CN113188617A - Wellhead three-phase fluid metering device - Google Patents
Wellhead three-phase fluid metering device Download PDFInfo
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- CN113188617A CN113188617A CN202110401065.7A CN202110401065A CN113188617A CN 113188617 A CN113188617 A CN 113188617A CN 202110401065 A CN202110401065 A CN 202110401065A CN 113188617 A CN113188617 A CN 113188617A
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- 239000012530 fluid Substances 0.000 title claims abstract description 109
- 239000000523 sample Substances 0.000 claims abstract description 46
- 238000001514 detection method Methods 0.000 claims abstract description 42
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 33
- 238000004519 manufacturing process Methods 0.000 claims abstract description 29
- 210000001503 joint Anatomy 0.000 claims description 8
- 238000005259 measurement Methods 0.000 description 38
- 239000003921 oil Substances 0.000 description 21
- 238000012545 processing Methods 0.000 description 13
- 238000005070 sampling Methods 0.000 description 13
- 230000005540 biological transmission Effects 0.000 description 9
- 238000010586 diagram Methods 0.000 description 7
- 238000005191 phase separation Methods 0.000 description 6
- 238000000034 method Methods 0.000 description 5
- 238000002604 ultrasonography Methods 0.000 description 4
- 239000007789 gas Substances 0.000 description 3
- 238000011161 development Methods 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 239000003129 oil well Substances 0.000 description 2
- 238000003556 assay Methods 0.000 description 1
- 238000005452 bending Methods 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 238000004891 communication Methods 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 230000007423 decrease Effects 0.000 description 1
- 238000004880 explosion Methods 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 238000005457 optimization Methods 0.000 description 1
- 230000000704 physical effect Effects 0.000 description 1
- 230000002035 prolonged effect Effects 0.000 description 1
- 238000000926 separation method Methods 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
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- 230000009466 transformation Effects 0.000 description 1
- 238000011144 upstream manufacturing Methods 0.000 description 1
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
- G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
- G01F1/66—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by measuring frequency, phase shift or propagation time of electromagnetic or other waves, e.g. using ultrasonic flowmeters
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
- G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
- G01F1/66—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by measuring frequency, phase shift or propagation time of electromagnetic or other waves, e.g. using ultrasonic flowmeters
- G01F1/662—Constructional details
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
- G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
- G01F1/68—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using thermal effects
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
- G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
- G01F1/68—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using thermal effects
- G01F1/684—Structural arrangements; Mounting of elements, e.g. in relation to fluid flow
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Abstract
The invention discloses a wellhead three-phase fluid metering device, which comprises: the device comprises an inlet joint, a measuring pipe, a flow detection assembly, a radio frequency probe, an ultrasonic amplitude detector and a control cabinet; wherein, flow detection subassembly, radio frequency probe and ultrasonic wave amplitude detector all set up on surveying buret. The inner diameter of the inlet joint and the inner diameter of the measuring pipe are equal to the inner diameter of the oil pipe; the measuring pipe is horizontally arranged; the control circuit board component of the control cabinet is used for determining the water production volume flow q in the fluid according to the detection data of the flow detection component, the radio frequency probe and the ultrasonic amplitude detectorwGas production volume flow qgAnd the volume flow q of produced oilo. The three-phase fluid metering device can detect and meter single-phase flow under the condition that oil, gas and water are not split, has simple structure and higher degree of automation, and improvesThe metering efficiency of the single-well three-phase fluid is improved.
Description
Technical Field
The invention belongs to the technical field of oil-gas well measuring equipment, and particularly relates to a wellhead three-phase fluid metering device.
Background
The split-phase online measurement of the crude oil single-well output can provide a basis for mastering the production condition of the oil well single-well and providing a transformation measure, provides basic data for the integral injection and production parameter optimization and production scheme adjustment of the oil field, and has great significance for the digital management of the oil field by accurate, instant and cost-controllable well mouth measurement equipment.
Under the conditions of different development stages and different well conditions, the oil well produces oil, gas and water in different fluid ratios and yields, and the components and physical properties of each phase change correspondingly, which brings great difficulty to split-phase metering. At present, three-phase flow metering methods are numerous, but all have certain application conditions and limitations. For single well metering, the following methods are commonly used: three-phase separation and metering. The three-phase separation device with better effect usually needs large-scale skid-mounted equipment, and is huge, expensive and not suitable for a single well; the small simple three-phase or two-phase separation device has poor separation effect, large metering error, complex structure and easy pipeline blockage under the conditions of thick oil and low temperature; ② metering without phase separation. At present, most of fully commercialized three-phase flow meters are foreign products, are usually suitable for metering under the condition of large flow, and the domestic large number of low-yield vertical well output can not reach the starting flow; and thirdly, manual sampling assay. The method has accurate result, but has no timeliness, labor intensity and lower digitization and intelligence degrees.
Disclosure of Invention
In order to solve the problems in the prior art, the invention provides a wellhead three-phase fluid metering device. The technical problem to be solved by the invention is realized by the following technical scheme:
a wellhead three phase fluid metering device comprising: the device comprises an inlet joint, a measuring pipe, a flow detection assembly, a radio frequency probe, an ultrasonic amplitude detector and a control cabinet;
the inlet joint is close to a wellhead, one end of the inlet joint is connected and communicated with an oil pipe, the other end of the inlet joint is communicated with one end of the measuring pipe, and the inner diameter of the inlet joint is equal to that of the oil pipe;
the measuring pipe is horizontally arranged, and the inner diameter of the measuring pipe is equal to that of the oil pipe;
the flow detection assembly is arranged on the measuring pipe and is communicated with the inside of the measuring pipe;
the radio frequency probe is fixedly arranged on the pipe wall of the measuring pipe and is communicated with the inside of the measuring pipe;
the ultrasonic amplitude detector is fixedly arranged on the pipe wall of the measuring pipe and is communicated with the inside of the measuring pipe;
the control case is arranged at the wellhead, and the flow detection assembly, the radio frequency probe and the ultrasonic amplitude detector are all electrically connected with a control circuit board assembly in the control case;
the control circuit board assembly is used for respectively determining the volume flow Q and the water holding rate w of the fluid in the measuring tube and the gas holding rate beta of the fluid on the section of the measuring tube according to the detection data and corresponding auxiliary parameters of the flow detection assembly, the radio frequency probe and the ultrasonic amplitude detector, and is also used for determining the water production volume flow Q in the fluid according to the volume flow Q, the water holding rate w and the gas holding rate betawGas production volume flow qgAnd the volume flow q of produced oilo。
In one embodiment of the present invention, the flow detecting assembly includes: a heat pulse generator and temperature sensor assembly;
the heat pulse generator is fixedly arranged on the pipe wall of the measuring pipe, is communicated with the inside of the measuring pipe and is used for releasing heat pulses to the fluid in the measuring pipe at regular time;
the temperature sensor assembly is fixedly arranged on the pipe wall of the measuring pipe, is communicated with the inside of the measuring pipe and is used for measuring the temperature of the fluid heated by the heat pulse generator in the measuring pipe;
and the control circuit board assembly is used for determining the volume flow Q according to the detection data of the temperature sensor assembly and corresponding auxiliary parameters.
In one embodiment of the present invention, the temperature sensor assembly includes: a first temperature sensor and a second temperature sensor;
the first temperature sensor and the second temperature sensor are arranged at intervals and are positioned at the downstream position of the heat pulse generator.
In one embodiment of the present invention, the control circuit board assembly for determining the volume flow rate Q of the fluid in the measuring pipe according to the detection data of the temperature sensor assembly and the corresponding auxiliary parameters comprises: according to the time interval delta T between two adjacent temperature peaks monitored by the first temperature sensor and the second temperature sensorpThe inner diameter D of the measuring tube and the distance Δ L between the first temperature sensor and the second temperature sensor determine the volume flow Q.
In one embodiment of the invention, the measurement pipe comprises an intermediate joint and a measurement main pipe section; the flow detection assembly comprises: a first ultrasonic transceiver and a second ultrasonic transceiver;
the middle joint is coaxial and communicated with the measuring main pipe section, and the inner diameter of the middle joint is equal to that of the measuring main pipe section;
the first ultrasonic transceiver and the second ultrasonic transceiver are fixedly arranged in the middle joint and are positioned at two radial ends of the middle joint; the ultrasonic transducer of the first ultrasonic transceiver and the ultrasonic transducer of the second ultrasonic transceiver are coaxial, and an included angle theta between an axial connecting line and the flow direction of the measuring main pipe section is 35-55 degrees;
the radio frequency probe and the ultrasonic amplitude detector are both fixedly arranged on the pipe wall of the measuring main pipe section.
In one embodiment of the present invention, the control circuit board assembly for determining the volume flow rate Q of the fluid in the measuring pipe according to the detection data of the flow rate detection assembly and the corresponding auxiliary parameters comprises: and the control circuit board assembly determines the average flow velocity v and the volume flow Q of the fluid along the measurement main pipe section according to the time difference delta t between forward flow and reverse flow of the ultrasonic waves of the first ultrasonic transceiver and the second ultrasonic transceiver in the fluid, the sound velocity c of the fluid in the measurement main pipe section, the included angle theta and the inner diameter D of the measurement main pipe section.
In one embodiment of the present invention, the ultrasonic amplitude detector includes: a third ultrasonic transceiver and a fourth ultrasonic transceiver;
the third ultrasonic transceiver and the fourth ultrasonic transceiver are fixedly arranged on the measuring pipe and are positioned at two radial ends of the measuring pipe; the ultrasonic transducer of the third ultrasonic transceiver and the ultrasonic transducer of the fourth ultrasonic transceiver are coaxial and are axially perpendicular to the axial direction of the measuring tube.
In one embodiment of the present invention, the control circuit board assembly for measuring a gas holdup β of the fluid on the tube section based on the ultrasonic amplitude detector detection data and the corresponding auxiliary parameter comprises: the control circuit board assembly is used for measuring an ultrasonic amplitude voltage signal U according to the third ultrasonic transceiver or the fourth ultrasonic transceiverusA time difference signal Δ T measured by the third ultrasonic transceiver or the fourth ultrasonic transceiverusAnd three ultrasonic calibration coefficients b1,b2,b3Determining the gas holdup beta.
In one embodiment of the present invention, the determining the water holding rate w of the fluid in the measuring tube according to the detection data of the radio frequency probe and the corresponding auxiliary parameters by the control circuit board assembly comprises: radio frequency voltage signal U measured based on radio frequency probeaAnd three radio frequency calibration coefficients k1,k2,k3And determining the water holding rate w.
In one embodiment of the invention, further comprising, a pipe bend;
one end of the bent pipe section is communicated with the other end of the measuring pipe, and the bent pipe section is bent upwards.
The invention has the beneficial effects that:
the three-phase fluid metering device is arranged at the wellhead, so that the single-phase flow (oil production volume flow, water production volume flow and gas production volume flow) can be detected and metered under the condition that oil, gas and water are not split, the structure is simple, the reliability of the device is improved, the three-phase fluid of a single well can be measured in real time, the automation degree is higher, and the metering efficiency of the three-phase fluid of the single well is improved.
The present invention will be described in further detail with reference to the accompanying drawings and examples.
Drawings
FIG. 1 is a schematic structural diagram of a wellhead three-phase fluid metering device provided by an embodiment of the invention;
FIG. 2 is a schematic diagram of another wellhead three-phase fluid metering device according to an embodiment of the present invention;
FIG. 3 is a schematic structural diagram of yet another wellhead three-phase fluid metering device provided by an embodiment of the present invention;
FIG. 4 is a schematic structural diagram of yet another wellhead three-phase fluid metering device provided by an embodiment of the present invention;
fig. 5 is a schematic external structural diagram of a control chassis according to an embodiment of the present invention;
fig. 6 is a schematic internal structural diagram of a control chassis according to an embodiment of the present invention;
fig. 7 is a schematic block diagram of circuit elements of a control cabinet according to an embodiment of the present invention.
Description of reference numerals:
10-an inlet connection; 20-a measurement tube; 21-an intermediate joint; 22-measuring the main tube section; 23-bending the pipe section; 24-a collar; 30-a flow detection component; 31-a heat pulse generator; 32-a first temperature sensor; 33-a second temperature sensor; 34-a first ultrasound transceiver; 35-a second ultrasound transceiver; 40-a radio frequency probe; 50-an ultrasonic amplitude detector; 51-a third ultrasound transceiver; 52-a fourth ultrasound transceiver; 60-control cabinet; 61-control circuit board assembly; 62-a display screen; 63-a data sampling and processing circuit board; 64-a radio frequency circuit board; 65-a data transmission module; 66-a front panel; 67-explosion proof joint; 68-a direct current switching power supply; 70-a housing; 71-end cap.
Detailed Description
The present invention will be described in further detail with reference to specific examples, but the embodiments of the present invention are not limited thereto.
Example one
Referring to fig. 1, a wellhead three-phase fluid metering device comprises: inlet fitting 10, measurement pipe 20, flow sensing assembly 30, rf probe 40, ultrasonic amplitude detector 50, and control box 60. The inlet joint 10 is arranged at the wellhead, one end of the inlet joint 10 is connected and communicated with an oil pipe, and the other end of the inlet joint 10 is communicated with one end of the measuring pipe 20. The inlet fitting 10 has an inner diameter equal to the inner diameter of the tubing. The measuring tube 20 is arranged horizontally, the inner diameter of the measuring tube 20 being equal to the inner diameter of the tubing. In this embodiment, fluid produced by a single well passes from the tubing through the inlet fitting 10 into the measurement pipe 20 and then into the external collection tank. Thus, the three-phase fluid can be detected and metered in the measuring tube 20, so that a real-time production of the single-well three-phase fluid can be obtained. Wherein, the inlet joint 10 is connected with the wellhead tubing through screw threads.
The flow sensing assembly 30 is disposed on the measurement pipe 20, and the flow sensing assembly 30 communicates with the inside of the measurement pipe 20. The sensed data from the flow sensing assembly 30 can be used to calculate the volumetric flow rate Q of the fluid along the measurement tube 20. The radio frequency probe 40 is fixed on the wall of the measuring tube 20, and the radio frequency probe 40 is communicated with the inside of the measuring tube 20. The radio frequency signal of the radio frequency probe 40 can be used to calculate the water holdup w of the fluid within the measurement tube 20. The ultrasonic amplitude detector 50 is fixed to the wall of the measurement pipe 20, and the ultrasonic amplitude detector 50 communicates with the inside of the measurement pipe 20. The data detected by the ultrasonic amplitude detector 50 can be used to calculate the gas holdup β of the fluid in the measurement pipe 20.
The control cabinet 60 is arranged at the wellhead, and the flow detection assembly 30, the radio frequency probe 40 and the ultrasonic amplitude detector 50 are all electrically connected with a control circuit board assembly 61 in the control cabinet 60. The flow detection assembly 30, the radio frequency probe 40 and the ultrasonic amplitude detector 50 respectively send detection data to the control circuit board assembly 61, and the control circuit board assembly 61 processes the detection data.
The control circuit board assembly 61 is used for determining the volume flow rate Q of the fluid in the measuring pipe 20 according to the detection data of the flow detection assembly 30 and corresponding auxiliary parameters, and controllingThe circuit board making assembly 61 is used for determining the water holding rate w of the fluid in the measuring pipe 20 according to the detection data of the radio frequency probe 40 and the corresponding auxiliary parameters, the control circuit board assembly 61 is used for determining the gas holding rate beta of the fluid in the measuring pipe 20 according to the detection data of the ultrasonic amplitude detector 50 and the corresponding auxiliary parameters, and the control circuit board assembly 61 is also used for determining the gas production volume flow Q in the fluid according to the volume flow Q, the water holding rate w and the gas holding rate betagVolume flow q of produced waterwAnd the volume flow q of produced oilo。
The three-phase fluid metering device of the embodiment can detect the three-phase mixed fluid in the measuring pipe 20, and obtain the real-time volume flow of the single-phase fluid, and does not need to perform phase separation on the mixed fluid or use phase separation setting, and has simple structure and high reliability. Meanwhile, the detectable range of each element used in data detection is large, the device is suitable for detection in different flow ranges, the three-phase mixed fluid of a single well can be measured in real time, the automation degree is high, and the metering efficiency of the three-phase fluid of the single well is improved. Wherein, when the fluid in the measuring pipe 20 is a three-phase or two-phase mixed fluid, the volume flow Q is a mixed volume flow.
In this embodiment, the measuring pipe 20 is horizontally disposed, so that the influence of gravity on the fluid in the measuring pipe 20 on the final metering result can be avoided. The inner diameter of the measuring tube 20 is the same as that of the oil tube, so that the influence of the additional resistance and pressure difference factors generated by the fluid in the measuring tube 20 due to the diameter expansion or necking on the measuring precision is avoided.
In a possible embodiment, the three-phase fluid metering device according to the invention can also be used for single-phase fluid metering, in which case the water retention is 100% when there is only single-phase fluid in the measuring tube 20, i.e. only one of oil, gas and water, for example when there is only water in the measuring tube 20, and the volume flow Q is the water production volume flow Qw(ii) a When only gas exists in the measuring tube 20, the gas holding rate is 100%, and then the volume flow Q is the gas production volume flow Qg(ii) a When only oil is present in the measurement tube 20, the volume flow Q is then the oil production volume flow Qo。
In one possible implementation, the three-phase fluid metering device of the present invention further includes a housing 70 and an end cap 71. Casing 70 cover is established outside surveying buret 20, and flow detection subassembly 30, radio frequency probe 40, ultrasonic wave amplitude detector 50 all are located casing 70, and casing 70 can play the guard action to surveying buret 20 and flow detection subassembly 30, radio frequency probe 40, ultrasonic wave amplitude detector 50, has prolonged metering device's life. An end cap 71 seals over the end of the housing 70 remote from the inlet.
Example two
As shown in fig. 1, in the present embodiment, on the basis of the first embodiment, it is further defined that the flow rate detecting assembly 30 includes: a heat pulse generator 31 and a temperature sensor assembly. The heat pulse generator 31 is fixed to the wall of the measuring pipe 20, the heat pulse generator 31 is connected to the inside of the measuring pipe 20, and the heat pulse generator 31 is used for timing the release of heat pulses to the fluid inside the measuring pipe 20. The heat pulse generator 31 can generate heat pulses to heat the fluid, so as to raise the temperature of the fluid and periodically heat the fluid. The temperature sensor assembly is fixedly arranged on the wall of the measuring pipe 20, is communicated with the inside of the measuring pipe 20, and is used for measuring the temperature of the fluid heated by the heat pulse generator 31 in the measuring pipe 20. The sensed data of the temperature sensor assembly can be used to calculate the volumetric flow rate Q of the fluid within the measurement pipe 20. The control circuit board assembly 61 is used to determine the volume flow Q based on the sensed data of the temperature sensor assembly and the corresponding auxiliary parameters.
Further, as shown in fig. 1, the temperature sensor assembly includes: a first temperature sensor 32 and a second temperature sensor 33. The first temperature sensor 32 and the second temperature sensor 33 are disposed at intervals, and both the first temperature sensor 32 and the second temperature sensor 33 are located at a position downstream of the heat pulse generator 31. In this embodiment, the first temperature sensor 32 and the second temperature sensor 33 are used for detecting the temperature of the fluid heated by the heat pulse generator 31, and therefore, the first temperature sensor 32 and the second temperature sensor 33 are located on the side of the heat pulse generator 31 away from the wellhead.
In this embodiment, after the heat pulse generator 31 heats the fluid flowing through it, the heated fluid sequentially passes through the first temperature sensor 32 and the second temperature sensor 33, and the first temperature sensor 32 and the second temperature sensor 33 sequentially detect the temperature of the heated fluid.
The radio frequency probe 40 and the ultrasonic amplitude detector 50 may be located at any position on the measurement pipe 20. The first temperature sensor 32 and the second temperature sensor 33 are Pt1000 temperature sensors.
In this embodiment, the control circuit board assembly 61 for determining the volume flow rate Q of the fluid in the measuring pipe 20 according to the detection data of the temperature sensor assembly and the corresponding auxiliary parameters includes: according to the time interval Delta T between the temperature peaks respectively monitored by the first temperature sensor 32 and the second temperature sensor 33pThe volume flow Q is determined by the inner diameter D of the measuring tube 20 and the distance Δ L between the first temperature sensor 32 and the second temperature sensor 33.
Specifically, the volumetric flow rate Q of the fluid is calculated by the formula one:
wherein: the unit of the volume flow Q is cubic meter per second (m)3/s), Δ L in meters (m), Δ TpIn seconds(s), D in meters (m), and D in diameter.
In this embodiment, after the heat pulse generator 31 heats the fluid, when the heated fluid passes through the first temperature sensor 32, the first temperature sensor 32 detects a first temperature, which is relatively high and thus is a temperature peak, the heated fluid continues to flow downstream, and when the heated fluid passes through the second temperature sensor 33, the temperature sensor detects a second temperature, which is a temperature peak, Δ TpIs the time interval between the time the first temperature is detected and the time the second temperature is detected.
Wherein the first temperature sensor 32 and the second temperature sensor 33 should be kept at a suitable distance to balance between the measurement range and the signal-to-noise ratio of the sensors. The distance between the first temperature sensor 32 and the second temperature sensor 33 is 80-120mm, preferably the distance between the first temperature sensor 32 and the second temperature sensor 33 is 100 mm. The distance between the heat pulse generator 31 and the first temperature sensor 32 is 380-430mm, preferably the distance between the heat pulse generator 31 and the first temperature sensor 32 is 400 mm.
Further, as shown in fig. 2 and 3, the measurement pipe 20 comprises an intermediate joint 21 and a measurement main pipe section 22; the flow sensing assembly 30 includes: a first ultrasonic transceiver 34 and a second ultrasonic transceiver 35. The intermediate joint 21 is coaxial and communicated with the measuring main pipe section 22, and the inner diameter of the intermediate joint 21 is equal to that of the measuring main pipe section 22 and is equal to that of the oil pipe. The first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 are fixedly arranged in the middle joint 21, and the first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 are positioned at two radial ends of the middle joint 21; the ultrasonic transducer of the first ultrasonic transceiver 34 and the ultrasonic transducer of the second ultrasonic transceiver 35 are coaxial, and the included angle theta between the axial connecting line and the flow direction of the measurement main pipe section 22 is 35-55 degrees. Control circuit board assembly 61 is configured to determine a volumetric flow rate Q of the fluid in main tube segment 22 based on the sensed data from the ultrasonic transducers of first ultrasonic transceiver 34 and second ultrasonic transceiver 35 and the corresponding auxiliary parameters. The first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 are both electrically connected to the control circuit board assembly 61.
In this embodiment, two opposite mounting grooves are formed in the inner wall of the intermediate joint 21, and the first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 are respectively fixed in the two mounting grooves. The intermediate connection 21 may be located at any position of the measuring main pipe section 22, for example, at any one of two ends of the measuring main pipe section 22, or the intermediate connection 21 may divide the measuring main pipe section 22 into two sections. The RF probe 40 and the ultrasonic amplitude detector 50 are fixedly mounted on the wall of the measurement main tube section 22. The measuring main pipe section 22 is a circular pipe structure.
In a possible implementation, the intermediate connector 21 is located between the inlet connector 10 and the measuring main pipe section 22, the other end of the inlet connector 10 is connected and communicated with one end of the intermediate connector 21, and the other end of the intermediate connector 21 is connected and communicated with one end of the measuring main pipe section 22. Wherein the intermediate connection 21 and the measuring main pipe section 22 are both located within the housing 70.
In this embodiment, the determining the volume flow Q of the fluid in the measuring pipe 20 by the control circuit board assembly 61 according to the detection data of the flow detection assembly 30 and the corresponding auxiliary parameters includes: the control circuit board assembly 61 determines the average flow velocity v and the volume flow Q of the fluid along the main pipe section 22 according to the time difference Δ t between the forward flow and the backward flow of the ultrasonic waves of the first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 in the fluid, the sound velocity c in the fluid in the main pipe section 22, the included angle θ, and the inner diameter D of the main pipe section 22.
In this embodiment, because an included angle θ exists between a connecting line of the axes of the transducers of the first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 and the flow direction of the main pipe segment 22, the first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 are disposed obliquely, the first ultrasonic transceiver 34 is close to the inlet joint 10, the second ultrasonic transceiver 35 is far away from the inlet joint 10, and the fluid in the intermediate joint 21 passes through the first ultrasonic transceiver 34 and then passes through the second ultrasonic transceiver 35. Therefore, when the first ultrasonic transceiver 34 transmits ultrasonic waves and the second ultrasonic transceiver 35 receives the ultrasonic waves transmitted by the first ultrasonic transceiver 34, the time for the ultrasonic waves to pass through the fluid is the time t1 for the ultrasonic waves to pass downstream, and when the second ultrasonic transceiver 35 transmits the ultrasonic waves and the first ultrasonic transceiver 34 receives the ultrasonic waves transmitted by the second ultrasonic transceiver 35, the time for the ultrasonic waves to pass through the fluid is the time t2 for the ultrasonic waves to pass upstream, and Δ t is the time difference between t1 and t 2.
Specifically, the average flow velocity v of the fluid along the measurement main tube segment 22 is calculated by the formula two:
where v is in meters per second (m/s), c is in meters per second (m/s), D is in meters (m), D is the diameter, and Δ t is in seconds(s).
The volumetric flow Q is calculated from the average flow velocity v and the inner diameter of the intermediate connection 21 (equal to the inner diameter of the measuring main tube section 22). The volume flow Q is vxmeasured as the cross-sectional area a of the main pipe section 22, a is pi D2/4。
Preferably, the included angle θ is 51 °.
In one possible implementation, the three-phase fluid metering device flow sensing assembly 30 includes a thermal pulse generator 31 and a temperature sensor assembly, or the flow sensing assembly 30 includes a first ultrasonic transceiver 34 and a second ultrasonic transceiver 35, one of which may be used to calculate the volumetric flow Q.
The flow rate detecting component 30 may also include the thermal pulse generator 31, the temperature sensor component, the first ultrasonic transceiver 34, and the second ultrasonic transceiver 35 to respectively calculate two volume flow rates Q, and then respectively obtain corresponding data according to the two volume flow rates Q, so that the data obtained according to the two volume flow rates Q can be cross-compared and verified, so as to further improve the metering accuracy. Moreover, the simultaneous arrangement of the heat pulse generator 31 and the temperature sensor assembly, and the first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 can adapt to different total well flow rates, for example, when the temperature difference measurement flow rate is higher in measurement accuracy at a lower production rate (when the flow rate is relatively low), the temperature difference measurement data can be used as the flow rate calculation data at the lower production rate; the ultrasonic measurement flow rate has high measurement accuracy at a high throughput (when the flow rate is relatively high), and the data of the ultrasonic measurement flow rate can be used as the calculation data of the flow rate at a high throughput. Therefore, the simultaneous arrangement of the heat pulse generator 31 and the temperature sensor assembly, and the first ultrasonic transceiver 34 and the second ultrasonic transceiver 35 can ensure the measurement accuracy under different working conditions, and is also suitable for production wells with different production rates and different production rates of the same production well, thereby improving the universality of the metering device.
Wherein the heat pulse generator 31 and the temperature sensor assembly can be arranged on the measuring main tube section 22.
Further, as shown in fig. 3, the ultrasonic amplitude detector 50 includes: a third ultrasonic transceiver 51 and a fourth ultrasonic transceiver 52. The third ultrasonic transceiver 51 and the fourth ultrasonic transceiver 52 are fixedly arranged on the measuring main pipe section 22 of the measuring pipe 20 and are positioned at two radial ends of the measuring main pipe section 22 of the measuring pipe 20; the ultrasonic transducers of the third ultrasonic transceiver 51 and the ultrasonic transducers of the fourth ultrasonic transceiver 52 are coaxial and axially perpendicular to the axial direction of the measuring main pipe section 22. The third ultrasonic transceiver 51 and the fourth ultrasonic transceiver 52 are both electrically connected to the control circuit board assembly 61.
In this embodiment, the control circuit board assembly 61 for measuring the gas holdup β of the fluid in the pipe 20 according to the data detected by the ultrasonic amplitude detector 50 and the corresponding auxiliary parameter includes: the control circuit board assembly 61 is used for controlling the ultrasonic amplitude voltage signal U measured by the third ultrasonic transceiver 51 or the fourth ultrasonic transceiver 52usThe time difference signal Δ T measured by the third ultrasonic transceiver 51 or the fourth ultrasonic transceiver 52usAnd three ultrasonic calibration coefficients b1,b2,b3The gas holdup beta is determined.
In this embodiment, one of the third ultrasonic transceiver 51 and the fourth ultrasonic transceiver 52 transmits ultrasonic waves, and the other thereof receives ultrasonic waves. Because the gas content in the fluid is different in size, the ultrasonic attenuation is different, and therefore, the gas holdup beta of the fluid on the section of the main pipe section 22 can be determined according to the amplitude signal of the ultrasonic wave in the main pipe section 22 received by the ultrasonic receiving end. Wherein, the ultrasonic wave calibrates the coefficient b1,b2,b3Are constants measured according to factors such as the structure and signal frequency of the third ultrasonic transceiver 51 and the fourth ultrasonic transceiver 52.
Specifically, the gas holdup β is calculated by the formula three:
β＝f(b1,b2,b3,Uus,ΔTus) (formula three)
Wherein beta is dimensionless, UusIn volts (V), Δ TusIn seconds(s). Gas holdup beta through pair b1,b2,b3，ΔTus，UusThe respective data are fitted, preferably, toTo fit using a least squares method.
It should be noted that the third ultrasonic transceiver 51 and the fourth ultrasonic transceiver 52 may periodically operate alternately as a receiving end and a transmitting end. For example, the third ultrasonic transceiver 51 transmits, the fourth ultrasonic transceiver 52 receives, and 10ms after the fourth ultrasonic transceiver 52 receives, the fourth ultrasonic transceiver 52 transmits, and the third ultrasonic transceiver 51 receives, and the cycle is repeated.
Further, the control circuit board assembly 61 for determining the water holding rate w of the fluid in the measurement pipe 20 according to the data detected by the rf probe 40 and the corresponding auxiliary parameters includes: radio frequency voltage signal U measured based on radio frequency probe 40aAnd three radio frequency calibration coefficients k1,k2,k3And determining the water holding rate w.
In this embodiment, the rf probe 40 includes an emitting probe and a measuring probe, and distinguishes oil and water (the oil and gas dielectric constant is much smaller than water) according to the difference of the dielectric constant of the measured medium, and according to the difference of the structure and frequency of the rf probe 40, the water holding rate w can be determined by the phase and amplitude of the rf signal received by the measuring probe, the signal amplitude decreases as the water holding rate of the medium increases, and the rf voltage signal indicates the amplitude of the rf signal.
Specifically, the water holdup w is calculated by the formula four:
w＝f(k1,k2,k3,Ua) (formula four);
wherein w is nothing, UaHas a unit of volt (V) and a radio frequency calibration coefficient k1,k2,k3Is a constant determined based on factors such as the configuration of the rf probe 40 and the frequency of the signal. Water holdup w is through pair k1,k2,k3，UaThe fit is obtained, preferably, by a least squares fit.
The calibration coefficient represents a model parameter required for calculating a flow rate from sensor data in an actually used measuring device, and is present to compensate for some unavoidable errors in mechanical, electronic, and other components of a certain instrument during a manufacturing process. Each particular instrument will have a set of calibration coefficients adapted to it.
Further, determining the water production volume flow Q in the fluid according to the volume flow Q, the water holding rate w and the gas holding rate betawGas production volume flow qgAnd the volume flow q of produced oilo。
Specifically, the water production volume flow q is calculated by the formula fivew：
qwW · Q (formula five);
calculating the gas production volume flow q by a formula sixg：
qgβ · Q (formula six);
calculating the oil production volume flow q by the formula seveno：
qoQ (formula seven).
Further, as shown in fig. 4, a wellhead three-phase fluid metering device further comprises a bent pipe section 23. One end of the bent pipe section 23 communicates with the other end of the measurement pipe 20, and the bent pipe section 23 is bent upward. The other end of the bend section 23 is connected with the collecting tank, the bend section 23 is vertically upwards protruded towards the direction far away from the horizontal plane, the bend section 23 can prevent air on one side of the collecting tank from entering the measuring main pipe section 22 of the measuring pipe 20, and the influence on the measurement of the fluid in the measuring main pipe section 22 is avoided. One end of the bent pipe section 23 is connected to the other end of the measuring main pipe section 22 by a collar 24.
Further, as shown in fig. 5, 6 and 7, the control circuit board assembly 61 includes: a display screen 62, a data sampling and processing circuit board 63, a radio frequency circuit board 64 and a data transmission module 65.
The output end of the data sampling and processing circuit board 63 is electrically connected with the display screen 62, and the input end of the data sampling and processing circuit board 63 is electrically connected with the radio frequency circuit board 64, the flow rate detection assembly 30, the heat pulse generator 31, the ultrasonic amplitude detector 50 and the temperature sensor assembly. The data sampling and processing circuit board 63 is electrically connected to the data transmission module 65. The radio frequency circuit board 64 is electrically connected to the radio frequency probe 40, and the radio frequency circuit board 64 is configured to output a transmission signal to a transmission probe in the radio frequency probe 40, receive a radio frequency voltage signal measured by a measurement probe of the radio frequency probe 40, and send the radio frequency voltage signal to the data sampling and processing circuit board 63.
Further, the display screen 62 is disposed on a front panel 66 of the control box 60. The display screen 62 is connected with the data sampling and processing circuit board 63 and is used for displaying the data such as the detection data and the volume flow data obtained by calculation; the rf circuit board 64 is used for outputting a transmission signal to the transmission probe in the rf probe 40, and at the same time, is used for receiving an rf voltage signal of the measurement probe in the rf probe 40 and transmitting the signal to the data sampling and processing circuit board 63. The input end of the data sampling and processing circuit board 63 may be electrically connected to the radio frequency circuit board 64, the first temperature sensor 32, the second temperature sensor 33, the heat pulse generator 31, the first ultrasonic transceiver 34, the second ultrasonic transceiver 35, the third ultrasonic transceiver 51, and the fourth ultrasonic transceiver 52, and the data sampling and processing circuit board 63 is used for signal acquisition, calculation processing, display, storage, and return of these components. The data transmission module 65 is configured to transmit the calculated data such as the detection data and the volume flow data back to the database server in the background through a wireless signal. The metering device also includes a dc switching power supply 68 for powering the associated electrical components. The input end of the DC switch power supply 68 is connected with a 220V AC power supply, and the output end is connected with the data sampling and processing circuit board 63, the radio frequency circuit board 64, the heat pulse generator 31,
The control cabinet 60 preferably but not limited to have an explosion-proof function, and an explosion-proof joint 67 is disposed on the control cabinet 60. The data sampling and processing circuit board 63 is preferably, but not limited to, an ARM (Advanced RISC Machine) development board and a PLC (Programmable Logic Controller) board. The Data transmission module 65 is preferably, but not limited to, a DTU (Data Transfer unit) communication module. The DC switching power supply 68 is preferably, but not limited to, a 220VAC-24VDC power supply.
In the description of the present invention, it is to be understood that the terms "center", "longitudinal", "lateral", "length", "width", "thickness", "upper", "lower", "front", "rear", "left", "right", "vertical", "horizontal", "top", "bottom", "inner", "outer", "clockwise", "counterclockwise", and the like, indicate orientations and positional relationships based on those shown in the drawings, and are used only for convenience of description and simplicity of description, and do not indicate or imply that the device or element being referred to must have a particular orientation, be constructed and operated in a particular orientation, and thus, should not be considered as limiting the present invention.
In the present invention, unless otherwise expressly stated or limited, the terms "mounted," "connected," "secured," and the like are to be construed broadly and can, for example, be fixedly connected, detachably connected, or integrally formed; can be mechanically or electrically connected; either directly or indirectly through intervening media, either internally or in any other relationship. The specific meanings of the above terms in the present invention can be understood by those skilled in the art according to specific situations.
The foregoing is a more detailed description of the invention in connection with specific preferred embodiments and it is not intended that the invention be limited to these specific details. For those skilled in the art to which the invention pertains, several simple deductions or substitutions can be made without departing from the spirit of the invention, and all shall be considered as belonging to the protection scope of the invention.
Claims (10)
1. A wellhead three phase fluid metering device, comprising: the device comprises an inlet joint (10), a measuring pipe (20), a flow detection assembly (30), a radio frequency probe (40), an ultrasonic amplitude detector (50) and a control cabinet (60);
the inlet joint (10) is close to a wellhead, one end of the inlet joint is connected and communicated with an oil pipe, the other end of the inlet joint is communicated with one end of the measuring pipe (20), and the inner diameter of the inlet joint is equal to that of the oil pipe;
the measuring pipe (20) is horizontally arranged, and the inner diameter of the measuring pipe is equal to that of the oil pipe;
the flow detection assembly (30) is arranged on the measuring pipe (20) and communicated with the inside of the measuring pipe (20);
the radio frequency probe (40) is fixedly arranged on the pipe wall of the measuring pipe (20) and is communicated with the inside of the measuring pipe (20);
the ultrasonic amplitude detector (50) is fixedly arranged on the pipe wall of the measuring pipe (20) and is communicated with the inside of the measuring pipe (20);
the control cabinet (60) is arranged at the wellhead, and the flow detection assembly (30), the radio frequency probe (40) and the ultrasonic amplitude detector (50) are electrically connected with a control circuit board assembly (61) in the control cabinet (60);
the control circuit board assembly (61) is used for respectively determining the volume flow Q and the water holding rate w of the fluid in the measuring pipe (20) and the gas holding rate beta of the fluid on the section of the measuring pipe (20) according to the detection data and corresponding auxiliary parameters of the flow detection assembly (30), the radio frequency probe (40) and the ultrasonic amplitude detector (50), and is also used for determining the water production volume flow Q in the fluid according to the volume flow Q, the water holding rate w and the gas holding rate betawGas production volume flow qgAnd the volume flow q of produced oilo。
2. A wellhead three phase fluid metering device according to claim 1, characterized in that the flow sensing assembly (30) comprises: a heat pulse generator (31) and a temperature sensor assembly;
the heat pulse generator (31) is fixedly arranged on the pipe wall of the measuring pipe (20), is communicated with the inside of the measuring pipe (20), and is used for releasing heat pulses to the fluid in the measuring pipe (20) at regular time;
the temperature sensor assembly is fixedly arranged on the pipe wall of the measuring pipe (20), is communicated with the inside of the measuring pipe (20), and is used for measuring the temperature of fluid heated by the heat pulse generator (31) in the measuring pipe (20);
the control circuit board assembly (61) is used for determining the volume flow Q according to the detection data of the temperature sensor assembly and corresponding auxiliary parameters.
3. A wellhead three phase fluid metering device, according to claim 2, characterized in that said temperature sensor assembly comprises: a first temperature sensor (32) and a second temperature sensor (33);
the first temperature sensor (32) and the second temperature sensor (33) are arranged at intervals and are positioned at the downstream position of the heat pulse generator (31).
4. A wellhead three phase fluid metering device according to claim 3, characterized in that the control circuit board assembly (61) for determining the volumetric flow rate Q of the fluid in the measuring pipe (20) based on the sensed data of the temperature sensor assembly and the corresponding auxiliary parameters comprises: according to the time interval Delta T between two adjacent temperature peaks monitored by the first temperature sensor (32) and the second temperature sensor (33)pThe inner diameter D of the measuring tube (20), the distance DeltaL between the first temperature sensor (32) and the second temperature sensor (33) determine the volume flow Q.
5. A wellhead three phase fluid metering device according to claim 1 or 2, characterized in that the measuring tube (20) comprises an intermediate joint (21) and a measuring main tube section (22); the flow sensing assembly (30) comprising: a first ultrasonic transceiver (34) and a second ultrasonic transceiver (35);
the intermediate joint (21) is coaxial and communicated with the measuring main pipe section (22), and the inner diameter of the intermediate joint is equal to that of the measuring main pipe section (22);
the first ultrasonic transceiver (34) and the second ultrasonic transceiver (35) are fixedly arranged in the middle joint (21) and are positioned at two radial ends of the middle joint (21); the ultrasonic transducer of the first ultrasonic transceiver (34) and the ultrasonic transducer of the second ultrasonic transceiver (35) are coaxial, and an included angle theta between an axial connecting line and the flow direction of the measuring main pipe section (22) is 35-55 degrees;
the radio frequency probe (40) and the ultrasonic amplitude detector (50) are both fixedly arranged on the pipe wall of the measuring main pipe section (22).
6. A wellhead three-phase fluid metering device according to claim 5, characterized in that the control circuit board assembly (61) for determining the volumetric flow rate Q of the fluid in the measuring pipe (20) based on the sensed data of the flow sensing assembly (30) and the corresponding auxiliary parameters comprises: the control circuit board assembly (61) determines the average flow velocity v and the volume flow Q of the fluid along the measuring main pipe section (22) according to the time difference delta t of the forward flow and the backward flow of the ultrasonic waves in the fluid of the first ultrasonic transceiver (34) and the second ultrasonic transceiver (35), the sound velocity c in the fluid in the measuring main pipe section (22), the included angle theta and the inner diameter D of the measuring main pipe section (22).
7. A wellhead triphase fluid metering device according to claim 5, characterized in that said ultrasonic amplitude detector (50) comprises: a third ultrasonic transceiver (51) and a fourth ultrasonic transceiver (52);
the third ultrasonic transceiver (51) and the fourth ultrasonic transceiver (52) are fixedly arranged on the measuring pipe (20) and are positioned at two ends of the measuring pipe (20) in the radial direction; the ultrasonic transducers of the third ultrasonic transceiver (51) and the ultrasonic transducers of the fourth ultrasonic transceiver (52) are coaxial and have an axial direction perpendicular to the axial direction of the measuring pipe (20).
8. A wellhead three phase fluid metering device according to claim 7, characterized in that said control circuit board assembly (61) for measuring gas holdup β of fluid in section of said measuring tube (20) based on data detected by said ultrasonic amplitude detector (50) and corresponding auxiliary parameters comprises: the control circuit board assembly (61) is used for measuring an ultrasonic amplitude voltage signal U according to the third ultrasonic transceiver (51) or the fourth ultrasonic transceiver (52)usA time difference signal DeltaT measured by the third ultrasonic transceiver (51) or the fourth ultrasonic transceiver (52)usAnd three ultrasonic calibration coefficients b1,b2,b3Determining the gas holdup rateβ。
9. A wellhead three phase fluid metering device according to claim 1, characterized in that the control circuit board assembly (61) for determining the water holding rate w of the fluid in the measuring pipe (20) based on the radio frequency probe (40) detection data and corresponding auxiliary parameters comprises: based on the radio frequency voltage signal U measured by the radio frequency probe (40)aAnd three radio frequency calibration coefficients k1,k2,k3And determining the water holding rate w.
10. A wellhead triphase fluid metering device according to claim 1, characterized by, that it further comprises, a pipe bend section (23);
one end of the bent pipe section (23) is communicated with the other end of the measuring pipe (20), and the bent pipe section (23) is bent upwards.
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