JP4305876B2 - Mixed liquid extraction device and mixed liquid density measuring device - Google Patents

Description

  The present invention relates to a mixed liquid extraction device that extracts a mixed liquid from a three-phase flow composed of a gas and two types of liquids, and a mixed liquid density measuring device that includes the mixed liquid extraction device.

  Oil produced from wells in the deep sea area forms a multiphase flow (three-phase flow, hereinafter abbreviated as multiphase flow) containing oil and water, and these phases are separated. After being transferred to the land without pressure, it is separated and refined through an oil well extraction process. The separated and refined oil / gas is sent and sent to the destination, and the water is drained. In the stage prior to the extraction well collection process, the flow rate of each phase of the multiphase fluid is measured for the extraction well management, the extraction process or the shipment management as necessary.

Regarding the flow rate measurement of each phase, for example, a conventional method based on a cross-correlation method using a density meter and an ultrasonic flow meter is disclosed in the prior art column of Patent Document 1 below. In this disclosed technique, a γ-ray density meter is used as the density meter. In the cross-correlation method, the average density of the gas-liquid two-phase flow is measured by using a γ-ray density meter, and the void ratio is obtained from the measured average density. And each flow volume is calculated | required from the volume flow rate of the multiphase fluid measured with the void rate and the ultrasonic flowmeter. In this case, it is possible to measure the flow rate of oil and water by adding an element for measuring the moisture content. However, the element for measuring the moisture content is expensive like the γ-ray density meter. In many cases, it is assumed that calibration is performed in the field, which causes a problem of increasing the cost.
JP 2001-165741 A

  It is known that the γ-ray density meter is expensive. Further, the γ-ray density meter and the moisture meter are often premised on calibration in the field, and there is a problem that the cost is further increased.

  The inventor of the present application considers the use of a Coriolis mass flow meter as a density meter in place of the γ-ray density meter in order to solve the above-described high cost problem. However, the present inventor believes that the Coriolis mass flowmeter cannot be simply applied as a substitute for the γ-ray density meter in the case of multiphase flow. In general, density measurement of a multiphase fluid with a Coriolis mass flowmeter at present is difficult unless the proportion of gas is low and the gas phase is uniformly distributed. That is, in order to accurately measure the density of the mixed phase liquid, the present inventor considers that an apparatus for extracting at least the amount of the mixed liquid necessary for the density measurement from the multiphase flow flowing through the pipeline is necessary.

  This invention is made | formed in view of the situation mentioned above, and makes it a subject to provide the liquid mixture extraction apparatus which makes it possible to extract a liquid mixture favorably from a multiphase flow. It is another object of the present invention to provide a mixed liquid density measuring device including the mixed liquid extraction device.

  The mixed liquid extraction apparatus according to claim 1, which has been made to solve the above problems, includes a differential pressure generator provided in a pipeline for flowing a three-phase flow composed of a gas and two kinds of liquids, and the differential pressure. A pair of communication pipes connected upstream and downstream of the generator, and a place to take in a part of the three-phase flow connected to the pair of communication pipes and using a pressure change before and after the differential pressure generator A gas-liquid extraction tank that is a place where a part of the three-phase flow is forcibly stirred, a gas-liquid discharge pipe that is connected to the gas-liquid extraction tank and discharges a gas containing a liquid phase, and the gas-liquid extraction tank A liquid reservoir tank that is connected to take in and collects at least a mixed liquid for density measurement required for density measurement, and a liquid flow rate adjustment valve provided at least on the downstream side of the liquid reservoir tank are provided.

  According to the present invention having such characteristics, a part of the three-phase flow taken into the gas-liquid extraction tank is forcibly agitated by a pressure change before and after the orifice (differential pressure generating device). . That is, a part of the taken-in three-phase flow is forcibly shaken left and right and up and down and stirred. At this time, the bubbles contained in the mixed liquid grow into large bubbles by the collision of the bubbles, and are separated from the mixed liquid to the gas phase side. Even small bubbles are easily separated from the mixed liquid to the gas phase side by the forced stirring action.

  According to the present invention, the mixed liquid from which bubbles have been separated accumulates in the liquid reservoir tank by adjusting the liquid flow rate control valve. The mixed liquid collected in the liquid reservoir tank is used for density measurement. Since density measurement is performed on the mixed liquid from which bubbles have been separated, a highly accurate measurement value is provided.

  According to the present invention, the liquid reservoir tank only needs to be able to take in and store the liquid mixture required by at least the density measuring device connected to the liquid mixture extraction apparatus of the present invention. There is no need for gas-liquid separation of all of the three-phase flow. In the gas-liquid extraction tank, it is sufficient that gas can be removed to the extent that the mixed liquid required by the density measuring device can flow to the reservoir tank (the actual output flow in the well is 2000 barrels even if it is small). When converted to 220 L / min ("L" means liters) When a Coriolis mass flow meter with a diameter of 25 mm is used as the density measuring device, a mixed liquid of 1 L / min at most is sufficient. Therefore, it is sufficient to capture 1/220 of the three-phase flow).

  According to the present invention, in order to measure the density of the liquid phase, a part of the three-phase flow is taken into the gas-liquid extraction tank instead of the total amount of the three-phase flow. Since the intake is not the total amount of the three-phase flow, the size of the mixed liquid extraction device can be reduced. ADVANTAGE OF THE INVENTION According to this invention, it becomes possible to reduce in size the apparatus containing the mixed liquid extraction apparatus and mixed liquid density measuring apparatus of this invention, for example, the whole multiphase flowmeter.

  The mixed liquid extraction device according to a second aspect of the present invention is the mixed liquid extraction device according to the first aspect, wherein the mixing is performed by restricting the entry of bubbles between the gas-liquid extraction tank and the liquid reservoir tank. A part having a function as a filter for taking in only the liquid into the liquid storage tank is provided.

  According to the present invention having such a feature, mixing of bubbles into the liquid reservoir tank is prevented by the filter function.

  A mixed liquid extraction apparatus according to a third aspect of the present invention is the mixed liquid extraction apparatus according to the second aspect, wherein a part having a function as the filter is bundled such that a plurality of thin tubes are circumscribed. A structure in which thin tubes are bundled, or a plate having a plurality of small holes, and the inside of a mixed liquid extraction pipe provided between the gas-liquid extraction tank and the liquid reservoir tank, or the gas-liquid It is characterized in that it is provided inside a mixed liquid extraction pipe that is connected to an extraction tank.

  According to the present invention having such a feature, a small hole wall surface of a structure in which tubules are bundled or a plate having a plurality of small holes is attached to the wall surface by capillary action and caused to drop by gravity, and at the same time, bubbles enter. And only the mixed liquid is fed into the reservoir tank. In the present invention, it is preferable that a structure in which thin tubes are bundled or a plate having a plurality of small holes has a wall surface with good wettability.

  A mixed liquid extraction apparatus according to a fourth aspect of the present invention is the mixed liquid extraction apparatus according to the first aspect, wherein the gas-liquid extraction tank and the liquid reservoir tank are connected by a pair of second communication pipes. It is said.

  According to the present invention having such characteristics, gas-liquid extraction tanks and gas-liquid extraction tanks that generate gas-liquid extractions and gas-related extractions that occur in a pair of communication pipes and gas-liquid extraction tanks connected to a pipeline are as follows. The same is done on the downstream side. According to the present invention, it is possible to send the mixed liquid that has achieved the separation of small bubbles to the density measuring device.

  A mixed liquid extraction apparatus according to a fifth aspect of the present invention is the mixed liquid extraction apparatus according to the fourth aspect, wherein the configuration of the pair of second communication pipes and the liquid reservoir tank is arranged downstream of the gas-liquid extraction tank. It is characterized by multistage.

  According to the present invention having such characteristics, gas-liquid extraction and gas-based discharge with a liquid are performed in multiple stages. As a result, separation of small bubbles or the like confined in particularly high-viscosity oil is more reliably performed.

  A mixed liquid extraction apparatus according to a sixth aspect of the present invention is the mixed liquid extraction apparatus according to any of the first to fifth aspects, wherein the mixed liquid extraction apparatus is configured to be detachable from the pipeline.

  According to the present invention having such a feature, it can be used for flow rate measurement for, for example, management of an oil well and a sampling process or shipment management by moving it to a necessary location.

  The mixed liquid density measuring device of the present invention according to claim 7, which has been made to solve the above-mentioned problems, is a mixed liquid extraction device according to any one of claims 1 to 6, and a density connected to the mixed liquid extraction device. A density measuring device main body for measuring density using a mixed liquid for density measurement from the mixed liquid extracting device, and a pipe for flowing the density measuring device main body and a three-phase flow. And a gas-liquid return pipe connected to the line.

  According to the present invention having such a feature, since it is a mixed liquid density measuring device configured to include a mixed liquid extraction device, it is possible to accurately measure the density.

  According to the mixed liquid extraction apparatus of the present invention, the mixed liquid can be favorably extracted from the multiphase flow. Moreover, according to the mixed liquid density measuring apparatus of this invention, there exists an effect that a density measurement can be performed with sufficient precision.

  Hereinafter, description will be given with reference to the drawings. FIG. 1 is a configuration diagram of a multi-phase flow meter showing an embodiment of the present invention. 2 is a configuration diagram of a mixed liquid density measuring unit (mixed liquid density measuring device), FIG. 3 is an explanatory diagram of a flow pattern in a horizontal pipe of a gas-liquid two-phase flow, and FIG. 4 is a diagram in a gas-liquid extraction tank. FIG. 5 is a configuration diagram showing another example of the gas-liquid two-phase flow rate measuring unit, FIG. 6 is a graph showing the measurement result of the oil / water density in the oil / water by the Coriolis meter, and FIG. 7 is the Coriolis meter. It is a graph which shows the measurement result of the moisture content (water / oil) in oil water.

  In FIG. 1, reference numeral 1 indicates a multiphase flow meter. The multiphase flow meter 1 includes a mixed liquid density measuring unit 2 corresponding to the mixed liquid density measuring device of the present invention, a gas-liquid two-phase flow rate measuring unit 3, and each phase flow rate calculating unit 4. . The mixed liquid density measuring unit 2 in the multiphase flow meter 1 having such a configuration includes a mixed liquid extracting unit 5 corresponding to the mixed liquid extracting device of the present invention and a density measuring unit 6 corresponding to the density measuring device. It is configured.

  The gas-liquid two-phase flow rate measuring unit 3 has a configuration capable of measuring each phase flow rate of a gas-liquid two-phase flow in a three-phase flow (for example, gas, oil, water) composed of a gas and two types of liquids. is doing. The gas-liquid two-phase flow rate measuring unit 3 is not particularly limited, but in this embodiment, a turbine-type gas-liquid two-phase flow meter is used (for example, a turbine disclosed in JP-A-8-201130). Type flowmeters are preferred). The gas-liquid two-phase flow rate measuring unit 3 includes a homogenizer 7, a turbine meter 8, a differential pressure gauge 9, a pressure gauge 10, and a thermometer 11.

  The measurement value obtained by the gas-liquid two-phase flow rate measurement unit 3 is taken into each phase flow rate calculation unit 4, and the measurement value obtained by the mixed liquid density measurement unit 2 is also taken into each phase flow rate calculation unit 4, Each phase flow rate calculation unit 4 calculates each phase flow rate of gas, oil, and water.

  In this embodiment, the multiphase flow meter 1 has a configuration in which, for example, a known turbine type gas-liquid two-phase flow meter is combined with a mixed liquid density measuring unit 2. It becomes possible to provide a multiphase flow meter capable of measuring a flow rate with high accuracy. The mixed liquid density measuring unit 2 is configured to take in a part of the three-phase flow instead of the total amount of the three-phase flow in order to measure the density of the liquid phase (mixed liquid), which will be described later. Therefore, it becomes possible to provide a multiphase flow meter that can be made compact.

  Hereinafter, with reference to FIG. 1 thru | or FIG. 7, about each structure and effect | action of the multiphase flowmeter 1 containing the mixed liquid extraction apparatus (mixed liquid extraction part 5) and mixed liquid density measurement apparatus (density measurement part 6) of this invention. explain.

  As described above, the mixed liquid density measuring unit 2 includes the mixed liquid extracting unit 5 and the density measuring unit 6. The mixed liquid extraction unit 5 includes an orifice 12, a communication pipe 13, a gas / liquid extraction tank 14, a gas / liquid discharge pipe 15, a gas discharge pipe 16, a liquid reservoir tank 17, and liquid flow rate control valves 18 and 19. have. The density measuring unit 6 includes a mixed liquid introduction tube 20, a density measuring unit main body 21 corresponding to the density measuring device main body, and a gas-liquid return pipe 22. The mixed liquid density measuring unit 2 is configured by connecting the mixed liquid extracting unit 5 and the density measuring unit 6 and has a structure that can be attached to and detached from the pipeline (main pipe) 23 ( The pipeline (main pipe) 23 has a structure that can be separated into, for example, a mixed liquid density measuring unit 2 and a gas-liquid two-phase flow rate measuring unit 3). In the mixed liquid density measuring unit 2, the measurement value obtained by the density measuring unit 6 is taken into each phase flow rate calculating unit 4.

  The orifice 12 is a differential pressure generating device and is attached to a pipeline (main pipe) 23. A three-phase flow flows through the pipeline (main pipe) 23. The three-phase flow is composed of a gas (gas) and two kinds of liquids (for example, oil and water). The gas-liquid two-phase flow in the three-phase flow is not particularly limited, but in this embodiment, a slag flow, a bubble flow, or a spiral flow is assumed.

  Here, the flow pattern in the horizontal pipe of the gas-liquid two-phase flow will be briefly described. It is known that the gas-liquid two-phase flow takes various flow modes depending on the combination of the flow rates of the gas and liquid. These flow patterns are shown in FIG. 3 (a) is a stratified flow, (b) is a wave flow, (c) is an annular flow, (d) is a bubble flow or spiral flow, (e) is a slag flow, and (f) is different from (c). An annular flow, (g) is a bubbling flow, (h) is an annular spray flow, and the flow state of the pipeline is generally said to be (d) or (c) in many cases.

  As shown in FIG. 3E, the slag flow has a liquid phase containing bubbles and a phase in which gas and liquid are separated into upper and lower layers, and these two phases appear alternately. It has become. The differential pressure ΔP generated when such a slag flow passes through the orifice 12 is large in the former phase and small in the latter phase. Although not specifically shown here, as a result of measuring the variation in the magnitude of the differential pressure ΔP, it has been found that there is 3.5 times as much opening in the former phase and the latter phase. That is, the differential pressure ΔP before and after the orifice 12 greatly changes periodically due to the slag flow. In addition, the pressure difference ΔP before and after the orifice 12 may change greatly in a short time (about 3 seconds, but not limited to this time).

  The communication pipe 13 is a pipe that is connected to the pipeline (main pipe) 23 and allows a part of the three-phase flow to flow, one end of which is connected to the upstream side of the orifice 12, a gas-liquid extraction pipe or a gas-liquid discharge pipe 13a, The gas-liquid extraction pipe or the gas-liquid discharge pipe 13b connected to the downstream side of the orifice 12 is constituted (it is possible only on the upstream side. It is preferred that the two are constituted). The communication pipe 13 is a gas-liquid extraction pipe or gas-liquid discharge pipes 13a and 13b and is paired. In the drawing, the communication pipe 13 is parallel to a predetermined length, and a pipeline (main pipe). It is arranged and formed so as to extend downward from 23. If a valve 24 is provided in the middle of each pair of communication pipes 13 (gas-liquid extraction pipes or gas-liquid discharge pipes 13a and 13b) and the opening and closing of the valve 24 is automatically controlled, an arbitrary time can be obtained. It becomes possible to measure with a belt. In this embodiment, it is assumed that the valve 24 is fully open and measurement continues while a three-phase flow is flowing through the pipeline (main pipe) 23.

  The gas-liquid extraction tank 14 is a container having an internal space having a desired volume (for example, about 1 L: hereinafter, “L” is used to mean liters), and a pair of communication pipes 13 (gas-liquid extraction pipes or gas The other ends of the liquid discharge pipes 13a and 13b) are connected. In FIGS. 2 and 4 (FIG. 4 is schematically shown), when a part of the three-phase flow is taken into the gas-liquid extraction tank 14 and accumulated to some extent, the gas-liquid extraction tank 14 The following actions will occur inside. That is, since the differential pressure ΔP before and after the orifice 12 changes greatly in a short time, a part of the three-phase flow taken in from the upstream gas-liquid extraction pipe or gas-liquid discharge pipe 13a (may be simply abbreviated as gas-liquid). The flow rate of extraction (if any) varies. In particular, large bubbles in the gas-liquid are ejected into the gas-liquid extraction tank 14 like an empty gun launched from a gun, and a large stirring flow is generated in the entire gas-liquid extraction tank 14. The stirring flow 25 generated in the gas-liquid extraction tank 14 combines small bubbles to grow into large bubbles, promotes gas separation, and collects bubbles in the upper part of the gas-liquid extraction tank 14. In the state accompanied by the liquid, the gas-liquid extraction pipe or the gas-liquid discharge pipe 13b on the downstream side is pushed into the pipeline (main pipe) 23 to cause the action of discharging.

  The gas-liquid extraction pipe or gas-liquid discharge pipe 13b on the downstream side mainly discharges the gas accompanied by the liquid, but when the pressure on the downstream side of the orifice 12 is high due to the variation of the differential pressure ΔP before and after the orifice 12. When the pressure in the gas-liquid extraction tank 14 decreases, the gas-liquid is sent from the gas-liquid extraction pipe or gas-liquid discharge pipe 13b on the downstream side into the gas-liquid extraction tank 14 and is locally applied to the entire stirring flow 25. A small stirring stream 26 is formed. The small stirring stream 26 contributes to the separation of the gas, as does the overall stirring stream 25. When a small stirring flow 26 is generated, a reverse flow is generated in the gas-liquid extraction pipe or gas-liquid discharge pipe 13b on the downstream side, so that the gas-liquid is discharged from the gas-liquid extraction pipe or gas-liquid discharge pipe 13b on the downstream side. Although no discharge is performed, a small stirring flow 26 is generated in the vicinity of the connection of the gas-liquid extraction pipe or the gas-liquid discharge pipe 13b on the downstream side, so that the separated gas is easily discharged after this. The above description is an effect obtained by configuring the communication pipe 13 (gas-liquid extraction pipes or gas-liquid discharge pipes 13a and 13b) in pairs.

  Explaining the discharge of the gas present in the upper part of the gas-liquid extraction tank 14, the bubbles separated by the large stirring flow 25 and the like gather in the upper part of the gas-liquid extraction tank 14 and pass through the valve 27 and the gas-liquid discharge pipe 15. And discharged with liquid. The discharge destination in this embodiment is a cross valve 41 (described later) provided in the gas-liquid return pipe 22 of the density measuring unit 6.

  A mixed liquid extraction pipe 28 is provided in the lower part of the gas-liquid extraction tank 14 (arrangement is an example). The mixed liquid extraction pipe 28 has a diameter of about 40 mm and stands upright at the lower part of the gas-liquid extraction tank 14 and is formed to have a length of about 100 mm, for example. The mixed liquid extraction pipe 28 is provided with a structure 29 in which thin tubes are bundled, which is about 2/3 in the length direction. The structures 29 in which the thin tubes are bundled are bundled so that the thin tubes are circumscribed, for example, with the inner diameter of the thin tubes being about 2 mm. The tubules are long in the direction of gravity and are bundled with such tubules. The structure 29 in which the thin tubes are bundled is combined in a cylindrical shape (columnar shape) and is inserted and installed in the mixed solution extraction tube 28 (the diameter of the mixed solution extraction tube 28 is set to 40 mm). In this case, the number of thin tubes is about 90). The structure 29 in which the thin tubes are bundled is provided for the purpose of preventing the bubbles in the gas-liquid extraction tank 14 from flowing into the liquid reservoir tank 17 (the installation is not necessary if the bubbles do not flow into the liquid reservoir tank 17). In this embodiment, it is installed as a safety measure.An example of the case where the installation is unnecessary is a case where the gas void ratio is low). The portion of the mixed liquid extraction pipe 28 has a function as a filter. In addition, said thin tube shall be replaceable with what made the small hole in the plate.

  The liquid flow rate adjustment valve 18 is provided in the middle of a connecting pipe 30 that connects the gas-liquid extraction tank 14 and the liquid storage tank 17. The liquid flow rate adjustment valve 18 is adjusted in opening degree so that, for example, the flow rate of the mixed liquid is about 2 to 6 L / min. The liquid flow rate control valve 18 is provided to supply an appropriate amount of the mixed liquid to the liquid storage tank 17.

  The mixed liquid from which gas has been removed on the gas-liquid extraction tank 14 side flows into the liquid reservoir tank 17. The liquid reservoir tank 17 is formed as a container in which the mixed liquid temporarily accumulates (the volume is, for example, 0.5 L). The liquid reservoir tank 17 has a structure in which the mixed liquid stays for about 1 minute, for example. The liquid reservoir tank 17 assumes the case where the internal gas cannot escape or the case where the mixed liquid contains extremely fine bubbles, and the gas and bubbles are to be described later via the valve 31 and the gas discharge pipe 16. It can be discharged to the cross valve 41. In this embodiment, the liquid storage tank 17 has a structure that can take in and store at least a mixed liquid for density measurement required by the density measuring unit 6.

  The liquid flow rate adjusting valve 19 is provided in the middle of a connecting pipe 32 that connects the liquid reservoir tank 17 and the mixed liquid introducing pipe 20 of the density measuring unit 6. The opening degree of the liquid flow rate adjusting valve 19 is adjusted so that the flow rate of the mixed liquid becomes an appropriate amount. As a specific example, the opening degree is adjusted so that the time for passing through a later-described Coriolis meter 38 in the density measuring unit main body 21 of the density measuring unit 6 is, for example, about 10 to 30 seconds (with a diameter of 25 mm). When using the Coriolis meter 38, about 0.5 to 1.5 L / min). At the position of the liquid flow rate control valve 19, only the mixed liquid (for example, oil / water) flows to the density measuring unit 6.

  A valve 33 and a discharge valve 34 are provided in the mixed liquid introduction tube 20 of the density measuring unit 6 to which the connection thin tube 32 is connected. Further, a valve 36 is also provided in a sub-bypass pipe 35 having one end connected to the mixed liquid introduction pipe 20 to bypass the density measuring unit main body 21 and the other end connected to the gas-liquid return pipe 22. In this embodiment, the valve 33 is fully open, and the discharge valve 34 and the valve 36 are fully closed. The valve 33 is provided on the density measuring unit main body 21 side.

  In this embodiment, the density measuring unit main body 21 includes a homogenizer 37, a Coriolis meter 38, and a mixed liquid return pipe 39. The homogenizer 37 is provided to homogenize the mixed liquid and make the mixed liquid density uniform. The homogenizer 37 is provided upstream of the Coriolis meter 38. The homogenizer 37 is provided in the vicinity of the Coriolis meter 38 to make the measurement of the mixing density by the Coriolis meter 38 more reliable. The Coriolis meter 38 only needs to have a configuration capable of performing density measurement in a known Coriolis mass flow meter (or may be one that can perform density measurement on the same principle as this). In this embodiment, a known Coriolis mass flow meter is used as the Coriolis meter 38. Since the Coriolis meter 38 does not depend on the flow rate of the mixed liquid (the measurement is performed by vibrating the mixed liquid filled in the built-in tube), the Coriolis meter 38 can measure with a small flow rate.

  The gas-liquid return pipe 22 is provided with a valve 40, a cross valve 41, and a check valve 42 in order from the Coriolis meter 38 side. The valve 40 is fully open. As the cross valve 41 and the check valve 42, known ones are used, and description of the operation and the like is omitted. The gas-liquid return pipe 22 is connected to a pipeline (main pipe) 23 on the downstream side of the orifice 12 of the mixed liquid extraction section 5 (reference numeral 43 indicates a merging section).

  As described above, the gas-liquid two-phase flow rate measuring unit 3 includes the homogenizer 7, the turbine meter 8, the differential pressure gauge 9, the pressure gauge 10, and the thermometer 11. Since the gas-liquid two-phase flow rate measuring unit 3 having the above configuration is the same as a known turbine type flow meter (for example, Japanese Patent Laid-Open No. Hei 8-201130), a detailed description of the configuration is omitted here. (The measurement method will be described later). Note that the gas-liquid two-phase flow rate measuring unit 3 may include a volume flow meter 44, a venturi tube 45, a differential pressure gauge 46, and the like shown in FIG. The reason why the turbine-type flow meter is used in this embodiment (not limited to the turbine-type flow meter in the above publication) is that the turbine-type flow meter maintains the gas-liquid two-phase flow in a mixed phase flow, and the total volume flow rate. This is because the gas-liquid volume flow ratio can be determined efficiently at the same time. In addition, turbine type flow meters are superior in cost and handling (other strengths such as using general industrial instruments and adapting only to flange standards for high pressure specifications such as oil fields). is there).

  As described above, each phase flow rate calculation unit 4 takes in the measurement value obtained by the gas-liquid two-phase flow rate measurement unit 3 and the measurement value obtained by the mixed liquid density measurement unit 2 to obtain a three-phase flow (for example, gas (Oil / water) each phase flow rate can be calculated. Each phase flow rate calculation unit 4 can be configured, for example, as a part of a control device (not shown) or as a combination of the calculation parts of the gas-liquid two-phase flow rate measurement unit 3 and the Coriolis meter 38. The flow rate of each phase is calculated by such a function. Each phase flow rate calculation unit 4 calculates a mixing ratio of the mixed liquid from the mixed liquid density, and calculates each flow rate of the mixed liquid from the mixing ratio and the mixed liquid flow rate.

  Next, a method for measuring gas-liquid in a gas-liquid two-phase flow with a turbine type flow meter will be described (assumed to be a summary). The gas-liquid in the mixed phase is homogenized like a single fluid by the homogenizer 7 installed on the upstream side and flows into the turbine rotor of the turbine meter 8. Since the density of the mixed fluid is homogenized by the homogenizer 7, the momentum of the mixed fluid acting on the turbine rotor is constant in the rotor radial direction. The turbine rotor rotates efficiently. The differential pressure ΔP generated before and after the homogenizer 7 is experimentally expressed as ΔP∝f (QM) * f (β) depending on the gas-liquid flow rate QM and the ratio of the gas flow rate QG to the QM (gas void ratio β). It is functionalized. Since the rotational speed N of the turbine rotor is expressed as N∝f (QM), QM and β are obtained from these two expressions by measuring ΔP and N. The liquid flow rate QL in the mixed fluid is calculated as QL = QM * (1−β), and the gas flow rate QG in the mixed fluid is calculated as QG = QM * β.

  An explanation related to density measurement by the Coriolis meter 38 will be given. Here, the mixed liquid is considered as an oil-water mixed liquid. Also, it is assumed that the density of each single phase of oil and water is known.

The water content α is calculated by the following equation: water content α = (mixing density of oil / water−density of oil) / (density of water−density of oil). Hereinafter, the expression of the moisture content α will be specifically described. QW is the flow rate of water, QO is the flow rate of oil, QL is the combined flow rate of water and oil, ρW is the density of water, ρO is the density of oil, and ρL is the combined density of water and oil. Since the mass flow rate of each of the water and the mass flow rate of oil water obtained by adding them are equal, the following equation (1) is obtained.
QW * ρW + QO * ρO = QL * ρL (1)
This equation (1) can be modified as follows. That is,
Since QO = QL * QW, QW * (ρW−ρO) = QL * (ρL−ρO) is obtained. Since the moisture content α = QW / QL, the moisture content α = (ρL−ρO) / (ρW−ρO).

  The oil flow rate QO and the water flow rate QW are obtained by multiplying the liquid flow rate QL in the mixed fluid described in the gas-liquid two-phase flow gas-liquid measurement method by the turbine type flow meter by the moisture content α, and QO = QL * ( 1−α), QW = QL * α.

  As described above with reference to FIGS. 1 to 5, the multiphase flow meter 1 is subjected to high-precision density measurement by the mixed liquid density measuring unit 2 corresponding to the mixed liquid density measuring device of the present invention. Therefore, the oil flow rate QO and the water flow rate QW are finally calculated with high accuracy.

  A supplementary explanation of the mixed liquid density measuring unit 2 in the multiphase flow meter 1 will be described in order to extract a part of the three-phase flow from the pipeline (main pipe) 23, in other words, to extract gas and liquid. ) A pair of communication pipes 13 (gas-liquid extraction pipes or gas-liquid discharge pipes 13a and 13b) connected in a bypass manner upstream and downstream of the orifice 12 installed at 23, and a gas-liquid extraction tank 14 are used. When a slag flow or the like flows through the pipeline (main pipe) 23, the pressure difference before and after the orifice 12 changes periodically. Accordingly, in the pair of communication pipes 13 (gas-liquid extraction pipes or gas-liquid discharge pipes 13a and 13b) and the gas-liquid extraction tank 14, gas-liquid extraction and gas-based discharge (pipeline (main pipe) 23) are performed. Are discharged at the same time. In the gas-liquid extraction tank 14, the gas-liquid is forcibly shaken and stirred left and right and up and down, and the gas with the liquid is discharged. As a result, a gas-liquid with a high liquid phase ratio remains in the gas-liquid extraction tank 14. Then, the gas is removed from the gas-liquid with a high liquid phase ratio, and the mixed liquid is extracted and accumulated in the liquid reservoir tank 17. A necessary amount of mixed liquid flows from the liquid reservoir tank 17 by the Coriolis meter 38, and the density of the mixed liquid is homogenized by the homogenizer 37. As a result, the Coriolis meter 38 performs highly accurate density measurement.

  Next, test results will be described with reference to FIGS. As a test specification, the diameter of the pipeline (main pipe) 23 including the turbine meter 8 was set to 50 mm. Further, the flow rate QL of the oil water was 4 to 15 m 3 / h, the gas void ratio β was 0 to 85%, and the water content α was 5 to 30% (the above “m 3” is used in the meaning of cubic meters). FIG. 6 is a graph showing the measurement result of the oil / water density in the oil / water atmosphere by the Coriolis meter 38, and ± 3 Kg / m 3 in the graph corresponds to a density measurement accuracy of slightly more than ± 0.3%. Usually, in the conventional multiphase flow rate system, the accuracy of density measurement is required to be higher than ± 0.5%, so that a good result is obtained in the present invention. FIG. 7 is a graph showing the measurement result of the moisture content (water / oil) in the oil and water with the Coriolis meter 38, and the measurement accuracy of the moisture content α is as good as ± 2.5%. .

  It is known that when measuring the density to calculate the moisture content α, the density measurement error increases. When the density ρL of the mixed liquid, the density ρO of the oil, the density ρW of the water, the error of the measurement density is γρL, and the error of the moisture content is γα, α = (ρL−ρO) / (ρW−ρO). Γα = 1 / (ρW−ρO) * γρL. That is, γα is enlarged by 1 / (ρW−ρO) times γρL. For example, assuming that the density of water ρW = 1 g / cm3 and the density of oil ρO = 0.85 g / cm3, γα = 1 / (ρW−ρO) * γρL = 1 / (1−0.85) * γρL≈7 * Since it becomes γρL, it becomes 7 times. Therefore, in this case, even if the density measurement is 0.5%, the moisture content calculation is 3.5%. In the present invention, the density measurement accuracy is a little more than ± 0.3%, which is a result of ± 2.5%, which is close to 7 times, and is theoretically consistent.

  As described above with reference to FIGS. 1 to 7, according to the mixed liquid extraction apparatus (mixed liquid extraction unit 5) of the present invention, the mixed liquid can be satisfactorily extracted from the multiphase flow. There is an effect. Further, according to the mixed liquid density measuring device (mixed liquid density measuring unit 2) of the present invention, since the mixed liquid extracting device (mixed liquid extracting unit 5) is included, there is an effect that the density measurement can be performed with high accuracy. . Therefore, the multiphase flow meter 1 including the mixed liquid extraction device (mixed liquid extraction unit 5) and the mixed liquid density measurement device (mixed liquid density measurement unit 2) of the present invention can measure the flow rate with high accuracy. Play.

  Next, another embodiment of the present invention will be described with reference to FIGS. FIG. 8 is a block diagram of a multiphase flow meter showing an embodiment of the present invention, FIG. 9 is a block diagram of a mixed liquid density measuring unit (mixed liquid density measuring device), and FIG. 10 is a state in a gas-liquid extraction tank. It is explanatory drawing which shows. In addition, the same code | symbol shall be attached | subjected to the same structure as the above-mentioned form, and description shall be abbreviate | omitted.

  In FIG. 8, a multiphase flow meter 1 'according to another embodiment of the present invention includes a mixed liquid density measuring unit 2' corresponding to the mixed liquid density measuring device of the present invention, and a gas-liquid two-phase flow measuring unit 3. And each phase flow rate calculation unit 4. The mixed liquid density measuring unit 2 'includes a mixed liquid extracting unit 5' corresponding to the mixed liquid extracting device of the present invention and a density measuring unit 6 corresponding to the density measuring device. The mixed liquid extraction unit 5 ′ includes an orifice 12, a pair of communication pipes 13 (gas-liquid extraction pipes or gas-liquid discharge pipes 13 a and 13 b), a gas-liquid extraction tank 14, a gas-liquid discharge pipe 15, and a gas discharge pipe. 16, a liquid reservoir tank 17, a liquid flow rate adjustment valve 19, and a pair of second communication pipes 51.

  The mixed liquid extraction unit 5 ′ differs from the mixed liquid extraction unit 5 of the above-described form only in the connection method of the gas-liquid extraction tank 14 and the liquid reservoir tank 17. That is, the gas / liquid extraction tank 14 and the liquid reservoir tank 17 are connected by a pair of second communication pipes 51 in place of the mixed liquid extraction pipe 28, the connection pipe 30, and the liquid flow rate control valve 18 existing in FIGS. 2 and 3. It is. In the mixed liquid extraction section 5 ′, gas-liquid extraction and gas-related discharge generated mainly in the pair of communication pipes 13 (gas-liquid extraction pipes or gas-liquid discharge pipes 13 a and 13 b) and the gas-liquid extraction tank 14 are discharged. The purpose is to perform in multiple stages. The mixed liquid extraction section 5 ′ is provided with a plurality of stages of a pair of communication pipes and tanks (the pair of the second communication pipe 51 and the liquid reservoir tank 17 in the figure is the second stage. The mixture liquid that has achieved separation of small bubbles can be sent to the density measuring unit 6 (because the basic actions and effects are the same as those described above). (Description is omitted).

  In addition, it goes without saying that the present invention can be variously modified without departing from the spirit of the present invention.

  For example, the mixed density measuring unit 2 (mixed density measuring unit 2 ′) may be arranged on the downstream side of the gas-liquid two-phase flow rate measuring unit 3.

It is a block diagram of the multiphase flowmeter which shows one embodiment of this invention. It is a block diagram of a mixed liquid density measurement part (mixed liquid density measuring device). It is explanatory drawing about the flow pattern in the horizontal pipe | tube of a gas-liquid two-phase flow. It is explanatory drawing which shows the state in a gas-liquid extraction tank. It is a block diagram which shows the other example of a gas-liquid two-phase flow volume measurement part. It is a graph which shows the measurement result of the oil-water density in the oil-water atmosphere by a Coriolis meter. It is a graph which shows the measurement result of the moisture content (water / oil) in the oily water by a Coriolis meter. It is a block diagram of the multiphase flowmeter which shows other one Embodiment of this invention. It is a block diagram of a mixed liquid density measurement part (mixed liquid density measuring device). It is explanatory drawing which shows the state in a gas-liquid extraction tank.

Explanation of symbols

1 Multiphase flow meter 2 Mixed liquid density measuring unit (mixed liquid density measuring device)
3 Gas-liquid two-phase flow rate measurement unit 4 Phase flow rate calculation unit 5 Mixed liquid extraction unit (mixed liquid extraction device)
6 Density measurement unit (density measurement device)
DESCRIPTION OF SYMBOLS 7 Homogenizer 8 Turbine meter 9 Differential pressure gauge 10 Pressure gauge 11 Thermometer 12 Orifice 13 Communication pipe 13a, 13b Gas-liquid extraction pipe or gas-liquid discharge pipe 14 Gas-liquid extraction tank 15 Gas-liquid discharge pipe 16 Gas discharge pipe 17 Liquid reservoir tank 18 , 19 Liquid flow rate control valve 20 Mixed liquid introduction pipe 21 Density measuring unit main body (density measuring device main body)
22 Gas-liquid return pipe 23 Pipeline (main pipe)
24, 27, 31, 33, 36 Valve 25 Stir flow 26 Small stir flow 28 Mixture extraction pipe 29 Structure bundled with narrow tubes 30, 32 Connection pipe 34 Discharge valve 35 Sub-bypass pipe 37 Homogenizer 38 Coriolis meter 39 Mixed liquid Return pipe 40 Valve 41 Cross valve 42 Check valve 43 Junction section 44 Volumetric flow meter 45 Venturi pipe 46 Differential pressure gauge 51 Second communication pipe

Claims (7)

A differential pressure generator provided in a pipeline for flowing a three-phase flow of gas and two types of liquid, a pair of communication pipes connected upstream and downstream of the differential pressure generator, and a pair of communication pipes connected to the pair of communication pipes. A gas-liquid extraction tank serving as a place for taking in a part of the three-phase flow and a place for forcibly stirring a part of the three-phase flow using a pressure change before and after the differential pressure generator; A gas-liquid discharge pipe connected to the liquid extraction tank for discharging gas containing a liquid phase, and a liquid reservoir connected to the gas-liquid extraction tank for receiving and storing at least a mixed liquid for density measurement required for density measurement. A mixed liquid extraction apparatus comprising: a tank; and a liquid flow rate adjustment valve provided at least on the downstream side of the liquid storage tank. The mixed liquid extraction device according to claim 1,
A portion having a function as a filter is provided between the gas-liquid extraction tank and the liquid reservoir tank to restrict the entry of bubbles and take only the mixed liquid into the liquid reservoir tank. Mixed liquid extraction device. The mixed liquid extraction apparatus according to claim 2,
The portion having the function as the filter is constituted by a structure in which a plurality of thin tubes are bundled so that the thin tubes are circumscribed, or a structure in which thin tubes are bundled, or a plate having a plurality of small holes, and the gas-liquid A mixed liquid extraction apparatus comprising: a mixed liquid extraction pipe provided between an extraction tank and the liquid reservoir tank; or a mixed liquid extraction pipe provided connected to the gas-liquid extraction tank. The mixed liquid extraction device according to claim 1,
The mixed liquid extraction apparatus, wherein the gas-liquid extraction tank and the liquid reservoir tank are connected by a pair of second communication pipes. The mixed liquid extraction apparatus according to claim 4,
The mixed liquid extraction apparatus, wherein the pair of second communication pipes and the liquid reservoir tank are multistaged on the downstream side of the gas-liquid extraction tank. The mixed liquid extraction apparatus according to any one of claims 1 to 5,
A mixed liquid extraction apparatus configured to be detachable from the pipeline. A liquid mixture extraction device according to any one of claims 1 to 6 and a density measurement device connected to the liquid mixture extraction device, wherein the density measurement device is a mixture for density measurement from the liquid mixture extraction device. A mixed liquid density measuring device comprising: a density measuring device main body for measuring density using a liquid; and a gas-liquid return pipe connected to the density measuring device main body and a pipeline for flowing a three-phase flow.

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