Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids— Concentric, Square‐edged Orifice Meters

Part 2: Specification and Installation Requirements

AGA Report No. 3 Part 2

Manual of Petroleum Measurement Standards Chapter 14.3.2

American Gas Association 400 North Capitol Street, NW Washington, DC 20001

American Petroleum Institute 1220 L Street, NW Washington, DC 20005

FIFTH EDITION, MARCH 2016

An American National Standard

ANSI/API MPMS Ch. 14.3.2/AGA Report No. 3, Part 2

ERRATA 2, JANUARY 2019

ERRATA 1, MARCH 2017

Special Notes

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Copyright © 2016 American Gas Association and American Petroleum Institute

Date of Issue: January 2019

Affected Publication: API Manual of Petroleum Measurement Standards, Chapter 14.3.2, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters—Part 2: Specification and Installation Requirements, Fifth Edition

Errata 2

Page 32, Section 6.5:

The equation (in SI units) should read:

 F  4.38 OD 10

L   m

1



2

E OD2  ID2  



where

S V  

L is the probe length (mm);

Fm is the virtual mass factor—a constant to take account of the extra mass of the cylinder due to the fluid surrounding it and vibrating with it. For a gas, Fm = 1.0 and for water and other liquids, Fm = 0.9;

OD is the outside diameter of probe (mm);

ID is the inside diameter of probe (mm);

S is the Strouhal number, dependent on the Reynolds No. and shape of the cylinder, but can be taken as 0.4 for worst case or 0.2 as suggested by API MPMS Ch. 8.

V is the velocity of fluid (m/sec);

E is the modulus of elasticity of probe material (kg/cm2);

ρ is the density of probe material (kg/m3).

The equation (in USC units) should read:

1

m  2 2 

 F 1.205 OD E 2

L  OD  ID



 S V  

where

L is the probe length (inches);

Fm is the virtual mass factor—a constant to take account of the extra mass of the cylinder due to the fluid surrounding it and vibrating with it. For a gas, Fm = 1.0 and for water and other liquids, Fm = 0.9;

OD is the outside diameter of probe (inches);

ID is the inside diameter of probe (inches);

S is the Strouhal number, dependent on the Reynolds No. and shape of the cylinder, but can be taken as 0.4 for worst case or 0.2 as suggested by API MPMS Ch. 8.

V is the velocity of fluid (ft/sec);

E is the modulus of elasticity of probe material (psi);

ρ is the density of probe material (g/cc).

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iii

Contents

Page

1. Scope 1

   1. General 1

   2. Construction and Installation Requirements 1

2. Normative References 1

3. Terms, Definitions, and Symbols 2

   1. Definitions 2

   2. Symbols/Nomenclature 4

4. Orifice Plate Specifications 6

   1. General 6

   2. Orifice Plate Faces 6

   3. Orifice Plate Bore Edge 8

   4. Orifice Plate Bore Diameter (dm, dr) and Roundness 8

   5. Orifice Plate Bore Thickness (e) 10

   6. Orifice Plate Thickness (E) 10

   7. Orifice Plate Bevel (θ) 13

5. Meter Tube Specifications 13

   1. Description 13

   2. Orifice Plate Holders 17

   3. Orifice Fittings Considerations 18

   4. Pressure Taps 19

   5. Flow Conditioners 21

6. Installation Requirements 23

   1. General 23

   2. Orifice Plate 23

   3. Meter Tube 31

   4. Acceptable Pulsation Environment 31

   5. Thermometer Wells 32

   6. Insulation 33

Annex A (informative) Research Projects and Tests Conducted Between 1922 and 1999 34

Annex B (informative) Orifice Meter Inspection Guidelines 53

Annex C (normative) Specific Installation Calibration Test 57

Annex D (normative) Flow Conditioner Performance Test 59

Annex E (normative) Maximum Allowable Orifice Plate Differential Pressure 63

Figures

1 Symbols for Orifice Plate Dimensions 6

2a Orifice Plate Departure from Flatness (Measured at Edge of Orifice Bore and Within

Inside Pipe Diameter) 7

2b Alternative Method for Determination of Orifice Plate Departure from Flatness (Departure

from Flatness = h2 – h1) 7

v

Contents

Page

2c Maximum Orifice Plate Departure from Flatness 7

1. Allowable Variations in Pressure Tap Hole Location 19

2. 1998 Uniform Concentric 19-Tube Bundle Flow Straightener 22

3. Eccentricity Measurements (Sample Method) 24

4. Orifice Meter Tube Layout for Flanged or Welded Inlet 27

Tables

1. Roundness Tolerance for Orifice Plate Bore Diameter, dm 9

2. Linear Coefficient of Thermal Expansion 9

3. Orifice Plate Thickness and Maximum Allowable Differential Pressure Based on the

   Structural Limit 11

4. Example Meter Tube Internal Diameter—Roundness Tolerances Within First Mean Meter

   Tube Diameter Upstream of Orifice Plate 16

5. Example Meter Tube Internal Diameter Roundness Tolerances—All Upstream Meter

   Tube Individual Internal Diameter Measurements 17

6. Maximum Tolerance of Orifice Plate Bore Eccentricity (εx) 25

7. Orifice Meter Installation Requirements Without a Flow Conditioner 28

8a Orifice Meter Installation Requirements With 1998 Uniform Concentric 19-Tube Bundle

Flow Straightener for Meter Tube Upstream Length of 17Di ≤ UL < 29Di 29

8b Orifice Meter Installation Requirements With 1998 Uniform Concentric 19-Tube

Bundle Flow Straightener for Meter Tube Upstream Length of UL ≥ 29Di 30

E-1 Maximum Allowable Calculated Differential Pressure Across 304/316SS Orifice Plate at 150 °F 64

vi

Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids— Concentric, Square-edged Orifice Meters

Part 2: Specification and Installation Requirements

1. Scope

   1. General

      
      

      This document establishes design and installation parameters for measurement of fluid flow using concentric, square- edged, flanged tapped orifice meters.

      
      

   2. Construction and Installation Requirements

      
      

      This document outlines the various design parameters that shall be considered when designing metering facilities using orifice meters. The mechanical tolerances found in this document encompass a wide range of orifice diameter ratios for which experimental results are available.

      
      

      For all existing installations, the decision to upgrade to meet the requirements of this standard shall be at the discretion of the parties involved. The parties should be cognizant that if a meter installation is not upgraded to meet this standard, measurement bias errors may exist due to inadequate flow conditioning and upstream straight pipe lengths.

      
      

      Use of the calculation procedures and techniques shown in the API MPMS Ch.14.3.1/AGA Report No. 3, Part 1 and API MPMS Ch.14.3.3/AGA Report No. 3, Part 3, with existing equipment is recommended, since these represent significant improvements over the previous methods. The uncertainty levels for flow measurement using existing equipment may be different from those quoted in API MPMS Chapter 14.3.1/AGA Report No. 3, Part 1.

      
      

      Use of orifice meters at the extremes of their diameter ratio (βr) ranges should be avoided whenever possible. Good metering design and practice tend to be somewhat conservative. This means that the use of the tightest tolerances in the mid-diameter ratio (βr) ranges would have the highest probability of producing the best measurement. An indication of this is found in the section on uncertainty in API MPMS Chapter 14.3.1/AGA Report No. 3, Part 1.

      
      

      This standard is based on βr between 0.10 and 0.75. Minimum uncertainty of the orifice plate coefficient of discharge (Cd) is achieved with βr between 0.2 and 0.6 and orifice bore diameters greater than or equal to 0.45 inch. Diameter ratios and orifice bore diameters outside of this range may be used; the user should consult the uncertainty section in API MPMS Chapter 14.3.1/AGA Report No. 3, Part 1 for limitations.

      
      

      Achieving the best level of measurement uncertainty begins with, but is not limited to, proper design. Two other aspects of the measurement process have to accompany the design effort; otherwise it is of little value. These aspects are the application of the metering system and the maintenance of the meters, neither of which is considered directly in this standard. These aspects cannot be governed by a single standard as they cover metering applications that can differ widely in flow rate, fluid type, and operational requirements. The user shall determine the best meter selection for the application and the level of maintenance for the measurement system under consideration.

      
      

2. Normative References

No other document is identified as indispensable or required for the application of this standard.

1