Feed gas flow metering device and collecting device

Abstract

The utility model provides a feed gas flow metering device and a feed gas collecting device, and the feed gas flow metering device comprises a temperature and pressure measuring part, a multiphase flow measuring part and a desanding separation part which are connected in sequence, the temperature and pressure measuring part can detect the temperature and the pressure of raw material gas, and the predicted first gas amount and the first liquid amount of a wellhead are obtained through iteration; the multi-phase flow measuring part can actually detect second gas quantity and second liquid quantity of a wellhead; the desanding separation part can be used for carrying out gas-liquid separation on the raw material gas and respectively discharging the raw material gas to obtain a third gas amount and a third liquid amount which are actually discharged; the multiphase flow measuring part can correct the gas flow output value according to the difference value among the first gas flow, the second gas flow and the third gas flow, and can also correct the liquid quantity output value according to the difference value among the first liquid quantity, the second liquid quantity and the third liquid quantity. The gas quantity difference value and the liquid quantity difference value can be conveniently and quickly obtained, and data of the multiphase flow measuring part can be quickly corrected, so that the measuring precision of the multiphase flow measuring part is improved.

Description

Technical Field

[0001] The utility model belongs to the technical field of natural gas collection equipment, and particularly relates to a flow metering device and a collection device for raw gas. Background Art

[0002] Shale gas is a natural gas resource that is available for exploitation and is stored in shale layers. Because it can be used in a variety of fields, people are very concerned about the output rate of shale gas during exploitation and will test the flow rate of shale gas.

[0003] In general, multiphase metering or separation metering is commonly used to measure and detect the flow rate during shale gas extraction. However, the separation metering method requires the use of more metering devices and separation equipment, resulting in a larger overall footprint, inconvenient installation and removal, and high cost for later maintenance. The more common multiphase metering method is generally measured by a multiphase flowmeter. When factors such as the density of the raw gas, instantaneous flow velocity, and the amount of sand produced at the bottom of the well change, it is very easy to cause deviations in the measurement results, thereby affecting the accuracy of the metering results of the multiphase flowmeter. Therefore, the metering results need to be corrected in a timely manner. At present, the most common correction method is manual on-site assisted calibration, but the manpower cost of manual on-site assisted calibration is too high and it is time-consuming and labor-intensive.

[0004] Therefore, when errors occur in the existing shale gas flow measurement, it is difficult to correct them quickly. Utility Model Content

[0005] In view of the above problems, the utility model proposes a flow metering device and a collection device for raw gas, wherein the flow metering device for raw gas comprises:

[0006] A temperature and pressure measuring unit, which can be connected to the gas tree at the wellhead, so that the raw gas discharged from the gas tree can flow through the temperature and pressure measuring unit, and the temperature and pressure of the raw gas can be detected by the temperature and pressure measuring unit;

[0007] The predicted first gas volume and first liquid volume at the wellhead can be obtained by iterating the temperature and pressure data of the raw gas;

[0008] A multiphase flow measurement unit, the multiphase flow measurement unit is connected to the temperature and pressure measurement unit, and the multiphase flow measurement unit can detect the gas volume and liquid volume of the raw gas and output them to obtain the second gas volume and the second liquid volume detected at the wellhead;

[0009] a sand removal and separation unit, the sand removal and separation unit being connected to the multiphase flow measurement unit, the sand removal and separation unit being capable of removing sand from the raw gas, and the sand removal and separation unit being capable of separating gas and liquid from the raw gas and discharging the gas and the liquid and the raw gas respectively, so as to obtain a third gas volume and a third liquid volume actually discharged;

[0010] The multiphase flow measurement unit can correct the gas volume output value according to the difference between the first gas volume, the second gas volume and the third gas volume;

[0011] The multiphase flow rate measurement unit can also correct a liquid amount output value according to a difference between the first liquid amount, the second liquid amount, and the third liquid amount.

[0012] In some specific embodiments, it also includes:

[0013] A main controller, the main controller is connected to the temperature and pressure measuring part;

[0014] The main controller can iteratively calculate the first gas volume and the second gas volume through the temperature and pressure of the raw gas detected by the temperature and pressure measuring unit.

[0015] In some specific embodiments, the main controller is also connected to the multiphase flow measurement unit and the sand removal and separation unit respectively;

[0016] The main controller is capable of comparing the first gas volume, the second gas volume and the third gas volume and the first liquid volume, the second liquid volume and the third liquid volume;

[0017] The main controller can also correct the output value of the multiphase flow measurement unit according to the comparison result.

[0018] In some specific embodiments, there are multiple temperature and pressure measuring parts;

[0019] There are a plurality of multiphase flow measurement units, and the plurality of multiphase flow measurement units are arranged in one-to-one correspondence with the plurality of temperature and pressure measurement units;

[0020] A plurality of the multiphase flow rate measuring units are arranged in parallel.

[0021] In some specific embodiments, the sand removal and separation unit includes:

[0022] A desander, wherein the desander is capable of desanding the raw gas;

[0023] A separator is connected to the desander, and the separator can separate the raw gas into gas and liquid.

[0024] In some specific embodiments, the desander and the separator are an integrated structure.

[0025] In some specific embodiments, the exhaust port of the separator is connected to an orifice flowmeter, and the orifice flowmeter can measure the exhausted gas phase to obtain the third gas volume.

[0026] In some specific embodiments, the exhaust port of the separator is connected to an electromagnetic flowmeter, and the electromagnetic flowmeter can measure the discharged liquid phase to obtain the third liquid volume.

[0027] In some specific embodiments, the temperature and pressure measuring unit is a wellhead temperature and pressure measuring device;

[0028] The multiphase flow measurement unit is a multiphase flow meter.

[0029] The raw gas collection device based on the same concept includes the raw gas flow metering device as described in any of the above specific embodiments.

[0030] The flow metering device of the raw gas of the utility model can detect the temperature and pressure of the wellhead through the temperature and pressure measuring part, so as to quickly iterate and obtain the prediction results about the first gas volume and the first liquid volume. The second gas volume and the second liquid volume at the wellhead can be detected in real time through the multiphase flow measuring part. The third gas volume and the third liquid volume actually discharged can be obtained through the sand removal and separation part. By obtaining the first gas volume, the second gas volume and the third gas volume and the first liquid volume, the second liquid volume and the third liquid volume, it is convenient for the staff to quickly obtain the gas volume difference and the liquid volume difference, and the multiphase flow measurement part data can be quickly corrected to improve the measurement accuracy of the multiphase flow measurement part.

[0031] The raw gas collection device of the utility model includes the above-mentioned raw gas flow metering device, so it has the same beneficial effects as the above-mentioned raw gas flow metering device, which will not be repeated here.

[0032] Other features and advantages of the utility model will be described in the following description, and partly become apparent from the description, or understood by implementing the utility model. The purpose and other advantages of the utility model can be realized and obtained by the structures indicated in the description, claims and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0033] In order to more clearly illustrate the embodiments of the utility model or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the utility model. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0034] Figure 1 The schematic diagram of the structure of the raw gas collection device in the embodiment of the utility model is shown;

[0035] Figure 2 A partial enlarged view of a raw gas collection device in an embodiment of the utility model is shown;

[0036] Figure 3 Another partially enlarged view of the raw gas collection device in the embodiment of the utility model is shown.

[0037] In the figure, 1, gas tree; 2, temperature and pressure measurement part; 3, multiphase flow measurement part; 4, sand removal and separation part; 41, desander; 42, separator; 421, orifice flowmeter; 422, electromagnetic flowmeter. DETAILED DESCRIPTION

[0038] In order to make the purpose, technical solution and advantages of the embodiment of the utility model clearer, the technical solution in the embodiment of the utility model will be clearly and completely described below in conjunction with the drawings in the embodiment of the utility model. Obviously, the described embodiment is a part of the embodiment of the utility model, not all of the embodiments. Based on the embodiment of the utility model, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the utility model.

[0039] Reference Figure 1The utility model provides a flow metering device for raw gas, including: a temperature and pressure measuring part 2, a multiphase flow measuring part 3 and a sand removal and separation part 4. A gas production tree 1 is arranged at the wellhead, and the raw gas in the well can be extracted through the gas production tree 1. At this time, the extracted raw gas contains substances such as gas phase, liquid phase and sand and gravel. The temperature and pressure measuring part 2 can be connected to the gas production tree 1 at the wellhead, so that the raw gas extracted from the gas production tree 1 can flow through the temperature and pressure measuring part 2, and the temperature and pressure of the raw gas can be detected by the temperature and pressure measuring part 2, and the detection result can be output. According to the detection result, iteration can be performed, so that the theoretical gas volume and liquid volume of the wellhead can be inferred, so that it is convenient for the staff to obtain the predicted first gas volume and first liquid volume of the wellhead. The multiphase flow measurement part 3 is connected to the temperature and pressure measurement part 2, and the raw gas that has passed through the temperature and pressure measurement part 2 will continue to pass through the multiphase flow measurement part 3. The gas volume and liquid volume in the raw gas can be detected by the multiphase flow measurement part 3, and the detection result can be output, so that the second gas volume and second liquid volume of the wellhead actually detected can be obtained. The sand removal separation part 4 is connected to the multiphase flow measurement part 3. The raw gas that has passed through the multiphase flow measurement part 3 will reach the sand removal separation part 4. The raw gas can be firstly sanded by the sand removal separation part 4, so as to remove the sand and other substances in the raw gas. In addition, the sand removal separation part 4 can also perform gas-liquid separation on the raw gas after the sand removal operation, and discharge the separated gas and liquid separately, so that when the gas and liquid are discharged separately, the third gas volume and the third liquid volume actually discharged can be obtained.

[0040] Specifically, after the worker obtains the first gas volume, the second gas volume and the third gas volume and the first liquid volume, the second liquid volume and the third liquid volume, the first gas volume and the second gas volume can be compared with the third gas volume respectively to obtain the gas volume difference between the first gas volume and the third gas volume and the gas volume difference between the second gas volume and the third gas volume respectively, and the value with the smaller error in the two gas volume differences is taken to correct and modify the gas volume detection result of the multiphase flow measurement unit 3, so that the gas volume detection result of the multiphase flow measurement unit 3 can be made more accurate. At the same time, the first liquid volume and the second liquid volume can be compared with the third liquid volume respectively to obtain the liquid volume difference between the first liquid volume and the third liquid volume and the liquid volume difference between the second liquid volume and the third liquid volume respectively, and the value with the smaller error in the two liquid volume differences is taken to correct and modify the liquid volume detection result of the multiphase flow measurement unit 3, so that the liquid volume detection result of the multiphase flow measurement unit 3 can be made more accurate. Through the structural setting of the raw gas flow metering device, the detection data on the first gas volume, the second gas volume and the third gas volume and the first liquid volume, the second liquid volume and the third liquid volume can be quickly obtained, so as to ensure the detection accuracy of the multiphase flow measurement part 3 while improving the correction speed of the multiphase flow measurement part 3 by the staff, thereby greatly saving the labor cost during maintenance.

[0041] First of all, it should be noted that the wellheads mentioned above and later are the wellheads of shale gas wells, and the raw gas is shale gas.

[0042] Secondly, it should be noted that the difference in gas volume between the first gas volume and the third gas volume and the difference in gas volume between the second gas volume and the third gas volume are both less than 5%. If the difference in gas volume is greater than 5%, it indicates that the flow metering device of the raw gas may have a major problem, and the obtained gas volume detection result may be wrong, which must be checked and debugged by the staff. The difference in liquid volume between the first liquid volume and the third liquid volume and the difference in liquid volume between the second liquid volume and the third liquid volume are both less than 10%. If the difference in liquid volume is greater than 10%, it indicates that the flow metering device of the raw gas may have a major problem, and the obtained liquid volume detection result may be wrong, which must be checked and debugged by the staff.

[0043] In some specific embodiments of the utility model, the flow metering device of the raw gas also includes: a main controller. The main controller is electrically connected to the temperature and pressure measuring unit 2. Thus, the detection results of the temperature and pressure of the raw gas detected by the temperature and pressure measuring unit 2 can be transmitted to the main controller. As the temperature and pressure parameter data of the raw gas are input into the main controller, the main controller can input the temperature and pressure parameter data into the iterative model to calculate the theoretical production of the gas volume and liquid volume at the wellhead, thereby iteratively obtaining the first gas volume and the second gas volume. The automation setting of the main controller is improved, and the correction efficiency is improved.

[0044] In some specific embodiments of the utility model, the main controller is also electrically connected to the multiphase flow measurement unit 3 and the sand removal separation unit 4, respectively. Therefore, the detection results of the actual gas volume and liquid volume of the raw gas detected by the multiphase flow measurement unit 3 and the detection results of the specific discharged gas volume and liquid volume obtained by the sand removal separation unit 4 can be transmitted to the main controller. And under the action of the main controller, the first gas volume, the second gas volume and the third gas volume difference, and the first liquid volume, the second liquid volume and the third liquid volume difference can be compared, so that the minimum gas volume difference between the gas volume difference between the first gas volume and the third gas volume and the gas volume difference between the second gas volume and the third gas volume can be obtained, and the minimum liquid volume difference between the liquid volume difference between the first liquid volume and the third liquid volume and the liquid volume difference between the second liquid volume and the third liquid volume can be obtained. The main controller can transmit the obtained minimum gas volume difference and minimum liquid volume difference to the multiphase flow measurement unit 3, so that the output value of the detection result of the multiphase flow measurement unit 3 can be corrected according to the comparison result. Improve the automation settings of the main controller and improve the calibration efficiency.

[0045] In some specific embodiments of the present invention, refer to Figure 1 and Figure 2, there are multiple temperature and pressure measuring parts 2. There are also multiple multiphase flow measuring parts 3, and multiple multiphase flow measuring parts 3 are arranged in one-to-one correspondence with multiple temperature and pressure measuring parts 2. Each multiphase flow measuring part 3 is respectively connected to the corresponding temperature and pressure measuring part 2, and each temperature and pressure measuring part 2 can be connected to the gas production tree 1 of a wellhead. Each multiphase flow measuring part 3 is also connected to the sand removal and separation part 4, so that multiple multiphase flow measuring parts 3 are arranged in parallel. It is possible to carry out data collection work and subsequent debugging and correction work on multiple wellheads at the same time.

[0046] Specifically, multiple temperature and pressure measuring units 2 can detect the temperature and pressure of multiple wellheads respectively, so that the predicted theoretical first gas volume and first liquid volume of each wellhead can be iteratively obtained through the main controller, and the actual second gas volume and second liquid volume detected at each wellhead can also be obtained through multiple multiphase flow measurement units 3, and the specific third gas volume and fourth gas volume discharged from all wellheads can be obtained through the sand removal separation unit 4. The gas volume difference between the multiple first gas volume addition values ​​and the third gas volume and the gas volume difference between the multiple second gas volume addition values ​​and the third gas volume can be obtained by comparing the sum of the predicted first gas volumes of all wellheads and the sum of the actual second gas volumes detected at all wellheads with the third gas volume, respectively. The gas volume difference between the multiple first gas volume addition values ​​and the third gas volume and the gas volume difference between the multiple second gas volume addition values ​​and the third gas volume can be obtained, and the value with the smaller error in the two gas volume differences can be taken to correct and modify the gas volume detection result of the multiphase flow measurement unit 3, so that the gas volume detection result of the multiphase flow measurement unit 3 can be made more accurate. At the same time, the sum of the predicted first liquid volumes of all wellheads and the sum of the actual second liquid volumes detected at all wellheads can be compared with the third liquid volume, thereby obtaining the liquid volume difference between the sum of the first liquid volumes and the third liquid volume and the liquid volume difference between the sum of the second liquid volumes and the third liquid volume. The value with the smaller error in the two liquid volume differences is taken to correct and modify the liquid volume detection result of the multiphase flow measurement unit 3, so that the liquid volume detection result of the multiphase flow measurement unit 3 can be made more accurate. In addition, the detection data of multiple multiphase flow measurement units 3 can be corrected at the same time, which can improve the correction speed of the multiphase flow measurement unit 3 by the staff while ensuring the detection accuracy of multiple multiphase flow measurement units 3, improve the overall efficiency of the correction work, and greatly save the labor cost during maintenance. It is no longer necessary to install multiple sand removal separation units 4 and multiple separate multiphase flow measurement units 3 to measure the flow, saving equipment installation, use costs and maintenance costs.

[0047] First of all, it should be noted that the first gas volume and the first liquid volume are predicted values ​​of the gas volume and liquid volume that may be contained in the wellhead, the second gas volume and the second liquid volume are actual detection values ​​of the gas volume and liquid volume contained in the wellhead, and the third gas volume and the third liquid volume are actual discharge values ​​of the gas volume and liquid volume of multiple wellheads.

[0048] Secondly, it should be noted that the correction and modification method is as follows: if the liquid volume difference between the sum of the multiple first liquid volumes and the third liquid volume is greater than the liquid volume difference between the sum of the multiple second liquid volumes and the third liquid volume, the detection value of the second liquid volume is used as the actual liquid volume output value. If the liquid volume difference between the sum of the multiple first liquid volumes and the third liquid volume is less than the liquid volume difference between the sum of the multiple second liquid volumes and the third liquid volume, the detection value of the first liquid volume is used as the actual liquid volume output value. If the gas volume difference between the sum of the multiple first gas volumes and the third gas volume is greater than the gas volume difference between the sum of the multiple second gas volumes and the third gas volume, the detection value of the second gas volume is used as the actual liquid volume output value. If the gas volume difference between the sum of the multiple first gas volumes and the third gas volume is less than the gas volume difference between the sum of the multiple second gas volumes and the third gas volume, the detection value of the first gas volume is used as the actual liquid volume output value.

[0049] Furthermore, the number of temperature and pressure measuring parts 2 is four, and the number of multiphase flow measuring parts 3 is also four, that is, four gas production trees 1 are used to perform gas extraction operations on four wellheads, so that the raw gas produced by the four wellheads can be detected by one of the temperature and pressure measuring parts 2 and one of the multiphase flow measuring parts 3 in turn, and then the raw gas produced by the four wellheads is collected and transported to the sand removal separation part 4 for actual discharge detection through four parallel multiphase flow measuring parts 3, and then the four groups of output values ​​can be corrected simultaneously through the detection results. The setting of four temperature and pressure measuring parts 2 and four multiphase flow measuring parts 3 can maintain the accuracy of the detection results while ensuring the correction efficiency. If the number is less than four, the correction efficiency is not fully utilized, and if it is greater than four, it may cause deviations in the detection results.

[0050] It should be noted that the number of the temperature and pressure measuring parts 2 and the multiphase flow measuring parts 3 may also be set to be greater than or less than four according to actual needs.

[0051] In some specific embodiments of the present invention, refer to Figure 3 The desander and separation part 4 includes: a desander 41 and a separator 42. The desander 41 can remove sand from the raw gas, thereby removing sand and gravel from the raw gas. The separator 42 is connected to the desander 41, and the raw gas from which the sand and gravel are removed can reach the separator 42, and the separator 42 can separate the raw gas into gas and liquid, so as to collect the gas and liquid separately, and can measure the specific gas volume and liquid volume separately, so as to obtain the third gas volume and the third liquid volume.

[0052] Furthermore, the desander 41 and the separator 42 are integrated structures, which are no longer skid-mounted separately, making transportation easier and eliminating the need for separate commissioning and installation after arriving at the site, thereby reducing the equipment footprint at the site, reducing the workload, and saving construction and installation costs.

[0053] Furthermore, the exhaust port of the separator 42 is connected to an orifice flowmeter 421, through which the exhausted gas phase can be measured, so as to obtain a specific value of the third gas volume, thereby improving the correction efficiency. The gas passing through the orifice flowmeter 421 will be collected out of the station.

[0054] Furthermore, the exhaust port of the separator 42 is connected to an electromagnetic flowmeter 422, which can measure the discharged liquid phase to obtain a specific value of the third liquid amount, thereby improving the calibration efficiency. The liquid passing through the electromagnetic flowmeter 422 will enter the sewage tank to complete the sewage discharge.

[0055] It should be noted that the temperature and pressure measuring unit 2 may be a wellhead temperature and pressure measuring device, and the multiphase flow measuring unit 3 may be a multiphase flow meter, as long as the functions to be realized can be achieved.

[0056] The utility model also provides a raw gas collection device, including a raw gas flow metering device as in any of the above-mentioned specific embodiments. Since it includes the above-mentioned raw gas flow metering device, the raw gas collection device has the same beneficial effects as the above-mentioned raw gas flow metering device, which will not be repeated here.

[0057] Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the aforementioned embodiments, or make equivalent replacements for some of the technical features therein; and these modifications or replacements do not make the essence of the corresponding technical solutions deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A flow metering device for raw gas, characterized in that: include: A temperature and pressure measuring unit, which can be connected to the gas tree at the wellhead, so that the raw gas discharged from the gas tree can flow through the temperature and pressure measuring unit, and the temperature and pressure of the raw gas can be detected by the temperature and pressure measuring unit; The predicted first gas volume and first liquid volume at the wellhead can be obtained by iterating the temperature and pressure data of the raw gas; A multiphase flow measurement unit, the multiphase flow measurement unit is connected to the temperature and pressure measurement unit, and the multiphase flow measurement unit can detect the gas volume and liquid volume of the raw gas and output them to obtain the second gas volume and the second liquid volume detected at the wellhead; a sand removal and separation unit, the sand removal and separation unit being connected to the multiphase flow measurement unit, the sand removal and separation unit being capable of removing sand from the raw gas, and the sand removal and separation unit being capable of separating gas and liquid from the raw gas and discharging the gas and the liquid and the raw gas respectively, so as to obtain a third gas volume and a third liquid volume actually discharged; The multiphase flow measurement unit is capable of correcting the gas volume output value according to the difference between the first gas volume, the second gas volume and the third gas volume; The multiphase flow rate measurement unit can also correct a liquid amount output value according to a difference between the first liquid amount, the second liquid amount, and the third liquid amount.

2. The flow metering device for raw gas according to claim 1, characterized in that: Also includes: A main controller, the main controller is connected to the temperature and pressure measuring part; The main controller can iteratively calculate the first gas volume and the second gas volume through the temperature and pressure of the raw gas detected by the temperature and pressure measuring unit.

3. The flow metering device for raw gas according to claim 2, characterized in that: The main controller is also connected to the multiphase flow measurement unit and the sand removal and separation unit respectively; The main controller is capable of comparing the first gas volume, the second gas volume and the third gas volume and the first liquid volume, the second liquid volume and the third liquid volume; The main controller can also correct the output value of the multiphase flow measurement unit according to the comparison result.

4. The raw gas flow metering device according to any one of claims 1 to 3, characterized in that: There are multiple temperature and pressure measuring parts; There are a plurality of multiphase flow measurement units, and the plurality of multiphase flow measurement units are arranged in one-to-one correspondence with the plurality of temperature and pressure measurement units; A plurality of the multiphase flow rate measuring units are arranged in parallel.

5. The raw gas flow metering device according to any one of claims 1 to 3, characterized in that: The sand removal and separation unit comprises: A desander, wherein the desander is capable of desanding the raw gas; A separator is connected to the desander, and the separator can separate the raw gas into gas and liquid.

6. The raw gas flow metering device according to claim 5, characterized in that: The desander and the separator are an integrated structure.

7. The flow metering device for raw gas according to claim 5, characterized in that: The exhaust port of the separator is connected to an orifice flowmeter, and the orifice flowmeter can measure the exhausted gas phase to obtain the third gas volume.

8. The flow metering device for raw gas according to claim 5, characterized in that: The exhaust port of the separator is connected to an electromagnetic flowmeter, and the electromagnetic flowmeter can measure the discharged liquid phase to obtain the third liquid volume.

9. The raw gas flow metering device according to claim 1, characterized in that: The temperature and pressure measuring part is a wellhead temperature and pressure measuring device; The multiphase flow measurement unit is a multiphase flow meter.

10. A raw gas collection device, characterized in that: A flow metering device for raw gas comprising the flow metering device as described in any one of claims 1 to 9.

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