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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



Measurement Coordination

SECOND EDITION, MONTH 2016


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.


Introduction

API Boiler Plate.


TABLE OF CONTENTS

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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


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.


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


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 × CSWM .

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.


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)

IMm = indicated Coriolis meter mass

KFm = K-factor in units of pulses per unit mass

MFm = 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.


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:


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.


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)


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.


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,


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.


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.


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.


Figure 1– Impact of Zero Error on Meter Factor

Figure 2 –Impact of Zero Stability on Repeatability versus Flow Rate


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.


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


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


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 re-establish 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


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).


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.


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.

(A-1)

where

Err0 = zero error (%) q0 = observed zero value qf = flow rate during normal operation

To determine if the meter needs to be zeroed evaluate if the value of Err0 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.

Err0q0

qf

----- 100=


% Flow Error = ((ZVNEW – ZV) / FR)×100 (A-2)

where

ZV = the recorded zero value at meter factor determination (“as found” recorded after the last proving)

ZVNEW = the current observed zero value FR = 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-and-bleed 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:


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.


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


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


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


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 back-pressure requirements at the outlet of the meter, the following equation can be applied:

(B-1)

where

Pb = minimum gauge back pressure at sensor outlet

∆p = pressure drop across the sensor at the maximum operating flow rate

pe = 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.

Pb 2p 1.25pe+=


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.


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):


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


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, on-command, 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.


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.

(C-1)

where

ρ = flowing density ƒ = 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.

1

f2---


Figure C-1 – Calibration System Schematic


Annex D (Normative)

Pressure Effect Compensation for Tube Stiffness

Section 5.1.2 of this standard recommends the use of a Pressure Effect Compensation for the effects of tube stiffness for all Coriolis meter applications, but is a requirement when the effect is biasing quantity determination by more than 0.05%.

This Annex provides guidance for:

Evaluation and determination of when pressure compensation is required Determination of Pressure Effect Compensation Indicator (PECI) status and the

documentation of same Generalized equations for calculation of the Pressure Compensation Factors

Pressure effect compensation for tube stiffness is applicable to both mass and density measurements of a Coriolis meter. Therefore, it applies to both mass and inferred volume determination. Operators should consult Manufacturers on the applicability and details of this correction for each specific meter design.

D.1 Evaluation of Pressure Effect on Quantity Determination

Pressure effect compensation applies to mass and volume quantities. It is a requirement to evaluate the variation of operating pressure, its impact on mass and/or volume determination, and if pressure compensation is necessary.

D.1.1 Evaluation of Pressure Effect on Mass Determination.

To evaluate the effect of pressure on mass measurement as required in section 5.1.2, the following generalized equations shall be used. Equation D-1 is used to evaluate the design stage and Equation D-2 is used to evaluate the operational stage. Refer to the meter manufacturer for a meter’s pressure effect ( ).

Design 0.05% ∗ _ _ D- 1

Operational 0.05% ∗ D- 2 Where: = Pressure effect in percent (%) of mass flow rate per

unit of gauge pressure (manufacturer value)

_ = Maximum operating pressure

_ = Minimum operating pressure


= Flow-weighted pressure of transaction period = Average pressure of the meter during prove

D.1.2 Evaluation of Pressure Effect on Volume Determination.

To evaluate the effect of pressure on volume measurement as required in section 5.1.2, the following generalized equations shall be used. Equation D-3 is used to evaluate the design stage and Equation D-4 is used to evaluate the operational stage. Refer to the meter manufacturer for a meter’s pressure effect for mass ( ) and density ( ).

Design 0.05%

∗ _ _

∗ _ _

∗ _ _

∗ D-3

Operational 0.05%

∗

∗

∗

∗ D-4

Where: = Pressure effect in percent (%) of mass flow rate per unit of gauge

pressure (manufacturer value)

= Density pressure effect in density units per a unit gauge (manufacturer value)

_ = Maximum operating pressure

_ = Minimum operating pressure

= Flow-weighted pressure of transaction period = Average pressure of the meter during prove = Meter run density at flowing pressure and temperature D.2 Pressure Effect Compensation Indicator Status

This standard prescribes four locations or options for applying pressure compensation. The methods are identified by the Pressure Effect Compensation Indicator (PECI) status listed below:


PECI Status: 1 (CT) = is active/applied in the Coriolis Transmitter.

2 (TD) = is active/applied in Tertiary Device.

3 (OS) = is active/applied within Off-Site measurement system.

4 (N/A) = is defaulted to and applied as 1.0000.

This Indicator status is required in both mass and volume applications. A PECI value shall be recorded to the Quantity Transaction Record(s) (QTR), measurement tickets, and proving reports.

D. 3 Pressure Effect Compensationfor Mass Determination

A Mass Pressure Effect Compensation Factor ( ) is used correct the mass

determination for the pressure effect on the flow tube(s).

Note: This factor is not the same as CPL for compressibility of the liquid.

Equation D-5 is a generalized equation that applies to the mass measurement of most Coriolis meters. It can be used to quantify the correction needed.

1

1 100 ∗ D-5

Where: = Mass Flow Pressure Effect Compensation Factor

= Mass flow pressure effect in percent (%) of rate per unit of gauge pressure

(manufacturer value)

= Flowing gauge pressure when PECI equals 1 (CT) or “2 (TD)”, Flow-weighted average gauge pressure when PECI equals “3 (OS)”

= Mass calibration pressure when PECI equals 1 (CT) or average meter

proving static gauge pressure when PECI equals 2 (TD) or 3 (OS)

= = meter, = master meter

The mass flow pressure effect correction algorithm of some Coriolis designs might not conform to the above generalized equation. Operators should consult manufactures on the applicability of this algorithm for the specific meter design to be used and method of implementation.

D.3.1 Pressures used in PECI Status for Mass

The actual pressure values or recordings vary for equation D-5. They vary by the choice of calculation location or status indicator choice.


Pressure values for equation 1 are based upon the following:

PECI = 1 (CT) - The is fixed by manufacturer. is a live pressure input to

transmitter (this method is the preferred method).

PECI = 2 (TD) - The is the average meter pressure of a proving, is a live

pressure input.

PECI = 3 (OS) - The is the average meter pressure of a proving, is a flow

weighted average pressure for accounting period.

PECI = 4 (N/A) - The is defaulted to and applied as 1.0000.

The PECI may be set to “4” if the operating pressure is maintained at or near proving pressure so that any bias in the quantity determination from those pressure differences does not exceed ±0.05%. See Section 5.1.2 and Section D.1.1, Equation D-1.

For more specific equations and details for each PECI status see Annex E Mass Calculations.

D 4 Pressure Effect Compensationfor Volume Determination

The Pressure Effect Compensation for volume determination is more complicated than for mass. The level of complication is dependent upon the pressure effect on mass and density determination by the meter. These effects can vary by meter design.

D.4.1 PECI Status and pressure used for Volume

In volume determination the location for correction and PECI are limited to two choices.

PECI = 1 (CT) - The and is fixed by manufacturer. is a live pressure

input to transmitter (this method is the only method for compensating for pressure effect on volume).

PECI = 4 (N/A) - There are no pressure effect corrections being made.

The PECI may be set to “4” if the operating pressure is maintained at or near proving pressure so that any bias in the volume determination from those pressure differences does not exceed ±0.05%. See Section 5.1.2 and Annex D.1.2, equations D-3 and D-4.

This Indicator status is required for volume applications. A PECI value shall be recorded to the Quantity Transaction Record(s) (QTR), measurement tickets, and proving reports.

D 5. Pressure Effect Compensationfor Density Determination

Although Chapter 9 is the appropriate standard to reference for stand-alone density measurement. Pressure effect compensation for tube stiffness is applicable to density measurements of a Coriolis meter. Operators should consult manufacturers on the applicability and details of this correction for each specific meter design.


D.5 PECI Status and pressure used for Density

In density determination using a Coriolis meter, the location for correction and PECI are limited to two choices.

PECI = 1 (CT) - The is fixed by manufacturer. is a live pressure input to

transmitter. (this method is the only method for compensating for pressure effect on density).

PECI = 4 (N/A) - There are no pressure effect corrections being made.

The PECI may be set to “4” if the operating pressure is maintained at or near density proving pressure so that any bias in the density determination from those pressure differences does not exceed error tolerances in Chapter 9.


Currently there is no Annex E the document. It will be adjusted as need.

Annex F (Normative)

Mass Calculations for Coriolis Meters

Ticketing and Proving F 1 Mass Determination This Annex prescribes guidelines for the determination of indicated mass, and mass. Strict adherence to calculation sequence and application of corrections factors shall be followed. Chain calculations should be performed without rounding or truncation. Equations throughout this Annex will be presented in two forms, first in a dynamic form used to continuously integrate quantities in electronic measurement devices over the Quantity Transaction Record (QTR) or batch period. The second is the traditional static form of the equation. F 1.1 Determination of Indicated Mass Quantities (IM) Equations 1 through 3 are used for integrating indicated mass quantities in tertiary devices and/or measurement systems, where the accumulation of the Coriolis transmitter’s internal indicated mass accumulators in the tertiary device will accumulate at exactly the same rate. Equation 1 defines how a meter’s indicated mass (IM) is continuously integrated over time in a tertiary device using a frequency output (pulses) from a Coriolis transmitter.

∗ (1)

Indicated Mass (IM) determined by snap shot readings (stop and start), external of transmitter using a pulse counter. Typically, this equation is not used in real time.

(2)

Where: = Indicated mass = Closing mass pulse count = Opening mass pulse count = Delta mass pulse count th sampling interval = Meter’s mass nominal K-Factor (pulse counts per unit mass)


= Quantity per pulse = over the th sampling interval

= th sampling interval = Number of sampling periods over the QTR and/or batch time period Indicated Mass (IM) determined by snap shot reading, external from transmitter using a communication link or manual reading of an accumulators or totalizers. Typically, this equation is not used in real time.

1.000

(3)

Where: = Indicated mass = Closing indicated mass = Opening indicated mass F 2 Pressure Effect Compensation for mass calculations A Pressure Effect Compensation Factor ( ) is used compensate for the pressure effect on the flow tube(s). This factor is not the same as CPL for compressibility of the liquid.

1

1 100 ∗ (4)

Where: = Flow Pressure Effect Compensation Factor = Flow pressure effect in percent (%) of flow rate per unit of gauge pressure

(manufacturer value) = 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 = = meter, = master meter The pressure effect correction algorithm of some Coriolis designs might not conform to the above generalized equation; manufacturers should be consulted on the applicability of this algorithm for the specific design and method of implementation if different. F 3 Pressure Effect Compensation Indicator Status This standard prescribes four methods for applying pressure compensation. The methods are identified by the Pressure Effect Compensation Indicator (PECI) status listed below: PECI Status: 1 (CT) = is active/applied in the Coriolis Transmitter.


2 (TD) = is active/applied in Tertiary Device.

3 (OS) = is active/applied within Off-Site measurement system.

4 (N/A) = is defaulted to and applied as 1.0000.

The status should be set in the tertiary device to indicate where and how is being applied. The PECI shall be recorded to the Quantity Transaction Record(s) (QTR), measurement tickets, and proving tickets. Pressure values for equation 4 are based upon the following: PECI = 1 (CT) - The is fixed by manufacturer, is a live pressure input to

transmitter (preferred method).

PECI = 2 (TD) - The is the average meter pressure of a proving, is a live pressure input.

PECI = 3 (OS) - The is the average meter pressure of a proving, is a flow weighted average pressure for accounting period.

PECI = 4 (N/A) - The is defaulted to and applied as 1.0000.

The PECI may be set to “4” if the operating pressure is maintained at or near proving pressure so that any bias in the quantity determination from those pressure differences does not exceed 0.05%. See Annex D. F 4 Determination of Mass Quantities Mass ( ) is calculated by multiplying the Indicated Mass ( ), with a Mass Meter Factor ( ) and pressure compensation factor ( ). Since this standard disallows meter factor implementation in the transmitter the measured mass determination can only be calculated in a tertiary device or off-site measurement system. It is critical when determining mass that the user understand where and how the pressure effect compensation is being applied to prevent its omission or correcting for it twice. PECI in Section F.3 describes the status of the pressure compensation. F 4.1 Pressure effect compensation record locations The following sections describe the requirements of implementing pressure effect compensation ( ) at various auditing locations to prevent its omission or double correction. F 4.1.1 Coriolis transmitter

1) PECI status shall be set to “1” and logged in the tertiary device 2) A CFPS value of 1.000 shall be used in tertiary devices and off-site measurement

systems 3) shall equal factory the factory calibration pressure of the sensor


4) The pressure measurement ( ) and mass meter factor ( shall be flow-weight averaged over the QTR and/or accounting period and logged in the tertiary device.

∗ ∗ ∗ ∗ 1.0 (5)

F 4.1.2 Tertiary device

1) PECI status shall be set to “2” in the tertiary device 2) Pressure effect compensation shall be turned off in the transmitter. 3) A live pressure input shall be used to determine CFPS for each sampling period in the

tertiary device. 4) shall equal the average proving pressure of the Coriolis meter. 5) The pressure measurement ( ), , calibration pressure ( ), and mass meter

factor ( shall be flow-weight averaged over the QTR and/or accounting period and recorded in the tertiary device.

1

1 100 ∗ (6)

∗ ∗ (7)

Where: = Flow pressure effect compensation factor over the th sampling interval = Flow pressure effect in percent (%) of rate per unit of gauge pressure = Flowing static gauge pressure or flow weighted average pressure at the

meter over the th sampling interval = Calibration or meter proving average static pressure (psig) = Mass = Indicated mass over the th sampling interval = Mass meter factor over the th sampling interval. = ith sampling interval = Number of sampling intervals over the QTR or batch time period F 4.1.3 Off-site measurement system

1) PECI status shall be set to “3” in the tertiary device 2) Pressure effect compensation shall be turned off in the transmitter. 3) A CFPS value of 1.000 shall be used in tertiary devices 4) shall equal the average proving pressure of the Coriolis meter


5) The pressure measurement ( ), calibration pressure ( ), and mass meter factor ( shall be flow-weight averaged over the QTR and/or accounting period and logged

in the tertiary device.

1

1 100 ∗ (8)

∗ ∗

(9)

Where: = Flow weighted flow pressure effect compensation factor = Flow pressure effect in percent (%) of rate per unit of pressure (psig) = Flow weighted average flowing pressure (psig)

= Flow weighted average calibration or meter proving average static

pressure (psig) = Mass = Closing indicated mass = Opening indicated mass = Flow weighted mass meter factor

= Flow weighted average flow pressure effect compensation factor F 4.1.4 Pressure compensation not required

1) PECI status shall be set to “4” in the tertiary device. 2) P effect does not exceed 0.05% per See Annex D. 3) Pressure effect compensation shall be turned off in the transmitter. 4) A CFPS value of 1.000 shall be used in tertiary devices.

∗ ∗ ∗ ∗ 1.0 (10)

Where: = Mass = Indicated mass over the th sampling interval = Mass meter factor over the th sampling interval. = Flow weighted average flow pressure effect compensation factor = ith sampling interval = Number of sampling intervals over the QTR or batch time period F 5 Mass Proving


There are two methods of mass proving of a Coriolis meter. These methods are inferred mass by means of volumetric (displacement or tank) prover and direct mass by means of Coriolis master meter. Only the “Average Meter Factor Method” shall be used for meter factor determination for both Inferred Mass and direct mass. See Chapter 12 for “Average Meter Factor Method” details. The generalized equations below illustrate these proving methods and API MPMS Chapter 4 provides operational guidelines. The following equations illustrate the determination of an intermediate meter factor (IMF) for inferred mass, direct mass and final meter factor.

(11)

(12)

∑

(13)

Where: = Intermediate meter factor = Intermediate meter factor over the th proving run = Mass meter factor = th proving run = Number of runs in the prove


F 5.1 Inferred Mass Proving Displacement Prover Inferred Mass Determination

∗ ∗ ∗ ∗ ∗ (14)

Where: = Base Prover Volume = Number of:

Passes per run for unidirectional Round trips per run for bidirectional

= BPV correction factor for the effect of temperature on steel = BPV correction factor for the effects of pressure on steel = Inferred Mass of the liquid in the prover = Prover density at measured temperature and pressure

= Units conversion to match the mass units output by the meter under test Tank Prover Inferred Mass Determination ∗ 1.0 ∗ ∗ 1.0 ∗ ∗ (15) Additional corrections in the determination are required if a pressured tank prover is used. A correction factor for the effects of pressure on steel along with vapor space volume, and density should be determined and included in the . ∗ 1.0 ∗ ∗ ∗ ∗ (16)

∗ 1.0 ∗ ∗ ∗ ∗ (17)

(18)

(19)

Where: = Inferred Mass of the liquid in the prover

= Inferred mass of the vapor in the prover = Adjusted tank prover volume, defined as the difference between the upper and lower

scale readings during a proving run = Sum of the liquid and vapor inferred mass in the prove


= Adjusted vapor space tank prover volume = BPV correction factor for the effect of temperature on steel = BPV correction factor for the effect of pressure on steel = Prover liquid density at measured temperature and pressure

= Prover vapor space density at measured temperature and pressure

= Units conversion to match the mass units output by the meter under test = Intermediate meter factor Line Meter Indicated Mass Determination for proving calculations

1. When pressure compensation effect is not applied in the Coriolis transmitter (PECI status is 2 or 3), no CFPS correction to the line meter pulses or the register readings shall be made in a tertiary device or off-site measurement system that will be used for the proving calculations.

2. The average proving pressure becomes the new Pcal for subsequent CFPS calculations when PECI status is 2 or 3.

Dynamic

∑

(20)

Discrete

(21)

(22) Where: = Number of whole pulses:

Between detectors switches for unidirectional Round trip for a bidirectional

= Number of interpolated pulses Between detectors switches for unidirectional Round trip for a bidirectional

= Number of whole pulses for the th pass or round trip Between detectors switches for unidirectional Round trip for a bidirectional

= Number of interpolated pulses for the th pass or round trip Between detectors switches for unidirectional Round trip for a bidirectional

= Number of: Passes per run for unidirectional Round trips per run for bidirectional


= th pass or round trip = Mass meter nominal K-Factor (pulse counts per a unit mass) = Closing indicated mass = Opening indicated mass F 5.1.1 Intermediate Meter Factor (IMF) Determination by Inferred Mass Proving

The following equation is used for all pipe provers.

∗ ∗ ∗ ∗ ∗ ∗

∑ (23)

The following equations are used for tank provers, atmospheric.

∗ 1 ∗ ∗ 1.0 ∗ ∗ ∗

∑ (24)

∗ 1.0 ∗ ∗ 1.0 ∗ ∗ ∗ 1.0

(25)

The “Adjusted Tank Volume” shall be substituted in equations 24 and 25 if a pressured tank prover is used, see Annex F 5.1, equations 16, 17, and 18 for details.

Where: = Intermediate meter factor = Base prover volume = Adjusted tank prover volume, defined as the difference between the upper

and lower scale readings during a proving run = Number of:

Passes per run for unidirectional Round trips per run for bidirectional

= BPV correction factor for the effect of temperature on steel = BPV correction factor for the effect of pressure on steel = Prover liquid density at measured temperature and pressure

= Units conversion to match the mass units output by the meter under test = Meter mass nominal K-Factor (pulse counts per a unit mass)


= Meter’s number of whole pulses for the th pass or round trip

Between detector switches for unidirectional Round trip for a bidirectional

= Meter’s number of interpolated pulses for the th pass or round trip

Between detector switches for unidirectional Round trip for a bidirectional

= Number of: Passes per run for unidirectional Round trips per run for bidirectional

= th proving run = Closing indicated mass = Opening indicated mass F 5.2 Intermediate Meter Factor (IMF) Determination by Direct Mass Proving by Coriolis Meter Direct mass proving is the method in which the proving of a line meter is performed by means of a mass meter (Coriolis Meter) used as a master meter prover. General Requirements: 1. Direct mass proving reports shall document PECI status and proving pressure. 2. PECI status for mass master meters shall be PECI 1 or 2. Master meter pressure effect

compensation is performed in the IMF equations for PECI 2 and in the transmitter for PECI 1. PECI 3, or 4 is not allowed on the master meter prover .

3. For the line meter all PECI status are valid and shall be documented on prove report.

∗ ∗ ∗

∗ (26)

Where: = Intermediate meter factor = Line meter nominal K-Factor (pulse counts per a unit mass) = Master meter prover nominal K-Factor (pulse counts per a unit

mass) = Master meter prover mass meter factor = Master meter number of whole pulses over a prove run = Master meter number of interpolated pulses for a prove run = Line meter’s number of whole pulses for a prove run = Line meter’s number of interpolated pulses for a prover run


= The master meter prover pressure effect compensation factor over a prove run. Note: CFPS would default to 1.0000 if PECI status on master meter is 1.

Where the register reading is used:

∗ ∗

(27)

Where: = Intermediate meter factor = Master meter prover closing indicated mass = Master meter prover opening indicated mass = The master meter prover pressure effect compensation factor over a

prove run. Note: CFPS would default to 1.0000 if PECI status on master meter is 1.

= Master meter prover mass meter factor = Line meter closing indicated mass = Line meter opening indicated mass F 5.3 Meter Factor Determination for Inferred Mass and Direct Proving When the intermediate meter factors ( ) meet an acceptable uncertainty criteria, a final average meter factor ( ) shall be calculated as follows:

∑

(28)

Where: = Mass meter factor = th intermediate meter factor = th proving run = Number of selected proving runs Reference API MPMS Chapters 4, and 13 for intermediate meter factor evaluation and acceptability criteria. F 6 Mass Measurement Tickets and Proving Reports F 6.1 Measurement Tickets The following is a list of the information necessary to document, and determine the transaction quantity (QTR).

Unique meter identifier


Batch ID Ticket ID Date/Time Open & Close Non-Resettable Open & Close Indicated Mass Totalizers Indicated Mass Meter Factor PECI Status CFPSm

PECI Status [Include the following when the PECI status is 2 (TD) or 3(OS)] (Flow weighted average pressure at the meter)

Mass If net mass applies, include the following to the ticket

Net Mass %S&WM or %S&WV Water Density CSWM If %S&WV (volume method) is used Emulsion Observed Density Emulsion Observed Temperature of Density Emulsion Base Density

F 6.2 Proving Report This section provides the necessary information to be contained in mass proving reports. Chapter 12 should be referenced for addition information or clarification of terms. F 6.2.1 Inferred Mass Proving Report The following is a list of the minimum measurement information necessary to document an inferred mass prove. General Data:

o Customer o Operator o Location o Meter ID o Date o Time

Meter Data:

o Meter Type o Meter Manufacturer o Flange Size


o Model No. o Sensor Serial Number o Transmitter Serial Number o Flow Calibration Factor(s) o Nominal K-Factor o Non-Resettable Totalizer Value o Zero Value, as found (in metered mass units o Date of last meter zero o Zero performed before this prove (Y/N) o Zero Value, as left o PECI Status

Prover data:

o Manufacturer o Type o Serial Number o Base Prover Volume o Wall Thickness o Internal Diameter o Flow Tube Material o Detector bar material o Thermal Expansion Coefficients o Calibration date

Product Data:

o Name o Prover flowing density (RHOtpp) in meter mass units / prover volume units, (i.e

lbs/Bbl) o Flow Density Determination Method

When the density is determined from a spot-sample or spot-measurement, then record the following information:

o Base Density o Equilibrium Vapor Pressure o Observed Density value

Temperature Pressure

o Equation of state Prove Data:

o Total Meter Pulses per run (summed if multiple passes) o Passes per run o Per run averages:

Prover


o RHOtpp (flowing density) recorded in metered mass units (line meter) / prover volume units (i.e lbs/Bbl)

o Temperature (Tp) o Switch Bar Temperature o Pressure (Pp) o Flow rate

Meter o temperature (optional) o pressure

Intermediate Meter Factor (IMF)

o Average data of all prove runs for Prover

Flowing Density (with DMF) recorded in metered mass units (line meter)/ prover volume units (i.e lbs/Bbl)

DMF Switch Bar Temperature CTSP CPSp BPV Inferred Prover Mass Flow rate

Meter: Pulses (N (avg)) Average pressure of prove runs (Pcal) Indicated mass (meter)

o Average Meter factor (average of the intermediate meter factors). o Uncertainty of runs o Repeatability of runs (optional)

Optional Meter Factor comparison Data:

Previous Prove data o Date o Meter Factor o MF Variance o Flow Rate, o Temperature, o Pressure o Flow Density o Zero Value (in metered mass units )

Optional General Data: o Technician Company o Witness Company


F 6.2.2 Direct Mass Proving Report The following is a list of the minimum measurement information necessary to document a direct mass prove. General Data:

o Customer o Operator o Location o Meter ID o Date o Time

Meter Data: o Meter Type o Meter Manufacturer o Flange Size o Model No. o Sensor Serial Number o Transmitter Serial Number o Flow Calibration Factor(s)

o Nominal K-Factor o Non-Resettable Totalizer Value o Zero Value “As found” (in metered mass units ) o Date of last meter zero o Zero performed this prove (Y/N) o Zero Value “as left” o PECI Status

Prover (Master Meter) Data: o Meter Type o Meter Manufacturer o Flange Size o Sensor Model Number o Sensor Serial Number o Transmitter Model Number o Transmitter Serial Number o Transmitter Seal Number o Flow Calibration Factor (s) o Nominal K-Factor o Non-Resettable Totalizer Value o Zero Value (in metered mass units) o Calibration Pressure (Pcal) o PECI Status (Status 1 or 2 only) o Proving/Calibration Date


Prove Data: o Per run Total Meter Pulses (N or Ni) Total Prover Pulses per run (N or Ni) Prover

o Temperature (Tp) o Pressure (Pp) o Flow rate

Prover Master Meter Factor (MMF) Master Meter Mass Meter mass Intermediate Meter Factor (IMF)

o Average data of all prove runs for

Prover Pulses (N (avg)) Prover Master Meter Factor (MMF) Mass (M) Flow rate Flowing pressure CFPS (if used in calculations)

Meter:

Pulses (N (avg)) Indicated mass (IMm)

o Average Meter factor (average of intermediate meter factors) IMF o Uncertainty of runs o Repeatability of runs

Optional Meter Factor Comparison Data:

Last Prove data: o Date o Meter Factor o MF Variance o Flow Rate, o Temperature, o Pressure o Flowing Density o Zero Value (in metered mass units) Product Data: o Name o Base Density o Observed Density

o Temperature o Pressure


Optional General Data: o Technician Company o Witness Company

F 7 Discrimination Irrespective of how the observed values are obtained and their level of discrimination, the values used in mass calculations shall be to the discrimination levels in the tables below. US Customary SI Units lb/gal* lb/bbl kg/l kg/m3* Density (Absolute, flowing)

A.xxxx ABC.xx ABC.xx ABC.xx

*Density discriminations are per GPA 2145-16

RD60/60** API** RD15/15** kg/m3** Density (base) 0.xxxxx ABC.xx 0.xxxxx ABC.xx **Density and gravity discriminations are per GPA 2145-16 Table F-1 US Customary & UK Imperial

Units SI Units

Reporting Mass lbs kg X.0 X.5 Correction Factor CFPS CFPS X.xxxxx X.xxxxx Mass Discrimination for Proving Calculations ABCDE.x, ABCD.xx, ABC.xxx, AB.xxxx

All other discriminations are in accordance with the appropriate API standard

Table F-2 F.8 Rounding Rounding rules can be found in Chapter 12.


F.9 Proving Report Proving report examples can be found in API MPMS Chapter 4.8.


Annex G (Informative)

Determination of Net Mass

In the petroleum measurement fluids of contain non-merchantable quantities such as sediment and water. This Annex presents calculation methods to make adjustments to mass quantities for non-merchantable quantities. G. Determination of Net Mass The non-merchantable sediment and water mass (SWM) quantity can be determined by taking the difference between the M and NM such that:

1.0% &100

(1)

∗ (2) SWM M NM (3) Where:

CSWM = Correction of Sediment & Water by Mass %S&WM= Percent of Sediment & Water by (M) Mass, SWM = Mass of sediment and water during the measurement period NM = Net mass during the measurement period M = mass of fluid measured during the measurement period

Determination for sediment and water (S&W) is governed by API MPMS Chapter 10. G .2 Determination of sediment and water (S&W) Methods for determination of sediment and water (S&W) are presented in API MPMS Chapter 10. G.2.1 Percent Sediment and Water for Mass quantities by Mass test method. API MPMS Chapter 10.7 (ASTM D4377) and 10.9 (ASTM D4928) both describe determination of water by mass, the limits for these methods are 2.0% and 5.0% respectively. API 10.1 (ASTM D473) and 10.8 (ASTM D4807) both describe determination of sediment by mass, the limits for these methods are 0.40% and 0.15% respectively.


Per API TR 2573 (ASTM D7829), “To obtain the total sediment and water results when the two are determined by separate methods: First, add the raw, unrounded results together, and then round the sum to the correct significant figure.” The resulting is the sediment and water percent by mass (%S&WM). G.2 Percent Sediment and Water by Mass quantities by volume test method. Determining sediment and water percent by centrifuge is a common and used often as a field procedure. See API MPMS Chapter 10.4. This standard describes determination of sediment and water by volume. The following equation from API MPMS Chapter 10.9 (ASTM D4928) converts percent sediment and water (%S&Wv) by Volume to a percent by Mass (%S&WM).

% & % & ∗ (4)

In accordance with API MPMS Chapter 10.9 (ASTM D4928) a density of water 999.016 kg/m3 shall be used unless otherwise determined by empirical or analytical methods.

Where: %S&Wv = Volume Percent sediment and water determined by volume test method


Bibliography

Documents

Manual of Petroleum Measurement Standards Chapter …ballots.api.org/copm/colm/ballots/docs/5_6_WG_Mar_2018.pdf · API Manual of Petroleum Measurement Standards, ... Chapter 4.8,