# REPORT



# Update of Fugitive Equipment Leak

Emission Factors

February, 2014

2014-00232100, 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, deve lop and produce natura l 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 su pport 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 communicat ion 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

‐ 6 th 

### Avenue S.W.

Calgary, AB, T2P 3K2i 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 categoriesiii 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 ..............................................................................................................................v i

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

....................................................................... 46v LIST OF TABLES

T ABLE 1: E MISSION FACTORS FOR THC EMISSIONS IN THE UPSTREAM OIL AND GAS INDUSTRY IN A LBERTA

(CAPP 1992).

............................................................................................................................... ......... 4

T ABLE 2: S UMMARY OF AVERAGE EMISSION FACTORS FOR UNCONTROLLED FUGITIVE THC EMISSIONS

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

T ABLE 3: S UMMARY OF FACILITIES FOR WHICH FUGITIVE EMISSION DATA WAS SUBMITTED AND USED IN THE

EMISSION FACTOR UPDATE STUDY

. ........................................................................................................ 7

T ABLE 4: S UMMARY OF EMISSION FACTOR UPDATE STUDY ESTIMATED TOTAL COMPONENT COUNTS BY TYPES

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

T ABLE 5: S UMMARY OF LEAK SURVEY RESULTS SHOWING LEAK FREQUENCY

, AVERAGE LEAK RATE AND

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

T ABLE 6: S UMMARY 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

T ABLE 7: E MISSIONS AND LEAK FREQUENCY RESULTS FROM APPLICATION OF M ETHOD 1 TO SITES HAVING

LEAKER COUNTS BUT NO LEAK MEASUREMENT DATA

. ..........................................................................18

T ABLE 8: E MISSIONS AND LEAK FREQUENCY RESULTS USING M ETHOD 2 FOR SITES WITH MEASURED LEAK

RATES

. ............................................................................................................................... ...................22

T ABLE 9: C OMBINED EMISSION FACTOR RESULTS FROM THE M ETHOD 1 AND M ETHOD 2 DATA SETS ............26

T ABLE 10: F INAL 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

T ABLE 11: I SSUED ENCOUNTERED IN ESTABLISHING EQUIPMENT AND PROCESS TYPE COUNTS FOR EACH

FACILITY

. ............................................................................................................................... ...............31

T ABLE 12: S CHEDULE OF DEFAULT COMPONENT COUNTS PER EQUIPMENT OR PROCESS TYPE (CAPP 2005). 35

T ABLE 13: S UMMARY OF EQUIPMENT OR PROCESS TYPES BY JURISDICTION AND IN TOTAL THAT ARE

INCLUDED IN THE EMISSION FACTOR UPDATE DATABASE

. .....................................................................40vi LIST OF FIGURES

F IGURE 1: D ISTRIBUTION OF THE APPLIED TOTAL COUNT AND LEAKING COMPONENT COUNT BY COMPONENT

TYPE IN DATABASE AND PRESENTED IN T ABLE 5...................................................................................16

F IGURE 2: L EAK FREQUENCY VERSUS T OTAL C OMPONENT C OUNT INCLUDING ALL COMPONENT TYPES

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

EXCLUDED ).

.............................................................................................................................. ............20vii 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 Gasviii 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 IN TR O D U C T IO N

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 factors2 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

service 1

. Components in odourized or H 2 S 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 H IS TO R IC A N D C U R R EN T E M IS S IO N F A C TO R M E T H OD OL OG I E S

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 CH 4 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 P U B L I S HE D E M I S S I O N F A C T ORS

The CAPP (1992) emission factor results are presented in Table 1.4 Table 1: Emission f actors f or THC emissions in the upstream oil and gas industry in Alberta

(CAPP 1992).

Component Type Type o f

Service Service Average

Emission

Rate 1 No

‐ Leak

Emission

Rate 2 Leak

Emission

Factor 2

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 (H

2 S) 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 98 985 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 80 806 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 EM I S S I ON F A C T OR U P D A T E M ET OD OL OG Y

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 was7 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.

Facilities Included 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 o f emission f actor 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 FU G IT IVE E M I SSIO N D A T A A N A L Y S IS

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 when9 screened in accordance with U.S. EPA Method 21, or the emissions are detectable by a

leak imaging infrared camera.

2 .4 C OM P ON EN T C OU N T S

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 M ET H OD 1 EM I S S I ON F A C T ORS

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 L EA K F REQU EN C Y ( L F )

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

equation:



### LF = N Leakers



### N

Total 

### ⋅ 100 Equation 1

Where:

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

N Leakers = the actual number of leaks reported for Component

Type “C i ” in the dataset.

N Total = the total number of Component Type “C i ” determined for all

facilities included in the dataset.

2 .5 .2 EM I S S I ON F A C T OR ( E F )

The average emission factor ( EF Average ) 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 A vera ge



# ∑ EF = LF

⋅ EF Leak 

### + (100 − LF )

⋅ EF No − Leak Equation 2 

### 100

Where:

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

(kg/h/source).

EF Leak = the Leak emission factor for Component type “C i ” as reported

(CAPP 1992).

EF No

‐ Leak = the No

‐ Leak emission factor for Component type “C i ” as

reported (CAPP 1992).

2 .6 M ET H OD 2 EM I S S I ON F A C T ORS

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 L EA K F REQU EN C Y ( L F )

Leak frequency is determined as indicated in Section 2.5.1 above.

2 .6 .2 EM I S S I ON F A C T OR ( E F )

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

equation:



### (Emissions from detected leaks) + N No − Leak 

### ⋅ EF No − Leak 

### EF Average 

### =

N Total Equation 3

Where:

EF Average = the calculated average emission factor for Component Type “C i ”

(kg/h/source).

∑ Emissions...Leaks

= the sum of all leaks reported for Component Type “C i ” in the

dataset.

N Total = the total number of components of type i.

N No

‐ Leak = N Total of component type “i” minus the number of leaking11 

# ∑ ∑ component type “C i ”.

EF No

‐ Leak = the No

‐ Leak emission factor for Component Type “C i ” as

reported (CAPP 1992).

2 .7 CO M BI N I N G T HE R E S U L T S O F M ET H OD 1 A N D 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 EF Average and N Total values):



### N

Total Method1 

### ⋅ EF Average Method1 

### + N Total Method 2 

### ⋅ EF Average Method 2 

### EF Average 

### = Equation 4



### N

Total Method 1 + 

### N Total Method 212 3 C O M P O N E N T E M IS S IO N F A C T OR S

3 .1 L EA K S U RV EY RES U L T S

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

.13Table5:Summaryofleaksurveyresultsshowingleakfrequency,averageleakrateandleakratestandarddeviation.ComponentTypeEstimatedTotalComponents1AppliedTotalComponentsReportedLeakingComponents2LeakFrequency:Average3(%)LeakRate:Average4(kg/h/source)LeakRate:STDEV5(kg/h/source)STDEV/Average(%)CompressorSeal(GV)4724728217.370.241710.56222233Connector(FG)46,24146,2413900.840.117010.17225147Connector(GV)153,741153,7412290.150.057950.16435284Connector(LL)32,50832,508100.030.084970.18350216ControlValve(FG)01414100.000.106700.0984392ControlValve(GV)50501938.000.063490.07409117Open‐EndedLine(FG)02323100.000.363720.87591241Open‐EndedLine(GV)1,1731,173252.132.648525.01464189Open‐EndedLine(LL)4400.000.000000.000000PressureReliefValve(FG)798011.270.000000.000000PressureReliefValve(GV)1,0541,05420.190.000180.0000635PressureReliefValve(LL)161600.000.000000.000000PumpSeal(FG)033100.000.064690.07612118PumpSeal(LL)43643600.000.000000.000000Regulator(FG)276644162.960.194910.35115180Regulator(GV)1031051514.560.344561.08567315Regulator(LL)011100.000.000000.000000Valve(FG)3,3103,310641.930.083670.10892130Valve(GV)27,21427,2141220.450.081840.48082588Valve(LL)10,51910,519110.100.038650.070481821TotalComponents=Sumofcomponentsbytypeforallfacilitiesincludedinsurvey.14Table5:Summaryofleaksurveyresultsshowingleakfrequency,averageleakrateandleakratestandarddeviation.ComponentTypeEstimatedTotalComponents1AppliedTotalComponentsReportedLeakingComponents2LeakFrequency:Average3(%)LeakRate:Average4(kg/h/source)LeakRate:STDEV5(kg/h/source)STDEV/Average(%)2Leakingcomponents=Totalnumberofleakingcomponentsbytypeincludedinsurvey.3LeakFrequency=Numberleakingdividedbytotalnumberbycomponenttype.4LeakRate:AverageofLeakRate:Average=Sumofemissionsfromallcomponentsofthattypedividedbythetotalnumberofthatcomponenttype.5LeakRate:STDEV=SDTEVofallleakratesbycomponenttype.Table 6: Summary o f leak survey results showing the number o f 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

Components 1

(Number) Leak Rate:

Average 2

(kg/h/source) Leak Rate:

STDEV 3

(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 ( L L) 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.

15Number 472 82 46,241 390 153,741 229 32,508

10 14 14 50 19 23 23 1,173 25 4 0 80 1 1,054 2 16 0 3 3 436 0 66 44 105 15 1 1 3,310 64 27,214 122 10,519

11180000160000140000120000100000800006000040000200000TotalCountandLeakingCountbyComponentsTypeTotalComponentsNumberLeakingComponentsNumberFigure1:DistributionoftheappliedtotalcountandleakingcomponentcountbycomponenttypeindatabaseandpresentedinTable5.163 .2 M ET H OD 1 L EA K F REQU E N C Y A N D E M I S S I O N R E S U L T S

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).

17Table7:EmissionsandleakfrequencyresultsfromapplicationofMethod1tositeshavingleakercountsbutnoleakmeasurementdata.SectorSweet/SourComponentTypeServiceLeakerCountComponentCountLeakFrequencyEF(kg/source/d)Method1EF3,595%Lower95%UpperCAPP2005EF4Method1EF/EstimatedApplied(%)LeakNo‐Leak(kg/h/source)ConfidenceLimitConfidenceLimit(kg/h/source)CAPP2005(Ratio)OilSourCompressorSealGV0161601.608000.001750.0017541%501%0.805000.0022OilSourConnectorFG32255225521.250.037500.000230.0007030%165%0.002460.2835OilSourConnectorGV7483148310.140.037500.000230.0002836%406%0.002460.1154OilSourConnectorLL0186618660.000.037500.000130.0001341%501%0.000190.6842OilSourControlValveGV0000.000.045100.000080.0000025%25%0.014600.0000OilSourOpen‐EndedLineOilSourPressureReliefValveOilSourPressureReliefValveGV039390.000.011950.001830.0018341%501%0.308000.0059FG0000.001.691000.000190.0000025%25%0.016300.0000GV027270.001.691000.000190.0001941%501%0.016300.0117OilSourPumpSealLL036360.000.437000.002300.0023041%501%0.023200.0991OilSourRegulatorFG202100.000.045100.000080.0451077%240%0.006686.7515OilSourRegulatorGV0000.000.045100.000080.0000025%25%0.006680.0000OilSourValveFG51441443.470.045100.000080.0016480%83%0.001511.0882OilSourValveGV19159150.110.045100.000080.0001344%312%0.001510.0856OilSourValveLL05805800.000.085200.000580.0005841%501%0.001210.47931ResultsarebasedonCompanyDdata2ResultsbasedonapplicationofEquation13ResultsbasedonapplicationofEquation24DefaultCAPPfugitiveemissionrateforcomponenttypefromTable2.5No‐LeakandLeakemissionfactorsarefromTable1.1819 3 .3 M ET H OD 2 L EA K F REQU EN C Y A N D EM I S S I ON RE S U L T S

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 CO M BI N E D A N D C O N SO L ID A T E D E M I S S I O N F AC T O R RES U L T S

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 where21 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%.22Table8:EmissionsandleakfrequencyresultsusingMethod2forsiteswithmeasuredleakrates.SectorSweet/SourComponentTypeServiceLeakerCountComponentCountLeakFrequency2(%)SumofLeaks(kg/h)No‐LeakEF(kg/h/source)Method2EF3,5(kg/h/source)95%LowerConfidenceLimit95%UpperConfidenceLimitCAPP2005EF4(kg/h/source)Method2EF/CAPP2005EF(Ratio)EstimateAppliedGasSourCompressorSealGV7222231.824.27990.001750.1957328%28%0.713000.2745GasSourConnectorFG345,1655,1650.664.96470.000610.0015730%195%0.000821.9112GasSourConnectorGV2023,66123,6610.091.35180.000190.0002536%386%0.000141.7641GasSourConnectorLL01,5091,5090.0000.000130.0001341%501%0.000550.2364GasSourControlValveGV111100.000.0680.000100.06800189%189%0.009647.0539GasSourOpen‐EndedLineGV41001004.000.97550.001830.0115136%84%0.189000.0609GasSourPressureReliefValveFG017170.0000.000190.0001941%501%0.017000.0112GasSourPressureReliefValveLL101100.000.000190.000190.0001925%25%0.021390.0000GasSourPressureReliefValveGV077770.0000.000190.0001941%501%0.017000.0112GasSourPumpSealLL023230.0000.002300.0023041%501%0.023200.0991GasSourRegulatorFG3252512.000.67960.000230.0273950%50%0.008113.3769GasSourRegulatorGV25540.000.00230.000100.000522115%2116%0.0000510.4000GasSourRegulatorLL101100.000.00010.000100.0001025%25%0.008110.0000GasSourValveFG36036030.500.36090.000230.0008356%149%0.002810.2944GasSourValveGV12,4732,4730.040.00010.000100.0001041%501%0.001160.0862GasSourValveLL05545540.0000.000810.0008141%501%0.003520.2301GasSweetCompressorSealGV7240240217.9114.91130.001750.0385326%32%0.713000.0540GasSweetConnectorFG28732,99432,9940.8731.74440.000610.0015728%195%0.000821.9108GasSweetConnectorGV193108,328108,3280.187.97910.000610.0006838%447%0.000820.8324GasSweetConnectorLL1023,69423,6940.040.84970.000130.0001736%393%0.000550.3015GasSweetControlValveFG13013100.001.32390.000230.1018444%44%0.016206.2863GasSweetControlValveGV17474736.171.03640.000230.0222048%48%0.016201.3702GasSweetOpen‐EndedFG20020100.007.32910.001830.3664627%27%0.467000.784723Table8:EmissionsandleakfrequencyresultsusingMethod2forsiteswithmeasuredleakrates.SectorSweet/SourComponentTypeServiceLeakerCountComponentCountLeakFrequency2(%)SumofLeaks(kg/h)No‐LeakEF(kg/h/source)Method2EF3,5(kg/h/source)95%LowerConfidenceLimit95%UpperConfidenceLimitCAPP2005EF4(kg/h/source)Method2EF/CAPP2005EF(Ratio)EstimateAppliedLineGasSweetOpen‐EndedLineGV168908901.8037.1020.001830.0434825%33%0.467000.0931GasSweetOpen‐EndedLineLL0220.0000.001830.0018341%501%0.018300.1000GasSweetPressureReliefValveFG048480.0000.000190.0001941%501%0.017000.0112GasSweetPressureReliefValveGV27797790.260.00040.000190.0001949%501%0.017000.0112GasSweetPressureReliefValveLL016160.0000.000190.0001941%501%0.005390.0353GasSweetPumpSealFG303100.000.19410.000190.06470108%108%0.023200.0000GasSweetPumpSealLL02832830.0000.002300.0023041%501%0.023200.0991GasSweetRegulatorFG33233100.005.1280.000230.1553929%29%0.0081119.1608GasSweetRegulatorGV994949.570.23890.000230.0027598%105%0.008390.3277GasSweetValveFG542,0992,0992.574.28660.000230.0022731%58%0.002810.8065GasSweetValveGV11420,05220,0520.574.41440.000230.0004531%256%0.002810.1597GasSweetValveLL117,58475840.150.42520.000810.0008639%469%0.003520.2457OilSourCompressorSealGV088000.001750.0017541%501%0.805000.0022OilSourConnectorFG61,3141,3140.460.67960.000230.0007545%160%0.002460.3033OilSourConnectorGV14,9054,9050.020.13590.000230.0002640%448%0.002460.1047OilSourConnectorLL01,7501,7500.0000.000130.0001341%501%0.000190.6842OilSourControlValveGV0110.0000.000080.0000841%501%0.014600.0055OilSourOpen‐EndedLineGV159591.700.84950.001830.0162036%66%0.308000.0526OilSourPressureReliefValveFG0440.0000.000190.0001941%501%0.016300.0117OilSourPressureReliefValveGV049490.0000.000190.0001941%501%0.016300.011724Table8:EmissionsandleakfrequencyresultsusingMethod2forsiteswithmeasuredleakrates.SectorSweet/SourComponentTypeServiceLeakerCountComponentCountLeakFrequency2(%)SumofLeaks(kg/h)No‐LeakEF(kg/h/source)Method2EF3,5(kg/h/source)95%LowerConfidenceLimit95%UpperConfidenceLimitCAPP2005EF4(kg/h/source)Method2EF/CAPP2005EF(Ratio)EstimateAppliedOilSourPumpSealLL021210.0000.002300.0023041%501%0.023200.0991OilSourRegulatorFG0000.0000.000080.000000%0%0.006680.0000OilSourRegulatorGV0220.0000.000080.0000841%501%0.006680.0120OilSourValveFG11151150.870.0680.000080.00067167%178%0.001510.4441OilSourValveGV21,0401,0400.190.11890.000080.0001991%225%0.001510.1286OilSourValveLL05575570.0000.000580.0005841%501%0.001210.4793OilSweetCompressorSealGV3242412.500.62860.001750.0277247%54%0.805000.0344OilSweetConnectorFG314,2164,2160.744.50240.000230.0013030%93%0.002460.5269OilSweetConnectorGV812,01612,0160.073.3980.000230.0005130%226%0.002460.2084OilSweetConnectorLL03,6893,6890.0000.000130.0001341%501%0.000190.6842OilSweetControlValveFG101100.000.16990.000080.1699098%98%0.0146011.6370OilSweetControlValveGV111100.000.10190.000080.10190141%141%0.014606.9795OilSweetOpen‐EndedLineFG303100.001.03640.001830.3454740%40%0.308001.1216OilSweetOpen‐EndedLineGV485854.7127.28610.001830.3227625%25%0.308001.0479OilSweetOpen‐EndedLineLL0220.0000.001830.0018341%501%0.003730.4906OilSweetPressureReliefValveFG010100.0000.000190.0001941%501%0.016300.0117OilSweetPressureReliefValveGV01221220.0000.000190.0001941%501%0.016300.0117OilSweetPumpSealLL073730.0000.002300.0023041%501%0.023200.0991OilSweetRegulatorFG606100.002.37860.000080.3964331%31%0.0066859.3463OilSweetRegulatorGV424100.004.92710.000081.2317827%27%0.00668184.3975OilSweetValveFG13493490.290.22090.000080.0007173%92%0.001510.4720OilSweetValveGV42,7342,7340.155.36890.000080.0020426%33%0.001511.3534OilSweetValveLL01,2441,2440.0000.000580.0005841%501%0.001210.479325Table8:EmissionsandleakfrequencyresultsusingMethod2forsiteswithmeasuredleakrates.SectorSweet/SourComponentTypeServiceLeakerCountComponentCountLeakFrequency2(%)SumofLeaks(kg/h)No‐LeakEF(kg/h/source)Method2EF3,5(kg/h/source)95%LowerConfidenceLimit95%UpperConfidenceLimitCAPP2005EF4(kg/h/source)Method2EF/CAPP2005EF(Ratio)EstimateApplied1ResultsarebasedondatafromallcompaniesexceptCompanyD.2ResultsbasedonapplicationofEquation13ResultsbasedonapplicationofEquation34DefaultCAPPfugitiveemissionrateforcomponenttypefromTable2.5WhereTotalNumber=zeroandNumberLeakersis>zero,Method2emissionfactor=SumOfAllLeaks/NumberLeakersandresultisshadedingrey.26Table 9: Combined emission factor results from the Method 1 and Method 2 data sets.SectorSweet/SourComponentTypeServiceMethod1DataMethod2DataCombinedResultsCAPP(2005)Results(kg/h/source)CombinedEF/AppliedComponentCountAverageEF(kg/h/source)AppliedComponentCountAverageEF(kg/h/source)AverageEF(kg/h/source)95%LowerConfidenceLimit(%)95%UpperConfidenceLimit(%)AverageEF(kg/h/source)95%LowerConfidenceLimit(%)95%UpperConfidenceLimit(%)CAPP2005EF(Ratio)GasSourCompressorSealGV00.00000220.195730.1957345.2045.30%0.7130036360.2745GasSourConnectorFG00.000005,1650.001570.0015746.25198.64%0.0008272721.9112GasSourConnectorGV00.0000023,6610.000250.0002550.51387.33%0.0001472721.7641GasSourConnectorLL00.000001,5090.000130.0001353.85502.49%0.0005572720.2364GasSourControlValveGasSourOpen‐EndedLineGasSourPressureReliefValveGasSourPressureReliefValveGasSourPressureReliefValveGV00.0000010.068000.06800192.64192.64%0.00964447.0539GV00.000001000.011510.0115150.3591.37%0.18900791270.0609FG00.00000170.000190.0001953.85502.49%0.0170098980.0112LL00.0000010.000190.0001943.3043.30%0.0213980800.0089GV00.00000770.000190.0001953.85502.49%0.0170098980.0112GasSourPumpSealLL00.00000230.002300.0023053.85502.49%0.02320741360.0991GasSourRegulatorFG00.00000250.027390.0273961.2961.40%0.00811741263.3769GasSourRegulatorGV00.0000050.000520.000522115.242116.03%0.000057412610.4000GasSourRegulatorLL00.0000010.000100.0001043.3043.30%0.00811741260.0123GasSourValveFG00.000006030.000830.0008366.06153.17%0.0028117170.2944GasSourValveGV00.000002,4730.000100.0001053.84502.29%0.0011631310.0862GasSourValveLL00.000005540.000810.0008153.85502.49%0.0035219190.2301GasSweetCompressorSealGV00.000004020.038530.0385343.7247.52%0.7130036360.0540GasSweetConnectorFG00.0000032,9940.001570.0015745.20198.04%0.0008232321.9108GasSweetConnectorGV00.00000108,3280.000680.0006851.88448.70%0.0008232320.8324GasSweetConnectorLL00.0000023,6940.000170.0001750.58394.80%0.00055901110.301527Table 9: Combined emission factor results from the Method 1 and Method 2 data sets.SectorSweet/SourComponentTypeServiceMethod1DataMethod2DataCombinedResultsCAPP(2005)Results(kg/h/source)CombinedEF/CAPP2005EF(Ratio)AppliedComponentCountAverageEF(kg/h/source)AppliedComponentCountAverageEF(kg/h/source)AverageEF(kg/h/source)95%LowerConfidenceLimit(%)95%UpperConfidenceLimit(%)AverageEF(kg/h/source)95%LowerConfidenceLimit(%)95%UpperConfidenceLimit(%)GasSweetControlValveFG00.00000130.101840.1018456.1856.180.0162027276.2863GasSweetControlValveGV00.00000470.022200.0222059.4059.500.0162027271.3702GasSweetOpen‐EndedLineFG00.00000200.366460.3664644.4044.400.46700581720.7847GasSweetOpen‐EndedLineGV00.000008900.043480.0434843.3948.050.46700581720.0931GasSweetOpen‐EndedLineLL00.0000020.001830.0018353.85502.490.01830581720.1000GasSweetPressureReliefValveFG00.00000480.000190.0001953.85502.490.0170098980.0112GasSweetPressureReliefValveGV00.000007790.000190.0001960.39501.900.0170080800.0112GasSweetPressureReliefValveLL00.00000160.000190.0001953.85502.490.0053998980.0353GasSweetPumpSealFG00.0000030.064700.06470114.02114.020.02320741362.7888GasSweetPumpSealLL00.000002830.002300.0023053.85502.490.02320741360.0991GasSweetRegulatorFG00.00000330.155390.1553945.6745.670.008117223819.1608GasSweetRegulatorGV00.00000940.002750.00275104.48111.100.00839722380.3277GasSweetValveFG00.000002,0990.002270.0022747.2468.350.0028117170.8065GasSweetValveGV00.0000020,0520.000450.0004547.30258.910.0028117170.1597GasSweetValveLL00.000007,5840.000860.0008652.79470.190.0035217170.2457OilSourCompressorSealGV160.0017580.001750.0017540.14171.300.8050036360.0022OilSourConnectorFG2,5520.000701,3140.000750.0007136.0968.830.0024615150.2902OilSourConnectorGV4,8310.000284,9050.000260.0002736.66217.080.0024615150.1101OilSourConnectorLL1,8660.000131,7500.000130.0001338.10244.770.00019901110.684228Table 9: Combined emission factor results from the Method 1 and Method 2 data sets.SectorSweet/SourComponentTypeServiceMethod1DataMethod2DataCombinedResultsCAPP(2005)Results(kg/h/source)CombinedEF/CAPP2005EF(Ratio)AppliedComponentCountAverageEF(kg/h/source)AppliedComponentCountAverageEF(kg/h/source)AverageEF(kg/h/source)95%LowerConfidenceLimit(%)95%UpperConfidenceLimit(%)AverageEF(kg/h/source)95%LowerConfidenceLimit(%)95%UpperConfidenceLimit(%)OilSourControlValveGV00.0000010.000080.0000853.85502.490.0146021210.0055OilSourOpen‐EndedLineGV390.00183590.016200.0104844.4568.120.30800781290.0340OilSourPressureReliefValveFG00.0000040.000190.0001953.85502.490.0163080800.0117OilSourPressureReliefValveGV270.00019490.000190.0001939.64324.540.0163080800.0117OilSourPumpSealLL360.00230210.002300.0023039.38188.230.02320741360.0991OilSourRegulatorFG20.0451000.000000.0451084.6135.360.00668722386.7515OilSourRegulatorGV00.0000020.000080.0000853.85502.490.00668722380.0120OilSourValveFG1440.001641150.000670.0012177.69136.240.0015179790.8022OilSourValveGV9150.000131,0400.000190.0001664.77147.810.0015179790.1085OilSourValveLL5800.000585570.000580.0005838.09247.690.0012119190.4793OilSweetCompressorSealGV00.00000240.027720.0277258.5464.710.8050036360.0344OilSweetConnectorFG00.000004,2160.001300.0013046.2799.420.0024615150.5269OilSweetConnectorGV00.0000012,0160.000510.0005146.39228.750.0024615150.2084OilSweetConnectorLL00.000003,6890.000130.0001353.85502.490.00019901110.6842OilSweetControlValveFG00.0000010.169900.16990103.92103.920.01460212111.6370OilSweetControlValveGV00.0000010.101900.10190145.23145.230.0146021216.9795OilSweetOpen‐EndedLineFG00.0000030.345470.3454753.2153.210.30800781291.1216OilSweetOpen‐EndedLineGV00.00000850.322760.3227643.3943.470.30800781291.0479OilSweetOpen‐LL00.0000020.001830.0018353.85502.490.00373781290.490629Table 9: Combined emission factor results from the Method 1 and Method 2 data sets.SectorSweet/SourComponentTypeServiceMethod1DataMethod2DataCombinedResultsCAPP(2005)Results(kg/h/source)CombinedEF/CAPP2005EF(Ratio)AppliedComponentCountAverageEF(kg/h/source)AppliedComponentCountAverageEF(kg/h/source)AverageEF(kg/h/source)95%LowerConfidenceLimit(%)95%UpperConfidenceLimit(%)AverageEF(kg/h/source)95%LowerConfidenceLimit(%)95%UpperConfidenceLimit(%)EndedLineOilSweetPressureReliefValveFG00.00000100.000190.0001953.85502.490.0163080800.0117OilSweetPressureReliefValveGV00.000001220.000190.0001953.85502.490.0163080800.0117OilSweetPumpSealLL00.00000730.002300.0023053.85502.490.02320741360.0991OilSweetRegulatorFG00.0000060.396430.3964347.3147.310.006687223859.3463OilSweetRegulatorGV00.0000041.231781.2317844.3144.310.0066872238184.3975OilSweetValveFG00.000003490.000710.0007181.4698.800.0015179790.4720OilSweetValveGV00.000002,7340.002040.0020444.0448.180.0015179791.3534OilSweetValveLL00.000001,2440.000580.0005853.85502.490.0012119190.479330Table 10: Final consolidated emission factors for application in estimating fugitive emissions from upstream oil and gas facilities after the implementation of a formal DI&Mprogram.SectorSweet/SourComponentTypeServiceLeakerCountComponentCountLeakFrequencyPost‐2007ConsolidatedResultsCAPP(2005)CombinedEF/CAPP2005EF(Ratio)EF(kg/h/source)95%LowerConfidenceLimit95%UpperConfidenceLimitEF(kg/h/source)95%LowerConfidenceLimit95%UpperConfidenceLimitGasAllCompressorSealsGV7942418.63%0.0466940.98%43.50%0.7130036%36%0.065GasAllConnectorGV534170,1480.31%0.0008236.22%250.08%0.0008232%32%1.000GasAllConnectorLL1025,2030.04%0.0001653.81%377.53%0.0005590%111%0.298GasAllControlValveGV316150.82%0.0399243.70%43.72%0.0162023%23%2.464GasAllOpen‐EndedLineAll401,0123.95%0.0466341.85%45.18%0.4670062%161%0.100GasAllPressureReliefValveAll39380.32%0.0001954.60%420.36%0.0170098%98%0.011GasAllPumpSealAll33090.97%0.0029150.01%366.79%0.0232074%136%0.125GasAllRegulatorAll4815830.38%0.0384444.83%44.86%0.0081172%238%4.740GasAllValveGV17225,2270.68%0.0005737.63%163.49%0.0028115%15%0.205GasAllValveLL118,1380.14%0.0008654.80%441.88%0.0035219%19%0.245OilAllCompressorSealsGV3486.25%0.0147459.93%66.05%0.8050036%36%0.018OilAllConnectorGV8529,8340.28%0.0005727.05%96.39%0.0024615%15%0.232OilAllConnectorLL07,3050.00%0.0001336.49%281.62%0.0001990%111%0.684OilAllControlValveGV2366.67%0.0906386.67%86.67%0.0146021%21%6.207OilAllOpen‐EndedLineAll81884.26%0.1569246.64%46.74%0.3080078%129%0.509OilAllPressureReliefValveAll02120.00%0.0001937.71%313.14%0.0163080%80%0.012OilAllPumpSealAll01300.00%0.0023038.39%294.44%0.0232074%136%0.099OilAllRegulatorAll121485.71%0.5282938.03%38.01%0.0066872%238%79.085OilAllValveGV145,2970.26%0.0012244.15%48.07%0.0015179%79%0.809OilAllValveLL02,3810.00%0.0005836.94%288.37%0.0012119%19%0.47931 4 D I SC U SSI O N O F R E SU L T S A N D R E C O M M E N D A TIO N S

4 .1 EQU I P M EN T S C H ED U L ES

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 f or 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 EQU I P M EN T S C H ED U L E R EC OM EN D A T I ON S

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 C OM P ON EN T C OU N T S

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 C OM P ON EN T C OU N T R EC OM M EN D A T I ON S

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

component counts.

4 .3 EM I S S I ON F A C T OR RE S U L TS

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 REC OM M EN D A T I ON S

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 RE F E RE N C E S

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 A PPEN DI X A

– D E FA U LT C OM P ON E N T C O U N T S B Y T YP E O F P RO C E SS O R

M A J O R E Q U IP M E N T U N IT

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.35Table12:Scheduleofdefaultcomponentcountsperequipmentorprocesstype(CAPP2005).Equipment/ProcessTypeandDefaultComponentCounts 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 Seal (LL) Regulator (FG) Regulator (GV) Valve (FG) Valve (GV) Valve (HL) Valve (LL)Absorption20046418221Absorption:ColdBed134121317Adsorption20046418221Battery:HeavyOilSatellite424284111101324Battery:HeavyOilSingle‐Well226054211102622Battery:Satellite662311121157Battery:SingleWellOil681511111221Battery:SWBwithTreater246711213338Boiler:ProcessBoiler252Boiler:UtilityBoiler252Bullet3960111527CleaningPlant:CrudeBitumen65956211451161737202139440CleaningPlant:HeavyOil1371202376224052111CompressorStation:Coolers293719CompressorStation:YardPiping849363267Compressor:Centrifugal‐Electric495381122114325Compressor:Centrifugal‐Electric‐SealstoFlare49538112114325Compressor:Centrifugal‐GasEngineCompressor:Centrifugal‐GasEngine‐SealstoFlareCompressor:Reciprocating‐Electric275224201Compressor:Reciprocating‐Electric‐SealstoFlare27524201Compressor:Reciprocating‐GasEngine2751452246201Compressor:Reciprocating‐GasEngine‐Sealsto27514524620136Table12:Scheduleofdefaultcomponentcountsperequipmentorprocesstype(CAPP2005).Equipment/ProcessTypeandDefaultComponentCounts 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 Seal (LL) Regulator (FG) Regulator (GV) Valve (FG) Valve (GV) Valve (HL) Valve (LL)FlareCompressor:Screw‐Electric228112235Compressor:Screw‐Electric‐SealstoFlare22812235Compressor:Screw‐GasEngineCompressor:Screw‐GasEngine‐SealstoFlareCompressor:VapourRecovery‐ElectricCompressor:VapourRecovery‐GasEngine252153Cycling2413862102131121Deepcut2413862102131121Dehydrator:Desiccant100141247Dehydrator:Glycol100141247ESDStation102FlareKnockoutDrum262031Fractionation241386102131131Fractionation:De‐butanizer177208627980Fractionation:De‐ethanizer177208627980Fractionation:De‐propanizer177208627980GasBoot3722GasSweetening:Amine7023321601GasSweetening:Diglycolamine7023321601GasSweetening:IronSponge134121317GasSweetening:Proprietary20046418221GasSweetening:Sulfinol702332160137Table12:Scheduleofdefaultcomponentcountsperequipmentorprocesstype(CAPP2005).Equipment/ProcessTypeandDefaultComponentCounts 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 Seal (LL) Regulator (FG) Regulator (GV) Valve (FG) Valve (GV) Valve (HL) Valve (LL)GasSweetening:Sulfreen134121317HeaderTie‐in:Cond/NGL1013HeaderTie‐in:FlowLine1013HeaderTie‐in:GasLine1013HeatExchanger137Heater:Gas‐firedUnitHeater101Heater:LineHeater4014511010Heater:SaltBathHeater252Heater:TankHeater1022Heater:UnitHeater1022Incinerator101MainLineBlockValve3017MainLineMeterStation17047615570MeterStation70234Meter/RegulatorStation94234Metering70224MolecularSieve100141247PigTrap113Pipeline:Butane1013Pipeline:Ethane1013Pipeline:PentanesPlus1013Pipeline:Propane1013PowerGenerator74538Table12:Scheduleofdefaultcomponentcountsperequipmentorprocesstype(CAPP2005).Equipment/ProcessTypeandDefaultComponentCounts 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 Seal (LL) Regulator (FG) Regulator (GV) Valve (FG) Valve (GV) Valve (HL) Valve (LL)Pump:OilPump(Recycle/Shipping)1013Pump:OtherPumps1013Pump:PumpStation2264721727227Pump:WaterPump(Recycle/Shipping)512Refrigeration:170312226513Refrigeration:Joule‐Thomson79411911RegulatorStation2410Separation405811217Separator:InletSeparator66411111Separator:TestSeparator492511515Stabilization80247312077SulphurRecovery10010TailGasCleanup255Tank:Farm190694Tank:PipelineTerminalTanks123Tank:PopTank24110Tank:ProductionTank2241110Tank:PumpStationTanks123Tank:StorageTank123Tank:TankFarmTanks123Treater17856112117TurboExpander123916482Well:Gas‐Deep>1000m191639Table12:Scheduleofdefaultcomponentcountsperequipmentorprocesstype(CAPP2005).Equipment/ProcessTypeandDefaultComponentCounts 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 Seal (LL) Regulator (FG) Regulator (GV) Valve (FG) Valve (GV) Valve (HL) Valve (LL)Well:Gas‐Injection196Well:Gas‐Shallow<1000m103Well:Oil‐Flowing5714Well:Oil‐HeavyPrimary229Well:Oil‐HeavyThermal229Well:Oil‐Pumping5711440 Table 13: Summary o f equipment or process types by j urisdiction 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 5841 Table 13: Summary o f equipment or process types by j urisdiction 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 Station42 Table 13: Summary o f equipment or process types by j urisdiction 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 1 143 7 A P P E N D IX B

‐ G UI D E L I N E S FOR C OU N T IN G E QU IP M E N T C O M P O N E N TS

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 A PPEN DI X C

‐ M E T H ODOL OG Y FOR A S S E SS IN G U N C E R TA IN T IE S

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/N 0. 5 where N is the number of sources.

8 .1 .1 CO M BI N G UN CE R T A I N T I E S IN M U L T IP L IC A T IO N S T E P S

The IPCC Tier

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

approximate for all random variables):



### U

Total 

### = 2 

### + U 2 

### +

... + U 2 Equation 5

where,

U Total ‐ is the percentage uncertainty in the sum of the quantities.

U 1 ,U 2 , U

n ‐ are the uncertainties in the individual quantities being multiplied.

8 .1 .2 CO M BI N I N G U N CE R T A I N T IE S I N A D D IT IO N ST E P S

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 = 

# ( U

1 

### ⋅ 

# x 1 

# )

+ 

# ( U

2 

### ⋅ 

# x 2 

# )

+

... + 

# ( U

n 

### ⋅ 

# x

n 

# )

Equation 6

total 

# x 1 

### + 

# x 2 

### +

... + 

# x

n

where:46 

### x 1 

### ,x 2 

### ,x n 

### - are the uncertain qua ntities being added.

8 .1 .3 U N C E R T A I N T I E S I N I N D I VID U A L IN P U T Q U A N T I T IE S

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 U P P ER A N D L OWER C ON F I D EN C E L IM IT S

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 ± U i ). Wherever the percent uncertainty for a

quantity was greater than 100%, the uncertainty value was taken to be (100/ U i )

∙ 100 when

determining the lower limit and +U i 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/N 0. 5 where N is the

number of sources in that category.