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, 1998EXECUTIVE SUMMARY

Since before the start of the Voluntar y 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 va luable 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 a ssist 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 techni ques 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 com panies 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 lea ks), and excludes all indirect sources of

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

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

production and processing are specifically ex cluded - 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 followi ng: fugitive pipeline and equipment leaks,

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

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

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

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

Throughout the development of this handbook, ac tive involvement of the individual

sponsor companies has been encouraged to hel p 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 docum ent 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 procedur es manual, and should not be used as

such.

iTechnical and Planning Issues

The discussion of emission management stra tegies 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 associat ed with estimating and measuring their

emissions. The available techniques for estimating and measure methane emissions

are delineated herein.

An important theme thr oughout the handbook is the need for good quality assurance

(QA)/quality control (QC) measures to ensur e 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 cl erical nature and can be assigned to junior

personnel, a team approach involving interm ediate- 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 wit h 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 ma y be used to either estimate or measure

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

assessment approach involves using national industry-average factors to estimate

fugitive emissions, and performing inter nal engineering estimates of vented gas

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

important in this approach to confirm corre ct 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.

iiMore advanced approaches may involve act ual screening and emission measurement

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

emission reduction measures companies ma y 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 t he 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 pr esented options include, but are not limited

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

direct measurement techniques.

iiiTABLE OF CONTENTS

Section Page

EXECUTIVE SUMMARY i

TABLE OF CONTENTS v

LIST OF TABLES ix

LIST OF FIGURES x i

GLOSSARY xiii

LIST OF ACRONYMS xix

A C K N O W L E D G E M E N T S x x

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 Infras tructure 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)

ivSection 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 Meas urement 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)

vSection 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 Equi pment Component Counts 127

10.2 Method 21 - Determination of Volatile Organic Compound Leaks 129

viLIST OF TABLES

Table Page

1 Summary of the procedures for estimati ng/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 estimati ng fugitive equipment leaks at gas

transmission

and distribution facilities 31

5 Typical compositions of proce ssed natural gas by province 33

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

Canadian

natural gas transmission and distribution facilities 54

7 Three-stratum emission factors for es timating fugitive equipment leaks at

Canadian

natural gas transmission and distribution facilities 58

8 Correlation parameters for estimating l eak 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 esti mate 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 dist ribution system and the amount of waste

gas involved as estimated by one gas distribution company 95

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

pneumatic instruments 101

vii14 Gas usage by pneumatic/hydraulic rota ry 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 Proc essed 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 combinati ons of temperature and pressure 108

viiiLIST OF FIGURES

Figure Page

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

c o m p r e s s o r 1 9

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

c o m p r e s s o r 2 1

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 us ing either a vacuum or blow-through

method 67

ixGLOSSARY

TRANSMISSION FACILITIES

Block Valve Station - A block valve us ed 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 wher e 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 t hat 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.

xTransmission 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 stati on 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 cons tructed 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 kPa g (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

xithe pipeline.

Transmission Stations - Transmission stat ions 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 r educes the pressure from

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

pressure, typically not in excess of 140 kPa g (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 distributi on facility located adjacent to a

transmission facility where gas is odourized and flows

through a splitter system for distri bution 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 regul ating 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

xiipressures of up to up to 690 kPa g (100 psig), although there

are polyethylene resins that allow operation at pressures

slightly over 700 kPa g (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

ex ist.

For the purpose of calculat ing methane emissions from

distribution mains, all small associated facilities, such as

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

Distribution Stations - Stations associ ated 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 kPa g [60 psig] but

sometimes only to 1200 kPa g [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

kPa g [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. Buri ed components are deemed to be

part of the piping.

Plastic Pipelines - Pipelines made of va rious types of plastic, ie. including

polyethylene, polyvinyl chloride, ABS, etc.

Protected Steel Pipelines - Steel pipeli nes that are cathodically protected.

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

customer. They include both pressure regulation and

xiiimeasurement. The regulator typi cally reduces pressure from

distribution pressure to 1.7 kPa g (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 usua lly made of steel pipe or steel

tubing (either cathodically prot ected or not) , or plastic

(usually polyethylene, but someti mes 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 me ter set. Typically, they operate

at pressures above 860 kPa g (125 psig).

Unprotected Steel Pipelines - Steel pipeli nes that are not cathodically protected.

EQUIPMENT

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

role is to control hydrates rat her than final treatment to meet

sales specifications.

Line Heater - An indirectly fired heat er 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 industrie s, 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

xivFugitive Emissions - Unintentional l eaks 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 t heoretical 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 t hat 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 unident ified, in existence on that

pipeline or pipeline system dur ing 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 com ponents as it travels from

the pipeline to the ground surface through the soil.

xvLIST OF ACRONYMS

AGA

- American Gas Association

CAPP

- Canadian Associati on of Petroleum Producers

CCME

- Canadian Council of Mini sters 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 C hemical Manufacturing Industry

THC

- Total Hydrocarbons

U.S. EPA

- U.S. Environm ental Protection Agency

VCR

- Voluntary Challenge and Registry

VOC

- Volatile Organic Compound

xviACKNOWLEDGEMENTS

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.

xvii1

1.0 INTRODUCTION

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

methane emissions from non-combustion sour ces 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 de scribes the different types of sources

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

emissions inventory, highlight s 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 parti cular needs and circumstances. Moreover, it

establishes a general source classifica tion 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 differ ent 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 list ed 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. Accord ingly, 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 mi nor differences, this section is consistent

with Section 2 of the companion handbook fo r 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 peri od and specific objectives to be achieved,

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

⋅ prepare an inventory of the target infr astructure 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 resu lts (e.g., develop tallies of equipment

components and process units by facility; co mpile 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 fulf il obligations made to the global

climate change voluntary cha llenge and registry program.

⋅ Conduct a statistical sampling/m easurement 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. Thereafte r, the process is greatly simplified,

provided the initial effort s have been properly documented.

One of the main difficulties is ident ifying resources and information available

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

requires a certain amount of res earch by someone with a good overall

knowledge of the company and its operati ons, 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 and4

installations are usually readily identifi ed through a variety of sources including

engineering, operations and accounting depar tments. However, minor facilities

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

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

protocol document is an effective mec hanism for substantiating the specific

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

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

performing the required emissions asse ssment 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 em ployed, 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 fac ilities 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 in stallation. 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 t here is a natural tendency to trivialize

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

be significant total contributors. Therefor e, 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., comp ressor 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, pr oduction accounting, insurance records,

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

should be made to flush out and identif y these pools of potentially useful5

information.

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

sources associated with each facility. Mec hanical 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., depressuri zation 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 exis ting 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 el ements to be considered in any field work

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

available times), anticipation of pot ential difficulties and safety issues,

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

poor weather conditions), and good communica tion and coordination of activities6

with site personnel.

Where practicable, operations personnel re sponsible for the target facilities and

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

correctly identified, and that the operat ing status and state of equipment are

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

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

that all the necessary information is colle cted. 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 perspec tive 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 QuattroP ro) 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 presentati on-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 ext ensive use is made of cell programming

features, a spreadsheet application may becom e 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 sp readsheet cells can mitigate some of7

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

The use of a database application enables complex information retrievals and

custom reporting of information that si mply would not be practicable with a

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

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

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

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

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

easier to maintain and support than spr eadsheets, as the applications become

more sophisticated.

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

specialized user training. A data m anagement system is most useful and

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

management systems offer an interactive env ironment that is easy to master,

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

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

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

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

debugged.

Additionally, a data management system, wh ile able to do very sophisticated

information retrievals, requires consider able 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 emi ssions 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 c ontrol (for example, a mainline block

valve would need to be leaking at a substantial rate before it would be8

economical to take it out of service for repairs),

⋅ identify trends in measurement data t hat 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 a ssessment strategy for future efforts

so that uncertainties are minimized for the available resources.

2.1.9 Quality Assurance/Qua lity 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 ther e 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 rele vant 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 t he 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 improvem ents 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 previ ous year rather than properly updated,

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

from area source category to tals where appropriate,

⋅ document any extrapolations from pr evious 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 operat ional improvements and upgrades.9

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

preparing the emissions invent ory 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 t he estimated amount of emissions in

proper context relative to the am ount of gas handled, and the distances

the gas is transported.

⋅ Some effort to forecast fu ture 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 Regi stry 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.ca10

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-classifi cation 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 standar ds (e.g., CSA Z662-96 Oil and Gas Pipeline

Systems) and government regulations es tablish their own values. The scheme

presented here is intended to achieve a r easonable 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 m ade. 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 distribut ion service apply (see Section 3.0). To

characterize the different facilities and in stallations 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 Equipment11

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 gr eatest 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 measur ement and estimation techniques. However,

many of these methods, particularly thos e specific to estimating trace organic

emissions, are still undergoing significant re finement. 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. T he 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-facilit y) approaches (Section 3.2.4).

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

inventory of the target co mponent 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 a ccordance 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 principl es and relies on large component population

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

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

presented in Section 3.2.1 to assist compani es 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 se lected where companies choose to

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

identified. Direct measurement of emissions fr om the leakers allows prioritization of the

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

emissions. Moreover, it allows for better pr ioritization 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 identif y individual leaking components.1314

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

chnique Information

equirements R Advantages Disadvantages

v

erage Emission

ctor s ⋅ 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 Approache s :

eak/No-leak Factors

S tratified Factors

P ublished Leak-rate

o rrelations

C ustom Leak-rate

o rrelations ⋅ Equipment

inventory.

⋅ Leak survey results. ⋅ Identifies leaking components.

⋅ Control efforts reflected in

results. ⋅ Labour intensive.

⋅ Moderate costs.

⋅ Poor to moderate accuracies (±300 percent a t

best).

reening Coupled with Direct

e asurements for Significant

a ker s :

H i-Flow Sampler

B agging ⋅ Equipment

inventory.

⋅ Leak survey results. ⋅ Identifies leaking components.

⋅ Excellent accuracy (potentially

±15 percent).

⋅ Control efforts reflected in

results. ⋅ Labour intensive.

⋅ Moderate to high costs.

h ole-Facility Quantification

p

proache s :

R emote Sensing

P lume Transect Method

T race/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 f o15

any

models). quickly delineating high-emission zones.16

3.1 Source Characterization

Emissions from fugitive equipment leaks are a ma jor 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 distributi on systems in Canada (CGA, 1997).

Fugitive equipment leaks may be defined as any lo ss 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 seat s, etc.). Most equipment components leak to

some extent. However, only a few percent of t he 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 tota l 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 por table 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 natur al 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 char acteristics of fugitive equipment leaks:

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

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

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

leakage (U.S. EPA, 1983).

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

but is generally independent of operating temper ature 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

u mmary of percent leaking components by type of facility

Facility Type Component

Category Total

Components 10 000 ppm 500 ppm

Leakers Percent

Leakers Leakers Perc e

Leak e

a nsmission - Compressor Stations Compressor

Seals

Other

omponents C 53

42 403 45

872 84.9

2.1 46

1 346 8 6

3

a nsmission - Border Meter Stations A ll Components 6 564 156 2.4 227 3

a nsmission - Receipt/Sales Meter

a tions All Components 3 244 177 5.5 221 6

a nsmission - Block/Control Valve

t es All Components 1 212 32 2.6 47 3

s tribution - Residential Sites A ll Components 676 0 0.0 2 0

s tribution - Commercial Sites A ll Components 901 2 0.2 6 0

s tribution - Industrial Sites A ll Components 1 332 23 1.7 55 4

s tribution - Farm Taps A ll Components 768 14 1.8 26 3

s tribution - District Regulating

a tions All Components 1 479 32 2.2 48 3

s tribution - 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 reciprocat ing 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 rec ent 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 des ign, 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 ma y 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 thei r 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 pa cking 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 co mpressor rod, and through ring joints.

Leakage from around cover plates and connecti ons 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 m 3 /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 r od, 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 lubricat ing 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 pressu re sufficient to ensure that any leakage is

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

the seal system where it commingles with t he 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 packi ng 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 gr adually 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 sl ow 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 90 o 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 pa cking 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 distributi on 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 diffe rent 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, ov erheating, seal wear, slidi ng 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 connec tions. 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 c ause leakage problems to arise. Some of the

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

surfaces, incorrect sealing material, im proper 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 ove r-pressured. They are spring loaded so26

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

open when the set point is exceeded. Relief va lves 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 instru ment 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 f ugitive equipment leaks. These techniques

may be divided into four basic categories:

⋅ average emission factors,

⋅ screening-based approaches,27

⋅ screening coupled with direct measurem ent 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 pr essure-relief valve (U.S. EPA, 1996).2829

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 facilitie s or for an overall company. However, it

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

leak statistics. Often, this may be a poor a ssumption 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 fac ility, the results may easily be in error by

several orders of magnitude.

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

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

surveys or counts taken from process flow di agrams 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). Ho wever, for larger facilities (e.g., border

meter stations, compressor stations) actual fi eld counts are preferabl e 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 procedur es 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 tr ansmission 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 comp ressor stations are on a per-compressorunit basis. The amount of compressor stat ion yard piping, excluding suction and30

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

u ipment schedules for Canadian gas trans mission and distribution facilities.

m ponent Distribution Facilities Transmission Facilities

Residentia

l Meter

Set 1 Commercial

Meter Set 1 Industrial

Meter Set 1 Farm

Tap 1 District

Regulator

Station 1 Gate

Station

1 Border

Meter

Station 2 Receipt/

Sales

Meter

Station 2 Farm

Tap 1 Reciprocatin

g

Compressor

Unit 3 Centrifugal

Compressor

Unit 3 Compressor

Station Yard

Piping 4

n nectors 18 76 122 60 78 240 100 95 60 317 476 747

n trol

v es ---- ---- ---- ---- ---- 1 0 0

---- 10 3

----

e n-Ended

e s 0 0 0 0 1 1 4 10 0 5 10 36

s sure

ef

v ices ---- 1 1 2 1 2 1 3 2 1 3 3

s sure

g ulators 1 3 7 4 4 8 1 2 4 1 3 7

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

w down

e s ---- ---- ---- ---- ---- 0 0

---- ---- ---- ---- 11

f ice

e rs ---- ---- 0

---- 0 1 1 1

---- ---- ---- ----

e r Flow

e rs 1 4 4 0 0 1 0

---- 0

---- ---- ----

rument

n trollers ---- ---- ---- ---- ---- 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 stati ons).

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 compre ssor stations. If the s tation has discharge coolers, add these a dditi o

components.

n ce the equipment inventory has been compiled, t he emissions are estimated using the equation:

where,

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

facility),

F

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

4),

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

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

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

r ee categories is applicable at gas tr ansmission and distribution facilities.

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

m issions. To calculate fugitive methane emissions for a fac ility, the gas composition must be known. The compositio

a tural gas transported by gas transmission and distribution system s can vary significantly depending on the area of t

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

o mposition. Gas that is produced and consumed in Alberta ( upstream of any reprocessing plants) may contain as litt l

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

y drocarbons 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 th e

two or more different incoming gas streams at a facility with notably different compositi ons, it may be appropriate t o

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

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

the application of this average-emission-fact or 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 di stribution 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

C onnector 1 45 357 2.732e-04 2.212e-04 3.252e-04 7.839e-01

B lock Valve 2 6 152 2.140e-03 1.281e-03 2.999e-03 2.177e+00

C ontrol Valve 3 273 1.969e-02 5.865e-03 3.352e-02 1.449e-01

P RV 168 2.795e-01 0.000e+00 6.348e-01 2.814e+01

R egulator 127 3.304e-03 0.000e+00 7.222e-03 2.413e-01

O rifice Meter 4 104 3.333e-03 1.981e-03 4.684e-03 1.920e-02

O ther Flow Meter 5 266 9.060e-06 0.000e+00 1.961e-05 1.400e-03

Station or Pressurized Comp. Blowdown

S ystem 6 102 9.369e-01 3.598e-01 1.514e+00 2.115e+01

Comp. Blowdown System - Depressurized

R ecip. 9 15 2.347e+00 7.613e-01 3.932e+00 1.013e+01

Comp. Blowdown System - Depressurized

C ent. 9 18 7.334e-01 0.000e+00 1.489e+00 4.043e+00

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

I nstrument Controller 7 17 4.681e-01 9.326e-02 8.429e-01 2.387e+00

C ompressor Seal - Centrifugal 8 21 8.139e-01 2.316e-01 1.396e+00 3.723e+00

C ompressor Seal - Reciprocating 8 36 6.616e-01 4.044e-01 9.188e-01 1.772e+00

Gas Distribution Mete r/Regulator Stations

Source Number

of Sources Average

Emissions

(kg/h/src) 95% Confidence Limits Maximum

Observed

Emissions

(kg/h/src)35

Lower Upper

C onnector 1 8 707 1.098e-04 8.720e-06 2.108e-04 3.371e-01

B lock Valve 2 1 985 1.109e-03 0.000e+00 2.911e-03 1.821e+00

C ontrol Valve 3 273 1.969e-02 5.865e-03 3.352e-02 1.890e+00

P RV 94 1.665e-02 0.000e+00 3.966e-02 1.076e+00

R egulator 369 1.915e-03 0.000e+00 4.304e-03 3.728e-01

O rifice Meter 4 104 3.333e-03 1.981e-03 4.684e-03 1.920e-02

O ther Flow Meter 5 266 9.060e-06 0.000e+00 1.961e-05 1.400e-03

S tation Blowdown System 6 102 9.369e-01 3.598e-01 1.514e+00 2.115e+01

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

Instrument Controller 7 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

C onnector 1 2 913 6.780e-06 0.000e+00 1.568e-05 1.310e-02

B lock Valve 2 263 3.330e-06 1.720e-06 4.940e-06 1.000e-04

P RV 6 2.717e-04 0.000e+00 8.144e-04 1.300e-03

R egulator 102 2.198e-05 0.000e+00 4.912e-05 1.400e-03

O rifice Meter 4 104 3.333e-03 1.981e-03 4.684e-03 1.920e-02

O ther Flow Meter 7 266 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 connecti ons 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 a ccounted for by the connector categor y (i.e., one connector for each end).

3 Accounts for leakage from the stem packing and the valve body. Em issions from the controller and actuator are accounted for b y the

Instrument Controller and Open-Ended Line categories respectively. Th is factor applies to all valv es with automatic actuators

(including fuel gas injecti on 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 fa ctor (i.e.,

these emissions must be calculated separately).

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

6 Accounts for leakage past a valve seat thr ough an open vent line to the atmosphere. Thes e vents are typically six inches or g reater in

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

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 us e natural gas as the supply m edium.

8 The Compressor Seal categories account for emissions from i ndividual compressor seals (i.e., fo r a four cylinder reciprocatin g

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 t he compressor is depressurized (i.e.,

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

T ypical 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

C 1 (Methane) 95.9490 92.8690 97.1294 95.6400 95.2128 95.0600 94.8890 94.7089

C 2 2.4160 4.0556 0.2579 2.5800 2.4306 0.4940 2.4740 2.4805

C 3 0.5440 1.1112 0.0201 0.0700 0.1374 0.0670 0.2130 0.2501

i-C 4 0.0710 0.1601 0.0005 0.0100 0.0043 0.0120 0.0130 0.030037

n-C 4 0.1130 0.2180 0.0005 0.0100 0.0043 0.0110 0.0200 0.0400

i-C 5 0.0190 0.0496 0.0008 0.0000 0.0013 0.0040 0.0050 0.0200

n-C 5 0.0110 0.0389 0.0004 0.0000 0.0010 0.0030 0.0080 0.0100

C 6 0.0260 0.0225 0.0001 0.0100 0.0012 0.0070 0.0030 0.0100

C 7+ 0.0000 0.0126 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.1250 0.6334 0.2618 0.5400 0.5552 0.1290 0.6560 0.6201

N 2 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.

T ypical 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

C 1 (Methane) 91.7957 85.4537 94.7955 91.7267 91.0242 91.3750 90.2786 89.8694

C 2 4.3324 6.9946 0.4718 4.6379 4.3553 0.8900 4.4118 4.4117

C 3 1.4306 2.8104 0.0539 0.1845 0.3611 0.1770 0.5570 0.6523

i-C 4 0.2461 0.5337 0.0018 0.0347 0.0149 0.0418 0.0448 0.1031

n-C 4 0.3917 0.7268 0.0018 0.0347 0.0149 0.0383 0.0689 0.1375

i-C 5 0.0818 0.2053 0.0035 0.0000 0.0056 0.0173 0.0214 0.0854

n-C 5 0.0473 0.1610 0.0018 0.0000 0.0043 0.0130 0.0342 0.0427

C 6 0.1336 0.1112 0.0005 0.0515 0.0062 0.0361 0.0153 0.0510

C 7+ 0.0000 0.0724 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.3281 1.5988 0.7009 1.4207 1.4561 0.3402 1.7121 1.6142

N 2 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 100.000038

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

Values 1

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:

C 1 divided by 10039

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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(kg/h) NATURAL GAS

EMISSIONS

(kg/h x 10 -4 )

C onnectors 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 Meters40

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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 66.0841

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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENTE

MISSION

FACTOR 1

(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 -242

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 - BlockV

alve Stations

COMPONENT TYPE STATIONAVERAGE

COMPONENT

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 -243

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

T

ransmission - Control-Valve Stations

COMPONENT TYPE STATIONAVERAGE

COMPONENT

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(kg/h) NATURAL GAS

EMISSIONS

(kg/h x 10 -4 )

Connectors 126 1.0 2.732 X 10 -4 344.2344

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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 -647

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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 2.34748

O rifice 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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 4857.849

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

D istribution - Gate Stations

COMPONENT TYPE STATIONAVERAGE

COMPONENT

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(kg/h) NATURAL GAS

EMISSIONS

(kg/h x 10 -4 )

Connectors 240 1.0 1.098 X 10 -4 263.5250

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

D istribution - District Regulating Stations

COMPONENT TYPE STATIONAVERAGE

COMPONENT FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1 NATURAL GAS

EMISSIONS51

COUNT 1 (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 DI STRICT 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 3.2.1-1352



## FUGITIVE EQUIPMENT LEAKS

Distribution - Farm Taps

COMPONENT TYPE FACILITYAVERAGE

COMPONENT

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 DIST RIBUTION 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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 Controllers54

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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 0.299755

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

COUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1

(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 -456

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

OUNT 1 FRACTION OF

TIME IN

SERVICE 1 COMPONENT

EMISSION

FACTOR 1 (kg/ho

ur) NATURAL GAS

EMISSIONS

(kg/hour x 10 -4 )

Connectors 1.098 X 10 -4

Control Valves 1.969 X 10 -257

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 MISCE LLANEOUS 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 tar get facility. This would normally be done

using a portable intrinsically-safe organic v apour 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 abov e 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 a58

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 bei ng covered by insulation). Useful data to

record during a leak survey includes the fo llowing (the critical it ems 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 t he screened component is located,

⋅ process fluid type and composition,

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

⋅ ambient conditions (e.g., mean tem perature, 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 rent ed 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. Typica lly, 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 t he 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 manuf acturing and petroleum refining industries,

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

CCME guidelines set the use of three-stratu m 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 mo st 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 categorie s except connectors. Due to their large

number at most facilities, it is suggested t hat 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 experi ence in other industries is this not is

not necessarily true (Schaich and St ine, 1989). For example, example61

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 esti mating fugitive equipment leaks at

C anadian 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

Connector 1 No

L eak 9 44512 98.79 0.0000338 0.0000271 0.0000406

L eak 10 556 1.21 0.01856 0.01465 0.02247

Block Valve 2 No

L eak 5907 96.02 0.0006132 0.0 0.001342

L eak 245 3.98 0.03895 0.02728 0.05062

Control Valve 3 No

L eak 233 85.35 0.01006 0.007532 0.01259

L eak 40 14.65 0.07581 0.0 0.1706

PRV No

L eak 63 33.87 0.0006471 0.0 0.001537

L eak 123 66.13 0.3814 0.0 0.8673

Regulator No

L eak 108 83.72 0.0000398 0.0000175 0.0000474

L eak 21 16.28 0.01977 0.004751 0.03439

Orifice Meter 4 No

L eak 83 79.81 0.001925 0.0006846 0.003165

L eak 21 20.19 0.0088 0.004936 0.01286

Other Flow Meter 5 No

Leak 259 97.37 0.0000037 0.0000016 0.0000059

L eak 7 2.63 0.0002064 0.0 0.0006932

Station or Pressurized No

L eak 27 26.47 0.0006213 0.0 0.001641

Compressor Blowdown

S ystem 6 Leak 75 73.53 1.274 0.4989 2.049

Compressor Blowdown System No 4 26.67 0.000 0.0 0.062

- L eak

D epressurized Reciprocating L eak 11 73.33 3.200 1.245 5.155

Compressor Blowdown System

- No

L eak 7 38.89 0.000 0.0 0.0

Depressurized Centrifugal L eak 11 61.11 1.200 0.0 2.422

Open-Ended Line No

L eak 179 27.88 0.0001127 0.0000249 0.0002006

L eak 463 72.12 0.1158 0.05458 0.177

Instrument Controller 7 No

L eak ---- 0.00

---- ---- ----

Leak 17 100.0

0 0.4681 0.09325 0.8429

Compressor Seal -

R eciprocating 8 No

L eak 5 13.89 0.00056 0.0 0.002115

L eak 31 86.11 0.7682 0.4865 1.049

Compressor Seal - Centrifugal 8 No

L eak 1 4.77 0.0000075

---- ----

Leak 20 95.23 0.8546 0.2469 1.462

Continued...63

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

C anadian natural gas transmission and di stribution facilities (Continued).

Gas Distribution Mete r/Regulator Stations

Source Number

of

Sources Perce

nt of

Sourc

es Emissions

(kg/h/src) 95% Confidence Limits

Lower Upper

Connector 1 No

L eak 8515 99.18 0.0000043 0.0000036 0.000005

L eak 70 0.82 0.01292 0.0004211 0.02542

Block Valve 2 No

Leak 1910 96.22 0.0000251 0.0000153 0.0000349

Leak 75 3.78 0.02872 0.0 0.07705

Control Valve 3 No

L eak 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

L eak 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 Meter 4 No

L eak 83 79.81 0.001925 0.0006846 0.003165

Leak 21 20.19 0.0088 0.004936 0.01286

Other Flow Meter 5 No

L eak 259 97.37 0.0000037 0.0000016 0.0000059

Leak 7 2.63 0.0002064 0.0 0.0006932

Station Blowdown System 6 No

Leak 27 26.47 0.0006213 0.0 0.001641

L eak 75 73.53 1.274 0.4989 2.049

Open-Ended Line No

L eak 179 27.88 0.0001127 0.0000249 0.0002006

Leak 463 72.12 0.1158 0.05458 0.177

Instrument Controller 7 No

Leak ---- 0.00

---- ---- ----

Leak 17 100.0

0 0.4681 0.09325 0.842964

Gas Distribution Commercial and Residential Sites

Source Number

of

Sources Perce

nt of

Sourc

es Emissions

(kg/h/src) 95% Confidence Limits

Lower Upper

Connector 1 No

L eak 2759 99.60 0.0000015 0.0000011 0.0000018

Leak 11 0.40 0.001279 0.0 0.003918

Block Valve 2 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

L eak

---- 0.00

---- ---- ----

Regulator No

L eak 95 93.14 0.0000087 0.0000066 0.0000108

Leak 7 6.86 0.000202 0.0 0.0006906

Orifice Meter 4 No

L eak 83 79.81 0.001925 0.0006846 0.003165

L eak 21 20.19 0.0088 0.004936 0.01286

Other Flow Meter 5 No

Leak 259 97.37 0.0000037 0.0000016 0.0000059

L eak 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

e ak/No-leak emission factors for esti mating 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 Upper65

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-E nded Line emission category. Leakage from the end

connections is accounted for by the connecto r 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. Emissi ons 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 emi ssion 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 fr om use of the leak/no-leak factors.

The sources are categorized based on th ree 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 s ource category using the equation:

where,

EF 1 , EF 2 , EF 3 = 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),

n 1 , n 2 , n 3 = 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) = B 0 + B 1 Log(SV) (5)

where:

B 0 , B 1 = model parameters as given in Table 8,

ER = leak rate in (kg/h/source), and67

SV = maximum screening value above background

measured using a detector calibrated to methane

(ppm)

T hree-stratum emission factors for estima ting fugitive equipment leaks at Canadian

gas transmission and distribution facilities.

Gas Transmission Facilities

Source Number

of

Sources Percent

of

S ources Emissions

(kg/h/src) 95% Confidence Limits

Lower Upper

C onnector 1 <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 Valve 2 <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

C ontrol Valve 3 < 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

R egulator <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

O rifice Meter 4 <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 Meter 5 < 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 System 6 <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 0.068

Sy stem -

Depressurized Reciprocating 1000-10000

> 10000 ----

11 ----

73.33 ----

3.200 ----

1.245 ----

5.155

Compressor Blowdown

S ystem - <1000 7 38.89 0.0 0.0 0.0

Depressurized Centrifugal 1000-10000

> 10000 ----

11 ----

61.11 ----

1.200 ----

0.0 ----

2.422

O pen-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 Controller 7 < 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

Reciprocating 8 1000-10000

> 10000 ----

31 ----

86.1 ----

0.7682 ----

0.4865 ----

1.049

C ompressor Seal - < 1000 1 4.8 0.0000075

---- ----

Centrifugal 8 1000-10000

>10000 ----

20 ----

95.2 ----

0.8546 ----

0.2469 ----

1.462

T hree-stratum emission factors for estimati ng fugitive equipment leaks at Canadian

gas transmission and distribution facilities (Continued).

Gas Distribution Mete r/Regulator Stations

Source Number

of

Sources Percent

of

S ources Emissions

(kg/h/src) 95% Confidence Limits

Lower Upper

C onnector 1 < 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

B lock Valve 2 < 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 Valve 3 < 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

P RV < 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

0.252369

R egulator < 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 Meter 4 <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

O ther Flow Meter 5 < 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

S tation Blowdown System 6 < 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

O pen-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

In strument Controller 7 < 1000

---- ---- ---- ---- ----

1000-10000

>10000 ----

17 ----

100.0 ----

0.4681 ----

0.09325 ----

0.8429

Continued...70

T hree-stratum emission factors for estimati ng 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

C onnector 1 < 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

B lock Valve 2 < 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 Meter 4 < 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 Meter 5 <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

O pen-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 connecti ons 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 a ccounted for by the connector categor y (i.e., one connector for each end).

3 Accounts for leakage from the stem packing and valve body. Emissi ons from the controller and actuator are accounted for by th e Instrument Controller and Open-Ended Line categories respectively. Th is factor applies to all valv es with automatic actuators

(including fuel gas injecti on 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 fa ctor (i.e.,

these emissions must be calculated separately).

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

6 Accounts for leakage past a valve seat thr ough an open vent line to the atmosphere. Thes e vents are typically six inches or g reater in

diameter and are used to blowdown major process units or secti ons of pipeline. Small diameter open-ended lines such as those us ed71

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 pneum atic control devices that use natural gas as the supply me dium.

8 The Compressor Seal categories account for emissions from i ndividual compressor seals (i.e., fo r a four cylinder reciprocatin g

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 B 0 B 1 Number of

Sources Correlation (R 2 )

C onnectors 1 -5.9147 0.75 305 0.71

V alves 1 -6.0399 0.83 369 0.67

Open-Ended Lines 2 -6.9586 1.28 64 0.44

Pressure Relief

Devices 2 -5.1479 0.91 29 0.46

Pressure Regulators 2 -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, th e default zero values in Table 9

do not apply. In this situation, all zero screening values should set to

one-half the instrument's mi nimum 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 func tion of the number of components for

typical gas production facilities, assuming no pegged sources (Lott et al.

1996). The results show that the uncer tainty 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 Ga s Research Institute, June 19,

1997).7374

D efault zero emission rates 1

.

Source Type Default-Zero Emission Rate 2

(kg/h/source)

G as valve 6.6 (10 -7 )

L ight liquid valve 4.9 (10 -7 )

L ight liquid pump 3 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 emissi ons 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 correla tions to achieve better accuracy for

their particular operations. The benefit in doing this is often questionable

since, in theory, the relationshi p 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 ra tes 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 anal ysis text). To apply the sign test, try

using a sample size of four. If all f our 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 correla tion 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 fa cility (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 co st of assessment at accuracy of total

estimated emissions. It involves using a simp lified 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-leak ers (see Table 6) are applied to the rest

of the components.

An important advantage of this overall approach is it provides reliable information for77

determining which leakers are actually co st-effective to repair, and for subsequently

prioritizing the repair work. In comparison, a conventional leak detection and repair

(LDAR) program involving Method 21 screeni ng techniques can identify pegged-source

leakers, but cannot identify which leaks shoul d 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 c an eliminate this need. For example, use

of bubble tests with no data recording, just taggi ng of leaking components, is at least 3 to

4 times faster than application of Met hod 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. Co mponents 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 ei ther 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 valv e or flange), and passing a measured flow

of clean gas (e.g., zero air or nitrogen) th rough 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 concentra tion of pollutants measured inside the

chamber. This is done using the relation:

where,

Q = metered volumetric sweep rate corrected standard temperature and

pressure (m 3 /h), and78

C

= concentration of methane in the outlet air (kg/m 3 ).

A schematic diagram of a bagging setup is pr esented 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 insi de 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 det ermine 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 intrinsi cally-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 em ission rate rather than simply a concentration

measurement or screening value. The emi ssion rate is determined based on the

sampling rate needed to capture all the emi ssions from a target leaking equipment

component, and on the corresponding concentra tion 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 c apture, especially if high winds are a factor

or if the leak has significant momentum. Ho wever, higher flow rates reduce the size of

leak that can be quantified and increase the c hance of interference from nearby leaks.

The Hi-Flow sampler, reportedly, is avail able as both a product and as a service and its

capabilities have been well demonstrated. Howeve r, 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 us ed 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 drawba ck is that they do not specifically isolate

emissions due to fugitive equipment leaks, or identify individual leaker s. 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 remo te 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 instrum ents 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 stat ion, accurate global positioning

system (GPS) or linear-distance meas urement 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 inte rference from other sources. The

readings are averaged over a time period that is large enough to dampen

the effect of short-term atmospheric fl uctuations (e.g., at least 5 minutes

and possibly much longer for slow meandering wind conditions), and is

adequate to capture temporal va riations of the source.

Careful planning, dispersion calculati ons, and possibly real-time mapping of

the target plume(s) are required to determine exactly what sources are

contributing to the measured conc entrations, 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 pr edicting short term dispersion of

atmospheric emissions from industria l 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-P LUS (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 involving82

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 incl ude hourly average values of wind,

temperature and turbulence. Terrain dat a 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 concentrati ons 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. A dditional 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 representat ive of the higher cost limit.

The monitoring of methane concentrations may be done using either point

or path-integrated measurement te chniques. 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 required83

monitoring work. These devices give average concentration measurement

over a specified path length (i.e., t he distance between the sender/receiver

and the retro-reflector). A major advant age of employing path-integrating

measurement techniques instead of point measurement technique is that it

can eliminate the need for multiple m easurements. 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 reliab ility 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 t he 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-measur e 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 SF 6 or CF 4 are used as the tracer gas. Assuming the tracer

and source emissions are exposed to much the same atmospheric

dispersion effects (i.e., moment um, thermal buoyancy and turbulent

mixing), the tracer results may be used to effectively calibrate the

dispersion model for calculating the po llutant emission rate. If the remote

sensing can be performed far enough away that the emission source

appears as a point source and is well simu lated 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 mete red, amounts of tracer gas (typically

SF 6 ) at a steady rate near the source(s) of interest. (Note: SF 6 , 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 requi red to satisfy this requirement.

However, large downwind distances will increase the possibility of

interference from nearby sources and pot entially 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, int egrating 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 atmo sphere 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 SF 6 readings are typically 1 to 3 ppt.

If the SF 6 and source plumes overlap perfectly, then the ratio of SF 6 to

pollutant concentrations will be constant (i.e., within ± 10 percent) over the

entire plume cross-section at the se lected downwind monitoring location.

Moreover, this ratio will also be equal to the corresponding ratio of emission

rates. Thus, provided the require ments of point-source behaviour are

satisfied and there is no interferenc e from other nearby sources, the

emission rate of each pollutant may be readily determined using the simple

relationship,85

where,

C

i = concentration of the target pollutant i,

C t = concentration of the tracer gas,

Q i = volumetric emission rate of the target pollutant i, and

Q t = 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 dis persion 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-locati on 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 m easurements will be in the order of

$2000 to $3000 per day, plus mobilizati on/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 pl ant 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 t hat 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 pi ping 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 pipi ng 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 tw o pipeline segments or joints, and emissions

through the pipe wall. The emissions through t he 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 onl y 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 addre ssed collectively in Section 4.2.1.

Pipeline blowdowns, whether intentional for operat ing reasons (such as to lower the pipeline

pressure or a post-construction purge), or unintent ional 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 pi peline during a specific time period

is easily related to the average leak frequency, dur ation and rate. However, it is difficult to

establish these values with any reasonable degr ee of confidence. For instance, while the

majority of pipeline operators have good document ation 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 durati on 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 st ill unidentified, but already existing, leaks. To assess

the volumes leaked from the pipelines, calculat ions that rely on various simplifications

and assumptions must therefore be made.

The calculation process outlined below will determine the volumes of methane released87

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-specif ic data provide the most accurate results,

so that should be the prefe rred 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 pi peline or pipeline system is corrected for the

“equivalent-leak” quantity,

⋅ a multiplication factor is applied to a ccount for the equivalent-leaks duration time

(by definition, one calendar year),

⋅ the resulting annual volume is then corre cted for the methane content of natural

gas in that particular system and the me thane oxidation rate by the soil, and

finally,

⋅ the annual methane volume is convert ed to tonnes of methane per year.

The calculations do not use the operating pressu re 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 l eak rates are the type of pipeline (i.e.

transmission, distribution or se rvice 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 repair ed 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 emissi on 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 pr acticable, or the presented

industry-average factors may be applied acco rding 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 “equival ent-leaks” and for oxidation of methane by

the soil, as well as the conversion factor fr om standard cubic feet to tonnes of methane,

are all provided.

The default industry-average leak factors pr esented 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 diffe r from the presented values, while others

experienced reasonable agreem ent 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 cm 3 at 23

_ C and atmospheric pressure of

101.325 kPa.

K = permeability constant

= 85 (for methane)

A = area of the outside wall of t he pipe, in multiplies of 100 in 2

P = pressure in the pipe, atmospheres (gauge)89

θ = lapsed time, days

t = pipe wall thickness in mils (i.e. inches x 10 3 )

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. Ex pressing the surface ar ea in terms of outside diameter (mm) and

pipeline length (km), the wall thickness in (mm), pressure in (kPa g ), 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 (kPa g ).

L = length of pipeline (km).

For accurate calculation, the distribution syst em 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 t he 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 C anadian 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 possibl e 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

T

ransm ssion Pipelines (Protected Steel Pipe i )

Step

No. Description Default Values 1

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

(C 1 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

T

ransm ssion Pipelines (Unprotected Steel P pe) i i

Step

No. Description Default Values 1

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

(C 1 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

D istribution Mains (Plastic Pipe)

Step

No. Description Default Values 1

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

(C 1 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/scf94

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 Values 1

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

(C 1 divided by 100)

6 Multiply the result from Step (5) by the correction factor

for methane oxidation by the soil. 0.9795

7 Multiply the result from St ep (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

D istribution Mains (Unprotected Steel Pipe)

Step

No. Description Default Values 1

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

(C 1 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

D istribution Mains (Cast Iron Pipe)

Step

No. Description Default Values 1

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

(C 1 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 Values 1

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

(C 1 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/scf99

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 Values 1

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

(C 1 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/scf100

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 Value 1

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

(C 1 divided by 100)

6 Multiply the result from Step (5) by the correction factor 0.989101

for methane oxidation by the soil.

7 Multiply the result from St ep (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

S ervice Lines (Copper Tubing)

Step

No. Description Default Value 1

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 5a102

for methane content by volume. (C 1 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

c ommon SDRs 1

.

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 -6103

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 pr ocess venting or purging activities requires a

range of approaches depending on the type of v enting being considered and its relative

contributions to total emissions. For common sma ll 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 in clude, 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 per formance 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 dehydrat ors (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 suppl y 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 depressurizi ng the system through a vent to the

atmosphere. If the gas is discharged to a flar e 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 aboveground105

facilities), unit blowdowns (for blow down 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.

p le of potential waste gas volumes and frequencies for blowdowns, purges and

other venting activities on mainline transmission pipeline segments and at

c ompressor stations.

Blowdown/Venting

Event Location Waste Gas

Volume 1

( 10 3 m 3 /event) Frequency of

Occurrence

Mainline BlockValve Blowdown Pipeline 0.3 to 2,770+ Very infrequently

for any given

segment (say once

e very 20 years).

Pipeline Purge Pipeline 0.1 to 150 Very infrequently

for any given

segment (say once

e very 20 years).

Station Blowdowns Compressor Station 0.3 to 1.5 Several times per

y ear or less.

Scrubber

B lowdowns Compressor Station 0.1 to 1.1 Typically, less than

o nce per year.

B ooster Vents 2 C ompressor Unit 0 .1 to 5.5 M onthly.

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 meas ures 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 ex ist 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 kPa g . Further gas may

then be recovered by using a mobile pulldown or transfer

compressor unit. Transfer rates fo r 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 mont h 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 r epair 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 T able 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, patc hes, clamps and stoppler equipment.

PVC pipe is repaired by pipe replacement or application of a leak seal. The

pipe replacement method involves cutti ng 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 kPa g 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 pressu rized 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 pur ging 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 li ne 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 distributi on system and the amount of waste gas

involved as estimated by one gas distribution company. Another reason for

b lowdowns is the abandonment of lines as part of replacement projects 1

.

Event Normal Operating

Pressure

(kPa g ) Waste Gas

Volume

(m 3 )

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.109110

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 ext end 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 controlle r, 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 spec ified control settings. The actuator

converts the energy changes it experienc es into mechanical adjustments to the

control device. In some instances t he actuator is equipped with a positioner to

ensure precise adjusting of the control devic e. 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 Isol ation-Valve Actuators - Large valves that would be

difficult to stroke manually using a handwheel or handle may be equipped with a111

pneumatic actuator. Depending on the r equired supply pressure and the

availability of compressed air, it is so metimes 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 applic ations: piston (or double-acting), rotary

vane and turbine. In applications requiring only small to moderate actuating forces,

diaphragm (or single-acting) actuators ar e most commonly used due to their lower

cost and reduced supply-gas requirements.

A single-acting actuator uses supply pre ssure to move the actuator in one

direction, and exhausts gas to allow the sp ring 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 ac ting actuator exhausts twice as much

gas as a single acting actuator in the same application. Rotary vane and turbine

actuators are essentially motorized operat ors 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 s upply gas pressure, and the amount of

travel/rotation and force required to st roke (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 m 3 /d, and injection pressure

capabilities of up to 62 000 kPa g 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 kPa g or less and others are designed to operate off high or erratic

pressures up to 10 340 kPa g

.

The amount of gas consumption is determi ned by the change in pressure of this

gas in passing through the gas motor, t he pumping rate and the required chemical

injection pressure. As much as 7.5 m 3 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 ty pe of glycol circulation pump) exhaust

about 0.178 m 3 of CH 4 per 10 3 m 3 of gas processed at gas plants. This factor

assumes that 33 percent of the dehydrator s 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 m 3 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 vo lume of emissions. Potential leakage past the

seat of the relief devices during non-relieving per iods (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 sa mple 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 H 2 S analyzer).113

Emission from the manual system may be attri buted 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 attac hed). 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 analyze r, the used portion of sample may be

released unchanged or as products of com bustion. Consequently, the amount of

emissions depends on the sampling rate and the characteristics of the analyzer. A value

of 0.0985 m 3 /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 vent ing and purging activities requires a thorough

investigation to properly identify all such s ources, and compile the information necessary

quantify the emissions (e.g., frequency of occurrenc e 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 rel ease events, so all that is required for these

sources is to aggregate the results and make appropr iate 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 prov ides average emission factors for

standard instrument control loops (e.g., li quid 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 consider ed separately. Presently, there is very

limited data available for doing this. Meas urements performed on one mainline control

valve indicated an average gas consumption rate of 1.504 m 3 /h. This agrees very well

with the average value of 1.608 m 3 /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-va lve operators is a function of the operating114

conditions, actuator type and size, and the fr equency of actuation. Shires and Harrison

(1996) report an average value of 0.018 m 3 /h/device for isolation valves equipped with

rotary vane actuator based on measurement s performed at four gas transmission

facilities in the U.S. (see Table 14). Manufac turer'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 emissi ons. There are no accepted factors for

estimating emissions from these types of ac tivities, 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 system s involved and calculate emissions based on

the amount of gas contained within these vo lumes 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),

V

s = physical volume of the system to be blown down or purged (m 3 ) (see Table

16 for specific volumes of various pipe sizes),

P i = initial system pressure (kPa) (absolute),

T i = initial system temperature (

_ C), and

Z i = compressibility factor for the natur al 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 rates115

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 moder ate flow rates, and where the back-pressure

caused by the flow measurement device c an be tolerated by the emission source.

Common types of in-line flow meters incl ude bubbleometers, rotameters, orifice meters,

turbine meters, and diaphragm meters.

For high flow rates or cases where back-pre ssures cannot be tolerated, emission rates

may be determined by performing velocity trav erses with a suitable velocity probe, and

then integrating the results ov er the stack or duct cross-section. If a convenient access

port is not available it may be possible to di rect 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 in trinsically-safe model should be selected.116

Typical gas consumption rates for a variet y of standard and low-bleed types of pneumatic

instruments 1

.

Type Supply Pressure: 140 kPa

g Supply Pressure: 240 kPa

g

Steady-state

(m 3 /h) Max.

Exhaust

(m 3 /h) Steady-state

(m 3 /h) Max.

Exhaust

(m 3 /h)

Standard

Consumptio

n

D evices Transmitter 0.12 0.72 0.20 1.20

C ontroller 0.40 to 0.80 4.5 to 5.5 0.60 to 1.00 7.0 to 8.5

I/P

T ransducer 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

D evices Transmitter 0.08 0.4 0.1 0.45

C ontroller 0.10 0.45 0.14 0.5

I/P

T ransducer 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

(kPa

g ) Actuator

Size Gas Usage

per Cycle

(m 3 /MPa) Number of

Devices Cycles

per Year Gas Usage

per

Device Type

(m 3 /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 m 3

S ite Weighted A erage = 53.2 ± 54% m v 3 /y/device (or 0.0061 ± 54% m 3 /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 m 3

Site Weighted Average = 472.3 ± 37% m 3 /y/device (or 0.0539 ± 37% m 3 /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

22.7118

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 m 3

Site Weighted Average = 80.8 ± 27% m 3 /y/device (or 0.0092 ± 237% m 3 /h/device)

Gas usage by pneumatic/hydraulic rotary vane isolation valve operators (Concluded).

Site Supply Gas

Pressure

(kPa

g ) Actuator

Size Gas Usage

per Cycle

(m 3 /MPa) Number of

Devices Cycles

per Year Gas Usage

per

Device Type

(m 3 /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 m 3

Site Weighted Average = 31.1 ± 39% m 3 /y/device (or 0.0036 ± 39% m 3 /h/device)

Average displacement device emission factor = 159.3 ± 112% m 3 /y/device (or 0.0182 ± 112% m 3 /h/device)

Source: Adapted from Shires and M.R. Harrison (1996), Table 4-7, pages 49 and 50.

M anufac urer data for t rbine-operate isolation valv s. t u d e

Site Supply Gas

Pressure

(kPa g ) Gas

Consumptio

n

(m 3 /h) Time

(s/operation

) Gas Usage

(m 3 /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 1157.9119

5 5520 800 90 19.96 29 1157.9

Average Turbine Device Emission Factor = 1914.2 ± 276% m3/y/device (or 0.219 ± 276%

m 3 /h/device)

Source: Adapted from Shires and M.R. Harrison (1996), Table 4-8, page 52.120

Summary of dimensional and specific inte rnal-volume data for selected pipe sizes.

NPS Schedul

e OD

(mm) WT

(mm) Specific

Volume

(m 3 /m) NPS Schedul

e OD

(mm) WT

(mm) Specific

Volume

(m 3 /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

3121

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

S ummary o dimension l and spec ic inte rnal-volume data for selected pipe sizes. f a if

NPS Schedul

e OD

(mm) WT

(mm) Specific

Volume

(m 3 /m) NPS Schedul

e OD

(mm) WT

(mm) Specific

Volume

(m 3 /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

3122

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

0123

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

S ummary o dimension l and spec ic inte rnal-volume data for selected pipe sizes. f a if

NPS Schedul

e OD

(mm) WT

(mm) Specific

Volume

(m 3 /m) NPS Schedul

e OD

(mm) WT

(mm) Specific

Volume

(m 3 /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

9124

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 0.67462125

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 inte rnal-volume data for selected pipe sizes.

NPS Schedul

e OD

(mm) WT

(mm) Specific

Volume

(m 3 /m) NPS Schedul

e OD

(mm) WT

(mm) Specific

Volume

(m 3 /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 Thickness126

Compressibility factors for "Rich Processed Na tural Gas" upstream of straddle plants for

v arious 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 0.762717127

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% C 1 , 7.45% C 2 , 1.91% C 3 , 0.17% iC 4 , 0.24% nC 4 , 0.06% iC 5 , 0.04% nC 5 , 0.10% nC 6+ , 0.72% N 2 and 0.90% CO 2

.

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

v arious 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 0.892689128

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% C 1 , 4.0556% C 2 , 1.1112% C 3 , 0.1601% iC 4 , 0.2180% nC 4 , 0.0496% iC 5 , 0.0389% nC 5 , 0.0225% nC 6+ , 0.8291% N 2 and 0.6334% CO 2

.

Compressibility factors for "Typical Processed Natural Gas" downstream of straddle various

c ombinations of temperature and pressure 1

.

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 0.982141129

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% C 1 , 2.4306% C 2 , 0.1374% C 3 , 0.0043% iC 4 , 0.0043% nC 4 , 0.0013% iC 5 , 0.0010% nC 5 , 0.0012% nC 6+ , 1.6519% N 2 and 0.5552% CO 2

.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 select ive absorption and the gl ycol is regenerated or

reconcentrated by thermal desorption. The us e 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 process ed 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 dehydr ator 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 fl ows 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 regener ated 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

H 2 O removed. At 6900 kPa

g , 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 someti mes 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 fl ows to a packed stripping still attached to the top

of a reboiler. In the still column, the wet glyco l flows down to the reboiler while contacting hot

gases (mostly water vapour and glycol) rising up fr om 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 175 o to 205 o C 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 strippi ng 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 v ent. 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 co st 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 info rmation on the amount of methane emissions.

Furthermore, the program can assess the emi ssion reduction that may be achieved from

use of selected control devices (e.g.,condens ers 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., HYSIM TM by Hyprotech, PRO/II TM by Simulation Sciences, and

PROSIM TM 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 justifi ed for the subject application alone.

6.2.3 Measurement . Emissions from a flash tank vent can be measured using the methods132

described in Section 5.2.2. A sample of t he 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

Values 1

1 Establish total gas throughput (10 3 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 m 3 /10 3

m 3

(if dehy has flash

tank)

- or -

0.1751 m 3 /10 3 m 3

(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 m 3 /10 3 m 3

4 Multiply the results from Step (1 ) by the basic emission factor

for gas consumption by a Kimray-type energy-exchange

p ump if one is used. 0.1777 m 3 /10 3 m 3

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/m 3134

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 accu rate 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 su itable 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 consumpti on 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). T he 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 t hat the system has not been designed for (that

excludes such releases as, for ex ample, 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 exte rnal 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-t oughness steel pipe. Therefore, unless a

transmission pipeline operating company has spec ific data from emissions from pipeline

dig-ins, the dig-ins emissions from tr ansmission pipelines can be assumed to be

negligible and ignored.

Emissions from dig-ins are extremely difficu lt 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 tem porarily or permanently stopped.

Most distribution companies have available det ailed statistics on dig-in incidents, and inhouse estimating methods to quantify the amount of gas released to the atmosphere.

The preferred methodology for estimating t he 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 Se ction 3.0) , and converted to tons per year

for inclusion in the overall emissions envelope.

For those companies that do not have the nec essary 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 quantif ication is available for a representative

sample of the total incidents, an average vo lume per incident can be used to calculate

the total company volume for dig-ins by multip lying 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, eit her in the original quantification of the

individual incidents, or in the final ca lculation of the company-wide emissions.137

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Blow and Purge Activities. A report prepared for GRI and U.S. EPA. GRI Report No. GRI94/0257.24. EPA Report No. EPA-6--/R-96-080g. 83 pp.

Radian International. 1996h. Methane Emissions Fr om the Natural Gas Industry. Volume 8:

Equipment Leaks. A report prepared for GRI and U.S. EPA. GRI Report No. GRI-94/0257.25.

EPA Report No. EPA-6--/R-96-080h. 130 pp.

Radian International. 1996i. Methane Emissions Fr om the Natural Gas Industry. Volume 9:

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 Fr om 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 R eport No. GRI-94/0257.27. EPA Report No. EPA6--/R-96-080j. 44 pp.

Radian International. 1996k. Methane Emissions Fr om 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 Fr om 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 Fr om the Natural Gas Industry. Volume 13:143

Chemical Injection Pumps. A report prepar ed for GRI and U.S. EPA. GRI Report No. GRI94/0257.30. EPA Report No. EPA-6--/R-96-080m. 42 pp.

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Glycol Dehydrators. A report prepared for GR I and U.S. EPA. GRI Report No. GRI-94/0257.31

. EPA Report No. EPA-6--/R-96-080n. 47 pp.

R adian International. 1996o. Methane Emissions Fr om 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.

S cotto, 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 Gener ating Unit-specific Emission

Estimates for Equipment Leaks for Equipment Leaks of VOC and VHAP. Prepared by Emission

Standards Division, Office of Air and Radiati on, 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 Leaks145

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 cla ssification 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 oxidize r), 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 va lve 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 ot her (either directly or through a line)

is counted as an open-ended valve or line. If t he open side of the valve is fitted with a

properly installed cap, plug, blind flange or se cond closed block valve, or is connected to

a control device then it is no longer consi dered 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 activi ties, 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 samp ling 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 di agrams, 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 im portant to also record the perc entage of the time that it is

out of service (i.e., there is zero gauge pre ssure 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 BBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBBB

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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 shall149

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 shelf150

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 the151

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 possible152

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 the153

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.