m, and then according to formula 21, the second stratigraphic coefficient value (Kh) before water intrusion is calculated. i =872mD.m.

[0288] The obtained (Kh) i Substituting these values ​​into Equations 16 and 17, we determine the coefficient A of the binomial productivity equation under the condition of no water intrusion. i =3.2266, B i =0.0258, which will yield A i and B i Substituting into Formula 22, the unobstructed flow rate Q of the water-producing gas well without water intrusion is calculated. AOFi =708.9×10 4 m 3 / d.

[0289] Formula 23 was used to calculate that the loss of unobstructed flow rate in the well due to water intrusion was 62.6%. The above calculation process solves the problem of overly cumbersome calculation processes in existing technologies, which is conducive to promotion and application.

[0290] The above calculations establish the second formation coefficient (Kh) for this water-producing gas well under conditions where it was not affected by water intrusion. i and unobstructed flow rate Q AOFi During the process, the water intrusion stage of the producing gas well can be determined. Based on the gas-water two-phase interpermeability curves obtained from the experiment, and the preset relative permeability values ​​of the gas phase (0.1) and water phase (0.1), the water intrusion process is divided into three stages: the water phase retention period, the gas-water phase holding period, and the water flooding period. Figure 11 As shown in the figure, the first critical water saturation value is 0.48, and the second critical water saturation value is 0.61. Since the water saturation value of the reservoir where the well is located (0.476) is less than the first critical water saturation value (0.48), it indicates that the well is currently in the water intrusion stage, which is the water phase retention period. At this time, the water phase permeability is very low, and the relative permeability of the water phase is much lower than that of the gas phase. The intruding water mainly accumulates on the pore throat wall and has not yet formed a large-scale continuous phase, but it has already caused a significant decrease in gas phase permeability. Next, the water phase will enter the gas-water phase retention period. As the water saturation increases, the water phase forms a large-scale continuous phase. After entering the water flooding period, as the water saturation increases, the relative permeability of the water phase rises rapidly, and the gas phase is locked by water, gradually losing its mobility and becoming a discontinuous phase.

[0291] Based on the above analysis, the following technical countermeasures are recommended for this water-producing gas well: 1. Reduce the gas well production near the gas-water interface to alleviate the damage to the gas phase flow capacity caused by the water phase retention due to the intrusion of formation water into the gas reservoir; 2. Considering that the well is about to enter a large-scale water production period, it is necessary to consider increasing the formation water treatment capacity and the water-bearing production capacity of the gas well.

[0292] Based on the same inventive concept, this invention also provides an apparatus for determining the water invasion stage of a water-producing gas well. Since the principle of the problem solved by this apparatus is similar to the aforementioned method for determining the water invasion stage of a water-producing gas well, the implementation of this apparatus can refer to the implementation of the aforementioned method, and the repeated parts will not be described again.

[0293] Based on the same inventive concept, this invention also provides an apparatus for determining the degree of production capacity loss of a water-producing gas well. Since the principle by which this apparatus solves the problem is similar to the aforementioned method for determining the degree of production capacity loss of a water-producing gas well, the implementation of this apparatus can refer to the implementation of the aforementioned method, and the repeated parts will not be described again.

[0294] This invention provides an apparatus for determining the water intrusion stage of a water-producing gas well, referring to... Figure 12 As shown, it includes:

[0295] The water saturation determination module 121 is used to determine the water saturation of the reservoir where the water-producing gas well is located based on the water-gas ratio of the water-producing gas well, the mine production data, and the pre-inverted functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio.

[0296] The water invasion stage determination module 122 is used to determine the water invasion stage of the water-producing gas well based on the reservoir water saturation and the gas-water two-phase interpermeability curve in the field.

[0297] The inversion module 123 is used to determine the functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio. It is obtained in advance by inversion based on the flow equations of the water phase and gas phase of the water-producing gas well, as well as the gas-water two-phase interpenetration curve of the reservoir.

[0298] This invention provides an apparatus for determining the degree of production capacity loss of a water-producing gas well, with reference to... Figure 13 As shown, it includes:

[0299] The first formation coefficient value determination module 131 is used to determine the first formation coefficient value, which characterizes the gas phase flow capacity of the reservoir under the influence of water invasion, based on the gas well binomial production capacity equation and the mine production data.

[0300] The second formation coefficient value determination module 132 is used to determine the relative permeability of the gas phase of the water-producing gas well after water invasion and the relative permeability of the gas phase of the water-producing gas well before water invasion; and to determine the second formation coefficient used to characterize the gas phase flow capacity of the water-producing gas well in the reservoir before water invasion.

[0301] The unobstructed flow rate determination module 133 is used to determine the unobstructed flow rate of the water-producing gas well under the influence of water intrusion, and the unobstructed flow rate of the water-producing gas well before water intrusion.

[0302] The capacity loss determination module 134 is used to determine the capacity loss of a water-producing gas well after water intrusion.

[0303] This invention provides a computing 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 aforementioned method for determining the water intrusion stage of a water-producing gas well, and the aforementioned method for determining the degree of production capacity loss of a water-producing gas well.

[0304] This invention provides a computer-readable storage medium storing a computer program. When executed by a processor, the computer program implements the aforementioned method for determining the water intrusion stage of a water-producing gas well and the aforementioned method for determining the degree of production capacity loss of a water-producing gas well.

[0305] Obviously, those skilled in the art can make various modifications to this invention without departing from its spirit and scope. Therefore, if these modifications fall within the scope of the claims and their equivalents, this invention is also intended to include these modifications.

Claims

1. A method for determining the water intrusion stage of a water-producing gas well, characterized in that, include: Based on the water-gas ratio of the water-producing gas well and the mine production data, as well as the pre-derived functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio, the water saturation of the reservoir where the water-producing gas well is located is determined. Based on the reservoir water saturation and the gas-water two-phase interpenetration curve in the mining area, the water-producing gas well is determined to be in the water invasion stage. The functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio is obtained in advance by inversion based on the flow equations of the water phase and gas phase of the water-producing gas well and the gas-water two-phase interpenetration curve of the reservoir.

2. The method as described in claim 1, characterized in that, The step of determining the water invasion stage of the producing gas well based on the reservoir water saturation and the gas-water two-phase interpermeability curve in the mining area includes: In the gas-water two-phase permeability curve of the reservoir, the water saturation corresponding to the preset relative permeability value of the gas phase is determined as the first critical water saturation, and the water saturation corresponding to the preset relative permeability value of the water phase is determined as the second critical water saturation. If the water saturation of the reservoir where the water-producing gas well is located is less than the first critical water saturation, then the water intrusion stage of the water-producing gas well is the water phase retention period. If the water saturation of the reservoir where the water-producing gas well is located is greater than the first critical water saturation and less than the second critical water saturation, then the water invasion stage in which the water-producing gas well is located is the gas-water stalemate period. If the water saturation of the reservoir where the water-producing gas well is located is greater than the second critical water saturation, then the water intrusion stage in which the water-producing gas well is located is the flooding period.

3. The method as described in claim 2, characterized in that, Determining the water invasion stage of the water-producing gas well also includes: Based on the reservoir water saturation and the gas-water two-phase interpenetration curve, determine the relative permeability of the water phase and the relative permeability of the gas phase corresponding to the reservoir water saturation. Based on the reservoir water saturation, relative permeability of the water phase, relative permeability of the gas phase, and the morphology of the gas-water two-phase inter-permeability curve, the corresponding water invasion characteristics of the water-producing gas well are identified. The water intrusion feature is used to represent any one or more of the following features: Intrusive water accumulation area; The scale of the intrusion; The flow state of the intruding water; The changing trends of relative permeability in the aqueous phase and relative permeability in the gas phase.

4. The method as described in claim 1, characterized in that, The functional relationship between the water saturation of the reservoir and the water-to-gas ratio in the water-producing gas well is obtained in advance through inversion based on the flow equations of the water and gas phases of the water-producing gas well and the gas-water two-phase interpenetration curve of the reservoir, including: Based on the flow equations of the water and gas phases in the water-gas well, the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio is obtained. Based on the gas-water two-phase interpermeability curve of the reservoir, the ratio of the relative permeability of the gas and water phases to the ratio of the reservoir water saturation is calculated to obtain the functional relationship between the ratio of the relative permeability of the gas and water phases and the reservoir water saturation. Based on the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio, and the functional relationship between the relative permeability ratio of the water and gas phases and the reservoir water saturation, the functional relationship between the reservoir water saturation and the water-gas ratio is obtained.

5. The method as described in claim 4, characterized in that, The flow equations for the aqueous phase and the gas phase are as follows: in: q g —Daily gas production, 10 4 m 3 / d; q w —Daily water production, m 3 / d; K—Reservoir permeability, mD; K rw —Relative permeability of the aqueous phase in gas-liquid two-phase flow; K rg —Relative permeability of the gas phase in gas-liquid two-phase flow; h—Reservoir thickness, m; p R —Reservoir pressure, MPa; p wf — Bottom hole flowing pressure, MPa; ψ R —The corresponding reservoir pressure is p R Simulated pressure at time, MPa 2 / mPa.s; ψ wf —The corresponding bottom hole flowing pressure is p wf Simulated pressure at time, MPa 2 / mPa.s; μ w — Formation water viscosity, mPa·s; B w — Formation water volume factor, m 3 / m 3 ; r e —Well control radius, m; r w — Well radius, m; S—epidermal coefficient; D—Non-Darcy flow coefficient, d / 10 4 m 3 ; T—Reservoir temperature, K; μ g —Gas viscosity, mPa·s; Z—Gas compressibility factor, dimensionless.

6. The method as described in claim 4 or 5, characterized in that, The functional relationship between the relative permeability ratio of the water and air phases and the water-air ratio is as follows: Among them, R wg For the water-to-air ratio, m 3 / 10 4 m 3 ; It represents the ratio of the relative permeability of the water and air phases.

7. A method for determining the degree of production capacity loss of a water-producing gas well, characterized in that, include: Based on the binomial production capacity equation of gas wells and the production data of the mining field, the first formation coefficient value is determined to characterize the gas phase flow capacity of the reservoir under the influence of water invasion in water-producing gas wells. Determine the relative permeability of the gas phase in the water-producing gas well after water intrusion, and the relative permeability of the gas phase in the water-producing gas well before water intrusion; Determine the value of the second formation coefficient used to characterize the gas phase flow capacity of water-producing gas wells in reservoirs before water invasion; Determine the unobstructed flow rate of the water-producing gas well under the influence of water intrusion, and the unobstructed flow rate of the water-producing gas well before water intrusion; Determine the degree of production loss of the water-producing gas well after water intrusion.

8. The method as described in claim 7, characterized in that, Determining the relative permeability of the gas phase in the water-producing gas well after water intrusion includes: Based on the water-gas ratio of the water-producing gas well and the mine production data, as well as the pre-derived functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio, the water saturation of the reservoir where the water-producing gas well is located is determined. Based on the water saturation of the reservoir where the water-producing gas well is located and the gas-water two-phase interpermeability curve, determine the relative gas phase permeability of the water-producing gas well after water intrusion, which corresponds to the water saturation of the reservoir. The functional relationship between the water saturation of the reservoir where the water-producing gas well is located and the water-gas ratio is obtained in advance by inversion based on the flow equations of the water phase and gas phase of the water-producing gas well and the gas-water two-phase interpenetration curve of the reservoir.

9. The method as described in claim 8, characterized in that, The functional relationship between the water saturation of the reservoir and the water-to-gas ratio in the water-producing gas well is obtained in advance through inversion based on the flow equations of the water and gas phases of the water-producing gas well and the gas-water two-phase interpenetration curve of the reservoir, including: Based on the flow equations of the water and gas phases in the water-gas well, the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio is obtained. Based on the gas-water two-phase interpermeability curve of the reservoir, the ratio of the relative permeability of the gas and water phases to the ratio of the reservoir water saturation is calculated to obtain the functional relationship between the ratio of the relative permeability of the gas and water phases and the reservoir water saturation. Based on the functional relationship between the relative permeability ratio of the water and gas phases and the water-gas ratio, and the functional relationship between the relative permeability ratio of the water and gas phases and the reservoir water saturation, the functional relationship between the reservoir water saturation and the water-gas ratio is obtained.

10. The method as described in claim 9, characterized in that, The flow equations for the aqueous phase and the gas phase are as follows: in: q g —Daily gas production, 10 4 m 3 / d; q w —Daily water production, m 3 / d; K—Reservoir permeability, mD; K rw —Relative permeability of the aqueous phase in gas-liquid two-phase flow; K rg —Relative permeability of the gas phase in gas-liquid two-phase flow; h—Reservoir thickness, m; p R —Reservoir pressure, MPa; p wf — Bottom hole flowing pressure, MPa; ψ R —The corresponding reservoir pressure is p R Simulated pressure at time, MPa 2 / mPa.s; ψ wf —The corresponding bottom hole flowing pressure is p wf Simulated pressure at time, MPa 2 / mPa.s; μ w — Formation water viscosity, mPa·s; B w — Formation water volume factor, m 3 / m 3 ; r e —Well control radius, m; r w — Well radius, m; S—epidermal coefficient; D—Non-Darcy flow coefficient, d / 10 4 m 3 ; T—Reservoir temperature, K; μ g —Gas viscosity, mPa·s; Z—Gas compressibility factor, dimensionless.

11. The method as described in claim 7, characterized in that, The degree of production loss of the water-producing gas well after water intrusion is calculated according to the following formula: Where F is the value of the degree of capacity loss; Q AOFi Q represents the unobstructed flow rate of the water-producing gas well before water intrusion. AOF The unobstructed flow rate of the water-producing gas well under the influence of water intrusion.

12. The method as described in claim 7, characterized in that, The expression for the binomial productivity equation of the gas well is: in: Kh — the first formation coefficient value, mD.m; p R —The reservoir pressure, in MPa; p wf —The bottom hole flowing pressure, MPa; q g —The daily gas production, 10 4 m 3 / d; —Average gas viscosity, taken The value of time, mPa·s; —Gas average compressibility factor, taken as The value at time; A' and B' are coefficients.

13. The method as described in claim 7, characterized in that, The determination of the second formation coefficient value, used to characterize the gas phase flow capacity of a water-producing gas well in a pre-water-invasion reservoir, includes: The loss of gas phase flow capacity in the reservoir is determined based on the relative permeability of the gas phase after water intrusion and the relative permeability of the gas phase before water intrusion. The second formation coefficient value is determined based on the first formation coefficient value and the gas phase flow capacity loss value.

14. The method as described in claim 13, characterized in that, The second stratigraphic coefficient value is calculated according to the following formula: in: (Kh) i —The second stratigraphic coefficient value, mD.m; —The loss of gas phase flow capacity in the reservoir; K rgi —The relative permeability of the gas phase in the water-producing gas well before water intrusion; K rgn —The relative permeability of the gas phase in the water-producing gas well after water intrusion.

15. An apparatus for determining the water intrusion stage of a water-producing gas well, characterized in that, include: The water saturation determination module is used to determine the water saturation of the reservoir where the water-producing gas well is located based on the water-gas ratio of the water-producing gas well, the mine production data, and the pre-derived functional relationship between the water saturation and the water-gas ratio of the reservoir where the water-producing gas well is located. The water invasion stage determination module is used to determine the water invasion stage of the water-producing gas well based on the reservoir water saturation and the gas-water two-phase interpermeability curve in the mine. The inversion module, which is used to determine the functional relationship between the water saturation and the water-gas ratio of the reservoir where the water-producing gas well is located, is obtained in advance by inversion based on the flow equations of the water phase and gas phase of the water-producing gas well, as well as the gas-water two-phase interpenetration curve of the reservoir.

16. An apparatus for determining the degree of production capacity loss of a water-producing gas well, characterized in that, include: The first formation coefficient value determination module is used to determine the first formation coefficient value, which characterizes the gas phase flow capacity of the reservoir under the influence of water invasion, based on the gas well binomial production capacity equation and the mine production data. The second formation coefficient value determination module is used to determine the relative permeability of the gas phase of the water-producing gas well after water invasion, and the relative permeability of the gas phase of the water-producing gas well before water invasion. Determine the second formation coefficient used to characterize the gas phase flow capacity of water-producing gas wells in reservoirs before water invasion; An unobstructed flow rate determination module is used to determine the unobstructed flow rate of the water-producing gas well under the influence of water intrusion, and the unobstructed flow rate of the water-producing gas well before water intrusion. The capacity loss determination module is used to determine the capacity loss value of the water-producing gas well after water intrusion.

17. A computing 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 water invasion stage of a water-producing gas well as claimed in any one of claims 1-6, and the method for determining the degree of production capacity loss of a water-producing gas well as claimed in any one of claims 7-14.

18. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores a computer program that, when executed by a processor, implements the method for determining the water invasion stage of a water-producing gas well as described in any one of claims 1-6, and the method for determining the degree of production capacity loss of a water-producing gas well as described in any one of claims 7-14.

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