REPORT 

Update of Fugitive Equipment Leak 

Emission Factors 

February, 2014 

2014-0023 
2100, 350 – 7 Avenue S.W. 

Calgary, Alberta 

Canada T2P 3N9 

Tel 403-267-1100 

Fax 403-261-4622

1000, 275 Slater Street 

Ottawa, Ontario 

Canada K1P 5H9 

Tel 613-288-2126 

Fax 613- 236-4280

403, 235 Water Street 

St. John’s, Newfoundland and Labrador 

Canada A1C 1B6 

Tel 709-724-4200 

Fax 709-724-4225

310, 1321 Blanshard Street 

Victoria, British Columbia 

Canada V8W 0B5 

Tel 778-410-5000 

Fax 778-410-5001

www.capp.ca  communication@capp.ca

The Canadian Association of Petroleum Producers (CAPP) represents companies, 

large and small, that explore for, develop and produce natural gas and crude oil 

throughout Canada. CAPP’s member companies produce about 90 per cent of 

Canada’s natural gas and crude oil. CAPP's associate members provide a wide 

range of services that support the upstream crude oil and natural gas industry. 

Together CAPP's members and associate members are an important part of a 

national industry with revenues of about $110 billion a year. CAPP’s mission is to 

enhance the economic sustainability of the Canadian upstream petroleum industry 

in a safe and environmentally and socially responsible manner, through 

constructive engagement and communication with governments, the public and 

stakeholders in the communities in which we operate. 

Disclaimer 

This publication was prepared for the Canadian Association of Petroleum 

Producers (CAPP) by Clearstone Engineering. While it is believed that the 

information contained herein is reliable under the conditions and subject to the 

limitations set out, CAPP and Clearstone Engineering do not guarantee its 

accuracy. The use of this report or any information contained will be at the 

user’s sole risk, regardless of any fault or negligence of Clearstone Engineering, 

CAPP or its co-funders. 
TECHNICAL REPORT

February

20, 2014 Update of Fugitive Equipment Emission Factors

Prepared For: Canadian Association of Petroleum Producers

2100, 350‐7th Avenue S.W.

Calgary, AB, T2P 3N9

Prepared by: Clearstone Engineering Ltd.

700, 900‐6th Avenue S.W.

Calgary, AB, T2P 3K2
i

DISCLAIMER

While reasonable effort has been made to ensure the accuracy, reliability and completeness of

the information presented herein, this report is made available without any representation as to

its use in any particular situation and on the strict understanding that each reader accepts full

liability for the application of its contents, regardless of any fault or negligence of Clearstone

Engineering Ltd.

   
ii

EXECUTIVE SUMMARY

Currently, industry can assess atmospheric emissions due to fugitive equipment leaks by

measurements and by estimation methods. The estimation methods often involve the use of

average emission factors. An emission factors is a statistical parameter that relates the total

amount of emissions from a population of sources to a relevant activity parameter for those

sources. For fugitive equipment leaks, the activity parameter is the number of equipment

components in hydrocarbon service. Different factors are applied for different types of

components and different types of hydrocarbon service (e.g., gas/vapour, light liquid or heavy

liquid). An emission factor is intended for estimating total emissions from large populations of

sources, but is not appropriate for application to individual sources or small numbers of sources.

This report presents updated average emission factors for estimating emissions from fugitive

equipment leaks at upstream oil and natural gas (UOG) facilities. The previous factors (CAPP,

2005) were developed based on measurement results collected from the mid 1990’s to early

2000’s. In 2007 CAPP published a best management practice (BMP) for Management of Fugitive

Emissions at Upstream Oil and Gas Facilities and provincial regulations came into effect to better

manage these emissions. The CAPP Fugitive Emissions BMP provides guidance on implementing

directed   inspection   and   maintenance   (DI&M)   procedures   to   specifically   target   fugitive

equipment leaks. The updated factors are reflective of current conditions at UOG facilities that

have implemented DI&M programs in accordance with the BMP and applicable regulatory

requirements.

Through industry participation, leak survey results for 120 facilities in Alberta and British

Columbia, comprising an estimated 276,947 equipment components, were compiled and

assessed. In comparison, the CAPP (2005) factors are based on leak survey results for 251,431

equipment components. A comparison of the two data sets indicates that, overall, the emissions

due to fugitive equipment leaks have decreased by 75 percent since the implementation of

DI&M programs. Only emission factors for connectors in gas/vapour service at natural gas

facilities were unchanged. Emission factors for all other categories with more than 50 leakers

showed substantial reductuins compared the CAPP (2005) values. These results are a strong

indication that DI&M programs and CAPP’s best management practice for Management of

Fugitive Emissions at Upstream Oil and Gas Facilities are effective in controlling fugitive

equipment leaks.

For the current work it was necessary to identify and quantify the processes and major

equipment units used at each facility and then, based on this information and the application of

typical   equipment   schedules,   develop   detailed   component   counts   for   each   facility.   The

examined facilities include those in both sweet and sour service, oil production facilities and

natural gas facilities ranging from single‐well batteries and compressor stations through to gas

processing facilities.Some consolidation of the data was performed where source categories
iii

involving  the  same  fundamental  type  of   component  were  determined  to  be  statistically

equivalent and this either provided better alignment with categories used in other jurisdictions

thereby allowing direct comparisons or aligned well with practicable‐to‐assess component

categories. The results are presented in Table 10 herein. The consolidations included eliminating

the distinction between fuel gas (FG) and gas/vapour (GV) service, and the distinction between

sweet and sour service. While there is some correlation of the data with these two parameters,

it is not often practicable to get the data needed to make such distinctions when developing

emissions inventories (especially at the regional or national level).  These consolidations reduced

the list of component categories to two primary categories: oil systems and natural gas systems.
iv

TABLE OF CONTENTS

DISCLAIMER.......................................................................................................................................i

EXECUTIVE SUMMARY.....................................................................................................................ii

TABLE OF CONTENTS.......................................................................................................................iv

LIST OF TABLES .................................................................................................................................v

LIST OF FIGURES ..............................................................................................................................vi

LIST OF ACRYNOMS ....................................................................................................................... vii

ACKNOWLEDGEMENTS................................................................................................................. viii

1       INTRODUCTION ....................................................................................................................... 1

2      HISTORIC AND CURRENT EMISSION FACTOR Methodologies................................................. 3

2.1 Published Emission Factors................................................................................................ 3

2.2 Emission Factor Update Methodology............................................................................... 6

2.3 Fugitive Emission Data Analysis ......................................................................................... 8

2.4 Component Counts............................................................................................................. 9

2.5 Method 1 Emission Factors................................................................................................ 9

2.5.1 Leak Frequency (LF)................................................................................................... 9

2.5.2 Emission Factor (EF)................................................................................................... 9

2.6 Method 2 Emission Factors.............................................................................................. 10

2.6.1 Leak Frequency (LF)................................................................................................. 10

2.6.2 Emission Factor (EF)................................................................................................. 10

2.7 COMBINING THE RESULTS OF METHOD 1 and 2 ............................................................... 11

3      COMPONENT EMISSION FACTORS ........................................................................................ 12

3.1 Leak Survey Results.......................................................................................................... 12

3.2 Method 1 Leak Frequency and Emission Results............................................................. 17

3.3 Method 2 Leak Frequency and Emission Results............................................................. 19

3.4 CombineD and Consolidated Emission Factor Results..................................................... 20

4      DISCUSSION OF RESULTS AND RECOMMENDATIONS........................................................... 31

4.1 Equipment Schedules....................................................................................................... 31

4.1.1 Equipment Schedule Recomendations.................................................................... 32

4.2 Component Counts........................................................................................................... 32

4.2.1 Component Count Recommendations.................................................................... 32

4.3 Emission factor Results..................................................................................................... 32

4.3.1 Recommendations................................................................................................... 32

5      REFERENCES .......................................................................................................................... 33

6      APPENDIX A – Default Component Counts By Type of Process or Major Equipment Unit... 34

7      APPENDIX B ‐ Guidelines for Counting Equipment Components.......................................... 43

8      APPENDIX C ‐ METHODOLOGY FOR ASSESSING UNCERTAINTIES ......................................... 45

8.1.1 Combing Uncertainties in Multiplication Steps....................................................... 45

8.1.2 Combining Uncertainties in Addition Steps............................................................. 45

8.1.3 Uncertainties in Individual Input Quantities............................................................ 46

8.1.4 Upper and Lower Confidence Limits ....................................................................... 46
v

LIST OF TABLES

TABLE 1: EMISSION FACTORS FOR THC EMISSIONS IN THE UPSTREAM OIL AND GAS INDUSTRY IN ALBERTA 

(CAPP 1992)......................................................................................................................................... 4 

TABLE 2: SUMMARY OF AVERAGE EMISSION FACTORS FOR UNCONTROLLED FUGITIVE THC EMISSIONS 

(KG/H/SOURCE) AT UPSTREAM OIL AND GAS FACILITIES (CAPP, 2005).................................................. 4 

TABLE 3: SUMMARY OF FACILITIES FOR WHICH FUGITIVE EMISSION DATA WAS SUBMITTED AND USED IN THE 

EMISSION FACTOR UPDATE STUDY. ........................................................................................................ 7 

TABLE 4: SUMMARY OF EMISSION FACTOR UPDATE STUDY ESTIMATED TOTAL COMPONENT COUNTS BY TYPES 

AND JURISDICTION BASED ON THE EQUIPMENT TOTALS AND DEFAULT COMPONENT COUNTS. ............... 8 

TABLE 5: SUMMARY OF LEAK SURVEY RESULTS SHOWING LEAK FREQUENCY, AVERAGE LEAK RATE AND 

LEAK RATE STANDARD DEVIATION. ......................................................................................................13 

TABLE 6: SUMMARY OF LEAK SURVEY RESULTS SHOWING THE NUMBER OF LEAKING COMPONENTS, THE 

AVERAGE LEAK RATE AND THE LEAK RATE STANDARD DEVIATION FOR REPORTED EMISSIONS WHERE THE 

ESTIMATED FACILITY COMPONENT COUNT FOR THE LEAKING COMPONENT WAS ZERO. .................15 

TABLE 7: EMISSIONS AND LEAK FREQUENCY RESULTS FROM APPLICATION OF METHOD 1 TO SITES HAVING 

LEAKER COUNTS BUT NO LEAK MEASUREMENT DATA. ..........................................................................18 

TABLE 8: EMISSIONS AND LEAK FREQUENCY RESULTS USING METHOD 2 FOR SITES WITH MEASURED LEAK 

RATES. ..................................................................................................................................................22

TABLE 9: COMBINED EMISSION FACTOR RESULTS FROM THE METHOD 1 AND METHOD 2 DATA SETS............26 

TABLE 10: FINAL CONSOLIDATED EMISSION FACTORS FOR APPLICATION IN ESTIMATING FUGITIVE EMISSIONS 

FROM UPSTREAM OIL AND GAS FACILITIES AFTER THE IMPLEMENTATION OF A FORMAL DI&M 

PROGRAM..............................................................................................................................................30

TABLE 11: ISSUED ENCOUNTERED IN ESTABLISHING EQUIPMENT AND PROCESS TYPE COUNTS FOR EACH 

FACILITY...............................................................................................................................................31

TABLE 12: SCHEDULE OF DEFAULT COMPONENT COUNTS PER EQUIPMENT OR PROCESS TYPE (CAPP 2005). 35 

TABLE 13: SUMMARY OF EQUIPMENT OR PROCESS TYPES BY JURISDICTION AND IN TOTAL THAT ARE 

INCLUDED IN THE EMISSION FACTOR UPDATE DATABASE. .....................................................................40 
vi

LIST OF FIGURES

FIGURE 1: DISTRIBUTION OF THE APPLIED TOTAL COUNT AND LEAKING COMPONENT COUNT BY COMPONENT 

TYPE IN DATABASE AND PRESENTED IN TABLE 5...................................................................................16 

FIGURE 2: LEAK FREQUENCY VERSUS TOTAL COMPONENT COUNT INCLUDING ALL COMPONENT TYPES 

(FREQUENCIES GREATER THAN 1% AND COUNTS LESS THAN 500 AND GREATER THAN 40,000 

EXCLUDED). ..........................................................................................................................................20 
vii

LIST OF ACRYNOMS

C Component

CAPP Canadian Association of Petroleum Producers

CEL Clearstone Engineering Ltd.

DI&M    Direct Inspection and Maintenance

EF Emission Factor

FG Fuel Gas

GV Gas/Vapour (process and sales gas)

h Hour

HL Heavy Liquid

kg Kilogram

LF Leak Frequency

LL Light Liquid

N Number of components

Sr Sour

Sw Sweet

UOG Upstream Oil and Gas

   
viii

ACKNOWLEDGEMENTS

The  development  of  this  report  has  been  sponsored  by  CAPP.  The  support  and  direction

provided by each of the participating companies and agencies involved is gratefully

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

the project steering committee and/or provided review comments.
1

1 INTRODUCTION

Emissions from fugitive equipment leaks at industrial facilities are most often estimated for use

in emissions inventories by applying component‐type average emission factors. Facility‐level

fugitive emission estimates based on these factors are used by companies for regulatory

reporting and by governments to meet national and international reporting agreements.

For  the  upstream  oil  and  natural  gas  (UOG)  industry,  the  most  up‐to‐date  set  of  average

emission factors was published as part of the CAPP/Environment Canada/NRCan Upstream Oil

and Gas emission inventory (CAPP 2005). These factors were based on emissions data collected

over the mid‐1990s to the early 2000s time period.

Since 2007, regulations have been in effect in Alberta (Directive 060), and subsequently in BC

and SK, that require UOG companies to conduct formal leak management programs. Industry

has adopted a directed inspection and maintenance (DI&M) approach which is documented as a

best management practice (BMP) by CAPP (2007), and is now a requirement of the regulations.

The potential positive effect of these regulations and the implementation of the CAPP BMP for

management of fugitive emissions on emissions from fugitive equipment leaks was expected to

result in an over estimation of emissions when using the CAPP (2005) average emission factors.

The objective of this study was, therefore, to draw on recent leak survey results compiled by

industry as part of regulated leak management programs to develop improved average emission

factors for estimating atmospheric emissions from fugitive equipment leaks at UOG facilities.

The review and assessment of fugitive equipment leaks, leak frequencies, and component‐type

average emission factors is provided herein.

The overall intent was to gather sufficient data from existing sources to provide an unbiased and

statistically defensible update of the UOG average emission factors for fugitive equipment leaks.

The scope was limited to upstream UOG infrastructure excluding oil sands operations.

Throughout this document, the term “fugitive emissions” refers specifically to atmospheric

emissions due to leakage from equipment components in hydrocarbon service. Only leaks that

result in the release of a process fluid to the atmosphere are considered. Leakage into the

process or to a waste gas collection and treatment or recovery system is specifically excluded.

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

contains greater than 10 percent hydrocarbons on a mass basis. Fugitive emissions from

equipment leaks are unintentional losses and may arise due to normal wear and tear, improper

or incomplete assembly of components, inadequate material specification, manufacturing

defects, damage during installation or use, corrosion, fouling and environmental effects (e.g.,

vibrations and thermal cycling). The potential for such emissions depends on a variety of factors
2

including the type, style and quality of components, type of service (gas/vapour, light liquid or

heavy liquid), age of component, frequency of use, maintenance history, process demands,

whether the process fluid is highly toxic or malodorous and operating practices.

Most of the atmospheric emissions from fugitive equipment leaks tend to be from components

in natural gas or hydrocarbon vapour service rather than from those in hydrocarbon liquid

service1

. Components in odourized or H2S service tend to have much lower average fugitive

emissions than those in non‐odourized or non‐toxic service. Components tend to have greater

average emissions when subjected to frequent thermal cycling, vibrations or cryogenic service.

Different types of components have different leak potentials and repair lives.

1 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. 
3

2 HISTORIC AND CURRENT EMISSION FACTOR METHODOLOGIES

UOG‐specific emission factors were developed in early 1990 in association with industry‐wide

emission inventories. Factor updates have been associated with UOG emissions inventory

updates and have reflected changes in industry practice and regulatory initiatives.

Average, no‐Leak and leak fugitive emission factors for various sources were developed in 1992

and used to compile a detailed inventory of CH4 and VOC emissions from UOG operations in

Alberta (CAPP 1992). The average factors are used to estimate the amount of emissions from

fugitive equipment based on the total number of equipment component in hydrocarbon service

in each applicable component category. The leak and no‐leak factors are applied using a tiered

approach in which the total number of components in each applicable category is disaggregated

in those which produce a hydrocarbon screening value using US EPA Method 21 of 10,000 ppm

or greater (i.e., leakers), and those that produce screening values of less than 10,000 ppm (non‐ 

leakers). The total emissions from this tiered approach are the sum of the leak and non‐leak

contributions.

The average, leak and no‐leak factors were reported for source components types operating in

gas/vapour (G/V), sweet gas/vapour (Sw G/V), sour gas (Sr G/V) and light liquid (LL) service.

Source emission component types included:

• Valves in gas production

• Valves in oil production

• Connectors in gas production

• Connectors in oil production

• Compressor seals

• Pump seals

• Pressure relief valves and

• Open‐ended lines.

In 2005, a Canada‐wide inventory of emissions from oil and gas operations was completed

(CAPP 2005). This report contained sets of average emission factors for emission source

component types in gas and oil operations. Emission factors in G/V, Sw G/V, Sr G/V and LL

service were reported. Also, factors for equipment components in Heavy Liquid (HL) service

were  reported.  Additionally,  default  equipment  component  counts  for  various  process  and

major equipment unit types employed in UOG industry were reported.

2.1 PUBLISHED  EMISSION  FACTORS  

The CAPP (1992) emission factor results are presented in Table 1.
4

Table 1:   Emission factors for THC emissions in the upstream oil and gas industry in Alberta

(CAPP 1992).

Component Type Type of

Service

Service Average

Emission

Rate1

No‐Leak

Emission

Rate2

Leak

Emission

Factor2

kg/h/source kg/h/source kg/h/source

Valves

Gas Production

Sw G/V 0.43510 0.00023 0.26260

Sr G/V 0.00518 0.00010 0.26260

LL 0.00270 0.00081 0.85200

Oil Production G/V 0.01417 0.00008 0.04510

LL 0.00121 0.00058 0.08520

Connectors

Gas Production

Sw G/V 0.00253 0.00061 0.03750

Sr G/V 0.00031 0.00019 0.03750

LL 0.00019 0.00013 0.03750

Oil Production G/V 0.00079 0.00023 0.03750

LL 0.00019 0.00013 0.03750

Compressor Seals All Sites G/V 0.80488 0.00175 1.60800

Pump Seals All Sites LL 0.02139 0.00230 0.43700

Pressure Relief Devices All Sites G/V 0.12096 0.00019 1.69100

Open‐Ended Lines All Sites All 0.00373 0.00183 0.01195

1   From Table 5, page 49 of CAPP 1992

2   From Table 7, page 54 of CAPP 1992

Subsequent to this publication, updated emission factors were developed using additional data

and   published   as   part   of   A   National   Inventory   of   Greenhouse   Gas   (GHG),   Criteria   Air

Contaminant (CAC) and Hydrogen Sulphide (H2S) Emissions (CAPP 2005). These updated factors

are presented in Table 2. Sector (natural gas or oil systems), Facility Designation (All, Sweet or

Sour),  Component  Service  (fuel  gas,  gas/vapour,  light  liquid  or  heavy  liquid)  replaced  the

previous designations in Table 1 and, as a consequence, the list of average emission factors

significantly expanded. Additionally, lower and upper uncertainty limits were developed for

each emission factor.

Table 2:  Summary of average emission factors for uncontrolled fugitive THC emissions (kg/h/source) at

upstream oil and gas facilities (CAPP, 2005).

Sector Sweet/

Sour

Service Component Type Emission Factor

(kg/h)

Lower

Uncertainty

(%)

Upper

Uncertainty

(%)

GAS ALL Fuel Gas Connectors 8.18E‐04 32 32

GAS ALL Fuel Gas Compressor Seals 7.13E‐01 36 36

GAS ALL Fuel Gas Control Valves 1.62E‐02 27 27

GAS ALL Fuel Gas Open‐Ended Lines 4.67E‐01 58 172

GAS ALL Fuel Gas Pressure Relief Valves 1.70E‐02 98 98
5

Table 2:  Summary of average emission factors for uncontrolled fugitive THC emissions (kg/h/source) at

upstream oil and gas facilities (CAPP, 2005).

Sector Sweet/

Sour

Service Component Type Emission Factor

(kg/h)

Lower

Uncertainty

(%)

Upper

Uncertainty

(%)

GAS ALL Fuel Gas Pressure Regulators 8.11E‐03 72 238

GAS ALL Fuel Gas Valves 2.81E‐03 17 17

GAS ALL Gas/Vapour Connectors 7.06E‐04 31 31

GAS ALL Gas/Vapour Compressor Seals 7.13E‐01 36 36

GAS ALL Gas/Vapour Control Valves 1.46E‐02 23 23

GAS ALL Gas/Vapour Open‐Ended Lines 4.27E‐01 62 161

GAS ALL Gas/Vapour Pressure Relief Valves 1.70E‐02 98 98

GAS ALL Gas/Vapour Pressure Regulators 8.11E‐03 72 238

GAS ALL Gas/Vapour Valves 2.46E‐03 15 15

GAS ALL Light Liquid Connectors 5.51E‐04 90 111

GAS ALL Light Liquid Control Valves 1.77E‐02 45 45

GAS ALL Light Liquid Open‐Ended Lines 1.83E‐02 79 127

GAS ALL Light Liquid Pressure Relief Valves 5.39E‐03 80 80

GAS ALL Light Liquid Pump Seals 2.32E‐02 74 136

GAS ALL Light Liquid Valves 3.52E‐03 19 19

GAS SOUR Gas/Vapour Connectors 1.36E‐04 72 72

GAS SOUR Gas/Vapour Control Valves 9.64E‐03 4 4

GAS SOUR Gas/Vapour Open‐Ended Lines 1.89E‐01 79 127

GAS SOUR Gas/Vapour Pressure Regulators 4.72E‐05 74 126

GAS SOUR Gas/Vapour Valves 1.16E‐03 31 31

GAS SWEET Gas/Vapour Connectors 8.18E‐04 32 32

GAS SWEET Gas/Vapour Control Valves 1.62E‐02 27 27

GAS SWEET Gas/Vapour Open‐Ended Lines 4.67E‐01 58 172

GAS SWEET Gas/Vapour Pressure Regulators 8.39E‐03 72 239

GAS SWEET Gas/Vapour Valves 2.81E‐03 17 17

OIL ALL Fuel Gas Connectors 2.46E‐03 15 15

OIL ALL Fuel Gas Compressor Seals 8.05E‐01 36 36

OIL ALL Fuel Gas Control Valves 1.46E‐02 21 21

OIL ALL Fuel Gas Open‐Ended Lines 3.08E‐01 78 129

OIL ALL Fuel Gas Pressure Relief Valves 1.63E‐02 80 80

OIL ALL Fuel Gas Pressure Regulators 6.68E‐03 72 238

OIL ALL Fuel Gas Valves 1.51E‐03 79 79

OIL ALL Gas/Vapour Connectors 2.46E‐03 15 15

OIL ALL Gas/Vapour Compressor Seals 8.05E‐01 36 36

OIL ALL Gas/Vapour Control Valves 1.46E‐02 21 21

OIL ALL Gas/Vapour Open‐Ended Lines 3.08E‐01 78 129

OIL ALL Gas/Vapour Pressure Relief Valves 1.63E‐02 80 80
6

Table 2:  Summary of average emission factors for uncontrolled fugitive THC emissions (kg/h/source) at

upstream oil and gas facilities (CAPP, 2005).

Sector Sweet/

Sour

Service Component Type Emission Factor

(kg/h)

Lower

Uncertainty

(%)

Upper

Uncertainty

(%)

OIL ALL Gas/Vapour Pressure Regulators 6.68E‐03 72 238

OIL ALL Gas/Vapour Valves 1.51E‐03 79 79

OIL ALL Heavy Liquid Connectors 7.50E‐06 90 111

OIL ALL Heavy Liquid Pressure Relief Valves 3.20E‐05 80 80

OIL ALL Heavy Liquid Pump Seals 3.20E‐05 74 136

OIL ALL Heavy Liquid Valves 8.40E‐06 19 19

OIL ALL Light Liquid Connectors 1.90E‐04 90 111

OIL ALL Light Liquid Control Valves 1.75E‐02 44 44

OIL ALL Light Liquid Open‐Ended Lines 3.73E‐03 79 127

OIL ALL Light Liquid Pressure Relief Valves 7.50E‐02 80 80

OIL ALL Light Liquid Pump Seals 2.32E‐02 74 136

OIL ALL Light Liquid Valves 1.21E‐03 19 19

Source: CAPP Vol 3, Table 19, 2004, 2005‐0015 (CAPP 2005).

2.2 EMISSION FACTOR UPDATE METODOLOGY

Subsequent to 2007, industry applied directed inspection and maintenance (DI&M) programs to

reduce  fugitive  emissions.  To  assess  the  potential  effectiveness  of  these  programs,  recent

fugitive emission survey data were provided by various companies, compiled and analyzed, and

used to develop emission factors reflecting current practice. The 95% confidence limits for these

factors were assessed using the methodology delineated in Appendix C.

Through CAPP and participating UOG companies, fugitive emission reports were made available

for assessment. In total, eight companies submitted field studies. One of the respondents

withheld data on emissions from compressor seals in its submission on the basis that it deemed

these to be a source of process venting rather than a source of leakage. All but one operator

included leak and emission rate data by component type; that operator included only a list of

leaking components with no leak‐rate measurement results. One operator was not able to

provide supporting facility drawings, so due to the resulting uncertainty regarding equipment at

its facilities the fugitive emission data they provided were not used.

Only one operator provided facility component counts by component type. For the other

reported facilities, detailed component counts were developed based on the application of

default   equipment  schedules   applied  to  the   number   and  types   of   processes   and  major

equipment    units    as    determined    from    process    flow    drawings    (PFDs)    or    piping    and

instrumentation drawings (P&IDs), meter schematics and equipment inventory files. Although

the intent was to include facilities from BC, AB, SK and MB, only data from BC and AB was
7

received. The total number of facilities by jurisdiction for which data were received and used is

summarized in Table 3.

Table 3:   Summary of facilities for which fugitive emission data was submitted

and used in the emission factor update study.

FacilitiesIncluded In Study

Company Total BC AB

A 14 0 14

B 27 5 22

C 21 21 0

D 5 0 5

E 4 4 0

F 10 6 4

G 39 2 37

Total 120 38 82

A count of the number of process and major equipment units by type of process and major

equipment unit and province is presented in Table 13 in Appendix A. Based on those process

and major equipment unit totals and the corresponding default component counts listed in

Table 12, the study total equipment component counts are summarized in Table 4 by type of

component.
8

Table 4:   Summary of emission factor update study estimated total component counts by types

and jurisdiction based on the equipment totals and default component counts.

Component Type BC AB Total

Compressor Seal (FG) 0 0 0

Compressor Seal (GV) 110 362 472

Connector (FG) 19,438 26,803 46,241

Connector (GV) 56,634 97,107 153,741

Connector (LL) 10,153 22,355 32,508

Control Valve (FG) 0 0 0

Control Valve (GV) 4 46 50

Control Valve (LL) 0 0 0

Open‐Ended Line (FG) 0 0 0

Open‐Ended Line (GV) 402 771 1,173

Open‐Ended Line (LL) 2 2 4

Pressure Relief Valve (FG) 45 34 79

Pressure Relief Valve (GV) 313 741 1,054

Pressure Relief Valve (LL) 0 16 16

Pump Seal (FG) 0 0 0

Pump Seal (LL) 163 273 436

Regulator (FG) 27 0 27

Regulator (GV) 11 92 103

Regulator (LL) 0 0 0

Valve (FG) 1,724 1,586 3,310

Valve (GV) 8,732 18,482 27,214

Valve (LL) 3,303 7,216 10,519

Total of all component types 101,061 175,886 276,947

2.3 FUGITIVE  EMISSION  DATA  ANALYSIS 

The compiled information was managed in a relational MS Access database. The approaches

used to process these data included:

• Method 1  ‐ application of post‐2007 leak frequency data and CAPP (1992) Leak and No‐ 

Leak emission factors. This method was only applied where leak‐rate measurement

results were unavailable.

• Method 2 ‐ application of post‐2007 leak detection and measurement results for leaking

components and estimation of emissions contributions from non‐leaking components

using the CAPP (1992) no‐leak emission factors. An equipment component is generally

deemed to be leaking if it produces a screening value of 10,000 ppm or greater when
9

screened in accordance with U.S. EPA Method 21, or the emissions are detectable by a

leak imaging infrared camera.

2.4 COMPONENT COUNTS

Each  of  the  applied  methods  of  analysis  required  knowledge  of  the  actual  or  estimated

inventory of equipment components in hydrocarbon service at each facility. For the emission

survey results submitted, only one respondent included component counts and these were

estimates rather than actual field‐based counts. For the rest of the facilities, process flow

drawings (PFDs) and piping and instrumentation drawings (P&IDs) were requested and used to

identify the processes and major equipment units in operation at each facility as well as provide

details of the yard piping. Typical (default) component counts (see Appendix A and CAPP[2005])

were applied to each type of process or major equipment unit, and the counting guidelines

presented in Appendix B were applied to the yard piping and, where necessary, to refine the

applied equipment schedules.

2.5 METHOD  1  EMISSION  FACTORS  

Method 1 (see Section 2.3) was applied to those facilities for which leak counts but no leak‐rate

measurement data were provided.

2.5.1 LEAK FREQUENCY (LF)

The Leak Frequency for any emission source component type is determined by the following

equation:

LF = NLeakers

NTotal

⋅100 Equation 1

Where:

LF or LFCi = leak frequency for Component Type “Ci” expressed as a %.

NLeakers = the actual number of leaks reported for Component

Type “Ci

” in the dataset.

NTotal = the total number of Component Type “Ci” determined for all

facilities included in the dataset.

2.5.2 EMISSION FACTOR (EF)

The average emission factor (EFAverage) of any component type, using the CAPP (1992) Leak and

No‐Leak emission factors contained in Table 1, is determined by the following equation:
10

Average

∑

EF = 

LF ⋅ EFLeak + (100 − LF) ⋅ EFNo − Leak 

Equation 2

100

Where:

EFAverage = the calculated average emission factor for component type “Ci”,

(kg/h/source).

EFLeak = the Leak emission factor for Component type “Ci” as reported

(CAPP 1992).

EFNo‐Leak = the No‐Leak emission factor for Component type “Ci” as

reported (CAPP 1992).

2.6 METHOD  2  EMISSION  FACTORS  

Method 2 (see Section 2.3) was applied to the survey data where the measured emissions rate

of the identified leaks was provided. In addition, this method applied previously reported No‐ 

Leak emission factors to assess emission contributions by the non‐leaking components (CAPP

1992). In theory, mechanical seals and connections are not perfect and will emit a certain

amount of process fluid when they are in pressurized service, even when they are new and

properly installed. The term “leakage” is used in the regulatory context to indicate that the

component is emitting at an excessive rate and is in need of repair or replacement.

2.6.1    LEAK FREQUENCY (LF)

Leak frequency is determined as indicated in Section 2.5.1 above.

2.6.2 EMISSION FACTOR (EF)

The average emission factor (EFAverage) of any component type is determined by the following

equation:

(Emissions from detected leaks) + NNo − Leak ⋅ EFNo − Leak

EFAverage = NTotal

Equation 3

Where:

EFAverage = the calculated average emission factor for Component Type “Ci”

(kg/h/source).

∑Emissions...Leaks = the sum of all leaks reported for Component Type “Ci” in the

dataset.

NTotal = the total number of components of type i.

NNo‐Leak = NTotal of component type “i” minus the number of leaking
11

∑ ∑

component type “Ci”.

EFNo‐Leak = the No‐Leak emission factor for Component Type “Ci” as

reported (CAPP 1992).

2.7 COMBINING THE RESULTS OF METHOD 1 AND 2

A hybrid approach was used to combine the results of Method 1 and Method 2. This was done

using Equation 4 for each component and service category (i.e., the summation is with respect

to the different data sets where each data set has its own EFAverage and NTotal values):

NTotalMethod1 ⋅ EFAverageMethod1 + NTotalMethod 2 ⋅ EFAverageMethod 2

EFAverage = Equation 4

NTotalMethod 1 + NTotalMethod 2
12

3 COMPONENT EMISSION FACTORS

3.1 LEAK SURVEY RESULTS

Table 5  presents the  total  estimated  number of each equipment component type  and the

number that were reported to be leaking at the facilities for which fugitive emission surveys

were completed and submitted for consideration. The relative distribution of these results is

depicted in Figure 1. A leak frequency of 17.37% was reported for Compressor Seals (GV). This is

a component type that is expected to vent. The average emission rate of those reported was

0.24171 kg/h/source with a standard deviation of 233%. Similarly, for Control Valve (GV), a leak

frequency of 38% was reported with a variability that was considerably less at 117%.

Some situations arose where certain component types occurred at a facility based on the leak

survey results but were not identified for that facility by the applied methodology for developing

facility‐level equipment component counts. Additionally, some cases occurred where the

estimated number of components in a given category for a facility was less than the number of

leaking components identified by the leak survey for the facility. The occurrences of these two

types of discrepancies are summarized in Table 6 and are attributed to weaknesses in the CAPP

(2005) default equipment schedules used to develop the estimated component counts. While

there is some potential to improve these default equipment schedules to help avoid the

identified discrepancies and improve the overall accuracy for all applicable component

categories, the uncertainties in the current schedules are not believed to have a significant

adverse impact on the developed emission factors given that they were initially derived from a

large reliable data set. Moreover, as a conservative approach, the estimated facility‐level

component counts were set equal to the population of reported leaks (i.e., an implied leak

frequency of 100%) for categories where the initial estimated count was less than the reported

number of leaks. The following are some examples of observed count discrepancies:

• 7 of 82 Compressor Seal (GV) components were reported leaking at facilities where no

compressor seals were calculated to be present. Further the average leak rate of these

compressor seals was 2.53 times the average leak rate reported for compressor seal

leaks.

• All reported Control Valve (FG), Pressure Relief Valve (FG), Regulator (FG) and Regulator

(LL) leaks were at facilities where the total component counts for those component

types were zero.

• Except for Valve (GV), average leak rates of component types, at facilities where the

total   component   count  was  zero,  were   greater  than  the   average  of  the   leaking

components presented in Table 5.
13

Table 5: Summary of leak survey results showing leak frequency, average leak rate and leak rate standard deviation.

Component Type Estimated

Total

Components1

Applied

Total

Components

Reported

Leaking

Components2

Leak

Frequency:

Average3

(%)

Leak Rate:

Average4

(kg/h/source)

Lea

S

(kg/

Compressor Seal (GV) 472 472 82 17.37 0.24171 0Connector (FG) 46,241 46,241 390 0.84 0.11701 0Connector (GV) 153,741 153,741 229 0.15 0.05795 0Connector (LL) 32,508 32,508 10 0.03 0.08497 0Control Valve (FG) 0 14 14 100.00 0.10670 0Control Valve (GV) 50 50 19 38.00 0.06349 0Open‐Ended Line (FG) 0 23 23 100.00 0.36372 0Open‐Ended Line (GV) 1,173 1,173 25 2.13 2.64852 5Open‐Ended Line (LL) 4 4 0 0.00 0.00000 0Pressure Relief Valve (FG) 79 80 1 1.27 0.00000 0Pressure Relief Valve (GV) 1,054 1,054 2 0.19 0.00018 0Pressure Relief Valve (LL) 16 16 0 0.00 0.00000 0Pump Seal (FG) 0 3 3 100.00 0.06469 0Pump Seal (LL) 436 436 0 0.00 0.00000 0Regulator (FG) 27 66 44 162.96 0.19491 0Regulator (GV) 103 105 15 14.56 0.34456 1Regulator (LL) 0 1 1 100.00 0.00000 0Valve (FG) 3,310 3,310 64 1.93 0.08367 0Valve (GV) 27,214 27,214 122 0.45 0.08184 0Valve (LL) 10,519 10,519 11 0.10 0.03865 01 Total Components = Sum of components by type for all facilitiesincluded in survey.
14

Table 5: Summary of leak survey results showing leak frequency, average leak rate and leak rate standard deviation.

Component Type Estimated

Total

Components1

Applied

Total

Components

Reported

Leaking

Components2

Leak

Frequency:

Average3

(%)

Leak Rate:

Average4

(kg/h/source)

Lea

S

(kg/

2 Leaking components = Total number of leaking components by type included in survey.3 Leak Frequency = Number leaking divided by total number by component type.4 Leak Rate: Average of Leak Rate: Average = Sum of emissionsfrom all components of that type divided by the total number of that 5 Leak Rate: STDEV = SDTEV of all leak rates by component type.
Table 6:   Summary of leak survey results showing the number of leaking components, the average leak rate and the

leak rate standard deviation for reported emissions where the estimated facility component count for the

leaking component was zero.

Component Type Leaking

Components1

(Number)

Leak Rate:

Average2

(kg/h/source)

Leak Rate:

STDEV3

(kg/h/source)

STDEV/

Average

(%)

Leaking

Components

Table 5

(Number)

Leak Rate

Table

6/Table 5

(Ratio)

Compressor Seal (GV) 7 0.61142 0.42697 70 82 2.530

Connector (FG) 14 0.21844 0.25549 117 390 1.867

Control Valve (FG) 14 0.10670 0.09843 92 14 1.000

Control Valve (GV) 7 0.08497 0.06722 79 19 1.338

Open‐Ended Line (FG) 23 0.36372 0.87591 241 27 1.000

Open‐Ended Line (GV) 1 0.00000     25 0.000

Pressure Relief Valve (FG) 1 0.00000     1 0.000

Pump Seal (FG) 3 0.06469 0.07612 118 3 1.000

Regulator (FG) 44 0.19491 0.35115 180 44 1.000

Regulator (GV) 10 0.49748 1.32425 266 15 1.444

Regulator (LL) 1 0.00000     1 0.000

Valve (FG) 2 0.11893 0.02403 20 64 0.287

1 Leaking components = Total number of leaking components by type included in survey.

2 Leak Rate: Average = Average of all leak rates by component type.

3 Leak Rate: STDEV = SDTEV of all leak rates by component type.

15
Number

472

82

46,241 390

153,741 229

32,508 10

14

14

50

19

23

23

1,173

2540

801

1,054 2

16033

436 0

66

44

105

15

180000160000140000120000100000

80000600004000020000

0

Total Count and Leaking Count by Components Type 

Figure 1: Distribution of the applied total count and leaking component count by component type in database and pres

16
3.2 METHOD 1 LEAK FREQUENCY AND EMISSION RESULTS

Company D provided leak data without emission measurements for a total of five facilities. The

data provided was processed based on Method 1 described in Section 2.5 and the emission

factor results are presented in Table 7.

All facilities in this category were from the crude oil sector, and all were designated as sour.

Except for Valve (FG), the calculated emission factors for the component types listed were

somewhat (ratio of 0.28 to 0.68) to considerably (ratio of 0.002 to 0.006) less than the CAPP

(2005) emission factors. The emission factor for Valve (FG) compared favorably (ratio of 1.09)

with the corresponding CAPP (2005) emission factor.

Component type counts, total and leakers, for all results in the Method 1 calculation category

were small ranging from 1 for Open‐ended Line (LL) to a maximum of 4831 for Connector (GV).

17
Table 7: Emissions and leak frequency results from application of Method 1 to sites having leaker counts but no leak measurement 

Sector Sweet/

Sour

Component

Type

Service Leaker

Count

Component Count Leak

Frequency

EF (kg/source/d) Method 1

EF3,5

95 %

Lower

Estimated Applied (%) Leak No‐Leak (kg/h/source) Confidence Limit 

Oil Sour Compressor

Seal

GV 0 16 16 0 1.60800 0.00175 0.00175 41% 

Oil Sour Connector FG 32 2552 2552 1.25 0.03750 0.00023 0.00070 30% 

Oil Sour Connector GV 7 4831 4831 0.14 0.03750 0.00023 0.00028 36% 

Oil Sour Connector LL 0 1866 1866 0.00 0.03750 0.00013 0.00013 41% 

Oil Sour Control Valve GV 0 0 0 0.00 0.04510 0.00008 0.00000 25% 

Oil Sour Open‐Ended

Line

Oil Sour Pressure

ReliefValve

Oil Sour Pressure

Relief

Valve

GV 0 39 39 0.00 0.01195 0.00183 0.00183 41% 

FG 0 0 0 0.00 1.69100 0.00019 0.00000 25% 

GV 0 27 27 0.00 1.69100 0.00019 0.00019 41% 

Oil Sour Pump Seal LL 0 36 36 0.00 0.43700 0.00230 0.00230 41% 

Oil Sour Regulator FG 2 0 2 100.00 0.04510 0.00008 0.04510 77% 

Oil Sour Regulator GV 0 0 0 0.00 0.04510 0.00008 0.00000 25% 

Oil Sour Valve FG 5 144 144 3.47 0.04510 0.00008 0.00164 80% 

Oil Sour Valve GV 1 915 915 0.11 0.04510 0.00008 0.00013 44% 

Oil Sour Valve LL 0 580 580 0.00 0.08520 0.00058 0.00058 41% 

1 Results are based on Company D data2 Results based on application of Equation 13 Results based on application of Equation 24 Default CAPP fugitive emission rate for component type from Table 2.5 No‐Leak and Leak emission factors are from Table 1.

18
19

3.3 METHOD 2 LEAK FREQUENCY AND EMISSION RESULTS

Four companies provided leak survey data that included measured leak rates for 115 UOG

facilities in both the oil and natural gas sectors, and included both sweet and sour facilities. The

data were processed using Method 2 as described in Section 2.6. The results are presented in

Table 8 and the developed emission factors are compared to the CAPP (2005) results. Except for

a few categories comprising small numbers of components and, consequently, subject to high

uncertainties, the rest of the categories showed significant decreases in the determined average

emissions factors.

The presented confidence limits in Table 8 account for the combined effects of uncertainties in

the following parameters:

• Average leaker emission rate per component (the values for each component category

were calculated based on the standard deviation in the measured leak rates).

• Default no‐leak rate per component (a lower uncertainty limit of  ‐20% and an upper

uncertainty limit of +500% were assumed).

• Number of leakers (an uncertainty of ±10% was assumed).

• Estimated number of non‐leakers (an uncertainty of ±25% was assumed).

The procedures used to combine the above uncertainties are delineated in Section 8 (Appendix

C). The developed factors tend to have greater uncertainties than the CAPP (2005) factors

because they include additional uncertainties (i.e., the number of non‐leakers).

The leak frequencies range from 0% to 100%. Considering only those component types where

the total component count exceeds 500, leak frequencies are less than 1% with two exceptions:

Gas‐Sweet‐Open‐Ended Line (GV) and Gas‐Sweet‐Valve (FG). No apparent trend relating

frequency to total count was noted as depicted by the data presented in Figure 2.
20

Figure 2:    Leak frequency versus Total Component Count including all component types

(frequencies greater than 1% and counts less than 500 and greater than 40,000

excluded).

The ratio of Method 2 emission factors to CAPP (2005) emission factors indicates that, with only

a few exceptions, the Method 2 emission factors are less than CAPP (2005). If categories with

fewer than 50 components are excluded, the exceptions are:

• Gas‐Sour‐Connector (FG) with a total count of 5,165 and a ratio of 1.911

• Gas‐Sour‐Connector (G/V) with a total count of 23,661 and a ratio of 1.764

• Gas‐Sweet‐Connector (FG) with a total count of 32,994 and a ratio of 1.911

• Oil‐Sweet‐Open‐Ended Line (GV) with a count of 85 and a ratio of 1.048

• Oil‐Sweet‐Valve (GV) with a count of 2,734 and a ratio of 1.353

If the total assessed emissions (i.e., the sum of the estimated no‐leak and measured leak

contributions) for the sample population of components used to develop the Method 2 factors

is compared to what would be estimated for the same sample set of components based on the

pre‐2007 emission factors (CAPP, 2005), then the overall result is a net emissions reduction of

73.7%.

3.4 COMBINED AND CONSOLIDATED EMISSION FACTOR RESULTS

The final emission factors determined by combining the results of the Method 1 and Method 2

data sets are presented in Table 9. Consolidating subcategories of each component type where
21

the differences between like categories are not statistically significant results in the final set of

developed emission factors, and these are presented in Table 10.

If the total assessed emissions (i.e., the sum of the estimated and measured leak contributions)

for the sample population of components used to develop the combined factors is compared to

what would be estimated for the same sample set of components based on the pre‐2007

emission factors (CAPP, 2005), then the overall result is a net emissions reduction of 75.3%.
22

Table 8: Emissions and leak frequency results using Method 2 for sites with measured leak rates.

Sector Sweet/

Sour

Component

Type

Service Leaker

Count

Component Count Leak

Frequency2

(%)

Sum of

Leaks

(kg/h)

No‐Leak

EF

(kg/h/source)

Method 2

EF3,5

(kg/h/source)

95 %

Lower

Confidence

Limit

Co

Estimate Applied

Gas Sour Compressor

Seal

GV 7 22 22 31.82 4.2799 0.00175 0.19573 28% 

Gas Sour Connector FG 34 5,165 5,165 0.66 4.9647 0.00061 0.00157 30% Gas Sour Connector GV 20 23,661 23,661 0.09 1.3518 0.00019 0.00025 36% Gas Sour Connector LL 0 1,509 1,509 0.00 0 0.00013 0.00013 41% Gas Sour Control Valve GV 1 1 1 100.00 0.068 0.00010 0.06800 189% Gas Sour Open‐Ended

Line

GV 4 100 100 4.00 0.9755 0.00183 0.01151 36% 

Gas Sour Pressure

Relief Valve

FG 0 17 17 0.00 0 0.00019 0.00019 41% 

Gas Sour Pressure

Relief Valve

LL 1 0 1 100.00 0.00019 0.00019 0.00019 25% 

Gas Sour Pressure

Relief Valve

GV 0 77 77 0.00 0 0.00019 0.00019 41% 

Gas Sour Pump Seal LL 0 23 23 0.00 0 0.00230 0.00230 41% Gas Sour Regulator FG 3 25 25 12.00 0.6796 0.00023 0.02739 50% Gas Sour Regulator GV 2 5 5 40.00 0.0023 0.00010 0.00052 2115% Gas Sour Regulator LL 1 0 1 100.00 0.0001 0.00010 0.00010 25% Gas Sour Valve FG 3 603 603 0.50 0.3609 0.00023 0.00083 56% Gas Sour Valve GV 1 2,473 2,473 0.04 0.0001 0.00010 0.00010 41% Gas Sour Valve LL 0 554 554 0.00 0 0.00081 0.00081 41% Gas Sweet Compressor

Seal

GV 72 402 402 17.91 14.9113 0.00175 0.03853 26% 

Gas Sweet Connector FG 287 32,994 32,994 0.87 31.7444 0.00061 0.00157 28% Gas Sweet Connector GV 193 108,328 108,328 0.18 7.9791 0.00061 0.00068 38% Gas Sweet Connector LL 10 23,694 23,694 0.04 0.8497 0.00013 0.00017 36% Gas Sweet Control Valve FG 13 0 13 100.00 1.3239 0.00023 0.10184 44% Gas Sweet Control Valve GV 17 47 47 36.17 1.0364 0.00023 0.02220 48% Gas Sweet Open‐Ended FG 20 0 20 100.00 7.3291 0.00183 0.36646 27% 
23

Table 8: Emissions and leak frequency results using Method 2 for sites with measured leak rates.

Sector Sweet/

Sour

Component

Type

Service Leaker

Count

Component Count Leak

Frequency2

(%)

Sum of

Leaks

(kg/h)

No‐Leak

EF

(kg/h/source)

Method 2

EF3,5

(kg/h/source)

95 %

Lower

Confidence

Limit

Co

Estimate Applied

Line

Gas Sweet Open‐Ended

Line

GV 16 890 890 1.80 37.102 0.00183 0.04348 25% 

Gas Sweet Open‐Ended

Line

LL 0 2 2 0.00 0 0.00183 0.00183 41% 

Gas Sweet Pressure

Relief Valve

FG 0 48 48 0.00 0 0.00019 0.00019 41% 

Gas Sweet Pressure

Relief Valve

GV 2 779 779 0.26 0.0004 0.00019 0.00019 49% 

Gas Sweet Pressure

Relief Valve

LL 0 16 16 0.00 0 0.00019 0.00019 41% 

Gas Sweet Pump Seal FG 3 0 3 100.00 0.1941 0.00019 0.06470 108% Gas Sweet Pump Seal LL 0 283 283 0.00 0 0.00230 0.00230 41% Gas Sweet Regulator FG 33 2 33 100.00 5.128 0.00023 0.15539 29% Gas Sweet Regulator GV 9 94 94 9.57 0.2389 0.00023 0.00275 98% Gas Sweet Valve FG 54 2,099 2,099 2.57 4.2866 0.00023 0.00227 31% Gas Sweet Valve GV 114 20,052 20,052 0.57 4.4144 0.00023 0.00045 31% Gas Sweet Valve LL 11 7,584 7584 0.15 0.4252 0.00081 0.00086 39% Oil Sour Compressor

Seal

GV 0 8 8 0 0 0.00175 0.00175 41% 

Oil Sour Connector FG 6 1,314 1,314 0.46 0.6796 0.00023 0.00075 45% Oil Sour Connector GV 1 4,905 4,905 0.02 0.1359 0.00023 0.00026 40% Oil Sour Connector LL 0 1,750 1,750 0.00 0 0.00013 0.00013 41% Oil Sour Control Valve GV 0 1 1 0.00 0 0.00008 0.00008 41% Oil Sour Open‐Ended

Line

GV 1 59 59 1.70 0.8495 0.00183 0.01620 36% 

Oil Sour Pressure

Relief Valve

FG 0 4 4 0.00 0 0.00019 0.00019 41% 

Oil Sour Pressure

Relief Valve

GV 0 49 49 0.00 0 0.00019 0.00019 41% 
24

Table 8: Emissions and leak frequency results using Method 2 for sites with measured leak rates.

Sector Sweet/

Sour

Component

Type

Service Leaker

Count

Component Count Leak

Frequency2

(%)

Sum of

Leaks

(kg/h)

No‐Leak

EF

(kg/h/source)

Method 2

EF3,5

(kg/h/source)

95 %

Lower

Confidence

Limit

Co

Estimate Applied

Oil Sour Pump Seal LL 0 21 21 0.00 0 0.00230 0.00230 41% Oil Sour Regulator FG 0 0 0 0.00 0 0.00008 0.00000 0% Oil Sour Regulator GV 0 2 2 0.00 0 0.00008 0.00008 41% Oil Sour Valve FG 1 115 115 0.87 0.068 0.00008 0.00067 167% Oil Sour Valve GV 2 1,040 1,040 0.19 0.1189 0.00008 0.00019 91% Oil Sour Valve LL 0 557 557 0.00 0 0.00058 0.00058 41% Oil Sweet Compressor

Seal

GV 3 24 24 12.50 0.6286 0.00175 0.02772 47% 

Oil Sweet Connector FG 31 4,216 4,216 0.74 4.5024 0.00023 0.00130 30% Oil Sweet Connector GV 8 12,016 12,016 0.07 3.398 0.00023 0.00051 30% Oil Sweet Connector LL 0 3,689 3,689 0.00 0 0.00013 0.00013 41% Oil Sweet Control Valve FG 1 0 1 100.00 0.1699 0.00008 0.16990 98% Oil Sweet Control Valve GV 1 1 1 100.00 0.1019 0.00008 0.10190 141% Oil Sweet Open‐Ended

Line

FG 3 0 3 100.00 1.0364 0.00183 0.34547 40% 

Oil Sweet Open‐Ended

Line

GV 4 85 85 4.71 27.2861 0.00183 0.32276 25% 

Oil Sweet Open‐Ended

Line

LL 0 2 2 0.00 0 0.00183 0.00183 41% 

Oil Sweet Pressure

Relief Valve

FG 0 10 10 0.00 0 0.00019 0.00019 41% 

Oil Sweet Pressure

Relief Valve

GV 0 122 122 0.00 0 0.00019 0.00019 41% 

Oil Sweet Pump Seal LL 0 73 73 0.00 0 0.00230 0.00230 41% Oil Sweet Regulator FG 6 0 6 100.00 2.3786 0.00008 0.39643 31% Oil Sweet Regulator GV 4 2 4 100.00 4.9271 0.00008 1.23178 27% Oil Sweet Valve FG 1 349 349 0.29 0.2209 0.00008 0.00071 73% Oil Sweet Valve GV 4 2,734 2,734 0.15 5.3689 0.00008 0.00204 26% Oil Sweet Valve LL 0 1,244 1,244 0.00 0 0.00058 0.00058 41% 
25

Table 8: Emissions and leak frequency results using Method 2 for sites with measured leak rates.

Sector Sweet/

Sour

Component

Type

Service Leaker

Count

Component Count Leak

Frequency2

(%)

Sum of

Leaks

(kg/h)

No‐Leak

EF

(kg/h/source)

Method 2

EF3,5

(kg/h/source)

95 %

Lower

Confidence

Limit

Co

Estimate Applied

1 Results are based on data from all companies except Company D.2 Results based on application of Equation 13 Results based on application of Equation 34 Default CAPP fugitive emission rate for component type from Table 2.5 Where Total Number = zero and Number Leakers is > zero, Method 2 emission factor = Sum Of All Leaks/Number Leakers and result is shaded in grey.
26

Table 9: Combined emission factor results from the Method 1 and Method 2 data sets.

Sector Sweet/

Sour

Component

Type

Service Method 1 Data Method 2 Data Combined Results 

Applied

Component

Count

Average EF

(kg/h/source)

Applied

Component

Count

Average EF

(kg/h/source)

Average EF

(kg/h/source)

95 % Lower

Confidence

Limit

(%)

95 % Upper

Confidence

Limit

(%)

Average 

(kg/h/sou

Gas Sour Compressor

Seal

GV 0 0.00000 22 0.19573 0.19573 45.20 45.30% 0.71

Gas Sour Connector FG 0 0.00000 5,165 0.00157 0.00157 46.25 198.64% 0.00

Gas Sour Connector GV 0 0.00000 23,661 0.00025 0.00025 50.51 387.33% 0.00

Gas Sour Connector LL 0 0.00000 1,509 0.00013 0.00013 53.85 502.49% 0.00

Gas Sour Control

Valve

Gas Sour Open‐ 

Ended Line

Gas Sour Pressure

Relief Valve

Gas Sour Pressure

Relief Valve

Gas Sour Pressure

Relief Valve

GV 0 0.00000 1 0.06800 0.06800 192.64 192.64% 0.00

GV 0 0.00000 100 0.01151 0.01151 50.35 91.37% 0.18

FG 0 0.00000 17 0.00019 0.00019 53.85 502.49% 0.01

LL 0 0.00000 1 0.00019 0.00019 43.30 43.30% 0.02

GV 0 0.00000 77 0.00019 0.00019 53.85 502.49% 0.01

Gas Sour Pump Seal LL 0 0.00000 23 0.00230 0.00230 53.85 502.49% 0.02

Gas Sour Regulator FG 0 0.00000 25 0.02739 0.02739 61.29 61.40% 0.00

Gas Sour Regulator GV 0 0.00000 5 0.00052 0.00052 2115.24 2116.03% 0.00

Gas Sour Regulator LL 0 0.00000 1 0.00010 0.00010 43.30 43.30% 0.00

Gas Sour Valve FG 0 0.00000 603 0.00083 0.00083 66.06 153.17% 0.00

Gas Sour Valve GV 0 0.00000 2,473 0.00010 0.00010 53.84 502.29% 0.00

Gas Sour Valve LL 0 0.00000 554 0.00081 0.00081 53.85 502.49% 0.00

Gas Sweet Compressor

Seal

GV 0 0.00000 402 0.03853 0.03853 43.72 47.52% 0.71

Gas Sweet Connector FG 0 0.00000 32,994 0.00157 0.00157 45.20 198.04% 0.00

Gas Sweet Connector GV 0 0.00000 108,328 0.00068 0.00068 51.88 448.70% 0.00

Gas Sweet Connector LL 0 0.00000 23,694 0.00017 0.00017 50.58 394.80% 0.00
27

Table 9: Combined emission factor results from the Method 1 and Method 2 data sets.Sector Sweet/

Sour

Component

Type

Service Method 1 Data Method 2 Data Combined Results 

Applied

Component

Count

Average

EF

(kg/h/source)

Applied

Component

Count

Average

EF

(kg/h/source)

Average

EF

(kg/h/source)

95 %

Lower

Confidence

Limit

(%)

95 %

Upper

Confidence

Limit

(%)

Averag

EF

(kg/h/sou

Gas Sweet Control

Valve

FG 0 0.00000 13 0.10184 0.10184 56.18 56.18 0.01

Gas Sweet Control

Valve

GV 0 0.00000 47 0.02220 0.02220 59.40 59.50 0.01

Gas Sweet Open‐ 

Ended Line

FG 0 0.00000 20 0.36646 0.36646 44.40 44.40 0.46

Gas Sweet Open‐ 

Ended Line

GV 0 0.00000 890 0.04348 0.04348 43.39 48.05 0.46

Gas Sweet Open‐ 

Ended Line

LL 0 0.00000 2 0.00183 0.00183 53.85 502.49 0.01

Gas Sweet Pressure

Relief Valve

FG 0 0.00000 48 0.00019 0.00019 53.85 502.49 0.01

Gas Sweet Pressure

Relief Valve

GV 0 0.00000 779 0.00019 0.00019 60.39 501.90 0.01

Gas Sweet Pressure

Relief Valve

LL 0 0.00000 16 0.00019 0.00019 53.85 502.49 0.00

Gas Sweet Pump Seal FG 0 0.00000 3 0.06470 0.06470 114.02 114.02 0.02Gas Sweet Pump Seal LL 0 0.00000 283 0.00230 0.00230 53.85 502.49 0.02Gas Sweet Regulator FG 0 0.00000 33 0.15539 0.15539 45.67 45.67 0.00Gas Sweet Regulator GV 0 0.00000 94 0.00275 0.00275 104.48 111.10 0.00Gas Sweet Valve FG 0 0.00000 2,099 0.00227 0.00227 47.24 68.35 0.00Gas Sweet Valve GV 0 0.00000 20,052 0.00045 0.00045 47.30 258.91 0.00Gas Sweet Valve LL 0 0.00000 7,584 0.00086 0.00086 52.79 470.19 0.00

Oil Sour Compressor

Seal

GV 16 0.00175 8 0.00175 0.00175 40.14 171.30 0.80

Oil Sour Connector FG 2,552 0.00070 1,314 0.00075 0.00071 36.09 68.83 0.00Oil Sour Connector GV 4,831 0.00028 4,905 0.00026 0.00027 36.66 217.08 0.00Oil Sour Connector LL 1,866 0.00013 1,750 0.00013 0.00013 38.10 244.77 0.00
28

Table 9: Combined emission factor results from the Method 1 and Method 2 data sets.Sector Sweet/

Sour

Component

Type

Service Method 1 Data Method 2 Data Combined Results 

Applied

Component

Count

Average

EF

(kg/h/source)

Applied

Component

Count

Average

EF

(kg/h/source)

Average

EF

(kg/h/source)

95 %

Lower

Confidence

Limit

(%)

95 %

Upper

Confidence

Limit

(%)

Averag

EF

(kg/h/sou

Oil Sour Control

Valve

GV 0 0.00000 1 0.00008 0.00008 53.85 502.49 0.01

Oil Sour Open‐ 

Ended Line

GV 39 0.00183 59 0.01620 0.01048 44.45 68.12 0.30

Oil Sour Pressure

Relief Valve

FG 0 0.00000 4 0.00019 0.00019 53.85 502.49 0.01

Oil Sour Pressure

Relief Valve

GV 27 0.00019 49 0.00019 0.00019 39.64 324.54 0.01

Oil Sour Pump Seal LL 36 0.00230 21 0.00230 0.00230 39.38 188.23 0.02Oil Sour Regulator FG 2 0.04510 0 0.00000 0.04510 84.61 35.36 0.00Oil Sour Regulator GV 0 0.00000 2 0.00008 0.00008 53.85 502.49 0.00Oil Sour Valve FG 144 0.00164 115 0.00067 0.00121 77.69 136.24 0.00Oil Sour Valve GV 915 0.00013 1,040 0.00019 0.00016 64.77 147.81 0.00Oil Sour Valve LL 580 0.00058 557 0.00058 0.00058 38.09 247.69 0.00

Oil Sweet Compressor

Seal

GV 0 0.00000 24 0.02772 0.02772 58.54 64.71 0.80

Oil Sweet Connector FG 0 0.00000 4,216 0.00130 0.00130 46.27 99.42 0.00Oil Sweet Connector GV 0 0.00000 12,016 0.00051 0.00051 46.39 228.75 0.00Oil Sweet Connector LL 0 0.00000 3,689 0.00013 0.00013 53.85 502.49 0.00Oil Sweet Control

Valve

FG 0 0.00000 1 0.16990 0.16990 103.92 103.92 0.01

Oil Sweet Control

Valve

GV 0 0.00000 1 0.10190 0.10190 145.23 145.23 0.01

Oil Sweet Open‐ 

Ended Line

FG 0 0.00000 3 0.34547 0.34547 53.21 53.21 0.30

Oil Sweet Open‐ 

Ended Line

GV 0 0.00000 85 0.32276 0.32276 43.39 43.47 0.30

Oil Sweet Open‐  LL 0 0.00000 2 0.00183 0.00183 53.85 502.49 0.00
29

Table 9: Combined emission factor results from the Method 1 and Method 2 data sets.Sector Sweet/

Sour

Component

Type

Service Method 1 Data Method 2 Data Combined Results 

Applied

Component

Count

Average

EF

(kg/h/source)

Applied

Component

Count

Average

EF

(kg/h/source)

Average

EF

(kg/h/source)

95 %

Lower

Confidence

Limit

(%)

95 %

Upper

Confidence

Limit

(%)

Averag

EF

(kg/h/sou

Ended Line

Oil Sweet Pressure

Relief Valve

FG 0 0.00000 10 0.00019 0.00019 53.85 502.49 0.01

Oil Sweet Pressure

Relief Valve

GV 0 0.00000 122 0.00019 0.00019 53.85 502.49 0.01

Oil Sweet Pump Seal LL 0 0.00000 73 0.00230 0.00230 53.85 502.49 0.02Oil Sweet Regulator FG 0 0.00000 6 0.39643 0.39643 47.31 47.31 0.00Oil Sweet Regulator GV 0 0.00000 4 1.23178 1.23178 44.31 44.31 0.00Oil Sweet Valve FG 0 0.00000 349 0.00071 0.00071 81.46 98.80 0.00Oil Sweet Valve GV 0 0.00000 2,734 0.00204 0.00204 44.04 48.18 0.00Oil Sweet Valve LL 0 0.00000 1,244 0.00058 0.00058 53.85 502.49 0.00
30

Table 10: Final consolidated emission factors for application in estimating fugitive emissions from upstream oil and gas facilities after the implem

program.

Sector Sweet/

Sour

Component

Type

Service Leaker

Count

Component

Count

Leak

Frequency

Post‐2007 Consolidated Results CAPP (2

EF

(kg/h/source)

95 %

Lower

Confidence

Limit

95 %

Upper

Confidence

Limit

EF

(kg/h/source)

95 

Low

Confid

Lim

Gas All Compressor

Seals

GV 79 424 18.63% 0.04669 40.98% 43.50% 0.71300 

Gas All Connector GV 534 170,148 0.31% 0.00082 36.22% 250.08% 0.00082 Gas All Connector LL 10 25,203 0.04% 0.00016 53.81% 377.53% 0.00055 Gas All Control

Valve

GV 31 61 50.82% 0.03992 43.70% 43.72% 0.01620 

Gas All Open‐ 

Ended Line

All 40 1,012 3.95% 0.04663 41.85% 45.18% 0.46700 

Gas All Pressure

Relief Valve

All 3 938 0.32% 0.00019 54.60% 420.36% 0.01700 

Gas All Pump Seal All 3 309 0.97% 0.00291 50.01% 366.79% 0.02320 Gas All Regulator All 48 158 30.38% 0.03844 44.83% 44.86% 0.00811 Gas All Valve GV 172 25,227 0.68% 0.00057 37.63% 163.49% 0.00281 Gas All Valve LL 11 8,138 0.14% 0.00086 54.80% 441.88% 0.00352 

Oil All Compressor

Seals

GV 3 48 6.25% 0.01474 59.93% 66.05% 0.80500 

Oil All Connector GV 85 29,834 0.28% 0.00057 27.05% 96.39% 0.00246 Oil All Connector LL 0 7,305 0.00% 0.00013 36.49% 281.62% 0.00019 Oil All Control

Valve

GV 2 3 66.67% 0.09063 86.67% 86.67% 0.01460 

Oil All Open‐ 

Ended Line

All 8 188 4.26% 0.15692 46.64% 46.74% 0.30800 

Oil All Pressure

Relief Valve

All 0 212 0.00% 0.00019 37.71% 313.14% 0.01630 

Oil All Pump Seal All 0 130 0.00% 0.00230 38.39% 294.44% 0.02320 Oil All Regulator All 12 14 85.71% 0.52829 38.03% 38.01% 0.00668 Oil All Valve GV 14 5,297 0.26% 0.00122 44.15% 48.07% 0.00151 Oil All Valve LL 0 2,381 0.00% 0.00058 36.94% 288.37% 0.00121 
31

4 DISCUSSION OF RESULTS AND RECOMMENDATIONS

4.1 EQUIPMENT  SCHEDULES  

Establishing equipment schedules for each of the facilities, without detailed field inspections or

operator feedback, presented significant challenges that reflect on the accuracy and uncertainty

of the final results. Equipment and process count issues encountered are summarized in Table

11.

Table 11:   Issued encountered in establishing equipment and process type counts for each

facility.

Issue Description

1 Meter schematics are not complete for purposes of making equipment counts.

Equipment in process service is mostly included but non‐process equipment

supplied with fuel gas is typically not shown or listed.

2 PFDs, PI&Ds and meter schematics are inconsistent with respect to the types of

equipment shown or listed. For example, pig receivers and launchers, meters, and

ESD valves often are not shown.

3 Facility boundaries are not well defined. Drawings attempt to show boundaries but

these are not necessarily clearly defined. Associated files listing equipment are not

boundary compatible.

4 Equipment listed in equipment files for a facility may include off‐site equipment

associated with gathering systems and well sites.

5 The naming conventions and process unit boundaries used for equipment are not

always compatible with those used in the CAPP default lists. For example glycol

dehydrators are sometimes listed as process boiler with a note in the comments

column indicating it is the dehydrator reboiler. Sometimes a contactor vessel is not

listed. Same applies for gas‐fired treaters. Line heaters were not always listed

properly.

6 Office furnaces, catalytic heaters and gas‐fired unit heaters seem to fall into the gas‐

fired unit heater category but not consistently.

7 Compressor vents are not completely defined resulting in miscoding of some

emissions.

8 The equipment schedules would benefit from regrouping, editing and equipment

defining.

9 Fugitive equipment leak component coding indicates that equipment component

schedules do not always capture all component types reported in the corresponding

leak surveys. Where this occurred it was for component types present in small

numbers and therefore did not significantly compromise the overall quality of the

developed component count estimates. Moreover, corrections were made to at

least ensure that the component counts in these cases were at least equal to the

number of detected leaks, which is conservative. Nonetheless, some opportunity for

improvement exists.
32

4.1.1 EQUIPMENT SCHEDULE RECOMENDATIONS

The  process and major equipment unit default equipment component schedules should be

updated and republished with equipment and process definitions and application instructions.

This should be done based on detailed component counts performed at actual facilities.

4.2 COMPONENT COUNTS

Default component counts listed in Table 12 are not complete and in some cases do not include

all appropriate component types listed by service (FG, GV, LL or HL). Fugitive emission surveys

identified some leaking component types at facilities where the estimated component type

count was zero; although, in these cases, the missed components were only present in small

quantities and corrections were made to account for these missed components.

4.2.1    COMPONENT COUNT RECOMMENDATIONS

These  results  should  be  reviewed  and,  where  appropriate,  used  for  updating  the  default

component counts.

4.3 EMISSION  FACTOR  RESULTS  

A direct comparison of the final developed emission factors with the previous CAPP (2005)

factors is provided in Table 10. Overall, a net component‐weighted reduction of 75 percent was

observed across all of the component categories. The emission factors for control valves and

regulators showed noteworthy increases for both natural gas and crude oil systems compared

to the CAPP (2005) factors; this is may reflect the impact of better leak measurement data for

these sources, but is suspected to be largely due to the poor quality of the component counts

for these categories potentially resulting an overstatement of the leak frequencies. The emission

factor for connectors in G/V service at natural gas facilities is unchanged. All other factors show

substantial reductions compared to the CAPP (2005) values, and they are based on relatively

large component populations which improves their reliability.

4.3.1    RECOMMENDATIONS

It  is  recommended  that  the  average  emission  factors  presented  in  Table  10  be  used  for

estimating emissions due to fugitive equipment leaks at facilities that are actively applying the

CAPP BMP for managing fugitive equipment leaks. The CAPP (2005) emission factors should still

be used for periods prior to implementation of the CAPP BMP and for facilities that are not

applying the CAPP BMP.
33

5 REFERENCES

CAPP. 1992.       A  Detailed  Inventory  of  CH4  and  VOC  Emissions  from  Upstream  Oil  &  Gas

Operations in Alberta, Vol III, Results of the Field Validation Program, Table 7, Picard et al,

March 1992.

CAPP. 2005        A National Inventory of Greenhouse Gas (GHG), Criteria Air Contaminant (CAC)

and Hydrogen Sulphide (H2S) Emissions by the Upstream Oil and Gas Industry Volume 5,

Compendium of Terminology, Information Sources, Emission Factors, Equipment Sched’s and

Uncertainty Data September 2004, Tables 3.1 and 4.1, Publication No. 2005‐0015.

IPCC. 2000. Good Practice Guidance and Uncertainty Management in National Greenhouse Gas

Inventories. http://www.ipcc‐nggip.iges.or.jp/public/gp/english/.
34

6 APPENDIX A – DEFAULT COMPONENT COUNTS BY TYPE OF PROCESS OR

MAJOR  EQUIPMENT  UNIT

The CAPP published schedule of default equipment component counts for specified process and

major equipment unit types is tabulated in Table 12. The list of equipment or process types has

been reordered and grouped to improve user application and additional equipment or process

types have been added to clarify type designations. For new types no estimation of component

counts is provided.
35

Table 12: Schedule of default component counts per equipment or process type (CAPP 2005).Equipment / Process Type and Default ComponentCounts

Connector(GV)

Connector(FG)

Connector(HL)

Connector(LL)

Control Valve (GV)

Compressor Seal(GV)

Compressor Seal (FG)

Open‐Ended Line (FG)

Open‐Ended Line (GV)

Open‐Ended Line (LL)

Pressure Relief Valve (FG)

Pressure Relief Valve (GV)

Pressure Relief Valve (HL)

Pressure Relief Valve (LL)

Pump Seal (HL)

Absorption 200 46 4 Absorption: Cold Bed 134 12 1 Adsorption 200 46 4 Battery: Heavy Oil Satellite 42 42 84 1 1 Battery: Heavy Oil Single‐ Well 22 60 54 2 1 Battery: Satellite 66 231 1 1 2 Battery: Single Well Oil 68 15 1 1 1 Battery: SWB with Treater 246 71 1 2 Boiler: Process Boiler 25 Boiler: Utility Boiler 25 Bullet 39 60 1 1 Cleaning Plant: Crude Bitumen 659 562 1145 11 6 17 3 Cleaning Plant: Heavy Oil 137 120 237 6 2 Compressor Station: Coolers 2937 Compressor Station: Yard Piping 849 36 3 Compressor: Centrifugal ‐ Electric 495 38 11 2 2 1 Compressor: Centrifugal ‐ Electric ‐ Seals to Flare 495 38 11 2 1 Compressor: Centrifugal ‐ Gas EngineCompressor: Centrifugal ‐Gas Engine ‐ Seals to FlareCompressor: Reciprocating ‐ Electric 275 2 2 4 Compressor: Reciprocating ‐ Electric ‐ Sealsto Flare 275 2 4 Compressor: Reciprocating ‐ Gas Engine 275 145 2 2 4 Compressor: Reciprocating ‐ Gas Engine ‐ Seals to 275 145 2 4 
36

Table 12: Schedule of default component counts per equipment or process type (CAPP 2005).Equipment / Process Type and Default ComponentCounts

Connector(GV)

Connector(FG)

Connector(HL)

Connector(LL)

Control Valve (GV)

Compressor Seal(GV)

Compressor Seal (FG)

Open‐Ended Line (FG)

Open‐Ended Line (GV)

Open‐Ended Line (LL)

Pressure Relief Valve (FG)

Pressure Relief Valve (GV)

Pressure Relief Valve (HL)

Pressure Relief Valve (LL)

Pump Seal (HL)

FlareCompressor: Screw ‐ Electric 228 1 1 2 Compressor: Screw ‐ Electric ‐ Seals to Flare 228 1 2 Compressor: Screw ‐ Gas EngineCompressor: Screw ‐ Gas Engine ‐Sealsto FlareCompressor: Vapour Recovery ‐ ElectricCompressor: Vapour Recovery ‐ Gas Engine 25 2 1 Cycling 241 386 2 10 Deepcut 241 386 2 10 Dehydrator: Desiccant 100 14 1 Dehydrator: Glycol 100 14 1 ESD Station 10 Flare Knockout Drum 26 20 Fractionation 241 386 10 Fractionation: De‐butanizer 177 208 6 Fractionation: De‐ethanizer 177 208 6 Fractionation: De‐propanizer 177 208 6 Gas Boot 37 Gas Sweetening: Amine 702 3 3 2 Gas Sweetening: Diglycolamine 702 3 3 2 Gas Sweetening: Iron Sponge 134 12 1 Gas Sweetening: Proprietary 200 46 4 Gas Sweetening: Sulfinol 702 3 3 2 
37

Table 12: Schedule of default component counts per equipment or process type (CAPP 2005).Equipment / Process Type and Default ComponentCounts

Connector(GV)

Connector(FG)

Connector(HL)

Connector(LL)

Control Valve (GV)

Compressor Seal(GV)

Compressor Seal (FG)

Open‐Ended Line (FG)

Open‐Ended Line (GV)

Open‐Ended Line (LL)

Pressure Relief Valve (FG)

Pressure Relief Valve (GV)

Pressure Relief Valve (HL)

Pressure Relief Valve (LL)

Pump Seal (HL)

Gas Sweetening: Sulfreen 134 12 1 Header Tie‐in: Cond/NGL 10 1 Header Tie‐in: Flow Line 10 1 Header Tie‐in: Gas Line 10 1 Heat Exchanger 13 Heater: Gas‐fired Unit Heater 10 Heater: Line Heater 40 145 1 Heater: Salt Bath Heater 25 Heater: Tank Heater 10 2 Heater: Unit Heater 10 2 Incinerator 10 Main Line Block Valve 30 1 Main Line Meter Station 1704 76 15 Meter Station 70 2 Meter/Regulator Station 94 2 Metering 70 2 Molecular Sieve 100 14 1 Pig Trap 11 Pipeline: Butane 10 1 Pipeline: Ethane 10 1 Pipeline: Pentanes Plus 10 1 Pipeline: Propane 10 1 Power Generator 74 
38

Table 12: Schedule of default component counts per equipment or process type (CAPP 2005).Equipment / Process Type and Default ComponentCounts

Connector(GV)

Connector(FG)

Connector(HL)

Connector(LL)

Control Valve (GV)

Compressor Seal(GV)

Compressor Seal (FG)

Open‐Ended Line (FG)

Open‐Ended Line (GV)

Open‐Ended Line (LL)

Pressure Relief Valve (FG)

Pressure Relief Valve (GV)

Pressure Relief Valve (HL)

Pressure Relief Valve (LL)

Pump Seal (HL)

Pump: Oil Pump (Recycle/Shipping) 10 Pump: Other Pumps 10 Pump: Pump Station 22 647 2 17 Pump: Water Pump (Recycle/Shipping) 5 Refrigeration: 170 31 2 2 Refrigeration: Joule‐Thomson 79 41 Regulator Station 24 Separation 40 58 Separator: Inlet Separator 66 41 Separator: Test Separator 49 25 1 Stabilization 80 247 3 Sulphur Recovery 100 Tail Gas Cleanup 25 Tank: Farm 190 Tank: Pipeline Terminal Tanks 12 Tank: Pop Tank 24 Tank: Production Tank 2 24 Tank: Pump Station Tanks 12 Tank: Storage Tank 12 Tank: Tank Farm Tanks 12 Treater 178 56 1 1 Turbo Expander 123 9 1 6 Well: Gas ‐ Deep > 1000 m 19 1 
39

Table 12: Schedule of default component counts per equipment or process type (CAPP 2005).Equipment / Process Type and Default ComponentCounts

Connector(GV)

Connector(FG)

Connector(HL)

Connector(LL)

Control Valve (GV)

Compressor Seal(GV)

Compressor Seal (FG)

Open‐Ended Line (FG)

Open‐Ended Line (GV)

Open‐Ended Line (LL)

Pressure Relief Valve (FG)

Pressure Relief Valve (GV)

Pressure Relief Valve (HL)

Pressure Relief Valve (LL)

Pump Seal (HL)

Well: Gas ‐ Injection 19 Well: Gas ‐ Shallow < 1000 m 10 Well: Oil ‐ Flowing 57 Well: Oil ‐ Heavy Primary 22 Well: Oil ‐ Heavy Thermal 22 Well: Oil ‐ Pumping 57 
40

Table 13:   Summary of equipment or process types by jurisdiction and in total that are included in the

emission factor update database.

Equipment / Process Type and Default Component Counts BC Facilities AB Facilities All Facilities

Absorption    

Absorption: Cold Bed    

Adsorption    

Battery: Heavy Oil Satellite    

Battery: Heavy Oil Single‐ Well    

Battery: Satellite    

Battery: Single Well Oil    

Battery: SWB with Treater    

Boiler: Process Boiler 11 11

Boiler: Utility Boiler 5 14 19

Bullet 16 16

Cleaning Plant: Crude Bitumen    

Cleaning Plant: Heavy Oil    

Compressor Station: Coolers 2 2

Compressor Station: Yard Piping 1 1

Compressor: Centrifugal ‐ Electric    

Compressor: Centrifugal ‐ Electric ‐ Seals to Flare    

Compressor: Centrifugal ‐ Gas Engine    

Compressor: Centrifugal ‐Gas Engine ‐ Seals to Flare    

Compressor: Reciprocating ‐ Electric 3 13 16

Compressor: Reciprocating ‐ Electric ‐ Seals to Flare    

Compressor: Reciprocating ‐ Gas Engine 48 132 180

Compressor: Reciprocating ‐ Gas Engine ‐ Seals to Flare 8 8

Compressor: Screw ‐ Electric 2 28 30

Compressor: Screw ‐ Electric ‐ Seals to Flare    

Compressor: Screw ‐ Gas Engine 2 16 18

Compressor: Screw ‐ Gas Engine ‐Seals to Flare    

Compressor: Vapour Recovery ‐ Electric 5 2 7

Compressor: Vapour Recovery ‐ Gas Engine    

Cycling    

Deepcut    

Dehydrator: Desiccant 2 2

Dehydrator: Glycol 28 50 78

Engine: Gas 4 4

ESD Station 43 94 137

Fractionation: De‐butanizer 1 1

Flare Knockout Drum 28 30 58
41

Table 13:   Summary of equipment or process types by jurisdiction and in total that are included in the

emission factor update database.

Equipment / Process Type and Default Component Counts BC Facilities AB Facilities All Facilities

Fractionation    

Fractionation: De‐ethanizer 8 8

Fractionation: De‐propanizer    

Gas Boot 2 3 5

Gas Sweetening: Amine 3 1 4

Gas Sweetening: Diglycolamine    

Gas Sweetening: Iron Sponge 2 2

Gas Sweetening: Proprietary    

Gas Sweetening: Sulfinol    

Gas Sweetening: Sulfreen    

Header Tie‐in: Cond/NGL    

Header Tie‐in: Flow Line 45 12 57

Header Tie‐in: Gas Line 99 185 284

Heat Exchanger 3 34 37

Heat Exchanger: Liquid 5 5

Heater: Gas‐fired Unit Heater 33 4 37

Heater: Line Heater 31 23 54

Heater: Salt Bath Heater 2 2

Heater: Tank Heater 2 2 4

Heater: Unit Heater 10 10

Incinerator 2 2

Main Line Block Valve 18 18

Main Line Meter Station    

Meter Station 5 106 111

Meter/Regulator Station 2 2

Metering 117 121 238

Methanol Sphere 4 4

Molecular Sieve    

Pig Trap 229 94 323

Pipeline: Butane    

Pipeline: Ethane    

Pipeline: Pentanes Plus    

Pipeline: Propane

Power Generator 38 4 42

Pump: Oil Pump (Recycle/Shipping) 18 15 33

Pump: Other Pumps 8 26 34

Pump: Pump Station    
42

Table 13:   Summary of equipment or process types by jurisdiction and in total that are included in the

emission factor update database.

Equipment / Process Type and Default Component Counts BC Facilities AB Facilities All Facilities

Pump: Water Pump (Recycle/Shipping) 4 4

Refrigeration: 7 7

Refrigeration: Joule‐Thomson 3 3

Regulator Station    

Scrubber 7 14 21

Separation 29 69 98

Separator: Inlet Separator 78 178 256

Separator: Test Separator 14 2 16

Stabilization 5 5

Sulphur Recovery    

Tail Gas Cleanup    

Tank: Farm 1 1

Tank: Pipeline Terminal Tanks    

Tank: Pop Tank    

Tank: Pop Tank 3 10 13

Tank: Production Tank 98 114 212

Tank: Pump Station Tanks    

Tank: Storage Tank 8 4 12

Tank: Tank Farm Tanks    

Treater 7 9 16

Turbo Expander    

Well: Gas ‐ Deep > 1000 m 7 16 23

Well: Gas ‐ Injection    

Well: Gas ‐ Shallow < 1000 m 23 23

Well: Oil ‐ Flowing    

Well: Oil ‐ Heavy Primary    

Well: Oil ‐ Heavy Thermal    

Well: Oil ‐ Pumping 1 1
43

7 APPENDIX  B  ‐  GUIDELINES  FOR  COUNTING  EQUIPMENT  COMPONENTS

The following guidelines were applied to count equipment components in hydrocarbon service

from drawings showing yard piping details and may be applied in performing actual counts at

facilities:

• Compressor Seals: A reciprocating compressor is deemed to have one seal associated

with each compressor cylinder regardless of whether it is really a single or tandem seal.

A centrifugal compressor has two seals, one on each side of the housing where the shaft

penetration occurs. Other components on the compressor and on any associated cooler

(e.g., valves, connectors, pressure relief valves, open‐ended valves and lines, and gas‐ 

operated instruments) need to be accounted for separately. Seals that are connected to

a  flare,  incinerator  or  other  end  control  device  rather  than  being  vented  are  not

counted.

• Connectors: Each threaded, flanged or mechanical connection is counted as a single

connector. Welded or backwelded connections are not counted.

Some types of components may have more than one set of connections associated with

them. For example a union may have 3 sets of connecting surfaces (2 end connections

and a centre connection), a nipple or reducer may have 2 (one at each end), and a tee

may have 3 (one at each end). If all 3 connection points on a union are threaded then a

union would be classified as a 3 connectors. A union that has welded end connections

would be counted as only one connector.

• Valves: This category accounts for leakage from around the valve stem and from the

valve body. The end connections and any leakage past the valve seat are counted

separately (see connectors and open‐ended valves or lines, respectively). A control valve

is any valve that is equipped with an actuator. A manual block valve is any valve that

must be manually operated. Venting by any pneumatic operators is not deemed to be

leakage, so if the valve itself is not in hydrocarbon service, then it is not counted.

• Pressure‐Relief Valve: Generally, a pressure‐relief valve that discharges directly to the

atmosphere or through a vent system is counted. However, if the valve discharges to a

control device (e.g., flare or thermal oxidizer), or has a rupture disk installed upstream

along with a monitoring system to indicate when the rupture disk has failed, then the

valve is not counted.

The connection on the upstream side of the valve is counted as a separate component.

The connection on the downstream side also is counted if the relief valve is connected

to a control device.
44

• Open‐ended Valves or Lines: Each valve in hydrocarbon service that has process fluid on

one side and is open to the atmosphere on the other (either directly or through a line) is

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

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

a control device then it is no longer considered to be open‐ended (i.e., there is zero leak

potential).

A drain valve that discharges into the top of an underground storage tank is considered

an open‐end line.

The  valve stem  and body, and the connector on the process side of the valve are

counted as separate components.

• Sampling System ‐  This category accounts for hydrocarbons that are released to the

atmosphere as part of actual sampling activities, and the results are adjusted to reflect

the frequency of occurrence. The individual parts of the system should be counted as

separate components. Thus, an open‐ended line that is used for routine sampling would

be counted as both a sampling system and an open‐ended line.

For manual gas sampling systems, the sampling emissions would include any initial

purge volumes released to the atmosphere, plus the gas released when the sample

container is disconnected.

While components may be counted from process diagrams, this frequently understates actual

component numbers. This is especially true for fittings (e.g., connectors and valves less than 2

NPS) and any third‐party packages (e.g., compressor units, heaters, and scrubbers) for which

detailed drawings and a bill of materials is unavailable.

When counting each component it is important to also record the percentage of the time that it

is out of service (i.e., there is zero gauge pressure on both sides of the component). This

information can be used to adjust the estimated emissions accordingly.
45

U 2 n

2 2 2

1

8 APPENDIX C  ‐ METHODOLOGY FOR ASSESSING UNCERTAINTIES

The uncertainties in the presented emissions factors were assessed using an IPCC (2000) Tier‐1

approach. This approach provides for the estimation of uncertainties by source using error

propagation equations based on the assumption of uncorrelated normally distributed

uncertainties under addition and multiplication. Convenient analytic expressions are given by

IPCC for determining the combined uncertainty in individual multiplication and addition steps of

the inventory development process. The multiplication steps in the emission factor assessment

occur where default no‐leak emission factors were applied to the portion of the component

population that were determined not to be leaking, and where the total assessed emissions for

a component category were multiplied by the inverse of the corresponding component count.

The addition steps result from the aggregation of individual measurement results and no‐leak

estimates to determine the total emissions. For a given source category, the level of uncertainty

will tend to decrease by a factor of 1/N0.5 where N is the number of sources.

8.1.1    COMBING UNCERTAINTIES IN MULTIPLICATION STEPS

The   IPCC   Tier‐1   relation   for   combining   uncertainties   in   multiplication   steps   is   (this   is

approximate for all random variables):

UTotal = 2 +U 2 +...+U 2

Equation 5

where,

UTotal ‐  is the percentage uncertainty in the sum of the quantities.

U1,U2, Un ‐  are the uncertainties in the individual quantities being multiplied.

8.1.2 COMBINING UNCERTAINTIES IN ADDITION STEPS

The overall uncertainty in the sum of the individual quantities is determined using the following

relation (this expression is exact for uncorrelated or independent variables):

U = 

(

U1 

⋅ x1) + (

U2 ⋅ x2

) + ... + (

Un ⋅ xn

)

Equation 6 total

x1 

+ x2 + ... + xn

where:
46

x1,x2,xn - are the uncertain quantities being added. 

8.1.3 UNCERTAINTIES IN INDIVIDUAL INPUT QUANTITIES

The uncertainty in an individual input quantity to a multiplication or addition step may be

determined using the following approaches, presented in the order of decreasing preference:

• an error analysis of the available measurement data,

• applicable uncertainty estimates presented in the open literature,

• default uncertainty values published by IPCC (2000), and

• expert judgement.

In each case, the uncertainty is the probable error in the measurement or accounting techniques

used to determine the input quantity, and in any related extrapolations or interpolations of

these values. Where an input quantity has been built up through multiplication and/or

summation of sub‐parameters the IPCC Tier‐1 rules for combining uncertainties in multiplication

and addition should be applied to each of these steps.

The actual assumptions made herein are summarized below:

• The no‐leak emission factors were assumed to have a lower confidence limit of 20% and

an upper confidence limit of 500 percent.

• Reported leak counts were assumed to have a confidence limit of ±10%. This allows for

the fact some components may have been incorrectly identified as leakers and some

leakers may have been missed.

• The estimated component populations were assumed to have an uncertainty of ±25%.

• The  leak measurement results were assumed to have an uncertainty of ±25%. This

allows for some inaccuracies in the measurements as well as some variability in the

source.

8.1.4    UPPER AND LOWER CONFIDENCE LIMITS

To determine the upper and lower limit of the emission factor confidence interval it is

appropriate to consider the shape of the uncertainty probability function for each quantity

being combined. Good practice in this regard (IPCC, 2000) is to assume either a normal or

lognormal distribution depending on which provides the most realistic results (i.e., results in

positive non‐zero confidence limits). Other distributions should only be used where there are

compelling reasons, either from empirical observations or from expert judgement backed by

theoretical argument.
47

The applied approach was as follows. Whenever the percent uncertainty for a quantity was less

than 100%, a normal probability function was assumed resulting in a symmetric distribution

about the mean (i.e., a balanced uncertainty of ±Ui). Wherever the percent uncertainty for a

quantity was greater than 100%, the uncertainty value was taken to be (100/Ui)∙100 when

determining  the   lower   limit   and   +Ui    when   determining  the   upper   limit  resulting   in   an

unbalanced uncertainty. This is equivalent to assuming a lognormal distribution and was done,

where applicable, to avoid a negative or zero lower confidence limit for the target quantity.

These rules concerning balanced and unbalanced uncertainties are applied appropriately to

each quantity before combining uncertainties using Equations 5 and 6. Thus, two sets of

calculations   are   performed:   one   to   determine   the   combined   uncertainty   applicable   for

evaluation of the upper confidence limit, and one to determine the value applicable for

evaluation of the lower confidence limit.

While use of the log normal assumption results in a tighter confidence interval than might

otherwise be expected, it is conservative with respect to the potential amount of emissions

since it results in greater estimated emissions at the lower confidence limit. Use of a normal

distribution in these cases would result in a negative emission factor, which is meaningless, or, if

the  negative  values  are  arbitrarily  set  to  zero,  an  understatement  of  the  lower  probable

emission rate.

In comparing the total uncertainty estimate for different source categories it is important to

consider the number of sources in each category as well as the uncertainties in the individual

emissions value for the sources in the category. The percentage uncertainty in the aggregate

emission estimate for a category will tend to decrease by a factor of 1/N0.5  where N is the

number of sources in that category.