Remote Automation Solutions Manual: Flow Measurement User Manual|RAS Manuals & Guides

Form Number A6043

Part Number D301224X012 March 2005

Flow Measurement

User Manual

Flow Computer Division

Website: www.EmersonProcess.com/flow

Flow Manual

Revision Tracking Sheet

March 2005

This manual is periodically altered to incorporate new or updated information. The date revision level of each page is indicated at the bottom of the page opposite the page number. A major change in the content of the manual also changes the date of the manual, which appears on the front cover. Listed below is the date revision level of each page.

Page Revision

All Pages Mar/05

All Pages May/97

FloBoss and ROCLINK are marks of one of the Emerson Process Management companies. The Emerson logo is a trademark and service mark of Emerson Electric Co. All other marks are the property of their respective owners.

This product may be covered under pending patent applications.

While this information is presented in good faith and believed to be accurate, Fisher Controls does not guarantee satisfactory results from reliance upon such information. Nothing contained herein is to be construed as a warranty or

guarantee, express or implied, regarding the performance, merchantability, fitness or any other matter with respect to the products, nor as a recommendation to use any product or process in conflict with any patent. Fisher Controls reserves the

right, without notice, to alter or improve the designs or specifications of the products described herein.

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Flow Manual

TABLE OF CONTENTS

Section 1 – Introduction ............................................................................................... 1-1

1.1 O

VERVIEW .................................................................................................................................. 1-1

Section 2 – Natural Gas Measurement........................................................................ 2-1

2.1 AGA REPORT NO. 7 - MEASUREMENT OF GAS BY TURBINE METERS ......................................... 2-1

2.2 AGA

2.3 C

REPORT NO. 3 – ORIFICE METERING OF NATURAL GAS..................................................... 2-7

ALCULATIONS FOR ULTRASONIC METERS............................................................................... 2-15

Section 3 – Compressibility .......................................................................................... 3-1

3.1 INTRODUCTION............................................................................................................................ 3-1

3.2 NX-19......................................................................................................................................... 3-1

3.3 AGA NO. 8 – 1985 VERSION....................................................................................................... 3-3

3.4 AGA NO. 8 – 1992 VERSION....................................................................................................... 3-5

Section 4 – Industry Application of the standards..................................................... 4-1

4.1 INTRODUCTION............................................................................................................................ 4-1

4.2 API CHAPTER 21, SECTION 1 ...................................................................................................... 4-1

4.3 BLM ONSHORE ORDER NO. 5 ..................................................................................................... 4-6

Section 5 – Contracts and Electronic flow Computers.............................................. 5-1

5.1 I

5.2 EXAMPLE CONTRACT 1 ............................................................................................................... 5-2

5.3 EXAMPLE CONTRACT 2 ............................................................................................................... 5-5

NTRODUCTION............................................................................................................................ 5-1

INDEX.............................................................................................................................I-1

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Flow Manual

SECTION 1 – INTRODUCTION

1.1 Overview

This manual discusses gas flow measurement based on philosophies expressed in AGA (American Gas Association) and API (American Petroleum Institute) guidelines.

 NOTE: AGA and API do not certify manufacturers’ equipment for flow measurement. Products of The Flow Computer Division of Emerson Process Management are in compliance with AGA and API guidelines.

The American Gas Association (AGA) has published various reports describing how to measure the flow of natural gas, starting with AGA Report No. 1, issued in 1930, describing the measurement of natural gas through an orifice meter. This report was revised in 1935 with the publication of AGA Report No. 2 and again in 1955 with the publication of AGA Report No. 3. The report was revised again in 1969, 1978, 1985, and 1992, but has remained AGA Report No. 3 -- Orifice Metering of Natural Gas and Other Related Hydrocarbons. Thus, AGA3 has become synonymous with orifice metering.

In 1975, the American Petroleum Institute (API) adopted AGA Report No. 3 and approved it as API Standard 2530 and also published it as Chapter 14.3 of the API Manual of Petroleum Measurement Standards. In 1977, the American National Standards Institute (ANSI) also approved AGA Report No. 3 and referred to it as ANSI/API 2530. Thus references to API 2530, Chapter 14.3 and ANSI/API 2530 are identical to AGA Report No. 3. In 1980 (revised in 1984 and in 1996), AGA Report No. 7-Measurement of Fuel Gas by Turbine Meters--was published, detailing the measurement of natural gas through a turbine meter.

While AGA No. 3 and AGA No. 7 detail methods of calculating gas flow, separate documents have been created to explain the calculation of the compressibility factor, used in both AGA No. 3 and AGA No. 7. The older method, called NX-19, was last published in 1963. A more comprehensive method was published in 1985 as AGA Report No. 8. This report was revised in 1992.

In 1992, the API released Chapter 21, Section 1, which addressed the application of electronic flow meters in gas measurement systems. It addresses the calculation frequency and the method of executing the AGA calculations.

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Flow Manual

SECTION 2 – NATURAL GAS MEASUREMENT

2.1 AGA Report No. 7 - Measurement of Gas by Turbine Meters

2.1.1 General Description

AGA No. 7 covers the measurement of gas by turbine meters and is limited to axial-flow turbine meters. Although the report covers meter construction, installation, and other aspects of metering, this Flow Manual summarizes only the equations used in calculating flow.

The meter construction and installation sections are specific to axial-flow turbine meters, but the flow equations are applicable to any linear meter, including ultrasonic and vortex meters.

2.1.2 Introduction

The turbine meter is a velocity measuring device. It consists of three basic components:

• The body

• The measuring mechanism

• The output and readout device

It relies upon the flow of gas to cause the meter rotor to turn at a speed proportional to the flow rate. Ideally, the rotational speed is proportional to the flow rate. In actuality, the speed is a function of passage-way size, shape, rotor design, internal mechanical friction, fluid drag, external loading, and gas density.

Several characteristics that affect the performance of a turbine meter are presented in Section 5 of AGA No. 7. Here is a summary of these characteristics:

Swirl Effect - Turbine meters are designed and calibrated under conditions approaching axial flow. If the flowing gas has substantial swirl near the rotor inlet, depending on the direction, the rotor can either increase or decrease in velocity. Buyer or seller can lose.

Velocity Profile Effect - If poor installation practices result in a non-uniform velocity profile across the meter inlet, the rotor speed for a given flow rate will be affected. Typically, this results in higher rotor velocities. Thus, less gas passes through the meter than the calculated value represents. Buyer loses.

Fluid Drag Effect - Fluid drag on the rotor blades, blade tips and rotor hub can cause the

rotor to slip from its ideal speed. This rotor slip is known to be a function of a dimensionless ratio of inertia to viscous forces. This ratio is the well known Reynolds number and the fluid drag effect has become known as the “Reynolds number effect.” Basically, it slows the rotor down, thus the Buyer wins.

Non-Fluid Drag Effect - Also decreasing rotor speed from its ideal speed are forces created

from non-fluid related forces, such as bearing friction and mechanical or electrical readout

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Flow Manual

drag. The amount of slip is a function of flow rate and density. Also know as “the density effect.” It also benefits the buyer.

Accuracy - Accuracy statements are typically provided within ± 1% for a designated range.

Linearity - Turbine meters are usually linear over some designated flow range. Linear

means that the output frequency is proportional to flow.

Pressure Loss - Pressure loss is attributed to the energy required to drive the meter.

Minimum and Maximum Flow Rates - Turbine meters will have designated minimum flow

rates for specific conditions.

Pulsation - Error due to pulsation generally creates an error causing the rotor to spin faster,

thus resulting in errors that favor the seller. A peak-to-peak flow variation of 10% of the average flow generally will result in a pulsation error of less than 0.25% and can be considered as the pulsation threshold.

2.1.3 Basic Gas Law Relationship

The basic gas law relationships are presented similarly in the 1985 and 1996 versions of AGA No. 7. The equation numbers shown here are from the 1996 version. The relationships are:

))()()(())((

TRNZVP = For Flowing Conditions [AGA Equation 12]

ffff

and

TRNZVP = For Base Conditions [AGA Equation 13]

))()()(())((

bbbb

where: P = Absolute pressure

V = Volume

Z = Compressibility

N = Number of moles of gas

T = Absolute temperature

R = Universal gas constant

subscript

= Flowing conditions (use with P, V, and Z)

= Base conditions (use with P, V, and Z)

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:

⎛

⎞

⎛

⎞

⎜

2-2 Natural Gas Measurement Rev Mar/05

⎟

⎜

⎟

⎜

⎝

⎠

⎝

⎞

⎟

⎜

⎟ ⎟ ⎠

[AGA Equation 14]

⎜

⎟

⎝

⎠

Flow Manual

2.1.4 Difference Between the 1985 and 1996 Versions

The difference between the versions as it applies to the flow calculations, is that the 1985 flow equations included factors, such as

factor. In the 1996 version, the correction factors have been combined into multipliers. For example, the pressure factors,

and Fb have been combined into the pressure multiplier, Pf /P

, the measured pressure factor, and FPb, the base pressure

1985:

P =

and

1996: Pressure Multiplier =

P =

PP • =

2.1.5 AGA No. 7 – 1985 Version

2.1.5.1 The Flow Equation

Rotor revolutions are counted mechanically or electrically and converted to a continuously totalized volumetric registration. Because the registered volume is at flowing pressure and temperature conditions, it must be corrected to the specified base conditions for billing purposes.

2.1.5.2 General Form of the Flow Equation and a Term-by-Term Explanation

Flow rate at base conditions (cubic feet per hour)

QQFFFFs

= [AGA Equation 15]

()( )( )

b f pm pb tm tb

()()

()

where: Qb = Volumetric flow rate at base conditions

= Volumetric flow rate at flowing conditions

= Pressure factor

= Pressure base factor

= Flowing temperature factor

= Temperature base factor

s = Compressibility ratio factor

Qf Flow Rate at Flowing Conditions (Cubic Feet per Hour)

where Q

= Flow rate at flowing conditions

= Volume timed at flowing conditions

= [AGA Equation 14]

= Counter differences on mechanical output

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Flow Manual

= Total pulses ×

on electrical output

t = Time

K = Pulses per cubic foot

where p

Where p

Fpb Pressure Base Factor

Pressure Factor

= Pf + pa

= Atmospheric pressure, psia

is the contract base pressure in psia.

= [AGA Equation 16]

73.14

= Static gauge pressure, psig

14 73.

[AGA Equation 18]

This factor is applied to change the base pressure from 14.73 psia to another contract

pressure base.

Flowing Temperature Factor

520

[AGA Equation 19]

Where Tf = actual flowing temperature of the gas in degrees Rankine. °R = ° F +

459.76

Temperature Base Factor

[AGA Equation 20]

520

Where Tb = the contract base temperature in degrees Rankine.

This factor is applied to change the assumed temperature base of 60 deg F to the actual

contract base temperature.

s Compressibility Factor Ratio

= [AGA Equation 21]

where Zb = Compressibility factor at base conditions

2-4 Natural Gas Measurement Rev Mar/05

= Compressibility factor at flowing conditions

Flow Manual

The compressibility ratio “s” can be evaluated from the supercompressibility factor “Fpv”,

which is defined as:

s = (F

)

where FZZ

The calculation of the supercompressibility factor F

pv b f

is given in AGA Report NX-19 or

AGA No. 8. For more information, refer to Section 3.

2.1.6 AGA No. 7 – 1996 Version

2.1.6.1 The Flow Equation

Rotor revolutions are counted mechanically or electrically and 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 billing purposes.

2.1.6.2 General Form of the Volumetric Flow Equation

Qb Flow rate at flowing conditions

= [AGA Equation 15]

where Q

= Flow rate at flowing conditions

= Volume timed at flowing conditions

= Counter differences on mechanical output

= Total pulses ×

× METER FACTOR on electrical pulse output

t = Time

K = K-Factor, pulses per cubic foot

METER FACTOR is a dimensionless term obtained by dividing the actual volume of gas passed through the meter (as measured by a prover during proving) by the corresponding meter indicated volume. For subsequent metering operations, actual measured volume is determined by multiplying the indicated volume registered by the meter times the METER FACTOR.

Qb Flow rate at base conditions (cubic feet per hour)

⎛

⎞

⎛

⎛ ⎜

()

⎜

⎝

⎞

⎜

⎟ ⎟

⎜

⎠

⎝

⎞

⎟

⎜

⎟

⎜

⎠

⎝

[AGA Equation 16]

⎟

⎠

where: Qb = Volumetric flow rate at base conditions

= Volumetric flow rate at flowing conditions

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Flow Manual

The P, T, and Z quotients in the above equation are the pressure multiplier, temperature multiplier, and the compressibility multipliers, respectively. They are defined below.

Pressure Multiplier

Multiplierpressure =

where: Pf = pf + pa , in psia

[AGA Equation 17]

= Static gauge pressure, in psig

= Atmospheric pressure, in psia

= Base pressure, in psia

Temperature Multiplier

MultipliereTemperatur =

[AGA Equation 18]

where: Tb = Base temperature, °R

Absolute Flowing Temperature,

= Flowing temperature, °R

°R = ° F + 459.76°

Compressibility Multiplier

MultiplierilityCompressib =

[AGA Equation 19]

where: Zb = Compressibility at base conditions

= Compressibility at flowing conditions

The compressibility multiplier can be evaluated from the supercompressibility factor, F

as follows:

= [AGA Equation 20]

)(

Where natural gas mixtures are being measured, compressibility values may be determined from the latest edition of AGA Transmission Measurement Committee Report No. 8 “Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases” or as specified in contracts or tariffs or as mutually agreed to by both parties. For more information, refer to Section 3.

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Flow Manual

2.2 AGA Report No. 3 – Orifice Metering of Natural Gas

2.2.1 General Description

AGA Report No. 3 is an application guide for orifice metering of natural gas and other related hydrocarbon fluids. This Flow Manual summarizes some of the equations used in calculating flow and is based on part 3 of the report.

2.2.2 Differences Between 1985 and 1992 Versions of AGA No. 3

AGA No. 3 – 1992 version was developed for flange-tap orifice meters only. The pipe tap methodology of the 1985 version is included as an appendix in the 1992 standard. This appendix is identical to the 1985 version with the exception of F implemented per the body of the 1992 standard. For F AGA No. 8 to calculate compressibility. The new version is based on the calculation of a discharge coefficient. The Reynolds number is a function of flow. It must be determined iteratively. In addition, the orifice diameter and pipe diameter are both corrected for temperature variations from the temperature at which they were measured. This requires additional parameters for the measured temperature of the pipe and the orifice material.

, Ftb, Ftf, Fgr, and Fpr. These factors are to be

, this indicates using the most recent version of

The empirical coefficient of discharge has received much emphasis in the creation of the 1992 report. It is a function of the Reynolds Number, sensing tap location, pipe diameter and the beta ratio. An expanded Regression data base consisting of data taken from 4 fluids (oil, water, natural gas, air) from different sources, 11 different laboratories, on 12 different meter tubes of differing origins and more than 100 orifice plates of different origins. This data provided a pipe Reynolds Number range of accepted turbulent flow from 4,000 to 36,000,000 on which to best select the mathematical model. Flange, corner, and radius taps; 2, 3, 4, 6, and 10 inch pipe diameters; and beta ratios of 0.1, 0.2, 0.375, 0.5, 0.575, 0.660, and 0.750 were all tested.

Technical experts from the US, Europe, Canada, Norway and Japan worked together to develop an equation using the Stolz linkage form that fits this expanded Regression Data Base more accurately than any previously published equations. The empirical data associated with this data base is the highest quality and largest quantity available today. This is perhaps the greatest improvement over the 1985 equations. This mathematical model for the Coefficient of Discharge is applicable and most accurately follows the Regression data base for nominal pipe sizes of 2 inches and larger, beta ratios of 0.1 to 0.75 (provided that the orifice plate bore diameter is greater than 0.45 inch), and pipe Reynolds number greater than or equal to 4000.

Concentricity tolerances have been tightened from the 1985 statement of 3%. The 1992 uses an equation to calculate the maximum allowed eccentricity. Eccentricity has a major effect on the accuracy of the coefficient of discharge calculations.

AGA No. 3 – 1992 version calls for the use of AGA No. 8 for the calculation of the supercompressibility factor. As no specific version is specified, this implies using the most recently released version, NX-19 or AGA No. 8 - 1985 version should not be used with the new version.

Unlike the 1985 report, the AGA No. 3 - 1992 report was divided into four parts:

• Part 1 - General Equations and Uncertainty Guidelines

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Flow Manual

• Part 2 - Specifications and Installation Requirements

• Part 3 - Natural Gas Applications

• Part 4 - Background, Development, Implementation Procedure, and Subroutine Documentation

for Empirical Flange Tapped Discharge Coefficient Equation

Part 3 provides an application guide along with practical guidelines for applying AGA Report No. 3, Parts 1 and 2, to the measurement of natural gas. Mass flow rate and base (or standard) volumetric rate methods are presented in conformance with North American industry practices.

2.2.3 AGA No. 3 – 1985 Version

The orifice meter is essentially a mass flow meter. It is based on the concepts of conservation of mass and energy. The orifice mass flow equation is the basis for volumetric flow rate calculations under actual conditions as well as at standard conditions. Once mass flow rate is calculated, it can be converted into volumetric flow rate at base (standard) conditions if the fluid density at base conditions can be determined or is specified.

AGA Report No. 3 defined measurement for orifice meters with circular orifices located concentrically in the meter tube having upstream and downstream pressure taps. Pressure taps must be either flange taps or pipe taps and must conform to guidelines found in the AGA 3 report.

This standard applies to natural gas, natural gas liquids, and associated hydrocarbon gases and liquids. It was not intended for non-hydrocarbon gas or liquid streams.

2.2.3.1 Topics Worthy of Mention

Concentricity - When centering the orifice plates, the orifice must be concentric with the inside

of the meter tube to within 3% of the inside diameters. This is more critical in small tubes, tubes with large beta ratios, and when the orifice is offset towards the taps.

Beta Ratio Limitations - Beta ratio, the ratio of the orifice to meter tube for flange taps, is

limited to the range of 0.15 to 0.7. For pipe taps, it should be limited to 0.2 to 0.67.

Pulsation Flow - Reliable measurements of gas flow cannot be obtained with an orifice meter

when appreciable pulsations are present at the place of measurement. No satisfactory adjustment for flow pulsation has ever been found. Sources of pulsation include:

Reciprocating compressors, engines or impeller type boosters

Pumping or improperly sized regulators

Irregular movement of water or condensates in the line

Intermitters on wells and automatic drips

Dead-ended piping tee junctions and similar cavities.

2.2.3.2 General Form of the Flow Equation

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