HANDBOOK FOR ESTIMATING METHANE EMISSIONS 

FROM CANADIAN NATURAL GAS SYSTEMS 

 

 Prepared for: 

 GRI Canada 

75 Wimbledon Road 

 Guelph, Ontario 

N1H 7V7 

 Environmental Technologies 

 Prepared by: 

D.J. Picard, M. Stribrny, and M.R. Harrison 

 

 of: 

Clearstone Engineering Ltd. 

Enerco Engineering Ltd. 

 & 

 Radian International 

May 25, 1998 

EXECUTIVE SUMMARY

Since before the start of the Voluntary Challenge and Registry Program (VCR), 

Canadian Gas Association (CGA) and its member companies have been devoting 

significant resources to developing greenhouse gas inventories for the natural gas 

industry. This work has been extremely valuable to the Canadian gas industry as a 

whole, as well as to individual CGA member companies. A major part of this work has 

been the determination of methane emissions (particularly from fugitive sources). 

Moreover, remediation of methane losses has always been a goal of the industry. 

Accordingly, this handbook is presented to assist companies with the many difficulties 

involved in determining their methane emissions. It summarizes the common 

assessment methods for each applicable source type, and provides information needed 

for users to choose from these techniques and develop an overall inventorying 

approach best suited to their particular needs and circumstances. The overall aim is to 

provide a flexible framework in which companies may assess their methane emissions, 

and to establish a base set of terms, source categories and nomenclature to facilitate 

inter-company comparisons and allow easy aggregation of methane-emissions data for 

future industry reporting initiatives. 

The handbook is limited to methane emissions from non-combustion sources (i.e., 

process venting and fugitive equipment leaks), and excludes all indirect sources of 

methane emissions (e.g., use of electricity from fossil fuel power plants). The target 

segments of the natural gas industry are transmission, storage and distribution. Gas 

production and processing are specifically excluded - users are referred to the Global 

Climate Change Voluntary Challenge Guide published by CAPP (1997) to address 

these sectors. 

The target source types include the following: fugitive pipeline and equipment leaks, 

emissions from third-party damage, blowdown events, purging activities, still-column 

vents on glycol dehydrators, compressor starts, use of natural gas as the supply 

medium for gas-operated devices (chemical injection pumps, control loops, valve 

actuators, etc.), and venting by gas samplers, analyzers, relief valves, and regulators. 

Throughout the development of this handbook, active involvement of the individual 

sponsor companies has been encouraged to help identify and address all special needs 

and demands that may be placed on the final document. This process has included two 

workshops, plus a series of critical internal and external reviews. Notwithstanding this, 

the handbook is intended to be a live document that will be updated as warranted. 

While some safety and operating issues are briefly discussed in this document, it is not 

intended as a safety and operating procedures manual, and should not be used as 

such. 

i 
Technical and Planning Issues

The discussion of emission management strategies and available emission control 

technologies is beyond the scope of this handbook. Rather, the handbook simply tries to 

provide the user with a general understanding of the target emission sources along with 

the difficulties and uncertainties associated with estimating and measuring their 

emissions. The available techniques for estimating and measure methane emissions 

are delineated herein. 

An important theme throughout the handbook is the need for good quality assurance 

(QA)/quality control (QC) measures to ensure reliable results, and the need to consider 

the potential errors involved before drawing any conclusions from the results. For 

example, approaches that may be acceptable for determining emissions from a large 

number of sources may be totally inappropriate for application to individual or small 

numbers of sources, and vice versa. Errors, depending on the methods employed and 

the numbers of sources considered, may range from a few percent to hundreds and 

even thousands of percent. 

While much of the work is of a simple clerical nature and can be assigned to junior 

personnel, a team approach involving intermediate- and senior-level personnel is 

required to assure: 

⋅ accurate and complete posting of information, 

⋅ no double or missed counting, and 

⋅ correct selection and application of the applicable assessment methods and 

related factors. 

Collectively, the team needs to be familiar with the target sources, applicable industry 

terminology, available assessment techniques, and sources of the required 

infrastructure and activity data. 

Assessment Methods

There are a variety of techniques that may be used to either estimate or measure 

methane emissions. These, typically, vary according to the type of source. The simplest 

assessment approach involves using national industry-average factors to estimate 

fugitive emissions, and performing internal engineering estimates of vented gas 

volumes. Proper source counting procedures and interpretation of facility definitions are 

important in this approach to confirm correct selection and application of emission 

factors. Values of the necessary industry-average factors are provided herein. However, 

where companies have developed unit-specific factors based on actual measurements 

and source surveys, these values are considered to be more accurate and should be 

used instead. 

ii 
More advanced approaches may involve actual screening and emission measurement 

techniques. Going to increased levels of detail will allow better accounting of actual 

emission reduction measures companies may have undertaken. An iterative approach 

may be appropriate for many applications. Simplified approaches may be used to 

develop an initial ranking of emissions by type of source. Further efforts may then be 

focussed on refining values that will lead to the greatest improvements to the accuracy 

of the overall inventory. 

The information presented for each estimation or measurement option identified herein 

includes: 

⋅ technical approach, 

⋅ common applications, 

⋅ advantages and disadvantages, 

⋅ potential accuracy, and 

⋅ costs. 

Sufficient information is provided to allow the user to make an informed selection from 

the available methods. 

Conclusions

The presented handbook is a general reference document that focuses strictly on the 

available options for assessing non-combustion emissions of methane at gas 

transmission, storage and distribution facilities. Rather than try and establish minimum 

standards and reporting formats, the document simply delineates all reasonable 

options, and provides sufficient perspective and background information to allow users 

to make their own informed decisions. The presented options include, but are not limited 

to, the use of component- and facility-level emission factors through to indirect and 

direct measurement techniques. 

iii 
TABLE OF CONTENTS

Section Page

EXECUTIVE SUMMARY i 

TABLE OF CONTENTS v 

LIST OF TABLES ix 

LIST OF FIGURES xi

GLOSSARY xiii 

LIST OF ACRONYMS xix 

ACKNOWLEDGEMENTS xx

1.0 INTRODUCTION 1 

2.0 DEVELOPMENT OF A METHANE EMISSIONS INVENTORY 3 

2.1 General Planning Considerations 3 

2.1.1 Objectives 3 

2.1.2 Study Team 4 

2.1.3 Delineation of Process Infrastructure and Operations 4 

2.1.4 Emissions Assessment Protocol 4 

2.1.5 Data Collection 5 

2.1.6 Field Work 6 

2.1.7 Data Management and Processing 7 

2.1.8 Data Analysis 8 

2.1.9 Critical Reviews 8 

2.1.10 Reporting 9 

2.2 Source Classification Scheme 10 

2.3 Uncertainties 11 

3.0 FUGITIVE EQUIPMENT LEAKS 13 

3.1 Source Characterization 14 

3.1.1 Reciprocating Compressor Packing Systems 18 

3.1.2 Centrifugal Compressor Seals 18 

3.1.3 Valves 20 

3.1.4 Pump Seals 24 

3.1.5 Connectors 24 

3.1.6 Pressure-relief Valves 24 

3.1.7 Open-ended Valves and Lines 25 

Continued... 

TABLE OF CONTENTS (Continued)

iv 
Section Page

3.2 Emission Assessment Techniques 25 

3.2.1 Average Emission Factors 28 

3.2.2 Screening-Based Approaches 51 

3.2.2.1 Leak/No-leak Emission Factors 53 

3.2.2.2 Three-Stratum Emission Factors 57 

3.2.2.3 Published Leak-Rate Correlations 57 

3.2.2.4 Custom Leak-Rate Correlations 65 

3.2.3 Screening Coupled With Direct Measurement of Significant Leakers 65 

3.2.4 Integral Approaches 68 

3.2.4.1 Remote Sensing 69 

3.2.4.2 Tracer/Pollutant Ratio Technique 71 

4.0 FUGITIVE PIPELINE LEAKS 75 

4.1 Source Characterization 75 

4.2 Emission Assessment Techniques 75 

4.2.1 Pipeline leaks 75 

4.2.2 Plastic Pipe Permeability 77 

5.0 PROCESS VENTING 91 

5.1 Source Characterization 91 

5.1.1 Blowdowns 91 

5.1.1.1 Gas Transmission Systems 91 

5.1.1.2 Gas Distribution Systems 93 

5.1.2 Purging 94 

5.1.3 Gas-operated Devices 96 

5.1.4 Emergency Pressure Relief 98 

5.1.5 Sampling Systems 98 

5.2 Emission Assessment Techniques 99 

5.2.1 Estimation Methods 99 

5.2.2 Direct Measurement 100 

6.0 GLYCOL DEHYDRATORS 111 

6.1 Source Characterization 111 

6.2 Emission Assessment Techniques 112 

6.2.1 Average Emission Factors 112 

6.2.2 Process Modelling 112 

6.2.3 Measurement 112 

Continued ...

TABLE OF CONTENTS (Concluded)

v 
Section Page

7.0 ACCIDENTAL RELEASES 115 

7.1 Source Characterization 115 

7.2 Emission Assessment Techniques 115 

7.2.1 Dig-ins 115 

8.0 REFERENCES CITED 117 

9.0 BIBLIOGRAPHY 121 

10.0 APPENDICES 125 

10.1 Development of Equipment Component Counts 127 

10.2 Method 21 - Determination of Volatile Organic Compound Leaks 129 

vi 
LIST OF TABLES

Table Page

1 Summary of the procedures for estimating/measuring emissions due to fugitive 

equipment leaks 14 

2 Summary if percent leaking components by type of facility 16 

3 Default equipment schedules for Canadian gas transmission and distribution 

facilities 29 

4 Average emission factors for estimating fugitive equipment leaks at gas 

transmission 

and distribution facilities 31 

5 Typical compositions of processed natural gas by province 33 

6 Leak/No-leak emission factors for estimating fugitive equipment leaks at 

Canadian 

natural gas transmission and distribution facilities 54 

7 Three-stratum emission factors for estimating fugitive equipment leaks at 

Canadian 

natural gas transmission and distribution facilities 58 

8 Correlation parameters for estimating leak rates from equipment components at 

gas transmission and distribution facilities 61 

9 Default zero emission rates 63 

10 Values of the constant c used to estimate permeation losses from plastic piping 

systems for common SDRs 89 

11 Example of potential waste gas volumes and frequencies for blowdowns, purges 

and other venting activities on mainline transmission pipeline segments and at 

compressor stations 92 

12 Typical blowdown event on a gas distribution system and the amount of waste 

gas involved as estimated by one gas distribution company 95 

13 Typical gas consumption rates for a variety of standard and low-bleed types of 

pneumatic instruments 101 

vii 
14 Gas usage by pneumatic/hydraulic rotary vane isolation valve operators 102 

15 Manufacturer data for turbine-operated isolation valves 103 

LIST OF TABLES (Concluded)

Table Page

16 Summary of dimensional and specific internal-volume data for selected pipe 

sizes 104 

17 Compressibility factors for "Rich Processed Natural Gas" upstream of straddle 

plants 

for various combinations of temperature and pressure 108 

18 Compressibility factors for "Typical Processed Natural Gas" upstream of straddle 

plants 

for various combinations of temperature and pressure 109 

19 Compressibility factors for "Typical Processed Natural Gas" downstream of 

straddle plants for various combinations of temperature and pressure 108 

viii 
LIST OF FIGURES

Figure Page

1 Schematic diagram of a piston-rod packing case system on a reciprocating 

compressor 19

2 Schematic diagram of a dry-gas seal at one end of the shaft on a centrifugal 

compressor 21

3 Schematic diagram of various types of process valves 22 

4 Schematic diagram of a pressure-relief valve 26 

5 Schematic diagram of an open-ended line 27 

6 90% confidence limits for emissions versus number of components screened 64 

7 Sampling trains for bagging a source using either a vacuum or blow-through 

method 67 

ix 
GLOSSARY

TRANSMISSION FACILITIES

Block Valve Station - A block valve used to isolate a segment of the main 

transmission pipeline for tie-in or maintenance purposes. 

Block valves are located at distances of 25 to 80 km along 

each line to limit the amount of piping that may need to be 

depressurized for tie-ins and maintenance, and to reduce the 

amount of gas that would be lost in the event of a line break. 

Booster Station - A facility where gas pressure is increased to 

overcome friction losses through a pipeline. Centrifugal or 

axial compressors are most commonly used in these 

applications. A station typically comprises several units in 

series or parallel, as well as the necessary suction and 

discharge piping. Many booster stations also have discharge 

coolers to reduce the viscosity of the compressed gas and 

thereby to increase the efficiency of gas transmission. 

Border Meter Station - A meter station where custody of the gas is transferred from 

one gas transmission system to another at a provincial or 

national boundary. These stations are usually larger than 

normal meter stations. Typically, they have 10 to 20 large 

diameter meter runs (16” to 20” lines) and no pressure 

regulation. 

Compressor Station - A facility where gas pressure is increased to allow the 

gas to enter into a higher pressure pipeline system (i.e., feed 

rather than booster service). Both centrifugal and 

reciprocating compressor units may be used in these 

applications. However, use of reciprocating compressors is 

most common. A station typically comprises several units in 

series or parallel, as well as the necessary suction and 

discharge piping. Many compressors also have discharge 

coolers to reduce the viscosity of the compressed gas and 

thereby to increase the efficiency of gas transmission. 

Control Valve Station - A modulating valve that controls either the flow rate or 

pressure through the pipeline. In the latter case, this facility 

is often referred to as a regulator station. Usually, high 

pressure gas from the pipeline is used as the supply medium 

needed to energize the valve actuator. 

x 
Transmission Farm Tap - Direct gas sales from a transmission pipeline to an individual 

customer, usually in rural areas where access to gas 

distribution system is not available. These facilities have 

usually only pressure regulating equipment (gas might be 

provided free of charge as a consideration for an easement, 

or the meter is located by the residence as part of the 

customer meter set). 

Receipt Meter Station - A meter station for measuring the amount of gas being 

supplied by a given source (e.g. gas processing plant or a 

gas battery) to a gas transmission system. 

Sales Meter Station - A meter station for measuring the amount of gas 

being withdrawn from a gas transmission system by a 

customer (e.g. gas distribution system, farm or industrial end 

user). It might include pressure regulating equipment. 

Storage - Most transmission systems incorporate the use 

of storage caverns or spheres to help balance daily and 

seasonal variations in loads, and, therefore, are able to 

operate at nearly full capacity much of the time. 

Storage Well - A well through which natural gas may be either 

injected or removed from an underground storage cavern. 

The overall storage system would typically be connected to a 

gas transmission system. 

Transmission Pipeline - A pipeline used to transport processed but unodourized 

natural gas to market (i.e., to gas distribution systems and 

major industrial customers ). Most transmission pipelines 

also have some farm taps which provide gas to farmers 

located along the pipeline in areas where service from 

distribution systems is not readily available. 

The pipelines are usually constructed of steel, although 

aluminum is used for some lower pressure applications 

(generally up to 500 psig). The pipe sizes range from 60.3 

mm to 1219.2 mm O.D. (2 to 48 NPS), with the mid-range 

sizes most common. The operating pressures typically range 

from 1380 to over 6900 kPag (200 to 1000+ psig). 

For the purposes of calculating methane emissions from 

transmission pipelines, all small associated facilities such as 

valve assemblies or pig traps are considered to be part of 

xi 
the pipeline. 

Transmission Stations - Transmission stations are stations associated with 

transmission pipelines and handle unodourized gas. They 

meter and/or regulate the gas pressure. They consist of 

Receipt/Sales Stations, Border Meter Stations and 

Transmission Farm Taps. 

DISTRIBUTION FACILITIES

Cast-Iron Pipelines - Pipelines made of cast iron. Cast iron has not been 

used for new construction in Canada since at least the 

1950s. 

Commercial Meter Set - Customer metering facilities for gas sales to a commercial 

customer. They include both pressure regulation and 

measurement. The regulator reduces the pressure from 

distribution pressure to 1.7 kPag (0.25 psig) or often a higher 

pressure, typically not in excess of 140 kPag (20 psig). 

Copper-Tubing Service 

Lines - Service lines made of copper tubing. Copper-tubing is 

no longer used in Canada for new construction, and for most 

companies, not since at least the 1960s. 

Gate Station - A distribution facility located adjacent to a 

transmission facility where gas is odourized and flows 

through a splitter system for distribution to different districts 

or areas. The inlet gas is often metered, heated, and the 

pressure reduced. These stations may have multiple 

metering and pressure regulating runs. 

Distribution Farm Tap - A small pressure regulating station located in rural or semirural areas on high-pressure pipelines flowing odourized gas. 

It usually only regulates the pressure down to a distribution 

pressure, and often, does not include metering equipment. 

Distribution Mains - Distribution mains deliver odourized gas to the customers. 

They range in size from 3⁄4 NPS in rural distribution to 24 

NPS, with the most common being 2 to 8 NPS. Systems 

constructed of plastic pipe (mostly polyethylene, but also 

P.V.C. or some other plastics), typically, are operated at 

xii 
pressures of up to up to 690 kPag (100 psig), although there 

are polyethylene resins that allow operation at pressures 

slightly over 700 kPag (100 psig). Higher pressure steel 

pipelines (either with or without cathodic protection) flowing 

odourized gas are considered distribution mains in this 

document. A few older systems constructed of cast iron also 

exist. 

For the purpose of calculating methane emissions from 

distribution mains, all small associated facilities, such as 

isolation valves, are considered to be part of the main. 

Distribution Stations - Stations associated with the distribution mains that handle 

odourized natural gas. By function they include gate stations, 

district regulating stations, distribution farm taps and 

industrial meter sets. 

District Regulating 

Stations - A secondary regulating facility located downstream of a gate 

station on gas distribution systems where gas pressure is 

further reduced (usually to about 400 kPag [60 psig] but 

sometimes only to 1200 kPag [175 psig], depending on the 

company). 

Industrial Meter Set - Metering facility that transfers gas from the 

distribution system to a large industrial customer. Typically, 

gas is supplied at intermediate or high pressure (400 to 3000 

kPag [60 to 435 psig] or more), and is metered and pressure 

regulated. 

Miscellaneous Pipeline 

Equipment - Aboveground or exposed equipment components (e.g., 

isolation/block valves, pressure-relief valves, connectors, 

etc.) used on the pipeline that do not occur at an actual 

distribution station. Buried components are deemed to be 

part of the piping. 

Plastic Pipelines - Pipelines made of various types of plastic, ie. including 

polyethylene, polyvinyl chloride, ABS, etc. 

Protected Steel Pipelines - Steel pipelines that are cathodically protected. 

Residential Meter Set - Customer metering facilities for gas sales to a residential 

customer. They include both pressure regulation and 

xiii 
measurement. The regulator typically reduces pressure from 

distribution pressure to 1.7 kPag (0.25 psig). 

Service Lines - Service line is usually a short, small diameter pipeline that 

delivers gas from distribution main or transmission pipeline 

to the customer. They are usually made of steel pipe or steel 

tubing (either cathodically protected or not) , or plastic 

(usually polyethylene, but sometimes PVC or other plastic) , 

although copper tubing was also sometimes used in the 

past. (Continued) 

Sizes vary from 1⁄2 to 2 NPS, with some commercial or 

industrial customers having service lines of much larger 

diameter. 

Service lines tied into transmission lines might operate at 

pressures exceeding the distribution pressure. They are 

called “ high-pressure service lines" and require double 

regulation at the customer meter set. Typically, they operate 

at pressures above 860 kPag (125 psig). 

Unprotected Steel Pipelines - Steel pipelines that are not cathodically protected. 

EQUIPMENT

 

Dehydrator - A dehydration unit located at sales or purchase station. Its 

role is to control hydrates rather than final treatment to meet 

sales specifications. 

Line Heater - An indirectly fired heater used to heat the fluid in the pipeline 

to above hydrate or freezing temperatures. 

Separator - A flow-through process pressure vessel used to separate a 

fluid into its constituent phases. In the gas transmission, 

storage and distribution industries, separators are typically 

used to scrub any free liquids from process and fuel gas 

streams. They are usually installed on the inlet of 

compressors and on the inlet to fuel gas systems. The 

vessel, itself, may either be a vertical or horizontal system 

and be equipped with a manual or automatic liquid dumping 

system. 

EMISSIONS TERMINOLOGY

xiv 
Fugitive Emissions - Unintentional leaks from piping and associated equipment 

components (e.g., from seals, packings or gaskets, or leaks 

from underground pipelines [resulting from corrosion, faulty 

connection, etc.]). Fugitive sources tend to be continuous 

emitters and have low to moderate emission rates. 

Vented Emissions - Vented emissions are releases to the atmosphere by design 

or operational practice, and may occur on either a 

continuous or intermittent basis. The most common causes 

or sources of these emissions are gas operated devices that 

use natural gas as the supply medium (e.g., compressor 

start motors, chemical injection and odourization pumps, 

instrument control loops, valve actuators, and some types of 

glycol circulation pumps), equipment blowdowns and purging 

activities, and venting of still-column off-gas by glycol 

dehydrators. 

Equivalent Leak - Equivalent-leak is a theoretical model for a pipeline leak that 

would emit same volume of natural gas over a period of one 

year as the specific leak does over its actual leaking period 

within that year. 

Equivalent-Leak Multiplier - A constant that is used to convert a volume emitted 

by a specific pipeline leak or leaks during a specific calendar 

year to a volume emitted during that same calendar year by 

all leaks, identified or unidentified, in existence on that 

pipeline or pipeline system during that calendar year. 

Pipeline Leak - Fugitive emission through a small opening in the wall of the 

pipeline or from valves, fittings or connectors attached to that 

pipeline. 

Methane Content of 

Natural Gas - Volume of methane contained in a unit volume of natural gas 

at 15_C 101.325 kPa. 

Oxidation Of Methane 

 By Soil - Process of chemical break-up of molecules of methane into 

other organic and inorganic components as it travels from 

the pipeline to the ground surface through the soil. 

xv 
LIST OF ACRONYMS

AGA - American Gas Association 

CAPP - Canadian Association of Petroleum Producers 

CCME - Canadian Council of Ministers of the Environment 

CEPA - Canadian Energy Pipeline Association 

CGA - Canadian Gas Association 

CMA - Chemical Manufacturers' Association 

CSA - Canadian Standards Association 

EC - Environment Canada 

EPA - Environmental Protection Agency 

GRI - Gas Research Institute 

LEL - Lower Explosive Limit 

LDAR - Leak Detection and Repair 

GHG - Greenhouse Gases 

GRI - Gas Research Institute 

GTC - Gas Technology Canada 

NBS - National Bureau of Standards 

NPS - Nominal Pipe Size 

OVA - Organic Vapour Analyzer 

ppm - Parts Per Million 

PRV - Pressure Relief Valve 

PVC - Polyvinyl chloride 

SDR - Standard Dimension Ratio 

SOCMI - Synthetic Organic Chemical Manufacturing Industry 

THC - Total Hydrocarbons 

U.S. EPA - U.S. Environmental Protection Agency 

VCR - Voluntary Challenge and Registry 

VOC - Volatile Organic Compound 

xvi 
ACKNOWLEDGEMENTS

The development of this handbook has been sponsored by members of Canadian Gas 

Association and GRI Canada. The support and direction provided by each of the 

companies and agencies involved is gratefully acknowledged. Special thanks are given 

to the following individuals and companies who participated on the project steering 

committee and/or provided review comments: 

Jasmine Urisk - Gas Technology Canada 

Greg Elenko - B.C. Gas Utility Ltd. 

Lorna Seppala - B.C. Gas Utility Ltd. 

Jennifer Keyes - Canadian Gas Association 

Alan Dixon - Canadian Western Natural Gas 

Gail Stasser - Canadian Western Natural Gas 

Earle Tuele - Centra Gas Alberta Inc. 

Roger Ord - Centra Gas BC Inc. 

Andy Galarnyk - Centra Gas Manitoba Inc. 

Miles Haukeness - Centra Gas Manitoba Inc. 

Robert Milne - Enbridge Consumer’s Gas Ltd. 

Brian Scott - Enbridge Consumer’s Gas Ltd. 

Nick Thalassinos - Enbridge Consumer’s Gas Ltd. 

Manfred Klein - Environment Canada 

Rob Owens - Foothills Pipe Lines Ltd. 

Sylvain Coulombe - Gaz Métropolitan, Inc. 

Paul Mitnyan - Gaz Métropolitan, Inc. 

Terry Carrington - Northwestern Utilities Limited 

Glenn Hodgson - Northwestern Utilities Limited 

Rob James - Northwestern Utilities Limited 

Cam Ross - Northwestern Utilities Limited 

Alan Anderson - NOVA Gas Transmission Ltd. 

David Richards - NOVA Gas Transmission Ltd. 

Elizabeth Siarkowski -` NOVA Gas Transmission Ltd. 

Srikanth Venugopol - NOVA Gas Transmission Ltd. 

Rob McBrien - NOVA Research 

K.C. Caswell - Pacific Northern Gas 

Kerry Hanley - TransGas/SaskEnergy 

Larry Kratt - TransGas/SaskEnergy 

Bernard Ryma - TransGas/SaskEnergy 

Sandra Barnett - TransCanada Pipelines Ltd. 

Brian Grant - Union Gas Limited 

Peter Mussio - Union Gas Limited 

Jennifer Eby - Westcoast Energy Inc. 

Bruce Kosugi - Westcoast Energy Inc. 

Richard Williams - Westcoast Energy Inc. 

xvii 

 1 

1.0 INTRODUCTION

This handbook presents a detailed compendium of the available methods for assessing 

methane emissions from non-combustion sources on natural gas transmission, storage 

and distribution systems. It is designed as a detailed reference guide for use by both 

management and practitioners. It identifies and describes the different types of sources 

to be considered, delineates the basic steps involved in developing a methane 

emissions inventory, highlights important quality control/quality assurance matters to be 

considered, and provides practical information for designing an overall assessment 

strategy best suited to a company's particular needs and circumstances. Moreover, it 

establishes a general source classification scheme to facilitate inter-company 

comparisons and easy aggregation of data for future industry reporting initiatives. 

A glossary of key terms and common acronyms is provided at the front of the handbook. 

General information concerning planning and designing of a methane emissions 

inventory is presented in Section 2 along with the reference emission-source 

classification scheme. 

Sections 3 to 7 characterize the different types of primary sources that may be 

encountered in the target sectors of the natural gas industry, and summarize the 

different methods for assessing the emissions from these sources. The source types 

considered include: fugitive equipment leaks, piping leaks, process venting, glycol 

dehydrators, and accidental releases. 

All references cited in this handbook are listed in Section 8. A bibliography of some 

additional useful references is presented in Section 9. 

Section 10 comprises the appendices. These appendices identify procedures for 

counting and screening equipment components to estimate emissions from fugitive 

leaks. 

Measures for controlling methane emissions from the target sources are provided 

elsewhere by CGA. 
 2 

2.0 DEVELOPMENT OF A METHANE EMISSIONS INVENTORY

To help ensure complete and reliable results, the assessment effort must be conducted 

in a thorough and well-organized manner. Accordingly, this section delineates the 

important matters to be considered in planning the development of a methane 

emissions inventory. As well, it documents the general classification of gas transmission 

and distribution facilities. Except for a few minor differences, this section is consistent 

with Section 2 of the companion handbook for methane emission from non-combustion 

sources. 

2.1 General Planning Considerations

Typically, the work may be divided into the following basic tasks, as presented in the 

general order of occurrence: 

⋅ establish the study area, reference period and specific objectives to be achieved, 

⋅ assemble a study team with the requisite expertise and resources, 

⋅ prepare an inventory of the target infrastructure and operations in the study 

region, 

⋅ formulate an appropriate methodology for assessing the target emissions from 

these sources, 

⋅ detail the sources sufficiently for application of the selected emission assessment 

procedures and classification of the results (e.g., develop tallies of equipment 

components and process units by facility; compile activity data, leak statistics, 

third-party damages, etc.), 

⋅ conduct field inspection and sampling campaigns as may be needed to provide 

the required information, 

⋅ prepare a computer application to manage and process the collected data, 

⋅ identify trends and anomalies in the emission results, 

⋅ develop and document appropriate quality assurance/quality control (QA/QC) 

procedures, 

⋅ prepare a final report on the results and document information (especially data 

sources and contacts) that may be useful in any future updates of the work, and 

⋅ develop recommendations for senior management. 

However, some of these task may be combined, depending on the actual scope of work 

and resources available. 

2.1.1 Objectives. The first step is to clearly establish the specific objectives to be 

achieved. This will often dictate the best approach to be taken and allow proper 

planning of the proposed work. 
 3 

Typical objectives may be as follows: 

⋅ Assess total company-wide methane emissions as an indication of 

environmental performance, and to fulfil obligations made to the global 

climate change voluntary challenge and registry program. 

⋅ Conduct a statistical sampling/measurement campaign to determine 

company-specific emission factors for selected key types of sources. 

⋅ Assess emissions from a single facility to investigate the possible need for 

control measures. 

⋅ Establish accurate emission rates from specific sources to engineer 

appropriate control measures. 

⋅ Evaluate operational improvements. 

2.1.2 Study Team. Personnel and technical requirements are most demanding the first 

time an assessment is undertaken. Thereafter, the process is greatly simplified, 

provided the initial efforts have been properly documented. 

One of the main difficulties is identifying resources and information available 

within the company that may be useful for the proposed undertaking. This usually 

requires a certain amount of research by someone with a good overall 

knowledge of the company and its operations, and an understanding of the target 

sources and proposed assessment techniques. 

Custom software applications may need to be developed to access electronic 

information and convert it to a useable format. Hardcopy data should be entered 

into a data base system or spreadsheet application for efficient management and 

processing. Facility inspections and emission measurement programs may be 

warranted. 

While much of the work may often be done by junior personnel, the work also 

requires the overview and involvement of senior personnel. As well, a range of 

technical support services may be required. 

2.1.3 Delineation of Process Infrastructure and Operations. Major facilities and 
 4 

installations are usually readily identified through a variety of sources including 

engineering, operations and accounting departments. However, minor facilities 

(e.g., farm taps, mainline block valves, etc.) may be more difficult to document. 

2.1.4 Emissions Assessment Protocol. The development of a company-specific 

protocol document is an effective mechanism for substantiating the specific 

information sources, factors, methodologies and QA/QC procedures used, or to 

be used. Moreover, it provides a clear road map for those charged with 

performing the required emissions assessment work, and facilitates careful 

planning of the work to be performed. 

It is especially needed where the emissions assessment is to be conducted on a 

regular or frequent basis, and can provide a sound basis for monitoring changes 

in emissions. 

2.1.5 Data Collection. Regardless of the techniques employed, a certain amount of 

source and activity data must be collected to support the assessment effort. The 

key issues are to ensure completeness, accuracy (i.e., no double counting) and 

correct posting of the information. This generally requires personnel with a good 

working knowledge of the equipment and facilities involved, and of the associated 

operations and engineering jargon. 

Compilation of the required source data usually means developing a detailed 

inventory of sources by facility or installation. This may include major point 

sources (e.g., vent stacks) through to the, often, many minor and fugitive sources 

(i.e., equipment leaks). A thorough approach is needed to ensure adequate 

accounting of total emissions. While there is a natural tendency to trivialize 

smaller sources, these, due to their numbers and periods of activity, may often 

be significant total contributors. Therefore, they should not be disregarded unless 

their collective contribution to total methane emissions is proven to be negligible. 

Conversely, once a thorough assessment has been done, a basis exists for 

simplifying the approach and better allocating resources in the future to best 

reduce uncertainties in the results. 

Many companies use computerized inspection-and-maintenance information 

management systems. These can be a very reliable means of counting major 

and critical-service components (e.g., compressor units, pressure relief devices, 

vessels, control valves, etc.). Also, some departments within a company may 

maintain databases of certain types of equipment or facilities for their own 

specific needs (e.g., tax accounting, production accounting, insurance records, 

quality control programs, safety auditing, license renewals, etc.). Some effort 

should be made to flush out and identify these pools of potentially useful 
 5 

information. 

Typical equipment schedules may be applied to estimate the number of other 

sources associated with each facility. Mechanical flow diagrams can be used to 

count process packages, but often do not show all of the actual equipment 

components (e.g., valves, flanges and fittings) except for very simple 

installations. 

The required activity data may include the following 

⋅ process operating conditions (e.g., gas compositions, temperatures, 

pressures and flows), 

⋅ maintenance records, 

⋅ accident reports, and 

⋅ tallies and details of unit, station and line blowdowns as well as 

compressor starts. 

Other data that may be needed is listed below: 

⋅ supply medium used for gas-operated devices, 

⋅ piping materials, 

⋅ is the process gas odourized?, 

⋅ operating practices (e.g., depressurization of idle compressors), and 

⋅ annual updates of new equipment installed. 

Typical difficulties that may be encountered in attempting to utilize available data 

are as follows: 

⋅ converting electronic data to a consistent or convenient format, 

⋅ reliable and accurate data entry, 

⋅ verification of database accuracies and completeness, and 

⋅ it may be necessary to develop special applications to perform custom 

retrievals of information from existing applications (this almost always 

involves more work than initially expected). 

2.1.6 Field Work. The primary objective of the field work is to ensure complete and 

accurate results. However, important elements to be considered in any field work 

are planning, organization, logistics (e.g., transportation, accommodation, 

available times), anticipation of potential difficulties and safety issues, 

contingencies or flexibility to respond to specific difficulties that may arise (e.g., 

poor weather conditions), and good communication and coordination of activities 
 6 

with site personnel. 

Where practicable, operations personnel responsible for the target facilities and 

installations should be involved in the work to ensure that emission sources are 

correctly identified, and that the operating status and state of equipment are 

interpreted properly. This is especially important at larger more-complex facilities. 

The use of checklists and proper data collection sheets is essential to ensuring 

that all the necessary information is collected. Moreover, it promotes an efficient 

and systematic approach to performing the necessary work. 

Developing a good overview description of a facility's process infrastructure and 

surroundings helps provide useful perspective for subsequent interpretation of 

the results. A photographic essay of the facilities and work performed is 

particularly useful for this purpose. Some considerations and suggestions 

regarding the use of cameras are as follows: 

⋅ Flash cameras are not allowed in hazardous locations. 

⋅ Prepare a written log of each photograph, preferably as the pictures are 

being taken or shortly thereafter. 

⋅ If multiple facilities or installations are to be visited, tag the start of 

photographs at each by taking a picture of the entrance sign. 

2.1.7 Data Management and Processing. The most practicable means of handling 

and processing the compiled data is to enter it into either a spreadsheet program 

(e.g., Lotus 123, Excel, or QuattroPro) or a data management system (e.g., 

dBASE, Paradox, FoxPro, Access, or Oracle), as appropriate. Typically, 

spreadsheets are best suited to managing small to moderate amounts of 

information, and for performing relatively basic calculations. The ability to use 

multiple sheets in a single file and to link files helps make it easy to organize and 

structure a spreadsheet application. Additionally, most personnel will be 

knowledgeable on the use of spreadsheet programs, and minimal effort is 

required to quickly produce presentation-quality output. For large amounts of 

information or many types of data, however, spreadsheets tend to be an 

inefficient means of data management and quickly become cumbersome and 

unwieldy to use. Furthermore, if extensive use is made of cell programming 

features, a spreadsheet application may become very difficult to modify or update 

without introducing errors, and will generally be more difficult to debug than a 

comparable database application. Greater use of macro programming features 

and linking of external applications to spreadsheet cells can mitigate some of 
 7 

these problems but soon it still is better to be using a data management system. 

The use of a database application enables complex information retrievals and 

custom reporting of information that simply would not be practicable with a 

spreadsheet program. Information may be arranged into logical groupings (or 

tables) that may be linked together to create a relational database. This allows 

efficient storage of information and makes it easier to manage the data. 

Furthermore, it is much easier to rearrange information and insert or delete fields 

as a project evolves than with a spreadsheet. Overall, databases tend to be 

easier to maintain and support than spreadsheets, as the applications become 

more sophisticated. 

A big disadvantage of data management systems is the need for more 

specialized user training. A data management system is most useful and 

productive where the user is competent in its programming features. Many data 

management systems offer an interactive environment that is easy to master, 

thus, allowing a novice to quickly begin doing useful work. However, interactive 

usage is very restrictive, much more susceptible to human error, and, for other 

than simple tasks, is far less efficient than using the system's programming 

features to develop scripts. Scripts may be continually reused and are readily 

debugged. 

Additionally, a data management system, while able to do very sophisticated 

information retrievals, requires considerable more effort than a spreadsheet to 

prepare presentation quality output. Often it is easier to output the data to 

another program for preparation of presentation graphs and tables. 

In general, if there is any uncertainty at the start of a project about whether to use 

a spreadsheet or data management system, then the latter should be chosen. 

The amount of information to be collected and the complexities of managing it 

almost always exceeds expectations. 

2.1.8 Data Analysis. A typical exercise in any emissions assessment effort is to 

summarize the results in charts and tables. The following are some specific 

matters to consider in reviewing the results: 

⋅ look for cost effective opportunities to reduce emissions and improve the 

quality of the developed estimates, 

⋅ the greatest sources of emissions do not necessarily offer the most costeffective opportunities for emissions control (for example, a mainline block 

valve would need to be leaking at a substantial rate before it would be 
 8 

economical to take it out of service for repairs), 

⋅ identify trends in measurement data that may either help find sources in 

need of control or point out areas where efforts may be reduced, and 

⋅ look for opportunities to adjust the assessment strategy for future efforts 

so that uncertainties are minimized for the available resources. 

2.1.9 Quality Assurance/Quality Control (QA/QC). As a basic QA/QC measure, it is 

important that the results be reviewed by senior operations, engineering and 

environmental personnel to help ensure there are no errors, omissions or double 

counting. Any apparent anomalies in the data should investigated so they can be 

fully understood and properly explained. 

As part of this process, it is useful to compare the results against any previous 

baseline data as well as with other relevant corporate, industry and national 

inventories. Moreover, the results should be put in context relative to current 

corporate and regulatory objectives. 

Other appropriate QA/QC measures may include the following: 

⋅ ensure that the reference year for the presented results is clearly stated, 

⋅ ensure that the sources of all source, activity and emission factor data as 

well as calculation procedures and test methods are identified and 

properly referenced (both for the benefit of future updates and to provide a 

clear trail for resolving anomalies), 

⋅ check for recent updates or improvements in calculation procedures and 

related factors being used, 

⋅ check for inconsistencies, 

⋅ rank sources to help identify anomalies, 

⋅ ensure that emissions have been adjusted to reflect out-of-service time 

and check these adjustment factors to ensure that they have not been 

simply carried forward from a previous year rather than properly updated, 

⋅ check to ensure that point source contributions have been subtracted out 

from area source category totals where appropriate, 

⋅ document any extrapolations from previous results and check that all 

applicable source categories have been corrected to the current reference 

year, 

⋅ subject a reasonable cross section of the targeted sources to a detailed 

procedures check, and 

⋅ document any recent operational improvements and upgrades. 
 9 

The actual QA/QC measures used in conducting the emissions assessment or 

preparing the emissions inventory should be fully documented. 

2.1.10 Reporting. The following is a suggested list of matters to be addressed in the 

developed final emissions-assessment report: 

⋅ The method of assessment should be fully documented. 

⋅ The emissions should, to the extent practicable, be compared to results in 

preceding years back to the baseline year of 1990. 

⋅ The expected accuracy of the results should be stated and the areas of 

greatest uncertainty clearly noted. This is critical for proper interpretation 

of the results and any claims of net reductions. 

⋅ Specific measures taken to reduce methane emissions should be 

described. 

⋅ A discussion should be provided of the differences between the previous 

year and the current year’s estimates if applicable. 

⋅ An effort should be made to put the estimated amount of emissions in 

proper context relative to the amount of gas handled, and the distances 

the gas is transported. 

⋅ Some effort to forecast future emissions should be made. 

Companies that elect to participate in Canada's Voluntary Challenge and 

Registry (VCR) Program may find detailed information on this initiative at the 

following Internet address: www.vcr-mvr.ca. Alternatively, companies may 

contact Voluntary Challenge and Registry Inc. at the address below: 

Voluntary Challenge and Registry Inc. 

170 Laurier Avenue W., Suite 600 

Ottawa, Ontario 

K1P 5V5 

Telephone: (613) 565-5151 

Fax: (613) 565-5743 

E-mail: info@vcr-mvr.ca 
 10 

As a first step, participants are encouraged to submit a letter of intent confirming 

a commitment to limit or reduce greenhouse gases from their operations. This is 

followed by an action plan and subsequent progress reports. A Participant's 

Handbook and Addendum is available at the VCR web site; it gives detailed 

information on how to report greenhouse gas emission reduction plans and 

actions. 

2.2 Source Classification Scheme

The use of a consistent source-classification scheme across the gas industry is 

necessary to allow meaningful comparisons of results between companies, and to 

facilitate easy aggregation of results for future industry and national reporting initiatives. 

It is recognized that many companies already have their own in-house terminology and 

definitions, and that certain industry standards (e.g., CSA Z662-96 Oil and Gas Pipeline 

Systems) and government regulations establish their own values. The scheme 

presented here is intended to achieve a reasonable balance between existing corporate, 

industry and government naming conventions, as well as to provide a logical grouping 

of sources according to functionality, industry sector, and type of facility. 

Basically, two main distinctions are made. For the purpose of assessing fugitive 

equipment leaks, all equipment that handles unodourized gas is deemed to be 

characterized by emission factors presented for gas transmission service, and if the gas 

is odourized the factors for gas distribution service apply (see Section 3.0). To 

characterize the different facilities and installations according to type and size, the 

following classifications shall be used: 

Distribution

⋅ Protected Steel Mains and Service Lines 

⋅ Unprotected Steel Mains and Service Lines 

⋅ Plastic Mains and Service Lines 

⋅ Cast Iron Mains 

⋅ Copper-tubing Service Lines 

⋅ Gate Stations 

⋅ District Regulating Stations 

⋅ Distribution Farm Taps 

⋅ Industrial Meter Stations 

⋅ Commercial Meter Sets 

⋅ Residential Meter Sets 

⋅ Miscellaneous Pipeline Equipment 
 11 

Transmission 

⋅ Protected Steel Pipelines 

⋅ Unprotected Steel Pipelines 

⋅ Border Meter Stations 

⋅ Receipt Meter Stations 

⋅ Sales Meter Stations 

⋅ Transmission Farm Taps 

⋅ Block Valve Stations 

⋅ Control Valve Stations 

⋅ Compressor and Booster Stations 

- Reciprocating Compressor Units 

- Centrifugal Compressor Units 

- Compressor Discharge Coolers 

- Compressor Station Yard Piping 

2.3 Uncertainties

The potential sources of uncertainties in an emissions inventory may include the 

following: 

⋅ inherent uncertainties of the selected estimation techniques, 

⋅ missing or incomplete information regarding the source population and activity 

levels, 

⋅ measurement errors, 

⋅ poor understanding of temporal and seasonal variations in the sources, and 

⋅ data entry and calculation errors. 

The first two items are likely to be the greatest sources of error, although all are 

potentially noteworthy. 

In general, the procedures documented in this handbook represent a range of simple (or 

first-order) through to best-available measurement and estimation techniques. However, 

many of these methods, particularly those specific to estimating trace organic 

emissions, are still undergoing significant refinement. The published emission factors 

are frequently updated as the science evolves. 
 12 

3.0 FUGITIVE EQUIPMENT LEAKS

A general discussion of the different types of equipment components that may leak is 

presented in Section 3.1 below, followed by the available estimation and measurement 

techniques for assessing these emissions. The assessment techniques are divided into 

the following four categories, as presented in the general order of increasing 

sophistication and accuracy (see Table 1 also): 

⋅ average emission factors (Section 3.2.1), 

⋅ screening-based approaches (Section 3.2.2), 

⋅ screening coupled with direct measurement of emission from significant leakers 

(Section 3.2.3), and 

⋅ integral (or whole-facility) approaches (Section 3.2.4). 

A basic requirement of the first three approaches is the development of a detailed 

inventory of the target component population. Procedures and guidelines for doing this 

are presented in the Appendices (i.e., Section 10.1). The screening approaches 

involving checking individual components for indications of leakage, usually using a 

portable organic vapour analyzer (OVA), in accordance with U.S. EPA's Method 21. A 

copy of Method 21 is provided in Section 10.2 for easy reference. 

The average emission factor approach is the simplest, although least reliable approach. 

It is generally only valid for developing regional or national emission inventories since 

the approach is based on statistical principles and relies on large component population 

(e.g., tens of thousands of components). Results for individual facilities or process units 

may easily be in error by several orders of magnitude. A series of calculation forms are 

presented in Section 3.2.1 to assist companies in refining the average emission factors 

for application to their systems to help ensure the best possible results. Separate forms 

are provided for gas transmission and distribution. 

Screening based approaches are normally selected where companies choose to 

undertake actual leak detection and repair (LDAR) programs since actual leakers are 

identified. Direct measurement of emissions from the leakers allows prioritization of the 

repair work, potentially allows for more efficient and reliable quantification of the 

emissions. Moreover, it allows for better prioritization and evaluation of the necessary 

repairs. 

The whole-facility approaches require a high degree of quality control/quality assurance 

to ensure meaningful results, and usually are susceptible to poor meteorological 

conditions and interference from any nearby emission sources. This approach is most 

cost-effective when applied to large facilities. However, it is not suitable for LDAR 

programs since it does not identify individual leaking components. 
 13 
 14 

ble 1. Summary of the procedures for estimating/measuring emissions due to fugitive equipment leaks. 

chnique Information 

Requirements 

Advantages Disadvantages 

verage Emission 

ctors

⋅ Equipment 

inventory. 

⋅ Simple. 

⋅ Low cost. 

⋅ Poor accuracy (errors decrease with increasin

 numbers of components, but may still be 

several 

 orders of magnitude for individual facilities). 

⋅ Does not account for control efforts. 

reening Approaches: 

eak/No-leak Factors 

Stratified Factors 

Published Leak-rate 

orrelations 

Custom Leak-rate 

orrelations 

⋅ Equipment 

inventory. 

⋅ Leak survey results. 

⋅ Identifies leaking components. 

⋅ Control efforts reflected in 

results. 

⋅ Labour intensive. 

⋅ Moderate costs. 

⋅ Poor to moderate accuracies (±300 percent at

best). 

reening Coupled with Direct 

easurements for Significant 

akers: 

Hi-Flow Sampler 

Bagging 

⋅ Equipment 

inventory. 

⋅ Leak survey results. 

⋅ Identifies leaking components. 

⋅ Excellent accuracy (potentially 

 ±15 percent). 

⋅ Control efforts reflected in 

results. 

⋅ Labour intensive. 

⋅ Moderate to high costs. 

hole-Facility Quantification 

pproaches: 

Remote Sensing 

Plume Transect Method 

Trace/Pollutant Ratio 

chnique 

⋅ Minimal. ⋅ Simple. 

⋅ Cost effective for large facilities. 

⋅ Reasonable accuracies (up to 

±10 

 to 25 percent for good 

conditions 

 and site-specific calibration of 

⋅ Susceptible to weather problems. 

⋅ Potential interference from other nearby 

sources. 

⋅ Costly for small facilities. 

⋅ Usually not practicable for identify individual 

leakers, 

 but some open-path systems can be useful fo
 15 

any 

 models). 

 quickly delineating high-emission zones.
 16 

3.1 Source Characterization

Emissions from fugitive equipment leaks are a major source of methane emissions at most gas 

facilities. Overall, they account for nearly half of the total methane emissions from natural gas 

transmission, storage and distribution systems in Canada (CGA, 1997). 

Fugitive equipment leaks may be defined as any loss of process fluids to the environment past 

seals, packings, valve seats and mechanical connections (e.g., compressor seals and rod 

packings, valve-stem packing, block-valve seats, etc.). Most equipment components leak to 

some extent. However, only a few percent of the potential sources at a site actually leak 

sufficiently at any time to be in need of repair or replacement. If the number of excessive leakers 

is less than 2 percent of the total number of potential sources, the facility is normally considered 

to be well maintained and fugitive equipment leaks properly controlled. 

In Canada and the United States, the leak status of an equipment component is expressed in 

terms of the maximum concentration (screening value) of organic material that can be measured 

at the leakage point (or interface) using a portable organic vapour analyzer. The current CCME 

(1993) Code of Practice for the measurement and control of fugitive VOC emissions from 

equipment leaks at chemical plants and refineries considers a component to be leaking if it has 

a screening values of 10 000 ppm or more. Table 2 summarizes the percentage of components 

determined to be leaking at different types of natural gas facilities during recent field work based 

on the presented leak definition as well as for a more stringent definition of 500 ppm. 

The following are some of the noteworthy characteristics of fugitive equipment leaks: 

⋅ There is a strong correlation between the rate of leakage and the type of service (e.g., 

gas/vapour and light liquid/two-phase streams) (Wetherold and Provost, 1979). 

However, there is no clear relationship between the size of a component and the rate of 

leakage (U.S. EPA, 1983). 

⋅ The potential for leakage increases with operating pressure and ambient temperature, 

but is generally independent of operating temperature or elevation above grade (Langley 

et al., 1981). 

⋅ Control valves have a greater potential for leakage than block valves. For block valves, 

the gate design has the most potential for leakage, while plug and ball designs have the 

least potential. 
 17 

ummary of percent leaking components by type of facility 

Facility Type Component 

Category 

Total 

Components 

10 000 ppm 500 ppm 

Leakers Percent 

Leakers

Leakers Perce

Leake

ansmission - Compressor Stations Compressor 

Seals 

Other 

Components 

53

42 403

45 

872 

84.9

2.1

46

1 346

86

3

ansmission - Border Meter Stations All Components 6 564 156 2.4 227 3

ansmission - Receipt/Sales Meter 

ations 

All Components 3 244 177 5.5 221 6

ansmission - Block/Control Valve 

tes 

All Components 1 212 32 2.6 47 3

stribution - Residential Sites All Components 676 0 0.0 2 0

stribution - Commercial Sites All Components 901 2 0.2 6 0

stribution - Industrial Sites All Components 1 332 23 1.7 55 4

stribution - Farm Taps All Components 768 14 1.8 26 3

stribution - District Regulating 

ations 

All Components 1 479 32 2.2 48 3

stribution - Gate Stations All Components 4 187 69 1.6 138 3

rce: Ross and Picard (1996), Table 1, page 7.
 18 

⋅ Off-line compressor units that have been depressurized and are left open to the 

atmosphere through the vent line leak more than ones that have not been depressurized 

or that are online (especially for reciprocating compressors) (Hummel et al., 1996). In the 

first case, the leakage is past the seats of upstream and downstream block valve. In the 

latter case, it is past the seat of the blowdown valve. 

⋅ Components in gas transmission service tend to leak more, on average, than 

components in gas distribution service. This may be due, in part, to the large disparity in 

typical operating pressures. However, it is likely that odourization of the distribution gas 

also is an important factor. 

⋅ Repaired components usually achieve a normal leak potential if the leaks do not recur 

during the first few weeks after repair (Eaton et al., 1980). 

⋅ At gas facilities it is noteworthy that most of the emissions from fugitive equipment leaks 

often come from only one or two problem leakers at a given site rather than many small 

to moderate leaks. The results of a recent measurement program sponsored by Gas 

Technology Canada member companies (Ross and Picard, 1996) determined that 42 

percent of total emissions measured were from the single largest source at each of the 

183 sites surveyed. Similar trends have also been observed in the U.S. 

Leakage may often be an indication of wear, damage, defects, severe process conditions, 

abusive environments, inadequate design, or improper installation. However, some 

components, like mechanical seals, are designed to leak a small amount in order to provide 

some lubrication of, as well as remove heat and debris from, the contact the surfaces. Seal 

designs can be implemented for some services which do not normally transmit any 

hydrocarbons directly to the atmosphere (i.e., leaked fluid can be collected and directed to a 

control device). 

The primary types of equipment components that may produce fugitive leaks in the natural gas 

industry are: 

⋅ reciprocating compressor packing systems, 

⋅ centrifugal compressor seals, 

⋅ valves (i.e., the stem packing system plus fittings and seams on the valve body), 

⋅ pump seals, 

⋅ connectors (i.e., threaded or gasketed surfaces), 

⋅ pressure-relief devices (i.e., the seated surfaces), and 

⋅ open-ended valves and lines (i.e., valve seats where there is process fluid on one side 

and the other side is open to the atmosphere). 

A description of each of these sources and their potential leakage points is provided in the 

subsections below. 
 19 

3.1.1 Reciprocating Compressor Packing Systems: Packings are used on reciprocating 

compressors to control leakage around the piston rod on each cylinder as shown in 

Figure 1. There are three locations on a packing case where leakage can occur: (1) the 

gasket on the face of the end cup nearest the cylinder, (2) between packing cups and (3) 

past the rings to the end furthest from the cylinder. Ring leakage typically occurs along 

the ring-side faces, between rings and the compressor rod, and through ring joints. 

Leakage from around cover plates and connections on the cylinder head are accounted 

for separately by classify each of these fittings as a connector (see Section 3.1.5) 

Leakage from the packing case discharges into the distance piece (or doghouse) 

between the compressor cylinder and the crank case. The distance piece (or doghouse) 

may be left open with the vent piping connected directly to the packing case, or the 

distance piece may be closed and the vents may be connected to both the packing case 

and the distance piece. The packing case and/or distance piece may be purged by an 

inert gas to reduce local leakage of process gas. Common practice is to route the 

packing and distance piece vents outside the building to the atmosphere. On small 

compressor packages the vent lines sometimes are connected to the plenum chamber of 

the shaft-driven air cooler to help draw off any leaked gas and disperse it. 

Conventional packing systems have always been prone to leaking a certain amount, 

even under the best of conditions. According to one manufacturer, leakage from within 

the cylinder or through any of the various vents will be on the order of 1.7 to 3.4 m3

/h 

under normal conditions and for most gases. However, these rates may increase rapidly 

as normal wear and degradation of the system occurs 

The amount of leakage from the packing case depends on the amount of misfit between 

the different components (i.e., piston rod, packing material, rings, and packing case), 

misalignment of the piston rod, and imperfections/disturbances on the rod surface and 

the faces that must be in contact to form proper seals. Vibration or temporary lubrication 

loss (if the packing is lubricated) can cause premature equipment failure and produce 

leakage problems. 

3.1.2 Centrifugal Compressor Seal Systems: Centrifugal compressors generally require 

shaft-end seals between the compressor and bearing housings. Face-contact oillubricated mechanical seals or oil-ring shaft seals may be used. However, dry-gas shaft 

seals are most common in natural gas transmission applications. 
 20 

Figure 1. Schematic diagram of a compressor packing system. 
 21 

Oil-lubricated seals operate at a pressure above that of the process so the seal oil flows 

in towards the process. This provides a positive barrier against leakage of process gas 

along the shaft to the atmosphere. Drain traps are used to capture oil between the seals 

and return it to the oil reservoir. The emissions results from dissolution or entrainment of 

process gas in the seal oil, and subsequent release of it in the degassing drum. The 

degassing drum is usually routed to atmosphere at a safe location and can be a 

significant source of emissions. 

A dry-gas seal system, as shown in Figure 2, uses a clean filtered buffer gas (e.g., 

nitrogen, air or natural gas) instead of a lubricating oil, and features a series of precision 

machined seal plates. The buffer gas serves to both cool and separate the individual seal 

plates. As well, it create a pressure dam to help minimize any outflow of process gas 

along the shaft to the atmosphere. If buffer gas can be tolerated in the process and is 

reasonably affordable, it is supplied at a pressure sufficient to ensure that any leakage is 

into the process and not to the atmosphere. Otherwise, the leakage is of process gas into 

the seal system where it commingles with the buffer gas and, ultimately, is discharge 

through the outer seal vent. 

The amount of leakage from a given seal will tend to increase with wear between the seal 

and compressor shaft, operating pressure and rotational speed of the shaft. 

3.1.3 Valves. There are three main locations on a typical valve where leakage may occur: (1) 

from the valve body and around the valve stem, (2) around the end connections, or (3) 

past the valve seat. This section deals with the first type of leakage. The end connections 

are classified as connectors and are discussed in Section 3.1.5. Leakage past the valve 

seat is only a potential source of emissions if the valve, or any downstream piping, is 

open to the atmosphere. This is referred to as an open-ended valve or line and is 

addressed in Section 3.1.7. 

A conventional process valve uses a packing gland to prevent the leakage of process 

fluid around the stem. The valve is equipped with a hand wheel or handle for manual 

operation, or an actuator for automatic control. The stem, itself, may be operated through 

either a sliding/rising or rotary motion, depending on the type of valve. The most common 

rising stem valves are the gate and globe. Common types of rotary (or quarter turn) 

valves are the plug, ball and butterfly. 

The potential leak points on each of the different types of valves are depicted in Figure 3 

and, as applicable, include around the valve stem, body seals (e.g., where the bonnet 

bolts to the valve body, retainer connections), body fittings (e.g., grease nipples, bleed 

ports), packing guide, and any monitoring ports on the stem packing system. Typically, 

the valve-stem packing is the most likely of these parts to leak. 
 22 

Figure 2. Schematic diagram of various types of process valves (API, 1996). 
 23 

Figure 3. Valves. 
 24 

Figure 3. Valves. 
 25 

The effectiveness of the packing gland is determined by the tightness of the packing 

material around the stem, the pressure of the process fluid and the surface smoothness 

of the stem and gland. Over time the gland gradually loses some of the packing material 

due to extrusion and wear, and must be tightened to maintain a proper seal. At some 

point, complete repacking of the gland is required. 

Over-tightening a packing gland can prevent or make manual operation of a valve 

difficult. For control valves, it can cause slow stem movement, poor process control, bad 

seating and possibly stalled conditions. It can also damage the packing and reduce its 

life. 

Rotary or quarter turn valves where stems turn 90o

 tend to be easier to seal than sliding 

stem valves. This is because they have less packing-to-shaft travel distance for each 

stroke of the valve, and therefore, less packing wear (Brestel et al., 1992). Additionally, 

they have less tendency to draw dust and other abrasives into the packing gland during 

their operation. However, the rotary valve packing is extremely difficult to retain in the 

packing area because of high packing stress requirements, plus the additional high 

localized stress caused by radial shaft deflection. 

3.1.4 Pump Seals. There are relatively few applications that require the use of a pump at gas 

transmission, storage or distribution facilities. Their use is most apt to be for lube oil 

circulation on compressor engines, or for glycol circulation on dehydration units. Positive 

displacement pumps are normally used in these applications. Positive displacement 

pumps have a reciprocating piston, diaphragm or plunger, or else a rotary screw or gear. 

Packing, with or without a sealant, is the simplest means of controlling leakage around 

the pump shaft. It may be used on both the rotating and reciprocating pumps. Specially 

designed packing materials are available for different types of service. The selected 

material is placed in a stuffing box and the packing gland is tightened to compress the 

packing around the shaft. All packings leak and generally require frequent gland 

tightening and periodic packing replacement. 

Particulate contamination, overheating, seal wear, sliding seal leakage and vibration will 

contribute to increased leakage rates over time. 

3.1.5 Connectors. A connector is any flanged or threaded connection, or mechanical coupling, 

but excludes all welded or back-welded connections. If properly installed and maintained, 

a connector can provide, essentially, leak-free service for extended periods of time. 

However, there are many factors that can cause leakage problems to arise. Some of the 

common causes include vibration, thermal stress and cycles, dirty or damaged contact 

surfaces, incorrect sealing material, improper tightening, misalignment, and external 

abuse. 

3.1.6 Pressure-Relief Valves. Pressure relief or safety valves are used to protect process 

piping and vessels from being accidentally over-pressured. They are spring loaded so 
 26 

that they are fully closed when the upstream pressure is below the set point, and only 

open when the set point is exceeded. Relief valves open in proportion to the amount of 

overpressure to provide modulated venting. Safety valves pop to a full-open positions on 

activation. 

When relief or safety valves reseat after having been activated, they often leak because 

the original tight seat is not regained either due to damage of the seating surface or a 

build-up of foreign material on the seat plug. As a result, they are often responsible for 

fugitive emissions. Another problem develops if the operating pressure is too close to the 

set pressure, causing the valve to "simmer" or "pop" at the set pressure. 

Gas that leaks from a pressure-relief valve may be detected at the end of the vent pipe 

(or horn). Additionally, there normally is a monitoring port located on the bottom of the 

horn near the valve as shown in Figure 4. 

3.1.7 Open-ended Valves and Lines. An open-ended valve is any valve that may release 

process fluids directly to the atmosphere in the event of leakage past the valve seat as 

depicted in Figure 5. The leakage may result from improper seating due to an obstruction 

or sludge accumulation, or because of a damaged or worn seat. An open-ended line is 

any segment of pipe that may be attached to such a valve and that opens to the 

atmosphere at the other end. 

Few open-ended valves and lines are designed into process systems. However, actual 

numbers can be quite significant at some sites due to poor operating practices and 

various process modifications that may occur over time. 

Some common examples of instances where this type of source may occur are listed 

below: 

⋅ scrubber, compressor-unit, station and mainline blowdown valves, 

⋅ supply-gas valve for a gas-operated engine starter (i.e., where natural gas is the 

supply medium), 

⋅ instrument block valves where the instrument has been removed for repair or other 

reasons, and 

⋅ purge or sampling points. 

3.2 Emission Assessment Techniques

There are a variety of different estimation and measurement techniques that may be used to 

assess the amount of methane emissions due to fugitive equipment leaks. These techniques 

may be divided into four basic categories: 

⋅ average emission factors, 

⋅ screening-based approaches, 
 27 

⋅ screening coupled with direct measurement of significant leakers, and 

⋅ whole-facility quantification approaches. 

The basic advantages and disadvantages of each are summarized in Table 1. A detailed 

discussion of the individual approaches is provided in the following subsections. 

Figure 4. Schematic diagram of a pressure-relief valve (U.S. EPA, 1996). 
 28 
 29 

Figure 5. Schematic diagram of an open-ended line. 

3.2.1 Average Emission Factors. The average emission factor method is the simplest, most 

cost-effective, but least reliable, approach for estimating emissions due to fugitive 

equipment leaks. It offers a reasonable first-order means of estimating total fugitive 

emissions from a large number of facilities or for an overall company. However, it 

assumes that the target facility or facilities are well represented by the industry average 

leak statistics. Often, this may be a poor assumption due to differences in environmental 

conditions, maintenance practices, age of equipment, equipment specifications and 

design standards. The results are especially susceptible to errors when the method is 

applied to only a few facilities. For a single facility, the results may easily be in error by 

several orders of magnitude. 

To apply the method, an inventory of equipment components must first be developed for 

each target facility or installation. Ideally, this should be done based on actual site 

surveys or counts taken from process flow diagrams and bills of materials. The use of 

drawings and bills of materials is quite adequate for small, relatively simple, installations 

(e.g., receipt meter stations and farm taps). However, for larger facilities (e.g., border 

meter stations, compressor stations) actual field counts are preferable since the drawings 

and bills of materials become tedious to use and may not provide complete details 

(especially on threaded piping and prepackaged process units such as compressor 

units). 

Special care must be taken when performing component counts to ensure that all 

potential leakage points are being properly tallied and classified. For example, a threaded 

union is equivalent to three connectors, a flanged or threaded valve is counted as a 

valve, two connectors and, possibly, an open-ended valve or line (i.e., if it is open to the 

atmosphere on one side). Specific procedures for counting equipment components are 

provided in Appendix 10.1. 

In the absence of actual information, the default equipment schedules in Table 3 may be 

used to develop the equipment inventory. These schedules were developed based on 

recent field surveys of Canadian gas transmission and distribution facilities. The 

equipment schedules presented for residential meter sites, commercial meter sites, 

industrial meter sites, farm taps, district regulator stations and gate stations are 

expressed on a per-facility or per-site basis. The amount of equipment at gas 

transmission facilities varies widely from site to site. Therefore, the schedules for meter 

stations are on a per-meter-run basis, and compressor stations are on a per-compressorunit basis. The amount of compressor station yard piping, excluding suction and 
 30 

discharge headers and valving for each unit, was found to be essentially independent of 

the number of compressor units. Accordingly, the total number of equipment components 

at a compressor station is determined by adding the components from yard piping plus 

the components from each of the compressor units. If discharge coolers are used on site 

the components from these must also be added. 
 31 

uipment schedules for Canadian gas transmission and distribution facilities. 

mponent 

Distribution Facilities Transmission Facilities 

Residentia

l Meter 

Set1

Commercial 

Meter Set1

Industrial 

Meter Set1

Farm 

Tap1

District 

Regulator 

Station1

Gate 

Station

1

Border 

Meter 

Station2

Receipt/ 

Sales 

Meter 

Station2

Farm 

Tap1

Reciprocatin

g 

Compressor 

Unit3

Centrifugal 

Compressor 

Unit3

Compressor 

Station Yard 

Piping4

nnectors 18 76 122 60 78 240 100 95 60 317 476 747 

ntrol 

ves ---- ---- ---- ---- ---- 1 0 0 ---- 10 3 ---- 

en-Ended 

es 0 0 0 0 1 1 4 10 0 5 10 36 

ssure 

ef 

vices

---- 1 1 2 1 2 1 3 2 1 3 3 

ssure 

gulators

1 3 7 4 4 8 1 2 4 1 3 7 

ck Valves 1 9 29 11 21 54 35 27 11 36 106 227 

wdown 

es ---- ---- ---- ---- ---- 0 0 ---- ---- ---- ---- 11 

ice 

ers ---- ---- 0 ---- 0 1 1 1 ---- ---- ---- ---- 

er Flow 

ers 1 4 4 0 0 1 0 ---- 0 ---- ---- ---- 

rument 

ntrollers ---- ---- ---- ---- ---- 1 0 ---- ---- ---- ---- 2 

rce: Ross and Picard (1966), Table 8, page27. 

Number of components per meter set (for residential, commercial and industrial meter sets) or site (for district and gate stations). 

Number of components per meter run. 

Number of components per compressor unit. 

Number of components per compressor station. For a station with 2 reciprocating units the total number of connectors would be 2*317 +
 32 

747 = 1381. 

Number of components associated with discharge coolers at compressor stations. If the station has discharge coolers, add these additio

components. 

nce the equipment inventory has been compiled, the emissions are estimated using the equation: 

where, 

ER = total leak rate (kg/h) of methane for the target source population (i.e., a sp

facility), 

Fi,j = applicable average emission factor (kg/h/source) for equipment components of type i in service j (see Ta

4), 

,j = total number of potential sources of type i in service j, and 

= mass fraction of methane in the process fluid for service j (see Table 5b for default values). 

he potential fluid service categories are gas/vapour, light liquid and heavy liquid; however, usually, only the first of the

ree categories is applicable at gas transmission and distribution facilities. 

he average emission factors presented in Table 4 for gas transmission and distribution systems are for total organic 

missions. To calculate fugitive methane emissions for a facility, the gas composition must be known. The compositio

atural gas transported by gas transmission and distribution systems can vary significantly depending on the area of t

ountry. Alberta, where the majority of Canada's natural gas is produced, tends to have the greatest variation in 

omposition. Gas that is produced and consumed in Alberta (upstream of any reprocessing plants) may contain as littl

8 mole percent methane, while gas destined for eastern Canada has been reprocessed to remove ethane and heavie

ydrocarbons and typically contains 93 to 97 mole percent methane. 
 33 

Typical compositions of processed natural gas in some of the provinces are summarized in Table 5 (a and b). If the

two or more different incoming gas streams at a facility with notably different compositions, it may be appropriate to

equation (1) by process stream rather than by facility. 
 34 

Forms 3.2.1-1 to 3.2.1-17 presented at the end of this subsection guide the user through 

the application of this average-emission-factor approach for both gas distribution and gas 

transmission facilities. Form 3.2.1-1 outlines the general calculation approach. Forms 

3.2.1-2 to 3.2.1-10 are for application to gas transmission systems, and Forms 3.2.1-11 

to 3.2.1-17 are for application to gas distribution systems. The last form for gas 

distribution systems is designed to capture information on any miscellaneous exposed or 

above-ground equipment that may exist on the pipeline but is located away from 

distribution stations.

4. Average emission factors for estimating fugitive equipment leaks at gas transmission and distribution facilities.

Gas Transmission Facilities

Source Number 

of Sources 

Average 

Emissions 

(kg/h/src) 

95% Confidence Limits Maximum 

Observed 

Emissions 

(kg/h/src) 

Lower Upper 

Connector1 45 357 2.732e-04 2.212e-04 3.252e-04 7.839e-01 

Block Valve2 6 152 2.140e-03 1.281e-03 2.999e-03 2.177e+00 

Control Valve3 273 1.969e-02 5.865e-03 3.352e-02 1.449e-01 

PRV 168 2.795e-01 0.000e+00 6.348e-01 2.814e+01 

Regulator 127 3.304e-03 0.000e+00 7.222e-03 2.413e-01 

Orifice Meter4 104 3.333e-03 1.981e-03 4.684e-03 1.920e-02 

Other Flow Meter5 266 9.060e-06 0.000e+00 1.961e-05 1.400e-03 

Station or Pressurized Comp. Blowdown 

System6

102 9.369e-01 3.598e-01 1.514e+00 2.115e+01 

Comp. Blowdown System - Depressurized 

Recip.9

15 2.347e+00 7.613e-01 3.932e+00 1.013e+01 

Comp. Blowdown System - Depressurized 

Cent.9

18 7.334e-01 0.000e+00 1.489e+00 4.043e+00 

Open-Ended Line 642 8.355e-02 3.926e-02 1.278e-01 8.592e+00 

Instrument Controller7 17 4.681e-01 9.326e-02 8.429e-01 2.387e+00 

Compressor Seal - Centrifugal8 21 8.139e-01 2.316e-01 1.396e+00 3.723e+00 

Compressor Seal - Reciprocating8 36 6.616e-01 4.044e-01 9.188e-01 1.772e+00 

Gas Distribution Meter/Regulator Stations

Source Number 

of Sources 

Average 

Emissions 

(kg/h/src) 

95% Confidence Limits Maximum 

Observed 

Emissions 

(kg/h/src) 
 35 

Lower Upper 

Connector1 8 707 1.098e-04 8.720e-06 2.108e-04 3.371e-01 

Block Valve2 1 985 1.109e-03 0.000e+00 2.911e-03 1.821e+00 

Control Valve3 273 1.969e-02 5.865e-03 3.352e-02 1.890e+00 

PRV 94 1.665e-02 0.000e+00 3.966e-02 1.076e+00 

Regulator 369 1.915e-03 0.000e+00 4.304e-03 3.728e-01 

Orifice Meter4 104 3.333e-03 1.981e-03 4.684e-03 1.920e-02 

Other Flow Meter5 266 9.060e-06 0.000e+00 1.961e-05 1.400e-03 

Station Blowdown System6 102 9.369e-01 3.598e-01 1.514e+00 2.115e+01 

Open-Ended Line 642 8.355e-02 3.926e-02 1.278e-01 8.592e+00 

Instrument Controller7 17 4.681e-01 9.325e-02 8.429e-01 9.534e-01 

Continued ... 

4. Average factors for estimating fugitive equipment leaks at gas transmission and distribution facilities (Concluded) 

Gas Distribution Commercial and Residential Sites

Source Number 

of Sources 

Average 

Emissions 

(kg/h/src) 

95% Confidence Limits Maximum 

Observed 

Emissions 

(kg/h/src) 

Lower Upper 

Connector1 2 913 6.780e-06 0.000e+00 1.568e-05 1.310e-02 

Block Valve2 263 3.330e-06 1.720e-06 4.940e-06 1.000e-04 

PRV 6 2.717e-04 0.000e+00 8.144e-04 1.300e-03 

Regulator 102 2.198e-05 0.000e+00 4.912e-05 1.400e-03 

Orifice Meter4 104 3.333e-03 1.981e-03 4.684e-03 1.920e-02 

Other Flow Meter7 266 9.060e-06 0.000e+00 1.961e-05 1.400e-03 

Open-Ended Line 642 8.355e-02 3.926e-02 1.278e-01 8.592e+00

Source: Ross and Picard (1996), Table 4, page 13. 

1 Includes flanges, threaded connections and mechanical couplings. 

2 Accounts for emissions from the stem packing and the valve body, and it applies to all types of block valves (e.g., butterfly, ball, globe, 

gate, needle, orbit and plug valves). Leakage past the valve seat is accounted for by the Open-Ended Line emission category. 
 36 

Leakage from the end connections is accounted for by the connector category (i.e., one connector for each end). 

3 Accounts for leakage from the stem packing and the valve body. Emissions from the controller and actuator are accounted for by the 

Instrument Controller and Open-Ended Line categories respectively. This factor applies to all valves with automatic actuators 

(including fuel gas injection valves on the drivers of reciprocating compressors). 

4 Accounts for emissions from the orifice changer. Emissions from sources on pressure tap lines etc. are not included in the factor (i.e., 

these emissions must be calculated separately). 

5 Accounts for emissions from other types of gas flow meters (e.g., diaphragm, ultrasonic, roots, turbine and vortex meters). 

6 Accounts for leakage past a valve seat through an open vent line to the atmosphere. These vents are typically six inches or greater in 

diameter and are used to blowdown major process units or sections of pipeline. Small diameter open-ended lines such as those used 

to blowdown chart recorders, meter runs etc. are accounted for by the Open-Ended Line category. 

7 The Instrument Controller category accounts for emissions from pneumatic control devices that use natural gas as the supply medium. 

8 The Compressor Seal categories account for emissions from individual compressor seals (i.e., for a four cylinder reciprocating 

compressor unit there are four seals so the compressor seal emissions for the unit would be four times the factor in the table). 

9 Accounts for leakage past the seats on the compressor unit suction and discharge valves when the compressor is depressurized (i.e., 

the blowdown valve is open to the atmosphere) and there is pressure on the pipeline side of these two isolation valves. 

Typical compo itions (mol p rcent) of processed natural gas by province. s e

Component BC AB SK MB ON 

WA 

Border 

Empres

s 

SK 

Border 

BC 

Border 

AB 

Border 

Regina MN 

Border 

Dawn 

C1

(Methane) 

95.9490 92.8690 97.1294 95.6400 95.2128 95.0600 94.8890 94.7089 

C2 2.4160 4.0556 0.2579 2.5800 2.4306 0.4940 2.4740 2.4805 

C3 0.5440 1.1112 0.0201 0.0700 0.1374 0.0670 0.2130 0.2501 

i-C4 0.0710 0.1601 0.0005 0.0100 0.0043 0.0120 0.0130 0.0300 
 37 

n-C4 0.1130 0.2180 0.0005 0.0100 0.0043 0.0110 0.0200 0.0400 

i-C5 0.0190 0.0496 0.0008 0.0000 0.0013 0.0040 0.0050 0.0200 

n-C5 0.0110 0.0389 0.0004 0.0000 0.0010 0.0030 0.0080 0.0100 

C6 0.0260 0.0225 0.0001 0.0100 0.0012 0.0070 0.0030 0.0100 

C7+ 0.0000 0.0126 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 

CO2 0.1250 0.6334 0.2618 0.5400 0.5552 0.1290 0.6560 0.6201 

N2 0.7260 0.8291 2.3284 1.1400 1.6519 4.2130 1.7190 1.8304 

Total 100.0000 100.000

0 

100.0000 100.0000 100.0000 100.0000 100.0000 100.0000

Source: Unpublished data from the files of Clearstone Engineering Ltd.

Typical compo itions (mass ercent) of processed natural gas by province. s p

Component BC AB SK MB ON 

WA 

Border 

Empres

s 

SK 

Border 

BC 

Border 

AB 

Border 

Regina MN 

Border 

Dawn 

C1

(Methane) 

91.7957 85.4537 94.7955 91.7267 91.0242 91.3750 90.2786 89.8694 

C2 4.3324 6.9946 0.4718 4.6379 4.3553 0.8900 4.4118 4.4117 

C3 1.4306 2.8104 0.0539 0.1845 0.3611 0.1770 0.5570 0.6523 

i-C4 0.2461 0.5337 0.0018 0.0347 0.0149 0.0418 0.0448 0.1031 

n-C4 0.3917 0.7268 0.0018 0.0347 0.0149 0.0383 0.0689 0.1375 

i-C5 0.0818 0.2053 0.0035 0.0000 0.0056 0.0173 0.0214 0.0854 

n-C5 0.0473 0.1610 0.0018 0.0000 0.0043 0.0130 0.0342 0.0427 

C6 0.1336 0.1112 0.0005 0.0515 0.0062 0.0361 0.0153 0.0510 

C7+ 0.0000 0.0724 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000 

CO2 0.3281 1.5988 0.7009 1.4207 1.4561 0.3402 1.7121 1.6142 

N2 1.2128 1.3321 3.9680 1.9091 2.7575 7.0712 2.8557 3.0328 

Total 100.0000 100.000 100.0000 100.0000 100.0000 100.0000 100.0000 100.0000
 38 

0 

Source: Unpublished data from the files of Clearstone Engineering Ltd. 

Calculation Form 3.2.1-1 

FUGITIVE EQUIPMENT LEAKS

General Steps

Step No. Description Default 

Values1

1 Establish the component count by type of component. Table 3 

 

 2 Multiply the results from Step (1) by the fraction of the time 

the components are in active hydrocarbon service. 

1.0 

3 Multiply the results from Step (2) by the corresponding 

component emission factor. 

Tables 4 

4 Sum up total emissions for each component type to calculate 

unit emissions per facility type. 

Calculation Forms

3.2.1-2 to 3.2.1-14

5 Convert to annual emissions by multiplying result of Step (4) 

by number of hours in a year. 8760 h/y 

6 Multiply results from Step (5) by corresponding numbers of 

facilities. 

None 

7 Multiply results from Step (6) by correction factor for methane 

content by weight. 

Table 5b: 

C1 divided by 100
 39 

8 Multiply results from Step (7) by factor for converting from kg 

to tonnes of methane. 

10-3 t/kg 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-2 

FUGITIVE EQUIPMENT LEAKS

Transmission - Border Meter Stations

COMPONENT TYPE RUN-AVERAGE

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4)

Connectors 100 1.0 2.732 X 10-4 273.2 

Control Valves 1.969 X 10-2

Open-Ended Lines 4 1.0 8.355 X 10-2 3342 

Pressure-Relief Devices 1 1.0 2.795 X 10-1 2795 

Pressure Regulators 1 1.0 3.304 X 10-3 33.04 

Block Valves 35 1.0 2.140 X 10-3 749 

Orifice Meters 
 40 

1 1.0 3.333 X 10-3 33.33 

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER METER RUN AT BORDER METER 

STATIONS 

7,225.57 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-3 

FUGITIVE EQUIPMENT LEAKS

Transmission - Receipt and Sales Meter Stations

COMPONENT TYPE RUN-AVERAGE

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4)

Connectors 95 1.0 2.732 X 10-4 259.54 

Control Valves 1.969 X 10-2

Open-Ended Lines 10 1.0 8.355 X 10-2 8355 

Pressure-Relief Devices 3 1.0 2.795 X 10-1 8385 

Pressure Regulators 2 1.0 3.304 X 10-3 66.08 
 41 

Block Valves 27 1.0 2.140 X 10-3 577.8 

Orifice Meters 1 1.0 3.333 X 10-3 33.33 

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER METER RUN AT RECEIPT STATIONS 17,676.75 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-4 

FUGITIVE EQUIPMENT LEAKS

Transmission - Farm Taps

COMPONENT TYPE SITEAVERAGECOM

PONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENTE

MISSION 

FACTOR1

(kg/h) 

NATURAL 

GASEMISSION

S 

(kg/h x 10-4)

Connectors 60 1.0 2.732 X 10-4 163.92 

Control Valves 1.969 X 10-2

Open-Ended Lines 8.355 X 10-2
 42 

Pressure-Relief Devices 2 1.0 2.795 X 10-1 5590 

Pressure Regulators 4 1.0 3.304 X 10-3 132.16 

Block Valves 11 1.0 2.140 X 10-3 235.4 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER TRANSMISSION FARM TAP 6,121.48 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-5 

FUGITIVE EQUIPMENT LEAKS Transmission - BlockValve Stations

COMPONENT TYPE STATIONAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4)

Connectors 30 1.0 2.732 X 10-4 81.96 

Control Valves 1.969 X 10-2
 43 

Open-Ended Lines 1 1.0 8.355 X 10-2 835.50 

Pressure-Relief Devices 2.795 X 10-1

Pressure Regulators 3.304 X 10-3

Block Valves 7 1.0 2.140 X 10-3 149.8 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER BLOCK-VALVE STATION 1,067.26 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-6 

FUGITIVE EQUIPMENT LEAKS

Transmission - Control-Valve Stations

COMPONENT TYPE STATIONAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4)

Connectors 126 1.0 2.732 X 10-4 344.23 
 44 

Control Valves 1 1.0 1.969 X 10-2 196.9 

Open-Ended Lines 1 1.0 8.355 X 10-2 835.50 

Pressure-Relief Devices 2.795 X 10-1

Pressure Regulators 3.304 X 10-3

Block Valves 8 1.0 2.140 X 10-3 171.2 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER CONTROL-VALVE STATION 1,547.83 

1 The presented data are based on national averages and, for improved accuracy, should be replaced with 

company-specific values where available.

 Calculation Form 3.2.1-7 

FUGITIVE EQUIPMENT LEAKS

Transmission - Reciprocating Compressor Units

COMPONENT TYPE UNITAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4) 
 45 

Connectors 317 1.0 2.732 X 10-4

866.04 

Control Valves 10 

 

1.0 1.969 X 10-2

1969 

Open-Ended Lines 15 1.0 8.355 X 10-2

4177.5 

Pressure-Relief Devices 1 1.0 2.795 X 10-1

2795 

Pressure Regulators 1 1.0 3.304 X 10-3

33.04 

Block Valves 36 1.0 2.140 X 10-3

770.4 

Compressor Blowdown System 

 (Depressurized Periods) 

1 0.446 2.347 10,467.6 

Compressor Blowdown System 

 (Pressurized Periods) 

1 0.554 9.369 X 10-1

5,190.4 

Compressor Seals 3.3 

(1 per cylinder) 

0.554 6.616 X 10-1

3,665.3 

Orifice Meters 1.0 3.333 X 10-3

 

Other Flow Meters 1.0 9.060 X 10-6

Instrument Controllers 1.0 4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER RECIPROCATING COMPRESSOR UNIT 29,934.3 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.
 46 

 Calculation Form 3.2.1-8 

FUGITIVE EQUIPMENT LEAKS

Transmission - Centrifugal Compressor Units

COMPONENT TYPE UNITAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4) 

Connectors 479 1.0 2.732 X 10-4

1308.63 

Control Valves 3 1.0 1.969 X 10-2

590.7 

Open-Ended Lines 10 1.0 8.355 X 10-2

8355 

Pressure-Relief Devices 3 1.0 2.795 X 10-1

8385 

Pressure Regulators 3 1.0 3.304 X 10-3

99.12 

Block Valves 106 1.0 2.140 X 10-3

2268.4 

Compressor Blowdown System 

 (Depressurized Periods) 

1 0.446 7.334 X 10-1

3,271.0 

Compressor Blowdown System 

 (Pressurized Periods) 

1 0.554 9.369 X 10-1

5,190.4 

Compressor Seals 2 0.554 8.139 X 10-1

9,018.0 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6
 47 

Instrument Controllers 4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER CENTRIFUGAL COMPRESSOR UNIT 38,486.3 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available. 

 Calculation Form 3.2.1-9 

FUGITIVE EQUIPMENT LEAKS

Transmission - Compressor Discharge Coolers

COMPONENT TYPE UNITAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4) 

Connectors 2937 1.0 2.732 X 10-4

8023.88 

Control Valves 1.969 X 10-2

Open-Ended Lines 8.355 X 10-2

Pressure-Relief Devices 2.795 X 10-1

Pressure Regulators 3.304 X 10-3

Block Valves 19 1.0 2.140 X 10-3

406.6 

Blowdown Lines 2.347 
 48 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER DISCHARGE COOLER 8,430.48 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available. 

 Calculation Form 3.2.1-10 

FUGITIVE EQUIPMENT LEAKS

Transmission - Compressor/Booster Station Yard Piping

COMPONENT TYPE STATIONAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4) 

Connectors 747 2.732 X 10-4

2040.8 

Control Valves 1.969 X 10-2

Open-Ended Lines 36 8.355 X 10-2

30078 

Pressure-Relief Devices 3 2.795 X 10-1

8385 

Pressure Regulators 7 3.304 X 10-3

231.28 

Block Valves 227 2.140 X 10-3

4857.8 
 49 

Blowdown Lines 11 2.347 258170 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 4.681 X 10-1

AVERAGE TOTAL EMISSIONS FROM YARD PIPING PER COMPRESSOR/BOOSTER 

STATION 

303,762.88 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available. 

 Calculation Form 3.2.1-11 

FUGITIVE EQUIPMENT LEAKS

Distribution - Gate Stations

COMPONENT TYPE STATIONAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4)

Connectors 240 1.0 1.098 X 10-4 263.52 
 50 

Control Valves 1 1.0 1.969 X 10-2 196.9 

Open-Ended Lines 1 1.0 8.355 X 10-2 835.5 

Pressure-Relief Devices 2 1.0 1.665 X 10-2 333 

Pressure Regulators 8 1.0 1.915 X 10-3 153.2 

Block Valves 54 1.0 1.109 X 10-3 598.86 

Orifice Meters 1 1.0 3.333 X 10-3 33.33 

 

Other Flow Meters 1 1.0 9.060 X 10-6 0.09 

Instrument Controllers 

1 1.0 4.681 X 10-1 4681 

AVERAGE TOTAL EMISSIONS PER GATE STATION 7,095.40 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-12 

FUGITIVE EQUIPMENT LEAKS

Distribution - District Regulating Stations

COMPONENT TYPE STATIONAVERAGE 

COMPONENT 

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

NATURAL GAS 

EMISSIONS 
 51 

COUNT1 (kg/h) (kg/h x 10-4)

Connectors 78 1.0 1.098 X 10-4 85.644 

Control Valves 1.969 X 10-2

Open-Ended Lines 1 1.0 8.355 X 10-2 835.5 

Pressure-Relief Devices 1 1.0 1.665 X 10-2 166.5 

Pressure Regulators 4 1.0 1.915 X 10-3 76.6 

Block Valves 21 1.0 1.109 X 10-3 232.89 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 

4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER DISTRICT REGULATING STATION 1,397.134 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-13 
 52 

FUGITIVE EQUIPMENT LEAKS

Distribution - Farm Taps

COMPONENT TYPE FACILITYAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4)

Connectors 60 1.098 X 10-4 65.88 

Control Valves 1.969 X 10-2

Open-Ended Lines 8.355 X 10-2

Pressure-Relief Devices 2 1.665 X 10-2 333 

Pressure Regulators 4 1.915 X 10-3 76.6 

Block Valves 11 1.109 X 10-3 121.99 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 

4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER DISTRIBUTION FARM TAP FACILITY 597.47 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.
 53 

 Calculation Form 3.2.1-14 

FUGITIVE EQUIPMENT LEAKS

Distribution - Industrial Meter Sets

COMPONENT TYPE STATIONAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4)

Connectors 122 1.0 1.098 X 10-4 133.956 

Control Valves 1.969 X 10-2

Open-Ended Lines 8.355 X 10-2

Pressure-Relief Devices 1 1.0 1.665 X 10-2 166.5 

Pressure Regulators 7 1.0 1.915 X 10-3 134.05 

Block Valves 29 1.0 1.109 X 10-3 321.61 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 4 1.0 9.060 X 10-6 0.362 

Instrument Controllers 
 54 

4.681 X 10-1

AVERAGE TOTAL EMISSIONS PER INDUSTRIAL METER STATION 756.478 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-15 

FUGITIVE EQUIPMENT LEAKS

Distribution - Commercial Meter Sets

COMPONENT TYPE STATIONAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/hour) 

NATURAL GAS 

EMISSIONS 

(kg/hour x 10-4)

Connectors 76 1.0 6.780 X 10-6 5.1528 

Control Valves ___ 

Open-Ended Lines 8.355 X 10-2

Pressure-Relief Devices 1 1.0 2.717 X 10-4 2.717 

Pressure Regulators 3 1.0 2.198 X 10-5 0.6594 

Block Valves 9 1.0 3.330 X 10-6 0.2997 
 55 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 4 1.0 9.060 X 10-6 0.3624 

Instrument Controllers 

8.355 X 10-2 

AVERAGE TOTAL EMISSIONS PER COMMERCIAL METER STATION 9.1913 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-16 

FUGITIVE EQUIPMENT LEAKS

Distribution - Residential Meter Sets

COMPONENT TYPE STATIONAVERAGE 

COMPONENT 

COUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1

(kg/h) 

NATURAL GAS 

EMISSIONS 

(kg/h x 10-4)

Connectors 18 1.0 6.780 X 10-6 1.2204 

Control Valves ___ 

Open-Ended Lines 8.355 X 10-2

Pressure-Relief Devices 2.717 X 10-4
 56 

Pressure Regulators 1 1.0 2.198 X 10-5 0.2198 

Block Valves 1 1.0 3.330 X 10-6 0.0333 

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 1 1.0 9.060 X 10-6 0.0906 

Instrument Controllers 8.355 X 10-2 

AVERAGE TOTAL EMISSIONS PER RESIDENTIAL METER STATION 1.5641 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

 Calculation Form 3.2.1-17 

FUGITIVE EQUIPMENT LEAKS

Distribution - Miscellaneous Pipeline Equipment

COMPONENT TYPE STATIONAVERAGE 

COMPONENTC

OUNT1

FRACTION OF 

TIME IN 

SERVICE1

COMPONENT 

EMISSION 

FACTOR1(kg/ho

ur) 

NATURAL GAS 

EMISSIONS 

(kg/hour x 10-4)

Connectors 1.098 X 10-4

Control Valves 1.969 X 10-2
 57 

Open-Ended Lines 8.355 X 10-2

Pressure-Relief Devices 1.665 X 10-2

Pressure Regulators 1.915 X 10-3

Block Valves 1.109 X 10-3

Orifice Meters 3.333 X 10-3

 

Other Flow Meters 9.060 X 10-6

Instrument Controllers 4.681 X 10-1 

TOTAL EMISSIONS FOR ALL MISCELLANEOUS EQUIPMENT ON SYSTEM 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

3.2.2 Screening-based Approaches. Screening-based approaches require that a full leak 

detection program be conducted at each target facility. This would normally be done 

using a portable intrinsically-safe organic vapour analyzer (OVA) in accordance with U.S. 

EPA's Method 21 (see Appendix 10.4). Basically, the OVA is used to measure the 

maximum concentration of organic vapours above background at each potential leakage 

point. The results are then recorded along with the corresponding type of component and 

service. Thus, the leak survey provides both an inventory of equipment components and 

an indirect measure of leakage. Moreover, it identifies specific components in need of 

repair. 

To achieve realistic results the screening should be done towards the middle of a 
 58 

maintenance period (e.g., midway between scheduled facility turn-arounds). Most 

screening instruments will not function properly in cold weather, which makes screening 

difficult to do during the winter. Also, not all components are accessible for screening 

(e.g., due to high temperatures, heights, or being covered by insulation). Useful data to 

record during a leak survey includes the following (the critical items are presented in 

italicized text): 

⋅ monitoring instrument type and model, 

⋅ operator's name, 

⋅ date,

⋅ facility name,

⋅ component identification number (if permanent IDs are not in place, assign IDs as 

each source is screened), 

⋅ component type (e.g., valve, connector, open-ended line, etc.), style, and nominal 

size,

⋅ process unit/stream where the screened component is located, 

⋅ process fluid type and composition, 

⋅ process conditions (i.e., temperature and pressure), 

⋅ ambient conditions (e.g., mean temperature, pressure and wind speed), 

⋅ service (i.e., gas, light liquid or heavy liquid),

⋅ number of hours per year the component is in service, 

⋅ screening value (ppm), 

⋅ background concentration (ppm), and 

⋅ comments. 

A single person usually can screen about 350 components per day (based on a full 8-

hour work day), and an OVA can be rented for $2000.00 per month. However, 

allowances need to be made for travel time and expenses, as well as subsistence and 

accommodation charges where applicable. Typically, the total costs of performing a leak 

survey may be in the range of $2.50 to $3.50+ per component. 

Response factors may be applied to the raw screening values to correct for the 

analyzer's sensitivity to the actual chemical composition of the sampled vapours. 

However, provided the instrument has been calibrated to methane, there will be little 

benefit in doing this (e.g., less than a 10 percent change in the estimated emissions). 

Some instrument manufacturers provide response factors in their user documentation. As 

well, some published values for selected analyzers are presented by Picard et al. (1992) 

and U.S. EPA (1995). 

The data compiled from a leak survey may be used to estimate leak rates by applying 

one of the following methods, presented in the order of increasing sophistication and 

accuracy: 
 59 

⋅ leak/no-leak emission factors, 

⋅ three-stratum emission factors, 

⋅ published leak-rate correlations, 

⋅ unit-specific leak-rate correlations, and 

⋅ no-leak factors coupled with sampling of leakers. 

It should be noted that in the chemical manufacturing and petroleum refining industries, 

where the implementation of a formal leak detection and repair program is mandatory, 

CCME guidelines set the use of three-stratum emission factors as the minimum accepted 

method for estimating emissions from fugitive equipment leaks. Notwithstanding this, the 

effort in any screening-based approaches is in performing the leak survey, not in 

performing the calculations. The screening work is essentially the same for the leak/noleak approach through to the correlation approach, with only slight differences in the 

actual information recorded. Consequently, in most cases it would make sense to simply 

use the correlation approach since it gives the most reliable results. Several commercial 

software packages are available for managing the compiled data and performing the 

necessary calculations. Alternatively, a simple spreadsheet or database application may 

be developed for this purpose. 

CMA (1989) and U.S. EPA (1988) recommend complete screening of all process 

components for all source/service categories except connectors. Due to their large 

number at most facilities, it is suggested that a statistically significant random screening 

of the connectors be conducted. The minimum sample size is determined using the 

equation: 

where, 

n = minimum sample size, and 

N = total number of process connectors. 

Equation (2) assumes a binomial distribution, a leak frequency for connectors of 2.09 

percent and minimum confidence limits of 95 percent. 
 60 

3.2.2.1 Leak/No-leak Emission Factors. To apply this approach, the screening 

values must be classified as either leaking (i.e., has a maximum screening 

value of 10 000 ppm or more) or non-leaking (i.e., has a maximum 

screening value of less than 10 000 ppm), and categorized by type of 

component and type of service. The amount of emissions is then estimated 

for each source category using the equation: 

where, 

= total methane leak rate (kg/h) of pollutant k for the target 

source population, 

= appropriate leaking emission factor for the source/service 

category of interest (see Table 6), 

= appropriate non-leaking emission factor for the components of 

type i in service j (see Table 6), 

= number of components screened and determined to be 

leaking (i.e., give a screening value of 10 000 ppm or more) 

for the source category of interest, 

= number of components screened and determined not to be 

leaking (i.e., give a screening value of less than 10 000 ppm, 

including those sources with a screening value of zero) for the 

source category of interest, 

= total number of components of type i in service j (i.e., all 

components screened plus those not screened), 

= mass fraction of methane in the process stream (see Table 

5b). 

It is assumed, in using the leak/no-leak method, that components within 

each screening range leak, on average, at the same as rate as for the rest 

of the gas industry. However, the experience in other industries is this not is 

not necessarily true (Schaich and Stine, 1989). For example, example 
 61 

significant differences have been noted in the relative number of sources 

with zero screening values. A zero screening value indicates that the true 

screening value of the source is below the lower detectable limit of the 

analyzer. 

eak/No-leak emission factors for estimating fugitive equipment leaks at 

Canadian natural gas transmission and distribution facilities. 

Gas Transmission Facilities

Source Number 

of 

Sources 

Perce

nt of 

Sourc

es 

Emissions 

(kg/h/src) 

95% Confidence Limits

Lower Upper 

Connector1 No 

Leak9

44512 98.79 0.0000338 0.0000271 0.0000406 

Leak10 556 1.21 0.01856 0.01465 0.02247

Block Valve2 No 

Leak 

5907 96.02 0.0006132 0.0 0.001342 

Leak 245 3.98 0.03895 0.02728 0.05062

Control Valve3 No 

Leak 

233 85.35 0.01006 0.007532 0.01259

Leak 40 14.65 0.07581 0.0 0.1706

PRV No 

Leak 

63 33.87 0.0006471 0.0 0.001537 

Leak 123 66.13 0.3814 0.0 0.8673

Regulator No 

Leak 

108 83.72 0.0000398 0.0000175 0.0000474 

Leak 21 16.28 0.01977 0.004751 0.03439

Orifice Meter4 No 

Leak 

83 79.81 0.001925 0.0006846 0.003165

Leak 21 20.19 0.0088 0.004936 0.01286

Other Flow Meter5 No 

Leak 

259 97.37 0.0000037 0.0000016 0.0000059 

Leak 7 2.63 0.0002064 0.0 0.0006932

Station or Pressurized No 

Leak 

27 26.47 0.0006213 0.0 0.001641

Compressor Blowdown 

System6

Leak 75 73.53 1.274 0.4989 2.049

Compressor Blowdown System No 4 26.67 0.000 0.0 0.0
 62 

- Leak 

Depressurized Reciprocating Leak 11 73.33 3.200 1.245 5.155

Compressor Blowdown System 

- 

No 

Leak 

7 38.89 0.000 0.0 0.0

Depressurized Centrifugal Leak 11 61.11 1.200 0.0 2.422

Open-Ended Line No 

Leak 

179 27.88 0.0001127 0.0000249 0.0002006 

Leak 463 72.12 0.1158 0.05458 0.177

Instrument Controller7 No 

Leak 

---- 0.00 ---- ---- ---- 

Leak 17 100.0

0

0.4681 0.09325 0.8429

Compressor Seal - 

Reciprocating8

No 

Leak 

5 13.89 0.00056 0.0 0.002115

Leak 31 86.11 0.7682 0.4865 1.049

Compressor Seal - Centrifugal8 No 

Leak 

1 4.77 0.0000075 ---- ----

Leak 20 95.23 0.8546 0.2469 1.462

Continued... 
 63 

eak/No-leak emission factors for estimating fugitive equipment leaks at 

Canadian natural gas transmission and distribution facilities (Continued). 

Gas Distribution Meter/Regulator Stations

Source Number 

of 

Sources 

Perce

nt of 

Sourc

es 

Emissions 

(kg/h/src) 

95% Confidence Limits

Lower Upper 

Connector1 No 

Leak 

8515 99.18 0.0000043 0.0000036 0.000005 

Leak 70 0.82 0.01292 0.0004211 0.02542

Block Valve2 No 

Leak 

1910 96.22 0.0000251 0.0000153 0.0000349 

Leak 75 3.78 0.02872 0.0 0.07705

Control Valve3 No 

Leak 

233 85.35 0.01006 0.007532 0.01259

Leak 40 14.65 0.07581 0.0 0.1706

PRV No 

Leak 

79 84.04 0.0006457 0.0001085 0.001183 

Leak 15 15.96 0.1009 0.0 0.2523

Regulator No 

Leak 

352 95.39 0.0000137 0.0000098 0.0000175

Leak 17 4.61 0.04129 0.0 0.09472

Orifice Meter4 No 

Leak 

83 79.81 0.001925 0.0006846 0.003165

Leak 21 20.19 0.0088 0.004936 0.01286

Other Flow Meter5 No 

Leak 

259 97.37 0.0000037 0.0000016 0.0000059 

Leak 7 2.63 0.0002064 0.0 0.0006932

Station Blowdown System6 No 

Leak 

27 26.47 0.0006213 0.0 0.001641

Leak 75 73.53 1.274 0.4989 2.049

Open-Ended Line No 

Leak 

179 27.88 0.0001127 0.0000249 0.0002006 

Leak 463 72.12 0.1158 0.05458 0.177

Instrument Controller7 No 

Leak 

---- 0.00 ---- ---- ---- 

Leak 17 100.0

0

0.4681 0.09325 0.8429
 64 

Gas Distribution Commercial and Residential Sites

Source Number 

of 

Sources 

Perce

nt of 

Sourc

es 

Emissions 

(kg/h/src) 

95% Confidence Limits

Lower Upper 

Connector1 No 

Leak 

2759 99.60 0.0000015 0.0000011 0.0000018 

Leak 11 0.40 0.001279 0.0 0.003918

Block Valve2 No 

Leak 

258 99.61 0.0000021 0.0000011 0.000003 

Leak 1 0.39 0.0001 ---- ---- 

PRV No 

Leak 

6 100.0

0

0.0002717 0.0 0.0008144 

Leak ---- 0.00 ---- ---- ---- 

Regulator No 

Leak 

95 93.14 0.0000087 0.0000066 0.0000108 

Leak 7 6.86 0.000202 0.0 0.0006906

Orifice Meter4 No 

Leak 

83 79.81 0.001925 0.0006846 0.003165

Leak 21 20.19 0.0088 0.004936 0.01286

Other Flow Meter5 No 

Leak 

259 97.37 0.0000037 0.0000016 0.0000059 

Leak 7 2.63 0.0002064 0.0 0.0006932

Open-Ended Line No 

Leak 

27 26.47 0.0006213 0.0 0.001641

Leak 75 73.53 1.274 0.4989 2.049

eak/No-leak emission factors for estimating fugitive equipment leaks at 

Canadian natural gas transmission and distribution facilities (Concluded).

Gas Distribution Commercial and Residential Sites

Source Number 

of 

Sources 

Perce

nt of 

Sourc

es 

Emissions 

(kg/h/src) 

95% Confidence Limits 

Lower Upper 
 65 

Source: Ross and Picard (1996), Table 6, page 19. 

---- No data available. 

1 Includes flanges, threaded connections and mechanical couplings. 

2 Accounts for emissions from the stem packing and the valve body, and it applies to all types of 

block valves (e.g., butterfly, ball, globe, gate, needle, orbit and plug valves). Leakage past the 

valve seat is accounted for by the Open-Ended Line emission category. Leakage from the end 

connections is accounted for by the connector category (i.e., one connector for each end). 

3 Accounts for leakage from the stem packing and the valve body. Emissions from the controller and actuator 

are accounted for by the Instrument Controller and Open-Ended Line categories respectively. This factor 

applies to all valves with automatic actuators (including fuel gas injection valves on the drivers of 

reciprocating compressors). 

4 Accounts for emissions from the orifice changer. Emissions from sources on pressure tap lines etc. are not 

included in the factor (i.e., these emissions must be calculated separately). 

5 Accounts for emissions from other types of gas flow meters (e.g., diaphragm, ultrasonic, roots, turbine and 

vortex meters). 

6 Accounts for leakage past a valve seat through an open vent line to the atmosphere. These vents are 

typically six inches or greater in diameter and are used to blowdown major process units or sections of 

pipeline. Small diameter open-ended lines such as those used to blowdown chart recorders, meter runs etc. 

are accounted for by the Open-Ended Line category. 

7 The Instrument Controller category accounts for emission from pneumatic control devices that use natural 

gas as the supply medium. 

8 The Compressor Seal categories account for emissions from individual compressor seals (i.e., for a four 

cylinder reciprocating compressor unit there are four seals so the compressor seal emissions for the unit 

would be four times the factor in the table). 

9 Non-leaking components with screening values of less than 10 000 ppm. 

10 Leaking components with screening values of 10 000 ppm or greater. 
 66 

3.2.2.2 Three-stratum Emission Factors. Use of the three-stratum factors offers a 

further increase in rigour and reliability from use of the leak/no-leak factors. 

The sources are categorized based on three ranges of screening values: 0 

to 1 000 ppm, 1 001 to 10 000 ppm and over 10 000 ppm. The amount of 

emissions is estimated for each source category using the equation: 

where, 

EF1, EF2, EF3 = THC emission factors for sources with screening 

values in the range of 0 to 1 000 ppm, 1 001 to 10 000 

ppm, and over 10 000 ppm, respectively (see Table 7), 

n1, n2, n3 = total number of sources surveyed that had screening 

values in the range of 0 to 1 000 ppm, 1 001 to 

10 000 ppm, and over 10 000 ppm, respectively, and 

The basic assumptions inherent in use of the three-stratum emission factor 

method are the same as those presented for the leak/no-leak method (see 

Section 3.2.2.1). 

3.2.2.3 Published Leak-Rate Correlations. Leak-rate correlations provide a 

method for estimating the leak rates corresponding to individual screening 

values. The use of this approach is a considerable refinement over the 

available emission-factor methods in which constants are applied over 

discrete ranges of screening values. 

The correlations are given by a two-constant relation of the form given 

below: 

Log (ER) = B0 + B1 Log(SV) (5) 

where: 

B0, B1 = model parameters as given in Table 8, 

ER = leak rate in (kg/h/source), and 
 67 

SV = maximum screening value above background 

measured using a detector calibrated to methane 

(ppm) 

Three-stratum emission factors for estimating fugitive equipment leaks at Canadian 

 gas transmission and distribution facilities. 

Gas Transmission Facilities

Source Number 

of 

Sources 

Percent 

of 

Sources 

Emissions 

(kg/h/src) 

95% Confidence Limits 

Lower Upper 

Connector1 <1000 44207 98.1 0.0000032 0.000003 0.0000033 

1000-10000 

>10000 

305 

556

0.7 

1.2

0.004480 

0.01856

0.003623 

0.01465 

0.005337 

0.02247

Block Valve2 <1000 5803 94.3 0.0005027 0.0 0.001242 

1000-10000 

>10000 

104 

245

1.7 

4.0

0.006782 

0.03895

0.003705 

0.02728 

0.009858 

0.05062

Control Valve3 <1000 167 61.2 0.000027 0.0000197 0.0000344

1000-10000 

>10000 

66 

40

24.2 

14.6

0.03544 

0.07581

0.03020 

0.0 

0.04068 

0.1706

PRV <1000 60 32.3 0.0002125 0.0000619 0.003632

1000-10000 

>10000 

3 

123

1.6 

66.1

0.009339 

0.3814

0.0 

0.0 

0.04927 

0.8673

Regulator <1000 10 26.3 0.0000127 0.0000099 0.0000155 

1000-10000 

>10000 

7 

21

18.4 

55.3

0.0004301 

0.01977

0.0001985 

0.004751 

0.0006618 

0.03439

Orifice Meter4 <1000 67 64.4 0.000032 0.0000198 0.0000442

1000-10000 

>10000 

16 

21

15.4 

20.2

0.009850 

0.0088

0.004703 

0.004936 

0.01500 

0.01286

Other Flow Meter5 <1000 258 97.0 0.000003 0.0000014 0.0000045 

1000-10000 

>10000 

1 

7

0.4 

2.6

0.0002000 

0.0002064

---- 

0.0 

---- 

0.0006932 

Station or Pressurized 

Compressor 

Blowdown System6

<1000 25 24.5 0.000023 0.000001 0.000045

1000-10000 

>10000 

2 

75

2.0 

73.5

0.008100 

1.274

---- 

0.4989 

---- 

2.049 

Compressor Blowdown <1000 4 26.67 0.0 0.0 0.0
 68 

System - 

Depressurized Reciprocating 1000-10000 

>10000 

---- 

11

---- 

73.33

 ---- 

3.200

 ---- 

1.245 

 ---- 

5.155

Compressor Blowdown 

System - 

<1000 7 38.89 0.0 0.0 0.0

Depressurized Centrifugal 1000-10000 

>10000 

---- 

11

---- 

61.11

 ---- 

1.200

 ---- 

0.0 

 ---- 

2.422

Open-Ended Line <1000 173 27.0 0.0000288 0.0000161 0.0000415

1000-10000 

>10000 

6 

463

0.9 

72.1

0.002533 

0.1158

0.0001628 

0.05458 

0.004904 

0.1770

Instrument Controller7 <1000 ---- ---- ---- ---- ---- 

1000-10000 

>10000 

---- 

17

---- 

100.0

---- 

0.4681 

---- 

0.09325 

---- 

0.8429 

Compressor Seal - <1000 5 13.9 0.00056 0.0 0.002115

Reciprocating8 1000-10000 

>10000 

---- 

31

---- 

86.1

---- 

0.7682 

---- 

0.4865 

---- 

1.049 

Compressor Seal - <1000 1 4.8 0.0000075 ---- ---- 

Centrifugal8 1000-10000 

>10000 

---- 

20

---- 

95.2

---- 

0.8546 

---- 

0.2469 

---- 

1.462 

Three-stratum emission factors for estimating fugitive equipment leaks at Canadian 

gas transmission and distribution facilities (Continued). 

Gas Distribution Meter/Regulator Stations

Source Number 

of 

Sources 

Percent 

of 

Sources 

Emissions 

(kg/h/src) 

95% Confidence Limits 

Lower Upper 

Connector1 <1000 8465 98.6 0.0000023 0.000002 0.0000025 

1000-10000 

>10000 

50 

70

0.6 

0.8

0.0003450 

0.01292

0.0002692 

0.0004211 

0.0004208 

0.02542

Block Valve2 <1000 1875 94.4 0.0000157 0.0000069 0.0000245

1000-10000 

>10000 

35 

75

1.8 

3.8

0.0005276 

0.02872

0.0003296 

0.0 

0.0007256 

0.07705

Control Valve3 <1000 167 61.2 0.000027 0.0000197 0.0000344

1000-10000 

>10000 

66 

40

24.2 

14.6

0.03544 

0.07581

0.03020 

0.0 

0.04068 

0.1706

PRV <1000 74 78.7 0.0001028 0.000022 0.001836

1000-10000 

>10000 

5 

15

5.3 

16.0

0.008680 

0.1009

0.002626 

0.0 

0.01473 

0.2523
 69 

Regulator <1000 346 93.8 0.0000098 0.0000084 0.0000126

1000-10000 

>10000 

6 

17

1.6 

4.6

0.0002333 

0.04129

0.0000753 

0.0

0.0003913 

0.09472

Orifice Meter4 <1000 67 64.4 0.000032 0.0000198 0.0000442

1000-10000 

>10000 

16 

21

15.4 

20.2

0.009850 

0.0088

0.004703 

0.004936

0.01500 

0.01286

Other Flow Meter5 <1000 258 97.0 0.000003 0.0000014 0.0000045 

1000-10000 

>10000 

1 

7

0.4 

2.6

0.0002000 

0.0002064

---- 

0.0 

---- 

0.0006932 

Station Blowdown System6 <1000 25 24.5 0.000023 0.000001 0.000045

1000-10000 

>10000 

2 

75

2.0 

73.5

0.008100 

1.274

---- 

0.4989 

---- 

2.049 

Open-Ended Line <1000 173 27.0 0.0000288 0.0000161 0.0000415

1000-10000 

>10000 

6 

463

0.9 

72.1

0.002533 

0.1158

0.0001628 

0.05458

0.004904 

0.1770

Instrument Controller7 <1000 ---- ---- ---- ---- ---- 

1000-10000 

>10000 

---- 

17

---- 

100.0

---- 

0.4681 

---- 

0.09325 

---- 

0.8429 

Continued... 
 70 

Three-stratum emission factors for estimating fugitive equipment leaks at Canadian 

gas transmission and distribution facilities (Concluded). 

Gas Distribution Commercial and Residential Sites

Source Number 

of 

Sources 

Percent 

of 

Sources 

Emissions 

(kg/h/src) 

95% Confidence Limits 

Lower Upper 

Connector1 <1000 2757 99.5 0.0000013 0.000001 0.0000016 

1000-10000 

>10000 

2 

11

0.1 

0.4

0.0002500 

0.001279

0.0 

0.0 

0.0008853 

0.003918

Block Valve2 <1000 257 99.2 0.0000019 0.000001 0.0000029

1000-10000 

>10000 

1 

1

0.4 

0.4

0.0000402 

0.0001

---- 

---- 

---- 

---- 

PRV <1000 6 100.0 0.0002717 0 0.0008144 

1000-10000 

>10000 

---- 

----

---- 

----

---- 

---- 

---- 

---- 

---- 

---- 

Regulator <1000 95 93.1 0.0000087 0.0000066 0.0000108 

1000-10000 

>10000 

---- 

7

---- 

6.9

---- 

0.000202 

---- 

0.0 

---- 

0.000691 

Orifice Meter4 <1000 67 64.4 0.000032 0.0000198 0.0000442

1000-10000 

>10000 

16 

21

15.4 

20.2

0.009850 

0.0088

0.004703 

0.004936 

0.01500 

0.01286

Other Flow Meter5 <1000 258 97.0 0.000003 0.0000014 0.0000045 

1000-10000 

>10000 

1 

7

0.4 

2.6

0.0002000 

0.0002064

---- 

 0.0 

---- 

0.0006932 

Open-Ended Line <1000 25 24.5 0.000023 0.000001 0.000045

1000-10000 

>10000 

2 

75

2.0 

73.5

0.008100 

1.274

---- 

0.4989 

---- 

2.049 

Source: Ross and Picard (1996), Table 7, page 23. 

---- No data available. 

1 Includes flanges, threaded connections and mechanical couplings. 

2 Accounts for emissions from the stem packing and the valve body, and it applies to all types of block valves (e.g., butterfly, ball, globe, 

gate, needle, orbit and plug valves). Leakage past the valve seat is accounted for by the Open-Ended Line emission category. 

Leakage from the end connections is accounted for by the connector category (i.e., one connector for each end). 

3 Accounts for leakage from the stem packing and valve body. Emissions from the controller and actuator are accounted for by the 

Instrument Controller and Open-Ended Line categories respectively. This factor applies to all valves with automatic actuators 

(including fuel gas injection valves on the drivers of reciprocating compressors). 

4 Accounts for emissions from the orifice changer. Emissions from sources on pressure tap lines etc. are not included in the factor (i.e., 

these emissions must be calculated separately). 

5 Accounts for emissions from other types of gas flow meters (e.g., diaphragm, ultrasonic, roots, turbine and vortex meters). 

6 Accounts for leakage past a valve seat through an open vent line to the atmosphere. These vents are typically six inches or greater in 

diameter and are used to blowdown major process units or sections of pipeline. Small diameter open-ended lines such as those used 
 71 

to blowdown chart recorders, meter runs etc. are accounted for by the Open-Ended Line category. 

7 The Instrument Controller Category accounts for emission from pneumatic control devices that use natural gas as the supply medium. 

8 The Compressor Seal categories account for emissions from individual compressor seals (i.e., for a four cylinder reciprocating 

compressor unit there are four seals so the compressor seal emissions for the unit would be four times the factor in the table). 

Correlation parameters for estimating leak rates from equipment components at gas 

transmission and distribution facilities. 

Source B0 B1 Number of 

Sources 

Correlation (R2) 

Connectors1 -5.9147 0.75 305 0.71

Valves1 -6.0399 0.83 369 0.67

Open-Ended Lines2 -6.9586 1.28 64 0.44

Pressure Relief 

Devices2

-5.1479 0.91 29 0.46

Pressure Regulators2 -6.4821 0.91 35 0.58

1 The correlation for this source is based on screening and bagging data collected by Ross and Picard 

(1996), by Environment Canada (Williams, 1996), and data collected for U.S. EPA (1995). 

2 The correlation for this source is based on screening and bagging data collected by Ross and Picard (1996) 

and Environment Canada (Williams, 1996).
 72 

The values of the correlation constants for application to the Canadian 

natural gas industry are summarized in Table 8. 

The basic approach involves processing each individual screening value as 

follows and then aggregating the results to determine total emissions: 

⋅ On-scale Screening Values - Components that have screening 

values within the detection range of the screening instrument and 

more than 1 ppm above background are assessed using equation 

(5). Do not average screening values and then enter the result into 

the correlation to estimate emissions. 

⋅ Zero Screening Values - Components with screening values of 

1 ppm or less above background are assigned a default emission 

rate in accordance with Table 9. If the instrument has a minimum 

detection limit greater than 1 ppm, the default zero values in Table 9 

do not apply. In this situation, all zero screening values should set to 

one-half the instrument's minimum detection limit and then 

processed using equation (5). 

⋅ Off-scale or Pegged Values - Components with off-scale or pegged 

values are either assigned the appropriate average emission rate for 

a leaking equipment component (i.e., see Table 6 or 7), or are 

bagged to determine the actual mass emission rate. 

The level of uncertainty in the total emissions estimated by this approach is 

a function of the number of components considered and the portion that are 

pegged sources. For a single component, the uncertainty may be as high 

as a factor of 100. Figure 6 presents the calculated uncertainties at the 

90 percent confidence limit as a function of the number of components for 

typical gas production facilities, assuming no pegged sources (Lott et al. 

1996). The results show that the uncertainty tends to decrease almost 

exponentially with the number of components. A facility would need to have 

at least 3000 components before the uncertainty would be below 50 percent 

for a 90 percent confidence level. Even more components would be 

required if there are pegged sources. However, very few facilities will have 

even 3000 components (see Table 3). The best overall accuracy for a 

facility that, generally, can be expected from use of the correlation method, 

including use of pegged emission factors, is about ±300 percent (telephone 

communication with Mr. R.A. Lott at Gas Research Institute, June 19, 

1997). 
 73 
 74 

Default zero emission rates1. 

Source Type Default-Zero Emission Rate2

(kg/h/source) 

Gas valve 6.6 (10-7) 

Light liquid valve 4.9 (10-7) 

Light liquid pump3 7.5 (10-6) 

Connector 6.1 (10-7) 

1 Source: U.S. EPA. 1995. Protocol for Equipment Leak Emission Estimates. Research Triangle Park, NC. 

Report No. EPA-453/R-95-017. Table 2-11. p. 2-33. 

2 Total hydrocarbon emissions. 

3 The light liquid pump default zero value can be applied to compressors seals, pressure relief valves, 

pressure regulators, agitators and heavy liquid pumps.
 75 

 Figure 6. 90% confidence limits for emissions versus number of components screened. 
 76 

3.2.2.4 Unit-Specific Leak-Rate Correlations. Some companies may wish to 

develop unit-specific leak-rate correlations to achieve better accuracy for 

their particular operations. The benefit in doing this is often questionable 

since, in theory, the relationship between a properly corrected screening 

value and the emission rate for a given component type and service is the 

same across all industries. Nonetheless, where there is some doubt, 

various nonparametric statistical methods may be applied to determined the 

validity of the available correlations (see Section 3.2.2.3). This involves 

comparing a set of predicted emission rates to actual measured values for a 

given source type and service category. The sign or a suitable rank-sum 

test may be applied to determine if the two data sets are statistically 

different (see almost any statistical analysis text). To apply the sign test, try 

using a sample size of four. If all four measured values are consistently 

greater than or consistently less than the predicted values, then the 

selected correlation probably does not provide reasonable emission 

estimates for the given application. 

To develop a leak-rate correlation it is necessary to compile a reasonable 

number of data points to cover the desired screening range for each target 

source/service category. Each data point must comprise an actual 

measured mass emission rate and corresponding screening value. U.S. 

EPA (1995) suggests using a minimum of six random data points for each 

of the following ranges that the correlation will span: 1 to 100 ppm, 101 to 1 

000 ppm, 1 001 to 10 000 ppm, 10 001 to 100 000 ppm and 100 001 to 1 

000 000 ppm. The collected data are fit to equation (5) using a leastsquares regression analysis. For further details on developing a unitspecific leak-rate correlations, refer U.S. EPA's (1995) protocol for 

equipment leak emission estimates. 

3.2.3 Screening Coupled With Direct Measurement of Significant Leakers. Experience has 

shown that the few leakers which occur at a facility (i.e., typically, 3 to 6 percent of the 

component population) contribute nearly all (i.e., 90 to 95 percent) of the fugitive 

emissions from components in gas service. The current approach takes advantage of this 

fact to provide a reasonable balance between cost of assessment at accuracy of total 

estimated emissions. It involves using a simplified screening program to quickly identify 

leakers. Much of the screening may be done using a soap solution (i.e., a bubble test) 

and there is no need to record screening values; however, a component inventory is still 

required. The leaking components are then sampled to determine the actual mass 

emission rate. The emission factors for non-leakers (see Table 6) are applied to the rest 

of the components. 

An important advantage of this overall approach is it provides reliable information for 
 77 

determining which leakers are actually cost-effective to repair, and for subsequently 

prioritizing the repair work. In comparison, a conventional leak detection and repair 

(LDAR) program involving Method 21 screening techniques can identify pegged-source 

leakers, but cannot identify which leaks should be fixed first or what actual emission 

reduction would be achieved if the repairs were made. Experience in the U.S. has been 

that a large percentage of pegged sources may not be cost effective to repair (Lott et al., 

1996). 

Furthermore, use of a portable organic vapour analyzer is much slower than other leak 

detection techniques; especially if screening data are being recorded for each component 

when an analyzer is used, and other methods can eliminate this need. For example, use 

of bubble tests with no data recording, just tagging of leaking components, is at least 3 to 

4 times faster than application of Method 21 using an organic vapour analyzer. If the 

ambient temperature is below freezing, propylene glycol may be added to the soap 

solution to prevent it from freezing. Components that cannot be screened effectively with 

soap, such as flanges, open-ended lines, or very hot components, may be screened 

using the organic vapour analyzer. 

Sampling of the leakers may be done using either conventional bagging and direct flow 

measurement techniques or using the Hi-Flow sampler recently developed by Indaco Air 

Quality Services, Inc. and Star Environmental Ltd. with support of Gas Research Institute. 

Both methods are generally accurate to within ±10 to 15 percent of value. However, the 

latter approach tends to be much less expensive since it takes less than one-tenth the 

time of an enclosure measurement to perform. 

Bagging consists of placing an enclosure or envelope around a target source (typically a 

leaking equipment component such as a valve or flange), and passing a measured flow 

of clean gas (e.g., zero air or nitrogen) through the enclosure to sweep the source and 

create a well-mixed environment. The emission rate is then determined based on the 

sweep rate and the steady-state concentration of pollutants measured inside the 

chamber. This is done using the relation: 

where, 

Q = metered volumetric sweep rate corrected standard temperature and 

pressure (m3/h), and 
 78 

C = concentration of methane in the outlet air (kg/m3). 

A schematic diagram of a bagging setup is presented in Figure 7. Plastic sheeting (e.g., 

Tedlar or Mylar) and duct tape are commonly used to form the enclosure. The time 

required to achieve a steady-state condition inside the enclosure is usually in the order of 

15 to 20 minutes, and will depend on the amount of void space, the air sweep rate and 

the emission rate. Costs may be in the order of $150 to $250 per component or more 

depending on the analytic method used to determine pollutant concentrations, the 

difficulty in bagging the component and the location of the facility. A detailed protocol for 

performing bagging measurements is presented Hausle (1993). 
 79 

Figure 7. Sampling train for bagging a source using the vacuum method (U.S. EPA, 

1995). 
 80 

The Hi-Flow sampler is, basically, an intrinsically-safe, portable organic vapour analyzer 

similar to that used as a screening instrument in LDAR programs. However, it is designed 

to provide a direct estimate of the actual emission rate rather than simply a concentration 

measurement or screening value. The emission rate is determined based on the 

sampling rate needed to capture all the emissions from a target leaking equipment 

component, and on the corresponding concentration of pollutants measured in the 

sampled material. Two opposing factors influence the choice of sample flow rate for the 

system. Higher flow rates provide better leak capture, especially if high winds are a factor 

or if the leak has significant momentum. However, higher flow rates reduce the size of 

leak that can be quantified and increase the chance of interference from nearby leaks. 

The Hi-Flow sampler, reportedly, is available as both a product and as a service and its 

capabilities have been well demonstrated. However, it is still being refined and has not 

yet gone into full-scale commercial production. The pricing is comparable to, although 

somewhat higher than, the cost of buying or leasing a typical OVA.

3.2.4 Whole-Facility Quantification Approaches. There are a variety of sophisticated integral 

or lumped analysis techniques that may be used to assess total methane emissions from 

specific process units or areas, or even an entire facility. They can be an economical 

means of determining total methane emissions from large facilities (e.g., multi-unit 

compressor stations and transfer stations), but become more expensive as the size of 

the facility or area decreases. A possible drawback is that they do not specifically isolate 

emissions due to fugitive equipment leaks, or identify individual leakers. Therefore, while 

useful for quantification of emissions, they are not useful for directed LDAR. Further 

testing would be required to provide this additional information. 

A review of many of the applicable integral techniques has been prepared by Picard 

(1998). Two specific options that may be worth considering for application at gas 

transmission and distribution facilities are remote sensing and the tracer/pollutant ratio 

technique. Both these options involve remote monitoring of upwind and downwind 

methane concentrations. Their practicable application is subject to the following basic 

requirements: 

⋅ no interfering sources of the target pollutants, 

⋅ reasonable access to appropriate upwind and downwind monitoring locations, 

⋅ methane concentrations at the downwind monitoring location must be detectable 

above background values and the monitoring results must be representative in 

terms of time, location and conditions, 

⋅ favourable meteorological conditions at the time of testing, 

⋅ low or stable background methane concentrations, and 

⋅ competent and experienced personnel are an essential prerequisite. 
 81 

Some additional considerations are listed below: 

⋅ some remote air monitoring instruments may have inadequate detection limits or 

may not be rated to operate in cold weather, and 

⋅ precipitation or fog during testing may interfere with the performance of some 

instruments. 

3.2.4.1 Remote Sensing. This method requires the use of a portable pollutant 

monitoring system, meteorological station, accurate global positioning 

system (GPS) or linear-distance measurement device, and a computerized 

dispersion modelling package. First, the pollutant concentration above 

background in the plume of the target source is measured at a known 

downwind location. Then, the source strength or emission rate is 

backcalculated using an appropriate dispersion model and site-specific 

meteorological data. 

The concentration measurements are done at a location sufficiently remote 

from the source for the plume to be well formed, and for the dispersion 

model to be valid, but close enough that the pollutants are easily detectable 

above background and so there is no interference from other sources. The 

readings are averaged over a time period that is large enough to dampen 

the effect of short-term atmospheric fluctuations (e.g., at least 5 minutes 

and possibly much longer for slow meandering wind conditions), and is 

adequate to capture temporal variations of the source. 

Careful planning, dispersion calculations, and possibly real-time mapping of 

the target plume(s) are required to determine exactly what sources are 

contributing to the measured concentrations, and to ensure that the 

selected measurement location is accessible. 

The dispersion model often selected to backcalculate source emission rates 

is ISCST3 developed by U.S. EPA (1995). ISCST3 is a refined, steadystate, Gaussian plume model for predicting short term dispersion of 

atmospheric emissions from industrial complexes comprised of multiple 

point, area and volume sources. It is valid for applications involving flat or 

simple terrain which rises no more than the height of the stack tops. 

ISCST3 requires hourly stability class, wind direction, wind speed, 

temperature and mixing height data. 

For more difficult application, CTDM-PLUS (Perry et al., 1989) may be 

used. CTDM-PLUS is the complex terrain dispersion model plus algorithms 

for unstable situations. It is a refined, steady-state, point-source Gaussian 

air-quality model for use in all stability conditions for applications involving 
 82 

complex terrain and multiple emission sources. Copies of ISCST3 and 

CTDM-PLUS are available at no cost, via the Internet, from U.S. EPA's 

Support Centre for Regulatory Air Models. The Internet address is 

www.epa.gov/scram001. 

The required meteorological data include hourly average values of wind, 

temperature and turbulence. Terrain data are input as digitized contours. 

Up to 25 hills may be defined. 

The actual procedure for backcalculating an emission rate depends on 

whether the target source is homogeneous or heterogeneous. In the first 

case (e.g., a uniform point or area source), the source is assumed to have 

an emission rate equal to unity, and dispersion modelling is done to 

calculate the ground level concentrations at the different measurement 

points, or the average value along a measurement path. The ratio of 

theoretical concentrations to measured concentrations is then use to scale 

the assumed emission rate to the true value. 

If the source is heterogeneous, areas of higher emissions (hot spots) must 

first be known in terms of their size, location and relative contribution before 

the dispersion modelling can be done. Additional testing and measurements 

are required to determine this extra information. 

A dedicated measurement program to determine methane emissions from a 

small installation might take several hours to complete and be 

representative of the lower cost limit. Multi-component monitoring for a very 

large complex facility with heterogeneous emissions may require several 

weeks of testing and be representative of the higher cost limit. 

The monitoring of methane concentrations may be done using either point 

or path-integrated measurement techniques. Typically, a continuous 

monitor would be employed since these are readily available for methane. 

The selected device usually is installed in trailers or vehicles which are 

moved about to different locations to conduct ambient air monitoring for 

appropriate periods of time (e.g., a few hours, days, months, or longer). 

Some of these instruments also are available as hand-held devices which 

may be easier to use. Portable continuous analyzers may also be used to 

develop path integrated average values. 

Diode laser systems specifically tuned to methane are available for 

measurement of methane concentrations to below ambient values (i.e., on 

the order of 1 ppm); they may be worth considering for the required 
 83 

monitoring work. These devices give average concentration measurement 

over a specified path length (i.e., the distance between the sender/receiver 

and the retro-reflector). A major advantage of employing path-integrating 

measurement techniques instead of point measurement technique is that it 

can eliminate the need for multiple measurements. Moreover, it is less 

sensitive to lateral heterogeneity in the plume's concentration profile (Piccot 

et al., 1996). 

The actual accuracy of the developed emission estimates will depend on a 

variety of factors including the reliability of the dispersion modelling, the 

quality of the measurements performed, the detection limits achieved, the 

representativeness of the compiled data, meteorological conditions, 

background noise and interferences. Estimates for simple point sources 

may be accurate to within ±10 to 25 percent of value under favourable 

conditions, while results can easily be in error by an order of magnitude for 

more demanding conditions. 

Typically, the greatest uncertainty in the estimated emission rate is due to 

the dispersion modelling. One of the most significant modelling input 

assumptions is the atmospheric stability value used for each modelling 

event (Piccot et al., 1996). For example, Minnich et al. (1991) report that 

emission rates may be underestimated by a factor of 2 if textbook vertical 

dispersion coefficients are employed. 

Ideally, dispersion coefficients should be estimated through tracer 

measurements performed concurrent with the remote sensing and 

meteorological measurements. Lamb et al. (1994) report that this can 

reduce total uncertainties to ±50 percent. The tracer measurements involve 

releasing a known rate of easy-to-measure tracer gas at the target source 

so that it commingles with the source plume. The tracer concentration 

above background is then measured at the remote monitoring location. 

Typically, either SF6 or CF4 are used as the tracer gas. Assuming the tracer 

and source emissions are exposed to much the same atmospheric 

dispersion effects (i.e., momentum, thermal buoyancy and turbulent 

mixing), the tracer results may be used to effectively calibrate the 

dispersion model for calculating the pollutant emission rate. If the remote 

sensing can be performed far enough away that the emission source 

appears as a point source and is well simulated by the tracer release, then 

the tracer/pollutant ratio technique may be applied as described in Section 

3.2.3.2. 
 84 

3.2.4.2 Tracer/Pollutant Ratio Technique. The tracer/pollutant ratio technique 

involves releasing small, carefully metered, amounts of tracer gas (typically 

SF6) at a steady rate near the source(s) of interest. (Note: SF6, with a 

global warming potential of 25 000, is a very powerful greenhouse gas, and 

therefore should, be used sparingly). Crosswind concentration profiles of 

both the tracer and target pollutants (i.e., methane) are then measured at a 

convenient downwind location, corrected for background levels, and used to 

infer pollutant emission rates based on the know tracer release rate. The 

objective is to move far enough away from the source and tracer release 

system that the two appear as a single point source (i.e., there is good 

spacial overlap of the plumes). In general, the larger the emission source, 

the greater the downwind distance required to satisfy this requirement. 

However, large downwind distances will increase the possibility of 

interference from nearby sources and potentially dilute the plume to below 

detection limits. Typically, suitable distances might be 50 to 100 metres for 

small facilities, and 1 to 3 km for large facilities. 

It is best to perform the concentration measurements using portable, highsensitivity, real-time instruments to allow real-time verification of point 

source behaviour, and confirmation that no interference from other source 

plumes is occurring. Alternatively, integrating volume samplers (typically 4 

to 8) may be deployed at appropriate fixed locations to simultaneously 

collect 15 to 30 minute average air samples for subsequent analysis. Use of 

both methods serves as a good quality assurance check. It is best to 

perform the measurements when the atmosphere is relatively stable (e.g., 

at night) so the plume concentrations are higher. 

To be considered detectable above background, a concentration reading 

should exceed the average background value by an amount equal to at 

least 2 to 3 times the standard variation in background concentrations. 

Thus, methane concentrations should be greater than 50 ppb above 

background. Background methane levels are typically 1800 ppbv (Shorter 

et al., 1997). Background SF6 readings are typically 1 to 3 ppt. 

If the SF6 and source plumes overlap perfectly, then the ratio of SF6 to 

pollutant concentrations will be constant (i.e., within ± 10 percent) over the 

entire plume cross-section at the selected downwind monitoring location. 

Moreover, this ratio will also be equal to the corresponding ratio of emission 

rates. Thus, provided the requirements of point-source behaviour are 

satisfied and there is no interference from other nearby sources, the 

emission rate of each pollutant may be readily determined using the simple 

relationship, 
 85 

where, 

Ci = concentration of the target pollutant i, 

Ct = concentration of the tracer gas, 

Qi = volumetric emission rate of the target pollutant i, and 

Qt = metered release rate of tracer gas in the source plume. 

The subscripts uw and dw denote upwind and downwind, respectively. 

The tracer ratio method has the advantage that no meteorological 

measurements are required and no dispersion modelling is invoked (Lamb 

et al., 1994). In practice, the method is successful because of the capability 

to monitor both methane and tracer plumes in real time with mobile 

analyzer systems so that the co-location of the methane and tracer plumes 

can be clearly established and sampling systems can be positioned directly 

in the plumes. 

The cost of performing the tracer measurements will be in the order of 

$2000 to $3000 per day, plus mobilization/demobilization charges and the 

cost of any detailed analyses for speciation of the source plume. 

Initial validation work done by Lamb et al. (1994) involving controlled 

pollutant and tracer releases, and a subsequent demonstration test 

conducted at a gas production facility indicate the tracer ratio method is 

accurate to within ±15 percent or better. Estimated emission rates of 

methane for an entire gas processing plant were extremely consistent 

(within 11 percent) among four individual tests conducted on two separate 

days with different wind directions and different downwind distances. For an 

individual test, the agreement among a number of fixed samplers and 

mobile traverse results was between 7 and 15 percent. This excellent 

agreement provided confirmation that the tracer release accurately 

simulated the methane source and that tracer and methane underwent the 

same transport and diffusion in the atmosphere. 
 86 

4.0 FUGITIVE PIPELINE LEAKS

This category accounts for leakage from the piping and any associated buried components that 

comprise a gas transmission or distribution pipeline. Details regarding the forms of leakage 

considered are presented in Section 4.1. The proposed technique for estimating the amount of 

emissions is based on the use of national average emission factors with allowance for company 

specific factors. Special forms are provided in Section 4.2 to guide the user through the required 

calculations according to the type of piping material and the service (transmission or 

distribution). 

Emissions due to catastrophic failures or dig-ins are addressed separately in Section 7.0. 

4.1 Source Characterizations

Fugitive pipeline leaks consist of emissions from underground valves and other buried fittings 

attached to the pipelines, connectors between two pipeline segments or joints, and emissions 

through the pipe wall. The emissions through the wall of the pipe include the leaks through, 

generally, small openings in the pipe wall; usually, as a result of a crack or corrosion of the wall 

material and normally caused by operational wear and tear, and emissions through the 

molecular structure of the wall itself. This latter type of emission is referred to as permeability of 

the pipe wall, and is documented and quantified only for plastic pipelines. The permeability 

emissions are addressed in Section 4.2.2 below. All other emissions described above are 

classified as pipeline leaks and are addressed collectively in Section 4.2.1. 

Pipeline blowdowns, whether intentional for operating reasons (such as to lower the pipeline 

pressure or a post-construction purge), or unintentional as the result of an accident (such as 

damage to the pipeline by excavating equipment, sometimes referred to as dig-ins), are 

classified as vented emissions or accidental emissions, and are discussed in Section 5.0. 

4.2 Emission Assessment Techniques

4.2.1 Pipeline Leaks. The amount of gas leaking from a pipeline during a specific time period 

is easily related to the average leak frequency, duration and rate. However, it is difficult to 

establish these values with any reasonable degree of confidence. For instance, while the 

majority of pipeline operators have good documentation of the number of leaks identified 

on their systems, there is no direct knowledge of the total number of leaks actually in 

existence at any one time. The actual duration of the individual gas leaks is unknown, 

and the leak rate is, for economic reasons, not measurable even for each identified leak, 

and outright unmeasurable for the still unidentified, but already existing, leaks. To assess 

the volumes leaked from the pipelines, calculations that rely on various simplifications 

and assumptions must therefore be made. 

The calculation process outlined below will determine the volumes of methane released 
 87 

during a period of one calendar year from a pipeline or pipeline system. It allows the use 

of company-specific data at each step, but provides industry average values developed 

by Radian International (CGA, 1997) to be used if company-specific data are not 

available. Generally, the use of company-specific data provide the most accurate results, 

so that should be the preferred method if available. 

Forms 4.2.1-1 through to 4.2.1-10 outline the specific calculations to be performed for 

each of the following categories of pipelines, respectively: 

⋅ Protected Steel Pipe Transmission Pipelines, 

⋅ Unprotected Steel Pipe Transmission Pipelines, 

⋅ Plastic Pipe Distribution Mains, 

⋅ Protected Steel Distribution Mains, 

⋅ Unprotected Steel Distribution Mains, 

⋅ Cast Iron Pipe Distribution Mains, 

⋅ Plastic Pipe Service Lines, 

⋅ Protected Steel Pipe Service Lines, 

⋅ Unprotected Steel Pipe Service Lines, and 

⋅ Copper Tubing Service Lines. 

Each of these calculation forms follow a consistent pattern: 

⋅ the total number of repaired leaks is determined, 

⋅ this value is multiplied by the average leak rate for that type of pipeline, 

⋅ the resulting gross leak rate for the pipeline or pipeline system is corrected for the 

“equivalent-leak” quantity, 

⋅ a multiplication factor is applied to account for the equivalent-leaks duration time 

(by definition, one calendar year), 

⋅ the resulting annual volume is then corrected for the methane content of natural 

gas in that particular system and the methane oxidation rate by the soil, and 

finally, 

⋅ the annual methane volume is converted to tonnes of methane per year. 

The calculations do not use the operating pressure or the pipeline diameter as a variable, 

since the leaked volumes do not vary significantly with these two parameters (Campbell 

et al., 1996). The variables impacting the leak rates are the type of pipeline (i.e. 

transmission, distribution or service line) and the pipe length. 

The “equivalent-leaks” multiplier is applied to the number of leaks repaired during the 

reference year to account for the fact there may have been leaks not found, and to 

correct for the leaking time duration of those leaks that either started leaking only after 

the start of the year or were repaired before the end of the year, or both. 
 88 

In several steps of the calculation chain, company-specific values should be used, if 

available, to get the most accurate emission rate. The number of leaks repaired during 

the specific year is usually known, but if it is not know, an industry average factor is 

provided based on the total length of pipelines or number of service lines in that category. 

Similarly, the average leak rate may be determined by measuring the gas flow 

immediately upstream and downstream of identified leaks, if practicable, or the presented 

industry-average factors may be applied according to the type of pipe material. 

Company-specific values for methane content in the natural gas may be used, or an 

appropriate value may be selected from Table 5. 

Some factors will probably not be available on a company-specific basis, or are uniformly 

applicable: the correction factors for “equivalent-leaks” and for oxidation of methane by 

the soil, as well as the conversion factor from standard cubic feet to tonnes of methane, 

are all provided. 

The default industry-average leak factors presented in Forms 4.2.1-1 through 4.2.1-10 

are based on national values factors developed in a recent U.S. study (Campbell et al., 

1996), and are used in the CGA (1997) emissions inventory. Some Canadian companies 

suggested their company-specific factors differ from the presented values, while others 

experienced reasonable agreement for their systems. 

4.2.2 Plastic Pipe Permeability. Although usually not a significant source of emissions, there 

is a potential for some losses to occur due to permeation through the walls of plastic 

piping. The permeated volume may be determined by the following equation (AGA, 

1994): 

where, 

V = volume of gas permeated in cm3 at 23_C and atmospheric pressure of 

101.325 kPa. 

K = permeability constant 

= 85 (for methane) 

A = area of the outside wall of the pipe, in multiplies of 100 in2

P = pressure in the pipe, atmospheres (gauge) 
 89 

θ = lapsed time, days 

t = pipe wall thickness in mils (i.e. inches x 103) 

The actual mass emission rate of methane, with corrections for some oxidation by the soil 

(i.e., 2 percent) and the amount of methane in the natural gas, may be calculated using 

the equation below. Expressing the surface area in terms of outside diameter (mm) and 

pipeline length (km), the wall thickness in (mm), pressure in (kPag), the lapsed time in 

(years) and correcting for oxidation by the soil (0.98 multiplier) and the methane content 

(by weight) of the natural gas we get: 

where, 

= mass emission rate of methane (tonnes per year), 

c = constant (see Table 10), 

= methane content of the natural gas (mass percent) (see Table 5b), 

= pipeline operating gauge pressure (kPag). 

L = length of pipeline (km). 

For accurate calculation, the distribution system should be subdivided into segments, one for 

each combination of Standard Dimension Ratio (SDR) (i.e., outside pipe diameter divided by the 

wall thickness with both values expressed in the same units of measure), methane content and 

operating pressure. If the information regarding the total length of plastic pipe related to each 

such segment is unknown, it is possible to select two or three major operating pressure levels at 

which segments of distribution system operate, and then use average values of c and for 

each. 

The majority of the plastic pipe in the Canadian gas distribution system probably involves 

pipe with an SDR ratio of 11, except that standard 11⁄4 NPS pipe usually has an SDR of 

10 and 1⁄2 NPS tubing usually has an SDR of 7. Depending on the amount of non-SDR 11 

pipe in the system, however, it might be possible to assume all pipe has an SDR of 11. 
 90 

The specified pipeline length should include both mains and services. If the total length 

of plastic service lines is unknown, the approximation of 20 m per service line can be 

used. 
 91 

Calculation Form 4.2.1-1 

FUGITIVE PIPELINE LEAKS

Transm ssion Pipelines (Protected Steel Pipe i )

Step 

No. 

Description Default Values1

1 Establish the number of repaired leaks. 0.018 x km of pipe 

2 Multiply (1) by the average leak rate. 2.55 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-leaks”. 

0.9395 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply result from Step (4) by the correction factor for 

methane content by volume. 

Per Table 5a 

(C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 

for methane oxidation by the soil. 

0.970 

7 

 

Multiply the result from Step (6) by the conversion factor 

from scf to tonnes of methane. 

19.23 x 10–6 t/scf 

1 The presented data are based on national averages and, for improved accuracy, should be replaced with 

company-specific values where available. 
 92 

Calculation Form 4.2.1-2 

FUGITIVE PIPELINE LEAKS

Transm ssion Pipelines (Unprotected Steel P pe) i i

Step 

No. 

Description Default Values1

1 Establish the number of repaired leaks. 0.0837 x km of pipe 

2 Multiply (1) by the average leak rate. 6.45 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-leaks”. 

0.9395 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply the result from Step (4) by the correction factor 

for methane content by volume. 

per Table 5a 

(C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 

for methane oxidation by the soil. 

0.982 

7 

 

Multiply the result from Step (6) by the conversion factor 

for scf to tonnes of methane. 

19.23 x 10–6 t/scf 

1 The presented data are based on national averages and, for improved accuracy, should be replaced with 

company-specific values where available.
 93 

Calculation Form 4.2.1-3 

FUGITIVE PIPELINE LEAKS

Distribution Mains (Plastic Pipe)

Step 

No. 

Description Default Values1

1 Establish the number of repaired leaks. 0.0480 x km of pipe 

2 Multiply (1) by the average leak rate. 2.74 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-leaks”. 

2.1397 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply the result from Step (4) by the correction factor 

for methane content by volume. 

per Table 5a 

(C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 

for methane oxidation by the soil. 

0.98 

7 

 

Multiply the result from Step (6) by the conversion factor 

from scf to tonnes of methane. 

19.23 x 10–6 t/scf 
 94 

1 The presented data are based on national averages and, for improved accuracy, should be replaced with 

company-specific values where available.

Calculation Form 4.2.1-4 

FUGITIVE PIPELINE LEAKS

Distribution Mains (Protected Steel Pipe)

Step 

No. 

Description Default Values1

1 Establish the number of repaired leaks. 0.0442 x km of pipe 

2 Multiply (1) by the average leak rate. 2.55 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-leaks”. 

2.1397 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply the result from Step (4) by the correction factor 

for methane content by volume. 

per Table 5a 

(C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 

for methane oxidation by the soil. 

0.97 
 95 

7 Multiply the result from Step (6) by the conversion factor 

from scf to tonnes of methane. 

19.23 x 10–6 t/scf 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.
 96 

Calculation Form 4.2.1-5 

FUGITIVE PIPELINE LEAKS

Distribution Mains (Unprotected Steel Pipe)

Step 

No. 

Description Default Values1

1 Establish the number of repaired leaks. 0.6213 x km of pipe 

2 Multiply (1) by the average leak rate. 6.45 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-leaks”. 

2.1397 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply the result from Step (4) by the correction factor 

for methane content by volume. 

per Table 5a 

(C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 

for methane oxidation by the soil. 

0.982 

7 

 

Multiply the result from Step (6) by the conversion factor 

from scf to tonnes of methane. 

19.23 x 10–6 t/scf 

1 The presented data are based on national averages and, for improved accuracy, should be replaced with 

company-specific values where available.
 97 

Calculation Form 4.2.1-6 

FUGITIVE PIPELINE LEAKS

Distribution Mains (Cast Iron Pipe)

Step 

No. 

Description Default Values1

1 Establish the number of repaired leaks. 30.69 scfh/km 

2 Multiply (1) by the total length (km) of mains. 

3 Multiply the result from Step (2) by the number of hours in 

a year. 

8760 h/y 

4 Multiply the result from Step (3) by the correction factor 

for methane content by volume. 

per Table 5a 

(C1 divided by 100) 

5 Multiply the result from Step (4) by the correction factor 

for methane oxidation by the soil. 

0.597 

6 

 

Multiply the result from Step (5) by the conversion factor 

from scf to tonnes of methane. 

19.23 x 10–6 t/scf 

1 The presented data are based on national averages and, for improved accuracy, should be replaced with 

company-specific values where available.
 98 

Calculation Form 4.2.1-7 

FUGITIVE PIPELINE LEAKS

Service Lines (Plastic Pipe)

Step 

No. 

Description Default Values1

1 Establish the number of repaired leaks. 0.0018 x no. of 

service lines 

2 Multiply (1) by the average leak rate per source. 0.37 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-lLeaks”. 

2.1397 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply the result from Step (4) by the correction factor 

for methane content by volume. 

per Table 5a 

(C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 

for methane oxidation by the soil. 

0.788 

7 

 

Multiply the result from Step (6) by the conversion factor 

from scf to tonnes of methane. 

19.23 x 10–6 t/scf 
 99 

1 The presented data are based on national averages and, for improved accuracy, should be replaced with 

company-specific values where available.

Calculation Form 4.2.1-8 

FUGITIVE PIPELINE LEAKS

Service Lines (Protected Steel Pipe)

Step 

No. 

Description Default Values1

1 Establish the number of repaired leaks. 0.0090 x no. of 

service lines 

2 Multiply (1) by the average leak rate per source. 1.15 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-leaks”. 

2.1397 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply the result from Step (4) by the correction factor 

for methane content by volume. 

per Table 5a 

(C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 

for methane oxidation by the soil. 

0.974 

7 

 

Multiply the result from Step (6) by the conversion factor 19.23 x 10–6 t/scf 
 100 

from scf to tonnes of methane. 

1 The presented data are based on national averages and, for improved accuracy, should be replaced with 

company-specific values where available.

Calculation Form 4.2.1-9 

FUGITIVE PIPELINE LEAKS

Service Lines (Unprotected Steel Pipe)

Step 

No. 

Description Default Value1

1 Establish the number of repaired leaks. 0.0393 x no. of 

service lines 

2 Multiply (1) by the average leak rate per source. 2.50 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-leaks”. 

2.1397 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply the result from Step (4) by the correction factor 

for methane content by volume. 

per Table 5a 

(C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 0.989 
 101 

for methane oxidation by the soil. 

7 Multiply the result from Step (6) by the conversion factor 

from scf to tonnes of methane. 

19.23 x 10–6 t/scf 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

Calculation Form 4.2.1-10 

FUGITIVE PIPELINE LEAKS

Service Lines (Copper Tubing)

Step 

No. 

Description Default Value1

1 Establish the number of repaired leaks. 0.0155 x no. of 

service lines 

2 Multiply (1) by the average leak rate per source. 0.94 scfh/leak 

3 Multiply the result from Step (2) by the correction factor 

for total “equivalent-leaks”. 

2.1397 

4 Multiply the result from Step (3) by the number of hours in 

a year. 

8760 h/y 

5 Multiply the result from Step (4) by the correction factor per Table 5a 
 102 

for methane content by volume. (C1 divided by 100) 

6 Multiply the result from Step (5) by the correction factor 

for methane oxidation by the soil. 

1.000 

7 

 

Multiply the result from Step (6) by the conversion factor 

from scf to tonnes of methane. 

19.23 x 10–6 t/scf 

1 The presented data are based on national averages and, for improved accuracy, should be 

replaced with company-specific values where available.

Values of the constant c used to estimate permeation losses from plastic piping systems for 

common SDRs1. 

NOMINAL 

PIPE SIZE 

(NPS) 

OUTSIDE 

DIAMETER 

(mm) 

WALL 

THICKNESS 

SDR c = 0.25185 x 10-6 x SDR 

1⁄2 15.88 2.28 7 1.76 x 10-6

3⁄4 26.66 2.41 11 2.77 x 10-6

1 33.40 3.02 11 2.77 x 10-6

1 1⁄4 42.16 4.22 10 2.52 x 10-6
 103 

1 1⁄2 48.30 4.39 11 2.77 x 10-6

2 60.32 5.49 11 2.77 x 10-6

2 1⁄2 73.00 6.62 11 2.77 x 10-6

3 

 

88.90 8.08 11 2.77 x 10-6

4 114.30 10.39 11 2.77 x 10-6

6 168.30 15.28 11 2.77 x 10-6

1 SDR - Standard Dimension Ratio (i.e., outside pipe diameter divided by the wall thickness with 

both values expressed in the same units). 
 104 

5.0 PROCESS VENTING

The assessment of gas volumes released from process venting or purging activities requires a 

range of approaches depending on the type of venting being considered and its relative 

contributions to total emissions. For common small to medium sized emitters sources such as 

gas operated devices (e.g., compressor starters, chemical injection pumps, odourization pumps, 

etc.) and instrument control loops, the options include, in the order of increasing reliability and 

assessment effort: 

⋅ application of average emission factors to typical event frequencies and/or source 

counts, 

⋅ application of manufacturer's data and performance curves to actual process 

conditions, activity levels and durations, and 

⋅ direct measurements. 

Blowdown and purging events warrant a careful engineering analysis of each particular case to 

determine typical emission volumes per event based on a mass balance. 

A brief description of the different types of venting and purging activities included in this 

category is given in Section 5.1. The applicable assessment techniques are delineated in 

Section 5.2. Process venting by glycol dehydrators (i.e., still-column off-gas emissions) and 

addressed separately in Section 6.0. 

5.1 Source Characterization

There are a variety of different venting events that may occur at gas transmission and 

distribution facilities. Process venting includes blowdown, purging and pressure relief events as 

well as the use of natural gas as the supply medium for gas-operated devices. All four 

categories of methane releases are delineated below. 

5.1.1 Blowdowns. Blowdown events consist of isolating a pressurized section of piping or 

piece of equipment and then depressurizing the system through a vent to the 

atmosphere. If the gas is discharged to a flare or thermal oxidizer then it is not 

considered here. 

The following subsections describe the main blowdown events specific to gas 

transmission systems, and to gas distribution systems. However, minor blowdown events 

such as changing or inspection of orifice plates on flow meters should also be 

considered. 

5.1.1.1 Gas Transmission Systems. There are three general categories of 

blowdowns on natural gas transmission systems: station blowdowns (for 

depressurization of yard piping and process equipment at aboveground 
 105 

facilities), unit blowdowns (for blowdown of individual compressor units), 

and mainline blowdowns (for depressurization of pipeline segments). 

Pipeline blowdowns occur very infrequently for the section of pipe between 

any two successive block valves but may create a significant amount of 

waste gas as is shown in Table 11. 

ple of potential waste gas volumes and frequencies for blowdowns, purges and 

other venting activities on mainline transmission pipeline segments and at 

compressor stations. 

 Blowdown/Venting 

Event 

 Location Waste Gas 

 Volume1

(103 m3/event)

 Frequency of 

 Occurrence 

Mainline BlockValve Blowdown Pipeline 0.3 to 2,770+ Very infrequently 

for any given 

segment (say once 

every 20 years). 

Pipeline Purge Pipeline 0.1 to 150 Very infrequently 

for any given 

segment (say once 

every 20 years). 

Station Blowdowns Compressor Station 0.3 to 1.5 Several times per 

year or less. 

Scrubber 

Blowdowns 

Compressor Station 0.1 to 1.1 Typically, less than 

once per year. 

Booster Vents2 Compressor Unit 0.1 to 5.5 Monthly. 

Compressor Starts Compressor Unit 0.01 to 1.2 Usually at least 

several times per 

month. 

Source: Adapted from Picard (1995), .Table 1, page 4. 

1 Based on the range of values observed for one gas transmission company. 

2 This accounts for the gas released when the piping and cylinders on the compressor unit itself are 

depressurized.
 106 

The amount of gas released during individual blowdown events depends on 

the internal volume of the piping and equipment to be depressurized, the 

initial temperature and pressure of the gas, and the mitigation measures 

employed. These factors may vary greatly between companies and for 

different locations on a given system. 

A few examples of the mitigative measures that may be encountered are as 

follows: 

⋅ End-user demands on the system may sometimes be used to 

achieve partial depressurization of an isolated pipeline section prior 

to a blowdown event and, thereby, reduce the amount of waste gas. 

In populated areas, this can be done using the demand load from 

large regulator stations which exist on the target pipeline segment; 

however, careful monitoring is required to ensure delivery pressures 

do not drop below service requirements. 

⋅ In remote areas where there are only a few small regulator stations, 

mainline compressor stations can be used to draw gas from a target 

section down to a pressure of about 4140 kPag. Further gas may 

then be recovered by using a mobile pulldown or transfer 

compressor unit. Transfer rates for a pulldown compressor will vary 

with the pressure differential between the section being evacuated 

and the receiving section. Once the rate at which gas is being 

evacuated drops below the incremental increase in fuel consumption 

required for the mainline compressors to ship gas around the out-ofservice mainline valve section for he transfer operation itself, the 

mobile compressor is stopped and the remaining gas in the mainline 

valve section is relieved through a blowdown system. 
 107 

The final pressure at the end of a pulldown operation using a mobile 

transfer compressor might be 700 to 1400 kPa. transfer times for 

typical mainline sections are approximately 24 to 48 hours. In 

comparison, a compressor station blowdown lasts about 2 minutes. 

Not all companies use pulldown compressors. A major reason for not 

using them has been the issue of manpower and capital costs for a 

unit that might be used only one month a year. Also, these transfer 

operations require more outage time than simple venting. 

⋅ Other options include schemes for vent gas recovery, and avoidance 

of blowdowns by using external repair techniques instead of cut outs 

to repair a damaged pipe segment. 

5.1.1.2 Gas Distribution Systems. The different types of blowdown events that 

may occur on gas distribution systems, and the amount of gas lost through 

these events are summarized in Table 12. As the presented values 

indicate, repairs or maintenance on distribution systems usually can be 

performed with minimal blowdown volumes. On PE mains, the line can be 

pinched or squeezed on either side of a repair or tie-in point. 

On steel mains, tie-ins can be made under pressure using hot-tap tees, 

thus, avoiding the need for any blowdown. Repairs can be made using full 

encirclement welding sleeves, patches, clamps and stoppler equipment. 

PVC pipe is repaired by pipe replacement or application of a leak seal. The 

pipe replacement method involves cutting the leaking portion of pipe from 

the line and connecting a new piece of PVC pipe using compression 

fittings. The leak seal method involves sealing the hole using a fibreglass 

wrap. In either case, the line can be repaired while it is under pressure 

provided adequate safety precautions are taken. The pipe replacement 

approach is usually used for repair of large leaks, and the latter approach is 

used for small leaks. 

Before a blowdown event is started, an effort is made to minimize the 

volume of gas that will be discharged. This may be achieved through the 

following measures: 

⋅ transfer the gas to a lower pressure network, 

⋅ use compressors to transfer gas to a higher pressure network, or 

⋅ discontinue feeding the source and allow the load on the pipeline to 

reduce the volume and pressure (this must be closely monitored as 

most customers require a specified minimum supply pressure). 
 108 

Pulldown compressors are usually only used when the pipeline is longer 

than 2 km and the pipe size is 168.3 mm O.D. (6 NPS) or greater. The 

pressure is reduced to about 10 to 20 kPag using a pulldown compressor. 

5.1.2 Purging. Purging events are much the same on transmission and distribution systems. 

Either natural gas is used to purge contaminants and unwanted material (e.g., 

accumulated liquids or debris) from pressurized piping and equipment, or else air, or 

possibly nitrogen, are used to purge natural gas from an isolated pressure system to 

allow safe access. Other examples of purging include discharge of accumulated liquids 

from scrubbers and drip pots, odourizer and orifice plate blowdowns, and clearing 

instrument lines and some types of flow recorder systems. 

Direct displacement of air with gas when putting a line into service, and direct 

displacement of gas with air when taking a line out of service, are acceptable purging 

techniques for pipe sizes up to 114.3 mm OD (4 NPS). However, the velocity must be 

kept high enough to prevent hazardous mixtures of these gases from forming at their 

interface. For applications involving larger pipe sizes, the air and gas are separated by a 

slug of inert gas (nitrogen or carbon dioxide). In some smaller applications, purging is 

done using nitrogen from a pumping truck. 

al blowdown events on a gas distribution system and the amount of waste gas 

involved as estimated by one gas distribution company. Another reason for 

blowdowns is the abandonment of lines as part of replacement projects1. 

 Event Normal Operating 

 Pressure 

 (kPag) 

Waste Gas 

Volume 

(m3) 

Service installation. 

Main installation. 

Meter installation. 

Repair to a damaged main or service 

line. 

420 

420 

420 

420 

0.4 

0.4 

0.03 

150 

Source: Adapted from Picard (1995), Table 2, page 8. 

1 One company estimated that it abandons 50 to 80 km of cast iron pipeline each year. 
 109 
 110 

The purged material is usually discharged directly to atmosphere through an appropriate 

vent system or atmospheric tank. However, if the gas has been odourized, some gas 

distribution companies may flare the waste gas instead (especially if significant volumes 

of gas are involved). 

Vent stacks used for purging normally extend about 2 m above the ground. Purging is 

considered to be complete when 100 percent gas is detected at the vent when purging 

the pipeline into service, or 0 percent is detected at the vent when purging a pipeline out 

of service. 

5.1.3 Gas-Operated Devices. Use of gas-operated devices is an issue if the supply medium is 

natural gas. Common examples of these types of devices at gas facilities include the 

following: 

⋅ Gas-operated Control Loops - There are two main sources of emissions 

associated with a gas-operated control loop: bleeding actions of the flapper nozzle 

detector used in each pneumatic instrument (e.g., controllers, transmitters, 

positioners and transducers), and exhausting of gas pressure from the actuator 

during stroking of the control device (usually a valve or a set of louvres). The total 

amount of gas emitted by a single control loop is determined by the number of 

bleeding instrument components, the number of actuators, the design of these 

components, and the level of control activity. 

Typically, the loop comprises an input sensing device (e.g., pressure, temperature 

or liquid level transducer), a controller, and a control device operated by an 

actuator. The sensing device monitors the process variable to be controlled. The 

controller regulates the energizing and de-energizing of the actuator based on the 

output from the sensing device and the specified control settings. The actuator 

converts the energy changes it experiences into mechanical adjustments to the 

control device. In some instances the actuator is equipped with a positioner to 

ensure precise adjusting of the control device. If some of the instruments in the 

control loop are electronic rather than pneumatic, then I/P (electric current to 

pneumatic pressure) or E/P (voltage to pneumatic pressure) positioners may also 

be incorporated in the control loop. 

Instances where natural gas may be used as the supply medium for pneumatic 

control loops include some industrial sales points, liquid-level controllers on inlet 

scrubbers, mainline control valves, and compressor recycle valves. In most other 

instances, compressed air is used. 

⋅ Pneumatic-Activated Isolation-Valve Actuators - Large valves that would be 

difficult to stroke manually using a handwheel or handle may be equipped with a 
 111 

pneumatic actuator. Depending on the required supply pressure and the 

availability of compressed air, it is sometimes necessary to use process gas to 

energize the actuator. 

There are three different types of pneumatic actuators that can provide the large 

actuating forces required in these applications: piston (or double-acting), rotary 

vane and turbine. In applications requiring only small to moderate actuating forces, 

diaphragm (or single-acting) actuators are most commonly used due to their lower 

cost and reduced supply-gas requirements. 

A single-acting actuator uses supply pressure to move the actuator in one 

direction, and exhausts gas to allow the spring force to move the actuator in the 

opposite direction. A double-acting actuator uses a combination of increasing 

supply pressure on one side of the piston and exhausting it on the other to move in 

each direction. Consequently, the double acting actuator exhausts twice as much 

gas as a single acting actuator in the same application. Rotary vane and turbine 

actuators are essentially motorized operators that are powered using the supply 

gas pressure. 

In each case, the amount of gas exhausted is determined by the efficiency of the 

actuator mechanism, the available supply gas pressure, and the amount of 

travel/rotation and force required to stroke (i.e., open or close) the valve. 

⋅ Small gas-driven pumps - Some of the most common applications where gasdriven pumps may be used are: 

⋅ injection of methanol and other chemicals into gas pipelines, 

⋅ high-pressure bearing lubrication, 

⋅ lubrication of mechanical seals, 

⋅ circulation of glycol on glycol dehydrators, and 

⋅ odourization systems. 

The basic unit comprises a unitized gas motor and pump. The gas motor operates 

by expanding the supply gas against a diaphragm or piston and rod assembly 

which in turn drives the pump plunger. The expanded supply gas is then vented to 

atmosphere or into a collection system and the cycle repeated. Pumping 

capacities of less than 3 L/d to more than 3 m3/d, and injection pressure 

capabilities of up to 62 000 kPag are available through a range of pump sizes and 

models. 
 112 

Some gas-driven pumps are designed to operate off low uniform supply pressures 

of 345 kPag or less and others are designed to operate off high or erratic 

pressures up to 10 340 kPag. 

The amount of gas consumption is determined by the change in pressure of this 

gas in passing through the gas motor, the pumping rate and the required chemical 

injection pressure. As much as 7.5 m3 of gas may be require to pump each litre of 

liquid; however, most applications will require much less gas than this (i.e., 

typically only half as much). 

Recent work sponsored by GRI/U.S EPA (Myers and Harrison, 1996) indicates 

Kimray pumps (the most commonly used type of glycol circulation pump) exhaust 

about 0.178 m3 of CH4 per 103 m3 of gas processed at gas plants. This factor 

assumes that 33 percent of the dehydrators are equipped with flash tanks and that 

10 percent have combustion vent controls (also see Section 6). 

⋅ Gas-driven motors - are widely used to start the reciprocating or turbine engines 

on natural gas compressors. The supply medium is the natural gas from the 

pipeline. The vent from the starter motor is usually open to the atmosphere; 

although, sometimes it may be connected to a flare system. 

Specific starting gas requirements for engine-driven compressors will vary 

according to the pressure of the start gas, the size of the compressor and the 

condition of the engine. A larger (10 MW) gas turbine-driven compressor may 

require as much as 225 m3 of natural gas for each start attempt. Consequently, if 

start sequences are initiated more than a few times during the year, significant 

amounts of gas may be vented to the atmosphere. 

5.1.4 Emergency Pressure Relief. Emergency pressure-relief events occur when the 

maximum operating pressure of a system is exceeded. While this, generally is a rare 

occurrence, it can contribute a significant volume of emissions. Potential leakage past the 

seat of the relief devices during non-relieving periods (i.e., the majority of the time) is 

accounted for separately (see Sections 3.1.6 and 3.2). 

5.1.5 Sampling Systems Sampling systems, typically, are encountered at gas transmission 

receipt and transfer stations. They may be as simple as a probe and valve assembly to 

facilitate manual collection of a grab sample for subsequent laboratory analysis. 

However, more often, they are designed to draw a continuous sample for online analysis 

by one or more analyzers (for example, a calorimeter, chromatograph, dew point 

analyzer, or H2S analyzer). 
 113 

Emission from the manual system may be attributed to the purging activities associated 

with each sampling event (purging is done to blow out any foreign matter in the sample 

probe or valve, and to remove any air in the sample lines when the sampler is put into 

service and the sample container is attached). Thus, the amount of emissions from a 

manual sampling system depends on the extent and frequency of purging. Leakage from 

any fittings and valves that actually make up the system, would be accounted for 

separately (see Section 3).. 

An online gas analyzer normally draws a continuous stream of sample. It uses some 

fraction of this stream and then vents both the unused and spent portions to the 

atmosphere. Depending on the type of analyzer, the used portion of sample may be 

released unchanged or as products of combustion. Consequently, the amount of 

emissions depends on the sampling rate and the characteristics of the analyzer. A value 

of 0.0985 m3/h was determined for one analyzer system on a natural gas transmission 

pipeline (unpublished report). 

5.2 Emission Assessment Techniques

A program to assess the emissions from venting and purging activities requires a thorough 

investigation to properly identify all such sources, and compile the information necessary 

quantify the emissions (e.g., frequency of occurrence and either release volume or the duration 

and average emission rate associated with each event). Many companies already maintain this 

kind of information for the larger blowdown and release events, so all that is required for these 

sources is to aggregate the results and make appropriate corrections for the methane content of 

the natural gas. However, a careful review of the data is required to ensure completeness (e.g., 

compressor blowdowns may not be tracked by all companies and these volumes are potentially 

large). 

5.2.1 Estimation Methods. Table 4 in Section 3.2.1 provides average emission factors for 

standard instrument control loops (e.g., liquid level and pressure controllers) based on 

actual measurements at gas transmission and distribution facilities (Ross and Picard, 

1996). Additional factors are provided in Table 13. 

Potential high-usage components such as such as mainline control valves and 

compressor recycle valves should be considered separately. Presently, there is very 

limited data available for doing this. Measurements performed on one mainline control 

valve indicated an average gas consumption rate of 1.504 m3/h. This agrees very well 

with the average value of 1.608 m3/h/device reported for continuous-bleed devices used 

at natural gas transmission facilities in the U.S. (Shires and Harrison, 1996). 

The amount of emissions from isolation-valve operators is a function of the operating 
 114 

conditions, actuator type and size, and the frequency of actuation. Shires and Harrison 

(1996) report an average value of 0.018 m3/h/device for isolation valves equipped with 

rotary vane actuator based on measurements performed at four gas transmission 

facilities in the U.S. (see Table 14). Manufacturer's data for turbine-operated isolation 

valves are presented in Table 15. 

In evaluating emissions from purging and blowdown events care needs to be taken to 

ensure there is no double counting of emissions. There are no accepted factors for 

estimating emissions from these types of activities, although the data provided in Tables 

11 and 12 may be used in the absence of any better information. It is preferable to 

consider the physical volume of the systems involved and calculate emissions based on 

the amount of gas contained within these volumes at the initial temperatures and 

pressures using the equation below: 

where, 

V = volume of gas initially contained within 

the system referenced at standard temperature and 

pressure (i.e., 15_C and 101.325 kPa), 

Vs = physical volume of the system to be blown down or purged (m3) (see Table 

16 for specific volumes of various pipe sizes), 

Pi = initial system pressure (kPa) (absolute), 

Ti = initial system temperature (_C), and 

Zi = compressibility factor for the natural gas at the initial temperature and 

pressure of the system (may be set to a value of 1.0 for gauge pressures 

below 400 kPa, selected from Table 17, 18 or 19 according to the type of 

natural gas mixture, or calculated using a suitable equation of state). 

Average consumption rates by gas-operated pumps, compressor starter motors, and 

pneumatic-actuated isolation valves should be assessed by the frequency or period of 

use and the manufacturer's performance curves. 

5.2.2 Direct Measurement. In some cases it may be practicable to determine venting rates 
 115 

through a statistical sampling of sources using direct flow measurement techniques such 

as duct or stack flow measurement methods. 

In-line flow meters usually provide the best accuracy (e.g., ±5 percent or better), but are 

limited to applications involving low to moderate flow rates, and where the back-pressure 

caused by the flow measurement device can be tolerated by the emission source. 

Common types of in-line flow meters include bubbleometers, rotameters, orifice meters, 

turbine meters, and diaphragm meters. 

For high flow rates or cases where back-pressures cannot be tolerated, emission rates 

may be determined by performing velocity traverses with a suitable velocity probe, and 

then integrating the results over the stack or duct cross-section. If a convenient access 

port is not available it may be possible to direct the flow through a temporary duct section 

with the necessary features. A pitot tube and manometer arrangement may be used for 

measurement of moderate to high velocities. A hot-wire anemometer provides the best 

sensitivity for low flows; however, an intrinsically-safe model should be selected. 
 116 

Typical gas consumption rates for a variety of standard and low-bleed types of pneumatic 

instruments1. 

Type Supply Pressure: 140 kPag Supply Pressure: 240 kPag

Steady-state 

(m3/h) 

Max. 

Exhaust 

(m3/h) 

Steady-state 

(m3/h) 

Max. 

Exhaust 

(m3/h) 

Standard 

Consumptio

n 

Devices 

Transmitter 0.12 0.72 0.20 1.20 

Controller 0.40 to 0.80 4.5 to 5.5 0.60 to 1.00 7.0 to 8.5 

I/P 

Transducer 

0.60 15.0 0.80 20.0 

P/P Positioner 0.32 4.4 0.46 7.6 

I/P Positioner 0.40 5.0 0.60 8.0 

Low 

Consumptio

n 

Devices 

Transmitter 0.08 0.4 0.1 0.45 

Controller 0.10 0.45 0.14 0.5 

I/P 

Transducer 

0.10 9 0.13 12.0 

P/P Positioner 0.15 0.45 0.20 7.5 

I/P Positioner 0.20 0.5 0.25 7.5 

1 Source: Picard and Sarkar (1993), Table 2-2, page 2-4.
 117 

Gas usage by pneumatic/hydraulic rotary vane isolation valve operators. 

 Site Supply Gas 

 Pressure 

 (kPag) 

 Actuator 

 Size 

 Gas Usage 

 per Cycle 

 (m3/MPa) 

 Number of 

 Devices 

 Cycles 

 per Year 

 Gas Usage 

per 

 Device Type 

 (m3/y) 

1 6447 6.5 x 3.5 

6.5 x 3.5 

9 x 7 

11 x 7 

14.5 x 14 

16.5 x 16 

16.5 x 16 

18 x 8 

18 x 8 

18 x 12 

25 x 16 

25 x 16 

0.0193 

0.0193 

0.0505 

0.0904 

0.3499 

0.4858 

0.4858 

0.2008 

0.2008 

0.3499 

1.3060 

1.3060 

4 

1 

1 

1 

1 

3 

2 

3 

1 

1 

5 

1 

12 

1 

1 

1 

1 

1 

12 

1 

12 

1 

12 

1 

10.8

0.2

0.7

1.2

4.6

19.1

152.7

7.9

31.6

4.6

1026.3

17.1

Total Emissions for Site 1 = 1276.7 m3

Site Weighted A erage = 53.2 ± 54% m v 3/y/device (or 0.0061 ± 54% m3/h/device) 

2 6447 25 x 16 

25 x16 

25 x 16 

20 x 16 

12.5 x 12 

12 x 12 

15 x 8 

18 x 8 

18 x 8 

20 x 16 

20 x 16 

26 x 36 

25 x 16 

9 x 7 

9 x 7 

1.3060 

1.3060 

1.3060 

0.8136 

0.1980 

0.1980 

0.1146 

0.2008 

0.2008 

0.8136 

0.8136 

3.1069 

1.3060 

0.0505 

0.0505 

4 

2 

2 

6 

4 

3 

1 

1 

1 

1 

1 

1 

1 

5 

2 

92 

64 

50 

5 

92 

5 

6 

6 

50 

2 

15 

36 

2 

5 

2 

6725.1

2339.2

1827.5

4181.0

41.5

16.6

9.6

140.5

5.6

170.8

409.8

87.0

548.2

17.7

2.8

Total Emissions for Site 2 = 16531.5 m3

Site Weighted Average = 472.3 ± 37% m3/y/device (or 0.0539 ± 37% m3/h/device) 

3 6895 5.5 x 3.5 

6.5 x 8 

9 x 7 

11 x 10 

12.5 x 10 

0.0144 

0.0329 

0.0505 

0.1306 

0.1146 

7 

14 

8 

1 

1 

15.2 

15.2 

15.2 

15.2 

15.2 

20.0

91.3

80.2

25.9

22.7
 118 

12.5 x 12 

20 x 16 

25 x 16 

16.5 x 16 

14.5 x 1412.5 

x 12 

0.1980 

0.8136 

1.3060 

0.4858 

0.34990.1980 

5 

3 

12 

9 

11 

15.2 

15.2 

15.2 

15.2 

15.215.2 

196.5

484.4

3110.7

867.9

69.539.3

Total Emissions for Site 3 = 5008.4 m3

Site Weighted Average = 80.8 ± 27% m3/y/device (or 0.0092 ± 237% m3/h/device) 

Gas usage by pneumatic/hydraulic rotary vane isolation valve operators (Concluded). 

 Site Supply Gas 

 Pressure 

 (kPag) 

 Actuator 

 Size 

 Gas Usage 

 per Cycle 

 (m3/MPa) 

 Number of 

 Devices 

 Cycles 

 per Year 

 Gas Usage 

per 

 Device Type 

 (m3/y) 

4 6550 12.5 x 12 

6.5 x 3.5 

11 x 10 

16 wkm 

0.1980 

0.0172 

0.1306 

0.2957 

3 

1 

1 

2 

12 

12 

12 

12 

94.8

2.7

20.8

99.3

Total Emissions for Site 4 = 217.7 m3

Site Weighted Average = 31.1 ± 39% m3/y/device (or 0.0036 ± 39% m3/h/device) 

Average displacement device emission factor = 159.3 ± 112% m3/y/device (or 0.0182 ± 112% m3/h/device) 

Source: Adapted from Shires and M.R. Harrison (1996), Table 4-7, pages 49 and 50. 

Manufac urer data for t rbine-operate isolation valv s. t u d e

Site Supply Gas 

Pressure 

(kPag) 

Gas 

Consumptio

n 

(m3/h) 

Time 

(s/operation

) 

Gas Usage 

(m3/operation) 

Actuation 

Frequenc

y 

(cycles/y) 

Natural Gas

Emissions 

(m3/y/devic

e) 

1 6200 to 

6690 

850 to 880 30 

120 

7.22 

28.88 

11 

1 

108.3 

2 5520 800 180 39.93 75 5989.0 

3 5520 800 90 19.96 29 1157.9 

4 5520 800 90 19.96 29 1157.9 
 119 

5 5520 800 90 19.96 29 1157.9 

Average Turbine Device Emission Factor = 1914.2 ± 276% m3/y/device (or 0.219 ± 276% 

m3/h/device) 

Source: Adapted from Shires and M.R. Harrison (1996), Table 4-8, page 52.
 120 

Summary of dimensional and specific internal-volume data for selected pipe sizes. 

NPS Schedul

e 

OD 

(mm) 

WT 

(mm) 

Specific 

Volume 

(m3/m) 

NPS Schedul

e 

OD 

(mm) 

WT 

(mm) 

Specific 

Volume 

(m3/m) 

1⁄2 80 21.34 3.73 0.00015

1 

2 XXHY 60.32 11.07 0.00114

5 

160 21.34 4.75 0.00011

0 

21⁄2 40 73.02 5.16 0.00308

8 

XXHY 21.34 7.48 0.00003

2 

--- 73.02 5.51 0.00301

9 

3⁄4 80 26.67 3.91 0.00027

9 

80 73.02 7.01 0.00273

4 

--- 26.67 4.78 0.00023

0 

160 73.02 9.52 0.00228

9 

160 26.67 5.54 0.00019

1 

XXHY 73.02 11.07 0.00203

3 

XXHY 26.67 7.82 0.00009

6 

3 --- 88.90 4.78 0.00494

4 

1 80 33.40 4.55 0.00046

4 

40 88.90 5.49 0.00476

9 

--- 33.40 5.56 0.00039

0 

--- 88.90 6.45 0.00453

6 

160 33.40 6.35 0.00033

7 

80 88.90 7.62 0.00426

1 

XXHY 33.40 9.09 0.00018

2 

--- 88.90 7.92 0.00419

2 

11⁄4 80 42.16 4.85 0.00082

8 

160 88.90 11.13 0.00348

8 

160 42.16 6.35 0.00068

2 

XXHY 88.90 15.24 0.00268

0 

XXHY 42.16 9.70 0.00040

7 

31⁄2 40 101.6 5.74 0.00637

9 

11⁄2 40 48.26 3.68 0.00131

4 

80 101.6 8.08 0.00573

3 
 121 

60 48.26 5.08 0.00114

0 

XXHY 101.6 15.24 0.00397

3 

80 48.26 7.14 0.00090

7 

4 40 114.3 6.00 0.00821

9 

XXHY 4826 10.16 0.00061

3 

80 114.3 8.56 0.00741

7 

2 40 60.32 3.91 0.00216

5 

120 114.3 11.13 0.00665

3 

--- 60.32 4.24 0.00211

1 

160 114.3 13.49 0.00598

8 

--- 60.32 4.78 0.00202

4 

XXHY 114.3 17.10 0.00503

9 

80 60.32 5.54 0.00190

4 

6 40 168.3 7.1 0.01865

1 

--- 60.32 6.35 0.00178

1 

80 168.3 11.0 0.01681

0 

--- 60.32 7.92 0.00155

4 

120 168.3 14.3 0.01532

8 

160 60.32 8.71 0.00144

5 

160 168.3 18.2 0.01366

4

NPS - Nominal Pipe Size 

OD - Outside Diameter 

WT - Nominal Wall Thickness 

Summary o dimension l and spec ic inte f a if rnal-volume data for selected pipe sizes. 

NPS Schedul

e 

OD 

(mm) 

WT 

(mm) 

Specific 

Volume 

(m3/m) 

NPS Schedul

e 

OD 

(mm) 

WT 

(mm) 

Specific 

Volume 

(m3/m) 

6 XXHY 168.3 21.9 0.01217

4 

14 30 355.6 9.5 0.08898

5 

8 20 219.1 6.4 0.03342

6 

40 355.6 11.1 0.08730

1 

30 219.1 7.0 0.03303

9 

60 355.6 15.1 0.08316

2 

40 219.1 8.2 0.03227

0 

80 355.6 19.1 0.07912

3 
 122 

60 219.1 10.3 0.03094

6 

120 355.6 27.8 0.07068

6 

80 219.1 12.7 0.02946

8 

160 355.6 35.7 0.06343

6 

120 219.1 18.2 0.02621

6 

16 10 406.4 6.4 0.12167

5 

XXHY 219.1 22.2 0.02397

0 

20 406.4 7.9 0.11982

7 

160 219.1 23.0 0.02353

3 

30 406.4 9.5 0.11787

2 

10 20 273.1 6.4 0.05321

6 

40 406.4 12.7 0.11400

9 

30 273.1 7.8 0.05207

7 

60 406.4 16.7 0.10927

2 

40 273.1 9.3 0.05087

0 

80 406.4 21.4 0.10383

4 

60 273.1 12.7 0.04818

8 

120 406.4 30.9 0.09326

5 

80 273.1 15.1 0.04633

9 

160 406.4 40.5 0.08316

2 

120 273.1 21.4 0.04165

6 

18 10 457.0 6.4 0.15497 

160 273.1 28.6 0.03661

0 

20 457.0 7.9 0.15288

4 

12 20 323.9 6.4 0.07601

3 

30 457.0 11.1 0.14848 

30 323.9 8.4 0.07407

1 

40 457.0 14.3 0.14414

1 

40 323.9 10.3 0.07224

9 

60 457.0 19.1 0.13775

4 

60 323.9 14.3 0.06848

8 

80 457.0 23.8 0.13163

9 

80 323.9 17.4 0.06564

3 

120 457.0 34.9 0.11775

0 
 123 

120 323.9 25.4 0.05857

8 

160 457.0 45.2 0.10555

4 

160 323.9 33.3 0.05199

6 

20 10 508.0 6.4 0.19259

8 

14 10 355.6 6.4 0.09229

4 

20 508.0 9.5 0.18780

5 

20 355.6 7.9 0.09068

5 

30 508.0 12.7 0.18292

1

NPS - Nominal Pipe Size 

OD - Outside Diameter 

WT - Nominal Wall Thickness

Summary o dimension l and spec ic inte f a if rnal-volume data for selected pipe sizes. 

NPS Schedul

e 

OD 

(mm) 

WT 

(mm) 

Specific 

Volume 

(m3/m) 

NPS Schedul

e 

OD 

(mm) 

WT 

(mm) 

Specific 

Volume 

(m3/m) 

20 40 508.0 15.1 0.17930

1 

30 40 762 19.1 0.41145

9 

60 508.0 20.6 0.17114 --- 762 23.8 0.40084

2 

80 508.0 26.2 0.16302

6 

--- 762 28.6 0.39014

1 

120 508.0 38.1 0.14643

8 

32 10 813 7.9 0.49914

2 

160 508.0 50.0 0.13074

1 

20 813 12.7 0.48719

3 

24 10 610.0 6.4 0.28011

1 

30 813 15.9 0.47930

8 

20 610.0 9.5 0.27432

5 

40 813 17.5 0.47538

9 

30 610.0 14.3 0.26548

5 

--- 813 23.8 0.46011

5 

40 610.0 17.5 0.25967

2 

--- 813 28.6 0.44864

6 

60 610.0 24.6 0.24700

5 

34 10 864 7.9 0.56504

9 
 124 

80 610.0 30.9 0.23603

0 

20 864 12.7 0.55233

1 

120 610.0 46.0 0.21074

1 

30 864 15.9 0.54393

3 

160 610.0 59.5 0.18934

5 

40 864 17.5 0.53975

8 

26 10 660 7.92 0.32589

5 

--- 864 23.8 0.52347

5 

20 660 12.7 0.31629

3 

--- 864 28.6 0.51123

6 

--- 660 15.9 0.30994

6 

36 10 914 7.9 0.63363

0 

--- 660 20.6 0.30074 20 914 12.7 0.62015

8 

28 10 711 7.9 0.37958

5 

30 914 15.9 0.61125

7 

20 711 12.7 0.36917

4 

40 914 19.1 0.60242

1 

30 711 15.9 0.36231

4 

--- 914 23.8 0.58955

8 

--- 711 20.6 0.35235

5 

--- 914 28.6 0.57656

6 

--- 711 25.4 0.34232

7 

38 --- 965 10.3 0.70049

0 

30 10 762 7.9 0.43732

1 

--- 965 11.9 0.69575

1 

20 762 12.7 0.42614

1 

--- 965 15.9 0.68397

4 

0.41876 0.67462
 125 

30 762 15.9 8 --- 965 19.1 4

NPS - Nominal Pipe Size 

OD - Outside Diameter 

WT - Nominal Wall Thickness

Summary of dimensional and specific internal-volume data for selected pipe sizes. 

NPS Schedul

e 

OD 

(mm) 

WT 

(mm) 

Specific 

Volume 

(m3/m) 

NPS Schedul

e 

OD 

(mm) 

WT 

(mm) 

Specific 

Volume 

(m3/m) 

38 --- 965 23.8 0.66100

9 

42 --- 1067 10.3 0.85997

4 

--- 965 28.6 0.64724

7 

20 1067 12.7 0.85210

2 

40 --- 1016 10.3 0.77818

9 

30 1067 15.9 0.84166

3 

--- 1016 11.9 0.77319

4 

40 1067 19.1 0.83128

9 

--- 1016 15.9 0.76077

6 

--- 1067 23.8 0.81616

7 

--- 1016 19.1 0.75091

4 

--- 1067 28.6 0.80086

7 

--- 1016 23.8 0.73654

5 

--- 1016 28.6 0.72201

5 

NPS - Nominal Pipe Size 

OD - Outside Diameter 

WT - Nominal Wall Thickness
 126 

Compressibility factors for "Rich Processed Natural Gas" upstream of straddle plants for 

various combinations of temperature a d pressure n 1. 

Absolute 

Pressure 

(kPa) 

0_C 

(dimensionless) 

5_C 

(dimensionless) 

10_C 

(dimensionless) 

15_C 

(dimensionless) 

100 0.996346 0.996543 0.996728 0.996901 

200 0.992694 0.993089 0.993459 0.993806 

300 0.989044 0.989637 0.990194 0.990716 

400 0.985395 0.986188 0.986932 0.987630 

500 0.981747 0.982742 0.983675 0.984549 

600 0.978102 0.979300 0.980421 0.981473 

700 0.974459 0.975860 0.977172 0.978402 

800 0.970818 0.972424 0.973927 0.975336 

900 0.967179 0.968991 0.970687 0.972275 

1 000 0.963543 0.965562 0.967451 0.969220 

2 000 0.927356 0.931512 0.935386 0.939001 

3 000 0.891629 0.898039 0.903985 0.909514 

4 000 0.856627 0.865389 0.873481 0.880972 

5 000 0.822707 0.833886 0.844160 0.853634 

6 000 0.790337 0.803932 0.816371 0.827798 

7 000 0.760103 0.776010 0.790516 0.803801 

8 000 0.732677 0.750658 0.767027 0.781994 

9 000 0.708752 0.728412 0.746327 0.762717 
 127 

10 000 0.688913 0.709729 0.728776 0.746251 

11 000 0.673516 0.694900 0.714608 0.732788 

12 000 0.662606 0.683995 0.703897 0.722395 

1 Values calculated using the Peng and Robinson equation of state (1976) for the following gas mixture (mol 

percent): 88.41% C1, 7.45% C2, 1.91% C3, 0.17% iC4, 0.24% nC4, 0.06% iC5, 0.04% nC5, 0.10% nC6+, 

0.72% N2 and 0.90% CO2. 

Compressibility factors for "Typical Processed Natural Gas" upstream of straddle plants 

various combinations of temperature a d pressure n 1. 

Absolute 

Pressure 

(kPa) 

0_C 

(dimensionless) 

5_C 

(dimensionless) 

10_C 

(dimensionless) 

15_C 

(dimensionless) 

100 0.996663 0.996845 0.997015 0.997176 

200 0.993330 0.993694 0.994036 0.994357 

300 0.990000 0.990547 0.991061 0.991543 

400 0.986673 0.987405 0.988091 0.988735 

500 0.983350 0.984268 0.985127 0.985933 

600 0.980031 0.981135 0.982168 0.983137 

700 0.976716 0.978006 0.979215 0.980347 

800 0.973405 0.974883 0.976267 0.977564 

900 0.970099 0.971765 0.973325 0.974786 

1 000 0.966797 0.968652 0.970389 0.972015 

2 000 0.934054 0.937850 0.941389 0.944693 

3 000 0.901958 0.907769 0.913167 0.918191 

4 000 0.870748 0.878630 0.885924 0.892689 
 128 

5 000 0.840724 0.850701 0.859899 0.868401 

6 000 0.812256 0.824299 0.835363 0.845558 

7 000 0.785772 0.799780 0.812613 0.824412 

8 000 0.761737 0.77519 0.791957 0.805213 

9 000 0.740609 0.757878 0.773681 0.788193 

10 000 0.722774 0.741160 0.758027 0.773544 

11 000 0.708480 0.727564 0.745153 0.761392 

12 000 0.697794 0.717156 0.735118 0.751787 

1 Values calculated using the Peng and Robinson equation of state (1976) for the following gas mixture (mol 

percent): 92.8693% C1, 4.0556% C2, 1.1112% C3, 0.1601% iC4, 0.2180% nC4, 0.0496% iC5, 0.0389% nC5, 

0.0225% nC6+, 0.8291% N2 and 0.6334% CO2. 

Compressibility factors for "Typical Processed Natural Gas" downstream of straddle various 

combinations of temperature and pressure1. 

Absolute 

Pressure 

(kPa) 

0_C 

(dimensionless) 

5_C 

(dimensionless) 

10_C 

(dimensionless) 

15_C 

(dimensionless) 

100 0.996956 0.997124 0.997282 0.997430 

200 0.993917 0.994254 0.994569 0.994865 

300 0.990883 0.991388 0.991862 0.992307 

400 0.987853 0.988529 0.989162 0.989756 

500 0.984829 0.985675 0.986467 0.987211 

600 0.981810 0.982827 0.983779 0.984672 

700 0.978796 0.979984 0.981097 0.982141 
 129 

800 0.975788 0.977148 0.978422 0.979616 

900 0.972785 0.974318 0.975754 0.977098 

1 000 0.969788 0.971495 0.973092 0.974588 

2 000 0.940170 0.943641 0.946879 0.949904 

3 000 0.911317 0.916598 0.921509 0.926084 

4 000 0.883437 0.890556 0.897154 0.903283 

5 000 0.856780 0.865734 0.874007 0.881670 

6 000 0.831632 0.842378 0.852279 0.861427 

7 000 0.808311 0.820753 0.832192 0.842740 

8 000 0.787145 0.801127 0.813965 0.825789 

9 000 0.768446 0.783747 0.797797 0.810737 

10 000 0.752472 0.768818 0.783850 0.797712 

11 000 0.739393 0.756475 0.772233 0.786799 

12 000 0.729270 0.746769 0.762987 0.778032 

1 Values calculated using the Peng and Robinson equation of state (1976) for the following gas 

mixture (mol percent): 95.213% C1, 2.4306% C2, 0.1374% C3, 0.0043% iC4, 0.0043% nC4, 

0.0013% iC5, 0.0010% nC5, 0.0012% nC6+, 1.6519% N2 and 0.5552% CO2. 
 130 

6.0 GLYCOL DEHYDRATORS

6.1 Source Characterization

Glycol dehydration is a continuous liquid desiccant process in which water or water vapour is 

removed from hydrocarbon streams by selective absorption and the glycol is regenerated or 

reconcentrated by thermal desorption. The use of triethylene glycol (TEG) is standard for 

dehydration of natural gas. 

This process is widely used in gas production and processing operations for removing water 

vapour from natural gas, but, normally, it is not required during the subsequent transmission and 

distribution stages. However, if the processed gas is placed in an underground storage cavern 

enroute to market, it may be necessary to re-dehydrate the gas upon removal from the cavern. 

The primary causes of methane emissions from a glycol dehydrator are secondary 

absorption/desorption by the TEG, entrainment of some gas from the contactor in the rich TEG, 

and use of stripping gas in the reboiler. These sources are the focus of this section. Other 

sources of methane emissions on a glycol dehydrator include fugitive equipment leaks (see 

Section 3.0) and venting by gas-operated devices (see Section 5.0). 

The basic dehydration process is as follows. Wet gas is brought into intimate contact with a 

counterflow of lean TEG in a vertical trayed contactor (or absorption column) to promote 

absorption of the water by the TEG. The wet gas flows in at the bottom of the tower and leaves 

at the top as dry gas, while the lean TEG enters at the top of the tower and exits at the bottom 

as rich TEG. The rich TEG is subsequently regenerated and return to the top of the tower to 

repeat the circuit. The TEG circulation rate is determined by the gas flow rate, the amount of 

water to be removed, the temperature and pressure in the tower, actual purity of the glycol at 

the inlet to the contactor, number of trays or packing height in the contactor, and the desired 

dew point depression (API, 1990). Typical values for plant applications are 17 to 50 L TEG/kg 

H2O removed. At 6900 kPag, glycol can absorb up to 7.5 standard litres of gas for every litre of 

glycol circulated (Sams, 1992). 

A low pressure flash separator is sometimes installed between the contactor and the 

regenerator to release any solution gas that may be entrained in the rich (wet) glycol, especially 

if a glycol energy exchange pump is used in the system. This type of pump uses pressure 

energy in the rich glycol to pump dry glycol into the contactor. The gas separated in the flash 

separator may be used to supplement the fuel and stripping gas required for the reboiler. Any 

excess flash gas is discharged through a back pressure valve to atmosphere. 

From the flash separator, the rich glycol then flows to a packed stripping still attached to the top 

of a reboiler. In the still column, the wet glycol flows down to the reboiler while contacting hot 

gases (mostly water vapour and glycol) rising up from the reboiler. The mixing of these two 

streams helps to preheat the wet glycol and to condense and recover any glycol vapours before 

the gases are vented from the top of the still. 
 131 

In the reboiler the glycol is heated to approximately 175o to 205oC to remove enough water 

vapour to reconcentrate it to 99.5 percent or more. Sometimes a small amount of natural gas 

(i.e., stripping gas) is injected into the bottom of the reboiler to help strip water vapour from the 

glycol. The water vapour rises through the stripping still and the lean glycol, finally, is cooled 

and returned to the top of the absorber column. 

6.2 Emission Assessment Techniques

The following discussion focus on the assessment of methane emissions from the flash tank (if 

one is used), and from the still-column off-gas vent. Refer to Section 3.0 for procedures for 

fugitive equipment leaks and Section 5.0 for venting by gas-operated devices. 

6.2.1 Emission Factors. The application of average emission factors to estimate methane 

emissions from glycol dehydrators is summarized in Form 6.2.-1. 

6.2.2 Process Modelling. Perhaps the most convenient method of estimating methane 

emissions from a glycol dehydrator is to use the simulation program GRI-GLYCalc 

developed for, and available at a nominal cost from, GRI (Thompson et al., 1994). GRIGLYCalc is primarily presented as a tool for estimating the amount benzene, toluene, 

ethyl benzene and xylene (BTEX) emitted by a glycol dehydrator (significant amounts of 

this material may be preferentially absorbed by the glycol and released off the flash tank 

and still column). However, in performing a rigorous simulation of the dehydration 

process, the program also provides information on the amount of methane emissions. 

Furthermore, the program can assess the emission reduction that may be achieved from 

use of selected control devices (e.g.,condensers and incinerators). The required input 

data includes, 

⋅ gas composition and flow rate, 

⋅ glycol circulation rate, 

⋅ temperature and pressure in the absorber column, 

⋅ type of glycol pump, 

⋅ operating pressure of the flash tank (if one is used) and amount of flash gas used 

by the process (if at all), 

⋅ type of glycol (TEG or DEG), and 

⋅ stripping gas usage. 

Alternatively, estimates may be made using commercial general-purpose process 

simulation packages (e.g., HYSIMTM by Hyprotech, PRO/IITM by Simulation Sciences, and 

PROSIMTM by Bryan Research & Engineering, Inc.). These will, potentially, provide more 

accurate results but require greater effort and expertise to use. Moreover, they are quite 

expensive and probably could not be justified for the subject application alone. 

6.2.3 Measurement. Emissions from a flash tank vent can be measured using the methods 
 132 

described in Section 5.2.2. A sample of the flash gas should be collected and analyzed to 

determine the actual methane content. 
 133 

Calculation Form 6.2.1-1 

OFF-GAS VENTING BY GLYCOL DEHYDRATORS

General Steps

Step No. Description Default 

Values1

1 Establish total gas throughput (103 m3) for the unit. None 

 

 2 Multiply the results from Step (1) by the basic emission factor 

for methane volumes discharged through the still-column offgas vent. 

0.00357 m3/103

m3 

 (if dehy has flash 

tank) 

- or - 

 0.1751 m3/103 m3

 (if dehy has no 

flash tank) 

3 Multiply the results from Step (1) by the basic emission factor 

for stripping gas consumption if stripping gas is used. 

0.670 m3/103 m3

4 Multiply the results from Step (1) by the basic emission factor 

for gas consumption by a Kimray-type energy-exchange 

pump if one is used. 

0.1777 m3/103 m3

5 Sum the results from Steps (2), (3) and (4). None. 

6 Multiply the results from Step (5) by factor for converting from 

cubic metres to tonnes of methane. 

0.6785 x 10-3 t/m3
 134 

1 The presented emission factors are based on data presented by GRI/US.EPA for glycol dehydrators and 

natural gas processing facilities (Myers, 1996). They only apply if the vent system does not have an 

combustion-type end control device.

Emissions from the still-column vent are more difficult to measure due to their high 

temperature and water content. The most accurate method would involve total capture, 

condensation of all water and condensable hydrocarbons, and final measurement and 

analysis of the uncondensed fraction. A more economical approach is, perhaps, to 

measure the total vent flow rate using a suitable intrinsically-safe device (e.g., a vanetype anemometer), collect a dry-gas sample (i.e., through a desiccant tube or absorption 

train) and analyze it for methane content, calculate the saturation water content of the 

gases at the measurement point based on the gas temperature and local barometric 

pressure, and then recombine the results to determined the actual methane emission rate 

Another option is to perform a mass balance based on the glycol circulation rate and an 

analysis of pressurized samples of the rich and lean glycol. The results need to be 

adjusted to reflect whether the rich sample was taken upstream or downstream of the 

flash tank. Also, any stripping gas consumption must be added to the results. The results 

are estimated to be low by as much as 20 percent for BTEX and as much as 40 percent 

for VOC values (Schievelbein, 1992). The accuracy for methane is not certain. 
 135 

7.0 ACCIDENTAL RELEASES

7.1 Source Characterization

Accidental releases are releases that occur as a result of accidents that are not part of normal 

operational or maintenance activities and that the system has not been designed for (that 

excludes such releases as, for example, relief valve emissions). 

The only significant types of natural gas emissions in this category are those from pipelines as a 

result of external damage of the pipe wall – so called third-party damages or dig-ins. 

7.2 Emission Assessment Techniques

7.2.1 Dig-ins. Damages to pipeline wall caused by external forces, usually by excavating 

equipment, are referred to as dig-ins. They are more frequently associated with 

distribution mains and services, as opposed to transmission pipelines, due to the 

significantly higher level of excavation activity in the vicinity of distribution pipelines, and 

due to the fact that transmission pipelines usually are located in well marked pipeline 

right of ways and constructed of high-toughness steel pipe. Therefore, unless a 

transmission pipeline operating company has specific data from emissions from pipeline 

dig-ins, the dig-ins emissions from transmission pipelines can be assumed to be 

negligible and ignored. 

Emissions from dig-ins are extremely difficult to quantify, since the emitted volume 

depends on a large number of variables: the extent and shape of the damage to the pipe 

wall, pipeline diameter, the operating pressure of the pipeline, the geometry and length of 

the pipeline system both upstream and downstream of the dig-in, the capacity of the gas 

source feeding gas into the pipeline system and the amount of the time before the 

blowing gas is either temporarily or permanently stopped. 

Most distribution companies have available detailed statistics on dig-in incidents, and inhouse estimating methods to quantify the amount of gas released to the atmosphere. 

The preferred methodology for estimating the dig-ins emissions is to utilize such 

company-specific data, corrected for the methane content of the natural gas ( either by a 

company-specific factor or per Table 5b in Section 3.0) , and converted to tons per year 

for inclusion in the overall emissions envelope. 

For those companies that do not have the necessary in-house data on dig-ins available, 

the following approximation can be used: 
 136 

where, 

= amount of methane emitted from dig-ins (t/y) 

x = methane content of natural gas (mass percent) (see table 5b or use 

company-specific data), and 

L = length of distribution mains and services (km). 

Some companies might document all dig-in incidents but quantify the volumes emitted 

from only some of them. If the volume quantification is available for a representative 

sample of the total incidents, an average volume per incident can be used to calculate 

the total company volume for dig-ins by multiplying it by the number of incidents. Care 

should be taken to ensure that a correction from natural gas volume to methane mass 

has been done somewhere in the calculation, either in the original quantification of the 

individual incidents, or in the final calculation of the company-wide emissions. 
 137 

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Underground Pipelines. A report prepared for GRI and U.S. EPA. GRI Report No. GRI94/0257.26. EPA Report No. EPA-6--/R-96-080i. 95 pp. 

Radian International. 1996j. Methane Emissions From the Natural Gas Industry. Volume 10: 

Metering and Pressure Regulating Stations in Natural Gas Transmission and Distribution. A 

report prepared for GRI and U.S. EPA. GRI Report No. GRI-94/0257.27. EPA Report No. EPA6--/R-96-080j. 44 pp. 

Radian International. 1996k. Methane Emissions From the Natural Gas Industry. Volume 11: 

Compressor Driver Exhaust. A report prepared for GRI and U.S. EPA. GRI Report No. GRI94/0257.28. EPA Report No. EPA-6--/R-96-080k. 81 pp. 

Radian International. 1996l. Methane Emissions From the Natural Gas Industry. Volume 12: 

Pneumatic Devices. A report prepared for GRI and U.S. EPA. GRI Report No. GRI-94/0257.29. 

EPA Report No. EPA-6--/R-96-080l. 85 pp. 

Radian International. 1996m. Methane Emissions From the Natural Gas Industry. Volume 13: 
 143 

Chemical Injection Pumps. A report prepared for GRI and U.S. EPA. GRI Report No. GRI94/0257.30. EPA Report No. EPA-6--/R-96-080m. 42 pp. 

Radian International. 1996n. Methane Emissions From the Natural Gas Industry. Volume 14: 

Glycol Dehydrators. A report prepared for GRI and U.S. EPA. GRI Report No. GRI-94/0257.31. 

EPA Report No. EPA-6--/R-96-080n. 47 pp. 

Radian International. 1996o. Methane Emissions From the Natural Gas Industry. Volume 15: 

Gas-Assisted Glycol Pumps. A report prepared for GRI and U.S. EPA. GRI Report No. GRI94/0257.33. EPA Report No. EPA-6--/R-96-080o. 30 pp. 

Scotto, R.L., T.R. Minnich, and M.R. Leo. 1991. A Method for Estimating VOC Emission Rates 

from Area Sources Using Remote Optical Sensing. Presented at the 1991 AWMA/EPA 

International Symposium on the Measurement of Toxic and Related Air Pollutants. Durham, NC, 

May, 1991. 6 pp. 

U.S. Environmental Protection Agency. 1995. Compilation of Air Pollutant Emission Factors - 

Volume I: Stationary Point and Area Sources. AP-42 Fifth Edition. Available through NTIS. 

Springfield, VA. Publication No. PB95-196028. 

U.S. Environmental Protection Agency. 1995. User's Guide for the Industrial Source Complex 

(ISC3) Dispersion Models. Volumes 1 and 2. EPA Publication Nos. EPA-454/B-95-003a & b. 

Available through NTIS. Publ. No. PB 95-222741 and PB 95-222758. 

U.S. Environmental Protection Agency. 1988. Protocols for Generating Unit-specific Emission 

Estimates for Equipment Leaks for Equipment Leaks of VOC and VHAP. Prepared by Emission

Standards Division, Office of Air and Radiation, and Office of Air Quality Planning and 

Standards. Research Triangle Park, NC. Report No. EPA-450/3-88-010. 

Wang, Y., T.S. Raihala, A.P. Jackman, and R. St. John. 1996. Use of Tedlar Bags In VOC 

Testing and Storage: Evidence of Significant VOC Losses. Environmental Science & 

Technology. v30, n10. pp. 3115-3117. 
 144 

 APPENDICES

10.1 Development of Equipment Component Counts 

10.2 Method 21 - Determination of Volatile Organic Compound Leaks 
 145 

10.1 DEVELOPMENT OF EQUIPMENT COMPONENT COUNTS

The following are the basic rules for compiling an accurate inventory of equipment components 

in active hydrocarbon service based on the classification scheme used to estimate fugitive 

equipment leaks: 

⋅ Compressor Seals: A reciprocating compressor is deemed to have one seal associated 

with each compressor cylinder regardless of whether it is really a single or tandem seal. 

A centrifugal compressor has two seals, one on each side of the housing where the shaft 

penetration occurs. Other components on the compressor and on any associated cooler 

(e.g., valves, connectors, pressure relief valves, open-ended valves and lines, and gasoperated instruments) need to be accounted for separately. 

⋅ Connectors: Each threaded, flanged or mechanical connection is counted as a single 

connector. Welded or backwelded connections are not counted. 

Some types of components may have more than one set of connections associated with 

them. For example a union may have 3 sets of connecting surfaces (2 end connections 

and a centre connection), a nipple or reducer may have 2 (one at each end), and tee may 

have 3 (one at each end). If all 3 connection points on a union are threaded then a union 

would be classified as a 3 connectors. A union that has welded end connections would 

be counted as only one connector. 

⋅ Valves: This category accounts for leakage from around the valve stem and from the 

valve body. The end connections and any leakage past the valve seat are counted 

separately (see connectors and open-ended valves or lines, respectively). 

⋅ Pressure-Relief Valve: Generally, an pressure-relief valve that discharges directly to the 

atmosphere or through a vent system is counted. However, if the valve discharges to a 

control device (e.g., flare or thermal oxidizer), or has a rupture disk installed upstream 

along with a monitoring system to indicate when the rupture disk has failed, then the 

valve is not counted.. 

The connection on the upstream side of the valve is counted as a separate component. 

The connection on the downstream side also is counted if the relief valve is connected to 

a control device. 

⋅ Open-ended Valves or Lines: Each valve in hydrocarbon service that has process fluid 

on one side and is open to the atmosphere on the other (either directly or through a line) 

is counted as an open-ended valve or line. If the open side of the valve is fitted with a 

properly installed cap, plug, blind flange or second closed block valve, or is connected to 

a control device then it is no longer considered to be open-ended (i.e., there is zero leak 

potential). 
 146 

A drain valve that discharges into the top of an underground storage tank is considered 

an open-end line. 

The valve stem and body, and the connector on the process side of the valve are 

counted as separate components. 

⋅ Sampling System - This category accounts for hydrocarbons that are released to the 

atmosphere as part of actual sampling activities, and the results are adjusted to reflect 

the frequency of occurrence. The individual parts of the system should be counted as 

separate components. Thus, an open-ended line that is used for routine sampling would 

be counted as both a sampling system and an open-ended line. 

For manual gas sampling systems, the sampling emissions would include any initial 

purge volumes released to the atmosphere, plus the gas released when the sample 

container is disconnected. 

While components may be counted from process diagrams, this frequently understates actual 

component numbers. This is especially true for fittings (e.g., connectors and valves less than 2 

NPS) and any third-party packages (e.g., compressor units, heaters, and scrubbers). 

When counting each component it is important to also record the percentage of the time that it is 

out of service (i.e., there is zero gauge pressure on both sides of the component). This 

information can be used to adjust the estimated emissions accordingly. 
 147 

10.2 METHOD 21 - DETERMINATION OF VOLATILE ORGANIC COMPOUND LEAKS

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 EMISSION MEASUREMENT TECHNICAL INFORMATION CENTRE

 NSPS TEST METHOD

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 (EMTIC M-21, 2/9/93) 

 Method 21 - Determination of Volatile Organic Compound Leaks 

1. APPLICABILITY AND PRINCIPLE

1.1 Applicability. This method applies to the determination of 

volatile organic compound (VOC) leaks from process equipment. These 

sources include, but are not limited to, valves, flanges and other 

connections, pumps and compressors, pressure relief devices, process 

drains, open-ended valves, pump and compressor seal system degassing 

vents, accumulator vessel vents, agitator seals, and access door seals. 

1.2 Principle. A portable instrument is used to detect VOC leaks 

from individual sources. The instrument detector type is not 

specified, but it must meet the specifications and performance criteria 

contained in Section 3. A leak definition concentration based on a 

reference compound is specified in each applicable regulation. This 

procedure is intended to locate and classify leaks only, and is not to 

be used as a direct measure of mass emission rate from individual 

sources. 

2. DEFINITIONS

2.1 Leak Definition Concentration. The local VOC concentration at 

the surface of a leak source that indicates that a VOC emission (leak) 

is present, The leak definition is an instrument meter reading based 

on a reference compound. 

2.2 Reference Compound. The VOC species selected as an instrument 

calibration basis for specification of the leak definition 

concentration. (For example, if a leak definition concentration is 

10,000 ppm as methane, then any source emission that results in a local 

concentration that yields a meter reading of 10,000 on an instrument 

meter calibrated with methane would be classified as a leak. In this 

example, the leak definition is 10,000 ppm, and the reference compound 

is methane.) 

2.3 Calibration Gas. The VOC compound used to adjust the instrument 

meter reading to a known value. The calibration gas is usually the 

reference compound at a known concentration approximately equal to the 

leak definition concentration. 
 148 

2.4 No Detectable Emission. The total VOC concentration at the 

surface of a leak source that indicates that a VOC emission (leak) 

is not present. Since background VOC concentrations may exist, and to 

account for instrument drift and imperfect reproducibility, a 

difference between the source surface concentration and the local 

ambient concentration is determined. A difference based on the meter 

readings of less than a concentration corresponding to the minimum 

readability specification indicates that a VOC emission (leak) is not 

present. (For example, if the leak definition in a regulation is 

10,000 ppm, then the allowable increase is surface concentration versus 

local ambient concentration would be 500 ppm based on the instrument 

meter readings.) 

2.5 Response Factor. The ratio of the known concentration of a VOC 

compound to the observed meter reading when measured using an 

instrument calibrated with the reference compound specified in the 

applicable regulation. 

2.6 Calibration Precision. The degree of agreement between 

measurements of the same known value, expressed as the relative 

percentage of the average difference between the meter readings and the 

known concentration to the known concentration. 

2.7 Response Time. The time interval from a step change in VOC 

concentration at the input of the sampling system to the time at which 

90 percent of the corresponding final value is reached as displayed on 

the instrument readout meter. 

3. APPARATUS 

3.1 Monitoring Instrument. 

3.1.1 Specifications 

a. The VOC instrument detector shall respond to the compounds being 

processed. Detector types which may meet this requirement 

include, but are not limited to, catalytic oxidation, flame ionization, 

infrared absorption, and photoionization. 

b. The instrument shall be capable of measuring the leak definition 

concentration specified in the regulation. 

c. The scale of the instrument meter shall be readable to + 

or - 5 percent of the specified leak definition concentration. 

d. The instrument shall be equipped with a pump so that a continuous 

sample is provided to the detector. The nominal sample flow rate shall 
 149 

be 0.1 to 3.0 liters per minute. 

e. The instrument shall be intrinsically safe for operation in 

explosive atmospheres as defined by the applicable U.S.A. standards 

(e.g., National Electrical Code by the National Fire Prevention 

Association). 

f. The instrument shall be equipped with a probe or probe extension 

for sampling not to exceed 1/4 in. in outside diameter, 

with a single end opening for admission of sample. 

3.1.2 Performance Criteria. 

a. The instrument response factors for the individual compounds to be 

measured must be less than 10. 

b. The instrument response time must be equal to or less than 30 

seconds. The response time must be determined for the instrument 

configuration to be used during testing. 

c. The calibration precision must be equal to or less than 10 percent 

of the calibration gas value. 

d. The evaluation procedure for each parameter is given in Section 

4.4. 

3.1.3 Performance Evaluation Requirements. 

a. A response factor must be determined for each compound that is to 

be measured, either by testing or from reference sources. The response 

factor tests are required before placing the analyzer into service, but 

do not have to be repeated at subsequent intervals. 

b. The calibration precision test must be completed prior to placing 

the analyzer into service, and at subsequent 3-month intervals or at 

the next use whichever is later. 

c. The response time test is required before placing the instrument 

into service. If a modification to the sample pumping system or flow 

configuration is made that would change the response time, a new test 

is required before further use. 

3.2 Calibration Gases. 

 The monitoring instrument is calibrated in terms of parts per 

million by volume (ppm) of the reference compound specified in the 

applicable regulation. The calibration gases required for monitoring 

and instrument performance evaluation are a zero gas (air, less than 10 

ppm VOC) and a calibration gas in air mixture approximately equal to 

the leak definition specified in the regulation. If cylinder 

calibration gas mixtures are used, they must be analyzed and certified 

by the manufacturer to be within + or - 2 percent accuracy, and a shelf 
 150 

life must be specified. Cylinder standards must be either reanalyzed 

or replaced at the end of the specified shelf life. Alternatively, 

calibration gases may be prepared by the user according to any accepted 

gaseous preparation procedure that will yield a mixture accurate to 

within 

+ or - 2 percent. Prepared standards must be replaced each day of use 

unless it can be demonstrated that degradation does not occur during 

storage. 

 Calibrations may be performed using a compound other than the 

reference compound if a conversion factor is determined for that 

alternative compound so that the resulting meter readings during source 

surveys can be converted to reference compound results. 

4. PROCEDURES 

4.1 Pretest Preparations. Perform the instrument evaluation 

procedure given in Section 4.4 if the evaluation requirement of Section 

3.1.3 have not been met. 

4.2 Calibration Procedures. Assemble and start up the VOC analyzer 

according to the manufacturer's instructions. After the appropriate 

warmup period and zero internal calibration procedure, introduce the 

calibration gas into the instrument sample probe. Adjust the 

instrument meter readout to correspond to the calibration gas value. 

(Note: If the meter readout cannot be adjusted to the proper value, a 

malfunction of the analyzer is indicated and corrective actions are 

necessary before use.) 

4.3 Individual Source Surveys. 

4.3.1 Type I - Leak Definition Based on Concentration. Place the 

probe inlet at the surface of the component interface where leakage 

could occur. Move the probe along the interface periphery while 

observing the instrument readout. If an increased meter reading is 

observed, slowly sample the interface where leakage is indicated until 

the maximum meter reading is obtained. Leave the probe inlet at this 

maximum reading location for approximately two times the instrument 

response time. If the maximum observed meter reading is greater than 

the leak definition in the applicable regulation, record and report the 

results as specified in the regulation reporting requirements. 

Examples of the application of this general technique to specific 

equipment types are: 

a. Valves - Leaks usually occur at the seal between the stem and the 

housing. Place the probe at the interface where the stem exits the 

packing and sample the stem circumference and the flange periphery. 

Survey valves of multipart assemblies where a leak could occur. 

b. Flanges and Other Connections - Place the probe at the outer edge 

of the flange-gasket interface and sample the circumference of the 
 151 

flange. 

c. Pump or Compressor Seals - If applicable, determine the type of 

shaft seal. Perform a survey of the local area ambient VOC 

concentration and determine if detectable emissions exist as described 

above. 

d. Pressure Relief Devices - For those devices equipped with an 

enclosed extension, or horn, place the probe inlet at approximately the 

centre of the exhaust area to the atmosphere. 

e. Process Drains - For open drains, place the probe inlet as near as 

possible to the centre of the area open to the atmosphere. For covered 

drains, locate probe at the surface of the cover and traverse the 

periphery. 

f. Open-ended Lines or Valves - Place the probe inlet at 

approximately the centre of the opening of the atmosphere. 

g. Seal System Degassing Vents, Accumulator Vessel Vents, Pressure 

Relief Devices - If applicable, observe whether the applicable ducting 

or piping exists. Also, determine if any sources exist in the ducting 

or piping where emissions could occur before the control device. If 

the required ducting or piping exists and there are no sources where 

the emissions could be vented to the atmosphere before the control 

device, then it is presumed that no detectable emissions are present. 

If there are sources in the ducting or piping where emissions could be 

vented or sources where leaks could occur, the sampling surveys 

described in this section shall be used to determine if detectable 

emissions exist. 

h. Access door seals - Place the probe inlet at the surface of the 

door seal interface and traverse the periphery. 

4.3.2 Type II - "No Detectable Emission". Determine the ambient 

concentration around the source by moving the probe randomly upwind and 

downwind around one to two meters from the source. In case of 

interferences, this determination may be made closer to the source down 

to no closer than 25 centimetres. Then move the probe to the surface 

of the source and measure as in 4.3.1. The difference in these 

concentrations determines whether there are no detectable emissions. 

When the regulation also requires that no detectable emissions exist, 

visual observations and sampling surveys are required. Examples of 

this technique are: (a) Pump or Compressor Seals - Survey the local 

area ambient VOC concentration and determine if detectable emissions 

exist. (b) Seal System Degassing Vents, Accumulator Vessel Vents, 

Pressure Relief Devices - Determine if any VOC sources exist upstream 

of the device. If such ducting exists and emissions cannot be vented 

to the atmosphere upstream of the control device, then it is presumed 

that no detectable emissions are present. If venting is possible 
 152 

sample to determine if detectable emissions are present. 

4.3.3 Alternative Screening Procedure. 

4.3.3.1 A screening procedure based on the formation of bubbles in a 

soap solution that is sprayed on a potential leak source may be used 

for those sources that do not have continuously moving parts, 

that do not have surface temperatures greater than the boiling point or 

less than the freezing point of the soap solution, that do not have 

open areas to the atmosphere that the soap solution cannot bridge, or 

that do not exhibit evidence of liquid leakage. Sources that have 

these conditions present must be surveyed using the instrument 

technique of Section 4.3.1 or 4.3.2. 

4.3.3.2 Spray a soap solution over all potential leak sources. The 

soap Solution may be a commercially available leak detection solution 

or may be prepared using concentrated detergent and water. 

A pressure sprayer or squeeze bottle may be used to dispense the 

solution. Observe the potential leak sites to determine if any bubbles 

are formed. If no bubbles are observed, the source is presumed to have 

no detectable emissions or leaks as applicable. If any bubbles are 

observed, the instrument techniques of Section 4.3.1 or 4.3.2 shall be 

used to determine if a leak exists, or if the source has detectable 

emissions, as applicable. 

4.4 Instrument Evaluation Procedures. At the beginning of the 

instrument performance evaluation test, assemble and start up the 

instrument according to the manufacturer's instructions for recommended 

warmup period and preliminary adjustments. 

4.4.1 Response Factor. 

4.4.1.1 Calibrate the instrument with the reference compound as 

specified in the applicable regulation. For each organic species that 

is to be measured during individual source surveys, obtain or prepare a 

known standard in air at a concentration of approximately 80 percent of 

the applicable leak definition unless limited by volatility or 

explosivity. In these cases, prepare a standard at 90 percent of the 

standard saturation concentration, or 70 percent of the lower explosive 

limit, respectively. Introduce this mixture to the analyzer and record 

the observed meter reading. Introduce zero air until a stable reading 

is obtained. Make a total of three measurements by alternating between 

the known mixture and zero air. Calculate the response factor for each 

repetition and the average response factor. 

4.4.1.2 Alternatively, if response factors have been published for the 

compounds of interest for the instrument or detector type, the response 

factor determination is not required, and existing results may be 

referenced. Examples of published response factors for flame 

ionization and catalytic oxidation detectors are included in the 
 153 

Bibliography. 

4.4.2 Calibration Precision. Make a total of three measurements by 

alternately using zero gas and the specified calibration gas. Record 

the meter readings. Calculate the average algebraic difference between 

the meter readings and the known value. Divide this average difference 

by the known calibration value and multiply by 100 to express the 

resulting calibration precision as a percentage. 

4.4.3 Response Time. Introduce zero gas into the instrument sample 

probe. When the meter reading has stabilized, switch quickly to the 

specified calibration gas. Measure the time from switching to when 90 

percent of the final stable reading is attained. Perform this test 

sequence three times and record the results. Calculate the average 

response time. 

5. BIBLIOGRAPHY 

1. Dubose, D.A., and G.E. Harris. Response Factors of VOC 

Analyzers at a Meter Reading of 10,000 ppmv for Selected Organic 

Compounds. U.S. Environmental Protection Agency, Research Triangle 

Park, NC. Publication No. EPA 600/2-81051. September 1981. 

2. Brown, G.E., et al. Response Factors of VOC Analyzers 

Calibrated with Methane for Selected Organic Compounds. U.S. 

Environmental Protection Agency, Research Triangle Park, NC. 

Publication No. EPA 600/2-81-022. May 1981. 

3. DuBose, D.A. et al. Response of Portable VOC Analyzers to 

Chemical Mixtures. U.S. Environmental Protection Agency, Research 

Triangle Park, NC. Publication No. EPA 600/2-81-110. September 1981.