Manual of Petroleum Measurement Standards Chapter 5—Metering

Section 6—Measurement of Liquid Hydrocarbons by Coriolis Meters

FIRST EDITION, OCTOBER 2002 REAFFIRMED, NOVEMBER 2013

Manual of Petroleum Measurement Standards Chapter 5—Metering

Section 6—Measurement of Liquid Hydrocarbons by Coriolis Meters

Measurement Coordination

FIRST EDITION, OCTOBER 2002 REAFFIRMED, NOVEMBER 2013

SPECIAL NOTES

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Copyright © 2002 American Petroleum Institute

FOREWORD

This standard may involve hazardous materials, operations, and equipment. This standard does not purport to address all of the safety problems associated with its use. It is the respon- sibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.

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Suggested revisions are invited and should be submitted to Measurement Coordination, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005.

iii

CONTENTS

Page

0 INTRODUCTION 1

1. SCOPE 1

2. FIELD OF APPLICATION 1

3. DEFINITIONS 1

4. REFERENCED PUBLICATIONS 2

5. ABBREVIATIONS 3

6. SYSTEM DESCRIPTION 4

   1. Flow Sensor Considerations 4

   2. Coriolis Transmitter Considerations 6

   3. System Design Considerations 6

7. SAFETY. 9

   1. Tube Failure 9

8. OPERATIONS/PERFORMANCE 11

   1. Start-up of Metering Systems 11

   2. Effects of Fluid Properties, Operating, and Installation Conditions on

      Coriolis Meter Performance 11

   3. Considerations for Changing the Stored Zero Value in the

      Flowmeter (Rezeroing) 12

   4. Maintenance 13

9. PROVING 13

   1. Proving Considerations 14

10. AUDITING AND REPORTING REQUIREMENTS 18

    1. Configuration Log 18

    2. Quantity Transaction Record (QTR) 18

    3. Event Log 18

    4. Alarm and Error Log 18

APPENDIX A PRINCIPLE OF OPERATION 19

APPENDIX B FACTORY CALIBRATION 21

APPENDIX C PROVING FORMS FOR METERS WITH MASS OUTPUTS 23

APPENDIX D PROVING FORMS FOR METERS WITH VOLUME OUTPUTS . . . 31 APPENDIX E CALCULATIONS 39

Tables

1 Typical Number of Proving Runs 16

1. Density Conversion Factors 23

2. Buoyancy Correction Factors (Not applicable to closed, pressurized vessels) . 23 E-1 Coriolis Meter—Proving Overview 39

1. Mass Discrimination Table 41

2. Density Discrimination Table 41

3. Correction Factor Discrimination Table 41

Page

Figures

1. Typical Coriolis Meter Accuracy Specification 6

2. Schematic for Coriolis Meter Installation 8

3. Factors Affecting Coriolis Meter Outputs 10

A-1 Coriolis Force Illustration 19

B-1 Calibration System Schematic 21

1. Proving Calculations: Conventional Pipe Prover—Coriolis Meter Mass 24

2. Proving Calculations: Small Volume Prover—Coriolis Meter Mass 25

3. Proving Calculations: Gravimetric Tank Prover—Coriolis Meter Mass 26

4. Proving Calculations: Volumetric Tank Prover—Coriolis Meter Mass 27

5. Proving Calculations: Volumetric Master Meter—Coriolis Meter Mass 28

6. Proving Calculations: Mass Master Meter—Coriolis Meter Mass 29

1. Proving Calculations: Conventional Pipe Prover—Coriolis Meter Volume 32

2. Proving Calculations: Small Volume Prover—Coriolis Meter Volume 33

3. Proving Calculations: Gravimetric Tank Prover—Coriolis Meter Volume 34

4. Proving Calculations: Volumetric Tank Prover—Coriolis Meter Volume 35

5. Proving Calculations: Volumetric Master Meter—Coriolis Meter Volume 36

6. Proving Calculations: Mass Master Meter—Coriolis Meter Volume 37

Chapter 5—Metering

Section 6—Measurement of Liquid Hydrocarbons by Coriolis Meters

0 Introduction

1. This standard is intended to describe methods to achieve custody transfer levels of accuracy when a Coriolis meter is used to measure liquid hydrocarbons.

2. Coriolis meters measure mass flow rate and density. It is recognized that meters other than the types described in this document are used to meter liquid hydrocarbons. This publi- cation does not endorse or advocate the preferential use of a Coriolis meter nor does it intend to restrict the development of other types of meters. Those who use other types of meters may find sections of this publication useful.

1. Scope

   1. This standard is applicable to custody transfer applica- tions for liquid hydrocarbons. Topics covered are:

      1. Applicable API standards used in the operation of Coriolis meters.

      2. Proving and verification using both mass- and volume- based methods.

      3. Installation.

      4. Operation.

      5. Maintenance.

   2. The mass- and volume-based calculation procedures for proving and quantity determination are included in Appendix E.

   3. Although the Coriolis meter is capable of simulta- neously determining density, this document does not address its use as a stand-alone densitometer. See API MPMS Chapter

      14.6 for this type of application. The measured density from the Coriolis meter is used to convert mass to volume.

      
      

2. Field of Application

   The field of application of this document is any division of the petroleum industry where dynamic flow measurement of applicable fluids is desired. The use of Coriolis meters for alter- nate applications or fluids may be addressed within other chap- ters of the API MPMS and are not precluded by this standard.

   
   

3. Definitions

   1. accessory equipment: Any additional electronic or mechanical computing, display, or totalization equipment used as part of the metering system.

      1

   2. base conditions: Defined pressure and temperature conditions used in the custody transfer measurement of fluid volume and other calculations. Base conditions may be defined by regulation or contract. In some cases, base condi- tions are equal to standard conditions, which within the U.S. are usually 14.696 psia and 60°F, and in other regions

101.325 kPa (absolute) and 15°C.

1. base density: The density of the fluid at base condi- tions.

2. calibration: The process of utilizing a reference standard to determine a coefficient which adjusts the output of the Coriolis transmitter to bring it to a value which is within the specified accuracy tolerance of the meter over a specified flow range. This process is normally conducted by the manufacturer.

3. cavitation: Phenomenon related to and following flashing if the pressure recovers and the vapor bubbles col- lapse (implode). Cavitation will cause a measurement error and can damage the sensor.

4. Coriolis meter: Also referred to as Coriolis mass meter or Coriolis force flowmeter. A Coriolis meter is a device which by means of the interaction between a flowing fluid and the oscillation of a tube(s), measures mass flow rate and density. The Coriolis meter consists of a sensor and a transmitter.

5. Coriolis meter factor, mass or volume (MF, MFm, MFv): A dimensionless number obtained by dividing the actual quantity of fluid passed through the meter (as deter- mined by proving), by the quantity registered by the meter. For subsequent metering operations, the actual quantity is determined by multiplying the indicated quantity by the meter factor.

   
   

6. Coriolis transmitter: The electronics associated with a Coriolis meter which interprets the phase shift signal from the sensor, converts it to a meaningful mass flow rate (repre- sented in engineering units or a scaled value), and generates a digital or analog signal representing flow rate and/or quantity. Most manufacturers also use it to drive the sensor tubes, determine fluid density, and calculate a volumetric flow rate.

7. flashing: A phenomenon which occurs when the line pressure falls to or below the vapor pressure of the liquid, often due to local lowering of pressure because of an increase in the liquid velocity.