# BEST MANAGEMENT PRAC TICE



# Management of Fugitive
Emissions at Upstream Oil and
Gas Facilities

January 2007

2007

- 00032100, 350

– 7 th Ave. S.W. Calgary, Alberta
Canada T2P 3N9 Tel (4 03) 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 natura l 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.

Re view 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

– Cl ea r stone 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 Engi neering Ltd., the Project Steering Committee, CAPP or its co

- funders.January 2007 Management of Fugitive Emissions At Upstream Oil and Gas Facilities 

### Table o f Contents

Section Page

Li st 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 Mon itoring 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 Append ices

................................ ................................ ................................ ................. 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

................................ .......................... 32January 2007 Management of Fu gitive Emissions At Upstream Oil and Gas Facilities Appendix 6 Component

- Specific Control Options

................................ .......................... 34

6.1 Recip rocating 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 Sys tems

................................ ................................ ............ 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 Conventiona l Seals 38

6.2.2 Dry Gas Seals

................................ ................................ .................... 39

6.3 Valves

................................ ................................ ................................ ............. 39

6.4 Sewers and D rains

................................ ................................ ......................... 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

................................ ................................ ....................... 46January 2007 Management of Fu gitive Emissions At Upstream Oil and Gas Facilities 

### List o f Tables

Table Page

1 Leak detection and measurement methods. 6

2 Summary of screening and measurement techniques 7

3 Default mean life of repair s for e con omic analysis of repair costs. 10

4

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

5

. Sample calculations of the simple payback per iod for individual leak repairs 24

6

. Leak/No

- leak emission factors for estimating fug itive 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 ca uses 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 35January 2007 Management of Fugitive Emissions i At Upstream Oil and Gas Facilities List o f Acr onym s

AENV

- Alberta Environment

API

- Am erican 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 Engineer s 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

- T

otal 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 CompoundJanuary 2007 Management of Fu gitive Emissions At Upstream Oil and Gas Facilities Acknowledgment

Special thanks are given to the follow ing 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. Chamb erland

- 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

- CanadaJanuary 2007 Manage ment of Fugitive Emissions iii At Upstream Oil and Gas Facilities Forward

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

the upstream oil and gas (UOG) industry. T he 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 P etroleum Technology Alliance of Canada (PTAC)

.

T he Canadian Association of Pet roleum 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 targe ting sources that are most likely to have larger volume emissions and which would be more cost effective to address. CAPP

and SEPA C

will incorporate improvement to emission factors into the best management practices document as they become available. 44) O nce 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 0 60 ( Upstream Petroleum Industry Flaring, Incinerating, and Venting) and in cost effectively manag ing the most likely sources of significant fugiti ve emissions

. The emissions of primary concern are methane (CH 4 ) 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

- effectiv e reductions in these emissions (e.g., through improved designs, D irected I nspection and M aintenance (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 an d 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 s pecific circumstances.January 2007 Management of Fugitive Emissions 1 At Upstream Oil and Gas Facilities 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, f law 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 eq uipment 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 environment al 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 perce ntage 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 e mission 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.January 2007 Management of Fugitive Emissions 2 At Upstream Oil and Gas Facilities 2 Implementation And Sc hedule 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,

wit h 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 pr ogram at existing UOG facilities should be completed by December 31, 2009

.
While this BMP provides for a phas ing

- in period, CAPP members will be requested to provide interim reports on the status of implementation of a DI&M

p rogram within their companies b y 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 imp oses a mandatory requirement to implement a program to detect and repair leaks and that such a progra m must meet or exceed CAPP BMP.

In view of the above, the use of the world “should” in th is BMP does not imply that action is not necessary within the cont ext of the EUB Directive 060 ; i.e.

,

a lternative 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 th is 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

fou rth quarter of 2008

. I nterim and final reports will be presented as a basis for

the continued improvement of th is BMP.

A review of the document is expected to take place within 24 months from the date of implementation to incorporate any adjustments that C APP 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 At Upstream Oil and Gas Facilities 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 evalu ate 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 a

t the next scheduled leak survey no Repair leaking components

s. 3.2.9

Is the leak easy to fix?

no no no

n o

no

orJanuary 2007 Management of Fugitive Emissions 4 At Upstream Oil and Gas Facilities 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

tech nologies 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 emiss ions, and

• M anagement’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 mater ial

- 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 managemen t 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 practica ble manner possible. This is done by focusing efforts on the types of components and service application s most likely to offer significant cost

- effective control opportunities (see Section 3 .2. 5 ). Non

target components are subjected to coarse or less frequ ent screening.

Typically, a facility will phase the DI&M program over a certain number of years by progressively add ing 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 targe t or non

- target component, the Decision T ree 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 Sectio n 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 quantifica tion or, alternatively, the leak should be measured or estimated to
determine if it is economic al to repair. W here an operator believes that it may not

be economic al

to repair , this should be documented based on reliable quantification of the amount of lea kage and the repair costs (see Section s 3.2.4January 2007 Management of Fugitive Emissions 5 At Upstream Oil and Gas Facilities and 3 .2.8 )

. If a leak poses a health

, safety

, or environmental c oncern, then it needs

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

3.2.2 Leak Definition

F ugitive 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 mor e 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 leak ing com ponents 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 st ill 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 technologi es include: d ifferential 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 o f 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 s uch alternative methods that provide a n 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 facili ties. For these reasons, this BMP provi des 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 t o 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 ar e being developed and can be used to identify leaking components.

Using a lternatives 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 At Upstream Oil and Gas Facilities 3.2.4 Leak Quantification

The quantification by measurement or e stimation 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 sens ing

methods.

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

leaks

.

Table 1

. Leak D etection and Measurement M ethods 1

.
Qualitative Methods 2 Quantitative Methods 3

Bubble Tests Portable Organic Vapour Analyzers 4
Optical emis sions detection ( L eak 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 le ak 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.January 2007 Management of Fugitive Emissions 7 At Upstream Oil and Gas Facilities Table 2 provides an indication of cost effectiveness for some of the screening and measurement techniques based on an EPA’s Lessons Learned S tudy

.

Table 2 Summary of Screening and Measurement

Techniques

Instrument/

T echnique Effectiveness Approxim ate Capital Cost
Soap S olution ** $

Electronic Gas Detectors * $$

Acoustic Detection /

Ultrasound Detection ** $$$

Toxic vapour analyzer /

Flame ionization

Detector * $$$

Bagging * $$$ High V olume Sampler *** $$$

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, open

ended lines, blowdown vents (i.e., during passive periods), instrument fittings, regulator and actuator diaphragms, compressor seals, engine and compressor crankcase vents, sump and drai n tank vents and covers. The amount of emissions from a leaking component is generally independent of the size of the component. Furthermore, a s previously mentioned, usually only the top 5 to 10 percent of

leak ing components account for 80 to 90 percent o f the em issions

. For equipment s 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

repa ir

, and the value of various potential indirect factors such as avoiding safety,January 2007 Management of Fugitive Emissions 8 At Upstream Oil and Gas Facilities health

, and environment impacts, avoiding damage to the component, improved process reliability and better performance.

Storage tanks at production and processing facilities a re 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 ta nks 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 reduction s are expected for these

components.

3.2.6 Monitoring F requency

The equipment components most likely to leak should be screened most freq uently. 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 emission s reductions yet also suits the un ique 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 ava ilability 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

- tuneJanuary 2007 Management of Fugitive Emissions 9 At Upstream Oil and Gas Facilities 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

sol u tion 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

emission s reductions

. 3.2.7 Inaccessible Components

Inaccessible source s or component s 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 exc luded 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 form s

. Compan ies should determine the best

format for flagging/identifying leak s as well as for leak surveys in acc ordance

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

- by

case basis in consideration of health, safety, environmental

, and economic al

con cerns. Wh ere feasible, r epairs 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

uneconomic al to repair and does not pose a safety, health

, or envir onmental

concern . In such cases, the components should remain tagged /identified and be re

screened 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 bei ng 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 :

ice Gas Rate Leak Annual Control

of Cost 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 = amou nt 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 060 5 or, for the

mid stream industry, the processing fee or margin

received

. Components that have a payback period greater than 1 year should be re

evaluated w ith the “Cost of C ontrol ” equal to direct repair or replacement cost only

. If this analysis shows the repair or replac ement 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 d efault 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 repair s 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 cons ervation 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 repair s 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

Hatches 1 Tank Fittings

Pressure Vacuum

Valves 2

Quarter

- Turn 4 Valves Rising Ste m 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 Primar y 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 a ctions are implemented.

This information will also assist in identifying the proper monitoring frequency

for that component to achieve maximum cost

- effective fugitive emission s reductions while suiting the unique characteristics and operations of the facil ity.

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 analysi s 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 concern s

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

E UB 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 . Operator s may elect to implement other approac hes 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

. Or der 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 In

Line 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 f or 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 Monogr aph 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 Can adian 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. Environmen tal 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. Less ons 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 Le ak 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 liqu id) 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 Seals 1 All Quarterly Pump Seals 1 All Quarterly

Pre ssure Relief

Valves All Annually

Open

- ended Lines All Annually Emergency Vent 1,2 All Annually Process Equipment

Blowdown Systems

1,2 All Quarterly

Tank Hatches 1 All Quarterly Vapour

Collection Systems Pressure

- Vacuum

Safety Valves 1 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

Process Stream Name/Identification

Code Type Leaker

Ta g No. Process

Tag

No. Type Type Odourized Size Measurement

Method THC

Leak

Rate (m 3 /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/NJanuary 2007 Management of Fugitive Emissions 20 At Upstream Oil and Gas F acilities

Direct Measure Datasheet

Location:

Date:

Source Data Measurement Data Tag

No. Type of Compone

nt Size Process Unit Meter Type Initial

Volume Final

Volu me 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

– Fla nge 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 GasJanuary 2007 Management of Fugitive Emissions 21 At Upstream Oil and Gas F acilities GAS SENSOR CALIBRATION RECORD Page ___ of ___

Site Name: Date Operating Company: Technicians:

Location: Industry Sector: Facility Type:

Field Calibration Checks Date of Last

Calibration Zero Chec k Span Check Units of

Measure Device Manufacturer Serial No.

Factory Office Day Time

Reading Actual Reading %ErrorJanuary 2007 Management of Fugitive Emissions 22 At Upstream Oil and Gas F acilities FLOW METER CALIBRATION RECORD Page ___ of ___

Site Name: Date Operating Company: Technicians:

Location: Industry Sector: Facility Type:

Field Calibration Checks Date of Last

Calibration Zero Check Span Check Device Manufacturer Serial No.

Factory Laboratory Day Time Reading Refere

nce Reading %Error Units of

MeasureJanuary 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 re pairs using the equ ation 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 ex amples given, the net gas price is taken to be $4.0/GJ or $0.1496/m 3 , 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 Petroleu m 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 Compon ent Type Nominal

Size (Inches) Stream

Type Hydrocarbon

Leak Rate (m 3 /hr) Hydrocarbon

Leak Rate (10 3 m 3 /y)

(A) Net Value

of Lost Gas ($/10 3 m 3 )

(B) Estimated

Repair
Cost ($)

(C) Default

Repair
Life (y) Payback

Period (y)

(C/A/B)

1982 Desiccant Deh ydrator 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 Dehydrato r 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 W et 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
Val ve 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 3.7January 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 t he 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

. T hese data should not to be used for quantifying the emissions from a sing le 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 compon ent 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

- sp ecific 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 reliab le 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,

EF L = 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 s ervice j (see

Table 6 ), X

n + n n EF + n EF N = ER j

N L N

N L L

j i, j i,

j i •       • •

• 

## ∑ ∑January 2007 Management of Fugitive Emissions 26 At Upstream Oil and Gas Facilities n L = 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,

n N = number of components screened and determined not to be leaking (i.e., give a screening

value of less than 10 000 ppm, including tho se sources with a screening value of zero) for
the source category of interest,

N j i, = 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 othe r 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

Connector 1 No Leak 9 44512 98.79 0.0000338 0.0000271 0.0000406

Leak 10 556 1.21 0.01856 0.01465 0.02247

Block Valve 2 No Leak 5907 96.02 0.0006132 0.0 0.001342

Leak 245 3.98 0 .03895 0.02728 0.05062

Control Valve 3 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 Meter

4 No Leak 83 79.81 0.001925 0.0006846 0.003165

Leak 21 20.19 0.0088 0.004936 0.01286

Other Flow Meter 5 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 System 6 Leak 75 73.53 1.274 0.4989 2.049January 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 2 7.88 0.0001127 0.0000249 0.0002006

Leak 463 72.12 0.1158 0.05458 0.177

Instrument

Controller

7 No Leak

---- 0.00

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

Leak 17 100.00 0.4681 0.09325 0.8429
Compressor Seal

– Reciprocating 8 No Leak 5 13.89 0.000 56 0.0 0.002115

Leak 31 86.11 0.7682 0.4865 1.049
Compressor Seal

- Centrifugal 8 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 pa st 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. Em issions 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 reciproca ting 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 f low 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 pro cess 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 emissio ns 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

- str atum 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 i s estimated for each source category using the equation:

where,

EF 1 , EF 2 , EF 3 = THC emission factors for sources with screening values in the range of 0 to 1 000 ppm, 1 001 to 10 000 ppm, and over 10 000 ppm, respectively (see Table 7).

n 1 , n 2 , n 3 = Total number of sources surveyed that had screening values in the range of 0 to

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

The basic assumptions inherent in use of the three

- stratum emission factor meth od 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) = B 0 + B 1 Log(SV) (5)

where:

B 0 , B 1 = Model parameters as given in Table 8.

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

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

to methane (ppm). n + n + n EF

n + EF n + EF n N = ER

3 2 1 3

3 2 2 1 1 j i,

j i       •

• •

• 

## ∑ ∑January 2007 Management of Fugitive Emissions 29 At Upstream Oil and Gas Facilities Table 7

. Three

- stratum emission factors for estimating fugitive equipment le aks at UOG facilities.

95% Confidence Limits

Source Number

of
Sources Percent of

Sources Emissions

(kg/h/src) Lower Upper

Connector 1 <1000 44207 98.1 0.0000032 0.000003 0.0000033

1000

- 10000

>10000 305

556 0.7

1.2 0.004480

0.01856 0.003623

0.01465 0.005337

0.02247

Block Valve 2 <1000 5803 94.3 0.0005027 0.0 0.001242

1000

- 10000

>10000 104

245 1.7

4.0 0.006782

0.03895 0.003705

0.02728 0.009858

0.05062

Control Valve 3 <1000 167 61.2 0.000027 0.0000197 0.000 0344

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 Meter

4 <1000 67 64.4 0.000032 0.0000198 0.0000442

1000

- 10000

>10000 16

21 15.4

20.2 0.009850

0.0088 0.004703

0.004936 0.01500

0.01286

Other Flow Meter 5 <1000 258 97.0 0.000003 0.0000014 0.0000045

1000

- 10000

>10000 1

7 0.4

2.6 0.0002000

0.0002064 ----

0.0 ----

0.0006932

<1000 25 24.5 0.000023 0.000001 0.000045 Station or Pressurized Compressor Blowdown System 6 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 Controller 7 <1000

---- ---- ---- ---- ---- 1000

- 10000

>10000 --- -

17 ----

100.0 ----

0.4681 ----

0.09325 ----

0.8429January 2007 Management of Fugitive Emissions 30 At Upstream Oil and Gas Facilities Table 7

. Three

- stratum emission factors for estimating fugitive equipment le aks 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
Reciprocating 8 1000

- 10000

>10000 ----

31 ----

86.1 ----

0.7682 ----

0.4865 ----

1.049
Comp ressor Seal

- <1000 1 4.8 0.0000075

---- ---- Centrifugal 8 1000

- 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 fl anges, 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 se ctions 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 B 0 B 1 Number of
Sources Correlation (R 2 )

Connectors 1

- 5.9147 0.75 305 0.71

Valves 1

- 6.03 99 0.83 369 0.67

Open

- Ended Lines 2

- 6.9586 1.28 64 0.44

Pressure Relief Devices 2

- 5.1479 0.91 29 0.46

Pressure Regulators 2

- 6.4821 0.91 35 0.58

1 The correlation for this source is based on screening and bagging data collected by Ros s 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 At Upstream Oil and Gas Facilities T he 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 th e 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 t his 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. T he 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 hav e 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 Researc h Inst itute, June 19, 1999)

.January 2007 Management of Fugitive Emissions 32 At Upstream Oil and Gas Facilities Table 9

. Default zero emission rates 1

. Source Type Default

- Zero Emission Rate 2

(kg/h/source)

Gas valve 6.6 (10 - 7 )

Light liquid valve 4.9 (10 - 7 )

Light liquid pump 3 7.5 (10
- 6 )

Connector 6.1 (10 - 7 )

1 Source: U.S. EPA. 1995. Protocol for Equipment Leak Emission Estimates. Research Triangle Park, NC. Report No.

EPA

- 453/R

- 95

- 017. Table 2

- 11. p. 2

- 33.

2 Total hydrocarbon emissions.

3 The light liquid pump default zero value can be applied to compressors seals, pressur e 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, variou s 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 suit abl e 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 o r 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 eac h 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 fur ther details on developing a unit

specific leak

- rate correlations, refer U.S. EPA's (1995) protocol for eq uipment

leak emission estimates

.January 2007 Management of Fugitive Emissions 33 At Upstream Oil and Gas Facilities Furthermore, use of a portable organic vapour analyzer is much slower than other leak detection techniques; especiall y 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 At Upstream Oil and Gas Facilities 

### Appendix 6 Component

- Specific Control Options

This appendix present s potential options for eliminating or controlling chronic leaks for each of the following common types of equipment components,

r espectively:

• Reciprocating compressors

• Centrifugal compressors

• Valve stem packing systems

• Sewers and drains

• Pump seals

• Flanged and threaded connections

• Pressure relief devices

• Open

- ended valves and line s

• Sampling points

6.1 Reciprocating Compressors

Packings a re 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 Ve nt 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 temp erature 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

connection s). 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 sulphid e).January 2007 Management of Fugitive Emissions 35 At Upstream Oil and Gas Facilities Figure 2. Schematic diagram of a piston

- rod packing

- case system on a reciprocating

compressor.January 2007 Management of Fugitive Emissions 36 At Upstream Oil and Gas Facilities 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 ground

level 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 so me 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

drai n 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 non

volatile 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 fini shes, 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 theJanuary 2007 Management of Fugitive Emissions 37 At Upstream Oil and Gas Facilities vent connections on the packing case or distance piece. This reduces or eliminates

the need to maintain a constant vacuum on the ven t 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 indicate d

. 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 c ylinder 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 require d 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 compartme nt 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

e ntering 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 rema in pressurized, but this should be

reviewed on a case

- by

- case basis to ensure that the correct pa cking arrangement is

installed.January 2007 Management of Fugitive Emissions 38 At Upstream Oil and Gas Facilities 6.1.7 Static Packing Systems

If compressors are left pressurized when shut down, emissions from the compressor seals may be eliminate d 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 compre ssor 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 packi ng 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 compr essor 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.

St atic 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 con tact 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 thei r 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

prov ide 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 At Upstream Oil and Gas Facilities Some oil leaks inward through the seal and is collected in drain traps before being

returned to the reservoir. Gas from the tra ps 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 degassi ng 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 oi l 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 h as 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 commonl y 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 se al 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 a re 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, mayJanuary 2007 Management of Fugitive Emissions 40 At Upstream Oil and Gas Facilities 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 t he 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

- tig htening 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.

R otary or quarter

- turn valves where stems turn 90 o (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 eac h 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 approximat ely 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 achieve d 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

p reformed graphite rings are installed, braided end rings are necessary.

Polymeric packing may be quite acceptable in many undemanding service applications with temperatures below 200 o C. 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 150 o C (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 v oids 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

stress es (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 At Upstream Oil and Gas Facilities 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 l ower 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 s hould 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 adjusti ng 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 conside red 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 leaka ge 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 heal th 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 emissio ns 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 At Upstream Oil and Gas Facilities • 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 almo st 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 t he 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

- cas es 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 serv ices 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 ex isting seal chamber with an enlarged

- bore retrofit seal chamber, as specified in the ANSI B

73 standard and API Standard 610, should be considered

. Introduced in the mid

1980’s, enlarged bore seal chambers with increased radial clearance between the

mechan ical 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 At Upstream Oil and Gas Facilities 6.6 Threaded and Flanged Connections

A properly installed and maintained mechanical coupling or threaded or flanged connection can pr ovide 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 1 0 . For instance, it is not

uncommon for some connections to be in advertently 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 adjustm ents 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 Devic es

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 r esponsible 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

. Co mmon 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 re

sealing chara cteristics, or installing a rupture disk immediately upstream of theJanuary 2007 Management of Fugitive Emissions 44 At Upstream Oil and Gas Facilities 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 shie ld 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 tox ic (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 h ave 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 m ay 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 i nstalled. 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 sy stems 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 gre atest where the sample (gas or liquid) is taken from aJanuary 2007 Management of Fugitive Emissions 45 At Upstream Oil and Gas Facilities 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 meth od 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 At Upstream Oil and Gas Facilities 

### 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, pump s 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 l eaks 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 surf ace 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 specifica tion 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 wit h 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 m eter readings of less than a concentration corresponding to the minimum readability specification indicates that a VOC emission (leak) is not present

. (For example, if theJanuary 2007 Management of Fugitive Emissions 47 At Upstream Oil and Gas Facilities leak definition in a regulation is 10,000 ppm, then the allowable increase is surfac e 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 calib rated 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 re adings

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 no t 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 r eadable 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

. Th e 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

.January 2007 Management of Fugitive Emissions 48 At Upstream Oil and Gas Facilities 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 cali bration 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 subse quent 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

ti me, 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, the y 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 gas es 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

no t 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 refe rence 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 beJanuary 2007 Management of Fugitive Emissions 49 At Upstream Oil and Gas Facilities 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 Definiti on 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 sam ple 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 Othe r 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 conc entration 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

- Pla ce 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 em issions exist.

h

. Access door seals

- Place the probe inlet at the surface of the door seal interface and traverse the periphery.January 2007 Management of Fugitive Emissions 50 At Upstream Oil and Gas Facilities 4.3.2 Type II

- "No Detectable Emission"

. Determine the ambient concentration around the source by moving the probe random ly 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) Pu mp 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 de vice

. 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 h ave 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 pre pared 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 Evaluat ion 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 mi xture to the analyzer and record the observed meter reading

. Introduce zero air until a stable reading is obtained

. Make a total of threeJanuary 2007 Management of Fugitive Emissions 51 At Upstream Oil and Gas Facilities 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 g as

. 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 i s 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 Com pounds

. 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. EP A 600/2

- 81

- 110

. September 1981.