A method for calculating water production in gas wells based on wellbore pressure gradient

Abstract

This invention belongs to the field of oil and gas field development technology and relates to a method for calculating gas well water production based on wellbore pressure gradient. Specifically, it involves acquiring the target gas well's flowing pressure test data, calculating the density of the gas-water two-phase flow mixture at the wellbore flowing pressure test point under the given conditions according to a gas-water two-phase flow model, calculating the water holdup at the wellbore flowing pressure test point under the current conditions based on regional fluid characteristics and the wellbore mixed fluid density, converting the water holdup to a water-gas ratio under standard conditions, and calculating the water production of a single well based on the metered gas production. The gas well water production calculation method based on wellbore pressure gradient established by the above process solves the problem of inaccurate water production measurement in some gas wells, realizing quantitative calculation of gas and water production, which is of great significance for the formulation of gas well production management measures and the refined development of gas fields.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development technology, specifically relating to a method for calculating water production of gas wells based on wellbore pressure gradient. Background Technology

[0002] In gas field development, gas production and water production are fundamental parameters and core indicators for evaluating well production dynamics and development efficiency. However, due to factors such as surface technology, some gas wells only measure gas production per well, which is relatively accurate, while water production cannot be measured. Water production data is often split based on human experience, resulting in distorted water production data for some gas wells and failing to effectively guide the analysis of gas well production dynamics.

[0003] Currently, two-phase metering is often used to accurately obtain the water production of gas wells. However, some wells cannot have their water production measured due to factors such as surface conditions. Therefore, some scholars have proposed methods for calculating the water production of gas wells. In 2017, Li Hong published a paper titled "A Method for Calculating Water Production of Condensate Gas Wells Based on Pressure Gradient" in *Chinese Science and Technology Papers*. Addressing the issue that wellhead gas and water production cannot be measured in the Yingmaili gas field, this paper proposes a method to calculate the water production of condensate gas reservoirs using wellbore pressure gradient data. Specifically, it assumes different water production rates and compares and analyzes the wellbore profile pressure values ​​obtained through the Hagedown-Brown model with the measured values. When the required accuracy is achieved, the corresponding water production is the desired value. This method involves complex model calculations and requires continuous iteration of the water production data. Patent No. CN 117520701 A, entitled "A Method, System, Medium, and Equipment for Calculating Daily Water Production at the Wellhead of a Water-Reaching Well," primarily uses the theoretical fluid density and the density of the mixed-phase fluid within the wellbore to determine the first equation for calculating the daily water production at the wellhead. A second equation is derived based on the mass of the produced gas. The volume of the daily gas production at the wellhead under formation conditions is determined using the formation gas volume coefficient, resulting in a third equation for calculating the daily water production. Substituting the second and third equations into the first equation yields a fourth equation for calculating the daily water production at the wellhead, which is then used to determine the total daily water production at the wellhead. However, this method does not consider the influence of wellbore inclination and bottom-hole pressure gradient on the fluid production of the gas well. When the inclination is large or there is fluid accumulation at the bottom of the well, its application in the mining field exhibits significant deviations.

[0004] In summary, existing methods for calculating gas well water production using pressure gradients are not very practical in mining operations and have low accuracy, failing to meet the dynamic needs of gas well production. Summary of the Invention

[0005] To address the above issues, the present invention aims to provide a method for calculating water production from gas wells based on wellbore pressure gradients. This method involves acquiring target gas well flow pressure test data; calculating the density of the gas-water two-phase flow mixture at the wellbore flow pressure test point based on a gas-water two-phase flow model; calculating the water holdup at the wellbore flow pressure test point under the current condition based on regional fluid characteristics and the density of the wellbore mixture; converting the water holdup into a water-gas ratio under standard conditions; and calculating the water production from a single well based on the metered gas production from that well.

[0006] To achieve the above objectives, the technical solution adopted by the present invention is: to provide a method for calculating the water production of gas wells based on wellbore pressure gradient, specifically including the following steps:

[0007] 1) Obtain the target gas well flowing pressure test data;

[0008] Select target gas well flow pressure test data in the target area to ensure the reliability of the flow pressure data; the acquisition of target gas well flow pressure test data includes the depth, vertical depth, pressure and temperature of the test point.

[0009] 2) Calculate the density of the gas-water two-phase flow mixture under the wellbore pressure test conditions based on the gas-water two-phase flow model;

[0010] During the vertical wellbore ascent of a gas well, pressure loss occurs due to the fluid's own gravity and the resistance of the gas-liquid two-phase flow. Based on the gas-water two-phase flow model, the ascent process is dominated by annular mist flow; therefore, it is simplified to a vertical wellbore pressure model, i.e.: ;

[0011] The wellbore pressure gradient is: ;

[0012] The density of the gas-water two-phase mixture at the test location inside the wellbore can be determined from the pressure gradient. ;

[0013] In the formula: ΔP is the pressure increment in the vertical pipe, MPa; ρ gw Density of the gas-water mixture, kg / m³ 3 g is the acceleration due to gravity, N / kg; ΔH is the vertical pipe depth increment, 100m; ▽P is the flow pressure gradient at the test point, MPa / 100m.

[0014] 3) Calculate the water holdup at the wellbore flow pressure test point under the current condition based on the regional fluid characteristics and the density of the mixed fluid in the wellbore;

[0015] Based on the gas composition and formation water characteristics of the target formation in the region, the densities of natural gas and formation water are determined; then, based on the pressure gradient and pressure data of the selected wellbore flowing pressure test points, the volume ratio of water and natural gas at the corresponding depth is calculated, thereby obtaining the water holdup rate;

[0016] Formula for calculating the density of natural gas at the selected test point: ;

[0017] Formula for calculating water holding capacity at selected test points:

[0018] ;

[0019] ;

[0020] In the formula: ρ g0 The density of natural gas under standard conditions, kg / m³ 3 ;ρ g To select the natural gas density under the test conditions in the wellbore, kg / m³ 3 ;ρ w Density of formation water, kg / m³ 3 ;P sc P represents the gas pressure under standard conditions, in MPa. wf To select the natural gas pressure at the wellbore test point, MPa; H w The water holdup of the mixture under the condition of selecting the wellbore test point is dimensionless.

[0021] 4) Based on the water holding capacity, convert it to the water-air ratio under standard conditions;

[0022] According to the gas law: ;

[0023] In the formula: V sc The volume of a gas under standard conditions is m. 3 ;T sc V represents the absolute temperature of a gas under standard conditions, expressed in Kelvin (K). wf The gas volume at the wellbore test point is in meters (m). 3 ;T wf Let K be the absolute temperature of the gas at the wellbore test point.

[0024] The volume coefficient of the gas at the wellbore test point is obtained from the pressure and temperature at that point. ;

[0025] The water-air ratio under standard conditions is calculated from the pressure-volume coefficient and water holdup at the wellbore test points: ;

[0026] Where: α is the water-air ratio under standard surface conditions, m 3 / m 3 B g The volume coefficient is dimensionless and is used to select the wellbore test point conditions.

[0027] 5) Calculate the water production of a single well based on the gas production of that well.

[0028] Based on the daily gas production and water-gas ratio data of the target well, the daily water production of the single well is calculated: ;

[0029] Where: q w For the target well's single-well water production, m 3 / d;q g The target well's single-well gas production under standard conditions, in m 3 / d.

[0030] The beneficial effects of this invention are: it establishes a method for calculating the water production of gas wells based on the wellbore pressure gradient, which solves the problem that some gas wells cannot accurately measure the water production, and realizes the quantitative calculation of gas and water production of gas wells, which is of great significance for the formulation of gas well production management measures and the refined development of gas fields. Attached Figure Description

[0031] Figure 1 This is a flowchart of a gas well water production calculation method based on wellbore pressure gradient according to the present invention.

[0032] Figure 2 This is a graph showing the flowing pressure and flowing temperature data of well A in the target area of ​​this invention;

[0033] Figure 3 This is a graph showing the flowing pressure and flowing temperature data of well B in the target area of ​​this invention. Detailed Implementation

[0034] To make the objectives, technical solutions, and beneficial effects of this invention clearer, the invention will be further described in detail below with reference to the accompanying drawings and embodiments.

[0035] Taking the X gas field in a domestic basin as an example, this gas field is characterized by tight, low-permeability, and high water saturation. It is mainly developed using horizontal wells in single layers, and while most wells produce water, the water production varies significantly. The main target layer, the He 1 section gas reservoir, has a relative density of 0.608 under standard conditions, and an absolute density ρ under standard conditions. g0 It is 0.786 kg / m 3 Formation water density ρ w 1040 kg / m 3 .

[0036] (1) Obtain the target gas well flowing pressure test data;

[0037] Based on the flowing pressure test data of target well A, pressure, temperature, and pressure gradient data at different depths were obtained, as shown in Table 1. The table shows that the section above 2470m is primarily vertical, while the section below 2470m is inclined. The flowing pressure and temperature are consistent across all depths of the wellbore, and no significant fluid accumulation was observed. Figure 1 As shown.

[0038] Table 1. Flow pressure data of Well A in Gas Field X

[0039]

[0040] (2) Calculate the density of the gas-water two-phase flow mixture under the wellbore pressure test point conditions based on the gas-water two-phase flow model;

[0041] As the gas and water move upward through the wellbore, their pressure gradually decreases due to their own weight and frictional resistance. In vertical pipe flow, the pressure loss is mainly caused by their own weight. Near the wellhead, the gas-water mixture is mainly in the form of mist, and the gas and water move at basically the same speed. Therefore, the parameters of the test point 500m away from the wellhead are selected as the calculation data.

[0042] Table 1 shows that the selected wellbore test point has a vertical depth of 500m and a fluid flow pressure P. wf The pressure is 8.171 MPa, and the fluid temperature T is... wf The temperature is 40.18℃, which is 313.18K. The wellhead pressure is 7.245MPa. Therefore, the vertical pipe pressure increment ΔP is 0.926MPa, the vertical pipe depth increment ΔH is 500m, and the vertical depth pressure gradient ▽P is 0.185MPa / 100m.

[0043] .

[0044] The density ρ of the gas-water two-phase flow mixture at 500m can be obtained from the formulas for calculating the wellbore fluid pressure gradient and the gas-water mixture density. gw It is 188.78 kg / m 3 ;

[0045] .

[0046] (3) Calculate the water holdup at the wellbore flow pressure test point under the current condition based on the regional fluid characteristics and the density of the mixed fluid in the wellbore;

[0047] Based on the fluid analysis data of the target layer in this area, the relative density of natural gas is 0.608, and the density of air is 1.293 kg / m³. 3 The density ρ of the natural gas in the gas reservoir under standard conditions is... g0 It is 0.786 kg / m 3 Because the natural gas is at pressure P at the test point wf If the pressure is 8.171 MPa, then the density ρ of the natural gas at the test point after compression is... g It is 104.60 kg / m 3 ;

[0048] ;

[0049] The formation water density ρ of the target layer in this area w 1040 kg / m3 Then, the water holding capacity H at the test point can be calculated using the formula. w It is 0.0900;

[0050] ;

[0051]

[0052] (4) Based on the water holding capacity at the test point, convert it into the water-air ratio under standard conditions;

[0053] Based on the pressure and temperature data at the selected wellbore test points, and combining the gas state equation and the volume coefficient equation, the volume coefficient B at the test points is calculated. g It is 0.01418;

[0054] ;

[0055] ;

[0056] When the gas-water mixture at the wellbore test point is transported to the surface under standard conditions, the water, being a liquid, experiences minimal volume change due to pressure, and its volume remains essentially unchanged upon reaching the surface. Natural gas, however, expands easily, resulting in a larger volume upon reaching the surface. Therefore, by combining the volume coefficient and water holdup, the water-to-gas ratio of the gas-water mixture at the test point under standard surface conditions can be calculated. It is 0.00128m 3 / m 3 ;

[0057]

[0058] (5) Calculate the water production of a single well based on the gas production of the single well.

[0059] According to the production report, gas and water were separately metered on the day of the flowing pressure test of target well A, and the gas production was q. g 49405m 3 / d, water production 65.0m³ 3 / d, the water production can be calculated from the gas production and gas-water ratio of well A. It is 63.0m 3 / d;

[0060]

[0061] like Figure 2 As shown, the daily water production of well A was 65.0 m³. 3 / d and calculated water production of 63.0 m³ 3 A comparison by / d shows that the data are basically consistent, with an absolute error of 2.0m. 3 The relative error was 3.08%, indicating that the calculation method is reliable.

[0062] like Figure 3 As shown in Table 2, the flowing pressure data of Well B in the Rituo gas field indicates the presence of liquid accumulation in the wellbore, with a measured water production of 11.0 m³. 3 / d, the water production rate can be calculated to be 12.0m³ using this method. 3 / d, with small measurement error.

[0063] Table 2 Flow pressure data of Well B in Gas Field X

[0064]

[0065] Table 3 compares the water production calculations of wells with and without liquid accumulation in the X gas field using different methods. The method in this study, which uses the pressure gradient of the vertical section of the wellbore to calculate water production, has high accuracy and small error, and is not affected by liquid accumulation at the bottom of the well.

[0066] Table 3 Comparison of Water Production from Different Types of Gas Wells and Different Methods

[0067]

[0068] In summary, this invention establishes a method for calculating water production in gas wells based on wellbore pressure gradients, effectively solving the problem that some gas wells cannot accurately measure water production. It realizes quantitative calculation of gas and water production in gas wells, which is of great significance for the formulation of gas well production management measures and the refined development of gas fields.

Claims

1. A method for calculating water production from gas wells based on wellbore pressure gradient, characterized in that, Includes the following steps: (1) Obtain the target gas well flowing pressure test data; Based on the gas-water two-phase flow model, the upward flow in the vertical pipe is dominated by annular mist flow. The water production is calculated by selecting the pressure gradient of the vertical section of the wellbore. The target gas well flow pressure test data is obtained, including the depth of the test point, vertical depth, pressure, and temperature. (2) Calculate the density of the gas-water two-phase flow mixture under the wellbore pressure test point conditions based on the gas-water two-phase flow model; Based on the gas-water two-phase flow model, the upward flow process in a vertical pipe is dominated by annular mist flow, which can be simplified into a vertical wellbore pressure model: ; The wellbore pressure gradient is: ; The density of the gas-water two-phase mixture at the test location inside the wellbore is determined from the flowing pressure gradient. ; Where: ΔP is the pressure increment in the vertical pipe, MPa; ρ gw Density of the gas-water mixture, kg / m³ 3 g is the acceleration due to gravity, N / kg; ΔH is the vertical pipe depth increment, 100m; ▽P is the flow pressure gradient at the test point, MPa / 100m; (3) Calculate the water holdup at the wellbore flow pressure test point under the current condition based on the regional fluid characteristics and the density of the mixed fluid in the wellbore; Specifically, the density of natural gas and formation water is determined based on the gas composition and formation water characteristics of the target layer in the region; the volume ratio of water and natural gas at the corresponding depth is calculated based on the pressure gradient and pressure at the selected wellbore flowing pressure test points, thereby obtaining the water holdup. Formula for calculating the density of natural gas at the selected test point: ; ； The formula for calculating the water holding capacity of the selected test points is as follows: ; In the formula: ρ g0 The density of natural gas under standard conditions, kg / m³ 3 ;ρ g To select the natural gas density under the test conditions in the wellbore, kg / m³ 3 ;ρ w Density of formation water, kg / m³ 3 ;P sc P represents the gas pressure under standard conditions, in MPa. wf To select the natural gas pressure at the wellbore test point, MPa; H w The water holdup of the mixture under the condition of selecting the well test point is dimensionless; (4) Based on the water holding capacity, convert it to the water-air ratio under standard conditions; The water-air ratio under standard conditions is calculated from the pressure-volume coefficient and water holdup at the wellbore test points: ; Where: α is the water-air ratio under standard surface conditions, m 3 / m 3 B g The volume factor, dimensionless, is used to select the wellbore test point condition; H w The water holdup of the mixture under the condition of selecting the well test point is dimensionless; (5) Calculate the water production of a single well based on the gas production of the single well.

2. The method for calculating gas well water production based on wellbore pressure gradient according to claim 1, characterized in that, In step (4), according to the gas law: ； Among them, V sc The volume of a gas under standard conditions is m. 3 ;T sc V represents the absolute temperature of a gas under standard conditions, expressed in Kelvin (K). wf The gas volume at the wellbore test point is in meters (m). 3 ;T wf Let K be the absolute temperature of the gas at the wellbore test point. The volume coefficient of the gas at the wellbore test point is obtained from the pressure and temperature at that point. ; The water-air ratio under standard conditions is calculated from the pressure-volume coefficient and water holdup at the wellbore test points: ; Where: α is the water-air ratio under standard surface conditions, m 3 / m 3 B g The volume factor, dimensionless, is used to select the wellbore test point condition; P sc P represents the gas pressure under standard conditions, in MPa. wf To select the natural gas pressure at the wellbore test point, MPa; H w The water holdup of the mixture under the condition of selecting the wellbore test point is dimensionless.

3. The method for calculating gas well water production based on wellbore pressure gradient according to claim 1, characterized in that, In step (5), the water production of a single well is calculated based on the gas production of that single well: ； Where, q w For the target well's single-well water production, m 3 / d;q g The target well's single-well gas production under standard conditions, in m 3 / d, ɑ represents the water-air ratio under standard surface conditions, m 3 / m 3 .

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