Shale gas horizontal well accumulated liquid position judgment method
阅读说明：本技术 一种页岩气水平井积液位置判断方法 (Shale gas horizontal well accumulated liquid position judgment method ) 是由 郭洪金 王大江 纪国法 孙志扬 张公社 许崇祯 于 2020-05-25 设计创作，主要内容包括：本申请提供一种页岩气水平井积液位置判断方法,涉及页岩气领域；其包括以下步骤：S1.计算页岩气水平井沿井筒分布的压力温度剖面,判断沿所述井筒方向的流型分布,计算所述井筒不同位置处的气体流速；S2.计算天然气偏差系数随压力温度的变化,已知天然气组分组成,计算出天然气拟临界压力、拟临界温度；S3.计算页岩气水平井的水平段、倾斜段以及垂直段三处的临界携液流量；S4.计算临界携液流量并对比不同位置处的气体真实流量,根据井眼轨迹分布绘制不同参数下产量与临界携液流量沿井眼轨迹对比变化图,根据所述对比变化图判断出积液的位置。该方法建立了一套系统的判断水平井中的积液位置的方法,提高了判断积液位置的准确度。(The application provides a method for judging the position of a liquid accumulation in a shale gas horizontal well, which relates to the field of shale gas; which comprises the following steps: s1, calculating a pressure temperature profile of a shale gas horizontal well distributed along a shaft, judging flow pattern distribution along the shaft direction, and calculating gas flow rates at different positions of the shaft; s2, calculating the variation of the natural gas deviation coefficient along with the pressure and temperature, knowing the composition of natural gas components, and calculating the pseudo-critical pressure and the pseudo-critical temperature of the natural gas; s3, calculating critical liquid carrying flow rates of the horizontal section, the inclined section and the vertical section of the shale gas horizontal well; and S4, calculating critical liquid carrying flow, comparing the actual gas flow at different positions, drawing a comparison change diagram of the yield and the critical liquid carrying flow along the well track under different parameters according to the well track distribution, and judging the position of the effusion according to the comparison change diagram. The method establishes a systematic method for judging the position of the accumulated liquid in the horizontal well, and improves the accuracy of judging the position of the accumulated liquid.)
1. The method for judging the position of the effusion of the shale gas horizontal well is characterized by comprising the following steps of:
s1, calculating a pressure temperature profile of a shale gas horizontal well distributed along a shaft, judging flow pattern distribution along the shaft direction, and calculating gas flow rates at different positions of the shaft;
s2, calculating the variation of the natural gas deviation coefficient along with the pressure and temperature, knowing the composition of natural gas components, and calculating the pseudo-critical pressure and the pseudo-critical temperature of the natural gas;
s3, calculating critical liquid carrying flow rates of the horizontal section, the inclined section and the vertical section of the shale gas horizontal well;
s4, calculating critical liquid carrying flow, comparing the actual gas flow at different positions, drawing a comparison change diagram of the yield and the critical liquid carrying flow along the well track under different parameters according to the well track distribution, and judging the position of the effusion according to the comparison change diagram; if the critical liquid carrying gas amount in the comparison change diagram is larger than the actual gas production amount, liquid is accumulated in the shale gas horizontal well section; and if the critical liquid carrying gas amount in the comparison change diagram is less than the actual gas production amount, no liquid is accumulated in the shale gas horizontal well section.
2. The method for determining the location of the liquid accumulation in the shale gas horizontal well according to claim 1, wherein in step S1, a boggs-Brill method is used to calculate the pressure-temperature profile of the shale gas horizontal well along the wellbore, and the boggs-Brill method comprises the following formula:
in the formula: p-pressure; z-length in the direction of the wellbore;-a pressure gradient; rhol-a liquid density; hl-liquid holdup; rhog-a gas density; g-acceleration of gravity; theta is the included angle between the pipe column and the horizontal direction; lambda-flow resistance coefficient; g-mass flow of the mixture; v-the average velocity of the mixture; d, the inner diameter of the oil pipe; a-the cross-sectional flow area of the tube; vsg-gas phase superficial flow rate.
3. The method for determining the location of the liquid accumulation in the shale gas horizontal well according to claim 2, wherein in the step S1, the method comprises the following steps:
s11, determining the calculated initial point pressure p, the calculated number n of sections and the section depth delta h according to basic data by adopting a formula of a Beggs-Brill method;
s12, assuming that the pressure difference in the calculation section is △ p, calculating the tail end pressure ph1 in the calculation section, and calculating the average pressure in the calculation sectionMean temperature
s13, calculating pressure difference delta p ' and tail end pressure p ' in the calculation section 'h1If | p 'is satisfied'h1-ph1If the absolute value is less than 0.0001, the calculated terminal pressure is used as the starting point pressure of the next section; if not satisfy | p'h1-ph1If l is less than 0.0001, then p 'is replaced'h1Replacing ph1, and continuing to calculate until the error requirement is met;
s14, repeating the steps S11 to S13 to continue to calculate the next segment of pressure distribution until all the calculation segments are calculated.
4. The method according to claim 3, wherein the basic data in step S11 includes liquid density, gas density, liquid phase volume flow, gas phase volume flow, liquid surface tension, gravitational acceleration, liquid viscosity, gas viscosity, wellbore inclination angle, tubing inner diameter, wellhead temperature, and temperature gradient.
5. The shale gas horizontal well liquid accumulation position judgment method according to claim 1, wherein in step S2, a Dranchuk-Abu-Kassem method is adopted to calculate the natural gas deviation coefficient along with the pressure and temperature, and the Dranchuk-Abu-Kassem method comprises the following formula:
and (3) performing iterative calculation on Z by adopting a Newton iterative method, wherein: z-natural gas deviation coefficient, a 1-0.3265, a 2-1.0700, TprTo planCritical temperature, A3-0.5339, a 4-0.01569, a 5-0.05165, ρprDimensionless contrast density, a6 ═ 0.5457, a7 ═ 0.7361, A8 ═ 0.1844, a9 ═ 0.1056, a10 ═ 0.6134, a11 ═ 0.7210, Ppr-pseudo-critical pressure.
6. The method for determining the location of the liquid accumulation in the shale gas horizontal well according to claim 1, wherein in step S3, the critical gas production rate of the shale gas horizontal well is:
in the formula: qcrCritical gas production, m3D; a-cross-sectional area of oil pipe, m2，
7. The method for determining the location of the liquid accumulation in the shale gas horizontal well according to claim 1, wherein in step S3, the critical velocity of the vertical section of the shale gas horizontal well is:
in the formula: g-acceleration of gravity; sigma-gas-water interfacial tension, N/cm; rholLiquid density, kg/m3；ρgGas density, kg/m3。
8. The method for determining the location of the liquid accumulation in the shale gas horizontal well according to claim 1, wherein in step S3, the critical velocity of the inclined section of the shale gas horizontal well is:
in the formula: g-acceleration of gravity; sigma-gas-water interfacial tension, N/cm; rholLiquid density, kg/m3；ρgGas density, kg/m3α -oblique angle of hole.
9. The method for determining the location of the liquid accumulation in the shale gas horizontal well according to claim 1, wherein in step S3, the critical speed of the horizontal well section of the shale gas horizontal well is:
in the formula: g-acceleration of gravity; sigma-gas-water interfacial tension, N/cm; rholLiquid density, kg/m3；ρgGas density, kg/m3。
Technical Field
The application relates to the field of shale gas, in particular to a shale gas horizontal well accumulated liquid position judgment method.
Background
Shale gas is an unconventional oil and gas resource which has large reserves and is difficult to mine, and in recent years, the shale gas realizes the industrialized and commercialized development due to the rapid development, maturity and perfection of domestic long horizontal well staged fracturing theory, technology and equipment. The shale gas generally has the characteristics of high initial yield, quick yield decrease in middle and later periods and low flowback rate. The fracturing fluid and gas are from the stratum to the well bottom to the well head for a long time, more stratum energy needs to be consumed, and when the later stratum pressure is insufficient, the fluid can be stagnated at the well bottom or a horizontal section, so that the technical problem of stable production work of shale gas discharging and production is caused, particularly, the uncertainty of the position of accumulated fluid is instructive to the selection of a discharging and production process.
The development time of shale gas at home and abroad is short, the later-stage drainage theory and technology generally use conventional natural gas means for reference, the connection with the specificity of the long horizontal section of the shale gas cannot be established, and the published report of the judgment method of the liquid accumulation position of the shale gas horizontal well is not seen at present.
Disclosure of Invention
The application provides a shale gas horizontal well effusion position judgment method, which solves the problem that in the prior art, the position of effusion cannot be judged accurately and systematically in a shale gas horizontal well.
The technical scheme of the application is as follows:
a shale gas horizontal well accumulated liquid position judgment method comprises the following steps:
s1, calculating a pressure temperature profile of a shale gas horizontal well distributed along a shaft, judging flow pattern distribution along the shaft direction, and calculating gas flow rates at different positions of the shaft;
s2, calculating the variation of the natural gas deviation coefficient along with the pressure and temperature, knowing the composition of natural gas components, and calculating the pseudo-critical pressure and the pseudo-critical temperature of the natural gas;
s3, calculating critical liquid carrying flow rates of the horizontal section, the inclined section and the vertical section of the shale gas horizontal well;
s4, calculating critical liquid carrying flow, comparing the actual gas flow at different positions, drawing a comparison change diagram of the yield and the critical liquid carrying flow along the well track under different parameters according to the well track distribution, and judging the position of the effusion according to the comparison change diagram; if the critical liquid carrying gas amount in the comparison change diagram is larger than the actual gas production amount, liquid is accumulated in the shale gas horizontal well section; and if the critical liquid carrying gas amount in the comparison change diagram is less than the actual gas production amount, no liquid is accumulated in the shale gas horizontal well section.
As a technical solution of the present application, in step S1, a pressure-temperature profile of the shale gas horizontal well along the wellbore is calculated by using a Beggs-Brill method, where the Beggs-Brill method includes the following formula:
in the formula: p-pressure; z-length in the direction of the wellbore;-a pressure gradient; rhol-a liquid density; hl-liquid holdup; rhog-a gas density; g-acceleration of gravity; theta is the included angle between the pipe column and the horizontal direction; lambda-flow resistance coefficient; g-mass flow of the mixture; v-average flow rate of mixture; d, the inner diameter of the oil pipe; a-the cross-sectional flow area of the tube; vsg-gas phase superficial flow rate.
3. The method for determining the location of the liquid accumulation in the shale gas horizontal well according to claim 2, wherein in the step S1, the method comprises the following steps:
s11, determining the calculated initial point pressure p, the calculated number n of sections and the section depth delta h according to basic data by adopting a formula of a Beggs-Brill method;
s12, assuming that the pressure difference in the calculation section is △ p, calculating the tail end pressure ph1 in the calculation section, and calculating the average pressure in the calculation sectionMean temperatureDetermining flow patterns, liquid holdup and drag coefficients within the computational segment from the computed data;
s13, calculating pressure difference delta p ' and tail end pressure p ' in the calculation section 'h1If | p 'is satisfied'h1-ph1If the absolute value is less than 0.0001, the calculated terminal pressure is used as the starting point pressure of the next section; if not satisfy | p'h1-ph1If l is less than 0.0001, then p 'is replaced'h1Replacing ph1, and continuing to calculate until the error requirement is met;
s14, repeating the steps S11 to S13 to continue to calculate the next segment of pressure distribution until all the calculation segments are calculated.
As an aspect of the present application, the basic data in step S11 includes liquid density, gas density, liquid phase volume flow, gas phase volume flow, liquid surface tension, gravitational acceleration, liquid viscosity, gas viscosity, wellbore inclination angle, tubing inner diameter, wellhead temperature, and temperature gradient.
As a technical solution of the present application, in step S2, the variation of natural gas deviation coefficient with pressure and temperature is calculated by using a Dranchuk-Abu-Kassem method, which comprises the following formula:
and (3) performing iterative calculation on Z by adopting a Newton iterative method, wherein: z-，A1＝0.3265，A2＝-1.0700，TprPseudo-critical temperature, A3-0.5339, a 4-0.01569, a 5-0.05165, ρprDimensionless contrast density, a6 ═ 0.5457, a7 ═ 0.7361, A8 ═ 0.1844, a9 ═ 0.1056, a10 ═ 0.6134, a11 ═ 0.7210, Ppr-pseudo-critical pressure.
6. The method for determining the location of the liquid accumulation in the shale gas horizontal well according to claim 1, wherein in step S3, the critical gas production rate of the shale gas horizontal well is:
in the formula: qcrCritical gas production, m3D; a-cross-sectional area of oil pipe, m2，di-tubing inner diameter, m; vg-critical speed, m/s; z-natural gas deviation coefficient; t-temperature.
As a technical solution of the present application, in step S3, the critical velocity of the vertical section of the shale gas horizontal well is:
in the formula: g-acceleration of gravity; sigma-gas-water interfacial tension, N/cm; rholLiquid density, kg/m3；ρgGas density, kg/m3。
As an embodiment of the present application, in step S3, the critical velocity of the inclined section of the shale gas horizontal well is:
in the formula: g-acceleration of gravity; sigma-gas-water interfacial tension, N/cm; rhol-liquidBulk density, kg/m3；ρgGas density, kg/m3α -oblique angle of hole.
As a technical solution of the present application, in step S3, the critical speed of the horizontal well section of the shale gas horizontal well is:
in the formula: g-acceleration of gravity; sigma-gas-water interfacial tension, N/cm; rholLiquid density, kg/m3；ρgGas density, kg/m3。
The beneficial effect of this application:
the method comprises the steps of calculating the change of a natural gas deviation coefficient along with pressure and temperature by using a Dranchuk-Abu-Kassem method, calculating a pressure and temperature profile distributed along a shaft by using a Beggs-Brill method, judging flow pattern distribution along the shaft direction, calculating gas flow rates at different positions, calculating critical liquid carrying flow and comparing real gas flows at different positions, drawing a comparison change diagram of yield and critical liquid carrying flow along the shaft path under different parameters according to the shaft path distribution, and systematically and effectively judging the position of liquid loading in a shale gas horizontal well section according to the comparison change diagram; the method is scientific and systematic, can effectively judge the position of the effusion of the shale gas horizontal well section, and is scientific and high in use efficiency.
Detailed Description
- 上一篇：一种医用注射器针头装配设备
- 下一篇：一种井下推靠器