Api mpms 5 7 2003 (american petroleum institute)

Manual of Petroleum Measurement Standards Chapter 5—Metering Section 7—Testing Protocol for Differential Pressure Flow Measurement Devices FIRST EDITION, FEBRUARY 2003 Manual of Petroleum Measurement[.]

Manual of Petroleum Measurement Standards Chapter 5—Metering

Section 7—Testing Protocol for Differential

Pressure Flow Measurement Devices

FIRST EDITION, FEBRUARY 2003

Manual of Petroleum

Measurement Standards

Chapter 5—Metering

Section 7—Testing Protocol for Differential Pressure

Flow Measurement Devices

Measurement Coordination Department

FIRST EDITION, FEBRUARY 2003

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iii

Page

1 INTRODUCTION 1

1.1 Scope 1

1.2 Differential Pressure or Head-Type Flow meters 1

2 TERMINOLOGY AND DEFINITIONS 6

2.1 Meter 6

2.2 Primary Element or Differential Producer 6

2.3 Differential Producer Holder 6

2.4 Meter Tube 6

2.5 Meter Tube Internal Diameter, D, D i, D m, or D r 6

2.6 Secondary Devices 6

2.7 Roughness Average, R a 7

2.8 Discharge Coefficient, C d 7

2.9 Expansibility Factor, ε or Y 7

2.10 Flow Conditioner 7

2.11 Reynolds Number, Re 7

2.12 Swirl 7

3 REQUIRED TESTS 8

3.1 Standard and Non-standard Tests 8

3.2 Liquid Flow Tests 9

3.3 Gas Flow Tests 9

3.4 General Guidelines for Both Liquid and Gas Flowrate Tests 10

3.5 Acoustic Noise Test 10

3.6 Laminar Flow Meter Tests 10

4 INSTALLATION AND TEST FACILITY REQUIREMENTS 11

4.1 Acceptable Test Facilities 11

4.2 Acceptable Test Fluids 11

4.3 Required Meter Dimensions 11

4.4 Required Piping Considerations Upstream of the Meter 11

4.5 Installation Requirements Specific for the Meter Being Tested 12

4.6 Effect of Flow Conditioners 12

4.7 Meter and Secondary Instrument Orientation 12

5 FLOW RATE EQUATION 12

6 PROCEDURE FOR REPORTING METER PERFORMANCE RESULTS 12

6.1 Required Tables, Graphs, and Other Information 12

6.2 Uncertainty Calculations 13

6.3 Sample Reporting Form 14

APPENDIX A TEST MATRIX 15

v

Figures

1 Concentric Orifice Flow Meter 2

2 Eccentric and Segmental Orifice Flow Meters 2

3 Quadrant-Edge and Conical Orifice Plates 2

4 Venturi Flow Meter 3

5 Flow Nozzle 3

6 V-Cone Flow Meter 3

7 DALL Tube Flow Meter 4

8 Wedge Flow Meter 4

9 Pitot-Static Tube Flow Meter 4

10 Multi-Port Averaging Pitot 5

11 Variable Area Flow Meter 5

12 Laminar Flow Element 5

vi

Manual of Petroleum Measurements Standards

Chapter 5—Metering Section 7—Testing Protocol for Differential Pressure Flow Measurement Devices

1 Introduction

This document defines the testing and reporting protocols

for flow measurement devices based on the detection of a

pressure differential that is created by the device in a flowing

stream These protocols are designed to supply industry with

a comparable description of the capabilities of these devices

for the measurement of single-phase fluid flow when they are

used under similar operating conditions The objectives of

this Testing Protocol are to:

1 Ensure that the user of any differential pressure flow

meter knows the performance characteristics of the

meter over a range of Reynolds numbers as applicable

or defined by tests,

2 Facilitate both the understanding and the introduction of

new technologies,

3 Provide a standardized vehicle for validating

manufac-turers’ performance specifications,

4 Provide information about relative performance

charac-teristics of the primary elements of the Differential

Pressure metering devices under standardized testing

protocol

To accomplish these objectives, the testing protocol defines

the test limits for operating conditions of the meter, the

requirements of the facility or facilities to perform the tests,

the fluids to be tested, and the ranges for pressure, differential

pressure, temperature, secondary instrumentation and

Rey-nolds number

Examples of flow meters covered in this standard include,

but are not limited to orifice plates, Venturis, nozzles,

V-Cones, wedge meters, and averaging Pitot tubes Reporting

and testing protocols for test facilities are included to ensure

that the performance characteristics of each meter are

com-pared with identical conditions as set forth in this standard

These protocols require descriptions of the test fluids to be

used, the mechanical configuration of piping, effects of fluid

flow profile and spatial orientation of the meter A description

of required dimensional measurements and tolerances and the

mathematical equations required to convert the differential

pressure reading to a flowrate prediction is also necessary

This document primarily addresses testing protocol for

differ-ential pressure flow meters that operate under the flowing

condition that is in the turbulent flow regime The differential

pressure flow measurement devices that operate on the ple of physical laws of laminar flows require special testingprotocol, which is addressed in Section 3.6

The protocols are limited to single-phase Newtonian fluidflow, and no consideration is given to pulsation effects Fur-ther revisions of this document may include the testing ofsuch meters in wet gas or multi-phase service and the effects

of pulsation This standard does not address testing protocols

of those devices that operate on the principle of critical orchoked flow condition of fluids

The testing protocol covers any flow meter operating onthe principle of a local change in flow velocity, caused by themeter geometry, giving a corresponding change of pressurebetween two set locations There are several types of differen-tial pressure meters available to industry It is the purpose ofthis standard to illustrate the range of applications of eachmeter and not to endorse any specific meter The basic princi-ple of operation of the flow measuring devices follows thephysical laws relating to the conservation of energy and massfor the fluid flows through the device

Any existing or later developed API MPMS documentaddressing a specific type or design of differential pressureflow measuring device will supersede the requirements of thisdocument Example of one such existing standard is API

Manual Petroleum Measurement Standards Chapter 14.3—

“Concentric, Square-Edged Orifice Meters.”

FLOW METERS

The operating principle of a differential pressure flowmeter is based on two physical laws—the conservation ofenergy and conservation of mass, where changes in flowcross-sectional area and/or flow path produce a differentialpressure, which is a function of the flow velocity, fluid path,and fluid properties The following diagrams are presented

as examples of the some of the possible differential pressuredevices Other variations of meter designs are available andpossible

It is the intention of this Testing Protocol that no tial pressure meter should be excluded Therefore, the exam-ples presented are of eligible meters and the document is notlimited to these meter types alone

differen-2 M ANUAL OF P ETROLEUM M EASUREMENTS S TANDARDS , C HAPTER 5—M ETERING

Figure 1—Concentric Orifice Flow Meter

Flow

Pressure taps

Flange Upstream piping Downstream piping

Figure 2—Eccentric and Segmental Orifice Flow Meters

Tap Hole Plate Tap

Figure 3—Quadrant-Edge and Conical Orifice Plates

Flow Flow

S ECTION 7—T ESTING P ROTOCOL FOR D IFFERENTIAL P RESSURE FL OW M EASUREMENT D EVICES 3

Figure 4—Venturi Flow Meter

Flow

Pressure taps Upstream piping Downstream piping

Figure 5—Flow Nozzle

Flow

Pressure taps

Flange Upstream piping Downstream piping

Figure 6—V-Cone Flow Meter

H L

Flow

4 M ANUAL OF P ETROLEUM M EASUREMENTS S TANDARDS , C HAPTER 5—M ETERING

Figure 7—DALL Tube Flow Meter

Flow

H L Pressure taps

Figure 8—Wedge Flow Meter

S ECTION 7—T ESTING P ROTOCOL FOR D IFFERENTIAL P RESSURE FL OW M EASUREMENT D EVICES 5

Figure 10—Multi-Port Averaging Pitot

6 M ANUAL OF P ETROLEUM M EASUREMENTS S TANDARDS , C HAPTER 5—M ETERING

2 Terminology and Definitions

The definitions are given to emphasize and clarify the

par-ticular meaning of terms as used in this document

A meter is the assembly of a primary element, a differential

producer holder with the upstream and downstream meter

tubes that will generate a differential pressure when placed in

a flow stream The differential pressure is monitored by

sec-ondary device(s) to derive the flow rate

PRODUCER

The primary element is defined as the differential producer

when placed in a flowing stream

The differential producer holder is defined as a

pressure-containing piping element used to contain and position the

differential producer and its associated differential pressure

sensing taps in the piping system An orifice fitting would be

an example of such a device

The meter tube is defined as the straight sections of pipe,

including all segments that are integral to the differential

pro-ducer holder, upstream and downstream of the differential

producer and the flow conditioner, if required

D m , or D r

In this document it has been assumed that the meter tube is

circular If the meter is used in a non-circular cross-sectional

flow line or a non-circular device is installed in a circular flow

line, the manufacturer of the device must explain how the

critical dimensions of the primary element would be defined

and calculated In addition, other necessary or critical

upstream and downstream flow conduit geometry and

dimen-sions for the non-circular differential pressure producing flow

measuring device must be defined by the manufacturer

The published meter tube internal diameter (D i) is the

inside diameter as published in standard piping handbooks

This internal diameter is used for determining the required

meter run length (e.g., for orifice meters as stated in Tables

2-7 and 2-8 of API MPMS Chapter 14.3 Part 2, “Specification

and Installation Requirements”)

The measured meter tube diameter (D m) is the average

inside diameter of the upstream section of the meter tube

measured at a distance from the primary element as defined

by either a published standard or by the meter’s design and at

the temperature of the meter tube (T m) at the time of the

inter-nal diameter measurements For example, an orifice diameter

is measured at one in upstream of the orifice plate The metermanufacturer must define how D m is obtained and utilized tocalculate the flow rate for that meter

The calculated meter tube internal diameter (D), if used, isthe inside diameter of the upstream section of the meter tubecomputed at flowing fluid temperature (T f) The calculatedmeter tube internal diameter (D) is used to determine thediameter ratio or β, if applicable, and in the Reynolds Num-ber calculations

The reference meter tube internal diameter (D r) is theinside diameter of the upstream section of the meter tube cal-culated at the reference temperature (T r) The reference diam-eter (D r) is the certified meter tube internal diameter (as

described in the orifice meter document API MPMS Chapter

14.3.2, Section 2.5.1.2)

The area ratio is the minimum unrestricted area at the mary element divided by the cross-sectional area of the metertube

pri-The diameter ratio is the bore diameter of the primary ment divided by the meter tube internal diameter

Instrumentation required for determining the flow throughthe primary element, which typically includes monitoringdifferential pressure and the sensors defining the flowingconditions and fluid properties (pressure, temperature, den-sity, etc.)

The static pressure and differential pressure are measuredusing either a digital or an analog transmitter Static pressuretransmitters measure either the absolute or gage pressure ofthe fluid Differential pressure transmitters measure the dif-ferential pressure developed between two points of measure-ment, caused by the primary element A multivariabletransmitter measures both static and differential pressure andmay also accept a temperature sensor input Analog transmit-ters provide an analog output proportional to the measuredvariable The output of digital transmitters can be either ana-log and/or digital

Measurement, P 1 , P 2 , and ∆∆∆∆P

The static pressure of the process is usually measuredupstream of the differential producer by a tap normal to theflow velocity The static pressure can be used (in conjunctionwith the temperature and composition) to determine the den-sity of the flowing fluid