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AGA Report No. 7

Measurement of Natural Gas by Turbine Meters Revised February 2006 Prepared by

Transmission Measurement Committee

Adh.

American Gas Association

Copyright © 2006 American Gas Association 400 North Capitol Street, NW, 4th Floor, Washington, DC 20001, U.S.A. Phone: (202) 824-7000 • Fax: (202) 824-7082 • Web: www.aga.org

Catalog # XQ0601

DISCLAIMER 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, the AGA provides for the exchange of information within the gas industry and scientific, trade and governmental organizations. Each publication is prepared or sponsored byan AGA Operating Section technical cornmittee. While AGA may adrninister the process, neither the AGA nor the technical cornmittee independently tests, evaluates, or verifies the accuracy of any information or the soundness of any judgments contained therein. The AGA disc1aims 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. The AGA makes no guaranty or warranty as to the accuracy and completeness of any infonnation published therein. The infonnation contained therein is provided on an "as is" basis and the AGA makes no representations or warranties including any express or implied warranty of merchantability or fitness for a particular purpose, In issuing and making this document available, the AGA is not undertaking to render professional or other services for or on behalf of any person or entity. Nor is the 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. The AGA has no power, nor does it undertake, to poli ce or enforce compliance with the contents ofthis document. Nor does the 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. The AGA does not take any position with respect to the validity of any patent rights asserted in connection with any items which are mentioned in or are the subject of AGA publications, and the AGA disc1aims 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. U sers of this publication should consult applicable federal, state, and local laws and regulations.

The 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 individual s and organizations acquainted with the measurement of natural gas. However, changes to this report may become necessary from time to time. If changes in this report are believed appropriate by any manufacturer, individual or organization, such suggested changes should be cornmunicated to AGA by completing the last page of this report titled, "Form for Suggestion to Change AGA Report No. 7, Measurement of Natural Gas by Turbine Meters" and sending it to: Operations & Engineering Services Group, American Gas Association, 400 North Capitol Street, NW, th 4 Floor, Washington, DC 20001, U.S.A.

Copyrights © 2006, American Gas Association, All Rights Reserved. III

FOREWORD This report is published in the fonn of a perfonnance-based specification for turbine meter 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 fonning Task Group R-7 of AGA's Transmission Measurement Cornmittee (TMC). In addition, comments to this report were made by the Committee on Gas Flow Measurement (COGFM) of the American Petroleum Institute (API). Research conducted in support of this report and cited herein has demonstrated that 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 followappropriate installation, use and maintenance ofturbine meter as applicable in each case. This version of AGA Report No. 7 is intended to supersede aH prior versions of this document. However, this document does not reference existing turbine meter instaIlations. The deCÍsion to apply this document to existing instaHations shall be at the discretion of the parties involved. Appendix B of this report contains the equations needed to convert volume measured at actual (line) conditions to equivalent volume at base conditions, or to mass. These equations may be used to perform such calculations with any type of positive displacement or inferential meter that registers in units of volume.

IV

ACKNOVVLEDGEMENTS Report No. 7, Measurement 01 Natural Gas by Turbine Meters, was developed by a Task Group of the American Gas Association's Transmission Measurement Committee. Individuals who made substantial contributions to the creation of this document are:

Larry Fraser, Fraser & Associates (Chairman) Angela Floyd, Panhandle Energy Dan Peace, Sensus Metering Systems Mark Pelkey, National Fuel Alex Podgers, American Meter Co. Research eondueted by Darin George, Ph.D., Southwest Research Institute at the Southwest Research Institute and the Colorado Experimental Engineering Station was instrumental in developing the seientific basis for the provisions of this Report. Other individuals who contributed to the development ofthe doeument are: Ed Bowles, Southwest Researeh Institute loe Bronner, Paeifie Gas and Eleetric Co. Jim Bowen, Instromet Frank Brown, Consultant Steve Caldwell, CEESI Cary Carter, Texas Gas Transmission Craig Chester, Williams Gas Pipeline Philip DiGiglio, KeySpan Corporation Chuek French, Gas Technology Institute Gamet Grudeski, TransCanada Calibrations Danny Harris, Columbia Gas lim Hagen, Great Lakes Gas Zaki Husain, Chevron Texaeo Mark Imboden, Controlotron Corp. Jim Keating, Consultant Erie Kelner, Southwest Researeh Institute ABen Knaek, Consumers Energy PauI LaNasa, CPL & Associates John Lansing, Daniel M&C Rick Ledesma, El Paso Pipeline Group Brad Massey, Southem Star Central Gas Pipeline George Mattingly, Consultant Dannie Mercer, Atmos Energy Corporation Roy Meyer, Exxon Mobil Winston Meyer, CenterPoint Energy Kevin Moir, DTE Energy John Naber, Daniel M&C Chris Overgaard, Nicor Gas Warren Peterson, TransCanda PipeLines Thanh Phan, Duke Energy Reese Platzer, Questar Pipeline King Poon, Thermo Electron Corp. Dan Rebman, Universal Ensco v

Daniel Rudroff, Welker Flow Measurement Systems Ine. Blaine Sawchuk, Canada Pipeline Aeeessories Bill Schieber, Solar Turbines Tushar Shah, Eagle Research Corporation Jerry Paul Smith, Consultant Walt Seidl, CEESI Karl Stappert, Daniel M&C John Stuart, Stuart Consulting Jim Witte, El Paso Pipeline Group

AGA acknowledges the contributions of the aboye individuals and thanks them for their time and effort in getting this docurnent revised. Lori Traweek

Ali Quraishi, StaffExecutive Engineering Services Director

Senior Vice President

VI

TABLE OF CONTENTS DISCLAIMER AND COPyRIGHT........................................................................................................................ 111 FOREWORD ••.............................................................................................................•............................................. IV ACKNOWLEDGEMENTS ....................................................................................................................................... V TABLE OF CONTENTS .•...•...........................•....................................................•................................................. VII MEASUREMENT OF NATURAL GAS BY TURBINE METERS •.....................••..•.........................••...•............. 1 1. 1.1 1.2

INTRODUCTION ............................................................................................................................................... 1 SCOPE ......•........................................................................................................................................................... PRINCIPLE OF MEASUREMENT .............................................................................................................................

1 1

2.

TERMINOLOGY ............................................................................................................................................... 2

3.

OPERATING CONDITIONS ............................................................................................................................ 5

3.1 3.2 3.3 3.4 3.5 3.6

4.

GAS QUALITY ...................................................................................................................................................... 5 OPERA TING PRESSURES ....................................................................................................................................... 5 TEMPERATURES, GASANDAMBIENT ................................................................................................................... 5 EFFECT OF GAS DENSITY ..................................................................................................................................... 5 GAS FLOW RA TE CONSIDERA TIONS ..................................................................................................................... 6 UPSTREAM PIPING ANO FLOW PROFILES ........................................................................................... ; .................. 6

METER DESIGN REQUIREMENTS .............................................................................................................. 7

4.1 COOES AND STANOAROS ...................................................................................................................................... 4.2 METER BODY ....................................................................................................................................................... 4.2.1 Meter Body End Connections ...................................................................................................................... 4.2.2 Corrosion Resistance .................................................................................................................................... 4.2.3 Meter Lengths and Bores ............................................................................................................................. 4.2.4 Pressure Tap ................................................................................................................................................. 4.2.5 Sealing .......................................................................................................................................................... 4.2.6 Miscellaneous ............................................................................................................................................... 4.3 METER MARKINGS ............................................................................................................................................... 4.4 DOCUMENTATION ................................................................................................................................................

5. 5.1 5.2 5.3 5.4

6.

7 7 7 7 7 7 7 8 8

8

PERFORMANCE REQUIREMENTS ............................................................................................................ 10 10 11 11 METER BODY INTERCHANGEABILITY ................................................................................................................ 11

GENERAL PERFORMANCE TOLERAN CES ............................................................................................................ TEMPERA TURE ANO GAS COMPOSlTION INFLUENCES ........................................................................................ PRESSURE INFLUENCES ......................................................................................................................................

INDIVIDUAL METER TESTS ....................................................................................................................... 12

6.1 INTEGRITY TEST ................................................................................................................................................ 6.2 LEAKAGE TEST .................................................................................................................................................. 6.3 CALIBRATION .................................................................................................................................................... 6.3.1 Calibration Conditions ............................................................................................................................... 6.3.1.1 Reynolds Number. ............................................................................................................................... 6.3.1.2 Density ................................................................................................................................................ 6.3.1.3 CalibrationGases ................................................................................................................................ 6.3.2 Calibration Guidelines ............................................................................................................................... 6.3.3 Calibration Configuration .......................................................................................................................... 6.3.4 Calibration Facilities .......... '" ..................................................................................................................... 6.3.5 Calibration Results ..................................................................................................................................... Vll

12 12 12 12 12 13 13 14 14 14 14

6.3.5.1 6.3.5.2 6.3.5.3 6.3.5.4 6.3.5.5 6.4 6.5 7.

Change Gears ....................................................................................................................................... 14 K-Factor(s) ........................................................................................................................................... 15 Meter Factors and Final Meter Factor.. ................................................................................................ 15 Rotor F actors for Dual-Rotor Meters ................................................................................................... 15 Meter Verification TesL ....................................................................................................................... 15 TEST REpORTS .................................•.................................................................................................................. 16 QUALITY ASSURANCE ........................................................................................................................................ 16

INSTALLATION SPECIFICATIONS •••••.•.......•.•.••.••••.•••••••.••....••..•••••••••••••••••.•.•_ •••••••••••••••••••...•.••••..••••••••••• 17

7.1 GENERAL CONSIDERA TIONS ...............•..•..•.......................................................................................................... 17 7.1.1 Flow Direction ............................................................................................................................................. 17 7.1.2 Meter Orientation and Support.................................................................................................................... 17 7.1.3 Meter Run Connections .............................................................................................................................. 17 7.1.4 Internal Surfaces ......................................................................................................................................... 17 7.1.5 Temperature Well Location ........................................................................................................................ 17 7.1.6 Pressure Tap Location ................................................................................................................................. 18 7.1.7 Flow Conditioning ...................................................................................................................................... 18 7.1.7.1 Tube Bundle Type Straigbtening Vanes .............................................................................................. 18 7.1.7.2 Other External Flow Conditioners ....................................................................................................... 18 7.1.7.3 Integral Flow Conditioners .................................................................................................................. 18 7.2 RECOMMENDED INSTALLA TION CONFIGURATIONS ............................................................................................. 18 7.2.1 Recornmended Installation for In-Line Meters ............................................................................................ 19 7.2.2 Optional Installation Configurations for In-Line Meters ............................................................................. 20 7.2.2.1 Short-Coupled Installation ................................................................................................................... 20 7.2.2.2 Close-Coupled Installation ................................................................................................................... 21 7.2.2.3 Meter-Integrated Flow Conditioning .................................................................................................... 22 7.2.3 Suggested Installation for Angle-Body Meters ............................................................................................ 23 7.3 ENVIRONMENTAL CONSIDERATIONS ................................................................................................................... 24 7.3.1 Temperature ................................................................................................................................................ 24 7.3.2 Vibration ..................................................................................................................................................... 24 7.3.3 Pulsations .................................................................................................................................................... 24 7.3.4 Hydrate Formation and Liquid Slugs .......................................................................................................... 24 7.4 ASSOCIATED DEVICES ........................................................................................................................................ 24 7.4.1 Filtration and Strainers ................................................................................................................................. 24 7.4.2 Throttling Devices ....................................................................................................................................... 25 7.5 PRECAUTIONARY MEASURES .............................................................................................................................. 25 7.5.1 Installation Resídue ..................................................................................................................................... 25 7.5.2 Valve Grease ............................................................................................................................................... 25 7.5.3 Over-Range Effects ..................................................................................................................................... 25 7.5.3.1 Run Pressurization ............................................................................................................................... 25 7.5.3.2 Blow Down Precautions ....................................................................................................................... 26 7.5.3.3 Flow Limiting Devices......................................................................................................................... 26 ACCESSORYINSTALLATION ............................................................................................................................... 29 7.6 7.6.1 Density Measurement Devíces ..................................................................................................................... 29 7.6.2 Volume Correctors and Instrumentation ...................................................................................................... 29 8. 8.1 8.2 8.3 8.4 8.5 8.6

METER MAINTENANCE AND FIELD VERIFICA TION CHECKS ........................................................30 GENERAL ............................................................................................................................................................ .30 VISUAL INSPECTION ........................................................................................................................................... .30 CLEANING AND OILING ....................................................................................................................................... 31 SPIN TIME TEST .................................................................................................................................................. 31 DUAL-RoTOR METER FIELD CHECKS ................................................................................................................. 33 RETESTING CONSIDERA TIONS ............................................................................................................................. 33

V1ll

APPENDIXA._....................................................................................................................................................... A-1 A.1 A.l.l A.l.2

A.2 A.2.l A.2.2 A.2.3

A.3

SINGLE ROTOR TURBINE METERS .....................................................•.............................................. A-1 GAsMETERDESIGN .................................................................................................................................... A-l LIQUIDMETERDESIGN ................................................................................................................................ A-2

DUAL-ROTOR TURBINE METERS ......................................................... _............................................. A-2 DUAL-RoTOR DESIGNS ............................................................................................................................... A-2 SECONDARY ROTOR DESIGNS ...................................................................................................................... A-S SECONDARY ROTOR FUNCTIONS .................................................................................................................. A-S

DUAL-ROTOR METER ELECTRONICS ............................................................................................... A-5

APPENDIX B •.. _..................................................................................................... _ ............................................ B-1 B.1

EQUATIONS FOR CALCULATING VOLUMETRIC FLOW ...................._........................................ B-1

B.l.l BASICGASLAWS ......................................................................................................................................... B-l B.l.2 FLOW RATE AT FLOWING CONDITIONS ......................................................................................................... B-2 B.l.3 FLOWRATE AT BASE CONDITIONS ............................................................................................................... B-2 B .1.4 PRESSURE MUL TIPLIER ................................................................................................................................ B-2 B.l.S TEMPERATURE MULTIPLIER ......................................................................................................................... B-3 B.l.6 COMPRESSIBILITY MUL TIPLIER .................................................................................................................... B-3 B.l.7 EQUATIONS FOR METER RANGEABILITY ...................................................................................................... B-3 B.l.7.l Maximum Flow rate .............................................................................................................................. B-3

B.2

EQUATIONS FOR CALCULATING MASS FLOW ............................................................................... B-5

APPENDIX C .......................................................................................................................................................... C-I C.I

METER REGISTER READING ................................................................................................................ C-1

C.2

ELECTRONIC COMPUTATION ............................................................................................................. C-I

C.3

MECHANICAL INTEGRATING DEVICES ........................................................................................... C-1

CA

PRESSURE, VOLUME AND TEMPERA TURE RECORDING DEVICES ......................................... C-I

APPENDIX D ......................................................................................................................................................... D-I D.I

CHANGE GEARS ....................................................................................................................................... D-I

D.2

K-FACTOR(S) .............................................................................................................................................. D-2

D.3

METER FACTOR ....................................................................................................................................... D-4

D.4

FINAL METER FACTOR .......................................................................................................................... D-8

D.5

ROTOR FACTORS FOR DUAL-ROTOR METERS ................................................................................ 10

APPENDIX E .....•........................................................................................................................................•.......... E-l E.1

REYNOLDS NUMBER AND FLOW RA TE MATCHING ..................................................................... E-1

E.2

PRESSURE AND FLOW RATE MATCHING ..........................................•.............................................. E-2

E.3

DENSITY AND REYNOLDS NUMBER MATCHING ........................................................................... E-2

E.4

DENSITY AND FLOW RATE MATCHING ............................................................................................ E-2

E.s.

EXAMPLE CALCULATIONS ................................................................................................................... E-2

E.s.1 TO MATCH REYNOLDS NUMBERS AND FLOW RA TES ................................................................. E-3 APPENDIX F .....••...........................•.......................................................................•.•............................................. F-l F.l

TESTING IN-LINE ....................................................................................................................................... F-l

IX

F.2

TESTING OUT OF LINE ....................................................................•.........................................•............. F-l

REFERENCE LIST ........................................................................................... _............................................... REF-l FORM FOR SUGGESTION TO CHANGE IN THE AGA REPORT NO. 7 .................................................... S-1

x

MEASUREMENT OF NATURAL GAS BY TURBINE METERS

1.

Introduction 1.1

Scope

These specifications apply to axial-flow turbine flow meters for measurement of natural gas, typically 2-inch and larger bore diameter, in which the entire gas stream flows through the meter rotor. Typical applications include measuring single-phase gas flow found in production, process, transmission, storage, and distribution and end-use gas measurement systems. Typical use is the measurement of fuel grade natural gas and associated hydrocarbon gases either as pure hydrocarbons or as a mixture of pure hydrocarbons and diluents. Although not within the scope of this document, turbine meters are used to measure a broad range of fluids other than natural gas. This report does not address the characteristics of electronic pulse signal generating devices within or attached to the meter, although it does address the use oftheir outputs. AIso not addressed are the characteristics of mechanical or electronic instruments that convert meter outputs from line conditions to base conditions. However, Appendix B do es contain the equations establishing the mathematical basis for the conversion process. Although these equations appear in this report, they may be used to convert volume registered by any type of meter. 1.2

Principie of Measurement

Turbine meters are inferentiaI meters that measure flow by counting the revolutions of a rotor, with blades, which turns in proportion to the gas flow velocity. From the geometry and dimensions of the rotor blades and flow channeI, for a particular turbine meter size and model, the gas volume at line conditions can be inferred trom counting the number of rotor revolutions. The revolutions are transferred into digital readout or electronic signals by sorne combination of mechanical gearing, generated e1ectronic or optical pulses, or frequency. The accumulated line volume can be converted to base volume at standard or contract conditions by accessory devices. Turbine meters can operate over a wide range of gas and ambient conditions. Their upper flow capacities are established and limited by maximum local internal gas velocities, noise generation, erosion, rotor speed, shaft bearing wear and pressure losses. The maximum flow capacity at line conditions is fixed for a particular turbine meter regardless of the operating pressure and temperature. The maximum base flow capacity increases in accordance with Boyle's and Charles' laws. Minimum flow capacities are limited by fluid and non-fluid drags (i.e., windage and mechanical friction los ses, respectively) that cause a particular turbine meter design to exceed the desired or prescribed performance limits.

2.

Terminology

For the purposes ofthis report, the following definitions apply: Change gears

A set of mating gears in the output gear train of sorne turbine meters that can be changed during the calibration process. A gear combination can be selected, with the appropriate ratio of teeth, to correct the mechanical output to reduce registration errors.

Designer

A company that designs and constructs metering facilities.

Error

The result of a measurement minus the true value of the measurand. Note: Since the true value cannot be determined, a value determined by means of a suitable reference meter is used. % error = [(measured value - reference value) / reference value] x 100%

Final meter factor

A number developed either by averaging the sum of the individual meter factors over the range of the meter or by weighting more heavily towards the meter factors over flow rates at which the meter is more likely to be used. The value is used as a correction factor. In addition, multi-point linearization or polynomial curve fitting techniques may be used.

K-factor

A number by which the meter's output pulses are multiplied to determine the volume through the meter. One or more factors may be used over a meter's operating range as determined by flow calibration results.

MAOP

Maximum allowable operating pressure.

Manufacturer

A company that designs, manufactures, sells and delivers turbine flow meters.

Maximum peak-to-peak error

The difference between the largest and the smallest errors throughout the calibrated range of the meter.

Measurement cartridge

An intemal assembly, removable from sorne meters, which ineludes the measurement components, but excludes the meter body.

Meter factor

A number by which the result of a measurement is multiplied to compensate for systematic error. The non-dimensional multiplying value is determined for each flow rate at which the meter is calibrated. The number is calculated by dividing the value from the reference meter by the indicated value of the

2

meter under test. It can be applied to individual flow rates or averaged to provide a single factor (final meter factor) for the meter. Operating range

The range of ambient and flowing gas conditions over which the meter is designed to operate.

Pressure drop

The permanent los5 of line pressure across the meter.

Q¡

The flow rate through the meter under a specific set of test or operating conditions. The maximum gas flow rate through the meter that can be measured within the specified performance requirements. The minimum gas flow rate through the meter that can be measured within the specified performance requirement. The transition flow rate. The flow rate through the meter at which performance requirements may change.

Rangeability

The ratio of the maximum to minimum flow rates over which the meter meets specified performance requirements (sometimes called "turndown ratio").

Reference meter

A meter or measurement device of proven flow measurement accuracy.

Repeatability

Cl05eness of the agreement between the results of successive measurements ofthe same measurand carried out under the same conditions of measurement. Notes: 1. These conditions are called repeatability conditions. 2. Repeatability conditions inelude: • The same measurement procedure • The same observer • The same measuring instrument used under the same conditions • The same location • Repetition over a short period of time 3. Repeatability may be expressed quantitatively in terms of the dispersion characteristics ofthe results. 4. A valid statement of repeatability requires specifications of the conditions of measurement, such as temperature, pressure and gas composition.

3

Rotor factor

The number of output pulses per unit volume for individual rotores) provided by the meter manufacturer for use in a proprietary algorithm. Rotor factors are assocÍated with the electronic pulse output(s) from each rotor, typically of a dualrotor turbine meter.

User

The individual or company that uses the turbine meter for measurement purposes.

4

3.

Operating Conditions Gas Quality

3.1

The meter should, as a minimum requirement, operate with any of the nonnal range natural gas composition mixtures specified in Table 1 of AGA Report No. 8, Compressibility Factors oiNatural Gas and Other Related Hydrocarbon Gases (Reference 1). The manufacturer should be consulted if any of the following are expected: •

Operation near the hydrocarbon or water vapor dew point of the natural gas mixture.

•

Total sulfur levels exceeding 20 grains per 100 cubic feet, including mercaptans, H2S and elemental sulfur compounds, or exceeding those specified in the National Association of Corrosion Engineers (NACE) guidelines for the materials ofwhich the meter is manufactured.

•

Exposure to other contaminants that may affect the meter's error by reducing the cross-sectional f10w area or building up on other sensitive features. Deposits may also contaminate bearing lubrication and lead to reduced service life.

Operating Pressures

3.2

The operating pressure of the meter shall be within the range specified by the meter manufacturer. The manufacturer shall specify the maximum allowable operating pressure for the meter design and construction. Turbine meters, in general, do not have a minimum operating pressure limit, although error may be increased if used under conditions for which the meter has not been calibrated. Section 6 provides information on calibration requirements.

Temperatures, Gas and Ambient

3.3

The meter shall be used within the manufacturer's flowing gas and ambient air temperature specifications. Depending upon material of construction, turbine meters can operate over a f10wing gas and ambient temperature range of -40 o p to + 165°P (-40°C to 74°C). It is important that the flowing gas temperature remain aboye the hydrocarbon dew point of the gas to avoid possible meter damage and measurement error. The manufacturer shall provide gas temperature and ambient air temperature specifications for the meter, as they may differ from the aboye.

Effect of Gas Density

3.4

Gas density can have three principal effects on the performance ofthe gas turbine meter: •

Rangeability - The rangeability of a turbine meter increases as gas density increases.

•

Pressure Drop - The pressure loss across a turbine meter increases as the gas density increases.

•

Error - Operating characteristics may change as gas density changes.

5

3.5

Gas Flow Rate Considerations

The manufacturer shall provide the operating flow rate range at various pressures. The user needs to consider the relationship between flow rate, error, pressure 10ss and service life. The performance requirements for operation are stated in Section 5.1 of this document. The pressure 10ss across a turbine meter increases with the square of a flow rate increase. Bearing lubrication or visual inspection frequencies may need to be adjusted in accordance with the operating flow rateo Flow limiting devices may be required to provide over-range protection for the meter. Designers and users are cautioned to evaluate noise, piping safety and meter integrity concems at maximum operating velocity. Refer to Section 7 of this document for more inforrnation on installation considerations.

3.6

Upstream Piping and Flow Profiles

Research was conducted on the effects of installation configuration on turbine meter error in 2002 and the results published in Reference 2, Section 7 provides inforrnation on installation requirements.

6

4.

Meter Design Requirements 4.1

Codes and Standards

The meter body and a11 other parts eomprising the pressure eontaining struetures shall be designed and construeted of materials suitable for the service conditions for whieh the meter is rated and in aceordance with any applicable eodes, regulations and speeifieations of the designer. The meter body sha11 operate without leakage or pennanent defonnation over the expeeted range of operating pressures, flowing gas temperatures and environmental conditions. 4.2

Meter Body 4.2.1

Meter Body End Connections

The body end connections shaU be designed in accordanee with appropriate flange or threaded connection standards. 4.2.2

Corrosion Resistance

AH wetled parts of the meter shaU be manufaetured of materials suitable for use in their intended application. A11 external parts of the meter should be made of corrosion-resistant material s or sealed with a corrosion-resistant coating suitable for use in environmental conditions typically found in the natural gas industry aml/or as specified by the designer. 4.2.3

Meter Lengths and Bores

Manufacturers shaH publish their standard overa11 face-to-face length of the meter body for each meter size and pressure rating. Turbine rneters are genera11y tolerant of minor diameter differences, such as pipe schedule size changes. However, the designer sha11 make sure that the recommendations of Section 7 are followed. 4.2.4

Pressure Tap

The rnanufacturer shall provide at least one pressure tap on the meter body. The static pressure from the meter tap provided and identified by the manufacturer shall be used for pressure correction of the meter registration volume. 4.2.5

Sealing

The meter may be provided with sealing arrangements to prevent access to its internal working parts, adjustments and reprogramming. The sealing arrangements shall be such that they do not prevent access to routine maintenance features of the meter, such as lubrication points. Where measurernent cartridges are interchangeable, the means of sealing the cartridge shal1 be designed to prevent access to adjustment and reprogramming when the cartridge is removed from the meter body. Any means provided to seal the cartridge to the meter body sha11 be independent of any other sealing means provided. Independent seaJing sha11 al10w the body-to-cartridge seal to be removed without permitting access to the cartridge's intemal working parts or adjustments.

7

4.2.6

Miscellaneous

The construction shaIl be mechanicaIly and electricaIly sound, and the materials, finish, etc., should be such as to provide assurance of long life and sustained accuracy. The meter may provide one or more outputs (mechanical or e1ectrical), proportional to the volume of gas that has passed through it, expressed at line conditions of pressure and temperature. The meter shaIl be designed in such a way that the body will not roIl when resting on a smooth surface with a slope ofup to 10 percent. The meter design shall al so permit easy and safe handling of the meter during transportation and installation. Threaded holes for hoisting eyes or clearance for lifting straps shall be provided. Meter Markings

4.3

A name platee s) containing the fo11owing information shall be affixed to the meter •

Manufacturer

•

Model and size (intemal nominal díameter)

•

Serial number

•

Date of manufacture or date code

•

Maximum allowable operating pressure (MAOP)

•

Maximum rated capacity at flowing conditions

•

K-factor amI/or rotor-factor(s), if applicable

Other markings on the meter sha11 indicate:

4.4

•

Inlet end or direction of flow

•

Direction of output shaft rotation, if applicable

•

Units ofvolume per revolution ofthe output shaft, if applicable

•

Material ofpressure containing components, (body, flanges, top plate, etc.)

•

Pressure reference tap (e.g., "PR," "Pr" or "Pm")

•

Orientation of measurement cartridge, if applicable

•

Serial number of measurement cartridge, if applicable

Documentation

The manufacturer shall provide a11 necessary data, certificates and documentation for correct configuration, set-up and use of the particular meter upon request by the user or designer. The user or designer may also request that copies of hydrostatic-test or lcak-test certificates, material certifications and casting or weld radiographs be supplied with delivery of the meter.

8

The manufacturer shalI provide or make available the following documents with the meter or when requested; all documents shall be dated: a) A description ofthe meter, giving technical characteristics and principIe of operation. b) A perspective drawing or photograph ofthe meter e) A list ofparts with a description oftheir constituent material s d) A dimensional drawing e) A drawing showing locations of seals f) A drawing of the data plate or badge, showing arrangement of inscriptions g) Instructions for installation, operation, and periodic maintenance h) A general description of operation i)

A description of available mechanical outputs and electronic output signals, and any adjustment mechanisms

j)

A description of available electronic interfaces, wiring points and essential characteristics

k) Documentation of compliance with applicable safety codes and regulations 1)

Test report of meter performance

9

5.

Performance Requirem ents 5.1

General Performance Tolerances

The manufacturer shall specify flow rate limits for Qmin, Qt and Qmax for each meter design and size. Meter performance at atmospheric pressure sha11 be within the fol1owing tolerances (see a1so Figure 1) after calibration. Repeatability:

±O.2% from Qmin to Qmax,

Maximum peak-to-peak error:

1.0% aboye Qto

Maximum error:

±1.0% from Qt to Qmax, and, ±1.5% from Qmin to Qt,

Qt not greater than 0.2 Qmax.

Transition flow rate:

Note 1. The tolerances apply after adjustment ofthe change gears (if any) andlor setting ofK-factors and application ofthe fmal meter factor. The tolerances apply after any corrections perfonned within the meter Note 2. itself but prior to the application of any linearization algorithms by equipment auxiliary to the meter. Note 3. These tolerances are applicable at atmospheric pressure. As operating gas pressure increases, the perfonnance of the turbine meter can be expected to improve dramatica11y, with sma11er values for repeatability and maximum peak-to-peak error, provided the meter is calibrated for the intended operating conditions.

o "ID

1.75 1.50 1.25 1.00 0.75

f

0.50 0.25

t====

Repeatabilily +/-0.2% Maximum peak-to-peak error 1.0% (a¡ ~ Qt)

-

e

0.00 eQ) -0.25 ~ -0.50 -0.75 -1.00 -1.25 -1.50 -1.75

f

f Qm¡n

al ~ 0.2 Qmax

Flow rate (Q¡)

Figure 1. Turbine Meter Tolerances at Atmospheric Pressure

10

f

5.2

Temperature and Gas Composition Influences

The turbine meter shall meet the aboye performance requirements over the full operating range of temperature and gas composition. 5.3

Pressure Influences

Research on the effects of pressure on turbine meter performance was conducted in 2002 and 2003, and the results published in Reference 3. To minimize error, turbine meters should be calibrated for the applicable operating conditions. Guidance on calibration requirements is provided in Section 6. 5.4

Meter Body Interchangeability

Meters with interchangeable measurement cartridges are designed so that the measurement cartridge can be removed from the meter body without removing the body from the installation. This design facilitates in situ inspection and replacement or upgrading of a cartridge. The construction of a meter with an interchangeable measurement cartridge shaIl be such that the performance characteristics specified in Section 5.1 are maintained after installation of the cartridge in other meter bodies of the same manufacturer, size and model, or after repeated removal and instaIlation of the measurement cartridge in the same meter body. However, slight differences in geometry from the body in which the cartridge was calibrated, body wear, cartridge-body misalignment or other influences may affect the performance of the cartridge and resuIt in measurement error. An independent study (Reference 4) was conducted to assess measurement error due to

cartridge change-out practices. The study indicates that operating a cartridge in a body other than the one in which it was calibrated can introduce random measurement errors from a negligible amount to as much as ±O.35%. Turbine meter users should bear in mind that calibration of measurement cartridges on a stand-alone basis, while convenient and less expensive than calibrating a cartridge and body as a combination, can add to measurement error.

11

6.

Individual Meter Tests 6.1

Integrity Test

The manufacturer shall test the integrity of a11 pressure-containing components for every turbine meter. The test shall be conducted in compliance with the appropriate industry standard, (ANSIIASME B16.1, B16.5, B16.34 or other, as applicable). 6.2

Leakage Test

Every turbine meter shall be leak-tested by the manufacturer after final assembly and prior to shipment to the customer or flow-calibration facility. The test shall be conducted in compliance with the appropriate industry standard. In the absence of specific standard(s), it is customary for manufacturers to conduct the test as follows: The test medium sha11 be a gas, such as nitrogen or airo The leak-test pressure shall be at least 1.10 times the MAOP and held for a minimum offive minutes. To pass this test, the meter must not have detectable leaks. 6.3

Calibration

In order to establish satisfactory performance characteristics, every turbine meter should be calibrated under conditions acceptable to and agreed upon between the parties to the transaction. For best performance, calibration conditions should match the anticipated inservice conditions, including considerations such as fluid characteristics, operating pressure, expected flow rates, the use of a dedicated meter body, inlet and outlet piping characteristics, and other factors that can affect meter perfonnance. However, limitations on the capability and availability of calibration facilities and the costs associated with transportation and testing may result in decisions to calibrate meters under conditions that, while not identical to those expected in service, provide a reasonable approximation thereof. Attention to replication of the crucial in-service parameters described below will ensure adequate perfonnance for most commercial applications. 6.3.1

Calibra/ion Conditions

Research (Reference 3) has shown that the performance of turbine meter s varíes with changes in flow rate and operating pressure. These variations are related to changes in Reynolds number and, in sorne cases density, and are particularly significant at low and intermediate operating pressures and flow rates. Attention to these issues at the time of calibration is crucial for optimal measurement. The following sections pro vide further guidance in this regard. 6.3.1.1

Reynolds Number

Reynolds number is a dimensionless ratio of inertial to viscous forces in the flow through the meter that takes into account the flow rate and physical properties of a moving fluid. Reynolds number can be used to correlate the calibration and operating conditions of a turbine meter under various flow rates, pressures and fluid types.

12

The basic equation for Reynolds number is: Re

=

(6.1)

p (D) (V) / JI

Reynolds number may also be calculated from either of the following formulae: Re

=

4(Q) / 1f(D) (0

Re= 4 (Q) (p) !Jr(D) (J.l)

Re p(rho) D V

where

Q v (nu) J.l (mu)

=

(6.2) (6.3)

Reynolds number Density ~eter diameter BuIk (average) velocity offlowing fluid Volumetric flow rate Kinematic viscosity Absolute viscosity

The aboye quantities must all be determined at the same conditions of temperature and pressure. The relationship between bulk velocity and flow rate is: (6.4) The relationship between absolute and kinematic viscosity and density is: (6.5) A meter calibration carried out in a test facility over a particular range of Reynolds numbers characterizes the meter' s performance when used to measure gas over the same range of Reynolds numbers when the meter is in service. Therefore, the Kfactors established during such a calibration, in most instances, can be used to compute flow measured by the meter in service.

6.3.1.2

Densíty

Research (Reference 3) has shown that the performance of sorne meters may al so be sensitive to variations in gas density. Variations in calibration tend to be larger at lower gas densities. Users with low-pressure, low-flow applications should consult the meter manufacturer for meter performance characteristics and obtain calibration data at the operating density to ensure that no significant measurement errors exist. Additional information on density matching is provided in Appendix E.

6.3.1.3

Calibratían Gases

The research described in Reference 3 was conducted using natural gas and air as test media. In addition, Reference 6 describes research that has been conducted to establish the suitability of other gases for calibration of turbine meters. The data show that turbine meters used in natural gas can be effectively calibrated in different

13

gases, and that satisfactory measurement will result provided calibration is conducted over the range of Reynolds numbers ami/or density expected at operating conditions. Further information on calibration in altemative gases is provided in Appendix E.

6.3.2

Calibration Guidelines

As discussed aboye, the expected operating Reynolds number range ami/or density for a meter needs to be taken into account when designing a calibration programo This requires establishing the expected range of flow rates and the properties of the gas to be measured at the intended meter location. The gas properties may be determined directly by measurement or by calculation from empirical equations. Test points should be selected throughout the range offlow rates over which the meter is to be tested. It may be decided to concentrate the majority of the test points in the range ofthe meter's heaviest expected usage. Further information and sample calculations appear in Appendix E.

6.3.3

Calibration Configuration

To minimize errors, meters should be calibrated in the same configuration as intended to be installed in service. However, most test facilities routinely perform calibrations in the recommended configuration described in Section 7.2. Research (Reference 2) has shown that the errors of meters calibrated in this manner will be acceptable when installed in any of the configurations described in Section 7.2. For applications with more severe installation configurations, the user should consult the manufacturer or test facility operator for experimental data to determine an adequate calibration configuration.

6.3.4

Calibration Facilities

Test facilities used for meter calibration shall be able to demonstrate traceability to relevant national primary standards and provide test results that are comparable to those from other such facilities.

6.3.5

Calibration Results

During calibration, the appropriate K-factor(s), meter factors, change gears ratios and rotor factors will be established. The applicable factors will be established for each output for meters with more than one output. Refer to Appendix D for detailed information and examples of determining and applying these factors.

6.3.5.1

Change Gears

For turbine meters with mechanical output(s), intemal gearing is typically used to adjust the registration to produce a (nearIy) fmite indicated volume (e.g., 100 cubic feet, 10 cubic meters, etc.) for each revolution of the output shaft. Differing change gear sets, comprised of two replaceable mating gears incorporated within the gear train, perrnit adjustments to be made to the overall gear ratio. While change gear sets with many ratios are available, it is not always possible to install gears with the precise ratio needed. Thus, there may be sorne residual bias in the meter's calibration

14

even after the best available change gears have been installed. The change gears are usualIy located in a non-pressurized region of the meter that is accessible during calibration, but that can be sealed to prevent unauthorized access. When an interchangeable measurement cartridge is moved to a new body, the change gears shalI be moved also. 6.3.5.2

K-Factor(s)

For turbine meters with electronic output(s), the appropriate K-factor(s) is established at the time of calibration. These value(s) are then entered into an electronic accessory device. The K-factor(s) is expressed in units of pulses/unit volume. By dividing the accumulated pulses by the K-factor or by dividing the instantaneous pulse frequency by the K-factor, the accumulated volume or the instantaneous flow rate, respectively, can be determined. 6.3.5.3

Meter Factors and Final Meter Factor

Meter factors are non-dimensional multiplier values. They are derived from calibration data by dividing the true volume of the reference meter by the indicated volume of the test meter, both volumes having first been corrected to the same base conditions. Alternatively, meter factors can be calculated from the percent error values provided at each calibration flow rate, by the formula: M eter factor = 100 / (1 00 + percent error)

Thus, the meter factor example of 1.005 would be the same as -0.5 percent error. The mechanical or electronic outputs of a turbine meter may be adjusted by the application of individual meter factors for specific flow rates or by a single final meter factor over the range of flow rates. This may be done omine manualIy or online in an electronic accessory device. The calibration facility may provide meter factors in addition to or in place of percent error values for each test flow rate of a meter. 6.3.5.4

Rotor Factorsfor Dual-Rotor Meters

For dual-rotor turbine meters, with associated algorithms for enhanced performance and diagnostics, the manufacturer will supply unique K -factors for each rotor' s electronic pulse output. These are referred to as "rotor factors" to distinguish them from K-factor, which is the term historically used to apply to the single-rotor electronic output of a meter. Refer to Appendix A, Sections A.2 and A.3 and to Appendix D, Section D.5 for more details. 6.3.5.5

Meter Verification Test

Following an adjustment, at least one test point shall be repeated to verify that the adjustment was calculated and applied correctly. If a linearization technique is applied in secondary or companion electronics, then at least two test points shalI be repeated.

15

6.4

Test Reports

The resuIts of each test required in Section 6.3 shall be documented in a report including, as a mmlmum: a) The name and address of the manufacturer b) The name and address of the test facility c) The model, size and serial number of the meter d) The date(s) ofthe test e) The name and title of the person who conducted the tests f)

The meter performance data

g) Test pressure and temperature h) Ambient temperature and atmospheric pressure i)

Test fluid, composition and properties at each test point, ifvarying

j)

A description of the test configuration used

k) The value of any adjustment made and the results of the verification test A copy of the report shall be available from the testing organization for a period of five years. 6.5

Quality Assurance

The manufacturer shall establish and follow a comprehensive quality-assurance program for the assembly and testing of the meter and its electronic system (e.g., ISO 9000, API Specification Q 1, etc.). The user shall have access to the quality-assurance documents and records.

16

7.

Installation Specifications

The impact on measurement has been assessed for the configurations described below. Various organizations have published test data. Configurations other than those described below may result in unacceptable measurement errors and are not recommended without further testing.

7.1

General Considerations 7.1.1

Flow Direction

Turbine meters, designed for flow in one direction only, shall be installed accordingly. Reverse flow may not damage the meter internals but may result in registration error. Tbe manufacturer may be consulted if reverse flow has occurred. Where reverse flow is expected, additional valving is necessary to allow gas to flow through the meter in the forward direction only, unless the turbine meter is recommended for bi-directional flow. 7.1.2

Meter Orientation and Support

Turbine meters, designed for horizontal orientation, shal1 be installed accordingly. A vertical in-line installation may be used; however, the manufacturer's recommendations for piping configuration and maintenance should be fol1owed. The meter and meter piping shall be adequately supported and installed so as to rninimize strain on the meter body. 7.1.3

Meter Run Connections

The meter and adjacent pipe sections should have the same nominal diameter, but schedule changes are acceptable provided satisfactory meter performance has been demonstrated. Meter inlet and outlet connections and companion pipe flanges shall be aligned concentrically. Gaskets shall not protrude into the flowing gas stream. Gasket protrusion or flange misalignment can affect meter perfonnance. 7.1.4

Internal Surfaces

The intemal surface of the meter should be kept cIear of any deposits that may affect the meter's cross-sectional area. The meter's perfonnance depends on a known crosssectional area. Pipe interior surfaces should be of commercial roughness or better. Welds on piping at the meter inlet and outlet should be ground flush with the internal surface of the pipe so that they do not protrude into the gas stream. 7.1.5

Temperature Well Location

The temperature well shall be located downstream of the meter to keep disturbances to a minimum. Generally temperature wells are installed between one and five nominal pipe diameters from the meter outlet but upstream from any valve or flow restrictor. It is important that the temperature well be installed to ensure that heat transfer from the adjacent piping and radiation effects of the sun do not influence the temperature reading of the flowing gas.

17

7.1.6

Pressure Tap Location

The pressure tap provided by the manufacturer on the meter shall be used as the point of pressure sensing for recording or integrating instruments and during calibration. 7.1. 7

Flow Conditioning

A flow conditioner may be used upstream of the turbine meter to reduce or eliminate the effects of swirl amI/or asymmetric flow. Headers, pipefittings, valves and regulators preceding the meter inlet may cause perturbed flow conditions. Flow conditioners shall be installed as specified in the following sections. There shall be no protrusions into the piping between the flow conditioner and the meter.

7.1.7.1

Tube Bundle Type Straightening Vanes

For specifications for these devices, refer to the latest revision of AGA Report No. 3, Orifice Metering 01 Natural Gas and Other Related Hydrocarbon Fluids (Reference 10). This design has demonstrated its effectiveness in the reduction of swirl but does not eliminate asymmetric flow.

7.1.7.2

Other External Flow Conditioners

Isolating flow conditioners offer an alternative to tube bundles. They are recommended for use if the contracting parties agree. Isolating flow conditioners general1y consist of perforated plates in various parterns, sometimes accompanied by vane assemblies. Several of these devices have been evaluated for performance and found to be effective in reducing swirl and asymrnetric flow.

7.1.7.3

1ntegral Flow Conditíoners

Only meters incorporating integral flow conditioners as described in Section 7.2.2.3 are recornmended for use in the short and close-coupled installations described in Sections 7.2.2.1 and 7.2.2.2.

7.2

Recornrnended Installation Configurations

Research (Reference 2) shows that turbine meters may be operated according to the recornmendations in this section with acceptable results, while more severe piping arrangements may result in considerable error. The magnitude of the error, if any, will be a function of the extent of the flow disturbances, the meter' s design, the quality of external and integral flow conditioning, amI/or the meter's ability to adjust for such conditions. However, other configurations may be used provided they are shown to be acceptable based on published experimental data.

18

7.2.1

Recommended Installationfor In-Line Meters

The recommended installation (Figure 2) ineludes at least 10 nominal pipe diameters of straight pipe upstream of the meter inlet, with a flow conditioner oudet located 5 nominal pipe diameters upstream of the meter inlet.

Optional - Rel. Temperature Well

Turbine Meter

- Sample Probe Pressure Tap

r'o" ,."'," "

Recommended - Blow Down Valve [3]

--1

0""'....

'-, l,

,

c==-==~:=J ---Ir1I

1

,

:

=

Temperature Well

'

,

.,J\f.ii 7 _

I .!-\ ':'f[J'¡

r-~--~~~~

5 Nominal Pipe [1)[2)

NOTES:

Diameters

'.

¡¡

Device

,

,,, ,, ,, ,, r-------------~, : L.

L.

Optional _______---l - 19 Tube Bundle - or Flow Conditioning Element

Optional

-Flow Limiting

Minimum 5 Nominal Pipe Diameters

~

[1] Recommended spacing, unless otherwise supported by published test data lor the fiow conditioning elemen!. [2] No pipe connections or protrusions allowed within this upstream section. [3] For recommended size 01 blow down valve, see Table 1. Locate downstream 01 meter.

Figure 2. Recommended Installation Configuration for In-line meters

A minimum length of 5 nominal pipe diameters of straight pipe is inc1uded downstream

of the meter. There shaIl be no pipe connections or protrusions within the upstream or downstream piping other than pressure taps, temperature wells or flow-conditioning elements. A typical recornmended installation meter run with accessories and optional devices is shown in Figure 3. The maximum pipe-size difference upstream or downstream of the recornmended installation should be one nominal pipe size. Valves, filters or strainers may be instaIled upstream or downstream of the recommended instaIlation piping. Any valve immediately upstream of the installation shall be fuIly open during meter operation. Strainers and filters should be kept c1ean for optimum performance.

19

Turbine Optional - Filter 90· Elbow or Tee - or Strainer Maximum

Pressure Tap

Reduction

1

Lo

~e~perature

10 Nominal Pipe

: [:---1

:

OH

1

1

~L - -

r-

~,. ~"'~\

__

:: .,

Optional:,."'tl \)1 ~" -Valve,'v '~I ~rlo Realmmended ~::: ::::.... .~ Pressure-Ioading ~

.7

I

5 Nominal

_

Pipe[1][2]

-,

_c·_

":. . :' j

-

Recommended Blow Down

V~~~!~)stream

:10;J':lJ--"'-M~¡[):

l.

Optional - 19 Tube Bundle

psigl31

-1

- - - - - --- - - - - - - - --- - - -

Minimum

¡+- 5 N~;:nal I

Lol..lj ~I

J

~¡"";':' ...."j

Optional [ . _ Bypass Une _

",,_

- •

-l f~(->''.

"""V....

:,."',,( \)1 Optlonal '~I -Valve ~ ::: ::::....

,'v

~~ I

lo - - - - - - - - - - - - - - - -

------------------------_: ~~~~~ L-----------------~I ~::::

NOTES:

... 1

[1) Recommended spacing, unless olherwise supported by published test data lor the flow conditioning element. [2) No pipe connections or protrusions allowed within this upstream section. [3) Size 01 pressure loading line and valve to be the same as recommended blow down valve sizing, (see Table 1).

Figure 3. Typical Meter Set Assembly: Recommended Installation

7.2.2

Optionallnstallation Configurations for In-Line Meters

The use of the following optional installation configurations may result m relatively higher, but still acceptable, measurement uncertainty.

7.2.2.1

Short-Coupled Installation

The short-coupled installation configuration shown in Figure 4 may be used where space is limited. Initial limited research (Reference 2) on tested meters indicates that locating a short-coupled installation with meter-integrated flow conditioning downstream of a high-Ieve1 perturbation (as defined in Reference 7) caused measurement bias not exceeding ±O.4% ofreading, which was within the error limits of ±1.0% specified in Section 5.1 (Figure 1). See Section 7.2.2.3 for a discussion on meter-integrated flow conditioning and Section 6.3 for calibration requirements. The short-coupled configuration includes at least four nominal pipe diameters of straight pipe upstream of the meter inlet, with a flow conditioner located at the inlet of the straight pipe. In addition, the distance between the flow conditioner outlet and the meter inlet should be at least two nominal pipe diameters. The meter may be connected to the vertical risers using elbows or tees. Tees enable visual inspection of the meter runo The maximum difference in size between the mn and the risers shall be one nominal pipe size. The installation of optional valves, filters or strainers in the risers is permitted, although users are cautioned that inclusions in the risers have not been confirmed by published research. Any valve in

20

1

- Lo •

Diameters"" ~"'~\

L?2~::~-~-J =~::/~D E~:'::"~COnd/

1

l'

Diameters -

r

DO.

~

t-_-..,.

~~~"j

l

1- 5

~"~"~

Optional - Flow limiting Device

Optional - Ref. Temperature Well - Sample Probe

the inlet riser shall be fully open during meter operation, and strainers and filters should be kept c1ean for optimum performance.

Optional _Filler _or Strainer

90 o Elbow or Tee Maximum Reduction

OM~:m~"", p., S"

li

F J.

Inlet,L--'

.. 1..'

- -

-:

Optional - Valve

I

1

~.: ~"

:,14..

=- _

(~~I'. ~ ~',

11 1 \\.....~ "1

L~~

Optional 19 Tube Bundle - or Flow Conditioning Element

\ ..... -"1 =. "-

9~~

.. L.'

::::::::C~:f::]

2 Nominal [1) [2) Pipe Diameters

-" I

r,~

---, i ' ,, ii ,' _..J i '

Minimum

_.:~

,

Turbine Meter [4)

C!-==J

,' 1'----I , I ,1' ~ , I '- -

Pressure Tap

Recommended Pressure-Ioading Une and valve lor operation over 200 psig [3)

OPtiona~--1

t

c.A::! -:

"j

, ~.: ~ ~~ ':' lc< \ 11 Recommended 1 \ .... \\~_'" -BlowDown ~ ".-,:...J Valve [3) ,-"-, Optional

- Flow Limiting Device

-V. . .

"1

-~

NOTES; [1) Recomrnended spacing, unless otherwise supported by published test data lor the flow conditioning elemen!. [2) No pipe cooneclions or prolrusions allowed wilhin this upstream section. [3) Size 01 pressure loading line and valve lo be the same as recommended blow down valve sizing, (Table 1). [4) Turbine meler musl have integral flow conditioner.

Figure 4. Short-Coupled Installation

7.2.2.2

Close-Coupled Installation

The close-coupled installation configuration shown in Figure 5 may be used where space is severely limited. Just as in the case of short-coupled installation, initial limited research (Reference 2) on tested meters also indicates that locating a closecoupled installation with meter-integrated flow conditioning downstream of a highlevel perturbation (as defined in Reference 7) caused measurement bias not exceeding ±O.4% of reading, which was within the error limits of ± 1.0% specified in Section 5.1 (Figure 1). See Section 7.2.2.3 for a discussion on meter-integrated flow conditioning and Section 6.3 for calibration requirements. Ihe meter may be connected to the vertical risers using elbows or tees. Iees enable visual inspection of the meter runo The maximum difference in size between the mn and the risers shall be one nominal pipe size. Ihe installation of optional valves, filters or strainers in the risers is permitted, although users are cautioned that inclusions in the risers have not been confmned by published research. Any valve in the inlet riser shall be fully open during meter operation, and strainers and filters should be kept c1ean for optimum performance.

21

Pressure Tap Turbine Meter (1) 90 o Elbow or Tee Maximum Reduction One Nominal Pipe Size

'-1-

1 ---¡ 1 , , I 1

I-rl

1 I 1----1 I 1 1 I1 1 I 1__ ... LI

¡_

, I 1 - -1 I 1

...,.~ l.

f'-=1. -11 ... ,......-...-rl '1'\..!.."/ ,'~ .~---" II~ 1" r~ I)I~

~:.-..::_ ;~\.':::{;J~}' .~_-""''1

Optional ,'~ J\\\ -Valves ..........,..," ~ 1)1 ,,,( .. " '

J\H

r.. ~~

'~~( _

1

>.,'//

a_...

Optional

L\S ..' ..-:,.>,. . (

...,:::..- ......1

r~' ..... c..l

Recommended ~I ~ _ _ _~ Pressure-Ioading 1 line and valve for~ 90 o Elbow operatlon over 200 psig [2)

!!.-_-

Recommended Blow Down Valve (Downstream) [2)

1

..

- Flow Limiting Device

NOTES: [1) Turbine meter must have integral flow condilioning elemenl. [2) Size of pressure-Ioading line and valve to be the same as recommended blow down valve sizing, (Table 1).

Figure 5. Close-Coupled Installation

7.2.2.3

Meter-Integrated Flow Conditioning

Research (Reference 2) has confirrned that turbine meters with integral flow conditioning in the nose-cone flow passages operate satisfactorily in short and closecoupled installations. Those integral flow conditioners tested were similar in design to that shown in Figure 6 and to those evaluated in Reference 8. For this design, the aspect ratios are BID < 0.15 and SIL < 0.35. These parameters are illustrated in Figure 6.

Integral Flow Conditioning on Nose-cone

1--

L

"'1

D

H - radial height of annular flow passage D - d iameter of the meter ¡nlet.

s - maximum chordlength between vanes L - vane len gth in axial direction

Figure 6. Dimensional Parameters for Integral Flow Conditioning

22

7.2.3

Suggested Installation for Angle-Body Meters

A suggested installation for angle-body meters is shown in Figure 7, When a flow conditioner is not used, 10 nominal pipe diameters of straight pipe shall be provided upstream of the meter. When a flow conditioner is used, the flow conditioner inlet shall be a minimum of five nominal pipe diameters from the meter inlet and the length of straight upstream pipe may be reduced to 5 diameters.

Horizontal Installation (Inlet in Horizontal Plane, Outlet Down ) Oplional - Filler - or Slrainer

\¡ -r-

90 o Elbow or Tee Maximum Reduction One Nominal Pipe Size

,-

Pressure Tap Inlel Piping 10 Nominal Pipe Diamelers Long (5 Nominal Pipe Diamelers wilh 19 lube bundle) (1)[2)

-1

Angle-Body Turbine Meler

!!~~~~~~~~~~"~~~~J r--~~~~ o

,--- -;-;í --J~; . . ",- "

....

Oplional - Valve

90

¡:::::

,,

"-,..:-..."', ,....... ,~

::)1:,-" "0

:~

Temperalure Well

-)--;'':.~Q­

1",·__ 'p " \'....

J

.-.1----1 Recommended ~~~, - Blow Down Valve I }, , _ _ _, Downslream [3) / '

II

,A. '\" ~­ '" tC< ~¡¡ ~ ~

,...1 ........ , "

0

Oplional - 19 Tube Bundle - or Flow Conditioning Elemenl

,',..- '\\\ '" rC< ')' Optional "" ' .... , , - Valve \ .........:-::,

Optional - Flow Lim~ing Device

Recommended Pressure-Ioading line and valve for operalion over 200 psig (3)

I '....

,

-~

NOTES: [1) Recommended spacing, unless olherwise supported by pubfished lesl dala lor Ihe f10w conditioning elemenl. [2] No pipe connections or prolrusions allowed within Ihis upslream section. [3] Size of pressure loading fine and valve lo be Ihe same as recommended blow down valve sizing, (see Table 1).

Figure 7, Suggested Installation for Angle-Body Meters

The meter inlet piping may be connected using a 90° elbow or tee, There are no restrictions on the downstream piping except that the flange attached to the meter outlet shall be full-size. Any valve immediately upstream ofthe installation shall be open fully during meter operation. The installation may be oriented vertically, Caution: Users are cautioned that the error of the angle-body configuration has not been confinned by published research. Contact the manufacturer for supporting experimental data for specific installation requirements,

23

7.3

Environmental Considerations 7.3.1

Temperature

The meter shall be installed and used within the ambient and flowing gas temperature limits specified by the manufacturero 7.3.2

Vibration

Turbine meters are in general not susceptible to vibration. However, vibration frequencies should be avoided that might excite the natural frequencies of the piping set, potential1y leading to excessive noise, structural damage to the pipe, amI/or reduced bearing service life of the meter. 7.3.3 Pulsations Pulsations may occur in several forms depending on the design of the system and the operating conditions. Turbine meters installed near compressors and fast-cycling regulators can register incorrectly. Flow pulsations generated by this type of equipment will generally cause a turbine meter to over-register. Pulsation dampeners installed between the source of pulsation and the turbine meter are an effective way of eliminating pulsation-induced measurement errors. Flow transients experienced in normal operation have negligible effect on turbine meter performance because turbine meters in general have the ability to follow slow changes in flow rate. 7.3.4 Hydrate Formation and Liquid Slugs Slugs of liquid or solids entering the meter may damage the meter. The presence of hydrates in the meter installation will cause inaccurate measurement. The meter piping should be designed to prevent liquid accumulation in the meter body and meter runo 7.4

Associated Devices 7.4.1

Filtration and Strainers

Filtration of the flowing gas may not be necessary in all cases but is recornmended for most meter applications. The accumulation of deposits due to a mixture of dirt, milI scale, condensates and/or lubricating oils will deteriorate meter performance. Bearing wear and measurement cartridge damage aml/or failure can be caused by foreign material in the flowing stream. Normal pipeline gas quality may deteriorate during peak demands, plant upsets and new tie-ins, or from normal internal pipeline corrosion resulting in dust, dirt andJor scale. Under such conditions, it is recornmended that a strainer with a basket of 3/32 inch maximum hole size and 40 mesh wire liners be installed upstream of the meter to catch the major part of this foreign material. In sorne instances, it may be preferable to install lO-micron filters for the removal of fine dust, thus increasing bearing life and minimizing deposits on the meters internal parts. A differential pressure gauge should be installed across the filter or strainer to indicate an increase in pressure drop resulting from a build-up of foreign matter in the filter or strainer. Normal pressure drop should be observed and recorded at various flow rates when the strainer or filter is clean.

24

Inspection of the devices should be performed whenever higher than normal pressure drops are indicated on the differential pressure gauge. A greater degree of meter protection can be accomplished through the use of a dry-type or separator-type filter installed upstream ofthe meter inlet piping. When cornmissioning a pipeline, it is recornmended that the meter be bypassed or a temporary strainer element installed to protect the meter from dirt and debris entrained within the initial flow. 7.4.2

Throttling Devices

The installation of a throttling device, such as a regulator or partially closed valve, is not recornmended in close proximity, especially upstream, to the meter. Where such installations are necessary, the throttling device should be placed an additional eight nominal pipe diameters upstream or an additional two nominal pipe diameters downstream of the in-line recornmended installation in Figure 2. In the configurations illustrated in Figures 3, 4, 5 and 7, the throttling device should be placedeight additional nominal pipe diameters upstream of the inlet vertical riser or an additional two nominal pipe diameters downstream of the oudet vertical riser. Placement of such a device in c10ser proximity to the meter may result in increased uncertainty amI/or reduced bearing life. 7.5

Precautionary Measures 7.5.1

Installation Residue

To prevent possible damage, the measurement cartridge or meter should be removed if work such as welding, hydrostatic testing, etc., is being performed in the irnmediate area of the meter. The inside of the meter body and piping shall be thoroughly c1eaned and inspected for construction debris prior to replacement. 7.5.2

Va/ve Grease

Grease can flow from sorne pipeline val ves into the gas stream during lubrication. Val ve grease can adhere to turbine meter blades, thereby affecting meter performance. Such valve types should not be located irnmediately upstream of a turbine meter. 7.5.3

Over-Range Effects

Surges of high-velocity gas through a turbine meter can severely damage the rotor. Extreme gas velocities can occur when pressurizing, blowing down or purging the meter runo The operation of flow- or pressure-control devices in the downstream piping system can also create extreme gas velocities. 7.5.3.1

Run Pressurization

It is good practice to provide isolation block valves for meter runs so that the meter(s) can be maintained and calibrated without service interruptions. F or single meter run stations, a flow bypass line should also be considered (see Figure 3). The isolatÍon block valves must be operated in the proper sequence and slowly to avoid reverse

25

spinning andlor over-speeding the meter during startup. If operating pressures are over 200 psig, a small pressure-Ioading line and valve around a large or fast acting inlet block valve will allow the meter mn to be pressurized slowly to avoid overspeeding damage to the stationary rotor. Recornmended sizes for pressure-Ioading lines and valves are the same as those for blow down valves in Section 7.5.3.2. 7.5.3.2

Blow Down Precautions

While most turbine meters can be operated beyond rated capacity for short periods of time with no damaging effects, oversized blow down valves can cause rotational speeds greatly in excess of the rated capacity. Therefore, blow down valves should be sized as shown in Table l. TABLE 1-BLOW DOWNVALvE SIZING Meter Run Valve Size mm Inches mm Inches

50 80 100 150 200 300

2 3 4 6

8 12

6 13 13 25 25 25

0.25 0.50 0.50 1.0 1.0 1.0

Consult the manufacturer for information on valve sizes for meters not covered in the Table 1. Sorne meters and secondary devices may be damaged when they are operated in a reverse direction. In such cases, the blow down valve shall be located downstream of the meter. 7.5.3.3

Flow Limitíng Devices

In those installations where excessive flow can occur as a result of the operation of the downstream piping system or as a result of the operation of flow- or pressurecontrol equipment, a restrictive device may be installed in the piping downstream of the meter ron to prevent meter over-ranging. An over-range protection device may be sized to limit the flow through the meter to approximately 120% of the maximum rated meter capacity. Meters shall not be operated beyond their rated capacity under normal circumstances. Refer to the sonic nozzle and critical orifice sizes in Table 2. A perrnanent pressure loss will occur even at sub-critical flow rates when one of these devices is installed. Therefore, adequate pressure needs to be available at the location. A critical orifice may result in up to 50% perrnanent pressure loss at critical conditions. Any flow-limiting device may generate significant noise.

26

TABLE 2-S0NIC VENTURI NOZZLE ANO CRITICAL ORIFICE SIZES (Based On Turbine Meter Rated Capacity, 0.6 Relative Density Gas) (See Note & Figure 8 on next pagel

nD"

TURBINE METER RATING cubic cubic meters/h feeUh 100 3500 115 4000 130 4500 250 8800 255 9000 280 10000 450 16000 510 18000 680 24000 760 27000 850 30000 1000 35000 1020 36000 1420 50000 1620 57000 1700 60000 2550 90000 2830 100000 4000 140000 4250 150000 6230 220000 6520 230000 7650 270000

SONIC

120% of RATING cubic ~ubic feetlh meters/h 120 4200 138 4800 156 5400 10600 300 306 10800 336 12000 540 19200 612 21600 816 28800 912 32400 1019 36000 1200 42000 1224 43200 1704 60000 1944 68400 2040 72000 3060 108000 3396 120000 4800 168000 5100 180000 7476 264000 7824 276000 9180 324000

27

VENTURI

mm

inch

13.0 13.7 14.7 20.6 20.8 21.8 27.7 29.5 33.8 35.8 37.8 40.9 41.4 49.0 52.3 53.6 65.5 69.1 81.8 84.6 102.6 104.9 113.5

0.51 0.54 0.58 0:81 0.82 0.86 1.09 1.16 1.33 1.41 1.49 1.61 1.63 1.93 2.06 2.11 2.58 2.72 3.22 3.33 4.04 4.13 4.47

nD"

"T" CRITICAL ORIFICE CRITICAL MAX. ORIFICE THICKNESS

mm

inch

15.2 0.60 16.3 0.64 17.3 0.68 24.1 0.95 24.4 0.96 25.7 1.01 32.3 1.27 34.3 1.35 39.6 1.56 42.2 1.66 44.2 1.74 47.8 1.88 48.5 1.91 57.2 2.25 61.2 2.41 62.7 2.47 76.7 3.02 81.0 3.19 95.8 3.77 99.1 3.90 120.1 4.73 122.7 4.83 132.8 5.23

mm

inch

1.88 2.03 2.13 3.00 3.02 3.20 4.04 4.29 4.95 5.26 5.54 5.99 6.07 7.16 7.65 7.82 9.60 10.11 11.96 12.40 15.01 15.34 16.61

0.074 0.080 0.084 0.118 0.119 0.126 0.159 0.169 0.195 0.207 0.218 0.236 0.239 0.282 0.301 0.308 0.378 0.398 0.471 0.488 0.591 0.604 0.654

The table in the previous page is based on the following fonnulae:

r

=

Venturi aIr rate (acfh)

l

2

D (inch) ]

0.00893

Gas rate (acfh)

=..J1ifi:6 x

Gas rate (acfh)

= 1.291

air rate

=

1.291 x air rate

[D (ineh)]2 0.00893

. h) ( V ' ) (0.00893)2 x Gas rate D ( me entun = 1.291 D(ineh) (Venturi) = (0.00786) .JGas rate D (ineh) (Orifice) = 1.17 x D (in eh) (Venturi) Note: To be sure that the orífice perfonns as a thin-plate, sharp-edged orifice in critical flow, the ratio of orifice pI ate thickness to the hole diameter shall be less than or equal to 0.125. Refer to Reference 9 for additional infonnation. If the thicknessto-diameter ratio is larger than 0.125, then discharge coefficients can have large and uncertain values within the range of 0.8 to 0.95 (vs. 0.73). This is caused by boundary layer/shock interactions within the orífice.

---1 r--

T or less

T or less

r

Flow

Diameter - D

Symmetric plate, both orifice edges sharp

Flow directional plate, leading edge sharp, trailing edge beveled

Figure 8. Critical Orífice Dimensions

28

7.6

Accessory Installation 7.6.1 Density Measurement Devices When using den sitometers , it is desirable to sample the gas as cIosely as possible to the meter. Care should be exercised not to disturb the meter inlet flow or to create an unmetered bypass. Densitometers should be installed downstream of turbine meters. Refer to manufacturers' installation instructions for further information. 7.6.2

Volume Correctors and Instrumentation

Accessory devices and instrumentation, such as mechanical or electronic correction devices, shall be installed and maintained in accordance with manufacturers' guidelines. Care should be taken to ensure that mechanical correcting devices or recorders do not create excess torque loads on the meter that could increase measurement uncertainty at low flow rates. Accessory devices should not be allowed to significantly reduce the spin time ofthe turbine meter. (Refer to Section 8.4)

29

8.

Meter Maintenance and Field Verification Checks 8.1

General

In addition to sound design and installation practices, turbine meter performance is dependent on good maintenance procedures, regular inspections and periodic field checks. The frequency of maÍntenance is dependent on the flowing gas conditions, station operation and/or contract requirements. Meters that operate under dirty flowing gas conditions will require more frequent inspections. In addition, the flowing gas condition will influence the oiling frequency for lubricated turbines. Changes in the performance of a meter may be detected by self-checking features, by visual inspection of the internal mechanism, by spin time tests, or by calibration. Section 6.3 recornmends matching in-service conditions during calibration to determine the best indication of meter error. However, periodic calibration using atmospheric air can be useful for monitoring ongoing meter performance. Sorne dual-rotor turbine meters have output readings that can be used for periodic or continuous checking. These readings can be used to determine the need for maintenance or inspection. A turbine meter can al so be field-checked by either another meter in series or a check rotor in tandem with the metering rotor in a two-rotor turbine meter. In the case oftwo meters in series, the check meter (a turbine meter or other suitable meter) must be installed relative to the field meter so that there is no effect on either meter's performance from the presence of the other. The effects of flowing pressure and temperature on both meters should be considered along with the error of the check meter at the operating conditions. In the case of a dual-rotor meter, both rotors can be calibrated, and field checking achieved by comparing the ratio of the two rotor outputs. 8.2

Visual Inspection

A visual inspection of flow conditioners, upstream and downstream piping, and the meter internals should be performed periodically to ensure there is no accumulation of debris, particularly in the flow passage area, drains, breather holes and lubricatíon systems. Removing the measurement cartridge from the meter body facilitates an inspection of the internal mechanisms. If the cartridge is not removable, remove the meter from the piping or use a borescope. The closures on the ends of the ron may be removed or opened for internal inspectíon of the piping. An inspection of the measurement cartridge consists of examining the rotor for damaged or missing blades, accumulation of solids, erosion or other damage that would affect rotor balance and blade configuration. When a meter is disassembled for any purpose, the mechanism should be thoroughly cleaned to remove dirt or foreign material. Meters in operation can ofien yield information by the noise they generate or by vibrations felt through the body. If the meter has severe vibration, it usually indicates damage. This condition will lead to complete rotor failure. Rotor rubbing and deteriorated bearings can ofien be heard at relatively low flow rates where such noises are not masked by normal flow noise. Concurrent with the internal meter inspection, checks should be performed to ensure that gaskets are properly aligned and that flow conditioners are free of obstructions.

30

8.3

Cleaning and Oiling

The manufacturer's recornmendations should be followed concerning oiling of new meters prior to service start-up and then periodically during service. Frequency of oiling is dependent upon the quality of the gas and operating conditions. Meters operating at high flow rates, high flowing temperatures or metering gas containing solids, liquids or other contaminants rnay require more frequent oiling or bearing replacement than those metering relatively c1ean gas at low flow rates. Monthly oiling is the generally recornmended starting frequency. Excessive oil can cause additional drag that temporarily decreases spin time. Inadequate oil can cause friction and wear in the bearing and result in bearing failure. The rotor bearings operate at a high rpm. Because of this, many turbine meters have provisions for externally oiling the rotor shaft bearings. Various methods may be available to accomplish the lubrication. A pressurized system provides a positive pressure in excess of the operating line pressure (e.g., manual pump gun). This en sures positive oiling and flushing of the rotor shaft bearings. A gravity method should be used in the absence of a pressure system. Automated oilers are also available for use on meters needing more frequent lubrication. Points other than the rotor shaft bearings may require periodic lubrication as recornmended by the manufacturero When a meter is disassembled, the mechanism should be thoroughly cleaned to remove dirt and foreign material. Additionally, oil should be added through the outside oil fitting and a visual check made to ascertain that oil is flowing freely to the main bearings. The user should also consider that significant accumulation of dirt on the nose cone, integral straightening vanes and the area inside the meter body may affeet the performance charaeteristics. Turbine meters intended for use as transfer master meters or for laboratory-controlled comparison testing may not require oiling prior to service. The manufacturer's recommendations should be followed in these cases. 8.4

Spin Time Test

Spin time tests are not intended to take the place of inspection, maintenance or periodic assessment of the meter's errors via a calibration check. However, a spin time test can be a practical indicator of the relative level of mechanical friction in the meter. Increased mechanical friction can result in degradation of meter performance and registration errors, especially at low flow rates and low operating pressures. As mechanical friction inereases, the potential for bearing or other component failure increases. Spin time is not indicative of overall meter performance. Conditions, such as damage or wear to the rotor and internal components, or debris and foreign material inside the meter, can affect meter performance with minimal change to the spin time. A thorough inspection should also be carried out when conducting a spin time test. The manufacturer provides spin times for individual meters and may provide spin times for the meter at various stages of disassembly. Such guidelines may also inelude minimum spin times for various models and sizes of meters. The manufacturer's published guidelines and procedures for conducting spin time tests should be followed. An example of a spin time test procedure appears in Appendix F.

31

It is recornmended that an initial spin time test be conducted to establish a baseline for the

meter with the meter or measurement cartridge completely assembled except for register or recording gauges where gear-driven. When accessory devices (register, integrating gauge, pulse generators, etc.) are installed, care should be taken to ensure that no excess friction is introduced. A spin time test should be performed to ascertain that the accessory device has not affected the meter. After oiIing, the meter should be operated according to the manufacturer's guidelines and procedure to reduce any drag from excess oH before performing a spin time test. When a meter that has been idIe for a long period of time faiIs to meet the manufacturer's specified minimum spin time it should be oiled and then operated for a period of time before repeating the spin time test. Spin time tests may be conducted on complete meters or on measurement cartridges alone. If either the meter or the cartridge is removed from the run for testing, the test shouId be conducted in a draft-free environment with the mechanism supported in its nonnaI operating position. Conducting a spin time test with the meter in line requires depressurizing the meter runo Ensure that the meter run shutoffvaIves do not Ieak because Ieakage ofthe vaIves andlor drafts in the meter run will affect the test. Low-pressure gas from a hose or tubing can be used to rotate the turbine rotor at a sufficient rate to begin the in-line spin time test. Bypasses around the shutoff vaIves can be installed for this purpose. Care should be taken to ensure that vented gas does not accumulate. Regardless of location, the test is conducted by setting the rotor in motion, manually or by a jet of air or gas, in the same direction as under flowing conditions. The rotor is timed until it stops rotating. When the rotor is set in motion by a jet, significant time may be added if the rotor is tumed at exceptionally high speeds. Ambient temperature, lubrication, the presence of accessories, the manner of initiating the blade rotation and other factors affect spin times and they must be considered to obtain repeatable and comparable results from test to test. It is recommended that records of spin time test be maintained for the purpose of detecting changes in bearing integrity over time. A typical decay curve for meter spin time is provided in Figure 9. 1000 900 800

~e

':lE lO

100 600

e o

500

72o

400

:>

~

\

\

300

\

200

"'-

100 O

o

20

i'--.

---

40

--60

BO

100

120

140

Time - Seconds

Figure 9. Typical Decay Curve for Turbine Meter Spin Time

32

A spin time test should be repeated three times, with deviations les s than 10% from the average of spin time. If spin times are les s than those recornmended by the manufacturer, the tests may be repeated at various levels of disassembly until the source of the abnormal friction is determined. Cleaning, oiling or replacing the bearings or other components may bring the spin time back to an acceptable value. Bearings, shafts, magnetic coupling assemblies or gearing may be replaced on sorne meters without affecting the meter's performance. Consult the manufacturer for specific recornmendations. A follow-up spin time test should be performed after repairs or component replacement. If an acceptable result is not obtained, the meter should be removed from service.

8.5

Dual-Rotor Meter Field Checks

Dual-rotor turbine meters may offer the ability to check the operation of the meter in situ by comparing the rotor outputs. Consult the manufacturers' literature for further information.

8.6

Retesting Considerations

Meters, or their measurement cartridges, should be retested on a periodic basis. The period between tests should be cornmensurate with meter usage and line conditions. In sorne cases, regulatory agencies establish the test intervals. The decision to perform periodic transferproving or flow calibration is left to the users. Often, when a meter or cartridge is retumed for repair/recalibration, the user requests an asfound calibration in order to have a record of the meter errors when it was removed from service. Such information is useful in the event of a measurement dispute and may be helpful in establishing recalibration intervals.

33

APPENDIXA

Turbine Meter Designs A.l

Single Rotor Turbine Meters A.1.1

Gas Meter Design

Schematics ofaxial-flow single-rotor gas turbine meters are shown in Figures A.I and A.2. Gas entering the meter increases in velocity through the annular passage formed by the nose cone and the interior wall of the body. The movement of gas over the angled rotor blades imparts a force to the rotor, causing it to rotate. The ideal rotational speed is directly proportional to the flow rateo The actual rotational speed is a function of the passageway size and shape, and the rotor designo It is also dependent upon the load that is imposed due to internal mechanical friction, fluid drag, extemalloading and the gas density.

Body

Rotor

Mechanical or Electrical Readout

End Connectio

Inlet

Outlet

Electronic Pickup

Mechanism Housing and Tail Cone

Figure A.1. Single Rotor Turbine Meter (Gas Design)

A-l

Body

Electronic Pickup Rotor

Inlet ~ Annular Passage

+-I~Outlet

Tail Figure A.2. Single Rotor Turbine Meter (Low Torque Design) A.1.2

Liquid Meter Design

The basic designs ofaxial-flow gas turbine meters differ significantly from liquid turbine meters due to density, viscosity and compressibility differences of the fluids. The need to extract sufficient kinetic energy trom the flow to provide the torque to overcome internal and external frictional los ses results in the proportions of the nose cone and annular passages typical of those shown in Figure A.l. However, gas turbine meter designs similar in proportions to liquid turbine meters, as shown in Figure A.2, have been successfully used for particular sizes and applications (i.e., sizes smaller than 4 inches operating at higher flow rates or pressures). Typically, these designs provide low torque at similar flow rates and pressure and cannot drive mechanical readout devices or instruments.

A.2

Dual-Rotor Turbine Meters A.2.1

Dual-Rotor Designs

Schematics of various dual-rotor turbine meters are shown in Figures AJ, A.4, A.5 and A.6. The primary rotor or main metering rotor of each of these designs is basically the same as that of a single-rotor turbine meter as shown in Figure A.l. The blades ofthe primary rotor will typically have pitch angles in the range of 30 to 60 degrees. This rotor may have an output drive for a mechanical register or for an accessory device.

A-2

Readout Body

Inlet

Main Rotor

Master Rotor or Proving Rotor

Annular Passage

Outlet

Electronic Pickups

Flow Guides

Figure A.3. Independent Tandem Turbine Rotors Separated by Flow Guides

Readout Body

Main Rotor

Inlet

Sensing / ' Rotor

Outlet

Electronic Pickups

Figure A.4. Dual-Rotor Turbine with Fluid-Coupled Sensing Rotor

A-3

Main Rotor

Body

Secondary Rotor

Inlet

Outlet

Electronic Pickups

Figure A.5. Fluid-Coupled Counter-Rotating Second Turbine Rotor

Body

Secondary or Slave Rotor

Main Rotor

Outlet

Inlet

Electronic Pickups

l....-__

Piggy-Back Bearing Arrangement

Figure A.6. Dual-Rotor Turbine with Friction Reducing Slave Rotor

A-4

Á.2.2

Secondary Rotor Designs

The secondary rotors are downstream of the main rotors in Figures A.3, A.4, A.S and A6. They may be separated from the primary rotors and isolated from them by flow conditioners between the two rotors (Figures A.3 and A.6). Sorne designs provide for fluid coupling of the secondary rotor to the primary rotor by positioning the rotors in close proxirnity to each other (Figures A.4 and A.S). In either case, rotation of the secondary rotor may be in the same or opposite direction as that of the primary rotor. Typically, the secondary rotor operates at a lower speed than the primary rotor in order to extend its service life and to differentiate the measurements of the two rotors for checking purposes. Á.2.3

Secondary Rotor Functions

The secondary rotor is provided for checking amI/ or improving the measurement integrity of the primary rotor under various flow and metering conditions. In sorne dual-rotor turbine meters, the secondary rotor can provide measurement adjustments to improve the output error of the primary rotor and provide diagnostics under certain operating conditions.

A.3

Dual-Rotor Meter Electronics

Electronic pulse outputs corresponding to the speed of the rotors in dual-rotor turbine meters are provided by sensors that detect the passage of individual turbine blades, spaces in chopper disks or the teeth of gears that are driven by the rotors. These signals are fed to a manufacturer's electronic accessory device or to a user device with appropriate algorithms that ca1culates and compares volumes from both rotors, ancl/or perfonns diagnostics.

A-5

APPENDIX B

V olumetric and Mass Flow Measurement B.l

Equations for Calculating Volumetric Flow

The turbine meter is a velocity-measuring device. It depends upon the flow of gas to cause the meter rotor to tum at a speed proportional to the flow rateo Rotor revolutions are counted mechanically or electrically and can be converted to a continuously totalized volumetric registration. Since the registered volume is at flowing pressure and temperature conditions, it must be corrected to the specified base conditions for accounting purposes. The register of the turbine meter indicates volume at flowing conditions so this value needs to be corrected to the base conditions. B.1.1

Basic Gas Laws

The subscripts "b" denoting base conditions, ''J' denoting flowing conditions and "r" denoting rated conditions are used in this appendix. The basic gas law relationship is expressed as follows: (P¡) (V¡) = (ZrJ (N) (R) (T ¡J

F or flowing conditions

Eq. (B.1)

(P b) (V b) =(Z b) (N) (R) (TbJ

For base conditions

Eq. (B.2)

or

where

P = Absolute pressure V = Volume Z = Compressibility N = Number of moles of gas T = Absolute temperature R = Universal gas constant

Since R is a constant for the gas regardless of pressure and temperature, and for the same number of moles of gas (N), the two equations can be combined to yield:

Vb

= V,

(~ '] (~ '] (~ '] Pb

)

T,) Z,)

B-l

Eq. (B.3)

B.1.2

Flow rate at Flowing Conditions

Q¡ = V¡

Eg. (B.4)

t where

Q¡ = Volumetric flow rate at flowing conditions

V¡ = Volume measured at flowing conditions during time interval t t

B.1.3

= Time

Flow rate at Base Conditions

Eg. (B.5)

B.1.4

Pressure Multiplier P

Pressure Multiplier =-L P¡,

Eg. (B.6)

p¡ = Pg + Pa

where

Pg = Flowing pressure, gage units Pa

=

Atmospheric pressure, absolute units

Pb

=

Base pressure, absolute units

In instances where the atmospheric pressure value is not defined by Federal Energy Regulatory Commission Tariff or contract terms, atmospheric pressure can be determined using the following eguations which are based on the National Oceanic and Atmospheric Administration publication, U. S. Standard Atmosphere, 1976 (Reference 11). English units

p" where

= 14.6960 x (1- 0.00000686 x

Elevation y2554

Eg. (B.7)

- Atmospheric pressure at 60°F, psia

Elevation - Height above mean sea level, feet

SI units Pa = 10 1.325 x (1 - 0.00002256 x Elevation y2554 where

- Atmospheric pressure at ISoC, kilopascals

Elevation - Height above mean sea level, meters

B-2

Eg. (B.8)

B.1.5

Temperature Multiplier

_ Tb

Temperatur Multiplie where

Tf

T b = Base temperature, absolute units

Tf

=

Flowing temperature, absolute units

Absolute temperature:

B.1.6

°R = °F + 459.67°, or °K = oC + 273.15°

Compressibility Multiplier

Compressibilit Multiplie where

Eq. (B. 9)

Zb Zf

=

=

=Z

b

Eq. (B.10)

Zf Compressibility at base conditions Compressibility at flowing conditions

The compressibility multiplier can be evaluated from the supercompressibility factor Fpv , as follows:

Z b =(F )2 Z pv r

Eq. (B.ll)

Compressibility values may be determined from the latest edition of AGA Report No. 8 Reference 1), or as specified in contracts or tariffs, or as mutually agreed upon by both parties.

B .1.7 B.l.7.1

Equations for Meter Rangeability Maximum Flow rate

Turbine meters are generally designed for a maximum flow rate in order to not exceed a certain rotor speed. This maximum flow rate remains the same (unless stated otherwise by the manufacturer) for all pressures within the operating range. Eq. (B.12)

The maximum flow rate at base conditions Qbmax can be expressed as:

Eq. (B. 13)

B-3

Minimum Flow rate and Rangeability

The minimum flow rate (or minimum capacity rating) for a turbine meter is the lowest flow rate at which the meter will operate within the specified error limit. Generally the minimum flow rate depends on the magnitude ofnon-fluid drag and the density ofthe measured gas. The minimum flow rate at base conditions is:

Eq. (B.14)

where:

G = Gas relative density

The range of operating flows for accurate measurement increases approximately as the square

~P

root of the pressure ratio Pf . r

Generally, the rated temperature and pressure are close to the base temperature and pressure. In this case:

Eq. (B.15)

And, the mínímum flow rate at flowing conditions ís:

Eq (B.l6)

Frequently the temperature and compressibility ratios are close to unity and can be neglected for purposes of approxímatíon. The operating range of the gas turbíne meter is the flow range over whích the meter wíll operate wíthín its specífied performance. In general, the turbíne meter range wíll vary dírectly wíth the square root ofthe gas density. As the density íncreases, the línearity of the meter wíll be extended to a lower flow rate whíle the upper límit remaíns fixed by the desígn consideration stated aboye. Thus:

QjmCLT 'l' = R angeabllty -= Qjmin

QbmaT Qbmm

=

QrmCLT Qrmm

B-4

(¿) (;) [i J [~r J r

r

j

f

Eq. (B.17)

B.2

Equations for Calculating Mass Flow

Mass flow measurement can be employed to arrive at base volume (VbJ or base volume flow rate (Qb) through the use of a turbine meter and densitometer or calculation from compositional analysis. The mass or mas s rate of flow is: M= (V¡) (PI)

where

M

=

VI

=

PI

= Density of flowing gas

Total mas s through the meter Total volume through the meter

and where

Q ro Q

Q¡ P¡

=

(Q¡) (p¡)

=

Mass rate of flow Volume rate of flow (actual or register)

=

Density of flowing gas

ro =

Eg.(B.18)

Eg. (B.19)

Since the mass or mas s rate of flow at flowing conditions eguaIs the mass at base conditions it can be stated that:

or,

( V¡, )( Pb ) =(Vr ) (P r )

Eq. (B.20)

(Vb) = (Vr ) 1!.L Pb

Eq. (B.21)

(Qb) = (Qr)!!..L Pb

Eq. (B.22)

The aboye eguations show that the base volume (VbJ or base volume flow rate (Qb) can be calculated by knowing the density of the fluid at both flowing and base conditions without the need to measure the flowing pressure (p¡) or the flowing temperature (T¡) and calculating the compressibility multiplier.

B-5

APPENDIXC

Computing Flow C.I

Meter Register Reading

When computing total uncorrected volume from the turbine meter register, two register readings are taken over a period of time as defined by the contract; e.g., one reading at the first of the month and the second reading at the end of the month. The first reading is subtracted from the second to obtain the uncorrected volume measured during the month. Ifthe smallest unit of volume that can be read from the register is greater than 1 cubic foot; e.g., 10,100, l,000, etc., then the difference ofthe two readings is multiplied by the smallest volume unit shown on the register.

C.2

Electronic Computation

Electronic outputs from meters may be applied to computers in conjunction with temperature and pressure transducers to obtain volumes for billing aml/or telemetering at base conditions.

C.3

Mechanical Integrating Devices

These instruments apply a pressure, or combined pressure and compressibility factor, to the metered gas volume correcting it to base pressure. An additionaI mechanism may aIso apply a temperature factor, thus providing registration at base conditions.

C.4 Pressure, Volume and Temperature Recording Devices Various types of recording devices are available to record pressure, temperature and uncorrected volume during the recording periodo The resulting charts can be integrated to arrive at volume at base conditions.

C-I

APPENDIX D

Meter Outputs and Adjustments Turbine meters have outputs that can be adjusted pursuant to calibration. The following are specjfic examples of mechanical and electronic adjustment methods and the associated calculations using hypothetical calibration data. AIso shown are example applications of various curve-fitting techniques to accomplish the implementation of K-factors and meter factors in accessory devices.

D.l

Change Gears

Calibration adjustment of the mechanical output of a turbine meter is typically accomplished by choosing an appropriate set of change gears. Change gears are a set of mating gears, one gear driving and the other being driven, that are part of the mechanical output shaft gearing reduction. The overall gear reduction allows one complete output shaft revolution of the meter to represent a fmite volume; for example 100 cubic feet, 1000 cubic feet, 1 cubic meter or 10 cubic meters. Since each set of available change gears has a different combination of teeth, changing them permits an adjustment to the overall gear ratio. The basic turbine meter design for each model uses a base set of change gears to achieve a specific ratio of intemal reduction gearing. However, due to manufacturing variations within a meter or specific customer re quirements , the initial factory calibration test results with the base set of change gears may not be adequate. Another set of change gears is then installed to shift the gear ratio and adjust the mechanical volume registration output. The adjustment shift will be the same amount for aIl flow rates. Table D.1 and Figure D.1 show an example of a turbine meter mechanical output performance before and after installation ofnew change gears (í.e., resulting in a registration shift of -0.24% for all flow rates). TABLE D.1. EXAMPLE - CHANGE GEAR SHIFT Test

Master Meter

Test Meter

Test Meter

Test Meter

Point

Ref. Flow Rate

Indicated Flow Rate

"As-Found"

"As-Left"

(at same conditions as Test meter)

with 72/51 Change Gears with 75/53 Change Gears

% ofQmax

0/0 of Qmax

% Error

(% Error - 0.24% Shift)

1

10.025

10.00

-0.25

-0.49

2

20.000

20.00

0.00

-0.24

3

49.875

50.00

0.25

0.01

4

74.750

75.00

0.33

0.09

5

99.650

100.00

0.35

0.11

D- 1

Turbine Meler Calibralion Change Gear Shift - Example

1.00 C 0.80 o :; 0.60 ... 'iii 0.40 '0, ~ 0.20 .!el) 0.00 :2-0.20 ....., ...5- 0.40 U¡-0.60 c#! -0.80 -1.00

0.24% Error Shift due to change gear adjustment

¡------ ¡------

----------

-""'\..

~

10

20

30

J

1

?f~ fll"'"

O

..

v

-r"As-Found"with 72/51 Chg Gears ~"As-Left"

40

50

60

with 75/53 Chg Gears

70

80

t

90

100

Flowrate (% Qmax)

Figure D.l. Change Gear Shift Example Notes:

1. Percent error = (Indicated Volume - Reference Volume) / Reference Volume x 100 2. Indicated and Reference Volumes must be at the same temperature and pressure conditions prior to performing the error calculation. 3. Percent error shift, for example (- 0.24%) = - {[(75/53) - (72/51)] / (72/51)} x 100 going from the as-found change gears (72/51) to the as-left change gears (75/53). 4. Change gear adjustments can be in discrete increments only and depend on the gear teeth combinations available.

D.2

K-Factor(s)

Turbine meter(s) K-factor(s), in pulses/volume units, is established at the time of calibration. Kfactors are used to convert pulses, accumulated from the electronic output of a meter, into indicated volume units. (See equation D.1.)

where:

v

= _P_u_l_s_es-=.f_

f

(K - factor)

Eq. (D.1)

Electronic pulses collected at flowing conditions during time interval t Volume measured at flowing conditions during time interval t t = Time interval (notused in equation) K-factor = K-factor established at calibration for the electronic output Pulses!

=

Vf

=

This calculation is usually accomplished in an electronic accessory device by dividing the pulses, accumulated over a time period, by the K-factor. Note that, there may be unique K-factors for each electronic pulse output ofthe meter. Also, there may be different K-factors associated with

D-2

specific flow rates as detennined by calibration. The manufacturer or calibration facility will provide the K-factor or K-factors for the meter electronic output(s). These values must be properly entered into an accessory electronic device in order to produce the correct registration volume(s) from the meter electronic pulse output(s). Table D.2 shows an example ca1culation of a single K-factor, related to change gear and intemal gear ratio of a turbine meter. Also shown is a K-factor that is determined as an average of individual K-factors from five flow rates of a calibration of a turbine meter that has only an electronic output.

..

TABLE D 2 EXAMPLES OF K-FACTORS ESTABLISHED BY CALlBRATION K-factor 1. High freguency Quise outl2ut from rotor shaft sensor (Calculated from gearing) (Change Gears established by calibration) = 103.3883 pulses/cu ft 4 x 15 x 122.0556 x 72 / 51 100 / pulses per internal driving External Driven cubic feet rey of main Gearing Gearing per Change change gear output rey rotor shaft Reduction Reduction Gear

K-factor (Average of 5 calibration values1 103.5303 pulses/cu ft

2. High freguency Quise outQut from rotor shaft sensor (Individual K-factors established by calibration)

% Test flow rate Test flow rate Test flow rate Test flow rate Test flow rate

No. No. No. No. No.

1 2 3 4 5

Qmax

10 25 50 75 100

10000 10000 10000 10000 10000 pulses collected from Test Mtr

/ / / / /

96.9650 = 103.1300 96.7227 = 103.3883 96.4810 = 103.6474 96.4004 = 103.7340 96.3840 = 103.7517 pulses/cu ft cubic ft Volume* of Ref. Mtr *Volumes corrected to P & T conditions ofthe test meter.

There may be a single K-factor for use with all flow rates over the operating range of the meter. A single K-factor may be based on change gear ca1culations, as in Table D.2, or upon arithmetic average of individual K-factors determined from calibration at various flow rates, or the single Kfactor may be weighted for an operating flow rate range. Table D.3 shows a single K-factor ca1culated from change gears and an example of an "as-found" meter test.

D-3

TABLE D.3. EXAMPLE - SINGLE K-FACTOR Test

Test Meter

Test Meter

Point

Indicated Flow Rate

RAs-Found"

K·factor

% Qmax

% Error

(pulses/cubic foot)

1

10.00

-0.25

2

20.00

0.00

103.3883 103.3883

3

50.00

0.25

103.3883

4

75.00

0.33

103.3883

5

100.00

0.35

103.3883

Note: The single K-factor shown here in Table D.3 is based on high-frequency pulse output from a sensor on a rotor shaft (see example 1 in Table D.2). A single K-factor for all flow rates, or individual K-factors for each calibration flow rates, may be entered into an electronic accessory device or flow computer for use in converting turbine meter output pulses to volume. Table D.4 shows an example of individual K-factors for each flow rate of the test meter. These individual K-factors have be en adjusted by the "as-found" percent errors to bring each flow rate test point to zero error.

TABLE D.4. EXAMPLE-INDIVIDUALK-FACTORS K-factor

(1/ Meter Factor) Multipliers

Individual K·factors

"As-Found"

(single value)

(1.000 + % Error/1 OO)

(for individual f10w rates)

% Error

Jpulses/cubic foot} 0.9975

(pulses/cubic foot) 103.1298

1.0000

103.3883

Test

Test Meter

Point 1

-0.25

2

0.00

103.3883 103.3883

3

0.25

103.3883

1.0025

103.6468

4

0.33

103.3883

1.0033

103.7295

5

0.35

103.3883

1.0035

103.7502

Note that the multiplier values shown in Table D.4 are derived from the as-found meter error and are used to calculate the individual K-factors. These muItiplier values are equivalent to the (l/meter factor) values shown in Section D.3. Also, note that the techniques of curve fitting or linearization, as shown in Section D.3 for meter factor, may be applied to the individual K-factors, as weIl, for use within an accessory device or flow computer.

D.3

Meter Factor

A calibration facility may provide meter factors in addition to or instead of percent error values for a meter. These may apply either to the mechanical or to the electronic pulse output(s) of a meter. Meter factors are non-dimensional numeric multipliers. The meter factor is the ratio of the reference volume to the indicated test meter volume, for a particular flow rateo Volumes for both test meter and the reference must be at the same conditions. The meter output is multiplied by the meter factor to adjust the meter output, in an effort to eliminate known errors. Table D.5 shows meter factors for the example test meter.

D-4

TABLE D.S. EXAMPLE - METER FACTORS Test Point

Test Meter

Master Meter

Test Meter

Ref. Flow Rate

Indicated Flow Rate

(at same conditions as Test meter)

Meter faclors

%Qm3.

% Qm••

(Referenee Volume or Flow Rate ) I (Indicated Test Meter Volume or Flow Ratel

10.025

10.000

1.0025

2

20.000

20.000

1.0000

3

49.875

50.000

0.9975

4

74.750

75.000

0.9967

5

99.650

100.000

0.9965

1

Measurement can be' improved by programming a flow computer to curve fit or linearize the meter factor calibration curve. Multi-point linearization or polynomial curve-fitting techniques may be used to apply the meter factors across the operating flow rate range. Tables D.6 through D.8 and Figures D.2 through D.6 show examples ofvarious curve-fitting techniques: AIso shown are examples of the relative percent errors that may result from the imperfections inherent to each technique. TABLE D.6. EXAMPLE - POLYNOMIAL CURVE FIT AND ERRORS Qi Flow Rate %

Test Meter

Polynomial Curve Fit

Adjusted K-factors

Polynomial Curve Fit

"As-found"

Meter factors

Meter factors

(103.38831 Meter factors)

(of Meter factors)

% Error

(from f10w ealibration)

(see Figure 0-2)

pulses I cubic foot

Resulting % Error

10

-0.25

1.0025

1.0021

103.1716

-0.04

20

0.00

1.0000

1.0006

103.3263

0.06

50

0.25

0.9975

0.9975

103.6474

-0.00

75

0.33

0.9967

0.9964

103.7618

-0.03

100

0.35

0.9965

0.9966

103.7410

0.01

Qma.

Polynom ial Curve Fit

1.0050 1.0040 Meter Factor = 108E -06(O/OQm axf - 0.000 179(O/OQm ax) + 10037399

1.0030

...o

-... u

1.0010

LL

1.0000

IV

-

~

1.0020

"

G)

0.9990 0.9980

~ ~

0.9970

~

0.9960 0.9950

o

20

f--

--Poly. (Meter Factors) f - -

~

G)

::¡¡:

-+-- Mete r Factors

--

.......

40 60 F10wrate (o/lOmax)

Figure D.2. Example - Polynomial Curve Fit

D-5

80

100

Linear inlerpolation curve fit

1.0050 1.0040

-+- Meter Factors

1.0030 '- 1.0020 o -O 1.0010 IU IJ.. 1.0000 'Q) a¡ 0.9990 ~

'" "'-

"

~

.~

~

0.9980 0.9970 0.9960 0.9950

o

r--

Linear S egment Fit r--

20

--..-

40 60 Flowrate (%Qmax)

10

80

Figure D.3. Example - Linear Interpolation Curve Fit TABLE D.7. EXAMPLE - LINEAR INTERPOLATION CURVE FIT AND ERRORS Meter factors

Flow Rate

(see Table above)

Meter factors Linear interpolation Curve Fit

(103.38831 Meter factors)

(of Meter factor)

% Qmax

(from f10w calibration)

(see Figure 0-3)

pulses I cubic feet

10

1.0025

1.0025

103.1305

Resulting % Error 0.00

1.0013

103.2541

0.04

1.0000

103.3883

0.00

0.9988

103.5125

0.02

0.9975

103.6474

0.00

0.9971

103.6907

0.01

0.9967

103.7306

0.00

0.9966

103.7410

0.00

0.9965

103.7514

Qi

15 20

1.0000

35 0.9975

50 62.5

0.9967

75 87.5 100

0.9965

Adjusted K-factors

Linear Interpolation

0.00

Turbine Meter calibrationl Curve Flt - Example 100 0.80

'2 o 0.60

~