OVERVIEW OF AGA REPORT 7 REVISION – MEASUREMENT BY TURBINE METERS
Robert Bennett
Honeywell PMC
2221 Industrial Road
Nebraska City, NE 68410
INTRODUCTION
This paper is to provide an overview of the AGA Report No. 7 – Measurement of Natural Gas by Turbine Meters.
BACKGROUND
Gas measurement in the U.S. and around the world is dominated by diaphragm, rotary, turbine, orifice, mass meters,
differential head, and ultrasonic meters. Each serves a different segment of the gas industry and each has its own set
of advantages and disadvantages.
These types of meters can be broken into two distinct categories: positive displacement, and inferential. Diaphragm
and rotary meters fall into the positive displacement group because they have well-defined measurement
compartments that alternately fill and empty as the meter rotates. By knowing the volume displaced in each meter
revolution and by applying the proper gear ratio, the meter will read directly in cubic feet or cubic meters.
Turbine, ultrasonic, mass meter, differential head, and orifice meters have no measurement compartments to trap and
then release the gas. These meters are categorized as inferential meters because the volume passed through them is
"inferred" by something else being observed or measured. In the orifice meter the volumes are determined only by
knowing the inlet pressure, differential pressure, plate size, and piping characteristics, all of which "infer" the flow
rates that in turn can be integrated over time to provide the volume.
Turbine meters, also called velocity meters, "infer" the volume of gas passing through them by measuring the velocity
of the gas stream. Gas moving through the meter impinges on a bladed rotor resulting in a rotational speed that is
proportional to the flow rate. The volume is determined by counting the number of meter rotations.
THEORY OF OPERATION
Turbine meters consist of three basic components (See Figure 1 and 1A):
1. The body which houses all parts and physically contains the gas pressure;
2. The measuring mechanism consisting of the rotor, rotor shaft, bearings, and necessary supporting structure;
3. The output and readout device. This device may be either a mechanical drive or a pulse detector system. A
mechanical drive transmits the indicated meter revolutions outside the body for uncorrected volume registrations.
For electrical pulse meters, it would be the pulse detector system and all electrical connections needed to transmit
the pulses outside.
Figure 1.
Figure 1A
Gas entering the meter increases in velocity as it flows through the annular passage formed by the nose cone or
upstream stator and the interior of the body. The movement of the gas over the angled rotor blades exerts a force to
the rotor causing it to rotate. The ideal rotational speed of the rotor is directly proportional to the flow rate of the
gas. The actual rotational speed is a function of the annular passageway size and shape, and rotor design. It is also
dependent on the load that is imposed due to internal mechanical friction, fluid drag, external loading, and gas
density.
TABLE OF CONTENTS OF REPORT NUMBER 7
Measurement of Natural Gas by Turbine Meters
1.
2.
3.
4.
5.
6.
7.
8.
Introduction
Terminology
Operating Conditions
Meter Design Requirements
Performance Requirements
Individual Meter Tests
Installation Specifications
Meter Maintenance and Field Verifications
Appendix A
1.
2.
3.
Single Rotor Turbine Meters
Dual Rotor Turbine
Dual Rotor Meter Electronics
Appendix B
1.
2.
Equations for Calculating Volumetric Flow
Equations for Calculating Mass Flow
Appendix C
1.
2.
3.
4.
Meter Register Reading
Electronic Computation
Mechanical Integrating Devices
Pressure, Volume, and Temperature Recording Devices
Appendix D
1.
2.
3.
4.
5.
Change Gears
K-Factors
Meter Factor
Final Mete Factor
Rotor Factors for Dual-Rotor Meters
Appendix E
1.
2.
3.
4.
5.
Reynolds Number and Flow Rate Matching
Pressure and Flow Rate Matching
Density and Reynolds Number Matching
Density and Flow Rate Matching
To Match Reynolds Numbers and Flow Rates
Appendix F
1.
2.
Testing In-Line
Testing Out of Line
Reference List
INTRODUCTION
It should be apparent that the Report has been completely rewritten. As stated in the Foreword, “This report is
published in the form of a performance-based specification for turbine meters for natural gas flow measurement. It
is the result of collaborative effort of natural gas users, turbine meter manufacturers, flow measurement research
organizations and independent consultants forming Task Group R-7 of AGA’s Transmission on Gas Flow
Measurement (COGFM) of the American Petroleum Institute.
Research conducted in support of this report and cited herein has demonstrated the turbine meters can accurately
measure natural gas and, therefore, should be able to meet or exceed the requirements specified in this report when
calibrated and installed according to the recommendations contained herein. Users should follow appropriate
installation, use, and maintenance of turbine meter as applicable in each case.”
TERMINOLOGY
Many new terms are listed in this section including: Final meter factor, Maximum peak-to-peak error, meter factor,
Rotor factor, Qi, Qmax, Qmin, and Qt. These definitions will result in conformity through the industry.
OPERATING CONDITIONS
This chapter is divided up into 6 subsections that list the field conditions under which the turbine meter must be able
to operate including: gas quality, operating pressures, gas temperatures, ambient temperatures, effects of gas density,
flow rates, and upstream piping and flow profiles.
METER DESIGN REQUIREMENTS
This chapter lists the performance requirements for the meter body, meter markings, and documentation that the
manufacturer must meet.
PERFORMANCE REQUIREMENTS
This chapter lists the error tolerances verses flow rate for turbine meters along with requirements for temperature,
gas composition, and pressure influences on the accuracy. The meters must also be designed such that the
measurement cartridges can be removed and are interchangeable.
FIGURE 2. Turbine Meter Tolerances at Atmospheric Pressure
INDIVIDUAL METER TESTS
Each meter is required to be integrity tested, leakage tested, and calibrated under conditions as close to field
conditions as possible. The test facility must have traceability to relevant national primary standards. The results of
individual meter testing will result in the establishment of K-factors, meter factors, final meter factor, rotor factors,
and change gear ratios for each output of the meter. Test reports must be documented thoroughly and records kept
for a minimum of 5 years. Quality assurance programs shall be established by the manufacturer and all records and
documents shall be available to the user.
INSTALLATION SPECIFICATIONS
In order to insure consistency of results from meter set to meter set, turbine meter installations must meet certain
requirements and these are listed in this chapter. It covers general considerations such as flow direction, meter
orientation and support, meter run connections, internal surfaces, temperature well location, pressure tap location,
and flow conditioning.
All of these requirements have resulted in several installation configurations.
1.
2.
3.
4.
Recommended Installation Configuration for In-line meters
Short-Coupled Installation
Close-Coupled Installation
Angle-Body meters
Figure 3. Recommended Installation for In-Line Meter
Figure 4. Short-Coupled installation
Figure 5. Close-Coupled Installation
It should be noted that with short and close-coupled installation, the use of integral flow conditioning nose cones
resulted in meeting the accuracy requirements.
Figure 6. Dimensional Parameters for Integral Flow Conditioning
A suggested installation for angle-body meters is shown in Figure 7.
Figure 7. Suggested Installation for Angle-Body Meters
This chapter also covers the effects of temperature, vibration, pulsations, hydrate formation, and liquid slugs on
meter performance. Auxiliary devices, such as filters, strainers, throttling devices and their use is discussed.
Precautionary measures for dirt, valve grease, over-ranging the meter, blow downs, flow limiting devices are
covered. Finally, densitometers and correctors mentioned.
METER MAINTENANCE AND FIELD VERIFICATION CHECKS
This chapter has sections on maintenance covering; general items, visual inspection, cleaning and oiling, spin time
test, dual rotor meter field checks, and retesting considerations. Almost everything required to keep a turbine meter
is good working condition in the field.
APPENDIX A – TURBINE METER DESIGNS
This covers the varying types of turbine meters that are on the market today: single rotor, dual rotor, and dual-rotor
electronics.
APPENDIX B – VOLUMETRIC AND MASS FLOW MEASUREMENT
Equations covering calculating volumetric flow through the Basic Gas Laws, meter rangeability, and determining
mass flow are presented in this appendix.
APPENDIX C – COMPUTING FLOW
How to determine the volume over time that has passed through the meter along with other accessories are here.
APPENDIX D – METER OUTPUTS AND ADJUSTMENTS
This appendix provides examples on how to adjust the outputs from a turbine meter through various mechanical and
electronic methods.
The first section details how to adjust mechanical output of the meter by use of different sets change gears, usually
in the index drive.
Figure 8. Change Gear Shift
Another method of adjusting the output of the meter is using K-factors either a single-factor for all flow rates or
individual K-factors covering a specific range of flows. Meter Factors can also be used through polynomial curve
fit, linear interpolation curve fit, or piecewise curve fit methods.
Figure 9. Polynomial Curve Fit
Figure 10. Piecewise Curve Fit
APPENDIX E – CALIBRATION GUIDELINES
Calibration of turbine meters over the expected range of flow rates and Reynolds numbers is the best method to
insure meter accuracy. This section shows how to determine Reynolds Numbers and how to match them to the
actual proving medium and flow rates.
APPENDIX F – SPIN TIME TESTS
Appendix outlines how to conduct either on in-line or out of line spin test.
CONCLUSION
The AGA Report No. 7 was completely rewritten from earlier versions. It is much more in line with how turbine
meters are now combining the mechanical mechanism with electronic data manipulation and correction methods that
insures accurate measurement over a wide range of flows and conditions.
REFERENCES
1.
American Gas Association Transmission Measurement Committee, “Report No. 7 – Measurement of
Natural Gas by Turbine Meters”, Revised February 2006.
Bob Bennett