Horizontal well gas-water two-phase flow fluid velocity calculation and flow imaging method

Abstract

The invention discloses a horizontal well gas-water two-phase flow fluid velocity calculation and flow imaging method, and relates to the technical field of unconventional gas reservoir development horizontal gas well production. According to the invention, the corresponding signal of the array flow velocity monitor and the rotation angle of the array flow velocity monitor are obtained, the fluid velocity of each probe position in the array flow velocity monitor is calculated, and the weight coefficient of the fluid velocity of each probe is determined according to the rotation angle of the array flow velocity monitor, so that the average flow velocity of the gas-water fluid is calculated. And then inverting a wellbore gas-water fluid velocity profile according to the average velocity of the gas-water fluid. The coincidence rate of the average velocity of the gas-water two-phase fluid of the horizontal well calculated based on the method and the actual average velocity of the fluid of the shaft is the highest, and the dynamic evaluation precision of gas and water generation of each production layer in unconventional gas reservoir horizontal well development is effectively improved.

Description

Technical Field

[0001] The present invention relates to the technical field of horizontal gas well production in unconventional gas reservoir development, and more specifically to a method for calculating fluid velocity and flow imaging of gas-water two-phase flow in a horizontal well. The method is an effective method for accurately and quantitatively calculating the average fluid velocity and dynamically and intuitively displaying the fluid velocity profile during the production process of a horizontal gas well in unconventional gas reservoir development. Background Art

[0002] With the increasing global demand for clean fossil energy represented by natural gas, unconventional natural gas resources represented by tight gas and shale gas have gradually become a hot spot for exploration and development at this stage. Unlike conventional natural gas reservoirs, unconventional natural gas reservoirs have extremely poor reservoir properties, and the permeability of the overburden matrix is ​​generally less than or equal to 0.1mD. Horizontal well development and multi-stage fracturing technology are currently the most commonly used technical means for exploiting such gas reservoirs. During the development of horizontal wells, the formation fluid is produced into the wellbore after multi-stage fracturing and further flows to the ground under the action of the wellbore pressure. Mine production shows that with the deepening of development, the horizontal gas well will produce gas and water at the same time after a period of production. Part of the formation water flows to the ground with the produced gas, and the other part gathers at the bottom of the well to form liquid accumulation and cause water lock and shutdown of some production layers, affecting the normal production of horizontal gas wells and seriously restricting the efficient development of unconventional gas reservoirs.

[0003] Therefore, accurately evaluating the production dynamics of gas-water two-phase flow in horizontal gas wells, determining the water-producing strata of gas wells, and clarifying the gas and water production at each production position in the multi-stage fracturing layer are the key foundations for guiding the optimization and adjustment of gas well development plans.

[0004] During the development of horizontal wells, the gravity differentiation of gas-water two-phase fluid in the wellbore is prominent. The coupling of factors such as horizontal wellbore structure, wellbore size, fluid properties, and water content results in complex contact between gas-water two-phase fluids, and variable force relationships between fluid media, which are mostly manifested as laminar flow, elastic flow, slug flow, bubbling flow, annular (fog) flow, etc. (Petalas and Aziz, 1996). The fluid velocity profile is extremely irregular. In order to accurately monitor the velocity information of gas-water two-phase fluid in horizontal wells, array flowmeters and other related monitoring technologies have been gradually introduced and widely used in dynamic monitoring of horizontal gas well production. Among them, the vertical centered array turbine flowmeter (5 turbine flowmeter probes) of the flow scanning imager FloScanImager series of Schlumberger Company in the United States and the annular array turbine flowmeter SAT (6 turbine flowmeter probes) of the MAPS combination of Sondex Company are the most representative. In horizontal gas wells, the vertical centered array turbine flowmeter of the FloScan Imager series has a better application effect. It obtains the fluid velocity response at each probe position by monitoring, calculates the fluid velocity at each probe position, and then calculates the overall average velocity of the gas-water two-phase fluid in the horizontal wellbore, which is expressed as: (1); where v m —The overall average velocity of gas and water in the horizontal wellbore, meters per minute (m / min); vi—The fluid velocity obtained by monitoring the probe position, meters per minute (m / min); αi—The weight of the contribution of the fluid velocity at each probe position to the average fluid velocity, decimal.

[0005] The relationship between the fluid velocity at each probe position and the response of the monitoring turbine flowmeter itself can be expressed as: (2); where RPS i —The logging speed in the horizontal wellbore is v l The response value of the i-th turbine rotor at time t, revolutions per second (rps); v l —The speed of the instrument during logging, also known as logging speed, in meters per minute (m / min); v th,i —Starting speed of the i-th turbine rotor, meters per minute (m / min); K i —The slope of the i-th rotor is obtained after rotor calibration, and the constant is obtained by experimental calibration.

[0006] At present, the radial distance equal height area weight method is used to calculate the weight coefficient of each turbine rotor position for calculating the fluid horizontal velocity of the vertical centered array turbine flowmeter monitoring data of the FloScan Imager series. The horizontal wellbore is divided into five equal parts radially based on the five turbine rotors. The area of ​​each area is calculated and compared with the total area of ​​the wellbore to obtain the probe weight coefficient of each area. This method works well in the ideal logging process where the instrument does not rotate.

[0007] However, in the actual process of monitoring the fluid velocity of horizontal wells, the logging instrument will rotate at any angle in the wellbore when it is lowered into the well and pulled up. Under certain conditions, this will cause the special situation that the monitoring turbine probe does not exist in a certain radially divided area. At this time, the radial distance equal height area weight method is still used to calculate the weight coefficient of each turbine rotor position, which will cause the limitation of large error in the quantitative calculation of the gas-water two-phase fluid velocity in the horizontal wellbore, thereby affecting the accuracy of the dynamic evaluation of the gas-water two-phase fluid production in the horizontal wellbore, and at the same time causing distortion in the inversion of the gas-water two-phase dynamic flow imaging, restricting the optimization and adjustment of the horizontal gas well development plan. Summary of the invention

[0008] In order to overcome the defects and deficiencies in the above-mentioned prior art, the present invention provides a method for calculating the fluid velocity of a gas-water two-phase flow in a horizontal well and for flow imaging. The purpose of the present invention is to solve the influence of the rotation of the array flow velocity monitor on the calculation of the average fluid velocity during the fluid velocity logging process in a horizontal gas well. The present invention obtains the corresponding signal of the array flow velocity monitor and the rotation angle of the array flow velocity monitor, calculates the fluid velocity of each probe position in the array flow velocity monitor, determines the weight coefficient of the fluid velocity of each probe according to the rotation angle of the array flow velocity monitor, thereby calculating the average flow velocity of the gas-water fluid, and then inverts the gas-water fluid velocity profile of the wellbore according to the average flow velocity of the gas-water fluid. The average velocity of the gas-water two-phase fluid in a horizontal well calculated based on the present invention has the highest consistency with the actual average velocity of the fluid in the wellbore, which effectively improves the accuracy of the dynamic evaluation of gas and water generation in each production layer in the development of horizontal wells in unconventional gas reservoirs.

[0009] In order to solve the above problems existing in the prior art, the present invention is implemented through the following technical solutions.

[0010] The present invention provides a method for calculating fluid velocity and flow imaging of gas-water two-phase flow in a horizontal well, the method comprising the following steps: S1, obtaining the response signal of each probe in the array flow rate monitor and the rotation angle of the array flow rate monitor offset from the central axis; S2, calculating the fluid velocity at each probe position according to the response signal of each probe of the array flow rate monitor; S3, determining the weight coefficient of each probe according to the rotation angle of the array flow rate monitor offset from the central axis; S4, calculating the average flow rate of the gas-water two-phase fluid according to the fluid velocity at each probe position in step S2 and the weight coefficient of each probe in step S3; S5. The wellbore fluid velocity profile is obtained by inverting the monitoring data from the array flow monitor.

[0011] Further preferably, step S5 further comprises: S501, based on the fluid velocity calculated by the corresponding signals of each probe of the array flow rate monitor, combined with the corresponding calculation of the water holdup meter or the density meter to obtain the water holdup of the horizontal well, expressed as: , where Y w Represents the water holding rate of horizontal wellbore, decimal; Y wi It indicates the water holdup rate obtained by monitoring the probe position, decimal; β i Indicates the water holdup weight of each probe position, a decimal; corresponds to the wellbore liquid level height; S502, grid the horizontal wellbore section; take the vertical center axis of the wellbore section as the y coordinate axis, and the origin of the center of the wellbore section as the x coordinate axis, based on the fluid velocity at each probe position v i Layered linear interpolation is used to obtain the fluid velocity distribution on the longitudinal center axis after gridding; S503, constraining the fluid velocity monitored at the center of the wellbore section, and then obtaining the fluid velocity distribution on the vertical center grid; at the same time, the fluid velocity distribution relationship on the horizontal direction of the corresponding wellbore section can be obtained; S504. By calculating the difference in the longitudinal and transverse directions and the fluid velocity distribution on the longitudinal center axis and the fluid velocity distribution in the transverse direction in steps S502 and S503, the fluid velocity distribution on the wellbore cross section is obtained by constraining the transverse and longitudinal velocity profile lines.

[0012] More preferably, in step S501, the relationship between the water holdup of the horizontal well and the liquid level height of the wellbore is: When Y w When ≤0.5, ; When Y w >0.5, ; Where Y w It represents the water holding rate of the wellbore corresponding to the imaging depth, in decimal; H represents the average liquid level height when the wellbore water holding rate is Yw, in meters; R represents the radius of the wellbore section, in meters.

[0013] More preferably, in step S502, the fluid velocity distribution on the longitudinal center axis after gridding satisfies the following relationship: When Re≤4000, ; When Re is greater than 4000, ; The Reynolds number Re is expressed as, ; Where Re is the Reynolds number of the gas-water two-phase fluid in the horizontal well, dimensionless; y is the ordinate corresponding to the vertical center axis after gridding, unit: meter; v y Indicates the fluid velocity at the vertical center of the wellbore section after gridding, unit: m / min; v yg,max Indicates the maximum velocity of the gas phase fluid in the vertical direction at the center of the wellbore section after gridding, unit: m / min; v yw,max It represents the maximum velocity of the water phase fluid in the vertical direction at the center of the wellbore section after gridding, in m / min; R represents the radius of the wellbore section, in meters; α represents the coefficient related to Re, where Re<10 5 When α=1 / 7; 10 5 <Re<4*10 5 When α=1 / 8; ρ is the density of the gas-water two-phase mixed fluid, unit: kg / m 3 ; μ is the viscosity of the gas-water two-phase mixed fluid, unit: m 2 / s; v m is the average velocity of gas-water two-phase fluid, unit: m / s.

[0014] More preferably, in step S503, the distribution relationship of the fluid velocity in the horizontal direction of the wellbore cross section is expressed as: When Re≤4000, ; When Re>4000, ; In the formula, Re represents the Reynolds number of the gas-water two-phase fluid in the horizontal well, and α represents the coefficient related to Re, where Re<10 5 When α=1 / 7; 10 5 <Re<4*10 5 α=1 / 8; x represents the horizontal coordinate corresponding to any vertical depth horizontal axis position after gridding, unit: meter; v x Indicates the fluid velocity at any vertical depth horizontal axis position after gridding, unit: m / min; v x,max It indicates the fluid velocity at the vertical center of the wellbore section, unit: m / min.

[0015] Further preferably, step S3 specifically includes: S301, calculating the distance from the projection position of each probe in the array flow velocity monitor to the central axis to the top of the wellbore according to the rotation angle of the array flow velocity monitor offset from the central axis; S302, dividing the wellbore into a plurality of flow regions according to the midpoints between the projection positions of adjacent probes onto the central axis; and calculating the corresponding area of ​​each region; S303: The ratio of the area where the probe is located to the total internal cross-sectional area of ​​the horizontal wellbore is used as the weight coefficient of the probe.

[0016] More preferably, in step S301, the array velocity monitor has 5 probes, and the distances from the projection positions of the 5 probes arranged from top to bottom to the central axis to the top of the wellbore are: ; ; ; ; ; In the formula, are the distances from the projection positions of the five probes arranged from top to bottom onto the central axis to the top of the wellbore, in meters; D1, D2, D3, D4 and D5 respectively represent the distances from the five probes to the top of the wellbore when the array flow rate monitor coincides with the central axis, in meters; θ represents the rotation angle of the array flow rate monitor offset from the central axis; R represents the cross-sectional radius of the wellbore, in meters; when θ=0, it means that the array flow rate monitor coincides with the central axis.

[0017] More preferably, in step S302, the area corresponding to each flow region is expressed as: ; ; ; ; ; Where A1, A2, A3, A4 and A5 represent the area of ​​the flow region corresponding to probes 1 to 5, unit: m 2 ; The weight coefficients of each probe are expressed as: , where A represents the total internal cross-sectional area of ​​the wellbore.

[0018] More preferably, in step S4, the average flow rate of the gas-water two-phase fluid is expressed as: ; Where, v1, v2, v3, v4 and v5 represent the fluid flow rate at probes 1 to 5, respectively, in m / min; v m Represents the average flow velocity of gas-water two-phase fluid.

[0019] Further preferably, in step S4, the total flow rate of the gas-water two-phase fluid in the wellbore needs to be calculated, which is expressed as: ; In the formula, Q represents the total flow rate of gas-water two-phase fluid in the horizontal well, unit: m 3 / d;v m It represents the average flow rate of gas-water two-phase fluid, in m / min; PC represents the horizontal wellbore pipe constant, in m 2 ·min / d.

[0020] Compared with the prior art, the beneficial technical effects brought by the present invention are as follows: 1. Higher calculation accuracy. The present invention fully considers the influence of the rotation of the logging instrument in calculating the average velocity of the gas-water two-phase fluid based on the monitoring data of the array turbine flowmeter, and eliminates the error caused by the rotation of the instrument through rotation angle correction.

[0021] 2. Strong operability and wide application scope. The established method is suitable for calculating the average velocity of gas and water under different flow conditions of turbine flowmeters in horizontal well arrays, and has a wider application scope.

[0022] 3. Flow imaging inversion is more accurate. The flow imaging method established by the present invention fully considers the vertical and longitudinal differences of the fluid medium in the horizontal wellbore, obtains a more accurate flow velocity profile through vertical and longitudinal processing, and accurately reflects the dynamic characteristics of the gas-water two-phase fluid.

[0023] 4. The present invention realizes accurate quantitative calculation of the average fluid velocity of the gas-water phase fluid flow process in the horizontal wellbore of unconventional oil and gas reservoirs, and obtains the wellbore fluid velocity profile based on the inversion of array flow data, accurately indicating the dynamic characteristics of the gas-water two-phase fluid flow in the horizontal well, laying a foundation for the calculation of gas and water production in each production layer of horizontal wells in the development of unconventional gas reservoirs and the optimization and adjustment of development plans. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] Figure 1 This is a schematic diagram of the structure of the vertical centered array turbine flowmeter of the FloScan Imager series when it is not rotating; Figure 2 It is a schematic diagram of the structure of the vertical centered array turbine flowmeter of the FloScan Imager series when any rotation occurs; Figure 3 It is a technical flow chart for realizing the method of the present invention; Figure 4 Schematic diagram of fluid velocity inversion imaging in a horizontal wellbore section. DETAILED DESCRIPTION

[0025] The following will be combined with the drawings of the present invention specification to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0026] Example 1 As a preferred embodiment of the present invention, refer to the attached specification Figure 3 As shown, this embodiment discloses a method for calculating fluid velocity and flow imaging of gas-water two-phase flow in a horizontal well, the method comprising the following steps: S1, obtaining the response signal of each probe in the array flow rate monitor and the rotation angle of the array flow rate monitor offset from the central axis; S2, calculating the fluid velocity at each probe position according to the response signal of each probe of the array flow rate monitor; S3, determining the weight coefficient of each probe according to the rotation angle of the array flow rate monitor offset from the central axis; S4, calculating the average flow rate of the gas-water two-phase fluid according to the fluid velocity at each probe position in step S2 and the weight coefficient of each probe in step S3; S5. The wellbore fluid velocity profile is obtained by inverting the monitoring data from the array flow monitor.

[0027] Example 2 As another preferred embodiment of the present invention, this embodiment further elaborates and supplements the technical solution of the present invention on the basis of the above-mentioned embodiment 1. In this embodiment, step S5 further includes: S501, based on the fluid velocity calculated by the corresponding signals of each probe of the array flow rate monitor, combined with the corresponding calculation of the water holdup meter or the density meter to obtain the water holdup of the horizontal well, expressed as: , where Y w Represents the water holding rate of horizontal wellbore, decimal; Y wi It indicates the water holdup rate obtained by monitoring the probe position, decimal; β i Indicates the water holdup weight of each probe position, a decimal; corresponds to the wellbore liquid level height; S502, grid the horizontal wellbore section; take the vertical center axis of the wellbore section as the y coordinate axis, the origin of the center of the wellbore section as the x coordinate axis, and calculate the fluid velocity v at each probe position. i , using layered linear interpolation, the fluid velocity distribution on the longitudinal center axis after gridding is obtained; S503, constraining the fluid velocity monitored at the center of the wellbore section, and then obtaining the fluid velocity distribution on the vertical center grid; that is, using the fluid velocity monitored by the probe at the center of the wellbore section as a constraint condition, using layered linear difference to obtain the fluid velocity distribution on the vertical center grid; at the same time, the fluid velocity distribution relationship on the horizontal direction of the corresponding wellbore section can be obtained; S504. By calculating the difference in the longitudinal and transverse directions and the fluid velocity distribution on the longitudinal center axis and the fluid velocity distribution in the transverse direction in steps S502 and S503, the fluid velocity distribution on the wellbore cross section is obtained by constraining the transverse and longitudinal velocity profile lines.

[0028] As a specific implementation of this embodiment, in step S501, the relationship between the water holdup of the horizontal well and the liquid level height of the wellbore is: When Y w When ≤0.5, ; When Y w >0.5, ; Where Y w It represents the water holding rate of the wellbore corresponding to the imaging depth, in decimal; H represents the average liquid level height when the wellbore water holding rate is Yw, in meters; R represents the radius of the wellbore section, in meters.

[0029] Furthermore, in step S502, the fluid velocity distribution on the longitudinal center axis after gridding satisfies the following relationship: When Re≤4000, ; When Re is greater than 4000, ; The Reynolds number Re is expressed as, ; Where Re is the Reynolds number of the gas-water two-phase fluid in the horizontal well, dimensionless; y is the ordinate corresponding to the vertical center axis after gridding, unit: meter; v y Indicates the fluid velocity at the vertical center of the wellbore section after gridding, unit: m / min; v yg,max Indicates the maximum velocity of the gas phase fluid in the vertical direction at the center of the wellbore section after gridding, unit: m / min; v yw,max It represents the maximum velocity of the water phase fluid in the vertical direction at the center of the wellbore section after gridding, in m / min; R represents the radius of the wellbore section, in meters; α represents the coefficient related to Re, where Re<10 5 When α=1 / 7; 10 5 <Re<4*10 5 When α=1 / 8; ρ is the density of the gas-water two-phase mixed fluid, unit: kg / m 3; μ is the viscosity of the gas-water two-phase mixed fluid, unit: m 2 / s; v m is the average velocity of gas-water two-phase fluid, unit: m / s.

[0030] More preferably, in step S503, the distribution relationship of the fluid velocity in the horizontal direction of the wellbore cross section is expressed as: When Re≤4000, ; When Re>4000, ; In the formula, Re represents the Reynolds number of the gas-water two-phase fluid in the horizontal well, and α represents the coefficient related to Re, where Re<10 5 When α=1 / 7; 10 5 <Re<4*10 5 α=1 / 8; x represents the horizontal coordinate corresponding to any vertical depth horizontal axis position after gridding, unit: meter; v x Indicates the fluid velocity at any vertical depth horizontal axis position after gridding, unit: m / min; v x,max It indicates the fluid velocity at the vertical center of the wellbore section, unit: m / min.

[0031] Example 3 As another preferred embodiment of the present invention, this embodiment further elaborates and supplements the technical solution of the present invention on the basis of the above-mentioned embodiment 1 or embodiment 2. In this embodiment, step S3 specifically includes: S301, calculating the distance from the projection position of each probe in the array flow velocity monitor to the central axis to the top of the wellbore according to the rotation angle of the array flow velocity monitor offset from the central axis; S302, dividing the wellbore into a plurality of flow regions according to the midpoints between the projection positions of adjacent probes onto the central axis; and calculating the corresponding area of ​​each region; S303: The ratio of the area where the probe is located to the total internal cross-sectional area of ​​the horizontal wellbore is used as the weight coefficient of the probe.

[0032] Refer to the instruction manual Figure 1 and attached Figure 2 As shown, in step S301, the array velocity monitor has 5 probes, and the distances from the projection positions of the 5 probes arranged from top to bottom to the central axis to the top of the wellbore are: ; ; ; ; ; In the formula, are the distances from the projection positions of the five probes arranged from top to bottom onto the central axis to the top of the wellbore, in meters; D1, D2, D3, D4 and D5 respectively represent the distances from the five probes to the top of the wellbore when the array velocity monitor coincides with the central axis, in meters; θ represents the rotation angle of the array velocity monitor offset from the central axis; R represents the radius of the wellbore section, in meters; Figure 1 As shown, when θ=0, it means that the array flow velocity monitor coincides with the central axis and no offset occurs.

[0033] Furthermore, in step S302, the area corresponding to each flow region is expressed as: ; ; ; ; ; Where A1, A2, A3, A4 and A5 represent the area of ​​the flow region corresponding to probes 1 to 5, unit: m 2 ; The weight coefficients of each probe are expressed as: , where A represents the total internal cross-sectional area of ​​the wellbore.

[0034] More preferably, in step S4, the average flow rate of the gas-water two-phase fluid is expressed as: ; Where, v1, v2, v3, v4 and v5 represent the fluid flow rate at probes 1 to 5, respectively, in m / min; v m Represents the average flow velocity of gas-water two-phase fluid.

[0035] Further preferably, in step S4, the total flow rate of the gas-water two-phase fluid in the wellbore needs to be calculated, which is expressed as: ; In the formula, Q represents the total flow rate of gas-water two-phase fluid in the horizontal well, unit: m 3 / d;v m It represents the average flow rate of gas-water two-phase fluid; PC represents the horizontal wellbore pipe constant, unit is m 2 ·min / d.

[0036] Example 4 As another preferred embodiment of the present invention, this embodiment further elaborates the technical solution of the present invention on the basis of the above-mentioned embodiment 1, embodiment 2 or embodiment 3. In this embodiment, When the array turbine flowmeter does not rotate, the five array turbine rotors are vertically centered on the wellbore section. At this time, probe No. 1 is at the top, probe No. 5 is at the bottom, and probes No. 2 to 3 are distributed from top to bottom. The wellbore is vertically divided into five flow areas according to the midpoint position between the two probes. The corresponding areas of each area are A1 to A5 from top to bottom, expressed as, (1); (2); (3); (4); (5); The total cross-sectional area of ​​the wellbore is expressed as (6); then, at this time, the average flow rate of the gas-water two-phase fluid is expressed as, (7); Where D1, D2, D3, D4 and D5 represent the distances between the five probes and the top of the wellbore when the array velocity monitor coincides with the central axis, in meters; A1, A2, A3, A4 and A5 represent the area of ​​the flow region corresponding to probes 1 to 5, unit: m 2 ; A represents the total cross-sectional area of ​​the wellbore; R represents the radius of the wellbore section, unit: meter; v1, v2, v3, v4 and v5 represent the fluid flow rate at probes 1 to 5, unit: m / min; v m Represents the average flow rate of gas-water two-phase fluid.

[0037] When the array turbine flowmeter rotates arbitrarily, the five array turbine rotors are tilted and distributed on the wellbore section according to the rotation angle. At this time, the projection of probe No. 1 on the vertical central axis of the wellbore section is still at the top, probe No. 5 is at the bottom, and probes 2 to 3 are distributed from top to bottom. After projecting to the central axis, the distance between the projection position of each probe and the top of the wellbore is (8) (9) (10); (11); (12); The wellbore is divided into five flow regions according to the midpoints of the two probes in the radial projection position. The corresponding area of ​​each region is expressed as: (13); (14); (15); (16); (17); At this time, the average flow rate of the gas-water two-phase fluid in the horizontal wellbore is still calculated using formula (7), and the corresponding total flow rate of the gas-water two-phase flow is expressed as (18); In the formula, are the distances from the projection positions of the five probes arranged from top to bottom to the central axis to the top of the wellbore, in meters; θ represents the rotation angle of the array velocity monitor offset from the central axis; Q represents the total flow rate of the gas-water two-phase fluid in the horizontal well, in m 3 / d;v m It represents the average flow rate of gas-water two-phase fluid; PC represents the horizontal wellbore pipe constant, unit is m 2 ·min / d.

[0038] The horizontal wellbore section is divided into m×n parts in the horizontal and vertical directions. Due to the influence of gravity differentiation of the fluid in the horizontal wellbore, the fluid velocity profile of the wellbore section after gridding satisfies a certain functional relationship in the vertical and horizontal directions. The fluid velocity is calculated based on the response of each probe, and the water holdup of the horizontal well is calculated in combination with the response of the water holdup meter or density meter to obtain Y. w , the corresponding wellbore liquid level H satisfies the relationship: When Y w When ≤0.5, (19); When Y w >0.5, (20); With the vertical center axis of the wellbore section as the y-axis and the center point of the wellbore section as the x-axis, the fluid velocity distribution on the longitudinal center axis after gridding satisfies the following relationship: When Re≤4000, (twenty one); When Re is greater than 4000, (twenty two); At this time, the velocity monitored at the center of the wellbore section is constrained, and the fluid velocity distribution on the vertical center grid is obtained. At the same time, the fluid velocity distribution relationship on the horizontal direction of the wellbore section can be obtained as follows: When Re≤4000, (twenty three); When Re>4000, (twenty four); The Reynolds number Re is expressed as, ; In the above formulas (19) to (24), Yw represents the water holding rate of the wellbore corresponding to the imaging depth, decimal; H represents the average liquid level when the wellbore water holding rate is Yw, unit: meter; R represents the radius of the wellbore section, unit: meter; Re represents the Reynolds number of the gas-water two-phase fluid in the horizontal well, dimensionless; y represents the vertical coordinate corresponding to the central axis after gridding, unit: meter; v y Indicates the fluid velocity at the vertical center of the wellbore section after gridding, unit: m / min; v yg,max Indicates the maximum velocity of the gas phase fluid in the vertical direction at the center of the wellbore section after gridding, unit: m / min; v yw,max It represents the maximum velocity of the water phase fluid in the vertical direction at the center of the wellbore section after gridding, in m / min; R represents the radius of the wellbore section, in meters; α represents the coefficient related to Re, where Re<10 5 When α=1 / 7; 10 5 <Re<4*10 5 α=1 / 8; x represents the horizontal coordinate corresponding to any vertical depth horizontal axis position after gridding, unit: meter; v x Indicates the fluid velocity at any vertical depth horizontal axis position after gridding, unit: m / min; v x,max It indicates the fluid velocity at the vertical center of the wellbore section, unit: m / min; ρ is the density of the gas-water two-phase mixed fluid, unit: kg / m 3 ; μ is the viscosity of the gas-water two-phase mixed fluid, unit: m 2 / s; v m is the average velocity of gas-water two-phase fluid, unit: m / s.

[0039] When the instrument rotates, the fluid velocity at the corresponding vertical center position is obtained using the relationship between formulas (23) and (24). The fluid velocity distribution on the wellbore cross section can be obtained by interpolation calculation in the vertical and horizontal axes and by constraining the distribution function.

[0040] Example 5 As another preferred embodiment of the present invention, this embodiment uses the technical solution of the present invention to calculate an application example of a horizontal well X in a gas field in southwest my country: Well X is a horizontal gas well in a gas field in southwest my country. The well was completed to a depth of 4350 meters, of which the horizontal section is 1500 meters long. It was completed and put into production in 2017. The well was completed with a 118mm inner diameter oil layer casing perforation. At present, the surface wellhead produces 256.96m3 of water per day under standard conditions. 3 / d, daily gas production 135000m 3 / d, a φ50.8 mm optical fiber-coiled tubing-carrying FloScan Imager logging instrument was used to test the gas production profile of the target layer. The fluid velocity at each array probe position was calculated using formula (2) in the background technology, and the water holdup of the full flow layer was calculated to be 0.38. The average fluid velocity of the full flow layer was calculated using formula (7) in Example 4 to be 50.223 m / min. The relative error compared with the wellhead was 3.20%, and the matching was good.

[0041] The velocity distribution of the fluid in the full flow layer calculated by the new method is as follows: Figure 4 As shown, it better reflects the distribution of wellbore fluid.

Claims

1. A method for calculating fluid velocity and imaging flow in horizontal well gas-water two-phase flow. Features: The method comprises the following steps S1, obtaining the response signal of each probe in the array flow rate monitor and the rotation angle of the array flow rate monitor offset from the central axis; S2, calculating the fluid velocity at each probe position according to the response signal of each probe of the array flow rate monitor; S3, determining the weight coefficient of each probe according to the rotation angle of the array flow rate monitor offset from the central axis; S4, calculating the average flow rate of the gas-water two-phase fluid according to the fluid velocity at each probe position in step S2 and the weight coefficient of each probe in step S3; S5. The wellbore fluid velocity profile is obtained by inverting the monitoring data from the array flow monitor.

2. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well according to claim 1, Features: Step S5 further comprises: S501, based on the fluid velocity calculated by the corresponding signals of each probe of the array flow rate monitor, combined with the corresponding calculation of the water holdup meter or the density meter to obtain the water holdup of the horizontal well, expressed as: , where Y w Represents the water holding rate of horizontal wellbore, decimal; Y wi It indicates the water holdup rate obtained by monitoring the probe position, decimal; β i Indicates the water holdup weight of each probe position, a decimal; corresponds to the wellbore liquid level height; S502, grid the horizontal wellbore section; take the vertical center axis of the wellbore section as the y coordinate axis, and the origin of the center of the wellbore section as the x coordinate axis, based on the fluid velocity at each probe position v i Layered linear interpolation is used to obtain the fluid velocity distribution on the longitudinal center axis after gridding; S503, constraining the fluid velocity monitored at the center of the wellbore section, and then obtaining the fluid velocity distribution on the vertical center grid; at the same time, the fluid velocity distribution relationship on the horizontal direction of the corresponding wellbore section can be obtained; S504. By calculating the difference in the longitudinal and transverse directions and the fluid velocity distribution on the longitudinal center axis and the fluid velocity distribution in the transverse direction in steps S502 and S503, the fluid velocity distribution on the wellbore cross section is obtained by constraining the transverse and longitudinal velocity profile lines.

3. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well as claimed in claim 2, Features: In step S501, the relationship between the water holdup of a horizontal well and the liquid level in the wellbore is: When Y w When ≤0.5, ; When Y w >0.5, ; Where Y w It represents the water holding rate of the wellbore corresponding to the imaging depth, in decimal; H represents the average liquid level height when the wellbore water holding rate is Yw, in meters; R represents the radius of the wellbore section, in meters.

4. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well as claimed in claim 2, Features: In step S502, the fluid velocity distribution on the longitudinal center axis after gridding satisfies the following relationship: When Re≤4000, ; When Re is greater than 4000, ; The Reynolds number Re is expressed as, ; Where Re represents the Reynolds number of the gas-water two-phase fluid in the horizontal well, dimensionless; y represents the ordinate corresponding to the vertical center axis after gridding, unit: meter; v y Indicates the fluid velocity at the vertical center of the wellbore section after gridding, unit: m / min; v yg,max Indicates the maximum velocity of the gas phase fluid in the vertical direction at the center of the wellbore section after gridding, unit: m / min; v yw,max It represents the maximum velocity of the water phase fluid in the vertical direction at the center of the wellbore section after gridding, in m / min; R represents the radius of the wellbore section, in meters; α represents the coefficient related to Re, where Re<10 5 When α=1 / 7; 10 5 <Re<4*10 5 When α=1 / 8; ρ is the density of the gas-water two-phase mixed fluid, unit: kg / m 3 ; μ is the viscosity of the gas-water two-phase mixed fluid, unit: m 2 / s; v m is the average velocity of gas-water two-phase fluid, unit: m / s.

5. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well as claimed in claim 4, Features: In step S503, the distribution relationship of the fluid velocity in the horizontal direction of the wellbore cross section is expressed as: When Re≤4000, ; When Re>4000, ; In the formula, Re represents the Reynolds number of the gas-water two-phase fluid in the horizontal well, and α represents the coefficient related to Re, where Re<10 5 When α=1 / 7; 10 5 <Re<4*10 5 When α=1 / 8, x represents the horizontal coordinate corresponding to any longitudinal depth horizontal axis position after gridding, unit: meter; v x Indicates the fluid velocity at any vertical depth horizontal axis position after gridding, unit: m / min; v x,max It indicates the fluid velocity at the vertical center of the wellbore section, unit: m / min.

6. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well according to any one of claims 1 to 5, Features: The S3 step specifically includes: S301, calculating the distance from the projection position of each probe in the array flow velocity monitor to the central axis to the top of the wellbore according to the rotation angle of the array flow velocity monitor offset from the central axis; S302, dividing the wellbore into a plurality of flow regions according to the midpoints between the projection positions of adjacent probes onto the central axis; and calculating the corresponding area of ​​each region; S303: The ratio of the area where the probe is located to the total internal cross-sectional area of ​​the horizontal wellbore is used as the weight coefficient of the probe.

7. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well according to claim 6, Features: In step S301, the array velocity monitor has five probes, and the distances from the projection positions of the five probes arranged from top to bottom to the central axis to the top of the wellbore are: ； ； ； ； ； In the formula, They are the distances from the projection positions of the five probes arranged from top to bottom to the central axis to the top of the wellbore, in meters; D 1 , D 2 , D 3 , D 4 and D 5 They respectively represent the distances between the five probes and the top of the wellbore when the array flow rate monitor coincides with the central axis, in meters; θ represents the rotation angle of the array flow rate monitor offset from the central axis; R represents the radius of the wellbore section, in meters; when θ=0, it means that the array flow rate monitor coincides with the central axis.

8. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well as claimed in claim 7, Features: In step S302, the area corresponding to each flow region is expressed as: ； ； ； ； ； Where A1, A2, A3, A4 and A5 represent the area of ​​the flow region corresponding to probes 1 to 5, unit: m 2 ; The weight coefficients of each probe are expressed as: , where A represents the total internal cross-sectional area of ​​the wellbore.

9. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well as claimed in claim 8, Features: In step S4, the average flow rate of the gas-water two-phase fluid is expressed as: ； In the formula, v 1 、v 2 、v 3 、v 4 and v 5 Respectively represent the fluid flow rate at probes 1 to 5, unit: m / min; v m Represents the average flow velocity of gas-water two-phase fluid.

10. A method for calculating fluid velocity and imaging flow of gas-water two-phase flow in a horizontal well according to claim 9, Features: In step S4, the total flow rate of the gas-water two-phase fluid in the wellbore also needs to be calculated, which is expressed as: ; In the formula, Q represents the total flow rate of gas-water two-phase fluid in the horizontal well, unit: m 3 / d;v m It represents the average flow rate of gas-water two-phase fluid; PC represents the horizontal wellbore pipe constant, unit: m 2 ·min / d.

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