Natural gas wellhead metering calibration device and method

Abstract

The present application relates to oil and gas metering technical field, it is a kind of natural gas wellhead metering calibration device and method, the former includes slug flow trap, high-efficiency separator, first liquid storage weighing tank, second liquid storage weighing tank, plunger pump and flowmeter, the inlet of slug flow trap is equipped with main delivery pipeline;The steps of the latter are as follows: (1) gas well production is transported to slug flow trap by main delivery pipeline, and is buffered by slug flow trap.This application has reasonable and compact structure, ingenious idea, the volume of associated gas separated by high-efficiency separator is accurately metered by flowmeter arranged on gas phase outlet pipeline;The produced liquid in the first liquid storage weighing tank and the second liquid storage weighing tank is weighed and metered in real time by setting the first liquid storage weighing tank and the second liquid storage weighing tank;The volume of produced liquid in the first liquid storage weighing tank and the second liquid storage weighing tank is measured by setting the first liquid level meter and the second liquid level meter, with the characteristics of fast, stable and efficient.

Description

Technical Field

[0001] This invention relates to the field of oil and gas metering technology, and is a natural gas wellhead metering calibration device and method. Background Technology

[0002] Currently, natural gas well production development mostly employs fracturing, and the products are primarily three-phase mixtures of oil, gas, and water. Due to the high initial pressure (nearly 10 MPa) of gas wells in Xinjiang oilfields, and the lack of suitable wellhead metering methods, individual gas wells are generally not metered. In recent years, with the commercialization of multiphase flow metering, multiphase flow meters have begun to be installed at a few wellheads. However, multiphase flow is affected by numerous factors such as temperature and pressure within pipelines, raising questions about its accuracy and making calibration of multiphase fluids impossible. Summary of the Invention

[0003] This invention provides a natural gas wellhead metering and calibration device and method, which overcomes the shortcomings of the prior art and can effectively solve the problem that existing single natural gas wells cannot perform metering and calibration of multiphase fluids.

[0004] One of the technical solutions of this invention is achieved through the following measures: a natural gas wellhead metering and calibration device, comprising a slug flow trap, a high-efficiency separator, a first liquid storage weighing tank, a second liquid storage weighing tank, a plunger pump, and a flow meter. The inlet of the slug flow trap is connected to a main pipeline. The first outlet of the slug flow trap is fixedly connected to the upper front side of the high-efficiency separator, and the second outlet of the slug flow trap is fixedly connected to the lower front side of the high-efficiency separator. A separator liquid phase outlet pipeline is fixedly connected between the lower rear side of the high-efficiency separator and the inlet of a first electric three-way ball valve. A first inlet pipeline is fixedly connected between the first outlet of the first electric three-way ball valve and the upper rear side of the first liquid storage weighing tank, and a second inlet pipeline is fixedly connected between the second outlet of the first electric three-way ball valve and the upper rear side of the second liquid storage weighing tank. The first liquid storage... A first liquid outlet pipeline is fixedly connected between the lower rear side of the liquid weighing tank and the first inlet of the second electric three-way ball valve; a second liquid outlet pipeline is fixedly connected between the lower rear side of the second liquid weighing tank and the second inlet of the second electric three-way ball valve; a weighing tank phase outlet pipeline is fixedly connected between the outlet of the second electric three-way ball valve and the inlet of the plunger pump; a mixing pipeline is provided at the outlet of the plunger pump; a gas phase outlet pipeline is fixedly connected between the upper rear side of the high-efficiency separator and the mixing pipeline; a flow meter is provided on the gas phase outlet pipeline; a first level gauge is provided on the first liquid weighing tank; a second level gauge is provided on the second liquid weighing tank; a first valve is provided on the first inlet pipeline; a second valve is provided on the second inlet pipeline; a third valve is provided on the first outlet pipeline; a fourth valve is provided on the second outlet pipeline; and an electric valve is provided on the liquid phase outlet pipeline of the separator.

[0005] The following are further optimizations and / or improvements to one of the above-mentioned technical solutions:

[0006] The above may also include a first pipeline and a second pipeline. A first pipeline is fixedly connected between the first inlet pipeline between the first valve and the first liquid storage weighing tank and the second inlet pipeline between the second valve and the second liquid storage weighing tank. A fifth valve and a sixth valve are provided on the first pipeline. A second pipeline is fixedly connected between the first pipeline between the fifth valve and the sixth valve and the separator liquid phase outlet pipeline between the electric valve and the first electric three-way ball valve.

[0007] The above may also include a third pipeline and a fourth pipeline. A third pipeline is fixedly connected between the first inlet pipeline between the third valve and the first liquid storage weighing tank and the second inlet pipeline between the fourth valve and the second liquid storage weighing tank. A seventh valve and an eighth valve are provided on the third pipeline. A fourth pipeline is fixedly connected between the third pipeline between the seventh valve and the eighth valve and the weighing tank outlet pipeline between the plunger pump and the second electric three-way ball valve.

[0008] The above may also include a bypass line, with a bypass line fixedly connected to the separator liquid phase outlet line corresponding to the inlet and outlet positions of the electric valve, and a ninth valve installed on the bypass line.

[0009] The above may also include a first venting pipeline, a second venting pipeline and a third venting pipeline. The high-efficiency separator, the first liquid storage weighing tank and the second liquid storage weighing tank are respectively equipped with a first venting pipeline, a second venting pipeline and a third venting pipeline, and a safety valve is provided on the first venting pipeline.

[0010] The above may also include a skid, on which a second liquid storage weighing tank, a first liquid storage weighing tank, a high-efficiency separator and a plunger pump are arranged sequentially from left to right.

[0011] The second technical solution of the present invention is achieved through the following measures: a method for using the above-mentioned natural gas wellhead metering calibration device, comprising the following steps:

[0012] (1) The gas well product is transported from the main pipeline to the slug trap and buffered by the slug trap;

[0013] (2) The buffered gas well product enters a high-efficiency separator for gas-liquid separation;

[0014] (3) The associated gas after separation is discharged from the high-efficiency separator through the gas phase outlet pipeline, and its volume is accurately measured by the flow meter installed on the gas phase outlet pipeline.

[0015] (4) The separated produced liquid enters the first storage weighing tank through the liquid phase outlet pipeline of the separator and the first inlet pipeline in sequence. After the first storage weighing tank is loaded with the corresponding volume of produced liquid, the first valve is closed and the second valve is opened. The mass of the produced liquid is accurately measured by the first storage weighing tank and the volume of produced liquid loaded in the first storage weighing tank is accurately measured by the first level gauge.

[0016] (5) The separated produced liquid enters the second storage weighing tank through the liquid phase outlet pipeline and the second inlet pipeline of the separator in sequence. After the corresponding volume of produced liquid is loaded into the second storage weighing tank, the second valve is closed and the first valve is opened. The mass of the produced liquid is accurately measured by the second storage weighing tank and the volume of produced liquid loaded in the second storage weighing tank is accurately measured by the first liquid level gauge.

[0017] (6) Repeat steps (4) to (5) until the metering demand per unit time is completed;

[0018] (7) Calculate the density of the produced fluid by the total volume and total mass of the produced fluid per unit time, and measure the density of light oil in a single well by a densitometer or a density bottle, and measure the density of produced water in a single well by a densitometer or a density bottle.

[0019] (8) The daily liquid production, daily water production, daily oil production and daily gas production of a single well were calculated.

[0020] This invention features a reasonable and compact structure and ingenious design. By incorporating a slug flow trap, it can replenish and buffer the intermittently mixed produced fluid in the gas well's output under slug flow conditions. A high-efficiency separator is used to separate the associated gas and produced fluid in the gas well's output into two phases. A flow meter installed on the gas phase outlet pipeline accurately measures the volume of associated gas separated by the high-efficiency separator. A first and second liquid storage weighing tank are used to measure the produced fluid in both tanks in real time. A first and second level gauge are used to measure the volume of produced fluid in the first and second liquid storage weighing tanks, respectively. This invention is characterized by its speed, stability, and high efficiency. Attached Figure Description

[0021] Appendix Figure 1 These are schematic diagrams of the main view structure of Examples 1 to 7.

[0022] Appendix Figure 2 The diagram shows the top view of the structure in Examples 1 to 7.

[0023] Appendix Figure 3 These are schematic diagrams of the rear view structure of Examples 1 to 7.

[0024] Appendix Figure 4 For the appendix Figure 1 A schematic diagram of the three-dimensional structure.

[0025] Appendix Figure 5 For the appendix Figure 1 The process flow diagram.

[0026] The codes in the attached diagram are as follows: 1 is a slug trap, 2 is a high-efficiency separator, 3 is the first liquid storage weighing tank, 4 is the second liquid storage weighing tank, 5 is a plunger pump, 6 is a flow meter, 7 is the main delivery pipeline, 8 is the first electric three-way ball valve, 9 is the second electric three-way ball valve, 10 is the liquid phase outlet pipeline of the separator, 11 is the liquid phase outlet pipeline of the weighing tank, 12 is the first liquid inlet pipeline, 13 is the second liquid inlet pipeline, 14 is the first liquid outlet pipeline, 15 is the second liquid outlet pipeline, 16 is the mixed delivery pipeline, 17 is the gas phase outlet pipeline, 18 is the first level gauge, 19 is the second level gauge, 20 is the first pipeline, 21 is the second pipeline, 22 is the third pipeline, 23 is the fourth pipeline, 24 is the bypass pipeline, 25 is the first vent pipeline, 26 is the second vent pipeline, 27 is the third vent pipeline, 28 is a safety valve, 29 is a skid, and 30 is an electric valve. Detailed Implementation

[0027] The present invention is not limited to the following embodiments, and the specific implementation can be determined according to the technical solution of the present invention and the actual situation.

[0028] In this invention, for ease of description, the description of the relative positions of the components is based on the appendix to the specification. Figure 1 The layout is described using a diagrammatic method, such as the positional relationships of front, back, top, bottom, left, and right, which are based on the instructions attached. Figure 1 The orientation of the layout is determined by the direction of the map.

[0029] The present invention will be further described below with reference to embodiments and accompanying drawings:

[0030] Example 1: As shown in the attached document Figures 1 to 5As shown, the natural gas wellhead metering calibration device includes a slug flow trap 1, a high-efficiency separator 2, a first liquid storage weighing tank 3, a second liquid storage weighing tank 4, a plunger pump 5, and a flow meter 6. The inlet of the slug flow trap 1 is connected to a main pipeline 7. The first outlet of the slug flow trap 1 is fixedly connected to the upper front side of the high-efficiency separator 2, and the second outlet of the slug flow trap 1 is fixedly connected to the lower front side of the high-efficiency separator 2. A separator liquid phase outlet pipeline 10 is fixedly connected between the lower rear side of the high-efficiency separator 2 and the inlet of a first electric three-way ball valve 8. A first inlet pipeline 12 is fixedly connected between the first outlet of the first electric three-way ball valve 8 and the upper rear side of the first liquid storage weighing tank 3. A second inlet pipeline 13 is fixedly connected between the second outlet of the first electric three-way ball valve 8 and the upper rear side of the second liquid storage weighing tank 4. The lower rear side of the first liquid storage weighing tank 3 is connected to the second electric three-way ball valve 9. A first liquid outlet pipeline 14 is fixedly connected between the first inlet and the second liquid storage weighing tank 4. A second liquid outlet pipeline 15 is fixedly connected between the lower rear side of the second liquid storage weighing tank 4 and the second inlet of the second electric three-way ball valve 9. A weighing tank phase outlet pipeline 11 is fixedly connected between the outlet of the second electric three-way ball valve 9 and the inlet of the plunger pump 5. A mixing pipeline 16 is provided at the outlet of the plunger pump 5. A gas phase outlet pipeline 17 is fixedly connected between the upper rear side of the high-efficiency separator 2 and the mixing pipeline 16. A flow meter 6 is provided on the gas phase outlet pipeline 17. A first liquid level gauge 18 is provided on the first liquid storage weighing tank 3. A second liquid level gauge 19 is provided on the second liquid storage weighing tank 4. A first valve is provided on the first liquid inlet pipeline 12. A second valve is provided on the second liquid inlet pipeline 13. A third valve is provided on the first liquid outlet pipeline 14. A fourth valve is provided on the second liquid outlet pipeline 15. An electric valve 30 is provided on the separator liquid phase outlet pipeline 10. During operation, by setting up a slug flow trap 1, the intermittently mixed produced fluid in the gas well output can be collected and buffered under slug flow conditions; by setting up a high-efficiency separator 2, the associated gas and produced fluid in the gas well output are separated into gas and liquid phases; by setting up a flow meter 6 on the gas phase outlet pipeline 17, the volume of associated gas separated by the high-efficiency separator 2 is accurately measured; by setting up a first liquid storage weighing tank 3 and a second liquid storage weighing tank 4, the produced fluid in both tanks is weighed and measured in real time; by setting up a first liquid level gauge 18 and a second liquid level gauge 19, the volume of produced fluid in the first liquid storage weighing tank 3 and the second liquid storage weighing tank 4 is measured respectively; by setting up a plunger pump 5, the produced fluid in the first liquid storage weighing tank 3 and the second liquid storage weighing tank 4 is transported in a mixed oil-water manner, and the associated gas in the gas phase outlet pipeline 17 is transported to the site.

[0031] The above-mentioned natural gas wellhead metering and calibration device can be further optimized and / or improved according to actual needs:

[0032] Example 2: As shown in the attached document Figures 1 to 5As shown, it also includes a first pipeline 20 and a second pipeline 21. The first pipeline 20 is fixedly connected between the first inlet pipeline 12 corresponding to the first valve and the first liquid storage weighing tank 3 and the second inlet pipeline 13 corresponding to the second valve and the second liquid storage weighing tank 4. The first pipeline 20 is equipped with a fifth valve and a sixth valve. The second pipeline 21 is fixedly connected between the first pipeline 20 corresponding to the fifth valve and the sixth valve and the separator liquid phase outlet pipeline 10 corresponding to the electric valve 30 and the first electric three-way ball valve 8. During use, this arrangement facilitates manual control of the liquid inlet to the first liquid storage weighing tank 3 and the second liquid storage weighing tank 4.

[0033] Example 3: As shown in the attached document Figures 1 to 5 As shown, it also includes a third pipeline 22 and a fourth pipeline 23. The third pipeline 22 is fixedly connected between the first inlet pipeline 12 between the third valve and the first liquid storage weighing tank 3, and the second inlet pipeline 13 between the fourth valve and the second liquid storage weighing tank 4. The third pipeline 22 is equipped with a seventh valve and an eighth valve. The fourth pipeline 23 is fixedly connected between the third pipeline 22 between the seventh and eighth valves and the weighing tank outlet pipeline 11 between the plunger pump 5 and the second electric three-way ball valve 9. During use, this arrangement facilitates manual control of the liquid discharge from the first liquid storage weighing tank 3 and the second liquid storage weighing tank 4.

[0034] Example 4: As shown in the appendix Figures 1 to 5 As shown, it also includes a bypass line 24, which is fixedly connected to the separator liquid phase outlet line 10 at the inlet and outlet positions of the electric valve 30. The bypass line 24 is equipped with a ninth valve. During use, this setting facilitates manual control of the separator liquid phase outlet line 10.

[0035] Example 5: As shown in the attached document Figures 1 to 5 As shown, it also includes a first vent line 25, a second vent line 26, and a third vent line 27. The high-efficiency separator 2, the first liquid storage weighing tank 3, and the second liquid storage weighing tank 4 are respectively equipped with the first vent line 25, the second vent line 26, and the third vent line 27. A safety valve 28 is installed on the first vent line 25. This arrangement facilitates venting during use.

[0036] Example 6: As attached Figures 1 to 5 As shown, it also includes a skid 29, on which, from left to right, are arranged a second liquid storage weighing tank 4, a first liquid storage weighing tank 3, a high-efficiency separator 2, and a plunger pump 5. During use, this arrangement ensures a rational layout within the skid, utilizing space efficiently to significantly reduce the floor space occupied by the skid-mounted equipment, and facilitating operation and maintenance.

[0037] Example 7: As attached Figures 1 to 5As shown, a method for using the above-mentioned natural gas wellhead metering calibration device includes the following steps:

[0038] (1) The gas well product is transported from the main pipeline 7 to the slug trap 1 and buffered by the slug trap 1;

[0039] (2) The buffered gas well product enters the high-efficiency separator 2 for gas-liquid separation;

[0040] (3) The associated gas after separation is discharged from the high-efficiency separator 2 through the gas phase outlet pipeline 17, and its volume is accurately measured by the flow meter 6 installed on the gas phase outlet pipeline 17.

[0041] (4) The separated produced liquid enters the first storage weighing tank 3 through the separator liquid phase outlet pipeline 10 and the first inlet pipeline 12 in sequence. After the first storage weighing tank 3 is loaded with the corresponding volume of produced liquid, the first valve is closed and the second valve is opened. The mass of the produced liquid is accurately measured by the first storage weighing tank 3, and the volume of produced liquid loaded in the first storage weighing tank 3 is accurately measured by the first level gauge 18.

[0042] (5) The separated produced liquid enters the second storage weighing tank 4 through the separator liquid phase outlet pipeline 10 and the second inlet pipeline 13 in sequence. After the second storage weighing tank 4 is loaded with the corresponding volume of produced liquid, the second valve is closed and the first valve is opened. The mass of the produced liquid is accurately measured by the second storage weighing tank 4, and the volume of produced liquid loaded in the second storage weighing tank 4 is accurately measured by the first liquid level gauge.

[0043] (6) Repeat steps (4) to (5) until the metering demand per unit time is completed;

[0044] (7) Calculate the density of the produced fluid by the total volume and total mass of the produced fluid per unit time, and measure the density of light oil in a single well by a densitometer or a density bottle, and measure the density of produced water in a single well by a densitometer or a density bottle.

[0045] (8) The daily liquid production, daily water production, daily oil production and daily gas production of a single well were calculated.

[0046] During use, the specific measurement principle of this invention can be as follows:

[0047] 1) The volume of associated gas per unit time (t1) is directly measured using flow meter 6, and it is V1;

[0048] 2) The mass of produced fluid oil and water per unit time (t1) is measured by the first liquid storage weighing tank 3 and the second liquid storage weighing tank 4, and its mass is m1;

[0049] 3) The volume of extracted liquid oil and water per unit time (t1) is measured by the first level gauge 18 and the second level gauge 19, V2;

[0050] 4) The density of the produced fluid ρ1 = m1 / V2;

[0051] 5) The density of light oil from a single well can be measured using a density meter or density bottle, and it is ρ2;

[0052] 6) The density of produced water from a single well can be measured using a density meter or density bottle, ρ3;

[0053] 7) The daily production of fluid, oil, and gas of a single well can be calculated through the automated program. The daily production of fluid per well is m1*24 / t1.

[0054] The daily oil (water) production of a single well is calculated by PLC based on m1, V2, ρ2, and ρ3, and the daily gas production of a single well is V1×24 / t1.

[0055] The above technical features constitute the preferred embodiment of the present invention, which has strong adaptability and optimal implementation effect. Unnecessary technical features can be added or removed according to actual needs to meet the requirements of different situations.

Claims

1. A natural gas wellhead metering calibration device, characterized in that... The system includes a slug trap, a high-efficiency separator, a first liquid storage weighing tank, a second liquid storage weighing tank, a plunger pump, and a flow meter. The slug trap has a main pipeline at its inlet. The first outlet of the slug trap is fixedly connected to the upper front side of the high-efficiency separator, and the second outlet of the slug trap is fixedly connected to the lower front side of the high-efficiency separator. A liquid phase outlet pipeline is fixedly connected between the lower rear side of the high-efficiency separator and the inlet of a first electric three-way ball valve. A first inlet pipeline is fixedly connected between the first outlet of the first electric three-way ball valve and the upper rear side of the first liquid storage weighing tank, and a second inlet pipeline is fixedly connected between the second outlet of the first electric three-way ball valve and the upper rear side of the second liquid storage weighing tank. A second inlet pipeline is fixedly connected between the lower rear side of the first liquid storage weighing tank and the inlet of the second electric three-way ball valve. A first liquid outlet pipeline is fixedly connected between the first inlet and the second liquid storage weighing tank. A second liquid outlet pipeline is fixedly connected between the lower rear side of the second liquid storage weighing tank and the second inlet of the second electric three-way ball valve. A weighing tank phase outlet pipeline is fixedly connected between the outlet of the second electric three-way ball valve and the inlet of the plunger pump. A mixing pipeline is provided at the outlet of the plunger pump. A gas phase outlet pipeline is fixedly connected between the upper rear side of the high-efficiency separator and the mixing pipeline. A flow meter is provided on the gas phase outlet pipeline. A first liquid level gauge is provided on the first liquid storage weighing tank, and a second liquid level gauge is provided on the second liquid storage weighing tank. A first valve is provided on the first liquid inlet pipeline, a second valve is provided on the second liquid inlet pipeline, a third valve is provided on the first liquid outlet pipeline, a fourth valve is provided on the second liquid outlet pipeline, and an electric valve is provided on the liquid phase outlet pipeline of the separator.

2. The natural gas wellhead metering calibration device according to claim 1, characterized in that... It also includes a first pipeline and a second pipeline. The first pipeline is fixedly connected between the first inlet pipeline between the first valve and the first liquid storage weighing tank and the second inlet pipeline between the second valve and the second liquid storage weighing tank. The first pipeline is equipped with a fifth valve and a sixth valve. The second pipeline is fixedly connected between the first pipeline between the fifth valve and the sixth valve and the separator liquid phase outlet pipeline between the electric valve and the first electric three-way ball valve.

3. The natural gas wellhead metering calibration device according to claim 1 or 2, characterized in that... It also includes a third pipeline and a fourth pipeline. A third pipeline is fixedly connected between the first inlet pipeline between the third valve and the first liquid storage weighing tank and the second inlet pipeline between the fourth valve and the second liquid storage weighing tank. A seventh valve and an eighth valve are provided on the third pipeline. A fourth pipeline is fixedly connected between the third pipeline between the seventh valve and the eighth valve and the weighing tank outlet pipeline between the plunger pump and the second electric three-way ball valve.

4. The natural gas wellhead metering calibration device according to claim 1 or 2, characterized in that... It also includes a bypass line, which is fixedly connected to the separator liquid phase outlet line corresponding to the electric valve inlet and outlet positions, and a ninth valve is installed on the bypass line.

5. The natural gas wellhead metering calibration device according to claim 3, characterized in that... It also includes a bypass line, which is fixedly connected to the separator liquid phase outlet line corresponding to the electric valve inlet and outlet positions, and a ninth valve is installed on the bypass line.

6. The natural gas wellhead metering calibration device according to claim 1, 2, or 5, characterized in that... It also includes a first venting pipeline, a second venting pipeline and a third venting pipeline. The high-efficiency separator, the first liquid storage weighing tank and the second liquid storage weighing tank are respectively equipped with the first venting pipeline, the second venting pipeline and the third venting pipeline, and a safety valve is installed on the first venting pipeline.

7. The natural gas wellhead metering calibration device according to claim 3, characterized in that... It also includes a first venting pipeline, a second venting pipeline and a third venting pipeline. The high-efficiency separator, the first liquid storage weighing tank and the second liquid storage weighing tank are respectively equipped with the first venting pipeline, the second venting pipeline and the third venting pipeline, and a safety valve is installed on the first venting pipeline.

8. The natural gas wellhead metering calibration device according to claim 4, characterized in that... It also includes a first venting pipeline, a second venting pipeline and a third venting pipeline. The high-efficiency separator, the first liquid storage weighing tank and the second liquid storage weighing tank are respectively equipped with the first venting pipeline, the second venting pipeline and the third venting pipeline, and a safety valve is installed on the first venting pipeline.

9. The natural gas wellhead metering calibration device according to claim 1, 2, 5, 7, or 8, characterized in that... It also includes a skid, on which, from left to right, are arranged a second liquid storage weighing tank, a first liquid storage weighing tank, a high-efficiency separator, and a plunger pump.

10. A method for a natural gas wellhead metering calibration device as described in any one of claims 1 to 8, characterized in that... The steps include the following: (1) The gas well product is transported from the main pipeline to the slug trap and buffered by the slug trap; (2) The buffered gas well product enters a high-efficiency separator for gas-liquid separation; (3) The associated gas after separation is discharged from the high-efficiency separator through the gas phase outlet pipeline, and its volume is accurately measured by the flow meter installed on the gas phase outlet pipeline. (4) The separated produced liquid enters the first storage weighing tank through the liquid phase outlet pipeline of the separator and the first inlet pipeline in sequence. After the first storage weighing tank is loaded with the corresponding volume of produced liquid, the first valve is closed and the second valve is opened. The mass of the produced liquid is accurately measured by the first storage weighing tank and the volume of produced liquid loaded in the first storage weighing tank is accurately measured by the first level gauge. (5) The separated produced liquid enters the second storage weighing tank through the liquid phase outlet pipeline and the second inlet pipeline of the separator in sequence. After the corresponding volume of produced liquid is loaded into the second storage weighing tank, the second valve is closed and the first valve is opened. The mass of the produced liquid is accurately measured by the second storage weighing tank and the volume of produced liquid loaded in the second storage weighing tank is accurately measured by the first liquid level gauge. (6) Repeat steps (4) to (5) until the metering demand per unit time is completed; (7) Calculate the density of the produced fluid by the total volume and total mass of the produced fluid per unit time, and measure the density of light oil in a single well by a densitometer or a density bottle, and measure the density of produced water in a single well by a densitometer or a density bottle. (8) The daily liquid production, daily water production, daily oil production and daily gas production of a single well were calculated.

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