AGA Report No. 9
Measurement of Gas by Multipath
Ultrasonic Meters
Third Edition
July 201 7
Prepared by
Transmission Measurement Committee
Operations & Engineering Section
AGA Report No. 9
Measurement of Gas by Multipath
Ultrasonic Meters
Third Edition
July 2017
Transmission Measurement Committee
Operations & Engineering Section
Copyright 2017, American Gas Association
400 North Capitol Street, NW, 4th Floor, Washington, DC 20001, U.S.A.
Phone: (202) 824-7000
Catalog # XQ1705
DISCLAIMERS AND COPYRIGHT
The American Gas Association’s (AGA) Operating Section provides a forum for industry experts to bring
collective knowledge together to improve the state of the art in the areas of operating, engineering and
technological aspects of producing, gathering, transporting, storing, distributing, measuring and utilizing
natural gas.
Through its publications, of which this is one, AGA provides for the exchange of information within the
gas industry and scientific, trade and governmental organizations. Each publication is prepared or sponsored
by an AGA Operating Section technical committee. While AGA may administer the process, neither AGA
nor the technical committee independently tests, evaluates or verifies the accuracy of any information or
the soundness of any j udgments contained therein.
AGA disclaims liability for any personal injury, property or other damages of any nature whatsoever,
whether special, indirect, consequential or compensatory, directly or indirectly resulting from the
publication, use of or reliance on AGA publications. AGA makes no guaranty or warranty as to the accuracy
and completeness of any information published therein. The information contained therein is provided on
an “as is” basis and AGA makes no representations or warranties including any expressed or implied
warranty of merchantability or fitness for a particular purpose.
In issuing and making this document available, AGA is not undertaking to render professional or other
services for or on behalf of any person or entity. Nor is AGA undertaking to perform any duty owed by any
person or entity to someone else. Anyone using this document should rely on his or her own independent
judgment or, as appropriate, seek the advice of a competent professional in determining the exercise of
reasonable care in any given circumstances.
AGA has no power, nor does it undertake, to police or enforce compliance with the contents of this
document. Nor does AGA list, certify, test or inspect products, designs or installations for compliance with
this document. Any certification or other statement of compliance is solely the responsibility of the certifier
or maker of the statement.
AGA does not take any position with respect to the validity of any patent rights asserted in connection with
any items that are mentioned in or are the subject of AGA publications, and AGA disclaims liability for the
infringement of any patent resulting from the use of or reliance on its publications. Users of these
publications are expressly advised that determination of the validity of any such patent rights, and the risk
of infringement of such rights, is entirely their own responsibility.
Users of this publication should consult applicable federal, state and local laws and regulations. AGA does
not, through its publications intend to urge action that is not in compliance with applicable laws, and its
publications may not be construed as doing so.
This report is the cumulative result of years of experience of many individuals and organizations acquainted
with the measurement of natural gas. However, changes to this report may become necessary from time to
time. If changes to this report are believed appropriate by any manufacturer, individual or organization,
such suggested changes should be communicated to AGA by completing the last page of this report titled,
“Form for Proposal on AGA Report No. 9. ”
Copyright 2017, American Gas Association, All Rights Reserved.
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FOREWORD
This report is a revision of the previous AGA Report No. 9, 2007 edition. It is a performance-based
specification for multipath ultrasonic meters for gas flow measurement. AGA’s Transmission Measurement
Committee (TMC) worked diligently for several years on its revision. It is the result of a collaborative effort
of users, meter manufacturers, independent consultants, flow-measurement service providers and research
organizations. This report was made available for comments from other relevant AGA committees, the
Committee on Gas Fluid Measurement (COGFM) of the American Petroleum Institute (API), Section H of
the GPA Midstream Association (GPA), ISO/TC 30/SC 5/WG 1 of the International Organization for
Standardization, and the committee for Measurement of Fluid Flow in Closed Conduit of the American
Society of Mechanical Engineers (ASME - MFC).
This version of AGA Report No. 9 is intended to supersede all prior versions of this document. However,
this document does not reference existing multipath ultrasonic meter installations. The decision to apply
this document to existing installations shall be at the discretion of the parties involved.
Research conducted in support of this report and cited herein has demonstrated that multipath ultrasonic
meters can accurately measure gas flow and, therefore, should be able to meet the requirements specified
in this report when calibrated and installed according to the recommendations contained herein. In
consultation with a competent professional, users should follow appropriate installation, use and
maintenance of an ultrasonic meter as applicable in each case.
Flow-calibration guidelines are provided for occasions when a flow calibration is requested or required to
verify the meter’s performance or to apply a calibration factor to minimize the measurement uncertainty.
(See Appendix A (Informative))
Unlike most traditional gas meters, multipath ultrasonic meters inherently have an embedded
microprocessor system. Therefore, this report includes, by reference, a standardized set of testing
specifications applicable to electronic gas meters. These tests, summarized in Appendix B (Normative), are
used to demonstrate the acceptable performanc e of the multipath ultrasonic meter’s electronic system under
different influences and disturbances.
The flow metering package and/or flow conditioner performance verification test found in Appendix C
(Normative) is intended to provide a method by which they can be shown to perform under varying test
flow conditions within the limit set in this Appendix.
An example of overall measurement uncertainty calculations is provided in Appendix D (Informative) with
assumed numerical values for estimating measurement uncertainty for sites using ultrasonic gas flow
meters.
In this document the words shall, should and recommended are to be used to mean as follows:
“ Shall” means a requirement to conform to the specific task.
“ Should ” and “ recommended ” are used synonymously to indicate good practices to follow, but not
required to conform to the specific task.
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ACKNOWLEDGEMENTS
AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters, was revised by a task group of
the American Gas Association’s Transmission Measurement Committee under the chairmanship of Rick
Spann of Dominion Energy Questar Pipeline Services and joint vice chairmanship of John Lansing of
CEESI and Reese Platzer of Enterprise Products Partners. Individuals who made substantial contributions
to the revision of this document are:
Ilia Bluvshtein, Union Gas
Kerry Checkwitch, Spectra Energy Transmission
Terrence Grimley, Southwest Research Institute
Danny Harris, Columbia Gas Transmission Co
Martin Schlebach, Emerson Process Management, Daniel Div.
Marcel Vermuelen, Krohne Oil & Gas
Jim Witte, Southwest Research Institute
Other individuals who contributed to the revision of the document are:
Robb Albers, National Fuel Gas Co.
Ardis Bartle, Apex Measurement & Controls
Belinda Bell, Southern Star Central Gas Pipeline
Jim Bowen, SICK, Inc.
Martin Bragg, Honeywell Process Solution
David Bromley, BP Pipeline Inc.
Pamela Chacon, Chevron Phillips
Craig Chester, formerly Williams Gas Pipeline
Joel Clancy, CEESI
Charles Derr, Elster Instomet
Juan Escobar, Saudi Aramco
Angela Floyd, BP Energy Co.
Michael Frey, Cameron
John Gerwig, Michael Baker International
Ted Glazebrook, Enterprise Products Partners
John Hand, TransCanada
Wayne Haner, TransCanada Calibrations
Peter Kucmas, Powell Controls
Gary McCargar, Oneok
Ron McCarthy, Siemens
Alastair McLachlan, Cameron
Dannie Mercer, Atmos Energy
Roy Meyer, ExxonMobil
Winston Meyer, CenterPoint Energy
Ryan Nutter, Dominion Transmission
Sam Patel, Consumers Energy
Mark Pelkey, National Fuel Gas Co.
Darren Pineau, Shell
Swarandeep Sandhawalia, TransCanada
Blaine Sawchuk, Canada Pipeline Accessories
Tushar Shah, Eagle Research Corporation
Rob Smith, New Mexico Gas Company
iii
Karl Stappert, Micro Motion
Bob Wurm, Tallgrass Energy
Tonya Wyatt, Micro Motion
AGA acknowledges the contributions of the above individuals and thanks them for their time and effort in
getting this document revised.
Christina Sames
Vice President, Operations & Engineering
Ali Quraishi
Director, Operations & Engineering Services
iv
TABLE OF CONTENTS
DISCLAIMERS AND COPYRIGHT ..................................................................................I
FOREWORD ....................................................................................................................II
ACKNOWLEDGEMENTS............................................................................................... III
1 .0 INTRODUCTION ....................................................................................................1
1.1
Scope .............................................................................................................................................................1
1.2
Principle of Measurement ...........................................................................................................................1
2.0 TERMINOLOGY, UNITS AND DEFINITIONS ........................................................2
2.1
Terminology ..................................................................................................................................................2
2.2
Engineering Units ........................................................................................................................................2
2.3
Definitions .....................................................................................................................................................3
3.0 OPERATING CONDITIONS ...................................................................................7
3.1
Gas Quality ...................................................................................................................................................7
3.2
Pressures .......................................................................................................................................................7
3.3
Temperatures, Gas and Ambient................................................................................................................7
3.4
Gas Flow Considerations .............................................................................................................................7
3.5
Upstream Piping and Flow Profiles ............................................................................................................8
3.6
Acoustic Noise ...............................................................................................................................................8
4.0 METER REQUIREMENTS .................................................................................... 1 0
4.1
Quality Assurance ...................................................................................................................................... 10
4.2
Flow Meter Body ........................................................................................................................................ 10
4.2.1
4.2.2
4.2.3
4.2.4
Maximum Operating Pressure.................................................................................................................... 10
Corrosion Resistance.................................................................................................................................. 10
Flow Meter Body Length and Internal Diameter ....................................................................................... 10
Ultrasonic Transducer Ports ....................................................................................................................... 11
v
4.2.5
4.2.6
4.2.7
4.2.8
Pressure Tap ............................................................................................................................................... 11
Integral Meters ........................................................................................................................................... 11
Miscellaneous ............................................................................................................................................ 11
Flow Meter Body Markings ....................................................................................................................... 11
4.3
Ultrasonic Transducers ............................................................................................................................. 12
4.4
Electronics .................................................................................................................................................. 12
4.5
Meter Firmware and Software ................................................................................................................. 14
4.6
Individual Meter-Manufacturing Tests and Checks ............................................................................... 16
4.7
Documentation ........................................................................................................................................... 17
4.3.1 Specifications ............................................................................................................................................. 12
4.3.2 Rate of Pressure Change ............................................................................................................................ 12
4.3.3 Transducer Tests ........................................................................................................................................ 12
4.4.1
4.4.2
4.4.3
4.4.4
4.5.1
4.5.2
4.5.3
4.5.4
4.5.5
4.5.6
General Requirements ................................................................................................................................ 12
Output Signal Specifications ...................................................................................................................... 13
Electrical Safety Design Requirements ...................................................................................................... 13
Component Replacement ........................................................................................................................... 13
Firmware .................................................................................................................................................... 14
Associated Flow Computing ...................................................................................................................... 14
Alarms ........................................................................................................................................................ 15
Meter Diagnostics ...................................................................................................................................... 15
User Interface Software ............................................................................................................................. 15
Inspection and Auditing Functions ............................................................................................................ 15
4.6.1 Dimensional Measurements ....................................................................................................................... 16
4.6.2 Leakage Test .............................................................................................................................................. 16
4.6.3 Zero-Flow and SOS Verification Test ....................................................................................................... 16
5. 0
I N STALL ATI ON . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 9
5.1
Environmental and Process Considerations ............................................................................................ 19
5.2
Metering Package Design Criteria............................................................................................................ 20
5.1.1
5.1.2
5.1.3
5.1.4
5.1.5
5.1.6
5.2.1
5.2.2
5.2.3
5.2.4
5.2.5
5.2.6
5.2.7
5.2.8
Ambient and Flowing Temperature ........................................................................................................... 19
External Mechanical Vibration .................................................................................................................. 19
Electrical Noise .......................................................................................................................................... 19
Process Pulsation ....................................................................................................................................... 19
Acoustic Noise ........................................................................................................................................... 20
Filtration and Separation ............................................................................................................................ 20
Installation Configuration .......................................................................................................................... 20
Alternative Installation Configuration ....................................................................................................... 22
Internal Surfaces ........................................................................................................................................ 22
Protrusions and Alignment ......................................................................................................................... 22
Thermowell(s) and Sample Probe(s) .......................................................................................................... 22
Flow Conditioning ..................................................................................................................................... 23
Orientation of Meters ................................................................................................................................. 23
Meter Tube Inspection and Cleaning Ports ................................................................................................ 23
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5.3
Close-Coupled Series Metering ................................................................................................................. 24
5.4
Handling ..................................................................................................................................................... 24
5.5
Miscellaneous Design Considerations ....................................................................................................... 24
5.4.1 Preparation and Packaging ......................................................................................................................... 24
5.4.2 Lifting and Supports................................................................................................................................... 24
6.0 FLOW CALIBRATION AND PERFORMANCE REQUIREMENTS ...................... 26
6.1
Preparation for Flow Calibration ............................................................................................................. 26
6.2
Metering Package Flow-Calibration Test ................................................................................................ 26
6.3
Metering Package Performance Requirements ....................................................................................... 28
6.4
Pressure, Temperature and Gas Composition Influences ...................................................................... 30
6.5
Calibration Adjustment Factors ............................................................................................................... 30
6.5.1 Calibration Test Reports ............................................................................................................................ 31
6.5.2 Final Considerations .................................................................................................................................. 32
7.0 COMMISSIONING, FIELD VERIFICATION, MAINTENANCE AND
RECALIBRATION ......................................................................................................... 33
7.1
Commissioning ........................................................................................................................................... 33
7.2
Field Verification........................................................................................................................................ 33
7.3
Maintenance ............................................................................................................................................... 33
7.4
Recalibration .............................................................................................................................................. 34
7.3.1 Inspection ................................................................................................................................................... 33
7.3.2 Cleaning ..................................................................................................................................................... 34
7.3.3 Component Replacement ........................................................................................................................... 34
8.0 ULTRASONIC METER MEASUREMENT UNCERTAINTY DETERMINATION ... 35
REFERENCE LIST ........................................................................................................ 36
APPENDIX A (INFORMATIVE): MULTIPATH ULTRASONIC METER FLOWCALIBRATION ISSUES ................................................................................................ 41
A.1
Why Flow-Calibrate a Multipath Ultrasonic Meter? ............................................................................ 41
A.2
Methods for Correcting a USM’s Flow Measurement Error ................................................................ 42
A.3
Flow-Weighted Mean Error (FWME) Correction ................................................................................. 43
A.4
Polynomial Algorithm ............................................................................................................................... 46
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A.5
Multi-Point/Piece-Wise Linear Interpolation ......................................................................................... 47
APPENDIX B (NORMATIVE): ELECTRONICS DESIGN TESTING ............................ 48
APPENDIX C (NORMATIVE): FLOW-METERING PACKAGE AND/OR FLOWCONDITIONER PERFORMANCE
VERIFICATION TEST
49
APPENDIX D (INFORMATIVE): EXAMPLES OF OVERALL MEASUREMENTUNCERTAINTY CALCULATIONS –
ULTRASONIC METER
50
D.1
Meter-Calibration Uncertainty ................................................................................................................ 50
D.2
Uncertainties Arising From Differences Between the Field Installation and the Calibration Lab ..... 50
D.3
Uncertainties Due to Secondary Instrumentation .................................................................................. 51
D.4
Uncertainty Analysis Procedure .............................................................................................................. 52
D.4.1
General .................................................................................................................................................... 52
D.4.2
The Mathematical Model ...................................................................................................................... 52
D.4.3
Contributory Variances ......................................................................................................................... 52
D.4.4
Combined Uncertainty (percent) .......................................................................................................... 54
D.4.5
Expanded Uncertainty ........................................................................................................................... 54
D.2.1
D.2.2
D.2.3
D.2.4
Parallel Meter Runs ................................................................................................................................... 50
Installation Effects .................................................................................................................................... 50
Pressure and Temperature Effects ............................................................................................................. 51
Contamination Effects ............................................................................................................................... 51
D.4.3.1
D.4.3.2
D.4.3.3
D.4.3.4
Uncertainty in the Uncorrected Volume FlowRate, Q f .......................................................................... 52
Uncertainty in the Measurement of Pressure.......................................................................................... 53
Uncertainty in the Measurement of Temperature ................................................................................... 53
Uncertainty in the Determination of Compressibility ............................................................................ 53
APPENDIX E (INFORMATIVE): USM COMMISSIONING AND VERIFICATION
CHECKLISTS ................................................................................................................ 55
E.1
Commissioning Checklist ......................................................................................................................... 55
E.2
USM Field Verification Checklist ............................................................................................................ 57
FORM FOR PROPOSALS ON AGA REPORT NO. 9 ................................................... 59
vi i i
1.0 Introduction
1.1 Scope
This report is for multipath ultrasonic transit-time flow meters used for the measurement of natural gas. It
may be used for the measurement of other gases in consultation with the meter manufacturer and a
competent professional. Multipath ultrasonic meters have at least two independent pairs of measuring
transducers (acoustic paths). Applications may include, but not limited to, measurement of single-phase gas
flow through production facilities, transmission pipelines, storage facilities, distribution systems and by
end-use customers.
1.2 Principle of Measurement
Transit-time multipath ultrasonic meters are inferential meters that derive the gas flow rate by measuring
the transit times of high-frequency sound pulses. Sound pulse transit times are measured between pairs of
transducers. Pulses transmitted along the acoustic path in the direction of the gas flow have a greater average
velocity relative to pulses transmitted against the gas flow. The difference in the sound pulse transit times
is related to the average gas flow velocity along that specific acoustic path. Numerical calculation
techniques are used to compute the average axial gas flow velocity and the gas volume flow rate at line
conditions through the meter by combining the measurements of all active acoustic paths.
The accuracy of an ultrasonic gas meter depends on several factors, such as:
•
•
•
•
•
•
Precisely measured dimensions of the flow meter body and ultrasonic transducer locations
The velocity integration technique inherent in the design of the meter
The shape of the velocity profile of the flowing gas stream at the meter
Stability of the flowing gas stream
The accuracy of transit-time measurements
Flow calibration
The accuracy of transit-time measurements depends on several factors, including:
•
•
•
•
The electronic clock accuracy and stability
Accurate and consistent detection of sound pulse transit times
Proper compensation for signal delays of electronic components and transducers
Dimensional integrity of the flow meter body
Ultrasonic meter (USM) accuracy is dependent on these fundamental characterizations and their continued
integrity over time. These accuracy dependencies may be adversely influenced by operational degradation
of the USM over time (e.g., erosion, corrosion and dirt build up on internal meter surfaces, electronics drift,
etc.). Emphasis on USM diagnostic data collection and interpretation in this document is made to impress
upon users the need to monitor USM integrity so that accuracy is maintained.
1
2.0 Terminology, Units and Definitions
For the purposes of this report, the following terminology, engineering units and definitions apply:
2.1 Terminology
auditor
designer
inspector
manufacturer
operator
SPU
USM
Representative of the operator or other interested party that audits operation
of multipath ultrasonic meters.
Company that designs and constructs metering facilities and purchases
multipath ultrasonic meters.
Representative of the designer who visits the manufacturer’s facilities for
quality-assurance purposes.
Company that designs, manufactures, sells and delivers multipath ultrasonic
meters.
Company that operates multipath ultrasonic meters and performs normal
maintenance, also referred to as User.
Signal Processing Unit, the portion of the multipath ultrasonic meter that is
made up of the electronic microprocessor system.
Multipath ultrasonic meter for measuring gas flow rates.
2.2 Engineering Units
The following units should be used for the various values associated with the USM.
Parameter
density
energy
mass
pipe diameter
pressure
temperature
velocity
viscosity
volume
volume, actual flowing conditions
volume, standard conditions
US Customary Units
SI Units
lb/ft3
Btu
lb
in
psi or lbf/in2
o
 F or R
ft/s
lb/ft s
cf or ft3
acf
scf
kg/m3
J
kg
mm
kPa
 C or K
m/s
cP or Pa s
m3
m3
m3
2
2.3 Definitions
Accuracy
Confidence Level
Calibration
Error
Error, Percent
Flow Meter Body
Flow Meter, Multipath
Ultrasonic
Inside Pipe Diameter
Length, Settling
Maximum Error
Maximum Peak-toPeak Error
A qualitative concept of the closeness in agreement of a
measured value and an accepted reference value. Accuracy is
not expressed in any quantitative numerical value; rather it is an
indication that a measurement is more accurate when it offers
less error or uncertainty.
The probability, expressed as a percentage, that the true value
lies within the stated uncertainty. For example: A proper
uncertainty statement would read: "500 lb/h ±1.0% at a 95%
level of confidence." This means when sampled numerous times,
it is expected that approximately 95 out of every 100
observations are between 495 lb/h and 505 lb/h.
The process of determining, under specified conditions, the
relationship between the output (or response) of a device to the
value of a traceable reference standard with documented
uncertainties. The relationship may be expressed by a statement,
calibration function, calibration diagram, calibration curve or
calibration table. In some cases, it may consist of an additive or
multiplicative correction of the indication with associated
measurement uncertainties. Any adjustment to the device, if
performed, following a calibration requires verification against
the reference standard.
The result of a measurement minus the reference value of the
measurand.
Note: Since a true value cannot be determined, in practice, a
conventional true (or reference) value is used.
% error = [(measured value – reference value) / reference value]
x 100%
The pressure-containing section of the meter where the gas
velocity flow measurement is determined.
Multipath ultrasonic meters have at least two independent pairs
of measuring transducers (acoustic paths).
The inside diameter of a pipe, as determined from direct
physical measurement or calculated from pipe schedule and wall
thickness.
The distance required between a flow disturbance and a flow
conditioner that allows the flow conditioner to function
properly.
The allowable error limit within the specified operational range
of the meter.
The difference between the largest and smallest error values
within a specified flow-rate range.
3
Maximum Speed-ofSound (SOS) Path
Spread
Mean error
The maximum difference in speed-of-sound values between any
two acoustic paths.
Measurement
Uncertainty
A parameter, associated with the result of a measurement that
characterizes the dispersion of the values that could reasonably
be attributed to the measured quantity. This dispersion includes
all components of uncertainty, including those arising from
systematic effects. The measurement uncertainty is typically
expressed as a standard deviation (or a given multiple of it),
defining the limits within which the true value of the
measurement is expected to lie with a stated level of confidence.
Metering Package
A piping package that consists of a meter and adequate upstream
and downstream piping, along with thermowell(s), sample
probe, and any flow conditioning to ensure that there is no
significant difference between the results indicated by the meter
in the laboratory and those indicated in the final installation.
A flow rate below which any indicated flow by the meter is
considered to be invalid and indicated flow output is set to zero.
(historically referred to as “low-flow cutoff”).
Pipe diameter corresponding to Nominal Pipe Size. For
example, the ND of schedule 40 NPS 4 pipe is 4 inches, whereas
the inside pipe diameter may be 4.026 inches.
The flow rate through a meter under a specific set of test or
operating conditions.
The maximum flow rate through a meter that can be measured
within the specified performance requirements at a specific
process condition.
The minimum flow rate through a meter that can be measured
within the specified performance requirement at a specific
process condition.
The transition flow rate through a meter at which performance
requirements may change.
A meter or measurement device of proven flow measurement
uncertainty.
A gas of known physical properties, e.g., nitrogen, that is used
as a baseline for comparison.
No-Flow Cutoff
Nominal Pipe
Diameter (ND)
qi
qmax
qmin
qt
Reference Flow Meter
Reference Gas
The arithmetic mean of all the observed errors or data points for
a given flow rate.
4
Repeatability
Reproducibility
Resolution
Roughness Average
(Ra)
The closeness of agreement between the results of successive
measurements of the same measurand carried out under the same
conditions of measurement.
Notes:
1. These conditions are called repeatability conditions.
2. Repeatability conditions include: the same measurement
procedure, the same observer, the same measuring
instrument used under the same conditions, the same
location, and repetition over a short period of time.
3. Repeatability may be expressed quantitatively in terms of
the dispersion characteristics of the results.
4. A valid statement of repeatability requires specifications of
the conditions of measurement (temperature, pressure, gas
composition, etc.) that may affect the results. When a value
of repeatability is given, a note shall be provided indicating
the specific calculations used to compute the dispersion
characteristics.
The closeness of agreement between the results of
measurements of the same measurand carried out under changed
conditions of measurement.
Notes:
1. A valid statement of reproducibility requires specification of
the conditions changed.
2. The changed conditions may include one or more of the
following: Principle of measurement, method of
measurement, observer, measuring instrument, reference
standard, location, conditions of use, or time.
3. Reproducibility may be expressed quantitatively in terms of
the dispersion characteristics of the results.
4. A valid statement of reproducibility requires specification of
the changed conditions of measurement that may affect the
results.
When a value of reproducibility is given, a note shall be
provided indicating the specific calculations used to compute the
dispersion characteristics.
The smallest change in the measurand that can be observed.
The roughness average (Ra) used in this report is that given in
ANSI B46.1 , and is “the arithmetic average of the absolute
values of the measured profile height deviation taken within the
sampling length and measured from the graphical centerline” of
Significant Change
the surface profile.
The difference in a value that can be shown, through statistical
analysis, to be different from a previous value.
5
Speed-of-Sound (SOS)
Deviation
The difference, in percent, between the average speed of sound
reported by a meter and the speed of sound of the gas being
measured, as calculated per AGA Report No. 8, Part 1 :
DETAILED Equation of State or Part 2: GERG-2008 Equation
of State.
True Value
The value determined with a perfect measurement process. The
true value is always unknown because all measurement
processes are imperfect to some degree.
Velocity Sampling
Interval
The time interval between two successive gas velocity
measurements by the full set of transducers or acoustic paths.
Zero-flow Reading
The maximum allowable flow velocity reading when the gas is
assumed to be at rest, i.e. both the axial and non-axial velocity
components are essentially zero.
6
3.0 Operating Conditions
3.1 Gas Quality
The meter shall meet the performance requirements in Section 6 operating within the natural gas property
ranges specified in AGA Report No. 4A, 2009 revision, Table 4.1. If any of the gas properties are outside
of this range, the manufacturer should be consulted.
The manufacturer should also be consulted if the operating conditions are at or near the critical density of
the natural gas mixture.
Deposits due to normal gas pipeline conditions (e.g., condensates, glycol, amines, inhibitors, water or traces
of oil mixed with mill-scale, dirt or sand) may affect the meter’s accuracy by reducing the meter’s crosssectional area and changing the surface roughness, thus affecting the gas velocity profile. Independent of
transducer mounting, deposits may also attenuate or obstruct the ultrasonic sound waves emitted from and
received by the ultrasonic transducers or reflected by the internal wall of the meter.
3.2 Pressures
Ultrasonic transducers used in USMs require a minimum gas density (a function of pressure) to ensure
acoustic coupling of the sound pulses to and from the gas. Therefore, the designer shall specify the expected
minimum operating pressure as well as the maximum operating pressure.
3.3 Temperatures, Gas and Ambient
As a minimum, the USM should operate over a flowing gas temperature range of -4 °F to 140  F (-20 °C to
60  C). The designer shall specify the expected operating gas temperature range.
The operating ambient air temperature range should be at a minimum -40 °F to 140  F (-40 °C to 60  C).
This ambient temperature range applies to the flow meter body with and without gas flow, field-mounted
electronics, ultrasonic transducers, cabling, etc. If the meter and the associated electronics are in direct
sunlight, the temperature limits stated may not be adequate.
The manufacturer shall state the flowing gas and ambient air temperature specifications for the multipath
ultrasonic meter, if they differ from the above.
3.4 Gas Flow Considerations
The flow-rate limits that can be measured by a USM are determined by the actual velocity of the flowing
gas. The designer should determine the expected gas flow rates and verify that these values are within the
range specified by the manufacturer. The designer should also consider the maximum velocity for piping
and equipment safety (e.g., “API RP 14E Offshore Production Platform Piping Systems ”, “API MPMS
Chapter 14, Section 1 Collecting and Handling of Natural Gas Samples for Custody Transfer”, etc.).
USMs have the inherent capability of measuring flow in either direction with equal accuracy; i.e., they are
bi-directional. The designer shall specify if bi-directional measurement is required so that the manufacturer
can properly configure the SPU parameters.
The designer/operator is cautioned that operating ultrasonic meters at flow rates below qt may incur greater
measurement uncertainty due to potential thermal gradients and non-ideal flow profiles.
7
3.5 Upstream Piping and Flow Profiles
Upstream piping configurations (i.e., various combinations of upstream fittings, valves, regulators, and
lengths of straight pipe) may affect the gas velocity profile entering a USM to such an extent that significant
measurement errors may result. The magnitude and sign of any error will be, in part, a function of the
meter’s ability to correctly compensate for such conditions.
Research results have shown that this effect is dependent on the meter design, as well as the type and
severity of the flow profile distortion produced at the meter. Although a substantial amount of data is
available on the effect of upstream piping, the full range of field piping installation configurations has not
been studied in detail.
Meter station designers/operators may gain insight into expected meter performance for given upstream
piping installation configurations by soliciting available test results from meter manufacturers, or by
reviewing test data found in the open literature. To confirm meter performance characteristics for a
particular piping installation configuration, flow calibration of the metering package, with the same
upstream piping configuration, may be required.
3.6 Acoustic Noise
The presence of acoustic noise in a frequency range coincident with a USM’s operating frequency may
interfere with pulse detection and, therefore, transit time measurement. If the USM cannot detect pulses,
the transit times between transducers can’t be measured and flow measurement ceases. Acoustic noise
interference can also cause pulse “mis s-detection” resulting in erroneous transit time measurements that
translate into volumetric errors. Designers shall consider whether interfering acoustic noise is anticipated
at a particular installation and take steps to prevent adverse effects on USM performance during the station
design phase.
Acoustic noise may be generated from numerous sources related to gas flow turbulence: e.g., high gas
velocities through piping and/or fittings, protruding probes, flow conditioners, pressure and regulating
control valves, etc. Since USM manufacturers specify the operating frequencies of their transducers, the
frequency range in which a particular meter might be affected by acoustic noise is known. Dynamic
operating conditions (flow, pressure and temperature), and the variety of acoustic noise generators, make
prediction of offending noise frequencies difficult. Consequently, decoupling a USM’s operating frequency
from piping system noise can be challenging.
Manufacturers recognize the potential for operating problems, and most USMs have diagnostic outputs that
indicate when acoustic noise impairs meter performance. The following strategies have been devised to
estimate and/or limit a USM’s susceptibility to noise interference:
•
•
•
•
Enhanced signal processing to improve ultrasonic pulse recognition and detection
Signal filtering to narrow the bandwidth surveyed for better/faster pulse recognition
Evaluation of USM response to acoustic noise prior to station installation
Attenuation between noise source(s) and USM, if required, could include blind tees, other fittings,
or acoustic filters. The designer should be aware that close-coupling of pipe fittings, such as blind
tee fittings, may distort velocity profiles.
In general, noise sources upstream of USMs have a more adverse impact on meter performance than those
installed downstream, although downstream installation of pressure reduction or other noise generating
equipment does not guarantee interference will not occur.
8
When considering installation of a USM, particularly in the vicinity of pressure or flow regulators, the
following factors should be assessed during the station design phase.
•
The valve’s (i.e., noise source) installed position relative to the meter upstream or downstream,
•
Operating frequency of the meter’s ultrasonic transducers, the range of frequencies generated by
•
•
distance between meter and source, number and type of fittings between meter and source.
the noise source, and any digital signal processing features that can be implemented that do not
impact the accuracy of the meter.
Additional separation between the USM and the noise source.
Signal processing to improve ultrasonic pulse recognition and detection.
When installation of a USM near a potential noise source is anticipated, the designer should contact the
manufacturer prior to finalizing the station design. Cooperation between designer and manufacturers during
facilities design can avoid the need for potentially expensive remedial actions after the meter is placed in
service.
9
4.0 Meter Requirements
The USM shall be designed and constructed of materials suitable for the service conditions for which the meter
is rated, and in accordance with any codes and regulations applicable to each specific meter installation, as
specified by the designer. For example, in the United States, the meter may need to be suitable for operation in
a facility subject to the U.S. Department of Transportation’s (DOT) regulations in 49 C.F.R. Part 1 92,
Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards.
4.1 Quality Assurance
The manufacturer shall establish and follow a written comprehensive quality assurance program for the
production, assembly and testing of the meter and its electronic system (e.g., ISO 9000, API Specification
Q1, etc.). A written description of the quality assurance program shall be made available upon request.
4.2 Flow Meter Body
4.2.1 Maximum Operating Pressure
Meters shall be manufactured to meet one of the common pipeline flange classes (e.g., ANSI Class 150,
300, 600, 900, etc.). The maximum design pressure of the meter shall be the lowest of the rated design
pressure of the flow meter body, flanges, transducer connections, and transducer assemblies. The
required maximum operating pressure shall be determined using the applicable codes for the jurisdiction
in which the meter will be operated and for the specified ambient temperature range. The designer
should provide the manufacturer with information on all applicable codes for the site and any other
requirements specific to the installation and operation.
4.2.2 Corrosion Resistance
All wetted parts of the meter shall be manufactured of materials compatible with natural gas and related
fluids, or other gases as specified by the designer.
All external parts of the meter should be made of a non-corrosive material or sealed with a corrosionresistant coating suitable for use in atmospheres typically found in the natural gas industry and/or as
specified by the designer.
4.2.3 Flow Meter Body Length and Internal Diameter
The manufacturer shall publish its overall face-to-face length of the flow meter body with flanges for
each pressure class and pipe schedule diameter. The internal diameter of the flange face (contact face)
will be within the tolerances published within applicable standards (e.g., ANSI schedule).
The flow meter body inside diameter in the measurement section, as defined by the manufacturer, shall
be of constant diameter to within 0.5% of the average internal diameter of the measurement section.
Refer to Section 4.6.1 for measurement details.
For a flow meter body having an internal diameter different than the associated metering package
piping, a transition taper is allowed as long as the meter conforms to the performance requirements
outlined in this document. The manufacturer shall provide the measurement section internal diameter
along with the internal diameter at the flow meter body flange faces.
10
4.2.4 Ultrasonic Transducer Ports
Because natural gas may contain some impurities (e.g., light oils, glycols, amines, inhibitors or
condensates), transducer ports should be designed in a way that reduces the possibility of liquids or
solids accumulating in the transducer ports.
4.2.5 Pressure Tap
At least one pressure tap shall be provided for measuring the static pressure in the measurement section
of the flow meter body. The designer may specify more than one static pressure connection. Pressure
taps are exclusively designated for measuring static pressure to determine standard volume. Each
pressure-tap hole should be between 1 /8" and 3/8" nominal inside diameter and cylindrical over a length
at least 2.5 times the diameter of the tapping, measured from the inner wall of the flow meter body.
The tap hole edge at the internal wall of the flow meter body shall be free of burrs and wire edges, and
have square edges. For a flow meter body with a wall thickness less than 5/1 6", the hole should be 1 /8"
nominal in diameter.
Female pipe threads should be provided at each pressure tap for a 1 /4" NPT or 1 /2" NPT connection.
Turning radius clearance should be provided to allow a valve body to be screwed directly into the
pressure tap. Pressure taps can be located at the top, left side, and/or right side of the meter body.
Pressure taps may have flanged connections when specified by the designer. The pressure-tap flange
may have a nominal size greater than 3/8”; however, the pressure -tap hole that penetrates into the flow
meter body should remain between 1 /8” and 3/8” nominal inside diameter.
4.2.6 Integral Meters
Manufacturers may provide more than one meter in a single flow meter body to accommodate redundant
measurement. This configuration is allowable provided that the manufacturer ensures that the SPUs do
not interfere with each other, and the excitation of transducers by the SPU(s) does not interfere with
signal detection in either device.
4.2.7 Miscellaneous
The meter should be designed in such a way that the body shall not roll when resting on a smooth
surface with a slope of up to 1 0%. This is to prevent damage to the protruding transducers and SPU
when the USM is temporarily set on the ground during installation or maintenance work.
The meter should be designed to permit easy and safe handling during transportation and installation.
Hoisting eyes or clearance for lifting straps should be provided. The designer can request that the
flanges directly up and downstream of the meter be dowelled to ensure exact positioning upon
reassembly in the field.
4.2.8 Flow Meter Body Markings
A nameplate containing the following information shall be affixed to the flow meter body:
•
•
•
•
•
•
•
The manufacturer, model number, serial number and month and year manufactured
Nominal meter size, flange class and schedule, and total weight
Meter inside diameter (measurement section)
Maximum and minimum storage temperatures
Body design code and material, and flange material
Maximum and minimum operating pressure and temperature
Maximum (qmax) and minimum (q min) actual (at flowing conditions) volumetric flow rate per
hour
11
•
•
Direction of primary or forward flow
(Optional) Purchase order number, shop order number and/or user tag number
The name plate(s) and markings shall be made of materials that will not deteriorate, fade, or peel when
meter is located in an outdoor environment.
Each transducer port shall be permanently marked with a unique designation for easy reference.
4.3 Ultrasonic Transducers
4.3.1 Specifications
The manufacturer shall state the general specifications of their ultrasonic transducers, including critical
dimensions, minimum and maximum allowable operating pressure, operating temperature range and gas
composition limitations.
4.3.2 Rate of Pressure Change
Sudden depressurization of the USM can damage the ultrasonic transducers. The manufacturer shall provide
clear instructions for depressurization and pressurization of the meter and transducers during installation,
start-up, maintenance and operation. Manufacturer shall state acceptable rates of change.
4.3.3 Transducer Tests
The manufacturer shall test transducers and document the results as part of the USM’ s quality-assurance
program. Each transducer shall be marked or tagged with a permanent serial number and be provided with
the general transducer information in Section 4.4.1. If the SPU requires specific transducer characterization
parameters, each transducer or transducer pair shall also be provided with test documentation that contains
the specific calibration test data, calibration method used and characterization parameter(s).
4.4 Electronics
4.4.1 General Requirements
The USM’s electronics system, including power supplies, microcomputer, signal processing
components and ultrasonic transducer excitation circuits, etc., referred to as a Signal Processing Unit
(SPU), may be housed in one or more enclosures and mounted on, next to, or remote from the meter.
The manufacturer shall uniquely identify all circuit boards.
Optionally, a remote unit containing the power supplies and the operator interface may be installed in
a non-hazardous area and connected to the SPU.
The SPU shall operate to meet the meter performance requirements in Section 6 for all environmental
conditions specified in section 3 and Appendix B (Normative).
The system shall contain a monitor function to ensure automatic restart of the SPU in the event of a
program fault or lock-up.
The meter should operate from a power supply of nominal 120V AC or 240V AC at 50 or 60 Hz, or
from nominal 12V DC or 24V DC power supply/battery systems, as specified by the designer.
12
4.4.2 Output Signal Specifications
The SPU shall be equipped with the following outputs:
• Serial data interface; e.g., RS-232, RS-485 or equivalent
• Two programmable frequency outputs representing flow rate at line conditions
• Discrete digital status indicator
The SPU may be equipped with the following additional outputs:
• Analog current loop (4-20 mA, DC)
• Ethernet
• A read-only serial port
• Additional frequency outputs
• Additional digital status outputs
The analog flow-rate signal should be scalable up to 1 20% of the meter’s maximum flow-rate, qmax.
An analog current loop (4-20mA, DC) output shall not be used for custody transfer due to possibility
of increased uncertainty.
A no-flow cutoff function shall be provided that sets the flow-rate output to zero when the indicated
flow rate is below a user specified minimum value.
The manufacturer should provide a selection to make the frequency output go to zero, maximum meter
flow rate, or to a user-selected value when the maximum meter capacity, or maximum calibrated flow
rate, is exceeded.
Two separate flow-rate outputs and a directional state output or serial data values shall be provided for
bi-directional applications to facilitate the separate accumulation of volumes.
All outputs shall be isolated from ground and have the necessary voltage protection to meet the
electronics design testing requirements of Appendix B (Normative).
4.4.3 Electrical Safety Design Requirements
The design of the USM, including the SPU, should be analyzed, tested and certified by an applicable
standards testing laboratory. The meter shall be labeled as approved for operation in a National Electric
Code Class I, Division 2, Group D, Hazardous Area, or similarly accepted electrical code for the
regional location of the installation at a minimum. Intrinsically safe designs and explosion-proof
enclosure designs are generally certified and labeled for Division 1 (or similarly accepted electrical
code for the regional location of the installation) applications. The designer may specify the more
severe Division 1 location requirement to achieve a more conservative installation design.
All exposed USM components shall be resistant to ultraviolet light, heat, oil and grease.
4.4.4 Component Replacement
The ability to replace transducers, cables, electronic parts and firmware is a requirement. Such
replacement shall not cause a change in the meter’s performance greater than the manufacturer’s
published repeatability of the meter. Additionally, component replacement shall not change the meter
package performance from the original calibration results by more than the long-term uncertainty of the
flow calibration test facility. The manufacturer shall provide proven procedures for the user and
sufficient data to demonstrate compliance with this requirement. If the manufacturer cannot meet this
requirement, flow calibration may be necessary. Refer to Section 7.3.3 Maintenance.
13
4.5 Meter Firmware and Software
4.5.1 Firmware
Computer codes responsible for the control and operation of the meter shall be stored in nonvolatile
memory. All flow-calculation constants and the operator-entered parameters shall also be stored in
nonvolatile memory.
The manufacturer shall maintain and publish a record of all firmware revisions, including:
• Revision number
• Date of revision
• Explanation of firmware modifications, additions, and the reason for any changes
• Explanation of any metrological effects
• Applicable meter models
• Circuit board revisions for which the firmware is applicable
The firmware revision number, revision date, serial number and/or checksum(s) shall be available and
capable of being displayed by the meter or interface device, for example:
• Local display
• Flow computer
• Operator software interface
4.5.2 Associated Flow Computing
The flow computer functions may be performed by an external device or directly integrated into the
USM’s SPU. For bi-directional applications, the USM shall be treated as two separate meters,
associated with two “meter runs” in a single flow computer or with two separate flow computers.
Adequate inputs and outputs shall be available to carry out these computational tasks.
For applicable flow computer requirements, the designer should reference API MPMS Chapter 21.1/
AGA Report No.13, Flow Measurement Using Electronic Metering Systems – Electronic Gas
Measurement.
Calculations
The calculation equations used in a flow computer for a USM shall be those described in AGA Report
No. 7, “Measurement of Natural Gas by Turbine Meters.” These equations correct for pressure,
temperature and compressibility of the flowing gas. The required calculations are summarized in the
following expressions:
Where:
Qb = Qf (Pf /Pb ) (Tb /Tf ) (Zb /Zf )
Vb =  Qb dt
Qb =
Qf =
Pb =
Pf =
Tb =
Flow rate at base conditions
Flow rate at flowing conditions
Absolute base pressure
Absolute static pressure of gas at flowing conditions from meter tap
Absolute base temperature
14
Absolute temperature of gas at flowing conditions
=
Compressibility factor of gas at base conditions
=
Compressibility factor of gas at flowing conditions
=
Accumulated volume at base conditions
=
Integrated over time
= Integration increments of time, typically one second
Tf =
Zb
Zf
Vb

dt
4.5.3 Alarms
The following alarm-status outputs should be provided in the form of fail-safe relay contacts or voltagefree solid-state switches isolated from ground:
• Output invalid: when the indicated flow rate at line conditions is invalid
• (Optional) trouble: when any of several monitored parameters fall outside of normal operation
for a significant period of time
• (Optional) partial failure: when one or more of the multiple ultrasonic path results is not usable
4.5.4 Meter Diagnostics
The manufacturer shall provide, via a digital data interface, the following meter diagnostics as a
minimum:
• Average flow velocity through the meter
• Flow velocity for each acoustic path (or equivalent for evaluation of the flowing velocity
profile)
• Average meter speed of sound
• Speed of sound (SOS) along each acoustic path
• Path Automatic Gain Control (AGC), gain level or similar indication of the signal strength
• Indication of accepted / rejected pulses for each acoustic path
• Signal to noise ratio (SNR) or equivalent
Additional diagnostic indicators that may be provided by the manufacturer are listed in Appendix E
(Informative).
4.5.5 User Interface Software
The meter shall be supplied with the capability for on-site or remote configuring of the SPU, and for
monitoring the meter’ s operation. The software shall be able to display and record the diagnostic data
as specified in Section 4.5.4, and the inspection and auditing functions as specified in Section 4.5.6.
4.5.6 Inspection and Auditing Functions
It shall be possible for the auditor or the inspector to obtain, view and print the flow measurement
constants and configuration parameters used by the SPU; e.g., calibration factors, firmware revision
number, revision date, serial number, checksum(s), meter dimensions, time averaging period and
velocity sampling rate. It shall be possible to verify metrological flow calculation factors and parameters
while the meter is in operation.
Provisions shall be made to prevent an accidental or undetectable alteration of those parameters that
affect the performance of the meter. Suitable provisions may include a sealable switch or jumper, a
permanent programmable read-only memory chip, or a password in the SPU.
15
4.6 Individual Meter-Manufacturing Tests and Checks
Prior to the flow calibration and/or field operation of each USM package, the meter manufacturer shall
perform the following tests and checks. The results of all tests and checks performed shall be documented
and provided in a report to the designer or operator, and retained by the manufacturer for a minimum of 10
years.
4.6.1 Dimensional Measurements
The manufacturer shall measure and document the average internal diameter of the meter, the length of
each acoustic path between transducer faces and the axial (flow meter body axis) distance between
transducer pairs (or angle of each acoustic path).
The average internal diameter should be calculated from a total of 12 internal diameter measurements.
Four internal diameter measurements (one in the vertical plane, another in the horizontal plane and two
in planes approximately 45  from the vertical plane) shall be made at three meter cross-sections: 1) near
the set of upstream ultrasonic transducers, 2) near the set of downstream transducers and 3) half way
between the two transducer sets.
If the acoustic path lengths or the axial distances between ultrasonic transducer pairs cannot be directly
measured, then the unknown distances shall be calculated using trigonometry and distances that can be
measured directly. Where the measurement of angles is difficult and the result is imprecise, such
measurements shall not be used to calculate the required distances.
The flow meter body temperature shall be measured and documented at the time these dimensional
measurements are made. The measured lengths shall be corrected to an equivalent length at a meter
body temperature of 68  F (20 C) by applying the applicable coefficient of thermal expansion for the
flow meter body material.
All instruments used to perform these measurements shall have valid calibrations traceable to national
standards; e.g., National Institute of Standards and Technology (NIST) in the U.S.A.
These measurements and calculations shall be documented on a certificate, along with the name of the
meter manufacturer, meter model, meter serial number, flow meter body temperature at the time
dimensional measurements were made, date, name of the individual who made the measurements and
name of the inspector, if present.
4.6.2 Leakage Test
Every USM, complete with transducers and transducer isolation valves (if used), shall be leak-tested
by the manufacturer after final assembly and prior to shipment to the designer, fabricator or flowcalibration facility. The test medium should be an inert gas such as nitrogen. The leak test pressure
shall be a minimum of 200 psig (1380 kPa), or the meter’s maximum pressure rating, whichever is less.
This pressure shall be maintained for a minimum of 15 minutes, with no leaks detectable with a noncorrosive liquid solution or an ultrasonic leak detector as described in ASTM E1002 (latest revision).
This leak test does not preclude the requirements to perform a hydrostatic test.
4.6.3 Zero-Flow and SOS Verification Test
The manufacturer shall perform a zero-flow verification test to obtain and document the zero-flow
reading. The manufacturer shall follow a detailed test procedure that includes the following elements,
at a minimum:
16
•
If zero-flow verification is performed at elevated pressure, blind flanges shall be attached to
the ends of the flow meter body. The selection of the reference gas shall be the responsibility
of the manufacturer. Air at atmospheric pressure and room temperature can be used as a
reference gas if the USM performs under such conditions. The acoustic properties of any
reference gas shall be well known and documented.
•
The gas pressure and temperature shall be allowed to stabilize at the outset of the test. The gas
velocities for each acoustic path shall be recorded for at least 30 seconds. The mean gas velocity
and standard deviation for each acoustic path shall then be calculated.
•
Adjustments to the meter shall be made as necessary to bring the meter performance into
compliance with the manufacturer’s specifications and the specifications stated in this report.
The measured speed-of-sound values shall be compared with the theoretical value computed using a
complete compositional analysis of the reference gas, measurements of the reference gas pressure and
temperature, and the equation of state used in AGA Report No. 8, Part 1 : DETAILED Equation of State
or Part 2: GERG-2008 Equation of State.
As part of the test procedure, the manufacturer shall document the ultrasonic transducer serial numbers
and their relative locations in the flow meter body. The manufacturer shall also document all parameters
used by the meter, e.g., transducer/electronic transit-time delays, zero-flow reading for each acoustic
path, incremental timing corrections, and all acoustic path lengths, angles, diameters and other
parameters used in the calculation of the gas velocity for each acoustic path. The manufacturer shall
note if the constants are dependent on specific transducer pairs.
The zero-flow verification test shall meet the following requirements:
•
•
•
•
•
The individual path gas velocity no greater than ±0.02 ft/sec (0.006 m/sec)
The speed of sound per path within ±0.2% of the theoretical value
Percentage of accepted pulses for each acoustic path are 1 00%
All gain levels are within the nominal limits provided by the manufacturer
Maximum SOS path spread not greater than 1 .5 ft/s (0.5 m/s)
Any per-path zero-flow issues outside the above specification shall be corrected at the path level. The
manufacturer may not implement a bulk zero-flow offset factor based on the zero-flow calibration.
Once all of the above conditions are satisfied, the flow calibration of a meter with the metering package
may commence at an operator-approved flow calibration facility.
4.7 Documentation
The manufacturer shall provide or make available the following set of documents, as a minimum, when
requested for quotation. All documentation shall be dated.
•
•
•
•
•
•
Description of the meter giving the technical characteristics and the principle of its operation.
Dimensioned drawing and/or photograph of the meter.
Nomenclature of parts with a description of constituent materials of such parts.
Description of the available output signals and any adjustment mechanisms.
A list of the documents submitted.
A recommended spare parts list.
17
The manufacturer shall provide all necessary data, certificates and documentation for correct configuration,
set-up and use of the meter upon delivery. The manufacturer shall provide the following set of documents
upon request. All documentation shall be dated.
• Certified dimensional meter drawings, including but not limited to overall process connection
dimensions, ratings, maintenance space clearances, conduit connection points, and estimated
weight.
• Meter-specific electrical drawings showing the customer wiring termination points.
• Instructions for installation, operation, periodic maintenance and troubleshooting.
• Description of software functions and configuration parameters at the time of shipment.
• Documentation that the design and construction comply with applicable safety codes and
regulations.
• A field verification test procedure as described in Section 7.2 “Field Verification.”
• Drawing showing the location of verification marks and seals if applicable.
• Drawing or picture of the data plate or face plate and of the arrangements for inscriptions.
• Drawing of any auxiliary devices.
• Copies of hydrostatic test certificates, material certificates, weld radiographic reports, and other
quality tests as specified by the designer.
• Results of the zero-flow verification results.
18
5.0 Installation
The metering package shall be installed to ensure it meets the performance requirements of this document.
5.1 Environmental and Process Considerations
Care should be taken to ensure that the performance of the metering package is not adversely affected by
environmental and process conditions.
5.1.1 Ambient and Flowing Temperature
In applications when the ambient temperature can be outside of the manufacturer’ s recommended
temperature range, consideration should be given to providing shelter, insulation, heating and/or cooling
for the metering package. This includes, but is not limited to, the upstream piping spool(s), USM
assembly, the downstream piping spool(s), and all secondary measurement equipment. Providing
properly sized shelter, insulation, heating and/or cooling should ensure that the meter is operating within
the manufacturer’s stated temperature limits and minimize gas temperature stratification.
Shelters or temperature-controlled enclosures should also be considered for USMs located in areas
subject to large cycling in ambient temperature and/or high radiant energy potential. Even if such
temperature cycles are within the manufacturer’s specification, over extended periods , the cycling may
stress and damage the SPU electronics. Flowing gas temperature measurement may be influenced by
radiant energy effects.
5.1.2 External Mechanical Vibration
External vibration sources may cause permanent mechanical damage to electronic boards and
components, card cages, wiring and connectors, all of which will negatively affect USM performance.
USMs should not be installed where vibration levels or frequencies might excite the resonant
frequencies of SPU boards, ancillary components and ultrasonic transducers. The manufacturer shall
provide vibration-testing results when available. Care should be taken to ensure compliance with local
rules and regulations governing mechanical vibrations. (See Appendix B (Normative)).
5.1.3 Electrical Noise
USM designs shall be tested by the manufacturer to ensure immunity to electromagnetic radiation
influences in accordance with current available standards. The USM and ancillary devices integral to
the meter, its connective wiring and conduits shall not be negatively influenced by external direct and/or
alternating electromagnetic radiation created by, but not limited to, solenoid transients, wireless
networks, 2-way radio communications and cathodic protection systems. The manufacturer shall
provide instrument specifications and test results related to electromagnetic radiation influences. See
Appendix B (Normative).
5.1.4 Process Pulsation
The designer should consider the possible existence of pulsation in the vicinity of the ultrasonic meter
caused by but not limited to flow, control valves, check valves, mechanical installation and/or induced
by compression.
The designer should provide an appropriate piping design or dampening solution to mitigate the
potential increase in measurement uncertainty caused by the pulsations.
A pulsation study may be required to arrive at the correct pulsation-dampening equipment,
configuration and location.
19
5.1.5 Acoustic Noise
When installing a USM near a potential noise source, it is recommended that the designer contact
manufacturers for recommendations prior to finalizing station design.
Noise calculation methods for pressure regulating valves are outlined in various publications such as
IEC-60534-8-3 and ISO 17089.
IEC-60534-8-3 discusses the acoustic noise in the audible range (< 20 kHz) outside of the pipe.
However, to calculate the audible noise outside the pipe, this method initially calculates the noise inside
the pipe based on the different types of valve/trim construction. As such, data is available on the
frequency spectrum inside the pipe. This data may be extrapolated to the ultrasonic frequency range of
the USM transducers and may provide a good approximation of potential ultrasonic noise present inside
the pipe. Refer to Section 3.6 for more detailed information and mitigation options.
5.1.6 Filtration and Separation
The accumulation of deposits due to mixtures of dirt, mill scale, condensates, glycols and/or lubricating
oils may impact the meter’s performance and should be avoided. Filtration and/or separation equipment
upstream of the metering package may be necessary when any of these conditions exist.
5.2 Metering Package Design Criteria
5.2.1 Installation Configuration
As previously noted in Section 3.5, various combinations of upstream fittings and valves can produce
velocity profile distortions at the meter that may result in measurement errors. The amount of meter
error will depend on the type and severity of the velocity profile distortion produced by the upstream
piping configuration and the meter’s sensitivity to these distortions , and will vary by meter design.
Research has demonstrated that asymmetric velocity profiles may persist for 50 pipe diameters or more
downstream from the initiation point while swirling velocity profiles may persist for more than 200
pipe diameters.
Although mitigation of distorted velocity profiles is commonly provided through the use of flow
conditioners, some meter designs may not require the use of flow conditioning. The manufacturer shall
provide test data generated by an independent flow-calibration laboratory that verifies meter
performance without a flow conditioner when subjected to the disturbed flow tests listed in Appendix
C (Normative). However, because flow conditioners are designed to produce an exit velocity profile
that reduces the effect of most upstream flow disturbances, the use of flow conditioning is
recommended to provide the basis for a repeatable and stable metering package. Flow conditioning
element(s) shall be qualified under Appendix C (Normative) and properly installed as per the
manufacturer’s instructions. The ability to confidently transfer the results of the calibration facility to
a field installation is greatly increased by using a properly qualified and installed flow conditioner.
The following options for configuration of an installed metering package are available for selection by
the designer/operator. The validity of each option to a specific meter model shall be confirmed by the
meter manufacturer and supported by test data. Data shall be obtained from an independent flow
calibration laboratory verifying the metering package design performs within the ±0.3% limit described
in Appendix C (Normative) when subjected to the required flow disturbance tests. The meter
manufacturer shall provide such test data when requested by the designer/operator.
20
Option 1: A conservative configuration with a flow conditioner (between spools UL1 and UL2) as
shown below. The manufacturer shall specify the flow conditioner(s) approved for use in this
configuration based on independently certified test data.
Where:
UL1 = min. 1 0 ND length
UL2 = min. 1 0 ND length
DL = Variable
Option 2: Manufacturer-recommended configuration with use of a flow conditioner between spools
UL1 and UL2 as shown below. The manufacturer shall specify the lengths of UL1 and UL2, as well as
the flow conditioner(s) approved for use in this configuration, based on independently certified test
data.
Where:
UL1 = Manufacturer-specified
UL2 = Manufacturer-specified
DL = Variable
Option 3: Manufacturer-recommended configuration with one upstream spool and no flow conditioner
as shown below. The manufacturer shall specify the length of UL1 based on independently certified
test data.
Where:
UL1 = Manufacturer-specified
DL = Variable
For bi-directional flow; upstream piping spool(s) and flow conditioner as applicable from Options 1 , 2
or 3 can be used on both ends of the metering package.
21
To reduce uncertainty that may result from field installation effects, the designer/operator may consider
calibrating the metering package with the upstream and downstream piping configuration identical
(size, fittings, lengths, orientation, etc.) to the planned field installation.
5.2.2 Alternative Installation Configuration
If the meter manufacturer is unable to provide the supporting test data required in Section 5.2.1, the
designer/operator may choose to flow-calibrate the metering package in-situ (where practicable), or in
a flow-calibration facility where the test piping configuration upstream and downstream of the metering
package are identical to the planned installation. In such cases, the metering package shall be calibrated
with end treatments (for inspection/cleaning, if used), the upstream riser or header including at least
two preceding pipe fittings that may cause flow disturbances, and the downstream riser or header. The
metering package and all piping elements shall be installed in the flow calibration facility to replicate
the orientation and spacing designed for the field installation.
5.2.3 Internal Surfaces
Experience has shown that a meter tube internal surface roughness (Ra) of 250 inch, or less, can be
advantageous in minimizing pipeline fouling contamination buildup and promote long-term stability.
To allow for the use of commercially available pipe, the practical roughness measurements for tubes
less than NPS 16 can be < 250 µinch and < 350 µinch for NPS 16 and larger. The presence of mill scale
and/or pitting can greatly accelerate the buildup process and should be avoided.
5.2.4 Protrusions and Alignment
Changes in internal diameters and protrusions shall be avoided in the metering package as they may
increase turbulence, vortex shedding and flow-profile distortions. The flanges at the meter and adjacent
piping internal diameters shall match to within 1% and be aligned to minimize flow disturbances,
especially at the upstream meter flange connections. All internal welds within the metering package
shall be ground smooth and flush with the pipe wall. No part of the upstream gasket, spacer ring or
flange face edge shall protrude into the flow stream. Gaskets with internal retention rings are
recommended, and the gasket internal diameter (ID) should be approximately 1 /8” larger than the pipe
ID. During installation care should be taken to ensure proper placements of gaskets, flow conditioner,
(when utilized), and any spacer plates prior to tightening of the bolts.
5.2.5 Thermowell(s) and Sample Probe(s)
The USM manufacturer should recommend the thermowell orientation with respect to acoustic paths.
For unidirectional flow, the designer shall have the thermowell installed downstream of the meter. The
first thermowell should be located at least 6 inches from the flange weld or 2 ND whichever is larger,
and no farther than 5 ND from the downstream USM flange face. For bi-directional flow installations,
the first thermowell(s) should be located at least 3 ND and no farther than 5 ND from either the USM
flange face or the end of measurement section.
For dual USM installations where the meters are directly connected together in series, the first
thermowell should be located at least 6 inches from the flange weld or 2 ND whichever is larger, and
no farther than 5 ND from the downstream USM flange face of the downstream meter.
In a bi-directional application if the flow is predominantly in one direction then it is recommended that
the temperature measurement be located downstream of the primary direction of the USM. It is not
22
required to install temperature measurement on the upstream side of the USM for reverse flow
measurement.
It is important that the thermowell be correctly installed to ensure that heat transfer from the piping,
radiant effects of the sun and thermowell attachments do not influence the temperature reading. The
recommended insertion length for thermowells and sample probes is between 1/3 ND to 1/2 ND for
line sizes NPS 2 to NPS 10 and 1/5 ND to 1/3 ND for line sizes NPS 12 and larger. Special thermowell
design may be required for insertion lengths greater than 1/3 ND.
The designer is cautioned that high gas velocities may cause flow-induced thermowell or sample probe
vibration. Catastrophic metal fatigue of these elements could result. For maximum probe length
calculations refer to ASME PTC 19.3 TW-2010.
For recommendations on the installation of sample probes refer to API MPMS Chapter 14, Section 1,
Collecting and Handling ofNatural Gas Samples for Custody Transfer, or other equivalent international
standards.
5.2.6 Flow Conditioning
A flow conditioner is optional, depending on the metering-package design, the severity of any upstream
flow profile disturbance and the desired or required metering package-measurement performance. The
manufacturer(s) should be consulted to determine the requirements of installing a particular type of
flow conditioner, when used, for a given upstream piping configuration and flow-meter path design.
All recommendations made by manufacturer(s) of the flow meter and the flow conditioner shall be
substantiated by test results and shall be provided to the designer/operator and be from an operatorapproved facility and/or governing body, all in accordance with Appendix C (Normative). See Section
5.2.1 for recommended positioning of a flow conditioner.
5.2.7 Orientation of Meters
The designer shall consult with the manufacturer to determine preferred meter orientations for an
intended upstream piping configuration. Orientation refers to horizontal, vertical and rotational
positioning. The metering package should be oriented during flow calibration to match the field
installation.
5.2.8 Meter Tube Inspection and Cleaning Ports
If utilized, meter tube inspection ports should be located a minimum of 3 ND downstream and/or
upstream of the ultrasonic flow-meter body flanges. Inspection ports for the flow conditioner should be
located 3 ND upstream of the flow conditioner. The port diameter should not exceed 6% of the pipe
diameter for meters larger than 1 2” and 0.750” (3/4 inch) for meters 1 2” and smaller.
Care should be taken to limit the dead volume present in components that may be connected to the
inspection port, in order to prevent the possible creation of resonance effects.
Inspection ports should be installed such that flow disturbance caused by them should not adversely or
directly influence the transducer acoustic paths.
When inspection and/or cleaning ports are installed as part of the metering package, the metering
package shall be flow-calibrated to remove any possible bias error caused by the ports.
Meter tube cleaning ports, if utilized, shall be located at either end of the metering package.
23
5.3 Close-Coupled Series Metering
Meters may be installed in series and close-coupled to provide check or redundant measurement. Meters
used can be from different manufacturers or can be of different path configurations to reduce common mode
errors. Care should be taken to ensure that the transducer ports and/or transducer excitation of each meter
does not interfere with flow stability and/or signal detection of an adjacent meter(s) and independent outputs
shall be provided for each meter. The complete custody transfer metering assemblies, including both meters,
shall be calibrated together.
5.4 Handling
5.4.1 Preparation and Packaging
The meter and associated piping shall be assembled prior to calibration either at the manufacturing
facility or the calibration lab. Individual components or the entire metering package should be prepared
and packaged to avoid marring of the internal and external finishes as well as physical damage from
lifting and moving equipment.
Upon calibration completion, the entire meter package should remain intact when logistically practical.
Prior to packaging, all piping components shall be labeled, indexed, and referenced to ensure proper
reassembly and alignment to match the calibrated assembly.
Manufacturer- and/or project-specific preservation and packaging requirements should be met to ensure
that the metering package is protected from potential normal and site specific potential damaging effects
including rust and corrosion.
5.4.2 Lifting and Supports
Proper lift points shall be identified by the designer on the components of an assembled metering
package and lifting instruction shall be part of documentation provided upon delivery of the metering
package. Care should be taken to ensure that lifting is carried out in a safe and proper manner per
industry guidelines. Lifting eyes on the meter are not designed for lifting the entire assembled metering
package.
Anti-roll mechanisms installed on USMs are designed to stabilize the flow-meter body only and are not
sufficient to prevent rotational movement of the metering package in storage and during shipment.
Blocking and support during transport of the metering package to the final destination needs to be
carefully considered and installed based on transportation methodology to prevent excessive movement.
5.5 Miscellaneous Design Considerations
The following items should be considered during design, fabrication, and installation to ensure ease of
maintenance activities.
1.
Meter run slope
2.
Pipe sag / Pipe supports
When the potential of liquid accumulation exists, an adequate slope in the direction of the flow may be
used to ensure drainage of liquids that may accumulate in metering packages.
Piping supports should be used to prevent sagging or lateral movement of the metering package. The
supports should be located along the metering package spools and at the inlet and outlet piping.
24
3. Spacer plates
At least one spacer plate should be used to facilitate easy installation and removal of meter-tube spools
or the flow conditioner for inspection and cleaning. It shall not be located on the meter flanges or the
downstream side of the flow conditioner.
4. Lifting and removal considerations
Crane access and overhead clearance should be considered to provide a means of easily maintaining
the metering package. This is especially critical when structures and enclosures are used to protect the
metering package.
5. Adequate spacing for maintenance / Transducer replacement
As recommended by the USM manufacturer, sufficient space around the metering package needs to be
allowed. Consideration should be given for routine maintenance and inspection and the possible use of
specialty tools for transducer removal.
6. Onsite inspection and cleaning considerations
Periodic on-site inspections and cleaning may be required to maintain maximum performance;
considerations should be made to allow for easy access to the metering package and its inspection ports
when used to perform these functions and to facilitate easy cleaning should build up develop.
7. Pressurization and de-pressurization considerations
Care should be taken to follow manufacturer’ s guidelines for pressurization and de -pressurization to
protect the integrity of components that may be adversely affected. Use of small-bore valves or
restriction devices should be considered to prevent rapid pressurization or de-pressurization.
8. Meter bypass / Proving connections
Consideration should be given to installing a bypass around the metering package to maintain
continuous flow during maintenance and inspection activities. It is recommended that the bypass
include double block and bleed features.
When on-site proving will occur proper piping and/or connections should be in place.
9. Connectivity
It is important to provide adequate wiring for communication connectivity to the USM. This may
include, but is not limited to, wiring for pulse and status outputs, 4-20 mA, RS232/485, Ethernet, and
USB to take advantage of continuous USM diagnostics monitoring.
25
6.0 Flow Calibration and Performance Requirements
It is a requirement that all custody transfer metering packages be flow-calibrated in a flow-calibration facility
or by a calibration system that is traceable to a recognized national or international standard. Prior to the flow
calibration and/or field operation of each USM metering package, the following tests and checks on each meter
shall be performed. The results of all tests and checks described in this section that are performed on each meter
shall be documented in a report produced by the flow-calibration facility (see Section 6.5.1).
The following specifies the minimum performance requirements that ultrasonic meters shall meet during flow
calibration.
6.1 Preparation for Flow Calibration
Before flow calibration the following shall be performed:
1. Prior to shipping the meter to the flow-calibration lab a zero-flow verification test shall be
performed (see Section 4.6.3).
2. Review the supplied factory test documentation per Section 4.7.
3. Inspect the metering package for any obvious damage or contamination and verify that the physical
meter configuration matches the configuration specified by the designer/operator.
4. Verify that the electronic configuration in the meter matches the configuration provided by the
manufacturer for the supplied meter.
5. Configure the test in such a way that the meter is calibrated using the output signal, calibration
method, test points, and verification points requested by the operator.
6. Verify that the appropriate firmware version is installed as specified by the designer/operator and/or
local metrological authority.
7. Ensure that the meter and any associated piping have been assembled, and that all required
thermowells and sample probes have been installed as required by the designer/operator. The
preferred installation of a thermowell and/or sample probes is downstream. If the thermowells or
sample probes are required upstream, as in the case of a bi-directional application, they shall be
installed prior to flow calibration.
6.2 Metering Package Flow-Calibration Test
The following nominal flow-rate test points are recommended: 0.025 qmax, 0.05 qmax, 0.10 qmax, 0.25 qmax,
0.50 qmax, 0.75 qmax, and qmax. The designer may also specify additional flow calibration test points at other
flow rates, and express the test points in terms of velocity or percentages of maximum velocity or flow rate
qmax value. Unless otherwise specified, the same forward flow rates should be used for the reverse flow
direction during bi-directional flow calibrations.
Calibration tests shall be designed in such a manner as to yield statistically significant measurement results
taking into considerations factors such as the number of flow-rate test points, the duration of data-collection
time for each flow-rate test point, and the number of repeat readings of each flow-rate test point.
It may not be possible to test the USM package to the maximum capacity because of the limitations of flow
calibration facilities. The designer should then specify a maximum flow rate that shall be used for the
calibration. The decision to use the meter beyond the maximum calibrated flow rate may be considered with
the recommendation from the manufacturer based on experience.
26
The designer, operator and/or manufacturer should provide the calibration facility with the following
information.
1.
Meter assembly handling instructions, rigging and lifting plan
2.
Meter size
3.
Meter tube data such as pipe schedule, ID, lengths and ANSI rating
4.
Flow conditioner(s) type and placement
5.
Maximum flow rate, or velocity, as defined by designer, operator and/or manufacturer
6.
Output signal to be used for calibration such as serial data, frequency or analog
7.
Position of thermowell(s) and/or temperature element
8.
9.
Additional testing data points when desired
A drawing showing the metering package assembly and any special installation requirements
1 0. Any special instructions, such as those for bi-directional calibrations
1 1 . A statement specifying whether the ultrasonic meter, flow conditioner(s) and meter tube will remain
assembled after calibration; when disassembled, orientation marks shall be provided for reassembly
1 2. Position, size, type and location for sample system probe components or any other flow
disturbances
During the calibration, meter diagnostic data shall be accumulated at each flow rate using the USM
manufacturer’s software. A minimum of 1 20 seconds of diagnostic data at each flow rate is recommended.
At least one SOS deviation check shall be done for each flow rate during the calibration. This meter
diagnostic data, and results of the SOS deviation check, can be used to develop a baseline of the meter’s
performance.
Thermodynamic or physical properties used during flow calibration shall be computed using methods from
AGA Report No. 8, Part 1 : DETAILED Equation of State or Part 2: GERG-2008 Equation of State.
When the manufacturer recommends any changes to the meter configuration prior to flow calibration, the
manufacturer shall advise the designer or operator of the recommendation for the flow calibration facility
to perform the needed meter-configuration changes. The flow-calibration facility shall maintain a record of
the initial meter configuration as received from manufacturer and keep a record of all subsequent changes.
All upstream elements that may protrude into the pipe such as thermowells and/or sample probes shall be
installed prior to the flow calibration. All flanges shall be aligned to minimize any misalignment or gasket
protrusions.
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6.3 Metering Package Performance Requirements
This section specifies a set of minimum USM performance requirements. A metering package is flowcalibrated to reduce measurement uncertainty below the manufacturer's minimum stated un-calibrated
performance requirements.
The designer is advised that the metering package “as -found” performance results can be a function of
piping configuration. The pipe fitting arrangement on the upstream side of the metering package can cause
error results that are greater than the values published in the following performance requirements.
USMs shall meet the following general flow measurement performance requirements prior to making any
calibration factor adjustment.
Repeatability:
≤ qi ≤qmax
±0.4% for qmin ≤qi ≤qt
±0.2% for qt
Resolution:
Velocity Sampling Interval:
SOS Deviation:
Maximum SOS Path Spread:
0.003 ft/s (0.001 m/s)
≤ 1 second
±0.2%
1 .5 ft/s (0.5 m/s)
Table 1 – General Performance Specification
The designer is referred to Section 6.5 and this section for an explanation of the methods and benefits of
flow calibrating a metering package and for calibration factor adjustment. The designer should also follow
carefully the installation recommendations of Section 5 as any installation effects may add to the overall
measurement uncertainty.
For each meter design and size, the manufacturer shall specify flow rate limits for q min, qt, and qmax.
28
Performance of the metering package shall meet the following requirements as determined during an as
found test at the flow calibration facility, for each flow rate, prior to making any calibration factor
adj ustment. The following criteria are to be assessed at the flow calibration conditions:
For meters 12” and larger:
±0.7% for qt ≤qi ≤qmax
Maximum Error:
±1 .4% for qmin ≤qi ≤qt
Maximum Peak to Peak Error:
±0.7% for qt ≤qi ≤qmax
±1 .4% for qmin ≤qi ≤qt
For meters 4” to 10”:
±1 .0% for qt ≤qi ≤qmax
Maximum Error:
±1 .4% for qmin ≤qi ≤qt
Maximum Peak to Peak Error:
±1 .0% for qt ≤qi ≤qmax
±1 .4% for qmin ≤qi ≤qt
For meters less than 4”:
±2.0% for qt ≤qi ≤qmax
Maximum Error:
±3.0% for qmin ≤qi ≤qt
Maximum Peak to Peak Error:
±1 .0% for qt ≤qi ≤qmax
±1 .4% for qmin ≤qi ≤qt
Table 2
– Size-Specific Performance Specification
29
Figure 1 - Performance Specification Summary
6.4 Pressure, Temperature and Gas Composition Influences
The USM shall meet the flow-measurement accuracy requirements in Section 6.3 over the user’s specified
range of operating pressure, temperature and gas composition without the need for adjustment, unless
otherwise stated by the manufacturer. When the USM requires a configuration change to characterize the
flowing gas conditions, such as gas density, pressure, temperature or viscosity, the manufacturer shall advise
the designer or operator regarding the sensitivity of these parameters. The designer or operator can apply
any changes should the operating conditions change.
6.5 Calibration Adjustment Factors
Calibration adjustment factors shall be applied to minimize any indicated meter-bias error. The accepted
methods of applying adjustment factors are:
• Single factor such as Flow-Weighted Mean Error (FWME) factor, or a zone-weighted single factor
• Polynomial algorithm
30
•
•
Piece-wise / Multi-point linear (PWL) interpolation
Or other industry accepted method
For a more detailed description of calibration adjustment factor application refer to Appendix A
Informative).
The purpose of conducting verification tests is to verify any metering bias has been minimized.
At least two verification points shall be taken after applying more than one adjustment factor. The designer
or operator may specify as many verification points as may be desired to assure that meter correction factors
have been correctly entered into the meter. There are several options to consider in choosing the verification
points described below. Examples of three commonly used industry methods are:
•
•
•
One verification point at an expected operating flow rate and one at previous as-found flow rate.
One verification point at an as-found flow rate, and one between two as-found flow rates.
Two verification points between two different as-found flow rates.
For bi-directional flow calibrations, a second set of calibration adjustment factors shall be used for reverse
flow.
6.5.1 Calibration Test Reports
The results of each test required in Section 6 shall be documented in a report prepared by the flow
calibration facility and supplied to the designer or the operator. The report for each meter shall include,
as a minimum, the following:
1.
The name of the manufacturer
2.
The name and address of the flow calibration facility
3.
The model and serial number of the meter
4.
The meter firmware version number
5.
The date(s) of the calibration
6.
The name and title of the person(s) who conducted the calibration(s)
7.
A reference to the facility calibration procedures used
8.
The upstream and downstream piping configuration used during flow calibration to include any
user specified ancillary components like filters, end treatments (tees), etc.
9.
The serial numbers of all piping and flow conditioners, when available
1 0. The “as - found” and “as -left” configuration parameters
1 1 . All calibration data, including flow rates, velocities, errors, pressure, temperature and gas
composition
1 2. A statement of uncertainty for the test conditions with reference to the method used
1 3. List of primary element(s) used at the flow calibration facility for meter calibration, when
requested
1 4. An identification of adj ustment method applied and adj ustment factors applied
1 5. Number on each page in the calibration report, such as 1 of 3
1 6. Typed names below signatures of all people who sign the calibration report
At least one copy of the complete report shall be sent to the entity that contracted with the calibration
facility, or as specified. The flow calibration facility shall ensure that the complete report is available
to the operator upon request for a period of 1 0 years after calibration of any meter.
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6.5.2 Final Considerations
Upon completion of the calibration, the complete metering package shall be marked to indicate
alignment of flanges at time of calibration. It is recommended that the designer consider leaving the
complete metering package assembled for shipment to the final installation location if logistically
feasible. Flow conditioner alignment shall also be marked when not already done so by the flow
conditioner manufacturer. Thermowells, sample probes and any other item protruding into the flow
stream should remain as installed to ensure the flow calibration transfers to the field and remains as the
final installation in the field.
A copy of the flow lab calibration as-left configuration report and baseline log file(s) should accompany
the meter to the field installation location. Other arrangements may be made by the parties of the
calibration services contract.
The meter diagnostic log files, obtained at the time of flow calibration, establish the meter baseline data.
Meter diagnostic analysis and SOS checks shall be included to provide a baseline of the metering
package performance. This baseline data can be used to verify the meter’ s performance upon startup,
during operation and after component changes. The baseline data can also be useful in conducting
historical meter diagnostic health checks of the metering package.
32
7.0 Commissioning, Field Verification, Maintenance and Recalibration
Section 7 offers guidance with respect to commissioning the calibrated and installed metering package, field
verification of performance indicators to establish comparison criteria for short and long-term verifications and
recalibration recommendations.
7.1 Commissioning
Commissioning is the process of the initial verification and documentation that the USM is installed and
functioning according to its specification, design, and regulatory/contract requirements. Installation
verification may include, but is not limited to, electrical wiring, signal outputs, data mapping, meter
configuration, and mechanical installation. The verification of the test result documentation and USM
configuration to these test certificates is an important part of commissioning.
During this process an initial diagnostic baseline can be created by comparing the diagnostic data collected
during the flow calibration and the diagnostic data collected during commissioning. This should ideally be
at flow conditions and velocities similar to those recorded at the calibration facility.
Note: See Appendix E (Informative) for a commissioning checklist sample.
7.2 Field Verification
The manufacturer shall provide a field verification test procedure to the operator that will allow the USM
to be functionally tested to ensure that the meter is operating properly. These procedures may include a
combination of a zero-flow verification test, speed-of-sound measurement analysis, individual path
measurement analysis, internal inspection, dimensional verification and other mechanical or electrical tests.
1. The field verification of a USM consists of comparing current meter diagnostic data against initial
diagnostic baseline values or to a prior-known good value to identify possible changes in the USM
performance. It is recommended that field verifications be conducted following commissioning. The
frequency of verifications should be guided by the meter data history, volume, operating conditions,
and/or operator policy.
2. Evaluation of any changes to these diagnostic indicators and their potential cause may guide the
operator in determining any impact on the meter performance and the need for any repair, flow
performance test (in-situ or laboratory), adjustment to maintenance interval or design improvement.
3. USMs provide serial data that can be collected through end-user polling systems. End-user custom
algorithms and commercial data-analysis packages can be utilized to provide real-time continuous
evaluation of the USM’ s performance that can help predict maintenance timing.
Note: See Appendix E (Informative) for a field verification checklist sample.
7.3 Maintenance
7.3.1 Inspection
An internal inspection of the metering package may be required whenever meter diagnostics indicates
a meter-performance change, or on a scheduled interval.
External inspection of the metering package should be conducted on a continuing basis while the meter
is in operation and should include, but is not limited to, structural integrity, mechanical and electrical
connections.
33
7.3.2 Cleaning
If internal inspection or meter diagnostics indicates contamination in the meter, cleaning should be
considered.
After meter cleaning, conduct a field verification test to confirm satisfactory meter performance.
7.3.3 Component Replacement
It is recommended to collect as-found meter data (log file) prior to performing component replacement
of electronics, cables, transducers, etc. Upon completion of the component replacement an as-left log
file should be collected and compared to a representative log file that represents the normal meter
performance based on the initial commissioning data.
7.4 Recalibration
No time-based recalibration interval is recommended in this document. The overall accuracy requirements
of the user’s measurement application, along with user operating procedures, comparisons to original
baseline data, and manufacturer’s recommendations can be considered to determine when recalibration may
be needed. Research and industry experience indicates meter diagnostic data is more effective in
determining the need for re-calibration rather than using a time-based interval.
34
8.0 Ultrasonic Meter Measurement Uncertainty Determination
The ISO Guide to the Expression of Uncertainty in Measurement (GUM) should be used as a reference for the
determination of uncertainty for installed ultrasonic flow meters.
The in-situ measurement uncertainty of ultrasonic flow meters is comprised of:
1.
Uncertainty associated with the meter calibration that includes both the calibration facility and meter
factor adjustment method.
2.
Uncertainties arising from differences between the field installation and the calibration lab including
those that are a function of age, piping configuration, flow conditions or contamination.
3.
Inherent uncertainties associated with the repeatability of measurement from an ultrasonic meter, both
in the calibration facility and in-situ.
4.
Uncertainties associated with secondary instrumentation, such as pressure and temperature sensors, gas
composition measurement, gas property/compressibility determination, and flow computers.
A complete analysis of the uncertainty components follows the process outlined in ISO 51 68 and includes both
statistically determined uncertainties (Type A uncertainties) and those uncertainties evaluated from methods
other than through a statistical analysis (Type B uncertainties). Known biases should be eliminated when
possible and are treated as Type B uncertainties when they cannot be eliminated.
Note: See Appendix D (Informative) for more information.
35
Reference List
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Washington, DC.
2. AGA Report No. 8, Thermodynamic Properties of Natural Gas and Related Gases , Part 1 – DETAIL
and GROSS Equations of State, American Gas Association, 2017, Washington, DC.
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5. API Manual of Petroleum Measurement Standards Chapter 21 .1, February 2013, Flow Measurement
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Society for Testing and Materials. West Conshohocken, PA
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Natural Gas and Other Gas by Pipeline: Minimum Federal Safety Standards , U.S. Government
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8. ISO 9951: 1993, Measurement of gas flow in closed conduits — Turbine meters, International
Organization for Standardization, Genève, Switzerland.
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ultrasonic flowmeters, International Organization for Standardization, Genève, Switzerland.
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de Métrologie Légale, Bureau International de Métrologie Légale, Paris, France.
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Légale, Paris, France
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Flow Conditioners in Short Run Meter Installations,” by T. A. Grimley, draft topical report (Jan. 1 999
– June 2000) to Gas Research Institute, Report No. GRI-01/0129, GRI Contract No. 5097-170-3937,
February 2002, Des Plaines, IL.
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NOVA Metcon Meeting, October 11, 2001, Calgary, Alberta, Canada.
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Society, July 23, 2001, Houston, Texas.,
15. “Numerical Simulation of the Flow Field Downstream of 90 Degree Elbows and the Simulated
Response of an Ultrasonic Flow Meter,” by Gerald L. Morrison and Karine Tung (Texas A&M
University), technical report to Gas Research Institute, Report No. GRI-01/0090, GRI Contract No.
5097-170-3937, June 2001, Des Plaines, IL.
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(Texas A&M University), technical report to Gas Research Institute, Report No. GRI-01/0091, GRI
Contract No. 5097-170-3937, April 2001, Des Plaines, Il.
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Association TMC Meeting, February 6, 2001.
18. “Ultrasonic Meter Installation Configuration Testing,” by Terrence A. Grimley, AGA 2000 Operations
Conference, May 7-9, 2000, Denver, CO.
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Natural Gas Measurement,” by T. Grimley, topical report (July 1 996 - December 1997) to Gas
Research Institute, GRI Contract No. 5097-270-3937, November 2000, Des Plaines, IL.
36
20. “Recent 1 2 - Inch Ultrasonic Meter Tests at the GRI Metering Research Facility,” by Edg ar B. Bowles,
Jr., TNO Flow Metering Seminar, September 20, 1999, Techniek Museum, Delft, The Netherlands.
21. “Recent 1 2 - inch Ultrasonic Meter Testing at the MRF,” by Terrence A. Grimley, AGA Gas
Measurement Research Council, September 14, 1999, Seattle, WA.
22. "12-inch Ultrasonic Flow Meter Verification Testing at the MRF," by Terrence A. Grimley, Fourth
International Symposium on Fluid Flow Measurement, June 28-30, 1999, Denver, Colorado. “The
Influence of Velocity Profile on Ultrasonic Flow Meter Performance, ” by Terrence A. Grimley, A.G.A.
1998 Operations Conference, May 17-19, 1998, Seattle, Washington.
23. “GRI MRF Ultrasonic Flow Meter Research Program Draft Plan 1 998/1 999,” by Terrence A. Grimley,
American Gas Association Winter Meeting, March 11, 1998, Orlando, Florida.
24. “Performance Testing of Ultrasonic Flow Meters,” by Terrence A. Grimley, The North Sea Flow
Measurement Workshop 1997, October 27-31, 1997, Kristiansand, Norway.
25. “Multipath and Single -Path Ultrasonic Flow Meters,” by Terrence A. Grimley, American Petroleum
Institute COPM Measurement Seminar, October 13, 1997, San Diego, CA.
26. “Performing Testing of Ultrasonic Flow Meters,” by Terrence A. Grimley and Edgar B. Bowles, Jr.,
American Gas Association Operating Section Operations Conference, May18-21, 1997, Nashville,
Tennessee.
27. “Performance Tests of 1 2 - Inch Multipath Ultrasonic Flow Meters,” by T. Grimley, U.S. Department of
Energy’s Natural Gas Conference, March 26, 1 997, Houston, Texas.
28. “Ultrasonic flowmeters undergo accuracy, repeatability tests,” by Terrence A. Grimley, Oil & Gas
Journal, December 23, 1996, pp. 101 -104, Houston, TX.
29. “Multipath Ultrasonic Flow Meter Performance,” by Terrence A. Grimley, the North Sea Flow
Measurement Workshop, October 28-31, 1996, Peebles, Scotland, UK.
30. “Metering Research Facility Program: Performance Test of 12-Inch Multipath Ultrasonic Flow
Meters,” by Terrence A. Grimley, topical report (Oct. 1 994 -March 1996) to Gas Research Institute,
Report No. GRI-96/0291, GRI Contract No. 5095-271-3363, August 1996.
31. “GRI/MRF Ultrasonic Meter Research Program,” by Terrence A. Grimley, A.G.A. TMC Ultrasonic
Meter Working Group, Montreal, Quebec, Canada, May 21, 1996.
32. “Multipath Ultrasonic Flowmeter Performance,” by Terrence A. Grimley, 1 996 A.G.A. Operations
Conference, Montreal, Quebec, Canada, May 19-22, 1996.
33. “GRI/MRF Ultrasonic Meter Research Program,” by Terrence A. Grimley, A.G.A. TMC Ultrasonic
Meter Working Group, Santa Fe, New Mexico, March 6, 1996.
34. “Uncertainty Analysis of Turbine and Ultrasonic Meter Volume M easurements,” Kegel, T. M., AGA
Operations Conference, Orlando, FL, May, 2003.
35. “Meter Station Uncertainty – Determination and Influence”, La Nasa, P., American Gas Association
Operations Conference and Biennial Exhibition, April, 2001, Dallas, Texas.
36. Kegel, T. M.,” Uncertainty Analysis of Turbine and Ultrasonic Meter Volume Measurements,” AGA
Operations Conference, Orlando, FL, May, 2003.
37. ANSI/ASME MFC-2M, Measurement Uncertainty for Fluid Flow in Closed Conduits, American
Society of Mechanical Engineers, 2013
38. ANSI/ASME PTC 19.1, Measurement Uncertainty, American Society of Mechanical Engineers, 1990.
39. ISO 5168, Measurement of Fluid Flow – Procedures for the evaluation of uncertainties, International
Organization for Standardization, 2005
40. Abernethy, R. B. et al, Handbook Uncertainty in Gas Turbine Measurements, AEDC-TR-73-5, Arnold
Engineering Development Center, 1973
41. ISO Guide to the Expression of Uncertainty in Measurement, International Organization for
Standardization, 2008
42. Taylor, B. N., and Kuyatt, "Progress Report on the Implementation of the ISO Guide to the Expression
of Uncertainty in Measurement", Proc. 1994 Meas. Sci. Conf., 1994.
37
43. ANSI/ASME PTC 19.1, Test Uncertainty, American Society of Mechanical Engineers, 2013.
44. Kegel, Thomas, "Basic Measurement Uncertainty," 74th International School of Hydrocarbon
Measurement, Tulsa, Oklahoma, May 25-27, 1999.
45. Wadsworth, H. M., Handbook of Statistical Methods for Engineers and Scientists, McGraw-Hill, 1990.
46. Morrow, T. B., "Pressure Effects and Low Flow Tests On 8-inch and 6-inch Ultrasonic Flow Meters,"
Topical Report GRI-04/0043, Gas Research Institute, Chicago, IL, Dec. 2004
47. Morrison, G. L., Brar, P., "CFD Evaluation of Pipeline Gas Stratification at Low Flow Due to
Temperature Effects," Topical Report GRI-04/0185, Gas Research Institute, Chicago, IL, Sept. 2004.
48. Morrow, T. B., "Multi-path Gas Ultrasonic Flow Meter Performance at Low Velocity," paper
FEDSM2005-77403, American Society of Mechanical Engineers, NY, June 2005.
49. Morrow, T. B., "Line Pressure and Low-Flow Effects on Ultrasonic Gas Flow Meter Performance,"
Topical Report GRI-05/0133, Gas Research Institute, Chicago, IL, Mar. 2005.
50. NIST Guidelines for Evaluating and Expressing the Uncertainty of NIST Measurement Results
(Technical Note 1297)
51. AGA Engineering Technical Note M-96-2-3, Ultrasonic Flow Measurement for Natural Gas
Applications
52. McManus, S.E., et al., “The decay of swirling gas flow in long pipes,” presented at the AGA Operating
Section Conference, Boston, Massachusetts, May 22, 1985.
53. van der Grinten, J. Extended type examination tests for high-pressure ultrasonic meters used in outdoor
metering stations. In : 9th International Symposium on Fluid Flow Measurement Publications [online].
Arlington, VA, 2015. [Accessed 11 November 2015]. Available from:
http://library.ceesi.com/docs_library/events/isffm2015/Docs/ExtendedTypeExaminationTestsHighPres
sure.pdf
54. Lawrence, P. Laboratory Testing of Chordal Path Ultrasonic Gas Meters With New Noise Reduction
Tee Designs. In : International Symposium on Fluid Flow Measurement [online]. 2015.
[Accessed11November2015].Available from:
http://library.ceesi.com/docs_library/events/isffm2015/Docs/LaboratoryTestingChordalPathUltrasonic.
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Workshop: Ultrasonic & Coriolis Metering [online]. 2015. [Accessed 11 November 2015]. Available
from: http://library.ceesi.com/docs_library/events/ceesi-Europe2015/Docs/18.pdf
56. Hawley, A., Owston, R. and Thorson, J. Effect of Upstream Piping Configuration on Ultrasonic Meter
Bias – Flow Validation. San Antonio, TX : PRCI, 2015. MEAS-6-5, Contract PR-015-13610.
57. Witte, J. and Grant, C. Performance Evaluation of New Generation Ultrasonic Meters in Compact
Installations Without Flow Conditioners. San Antonio, TX : PRCI, 2014. MEAS-6-9, Contracts PR015-13602 and PR-015-14600.
58. Hawley, A. and Owston, R. Effect of Upstream Piping Configurations on Ultrasonic Meter Bias. San
Antonio, TX : PRCI, 2013. MEAS-6-5, Contract PR-015-12605.
59. Brown, G. and Griffith, B. THE EFFECTS OF FLOW CONDITIONING ON THE PERFORMANCE
OF MULTIPATH ULTRASONIC METERS. In : International Symposium in Fluid Flow
Measurement [online]. 2012. [Accessed 11 November 2015]. Available from:
http://library.ceesi.com/docs_library/events/isffm2012/Docs/206_EFFECTS_FLOW.pdf
60. Hawley, A. and George, D. Effect of Upstream Piping Configuration on Ultrasonic Meter Bias. San
Antonio, TX : PRCI, 2012. MEAS-6-5, Contract PR-015-10603.
61. Grimley, T. and Hawley, A. EFFECT OF DIRTY OR WORN FLOW CONDITIONERS ON METER
PERFORMANCE. San Antonio, TX : PRCI, 2010. MEAS-5-14, Contract PR-015-09602.
62. Smorgrav, S. and Abrahamsen, A. K. OIML R 137-1, the first ultrasonic meter to be tested to accuracy
class 0.5?. In : North Sea Flow Measurement Workshop [online]. 2009. [Accessed 11 November
2015]. Available from: http://www.tuvnel.com/_x90lbm/NSFMW_2009_-_Technical_Papers.pdf
38
63. AGA Transmission Measurement Committee Report No. 3 Part 2\ API 14.3.2, Orifice Metering of
Natural Gas and Other Related Hydrocarbon Fluids, American Gas Association, 2015, Washington,
DC.
64. Zanker, Klaus, “Ultrasonic Meter Recalibration Frequency Phase 2”, PRCI Report PR-343-14605-R01,
August, 2015.
65. Crowe, Jeff and Geerligs, John, “Bidirectional Ultrasonic Meter Thermowell Location” American Gas
Association Operations Conference, April, 2016, Phoenix, Arizona.
39
40
Appendix A (Informative): Multipath Ultrasonic Meter Flow-Calibration Issues
A.1 Why Flow-Calibrate a Multipath Ultrasonic Meter?
The flow measurement accuracy specifications in Section 6 are included to permit a multipath ultrasonic
meter to have a maximum error, prior to application of any calibration factor adjustment, of up to 0.7%
for meters 1 2” and larger, and 1 .0% for meters 4” to 10” for flow rates between qt and qmax and a maximum
error of up to 1 .4% for flow rates between qmin and qt. For meters smaller than 4” a maximum error of up
to ±2.0% for flow rates between qt and qmax and a maximum error of up to 3.0% for flow rates between
qmin and qt is allowed. As the following example illustrates, multipath ultrasonic meters may operate within
this allowable measurement accuracy envelope, but still produce significant and costly errors in terms of
the measured gas volume. One effective means of minimizing the measurement uncertainty of a multipath
ultrasonic meter is to flow-calibrate the meter.
Example:
A multipath ultrasonic meter manufacturer rates the flow capacity of a 1 2  diameter USM as follows. Note
that the specified value for qt is less than 0.1 qmax, per the requirements in qt definition.
qmax =
qt =
qmin =
280,000
acf/h
24,400
acf/h
7,000
acf/h
Flow calibration of this meter at a test laboratory yields the following results, after averaging multiple test runs
near each of the recommended nominal test rates (RNTR).
RNTR
Nominal Test
Rate
(acf/h)
Actual Test Rate
- Reference Meter
(acf/h)
Meter
Reported
Rate*
(acf/h)
282,1 1 1
21 1 ,366
1 41 ,1 1 1
70,742
28,480
1 3,729
280,000
280,1 53
qmax
21 0,000
21 0,01 1
0.75 qmax
1 40,000
1 40,286
0.5 qmax
70,000
70,382
0.25 qmax
28,000
28,369
0.1 qmax
1 4,000
1 3,705
0.05 qmax
7,000
6,971
6,963
0.025 qmax
Table A.1 Flow Calibration Data for a 12 Diameter USM
USM
Error
(%)
0.70%
0.65%
0.59%
0.51 %
0.39%
0.1 8%
-0.1 1 %
* The “Meter Reported Rate” has been rounded to the nearest whole acf/h. The “USM Error” is based on the
values for the “Meter Reported Rate” prior to rounding and the “Actual Test Rate - Reference Meter.”
The flow-calibration data from Table A.1 are plotted on Figure A.1 below.
To estimate the error in the volume of gas measured by this meter, assume that, in field service, the gas is
typical pipeline-grade quality and that it flows through the USM at a rate of 1 40,286 acf/h (i.e., roughly 0.5
qmax) at a line pressure of 600 psig. For this operating condition, the flow calibration data indicate that the
meter error will be 0.59% (see Table A.1 ). If this flow rate is held constant for a year, the resulting
41
measurement error is about 330 million standard cubic feet of gas per year. Also, note that the error, in
terms of the measured volume of gas, is proportional to the square of the USM diameter, so a comparable
percentage error for a 20  diameter meter would be more than 900 million standard cubic feet of gas per
year.
From the example above, the magnitude and direction (i.e., overestimation or underestimation) of the
measurement error of the USM is a function of the flow rate. That is, in this case, the USM overpredicts the
flow rate in the middle and high end of the operational range and underpredicts on the low end of the range.
Furthermore, the meter error can be substantially corrected by using the flow calibration data. The following
discussion explains how test flow data can be used to minimize meter error.
Figure A.1 Uncorrected Flow Calibration Data for a 12 Diameter USM
Note that the individual data points in Figure A.1 represent averaged values for multiple test runs near each
of the recommended nominal test rates.
A.2 Methods for Correcting a USM’s Flow Measurement Error
The above example demonstrates the potential value of minimizing a USM ’s measurement inaccuracy or
uncertainty. The total flow measurement error of a USM consists of two parts: (1 ) random (or precision)
errors and (2) systematic (or bias) errors. Random errors can be caused by various influences on a meter’s
operation. Random errors normally follow a certain statistical distribution. The magnitude of the random
error can usually be reduced by acquiring multiple measurement samples and then applying accepted
statistical principles. Uncertainties that can be characterized using statistical methods are considered “Type
A” uncertainties in the Guide to the Expression of Uncertainty of Measurement (GUM) approach.
Systematic errors cause repeated USM measurement readings to be in error (for some unknown reason) by
roughly the same amount. Flow calibration of a USM can minimize the systematic error of the meter.
Operational experience has shown that, in most cases, the major portion of the total flow measurement error
of an uncalibrated USM results from systematic errors.
42
Due to machining tolerances, variations in component manufacturing processes, variations in the meter
assembly process and other factors, each USM has its own unique operating characteristics. Thus, to
minimize a particular USM ’s flow measurement uncertainty, the manufacturer or operator can flowcalibrate a USM and then use the calibration data to correct or compensate for the USM ’s measurement
error. Residual unknown systematic errors may still exist after calibration as the result of operational or
installation differences, or other considerations. These residual systematic errors are considered to be “Type
B” uncertainties in the GUM approach.
Several error correction techniques specified in Section 6.5 are available, depending on the meter
application and the needs of the operator. An exhaustive discussion of the various meter error correction
techniques is beyond the scope of this document. The designer or operator should consult with the
manufacturer regarding the available options for a particular USM.
A.3 Flow-Weighted Mean Error (FWME) Correction
The calculation of a meter’s FWME from actual flow test data is a method of calibrating a meter when only
a single calibration factor correction is applied to the meter’s output. Application of this factor to a USM’s
output is similar to the use of an index gear ratio in a turbine or rotary flow meter. The example used in
Section A.1 above will now be used to demonstrate how to calculate the FWME for a 1 2  diameter USM
that has been flow calibrated under operating conditions similar to those that the meter would experience
during field service. A single calibration factor F (i.e., one FWME correction factor) is determined and then
applied to the test results such that the resulting FWME is equal to zero. The meter’s performance, both
before and after the calibration factor is applied, shall be compared with the requirements specified in
Section 6.3.
The FWME for the data set presented in Table A.1 of Section A.1 above is calculated as follows.
퐺푊푀퐹 =
∑ 표푖= 1 ( 푞 푞푖 ) × 퐹
푛푎푥
∑ 표= 1 푞 푞
푖
푖
푖
푛푎푥
Where SUM is the summation of the individual terms representing each of the test flow points, qi is an
actual test flow rate from the reference meter, and
qi / qmax
is a weighting factor ( wfi) for each test flow point, and
Ei is the indicated flow rate error (in percent) at the actual test flow rate q .
i
(An alternative method for computing the FWME that decreases the contribution of the highest flow rate
point is to use a reduced weighting factor, such as 0.4, when qi  0.95 qmax. The designer or the operator
may also use different weighting factors, depending on whether the meter is run mostly in the lower, middle
or upper range of flow.)
43
Applying the above equation for FWME to the test data in Table A.1 produces the results shown in Table
A.2. Note that a column labeled wfi is included in Table A.2 to show the weighting factor that is applied to
each Ei value.
qi
reference
(acf/h)
wfi= qi/qmax
Ei
(%)
wfi*Ei
(%)
280,1 53
1 .0005
0.7500
0.501 0
0.70%
0.65%
0.59%
0.699%
0.484%
0.295%
0.251 4
0.1 01 3
0.0489
0.51 %
0.39%
0.1 8%
0.0249
-0.1 1 %
0.1 29%
0.040%
0.009%
0.003%
∑=
2.6781
∑=
1 .652%
FWME=
0.61 7%
21 0,01 1
1 40,286
70,382
28,369
1 3,705
6,971
F=
0.9939
Table A.2 FWME Calculation Summary for a 12 Diameter USM
The FWME value for the test data in Table A.2 is calculated as follows (without any calibration factor
correction being applied to the data).
∑ 표 (푤푓 × 퐹 ) 1 .652%
= 2.678 1 = 0.6 1 7%
퐺푊푀퐹 = ∑= 표1
= 1 (푤푓 )
푖
푖
푖
푖
푖
A single calibration factor F can now be applied to the meter output to reduce the magnitude of the
measurement error. The value of F is calculated using the following equation.
00
퐺 = 1 00 +1퐺푊푀
퐹
For this example, the FWME is 0.61 7% and the single calibration factor is calculated to be 0.9939. By
multiplying the USM’s output by 0.9939 (i.e., by applying the calibration factor), the resulting FWME shall
then equal zero. The adjusted test data are presented in Table A.3 below. In this table, each Ei has been
adjusted to obtain a residual error after adjustment Eir1 using the following equation.
퐹푖푠1
= (퐹 + 1 00 ) × 퐺 − 1 00
푖
44
Ei
(%)
0.70%
0.65%
1.0005
0.7500
0.59%
0.5010
0.51%
0.2514
0.39%
0.1013
0.18%
0.0489
-0.11%
0.0249
2.6781
∑=
wfi
wfi*Eir1
Eir1
(%)
(%)
0.082% 0.082%
0.028% 0.021%
0.028% 0.014%
0.105% 0.026%
0.225% 0.023%
0.436% 0.021%
0.727% 0.018%
= 0.000%
∑
Table A.3 FWME Corrected Flow Calibration Data Summary for a 12 Diameter USM
Using the adjusted data from Table A.3 to calculate FWME produces the following result.
퐺푊푀퐹 =
0.000%
2.678 = 0.000%
1
In the following plot, the FWME corrected flow calibration data have been added to the test data presented
in Figure A.1. The FWME Corrected Error (red line) represents the meter’s error after a single calibration
factor of 0.9939 has been applied to the original flow calibration data.
Figure A.2 Uncorrected, FWME, Polynomial, and PWL Corrected Flow Calibration Data for a 12
Diameter USM
45
The FWME correction method is most effective at minimizing the measurement uncertainty if a USM’s
measurement error (expressed in percent error) does not change over the flow range of the meter. The
FWME correction shifts the Uncorrected Error curve up or down, so, ideally, if Uncorrected Error is parallel
to axis X (the measurement error is the same over the flow range) then FWME Corrected Error would be
zero for all flow rates. In our example, for flow rates above about 25% of the capacity of the meter, the
measurement error has been significantly reduced by applying a single FWME calibration factor. However,
for flow rates below about 25% of the meter’s capacity, the single FWME calibration factor does not reduce
the measurement error because the USM’s error changes over the meter’s flow range. Therefore, when the
USM’s measurement error is flow dependent, the operator can either accept the higher error on the low end
of the meter’s flow range or apply more sophisticated correction techniques to reduce the error on the low
end of the meter’s range. Two of these techniques are described in Sections A.4 and A.5 below.
A.4 Polynomial Algorithm
Polynomial algorithms use polynomial functions for approximation of the calibration factor F over the
USM’s flow range.
F = a0 + a 1 x q + a 2 x q 2 + … + a n x q n
Normally, second order polynomial a0+a1 qi+a2qi2 is used that employs three parameters: a0, a1 , and a2.
F = a0 + a1 x q + a2 x q2
For the test data in Table A.1, values of parameters are computed using least squares method: a0=0.99941,
a1 =-6.1610*10-8, a2=1.4517*10-13 . The adjusted flow rate qadj over the meter’s range is calculated using the
above parameters.
qadj = q x (0.99941 - 6.161*10-8 x q + 1.4517*10-13 x q2 )
Table A.4 shows adjusted flow rates and residual errors for each test flow rate.
qi
reference
(acf/h)
280,153
210,011
140,286
70,382
28,369
13,705
6,971
qi
reported
(acf/h)
282,111
211,366
141,111
70,742
28,480
13,729
6,963
qi
adjusted
(acf/h)
280,301
209,860
140,209
70,443
28,417
13,710
6,956
Eir2
(%)
0.05%
-0.07%
-0.05%
0.09%
0.17%
0.04%
-0.22%
Table A.4 Polynomial Corrected Flow Calibration Data Summary for a 12 Diameter USM
The green line in Figure A.2 represents polynomial corrected error. This calibration technique provides
better results for low flows than FWME technique. Flow weighting methods can further be used to improve
polynomial corrected error in critical areas, such as in the operating flow range.
46
A.5 Multi-Point/Piece-Wise Linear Interpolation
This is the most frequently used correction technique in North & South America. A multi-point/piece- wise
linear interpolation (PWL) uses linear function for the calibration factor between adj acent test points i and
i+1 .
퐺=퐺
푖
qi, qi+1 refer to
+ (퐺푖 +1
− 퐺 )× 푞
“qi reported” in Table A5 .
−푞
+1 − 푞
푞
푖
푖
푖
푖
For 7 test points specified in Table A.1 , there are 6 linear functions
F = Fi + ai x (q - qi), where 푎푖
−퐺
= 퐺푟 +1
+1 − 푟
푖
푖
푖
푖
and each linear function has two parameters Fi and ai specific for the flow rates between these test points.
The adj usted flow rate qadj between adj acent test points i and i+1 is computed by application of the calculated
calibration factor to the meter’s output.
qadj = q x [ Fi + ai x (q - qi)]
Table A.5 shows parameters Fi and ai along with adjusted flow rate and residual error Eir3 for each test flow
rate.
qi
qi
reference
(acf/h)
reported
(acf/h)
Fi
280,1 53
282,1 1 1
0.9931
21 0,01 1
1 40,286
70,382
28,369
1 3,705
6,971
21 1 ,366
1 41 ,1 1 1
70,742
28,480
1 3,729
6,963
0.9936
0.9942
0.9949
0.9961
0.9982
1 .001 1
ai
-0.0000000075
-0.0000000080
-0.00000001 08
-0.0000000283
-0.0000001 431
-0.0000004328
qi
adj usted
(acf/h)
Eir3
(%)
280,1 53
0.00%
21 0,01 1
1 40,286
70,382
28,369
1 3,705
6,971
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
Table A.5 Multi/Point/PWL Corrected Flow Calibration Data Summary for a 12 Diameter USM
The marks on the zero axis in Figure A.2 represent PWL corrected error at the test flow rates. It should be
mentioned that the disadvantage of the PWL technique is the fact that the measurement error of the flow
calibration facility for each flow rate at the time of the USM calibration becomes systematic error of the
USM for this flow rate.
47
APPENDIX B (Normative): Electronics Design Testing
The design of the USM's electronics shall be tested to demonstrate that the USM will continue to meet the
performance requirements of Section 6, while operating under the influences and disturbances specified in the
current revisions of OIML R 1 37-1 & 2, Edition 201 2 (E), Gas meters, and OIML D 1 1 , Edition 201 3 (E),
General requirements for measuring instruments – Environmental conditions .
For the climate conditions refer to Humidity class H3. This class applies to instruments or parts of instruments
used in open-air locations excluding those in extreme climate zones like polar and desert environments. For
mechanical conditions refer to mechanical class M2. This class applies to locations with significant or high
levels of vibration and shock, e.g. transmitted from machines and passing vehicles in the vicinity or adjacent to
heavy machines, conveyor belts, etc. For electromagnetic conditions refer to electrical class E3. This class
applies to measuring instruments powered by the battery of a vehicle and exposed to electromagnetic
disturbances, which correspond to those likely to be found in any environment not considered hazardous for
general public.
These test requirements shall apply to the design of all circuit boards, ultrasonic transducers, interconnecting
wiring and customer wiring terminals. The electronics shall be in operation, measuring zero flow, and remain
1 00% functional during the tests. In the case of high-voltage transient and electrostatic discharge tests, the meter
may temporarily stop functioning but shall automatically recover within 30 seconds.
During these tests, the ultrasonic transducers may be operated in a smaller and lighter test cell (or test cells)
instead of a full flow-meter body. However, the transducers shall actually be measuring zero flow and be
exposed to the same test conditions as other parts of the electronic system.
48
Appendix C (Normative): Flow-Metering Package and/or Flow- Conditioner Performance
Verification Test
This Appendix to AGA 9 is intended to provide a method by which an ultrasonic metering package can be
shown to perform acceptably under varying test flow conditions.
A series of flow-verification tests, with a standard set of flow-disturbance elements placed upstream of the
meter, is provided to verify meter measurement performance. The specified upstream piping installations are
intended to create a representative range of flow distortions that are typical of what may be produced in field
service at the inlet to the meter run. It should be cautioned that these test-flow distortions may not necessarily
be representative of worst-case field conditions. The meter manufacturer is responsible for specifying the
upstream length(s) of straight pipe and the meter-run piping configuration and for specifying the presence or
absence of a flow conditioner. These tests will allow manufacturers to validate installation recommendations
and designers/operators to compare meter performance and installation requirements under a common set of
operating conditions.
The purpose of these tests is to help verify that an ultrasonic meter shall function within acceptable measurement
performance limits when installed in a field meter station. For the recommended performance verification tests,
it is strongly advised that the test-meter piping configuration (i.e., the flow meter, flow conditioner (if used),
and associated upstream and downstream piping) replicate the field piping as closely as possible. It should be
noted that pipe fittings, valves, regulators, etc. typically located upstream of the flow conditioner are not usually
part of a flow-calibrated meter installation, but such piping elements can adversely affect the flow profile and,
potentially, the measurement accuracy of the meter.
For meter installation configurations that utilize a flow conditioner, the flow conditioner shall be included as
part of the test assembly for the initial, or baseline, flow-meter calibration. Since the response of an ultrasonic
meter to a flow conditioner is unique to the meter/flow conditioner combination, tests with one meter/flow
conditioner combination should not be used to infer results when either component or the accompanying piping
configuration is changed.
The metering package shall be subjected to the upstream flow disturbance tests specified in OIML R 1 37 -1 &
2, Edition 201 2 (E), Gas meters , Annex B, Titled “Flow disturbance tests.” The result of each tested flow rates
of the calibrated test assembly compared to the disturbed flow tests shall not exceed ±0.3% difference.
49
Appendix D (Informative): Examples of Overall Measurement-Uncertainty Calculations –
Ultrasonic Meter
D.1 Meter-Calibration Uncertainty
Commercial flow calibration facilities maintain formal estimates of uncertainty for each operating/test
scenario. These estimates recognize the contributing influence of all measurement parameters involved
in the calibration.
A stated estimate of calibration uncertainty shall accompany the documentation of each meter
calibration. If the uncertainty is not the same for all flow rates, then it shall be shown for each flow rate.
The stated estimate of uncertainty of meter calibration remains with the meter assembly for as long as
the calibration parameters are applied to its operation. In-situ sources of uncertainty are incremental to
calibration uncertainty.
D.2 Uncertainties Arising From Differences Between the Field Installation and the Calibration
Lab
Measurement uncertainty increases when:
1. The in-situ condition of the meter differs from its condition during calibration
2. The in-situ characteristics of the gas flow differ from those present during calibration
The sections that follow provide the basis for assessing operational conditions that may influence
measurement uncertainty. These operational conditions may result in differences from the calibration
conditions.
D.2.1 Parallel Meter Runs
As described in Annex J of ISO 5168-05, a special situation exists for meters used in parallel. The
combined uncertainty of parallel meter runs is less than that of individual meter runs. The process for
estimating uncertainty identifies sources that produce different effects in each meter run and, therefore,
are uncorrelated, versus those that produce the same effect in each meter assembly (correlated).
D.2.2 Installation Effects
1. Flow distortions from upstream piping elements (valves, headers, flow conditioners, etc.) may
change the registration of a meter. The manufacturer of the meter should be consulted for estimation
of the associated uncertainty.
2. Acoustic interference, such as that produced by certain types of control valves, may result in loss
of acoustic signal quality. Current metering technology provides diagnostic information that will
identify the onset and extent of signal quality problems.
3. At low flow rates, including temperature-induced convective flows in piping, meters may respond
with sporadic indications of flow where no flow was expected. Although the symptoms of this
effect may be masked with automated “no -flow cutoffs,” uncertainty may be increased if the cutoff points are too high, resulting in measurement error.
4. Gas pulsation may result in metering error. No generalized, all-purpose methods exist for
quantifying the magnitude of such errors.
50
D.2.3 Pressure and Temperature Effects
1. Flow-meter body dimensional changes will result from pressure and temperature changes in
the flow-meter body material. The extent of error can be estimated arithmetically (see ISO
17089-1) from material specifications.
2. Thermal stratification of gas may occur, especially when flows are low and temperature
gradients exist between one side of the pipe and the other. Stratification may produce irregular
propagation rates of acoustic signals, leading to increased uncertainty. Variation of sound
speed from path to path is a symptom of this effect in some designs and can provide an
indication of flowing temperature gradient, but should not be used as a basis for adjustment.
D.2.4 Contamination Effects
1. Pipe-wall surface contamination of the metering package may produce changes to the internal
area of the pipe, as well as changes to the effective roughness. Industry experience has shown
that each effect may result in measurement bias. In theory, an unplanned reduction in pipe area
will produce over-registration in an ultrasonic flow meter. Surface-roughness changes in the
meter and upstream piping can affect the gas velocity profile and thus increase uncertainty.
This profile change may create over- or under-registration depending upon meter design.
However, it is not currently feasible to reliably predict the extent of bias as a function of liquid
coatings or increased pipe-wall roughness.
2. Transducer surface contamination, due to liquids or solid buildup, may reduce signal quality
or change the effective path length, which affects meter accuracy.
3. Flow conditioner contamination may create a distorted velocity flow profile thus increasing
measurement uncertainty. Diagnostic information, such as path velocity changes and
turbulence levels, are useful in identifying the onset of flow conditioner contamination.
D.3 Uncertainties Due to Secondary Instrumentation
The uncertainties of field equipment include the permanent, in-situ equipment as well as calibration
devices used to maintain the equipment. Local operating conditions, such as ambient temperature and
current gas pressure, may influence the performance of in-situ equipment as well as calibration
equipment.
The performance of pressure and temperature sensors is critical to all metering technologies. For linear
meters, such as ultrasonic flow meters, the relationship between pressure, temperature and volume are
directly proportional.
Secondary equipment includes devices such as flow computers that are responsible for converting realtime, uncorrected measurement data to fully corrected volume and energy data, gas composition
measurement devices including sampling systems and gas chromatographs. Applicable standards, such
as API MPMS Chapter 21.1/AGA Report No.13, Flow Measurement Using Electronic Metering
Systems – Electronic Gas Measurement, and AGA Report No. 8 Thermodynamic Properties ofNatural
Gas and Related Gases, API MPMS Chapter 14.1, Collecting and Handling of Natural Gas Samples
for Custody Transfer, prescribe the industry-recommended practices and requirements with respect to:
•
•
•
•
Sampling and integration frequencies
Linear meter k-factors
Variable averaging and integration
No-flow cut-off
51
Equations of state
Sampling system
Compressibility computations
•
•
•
D.4 Uncertainty Analysis Procedure
D.4.1 General
The following is a simplified example, with assumed numerical values, of estimating measurement
uncertainty for sites using ultrasonic gas flow meters.
Following the pattern demonstrated in ISO 5168, the estimation of uncertainty is based on a sequence
of:
a. Establishing a mathematical model for the measurement process
b. Listing and quantifying the contributory variances
c. Combining variances into a composite statement of uncertainty
D.4.2 The Mathematical Model
The gas volume flow rate at base conditions is given by:
Qb

 Pf   Tb


P
 b   Tf
Q f 
 Z
b

 Z
 f




D.4.3 Contributory Variances
Given that Pb and Tb are fixed (by definition) the relative (percentage) combined standard uncertainty
in the measurement is given by the following equation:
2
u* Qb 
* 2
* 2
 uQ
 uP
f
f
* 2
 uT
f
*
 u
2
Z 
 b 
 Z 
 f
D.4.3.1 Uncertainty in the Uncorrected Volume FlowRate, Q f
The total uncertainty is composed of uncertainty in the calibration plus uncertainty in the field.
Calibration uncertainty is assumed to include the uncertainties of the flow laboratory, its chain of
traceability and the repeatability of the meter under test. Uncertainty under field conditions is
assumed to include all site-specific installation effects, including those associated with flow
characteristics, equipment age, cleanliness and data acquisition.
u Q* f
uQ* f
FIELD
uQ* f
uQ* f

CAL
2



0. 15 % , coverage factor k=1, as estimated by flow laboratory
0. 15 % , as estimated by user
0. 15 2  0. 15 2
0. 21 %
52
D.4.3.2 Uncertainty in the Measurement of Pressure
Pressure measurement uncertainty is composed of uncertainty in the calibration and uncertainty in
the field. For simplicity, calibration uncertainty is assumed to include the portable field device and
reference equipment in its chain of traceability. The estimate of field uncertainty includes the effect
of ambient conditions, equipment age and data acquisition.
2
2
u P* f  u *pCAL  u *pFIELD
2
u *pCAL  0. 03 % ,
coverage factor k=1, as estimated by the test equipment vendor
u *pFIELD  0. 1 % ,
coverage factor k=1, as estimated by the field equipment vendor
2
u P* f  0. 03 2  0. 1 2
u P* f  0. 1 %
D.4.3.3 Uncertainty in the Measurement of Temperature
Temperature measurement uncertainty is composed of uncertainty in the calibration and uncertainty
in the field. Calibration uncertainty is assumed to include the portable field device and reference
equipment in its chain of traceability. The estimate of field uncertainty includes the effect of
ambient conditions, equipment age and data acquisition.
2
2
uT* f  uT*CAL  uT*FIELD
uT*CAL  0. 03 % ,
2
coverage factor k=1, as estimated by the test equipment vendor
uT*FIELD  0. 17% ,
coverage factor k=1, as estimated by the field equipment vendor
2
uT* f  0. 03 2  0. 17 2
uT* f  0. 17 %
D.4.3.4 Uncertainty in the Determination of Compressibility
For this example, uncertainty in the estimation of compressibility is primarily a function of
uncertainty in AGA Report #8 (Detail Method) for a given pressure, temperature and gas
composition regime. For simplicity, the uncertainty of gas composition analysis is assumed here to
be zero, as is the method of determining Zb. A more comprehensive analysis of measurement
uncertainty would assess the contributory variances of calibration standards and chromatography.
uZ* f  0. 05 % , coverage factor k=1, estimated for the given combination of gas pressure,
temperature and composition
53
D.4.4
Combined Uncertainty (percent)
From the values of the above examples, the revised expression for combined uncertainty is:
u * Qb   u Q* f  u P* f  uT* f  u Z* f
2
2
2
2
2
u * Qb   0. 21 2  0. 1 2  0. 17 2  0. 05 2
2
u * Qb   0. 08446
2
u * Qb   0. 29%
D.4.5
Expanded Uncertainty
An expanded uncertainty, coverage factor k=2, approximate confidence level 95%, is:
*
Qb   ku* Qb 
u95
*
Qb   2 × 0.29%
u95
u95* Qb   0. 58 %
If the measured flow is xx cubic feet per hour, the result of the measurement is presented as:
xx cubic feet per hour ±0.58% (expanded uncertainty, coverage factor k=2, approximate confidence
level 95 percent).
54
Appendix E (Informative): USM Commissioning and Verification Checklists
E.1 Commissioning Checklist
USM Commissioning Checklist (Example)
Note: These steps need to be completed prior to first flow. Maximum frequency should always be checked to ensure no
signal degradation at higher frequencies.
Electrical Connections
Completed
Prior to powering up the meter
1
Verify power supply is correctly installed and at the correct operating voltage
2
Verify and or set hardware jumpers (if required)
3
Communication switches for appropriate man/machine interface
4
Disable hardware write protection switch
USM Configuration
Completed
Connect the meter to the power source
1
Station Name
2
Meter Name or number
3
Address
4
Communication parameters (Serial, Modbus, Protocol, if used)
5
Verify that the k-factor in the meter and the RTU match.
Output Verification
Completed
1
Frequency output test. Test a minimum of 3 points. (25,50,100 % of maximum
frequency)
2
Analog 4-20mA output test (if used). Test a minimum of 3 points. (25,50,100 %
of full scale). (If used)
3
Serial Modbus (if used)
4
Digital outputs (If used)
55
Completed
USM Verification
1
Collect a start- up meter configuration file. Compare the start-up file with the asleft calibration meter configuration file to ensure that no meter value has been
altered. If any meter value has been altered, investigate the cause and return the
value to the as-left meter value as appropriate
2
Verify all SCADA inputs are properly mapped to the appropriate data base inputs
in the gas measurement system.
3
Collect a signal wave form file
4
Compare the signal waveform file to the supplied wave form file collected during
the meter calibration. Evaluate for changes in shape, signal quality, baseline noise
to determine if pipe configuration or ultrasonic noise sources are not interfering
with the USM. Consult with manufacturer as needed.
5
With no flow, check for zero-flow performance
6
Check and verify that the no-flow cutoff is set sufficiently to not allow any
spurious output to the data collection device (RTU, PLC, etc.)
7
Inspect the meter diagnostic set and ensure that all diagnostic values are operating
within nominal parameters (typically specific to each manufacturers design).
Gather diagnostic datasets at various flow rates and compare to those values
collected during calibration. Any values with deviations outside expected normal
variations (per manufacturer) should be investigated and explained. These data
sets should be carefully preserved as they will serve as the as-installed condition
baseline for future field verification activities. Use Field Verification checklist for
this step.
56
E.2 USM Field Verification Checklist
USM Field Verification Checklist (Example)
1
Obtain a copy of the installed meter configuration from Note Baseline values in the table below.
the last field verification along with the baseline meter
configuration, baseline diagnostics and waveform files
collected at meter commissioning as reference material.
2
Download a current configuration file from the meter Note:
and compare to the baseline meter configuration file. If
any meter value has been altered, investigate the cause
and if appropriate, return the value to the original meter
value (be aware that configuration settings may have
been changed for operational reasons and care should
be taken before reverting to prior condition). Note any
variance.
3
With meter flowing in a stable condition, (above 10 fps Note current values in the table below.
if possible so all diagnostics are working) collect a
diagnostic
data set from the
meter.
Note: Diagnostic data set results are based on the
averages over the length of collection interval. This can
mask small measurement variances.
4
Compare actual reported SOS from the flow meter to Meter Avg.
chromatograph or AGA8 calculated SOS value. These
values should closely agree with each other (typically
within 0.2%). See note 1 below.
Calculated
Example: (Calculated - Meter Avg.) / Calculated * 100 Difference
% Difference
5
Compare other key parameters (manufacturer specific) Note:
with the baseline values (at a similar flow rate) captured
at commissioning. These values should closely agree
with each other. Any values with deviations outside
expected normal variations (per manufacturer) should
be investigated.
Diagnostic Data
Baseline
SOS Per-Path Agreement (ft/s) See note 2 below
Swirl Angle (calculated or measured)
Signal Strength (gain)
Signal to Noise Ratio
Flow Velocity Profiles
57
Current
Asymmetry
Cross Flow (if calculated or measured)
Turbulence (if calculated or measured)
(Additional)
(Additional)
(Additional)
(Additional)
(Additional)
6
Collect a Wave-form File
Note:
Note 1.
Field verification of the meter’s reported SOS compared to the calculated using gas composition, pressure
and temperature may have higher deviation when compared to flow calibration data due to a variety of
reasons. These include, but are not limited to, varying gas composition, gas chromatograph sample time,
uncertainties in temperature calibration, proximity of operating near the critical point, and other variables.
Industry experience has shown that field agreement of the meter’s indicated SOS in comparison to the
computed SOS should closely agree with each other typically within 0.2%. If the difference is greater than
0.2%, historical data, along with verification of all secondary devices that are used to calculate the
theoretical SOS, should be evaluated to determine an acceptable deviation limit.
Note 2.
Comparison of the individual path SOS values relative to each other, which are used for flow calculations,
should be verified to be within 1.5 ft/s. If the difference is exceeded, this may be due to thermal
stratification, contamination, or problems related to the transducers, and should be evaluated to determine
an acceptable deviation limit.
58
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