SY 5671-1993 Flowmeter Handover Measurement Procedure for Petroleum and Liquid Petroleum Products SY5671-1993 Standard Download Decompression Password: www.bzxz.net

Petroleum and liquid petroleum products
Flowmeter delivery measurement procedures
SYL 03--3
! , General provisions
2. Measuring instruments and standard devices
3. Metering procedures
4. Oil volume calculation
5. Temperature and pressure correction
Appendix A Nomenclature and terminology ...
(965
(987
w (972)
(975)
(978)
Appendix B Technical requirements for installation of measuring instruments and standard devices (8) Appendix C Instructions for use of liquid petroleum average compression coefficient table (82) 964
Standard of the Ministry of Petroleum Industry of the People's Republic of China Petroleum and liquid petroleum products
Flowmeter delivery measurement procedures
SYL 0383
This regulation is applicable to the delivery measurement of crude oil and heavy liquid petroleum products (hereinafter referred to as oil products) with a viscosity range of 10~150 centimeters using a positive displacement flow meter (hereinafter referred to as flow meter). When implementing this regulation, the relevant provisions of the "Measurement Management Measures for Delivery of Oil and Petroleum Products" issued by the Ministry of Petroleum Industry must be complied with. 1. General Purchase
1.1 Measuring Accuracy
The flow meter used for oil delivery measurement and its measurement accuracy are stipulated as follows
1.1.1 The flow meter accuracy should not be less than 0.2 level. 1.1.2 The comprehensive error of weight measurement (accuracy of the measurement system) should reach ± ​​0.35%.
1.2 Principles and requirements for setting up metering stations
1.2.1 The metering station used for oil product handover measurement shall be established by the supplier; the metering instruments and working standards used shall be selected and equipped by the supplier. 1.2.2 The metering station shall select one of the following two types according to the scale of the quantity handover
Approved by the Ministry of Petroleum Industry of the People's Republic of China on 18B3-03-12 and implemented on 1983-07-01
a. Volume measurement type: The volume of oil products is measured by flow meter. The density and water content are measured by artificial temperature and sampling, and the quality of the oil products is obtained by table conversion. 6. Quality measurement type: The volume, density, water content, etc. of the oil products are continuously measured and measured by all instruments, and the quality of the oil products is automatically calculated. 1.2.3 Under abnormal circumstances, there are areas in the metering station where gas emission and accumulation can form explosion and fire hazards. , the electrical instruments used (including flowmeters, density meters, water content analyzers and other measuring instruments' electrical transmitters) and associated equipment should meet the explosion-proof requirements, and their explosion-proof types, grades, groups and connection requirements should all comply with the requirements for electrical devices in explosion and fire hazardous places in the "National Electric Power Design Code".
1.3 Verification requirements
1.3.1 All newly installed flowmeters, after maintenance and in the verification cycle, must be calibrated before use to determine the actual use accuracy of the flowmeter. 1.3.2 Flowmeters used for oil product delivery measurement should be subject to online real liquid calibration.
1.3.3 For crude oil measurement, the metering instrument used is the working standard: the crude oil large flow metering and calibration station of the Ministry of Petroleum Industry shall implement periodic calibration; for petroleum product measurement, the newly used metering instruments and working standards shall be subject to periodic calibration by the units authorized by the Ministry of Petroleum Industry or the measurement management departments of the government at the same level.
1.3.4 Calibration cycle
1.3.4.1 The flowmeter and supporting instruments in the figure are generally three to six months.
1.3.4.2 The standard volume tube used as the working standard is three years, and the standard full volume meter is one year.
1.4 Measurement form
1.4.1 Loading measurement: It is a one-time measurement of a short time (no more than 2 hours). It is required to read the value displayed on the instrument at the beginning and end of the measurement, and deduct it to liters.
1.4.2 Ship loading measurement: It is a one-time measurement of a longer time (more than 2 hours). When the total measurement time does not exceed 8 hours, the data is taken according to the loading requirements. If the measurement time exceeds 8 hours, at the beginning of the measurement, read the instrument base number and then read the measurement data every 8 hours, and the final cumulative number of the instrument read is used as the total quantity measured. 1.4.3 Long-distance pipeline volume: For continuous measurement of long-distance (more than 24 hours), the measurement data should be read every 8 hours, and the reading should be accurate to cubic meters. 2. Measuring rods and standard requirements
2.1 Selection of flow meter
2.1.1 The common flow rate through the flow meter should be selected within the range of 70~80% of the maximum flow rate of the flow meter
2.1.2 When selecting the size of the flow meter, both the measurement accuracy and economic rationality should be considered. When one flow meter cannot meet the measurement requirements, it is advisable to use a parallel measurement method of multiple units. 2.1.3 The number of flow meters should be determined according to the total amount of oil products to be measured. At the same time, factors such as verification and maintenance should be considered, and sufficient spare units should be reserved. 2.2 Composition of flow meter system
The flow meter should be equipped with auxiliary equipment such as filters, air eliminators, regulating valves, check valves, etc. to form a flow meter measurement system (see Figure 1). 2.2.1 The filter and the air eliminator shall be installed at the inlet of the flow meter. 2.2.2 The back pressure regulating valve and the check valve shall be installed at the outlet of the flow meter. For the measurement of loading and shipping, the flow meter outlet may not be equipped with a check valve. 867
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Air eliminator
Degree meter
Through pressure gauge
1. Combined moisture separator
Heart-to-heart stop reading
tStandard device production
3 Total density meter for port tickets
@Stanza valve
Heart-to-heart meter Standard loading volume Connecting check valve
Figure Schematic diagram of flow meter measurement system
2.2.3 A 0.5-level pressure gauge shall be installed at the inlet of the filter and the outlet of the flow meter.
2.2.4 A hygrometer with a 0.2°C graduation should be installed at the outlet of the flowmeter. 2.3 Selection of standard push device
2.3.1 For the real liquid verification of large-diameter flowmeters for measuring oil, one of the following three standard devices can be selected:
a. Fixed standard volume tube, with a reproducibility of ±C02b. Vehicle-mounted standard push volume tube, with a reproducibility of ±0.02g!, standard flowmeter, with an accuracy of 0.1 level.
2.3.2 For the verification of centering and small-diameter flowmeters, other standard devices other than the above three standard devices can also be used. 2.3.3 When selecting the working standard, the error of the working standard should be less than 1/3 of the allowable error of the flowmeter being tested.
2.3.4 When using a standard volume tube as a working standard, the flow range of the volume tube should be consistent with the flow range of the flow meter being calibrated. Generally, the volume of the reference section of the volume tube should not be less than 0.5% of the maximum hourly flow value of the flow meter. 968
2.3.5 The form of the standard device should be determined according to the pool volume of the meter, the caliber of the flow meter and the number of units.
2.4, Selection of density and water content instrument
2.4.1 The instrument for measuring oil density should be a dynamic tube density meter that can continuously measure the dynamic density of oil in the pipeline online and is matched with a mass calculation instrument. Its absolute error is ±0.001 g/cm, and the measurement accuracy of the instrument is t0.1%.
2.4.2 The instrument for determining the water content of crude oil should be a crude oil low water content analyzer with a measurement range of 0-5%, which can continuously measure the water content of crude oil in the pipeline online and is matched with a pure water accumulation instrument. The measuring accuracy of the instrument is ±e.1%.
2.4.3 The number of density meters and water content analyzers shall be determined according to the metering pipeline of the metering station. Generally, one metering pipeline shall be equipped with one density meter and one water content analyzer. For stations with continuous metering, one shall be prepared for each. 2.4.4 The display instrument of the density meter and water content analyzer shall be selected in conjunction with the detection instrument.
2.5 Selection of mass calculation instrument
2.5.1 The mass calculation instrument involved in the quality calculation of the product shall be determined according to the matching degree of the stacked instruments in the metering station and the need to realize the centralized detection of metering data.
2.5.2 The mass calculation instrument includes a mass integrator and a pure water integrator. It shall be used in conjunction with the flow integrator of the flow meter and the display instrument of the density meter and water content analyzer.
3. Metering procedure
3.1 Type of mass measurement
3.1.1 Before measuring, the base number of the cumulative counter of the flow meter, flow totalizer, mass totalizer, and pure water totalizer should be recorded. 3.1.2 Record the volume of the measured oil.
Read the accumulated volume of the cumulative counter of the flow meter and flow totalizer according to the requirements of Article 1.4. The accumulated number of the flow meter and flow totalizer is allowed to have a difference of 1 number in the mantissa.
31.3 Record the mass of the measured oil
While reading the volume of the oil, read the accumulated mass value of the oil in the mass totalizer.
3.1.4. Record the water content of the measured crude oil. While reading the cumulative number of the oil mass, read the amount of pure water accumulated by the pure water calculator.
3.2 Volumetric measurement type
3.2.1 At the beginning of measurement, first record the base number of the cumulative counter on the flow meter head.
3.2.2 During the measurement process, the sampling of the oil and the determination of temperature, density and water content shall be carried out in accordance with the provisions of Articles 3.3, 3.4, 3.5 and 3.6. 3.2.3 When the measurement is completed or the specified measurement time is reached, record the volume of the oil accumulated in the cumulative counter on the flow meter head in accordance with the measurement requirements of Article 1.4. 3.3 Sampling
When using a flow meter for measurement, pipeline sampling shall be implemented. The sampling location, sampling method and sampling requirements shall be implemented in accordance with the following provisions. 3.3.1 Sampling location
3.3.1.1 The oil sample shall be taken from the pipeline sampler installed horizontally on the vertical pipeline at the outlet of the flow meter or installed horizontally at 90° on the fluid consumption area (Schnog number Re>2000) of the pipeline near the outlet of the flow meter. 3.3.1.2 The 45° slope at the inlet end of the sampling tube shall face the direction of liquid flow, the midpoint of the inlet slope shall be located at 1/3 of the pipe diameter, and the exposed part of the sampling tube shall be as short as possible.
3.3.2 Sampling method
3.3.2.1 For loading measurement, sampling shall be carried out once each at 10 minutes after the oil in the tank flows through the flow meter at the beginning of measurement, at the middle time and at 10 minutes before the end of measurement. The samples taken shall be mixed into an intermittent sample in equal volumes. 3.3.2.2 For loading measurement: sampling should be done once 10 minutes after the oil in the tank flows through the flow meter at the beginning of measurement and 10 minutes before the end of measurement. Sampling should be done once every 1 hour in between. Then, the samples taken should be mixed into an intermediate sample with equal volume.
3.3.2.3 For long-distance pipeline measurement: sampling should be done once every 2 hours. 3.3.3 Sampling requirements
3.3.3.1 Before sampling, some oil to be sampled should be released, the sampler should be rinsed clean, and then the sample should be collected in a sample container or collector. 3.3.3.2 When taking high-freezing point samples, attention should be paid to pipeline insulation to prevent the oil from solidifying. When taking volatile samples, light fraction loss should be prevented. 3.4 Temperature measurement
The temperature measurement method shall be carried out in accordance with the following provisions. The temperature measurement part is on the pipeline at the outlet of the flow meter, and the thermometer reading is accurate to 0.2°C. 3.4.1 For loading measurement, the temperature should be measured once at the beginning of measurement, 10 minutes after the oil flows through the flow meter, in the middle time and 10 minutes before the end of measurement. The arithmetic mean of the three measured temperatures is taken as the average temperature of the oil. 3.4.2 For loading measurement: the temperature should be measured once at the beginning of measurement, 10 minutes after the oil flows through the flow meter, and 10 minutes before the end of measurement. The temperature should be measured once every 1 hour in between, and the arithmetic mean of the measured temperatures during the measurement time is taken as the average temperature of the oil.
3.4.3 For long-distance pipeline measurement: the temperature should be measured once every 2 hours. The arithmetic mean of the temperature measurements taken four times within 8 hours is taken as the average temperature of the product measured for 8 hours1
3.5 Density determination
The method for determining density shall be in accordance with GB1884--80 (Determination of density of petroleum and liquid petroleum products (density meter method)). The density meter reading is estimated to 0.0001 g/cm, and the temperature is read to 0.2°C. The specific requirements are as follows: 3.5.1 For loading and shipping measurement: the samples taken shall be continuously measured2, and the density and temperature values ​​shall be read at the same time
3.5.2 For long-distance pipeline measurement: the density and temperature of the samples taken once every 2 hours shall be measured, and each sample shall be measured twice in a row. 3.6 Determination of water content in crude oil
The method for determining the water content of the original bubble shall be in accordance with GB 260-77 "Method for Determination of Water Content in Petroleum Products" is implemented. The specific requirements are as follows: 3.6.1 For loading and shipping measurement, the water content of the samples taken shall be measured in parallel, and the arithmetic mean of the parallel measured results shall be taken as the water content of the measured crude oil, and the data shall be expressed in weight percentage. 3.6.2, For long-distance pipeline measurement: the water content of the samples taken once every 2 hours shall be measured in parallel: the arithmetic mean of all the results obtained by parallel determination of the samples taken within 8 hours shall be taken as the water content of the measured crude oil after 8 hours of measurement, and the data shall be expressed in weight percentage 4. Oil volume calculation
4.1 Density conversion
Convert the apparent density (p) of the oil product measured by the petroleum densitometer and the temperature value (t℃) measured at the same time into a table Calculate to the standard density (p20) at 20°C. For the table lookup method and the correction method for the mantissa of density and temperature, see Table I "Petroleum Apparent Density Conversion Table" and instructions of GB1885-80
4.1.1 For loading and shipping measurement: convert the two continuously measured temperatures and apparent densities to the standard density at 20°C, and take the arithmetic mean as the standard density (p20) of the measured oil.
4.1.2 For long-distance pipeline measurement: convert all temperatures and apparent densities measured by the samples taken within 8 hours to the standard density at 25°C, and take the arithmetic mean as the average standard density (cao) of the measured oil after 8 hours of measurement.
4.2 Calculation of standard volume||t t||4.2.1 Convert the volume measured by the flowmeter at the metering temperature (t°℃) to the volume (V) at the standard temperature (20℃). The conversion formula is VaoK·Vt
Where: t--actually measured volume at the metering temperature (t\C), its value is the cumulative number of the flowmeter head counter minus the previous base number; K oil volume coefficient, its value is obtained by checking the metering temperature (r℃) and the standard oil friction (p20) in GB1885--80 Table ⅡA "Oil Volume Coefficient Table",
4.2.2 Use a flowmeter with automatic temperature compensation, and the temperature compensator will automatically convert the measured volume (Vt) at the metering temperature (t℃) to the standard volume (V2o) at 20\C, and read it directly from the flowmeter head counter. 4.2.3 For flow meters that automatically compensate the measured volume at the measuring temperature to the standard volume at 60°F, the volume (V15.6) at 60\F (equal to 15.6°C) should be converted to the standard volume (V20) at 20°C. The conversion formula is:
Va-K·Vi5.5
wherein the K value is still in Table II.4 of GB1885-80 "Table of Volume Coefficients of All Oils". 4.3 Calculation of Mass
When the oil is calculated by weight in air, the influence of air buoyancy should be considered, and the mass in vacuum (M) should be converted to the weight in air ({): 4.3.1 For volumetric measurement types, the weight of the oil in air is calculated according to the following 973
formula.
a, the calculation formula for correction based on the air buoyancy correction value is: m=(p2o-0.001)·Vzt
where: 0.0011——the air buoyancy correction value of the oil density (g/cm). b, the calculation formula for correction based on the air buoyancy correction coefficient is m=pn· Y2n·F
where: F——air buoyancy correction coefficient. Its value is obtained by referring to GB1885-80 Table IB "Conversion coefficient table of oil vacuum mass to air weight" according to the standard density of the oil.
If there is a dispute between the calculation results of the above formula (1) and (2), the calculation result of formula (2) shall prevail.
4.3.2 For the oil volume (Vt) and density (pt) measured under dynamic conditions by using a flow meter and a density meter in mass measurement type, after calculation by the item integrator, the mass (M) of the oil in vacuum can be directly obtained. The calculation formula to convert it to the weight in air (m) is: m=M·F
Where: F--air buoyancy correction coefficient. Its value is still based on GB1885-80 Table IB.
For long-distance pipeline continuous metering, when the oil density changes within a certain range, a fixed F value can be used.
4.4 Calculation of pure oil volume
For crude oil transfer metering, when calculating the oil volume, the water content in the crude oil is generally calculated according to the final volume.
4.4.1 The water content of the crude oil sample is determined by artificial testing or by a water analyzer. The calculation formula for its pure injection volume is as follows: t.=m (!-w)
Where: m.--pure crude oil weight;
--mixed crude oil weight
\--the weight percentage of water in the crude oil sample. 4.4.2 Use an online low water content analyzer and pure water integrator to match the flow meter density meter and mass integrator to directly obtain the crude oil mass and the mass of pure water in the crude oil. The calculation formula for the pure oil weight is as follows: mc=(M-Ms)·F
Formula: nc--pure oil mass of crude oil
M--crude oil mass obtained by the mass integrator; Mis--pure water mass obtained by the pure water integrator; F---air buoyancy correction coefficient, its value is still in Table B of GB1885-83.
5. Temperature and pressure correction
5.1 Correction range
When using a flow meter that uses a real liquid or a product with a viscosity similar to that of a real liquid component and is calibrated periodically, and the actual viscosity of the oil product is less than 10 centipoise, and the working temperature and pressure exceed the following range, the temperature and pressure should be corrected. 5.1.1 For flowmeters calibrated at the lowest temperature of the filter product under normal flow conditions, when the working temperature is higher than the calibration temperature, the difference exceeds 15°C.
5.1.2 For flowmeters calibrated at the lowest pressure that can ensure the flowmeter can be calibrated normally, when the working pressure is higher than the calibration pressure, the difference exceeds 10kgf/cm (98×10/Pa).
5.2 Correction method
The leakage error of the flowmeter caused by temperature is corrected by adjusting the error during flowmeter calibration. The measurement error caused by internal pressure is corrected by calculating the standard volume in oil volume calculation.
5.3 Calculation of temperature correction
For flowmeters calibrated at normal temperature, when the working temperature is 15°C higher than the calibration temperature, the error caused by the flowmeter adjustment is 0.05%. At this time, the influence of temperature should be corrected, and the correction formula is as follows: E=Et+βm(ti-ta)
Wherein: ——Instrument error during actual use at working temperature (%) + F:-~Instrument error at calibration temperature (%);
Et——Liquid temperature during calibration (℃);
t2—Liquid temperature during operation (℃);
βa——Volume expansion coefficient of flowmeter measuring cavity material (%/°C) 5.4 Calculation of Leli correction
The working pressure is higher than the pressure during flowmeter calibration, and the difference exceeds 10kgl/cm2 (98×10Pa). The measurement error caused by the reduction of the pressure surface of the measured liquid volume has reached 0.08. At this time, the influence of pressure should be corrected. The correction formula is as follows:
1-(Pr-P.) F,
Where: V-the volume actually flowing through the flowmeter corrected to the reference pressure; Vh——the volume measured by the flowmeter under the working pressure; P-base pressure (or calibration pressure);
Ph——the working pressure during measurement,
F, liquid petroleum compression coefficient.
The compression coefficient F of liquid petroleum, the value is in Table 1: API Standard 110: (USASZ1.1.170) "Liquid Petroleum Compression Coefficient Table" (the coefficients given in the table, add 0.0%30 before the number), or check the curve shown in Figure 2. 976
20 4G 6820F
2040608000
The method for calculating the compression coefficient FP is as follows: From the intersection of the API temperature of the liquid measured at F and the peak oil temperature curve of the measured liquid, the compression coefficient can be directly obtained from the intersection. If the temperature is not known, it can be approximated by the internal method of the two deviation curves. The compression coefficient is expressed as a percentage of the error of 11000/hour. When using the pressure correction formula, the compression coefficient value should be divided by 100,000
Figure 2 Average compression coefficient of roller body right side 877
Appendix A Terms and Terminology
(Supplement)
,1 Positive displacement flowmeter; When the flowing liquid enters the flowmeter, the measured cavity The rotating fixed volume space is continuously displaced, and the displaced part of the liquid body is counted, and the accumulated volume flow rate is indicated by the counter on the meter head.
A,2 Flow meter accuracy, within the range of the flow meter, the degree of closeness between the actual value of the flow meter and the true value or theoretical value. It is expressed in percentage. A.3 Comprehensive measurement error: It is determined by the accuracy of various measuring instruments that make up the metering system, and is determined based on the measurement errors of these instruments and expressed in percentage. It is also called metering system accuracy. A.4 Auxiliary equipment; equipment installed with the flow meter, such as degassers, filters, back pressure regulating valves, etc. These auxiliary equipment ensure the metering accuracy and normal use of the flow meter.
A.5 Degassers, for separating and eliminating oil from petroleum A device set up to remove gas (air or steam).
A.6 Filter: A device equipped with a metal filter mesh to remove solids in the fluid.
A.7 Back pressure regulating valve: An automatic regulating valve installed downstream of the flow meter to maintain a stable pressure in the flow meter pipe section.
A.8 Calibration: All work performed to evaluate the metrological performance of the measuring instrument and determine whether it meets the requirements of the calibration procedures. A.9 Actual liquid: The liquid measured by the flow meter is used as the calibration liquid for the calibration device. This calibration liquid is called actual liquid. 978
A.10 Dynamic metering: Continuously measure liquid petroleum in a flowing state.
A.11 Flow meter error refers to the indication value of the flow meter under working conditions. The error between the actual value during calibration. Expressed as a percentage. 4.12 Instrument error adjustment During calibration, by adjusting the instrument error adjuster of the volumetric flowmeter, the indicated value of the flowmeter is close to the actual value during calibration, which can ensure that the flowmeter reaches the specified accuracy.
A.13 API degree: A degree related to the relative density of oil products at 60/60°F specified by the American Petroleum Institute (API), which is a function of relative density. 97
Appendix B Technical requirements for installation of measuring instruments and standard devices (supplement)
B.1 The installation of flowmeters and their auxiliary equipment must comply with the technical requirements for instrument installation and process design requirements.
B.2 The vibrating tube density meter should be installed vertically, and its oil inlet pipeline should be low in and high out. The inlet of the density meter should be located on the pipe section between the flowmeter outlet and the cut-off valve at the flowmeter outlet, and the outlet of the density meter should be located on the outlet pipeline of the above-mentioned cut-off valve.
B.3 The crude oil low water content analyzer should be installed in parallel with the density meter, and a sampling valve should be installed on the oil pipe section below it.
B.4 For flow meters that need to be calibrated offline, the installation design should ensure that the flow rate is easy to disassemble, install and transport.
B.5 The metering and calibration system should be installed with valves that are reliable, well sealed and have small flow force.
B.6 All instruments that need to be calibrated, such as flow meters, density meters, water content analyzer display meters and mass calculation instruments, must be calibrated and qualified before they can be installed.
B.7 The metal shielded cable used for signal transmission between the transmitter and the display instrument of the metering instrument should be laid in a centralized manner as far as possible along the shortest route, and should be horizontal and vertical to avoid crossing. Signal cables shall not be laid in the same trench as power cables, and the two should be laid perpendicular to each other as much as possible.
B.8 The installation of instruments and lines should prevent mechanical damage, and avoid being affected by high temperature and humidity, corrosion, strong vibration, strong magnetic field and static interference. B.9 The installation of fixed standard volume tubes should meet the following requirements: a. The installation of standard volume tubes should have hangers and support frames to ensure that the tube body is fixed and not subject to vibration.
b. When installing the standard volume pipe, it should be horizontal and vertical to prevent the standard volume pipe from deformation and minimize the impact of the expansion and contraction of the pipeline on the standard volume pipe.
C. The installation position of the standard volume pipe should be close to the flow meter to be calibrated. The connecting pipe section between the two should be shortened as much as possible. The diameter of the pipe section shall not be less than the diameter of any flow meter to be tested.
d. When installing the connecting pipe section from the flow meter system to the standard volume pipe, it should be gradually tilted upward.
e. An exhaust valve should be installed at the highest point of the pipeline system and the top of the ball cylinder. A drain valve should be installed at the lowest point of the pipeline system. At the inlet and outlet of the standard volume pipe, a 0.4-level standard pressure gauge and a standard push thermometer with a minimum graduation value of 0.1"C should be installed. B.10 To determine the standard volume The standard volume of the reference pipe section of the pipe is generally equipped with a water calibration system consisting of a water pump, a water pool, a standard measuring instrument, etc. The requirements are as follows:
8. The vertical distance between the water pump and the water pool must be within the range of the suction height requirements allowed by the water pump:
b. The displacement of the water pump; it should be equal to or greater than the minimum displacement that can be calibrated by the standard volume pipe.
B.11 Measuring instruments and online standard devices must be installed after the process pipeline has been strictly cleared and the strength test has passed. The strength test of the process pipeline shall be carried out in accordance with relevant regulations. B.12 Newly installed or disassembled and reinstalled measuring instruments, standard devices and auxiliary equipment should be tested for air tightness before use. The air tightness test is carried out with compressed air, and the test pressure is ki/cm (58.8×10Pa), stabilize the pressure for 10 minutes, and the pressure does not drop to qualified 981
Appendix C Instructions for the use of the average compressibility coefficient table of liquid petroleum (reference)
The units of temperature, density, and pressure used in the API standard are different from the standard units used in my country. When using the average compressibility coefficient table of liquid petroleum in the API standard and performing pressure correction calculations, it is necessary to convert the unit system. C.1 Temperature conversion
Convert the Celsius temperature (°℃) used in the Chinese standard to the Fahrenheit temperature (°F) of the API standard. The conversion formula is as follows: F=x℃+2
C.2 Density conversion
Convert the standard density 02 used in my country to API degree. There are two conversion methods:
C.2.1 Calculation method
a. Convert the density value p2 at the standard temperature (20℃) to the density value p15.6 at 15.8°C (60°7).
p15.6=p2(15.6-20）
The value is the temperature coefficient of petroleum density. Check GB1885-80 Table V (Table of Temperature Coefficients of Petroleum Density).
b, convert p15. to API degree.
API degree=141.5
60/60°F
Pst/Ps15.
The density of water at 15.6°C ps.=0.904 g/cm. C.2.2 Table Lookup Method
First, check the conversion table of petroleum density at 20°C and density at 15°C in Table A of GB1885-80 standard, convert the density value at 20°C to the density value at 15°C
Then check Appendix 1 of GB1885-80 standard, and find the corresponding API
C.3 Pressure Conversion
The pressure unit of the average compression coefficient of liquid petroleum obtained by looking up a table or curve is lb/h. When calculating, it needs to be converted to the pressure unit used in my country: kgf/cm.
1 kgf/cm=14.22 lb/h\ or 1 lb/h*=0.07031 kgf/cmWww.bzxZ.net
C.4 Pressure Correction Calculation Example
Crude oil is transported through a pipeline and measured by a volumetric flowmeter. The daily oil output is 10,000m (standard volume at 20°C). The density of crude oil at 20°C is 0.8634g:cm, and the measurement temperature is 40\C. When the reference force (or pressure during flowmeter calibration) is 1kg f/cm, when the working pressure is higher than 1Ckgf/em\, calculate the actual loss after pressure correction.
C.4.1 Calculate the compressibility coefficient Fp value (by calculation method) &·Convert temperature:
F=x℃+32=×40+2=104(\F）
E·Convert density and calculate API degree: p15.-p+4.4g=0.8632+(4.4X0,00065）983
=0.86626（g/cm2）
API change
=31,69
c, calculate the compressibility coefficient of crude oil:
:31.5=141.5
According to The temperature and density obtained by the above conversion are found in Table 1 Liquid Petroleum Average Compression Coefficient Table》 and we get:
Fp=0.56x10-5(1b/in*)-1
d·Convert the pressure:
Fp=0.56x10-3(Ib/in)--
=0.56x10-5x(0.07031kgf/cm*)-=7.96X10-5(kgf/cm5)-
C.4.2 Calculate the actual volume of the flow meter after pressure correction c
i-（m-Pec)·Fp
1-(11-1)x7.96×10-5
=1007.97 (m))
Zhongpinxin
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