Water production prediction method for gas well with water gas reservoir

Abstract

The invention relates to a water-containing gas reservoir gas well water production prediction method, which has the technical scheme that a water drive characteristic curve equation considering water seal gas influence is deduced, upper and lower bounds of a heterogeneity coefficient A and a water invasion constant B are provided, and the heterogeneity coefficient A and the water invasion constant B are adjusted to fit an actual water-gas ratio so as to predict the water-gas ratio at a certain moment. And predicting the gas production rate at a certain moment through a yield decline method so as to predict the water production rate at a certain moment, and drawing a gas-water relative permeability fitting curve, a water-gas ratio prediction map and a gas production rate prediction map. The method has the advantages of being easy and convenient to operate and accurate in result, and has certain guiding significance on development of the gas well with the water gas reservoir.

Description

Technical Field

[0001] The invention relates to a method for predicting water production of a gas well in a water-containing gas reservoir, and belongs to the field of gas reservoir engineering. Background Art

[0002] Water-bearing gas reservoirs are widely distributed in my country, especially in the Sichuan Basin and other regions. These areas are not only rich in natural gas resources, but most of them are complex water-bearing gas reservoirs. The geological conditions of such gas reservoirs are variable, with various water distributions such as edge water and bottom water, and often lack a clear gas-water boundary. During the development process, water invasion poses a significant challenge to gas well production. When the gas well begins to produce water, the production pattern of gas and water becomes difficult to predict, which increases the technical difficulty of mining. For the current water-driven gas reservoirs, there is no simple and efficient method for predicting water production in gas wells. Therefore, there is an urgent need for simpler and more efficient means of predicting water invasion hazards to improve the development effect of water-bearing gas reservoirs.

[0003] At present, there is no simple method to predict water production in gas wells. This method is easy to operate and has accurate results, which has certain guiding significance for the development of gas wells in water-bearing gas reservoirs. Summary of the invention

[0004] The purpose of the present invention is to make a simpler and more accurate prediction of water production of gas wells in water-containing gas reservoirs in order to solve the problems existing in the prior art.

[0005] To achieve the above object, the present invention provides a method for predicting water production in a gas well of a water-containing gas reservoir, the method comprising the following steps:

[0006] S100, derive the water drive characteristic curve equation considering the influence of water seal gas, the steps are as follows:

[0007] S101. Define the reservoir heterogeneity coefficient as equation Water storage volume coefficient equation Substitute into the water seal reserve definition equation in sequence The water seal reserve equation is obtained:

[0008] G B =AGR B

[0009] Where A is the heterogeneity coefficient, unit is dimensionless; A H is the cross-sectional area of ​​the high permeability region, in m 2 ; A L is the cross-sectional area of ​​the low permeability region, in m 2 ; K H is the permeability of the high permeability area, in m 2 ; K L is the permeability of the low permeability area, in m2 ω is the water volume coefficient, unit is dimensionless; R is the recovery degree, which is calculated by the cumulative gas production G p Divided by the dynamic reserve G, the unit is dimensionless; B is the water invasion constant, the unit is dimensionless; R B is the water invasion constant of the production degree. According to the definition, the water invasion constant of the production degree is R B Equal to the water storage volume coefficient ω; W e is the water intrusion, in m 3 ; W p is the cumulative water production, in m 3 ; B w is the formation water volume coefficient, unit is dimensionless; B gi is the natural gas volume coefficient under original conditions, unit is dimensionless; G is the dynamic reserves, unit is ten thousand cubic meters; G B is the water seal reserve, in m 3 ;

[0010] S102, the water storage volume coefficient equation and the water storage equation G in S101 B =AGR B Substitute into the gas volume change equation one by one and the material balance equation of water-containing gas reservoir W e -W p B w =(GG B )B gi Derive the water saturation equation:

[0011]

[0012] In the formula, S w is water saturation, unit is dimensionless; S wi is the water saturation under original conditions, unit is dimensionless;

[0013] S103, the water saturation equation derived in S103 Substitute into the water-gas ratio equation The water drive characteristic curve equation considering the influence of water seal gas is derived:

[0014]

[0015] Where WGR is the water-gas ratio, in cubic meters; μ g is the viscosity of natural gas, in mPa·s; μ w is the formation water viscosity, in mPa·s; B w is the formation water volume coefficient, unit is dimensionless; B g is the volume coefficient of natural gas, defined as The unit is dimensionless; p sc is the surface pressure, in MPa; p is the formation pressure, in MPa; T is the formation temperature, in K; T sc is the ground temperature, in K; Z is the gas deviation factor under formation conditions, in dimensionless units; Z sc is the gas deviation factor under ground conditions, and its unit is dimensionless; n and b are constants related to reservoir and fluid properties, obtained by fitting the gas-water relative permeability curve, and their unit is dimensionless;

[0016] S200, prepare production data, give the upper and lower limits of the two parameters of reservoir heterogeneity coefficient A and water invasion constant B, where the upper limit of reservoir heterogeneity coefficient A is infinite, the lower limit of reservoir heterogeneity coefficient A is 0, the upper limit of water invasion constant B is 20, the lower limit of water invasion constant B is 1, and the initial value within the limit is randomly given; dynamic reserves G is a known parameter, and reservoir heterogeneity coefficient A and water invasion constant B are both variable parameters; adjust heterogeneity coefficient A and water invasion constant B to fit the actual water-gas ratio to predict the water-gas ratio at a certain moment, so as to find the best fit between the predicted value and the measured value; the convergence standard of water-gas ratio fitting can be expressed as:

[0017]

[0018] Where, MAPE is the relative percentage of error, unit is dimensionless; n is the number of iterations; WGR i (A, B) is the predicted water-gas ratio, in cubic meters / cubic meters; WGR i is the actual water-gas ratio, in cubic meters / cubic meters;

[0019] S300, the idea of ​​predicting the water production of the gas well is: use the Arps production decline method to predict the gas production of the gas well at a certain moment, substitute the predicted gas production into the predicted water-gas ratio in S200 to obtain the predicted water production of the gas well at a certain moment. BRIEF DESCRIPTION OF THE DRAWINGS

[0020] Figure 1 It is the technical roadmap of this method;

[0021] Figure 2 This is the relative permeability fitting diagram of a gas well in a water-containing gas reservoir;

[0022] Figure 3 It is a water-gas ratio prediction diagram of a gas well in a water-gas reservoir;

[0023] Figure 4 This is a gas production prediction chart for a gas well in a water-containing gas reservoir. DETAILED DESCRIPTION

[0024] The present invention provides a method for predicting water production in a gas well in a water-containing gas reservoir. Figure 1For the technical roadmap of this method, the following steps are implemented for a domestic water gas reservoir:

[0025] Step 1: Derive the water drive characteristic curve equation considering the influence of water-locked gas: Define the reservoir heterogeneity coefficient as Water storage volume coefficient equation Substitute into the water seal reserve definition equation in sequence The water seal reserve equation is obtained:

[0026] G B =AGR B

[0027] Where A is the heterogeneity coefficient, unit is dimensionless; A H is the cross-sectional area of ​​the high permeability region, in m 2 ; A L is the cross-sectional area of ​​the low permeability region, in m 2 ; K H is the permeability of the high permeability area, in m 2 ; K L is the permeability of the low permeability area, in m 2 ω is the water volume coefficient, unit is dimensionless; R is the recovery degree, which is calculated by the cumulative production G p Divided by the dynamic reserve G, the unit is dimensionless; B is the water invasion constant, the unit is dimensionless; R B is the water invasion constant of the production degree. According to the definition, the water invasion constant of the production degree is R B Equal to the water storage volume coefficient ω; W e is the water intrusion, in m 3 ; W p is the cumulative water production, in m 3 ; B w is the formation water volume coefficient, unit is dimensionless; B gi is the natural gas volume coefficient under original conditions, unit is dimensionless; G is the dynamic reserves, unit is ten thousand cubic meters, take 73.5; G B is the water seal reserve, in m 3 ; Then the water storage volume coefficient equation And the derived water storage equation G B =AGR B Substitute into the gas volume change equation one by one and the material balance equation of water-containing gas reservoir W e -W p B w =(GG B )B gi Derive the water saturation equation:

[0028]

[0029] In the formula, S w is water saturation, unit is dimensionless; S wi is the water saturation under the original conditions, the unit is dimensionless, and it is taken as 0.43; then the derived water saturation equation Substitute into the water-gas ratio equation The water drive characteristic curve equation considering the influence of water seal gas is derived:

[0030]

[0031] Where WGR is the water-gas ratio, in cubic meters; μ g is the viscosity of natural gas, in mPa·s, and is taken as 0.02; μ w is the formation water viscosity, in mPa·s, and is taken as 0.5; w is the formation water volume coefficient, dimensionless, and is taken as 1.03; B g is the volume coefficient of natural gas, defined as The unit is dimensionless; p sc is the surface pressure, in MPa, taken as 0.101; p is the formation pressure, in MPa; T is the formation temperature, in K, taken as 330; T sc is the ground temperature, in K, taken as 293.15; Z is the gas deviation factor under formation conditions, in dimensionless units, calculated by the formation pressure according to the DAK method;; Z sc is the gas deviation factor under ground conditions, which is 1; the unit is dimensionless; n and b are constants related to reservoir and fluid properties, which are obtained by fitting the gas-water relative permeability curve, and the unit is dimensionless; n is 28042863055.035, b is 25.95, and the fitting effect is as follows: Figure 2 As shown;

[0032] Step 2: Prepare production data and predict the future water-gas ratio: Given the upper and lower limits of the two parameters, reservoir heterogeneity coefficient A and water invasion constant B, the upper limit of reservoir heterogeneity coefficient A is infinite, the lower limit of reservoir heterogeneity coefficient A is 0, the upper limit of water invasion constant B is 20, the lower limit of water invasion constant B is 1, and the initial value within the limit is randomly given; dynamic reserves G is a known parameter, and reservoir heterogeneity coefficient A and water invasion constant B are both variable parameters; adjust heterogeneity coefficient A and water invasion constant B to fit the actual water-gas ratio to predict the water-gas ratio at a certain moment, so as to find the best fit between the predicted value and the measured value; the convergence standard of water-gas ratio prediction can be expressed as:

[0033]

[0034] Where, MAPE is the relative percentage of error, unit is dimensionless; n is the number of iterations; WGRi (A, B) is the predicted water-gas ratio, in cubic meters / cubic meters; WGR i is the actual water-gas ratio, in cubic meters / cubic meters;

[0035] After the prediction is successful, stop adjusting the two parameters of heterogeneity coefficient A and water invasion constant B. According to the prediction results at this time, when the recovery degree is 0.63, the predicted value of water-gas ratio WGR is 0.024. The prediction effect is as follows: Figure 3 As shown;

[0036] Step 3: According to the prediction results of Arps production decline method, when the recovery degree is 0.63, the daily gas production is 58,600 cubic meters. The fitting results are as follows Figure 4 As shown; at this time, it can be calculated that when the recovery degree is 0.63, the daily water production is 1406 cubic meters;

[0037] Finally, it should be noted that the above embodiments are only used to illustrate rather than limit the technical solutions of the present invention. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art should understand that the present invention can still be modified or replaced by equivalents. Any modification or partial replacement that does not depart from the spirit and scope of the present invention should be included in the scope of the claims of the present invention.

Claims

1. A method for predicting water production in a gas well in a water-containing gas reservoir, characterized in that: The method comprises the following steps: S100, derive the water drive characteristic curve equation considering the influence of water seal gas, the steps are as follows: S101. Define the reservoir heterogeneity coefficient as equation Water storage volume coefficient equation Substitute into the water seal reserve definition equation in sequence The water seal reserve equation is obtained: G B =AGR B Where A is the heterogeneity coefficient, unit is dimensionless; A H is the cross-sectional area of ​​the high permeability region, in m 2 ; A L is the cross-sectional area of ​​the low permeability region, in m 2 ; K H is the permeability of the high permeability area, in m 2 ; K L is the permeability of the low permeability area, in m 2 ω is the water volume coefficient, unit is dimensionless; R is the recovery degree, which is calculated by the cumulative gas production G p Divided by the dynamic reserve G, the unit is dimensionless; B is the water invasion constant, the unit is dimensionless; R B is the water invasion constant of the production degree. According to the definition, the water invasion constant of the production degree is R B Equal to the water storage volume coefficient ω; W e is the water intrusion, in m 3 ; W p is the cumulative water production, in m 3 ; B w is the formation water volume coefficient, unit is dimensionless; B gi is the natural gas volume coefficient under original conditions, unit is dimensionless; G is the dynamic reserves, unit is ten thousand cubic meters; G B is the water seal reserve, in m 3 ; S102, the water storage volume coefficient equation and the water storage equation G in S101 B =AGR B Substitute into the gas volume change equation one by one and the material balance equation of water-containing gas reservoir W e -W p B w =(GG B )B gi Derive the water saturation equation: In the formula, S w is water saturation, unit is dimensionless; S wi is the water saturation under original conditions, unit is dimensionless; S103, the water saturation equation derived in S103 Substitute into the water-gas ratio equation The water drive characteristic curve equation considering the influence of water seal gas is derived: Where WGR is the water-gas ratio, in cubic meters; μ g is the viscosity of natural gas, in mPa·s; μ w is the formation water viscosity, in mPa·s; B w is the formation water volume coefficient, unit is dimensionless; B g is the volume coefficient of natural gas, defined as The unit is dimensionless; p sc is the surface pressure, in MPa; p is the formation pressure, in MPa; T is the formation temperature, in K; T sc is the ground temperature, in K; Z is the gas deviation factor under formation conditions, in dimensionless units; Z sc is the gas deviation factor under ground conditions, and its unit is dimensionless; n and b are constants related to reservoir and fluid properties, obtained by fitting the gas-water relative permeability curve, and their unit is dimensionless; S200, prepare production data, give the upper and lower limits of the two parameters of reservoir heterogeneity coefficient A and water invasion constant B, where the upper limit of reservoir heterogeneity coefficient A is infinite, the lower limit of reservoir heterogeneity coefficient A is 0, the upper limit of water invasion constant B is 20, the lower limit of water invasion constant B is 1, and the initial value within the limit is randomly given; dynamic reserves G is a known parameter, and reservoir heterogeneity coefficient A and water invasion constant B are both variable parameters; adjust heterogeneity coefficient A and water invasion constant B to fit the actual water-gas ratio to predict the water-gas ratio at a certain moment, so as to find the best fit between the predicted value and the measured value; the convergence standard of water-gas ratio prediction can be expressed as: Where, MAPE is the relative percentage of error, unit is dimensionless; n is the number of iterations; WGR i (A, B) is the predicted water-gas ratio, in cubic meters / cubic meters; WGR i is the actual water-gas ratio, in cubic meters / cubic meters; S300, the idea of ​​predicting the water production of the gas well is: use the Arps production decline method to predict the gas production of the gas well at a certain moment, substitute the predicted gas production into the predicted water-gas ratio in S200 to obtain the predicted water production of the gas well at a certain moment.

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