BEST MANAGEMENT PRACTICE

Management of Fugitive 

Emissions at Upstream Oil and 

Gas Facilities

January 2007

2007-0003
2100, 350 – 7th Ave. S.W.

Calgary, Alberta

Canada T2P 3N9

Tel (403) 267-1100

Fax (403) 261-4622

403, 235 Water Street

St. John’s, Newfoundland

Canada A1C 1B6

Tel (709) 724-4200

Fax (709) 724-4225

Email: communication@capp.ca Website: www.capp.ca

The Canadian Association of Petroleum Producers (CAPP) represents 150 

companies that explore for, develop and produce natural gas, natural gas liquids, 

crude oil, oil sands, and elemental sulphur throughout Canada. CAPP member 

companies produce more than 95 per cent of Canada’s natural gas and crude oil. 

CAPP also has 130 associate members that provide a wide range of services that 

support the upstream crude oil and natural gas industry. Together, these members 

and associate members are an important part of a $100-billion-a-year national 

industry that affects the livelihoods of more than half a million Canadians.

Review by January 2009

Disclaimer

This publication is issued by the Canadian Association of Petroleum Producers 

(CAPP). While it is believed that the information contained herein is reliable 

under the conditions and subject to the limitations set out, CAPP, its consultants 

– Clearstone Engineering Ltd – and the Project Steering Committee do not 

guarantee its accuracy. The use of this report or any information contained will 

be at the user’s sole risk, regardless of any fault or negligence of Clearstone 

Engineering Ltd., the Project Steering Committee, CAPP or its co-funders.
January 2007 Management of Fugitive Emissions

At Upstream Oil and Gas Facilities

Table of Contents

Section Page

List of Acronyms.......................................................................................................................i

Acknowledgment..................................................................................................................... ii

Forward ................................................................................................................................... iii

1 Applicability .................................................................................................................1

2 Implementation And Schedule For Review................................................................2

2.1 Schedule for review .........................................................................................2

3 Basic Control Strategy .................................................................................................4

3.1 Technology and Standards..............................................................................4

3.2 Management Systems......................................................................................4

3.2.1 Directed Inspection & Maintenance (DI&M) Program....................4

3.2.2 Leak Definition....................................................................................5

3.2.3 Leak Detection.....................................................................................5

3.2.4 Leak Quantification.............................................................................6

3.2.5 Target Components.............................................................................7

3.2.6 Monitoring Frequency ........................................................................8

3.2.7 Inaccessible Components....................................................................9

3.2.8 Tagging Components..........................................................................9

3.2.9 Leak Repairs........................................................................................9

3.2.10 Personnel Training ............................................................................11

3.2.11 Primary Calibrations and Field checks............................................11

4 Inspection, Monitoring & Record-Keeping..............................................................12

5 Corporate Commitment .............................................................................................13

6 Appendices .................................................................................................................14

7 References Cited ........................................................................................................15

Appendix 1 Table 4. Examples Of Leak Monitoring Frequencies For Leak-Prone Equipment 

Components................................................................................................................17

Appendix 2 Sample Leaker Tag........................................................................................18

Appendix 3 Appendix III – Leak Survey Forms..............................................................19

Appendix 4 Economic Analysis........................................................................................23

Appendix 5 Emissions Inventory From Method 21 Data ................................................25

5.1 Leak/No-leak Emission Factors....................................................................25

5.2 Three-stratum Emission Factors...................................................................28

5.3 Published Leak-Rate Correlations................................................................28

5.4 Unit-Specific Leak-Rate Correlations..........................................................32
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Appendix 6 Component-Specific Control Options..........................................................34

6.1 Reciprocating Compressors..........................................................................34

6.1.1 Vent Monitoring Systems.................................................................34

6.1.2 Emission-Controlling Vent Systems................................................34

6.1.3 High Performance Packing Systems................................................36

6.1.4 Barrier Fluid Systems .......................................................................36

6.1.5 Purge Gas Systems............................................................................37

6.1.6 Unit Shutdown Practices...................................................................37

6.1.7 Static Packing Systems.....................................................................38

6.1.8 Valve Cap Leakage ...........................................................................38

6.2 Centrifugal Compressors...............................................................................38

6.2.1 Emission-Controlling Vent Systems Used with Conventional Seals38

6.2.2 Dry Gas Seals ....................................................................................39

6.3 Valves.............................................................................................................39

6.4 Sewers and Drains .........................................................................................41

6.5 Pumps.............................................................................................................41

6.6 Threaded and Flanged Connections............................................................43

6.7 Pressure Relief Devices.................................................................................43

6.8 Open-ended Valves and Lines......................................................................44

6.9 Sampling Points.............................................................................................44

Appendix 7 US EPA Method 21 .......................................................................................46
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List of Tables

Table Page

1 Leak detection and measurement methods. 6

2 Summary of screening and measurement techniques 7

3 Default mean life of repairs for economic analysis of repair costs. 10

4. Examples of leak monitoring frequencies for leak prone equipment components 17

5. Sample calculations of the simple payback period for individual leak repairs 24

6. Leak/No-leak emission factors for estimating fugitive leaks at UOG facilities 26

7. Three-stratum emission factors for estimating fugitive leaks at UOG facilities 29

8. Correlation parameters for estimating leak rates from equipment components 30

9. Default zero emission rates 32

10. Common causes of leakage from flanged and threaded connections 43

Figures

1. DI&M Decision Tree 3

2. Schematic diagram of a piston-rod packing-case system 

on a reciprocating compressor 35
January 2007 Management of Fugitive Emissions i

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List of Acronyms

AENV - Alberta Environment

API - American Petroleum Institute

ASME - American Society of Mechanical Engineers

BMP - Best Management Practice

CAC - Criteria Air Contaminant

CAPP - Canadian Association of Petroleum Producers

CASA - Clean Air Strategic Alliance

CCME - Canadian Council of Ministers of the Environment

DI&M - Direct Inspection and Maintenance (DI&M) 

EUB - Alberta Energy and Utilities Board

EC - Environment Canada

GHG - Greenhouse Gases

MTBF - Mean Time Between Failure

NACE - National Association of Corrosion Engineers

NFPA - National Fire Protection Association

NMHC - Non-Methane Hydrocarbon

NPT - National Pipe Thread

PTAC - Petroleum Technology Alliance of Canada 

PTFE - Polytetrafluoroethylene

SEPAC - Small Explorers and Producers Association of Canada

THC - Total Hydrocarbons

TOC - Total Organic Compounds

TNMOC - Total Non-methane Organic Compounds

UOG - Upstream Oil and Gas

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

VOC - Volatile Organic Compound
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Acknowledgment

Special thanks are given to the following individuals and companies who participated on the 

project steering committee and/or provided review and comments at different times throughout 

the duration of the project:

M. Brown - Alberta Energy and Utilities Board

B. Forsyth - BP Canada

C. Chamberland - Shell Canada Limited

W. Hillier - Husky Energy

M. Layer - Environment Canada

S. McIntyre - Canadian Natural Resources Limited

L. Miller - BP Canada

R. Pettipas - Conoco-Phillips Canada

S. Reilly - Talisman Energy

B. Ross - Nexen Inc.

S. Sian - CAPP

R. Sikora - KEYERA Energy

J. Squarek - CAPP

R. Sundermann - EnCana

J. Tatham - BP Canada

A. Varley - Petro-Canada
January 2007 Management of Fugitive Emissions iii

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Forward

The issue of fugitive emissions management has and continues to be important to 

the upstream oil and gas (UOG) industry. The genesis of this fugitive emissions 

Best Management Practice (BMP) can be traced back to earlier undertakings of 

the Air Research Planning Committee (ARPC) of the Petroleum Technology 

Alliance of Canada (PTAC).

The Canadian Association of Petroleum Producers (CAPP), the Small Explorers 

and Producers Association of Canada (SEPAC), Environment Canada (EC) and 

the Alberta Energy and Utilities Board (EUB) have coordinated efforts to develop 

this BMP which also satisfies recommendations No. 43 and 44 of the Clean Air 

Strategic Alliance (CASA) Flaring and Venting Project Team (FVPT):

43) CAPP and SEPAC develop a best management practices document by 

December 31, 2005 to assist the upstream oil and gas industry in managing 

fugitive emissions and targeting sources that are most likely to have larger 

volume emissions and which would be more cost effective to address. CAPP 

and SEPAC will incorporate improvement to emission factors into the best 

management practices document as they become available.

44) Once a best management practices document has been developed by CAPP 

and SEPAC, the EUB should require licensees to develop and implement leak 

detection and repair programs to minimize fugitive emissions from upstream 

petroleum industry facilities.

The aim of this BMP is to assist the UOG industry in meeting the requirements 

under section 8.7 of the EUB Directive 060 (Upstream Petroleum Industry 

Flaring, Incinerating, and Venting) and in cost effectively managing the most 

likely sources of significant fugitive emissions. 

The emissions of primary concern are methane (CH4) and non-methane volatile 

organic hydrocarbons (NMVOC).

This BMP: 

• identifies the typical key sources of fugitive emissions at UOG facilities, 

• presents strategies for achieving cost-effective reductions in these emissions 

(e.g., through improved designs, Directed Inspection and Maintenance 

(DI&M) practices, improved operating practices, and the application of new 

and retrofit technologies), and 

• summarizes key considerations and constraints. 

While this BMP is specific to fugitive equipment leaks, it considers leakage 

directly to the atmosphere and unintentional gas carry-through to storage tanks.

The BMP also considers emerging technologies that have the potential to improve 

the efficiency and effectiveness of leak detection. The overall aim is to provide 

practical guidance to operators for developing focused approaches to manage and 

reduce fugitive emissions at individual oil and gas facilities, while giving 

consideration to each facility’s specific circumstances.
January 2007 Management of Fugitive Emissions 1

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1 Applicability

This BMP provides guidance for the management of fugitive emissions at UOG 

facilities from leaks (i.e., the loss of process fluid to the environment past a seal, 

threaded or mechanical connection, cover, valve seat, flaw or minor damage 

point) on equipment components in hydrocarbon service.

A component is considered to be in hydrocarbon service when the process fluid 

being handled contains greater than 10 percent hydrocarbons on a mass basis. 

Fugitive emissions from equipment leaks are unintentional losses and may arise 

due to normal wear and tear, improper or incomplete assembly of components, 

inadequate material specification, manufacturing defects, damage during 

installation or use, corrosion, fouling and environmental effects. Components also 

tend to have greater average emissions when subjected to frequent thermal 

cycling, vibrations or cryogenic service.

Only a small percentage of the equipment components have any measurable 

leakage, and of those only a small percentage contributes to most of the 

emissions. Thus, the control of fugitive emissions is a matter of minimizing the 

potential for big leaks and providing early detection and repair. 

The UOG industry is characterized by many small widely dispersed facilities

rather than a few large facilities so it is appropriate to apply a directed approach 

that targets the sources most practicable to control, components most likely to 

result in big leaks. At each target facility, efforts should be focused on the areas 

most likely to offer significant, cost-effective control opportunities (e.g., on 

specific component types and service applications). 

This BMP is designed to apply to components in sweet gas service which are 

expected to represent the greatest opportunity for emission reductions.1 Existing 

mechanisms to address odour, health and safety concerns in sour facilities are 

deemed to meet or exceed the purpose of this BMP.2 Furthermore, this BMP is 

designed to apply primarily to fugitive equipment leaks from components in 

natural gas or hydrocarbon vapour service. This reflects the greater difficulty in 

containing a gas than a liquid (i.e., due to the greater mobility or fluidity of 

gases), and the general reduced visual indications of gas leaks.

 

1

For the purpose of this BMP, sweet gas is defined as natural gas with an H2S concentration of less than 10 

mol/kmol in accordance with the approach adopted in the EUB Directive 060.

2

 Odour emissions are addressed under section 14 of the EUB Directive 064, which states that “in accordance with 

the OGC Act, part 1(4)(f), the EUB has jurisdiction to control pollution above, at, or below the surface in the 

drilling wells and in operations for the production of oil and gas. In this regard, migration of H2S emissions off 

lease is considered pollution and may be defined as a major unsatisfactory inspection”. Appendix 1, 3 and 11 of 

Directive 064 also provide additional information regarding off-site regulatory requirements for H2S odour 

management.
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2 Implementation And Schedule For Review

Efficient management of fugitive emissions is best achieved through the 

application of DI&M techniques. DI&M focuses inspection and correction efforts 

on the areas most likely to offer significant cost-effective control opportunities, 

with coarse or less frequent screening of other areas for additional opportunities. 

The Decision Tree reproduced under Figure 1 has been developed to provide a 

process to effectively manage fugitive emissions.

When phasing-in their DI&M program, companies may consider factors such as 

size and age of facility or type of facility, percentage of components per year, 

percentage of facilities, business units, geographic area, shutdown schedule, and 

economic classification of repairs. The implementation of a DI&M program at 

existing UOG facilities should be completed by December 31, 2009.

While this BMP provides for a phasing-in period, CAPP members will be 

requested to provide interim reports on the status of implementation of a DI&M 

program within their companies by March 31, 2008 and March 31, 2009. These 

status reports will indicate any problem areas or improvements and allow for 

updating and additions to the BMP as necessary.

When implementing this BMP, companies should keep in mind that the EUB

Directive 060 imposes a mandatory requirement to implement a program to detect 

and repair leaks and that such a program must meet or exceed CAPP BMP.

In view of the above, the use of the world “should” in this BMP does not imply 

that action is not necessary within the context of the EUB Directive 060; i.e., 

alternative methodologies to those described in the BMP can be used as long as 

the expected results are achieved or exceeded. “No action” is not an option.

2.1 Schedule for review

Concurrent with the introduction of this BMP is a field investigation program to 

verify the effectiveness of the methodologies proposed in this document. The field 

work should provide further knowledge on key detection, monitoring and control 

technologies and practices, as well as additional data to review and modify as 

needed the recommended monitoring frequency and default repair lives for 

different types of equipment. This field investigation work will be conducted in 

cooperation with EC and EUB and will extend over a two-year period until the 

fourth quarter of 2008. Interim and final reports will be presented as a basis for 

the continued improvement of this BMP.

A review of the document is expected to take place within 24 months from the 

date of implementation to incorporate any adjustments that CAPP and its 

members deem necessary as result of the expertise gained during the first year of 

implementation and the ongoing field investigation work.

Thereafter, this BMP will be regularly reviewed and revised as necessary.
January 2007 Management of Fugitive Emissions 3

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Figure 1 - DI&M Decision Tree:

Does the leak 

require a 

shutdown to 

fix?

yes

Implement a DI&M program to focus on big 

leaks. Then for each leak detected proceed as 

follows.

s.3.2.1, 3.2.2, 3.2.3 

Is the leak 

economical to 

fix?

s. 3.2.9

yes

yes

Measure or estimate the size of the leak 

and evaluate the cost effectiveness of 

fixing it. s. 3.2.4

no

Add to repair list and fix during 

next planned/unplanned shutdown

without quantification.

s. 3.2.9

Are there health, 

safety, or 

environmental 

concerns?

s. 3.2.1

yes

Re-evaluate at the next 

scheduled leak survey

Repair leaking components no

s. 3.2.9

Is the leak 

easy to fix?

no

no no

n o

no

or
January 2007 Management of Fugitive Emissions 4

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3 Basic Control Strategy

The key elements for effective long-term control of fugitive emissions are the 

application of best available technology and standards, implementation of 

management systems, and corporate commitment. The application of control 

technologies and design standards, alone, do not preclude the potential for 

fugitive emissions. Reliable fugitive emissions control requires:

• the development of monitoring programs, operating procedures and 

performance objectives for controlling fugitive emissions, and 

• Management’s commitment to the implementation and maintenance of a 

DI&M program.

3.1 Technology and Standards

The first step in controlling fugitive equipment leaks should always be to 

minimize potential for leaks by applying proper design and material-selection 

standards, to follow the manufacturer’s specifications for the installation, use and 

maintenance of components and to implement practicable control technologies 

(e.g., reduction, recovery and treatment systems).

3.2 Management Systems

A management system is needed to establish objective performance targets and to 

implement ongoing monitoring and predictive maintenance programs to ensure 

that leaks are detected and remain well controlled. The following sections 

describe the basic elements of a DI&M program.

3.2.1 Directed Inspection & Maintenance (DI&M) Program

The first step is to determine which types of components will be targeted (i.e., 

subjected to regular screening for leaks). The objective is to minimize the 

potential for leaks in the most practicable manner possible. This is done by 

focusing efforts on the types of components and service applications most likely 

to offer significant cost-effective control opportunities (see Section 3.2.5). Nontarget components are subjected to coarse or less frequent screening.

Typically, a facility will phase the DI&M program over a certain number of years 

by progressively adding to the list of target components until all key potential 

contributors are being targeted. Once a leak is detected, regardless of whether it is 

a target or non-target component, the Decision Tree reproduced under Figure 1 

should be followed to determine if a leak need to be repaired. Once a leak is 

determined to need fixing, this should be done within a reasonable period of time 

(see Section 3.2.9), or at the next facility turnaround if a major shutdown is 

required.

A facility may choose to simply repair or fix the leak. If it is not a simple repair or 

fix, an operator may choose to program the repair at the next shut down without 

quantification or, alternatively, the leak should be measured or estimated to 

determine if it is economical to repair. Where an operator believes that it may not 

be economical to repair, this should be documented based on reliable 

quantification of the amount of leakage and the repair costs (see Sections 3.2.4 
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and 3.2.8). If a leak poses a health, safety, or environmental concern, then it needs 

to be repaired regardless of whether it is economical to fix.

3.2.2 Leak Definition 

Fugitive emissions control is becoming more common as a condition of a 

facility’s operating approval. Accordingly, it is useful to consider a definition that 

corresponds to those typically applied in other industries. Firstly, a leak could be 

defined as a screening concentration of 10,000 ppm or more

3

 for the purposes of 

deciding whether to measure the emission rate and evaluate the practicability of 

making repairs. Below this threshold the emissions generally become too small to 

quantify. Moreover, usually only the top 5 to 10 percent of leaking components

account for 80 to 90 percent of the emissions at a facility. Consequently, there is 

limited value in dedicating resources to measure or estimate emissions from 

components that do not achieve the screening value identified. However facilities 

may still choose to repair these below 10 000 ppm emissions without 

measurement.

There are several new emerging technologies that have the potential to improve 

efficiency and effectiveness of leak detection programs and replace US EPA 

Method 21. These technologies include: differential lasers to measure atmospheric 

concentrations of component gases, computer analysis of ambient air sample 

trends to estimate leak source location and volumes and infrared optical 

technology to visually inspect the components. Many of these and other

technologies are being developed and can be used to identify leaking components.

3.2.3 Leak Detection

Leak screening should be done on accessible components using a portable organic 

vapour analyzer in accordance with US EPA Method 21 or using such alternative 

methods that provide an equivalent result (see Section 3.2.2 for the leak 

definition). In some cases, US EPA Method 21 has been considered too slow and 

labour intensive and more suited for large facilities. For these reasons, this BMP 

provides the opportunity to use other methods.

There are several new emerging technologies that have the potential to improve 

efficiency and effectiveness of leak detection programs and replace US EPA 

Method 21. These technologies include: differential lasers to measure atmospheric 

concentrations of component gases, computer analysis of ambient air sample 

trends to estimate leak source location and volumes and infrared optical 

technology to visually inspect the components. Many of these and other 

technologies are being developed and can be used to identify leaking components.

Using alternatives to US EPA Method 21 may also allow operators to evaluate 

components that may have not been accessible otherwise.

 

3

 This is the current leak definition applied by the CCME (1993) guidelines for the measurement and control of 

fugitive volatile organic compound (VOC) emissions from equipment leaks at petroleum refineries and organic 

chemical plants based on US EPA Method 21.
January 2007 Management of Fugitive Emissions 6

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3.2.4 Leak Quantification

The quantification by measurement or estimation of leak rates to evaluate the 

feasibility of repairing or replacing a component should be sufficiently accurate 

for this purpose (e.g., within ±25 percent or enough to clearly establish a positive 

net financial benefit). Depending on the type of component and information 

available, potentially valid quantification methods may include, but are not 

limited to, process modelling, material balances, flow capture and metering 

systems, duct sampling techniques, tracer tests and some types of remote sensing 

methods.

Table 1 provides a list of potential methods to detect, and measure or estimate

leaks.

Table 1. Leak Detection and Measurement Methods1.

Qualitative Methods2 Quantitative Methods3

Bubble Tests Portable Organic Vapour Analyzers4

Optical emissions detection 

(Leak imaging) 

Quantitative remote sensing techniques

Ultrasonic Leak Detectors Engineered estimates

1 This is not necessarily a complete list of valid methods. 

2 A leak detection method is deemed to be qualitative where it provides a leak detection capability 

consistent with, or better than, the leak definition given in Section 3.2.2 but is not able to provide a 

quantitative output that can be related to the leak definition. If a qualitative method can be 

enhanced to consistently provide quantitative output that can be related to the leak definition then it 

may be reclassified as a quantitative method.

3 A leak detection method is deemed to be quantitative where it provides a minimum leak detection 

capability consistent with, or better than, the leak definition given in Section 3.2.2 and provides 

quantitative output that can be related to the leak definition. 

4 Operators note that the sensors may be damaged by vapours at high concentrations or give a false 

reading depending on the calibration gas.
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Table 2 provides an indication of cost effectiveness for some of the screening and 

measurement techniques based on an EPA’s Lessons Learned Study.

Table 2 Summary of Screening and Measurement

Techniques 

Instrument/Technique Effectiveness Approximate 

Capital Cost

Soap Solution ** $

Electronic Gas Detectors * $$

Acoustic Detection / 

Ultrasound Detection

** $$$

Toxic vapour analyzer / 

Flame ionization 

Detector

* $$$

Bagging * $$$

High Volume Sampler *** $$$

Rotameter ** $$

Leak Imaging *** $$$

* Least effective at screening/measurement

*** Most effective at screening/measurement

$ Smallest capital cost

$$$ Largest capital cost 

Source: EPA’s Lessons Learned Study & Presentation to Energy Management, Workshop, 

Methane to Markets, Directed Inspection and Maintenance, Roger Fernandez, EPA, January 16, 

2007.

3.2.5 Target Components

All equipment components on process-, fuel- and waste-gas systems are potential 

sources of fugitive emissions. The types of components may include flanged and 

threaded connections (i.e., connectors), valves, pressure-relief devices, openended lines, blowdown vents (i.e., during passive periods), instrument fittings, 

regulator and actuator diaphragms, compressor seals, engine and compressor 

crankcase vents, sump and drain tank vents and covers. The amount of emissions 

from a leaking component is generally independent of the size of the component.

Furthermore, as previously mentioned, usually only the top 5 to 10 percent of 

leaking components account for 80 to 90 percent of the emissions.

For equipments in gas service, the most cost-effective types of components to 

target tend to be, in the order of decreasing cost-effectiveness: compressor seals, 

open-ended lines, pressure relief valves, regulators, and control valves. The least 

cost-effective components to target tend to be connectors and block valves. The 

priority and feasibility of repairing a given component will depend on the leak 

rate, value of the process fluid being lost, cost of repairs, life expectancy of the 

repair, and the value of various potential indirect factors such as avoiding safety, 
January 2007 Management of Fugitive Emissions 8

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health, and environment impacts, avoiding damage to the component, improved 

process reliability and better performance.

Storage tanks at production and processing facilities are potentially a significant 

source of emissions due to working or evaporation losses; particularly where 

intentional boiling or flashing losses occur. Other less recognized, and often 

unaccounted for, contributions to atmospheric emissions from storage tanks may 

include the following:

• Leakage of process gas or volatile product past the seats of drain or blowdown 

valves into the product header leading to the tanks.

• Inefficient separation of gas and liquid phases upstream of the tanks allowing 

some gas carry-through (by entrainment) to the tanks. This usually occurs 

where liquid volume (e.g., produced water) has increased significantly over 

time resulting in a facility’s inlet separators being undersized for current 

conditions.

• Piping changes which result in the unintentional placement of high vapour 

pressure product in tanks not equipped with appropriate vapour controls.

• Displacement of large volumes of gas to storage tanks during pigging 

operations.

Malfunctioning or improperly set blanket gas regulators and vapour control valves 

can result in excessive blanket gas consumption and, in turn, increased flows to 

the end control device (e.g., vent, flare or vapour recovery compressor). The 

blanket gas is both a carrier of product vapours and a potential pollutant itself 

(i.e., natural gas is usually used as the blanket medium for blanketed tanks at gas 

processing plants).

Leakage from components in oil or light hydrocarbon liquid service is usually 

easy to visually detect and often is well controlled by normal maintenance 

programs. However due to their low average leak rates, less substantive 

improvements in fugitive emissions reductions are expected for these 

components.

3.2.6 Monitoring Frequency

The equipment components most likely to leak should be screened most 

frequently. Studies indicate that components subject to vibration, high use, or 

temperature cycles are the most leak-prone. Operators should develop a DI&M 

survey schedule that achieves maximum cost-effective fugitive emissions

reductions yet also suits the unique characteristics and operations of their facility. 

Operators may choose to determine the frequency of follow-up surveys based on 

different factors such as anticipated life of repairs made during their previous 

survey, company maintenance cycle, and availability of resources. If subsequent 

surveys show numerous large or recurring leaks, the operator may chose to 

increase the frequency of follow-up surveys. These follow-up surveys may focus 

on components repaired during previous surveys, or on the classes of components 

identified as most likely to leak. Over time, operators can continue to fine-tune 
January 2007 Management of Fugitive Emissions 9

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the scope and frequency of surveys as leak patterns emerge. 4 Where the repair 

frequency is high, permanent leak detection system may be a more practical 

solution and should be considered.

Examples of leak monitoring frequencies for leak-prone components are provided 

under Appendix 1. Operators should design a frequency monitoring program best 

suited for its operations while ensuring maximum cost-effective fugitive 

emissions reductions.

3.2.7 Inaccessible Components

Inaccessible sources or components can be defined as equipment that is more than 

2 metres above a permanently available support surface or is cover protected or 

insulated (CCME 1993). This equipment is excluded from a DI&M program 

under this BMP. However, if these components are leaking and become 

accessible during facility shut-downs or turn-around, they should then be repaired.

3.2.8 Tagging Components

All leaking components should be flagged using a tag or an alternative method for 

identification purposes as well as to ensure that the component is repaired and that 

it will be given appropriate follow-up attention under the company’s DI&M 

program. This should assist in identifying the proper monitoring frequency for 

that specific component.

An example of a leaker tag is provided under Appendix II while Appendix III

provides an example of leak survey forms. Companies should determine the best 

format for flagging/identifying leaks as well as for leak surveys in accordance 

with the unique characteristics and operations of their facilities.

3.2.9 Leak Repairs

Decisions to repair or replace leaking components should be made on a case-bycase basis in consideration of health, safety, environmental, and economical

concerns. Where feasible, repairs or replacements should be done within 45 days 

from the time a leak is detected. Where a major shutdown is required to facilitate 

this work, or there are marginal economics for repairing the component, the repair 

or replacement may be delayed until the next planned shutdown, provided this 

does not pose any safety, health, or environmental concerns.

A leaking component need not be repaired if the component is shown to be 

uneconomical to repair and does not pose a safety, health, or environmental 

concern. In such cases, the components should remain tagged/identified and be rescreened at the next scheduled leak survey.

The economics of repairing a leak or replacing the components should be based 

on the market value of the process fluid being lost, the repair, the replacement 

cost, and the life expectancy of the applied solution. All leak repairs that have a 

simple payback period of less than 1 year based on the following equation should 

 

4

 Lessons Learned from Natural Gas Star Partners, Directed Inspection and Maintenance at gas processing plants 

and booster stations, EPA, October 2003.
January 2007 Management of Fugitive Emissions 10

At Upstream Oil and Gas Facilities

be deemed economical to repair and should be repaired as soon as possible but no 

later than 45 days:

Annual Leak Rate Gas ice

Cost of Control PBP

× Pr

=

Where,

PBP = payback period (years).

Cost of Control = direct repair or replacement costs + gas vented 

during repair + cost of lost production due to 

shutdown

Annual Leak Rate = amount of gas/vapour emitted directly to the 

atmosphere or that leaked into a vent or flare system 

which does not have vent or flare gas recovery.

Gas Price = current market price of the gas based on criteria 

specified by the EUB Directive 0605 or, for the 

midstream industry, the processing fee or margin 

received.

Components that have a payback period greater than 1 year should be reevaluated with the “Cost of Control” equal to direct repair or replacement cost 

only. If this analysis shows the repair or replacement is economic to do during a 

major shut down, it should then be scheduled for repair at the next shut down.

Where the payback period is greater than the anticipated life expectancy of the

repair or replacement, the component may be deemed uneconomic to repair or 

replace and supporting details of this cost evaluation shall be kept on file. Table 3

is provided as an indication of possible mean default life expectancies of 

component repairs that an operator may choose to use in the absence of official 

data on the life expectancy of the affected component.

Table 3. Default mean life of repairs for economic analysis 

of repair costs.

Source Category Mean Repair Life

(years)

Seals 1

Valve Covers 1

Variable Volume 

Pocket

1

Governor 1

Compressors - Reciprocating

Cylinder Head 1

Compressors – Centrifugal Seals 1

Connectors All 5

 

5

 The commodity price forecasts used in evaluations of conventional gas conservation projects (gas gathered, 

processed, and sold to market) will be the most recently published by Dobson Resource Management. 
January 2007 Management of Fugitive Emissions 11

At Upstream Oil and Gas Facilities

Table 3. Default mean life of repairs for economic analysis 

of repair costs.

Source Category Mean Repair Life

(years)

Open-Ended Lines All 2

Pressure Relief Valves All 2

Pumps Seals 1

Regulators All 5

Tank Fittings Hatches 1

Pressure Vacuum 

Valves

2

Valves Quarter-Turn 4

Rising Stem 2

Vents All 1

Sample calculations for payback periods are presented in Appendix IV.

3.2.10 Personnel Training

Proper personnel training should be part of the DI&M program. This training is 

needed to ensure that the program achieves the best results. 

3.2.11 Primary Calibrations and Field checks

All instruments used to detect and measure leaks should be factory serviced or 

serviced by a factory authorized technician and should be calibrated regularly as 

per the specification of the manufacturer or whenever problems arise.
January 2007 Management of Fugitive Emissions 12

At Upstream Oil and Gas Facilities

4 Inspection, Monitoring & Record-Keeping

Operators should have a record program to support the company’s DI&M system. 

Proper record keeping should assist in ensuring that leaking components are 

identified and repaired and that appropriate follow-up actions are implemented. 

This information will also assist in identifying the proper monitoring frequency 

for that component to achieve maximum cost-effective fugitive emissions

reductions while suiting the unique characteristics and operations of the facility.

Although it remains for each company to define its record keeping system, 

consideration should be given to the recording of the following information:

• Records of repairs made on leaking components, including leak repair 

frequency.

• The economic analysis performed on all leaking equipment components that 

have not been fixed on the basis that this is uneconomic to do and do not pose 

any safety, health, or environmental concerns.

Record keeping in support of a company’s DI&M program may be audited by the 

EUB to assess compliance with section 8.7 of the EUB Directive 060.
January 2007 Management of Fugitive Emissions 13

At Upstream Oil and Gas Facilities

5 Corporate Commitment

Corporate commitment should entail full management support including adequate 

funding and resource allocation.

Components that are initially tight may leak, and leaks, once fixed, may reoccur. 

Consequently, the reduction of fugitive emissions requires a dedicated ongoing 

commitment.
January 2007 Management of Fugitive Emissions 14

At Upstream Oil and Gas Facilities

6 Appendices

The information provided in the following appendices is included as guidance

only. Operators may elect to implement other approaches to develop their DI&M 

program.
January 2007 Management of Fugitive Emissions 15

At Upstream Oil and Gas Facilities

7 References Cited

Aikin, J.A. 1992. Valve Packing and Live-Loading Improvements. Valve Magazine. Valve 

Manufacturers Association of America. Washington, D.C. v4, n3. pp. 21-26, 52.

American Industrial Hygiene Association. 1993. Odor Thresholds for Chemicals With 

Established Occupational Health Standards. Stock No. 108-EA-89. Fairfax, Virginia.

American Petroleum Institute. 1989. Standard 610: Centrifugal Pumps for General Refinery 

Service. 7

th Edition. Washington, D.C. Order No.822-6100. pp. 139.

American National Standards Institute. 1988. Standard B-16.5: Piping Flanges and Flange 

Fittings. New York, NY. pp. 172.

American National Standards Institute. 1993. Standard B-31.3: Chemical Plant and Petroleum 

Refinery Piping. New York, NY. pp. 335.

American National Standards Institute. 1991. Standard B-73.1M: Specification for Horizontal 

End Suction Centrifugal Pumps for Chemical Process. New York, NY. Order No. J01991.

American National Standards Institute. 1991. Standard B-73.2M: Specification for Vertical InLine Centrifugal Pumps for Chemical Process. New York, NY. Order No. J04991.

American Society of Mechanical Engineers. 2004. ASME Boiler and Pressure Vessel Code: An 

American National Standard. Section VIII - Rules for Construction of Pressure Vessels, Division 

1. New York, NY.

Battilana, R.E. 1989. Better Seals Will Boost Pump Performance. Chemical Engineering 

Progress. v85, n7. pp. 106-114. (July, 1989)

Brestel, R., W. Hutchens, and C. Wood. 1992. Technical Monograph 38: Control Valve Packing 

Systems. Fisher Controls International, Inc. Marshalltown, Iowa. pp. 22.

Lipton, S. 1992. Reduce Fugitive Emissions Through Improved Process Equipment. Chemical 

Engineering Progress. v88, n10. pp. 61-68. (Oct., 1992)

The Canadian Council of Ministers of the Environment. 1993. Environmental Code of Practice 

for the Measurement and Control of Fugitive VOC Emissions from Equipment Leaks. Prepared 

by the National Task Force on The Measurement and Control of Fugitive VOC Emissions from 

Equipment Leaks. Ottawa, ON. pp. 35.

U.S. Environmental Protection Agency. 1988. Protocols for Generating Unit-specific Emission 

Estimates for Equipment Leaks of VOC and VHAP. Research Triangle Park, NC. Report No. 

EPA-450/3-88-010.

U.S. Environmental Protection Agency. 1980. VOC Fugitive Emissions in Synthetic Organic 

Chemicals Manufacturing Industry - Background Information for Proposed Standards. Report 

No. EPA-450/3-80-033a. Table 4-7. Page 4-24.
January 2007 Management of Fugitive Emissions 16

At Upstream Oil and Gas Facilities

U.S. Environmental Protection Agency. 2003. Lessons Learned from natural Gas Star Partners, 

Directed Inspection and Maintenance at gas processing plants and booster stations.

Wright, J.B. 1993. Avoid Valve Leaks. Chemical Engineering Progress. v89, n6. pp. 62-64. 

(June, 1993).
January 2007 Management of Fugitive Emissions 17

At Upstream Oil and Gas Facilities

Appendix 1 Table 4. Examples Of Leak Monitoring Frequencies 

For Leak-Prone Equipment Components 

Table 4. Examples of leak monitoring frequencies for leak-prone equipment 

components, presented by component category and type

Source

Category

Type of 

Component

Service

(sweet gas, light 

liquid)

Frequency

Control Valves Gas/Vapour/LPG Annually

Block Valves –

Rising Stem

Gas/Vapour/LPG Annually

Block Valves –

Quarter Turn

Gas/Vapour/LPG Once every 5 years

Compressor Seals1 All Quarterly

Pump Seals1 All Quarterly

Pressure Relief 

Valves

All Annually

Open-ended Lines All Annually

Emergency Vent1,2 All Annually

Process 

Equipment

Blowdown Systems 

1,2

All Quarterly

Tank Hatches1 Vapour All Quarterly

Collection 

Systems

Pressure-Vacuum 

Safety Valves1

All Quarterly

1 Alternatively, institute a predictive maintenance program to monitor seals performance

2 Emergency vents and blowdown systems should be screened during periods when relief or blowdown 

events are not occurring to determine the amount of leakage into these systems.
January 2007 Management of Fugitive Emissions 18

At Upstream Oil and Gas Facilities

Appendix 2 Sample Leaker Tag

Leak repaired c Date __________________
January 2007 Management of Fugitive Emissions 19

At Upstream Oil and Gas Facilities

Appendix 3 Appendix III – Leak Survey Forms

LEAK RATE MEASUREMENTS Page ___ of ___

Site Name: Date

Operating 

Company:

Technicians:

Location:

Survey Contractor:

Process Unit Component Information

Name/Identification Process Stream

Code

Type Leaker

Tag No.

Process

Tag 

No.

Type

Type Odourized

Size Measurement

Method

THC

Leak 

Rate

(m3/h)

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N

Y/N
January 2007 Management of Fugitive Emissions 20

At Upstream Oil and Gas Facilities

Direct Measure Datasheet

Location:

Date:

Source Data Measurement Data

Tag

No.

Type of

Compone

nt

Size Process Unit Meter 

Type

Initial 

Volume

Final 

Volume

Time Temp

(C)

Pressure

(kPa)

Comments

CV – Control Valve

NV – Needle Valve

BV – Ball Valve

GBV – Globe Valve

GTV – Gate Valve

PV – Plug Valve

BFV – Butterfly Valve

MW – Manway

PRV – Pressure Relief Valve

O – Open-Ended Line

PR – Pressure Regulator

R - Regulator

GOV – Govenor

PIG – Pig Trap Cover

FC – Filter Cover

VC – Valve Cap

C - Coupling

F – Flange

T – Threaded Fitting

TB – Tube Fitting

PS – Pump Seal

CS – Compressor Seal

SW/PG – Sweet Process Gas

SR/PG – Sour Process Gas

FG – Fuel Gas

S – Sales Gas

P – Propane

C2 - Ethane

C – Condensate

MP – Multipahse

O – Oil

CO – Crude Oil

AG – Acid Gas
January 2007 Management of Fugitive Emissions 21

At Upstream Oil and Gas Facilities

GAS SENSOR CALIBRATION RECORD Page ___ of ___

Site Name: Date

Operating Company: Technicians:

Location:

Industry Sector:

Facility Type:

Date of Last Field Calibration Checks

Calibration Zero Check Span Check Units of 

Measure

Device Manufacturer Serial No.

Factory Office

Day Time

Reading Actual Reading %Error
January 2007 Management of Fugitive Emissions 22

At Upstream Oil and Gas Facilities

FLOW METER CALIBRATION RECORD Page ___ of ___

Site Name: Date

Operating Company: Technicians:

Location:

Industry Sector:

Facility Type:

Date of Last Field Calibration Checks

Calibration Zero Check Span Check

Device Manufacturer Serial No.

Factory Laboratory

Day Time

Reading Refere

nce

Reading %Error

Units of 

Measure
January 2007 Management of Fugitive Emissions 23

At Upstream Oil and Gas Facilities

Appendix 4 Economic Analysis

Table 5 presents example calculations for determining the simple payback period of individual 

leak repairs using the equation presented in Section 3.2.8. As indicated in the table, the simple 

payback period is calculated as the estimated repair costs (column C) divided by the product of 

the leak rate (column A) and the net gas value (column B). For the examples given, the net gas 

price is taken to be $4.0/GJ or $0.1496/m3, which, in this case, is the market value of the gas 

(i.e., determined from the Chenery-Dobson Resource Management Ltd. Survey of Hydrocarbon 

Price Forecasts Utilized by Canadian Petroleum Consultants and Canadian Banks). The effect of 

discount rates and inflation rates are neglected for simplification purposes.
January 2007 Management of Fugitive Emissions 24

At Upstream Oil and Gas Facilities

Table 5. Sample calculations of the simple payback period for individual leak repairs. 

Tag 

ID

Process Unit / 

Location

Component 

Type

Nominal

Size 

(Inches)

Stream

Type

Hydrocarbon 

Leak Rate 

(m3/hr)

Hydrocarbon 

Leak Rate

(103 m3/y)

(A)

Net Value

of Lost Gas

($/103 m3)

(B)

Estimated 

Repair 

Cost

($)

(C)

Default

Repair 

Life 

(y)

Payback 

Period 

(y)

(C/A/B)

1982 Desiccant Dehydrator Open Ended 

Line

0.5 Regen. 

Gas

0.0046 0.0402 149.60 60 2 10.0

1985 Desiccant Dehydrator Regulator 0.5 Dry Gas 0.0050 0.0437 149.60 175 5 26.8

1986 Desiccant Dehydrator Plug Valve 12 Dry Gas 0.8326 7.2934 149.60 480 4 0.4

1987 Desiccant Dehydrator Gate Valve 0.75 Dry Gas 0.0045 0.0393 149.60 60 4 10.2

1988 Desiccant Dehydrator Open Ended 

Line

0.5 Dry Gas 0.0812 0.7111 149.60 60 2 0.6

1990 Desiccant Dehydrator Flange 8 Wet Gas 0.0010 0.0088 149.60 100 2 76.0

1991 Desiccant Dehydrator Gate Valve 8 Wet Gas 0.0046 0.0407 149.60 353 2 58.0

1992 Desiccant Dehydrator Flange 8 Wet Gas 0.0026 0.0228 149.60 100 2 29.3

1993 Desiccant Dehydrator Ball Valve 0.5 Wet Gas 0.0028 0.0241 149.60 60 4 16.6

1995 Desiccant Dehydrator Gate Valve 

(Control Valve)

8 Wet Gas 0.0090 0.0785 149.60 353 2 30.1

1996 Desiccant Dehydrator Gate Valve 

(Control Valve)

8 Wet Gas 0.0015 0.0129 149.60 353 2 182.9

1997 Desiccant Dehydrator Flange 8 Wet Gas 0.0036 0.0313 149.60 100 2 21.4

1998 Desiccant Dehydrator 3-Way Control 

Valve

8 Wet Gas 0.0021 0.0187 149.60 350 4 125.1

4087 Desiccant Dehydrator Threaded 

Connection

1 Wet Gas 0.0062 0.0544 149.60 30 2 3.7
January 2007 Management of Fugitive Emissions 25

At Upstream Oil and Gas Facilities

Appendix 5 Emissions Inventory From Method 21 Data

The leak screening data compiled using US EPA Method 21 (i.e., measurements of the 

vapour concentration at the leakage point on each component) may be used to estimate 

total fugitive emissions from the site for the purposes of developing an emissions 

inventory. These data should not to be used for quantifying the emissions from a single 

component for the purposes of conducting an evaluation of the economics of repairing or 

replacing the component since they do not provide sufficient accuracy for this purpose. 

The use of Method 21 data to calculate the emission rate from a single component may 

easily be in error by 2 to 3 orders of magnitude, while economic justification for not 

repairing a component should be based on a leak rate measurement accurate to ±25 

percent. For component quantification purposes see section 3.2.4.

Emissions may be estimated from US EPA Method 21 data by applying one of the 

following methods, presented in the order of increasing sophistication and accuracy:

• leak/no-leak emission factors,

• three-stratum emission factors,

• published leak-rate correlations, and

• unit-specific leak-rate correlations.

There is relatively little difference in the effort required to apply each approach once the 

screening data have been compiled. Consequently, it may be preferable to use the 

correlation approach since it gives the most reliable results. Simple spreadsheet or database 

application may be developed for this purpose.

5.1 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,

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

EFL = appropriate leaking emission factor for the source/service category of interest (see 

Table 6),

EF N = appropriate non-leaking emission factor for the components of type i in service j (see 

Table 6),

X

n +n

EF n + EF n

ER= N j

L N

L L N N

i, j

i, j

i j

• 









 • •

∑∑ •
January 2007 Management of Fugitive Emissions 26

At Upstream Oil and Gas Facilities

nL = 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,

nN = 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,

Ni, j = total number of components of type i in service j (i.e., all components screened plus those 

not screened),

X j = mass fraction of methane in the process stream 

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 UOG. However, the 

experience in other industries is this not is not necessarily true (Schaich and Stine, 1989). 

For example, 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 vapour analyzer used to screen for leaks.

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

facilities.

95% Confidence Limits

Source

Number

of 

Sources

Percent 

of 

Sources

Emissions

(kg/h/src) Lower Upper

Connector1 No Leak944512 98.79 0.0000338 0.0000271 0.0000406 

Leak10 556 1.21 0.01856 0.01465 0.02247

Block Valve2 No Leak 5907 96.02 0.0006132 0.0 0.001342 

Leak 245 3.98 0.03895 0.02728 0.05062

Control Valve3 No Leak 233 85.35 0.01006 0.007532 0.01259

Leak 40 14.65 0.07581 0.0 0.1706

PRV No Leak 63 33.87 0.0006471 0.0 0.001537 

Leak 123 66.13 0.3814 0.0 0.8673

Regulator No Leak 108 83.72 0.0000398 0.0000175 0.0000474 

Leak 21 16.28 0.01977 0.004751 0.03439

Orifice Meter4 No Leak 83 79.81 0.001925 0.0006846 0.003165

Leak 21 20.19 0.0088 0.004936 0.01286

Other Flow Meter5 No Leak 259 97.37 0.0000037 0.0000016 0.0000059 

Leak 7 2.63 0.0002064 0.0 0.0006932

Station or 

Pressurized

No Leak 27 26.47 0.0006213 0.0 0.001641

Compressor 

Blowdown System6

Leak 75 73.53 1.274 0.4989 2.049
January 2007 Management of Fugitive Emissions 27

At Upstream Oil and Gas Facilities

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

facilities.

95% Confidence Limits

Source

Number

of 

Sources

Percent 

of 

Sources

Emissions

(kg/h/src) Lower Upper

Compressor 

Blowdown System -

No Leak 4 26.67 0.000 0.0 0.0

Depressurized 

Reciprocating

Leak 11 73.33 3.200 1.245 5.155

Compressor 

Blowdown System -

No Leak 7 38.89 0.000 0.0 0.0

Depressurized 

Centrifugal

Leak 11 61.11 1.200 0.0 2.422

Open-Ended Line No Leak 179 27.88 0.0001127 0.0000249 0.0002006 

Leak 463 72.12 0.1158 0.05458 0.177

Instrument 

Controller7

No Leak ---- 0.00 ---- ---- ----

Leak 17 100.00 0.4681 0.09325 0.8429

Compressor Seal –

Reciprocating8

No Leak 5 13.89 0.00056 0.0 0.002115

Leak 31 86.11 0.7682 0.4865 1.049

Compressor Seal -

Centrifugal8

No Leak 1 4.77 0.0000075 ---- ----

Leak 20 95.23 0.8546 0.2469 1.462

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

---- No data available.

1 Includes flanges, threaded connections and mechanical couplings.

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

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

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

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

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

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

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

(i.e., these emissions must be calculated separately).

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

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

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

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

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

medium.

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

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

9 Non-leaking components with screening values of less than 10 000 ppm.

10 Leaking components with screening values of 10 000 ppm or greater.
January 2007 Management of Fugitive Emissions 28

At Upstream Oil and Gas Facilities

5.2 Three-stratum Emission Factors

Use of the three-stratum factors offers a further increase in rigour and reliability from use 

of the leak/no-leak factors. The sources are categorized based on three ranges of screening 

values: 0 to 1 000 ppm, 1 001 to 10 000 ppm and over 10 000 ppm. The amount of 

emissions is estimated for each source category using the equation:

where,

EF1, EF2, EF3 = THC emission factors for sources with screening values in the range of 0 to 1 000 

ppm, 1 001 to 10 000 ppm, and over 10 000 ppm, respectively (see Table 7). 

n1, n2, n3 = Total number of sources surveyed that had screening values in the range of 0 to 

1 000 ppm, 1 001 to 10 000 ppm, and over 10 000 ppm, respectively.

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.

5.3 Published Leak-Rate Correlations

Leak-rate correlations provide a method for estimating the leak rates corresponding to 

individual screening values. The use of this approach is a considerable refinement over the 

available emission-factor methods in which constants are applied over discrete ranges of 

screening values.

The correlations are given by a two-constant relation of the form given below:

Log (ER) = B0 + B1 Log(SV) (5)

where:

B0, B1 = Model parameters as given in Table 8.

ER = Leak rate in (kg/h/source).

SV = Maximum screening value above background measured using a detector calibrated 

to methane (ppm). 

n +n +n

n EF +n EF +n EF ER= N

1 2 3

1 1 2 2 3 3

i, j

i j











 • • •

∑∑ •
January 2007 Management of Fugitive Emissions 29

At Upstream Oil and Gas Facilities

Table 7. Three-stratum emission factors for estimating fugitive equipment leaks at UOG facilities.

95% Confidence Limits

Source

Number

of 

Sources

Percent of 

Sources

Emissions

(kg/h/src) Lower Upper

Connector1<1000 44207 98.1 0.0000032 0.000003 0.0000033 

1000-10000

>10000

305

556

0.7

1.2

0.004480

0.01856

0.003623

0.01465

0.005337

0.02247

Block Valve2<1000 5803 94.3 0.0005027 0.0 0.001242 

1000-10000

>10000

104

245

1.7

4.0

0.006782

0.03895

0.003705

0.02728

0.009858

0.05062

Control Valve3<1000 167 61.2 0.000027 0.0000197 0.0000344

1000-10000

>10000

66

40

24.2

14.6

0.03544

0.07581

0.03020

0.0

0.04068

0.1706

PRV <1000 60 32.3 0.0002125 0.0000619 0.003632

1000-10000

>10000

3

123

1.6

66.1

0.009339

0.3814

0.0

0.0

0.04927

0.8673

Regulator <1000 10 26.3 0.0000127 0.0000099 0.0000155 

1000-10000

>10000

7

21

18.4

55.3

0.0004301

0.01977

0.0001985

0.004751

0.0006618

0.03439

Orifice Meter4<1000 67 64.4 0.000032 0.0000198 0.0000442

1000-10000

>10000

16

21

15.4

20.2

0.009850

0.0088

0.004703

0.004936

0.01500

0.01286

Other Flow Meter5<1000 258 97.0 0.000003 0.0000014 0.0000045 

1000-10000

>10000

1

7

0.4

2.6

0.0002000

0.0002064

----

0.0 

----

0.0006932

Station or Pressurized <1000 25 24.5 0.000023 0.000001 0.000045

Compressor

Blowdown System6

1000-10000

>10000

2

75

2.0

73.5

0.008100

1.274

----

0.4989 

----

2.049 

Compressor 

Blowdown System -

<1000 4 26.67 0.0 0.0 0.0

Depressurized 

Reciprocating

1000-10000

>10000

----

11

----

73.33

 ----

3.200

 ----

1.245

 ----

5.155

Compressor 

Blowdown System -

<1000 7 38.89 0.0 0.0 0.0

Depressurized 

Centrifugal

1000-10000

>10000

----

11

----

61.11

 ----

1.200

 ----

0.0

 ----

2.422

Open-Ended Line <1000 173 27.0 0.0000288 0.0000161 0.0000415

1000-10000

>10000

6

463

0.9

72.1

0.002533

0.1158

0.0001628

0.05458

0.004904

0.1770

Instrument Controller7<1000 ---- ---- ---- ---- ----

1000-10000

>10000

----

17

----

100.0

----

0.4681 

----

0.09325 

----

0.8429 
January 2007 Management of Fugitive Emissions 30

At Upstream Oil and Gas Facilities

Table 7. Three-stratum emission factors for estimating fugitive equipment leaks at UOG facilities.

95% Confidence Limits

Source

Number

of 

Sources

Percent of 

Sources

Emissions

(kg/h/src) Lower Upper

Compressor Seal - <1000 5 13.9 0.00056 0.0 0.002115

Reciprocating81000-10000

>10000

----

31

----

86.1

----

0.7682 

----

0.4865 

----

1.049 

Compressor Seal - <1000 1 4.8 0.0000075 ---- ----

Centrifugal81000-10000

>10000

----

20

----

95.2

----

0.8546 

----

0.2469 

----

1.462 

Source: Ross and Picard (1996), Table 7, page 23.

---- No data available.

1 Includes flanges, threaded connections and mechanical couplings.

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

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

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

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

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

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

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

these emissions must be calculated separately).

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

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

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

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

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

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

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

Table 8. Correlation parameters for estimating leak rates from equipment 

components at UOG facilities.

Source B0 B1 Number of 

Sources

Correlation (R2)

Connectors1-5.9147 0.75 305 0.71

Valves1-6.0399 0.83 369 0.67

Open-Ended Lines2-6.9586 1.28 64 0.44

Pressure Relief Devices2-5.1479 0.91 29 0.46

Pressure Regulators2-6.4821 0.91 35 0.58

1 The correlation for this source is based on screening and bagging data collected by Ross and Picard (1996), by 

Environment Canada (Williams, 1996), and data collected for U.S. EPA (1995).

2 The correlation for this source is based on screening and bagging data collected by Ross and Picard (1996) and 

Environment Canada (Williams, 1996).
January 2007 Management of Fugitive Emissions 31

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The values of the correlation constants for application to the Canadian UOG 

industry are summarized in Table 8.

The basic approach involves processing each individual screening value as 

follows and then aggregating the results to determine total emissions:

• On-scale Screening Values - Components that have screening values within 

the detection range of the screening instrument and more than 1 ppm above 

background are assessed using equation (5). Do not average screening values 

and then enter the result into the correlation to estimate emissions.

• Zero Screening Values - Components with screening values of 1 ppm or less 

above background are assigned a default emission rate in accordance with 

Table 9. If the instrument has a minimum detection limit greater than 1 ppm, 

the default zero values in Table 8 do not apply. In this situation, all zero 

screening values should set to one-half the instrument's minimum detection 

limit and then processed using equation (5).

• Off-scale or Pegged Values - Components with off-scale or pegged values 

are either assigned the appropriate average emission rate for a leaking 

equipment component (i.e., see Table 6 or 7), or are bagged to determine the 

actual mass emission rate.

The level of uncertainty in the total emissions estimated by this approach is a 

function of the number of components considered and the portion that are pegged 

sources. For a single component, the uncertainty may be as high as a factor of 

100. The uncertainty tends to decrease almost exponentially with the number of 

components. A facility would need to have at least 3000 components before the 

uncertainty would be below 50 percent for a 90 percent confidence level. Even 

more components would be required if there are pegged sources. However, very 

few facilities will have even 3000 components. The best overall accuracy for a 

facility that, generally, can be expected from use of the correlation method, 

including use of pegged emission factors, is about ±300 percent (telephone 

communication with Mr. R.A. Lott at Gas Research Institute, June 19, 1999).
January 2007 Management of Fugitive Emissions 32

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Table 9. Default zero emission rates1.

Source Type Default-Zero Emission Rate2

(kg/h/source)

Gas valve 6.6 (10-7)

Light liquid valve 4.9 (10-7)

Light liquid pump37.5 (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.

5.4 Unit-Specific Leak-Rate Correlations

Some companies may wish to develop unit-specific leak-rate correlations to 

achieve better accuracy for their particular operations. The benefit in doing this is 

often questionable since, in theory, the relationship between a properly corrected 

screening value and the emission rate for a given component type and service is 

the same across all industries. Nonetheless, where there is some doubt, various 

nonparametric statistical methods may be applied to determine the validity of the 

available correlations. This involves comparing a set of predicted emission rates 

to actual measured values for a given source type and service category. The sign 

or a suitable rank-sum test may be applied to determine if the two data sets are 

statistically different (see almost any statistical analysis text). To apply the sign 

test, try using a sample size of four. If all four measured values are consistently 

greater than or consistently less than the predicted values, then the selected 

correlation probably does not provide reasonable emission estimates for the given 

application.

To develop a leak-rate correlation it is necessary to compile a reasonable number 

of data points to cover the desired screening range for each target source/service 

category. Each data point must comprise an actual measured mass emission rate 

and corresponding screening value. U.S. EPA (1995) suggests using a minimum 

of six random data points for each of the following ranges that the correlation will 

span: 1 to 100 ppm, 101 to 1 000 ppm, 1 001 to 10 000 ppm, 10 001 to 100 000 

ppm and 100 001 to 1 000 000 ppm. The collected data are fit to equation (5) 

using a least-squares regression analysis. For further details on developing a unitspecific leak-rate correlations, refer U.S. EPA's (1995) protocol for equipment 

leak emission estimates.
January 2007 Management of Fugitive Emissions 33

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Furthermore, use of a portable organic vapour analyzer is much slower than other 

leak detection techniques; especially if screening data are being recorded for each 

component when an analyzer is used, and other methods can eliminate this need. 

For example, use of bubble tests with no data recording, just tagging of leaking 

components, is at least 3 to 4 times faster than application of US EPA Method 21 

using an organic vapour analyzer.
January 2007 Management of Fugitive Emissions 34

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Appendix 6 Component-Specific Control Options

This appendix presents potential options for eliminating or controlling chronic 

leaks for each of the following common types of equipment components, 

respectively:

• Reciprocating compressors

• Centrifugal compressors

• Valve stem packing systems

• Sewers and drains

• Pump seals

• Flanged and threaded connections

• Pressure relief devices

• Open-ended valves and lines

• Sampling points

6.1 Reciprocating Compressors

Packings are used on reciprocating compressors to control leakage around the 

piston rod on each cylinder. A schematic diagram of a conventional packing 

system is presented in Figure 2. Typically, the distance piece is either left open 

with the vent piping connected directly to the packing case, or the distance piece 

is closed and the vents may be connected to both the packing case and the 

distance piece. The packing and distance piece vents are commonly routed outside 

the building to the atmosphere if the process gas is sweet, but should be connected 

to an emission controlling vent system if the gas is sour. The latter approach 

provides continuous treatment of any emissions and allows for more convenient 

scheduling of any required maintenance to the packing system.

6.1.1 Vent Monitoring Systems

It is good practice to install instrumentation on the vent lines to indicate excessive 

vent rates and the need for maintenance. A sensitive rotameter, an orifice and 

pressure differential indicator providing flow indication, or a temperature element 

may be used depending on the application.

6.1.2 Emission-Controlling Vent Systems

Where emission-controlling vent systems are employed they should be designed 

to minimize the potential for either the flow of process gas through the distance 

piece into the compressor crank case, or air ingress to the vent system through the 

nose of the packing case or through the air breather on the crank case and past the 

wiper packing leading to the distance piece (depending on the location of the vent 

connections). Both conditions pose a potential explosion hazard. Additionally, the 

leakage of process gas into the crank case could possibly result in contamination 

of the lubricating oil or corrosion problems (especially if the process gas contains 

hydrogen sulphide).
January 2007 Management of Fugitive Emissions 35

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Figure 2. Schematic diagram of a piston-rod packing-case system on a reciprocating 

compressor.
January 2007 Management of Fugitive Emissions 36

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There are three basic types of emission controlling vent systems that may be 

considered: low pressure vapour recovery units (e.g., for compressor fuel), 

incinerators, or flares. Vent gas capture may be achieved by using a small rotary 

vane or liquid ring vacuum pump or an ejector installed to maintain a vacuum on 

the vents and compress the vent gas for appropriate disposition. The gas can 

sometimes be used in the fuel gas system if it is compressed dry or it can be 

routed to a low pressure flare. The pump is usually run on a continuous basis and 

at a constant speed. If there is no vent gas flow, the pump produces maximum 

vacuum on the vent lines. To reduce the risk of pulling air into the vent gas 

capture system and creating an explosive atmosphere in these situations, a sweet 

natural gas purge controlled using a vacuum regulator may be used to limit the 

maximum vacuum produced.

If there is not a continuous low pressure flare system on site and recovery of the 

vent gas is not practical, a small natural draft incinerator unit or shrouded groundlevel flare may be most suitable. A vacuum pump is not usually needed with these 

devices if piping distances are not too great since the natural draft of the selected 

combustion unit will provide a slight vacuum. The incinerator or flare may be 

equipped with an electronic ignition system to maintain the pilot. The pilot 

consumes a small amount of fuel gas. A solar panel and battery may be used to 

power the ignition system if there is no electricity available on site.

With compressors using lubricated packings it is important to consider that the 

vented and drained fluids from the packing and distance piece will contain some 

oil. Small pressure vessels (drain pots) should be fitted on the vent and drain lines 

to capture these liquids. Appropriate design and operational practices must be 

followed to prevent gas release when these liquids are drained. If a closed process 

drain system is available which has a receiver vented to flare, this can be used. If 

a closed drain system is not available and it is a sweet application, the liquids may 

be injected into the flare header if the flare system is designed to accept nonvolatile liquids. Fuel gas or an inert supply gas can be used to blow liquids up to 

the flare header and the oil eventually accumulates in the knock-out drum. 

Injecting sour lubricating oil into the flare system is not recommended, especially 

high viscosity "tallow" based oils used for cylinder/packing lubrication, as this oil 

will eventually plug up the system.

6.1.3 High Performance Packing Systems

The effective life of packing systems can be increased by using more refined 

designs with tighter tolerances, smoother finishes, o-rings between packing cups 

and lapped cup surfaces. These changes should, however, be coupled with 

improved rod surfaces and alignment and increased packing case maintenance to 

be effective.

6.1.4 Barrier Fluid Systems

A barrier fluid system is an add-on control that is used in combination with an 

emission controlling vent system. Its purpose is to prevent leakage beyond the 
January 2007 Management of Fugitive Emissions 37

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vent connections on the packing case or distance piece. This reduces or eliminates 

the need to maintain a constant vacuum on the vent system, and possibly the need 

to compress the vent gas. A barrier fluid system serves no useful purpose if the 

vents discharge directly to the atmosphere.

Barrier fluid systems should include a means for monitoring barrier fluid and vent 

flow, pressure, and temperature which can aid in predicting packing failures. If a 

higher than normal flow of barrier fluid is required to maintain barrier pressure or 

if high vent flow occurs, or there is a loss of pressure then a need for packing 

maintenance is indicated.

The barrier is created by introducing a pressurized chamber between the vent 

connection and the nose of the packing mechanism or distance piece, and passing 

a continuous supply of an inert fluid (typically nitrogen, if it is available, or oil 

from the cylinder lubricator) through this void. The chamber is formed and sealed 

using side loaded packing rings. The pressure of the purge fluid is set so that any 

leakage that may occur will be from the barrier chamber (i.e., into the vent system 

and out the nose of the packing, partition or wiper case), rather than into it. 

Consequently, only inert purge fluid is leaked and not process gas.

A barrier fluid system may be easily retrofit to any reciprocating compressor; 

although, some machining work will be required if there are no purge 

connections. API Specification 618 requires that a purge connection and side 

loaded seal rings be provided at the following: (1) primary cylinder packing, (2) 

the wiper packing, and (3) at the partition packing where a two compartment 

housing (distance piece) is used between the cylinder and the crank case.

6.1.5 Purge Gas Systems

In sour applications, it is good practice to purge sweet natural gas through the 

packing case, intermediate section, and wiper section to prevent sour gas from 

entering the crank case. To do this a vacuum pump is installed on the "cylinder" 

distance piece, and purge gas is admitted to the "frame" side distance piece.

6.1.6 Unit Shutdown Practices

Leakage into unit blowdown systems can be a significant source of fugitive

emissions from compressors. The amount of leakage is greatest when the 

compressor has been depressurized promoting leakage past the seats of the 

upstream and downstream unit isolation valves into the unit blowdown system. 

When the unit is left pressurized, leakage is only promoted past the seat of the 

unit blowdown valve. Thus, it is generally good practice to leave compressors 

pressurized when they are not running if this can be tolerated. If the compressor is 

in sour service, a short shutdown leaving the compressor pressurized is acceptable 

provided that the packing is not leaking excessively, and the vent is tied into a low 

pressure sour vent system. For longer shutdowns, the compressor should be blown 

down.

In sweet applications, the compressor can remain pressurized, but this should be 

reviewed on a case-by-case basis to ensure that the correct packing arrangement is 

installed.
January 2007 Management of Fugitive Emissions 38

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6.1.7 Static Packing Systems

If compressors are left pressurized when shut down, emissions from the 

compressor seals may be eliminated during those periods by installing a static 

packing system to effect a seal around the piston rod after the compressor is 

stopped. This helps contain the gas in the compressor cylinders and eliminates the 

need to maintain barrier gas flow when the compressor is stopped. Leakage from 

cylinder gaskets and unloader glands can still occur. The emissions during 

operation are unaffected except that space taken up by the static packing may 

dictate that a less sophisticated running packing be used.

A static packing system replaces some cups in the packing case (it is usually 

necessary to lap the case). It comprises a conformable seal made of relatively soft 

rubber or teflon. The seal is brought into contact with the compressor rod by 

pressurized gas when the compressor is stopped. The amount of pressure required 

to actuate the seal is normally about half of the pressure in the cylinder; although, 

this may be higher. When the actuating pressure is lowered, the seal is released 

and the compressor may be restarted.

Static packing systems are not applicable to all compressors, (usually because of 

space and design limitations).

6.1.8 Valve Cap Leakage

Leakage past the valve caps, as depicted in Figure 2, is really only a problem with 

improperly specified O-Rings (i.e., due to explosive de-compression), or where 

lead or aluminum seals are used in lieu of O-Rings (such as EI, or IR 

compressors).

6.2 Centrifugal Compressors 

Centrifugal compressors generally require shaft end seals between the compressor 

and bearing housings. Face contact oil lubricated mechanical seals or oil ring 

shaft seals are commonly used in hydrocarbon services. Dry gas shaft seals are 

frequently applied in many process and natural gas services and are the preferred 

choice for centrifugal compressors due to their lower leakage potential.

There are several options for reducing atmospheric emissions from the seals on 

centrifugal compressors: emission controlling vent systems (degassing drum vent 

control) for mechanical contact and oil film seals, dry gas seals and pressurized 

motor drive compressors.

6.2.1 Emission-Controlling Vent Systems Used with 

Conventional Seals

Face contact seals use two sealing rings held in close contact by a spring 

mechanism balanced with fluid pressures from the process gas and seal oil. An oil

ring seal uses a journal type ring which is sealed with pressurized and circulating 

oil. Both oil lubricated face contact and oil film seals, often arranged in the double 

configuration, use oil at a pressure higher than the process gas pressure. They 

provide a positive seal from gas leakage along the shaft to the atmosphere; 

however, other emissions are associated with the system.
January 2007 Management of Fugitive Emissions 39

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Some oil leaks inward through the seal and is collected in drain traps before being 

returned to the reservoir. Gas from the traps should be routed to an emission 

controlling vent system or back to the compressor suction. Any installations 

which vent the traps directly to atmosphere will have very high emissions and 

losses of process gas. The vent on lube oil degassing drums should therefore be 

tied in to an emission-controlling vent gas system provided this does not impose 

excessive backpressure on the degassing drum and lube oil reservoir.

6.2.2 Dry Gas Seals

Dry gas seals generally offer substantially reduced emissions compared to wet 

seal systems depending on the vent gas controls provided. Additionally, when 

properly applied, gas seals often yield both capital and operating cost savings over 

conventional oil lubricated seals. The capital savings are due to the simplification 

of the oil system by deletion of the seal oil part of the system. Operational savings 

can be realized in services where clean seal gas is available due to the longer 

running life of the essentially non-contacting seals.

Dry gas seals operate without oil. The seal has two precision machined sealing 

plates, usually one of silicon carbide or tungsten carbide and one of carbon. The 

seals are separated by clean, filtered seal gas which is used to create a pressure 

dam effect involving radial or spiral groves in one seal face. Due to very close 

running clearances, leakage rates are very low. Per seal face set leakage rates of 

about 0.5 kg/h can be expected, depending on the seal size and pressure 

differential.

The pressure differential across the seal must be maintained or the hydrodynamic 

forces will not separate the faces. High vent back-pressure can therefore cause 

seal failure. To prevent loss of this pressure differential in applications involving 

single seals and low operating pressures, the outer seal vent is commonly routed 

to atmosphere at a safe location. The outer seal chamber is typically purged with 

nitrogen to prevent local discharge to atmosphere.

A tandem gas seal arrangement is available. The tandem arrangement provides 

protection in the event the inboard seal fails, and it is becoming the minimum 

standard for high pressure applications with flammable gases. The inter-seal vent 

can be routed to an appropriate emissions controlling vent system. Emissions are 

still typical at the outer seal vent.

6.3 Valves

There are two main locations on a typical valve where leakage may occur: (1) 

from the valve body and around the valve stem, and (2) past the valve seat. The 

latter potential source of emissions is only an environmental concern if the line 

downstream of the valve is open to the atmosphere, and if so, it is classified as an 

open-ended line.

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

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

for manual operation, or an actuator for automatic control. The stem, itself, may 
January 2007 Management of Fugitive Emissions 40

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be operated through either a sliding/rising or rotary motion depending on the type 

of valve.

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

packing material around the stem and the pressure of the process fluid. Over time 

the gland gradually looses some of the packing material due to extrusion and wear 

and must be tightened to maintain a proper seal. At some point, complete 

repacking of the gland is required.

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

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

control, bad seating and possibly stalled conditions. It can also damage the 

packing and reduce its life.

Rotary or quarter-turn valves where stems turn 90o (e.g., plug, ball or butterfly 

valves) tend to be easier to seal than sliding-stem valves (e.g., gate or globe 

valves). This is because quarter-turn valves have less packing-to-shaft travel 

distance for each stroke of the valve, and therefore, less packing wear (Brestel et 

al., 1992). Additionally, quarter-turn valves have less of a tendency to draw dust 

and other abrasives into the packing gland during their operation. Wear on the 

stem packing is approximately 10 percent of sliding-stem valves. Leak 

frequencies and average leak rates for quarter turn valve are less than half of that 

for rising stem valves and only a quarter of that for gate valves in particular. 

Accordingly, where practicable to use, quarter-turn valves should be the preferred 

choice for manual and automated on/off applications in gas, LNG or LPG service.

For demanding service applications (e.g., vibration or thermal cycling) where leak 

frequencies of less than 2 percent are not being achieved and the use of rotary or 

quarter-turn valves is not practicable, consideration should be given to using high 

performance packing materials and stem seal designs and such as live-loaded 

packings, bellows seals and dual packing with bleed or environmental monitoring 

ports.

Overall, graphite packing systems are reported to provide the best leak control. 

One graphite packing set at the outboard end is normally sufficient, with the 

intervening packing box volume filled with spacer rings (Lipton, 1992). Where 

preformed graphite rings are installed, braided end rings are necessary.

Polymeric packing may be quite acceptable in many undemanding service 

applications with temperatures below 200oC. Braided non-asbestos materials are 

reported to be less effective than the previous braided asbestos packing and are 

limited to applications with process temperatures below 150oC (Aikin, 1992). The 

problems are with the blocking agents and fibre size. The fibre sizes of the new 

materials are larger than that of asbestos, so voids between the fibres are larger. 

These voids are filled with various blocking agents, such as 

polytetrafluoroethylene (PTFE), which tend to extrude or burn off at high 

temperatures. In addition, the large fibres fracture at relatively low packing 

stresses (i.e., 27.6 MPa), and with relatively low numbers of stem stroking cycles. 

Consequently, they are subject to inherently high consolidation and therefore 

should be live-loaded and used with anti-extrusion rings.
January 2007 Management of Fugitive Emissions 41

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An important consideration in changing to alternate packing materials is the 

potential for an increase in the force needed to stroke the valve. It may be 

necessary to install larger handles or handwheels on manual valves, and more 

powerful actuators on the control valves. Additionally, the packing follower (or 

gland) bolts may not be capable of generating enough stress to compress the 

packing (Wright, 1993). The coefficient of friction of many asbestos replacement 

materials prevents normal packing in multiple ring packing boxes from stressing 

the lower rings to the level required for sealing (Wright, 1993).

The valve must be in good mechanical condition to ensure optimum packing 

performance and low emissions. The stem should be straight and unmarked 

(especially for control valves). The packing box should also be unmarked and any 

unused bleed-off holes should be plugged.

Extended packing housings may be required to accommodate some alternate 

packing materials.

Packing removal (for inspection and repacking) with a metal pick is laborious and 

frequently results in marring of the stem and packing box wall. Specially designed 

water picks are commercially available which are much faster and easier to use, 

and which do not mar the stem or wall services (Lipton, 1992).

Maintenance of static packing by adjusting gland bolts is required to assure 

emission control.

6.4 Sewers and Drains

The potential for oil to enter the process sewer system or any open drainage or 

storage systems should be minimized. Closed recovery system for drainage of 

equipment should be considered to reduce quantities of hydrocarbons being 

released into the open process sewers. This in turn will reduce emissions from 

sewer vents and from connected API separator and waste water treatment ponds.

6.5 Pumps

Excessive seal leakage is a direct symptom of the misapplication of a seal and 

improper operation of the seal or its associated rotating or reciprocating 

equipment. Few seals leak abnormally, and these can be readily identified and 

corrected. A strong correlation exists between the level of seal leakage and the 

mean time between failure (MTBF) of its associated equipment.

Mechanical seals should be the minimum standard for use on centrifugal pumps 

used in light hydrocarbon liquid service except where leakage from the pumps 

may pose an occupational health hazard (i.e., where the liquid contains large 

concentrations of benzene) or the pumped fluid has a specific gravity less than 0.4 

(because single and tandem seals may be inadequately lubricated by such fluids). 

The available options for reducing emissions from the base case of single 

mechanical seals are, in the general order of increasing cost and performance 

capabilities:

• Bellows Seals,

• Throttle Bushing with Vent Diversion,
January 2007 Management of Fugitive Emissions 42

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• Tandem Mechanical Seals,

• Double Mechanical Seals,

• Sealless Pumps,

• Gas Seals for Volatile Services, and

• Blow-cases Instead of Pumps.

Double seals are the best choice for maximum containment of the process fluid 

unless a vapour control system or sealless pumps are used. A double mechanical 

seal can be expected to reduce leakage to almost zero when operating properly. 

There are no direct or indirect increases in emissions associated with the use of 

this technology except leakage of the barrier fluid which is usually not a VOC or 

harmful substance. Some leakage of the barrier fluid into the product must be 

tolerated. Double seals may generate slightly more heat than tandem and single 

seals and additional cooling medium flow or auxiliary coolers may be required.

Sealless pumps are generally limited to single stage applications. Canned motor

and magnetic drive pumps are available in sizes up to approximately 500 kW, and 

50 kW, respectively.

Gas seals are not applicable to most pump services. Only very clean, volatile 

services such as propane are suitable.

A principal reason for using blow-cases is that they do not require electrical 

power; however they may offer potential for reduction of emissions in liquid 

moving applications. The only seals required are valve packings. There may be a 

potential for the application of blow-cases to other services where sealing is a 

chronic problem. Where blow cases are used the motive gas should be discharged 

to an emissions controlling vent system. A common application is on gas 

gathering systems for injecting low pressure condensate from a compressor 

suction drum into the pipeline at discharge pressure. Compressed natural gas is 

used as the motive gas. The expanded gas may be displaced back to the 

compressor suction at the end of the cycle.

If change out of a mechanical seal is called for, upgrading of the existing seal 

chamber with an enlarged-bore retrofit seal chamber, as specified in the ANSI B73 standard and API Standard 610, should be considered. Introduced in the mid1980’s, enlarged bore seal chambers with increased radial clearance between the 

mechanical seal and seal chamber wall, provide better circulation of liquid to and 

from seal faces. Improved lubrication and heat removal (cooling) of seal faces 

extend seal life and lower maintenance costs. Extensive field and laboratory 

evaluations have shown that, on average, seal life is doubled when a properly 

designed and applied seal is operated in an enlarged-bore seal chamber (Battilana, 

1989).

Reciprocating pumps have similar sealing problems to reciprocating compressors. 

The performance of the packing systems may be greatly enhanced by installing a 

barrier fluid system similar to that described for reciprocating compressors.
January 2007 Management of Fugitive Emissions 43

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6.6 Threaded and Flanged Connections

A properly installed and maintained mechanical coupling or threaded or flanged 

connection can provide essentially leak free service for extended periods of time. 

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

of the common causes are summarized in Table 10. For instance, it is not 

uncommon for some connections to be inadvertently left un-tightened following a 

facility turnaround or specific inspection and maintenance activity (especially on 

fuel gas piping). Most of the listed issues can be addressed by conducting leak 

checks immediately following any changes or adjustments to a connection.

The application of proper mechanical design standards and material specifications 

are necessary to ensure adequate performance of connectors under load conditions 

(see ANSI Standards B16.5 and B31.3 for flanges).

6.7 Pressure Relief Devices

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.

Table 10. Common causes of leakage from flanged and threaded connections.

Flanged Connections Threaded Connections

Thermal stress and cycles.

Incorrect or re-used gasket material.

Missing gaskets.

Misalignment of piping or flange faces.

Dirty or damaged flange faces.

Inadequate or non-uniform bolt stresses.

Improper tightening sequence.

External abuse.

Thermal stress and cycles.

Dirty, roughly cut or damaged threads.

Crossed threads.

Poor quality or no thread sealant used.

Misaligned piping.

Inadequate tightening of the connection.

External abuse.

It is good practice, where a relief or safety valve may require servicing between 

scheduled facility turnarounds, to install a block valve upstream of a relief system 

to facilitate early replacement or repair of the components. This use of an 

upstream block valve is allowed under most Boiler and Pressure Vessel Acts, 

provided the valve is normally car-sealed open.

In demanding service applications consideration may also be given to specifying 

the use of resilient valve seats (elastomeric o-rings), as they have superior resealing characteristics, or installing a rupture disk immediately upstream of the 
January 2007 Management of Fugitive Emissions 44

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relief valve. A pressure gauge or suitable telltale indicator is needed between the 

disk and the relief valve to indicate when the disk has failed (ASME, 2004). The 

rupture disk will shield the relief valve from corrosive process fluids during 

normal operation. If an overpressure condition occurs, replacement of the disk 

may be delayed until the next scheduled shutdown period. In the interim, 

protection against over-pressuring is provided by the relief valve. The rupture disk 

should have a set pressure that is slightly higher than that of the relief valve to 

help avoid simmering problems.

Relief valves should be connected to an emission controlling vent system where 

the process fluid is toxic (i.e., at sour facilities). Where relief valves are connected 

to a common vent system leakage is difficult to detect and, as a result, may lead to 

a significant level of waste and cause unnecessary emissions. Leakae into flare 

systems is considered to have a flaring efficiency of only 60 percent because the 

flare system is sized normally for emergency relief, and performs less efficiently 

at low flows (U.S. EPA, 1980).

6.8 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. 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 as 

follows: scrubber blowdowns, truck loading and unloading connections on storage 

tanks, instrument block valves where the instrument has been removed for repair 

or other reasons, manual methanol injection points on pipelines, drains, and purge 

or sampling points.

Fugitive emissions from these sources should be controlled by installing a stopper 

(for example, a cap, plug or blind flange) on open-ended valves, and a stopper or 

a second block valve on open-ended lines. If the open end of a line is easily 

accessible and in close proximity to the block valve, a stopper is usually the best 

solution. Otherwise, a second block valve should be installed. Where a stopper is 

used it should be chained so it is not lost or misplaced when temporarily removed 

for use of the valve or line. A swivel connection may be needed to allow easy 

removal and replacement of the stopper.

6.9 Sampling Points

Sampling systems are generally only relevant at gas transmission facilities, gas 

processing plants, and possibly some oil batteries. Routine sampling is not 

common at most other oil and gas field facilities. The potential for emissions from 

sampling activities is greatest where the sample (gas or liquid) is taken from a 
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pressurized source. The collection of liquid samples by dipping a tank is generally 

not a source of emissions if this is done carefully so there is no spillage.

Closed loop sampling is the primary method for controlling emissions from 

pressurized sampling points. This method returns purge fluid back to the process 

stream. Where this is not practicable, the purge material can be directed to the 

flare system.
January 2007 Management of Fugitive Emissions 46

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Appendix 7 US EPA Method 21

•••••••••••••••••••••••••••••••••••••••••••••••••••••••

EMISSION MEASUREMENT TECHNICAL INFORMATION CENTRE

NSPS TEST METHOD

•••••••••••••••••••••••••••••••••••••••••••••••••••••••

(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.

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 
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leak definition in a regulation is 10,000 ppm, then the allowable increase is surface concentration 

versus local ambient concentration would be 500 ppm based on the instrument meter readings.)

2.5 Response Factor. The ratio of the known concentration of a VOC compound to the 

observed meter reading when measured using an instrument calibrated with the reference 

compound specified in the applicable regulation.

2.6 Calibration Precision. The degree of agreement between measurements of the same known 

value, expressed as the relative percentage of the average difference between the meter readings 

and the known concentration to the known concentration.

2.7 Response Time. The time interval from a step change in VOC concentration at the input of 

the sampling system to the time at which 90 percent of the corresponding final value is reached 

as displayed on the instrument readout meter.

3. APPARATUS

3.1 Monitoring Instrument.

3.1.1 Specifications

a. The VOC instrument detector shall respond to the compounds being processed. Detector types 

which may meet this requirement include, but are not limited to, catalytic oxidation, flame 

ionization, infrared absorption, and photoionization. 

b. The instrument shall be capable of measuring the leak definition concentration specified in the 

regulation.

c. The scale of the instrument meter shall be readable to + or - 5 percent of the specified leak 

definition concentration.

d. The instrument shall be equipped with a pump so that a continuous sample is provided to the 

detector. The nominal sample flow rate shall 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.
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b. The instrument response time must be equal to or less than 30 seconds. The response time 

must be determined for the instrument configuration to be used during testing.

c. The calibration precision must be equal to or less than 10 percent of the calibration gas value.

d. The evaluation procedure for each parameter is given in Section 4.4.

3.1.3 Performance Evaluation Requirements.

a. A response factor must be determined for each compound that is to be measured, either by 

testing or from reference sources. The response factor tests are required before placing the 

analyzer into service, but do not have to be repeated at subsequent intervals.

b. The calibration precision test must be completed prior to placing the analyzer into service, and 

at subsequent 3-month intervals or at the next use whichever is later.

c. The response time test is required before placing the instrument into service. If a modification 

to the sample pumping system or flow configuration is made that would change the response 

time, a new test is required before further use.

3.2 Calibration Gases.

The monitoring instrument is calibrated in terms of parts per million by volume (ppm) of the 

reference compound specified in the applicable regulation. The calibration gases required for 

monitoring and instrument performance evaluation are a zero gas (air, less than 10 ppm VOC) 

and a calibration gas in air mixture approximately equal to the leak definition specified in the 

regulation. If cylinder calibration gas mixtures are used, they must be analyzed and certified by 

the manufacturer to be within + or - 2 percent accuracy, and a shelf 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 
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adjusted to the proper value, a malfunction of the analyzer is indicated and corrective actions are 

necessary before use.) 

4.3 Individual Source Surveys.

4.3.1 Type I - Leak Definition Based on Concentration. Place the probe inlet at the surface of 

the component interface where leakage could occur. Move the probe along the interface 

periphery while observing the instrument readout. If an increased meter reading is observed, 

slowly sample the interface where leakage is indicated until the maximum meter reading is 

obtained. Leave the probe inlet at this maximum reading location for approximately two times 

the instrument response time. If the maximum observed meter reading is greater than the leak 

definition in the applicable regulation, record and report the results as specified in the regulation 

reporting requirements. Examples of the application of this general technique to specific 

equipment types are:

a. Valves - Leaks usually occur at the seal between the stem and the housing. Place the probe at 

the interface where the stem exits the packing and sample the stem circumference and the flange 

periphery. Survey valves of multipart assemblies where a leak could occur.

b. Flanges and Other Connections - Place the probe at the outer edge of the flange-gasket 

interface and sample the circumference of the 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.
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4.3.2 Type II - "No Detectable Emission". Determine the ambient concentration around the 

source by moving the probe randomly upwind and downwind around one to two meters from the 

source. In case of interferences, this determination may be made closer to the source down to no 

closer than 25 centimetres. Then move the probe to the surface of the source and measure as in 

4.3.1. The difference in these concentrations determines whether there are no detectable 

emissions. When the regulation also requires that no detectable emissions exist, visual 

observations and sampling surveys are required. Examples of this technique are: (a) Pump or 

Compressor Seals - Survey the local area ambient VOC concentration and determine if 

detectable emissions exist. (b) Seal System Degassing Vents, Accumulator Vessel Vents, 

Pressure Relief Devices - Determine if any VOC sources exist upstream of the device. If such 

ducting exists and emissions cannot be vented to the atmosphere upstream of the control device, 

then it is presumed that no detectable emissions are present. If venting is possible 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 
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measurements by alternating between the known mixture and zero air. Calculate the response 

factor for each repetition and the average response factor. 

4.4.1.2 Alternatively, if response factors have been published for the compounds of interest for 

the instrument or detector type, the response factor determination is not required, and existing 

results may be referenced. Examples of published response factors for flame ionization and 

catalytic oxidation detectors are included in the 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.