Oil well mouth diagnosis device

Abstract

An oil well mouth diagnosis device is installed on an oil outlet pipeline of an oil well mouth, completes on-line monitoring of underground pump conditions, liquid production capacity, water content and the like of an oil well, can achieve signal remote transmission, enables a platform computer to plot obtained data and conduct remote control on the device, avoids manual on-site testing operation, and improves work efficiency. Therefore, the three problems of single well liquid production capacity metering, pump condition diagnosis under the condition of a strip indicator diagram and water content measurement in current oil extraction production digitization and intelligentization are solved, and an effective means is provided for digitization and intelligentization management of an oil extraction well.

Description

Technical Field

[0001] The present invention is to establish a comprehensive device installed at the wellhead of an oil well for measuring the liquid production volume and diagnosing the pump condition, belonging to the technical field of oil production engineering applications. Background Art

[0002] Under the traditional management mode of oil production wells, various production dynamic data are manually recorded. For the measurement of the liquid production volume, after the fluid produced by the oil well is transported through the gathering pipeline to the metering station, the oil well production fluid to be measured is reversed in the metering station to separate and bypass the gas, and the liquid accumulates in the separator tank. The time taken for the liquid level to rise to a certain height is observed through a glass tube to calculate the daily liquid production volume of the well; the water cut is measured by taking samples at the wellhead and discharging them to the laboratory for distillation; the diagnosis of the working state of the downhole pump is carried out by combining the load-displacement relationship curve (i.e., the indicator diagram) of the pumping unit with the production dynamic parameters. Due to the large amount of work for each test, it can only be arranged to be measured regularly, which not only results in high production management costs but also poor timeliness of the data, making the discovery and handling of problems lag behind.

[0003] With the development and progress of computer technology, as well as the development and application of the Internet, work on digital and intelligent management is also being carried out in oilfield production to improve production management and technical management levels and promote the development and progress of the industry. So far, many oil wells have installed Internet of Things equipment such as measuring pressure, temperature, dynamic liquid level, indicator diagram, and current curve to replace manual data recording. However, automatic measurement of the liquid production volume of a single well remains a difficult problem.

[0004] The difficulty in digitizing the measurement of fluid production lies in the fact that the fluid produced from the wellhead is a three-phase mixture of oil, gas, and water, and it is not evenly mixed. The gas in the fluid can exist in the form of large bubbles, mist, or slugs. Over the years, various measurement methods for the wellhead-produced fluid have been proposed or tested, such as gas-liquid separation method, tipping bucket liquid measurement method, weighing method, orifice flow method, etc. However, due to various reasons, these methods are difficult to be successfully implemented under wellhead conditions and obtain reliable data: Among them, in the same pressure system of a small device with a small space, it is difficult for the gas and liquid to go their separate ways in the gas-liquid separation method, and it is impossible to move the large system shared by multiple wells in the metering room to the well site for gas-liquid separation and mechanical automatic control operations; in a small device, it is also difficult to separate the gas and liquid in the tipping bucket oil measurement method to allow the gas to bypass and only measure the liquid. Moreover, when there is dead oil and heavy wax accumulation in the tipping bucket, it is unreliable to measure the liquid volume by the number of weight flips; the problem of the weighing method is similar to that of the tipping bucket. It is impossible to take out and weigh the flowing fluid in a small device and then return it to the pipeline, and it is also difficult to adapt to waxy and highly viscous liquids. Therefore, it is impossible to be in good condition for a long time without cleaning; for the orifice flowmeter method, due to the large difference in the flow rate levels of oil wells, the daily liquid production of a single well ranges from a few tenths of a ton to hundreds of tons or more. It is impossible to adapt to the flow rates under different oil wells, different pump conditions of the same well, or different pumping parameters with a single orifice diameter. Without solving the problem of automatically changing the orifice diameter, it is difficult to obtain the required pressure difference through orifice throttling and thus calculate the flow rate.

[0005] In addition, in terms of the pump condition diagnosis of pumping wells, the traditional method is to analyze the pump condition based on the relationship curve between load and displacement (since this curve forms a closed graph reflecting the work done by the polished rod of the pumping unit, it is also called the indicator diagram). When the indicator diagram is in a strip shape, there are no obvious loading and unloading characteristics, and this graph has multiple solutions. Whether it is manual identification or computer identification, it is difficult to directly determine whether the downhole pump is in a working state of rod and tubing breakage, leakage, or pumping spray. This has always been a difficult point in pump condition diagnosis work at home and abroad until 1984 when the author successfully developed the double choke curve diagnosis method and promoted it to oilfields across the country, effectively solving this problem. However, in the new situation of digital and intelligent management requirements where people do not need to be on-site for operation, it is also necessary to solve the problem of automatically measuring the choke pressure curve on the Internet of Things equipment at the wellhead. Summary of the Invention

[0006] The present invention provides a comprehensive oil well wellhead detection device, which is installed on the outlet pipeline of the oil well wellhead. By automatically measuring various pressures, volumetric flow rates, and fluid densities at the wellhead, the instantaneous and cumulative liquid production can be calculated. Additionally, by installing a water cut detector, the device can complete the on-line monitoring of the downhole pump conditions, liquid production, water cut, etc. of the oil well, which are difficult to directly obtain at the wellhead before. Moreover, it can achieve signal remote transmission, and the platform computer can draw and analyze the obtained data and remotely control the device, eliminating the need for on-site manual testing operations, thereby solving the two problems of metering the unstable mixed flow of oil, gas, and water in a single well and diagnosing the pump conditions in the case of a bar-shaped dynamometer diagram in the current digital and intelligent oil production. Through the invention and application of this device, an effective means is provided for the digital and intelligent management of oil production wells.

[0007] The technical solution adopted by the present invention to solve its technical problems is as follows: This device is connected in series to the outlet pipeline of the wellhead. The fluid produced at the wellhead first flows through an orifice plate with adjustable aperture, and the adjustment of the orifice plate aperture is achieved by driving the orifice plate shaft with a motor. Pressure sensors are respectively arranged before and after the orifice plate, so that the fluid flow rate can be calculated based on the aperture and the pressure drop reflected by the pressure sensors. After the fluid flows through the orifice plate, it enters the mixing chamber, and the mixing of the fluid is realized by driving the mixing blades with the extension shaft of the screw flowmeter. After being mixed, the fluid passes through a densitometer and a water cut analyzer, and then enters the screw flowmeter and drives the rotor of the screw flowmeter to rotate, which not only realizes the measurement of the volumetric flow rate of the fluid but also provides power for mixing. The fluid flows downward into the export pipeline after coming out of the screw flowmeter. The extension shaft of the screw flowmeter extends outside the pipe and drives a generator and a pulse generator. The generator provides electrical energy and charges the battery, and the pulse generator records the volumetric flow rate and cumulative flow rate of the fluid. Since the orifice plate flowmeter calculates the liquid flow rate through the pressure difference generated by the fluid passing through the orifice and through complex multiphase flow calculations. While the screw flowmeter measures the fluid flow rate in a volumetric manner and is equipped with a densitometer to obtain the liquid flow rate therein. Starting from different physical methods, the two complement each other to obtain more reliable measurement results.

[0008] While having the function of measuring the liquid volume, this device also has the function of diagnosing the pump conditions. When it is necessary to diagnose the downhole pump conditions, the motor receives an instruction from the platform and drives the orifice plate shaft to drive the orifice plate to rotate to a position where the flow passage is blocked. The pressure in front of the orifice plate rises. According to the relationship between the pressure rise in front of the orifice plate and time, it can be determined whether the downhole pump is in a pumping state, leakage, or breakage and failure, thus solving the difficulties in diagnosing pump conditions using the traditional dynamometer diagram method and eliminating the need for on-site manual operation, meeting the development needs of intelligent management.

[0009] Advantages of the present invention: First, by comprehensively applying two flow measurement methods suitable for fluid containing impurities and with different working principles, namely the differential pressure method and the volumetric combined with density method, the problem of single-well liquid production measurement is reliably solved. Since the produced fluid in oil wells contains impurities such as sand and mud, conventional mechanical meshing flowmeters are not suitable for measuring the produced fluid in oil wells. Second, a process for replacing the orifice plate aperture is designed for the differential pressure method measurement, which solves the problem that the conventional orifice plate measurement has a limited applicable flow range and reliable results cannot be obtained when the liquid production capacity of the oil well changes. Third, a stirring process is added to the rotating shaft for volumetric method measurement, which solves the problem that the density of the gas-liquid mixture can be effectively measured only when it is uniformly mixed, so as to cooperate with the volume flowmeter to obtain the liquid volume flowing through. Fourth, by adopting the process setting of automatic orifice plate flow blocking, the difficult problem that cannot be achieved in the pump condition diagnosis by computer is solved. There is no need for on-site manual operation, meeting the needs of intelligent management. Fifth, the power of the screw flowmeter rotating shaft is borrowed to drive the generator to generate electricity and charge the battery, solving the problem of continuous power source, so as to meet the power consumption needs of the motor for actions and signal transmission when receiving action instructions, thus avoiding the damage and safety problems easily caused by pulling wires on the well site during operation construction, and also eliminating the maintenance work due to battery replacement, thus facilitating application.

[0010] In summary, this device measures the pressure of the passing fluid at different control nodes, stirs the fluid to measure the volume flow, density and water content, and transmits various signals to the electric control box of the well, and then remotely transmits them to the control platform. The control platform can interpret and remotely control the data provided by this device. The power required for the operation of this device can be supplied by the device itself without external power supply. Brief Description of the Drawings

[0011] The present invention will be further described below in conjunction with the drawings and embodiments. Figure 1 It is a schematic structural diagram of the present invention. Detailed Embodiment

[0012] As shown in the Figure 1 drawing, this device consists of a horizontal pipe 1, a battery 2, a generator 3, a pulse signal generator 4, pressure sensors 5, 6, a motor 7, an orifice plate shaft 8, an upper baffle 9, an orifice plate 10, a vertical pipe 13, blades 14, a lower baffle 15, a density meter 17, a screw flowmeter 18, an extension shaft 19, a water cut analyzer 20, a universal joint 21, a core rod 22, etc. Among them, the baffles 10 and 15 are respectively provided with flow holes 11 and 16, and the orifice plate 10 is provided with a plurality of throttling holes 12.

[0013] After the wellhead produced fluid enters the horizontal pipeline 1 of this device, it passes through the throttling orifice 12 of the orifice plate 10, then through the flow-through orifice 11 of the baffle 9, turns downward and enters the vertical pipe 13. After being stirred by the stirring blade 14, it enters the screw flowmeter 18 through the flow-through orifice 16 of the baffle 15, and then flows downward into the oil pipeline to complete the travel process of the fluid in this device.

[0014] When flowing through the orifice plate 10, due to the throttling effect of the throttling orifice 12 of the orifice plate, a throttling pressure difference will be generated before and after the orifice plate 12, and this pressure difference is recorded by the pressure sensors 5 and 6. The orifice plate 10 is circumferentially distributed with several throttling orifices of different apertures (including a blind hole). When it is necessary to change the aperture of the throttling orifice 12, the motor 7 drives the orifice plate shaft 8 to drive the orifice plate 10 to rotate a certain angle according to the instruction of the platform, so that the throttling orifice of another aperture corresponds to the flow-through orifice 11 on the baffle 9, thereby changing the throttling aperture. When it is necessary to diagnose the downhole pump condition, the blind hole position on the orifice plate 10 blocks the flow-through orifice 11 on the baffle 9, then the pressure of the pressure sensor 5 will rise. When the pressure rises to the specified threshold value, rotate the orifice plate 12 to relieve the pressure and restore to the normal flow state, and the pressure change curve during the blind plug period will be recorded and uploaded to diagnose the working condition of the downhole pump, because the relationship between pressure and time under different pump conditions is different.

[0015] After the fluid enters the vertical pipe 13 and is stirred, it enters the screw flowmeter 18, drives the rotor of the flowmeter to rotate, and drives the core rod 22 to rotate. The core rod 22 drives the extension shaft 19 to rotate through the universal joint 21, so that the blades 14 fixed on the shaft mix the gas and liquid evenly, so that the densitometer 17 can measure the uniform density, and the measurement result will not be affected by the free gas distributed in the fluid in the form of large bubbles or gas plugs. Similarly, when the water cut analyzer 20 is installed, the oil, gas and water also need to be evenly distributed to obtain relatively stable results.

[0016] The part of the extension shaft 19 exposed outside the pipe drives the generator 3 to generate electricity to charge the battery 2 to meet the electricity required for the device to record and transmit signals and to instruct the motor 7 to work. The upper end of the extension shaft 19 is connected to the pulse signal generator 4, so that the volume output represented by the rotation speed of the screw flowmeter 18 is recorded and transmitted.

[0017] The above device structure and working process are adapted to the digital full-automatic mode, and do not require manual operation and data reading on the well. If it is used under the traditional working conditions of manual well inspection, this device can also be simplified to a manual version, that is, the supporting generator 3, motor 7 and battery 2 are not installed, the pulse signal generator 4 is changed to a mechanical counter, and the pressure sensors 5 and 6 only use conventional pressure gauges. The worker directly records the pressure value displayed on the pressure gauge, the value of the counter, and the values reflected by the densitometer 17 and the water cut analyzer 20 during the well inspection. When it is necessary to diagnose the pump condition, manually rotate the orifice plate shaft 8 to block and release the liquid flow channel.

Claims

1. An oil well wellhead detection device, characterized in that: The horizontal pipe 1 is provided with a baffle 9 and an orifice plate 10 with a rotating shaft 8. The rotating shaft 8 extends to the outside of the horizontal pipe 1. The orifice plate 10 is provided with a plurality of throttle holes with different apertures. Pressure sensors 5 and 6 are installed before and after the orifice plate 10.

2. The oil well wellhead detection device according to claim 1, further characterized in that, The horizontal pipe 1 is connected to a vertical pipe 13 below. The vertical pipe 13 is provided with a baffle 15 with a flow-through hole 16. A densitometer 17, a water content analyzer 20, and a screw flowmeter 18 are also installed below it. The upper end of the screw flowmeter 18 is sequentially connected with a core rod 22, a universal joint 21, and an extension shaft 19. Stirring blades 14 are provided on the extension shaft 19.

3. The oil well wellhead detection device according to claim 1, further characterized in that, Outside the horizontal pipe 1, there are a battery 2, a generator 3, a pulse signal generator 4, and a motor 7. The motor 7 is fixed on the extension shaft 19, and the pulse signal generator 4 is connected to the top of the extension shaft 19.

4. The oil well wellhead detection device according to claim 1, further characterized in that, This device can be made into a manual version. In the manual version mode, electrical related equipment can be removed. The pulse signal generator 4 can be changed to a mechanical counter, and the pressure sensors 5 and 6 only use conventional pressure gauges.

5. The oil well wellhead detection device according to claim 1, further characterized in that, It can be made into a simplified version 1. The simplified version 1 removes the settings installed on the vertical pipe 13 and its related generator 3, pulse signal generator 4, and battery 2, and only retains the settings inside the horizontal pipe, the pressure monitoring instrument, and the motor, with an external power supply.

6. The oil well wellhead detection device according to claim 1, further characterized in that, It can be made into a simplified version 2. The simplified version 2 removes the related settings of the horizontal pipe 1 and only retains the related settings of the vertical pipe 13 and the pulse generator 4, motor 3, and battery 2 outside the pipe.

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