REFERENCE

NBS

PUBLICATIONS

NBSIR 86-3057

A 1 1 1 0 5 b 3 1 3 1

0

HAri INST Of standards & TECH fuc. (AL

All 102631310

s« «»» GAS HANDBOOK

Paul R. Ludtke

National Bureau of Standards

U.S. Department of Commerce

Boulder, Colorado 80303

August 1986

-QC

100

• U56

86-3057

1986

NBSIR 86-3057

NATURAL GAS HANDBOOK

MBS

RESEARCH ' information CENTER

Ur h

j /> o /

I n

Paul R. Ludtke

Chemical Engineering Science Division

Center for Chemical Engineering

National Engineering Laboratory

National Bureau of Standards

Boulder, Colorado 80303

August 1986

Prepared for

U.S. Air Force

Engineering and Services Center

Tyndall Air Force Base, Florida 32404

U.S. DEPARTMENT OF COMMERCE, Malcolm Baldrige, Secretary

NATIONAL BUREAU OF STANDARDS, Ernest Ambler, Director

Foreword

This handbook was written for Base Civil Engineering (BCE) personnel and

Real Property Management Agency personnel who have responsibility for checking

the monthly gas utility bills and authorizing payment for natural gas

purchased by the Air Force. Air Force Contracting Officers negotiating

agreements with Gas Utility Companies should also find this handbook useful

for background information. The purpose of the handbook is to promote a

better understanding of gas metering principles and the computations involved

in the sale of natural gas.

The handbook was prepared by the National Bureau of Standards, Center for

Chemical Engineering, for the U.S. Air Force under project order No. F84-67.

Identification of Commercial Equipment

Identification of certain commercial equipment and instruments has been

necessary in this report. Such identification does not imply recommendation

or endorsement by the National Bureau of Standards, nor does it imply that the

equipment identified is necessarily the best available for the purpose.

Use of Non-SI Units

It is necessary to write this report using units normally encountered on

gas utility bills and used universally throughout the natural gas industry.

The use of SI units or dual units would add unnecessary complication to this

report and only serve to confuse the intended audience. The necessary use of

non-SI units in this report departs from the usual NBS practice of using SI

ili

units .

Table of Contents

Page

Foreword ........... iii

Definitions and Terminology ....... ix

1 .0 Introduction .......... 1

2.0 Characterization of Natural Gas ...... 4

3.0 Water Content of Natural Gas ....... 7

4.0 Heating Value of Natural Gas ....... 11

5.0 Volume Measurement of Gas ....... 14

5.1 Turbine Meters ......... 20

5.1.1 Calculation of Base Volumes .... 27

5.2 Gas Displacement Meters ....... 33

5.2.1 Rotary Displacement Meters .... 33

5.2.2 Diaphragm Displacement Meters .... 37

5.2.3 Calculation of Base Volumes .... 42

5.3 Orifice Meters ......... 45

5.3.1 Calculation of Flow Through an Orifice Meter . 54

5.4 Comparison of Natural Gas Flowmeters .... 65

5.5 Telemetering of Meter Output ...... 68

6.0 Meter and Instrument Accuracy Checks ..... 69

7.0 Gas Service Meter Stations ....... 74

8.0 Utility Bills .......... 80

8.1 Methods of Selling Gas ....... 81

8.2 Rate Categories ........ 82

8.3 Miscellaneous Charges ....... 83

8.4 Required Billing Information ...... 86

9.0 References and Standards ........

v
Appendices

Air Force Base Survey Information

Unit Conversions
List of Figures

Figure

3. 1 Water Content of Saturated Natural Gas ....

5.1 Compressibility of Methane Gas. .....

5.2 Typical Turbine Meter .......

5.3 Accuracy Curve for a Turbine Meter .....

5.4 Recommended Installation Configuration for a

Gas Turbine Meter .......

5.5 Typical Straightening Vane Bundle .....

5.6 Photo of a Turbine Meter Installation ....

5.7 A Typical Lobe Type Rotary Displacement Meter.

5.8 Performance Curve for a Lobe Type Rotary Displacement Meter

5.9 Typical Diaphragm Type Positive Displacement Meter

5.10 Accuracy Curve for a Diaphragm Meter ....

5.11 Large Diaphragm Meter with a Pressure Correcting Instrument

5.12 Cross-section and Pressure Profile of an Orifice Meter .

5.13 Orifice Plate Installed between Two Pipe Flanges, flange

type pressure taps .......

5.14 Orifice Meter Fitting .......

5.15 A Bonnet type Orifice Meter Fitting ....

5.16 Recommended Installation Configuration for an Orifice Meter

5.17 Comparative Flow Capacities of the Various Type Meters .

6.1 Pressure and Temperature Correcting Instrument,

Odometer Type Readout ......

Page

10

18

21

22

23

24

26

34

36

38

40

41

47

49

50

52

53

66

70

Vll
List of Figures, Cont'd

Figure

6.2 Pressure and Temperature Correcting Instrument With Odometer

Type Readout and Dial Type Index ....

7.1 Typical Outdoor Meter Station, Eglin AFB

7.2 Natural Gas Oil-type Scrubber, Eglin AFB

7.3 Gas Service Line Heater at Minot AFB ....

Page

71

75

77

79

List of Tables

Table

5.1 Orifice Meter Gas Measurement Statement .

A1 Air Force Base Survey Information

Page

61

93
Definitions and Terminology

Abbreviations

AFB

A.G.A.

BCE

Btu

CCF

MCF

MMCF

mole

n

psia

psig

psid

ppm

R

SCFH

SG

SI

Z

J

MJ

Th

daTh

& Acronyms

Air Force Base

American Gas Association

Base Civil Engineering

British thermal unit

one hundred cubic feet of gas.

one thousand cubic feet of gas.

one million cubic feet of gas.

one molecular weight of a compound.

the number of moles of a gas.

pounds per square inch, absolute.

pounds per square inch, gauge.

pounds per square inch, differential.

parts per million (volume basis).

the universal gas constant (this constant has various units),

standard cubic feet per hour (60°F & 14.73 psia)

specific gravity = the mass of a unit volume of gas divided by

the mass of the same unit volume of air, at a specified

temperature

the International System of Units,

compressibility factor.

joule = the unit of energy in the metric system; 1055 joules =

1 Btu (International).

megajoule = one million joules

Therm = 100,000 Btu

dekaTherm = one million Btu

IX
Definitions

• Atmospheric Pressure (P a )

The absolute pressure in the atmosphere at a given location. The

average annual pressure at the nearest weather station to an Air Force Base

will sometimes be used for contractual purposes.

• Ideal Gas

A gas that obeys the ideal gas law of PV = nRT (Z=1).

• One cubic foot of gas

The amount of gas that will occupy a volume of one cubic foot.

• Boyle’s Law

Boyle's law states that if the temperature of a given quantity of gas

is held constant, the volume will vary inversely with the absolute pressure.

The law may be expressed in equation form:

P^

P 2

V*

or PV = Constant 1

J T

• Charles' Law

Charles' law states that if the pressure of a given quantity of gas is

held constant, the volume will vary in direct proportion to the absolute

temperature. Expressed in an equation:

= X4. or = Constant 1 V 2 T 2 V

J P

• Pressure and Temperature Base

When natural gas is purchased or sold on a volume basis, a pressure

and a temperature have to be specified in order to completely define the

amount of gas transferred. The most common pressure and temperature base

in the gas utility industry is 14.73 psia and 60°F. 60°F is used almost

universally, but other pressures such as 14.65 psia are quite common.

x
Metered Volume of Gas

This is the volume of gas that passes through the meter at the meter

temperature and pressure.

• Base or Billing Volume of Gas

This is the volume of gas that results when the metered volume of gas

is converted to the billing pressure and temperature base (such as 14.73

psia and 60°F).

• Gross and Net Heating Value of Natural Gas

There are two basic definitions for the heating value of a fuel gas;

one is the gross or higher heating value (HHV), and the other is the net or

lower heating value (LHV). The difference between the two depends on the

state of the water product of combustion; i.e., whether the water is in the

liquid or vapor state.

The stoichiometric chemical reaction for the combustion of methane is

CH^ + 20 2 + 2H 2 0 + C0 2 .

The products of combustion are water and carbon dioxide. When the

reactants and the products are at the same initial conditions of pressure

and temperature, the exothermic heat of combustion is dependent upon the

state of the water in the combustion products. If the water is in the

liquid state, the heat of combustion is called the gross or higher heating

value. If the water is in the vapor state, the heat of combustion is

called the net or lower heating value. The difference between the two

values is of course the latent heat of vaporization of the water product.

• Compressibility Ratio (s)

This is the ratio of the compressibility of the natural gas at base

conditions (Z b ) to the compressibility at the metered or flowing conditions

XI
(Zf). The compressibility ratio is defined as Z^/Zp, and is properly

designated by (s).

• Supercompressibility Factor (Fp V )

The supercompressibility factor is one of the correction factors in

the A.G.A. orifice equation. This term accounts for the compressibility of

the gas, and is defined as

• Dry Natural Gas

Dry gas has negligible water vapor content; less than 7 lbs/MMCF

(< 147 ppm H 2 0).

• Absolutely Dry Natural Gas

By definition, gas that contains zero water vapor.

• Sour Gas

Sour gas contains hydrogen sulfide and other sulfur compounds.

• Sweet Gas

Sweet gas contains less than one grain of hydrogen sulfide per one

hundred cubic feet of gas.

• Saturated Gas

Saturated gas is completely saturated with water vapor.

• Certified Calibration Gas

A hydrocarbon gas with certified mole fraction and heating value.

Certified gas is necessary for gas chromatographs, combustion calorimeters,

and flame titration instruments used for measuring heating value.

Xll
Rangeability

A characteristic of gas meters; the rangeability is defined as the

ratio of maximum to minimum flow rate that a meter can measure accurately,

at a constant pressure.

Relative Density

This is simply another term for specific gravity.

Wobbe Index

This is an index used to characterize natural gas. It is

Net or Gross Heating Value

r

. 31

(Relative Density)V2 U

Index

An index is a small unit that attaches to the top of a gas meter. The

index is activated by the meter (once/revolution) and the index output is a

dial or odometer type readout, in terms of cubic feet or liters of gas.

The internal mechanism contains the necessary gears, wheels, and dials.

Instrument

An instrument is similar to a meter index, but it is considerably more

sophisticated. The instrument also attaches to the gas meter; it is driven

by the meter output, but also has pressure and temperature sensors. The

pressure and temperature values are used to correct the metered volumes to

a specified billing volume. Usually the instrument will have two odometer

type dials; one for the non-corrected volume, and another volume reading

corrected to the specified pressure and temperature base. Often times a

circular chart is part of the instrument package; the circular chart

provides a permanent record of meter pressure and temperature, plus the

meter revolutions. Instruments are available that will also correct for
the compressibility ratio. Two typical temperature and pressure correcting

instruments are shown in figures 6.1, 6.2

• Beta Ratio ( 3

A descriptive term for orifice meters; it is the ratio of the orifice

bore diameter to the inside diameter of the pipe.

xiv
Abstract

A Natural Gas Handbook has been prepared to help Air Force BCE personnel

better understand the principles of metering and selling natural gas on an

energy content basis. The various aspects of natural gas such as heating

value, moisture content, and hydrogen sulfide content are discussed. The

character istics of the various types of meters currently used for flow

measurements are given. The correct procedures for calculating gas utility

bills, including compressibility corrections, are presented. The

responsibility of the gas utility to periodically check the gas meter and

instrument accuracy is discussed. A list of information that should appear on

the gas utility bill is given, and the various methods of selling natural gas

are discussed.

Key words: compressibility; gas meters; heating value; natural gas

XV

1 .0 Introduction

During the initial survey phase of this study, fourteen different Air

Force bases within the U.S. were visited. The purpose of the visits was to

obtain a representative sampling of the way natural gas is purchased by the

Air Force. The gas metering facilities at each base service entrance were

inspected, and there were discussions with the BCE gas utility personnel about

problem areas concerning gas metering and billing procedures. In addition,

meetings were conducted with technical representatives from the gas utility

serving the Base, with BCE personnel attending; various aspects of gas

metering, heating value measurement, meter calibration, and billing procedures

were discussed.

The information gathered during the survey and study phases was used to

prepare this Natural Gas Handbook for the Air Force. The purpose of the

handbook is as follows:

• to promote a better understanding of gas metering and measurement

techniques, and the billing procedures for gas delivered,

• to promote a better understanding of temperature and pressure

corrections to metered volumes, and also the correction factor for

the deviation from Boyle’s law.

• To accurately define the supercompressibility factor and the

compressibility ratio, and point out the difference between the two.

• To promote a better understanding of the parameters which determine

the heating value of natural gas, the various methods of measuring

heating value, and the sale of gas on a heating value or energy

content basis.

• To provide sample billing calculations showing all the steps in going

from metered volume differences to dollars owed for gas delivered.

1
• To inform BCE personnel about new meter correcting instruments, and

pulse transmitters which facilitate telemetering of meter output.

During the survey we found that there are definite trends taking place in

the sale of natural gas to government bases and light industry. There is a

definite movement toward the sale of natural gas on a heat content basis. Gas

has become considerably more expensive. Thus there is more emphasis on

measuring it accurately and selling it on a more equitable basis, and that

basis is the heat content of the gas. Because of this, one complete section

of this report is devoted to the various methods of measuring heat content,

to new instruments to measure heat content, and to methods of calculating heat

content from chromatographic mole fraction analysis.

Orifice meters are being used less at the Air Force base meter stations.

The orifice meters are being replaced mostly with turbine meters, and some

rotary displacement meters.

The use of newer, more sophisticated correcting instruments atop the gas

meters is increasing. The older family of instruments provided pressure and

temperature correction to a specified base, but the current instruments can

also correct for the compressibility ratio and transmit the data by pulse

senders to central data acquisition stations (telemetering).

The natural gas industry has its own set of units or nomenclature that is

fairly consistent throughout the pipeline transmission and gas utility

companies. However, these are not the recommended SI units. The units that

the BCE and utilities management personnel will encounter on the gas utility

bills are listed below, and for consistency these are also the units that will

be used throughout this handbook.

2
CCF One hundred cubic feet of gas

MCF One thousand cubic feet of gas

MMCF One million cubic feet of gas

Btu British thermal unit

Therm = 100,000 Btu

MJ One million joules (mega joule)

psia pounds per square inch absolute

psig pounds per square inch gauge

°F degrees Fahrenheit

Thus, we will use MCF for 1,000 cubic feet of gas and MMCF for 1,000,000

cubic feet of gas. This is not consistent with present Air Force terminology

wherein 1,000 cubic feet of gas is denoted KCF, and 1,000,000 cubic feet of

gas is denoted MCF.

The American Gas Association (A.G.A.) has set guidelines for the use of

metric units [9] but the natural gas industry has not yet started toward

metric conversion.

This study was limited to an evaluation of the various methods of

purchasing, metering, and billing for natural gas sold to Air Force bases.

Only the primary gas meters on the service lines entering the Base were

considered. Additional submetering within the Base (except power plants) and

the facility gas distribution systems were only peripherally included in this

study

3
2.0 Characterization of Natural Gas

Raw natural gas from oil and gas wells must be processed in order to

obtain a marketable product; water vapor, inert and poisonous constituents,

and condensable hydrocarbons are removed to tolerable levels. The processed

(sweet) gas sold to industry and the public is mostly methane with small

amounts of ethane, propane, butane, pentane, carbon dioxide, and nitrogen. A

typical analysis would have constituents in the following ranges:

Methane

Ethane

Propane

Butane

Pentane

Carbon Dioxide

Nitrogen

Hydrogen Sulfide

Water

90 to 96 Mole %

0 to 8

" "

< 1.0 " "

<0.5 " "

<0.5 " "

0 to 2

" "

0.5 to 8

" "

<1 grain/CCF

1 to 4 lbs/MMCF

Natural gas is classified in several broad categories, as follows:

• Wet gas contains the heavier, condensable, hydrocarbons such as

propane, butane, pentane, and above. This term shouldn't be

confused with saturated gas; which means the gas is

saturated with water.

• Lean gas denotes an absence of the above condensable hydrocarbons.

• Dry gas has negligible water vapor content; less than 7 lbs/MMCF.

• Sour gas contains hydrogen sulfide and other sulfur compounds.

• Sweet gas denotes an absence of hydrogen sulfide and other sulfur

compounds, i.e. < 1 grain H 2 S/CCF.

Natural gas sold to the public is characterized as lean, dry, and sweet.

4
The degree to which raw natural gas is processed is to some extent

dictated by distribution and safety constraints. The water vapor must be

removed because water will promote the formation of solid gas hydrates in the

pipeline, as explained in section 3.0.

The heavier hydrocarbons such as propane, butane, pentane and above may

condense to liquid in the pipeline; accumulation of condensed liquid is a

safety hazard and will also restrict the gas flow. Thus the concentrations of

the heavier hydrocarbons are usually very low.

Hydrogen sulfide (H 2 S) must be removed since it is extremely toxic and

dangerous. It is also corrosive in the presence of air and water. The

hydrogen sulfide content of processed gas is usually limited by contract

specification to less than one grain H2 S per 100 cubic feet of gas, or less

than 1.44 lbs H 2 S per MMCF gas (approximately l6ppm H 2 S).

It is also common practice to limit the inert species (carbon dioxide and

nitrogen) to approximately 3 Vol.% of total. With the above constraints, the

heating value of the processed gas ranges from 950 to 1235 Btu/ft 3 [14.73 psia

& 60 °F]

Before final distribution, the utility companies add a commercial odorant

to the gas; the odorant is a mixture of mercaptans, aliphatic sulfides, or

cyclic sulfur compounds. The concentration ranges from 0.25 to 1.5 lbs

odorant per MMCF gas.

The processed gas is normally particulate free, but will entrain pipeline

scale and rust at high flow rates. The explosive and flammability limits of

natural gas are very close to those for methane (5-15 Vol.$). Processed

natural gas from different sources is sometimes blended in the field to adjust

the heating value, or it may be blended with propane or vaporized LNG.

5
Moreover, there are some utilities that blend air with natural gas to decrease

the heating value.

6
3.0 Water Content of Natural Gas

Processed natural gas contains only a negligible amount of water vapor

(moisture). The water must be removed because solid gas hydrates will form at

temperatures well above 0°C, at prevailing pipeline pressures of 400 to 800

psig. The buildup of these ice-like crystals can restrict or stop pipeline

gas flow. Water is easily removed during processing by absorption using

hygroscopic liquids or by adsorption on activated solid desicants such as

molecular sieves. The usual process is to use diethylene or triethylene

glycol in an absorbtion tower. Within the continental United States, the

natural gas contract specifications almost always limit the water content to

the range of five to seven pounds per million cubic feet of gas (5~7 lbs

H 2 0/MMCF). At 14.73 psia and 60°F, this is equivalent to 105 to 147 ppm

water, respectively.

Various terms are used to characterize the amount of water vapor in

natural gas, and one has to be very careful with this terminology. Most of

the processed natural gas sold in the United States has only a negligible

amount of water vapor as explained above. Throughout the Natural Gas Industry

this is called processed gas, dry gas, and as-delivered gas. However, in the

strict sense of the word, the gas is not absolutely dry. It still contains up

to 1 47 ppm water

Therefore, in order to keep in step with current terminology, natural gas

with zero water vapor content will be called absolutely dry gas, and natural

gas with less than 7 lbs H 2 0/MMCF will be called dry, processed, or

as-delivered natural gas.

At the other extreme we have saturated natural gas which is completely

saturated with water; this definition is straightforward with no confusion.

7
At 60°F the vapor pressure of water is 0.25611 psia. Thus saturated natural

gas at 14.73 psia and 60 °F contains

0.2561 1 1.7387 Vol.56 Water

14.73

X “ ;

in parts per million this is 1 7,387 ppm. Thus saturated natural gas will hold

a significant amount of water; water of course is inert and will decrease the

heating value of dry gas. If a given source of absolutely dry gas had a

heating value of 1000 Btu/ft 3

, the same gas saturated with water vapor would

have a heating value of

1 00 - 1.7387 v innn Btu _ 982.6 Btu

100 ft 3 ft 3

This is a significant decrease.

For comparison, the same gas with as-delivered water content of

7 lbs/MMCF (I47ppm) would have a heating value of

10 6 - 147 „ nnn Btu 999.85 Btu/ft 3 10 e x iuuu

ft a

Thus the as-delivered water content has negligible effect on the heating value

of the gas.

The one area where saturated natural gas is encountered is with

combustion calorimetry. The gas is necessarily saturated as it passes through

the calorimeter, and the heating value recorded is for saturated natural gas.

8
In order to determine the heat content of the same absolutely dry gas, one

merely divides by 0.9826, as shown below. Using the saturated value of 1020

Btu/f

3

,

1020 Btu/ft 3 [sat] 1038 Btu/ft 3 [dry]

0.9826

Figure 3.1 shows the water vapor content of natural gas at 14.73 psia and 60 °F

for various dew-point (saturated) conditions of temperature and pressure.

9
WATER

VAPOR

CONTENT

(lbs H

z

O/MMCF)

Water Content of Saturated Natural Gas

*Cubic feet<? 14.73 psia & 60°F

Reprinted from: AGA GAS MEASUREMENT MANUAL (Revised), GENERAL - Part No. One. Permission granted by American Gas Association, Distribution Measurement and Transmission Measurement Committees of the Operating Section.

Figure 3,1

10
4.0 Heating Value of Natural Gas

There are two basic definitions for the heating value of a fuel gas: one

is the gross or higher heating value (HHV), and the other is the net or lower

heating value (LHV). The difference between the two depends on the state of

the water product of combustion; i.e., whether the water is in the liquid or

vapor state.

The stoichiometric chemical reaction for the combustion of methane is

CH„ + 20 2 + 2H 2 0 + C0 2

The products of combustion are water and carbon dioxide. When the reactants

and the products are at the same initial conditions of pressure and

temperature, the exothermic heat of combustion is dependent upon the state of

the water in the combustion products. If the water is in the liquid state,

the heat of combustion is called the gross or higher heating value. If the

water is in the vapor state, the heat of combustion is called the net or lower

heating value. The difference between the two values is, of course, the

latent heat of vaporization of the water product.

The gross or higher heating value is the term most widely used in the

natural gas industry probably because the widely used combustion

calorimeters measure the gross heating value.

There are three basic methods or instruments for measuring the heating

value of natural gas, and all three are currently used.

1 ) combustion calorimeters

2) flame titrators

3) gas chromatographs

The combustion calorimeters have been widely used for years and there are

still many in service. The calorimeters must be located in a temperature

controlled environment, and the response time is on the order of several

11
minutes. The calorimeters have a water bath and measure the gross heating

value of saturated gas. The specific gravity has to be measured with another

independent instrument.

There are several types of flame titration instruments available. They

all operate on the basic principle that the heating value of a gas or gas

mixture is proportional to the flame temperature of a stoichiometric mixture.

Several methods are being used to sense the optimum stoichiometric ratio: one

method is to measure the flame temperature, and another is to sense the oxygen

content of the combustion products. The flame titrators have a response time

of approimately 20 seconds; a temperature controlled environment is not

necessary; and some instruments are also capable of measuring the specific

gravity of the gas.

The gas chromatographs are even more sophisticated and more expensive,

but they also provide all the information necessary to calculate heating

value, specific gravity, the compressibility factor, and mole percent of inert

gases. The mole fraction of all species except water is routine output.

Recently, there has been agreement on a standard method (ANSI/ API-2530 , second

edition) [11] of calculating the heating value of natural gas from mole

fraction analysis. Previously, there were several different methods of

calculation, from several trade associations, with no complete agreement

between methods.

It should be clearly pointed out that the heating value of a gas or gas

mixture is for a cubic foot of gas at specified conditions of temperature,

pressure, and moisture content; in addition one has to indicate whether it is

gross or net heating value. Each of the above qualifiers must be clearly

specified if the heating value (energy content) is to be meaningful. For

12
example, if the gross heating value of as-delivered gas is 1020 Btu per cubic

foot at base conditions, the heating value should be written as follows:

Gross

1020 Btu/ft

3 60 °F & 14.73 psia

as-delivered moisture

The heating value normally encountered in the natural gas industry is the

gross heating value for as-delivered gas, at some specified pressure and

temperature base. The heat or energy content of natural gas is increasingly

important, because the trend is definitely toward the more equitable method of

selling gas on an energy content (Therm) basis.

13
5.0 Volume Measurement of Gas

There are three basic types of meters being used to meter natural gas

delivered to government installations: these are orifice meters, turbine

meters, and positive displacement meters (rotary and diaphragm types). The

type of meter best suited for a given installation depends on the following

parameters

• The range of gas flow required during the winter and summer months,

• The service gas pressure at the meter (this varies from 10 to 150 psig),

• The temperature extremes the meter will incur,

• The physical size of the meter,

• The possible use of parallel meters —often meters are installed such that

a parallel secondary meter cuts in at a predetermined high flow rate

through the primary meter,

• The maintenance and service time the utility company is willing to devote

to a meter station,

• The presence of dirt or scale at high flowrates,

• The presence of heavier hydrocarbons (>C 4 ) that would tend to condense at

colder temperatures.

As an integral part of the meter, there are various types of indexes,

instruments, and chart recorders that are used to record and indicate the

accumulated volume of gas that has flowed through the meter. These are

explained in detail in a later part of this section.

Natural gas entering government bases flows through the primary service

meters at various temperatures and pressures. The metered temperature and

pressure are dependent upon geographical location, the ambient temperature,

the delivery pressure in the service line, and the amount of isenthalpic

expansion (pressure reduction) just upstream of the meter. The metered gas

14
pressure and temperature are usually continuously monitored and recorded,

except for the small diaphragm meters.

However, it is necessary to buy, sell, bill, and measure heating value in

terms of a cubic foot of gas at a certain pressure, temperature, and moisture

content. This is usually referred to as a base or billing pressure and

temperature. The prevalent and most popular base temperature and pressure in

the natural gas industry is 14.73 psia and 60 °F; however, some utility

companies use other pressure bases such as 14.65 psia. The base temperature

of 60°F is used almost universally.

So, after metering the incoming gas at the delivery pressure and

temperature, it becomes necessary to convert the metered volume to a new

volume, at the billing base temperature and pressure.

In order to convert the metered volume to the base billing volume, we use

two gas laws, plus a correction to account for the deviation from one of the

laws. Each of these laws and the correction will now be discussed separately.

• Charles 1 Law

Charles 1 law states that if the pressure of a given quantity of gas is

held constant, the volume will vary in direct proportion to the absolute

temperature. Expressed as an equation, we have,

This is a simple linear correction. For example, if the metered gas

temperature was 20 °F at some cold location, in order to correct that metered

volume to a base temperature of 60 °F, we would first convert the 20° and 60°F

temperatures to the absolute Rankine temperature of 460 + 20 = 480°R, and

460 + 60 = 520 °R. The new volume at the base temperature of 60 °F would be:

V

Constant ] (1 )

15
V 520 = 1.0833 X V 480

The above calculation assumes that the pressure is constant at both

temperatures. Thus, Charles' Law is a simple linear temperature correction,

however, one must be careful to use absolute temperature values.

• Boyle's Law

Boyle's law states that if the temperature of a given quantity of gas is

held constant, the volume varies inversely with the absolute pressure.

Expressed in equation form, we have

^ , or P j

x = P 2 V 2 , or PV = Constant ] T

(2)

This is a straightforward linear correction provided the gas is an ideal

gas. For example, if gas was flowing through a meter at 60 °F and 60 psig, and

the metered volume was to be converted to a billing base of 60 °F and 14. 73

psia, the correction procedure would be as follows.

First convert the pressures to absolute values:

60 psig + 14.4 psia (atmospheric pressure) = 74.4 psia

and 14.73 psia is already an absolute value.

Thus, the metered gas volumes converted to the billing base volume § 60°F

and 14.73 psia would be

Xbaae. . =

pm&tar.

j or

vmet er p base

„ 74.4 psia _ „ “base -

ii|. 73 psia

x v meter*

Charles' and Boyle's laws are often combined to give an "Ideal Gas Law"

in the form,

= -ir-2- = Constant (3)

16
However, natural gas does not behave as an ideal gas at pressures above

- 60 psia. This non-ideal behavior is accounted for by a correction term

called the compressibility factor, almost always designated as Z. A

compressibility plot for the major constituent of natural gas (methane) is

shown in figure 5.1.

The equation of state for an ideal gas (Z=1) is

PV = nRT* (4)

and the virial equation of state for a real gas (Z*1 ) becomes

PV = nZRT. (5)

The compressibility factor (Z) is a correction factor to compensate for

the non-ideal nature of real gases at higher pressures. The compressibility

factor is a function of pressure and temperature, and one should note from

figure 5.1 that the compressibility factor for methane (and natural gas) can

be significant at higher pressures and especially at lower temperatures.

At the natural gas wholesale level, base pressures of 600 - 800 psig are

common at orifice meter custody transfer stations, and the compressibility

correction becomes significant. At the other extreme, the compressibility

correction for gas at about one atmosphere flowing through a small diaphragm

meter is negligible.

If we put equation 5 in a different form as shown below

nZRT

V ~ P

it is easier to see how the compressibility correction manifests itself for

volume measurements that are different from those of an ideal gas.

*R = The universal gas constant

P & T are absolute pressure and temperature

17
18
For instance, in a positive displacement metering application, we measure

temperature, pressure, and volume through the meter. The temperature and

pressure are correct values, and R is a constant. Thus if Z * 1 , the volume

has to vary proportional to Z. The bottom line is:

• If Z = 1, the volume measurement will be the same as for an ideal gas.

• If Z is less than 1

, the volume measured is less than that of an ideal

gas.

• If Z is more than 1 , the volume measured is more than that of an ideal

gas.

In summary, there are three factors that have to be applied to metered

gas volumes (excluding orifices) in order to convert the volumes read on the

meter to a volume at base or billing conditions.

• A linear temperature correction (Charles' Law)

• A linear pressure correction (Boyle's Law)

• A compressibility correction (deviation from ideal gas behavior)

These three adjustments to metered volumes for the various gas meters will be

demonstrated in the following sections.

19
5.1 Turbine Meters

Turbine meters are becoming increasingly popular for natural gas

measurement in the U.S. at the retail level. All of these meters will

accommodate indexes and correcting instruments, thus making a compact, low

maintenance metering unit. A cross-section of a typical turbine meter is

shown in figure 5.2.

Turbine meters infer the volume flow through a pipe from the rotation of

a turbine blade in the flow stream. The incoming gas is forced into an

annular zone on the perimeter of the nose cone where the kinetic energy of the

gas displaces the rotor blades to make the rotor spin with an angular velocity

proportional to the velocity of the gas. A mechanical or electric readout is

calibrated to give volume flow through the meter.

A typical accuracy curve for a turbine flowmeter is shown in figure 5 . 3 .

At flow rates less than 10? of rated capacity the turbine meter deviates

sharply from the calibration curve. However, these meters typically have a

nice flat calibration curve over the upper 90? of their rated capacity, as

indicated in the figure.

The recommended installation configuration for an in-line gas turbine

meter is shown in figure 5.4. A strainer or filter upstream of the meter is

absolutely necessary to minimize contamination of the rotor bearings and to

prevent damage to the rotor blades by larger particulates such as scale and

rust. The use of straightening vanes upstream of the turbine meter is also

recommended. Straightening vanes minimize cross-currents and swirl set up by

upstream piping components. A typical straightening vane or "tube bundle" is

shown in figure 5.5.

There are various types of straightening vane modules available: square,

round, and hexagonal tubes. Whatever the shape, the cross-section geometry

20
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Recommended

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Used

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American

Gas

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Vane

Bundle

24

Figure

5.5
should be symmetrical. Straightening vanes are used to minimize swirl and

cross currents in the flow stream that are caused by pipe fittings, valves,

and regulators upstream of the meter. Additional design specifications for

straightening vanes can be found in A.G.A. Report No. 7 , Measurement of Gas by

Turbine Meters [4 ]

Most utility companies will install a by-pass around the gas meter piping

so that the meter can be serviced without interrupting gas service to the

customer

One disadvantage of turbine meters is their susceptibility to damage by

overspeeding. They can be operated up to 1 50% of their rated capacity for

short periods; beyond that, damage to the rotor or bearings will probably

occur. There are two precautions to protect against overspeeding:

1 ) Pressure blow-down valves should be located downstream of the meter and

be sized properly.

2) A critical flow orifice or sonic velocity nozzle may be installed

downstream to limit the flow to 120? of the meters maximum rated

capacity, provided adequate pressure is available. The sonic nozzle is

more desirable since it has considerably less permanent pressure loss

than the orifice.

In addition to the recommended installation configuration shown in figure

5.4, the A.G.A. also has short-coupled and close-coupled installation

recommendations for in-line gas turbine meters. These are also given in the

A.G.A. Report No. 7 [4]. A photo of a typical turbine meter installation with

an upstream strainer and a correcting instrument with a chart recorder is

shown in figure 5.6.

The advantages and disadvantages of gas turbine meters are listed below:

25
26

Photo

of

a

turbine

meter

installation
Advantages

• Comparatively small in size,

• Maintenance on the meter and recording instrument is minimal,

• The meter inner works can be easily removed for a spin test, and may be

easily interchanged with little down-time.

• A spin test to determine the mechanical friction in the meter mechanism

is easily conducted.

• Variable rangeability, dependent on inlet pressure (18 @ 0.25 psig and 50

@ 100 psig).

Disadvantages

• Upstream strainers and possibly filters are necessary; particles of

significant size can cause rotor blade damage or may wipe out the entire

rotor

• The rotor bearings are subject to contamination by dirt or debris in the

gas stream. In past years bearing failure has been a problem area for

process gas turbine meters.

• Gas turbine rotors are subject to overspeeding. Rotor speeds exceeding

1 50% of rated capacity can easily damage the rotor.

Any deterioration in the performance of a gas turbine meter due to increased

mechanical friction or missing rotor blades will almost always decrease the

rotor speed and thus record a lower flow rate than actual. This of course

favors the buyer downstream rather than the upstream supplier.

5.1.1 Calculation of Base Volumes

A gas turbine meter may have an index output (dial or digital) that gives

cumulative volume flow at the temperature and pressure of the gas flowing

through the meter. Thus we have a cumulative volume at a flow temperature and

pressure, but we need a billing volume at a base temperature and pressure.

27
The task is to convert the volume read on the meter to the billing or base

volume.

The general equation for the gas at each set of conditions is:

For the meter,

(Pf)(Vf) = (Z f )(n f )(Rf )(Tf ) Flowing Conditions

For base conditions,

(P b )(V b ) = (Z b )(nb )(Rb )(Tb ) Billing Conditions

where

P = absolute pressure

V = volume

Z = compressibility factor

n = number of moles of gas

R = universal gas constant

T = absolute temperature

and the subscripts,

f = flow conditions

b = base or billing conditions

Now if we combine both of the equations above and solve for the base

volume V b , we have

Vb VbVb

P fv

f

" z

f nf

R

f

T

f or

V = V

b f

The number of moles of gas at each state is the same, so

n.

n. = 1

28
Similarly, the universal gas constant at both states is the same, so

Thus, the equation for reduces to

Z b and Zf are the compressibility factors for the gas at each state (flow and

base). The compressibility factors account for the compressibility of the gas

at each state; this term is sometimes referred to as a correction for the

deviation from Boyle’s law.

The ratio Z^/Zf is properly called the compressibility ratio, and it is

designated by (s). Thus,

z—b

= s = Compressibility Ratio.

Z

f

This ratio is often called various other incorrect names such as

supercompressibility , supercompressibility factor, supercompressibility

effect, etc., all of which are misnomers and incorrect. The

supercompressibility factor is a similar compressibility correction term which

applies only to the flow of gas through an orifice meter; this is fully

explained in Section 5.3.

The compressibility ratio (s) can be easily found in table 10.5 of the

A.G.A. Report No. 7 , Measurement of Gas by Turbine Meters [4]. The table is

for a hydrocarbon gas with a specific gravity of 0.6; the specific gravity of

natural gas is not always 0.6, but it is usually very close. The table is for

base conditions of 14.73 psia and 60°F, thus = 1. To use the table, one

merely selects the proper value of (s) for the flow (meter) conditions of

29
pressure and temperature. If the flow temperature were 20°F f and the flow

pressure were 100 psig, s = Z b /Zf = 1.0209. The compressibility factor (Zf)

for natural gas at high pressures and low temperatures has values less than

one, as indicated in figure 5.1. Thus in this case Zf = 0.9795. With the

compressibility ratio, we now have all the information necessary to correct

the metered volume to a base billing volume. As an example, assume the

following:

• The average monthly gas temperature at the meter = Tf = 20 °F.

• The regulated gas pressure at the meter = Pf = 100 psig.

• The difference in meter readings for the monthly billing period =

644 MCF.

We first have to convert to absolute pressures and temperatures. Our base

temperature = 60°F, we convert this to absolute Rankine temperature by adding

460. Thus,

Tb

= 60 °F + 460 = 520 °R . Similarly Tf

= 20 °F + 460 = 480°R .

To convert to absolute pressure, the atmospheric pressure P a must be

known. This is usually specified in the gas contract. We will assume

P a

= 14.4 psia. Our meter or flow pressure is gauge pressure (psig) plus the

atmospheric pressure (P a ); (Pf = Pg + P a

). So our flow pressure (Pf) = 14.4

psia + 100 psig = 114.4 psia . The billing base pressure is already given in

absolute units of 14.73 psia.

The expression becomes,

V b = 644MCF x 1 .0209

520 °R 114.4 psia

X 480 °R

X 14.73 psia

30
V b

= 644MCF x 1.0209 x 1.0833 x 7.766

Vh = 5532 MCF [14.73 psia & 60°F].

So the 644 MCF of gas that flowed through the meter @ 100 psig and 20 °F would

occupy a volume of 5532 MCF at a pressure of 14.73 psia and a temperature of

60 °F.

With the delivered gas now converted to billing base conditions, the

customer can be billed for the gas on either a volume basis (MCF) or on an

energy basis (Therms).

If the gas were sold on a volume basis at a price of $4.75/MCF, the

monthly bill would be

$4.75 5532 MCF = $26 , 277 . 00/month

MCF

X month

If the gas were sold on an energy basis, the calculation would be as

follows. Assume:

• The average monthly heat content of the as-delivered natural gas is 1032

Btu/f

3 [60 °F & 14.73 psia].

• The price of gas is 46 cents/Therm or $4. 60/dekaTherm.

(1 Therm = 100,000 Btu and 1 dekaTherm = 1,000,000 Btu)

The monthly gas bill would be,

On a Therm basis :

5532 MCF .. 1000 ft 3 ..1032 Btu .. $0.46 . 1 Therm $26 ,262/month

month

X MCF

X ft 3 X Therm

X 100,000 Btu

On a dekaTherm basis :

5532 MCF .. 1000 ft 3

.. 1032 Btu $4.60 1 dekaTherm $26 ,262/month

month X MCF

X

f

3 X dekaTherm X 1,000,000 Btu

So, regardless of whether the gas is sold on a volume basis or an energy

content basis, the gas flowing through the meter has to be converted to cubic

feet of gas at base conditions. Once we have the volume at base conditions

31
( Vj-j) » the gas can be sold on a volume basis @ $ per MCF, or it can be sold on

an energy content basis @ $ per Therm. However, if the gas is to be sold on

an energy content basis, we have to know the heat content of

at the base conditions. This is another reason why it is so

establish base conditions of temperature and pressure and to

such as heat content with respect to that base.

the delivered gas

important to

take measurements

32
5 .2 Gas Displacement Meters

The gas flowing through this type of meter occupies a definite volume

within the meter rather than spinning a rotor as with the turbine meter.

There are two main types of displacement meters: rotary and diaphragm.

Positive displacement meters have the desirable feature that upstream flow

stra ighteners or conditioners are not required; thus installation

configuration is not as critical as with some of the other type meters.

5.2.1 Rotary Displacement Meters

Rotary displacement meters operate on the principle of measuring gas (or

liquid) that fills voids or chambers of given volume as the gas flows through

the meter. The chambers are usually created by rotary lobes of figure-8

cross-section or rotary worm drives. Rotation results from the flow of gas

through the meter. These meters have very close tolerances between the

rotating lobes, between the lobes and the semi-cylindrical shells, and the

lobe end plates; precision machining and assembly is necessary. A photo of a

typical lobe-type rotary displacement meter is shown in figure 5.7.

Rotary meters are normally used for large volume flow measurement applications

such as a Base service entrance or a central power plant.

New compact designs are now available in the smaller range of meters;

thus a wide range of sizes (flow capacities) are now available. The inherent

design of these meters make them suitable for high pressure applications.

Standard meters with working pressures of 300 and 600 psig are available and

special meters with 1200 and 1400 psig working pressures can be purchased.

The capacity of rotary meters is limited by the permissible speed of the

rotating parts, and overspeeding must be prevented by using an orifice or

sonic nozzle downstream of the meter. Restricting orifice plates are usually

sized to cause critical flow § approximately 120% of rated meter capacity.

33
A typical lobe type rotary displacement meter

Permission granted by Dresser Industries Inc Dresser Meter Division.

HI

Position 1. As bottom impeller rotates In counterclockwise direction toward

horizontal position, gas enters space between impeller and cylinder

f§I[ jv,

W jr

Position 2.

In horizontal position, a definite volume of gas is contained in bottom

compartment.

\£/ Position 3. As impeller continues to turn, the volume of gas is discharged.

Position 4. Concurrently, top impeller rotating in opposite direction has trapped

a definite volume of gas in its horizontal position, confining another known

and equal volume of gas. Process is repeated four times for each complete revolution of impeller shafts. Flow of gas creates the rotation of impellers

Figure 5,7

34
The rotary meters are normally sized for maximum load @ 50 to 100$ of their

rated capacity. The rangeability of these meters is typically fifty to one.

A typical performance curve for rotary lobe meters is shown in figure 5.8.

The accuracy suffers at low flow rates because a greater percentage of the

total gas flow slips past the lobe clearance passages.

One desirable feature of these meters is the ease in which the condition

of the meter may be checked. The pressure differential (AP) across the meter

during operation gives a good indication of rotating friction as well as lobe

clearance passages. Pressure taps are provided on most of the rotary meters

so the pressure differential can be measured without altering the meter flow

or taking the meter run out of service. A curve indicating the normal AP

across the meter is usually provided by the manufacturer as shown in figure

5.8.

A complete line of indexes, correcting instruments, pulse transmitters,

and telemetering equipment is available for rotary displacement meters.

The advantages and disadvantages of the rotary displacement meters are

given below:

Advantages

• High pressure capability,

• Simple, quick method of checking condition of meter,

• Reliable design -- proven low maintenance,

• Broad operating temperature range (-40 °F to 140/250°F),

• Upstream flow straighteners are not necessary.

Disadvantages

• Close tolerance construction,

• Overspeeding must be prevented,

• The larger meters are noisy,

35
FLOW

RATE

AT

INLET

CONDITIONS -

CFH

(Multiply x

100)

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36
• Limited rangeability (22 to 77, dependent upon model).

The procedure for calculating base billing volume from metered volumes is

the same for the rotary and diaphragm meters; a sample calculation will be

presented at the end of the next section on diaphragm type positive

displacement meters.

5.2.2 Diaphragm Displacement Meters

Diaphragm type displacement meters also have chambers of a given volume

that measure the gas as it flows through the meter. There is a wide range of

sizes available ranging from 100 to 10,000 SCFH. A cross-section of a typical

diaphragm meter is shown in figure 5.9. Diaphragm meters are excellent

measuring devices from practically zero flow up to their maximum rated

capacity. They have an excellent rangeability of 100:1, and are preferred for

applications with cyclic loads. These meters also have the desirable feature

that the measuring module can be easily replaced; most of these meters have a

horizontal bolted flange which affords easy removal of the measuring module.

One unique characteristic of these meters is that they must be set level.

Most of the newer diaphragm meters have an aluminum case and the

operating pressure is 100 psig or less. However some of the meters can be

purchased with a ductile iron body and cover with a pressure rating of 500

psig.

Another desirable feature available on most of the meters is temperature

compensation (correction to a 60°F base) within the meter. The temperature

compensated meters usually have a red badge or nameplate. For low pressure

metering applications, this allows one to use a temperature corrected meter

with a simple index, and get a temperature corrected volume reading without

correcting instruments. Small diaphragm type gas meters are used for most

37
index Driving

Movement

Valve Cover

Valve Seat

L/F* Main

Movement Assembly

L/F* Diaphragm.

Carrier Bracket

Synthetic

Diaphragm

Prime Dip & Electrostatic

Spray Finish Paint

Hub

Sealed Index Box

Index

L/F* Tangent

Crank

Temperature

Compensation Unit

Diaphragm Carrier

Wire Assembly

Die Cast Aluminum Covers,

Center & Top Casting

*Lubrication-Free

Typical diaphragm type positive displacement meter

Figure b.9

Courtesy of Sprague Meter Division

of Sangamo Weston Inc.

38
residential housing throughout the U.S. Large diaphragm meters are used on

many commercial buildings and for sub-metering at Government Bases.

A typical accuracy curve for diaphragm meters is shown in figure 5.10;

the factory calibration accuracy is within ±\% over the meter operating range.

A photograph of a large diaphragm meter with a pressure correcting instrument

on top is shown in figure 5.11.

The advantages and disadvantages of diaphragm type displacement meters

are shown below:

Advantages

• Good rangeability, (100 to 1)

• Temperature compensation available

• Measuring module is easily replaced.

• Large selection of sizes

• Negligible accuracy deterioration at low flow rates

• Flow straighteners are not necessary.

Disadvantages

• The aluminum case meters have a maximum pressure of 100 psig.

• The high capacity meters are physically large and must be set level.

• Diaphragm meters should not be operated at extremely low or extremely

high flows for an extended period of time; at low flow rates, the leakage

becomes a significant portion of total flow, and extended service at high

flow rates causes premature wear.

39
AoBjnoov iu0OJ0d

CD

i—

LA

LU

CCZD

CD

Li40

Courtesy

of

the

American

Meter

Company
Large diaphragm meter with a pressure correcting instrument

Figure 5,11

41
5

2.3 Calculation of Base Volumes

A typical example of a diaphragm type meter calculation would be as

follows

Assume

• The diaphragm meter has the temperature compensated option; thus the

volume readings on the meter index are already temperature corrected to

60 °F

• The meter has a simple index attached which senses only meter

revolutions; there are no temperature, pressure, or compressibility

corrections within the index.

• The average barometric pressure at the location is 14.4 psia, and the

pressure regulator upstream of the meter is set for 4 ounces (0.25 psid)

pressure differential with respect to atmospheric pressure, P a

. Thus the

meter pressure averages 14.4 + 0.25 = 14.65 psia throughout the year.

• The meter index reading for the billing period is 644 MCF (present less

previous meter readings).

Given

• The billing base for the utility company is 60°F and 14.73 psia.

• The compressibility correction for non-ideal gas behavior is negligible.

Thus, the calculation to determine base billing volume (the volume of the

metered gas at 60°F and 14.73 psia would be as follows:

V v

Tb Pf

= V„ x — x — x Zb

b f Tf

P b Zf

where

v b

= base billing volume

Vf

= metered (flowing) volume of gas

Tb = base billing temperature (absolute) = 60°F + 460

42
Tf = flowing gas temperature (absolute) = 60 °F + 460 = 520 °R.

Pf = absolute pressure of the flowing gas = P g

+ P a = gauge plus

atmospheric pressure.

P b

= base billing pressure = 14.73 psia.

= compressibility factor for base condition = 1.

Zf = compressibility factor for flowing condition = 1.

or,

Vb 644 MCF x 60 °F + 460

60 °F + 460

14.65 psia

X 14.73 psia

Vb 644 MCF x 14.65 psia

14.73 psia

= 640.5 MCF [60 °F & 14.73 psia]

Thus if all the gas that passed through the meter during the billing

period were placed in a chamber at 60°F and 14.73 psia, the gas would then

occupy 640.5 MCF (640,500 cubic feet).

If we further assume the price of gas is $4.75/MCF [60°F, & 14.73 psia],

the billing period gas cost would be

$4.75 x 640.5 MCF = $3,042.38 . MCF

If the gas were sold on an energy basis, and the average heating value

for the billing period was 1032 Btu/ft 3 [60°F & 14.73 psia], and the price of

gas was $4. 60/dekaTherm, the gas cost would be

644 MCF . 1000 ft 3 „ 1032 Btu „ $4.60 .,1 dekaTherm $3,057.20

X MCFX ft 3 X dekaTherm X

1 x 10 6 Btu

One should note that if the gas is to be sold on an energy content basis

(Therms or dekaTherms), the average heating value of the gas for the billing

period at base conditions (60°F and 14.73 psia) has to be known. This is why

it is most convenient to have a standard or base (of temperature and pressures

43
to measure, sell, and determine heating value of the gas at that standard

condition

If the diaphragm meter in the above example had not been the temperature

compensated type, an average temperature for the flowing gas (Tf) during the

billing period would have be measured. This would probably be done with a

thermometer well in the gas piping downstream of the meter and a chart

recorder; an average temperature for the billing period would then be

determined from the charts for that period.

If we assume the average temperature was 46 °F, the temperature correction

would be as follows:

^b 60 °F + 460

= 520°R = „ T 46 °F + 460 “ 506 °R

" '

and the base billing volume would be

V

b

644 MCF x 520 °R

506 °R

14.65 1 X 14.73

X

1 658 MCF

[60 °F & 14.73 psia].

During the past in some of the southern states, the gas contract might

specify that an average annual temperature of 60 °F may be assumed for all gas

passing through small diaphragm meters. This eliminates the temperature

correction for those meters. In the colder northern climates, the average

metered gas temperature will be less than 60 °F (since most of the gas is used

during the winter months), and it becomes necessary to measure the temperature

of the gas if it is to be sold on an equitable basis.

Since the dramatic increase in the cost of natural gas during recent

years, the trend is definitely toward measuring consumption correctly. The

larger diaphragm meters are being fitted with thermometers and charts or

correcting instruments, so the metered gas temperature can be measured

correctly.

44
5 .3 Orifice Meters

An orifice meter is a very simple and rugged meter with no moving parts,

and this is one of its virtues. An orifice meter consists of a thin plate

with a hole (usually concentric) in it and pressure taps on each side of the

plate. The plate is usually placed between two pipeline flanges, and static

pressure taps are located on both sides of the orifice plate to measure

differential pressure across the plate. The leading edge of the orifice bore

always has a sharp corner, whereas the trailing or downstream edge is

sometimes beveled. The orifice plate is securely placed in a pipeline such

that the plane of the plate is perpendicular to the axis of flow.

The hole in the orifice plate (the bore) poses a restriction to the

pipeline fluid, and a differential pressure develops across the orifice plate.

The pressure drop across the plate is a function of the fluid density and

flowrate; this is the basic principle of the meter. Orifice meters are

sometimes termed a differential producing primary device. The differential

pressure across the orifice plate is measured using static pressure taps; and

an appropriate transducer. The two popular pressure tap configurations are

termed flange taps and pipe taps. A concentric orifice plate with flange taps

is the usual configuration found in the United States for natural gas

measurements

A cross-section drawing of an orifice meter is shown in figure 5.12, with

a companion plot for the pressure profile in the vicinity of the meter. The

two most popular and most prevalent types of pressure taps are shown in the

figure. Ideally, the downstream pressure tap would be located at the vena

contracta, but this is a function of 3 ratio and flow rates, so the plane of

the vena contracta is not stationary.

45
Orifice plates with different bore diameters may be used. A term called

"beta ratio" (&) is used to denote the ratio of the orifice bore diameter to

the upstream pipe I.D.,

orifice bore diameter

pipeline inside diameter

The A.G.A. recommends beta ratio limits of 0.15 to 0.7 for flange taps.

Orifice meters are simple but they do have the strict requirements that there

be a minimum amount of straight pipe upstream of the orifice plate, and also

another smaller amount of straight pipe downstream of the plate. This is to

minimize swirl and flow profile distortions in the flow stream which cause

inaccuracy in the flow measurement. Straightening vanes may also be used

upstream of the orifice plate to minimize swirl and promote straight

streamlines. There are detailed recommended guidelines for the installation

of orifice meters in the A.G.A. Report No. 3 , Orifice Metering of Natural Gas ,

ANSI/API 2530 [1 ].

There are three parameters (measurements) from the orifice meter that are

continuously recorded, usually on a 24 hour circular chart; these are the

static pressure in the pipe, the differential pressure across the orifice

plate, and the temperature of the fluid in the pipe. These charts are

subsequently processed (read) using a special machine manufactured expressly

for this purpose. The two pressure traces are integrated with respect to time

to calculate the average daily pressure and the average differential pressure.

The static pressure values range from 50 to 200 psig at the retail level, and

from 500 to 800 psig at the wholesale level. The differential pressure ranges

from 10 to 200 inches of water. The calibration of these pressure transducers

should be checked weekly or at least every month.

46
Orifice

Meter

Installation

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co CD Eo o UL- c c/>

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CO 0 o D

CO </) o 0 o a c E

(/) 3 c E o

in .E 4-> c E JC

a>

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•rC

t- o "O 0 >>-rQ_ c Q. 4-> co jco O ro a U t-U 0) 0 a> o a jz i/> CL 1- 4-> in * «4-O un

co

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47
The temperature of the pipeline fluid is usually measured downstream of

the orifice plate, with a thermometer /well arrangement. The well is located

downstream because placing it upstream would upset the streamline flow of the

fluid. The calibration interval on the temperature transducer is not nearly

as critical. Usually, the temperature is continuously recorded on a separate

24-hour chart.

The A.G.A. Report No. 3 , Orifice Metering of Natural Gas , ANSI/API 2530

recommends that, "the upstream edge of the measuring orifice shall be square

and sharp so that it will not reflect a beam of light when viewed without

magnification, and it should be maintained in this condition at all times.

Moreover, the orifice plate shall be kept clean at all times and free from

accumulations of dirt, ice, and other extraneous material." In order to

maintain the orifice plates in proper condition, as described above, the gas

utility and pipeline transmission companies normally remove and inspect the

orifice plates every 30 to 90 days.

Orifice plates are sometimes placed directly between two flanges with

appropriate pressure taps, as shown in figure 5.13. This type of installation

requires that the line be depressurized and momentarily taken out of service

(or use a bypass) in order to inspect the orifice plate. However, most

orifice plates are positioned in the flow stream with special orifice fixtures

or fittings, with integral flange taps that afford easy removal of the orifice

plate for inspection and changeout. There are two basic types; one type of

fitting has a removable top plate which allows access to the orifice plate for

inspection, but the line must be depressurized and taken out of service during

removal of the orifice plate. A fitting of this type is shown in figure 5.14.

48
49

Orifice

plate

between

two

flanges.
50

Courtesy

of

Colorado

Interstate

Gas

Company
Another more sophisticated type of fitting allows removal of the orifice

plate for inspection or changeout without depressurizing the line or

interrupting flow. This is accomplished by cranking the orifice plate up into

a bonnet enclosure, sealing off the bonnet enclosure, depressurizing the

bonnet enclosure, removing the orifice plate, then reversing the procedure for

reinstallation of the plate into the flow stream. The bonnet type fitting is

most desirable if the orifice plate is to be inspected periodically as

required, however these fittings are expensive, especially for the larger

tranmission pipeline sizes. A photo of a 20-inch bonnet type orifice meter

fitting is shown in figure 5.15.

The ability to changeout orifice plates to a larger or smaller bore size

gives the orifice meter good rangeability. When gas consumption increases

during the extremely cold months, a plate with a larger bore can be installed,

and similarly, when gas flow is reduced in the summer months, an orifice plate

with a smaller bore can be installed in order to maintain a differential

pressure in the desirable range. The rangeability is limited by the necessity

of staying in a desirable g and AP range.

A recommended orifice meter installation is shown in figure 5.16. An

adequate amount of straight line upstream of the orifice is very important;

upstream straightening vanes are recommended; about five diameters of straight

line downstream is desirable; a bonnet type fitting for the orifice plate is

desirable; and the temperature probe should be located downstream of the

orifice. Very precise guidelines for orifice meter installation

configurations are given in A.G.A. Report No. 3 ANSI/API 2530 [1]; it is

important that orifice meter installations conform to these recommendations.

51
Bonnet type orifice meter fitting

Courtesy of Colorado FIGURE 5 u 15

Interstate Gas Company

52
Recommended

Installation

Configuration

for

an

Orifice

Meter

a

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LUHOZ * s 1 2 <- o.

00

(0

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os =© JE E T3 3 C E © c CO E 6

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LO

LU

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53
The advantages and disadvantages of orifice meters are given below:

Advantages

• Simple, no moving parts

• Reliable

• Rugged

• Good meter at extreme temperatures

• No calibration required

• Useful over a wide flow range

• Relatively Inexpensive

Disadvantages

• Periodic calibration of pressure transducers

• Periodic inspection of orifice plates

• Without a bonnet type fitting, the flow line has to be de-pressur ized for

orifice plate inspection.

5.3-

Calculation of Flow Through an Orifice Meter

We get three measurement parameters from an orifice meter:

1 ) Temperature of the flowing gas

2) Static pressure near the orifice plate

3) Pressure differential across the orifice plate.

In addition, we use the local atmospheric pressure, the local acceleration of

gravity, the specific gravity of the gas, and the mole fractions of nitrogen

and carbon dioxide to calculate the volume flow rate through an orifice meter.

The expression recommended and used almost universally by the natural gas

industry to calculate flow through an orifice is given below, and explained in

detail in the A.G.A. Report No. 3 . ANSI/API 2530 [1],

Oh = C' (Pf x hw )

1

4 [ft 3 /hr]

54
where Q b

= volume flow rate of natural gas at base temperature and

pressure, in units of ft 3 /hr,

C’ = F b

>c Frx Y x Fp bx Fbb x Fb p x Fg x FpV

x Fmx Fax F lf

Pf = the absolute static pressure in psia, and hw = the differential pressure

across the orifice plate in units of inches-of-water (water at 60 °F).

The various factors of C* are specific gravity, compressibility,

manometer and thermal expansion corrections, orifice dimensional constants,

and pressure and temperature base adjustments. Each factor is concisely

described below. Some of these factors are dependent upon the type of orifice

pressure taps.

Factors of C

*

• Fb

= Basic Orifice Factor

F

b

- 218.M d* K

q

h .

This factor is a function of the type of pressure tap, the orifice bore

size, the specific gravity, the flowing temperature, and the pressure and

temperature base.

• Fr

= Reynolds No. Factor

This factor is mainly an adjustment for the actual Reynolds number, but it

is also dependent upon the B ratio and the type of pressure tap.

E = d(830-5000B + 9000B 2 - 4200B 3 + B)

530 Where B = x for flange taps, and

( D j 2

V d Y

R . = ~7~X . d 12 y.

55
Y = Expansion Factor

This is a factor to compensate for the change in gas density between the

two pressure taps. This factor is also a function of the type of

pressure tap, and whether the absolute pressure was measured at the

upstream or downstream static pressure tap. Various expressions,

dependent upon the variables above, are given in the A.G.A. Report No. 3 ,

ANSI/API 2530 for calculating the expansion factor.

Fpt> = Pressure Base Factor

This is simply a factor to change to a new contract (or billing) pressure

base different from 14.73 psia.

Pb

14.73

Pb

' (absolute pressures)

Where P^ = the new contract base pressure in psia.

F^b = Temperature Base Factor

This is a factor to change to a new contract (or billing) temperature

base other than 60 °F. 60 °F = (460 + 60 ) = 520° Rankine.

T

b

(°R)

F^ = (Absolute Temperatures)

tb 520°R

where T^ = the new contract temperature base in degrees Rankine.

F^f = Flowing Temperature Factor

This is a factor to change from the assumed flowing temperature of 60 °F

to the actual flowing temperature Tf.

1/ r520 °R\ 2 F = [— J (Absolute Temperatures)

X 1

where Tf = the actual flow temperature of the gas in degrees Rankine.

56
• Fg = Specific Gravity Factor

This is a correction factor to put the real specific gravity of the gas

into the expression. The expression assumes a specific gravity of 1.

where G = the specific gravity of the flowing gas. The specific gravity

of air = 1

• Fp V

= Supercompressibility Factor

This is a correction factor to compensate for the compressibility of the

flow gas, or what is sometimes termed the deviation from Boyle's law.

where = the compressibility factor of the gas at base pressure, and Zf

= the compressibility factor of the gas at flow conditions.

Usually base conditions are 14.73 psia and 60°F, where Z^ = 1 . Thus the

expression for the supercompressibility factor becomes

The relationship between the compressibility ratio (s) for turbine and

positive displacement meters, and the correction term (FpV ) in the orifice

flow equation called, the supercompressibility factor is as follows:

Both are corrections for the compressibility of the metered gas at

flowing conditions, or what is often termed the deviation from Boyle's law.

However, there is a distinct difference between the two correction factors,

and they should be labelled properly.

57
For positive displacement and turbine meters:

s = compressibility ratio = Zf

For orifice meters only:

F^ = supercompressibility Factor = J^

2

.

There is considerable confusion about the above two correction factors

and the terminology used for each consists of many variations of the above.

In addition, the subscripts are often deleted to further confuse the

terminology

There are tables available for the compressibility ratio (s) that should

be used for positive displacement and turbine meters [4], and there are also

tables for the supercompressibility factor (Fp V ) for the orifice meters.

The current A.G.A. Manual for the Determination of Supercompressibility

Factors for Natural Gas [ 3 ] contains a table for the supercompressibility

factor (FpV ). However, it should be pointed out that the FpV table is for

what is termed normal natural gas mixtures. This means the table is valid for

hydrocarbon gases with a specific gravity less than 0.75, and the inerts are

limited to 15 mole percent carbon dioxide (C0 2 ) and 15 mole percent nitrogen

(N 2 ).

If the delivered natural gas is not 0.6 specific gravity, adjustment

factors for temperature (F^) and pressure (Fp) must be calculated from simple

expressions. The adjustment factors are a function of specific gravity, mole

percent C0 2 , and mole percent N 2

. These two adjustment factors are then

multiplied by the actual flowing temperature and pressure to obtain an

adjusted temperature and pressure that is then used to determine FpV f rom the

tables. This procedure is called the "A.G.A. Standard Method" of calculating

the supercompressibility factor, and is explained in detail in reference [ 3 ].

58
If an Air Force base purchases gas measured by orifice meters, the BCE

gas utility representative should definitely purchase the A.G.A. Report # 3,

ANSI/API 2530 entitled, Orifice Metering of Natural Gas [1], and the A.G.A.

companion report, Manual for the Determination of Supercompressibility Factors

for Natural Gas [3]* A complete set of FpV tables and sample calculations for

the adjustment factors are contained in these reports. The FpV tables can

also be used to determine if the supercompressibility factor is close to what

it should be; if one knows the average daily temperature and pressure of the

flowing gas, the adjustment factors can be neglected, and the Fp V from the

tables can be checked against the FpV on the gas statement to see if the two

are in close agreement.

For flowing gas temperatures of 40 to 60 °F, the supercompressibility

factor represents a correction on the order of 0.5 to 1.4 percent for metered

pressures of 75 to 150 psig (usual base service entrance pressure). However,

for transmission line pressures of 600 to 800 psig at the orifice meter, the

supercompressibility correction will be in the range of five to eight percent.

Thus at higher pressures, the supercompressibility factor becomes a very

significant correction to the metered gas flow.

• Fm = Manometer Factor

This is a correction factor to account for the weight of the gas column

above the mercury, and also to account for the change in the density of

the mercury when the mercury temperature is not at 60 °F. The above

correction factor is used when a mercury manometer is used to measure

static and differential orifice pressures. If other types of non-mercury

transducers are used the manometer factor would be omitted.

Fm

Y Y

* 846 . 324 J

59
where Ym and Yg = the specific weight of the mercury and gas

respective ly

F]_ = Location Factor

This correction factor accounts for the change in the density of mercury

due to location other than at sea level and 45° latitude, i.e., g *

980.665 cm/sec 2. This too is a correction factor that pertains to

mercury manometers only.

F = [ —— 1°* 5 1 *-980.665

where g]_ = the acceleration of gravity at the measuring location.

• Fa

= The Orifice Thermal Expansion Factor

This correction factor accounts for the expansion and contraction of the

orifice bore when the orifice plate temperature is appreciably different

from the temperature at which it was bored, assumed to be 68 °F.

For 304 & 316 SS orifice plates:

Fa

= 1 + [0.0000185 (°F-68)]

where °F = the operating temperature of the orifice plate.

At moderate temperatures, this correction is negligible.

The average values for the pressure differential (hw ) and the static

pressure (Pf) are obtained from the daily orifice meter charts. These charts

are processed by special integrating machines which give the average Pf and hw

for the measurement period (usually 24-hours).

All of the above parameters should be included as supplementary

information along with the monthly bill. A typical gas measurement statement

for two orifice meters is included in Table 5.1. This is a wholesale level

statement, but similar statements should be included for any retail level

orifice meter located on a government base. The BCE gas utility

60
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(£ o oo oo oo OO oo oo oo oo oo o oo oo oo oo oo oo oo oo oo o oo oo OO oo oo oo oo oo oo o oo oo oo oo oo oo oo oo oo “r " — H*r - - -4-^ -4—4 —r«*4 —7-3 ^-4 - - —47-3 .44 —

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61

Orifice

meter

gas

measurement

statement
representative may have to specifically ask for this additional information;

f often times, at the retail level, the utility company will send a bill

indicating only the volume (MCF’s) or energy (Therms) delivered for the

billing period. If there is to be any meaningful check of gas purchased by

orifice meter measurements, this additional information is necessary.

An explanation of the gas statement for the two orifice meters is

necessary. This statement gives information for the first ten days of

January-85. There are two orifice meters, each in the same size (8-inch

nominal) pipe, however the orifice bores are of different size (4 and 4.5

inches diameter). The pressure range of the static pressure transducer is 0

to 250 psig, and the differential pressure range is 0 to 100 inches of water.

Both orifice plates have flange taps and both transducers have a mercury

medium. The contract pressure base is 14.73 psia, and the temperature base is

60 °F. They also indicate that A.G.A. Method # 3 is used to compute the volume

and energy flow through the orifice meters.

An explanation of the information in the columns of the statement (from

left to right) follows:

• There are two different orifice meters, #12 and #22.

• The temperatures of the flowing gas is the average daily temperature for

each meter.

• The specific gravity has the decimal point missing —all those numbers are

in the range of 0.59. These values are the average specific gravity of

the gas flowing through each orifice meter for a given day.

• The static pressure has units of psig.

• The average differential pressure has units of inches-of-water (the water

@ 60 °F )

62
• The next eight columns list the daily correction factors for each orifice

(F b thru F]_ )

• The total multiplier column (C') is equal to the product of all the

correction factors (the previous 8 columns). The correction factors have

various units, and some are dimensionless.

• The machine factor column contains a constant associated with the chart

and integration machine, including hours of actual gas flow.

• The integrated differential index cycle column contains the (Pp x hw

)*4

term plus other constants.

• The volume column contains the daily volume of gas delivered in units of

MCF at 14.73 psia and 60°F.

• The Btu column contains the daily average heating value of the metered

gas in units of Btu/ft 3 [14.73 psia & 60°F].

• The column labeled THERMS gives the total energy delivered per day for

each meter; the units are Therms.

This gas statement gives the total MCF and total Therms delivered per day

or per billing period, so the gas could be sold on either basis. This

statement is complete and fairly concise, but some of the units are not

given. Units are most important. For example, the temperature base and

flowing gas temperature have units of °F. The atmospheric, contract base, and

statement base pressures all have units of psia. The static pressure has

units of psig, and the average differential pressure has units of

inches-of-water . The Btu column evidently has units of Btu/ft 3 [60°F & 14.73

psia]; all these units should be clearly specified.

The calculation on this gas statement is conducted as follows:

Total Multiplier Machine .

_

v _ Gas Volume rw„_,

/^.x x xl SXC ~ _ L MC F J (C T ) Factor Day

63
The basic A.G.A. # 3 equation for volume flow through an orifice is

Q = C' (p_ x h Y

2 [ft 3 /hr]

h ^ f w' L J

Thus in the above statement, the

Machine Factor x ISxC = (P. x h Y2 x 24 hrs. ^ f w'

Another important aspect of orifice meter gas statements is the manner in

which the correction factors and constants are listed. The gas statements

from the utility companies will vary somewhat, especially with regard to the

integration constant associated with the machine that processes the daily

charts. Sometimes the correction factors that remain constant will be lumped

together to form another constant.

The main purpose of this section is to acquaint the BCE and property

management agency personnel with the basic, fundamental orifice calculation so

that after a brief explanation of the orifice meter gas statement by the

Utility Company, BCE personnel should be able to clearly understand,

calculate, and check the monthly gas statement for an orifice meter.

64
5.4 Comparison of Natural Gas Flowmeters

Comparison of natural gas flowmeters is not straightforward because there

are so many parameters to be considered. Some of the more important factors

to be considered in meter selection are given below:

• Flow capacity

• Rangeability

• Operating pressure

• Operating temperature

• The presence of condensates

• Physical limitations on the size of meter

• Present and future compatibility with remote readout instrumentation and

flow computers

There are four basic types of meters, and each type has an optimum set of

operating conditions. Figure 5.17 shows the flow capacity range for each type

meter. The diaphragm meter is best suited for applications where the flow

rates are less than 100 SCFH, and the orifice meter is the only suitable meter

for flow rates in excess of 10 7 SCFH.

Every type of meter (excluding the orifice) has recommended operating

temperatures that are about the same. The manufacturer's recommended

operating temperature range for each type meter is given below:

Rotary displacement, -40 to 140°F

Diaphragm displacement, -30 to 150°F

Turbine meters, -40 to 165°F

If the gas meter operating temperature lies outside this envelope, an

orifice meter should be considered for the application. Orifice meters have

been used in applications where the flowing gas temperatures range from -65 t

500 °F

65
Comparative

Flow

Capacities

Of

The

Various

Type

Meters

66
The accuracy to be expected from the positive displacement and turbine

flowmeters is fairly good; all of these meters will read within a ± one

percent accuracy band with a factory calibration. Typical accuracy curves for

the turbine, rotary displacement, and diaphragm displacement meters are shown

in figures 5.3, 5.8, and 5.10 respectively. The diaphragm meters experience

minimal leakage at low flow rates, whereas the turbine and rotary displacement

meters exhibit more uncertainty at the very low flow rates.

It is more difficult to assign a measurement uncertainty to orifice

meters. There are a number of measurement factors, including fluid

properties, with individual tolerances that enter into the overall measurement

tolerance. The A.G.A. Report No. 3, ANSI/ API 2530 [1] indicates that orifice

meters are capable of an overall flow measurement tolerance of ±0.75 percent.

The ASME report Fluid Meters [2] cites examples of total measurement

uncertainties in the range of 0.72 to ±1.25 percent tolerance. Thus it

appears that properly configured and instrumented orifice meters are capable

of measurement accuracy commensurate with the turbine and positive

displacement meters.

67
5.5 Telemetering of Meter Output

Complete telemetering systems are now available for turbine, rotary

displacement, large diaphragm displacement, and orifice meters. These systems

consist of a pulse transmitter attached to the meter, wiring to an energy

management station or central computing system, then various types of flow

totalizers, recorders, and gas flow computers at the central station. Most of

the meter manufacturing companies now offer complete telemetering systems.

There is not a lot of gas telemetering equipment in the field yet, but

several utility companies indicated that telemetering equipment was being

evaluated on a trial basis. There was no telemetering equipment on the main

gas service meters at the Air Force bases visited during this study.

Telemetering of gas flow through the main service meters and the large

submeters such as at base power plants to central energy management systems

would be an ideal application for energy monitoring, management, and peak

usage determination.

Although gas meter telemetering equipment is not used extensively at

present, BCE personnel will be seeing more of this equipment in the future, as

more energy monitoring systems are installed at government bases.

68
6.0 Meter and Instrument Accuracy Checks

Periodic checks of gas meter accuracy and the associated instruments are

necessary, and usually the gas utilities have an established calibration

program, wherein the larger gas meters are checked at least once per year and

the smaller ones on a less frequent basis. The meters should be adjusted if

necessary, and a copy of the calibration results should be forwarded to the

BCE office or the Utilities Management Agency for their records (the Utility

Brochure). Copies of meter inspection and accuracy test reports are available

for inspection at the gas utility meter shop. The utility companies are

usually not nearly as concerned about the smaller diaphragm meters. They

typically have a statistical calibration program, wherein each of the smaller

meters would be checked once during an eight or ten year period.

The correcting instruments attached to the meters should also be serviced

and checked on a regular basis; the usual service interval is six to twelve

months. A typical pressure and temperature correcting instrument mounted on a

diaphragm type meter is shown in figure 6.1, and another similar instrument

often found on turbine meters is shown in figure 6.2.

With regard to orifice meters, there are three critical

measurements: the static pressure, the differential pressure, and the

temperature. The calibration of the two pressure transducers should be

checked every two to three weeks, and at least every month. The temperature

sensors are much less apt to deviate from calibration, and don’t have to be

checked as often.

Turbine meters are normally given a spin-time test in the field to obtain

an indication of the total friction within the meter. A stream of air is

directed toward the rotor to get it up to speed, then the time required for

the rotor to cease moving is the criterion used to determine the condition of

69
70

Pressure

and

temperature

correcting

instrument,

odometer

type

readout
Permission granted by

Mercury Instruments Inc.

Pressure and temperature correcting instrument

with odometer type readout and dial type index

Figure 6,2

71
the bearings and other moving parts. If there is a significant decrease in

spin-time, the measuring module should be removed for additional service in

the meter shop. The accumulation of dirt and foreign particles is one of the

weak points of the turbine meter, however filters (strainers) are almost

always used upstream to protect the meter. The spin-time test is easily and

quickly conducted in the field.

Another desirable feature of most turbine meters is that they are

constructed such that one bolted flange separates the measuring module of the

meter from the in-line body or housing; thus a replacement metering section

can be bolted into the meter housing very quickly if necessary.

Instructions about how to conduct a spin-time test on a turbine meter are

given in the A.G.A. manual , Measurement of Gas by Turbine Meters , Transmission

Measurement Committee Report No. 7 , 1985 [M]. The typical spin times for

turbine meters are listed in the manufacturer's service manuals for the given

meter

Rotary displacement meters are also easily checked in the field; these

meters are checked by measuring the differential pressure (AP) across the

meter without even disturbing the measurement process. Most of the rotary

meters have pressure taps right on the meter housing, and a AP curve vs. flow

is supplied by the meter manufacturer (see figure 5.8). Any significant

deviation from the usual differential pressure is a good indication that the

meter should be pulled and sent to the shop for servicing. Instructions for

checking the differential pressure across the meter are usually given in the

manufacturer's meter manual.

The large diaphragm displacement meters are usually checked in-place in

the field with some type of portable transfer prover. The small residential

type of diaphragm meters are usually checked less often in the meter shop with

72
a bell prover. In that regard, most of the government gas contracts stipulate

that a government representative shall have the right to witness the

calibration of service gas meters. Thus, BCE employees should feel free to

request an invitation to witness the accuracy check of their gas service

meters

73
7.0 Gas Service Meter Stations

There are usually one or more meter stations near the boundary of an Air

Force base, wherein the gas utility service line feeds natural gas into the

base distribution system. The meter station serves to regulate the pressure

to the base distribution system and to meter the gas going into the base.

There are also shutoff valves in case of emergency, and relief valves in case

of regulator valve malfunction.

The plumbing sequence at a meter station usually consists of the

following

The gas utility service line entrance (75 to 500 psig), scrubber or

filter, shutoff plug valve, pressure reducing valve, pressure relief valve,

line heater (extreme cold areas), strainer or filter, flowmeter, flow limiting

restriction, shutoff plug valve, base main line gas distribution system. In

addition, there is usually a by-pass loop with a shutoff valve around the

flowmeter section; thus gas can be routed through the by-pass in case of meter

changeout or malfunction.

A typical meter station would be located outdoors but within a locked,

fenced-in area, as shown in figure 7.1. Some meter sets are located inside a

small meter house with the relief valves vented to the outside and shutoff

plug valves located just outside the house on both the entrance and exit lines

The meters are serviced and read periodically by the gas utility field

personnel who have keys to the meter stations.

The utility company almost always has responsibility for maintenance of

the meter station components, including the periodic calibration of the meters

The utility company also has responsibility for any leaks at the meter station

Any perceptible leakage should be reported to them immediately, especially if

74
75

Typical

outdoor

meter

station,

Eglin

AFB
the meter station is enclosed by a building. The lower flammability limit

of methane is extremely low - 5 Mol.% in air; thus one has to be very careful

about walking into meter houses where there is gas leakage in the meter

station piping. It should be pointed out, however, that most of the meter

houses are well vented to the outside.

The Government usually has responsibility for all piping and components

down stream of the Base meter stations, including corrosion control of the

Base gas distribution piping.

Sometimes it is necessary to install a scrubber or filter unit just

upstream of the meter station. These units are necessary when the incoming

gas contains particulates or entrains scale or rust from the pipeline inner

surface at high flow rates. A typical oil type scrubber is shown in figure

7.2.

In some areas of the U.S. line heaters (fired by gas) are used to heat

the incoming natural gas to prevent excess ice build-up on the outside of the

line downstream of the pressure reducing valve. These are used in extreme

cold areas such as Minot, North Dakota and also in cold, humid areas such as

Tacoma, Washington. In all cases where heaters are used, there is an

isenthalpic expansion at the pressure reducing valve providing refrigeration

to the low pressure side of the line. The ice build-up on the outside of the

piping becomes a problem because it will cause stress in the meter station

piping and has broken pipes in some instances.

The other concern is that some of the heavier hydrocarbons may condense

to liquid downstream of the pressure reducing valve. Still another concern is

the operating temperature of the downstream gas meter. The gas temperature

must not fall below the minimum operating temperature of the

meters, usually -20 to -40 °F.

76
Figure 7.2

77
The line heaters are provided and maintained by the utility company, and

fired by natural gas tapped off upstream of the meter. Thus, the Air Force

Base is not charged for the heater fuel. BCE personnel normally have little

concern with these heaters, but they should be aware of their purpose and

function in case of any malfunction or emergency. The gas service line heater

at Minot AFB is shown in figure 7-3.

78
79

Gas

service

line

heater

at

Minot

AFB
8.0 Utility Bills

There are many variations in the format and the amount of information on

the gas utility bills received by Air Force bases across the U.S. Some of the

bills are fairly complete with all of the correction factors listed

separately. Others list just one composite correction factor, while others

have vital information missing, or the units are not clearly labelled.

Usually, all the gas from one utility company serving various entrance meters

at a base will be billed conjunctively, i.e., all the gas meters will be on

the same bill. The units listed in Section 1 .0 are the units or acronyms

usually encountered on the bill, with few variations.

80
8.1 Methods of Selling Gas

There are three major methods of selling natural gas to Government Bases

in the United States:

(1 ) One method is to sell strictly on a volume basis with a guaranteed

minimum energy content (heating value) for the gas.

(2) A second method is to sell on a volume basis with an energy content

window; the price increases slightly if the heat content of the gas rises

above the energy content window, and similarly, the price decreases

slightly if the average heat content of the gas falls below the window.

The correction factor is usually called the Btu factor on the bill. The

calculation usually goes as follows:

Assume the energy window is 980 to 1020 Btu/ft 3

. If the average monthly

heating value of the gas lies within the above interval, the Btu factor

would be one (1.0). Any values outside the window would be divided by

the average window value of 1000 Btu/ft 3 to determine the Btu factor.

Thus, if the average monthly heat content were 1030 Btu/ft 3

, the Btu

factor would be 1030/1000 = 1.030. If the average monthly heating value

were 975, the Btu factor would be 975/1000 = 0.975. The Btu factor is

then multiplied by the total gas consumed (usually MCF) or the total

dollars owed in order to actuate the slight adjustment for deviation from

the desired heat content window. Using this method of calculation the

gas is sold on a quasi-heat content basis.

(3) A third method is to sell gas strictly on an energy or heat content basis

(often referred to as a Therm basis). The gas is still metered on a

volume basis, but in addition, the heat content is measured daily, and

the monthly average heating value is multiplied by the total volume

consumption to calculate the energy (usually Therms) consumed for thf

81
month or billing period. Using this method, the gas is then priced on an

energy basis (usually $/Therm or $/dekaTherm) . A simple monthly bill for

850 MCF of gas priced at $5.20/dekaTherm would be calculated as follows:

850 MCF x 1000 ft 3 MCFx 1015 Btu

ft 3 x

1 dekaTherm $5.20

10 6 Btu

X dekaTherm

$*1,486.30

8.2 Rate Categories

There are usually two basic rate categories for natural gas sold to Air

Force bases in the U.S.; these are firm and interruptible. However, there is

considerable variation in the rate structure for each category.

• Firm Gas The utility is required to sell gas to the customer as long as

gas is available. Some utilities have priority levels within their firm

gas category. There is often a demand charge associated with the firm

gas category, as explained under miscellaneous charges.

• Interruptible Gas Within this rate category, the utility has the option

to suspend or curtail gas service to the base upon fairly short notice.

The cost of gas under this rate is normally slightly less than the firm

gas rate. The gas supplied to central power plants on bases is often

interruptible gas. The annual savings due to the decreased rate can be

considerable, however often times an alternate back-up source of energy

must be provided in case of gas curtailment, and there is obviously an

expense in maintaining these systems, or keeping an alternate supply of

fuel on hand. The most popular back-up fuels are fuel oil, propane, and

coal.

82
8 . 3 Miscellaneous Charges

In addition to the basic commodity cost of gas, there are a number of

other charges that appear on the monthly utility bills. The BCE and Property

Management Agency personnel should clearly understand the nature and basis of

these charges to insure that they are calculated correctly. A brief

explanation of these various charges is given below.

• Demand Charge

The demand charge is normally associated and based on firm gas only.

This is an additional charge based on the maximum usage rate (or demand)

of natural gas during a previous specified period. It may be regarded as

a fee the utility company charges for their investment in transmission

equipment in order to serve the customer as much gas as required during

peak demand periods. There are many variations of the demand charge; it

may be a constant annual or monthly fee, or it may be based on the use of

firm gas. It is usually evident from the bill how the demand charge is

calculated

• Service Charge

The service charge is usually a fixed amount based on a year, month, or

billing period. However, the service charge may be based on gas

consumption, and have a minimum monthly value. At some bases the utility

company may have a service charge for each meter, based on the size of

the meter. In some respects, this is similar to a monthly rental charge

for the meter. Service charges range from $10 per month for the entire

base (just a token amount) to ~ $1,000 per month per large meter at other

bases

The type and amount of service charge is very dependent upon the utility

company providing gas service and the initial contract agreement betwe83
the government contracting officer and the utility. Service charges have

many variations and there appears to be no set pattern.

Wheeling or Transportation Charge

This is usually a charge or credit for gas that passes thru service or

base distribution gas lines that belong to some other party. One common

wheeling credit on utility bills is for gas that flows thru base

distribution lines to a school on base that buys gas directly from the

utility. The gas is metered at the school with a utility gas meter, the

school pays the utility directly for gas, but the gas flows thru base

distribution lines; thus the base is reimbursed for the use of their gas

distribution system.

At Lackland and Kelly Air Force bases the natural gas is purchased from

Valero Transmission Company, but the City of San Antonio distributes,

meters, and bills the gas to the bases. For this service the City of San

Antonio Public Service charges a transportation fee. Wheeling and

transportation charges are usually not excessive.

Gas Cost Adjustment (GCA)

This cost adjustment reflects charges in the wholesale price the utility

company must pay for natural gas. The Federal Energy Regulatory

Commission (FERC) allows the utilities to pass along to their customers

any increased or decreased costs of gas from their suppliers. The

adjustment is based on a cubic foot of gas, thus is proportional to the

total amount of gas consumed per billing period. The adjustment can be

significant whenever the cost of gas is changing abruptly. The base

contracting officer and the utility companies have no control over this

adjustment to the cost of natural gas.

84
Franchise Fee

Some utility companies obtain franchises from incorporated cities and

towns within their service territory. As part of the franchise, the

utility company pays a fee based on the dollar amount of each customers

bill for the use of the municipalities alleys, streets, and rights-of-way

where gas lines are located. These fees are listed separately on the

bill, and Government installations are usually not exempt from this fee.

• Penalty for Non-curtailment of Interruptible Gas

Most gas utility contracts have a provision allowing the utility company

to charge a penalty or exorbitant rate for natural gas consumed after the

base has been told to curtail or interrupt the use of their interrupt ible

natural gas. This penalty ranged form three to seven times (3 to 7X) the

normal charge for natural gas at the Air Force bases visited during this

study. Thus, the use of natural gas after being told to curtail can be

prohibitively expensive, and the back-up energy systems for interruptible

gas curtailment should be in a state of readiness so they may be fired-up

on a relatively short notice.

• Minimum Monthly Charge

Some utility companies have a minimum monthly charge for gas service.

This is just one more miscellaneous charge, obviously of most concern

during the summer months when gas consumption is low.

The miscellaneous charges on utility bills vary considerably in nature and

dollar value, and usually start with the initial gas contract. It is

important to keep them to a minimum since some demand charges are extremely

high.

85
8.^ Required Billing Information

The following information should be on every gas utility bill so that the

BCE representative authorizing payment of the bill can easily check the

calculations to ensure that the bill is correct:

• Previous and present gas meter readings with appropriate units (CCF or

MCF)

• Temperature correction factor

• Pressure correction factor

• Supercompressibility factor or the compressibility ratio; if neglected,

that should be so stated.

• The three previous correction factors should not be lumped into one

composite correction factor.

• The billing pressure and temperature base

• Each miscellaneous charge should be clearly itemized.

• The average heat content of the gas for the billing period should be

clearly defined; the pressure, temperature, and moisture content of the

cubic foot of gas yielding the given Btu should be stated.

• The Btu factor (Heat Content Factor) if the gas is sold on a volume basis

with a heat content window.

• The firm and interruptible rates should be clearly stated.

• If the gas is measured with an orifice meter, a gas statement including

all the orifice correction factors should be sent along with the bill.

There should be sufficient information on the gas bill so that the BCE can

* easily check the calculations from the meter readings to the dollars owed for

the billing period.

86
9.0 References and Standards

[1 ] Orifice Metering of Natural Gas, American Gas Association Report No. 3,

American National Standard Institute ANSI/API 2530, First Edition, A.G.A.

Catalog No. XQ0178.

[2] Fluid Meters, Their Theory and Application, Sixth Edition, 1971, The

American Society of Mechanical Engineers.

[3] Manual For the Determination of Supercompressibility Factors For Natural

Gas, Par Research Project NX-19, American Gas Association, 1962, A.G.A.

Catalogue No. 1,003*10.

[4] Measurement of Gas By Turbine Meters, Transmission Measurement Committee

Report No. 7, American Gas Association, 1985, A.G.A. Catalogue No.

X20585.

[5] American Gas Association Gas Measurement Manual, General—Part No. One,

A.G.A. Catalogue No. X21081.

[6] American Gas Association Gas Measurement Manual, Displacement

Measurement —Part No. Two, A.G.A. Catalogue No. XZ0277.

[7] Heating Values of Natural Gas and its Components, NBSIR 82-2*101,

Armstrong, G.T. and T.L. Jobe, 1982, National Bureau of Standards.

[8] The Thermophysical Properties of Methane, from 90 to 500 K at Pressures

to 700 Bar. NBS Technical Note 653, R . D. Goodwin.

[9] Metric Unit (SI) Application Guide for the A.G.A., Prepared by the

Metrication Task Committee, 1980.

[10] Gas Transmission and Distribution Piping Systems, ANSI/ ASME B31 . 8-1982,

American Society of Mechanical Engineers.

[11] Orifice Metering of Natural Gas, ANSI/API 2530, Second Edition, A.G.A.

Catalog No. XQ0285.

87



Appendix No. 1

Air Force Base Survey Information

During the survey phase of this study, we visited fourteen different Air

Force bases within the U.S. in order to inspect the natural gas service

meters, talk to BCE personnel, and interview technical representatives from

the respective gas utility companies. The Bases visited and their location

are listed below:

Air Force Base Location

Offutt AFB Omaha, Neb.

Air Force Academy Colorado Springs, Colo.

Hill AFB Ogden, Utah

Lowry AFB Denver, Colo.

F.E. Warren AFB Cheyenne, Wyo.

McChord AFB Tacoma, Wash.

Kirtland AFB Albequerque, N.M.

Tyndall AFB Panama City, Fla.

Eglin AFB Valparaiso, Fla.

Minot AFB Minot, No. Dakota

Kelly AFB San Antonio, Texas

Lackland AFB San Antonio, Texas

Wright Patterson AFB Dayton, Ohio

Hanscom Field Bedford, Mass.

In addition to the above, we had telephone conversations with BCE personnel at

Holloman and Ellsworth Air Force bases and obtained utility bills for these

two bases.

91
Pertinent summary information about each base is given in Table A1 . This

information was gathered during the period November 84 to April 85. The table

is useful to compare annual energy consumption for each base, the variation in

heating value of natural gas, the demand and service charges, the variation in

penalty for non-curtailment of interruptible gas, the different methods

of selling natural gas, and the average cost per dekaTherm of energy. The

average cost of gas in the last column takes into account all types of

additional charges on the utility bill.

The price of natural gas ranged from $3.88 to $5.16 per dekaTherm (one

million Btu). The monthly demand charge for firm gas varied from zero to

$61 ,000 per month. This charge should be carefully considered by Air Force

contracting specialists when negotiating with the gas utility companies. The

heating value of a cubic foot of dry natural gas at 60 °F and 14.73 psia varied

from 991 to 1068 Btu/ft 3

. Hill AFB had the highest annual consumption of

natural gas of all the bases visited.

92
AIR

FORCE

BASE

SURVEY

INFORMATION

Remarks 13

Gas 1

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FORCE

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SURVEY

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94

Table

Al,

Continued
Appendix No. 2

Unit Conversions

Only the unit conversions and prefixes normally encountered on gas

utility bills and natural gas specifications will be given in this appendix.

Volume

28.316 liters = 1 foot 3

37.24 feet 3 = 1 meter 3

Mass

1 grain = 0.0648 grams

1 pound = 7000 grains

1 pound = 453-6 grams = 0.4536 kilograms

1 kilogram = 2.205 pounds

Energy

1 Btu = 1055 joules (it)

1 mega joule = 947.99 Btu

1 Therm = 100,000 Btu

1 dekaTherm = 1,000,000 Btu

1 Therm = 105.5 mega joules

Pressure

1 atm = 29.9212 in. Hg (Hg § 0°C)

1 atm = 407.1 9 in. H 2 0 (H 2 0 § 60°F)

1 atm = 14.696 psia

1 atm = 760 torr = 760 mm Hg (Hg § 0°C)

1 in. Hg = 13.5702 in. H 2 0) (Hg & H 2 0 @ 60°F)

1 torr = 1 mm Hg (Hg § 0°C)

1 torr = 0.53577 in. H 2 0 (H 2 0 § 60°F)

1 psi = 27.707 in. H 2 0 (H 2 0 @ 60°F)

1 psi = 51 .71 5 torr

95
NBS-114A (REV. 2-80

U.S. DEPT. OF COMM.

4.

BIBLIOGRAPHIC DATA

SHEET (See instructions)

1. PUBLICATION OR

REPORT NO.

NBSIR 86-3057

2. Performing Organ. Report No. 3.

TITLE AND SUBTITLE

Publication Date

August 1986

NATURAL GAS HANDBOOK

5. AUTHOR(S)

Paul R. Ludtke

6. PERFORMING ORGANIZATION (If joint or other than NBS, see instructions) 7. Contract/Grant No. NATIONAL BUREAU OF STANDARDS

DEPARTMENT OF COMMERCE 8. Type of Report & Period Covered

WASHINGTON, D.C. 20234

9.

SPONSORING ORGANIZATION NAME AND COMPLETE ADDRESS (Street. City. State, ZIP) U. S. Air Force

Engineering and Services Center

Tyndall Air Force Base, FL 32404

10.

SUPPLEMENTARY NOTES

Document describes a computer program; SF-185, FIPS Software Summary, is attached.

11.

ABSTRACT (A 200-word or less factual summary of most significant information. If document includes a si gn i fi cant bibliography or literature survey, mention it here) A Natural Gas Handbook has been prepared to help Air Force BCE personnel better

understand the principles of metering and selling natural gas on an energy content

basis. The various aspects of natural gas such as heating value, moisture content,

and hydrogen sulfide content are discussed. The characteristics of the various types

of meters currently used for flow measurements are given. The correct procedures

for calculating gas utility bills, including compressibility corrections, are presented

The responsibility of the gas utility to periodically check the gas meter and

instrument accuracy is discussed. A list of information that should appear on the gas

utility bill is given, and the various methods of selling natural gas are discussed.

12. KEY WORDS (Six to twelve entries; alphabetical order; capitalize only proper names; and separate key words by semicolon s)

compressibil ity; gas meters; heating value; natural gas.

13. AVAILABILITY

Unl imited

| | For Official Distribution. Do Not Release to NTIS

1 Order From Superintendent of Documents, U.S. Government Printing Office, Washington, D.C. 20402.

[_Xj Order From National Technical Information Service (NTIS), Springfield, VA. 22161

14. NO. OF

PRINTED PAGES

112

15. Price

USCOMM-DC 6043-P80

U. S. GOVERNMENT PRINTING OFFICE: 1986-673-066/45,319 REGION NO 8