Manual of Petroleum Measurement Standards Chapter 5 Metering Section 6 Measurement of Liquid Hydrocarbons by Coriolis Meters 2018 WG ballot version March 2018 This document is not an API Standard; it is under consideration within an API technical committee but has not received all approvals required to become an API Standard. It shall not be reproduced or circulated or quoted, in whole or in part, outside of API committee activities except with the approval of the Chairman of the committee having jurisdiction and staff of the API Standards Dept. Copyright API. All rights reserved.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 2 Manual of Petroleum Measurement Standards Chapter 5 Metering Section 6 Measurement of Liquid Hydrocarbons by Coriolis Meters Measurement Coordination SECOND EDITION, MONTH 2016
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 3 FOREWORD This standard may involve hazardous materials, operations, and equipment. This standard does not purport to address all of the safety problems associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use. API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure the accuracy and reliability of the data contained in them; however, the Institute makes no representation, warranty, or guarantee in connection with this publication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use or for the violation of any federal, state, or municipal regulation with which this publication may conflict. Suggested revisions are invited and should be submitted to Measurement Coordination, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 4 Introduction API Boiler Plate.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 5 TABLE OF CONTENTS API Staff to compete
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 6 Chapter 5 Metering Section 6 Measurement of Liquid Hydrocarbons by Coriolis Meters 1 SCOPE This standard is intended to be a guide for the specification, installation, verification and operation of Coriolis meters used to dynamically measure liquid hydrocarbons. API MPMS Chapter 5.6 also includes information that will assist in troubleshooting and improving the performance of the meters. Use of a Coriolis meter as a stand-alone density meter is not addressed by the standard. 1.1 Field of Application The standard describes methods to achieve custody transfer measurement of liquid hydrocarbons quantities (mass or volume) using a Coriolis meter. Coriolis meters can provide outputs for mass flow rate, volumetric flow rate and density. Guidance for the measurement of density is found in API MPMS Chapter 9. This document provides guidance for the application, installation, proving, mass calculations, auditing, reporting and security requirements for Coriolis meters. Some of the guidance provided within also applies to allocation measurement. API MPMS Chapter 20, Allocation Measurement allows for different performance requirements. 2 NORMATIVE REFERENCES The following referenced documents are indispensable for the application of this document. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments) applies. API Manual of Petroleum Measurement Standards, (MPMS) Chapter 1, Vocabulary API MPMS, Chapter 4.8, Operation of Proving Systems API MPMS, Chapter 5.5, Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems API MPMS Chapter 6, (All Sections) Metering Systems API MPMS Chapter 9, (All Sections) Density Determination API MPMS Chapter 10, (All Sections) Sediment and Water
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 7 API MPMS, Chapter 12.2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods API MPMS Chapter 13.2, Statistical Methods of Evaluating Meter Proving Data API MPMS Chapter 9.4, Continuous/On-line Density Measurement and Applications API MPMS Chapter 20, (All Sections), Allocation Measurement of Oil and Natural Gas API MPMS Chapter 21.2, Flow Measurement Using Electronic Metering Systems API TR 2573, (ASTM D7829) Standard Guide for Sediment and Water Determination in Crude Oil 3 TERMS, DEFINITIONS, AND SYMBOLS 3.1 Terms and Definitions For the purpose of this document, the following definitions apply. Refer to API Manual of Petroleum Measurement Standards (MPMS) Chapter 1 for the definition of additional terms used in this standard. 3.1.1 calibration The process of utilizing a reference standard to determine a coefficient which adjusts the output of the Coriolis transmitter to bring it to a value which is within the specified accuracy tolerance of the meter over a specified flow range. This process is normally conducted by the manufacturer. 3.1.2 cavitation Phenomenon related to and following flashing if the pressure recovers and the vapor bubbles collapse (implode). 3.1.3 Mass (Coriolis), M The meter s indicated mass corrected with an applied meter factor and the flow pressure effect compensation factor; i.e. M = IM MF 3.1.4 Coriolis meter A Coriolis meter is a transmitter and a sensor.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 8 3.1.5 meter factor (Coriolis), mass or volume (MF, MFm, MFv) A dimensionless number obtained by dividing the actual quantity of fluid passed through the meter (as determined by proving), by the quantity registered by the meter. For subsequent metering operations, the actual quantity is determined by multiplying the indicated quantity by the meter factor. 3.1.6 transmitter (Coriolis) The electronics associated with a Coriolis meter which interpret the phase shift signal from the sensor, converts it to a meaningful mass flow rate (represented in engineering units), and generates an output signal representing mass flow rate and/or quantity. Manufacturers can also use it to drive the flow tube(s), determine fluid density, and calculate and output a volumetric flow rate. 3.1.7 sensor (Coriolis) A mechanical assembly consisting of: A. Housing: the means of providing environmental protection. This may or may not provide secondary containment. B. Measurement sensor (s): Sensors to monitor oscillations and to detect the effect of Coriolis forces. These are also referred to as pickups or pickoffs. C. Support structure: A means for supporting the vibrating conduit. D. Flow tube: Oscillating flow tubes(s) or channel through which the fluid to be measured flows. E. Vibrating drive system: The means for inducing the oscillation of the flow tubes. 3.1.8 indicated mass (Coriolis) IM The registered indicated mass quantity, i.e. closing reading minus opening reading; i.e. IM = (pulses or counts) / K-factor. 3.1.9 manufacturer density calibration factor A numerical factor that can be used to compensate for the density sensitivity of each Coriolis sensor. It is unique to the sensor and derived during sensor calibration. When programmed into the transmitter, the density calibration factor(s) causes the meter density measurement performance to meet its stated specifications. NOTE The manufacturer density calibration factor should not be confused with Density Meter Factor (DMF). 3.1.10 manufacturer flow calibration factor A numerical factor that can be used to compensate for the flow sensitivity of each Coriolis sensor. It is unique to the sensor and derived during sensor calibration. When
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 9 programmed into the transmitter, the flow calibration factor(s) causes the meter flow rate measurement performance to meet its stated specifications. NOTE The Manufacturer Flow Calibration Factor should not be confused with K- factor or Meter Factor (MF). 3.1.11 net mass; NM The Mass (M) of the fluid without Sediment and Water (S&W). NM = M CSW M. 3.1.11 pressure drop (pressure loss) The difference between upstream and downstream pressures due to the frictional and inertial losses associated with fluid motion in the entrance, exit, and internal passages of the flowmeter or other specified systems and equipment. 3.1.12 sediment and water mass: SWM The mass of Sediment and Water during a measurement period. (SWM = M NM) 3.1.13 zeroing A procedure that sets the stored zero value. NOTE The zeroing operation should not be confused with resetting the totalizer. 3.1.14 zero offset, observed The difference between the current observed zero value and the previous observed zero value. 3.1.15 zero stability The variability of the observed zero value during the process of determining the value. NOTE This is a systematic uncertainty, which can be present over the working range of the meter. 3.1.16 zero value, observed The average mass or volume flow rate observed reading under zero (no) flow conditions, without inhibited flow indications (i.e., low-flow cutoff disabled and bidirectional flow enabled). 3.1.17 zero error The observed zero value expressed as a percentage of normal flow rate.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 10 3.1.18 zero value, stored The value within the transmitter representing a no flow condition. 3.1.19 zero verification The process of determining if the observed zero value is within the operator s zero error limit (a tolerance). 3.1.20 zero value, as-found The observed zero value before a meter is zeroed. 3.1.21 zero value, as-left The observed zero value after a meter has been zeroed. 3.2 Acronyms and Symbols (To be updated upon completion of document) IM m = indicated Coriolis meter mass KF m = K-factor in units of pulses per unit mass MF m = meter factor when the Coriolis meter is configured to indicate mass 4 GENERAL A Coriolis meter consists of a sensor and a transmitter. A sensor has one or more flow tubes through which the fluid flows. The flow tube or tubes are made to vibrate at their natural or harmonic frequencies by means of an electromagnetic driving mechanism. The fluid flowing through the tube(s) generates a Coriolis force that is directly proportional to the mass flow rate of the fluid. The magnitude of the Coriolis force is measured and used to determine a mass flow rate. The transmitter powers the sensor, processes the output from the sensor in response to mass flow, and generates signals for the tertiary device(s). The frequency of the oscillating flow tube(s) can be measured and used to determine the density of the fluid. Density determination is independent of the mass flow rate determination. A meter typically can determine a volumetric flow rate through calculation by dividing the mass flow rate with either the measured flowing density or a user programmed (fixed) density.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 11 5 APPLICATION 5.1 Sensor Considerations Sensors should be selected to measure flow rate over the full operating flow range. Consider the effect of the following issues on the sensor to ensure it meets all requirements. 5.1.1 Flow Tube Design Flow tube(s) restrict the cross-sectional flow area resulting in higher fluid velocity and pressure drop than experienced in the associated piping. The pressure drop (pressure loss) depends on the sensor design along with the viscosity and density of the fluid and the desired flow rate. Higher fluid velocities, when coupled with abrasive particles in the stream, can cause flow tube(s) erosion and measurement error. Select the sensor to provide required accuracy within the allowable system pressure drop constraints while avoiding erosion. Consult the manufacturer for sensor limitations and methods to calculate velocity and pressure drop. Avoid cavitation or flashing in the meter and the prover. Cavitation will cause a measurement error and can damage the sensor. Equation B-1 in Annex B provides a guideline to maintain sufficient pressure downstream of the meter and the prover. A provision for adequate draining, vapor elimination, and cleaning should be considered based upon the fluid characteristics and sensor design. Sensors should be installed to avoid trapping vapors, particulates, or liquids heavier than the process liquid. Different flow tube geometry can be more or less likely to promote the accumulation of sediments or coatings within the tube(s). Besides restricting flow, the accumulation of material within the flow tube(s) can affect the observed zero, and the accuracy of the density and volume measurements. The user should ensure that the flow tube material is compatible with operating conditions and fluid properties including any corrosiveness or abrasiveness characteristics. 5.1.2 Accuracy Sensors have different accuracy specifications and sensitivities with regard to changes in ambient and operating conditions. Consult the manufacturer for the performance envelope describing error limits throughout these conditions and consider the limits with respect to the system requirements. To address the effects of process pressure and temperature on the accuracy of the measurement of mass, density and the corresponding determination of volume:
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 12 Temperature effect compensation for the flow tube(s) stiffness shall be integral to the meter and performed real time in the meter. Pressure effect compensation for flow tube(s) stiffness is recommended for all applications, but is required when the effect is biasing quantity determination by more than 0.05%. Generalized equations are for evaluation of the effect are provided in Annex D. Note: This pressure effect compensation is not the correction for compressibility of liquid (CPL). Pressure effect on flow tube stiffness can also affect density determination and its use to volume calculations (e.g. CTL, CPL, CTPL). Refer to API MPMS Chapter 9, Density Determination. Real-time pressure compensation is preferred and can be accomplished by: o Activating the pressure effect compensation mode in the transmitter (if available) and using a live pressure input (analog or digital communication) to continuously adjust for pressure change. Pressure values should be shared between the transmitter and tertiary device for audit purposes. Or, o Activating the pressure effect compensation mode in the transmitter and using a live pressure measurement integral to the sensor. Pressure values should be shared between the transmitter and tertiary device for audit purposes. This integral pressure value may not be suitable for other calculations requiring a pressure value. Or, o Calculating the pressure compensation in a tertiary device. See Annex D for details. In lieu of real-time compensation, pressure compensation is turned off in the transmitter and: o Prove the meter close enough to the average operating pressure to satisfy equation D. 2 in Annex D (while not affecting flow rate enough to affect meter performance), or; o Correct the ticket external to the metering system (See Annex D and E). Activating the pressure compensation in the transmitter with a fixed pressure shall not be allowed. Any change in pressure compensation values or implementation of pressure compensation requires proving. Reprogramming the transmitter after proving is not allowed. (Reference Section 7.2.7) In both mass and volume measurement applications, this standard requires documentation of flow tube pressure effect compensation in accordance to Annex D.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 13 5.1.3 Flow Tube Pressure Rating Flow tube(s) and end connections shall meet the pressure code requirement for the service. The external housing around the flow tube(s) is designed to protect the sensor electronics and is not designed to meet the same pressure ratings as the flow tube(s). 5.1.4 Documentation Meter manufacturers provide calibration certificates. Other documentation for the meter such as electrical area classification certification, hydrostatic test report, material test reports can be provided. 5.1.5 Bidirectional Flow These meters are capable of bidirectional flow. If bidirectional flow is required, ensure that the transmitter and the flow computer are both capable of bidirectional flow. If the meter is used to measure bidirectional flow, a meter factor shall be developed for each flow direction. 5.1.6 Pressure Containment and Relief Optional sensor features can be provided by the manufacturer to reduce the effect of flow tube failure. Items to consider: Sensor housings constructed as a pressure-containing vessel, designed to contain fluid under pressure to a specified pressure limit. Rupture disks, pressure relief valves and drains, or vents on the sensor housing, designed to relieve pressure or allow fluids release from inside the sensor housing. 5.1.7 Crosstalk With multiple sensors in close proximity, either in parallel or series, the vibrations generated by each sensor could interfere (crosstalk) with each other, thereby causing measurement error. Vibration isolation or dampening can be achieved by altering piping or supports. Consult the manufacturer to reduce the possibility of crosstalk. 5.2 Transmitter Considerations 5.2.1 Environmental Evaluate the temperature, humidity and corrosion extremes at the installation for appropriate protection. 5.2.2 Electrical Select the transmitter and sensor to meet the required electrical area classification. Consider the power requirements for the sensor and transmitter. Design the electrical signal system to provide appropriate fidelity and security. (Reference API Chapter 5.5)
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 14 The sensor, transmitter, and their interconnecting cables are all susceptible to Electromagnetic Interference (EMI). Since the electrical signals of the meter are at relatively low power levels, care should be taken to avoid interference generated from nearby electrical equipment and wiring. 5.2.3 Operability Considerations Mount the transmitter such that it can be easily accessed to attach communications equipment, to view displays, and to use associated keypads. The meter pulse output signal is from the transmitter, not from the sensor. For applications using portable provers, install the transmitter as close as practical to the proving computer location. This facilitates connecting pulse signal to the prover. Consideration should be given for access to and operation of the meter. Items to consider are: Programing or configuring method,(keypad, hand-held tool or laptop) Local display if required Ease of electrical connections Ease of zeroing and programing changes 5.2.4 Frequency Output to Tertiary Devices Sensors do not, by the nature of their operation, have a pulse output representing either mass or volume. The transmitter performs internal calculations to determine a flow rate and generates a user defined frequency to represent flow rate. The exact relationship between frequency and flow rate is typically configured by the user. Alternately, some versions of these meters allow the user to enter a K-factor. When the K-factor is entered, the frequency value and flow rate value are typically calculated in the transmitter. To estimate a K-factor from frequency and a flow rate (pulse scaling factor) use Equation 1 below. User defined frequency / User defined flow rate = K-factor (Equation 1) Example: 1000 Hertz / 10 barrels/second = 100 pulses/barrel 1000 Hertz / 1000 pounds/second = 1 pulse/pound 1000 Hertz / 16.667 pounds/second = 60 pulses/pound (approximately) Care should be taken when selecting the values to ensure that the following two conditions are satisfied: When fluid is flowing through the meter at maximum specified flow rate the frequency output by the transmitter should not exceed 90 % of the maximum input frequency of the tertiary device(s) receiving the pulse signal.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 15 When fluid is flowing through the meter at minimum specified flow rate the frequency output by the transmitter should be high enough to produce sufficient pulse resolution to provide the appropriate flow rate and quantity indications, especially for proving. 5.2.5 Low Flow Cut-off Low-flow or no flow cut-offs can be programmed in the transmitter or the tertiary device. These values inhibit flow totalization for very low flow or true no flow conditions that can occur. 5.3 System Design Considerations Coriolis meter based measurement system design considerations for custody transfer metering can be found in Annex C and API MPMS Chapter 6. 6 Installation and Operation 6.1 Mounting Follow the manufacturer recommendations for the proper mounting of the sensor. Consideration should be given to the support of the sensor, the alignment of the inlet and outlet flanges with the sensor, and the orientation of the sensor. Piping should be supported or anchored to avoid transferring stresses from the piping to the sensor. Meter performance, specifically observed zero offset, can be adversely affected by axial bending and torsional stresses from pressure, weight, and thermal effects. These stresses and associated loads can be minimized by utilizing properly aligned pipe and well-designed pipe supports. During the system construction phase, a pipe spool piece equal in length to the meter, should be used in place of the meter to correctly align pipework. Sensor orientation depends on the application and the geometry of the flow tube(s) and should be recommended by the manufacturer. For example, solids settlement, plugging, coating, or trapped gas can affect the meter performance. 6.2 Installation Conditions There are several considerations for installing a Coriolis meter: Vibration Meters are designed to withstand vibration in pipeline installations, but vibration near the frequency of the sensor (or one of its harmonics) can affect the accuracy of the meter. The sensor should be installed as far as possible from vibration sources such as pumps,
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 16 compressors, and motors. The manufacturer can advise on vibration mitigation methods. Multiple sensor vibration interference (crosstalk) Sensors of the same size and model operate at similar frequencies and can transmit vibrational energy to adjacent meters. This can cause measurement errors (see 5.1.7). Pulsating flow Hydraulic pulsation, especially near the operating frequency of the sensor (or one of its harmonics) can affect the measurement of the meter. If this condition exists, pulsation dampeners can be helpful. Mechanical stress The sensor is susceptible to axial, radial, and torsional stresses caused by the piping installation (see 6.1). Non-uniform velocity profile or swirl Testing on several meter designs has indicated that non-uniform velocity profile, including swirl, has little or no effect on meter performance. This might not hold true for all meter designs. Electromagnetic and radio frequency interference Strong magnetic fields could affect the electromagnetic signals from the sensor. The meter sensor and electronics should not be installed near radio frequency or electromagnetic interference sources such as variable frequency motors, transformers, radio transmitters, large switchgear, or high voltage cables. Cable(s) that connect the sensor and transmitter should not be installed near high voltage power cables or sources of EMI and RFI noise. Voltage regulation Install power line conditioning if the power to the electronics is not clean. 6.3 Meter Commissioning 6.3.1 Fill To avoid damage to the sensor, a pipe spool should be installed in place of the meter each time new piping or fluids are introduced into the piping system that can contain deleterious materials from construction or maintenance activities. Avoid cavitation, flashing, and fluid hammer when filling to prevent damage to the sensor. Avoid shock loading caused by rapid opening or closing of valves. 6.3.2 Initial Zero Verification As part of the commissioning and prior to performing the initial zero verification, flow should be established through the sensor until normal operating conditions are achieved. While maintaining normal operating conditions, a procedure shall be followed to verify and record the observed zero value. In order to verify the observed zero value there shall be no flow through the sensor. See Annex A for a zero value verification and evaluation procedure. An improperly zeroed meter or a shift in observed zero value can result in measurement bias. A zero shift is usually caused by variations in temperature, pressure or density, or changes in the mounting conditions as a result of poor installation practices. The bias is a constant offset in flow rate. Thus, this constant offset will result in a percent error that increases as the flow rate decreases.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 17 The observed zero value in real time will not normally be a constant value. Small variations are expected and a properly zeroed meter will fluctuate between positive and negative flow rate values within the specified zero stability of the meter. 6.4 Conditions Affecting Meter Performance Performance can be affected by conditions that change the flexibility of the oscillating flow tube(s), as well as, fluid properties, operating conditions, and installation conditions. If there are changes in those properties or operating conditions, or there is an alteration to the sensor installation, a change in meter factor can result. Flow rate o Fluid velocity can affect the density measurement. When the volumetric flow rate is determined from meter s measured density, higher velocities can produce measurement errors, with the error increasing as the velocity increases. Manufacturers can compensate for this effect in the transmitter. o As the flow rate approaches no flow meter factor variation increases due to the zero offset (a measurement bias primarily affecting the lower range of the meter) and zero stability. See Figure 1 and 2. Fluid temperature Changes in fluid temperature affect the elasticity of the oscillating flow tube(s). The effect of temperature is systematic and is characterized and compensated for in the transmitter to minimize its influence on the performance of the meter. The magnitude of this effect depends on meter size, flow tube material, geometry and amount of temperature change. Fluid temperature changes within the sensor and connecting piping can create piping stresses which can change the observed zero value. Fluid pressure Changes in pressure affect the vibrational characteristics of the flow tube(s). The effect of pressure is systematic, affecting both mass flow and density measurements. The effect can be characterized and compensated for to minimize its influence on the performance of the meter. The magnitude of this effect depends on meter size, design, and amount of pressure change. Pressure sensitivity tends to increase with sensor size. For installations not using live pressure compensation, any pressure effect bias will be minimized by operating within a narrow range of the proving pressure. Consult the manufacturer for the effects of pressure on their sensor and reference Section 5.1.2.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 18 Two-phase liquids Gas, vapor, or air in a liquid stream is detrimental to accurate measurement. Two-phase liquids are unacceptable for custody transfer measurement applications. Flashing or cavitation within the sensor Flow tube geometries and sensor designs can create a pressure area within the sensor which is lower than the outlet pressure. Sufficient backpressure shall be maintained on the sensor and prover to prevent flashing or cavitation in the sensor or prover (Reference Annex C). Coatings or deposits in the flow tube(s) Heavy or non-uniform coating of the flow tube can cause a shift in the meter factor and the density as well as linearity and meter performance. Volume meter factors are impacted more than mass meter factors. Erosion of the flow tube Abrasive solids can reduce the flow tube thickness, which in severe cases can lead to meter and density factor shifts and sensor tube failure. Volume meter factors are impacted more than mass meter factors. Corrosion of the sensor Flow tube material compatibility with the fluid is essential for reliable service. Density Changes in fluid density can affect volume measurement and could require a new volume proving of the meter. Viscosity Change in the fluid viscosity can affect meter performance and meter factors and at some point can require proving of the meter to minimize the effect. Some meters can compensate for the changes in viscosity. The manufacturer recommendation for viscosity compensation should be followed. Additionally, boundary layer thickening inside the tube caused by increasing viscosity, affects operating flow range of the meter.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 19 Figure 1 Impact of Zero Error on Meter Factor Figure 2 Impact of Zero Stability on Repeatability versus Flow Rate
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 20 6.5 Maintenance 6.5.1 Sensor Repair or Replacement Following repair or replacement of the sensor, ensure that the correct manufacturer calibration factors are entered into the transmitter to match the unique characteristics of that sensor. The calibration factors will be provided by the manufacturer. An initial zero verification (See Annex A) and proving shall be accomplished after installation of a repaired or replacement sensor. 6.5.2 Transmitter Repair or Replacement After repair or replacement, ensure that the correct manufacturer calibration and K- factors are entered into the transmitter. Replacement of circuit boards or the transmitter can affect the meter and density indications and meter factors. An initial zero verification (See Annex A) and proving shall be accomplished after any repair or replacement of a transmitter. 7 PROVING 7.1 General This section addresses proving issues related specifically to Coriolis meters. Detailed requirements for operations of provers and meter factor determination requirements are provided in API MPMS Ch. 4.8. Coriolis meters are unique in that they can be used to indicate in either mass or volume. A meter is calibrated by the manufacturer to determine one or more calibration factors that are entered into the transmitter. These factors, although adjustable, should remain unchanged. A proving shall be accomplished after changes to any calibration factors within the transmitter. 7.2 Proving Considerations 7.2.1 Conditions Proving conditions should be as close to the actual metering conditions as practical. See API MPMS Ch. 4.8 for additional details. The meter should be proved on a similar fluid and under similar operating and installation conditions as encountered in normal operations. If operating or installation conditions change, the meter should be proved under the new condition as soon as practical.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 21 7.2.2 Density Density stability is critical during proving for either mass or volume outputs. For proving calculations, it is important to distinguish between flowing, observed, and base density, how each is determined, and when and where each are applied to a proving. There are various ways to determine density. Density measurements can be made online or off-line via a representative sample as recommended in API MPMS Ch. 9. Density method determination can be calculated from fluid composition, published equations or be contractually controlled. The appropriate API physical property standards should be referenced for more information on density determination and calculation. Record density values as recommended in API MPMS Ch. 12.2 and Annex F (mass calculation). 7.2.3 Evaluation of Meter Proving Data 7.2.3.1 Number of Runs for a Proving The random uncertainty of the proving results is the primary criteria for an acceptable proving. The Coriolis meter is a computational meter and might require more runs than a displacement or turbine meter to obtain the requisite uncertainty. See API MPMS Ch. 4.8 for additional details. 7.2.3.2 Contributors to Increased Random Uncertainty The following will lead to increased random uncertainty: o Proof duration too short o Cavitation or void fraction in the fluid o Noise or vibration at frequencies that affect the sensor o Zero instability, especially at low flow rates o Flow or density instability o Excessive time delay between the measured flow and manufactured flow pulses (See API MPMS Ch. 4.8) o Excessive flow velocity o Installation issues (varying pipe stress, poor wiring) 7.2.4 Reproducibility Meter factor reproducibility is the ability of a meter to generate results over a period of time where the range of variation of (change in) pressure, temperature, flow rate, and physical properties of the liquid is negligibly small. The expected reproducibility should be determined by the operating company based on financial risk and experience with each individual meter and proving system or meter linearity. For inferred mass proving, where density is to be determined at the prover, the random uncertainty and reproducibility of the mass meter factor is affected by meter performance, the method of prover density determination, the number of density
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 22 samples or readings taken, and the density meter proving. Assessment of the mass meter factor should include evaluating the prover density uncertainty. See MPMS Chapter 4.8 for additional information. Determining acceptable meter factor reproducibility is an operating company responsibility. When the reproducibility of a meter factor is outside the operating company tolerances, the meter zero (observed zero value) needs to be verified. See Annex A for zero verification procedures. Needless zeroing should be avoided in order to minimize potential errors associated with meter factor reproducibility. Industry practice is to allow a greater combined reproducibility tolerance for inferred mass measurement systems which use volume (e.g., turbine) and density meters. The reproducibility for these systems is the sum of the actual meter reproducibility of the volume meter and density meter. Thus the two meters factors can cancel out each other or produce a larger reproducibility tolerance (larger MF shift). This greater tolerance should be extended to Coriolis meters that are proved by inferred mass method. Common practice for custody transfer applications is to accept new meter factors within 0.10 % to 0.50 % of the previous meter factor. Action and tolerance limits will be defined individually by each operating company. Guidance on action and tolerance limits is provided in API MPMS Chapter 13.2. Reasons for Non-reproducibility Transmitter configuration should be reviewed when unexpected variations in meter factor occur to confirm that any value or factor (Calibration Factors, K-factor) that impacts flow indication or output have not been changed since the last prove. See Section 8. Other reasons for lack of reproducibility: o Zero offset (shift) from previous proving o Change in operating pressure from the previous proving when pressure compensation is not active in the transmitter or proving pressure is different. See Annex D. o Choice of prover density determination for inferred mass proving and its sampling frequency (the number of samples taken). o Changes in fluid density. 7.2.4.1 When to Zero When the reproducibility of a meter factor is outside the operating company tolerances, the observed zero value should be verified. See Annex A for zero verification procedures. Zeroing of the meter shall not occur without first verifying and then recording the observed zero value. A proving shall always follow any zeroing procedure. The need for zeroing the meter will depend on the normal operating flow rate of the meter. When the observed zero value is very small, it has minimal effect on meter performance at the maximum rated flow rate of the meter. The influence of the observed zero value becomes more significant at lower flow rates as illustrated by the meter
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 23 performance specification shown in Figure 1. In general, the error associated with the observed zero value can be determined from equation A-1 in Annex A. If the zero error is outside the tolerance and then the meter is zeroed, the meter shall be proved after zeroing. If the meter reproducibility continues to change over time, from proof to proof, the observed zero can be influenced (changing) for various reasons including: Sensor installation conditions (e.g., upstream piping configuration, vibration, pulsation) Pipeline stress (e.g., as induced by ambient temperature changes or maintenance on adjacent equipment) Changes in fluid conditions that affect the meter (temperature, pressure and density) 7.2.5 Frequency of Proving In addition to the initial field proving, periodic proves are necessary to confirm or reestablish the performance of the meter. Proves should be performed per API MPMS. 4.8. Prove the meter any time the meter is zeroed or when any changes have been made in the transmitter that impact flow indication or output. 7.2.6 Proving Methods 7.2.6.1 General The methodologies used to prove a Coriolis meter are direct mass, inferred mass, and volumetric. These methodologies differ significantly in the way they determine the reference quantity of fluid (prover quantity) for a proving. The reference quantity should match the engineering units of the meter s output. See API MPMS Ch. 4.8 for details of the approved proving methods. 7.2.6.2 In-situ Proving (field) In-situ proving, under actual operating conditions, provides the preferred means of establishing meter factors. 7.2.6.3 Laboratory Proving Laboratory proving in place of field proving is not recommended for custody applications. This method leads to greater measurement uncertainties than field proving. Due to the inability to prove after zeroing, measurement uncertainties can increase. The increase can result from the fact that it is impractical to duplicate the mechanical stresses of a field installation in a lab proving. The difference in the observed zero value in the laboratory and the observed zero value at the field location should be within a tolerance that is acceptable to the operator. 7.2.7 Application of the Meter Factor The result of a meter proving will be a new meter factor. All meter factors (MFm, MFv, DMF) shall only be applied in devices that are compliant with API MPMS Ch. 21
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 24 Application of a meter factor in a transmitter that will change the pulse output is not allowed. No factors or values (meter factor, calibration, or configuration factors) that affect the pulse output or indicated quantity shall be changed in the transmitter after proving. When it is necessary to change calibration or configuration factors or perform maintenance on the meter, perform a prove to check for changes in meter factor. Reference Chapter 4.8. 8 AUDITING, REPORTING AND SECURITY REQUIREMENTS FOR CORIOLIS MEASUREMENT API MPMS Ch. 21 (two sections) address auditing and reporting requirements for Electronic Liquid Measurement (ELM) systems. The audit requirements for quantity (volume or mass) transactions using a Coriolis meter are similar. Configuration and setup parameters factors contained in the transmitter and tertiary devices shall be recorded in these logs and records. This information in the transmitter shall be auditable and secured in the transmitter. 8.1 Configuration Log See API MPMS Ch. 21 Electronic Liquid Measurement (two sections) for the general contents of a Configuration Log. The intent of a configuration log in Chapter 21.2 applies to a Coriolis meter, its measurement as well as the tertiary device. Additional information provided below and in Annex F shall be part of any audit package. Manufacturer Density Calibration Factor(s), Manufacturer Flow Calibration Factor(s), Pressure effect coefficient on the flow tube(s) in percent of flow ( ). 8.2 Quantity Transaction Record (QTR) See API MPMS Chapter 21.2, Electronic Liquid Measurement (two sections) for the requirements of a Quantity Transaction Record. These requirements vary based upon the quantity type recorded. For volume and inferred mass measurement all requirements of Chapter 21.2 apply. Additional requirements for mass measurement can be found in Annex F. Additional requirements common to any quantity type and specific to Coriolis meters are: PECI (Pressure Effect Compensation Indicator status) (Flowing gauge pressure when PECI equals 2 (TD), Flow-weighted average gauge pressure when PECI equals 3 (OS) ) (Calibration or average meter proving static gauge pressure) (Pressure Effect Compensation Facto).
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 25 8.3 Event Log for Coriolis meters See API MPMS Ch. 21 Electronic Liquid Measurement (two sections) for Event Log requirements. Event logs record exceptions and changes to any parameter or data in the transmitter and tertiary devices. An Event log shall be recorded and provide in an audit package for Coriolis meters. In addition to the items above, the event of zeroing of the Coriolis meter shall be recorded, including the date and time the meter was zeroed, along with the as-found and as-left observed zero value in flow indication units (i.e. BPH, GPM). Each zero value has a corresponding meter factor associated with it. Recording some indication of zero stability is also recommended. 8.4 Alarm and Error Log Alarm and Error Logs shall be recorded and provide as part of audit packages for sensors, their transmitter and tertiary devices. See API MPMS Ch. 21 Electronic Liquid Measurement for guidance on alarm logs. 8.5 Security and Access Transmitters shall be secured against tampering or unauthorized or un-documented changes to any variable or parameter that can alter the flow or density measurement. This can be achieved by several methods including passwords or tamper evident seals or locks. See API MPMS Ch. 21.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 26 ANNEX A (Normative) Zero Verification A.1 ZERO VERIFICATION PROCEDURE As a part of the meter proving process or when meter factors shift beyond an operator tolerance, observe the zero value and record it for evaluation. This observed zero value should be determined at the same conditions under which the meter factor was determined. The need to zero initially or at any time is based on the operator tolerance for the amount a zero value or shift should be contributing to meter factor errors or shifts. Initially, a meter shall be installed and brought to line or process conditions prior to evaluating the zero value. Failure to properly purge the sensor prior to evaluating the zero can lead to an incorrect evaluation. Once the sensor is at operating conditions, observe and record the flow rate, safely block in the sensor, observe and record the zero value. Use equation A-1 to estimate the percent shift in the meter factor that can be contributed by the zero value. q Err 0 0 = ---- 100 q f (A-1) where Err 0 = zero error (%) q 0 = observed zero value = flow rate during normal operation q f To determine if the meter needs to be zeroed evaluate if the value of Err 0 of equation A- 1 is within operator s tolerance (e.g. 0.04 %). If the value is not in tolerance a new zero is required. In the case of the initial verification (startup verification) the recorded zero value (as found) is expected to be zero. The meter shall be proved after the meter has been zeroed. After performing a zero operation, the new observed zero value (as left, current) should be compared to the recorded zero value (as found, previous). Equation A-2 can be used to determine the amount of shift in the meter factor relative to the difference in as found and as left zero values.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 27 % Flow Error = ((ZV NEW ZV) / FR) 100 (A-2) where ZV ZV NEW FR = the recorded zero value at meter factor determination ( as found recorded after the last proving) = the current observed zero value = actual flow rate of the line meter If an observed zero value cannot be obtained within an acceptable tolerance an investigation into the cause should occur. Zero Verification Steps In order to verify the observed zero value of the meter, there shall be no flow through the sensor. The sensor shall be filled with the liquid to be measured at normal operating conditions. The procedure to verify the zero value is as follows: 1. Open bypass valve if so equipped. 2. Stop flow through the sensor by closing the downstream double block-andbleed valve and ensure seal integrity. 3. Close upstream valve if provided. CAUTION: Isolating a fluid-filled system (blocking it in) can result in elevated pressures if the temperature rises. 4. If a threshold is set in the meter to suppress the indication (low-flow cutoff, bidirectional flow), then this value should be set to zero during this procedure. Some transmitters allow the user to view the actual flow rate independently of the low-flow cutoff setting. 5. The observed zero value will not normally be constant. Small variations are expected and a properly zeroed meter will fluctuate between positive and negative flow rates within the specified zero stability for that meter. Installation conditions that could be the cause of zero instability include: leaking valves two-phase fluid (gas breakout) external vibrations at interfering frequencies 6. After following the zero verification procedure:
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 28 If the observed zero value is found to be outside the operator expectation for error (see Equation A-1) evaluate the installation for the conditions listed in Section 6.4 and the following: possible pipe stress leaking valves extreme temperature changes of the product while zeroing transmitter improperly programmed for the sensor If the observed zero value is found to be within the operating company expectation for error, reset the low-flow cutoff to original settings. Examples of how to determine acceptable observed zero value reference Section A.2. A log or graph should be maintained of all meter factors and zero adjustments (observed zero values as found and as left) so that trending of the meter performance can be conducted per API MPMS Ch. 13.2. A.2 ZERO VERIFICATION EXAMPLES The following are informative examples of how to evaluate zero values in order to determine if the meter needs to be zeroed. Normally, a zero shift can be resolved by properly installing the meter, purging the line and bringing the meter to line conditions. Reproving the meter alone may not resolve a zero shift problem (error) when the meter requires maintenance, repair or the flow will deviate significantly from the current proving flow rate. If the flow rate at operating conditions is 10 % below maximum meter range, the operator zero tolerance may need to be increased to accommodate zero stability or poor stability. Examples are below. A.2.1 Example 1: Zeroing NOT required on initial installation A new meter has been installed. There is no initial observed zero value for this installation, since it is a new meter. The assumed value for ZV would be zero (as found). The new meter was brought to operating conditions and the observed zero value of the meter at the current conditions was +0.7 lb/min. The difference in the current zero value from the factory (0, as found)) is 0.7 lb/min. The expected flow rate of the line meter is 6005 lb/min, then: Flow Error 0.01 % = ((0.7 0) / 6005) 100 The meter would not require zeroing because this observed zero value could only contribute 0.0001 bias in meter factor if or when proved at 6005 lb/min flow rate.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 29 A.2.2 Example 2: Zeroing required A meter was initially proved at a flow rate of 5000 lb/min with a +2.5 lb/min zero value (as found). A meter factor of 0.9995 was generated. At the next proving the meter factor was 0.9968. The observed zero value of the meter after the proving and at the current conditions was +17 lb/min. The difference in the current observed and the recorded zero value (as found) is 14.5 lb/min. If the line meter is flowing at 5005 lb/min, then: Flow Error 0.29 % = ((17 2.5) / 5005) 100 The meter should be zeroed because this zero shift could be the cause of the 0.0027 meter factor shift. After zeroing the new observed zero value should be recorded and flow error calculated based on the same equation. Prove the meter after zeroing and the new meter factor should be close to the original meter factor of 0.9998 when the zero value was +2.5 lb/min. A new observed zero value should be obtained after the prove and it becomes the as found zero value for the new meter factor. A.2.3 Example 3: Zeroing NOT required A meter was initially proved at a flow rate of 7000 lb/min with a +2.5 lb/min zero value (as found), and a meter factor of 0.9997 was generated. At the next proving the meter factor was 0.9990. Typically, no action would be taken since the meter factor only shifted 0.0007. If the observed zero value was determined to be +3.5 lb/min., the difference to the recorded zero value (as found) is 1 lb/min. If the flow rate for this proving was 7700 lb/min, then meter does not need to be zeroed because this zero shift would only contribute to a 0.0001 shift in the meter factor. 0.012 % = ((3.5 2.5) / 7700) 100 A.2.4 Example 4: Meter repair and proving could be required A meter was initially proved at a flow rate of 6000 BPH with a +2.5 BPH zero value (as found). The meter factor of 0.9996 was generated. At the next proving the meter factor was 0.9958. The observed zero value of the meter after the proving and at the current conditions was +25 BPH. The difference in the current observed zero and the recorded zero value (as found) is 22.5 BPH. If the flow rate for this proving was 6006 BPH, then; 0.37 % = ((25 2.5) / 6006) 100
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 30 The meter should be zeroed. After zeroing a new observed zero value was 20 BHP. This zero value will contribute to a 0.0029 meter factor from the 0.9996. 0.29 % = ((20 2.5) / 6006) 100 An investigation should occur to resolve the reason that an acceptable zero value could not be obtained (it should be close to 2.5 BPH). A new proving with the 20 BPH should generate a meter factor near 0.9971. The new proving will only correct for this high zero value at this flow rate. This zero value will contribute to more significant meter factor shifts when the meter is operated at flow rates lower than 6,000 BPH. See next two examples. A.2.5 Example 5: Zero Error contribution to meter factor linearity A meter was initially proved at several flow rates to determine a meter factor curve with a +2.5 BPH zero value (as found). The observed zero value of the meter at the next verification was 7.5 BPH. The difference in the observed zero and the as found value is 5 BPH. If the meter is proved again at the same rates to verify the MF curve without zeroing, equation A-2 can be used to estimate meter factor shift at any flow rate over the range of the meter. See the table below. Flow Rate (BPH) 6006 5005 3754 2503 1251 Zero at Proving (ZV) 2.5 2.5 2.5 2.5 2.5 Observed Zero (ZVnew) 7.5 7.5 7.5 7.5 7.5 Expected % MF Shift 0.08 0.1 0.13 0.2 0.4
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 31 A.2.6 Example 6: Zero contribution on meter factor linearity (graphically) A meter was proved at 5 flow rates to establish a linearity curve. The as found zero was 2 lb/min. Figure A-1 Meter Factor Curve as found Zero The meter was zeroed and the observed zero was 0.25 lb/min. The meter was proven again at similar rates to establish new meter factor linearity. The 0.25 lb/min observed zero value would be the new value for the old curve above and becomes the as found value for the new meter factor curve. Figure A-2 Meter Factor Curve as left 0.25 lb/min zero
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 32 Equation A-2 can be used to estimate and validate the shift in the linearity curve. Figure A-3 Estimated Zero Change, Equation A-2
Annex B (Informative) System Design, Diagnostics and Verification Considerations B.1 General Consideration should be given to the following items before using Coriolis meters for custody transfer measurements: External vibrations at specific frequencies can cause measurement errors. Two-phase flow (liquid/gas) is unacceptable. Meter systems should comply with all applicable codes and regulations. A schematic diagram of a typical meter installation is shown in Figure B-1. B.2 System Design The meter should be oriented in a position that will assure that the flow tube(s) are completely filled with fluid under all flow and static conditions. Provisions should made to not measure flow during no-flow conditions if gas can accumulate in the flow tubes and cause false readings (e.g. spurious or ghost counting). Where the flow range or pressure drop is too great for one meter, the installation of a bank of meters in parallel can be used. When more than one meter is installed in parallel, a means should be provided to balance flow through the meters and isolate the meters for proving purposes. Any condition that tends to contribute to vaporization or cavitation of the liquid stream should be avoided by system design and by operating the meter within its specified flow range. Vaporization or cavitation can be minimized or eliminated by maintaining sufficient pressure in and immediately downstream of the meter. In lieu of actual test data to determine backpressure requirements at the outlet of the meter, the following equation can be applied: P b = 2p + 1.25p e (B-1) where P b p p e = minimum gauge back pressure at sensor outlet = pressure drop across the sensor at the maximum operating flow rate = absolute equilibrium vapor pressure of liquid at the maximum operating temperature NOTE For some dense-phase fluids, such as ethylene and high-purity ethane, these guidelines might not be sufficient. Two-phase flow (liquid/gas) affects meter performance and is unacceptable for custody transfer. A meter installation should be equipped with air/vapor elimination equipment so that measurement accuracy is not degraded by air or vapor. The effect of fluid swirl and non-uniform velocity profiles caused by upstream and downstream piping configuration on meter performance can differ from one meter design to another.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 34 For volumetric measurement, thermowells for the temperature transmitter and test well should be installed near the sensor so that the measured temperature is representative of the fluid temperature in the meter. For mass measurement it is recommended that similar temperature thermowells and transmitter be installed. Normal practice is to install thermowells downstream of the meter. A pressure transmitter should be installed near the sensor. This pressure measurement is used to compensate for pressure effects (pressure compensation) on flow tube(s) and for fluid compressibility correction (CPL) in volume applications. Strainers or other protective devices should be installed upstream of the meter to remove foreign objects which can cause measurement error. Provide easy access to the transmitter for servicing, display readout and proving connections. Provide physical access for portable proving and service vehicles. Avoid installations near sources of flow pulsation and vibration. Figure B-1 Typical Schematic for Coriolis Meter Installation B.3 Zero Value Verification Zero value verification is required as part of the normal operating procedure for the meter. Valves to stop flow through the meter are needed to allow for zero verification and zeroing. It is preferable to have shut-off valves located both upstream and downstream of the meter to block it in during zeroing. As a minimum, a block-and-bleed valve located downstream of the meter is required.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 35 B.4 Density Verification In some measurement applications fluid density verification could be necessary. Consider the following: Ability to sample product for analysis. Ability to install a temporary pycnometer to verify fluid density. B.5 Valves Valves in a meter installation which divert, control or block flow during metering or proving should be capable of smooth opening and closing. The critical valves shall provide a leak-proof shutoff with a method of checking for leakage, such as a block and bleed. See Figure B-1. Automatic devices, such as a flow-limiting control valve or restricting orifice, if required to prevent flows in excess of the maximum rate of the meter, should be installed downstream of the meter. The device should be selected or adjusted so that sufficient backpressure will be maintained to avoid cavitation or vaporization. Special considerations should be given to bidirectional installations to minimize the effect of flow-limiting devices on the meter performance. The meter should be protected from pressure surges as well as from excessive pressures caused by thermal expansion of the fluid when the installation is not operating. A relief valve, if used, should not be installed between the prover and the meter. B.6 Proving Facilities Facilities should be provided for proving the meter under normal operating conditions. Stability of temperature, pressure, flow rate, and product composition is necessary to achieve acceptable proving repeatability. Metering systems should be provided with either manual or automatic means to permit proving the meter under conditions of flow rate, flow direction, pressure, temperature, and fluid characteristics that exist during the normal operation of the meter. Connections for proving should be installed so air or vapor is not trapped in the piping between the meter and the prover. Adequate bleed-off connections should be provided (see API MPMS Ch. 4.8). Reducing the distance between the meter and prover can minimize problems with proving results. It is recommended that the sensor be located upstream of the proving connection. Consider the location and distance between the proving computer and the transmitter. Unlike other meter types, where the pulse generation is located at the primary element, the Coriolis meter pulses come from the transmitter. If the transmitter is not located near the meter and proving computer, then a remote termination junction box should be provided near the proving computer to provide access to the meter pulses. B.7 Diagnostic Measurements The inherent design of a Coriolis meter can offer diagnostics that through a manual or automatic process identify conditions that affect meter performance. Diagnostic methods can require the use of an external tool or can be integrated into meter design. The following lists examples of parameters or analysis measures that some meters provide for diagnostic measurement via a local display or a digital interface (e.g. RS-232, RS-485):
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 36 EPROM checksum Configuration change flag Drive gain or power indication Pickoff or signal amplitude Temperature output(s) Live zero flow (no flow) indication Status and measurement quality indicators Alarm and failure indicators Flowing density or flow tube resonant frequency Flow tube health indication Flow tube balance or symmetry Frequency output test Digital status output test Analog output test NOTE Please consult manufacturer for the diagnostic parameters that are available. To further optimize the use of diagnostics, the operator should establish a baseline of the meter diagnostic indicators during initial installation and meter proving. Deviations from baseline diagnostics are useful in establishing acceptance criteria. During the proving, meter diagnostics can be monitored for alarm or an out of tolerance condition. If an advanced diagnostic for flow tube health exists, this diagnostic test can be performed after proving is complete and results reported. Actual diagnostic capabilities vary by design; the user should consult with the manufacturer to determine an appropriate set of diagnostics for the particular design. A meter log file generated at calibration can establish meter baseline data. Meter log data and the results of an automated flow tube health diagnostic should be included to provide a baseline of the metering module performance at proving. Baseline data can be used to verify meter performance upon startup, during operation, and after component changes. Baseline data can also be useful in conducting health checks of the metering module. It is recommended that the manufacturers identify the parameters that define the baseline performance for their products. B.8 Installation Baseline Operators typically establish the field baselines during the initial installation and startup of the meter. Parameters that can be used to baseline meter performance are drive current, sensor amplitude, and zero value. Manufacturers often offer diagnostics that infer change in meter performance or flow factor. These baseline relationships are useful in establishing acceptance criteria for the various relationships and the need for a flow performance test (proving) and adjustment (if necessary). B.9 Maintenance Users should follow manufacturer recommendations for maintenance. Monitoring diagnostics, performing periodic meter verification procedures, and possibly trending and long-term monitoring of performance indicators, can identify if abnormal conditions develop. Maintenance procedures, like cleaning, should be condition-based (based upon meter factors, process conditions, diagnostics, and/or meter usage). The monitoring of performance indicators can identify the need for cleaning. For example, by monitoring the measured flowing
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 37 density and comparing it to the actual fluid density, it is possible to infer coating on the flow tube(s). Performance indicators available to the user are design specific and the meter manufacturer should be consulted on performance indicators available and their interpretation. B.10 Meter Verification The field verification of a Coriolis metering system consists of monitoring and evaluating metering conditions, diagnostic indicators output by the transmitter, or ancillary devices of the metering system designed to identify possible change in system performance and the cause. The evaluation of these indicators can guide the operator in determining the need to re-zero the meter, execute a proving, adjust maintenance intervals, and implement design improvements, if necessary, to the metering system. The operator should follow design-specific meter verification procedures recommended by the manufacturer and as a minimum the following general meter verification procedures should be performed: Diagnostic indicators Verify all transmitter diagnostic indicators to be in the normal state. Zero check Perform a zero verification. Transmitter calibration factors Verify the flow and density calibration factors and any correction factors in the configuration of the transmitter to be unchanged from most recent proving. The meter transmitter verification should coincide with the zero verification. Sensor Verification Sensor diagnostics can be available that continuously, oncommand, or procedurally verify the performance of the sensor or infers change in measurement performance. Users should consult the meter manufacturer for the availability of these types of diagnostics. B.11 Proving Interval Operators, regulatory agencies or contracts specify proving intervals. In some cases meter diagnostics can be used to assess the condition of the meter. The user could develop a method and procedure to determine whether the proving intervals can be extended or shortened.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 38 Annex C (Informative) Factory Calibration During factory calibration, the output of a Coriolis meter under test is compared with a standard of higher accuracy to establish an initial calibration factor. Coriolis meters are typically factory calibrated on gravimetric flow stands that are traceable to a national standard or by comparison to other traceable flow standards. Gravimetric flow stands typically flow water through the meter which is collected in a tank on a weigh scale (see Figure C-1). The mass readout from the meter is compared to the weigh scale mass indication, corrected for buoyancy effect. From this comparison a calibration factor is developed which converts the sensor output to a flow rate in desired engineering units. Multiple tests at different flow rates establish a repeatable calibration factor within the meter accuracy tolerance. A separate calibration is performed on the density measurement of the meter. Density (ρ) of the fluid contained within the vibrating flow tube is inversely proportional to the flow tube frequency (ƒ) of the sensor assembly. This relationship is represented by the following equation. 1 --- f 2 (C-1) where ρ ƒ = flowing density = flow tube frequency, resonant frequency of the sensor Factory calibration of density involves measurement of the flow tube frequency from the sensor and the density value of the calibration fluid while the meter is full of fluid, either in a static or flowing state. Most density meters are calibrated with two or more fluids (generally air and water) whose density values are well defined and relatively stable. Density values for the fluid(s) can be determined either by using equations of state or calculations from laboratory data or by incorporating a transfer standard to determine the density of the fluid during calibration. For convenience, and to establish traceability to acceptable standards, the test fluids may be referenced to base conditions of temperature and pressure using equations outlined in API MPMS Ch. 9.4. All the factory parameters should be measured with instruments traceable to NIST or another internationally recognized national metrology institute (NMI). The factory calibration produces the manufacture density calibration factor that defines the density per time period squared relationship for each density meter. This equation is then linearly interpolated or extrapolated by the transmitter to determine fluid density in the field.
SECTION 6 MEASUREMENT OF LIQUID HYDROCARBONS BY CORIOLIS METERS 39 Figure C-1 Calibration System Schematic