TECHNICAL REPORT

A National Inventory of Greenhouse Gas 

(GHG), Criteria Air Contaminant (CAC) and 

Hydrogen Sulphide (H2S) Emissions by the 

Upstream Oil and Gas Industry

Volume 3, Methodology for Greenhouse 

Gases

September 2004

2005-0013
2100, 350 – 7th Ave. S.W.

Calgary, Alberta

Canada T2P 3N9

Tel (403) 267-1100

Fax (403) 261-4622

905, 235 Water Street

St. John’s, Newfoundland

Canada A1C 1B6

Tel (709) 724-4200

Fax (709) 724-4225

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

The Canadian Association of Petroleum Producers (CAPP) represents 150

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

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

companies produce more than 98 per cent of Canada’s natural gas and crude oil. 

CAPP also has 125 associate members that provide a wide range of services that 

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

and associate members are an important part of a $75-billion-a-year national 

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

Review by July 2010

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.
 

 

Volume 3 – METHODOLOGY FOR 

GREENHOUSE GASES 

A National Inventory of Greenhouse Gas (GHG), Criteria 

Air Contaminant (CAC) and Hydrogen Sulphide (H2S) 

Emissions by the Upstream Oil and Gas Industry 

PREPARED BY: 

Clearstone Engineering Ltd. 

700, 900-6 Avenue S.W. 

Calgary, Alberta 

T2P 3K2 

PREPARED FOR: 

CAPP 

2100, 350-7 Avenue S.W. 

Calgary, Alberta 

T2P 3N9 

Attention: Rick Hyndman 

September 2004 
i

TABLE OF CONTENTS

1.0 INTRODUCTION 1 

2.0 GENERAL INFORMATION 2 

2.1 Emissions Assessment Methods 2 

2.2 Units of Measure and Reference Conditions 3 

2.3 Data Collection 4 

2.4 Data Management and Processing 5 

2.5 Quality Assurance / Quality Control (QA/QC) 6 

2.6 Uncertainties 7 

2.6.1 Error Propagation Equations 7 

2.6.2 Determination of Primary Data Uncertainties 8 

2.6.3 Determination of Error Bounds 9 

2.6.4 Noteworthy Considerations 10 

2.7 Atmospheric Oxidation 10 

2.8 Carbon and Hydrocarbon Content and Heating Values 11 

2.9 Handling of Indirect Emissions 11 

3.0 FUEL COMBUSTION 12 

3.1 Determination of Fuel Consumption 12 

3.1.1 Important Considerations 13 

3.1.2 Proration of Total Measured Fuel Usage to Individual Devices 14 

3.1.3 Fuel Consumption Based on Maximum Rated Power Output 15 

3.1.4 Fuel Consumption Based on Actual Work or Heat Output 18 

3.2 Compressor Engines 18 

3.2.1 Source Characterization 18 

3.2.1.1 Reciprocating Engines 18 

3.2.1.2 Gas Turbines 19 

3.2.2 Important Considerations 20 

3.2.3 Default Emission Factors 20 

3.3 Process Heaters and Boilers 20 

3.3.1 Source Characterization 20 

3.3.2 Important Considerations 23 

3.3.3 Default Emission Factors 23 

4.0 FLARING 26 

4.1 Acid Gas 26 

4.2 Thermal Oxidizers 27 

4.2.1 Source Characterization 27 

4.2.2 Important Considerations 28 

4.2.3 Default Emission Factors 28 

5.0 FORMATION CARBON DIOXIDE RELEASES 30 

6.0 VENTING 31 

6.1 Source Characterization 31 

6.2 Important Considerations 32 

6.3 Default Emission Factors 34 

6.3.1 Blowdowns 34 
ii

6.3.2 Gas Analyzers 35 

6.3.3 Gas-Operated Devices 35 

6.3.4 Other 37 

6.4 Glycol Dehydrators 38 

6.4.1 Source Characterization 38 

6.4.2 Important Considerations 39 

6.4.3 Default Emission Factors 39 

7.0 FUGITIVE AND OTHER UNINTENTIONAL RELEASES 40 

7.1 Equipment Leaks 40 

7.1.1 Source Characterization 40 

7.1.2 Important Considerations 41 

7.1.3 Default Emission Factors 41 

7.2 Storage Losses 47 

7.2.1 Source Characterization 47 

7.2.2 Important Considerations 47 

7.2.3 Default Emission Factors 47 

7.3 Handling Losses - Tankers 49 

7.3.1 Source Characterization 49 

7.3.1.1 High Vapour Pressure Carriers 49 

7.3.1.2 Low Vapour Pressure Carriers 49 

7.3.2 Important Considerations 49 

7.3.3 Default Emission Factors 49 

7.3.3.1 High Vapour Pressure Carriers 49 

7.3.3.2 Low Vapour Pressure Carriers 50 

7.4 Accidental Releases 52 

7.4.1 Source Characterization 52 

7.4.2 Important Considerations 52 

7.4.3 Default Emission Factors 52 

8.0 SPECIATION OF EMISSIONS 53 

9.0 AN OVERVIEW OF EMISSION SOURCES BY ACTIVITY 61 

9.1 Well Drilling and Associated Testing 61 

9.1.1 Drilling Rigs 61 

9.1.2 Drilling Fluids 62 

9.1.2.1 Entrainment of Solution Natural Gas 63 

9.1.2.2 Volatilization of Invert Drilling Fluids 63 

9.1.3 Drill-Stem Testing 64 

9.2 Well Servicing and Associated Testing 65 

9.2.1 Service Rigs 65 

9.2.2 Pumping Units 65 

9.2.3 Wireline Units 66 

9.2.4 Venting During Well Servicing 66 

9.2.4.1 Conventional Service Work 66 

9.2.4.2 Blowdown Treatments for Natural Gas Wells 67 

9.2.5 Fugitive Emissions From Well Servicing 67 

9.3 Light/Medium Crude Oil Production 68 

9.3.1 Light/Medium Crude Oil Wells 68 
iii

9.3.2 Light/Medium Crude Oil Flow Lines 69 

9.3.3 Single-Well Light/Medium Crude Oil Batteries 69 

9.3.4 Satellite Light/Medium Crude Oil Batteries 71 

9.3.5 Group (or Central) Light/Medium Crude Oil Batteries 72 

9.4 Heavy Crude Oil From Cold Production 72 

9.4.1 Cold Production Heavy Crude Oil Wells 74 

9.4.2 Cold Production Heavy Crude Oil Flow Lines 75 

9.4.3 Cold Production Heavy Crude Oil Single-Well Batteries 75 

9.4.4 Cold Production Heavy Crude Oil Satellite Batteries 75 

9.4.5 Cold Production Heavy Crude Oil Central Batteries (Cleaning Plants) 76 

9.5 Heavy Crude Oil From Thermal Production 77 

9.5.1 Thermal Production Heavy Crude Oil Wells 77 

9.5.2 Crude Oil Flow Lines and Natural Gas Gathering Systems 77 

9.5.3 Thermal Production Heavy Crude Oil Satellite Batteries 77 

9.5.4 Thermal Production Heavy Crude Oil Cleaning Plants 78 

9.6 Natural Gas Production 78 

9.6.1 Natural Gas Wells 78 

9.6.2 Natural Gas Gathering Systems 79 

9.6.2.1 Low-Pressure Gathering Systems 79 

9.6.2.2 Heated Gathering Systems 81 

9.6.2.3 Dehydrated Gathering Systems 83 

9.6.2.4 Other Gathering System Field Installations 85 

9.6.3 Natural Gas Batteries 86 

9.7 Natural Gas Processing 87 

9.8 Natural Gas Transmission, Storage and Distribution 90 

9.9 Petroleum Liquids Transportation 90 

9.9.1 Crude Oil Transportation Systems 90 

9.9.2 Natural Gas Liquid / Liquified Petroleum Gas Systems 91 

9.9.2.1 Surface Transportation (Road and Rail) 91 

9.9.2.2 High Vapour Pressure Pipelines 92 

9.9.3 Pentanes-Plus Systems 93 

9.9.3.1 Surface Transportation 93 

9.9.3.2 Low Vapour Pressure Pipelines 93 

9.10 Accidents and Equipment Failures 94 

9.10.1 Pipeline Ruptures, Well Blowouts and Spills 94 

9.10.2 Surface-Casing Vent Flows 94 

9.10.3 Gas Migration to the Surface 95 

9.11 Waste Oil Reclaiming and Disposal 95 

9.11.1 Oilfield-Waste Transporters 95 

9.11.2 Waste-Oil Reclaimers 95 

9.11.3 Land Treatment Facilities 96 

9.11.4 Road Oiling 96 

10.0 EXTRAPOLATION OF 2000 INVENTORY RESULTS TO THE PERIOD 1990 

TO 1999 98 

11.0 REFERENCES CITED 105 

11.1 Other Information Sources 111 
iv
v

LIST OF ACRONYMS

AGA - American Gas Association 

BSFC - brake-specific fuel consumption 

CAC - criteria air contaminant 

CAPP - Canadian Association of Petroleum Producers 

CCME - Canadian Council of Ministers of the Environment 

CGA - Canadian Gas Association 

CH4 - methane 

CO2O - carbon dioxide form atmospheric oxidation 

CO2E - carbon dioxide equivalent 

CSA - Canadian Standards Association 

EC - Environment Canada 

GHG - greenhouse gases 

GRI - Gas Research Institute 

GTC - Gas Technology Canada 

H2S - hydrogen sulphide 

HEL - higher explosive limit 

HHV - high (or gross) heating value 

IPCC - International Panel on Climate Change 

kt - kilotonnes 

LEL - lower explosive limit 

LHV - lower (or net) heating value 

N2O - nitrous oxide 

NBS - National Bureau of Standards 

NMHC - non-methane hydrocarbon 

NPRI - National Pollutant Release Inventory 

PM2.5 - particulate matter ≤ 2.5 μm in aerodynamic diameter 

PM10 - particulate matter ≤ 10 μm in aerodynamic diameter 

POM - polycyclic organic matter 

ppm - parts per million 

SEPAC - Small Explorers and Producers Association of Canada 

THC - total hydrocarbons 

TNMOC - total non-methane organic compounds 

TOC - total organic compounds 

TPM - total particulate matter 

UOG - upstream oil and gas 

UNFCCC - United Nations Framework Convention on Climate Change 

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

VCR - Voluntary Challenge and Registry 

VOC - volatile organic compound 
vi

CONVERSIONS

USEFUL CONVERSION FACTORS 

Physical Quantity SI to English Conversion English to SI Conversion 

Length 1 m =3.2808 ft 

1 km = 0.6213712 mi 

1 ft = 0.3048 m 

1 mi = 1.609344 km 

Area 1 m2 = 10.7639 ft2 1 ft2 = 0.092903 m2

Volume 1 m3

 = 35.3134 ft3

1 L = 0.2641720 U.S. gal 

1 ft3 = 0.02837 m3

1 U.S. gal = 3.785412 L 

Velocity 1 m/s = 3.2808 ft/s 

1 km/h = 0.6213712 mph 

1 ft/s = 0.3048 m/s 

1 mph = 1.609344 km/h 

Density 1 kg/m3 = 0.06243 lbm/ft3 1 lbm/ft3 = 16.018 kg/m3

Force 1 N = 0.2248 lbf 1 lbf = 4.4482 N 

Mass 1 kg = 2.20462 lbm 1 lbm = 0.45359737 kg 

Pressure 1 kPa = 0.145038 psi 

1 kPa = 4.01474" WC 

1 psi = 6.89476 kPa 

1" WC = 0.249082 kPa 

Energy 1 kJ = 0.94783 Btu 1 Btu = 1.05504 kJ 

Power 1 W = 3.4121 Btu/h 

1 kW = 1.3405 hp 

1 Btu/h = 0.29307 W 

1 hp = 0.746 kW 

Heat Flux/Unit Area 1 W/m2 = 0.317 Btu/h·ft2 1 Btu/h·ft2 = 3.154 W/m2

Heat Flux/Unit 

Length 

1 W/m = 1.0403 Btu/h·ft 1 Btu/h·ft = 0.9613 W/m 

Heat Generation/Unit 

Volume 

1 W/m3

 = 0.096623 Btu/h·ft3 1 Btu/h·ft3 = 10.35 W/m3

Energy/Unit Mass 1 kJ/kg = 0.4299 Btu/lbm 1 Btu/lbm = 2.326 kJ/kg 

Specific Heat 1 kJ/kgoC = 0.23884 Btu/lbmoF 1 Btu/lbm·oF = 4.1869 kJ/kg·oC 

Thermal Conductivity 1 W/moC = 0.5778 Btu/h·ftoF 1 Btu/h·ft·oF = 1.7307 W/m·oC 

Convective Heat 

Transfer Coefficient 

1 W/m2C = 0.1761 Btu/h·ft2·

o

oF 1 Btu/h·ft2·oF = 5.6782 W/m2·oC 
1

1.0 INTRODUCTION

This volume describes the methodology which has been used to develop the present GHG 

emissions inventory for the subject portions of the oil and gas industry for the year 2000. 

The following sections of this volume: 

• provide an overview of the UOG industry, 

• describe the methodologies used to assess emissions from each type of primary 

emissions source, 

• document the procedures and information used to develop quantitative estimates of 

the uncertainty in the inventory results, 

• identify the sources of information used to compile the inventory, 

• highlight the key assumptions used to bridge data gaps, and 

• summarize the measures taken to assure that the results are as complete and accurate 

as possible. 

Specifically: 

• Section 2 presents general information concerning the initial planning and design of 

the inventory. 

• Section 3 describes the approach taken for assessing emissions from combustion 

sources. The source types considered include: natural gas-fuelled compressor 

engines, process heaters and boilers, industrial space heaters, flares and thermal 

oxidizers. 

• Section 4 describes how emissions from waste gas flaring are handled. 

• Sections 5 and 6 detail emissions related to venting of formation CO2 and natural 

gas, respectively. 

• Section 7 delineates the procedures for estimating emissions from fugitive sources, 

including equipment leaks, storage tanks and tanker activities, and accidental 

releases, respectively. 

• Section 8 presents the procedures used for speciation of the emissions. 

• Section 9 details the procedures used to estimate the number of sources and relative 

activity levels in each segment of the industry. 

• Section 10 provides a description of the methods used to extrapolate the inventory 

results to the period 1990 through 1999. Included are tables describing the activity 

values used to prorate the inventory results and the actual activity data for each year 

and province/territory. 

• Section 11 lists all references cited in this volume. 

Volume 5 of this report contains a glossary of terminology used in this and the other volumes of 

this report, as well as a compendium of emission factors used and a listing of uncertainty values 

determined. 
2

2.0 GENERAL INFORMATION

2.1 Emissions Assessment Methods

The present GHG emissions inventory was developed using a bottom-up approach, beginning 

with individual facilities and their equipment, and the following primary types of GHG 

emissions sources: 

• fuel combustion 

• flaring, 

• formation CO2, releases, 

• venting (reported and unreported),and 

• fugitive and other unintentional releases (equipment leaks, storage and handling 

losses, and accidental releases). 

The resulting emissions were then aggregated to determine overall emissions by facility type, 

activity type and geographic area. 

The particular emissions assessment methodology applied to each facility and its equipment was 

determined on a case-by-case basis, with the objective being to obtain the most reliable estimate 

possible from the information available. The basic methods considered in each case are listed 

below in the order of decreasing preference: 

• Emission Monitoring Results – Some facilities, as a condition of their operating 

approval, are required to monitor and report their atmospheric emissions of certain 

substances. The use of actual emission monitoring results is the preferred approach 

wherever such data are available. 

• Emission Source Simulation Results – Computer models are available for 

estimating emissions from some types of sources; for example, GRI GlyCalc for 

predicting emissions from glycol dehydrators and US EPA TANKS to predict 

evaporation losses from storage tanks. These models apply empirical correlations 

and/or fundamental engineering principles to develop rigorous emission estimates 

based on the specific operating and design parameters of the source. When properly 

applied, simulators offer the ability to predict accurately emissions from individual 

sources (generally to within ±25 percent or better), but have the disadvantage of 

requiring more time, effort, user knowledge, and input data to apply. Moreover, the 

necessary design and operating input data may be difficult to obtain. Consequently, 

the use of emission source simulations herein is primarily limited to the development 

of emission factors based on typical process and operating conditions for different 

segments of the industry. 

• Emission Factors – This is a statistical approach in which the average emission from 

a group of sources is related to an appropriate activity value using a simple relation of 

the form: 

ERi = EFi × AR × (1 – CFi) 
3

 where, 

ERi = emission rate of substance i for the selected source. 

EFi = emission factor for estimating emissions of substance i from the 

selected source. 

AR = activity rate for the parameter to which the emission factor applies 

(e.g., amount of fuel consumed). 

CFi = efficiency of any emission control (or abatement) device that may 

be used on the emission source which is not accounted for in the 

applied emission factor. In the absence of specific data it will be 

assumed that the target sources have no special controls. 

The use of emission factors is often an over simplification which may be subject to 

very high uncertainties (e.g., orders of magnitude) when applied to a single source, 

but becomes a statistically valid approach when considering aggregate emissions 

from large numbers of sources. The available sources of emission factors are, in the 

order of decreasing preference: 

i) custom factors based on recent emission measurements on the target 

source, 

ii) manufacturer’s values 

iii) Canadian-specific values, and 

iv) published values from the open literature (e.g., US EPA’s AP-42 

compilation of air pollutant emission factors). 

• Destruction and Removal Efficiencies (DREs) – The emissions of individual 

substances input to a combustion device may be estimated based on the extent to 

which they are expected to be destroyed (i.e., converted to intermediate, partiallyoxidized and fully-oxidized products of combustion) and/or removed by that device. 

This is done using a relation of the form: 

DRE = (1 – ERi/IRi) x 100 

where, 

DREi = destruction and removal efficiency of substance i for the selected 

source. 

ERi = emission rate of substance i from the selected source. 

IRi = input rate of substance i to the selected source. 

All source-specific considerations and default emission factors are delineated in Sections 3 to 9, 

which follow. Available manufacturer’s and other emission factors are listed in Volume 5. 

2.2 Units of Measure and Reference Conditions

In the general literature, emissions and source parameters may be expressed using a wide range 

of units, formats, classifications and terminology. Herein, every effort has been made to maintain 
4

a consistent convention to allow convenient comparisons and aggregation of results, and to be 

consistent with applicable national and international reporting requirements. 

Consumption of gaseous fuels or combustibles is expressed in terms of the gross (or higher) 

heating value of the material in units of GJ; this is common practice for gas purchases and sales. 

Liquid fuels are expressed on a volume basis in units of litres. All emission factors are expressed 

on an energy basis in units of ng/J (gross) in general accordance with IPCC (2000) good practice 

guidance. All volumetric gas flows are expressed in cubic metres at standard reference 

conditions of 101.325 kPa and 15oC. The conversion table presented at the front of this volume 

may be used to convert available data to these units as needed. 

Throughout this document, the term “sour natural gas” is used to indicate a natural gas 

containing 0.01 moles or more of H2S per kmole of total gas (i.e., 10 ppmv H2S) as defined by 

AEUB Guide 56. Petroleum liquid production is classified as sour when it contains 0.5 percent 

sulphur on a mass basis (this sulphur content does not have to be in the form of H2S). Substances 

that contain less than these limits are referred to as sweet. 

2.3 Data Collection

Regardless of the techniques employed, a certain amount of source and activity data is needed to 

support the assessment effort. The key challenges include: ensuring completeness, accuracy (i.e., 

no double counting) and correct posting of the information. 

The required activity data includes the following: 

• measured volumes of natural gas taken from the process, 

• vented and flared waste-gas volumes, 

• fuel purchases (e.g., propane, diesel fuel, etc.), 

• fuel analyses, 

• emissions monitoring results, 

• process operating conditions that may be used to infer the work being done by 

combustion devices (e.g., gas compositions, temperatures, pressures and flows), and 

• spill and inspection reports. 

Other required data includes the following: 

• types of processes being used, 

• equipment inventories, 

• emission source control features, 

• sulphur content of the fuels consumed and waste gas flared, and 

• composition of the inlet and outlet streams. 

To fulfil these needs the study drew on official data from the producing provinces, supplemented 

by survey information on 1500 facilities provided by oil and gas producers. A complete listing of 

the different government sources used for the different oil and gas producing regions in Canada 

is provided in a Volume 5 of this report. 
5

Compilation of the required source data involved developing a detailed inventory of sources by 

facility or installation. This included larger point sources (e.g., compressor engines, process 

heaters or boilers, storage tanks, glycol dehydrators) through to the often many minor sources 

(e.g., portable fired equipment, pigging facilities, mainline block valves, metering equipment, 

etc). Where available, equipment lists were used to determine the amount and type of equipment 

at a site. Otherwise this information was inferred for each facility based on consideration of the 

type and amount of production accounting activity, the types of linked infrastructure (e.g., inlet 

and outlet pipeline systems), typical design and operating practices for the type of facility, and 

related trends determined from limited industry surveys. The specific details of these inferences 

are delineated by industry segment in Section 11. 

While there is a natural tendency to trivialize smaller sources, these, due to their numbers and 

periods of activity, may often be significant on an aggregate basis. Therefore, the objective was 

to account for all sources unless their collective contribution to total emissions could be proven 

to be negligible and their inclusion impracticable. 

Typical difficulties encountered in attempting to utilize the available data are as follows: 

• converting electronic data to a consistent or convenient format, 

• reliable and accurate data entry, 

• verification of database accuracies and completeness, 

• development of special applications to perform custom retrievals of information from 

existing applications, 

• identifying multiple process trains or process units of the same type at a facility, 

• determining emission controls being utilized, and 

• prorating total facility fuel consumption to the individual pieces of combustion 

equipment. 

2.4 Data Management and Processing

A relational database application was developed using Microsoft Access to process and manage 

the emissions inventory information. The database was designed as a series of tables containing 

related data. Table 1 provides a summary of the primary tables within the database, a description 

of the type of data the table contains and the number of records in each table. In addition to 

these, there are a number of tables that contain emission factors, equipment schedules, control 

factors and lookup tables with definitions for codes used in the main tables. 

As part of the deliverables for the project, a detailed facility level database of GHG emissions 

was prepared. The database contains the fields listed in Table 2.. 

Notwithstanding this, some elements of the inventory work were done externally in spreadsheet 

applications and using other applications (for example, to pre-process, translate, reformat, reduce 

or merge some input data files. 
6

Table 1. GHG emission database table details. 

Table Description Records 

Annual Production production volumes for each facility (from provincial 

regulatory agencies) 421 917 

Facilities name, facility type, sector and location for each facility 

(also contains facilities that are not currently active) 273 780 

Sources a list of all sources located at each facility 364 382 

Speciation Profiles facility specific composition data 321 145 

Emission Detail emission results for each facility and source 7 398 413 

Table 2. GHG Emission Database 

Parameter Description 

Facility ID A unique identifier for each facility in the database 

Industry Sub-Sector The sub-sector of the UOG sector. 

Facility Type The type of facility within the sub-sector 

Emission Source Type Fuel Combustion, Fugitive Equipment Leaks, Venting, etc. 

Emission Compound CO2, CH4, N2O, CO2E, CO2O, NMHC 

Total Emissions Total emissions in tonnes 

Lower Uncertainty Aggregated uncertainty for the source expressed as a fraction of 1. 

Upper Uncertainty Aggregated uncertainty for the source expressed as a fraction of 1. 

2.5 Quality Assurance / Quality Control (QA/QC)

As a basic QA/QC measure, all results were subjected to an internal review by senior operations, 

engineering and environmental personnel to help ensure that no errors, omissions or double 

counting occurred. In addition, copies of the draft results were disseminated, via contact lists 

provided by CAPP, to individual companies for comment. A second level of review was also 

provided by the project steering committee and additional experts nominated by the study 

sponsors. 

Where possible, the results were compared to previous baseline data and to other relevant 

corporate, industry and national inventories. Any apparent differences or anomalies were put in 

context relative to corresponding changes in activity levels, impacts of new regulatory 

requirements and voluntary industry initiatives. 

Specific elements of the internal review conducted are: 

• Confirmation that all useful sources of the required emission source, activity and 

emission factor data, calculation procedures and test methods are identified and 
7

properly referenced (both for the benefit of future updates and to provide a clear trail 

for resolving anomalies). 

• Checks for recent updates or improvements in the selected calculation procedures and 

emission factors. 

• Ranking of sources based on their emission and energy intensities to help identify 

anomalies. 

• Checks to ensure that point source contributions are subtracted from area source 

category totals where appropriate. 

• Confirmation of consistency between onsite equipment, products produced and 

connected infrastructure. 

• Confirmation that combustion equipment is assigned to all sites with reported fuel use 

and none is assigned at sites with no fuel use. 

• Tests for agreement between summaries of the activity data after being entered into 

the database application and corresponding published totals where available. 

• Manual checks of each type of calculation performed by the database application. 

• Confirmation that zero in (emission factor or activity level) gives zero out. 

• Gross checks to ensure that the amounts of reported and calculated emissions for each 

facility are reasonable compared to facility throughputs. 

2.6 Uncertainties

Uncertainties in inventories arise through at least three different processes (IPCC, 2000): 

• Uncertainties from definitions (e.g., meaning incomplete, unclear, or faulty definition of 

an emission or uptake), 

• Uncertainty from natural variability of the process that produces the emission, 

• Uncertainties from the assessment of the process or quantity, including, depending on 

the method used: (i) uncertainties from measuring, (ii) uncertainties from sampling, (iii) 

uncertainties from reference data that may be incompletely described, and (iv) 

uncertainties from expert judgement. 

For the purposes of this study, uncertainties from definitions are assumed to be adequately 

controlled through the applied QA/QC procedures, and therefore, negligible. Quantitative 

uncertainty estimates to account for the later two contributions were developed using the Tier 1 

approach published by IPCC (2000). This approach employs simple error propagation equations 

based on the assumption of uncorrelated normally distributed uncertainties under addition and 

multiplication. 

2.6.1 Error Propagation Equations

Basically, an emissions inventory may be viewed as the sum of emission estimates for multiple 

sources, where the estimate for each source is typically the product of an emission factor and a 

corresponding activity value. The overall uncertainty in the sum of the individual emission 

estimates is determined using the following relation (this expression is exact for uncorrelated or 

independent variables): 
8

( )( ) ( )

x x x

U x U x U x U n

n n

total + + +

• + • + + • = ......

1 2

2 2

2 2

2

1 1 (1) 

Where: 

Utotal - is the percentage uncertainty in the sum of the quantities. 

xi Ui and - are the uncertain quantities and the percentage uncertainties 

associated with them, respectively. 

The uncertainty in each individual emission estimate in the summation is determined by 

combining the uncertainty in the corresponding emission factor and activity parameter using the 

following relation (this is approximate for all random variables): 

2 2

2

2

1 ... Utotal = U +U + +U n (2) 

Where the activity parameter for a source is continuous (e.g., gas throughput or fuel gas 

consumption), the uncertainty in the emission estimate for that source is calculated using Equation 

2. Where the activity parameter for a source is a count or integer value (e.g., number of equipment 

components, number of stations, number of compressors, etc.), Equation 1 is used to evaluate the 

aggregate uncertainty for N sources of the same type and average strength, and Equation 2 is used to 

account for the fact the value N may have some uncertainty in it. 

2.6.2 Determination of Primary Data Uncertainties

The uncertainties assigned to each type of activity data, emission factor and speciation profile are 

listed in Volume 5 of this report along with their reference. The approach used to evaluate these 

uncertainty values was to first, where applicable, divide each factor or parameter into its 

constituent elements, then determine the uncertainty in each element, and finally calculate the 

combined uncertainty using the rules described in Section 2.6.1. 

The uncertainty in each primary data type is estimated using one of the following approaches, 

presented in the order of decreasing preference: 

• Error analysis of the available measurement data. 

• Applicable uncertainty estimates presented in the open literature. 

• Default uncertainty values published by IPCC (2000). 

• 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. 

When deriving uncertainty values from measurement data, a Student-t distribution is assumed for 

sample sizes of less than 30 and a normal distribution is assumed for larger sample sizes. 
9

The primary source of published uncertainty values is the report on methane losses from the US 

natural gas industry sponsored by US EPA/GRI (1996). Additional uncertainty values are taken 

from IPCC (2000). 

Where suitable data or published values are unavailable, it is necessary to use professional 

judgement and solicit informal input from applicable experts to provide uncertainty values. The 

application of formal protocols for expert elicitation is beyond the scope of this work. Rather, values 

are estimated by the project team and through information discussions industry experts. The formal 

review of this document by the Project Steering Committee and other external reviewers is deemed 

to provide a reasonable mechanism for the critique of the presented uncertainty values. 

2.6.3 Determination of Error Bounds

In practice, uncertainties found in inventory source categories and individual source estimates may 

vary from a few percent to orders of magnitude, and may be correlated. This is not consistent with 

the assumptions inherent in Equations 1 and 2 used for combining uncertainties, namely that the 

variables are uncorrelated with a standard deviation of less than about 30% of the mean, but under 

these circumstances, the presented relations may still be used to obtain an approximate result (IPCC, 

2000). 

The inventory uncertainty is expressed by giving the range within which the unknown true 

emission total is expected to occur subject to a specified probability (or level of confidence). The 

higher the required level of confidence, the wider the range becomes. The IPCC suggests using a 

95% confidence interval which is adopted for use here. 

To determine the upper and lower limit of the inventory confidence interval it is appropriate to 

consider the shape of the uncertainty probability function for each quantity being combined. IPCC 

(2000) good practice is been followed in this regard, which 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. 

Accordingly, wherever the percent uncertainty for a quantity is less than 100%, a normal probability 

function is assumed resulting in a symmetric distribution about the mean (i.e., a balanced 

uncertainty of ±Ui). Wherever the percent uncertainty for a quantity is greater than 100%, the 

uncertainty value is 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 is 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 1 and 2. 

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. 
10

For example, a quantity, x, that is determined to have an upper uncertainty bound of UUpper = +50% 

would be assumed to have a lower uncertainty bound of ULower = -50%. In comparison, a quantity 

that is determined to have an upper uncertainty bound of UUpper = +125% would be assumed to have 

a lower confidence limit of ULower = (100/125) * 100% = -80%. Similarly, an upper uncertainty 

bound of UUpper = +200% would result in a lower uncertainty bound of ULower = (100/125) * 100% = 

-50%. 

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 rate, which is meaningless, or, if 

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

emissions. 

2.6.4 Noteworthy Considerations

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 

emission estimates for the sources in these categories. 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. Thus, it is possible that a category with many sources and 

relatively high uncertainties in individual emission estimates (e.g., fugitive equipment leaks) may 

have a lower total uncertainty in the aggregate emission estimate than a category with much 

fewer sources and better uncertainties per source (e.g., venting). In general the uncertainties 

associated with GHG emissions from a specific facility are relatively large but when the 

emissions from many hundreds or thousands of facilities are aggregated the overall uncertainty 

may be very low. For example, for gas processing plants the average uncertainty in GHG 

emissions at a facility level is on the order of ±25 percent but the aggregate uncertainty in GHG 

emissions for all plants is on the order of ±1.2 percent. 

2.7 Atmospheric Oxidation

IPCC (1996) practice is to account for all releases of carbon to the atmosphere as CO2 except 

unoxidized carbon emitted in a solid (or stored) form such as particulate matter, soot or ash. In 

general, carbon emitted in a solid form is assumed to remain stored indefinitely (i.e., not emitted 

to the atmosphere). Carbon released as carbon monoxide (CO), methane (CH4), or non-methane 

hydrocarbons (NMHC) is evaluated separately from, and in addition to, the CO2 emission 

assessment. This apparent double counting allows for the fact that these non-CO2 compounds all 

oxidize to CO2 in the atmosphere within a period of a few days to about 12 years, depending on 

the substance. 

For combustion sources, the IPCC accounting of GHG contributions due to atmospheric 

oxidation of non-CO2 gases is implicitly accounted for in the applied factors. The CO2 emission 
11

factors for fuels assume complete conversion of all carbon to CO2 except that portion which is 

emitted in a solid form. For non-combustion sources, the IPCC requirements for including 

contributions due to atmospheric oxidation of the associated non-CO2 emissions are not 

explicitly stated in either IPCC methodology manual or good practice guidance, but are currently 

being emphasized through the UNFCCC Secretariat’s national inventory review process. Here 

contributions due to atmospheric oxidation of non-CO2 emissions by non-combustion sources are 

calculated and reported separately as CO2O (i.e., equivalent CO2 emissions due to atmospheric 

oxidation of non-CO2 emissions from non-combustion sources). 

2.8 Carbon and Hydrocarbon Content and Heating Values

The carbon and hydrocarbon content and heating values of all streams were calculated based on 

their composition using the standard estimation procedures described by Reid et al. (1987). Sitespecific composition data was used wherever available, otherwise industry average values 

calculated based on the available data were assumed. 

2.9 Handling of Indirect Emissions

One initial goal of the inventory was to collect data that would allow assessment of indirect 

emissions associated with consumption of purchased electric power, steam and hydrogen. This 

part of the project relied heavily on the industry survey to determine how pervasive the purchase 

of these energy forms is in the UOG sector. The results of the industry survey indicate that 

purchase of hydrogen does not occur in the UOG sector. In 2000, purchase of steam is limited to 

two sites which operate cogeneration facilities to simultaneously produce steam and electric 

power. 

Purchase of electric power for use by prime movers (i.e., pump and compressor drivers) and 

ancillary equipment (e.g., lighting, etc.) is pervasive throughout the UOG sector. Purchased 

electric power use at individual facilities may range from none (for remote facilities that generate 

their own electric power) to virtually 100 percent of energy use (at fully electrified compressor 

stations). As the purchased electric power data from the industry survey were incomplete (i.e., 

about 340 facilities out of over 35 000 facilities and over 200 000 well sites), the electric power 

utilities were contacted to investigate whether this information is available from that avenue. 

Unfortunately the electric power utilities do not organize their data in a format that would allow 

easy extraction of electric power consumption data at a facility level. Short of obtaining lists of 

all power accounts for each facility (hundreds of thousands of accounts) and then aggregating 

these data, there does not seem to be practical means of obtaining electric power use at the 

facility level. 
12

3.0 FUEL COMBUSTION

3.1 Determination of Fuel Consumption

At most facilities, natural gas, or sometimes even crude oil, is taken from the process and used as 

fuel. On an industry-wide basis, most of this fuel is used by compressor engines, pump engines, 

heaters and boilers. The estimated disposition of this fuel by type of device is presented in Table 

3 below. 

Table 3. Disposition of burned fuel gas by sub-sector of the UOG industry. 

Fraction of Fuel Burned (percent) 

Sub-Sector Reciprocating 

Engines 

Gas 

Turbines 

Heaters/ 

Boilers 

Light/Medium Crude Oil Prod. 91.4 0.0 8.6 

Heavy Crude Oil Cold Prod. 49.8 0.0 50.2 

Heavy Crude Oil Thermal Prod. 0.7 0.0 99.3 

Natural Gas Prod. 79.2 4.4 16.4 

Sweet Natural Gas Processing Plants 84.9 0.0 15.1 

Sour Natural Gas Plants – Injection 96.1 0.0 3.9 

Sour Natural Gas Plants – Flaring 82.0 0.0 18.1 

Sour Natural Gas Plants – Recovery 15.6 10.2 84.3 

Reprocessing Plants 0.0 39.2 60.8 

Propane Consumption 40.0 0.0 60.0 

Other fuel uses include make-up gas to flare gas streams to satisfy minimum heating value 

requirements for stable combustion, supplemental fuel for incinerators to achieve good 

destruction efficiencies and/or to maintain the minimum stack temperatures needed to achieve 

good atmospheric dispersion of the emitted substances, flare and incinerator pilot gas, flare and 

vent header purge gas, blanket gas for storage tanks, and the supply medium for gas operated 

devices (e.g., instrument control loops, chemical injection pumps and compressor starters). 

In most cases, natural gas taken from the process is the principal type of fuel used for stationary 

combustion devices, while purchased liquid fuels are mostly used for mobile sources (e.g., 

construction equipment and motor vehicles). Purchased propane is sometimes used for small 

compressors, pumpjack engines and portable heaters and torches. 

The following subsections delineate the methods used to prorate reported fuel gas consumption 

(i.e., fuel gas taken from the process). The volumes of the different types of purchased fuels 

consumed (e.g., natural gas, propane and diesel) are estimated based on available trend data for a 

representative cross-section of the industry. 
13

3.1.1 Important Considerations 

Operators are required, as part of normal production accounting requirements, to report the total 

amount of fuel taken from the process at each of their sites. Purchased fuel is generally not 

tracked as part of these requirements. The types of facilities where significant amounts of fuel 

may be purchased include thermal heavy oil and bitumen production facilities, as well as some 

minor field installations and wellsite facilities on sour systems where sweet process fuel is not 

available. 

There are a wide variety of fuel-gas metering arrangements that may occur at facilities to 

determine reportable fuel consumption. This complicates production accounting requirements 

and introduces a potential for error. Often complexities in fuel gas metering and accounting are 

introduced as a result of additions and changes to an existing facility over time. 

At many facilities, a single flow meter is installed to measure the total amount of reportable fuel 

withdrawn from the process. Sometimes secondary meters are installed to determine fuel 

disposition by major fuel-use categories but this additional information is usually only for 

internal use at such facilities and is not carried forward into the final production accounting 

statistics reported to government agencies. 

In other cases, the available fuel gas meter or meters may measure only a portion of the fuel gas 

usage. For example, it is common practice for packaged compressor units to be supplied with a 

dedicated fuel gas meter. A facility might rely on these meters to determine fuel use by the 

compressor engines, and then simply estimate the amount of fuel consumption by all other 

sources (e.g., fuel for heaters, reboilers, incinerators, flare pilots, and for flare header purge and 

makeup gas). 

Fuel gas used for non-combustion purposes (e.g., instrument gas, compressor start gas, 

dehydrator stripping gas, blow-case supply gas, and some blanket gas and equipment purging 

applications) may occur either upstream or downstream of available fuel gas meters, or a 

combination thereof. 

Sometimes fuel gas is added to waste gas streams (e.g., to acid gas at flaring sour gas plants) to 

meet the minimum required heating value for stable flaring of the stream. 

At small field installations (e.g., meter stations, field dehydrators and line heaters), total fuel use 

reported by companies may not be metered at all but rather estimated based on equipment duties 

and operating hours. The fuel use at well sites is normally allocated to the first downstream 

facility (e.g., battery) rather than reported at the well-site level. With the implementation of the 

petroleum registry in Alberta, this is beginning to change. It is now possible to report fuel use at 

the point where it is actually consumed. 

In estimating emissions, it is important to determine the amount of purchased fuel consumption, 

the disposition of total reported and purchased fuel use by type of combustion device. This is 

most important for determining emissions of criteria air contaminants such as CO, NOx, and PM, 
14

since the emission factors for these substances vary greatly according to the type of combustion 

device (i.e., reciprocating engine, turbine engine or heater/boiler). For GHG emissions it is less 

of an issue since CO2 is the predominant contributor to GHG emissions from fuel combustion, 

and the emission factors for this substance vary little with the type of combustion device. 

Methane emission factors for fuel combustion do vary significantly with the type of combustion 

device and may contribute up to 17 percent of fuel-use GHG emissions. N2O emissions from fuel 

combustion are a much less important contributor to fuel-use GHG emissions. Moreover, N2O 

emission factors are not generally available for all types of combustion devices. 

For natural gas, the composition of the fuel may vary appreciably from site to site but the actual 

carbon content of the fuel is much less sensitive. Typical values may range from 64 to 76 percent 

on a mass basis for different types of gas streams (e.g., raw gas, processed gas, tank vapours and 

dehydrator vent gas). For processed natural gas, the carbon content may only range from about 

72 to 74 percent on a mass basis. 

3.1.2 Proration of Total Measured Fuel Usage to Individual Devices 

Three types of situations are encountered regarding reported fuel use at individual facilities: 

• Information is available on the number, types and sizes of combustion equipment at the 

site. In these cases, calculations are performed to estimate the theoretical amount of fuel 

use by each device and the results are then used to develop factors for prorating the actual 

reported fuel use. 

• No information is available on the number and sizes of combustion equipment at the site, 

but based on the type of facility it could be reasonably assumed that all fuel was 

consumed by a specific type of combustion device. For example, at a gas gathering 

compressor station it could reasonably be assumed that all fuel is consumed by one or 

more reciprocating engines. At an oil production facility with no gas conservation, the 

fuel could reasonably be assumed to be all consumed by process and tank heaters. 

• No information is available on the number and sizes of combustion equipment at the site 

and it is likely that more than one type of combustion device is being used. In these cases, 

the fuel use is prorated using the average proration values determined for other facilities 

of the same type for which such detailed information are available (see Table 3). 

The proration of reported fuel use based on theoretical fuel use is done using the following 

equation: 

where, 

eFi = estimated fuel gas consumption (GJ/y) by combustion device i, 

éFi = theoretical fuel gas consumption (GJ/y) by combustion device i, 

kN = normalization correction factor (dimensionless). 

The value of kN is determined using the following equation: 

eFi

= e′Fi

⋅ k N
15

where, 

eF = total measured fuel gas usage at the site (GJ/y), 

e FC ∑ ′ = sum of the calculated/theoretical fuel gas usage by each 

combustion device at the site (GJ/y), and 

éFnc = calculated/theoretical fuel gas usage by all non-combustion devices 

at the site (GJ/y). 

The procedures for calculating the theoretical amount of fuel consumption by a combustion 

device are presented in Sections 3.1.3 and 3.1.4. 

3.1.3 Fuel Consumption Based on Maximum Rated Power Output

In the absence of any better information, the theoretical fuel gas consumption by a stationary or 

portable combustion device is estimated based on its maximum rated power output, the heating 

value of the fuel and an appropriate thermal efficiency, load factor and operating factor as given 

by the following equation: 

where, 

eF = rate of fuel consumption expressed as an energy flow rate and 

based on the higher heating value of the gas (GJ/y), 

emax = maximum rated power output of the combustion device (kW), 

kL = fractional loading of the combustion device when it is operating 

(dimensionless) (see Table 5 for default values), 

tO = number of hours during the year that the device is actually 

operating (h) (see Table 6 for default values), 

η = thermal efficiency of the device based on the net heat/energy input 

rate (percent) (see Table 4 for default values), 

HHVF = higher (gross) heating value of the fuel gas (MJ/m3), 

LHVF = lower (net) heating value of the fuel gas (MJ/m3), and 

gc = factor to convert from units of kJ/s to GJ/y, 

= 31.536. 

Default thermal efficiency, load and operating factors are presented in Tables 4 to 6, 

respectively. 

e

e - e k =

F

F F

N

C

NC

∑ ′

∑ ′

e g

LHV

100 HHV

8760

t

e = k c

F

O F

F L ⋅ ⋅ 













 ⋅ ⋅ max η
16

Table 4. Typical input heat rates and thermal efficiencies (based on the net heating 

value of the fuel) for different types and sizes of natural gas-fuelled 

equipment. 

Source Type Maximum Rated 

Power Output 

(kW) 

Input Heat 

Rate 

(kJ/kW•h) 

Thermal 

Efficiency 

(percent) 

<325 12 857 281

325 to 600 11 250 321

600 to 2250 10 000 351

Reciprocating Engines 

>2250 9 474 381

Turbine Engines All 10 909 332

<375 (Natural Draft) 4 736 763

<375 (Forced Draft) 4 500 802

Industrial and Commercial 

Heaters and Boilers 

≥375 4 500 802

Residential Water Heaters All 7 500 484

Residential Furnaces All 5 143 705

Vented Outdoors 4 500 806 Catalytic Heaters 

Vented Indoors 3 600 100 

Thermoelectric Generators All 100 000 3.62

Note: The shaded entries in the table are used as defaults where no other information was supplied. 

1 Adapted from Perry and Chilton (1973). 

2 Estimated based on a review of current manufacturer’s data for selected units. 

3 Adapted from Fig 8-30 of GPSA Engineering Data Book, Volume 1, tenth Edition, 1987. 

4 Adapted from Geller (1988). 

5 Adapted from Baumeister et al. (1978). 

6 Catalytic heaters emit radiant heat and discharge thermal heat with the combustion products. Thus, 

the thermal efficiency of a catalytic heater depends on the ability of the room to absorb the radiant 

heat (i.e., on the absorptivity of the objects in the room). Based on discussions with one major 

manufacturer of catalytic heaters used in process buildings, actual unit efficiencies may range 

from 50 to 80 percent. Although, a value of 80 percent is typically used for design purposes. 
17

Table 5. Estimated load factors for combustion devices during actual 

running/firing periods1. 

Source Type Load Factor (kL) 

(Fraction of Maximum Rated Power Output) 

Reciprocating Engines 0.75 

Turbine Engines 0.90 

Industrial and Commercial 

Heaters and Boilers 

1.0 

Residential Water Heaters 1.0 

Residential Furnaces 1.0 

Catalytic Heaters 1.0 

Thermoelectric Generators 1.0 

1 Based on engineering estimates and personal experience. 

Table 6. Typical portion of the time combustion devices are actually 

running/operating. 

Source Type Fractional Time 

In Operation 

Annual 

Operating Hours 

Reciprocating Engines 0.791 6920 

Turbine Engines 0.811 7096 

Industrial and Commercial 

Heaters and Boilers <29 MW 

0.502 4380 

Industrial and Commercial 

Heaters and Boilers >29 MW 

1.0 8760 

Residential Water Heaters 0.173 1489 

Residential Furnaces 0.254 2190 

Catalytic Heaters 0.505 4380 

Thermoelectric Generators 0.956 8322 

1 Mean of data collected by Legge and Baker (1987) for equipment at oil and gas facilities in 

Alberta. 

2 Arbitrarily determined based on typical sizing practice for the types of applications usually 

encountered at gas facilities. 

3 Based on hot water usage only during normal day-time working hours (i.e., 8 hours per day for 5 

days per week), and an assumed 50 percent duty during this period. 

4 Based on use only during the colder half of the year and on an assumed 50 percent duty during this 

period. 

5 Based on use only during the colder half of the year and on an assumed 100 percent duty during 

this period. 

6 Based on use an assumed 100 percent duty except for a 2 to 3 week shutdown period each year. 
18

3.1.4 Fuel Consumption Based on Actual Work or Heat Output

If insufficient data are available to estimate fuel gas consumption based on the available power 

output of a device, fuel consumption is estimated based on the amount of work or heat output as 

indicated by available process data (e.g., temperatures, pressures and flows) and allowing for the 

efficiency of the device. The calculation procedures and process data used depended on the type 

of combustion device, and are delineated in Sections 3.2 and 3.3, accordingly. 

Equipment manufacturers typically report specific fuel requirements based on the net heating 

value of the fuel rather than the gross heating value as considered herein. Consequently, where 

fuel consumption is estimated from equipment performance curves, the results are converted to a 

gross-heating-value basis before being used with the equations and emission factors provided in 

this document. 

3.2 Compressor Engines

3.2.1 Source Characterization

Both reciprocating and turbine engines are used as prime movers for natural gas compressor 

units. 

3.2.1.1 Reciprocating Engines

Natural gas-fuelled reciprocating engines used in compressor applications may range in size 

from about 30 to 3500 kW, and typically operate at speeds of 800 to 1800 rpm. Some low-speed 

(i.e., 360 to 525 rpm) single-cylinder and two-cycle units also are available. 

Reciprocating engines are available in both naturally-aspirated (NA) and turbocharged-aftercooled (TA) configurations. Additionally, both high and low compression ratio versions are 

available for most engines. The high compression ratio pistons are used on TA engines to reduce 

brake-specific fuel consumption (BSFC) and emissions, but can only burn a very narrow range 

of fuels. The low compression ratio pistons are used on both TA and NA standard engines. 

Any combination of aspiration type, compression ratio, fuel composition and emission control 

technology can change the rating of a given engine. So, where actual configuration data are 

available unit-specific performance and emission factor data are applied. 

Optimum combustion conditions (maximum power) are obtained when the air-fuel ratio is close 

to stoichiometric. Current natural gas engines are generally designed to run lean. The excess air 

promotes more complete combustion of the fuel, which helps to improve fuel efficiencies and 

reduce the thermal load on the engine. Fuel efficiency varies as a function of actual power output 

and engine speed. 
19

Unfortunately, the conditions that tend to promote maximum power output and fuel efficiency 

also create the highest combustion temperature, which promotes the formation of NOx emissions. 

The common method to limit emissions on gas engines is called lean burn, a technology 

developed in the 1980s. Lean-burn engines use the turbocharger to run 50 to 100 percent excess 

air (above the stoichiometric requirement) through the combustion chamber. Excess air reduces 

combustion temperatures resulting in lower NOx but higher CO, CH4 and total hydrocarbons 

(THCs) when compared with the rich-burn engine. It is critical to maintain a nearly constant airfuel ratio in order to maintain emission levels of an engine. 

3.2.1.2 Gas Turbines

Stationary gas turbine engines are available in sizes up to a current maximum capacity of 220 

MW but typical sizes tend to be in the range of 1 to 25 MW for most industrial applications. In 

the gas industry they tend to be used in processing and transmission rather than gathering 

applications. 

The rated thermal efficiency of turbine engines is typically 30 to 35 percent and can be as high as 

42 percent for new gas turbine models with smaller units tending to the lower end of the range. 

The input heat rates required to achieve the manufacturer’s published power outputs for each unit 

are referenced at standard conditions and on the net heating value of the fuel, and must be 

derated to site conditions. Differences in ambient air temperature, altitude, barometric pressure 

and humidity should all be accounted when making these adjustments. No power correction is 

normally required. 

The gas turbine, in general, is a low emitter of exhaust gas air contaminants relative to 

reciprocating engines in similar service (e.g., methane emissions are roughly an order of 

magnitude lower for gas turbines than for similarly rated reciprocating engines). This is because 

the fuel is burned with ample excess air to ensure essentially complete combustion at all but 

minimal load conditions. 

The amount of NOx emissions produced by turbine engines is a function of the fuel burned, 

firing temperature, exhaust discharge temperature and residence time in the combustion zone. 

Since the trend towards high turbine efficiencies leads to higher pressure ratios and firing 

temperatures, the emission rates of NOx are higher for these units. 

The normal method for reducing NOx formation in turbines is to reduce combustion 

temperatures. Maintaining an operating temperature in the combustor at 1500oC or below 

virtually eliminates production of NOx; however, this is not achievable by conventional 

combustion control methods such as steam or water injection, or premixing air and natural gas 

prior to entering the combustor (this process is referred to as lean premix or dry-low-NOx

[DLN]). Presently, the low combustion temperatures are only achieved through catalytic 

combustion (e.g., the XONON combustion system by Catalytica Combustion Systems Inc.). 
20

The most common post-combustion NOx reduction treatment is selective catalytic reduction 

(SCR). This reduces NOx emissions approximately 80 percent, but is expensive and requires the 

operator to store large quantities of ammonia. 

3.2.2 Important Considerations

Many natural gas-fuelled engines have been retrofit with NOx emission control features. But 

little information is available to document the extent of these actions. Furthermore, where 

catalytic converters (3-way catalytic converters can reduce NOx, CO and CH4 emissions) have 

been installed few companies have implemented formal programs to maintain these systems so 

their average performance is uncertain. As a likely conservative approximation, NOx emission 

controls are only assumed to be in use where documentation is available. 

Additionally, the general experience from performance tests conducted on engines used in the 

UOG industry has been that those at larger manned facilities are better maintained and tuned 

than those at small manned facilities. This contributes to the uncertainties in the applied emission 

factors. 

3.2.3 Default Emission Factors

Table 7 presents some average emission factors for natural gas-fuelled reciprocating engines. 

Corresponding factors are presented for natural gas-fuelled turbines in Tables 8 and 9. Actual 

manufacturer’s data and available test data for specific makes and models of compressor engines 

are provided in as separate volume. 

3.3 Process Heaters and Boilers

This category includes boilers, choke heaters, line heaters, reboilers and utility heaters. These are 

mainly indirect fired units. 

3.3.1 Source Characterization

Two general types of fired heaters and boilers are used in the natural gas industry (GPSA, 1987): 

watertube and firetube. Watertube units are designed to pass water through the inside of heat 

transfer tubes while the outside of the tubes is heated by direct contact with the hot combustion 

gases and through radiant heat transfer. Firetube units are designed such that the hot combustion 

gases flow through tubes which heat a liquid circulated outside of the tubes. Firetube boilers 

range in duty from 10 kW (e.g., small utility heaters) to 3 500 kW (e.g., gas pipeline line 

heaters). The design, controls, and operation of firetube heaters varies widely from vary simple 

natural draft designs to well-instrumented forced air units. Good fuel efficiency is achieved 

through low stack temperatures, low excess air, and insulation of the unit. 

Basic design features may include: 

• Multi-pass fire tubes. 

• Forced or natural draft combustion air systems. 
21

• Smaller units (10 to 75 kW) tend to have on-off firing while larger units often have full 

modulation firing. 

• Air dampers may include single-blade, rotary and multi-blade designs. 

• Only the larger sizes of boilers would tend to have any kind of emission control. These 

may include low-NOx burners and internal flue gas recirculation (FGR). Post combustion 

control techniques generally are not used on boilers with energy inputs less than 30 MW. 

A boiler’s excess air supply provides for safe operation above stoichiometric conditions. A 

typical burner is usually set up with 10 to 20 percent excess air (2 to 4 percent excess O2). NOx

controls that require higher excess air levels can result in fuel being used to heat the air rather 

than converting it to usable energy. 

Table 7. Emission factors for CACs from stationary natural gas-fuelled 

reciprocating engines1. 

Substance 2-Stroke Lean-Burn

(ng/J) 

4-Stroke 

Lean-Burn 

(ng/J) 

4-Stoke 

Rich-Burn 

(ng/J) 

NOx 1363 (834)2 1754 (364)2 950 (976)2

N2O7 5.72 5.72 5.72 

CO 166 (152)2 136 (240)2 1600 (1509)2

CO2

3,6 49 300 49 300 49 300 

SO2

4,6 0.25 0.25 0.25 

TOC 705 632 154 

VOC 52 51 13 

Methane 624 538 99 

PM10 (Filterable) 16.5 0.033 4.1 

PM2.5 (Filterable) 16.5 0.033 4.1 

ND - No data. 

1. Adapted from U.S. EPA (2000): Supplement to Compilation of Air Pollutant Emission Factors, Volume 1 - 

Stationary Point and Area Sources. Table 3.2-1 to 3.2-3. 

2. Bracketed value is at <90% load and the other value is at 90 to 105% load. 

3. Based on 99.5 percent conversion of the fuel carbon to CO2 for natural gas. The fuel carbon content is 

based a typical natural gas composition at the Alberta/Saskatchewan border. 

4. Assumes the sulphur content of natural gas is 70.6 grains/103

 m3. 

5. Considered less than 1 μm in aerodynamic diameter. 

6. Where fuel compositions are known, CO2 and SO2 are calculated based on fuel carbon and sulphur content 

assuming 99.9 percent of carbon is converted to CO2 (the remainder is soot) and 95.5 percent of the sulphur 

is converted to SO2 ( the remainder is unburned). 

7. Adapted from CAPP (1999): A Detailed Inventory of CH4 and VOC emissions from Upstream Oil and Gas 

Operations in Canada. CAPP Pub. # 1999-0010. 
22

Table 8. Summary of U.S. EPA average emission factors for different types of 

natural gas-fuelled turbine engines1,2. 

Technology NOx

(ng/J) 

N2O 

(ng/J) 

CO 

(ng/J) 

CO2

4,5

(ng/J) 

Uncontrolled 138 1.29 353 49 300 

With Water/Steam Injection 56 ND 13 49 300 

Lean-Premix Turbines 43 ND 6.5 49 300 

ND - No data. 

1 Adapted from U.S. EPA (2000): Supplement to Compilation of Air Pollutant Emission Factors, Volume 1 - 

Stationary Point and Area Sources. Table 3.1-1. 

2 Only tests with 90 to 100 percent loads were considered for CO and NOx. NOx emissions decrease at lower 

load conditions, while CO emissions increase at lower load conditions. Test data indicate that as much as 

30 percent NOx reduction and 200 percent CO increase are possible when the unit load is reduced to 75 

percent. 

3 It is recognized that the uncontrolled emission factor for CO is higher than the water-steam injection and 

lean-premix emission factors, which is contrary to expectation. 

4 Based on 99.5 percent conversion of the fuel carbon to CO2 for natural gas. The fuel carbon content is 

based a typical natural gas composition at the Alberta/Saskatchewan border. 

5 Where fuel compositions are known, CO2 is calculated based on fuel carbon and sulphur content assuming 

99.995 percent of carbon is converted to CO2 (the remainder is soot). 

Table 9. Emission factors for CACs and GHGs from natural gas-fuelled turbines1. 

Substance Emission Factor (ng/J) 

CO2

2,7 49 300 

N2O 1.29 

TPM, PM10, PM2.5

4

 0.82 

SO2

5,7 0.25 

CH4 3.69 

THC 4.73 

VOC 0.90 

NMHC6 1.04 

ND - No data. 

1 Adapted from U.S. EPA (1998): Draft Supplement to Compilation of Air Pollutant Emission Factors, 

Volume 1 - Stationary Point and Area Sources. Table 3.1-2. 

2 Based on 99.5 percent conversion of the fuel carbon to CO2 for natural gas. The fuel carbon content is 

based a typical natural gas composition at the Alberta/Saskatchewan border. 

3 PM emission factor determined using EPA Method 5. 

4 All PM (total, condensable and filterable) is assumed to be less than 2.5 μm in diameter. Therefore, the PM 

emission factors presented here may be used to estimate PM2.5 or PM10 emissions. Total PM is the sum of 

the filterable and condensable PM. Filterable PM is the particulate matter collected on, or prior to, the filter 

of an EPA Method 5 (or equivalent) sampling train. 

5 Assumes the sulphur content of natural gas is 70.6 grains/103

 m3. 

6 Calculated as the difference between THC and methane emission factors. 

7. Where fuel compositions are known, CO2 and SO2 are calculated based on fuel carbon and sulphur content 

assuming 99.995 percent of carbon is converted to CO2 (the remainder is soot) and 99.5 percent of the 

sulphur is converted to SO2 ( the remainder is unburned). 
23

3.3.2 Important Considerations

Except where unit-specific emission factors are known, all heaters and boilers are assumed to be 

represented by the average emission factors presented in Section 3.3.3. 

3.3.3 Default Emission Factors

Average emission factors for natural gas -fuelled heaters and boilers are presented in Tables 10 

and 11. Table 12 presents some additional factors presented by one manufacturer for common air 

contaminants from low-NOx natural gas-fuelled heaters and boilers. Emission factors for GHGs 

from propane- and butane-fuelled heaters and boilers are presented in Table 13. 

Table 10. Emission factors for nitrogen oxides (NOx), carbon monoxide (CO) and 

carbon dioxide (CO2) from natural gas-fuelled heaters and boilers1. 

Source Types Size 

(MW) 

Emission Controls NOx

(ng/J)2

CO 

(ng/J) 

CO2

4,5

(ng/J) 

Uncontrolled - Pre-NSPS3 118 35 49 550 

Uncontrolled - Post-NSPS3 80 35 49 550 

Controlled - Low NOx Burners 59 35 49 550 

>29 

Controlled - Flue Gas Recirculation 42 35 49 550 

Uncontrolled 42 35 49 550 

Controlled - Low NOx Burners 21 35 49 550 

Wall-fired 

Units 

≤29 

Controlled - Low NOx Burners/Flue 

Gas Recirculation 

13 35 49 550 

Tangential- Uncontrolled 72 10 49 550 

Fired Units 

All 

Controlled - Flue Gas Recirculation 32 41 49 550 

Residential 

Furnaces 

<0.088 Uncontrolled 40 17 49 550 

Note: The shaded entries in the table are used as defaults where no other information was supplied.

1. Adapted from U.S. EPA (1998): Compilation of Air Pollutant Emission Factors, Volume 1 - Stationary 

Point and Area Sources. Table 1.4-1. 

2. Expressed as NO2. For large and small wall-fired boilers with SNCR control, apply a 24 percent reduction 

to appropriate NOx emission factor. For tangential-fired boilers with selective non-catalytic reduction 

(SNCR) control, apply a 13 percent reduction to the appropriate NOx emission factor. 

3. NSPS = New Source Performance Standard as defined in 40 CFR 60 Subparts D and Db. Post-NSPS units 

are boilers with greater than 73 MW of heat input that commenced construction modification or 

reconstruction after August 17, 1971, and units with heat input capacities between 29 and 73 MW that 

commenced construction modification or reconstruction after June 19, 1984. 

4. Based on approximately 100 percent conversion of fuel carbon to CO2. 

5. Where the fuel composition is known, CO2 is calculated based on fuel carbon and sulphur content assuming 

99.995 percent of carbon is converted to CO2 (the remainder is soot). 
24

Table 11. Emission factors for CACs and GHGs from natural gas combustion by 

heaters and boilers1. 

Substance Emission Factor (ng/J) 

CO2

2,5 49 550 

N2O (Uncontrolled) 0.93 

N2O (Controlled-low-NOx burner) 0.27 

TPM, PM10, PM2.5

3

 0.80 

SO2

4,5 0.25 

TOC 4.6 

Methane 0.97 

VOC 2.3 

TPM - Total Particulate Matter 

TOC - Total Organic Compound 

VOC - Volatile Organic Compound 

1. Adapted from U.S. EPA (1998): Compilation of Air Pollutant Emission Factors, Volume 1 - Stationary 

Point and Area Sources. Table 1.4-1. 

2. Calculated based on 100 percent conversion of fuel carbon to CO2 for a typical natural gas composition at 

the Alberta/Saskatchewan border. 

3. All PM (total, condensable and filterable) is assumed to be less than 1.0 micrometres in diameter. 

Therefore, the PM emission factors presented here may be used to estimate PM10, PM2.5 and PM1

emissions. Total PM is the sum of the filterable and condensable PM. Condensable PM is the particulate 

matter collected using EPA Method 202 (or equivalent). Filterable PM is the particulate matter collected 

on, or prior to, the filter of an EPA Method 5 (or equivalent) sampling train. 

4. Assumes the sulphur content of natural gas is 70.6 grains/103

 m3 (4.57 g/103 m3). 

5. Where the fuel composition is known, CO2 and SO2 are calculated based on fuel carbon and sulphur 

content assuming 99.995 percent of carbon is converted to CO2 (the remainder is soot) and 99.5 percent of 

the sulphur is converted to SO2 ( the remainder is unburned). 

Table 12. Manufacturer’s emission factors for common air contaminants from 

natural gas-fuelled commercial firetube boilers for different NOx control 

levels. 

Substance Emission Factors (ng/J) 

Uncontrolled1 60 ppm2

NOx

30 ppm2

NOx

25 ppm2

NOx

20 ppm2

NOx

CO 64 64 17/473 17/473 64 

CO2

4

 49 550 49 550 49 550 49 550 49 550 

NOx 52 30 15 13 10 

THC 6.9 6.9 6.9 6.9 6.9 

PM 4.3 4.3 4.3 4.3 4.3 

1 Equivalent to a NOX value of 100 ppm. 

2 ppm levels are given on a dry volume basis and corrected to 3 percent oxygen (15 percent excess air). 

3 The low CO value applies when the boiler is operated at greater than 50 percent of rated capacity, and the 

higher CO value applies to all lesser load values. 

4 Calculated based on 100 percent conversion of fuel carbon to CO2 for a typical natural gas composition at 

the Alberta/Saskatchewan border. 
25

Table 13. Emission factors for LPG-fuelled heaters and boilers1. 

Butane-Fuelled Units2 Propane-Fuelled Units2

Industrial 

(3 to 30 MW) 

Commercial 

(0.1 to 3 MW) 

Industrial 

(3 to 30 MW) 

Commercial 

(0.1 to 3 MW) 

Substance 

(ng/J) (g/L) (ng/J) (g/L) (ng/J) (g/L) (ng/J) (g/L) 

TPM, PM10, PM2.5

3

 2.5 0.07 2.1 0.06 2.8 0.07 1.9 0.05 

SO2

4

 423 

x S 

0.011 

x S 

423 

x S 

0.011 

x S 

417 

x S 

0.012 

x S 

417 

x S 

0.012 

x S 

NOx

5

 87 2.5 63 1.8 90 2.3 66 1.7 

N2O 3.8 0.1 3.8 0.1 4.3 0.1 4.3 0.1 

CO2

6

 59 700 1710 59 700 1710 59 200 1500 59 166 1500 

CO 15 0.43 9 0.25 15 0.38 9 0.23 

VOC 1.5 0.05 1.5 0.05 1.5 0.04 1.5 0.06 

CH4 0.97 0.02 0.97 0.02 0.97 0.02 0.97 0.02 

Note: The shaded entries in the table are used as defaults where no other information was supplied. 

1. Adapted from U.S. EPA (1998): Compilation of Air Pollutant Emission Factors, Volume 1 - Stationary 

Point and Area Sources. Table 1.4-5. 

2. Based on a gross heating value of 28.718 MJ/m3

 for liquid butane and 25.394 MJ/m3 for liquid propane. 

Assumes emissions (except SO2 and NOx) are the same, on a heat input basis, as for natural gas 

combustion. The NOx emission factors have been multiplied by a correction factor of 1.5, which is the 

approximate ratio of propane/butane NOx emissions to natural gas NOx emissions. 

3. Filterable particulate matter (PM) is that PM collected on or prior to the filter of an EPA Method 5 (or 

equivalent) sampling train. For natural gas, a fuel with similar combustion characteristics, all PM is less 

than 10 μm in aerodynamic equivalent diameter (PM10). 

4. S equals the sulphur content of the of the fuel expressed in grains/100 ft3 of vapour. 

5. Expressed as NO2. 

6. Assuming 99.5 percent conversion of fuel carbon to CO2. 

7. VOC is assumed to be TOC (total organic carbon) minus methane.
26

4.0 FLARING

A flare is an open flame used for routine or emergency disposal of a hazardous waste gas stream. 

There are a variety of different types of flares including: flare pits, flare stacks, enclosed flares 

and ground flares. 

Flaring is currently used in a number of oil and gas operations, both upstream and downstream. 

Flaring is usually differentiated depending on whether or not it involves acid gas. 

Since 1999, AEUB has been pursuing an initiative to substantially reduce flaring of all kinds in 

Alberta, particularly flaring of solution gas at crude oil production facilities. Initially, this 

initiative was primarily driven by concerns about toxic products of partial or incomplete 

combustion that may be formed in flares. The specific requirements imposed on industry are 

presented in AEUB Guide 60 (1999). AEUB (2001, 2002) is now expanding this initiative to 

include reduction of venting in response to concerns of related greenhouse gas (GHG), and 

volatile organic compound (VOC) emissions. Other provinces are considering adopting similar 

requirements. Commencing 1 January 2000, the reduction of the New Oil Well Production 

Period (NOWPP) flare limit set out in Informational Letter (IL) 87-92 to 300 x 103m3/month 

(0.000911 Mt CO2E/month) from 500 x 103 m3/month (0.001518 Mt CO2E/month)(a 40 percent 

reduction), implementation of a maximum gas oil ratio (GOR) criterion of 3000 m3

/m3 above 

which conservation would be required, and tie-in of development wells within one month in 

pools where gas conservation exists. 

4.1 Acid Gas

Acid gas is a by-product of the gas sweetening process employed at natural gas processing 

plants. Depending on the composition of the raw gas stream, acid gas is typically composed of 

CO2 and H2S with small amounts of residual hydrocarbons. If the acid gas does not contain 

regulated concentrations of H2S the acid gas may be vented to the atmosphere. This is sometimes 

the case at sweet gas processing plants that must remove CO2 to meet pipeline specifications. 

More frequently, however, the acid gas contains significant H2S and must be flared, processed by 

a sulphur recovery unit or disposed of by injection into a suitable underground formation, 

depending on the regulatory requirements, costs involved and site-specific constraints. The 

formation CO2 in acid gas streams passes through each of these disposal/treatment systems 

unchanged and, with the exception of disposal by underground injection, is ultimately released to 

the atmosphere. 

The amount of acid gas production is usually metered and the CO2 content, although not 

normally tracked by regulatory agencies, is known by the facility operators. The allowable 

options for disposal of the acid gas depend on the sulphur inlet rate. In Alberta, where 65 percent 

of the acid gas is estimated to occur, the AEUB and Alberta Environment have recently issued 

new regulations regarding the disposition or treatment of acid gas (EUB ID 2001-03). At new 

plants, acid gas may be flared if the sulphur inlet rate is less than 1 tonne per day, otherwise the 

acid gas must be processed by a sulphur recovery unit. The required design sulphur recovery 

efficiency varies between 70 and 99.8 percent, depending on the sulphur inlet rate. The higher 
27

the sulphur inlet rate the greater the required recovery efficiency. Existing facilities are being 

gradually de-grandfathered over time. 

Acid gas injection is an alternative approach to meeting the sulphur recovery requirements that 

has an effective recovery efficiency of nearly 100 per cent if operated successfully. It usually is a 

less costly option than providing sulphur recovery for small to medium sized applications (e.g., 

for a sulphur inlet rate of up to at least 400 tonnes per day), and consequently, is the preferred 

choice for new gas processing facilities in these situations. At existing facilities, the economics 

generally do not favour switching to acid gas injection unless there is a need for substantial 

upgrades or changes to the sulphur recovery unit (e.g., when a unit becomes oversized or 

undersized for an application due to changes in the facility throughput). In all cases, economic 

access to a suitable disposal reservoir is usually the determining factor. 

4.2 Thermal Oxidizers

4.2.1 Source Characterization

Thermal oxidizers are combustion devices used to dispose of waste streams. These devices may 

include conventional open-flame flare systems, enclosed flares and incinerators. Enclosed flares 

and incinerators are distinguished by their use of a refractory-lined chamber to contain the flame 

heat to create a finite post flame combustion zone. Enclosed flare systems differ from 

incinerators in terms of the amount and type of control systems provided. An enclosed flare 

either has no special controls or only stack-top temperature control. An incinerator has at least 

stack-top temperature and oxygen control and may also feature a continuous stack emission 

monitoring system. 

Properly designed and operated open-flame flares are able to achieve a destruction efficiency of 

98 percent, while enclosed flares and incinerators are able to achieve destruction efficiencies of 

greater than 99 percent. However, recent work by Strosher (1996) has shown that, for open 

flares, actual combustion efficiencies may be substantially lower. Differences between the 

destruction efficiency and the combustion efficiency are due to the formation of products of 

partial or incomplete combustion. The amount and types of incomplete combustion products 

formed is depended on a number of factors including: burner/flare tip design, exit velocities, 

wind conditions, amount of condensation or liquid carry-over through to the flare tip, and the 

waste gas composition. Presently, there is no reliable means of predicting such emissions, and 

the assessment of these emissions through measurements is difficult and currently is deemed to 

be impracticable. The potential for products of incomplete combustion is more apt to be an issue 

when burning heavier molecular weight streams as may be encountered at oil and solution gas 

production facilities, than the dry natural gas streams normally handled by gas production and 

processing. 

At natural gas facilities open-flame flare systems are primarily used for disposal of waste gas 

volumes from purging and blowdown events, and, generally, are only used if the gas is odourized 

or is sour. Otherwise, common practice for many companies is to dispose of the waste gas by 
28

controlled venting. Small enclosed flares or incinerators are sometimes used to dispose of 

compressor packing-case or seal vent gas. 

4.2.2 Important Considerations

Usually only acid gas systems are equipped with a flow measurement device, although metering 

of flare gas flows in other situations is becoming more common. On emergency flare systems the 

issue has been avoiding the use of obstructive flow meters (e.g., orifice meters) that could cause 

plugging or introduce excessive backpressure in the system, and finding meters that can provide 

accurate results over the wide range of flow rates that may occur. Ultrasonic flow meters have 

been gaining popularity in these applications and use of continuous tracer-based systems has 

successfully implemented as well. 

Where flows are not known, excessive flaring is usually noticed only when the flame size at the 

flare tip increases substantially or valves connected to the header system provide visible (e.g., 

becomes are iced up) or audible indications of appreciable leakage past the valve seat. 

Unfortunately, significant gas losses may occur into a flare system without triggering either of 

these two crude indicators, and such flows normally are not accounted for in any reporting 

efforts. 

For all forms of thermal oxidizers it is necessary to determined the total volumes of combustibles 

being disposed (i.e., fuel/pilot gas plus waste gas). All flares at sour facilities are assumed to be 

operated continuously and consume approximately 11.7 kJ/s of pilot fuel gas. 

4.2.3 Default Emission Factors

Atmospheric emissions from thermal oxidizers are estimated in accordance with the procedures 

presented in Section 3.2. Emissions from enclosed flare systems and incinerators are assessed 

using the emission factors presented in Section 3.3 for equivalent process heaters and boilers. For 

conventional flare systems, specific emission factors have been published by U.S. EPA (1995) 

for quantification of some of the primary contaminants formed. These factors are presented in 

Tables 14 and 15. The first table gives the factors for the major contaminants. The second table 

provides factors for the major components of the total hydrocarbon fraction in the combustion 

gases. Although the factors are determined from tests using heavier-than-methane hydrocarbons, 

they are deemed to be useful for obtaining rough estimates of the amount of emissions from 

natural gas flaring. 
29

Table 14. Emission factors for flare operations1,2. 

Component Emission Factor 

(ng/J) 

THC3 60 

CO2

4 48 560 

CO 159 

NOx 29 

N2O ND 

TPM, PM10, PM2.5

5 57 

VOC6 22 

CH4

6 33 

ND - No data. 

1. Adapted from Table 13.5-1 of AP-42 (U.S. EPA, 1995). 

2. Based on tests using crude propylene containing 80% propylene and 20% propane. 

3. Measured as methane equivalent. 

4. Calculated based on an overall carbon balance for a typical natural gas composition at the 

Alberta/Saskatchewan border, and assuming 98 percent conversion of fuel carbon to CO2. 

5. U.S. EPA Fire 6.22 database. Flaring of Landfill Gas. 

6. U.S. EPA AP-42 Table 13.5-1. 37 percent of THC is VOC and 55 percent is CH4. 

Table 15. Hydrocarbon composition of flare emissions1,2. 

Component Composition 

Average 

(Volume %) 

Range 

(Volume %) 

Methane 55 14 to 83 

Ethane/Ethylene 8 1 to 14 

Acetylene 5 0.3 to 23 

Propane 7 0 to 16 

Propylene 25 1 to 65 

1. Taken from Table 11.5-2 of AP-42 (U.S. EPA, 1995). 

2. The composition presented is an average of a number of test results obtained under the following sets of 

conditions: steam-assisted flare using high heating-value feed; steam-assisted using low heating-value feed; 

air-assisted flare using high heating-value feed; and air-assisted using low heating -value feed. In all tests, 

waste gas was a synthetic gas consisting of a mixture of propylene and propane. 
30

5.0 FORMATION CARBON DIOXIDE RELEASES

Formation carbon dioxide (CO2) is naturally occurring CO2 present in crude oil and natural gas 

at the time of production (primarily in the gas phase). Its contribution to vented and leaked 

emissions is accounted for in the applied speciation profiles (see Section 9). 

Most emissions of formation CO2 result from the processing of acid gas streams at sulphur 

recovery plants or from acid gas disposal by vent or flare systems. Formation CO2 may also be 

emitted as a waste by-product of deep cut extraction processes at these same natural gas 

processing plants. In the latter two cases, the amount of CO2 emissions are taken directly from 

survey responses provided by industry for individual facilities, or, in the absence of any 

responses, are estimated based on a mass balance that considers the total amount of formation 

CO2 in the facility inlet and sales streams, and the fate of the removed formation CO2. The 

concentrations of formation CO2 in the inlet gas streams are calculated based on the sources and 

amount of production linked to each facility and the corresponding pool-specific gas analyses 

available from regulatory agencies and production accounting registries. If the sales gas 

concentrations were not provided by the industry survey, the sales gas at each facility is assumed 

to contain less than 0.25 percent formation CO2 (a typical value observed in natural gas 

transmission systems). 
31

6.0 VENTING

A brief description of the different types of venting and purging activities included in this 

category is given in Section 6.1. Much of this discussion also applies to flaring activities (often 

waste gas is vented if it is sweet and flared if it is sour or malodorous). The average emission 

factors for assessing the amount of these emissions are delineated in Section 6.3. Venting from 

glycol dehydrators (i.e., still-column off-gas emissions) is addressed separately in Section 6.4. 

6.1 Source Characterization

Vent (and flare) systems exist in essentially all segments of the oil and gas industry and are used 

for two basic types of waste gas disposal: intermittent and continuous. Intermittent applications 

may include the disposal of waste volumes from emergency pressure relief episodes, operator 

initiated or instrumented depressurization events (e.g., depressurization of process equipment for 

inspection or maintenance purposes, or depressurization of piping for tie-ins), plant or system 

upsets, well servicing and testing, pigging events, purging activities and routine blowdown of 

instruments, drip pots and scrubbers. 

Continuous or frequent applications may include disposal of associated gas, treater off-gas 

and/or tank vapours at oil production facilities where gas conservation is uneconomical or until 

such economics can be evaluated, casing gas at heavy oil wells, process waste or byproduct 

streams that either have little or no value or are uneconomical to recover (e.g., vent gas from 

glycol dehydrators, acid gas from natural gas sweetening units, and sometimes stabilizer 

overheads), and vent gas from gas-operated devices where natural gas is used as the supply 

medium (e.g., instrument control loops, chemical injection pumps, samplers and compressor 

starter motors). Typically, waste gas volumes are flared if they pose an odour, health or safety 

concern, and otherwise are vented. 

In all provinces companies are required to conserve natural gas wherever it is economical to do 

so; however, the level of enforcement and the requirements of companies in evaluating the 

feasibility of natural gas conservation varies. At the same time, many companies operate in 

multiple regions and tend to develop company-wide polices designed to accommodate the most 

stringent requirements. 

The current AEUB Guide 60 requirements with respect to venting are as follows: 

• If continuous vent volumes are sufficient to support combustion, the gas should generally 

be burned in a flare. 

• Gas will not be vented if it constitutes an unacceptable fire or explosion hazard on or off 

the facility lease. 

• Venting of gas containing H2S to the atmosphere must not result in exceedance of Alberta 

Ambient Air Quality Guidelines for H2S or Occupational Exposure Levels for H2S. 

• As in Section 7.070 of the Alberta OGC Regulations, stock tank vapours and other gas 

emissions from batteries receiving gas or having vapours containing more than 10 moles 

of H2S per kilomole of gas must be burned. 
32

• Continuous venting of gas containing H2S and other odourous compounds must not result 

in odours outside the lease boundary. 

• The true vapour pressure of hydrocarbon product stored in atmospheric storage tanks 

shall not exceed 83 kilopascals where such tanks are vented to the atmosphere. 

• Vented gas from gas dehydrators is subject to limitations on benzene emissions, as 

detailed in IL 2001-07 and CAPP (2000). 

• If operators have reason to expect that the benzene content of vented gas exceeds 5 moles 

per kilomole, then site vent gas benzene emissions must be assessed and, if necessary, 

controlled so that total benzene emissions for the facility or lease site will not exceed: 

o 3.0 tonnes per year for facilities commissioned after six months from the issuance 

of this guide; or 

o 5.0 tonnes per year for facilities commissioned prior to the issuance of this guide, 

effective 1 January 2001. 

In May of 2002 AEUB issued General Bulletin GB 2002-05, which further defines the 

requirements for evaluation of solution gas vent gas conservation. Initially, the emphasis is on 

vents larger than 800 m3/day (0.886 kt CO2E/year), and then by 2003 to 2004 vents down to 500 

m3/day (0.554 Mt CO2E/year) are targeted. 

For purposes of the current inventory, venting has been separated into those forms that are 

generally reported and those which are not. 

• Reported venting is the sum of all vented volumes stated in production accounting statistics. 

These volumes are assumed to comprise, where applicable, casing gas venting, waste 

associated gas flows, treater and stabilizer off-gas and gas volumes discharged during 

process upsets and equipment depressurization events. 

• Unreported venting is the sum of all miscellaneous vented volumes not normally included in 

reported vented volumes and not otherwise accounted for in the developed emissions 

inventory. This may include instrument vent gas, compressor start gas, purge gas and 

blanket gas that is discharged directly to the atmosphere, dehydrator still column off-gas, 

storage and loading/unloading losses. 

6.2 Important Considerations

In most provinces, all vented (and flared) gas is required to be reported monthly to the nearest 

0.1 x 103

m3/month (0.304 x 10-3 kt CO2E/month), adjusted to 101.325 kPa and 15°C, as part of 

routine production accounting procedures. The requirement to report all gas vented (or flared) 

includes emissions from routine operations, emergency conditions, and the depressuring of 

pipeline, compression, and processing systems. Vented gas excludes fugitive emissions from 

piping and equipment leaks. 

Typically, separate reports are submitted to the provincial governments for crude oil and natural 

gas production facilities, natural gas gathering systems, and natural gas processing plants. Some 

venting (and flaring) data and other information on oil and natural gas transmission systems and 
33

natural gas distribution systems are also reported to Statistics Canada and the National Energy 

Board. The production accounting reporting requirements in Alberta are detailed in the AEUB’s 

Guide 7 (2001). 

Although there have been substantial improvements in reporting practices in recent years, there 

remains significant uncertainty in many reported vented (and flared) volumes. The main sources 

of uncertainty are as follows: 

• There are inconsistencies in what individual companies are actually including in their 

reported vented and flared volumes. In some cases this is due to differences in reporting 

requirements between provinces (for example, companies are not required to report the 

volumes of casing gas vented from some heavy crude oil wells in Saskatchewan but are 

in Alberta). In other cases, it is due to a lack of specificity in the current requirements, 

and limited auditing of the results. 

All measured quantities are likely to be fully accounted; however, flow meters are 

normally only installed on larger continuous vent or flare systems, if at all. Where there is 

no measurement data the volumes must be estimated. The problems here are the lack of 

detailed estimation guidelines, the lack of any formal tracking of the activity data needed 

to make many of these estimates (e.g., frequency and details of equipment or piping 

blowdown events, frequency of compressor engine starts, etc), and differences in which 

sources individual operators are even considering. 

In Alberta, the AEUB has established standards for measurement of flaring at pipeline 

and natural gas processing facilities (i.e., AEUB ID 94-01). In general, metering accurate 

to ± 5 per cent is required for the flare or vent gas sources listed below: 

o acid gas flared, either continuously or in emergencies, from natural gas 

sweetening systems regardless of volume, 

o fuel gas make-up to acid gas flared (where fuel gas must be added to meet 

minimum acid gas heating value requirements), 

o continuous or routine flare sources in conventional crude oil and natural gas 

production or processing facilities where annual average flared volumes exceed 

500 m3

/day (1.52 x 10-3 kt CO2E/day), and

o solution gas flared from heavy crude oil or crude bitumen production facilities 

within designated oil sands areas where annual average flared or vented volumes 

exceed 2000 m3

/day (5.12 x 10-3 kt CO2E/day for flaring and 18.2 x 10-3 kt 

CO2E/day for venting), based on general metering requirements specified in IL 

91-09.

Routine flare sources are defined as those sources that, by process design, are used on a daily 

basis to dispose of low-pressure or waste gases. The definition excludes flare sources used solely 

for emergency shutdown or overpressure protection. Where all solution gas is flared or vented 

from conventional or heavy oil production facilities, produced gas measurements (minus 

measured fuel gas use) can be used to report volumes flared or vented. In such situations, 

specific flare or vent gas meters are not required.
34

o Historically, there has been a problem with some vented volumes being reported as 

flared. The actual split has a significant impact on the total CO2-equivalent (CO2E) 

emissions from these activities since unburned CH4 contributes approximately 7.7 times 

more radiative forcing on a 100-year time horizon than fully combusted CH4. Production 

accounting forms for production facilities, the major source of venting and flaring, 

provide separate cells for reporting of vented volumes and flared volumes. These values 

are often automatically estimated by production accounting systems based on reported 

liquid volumes and reported or estimated gas-to-oil ratios or solution gas factors. An 

informal review of the production accounting systems of several operators indicates that 

calculated results have often been reported as flared volumes by default, which may often 

be incorrect. 

At natural gas processing plants, acid gas volumes are reported separately from other 

venting or flaring volumes; however, the latter amounts are reported as a single 

aggregated value. Venting and flaring from natural gas gathering systems is also reported 

as a single aggregate value. 

• Some operators have tended to use vented and flared entries as balancing terms to 

achieve reasonable metering differences when completing production accounting 

reports. 

• Venting at wells is at times, reported at the battery, even though it is occurring at the 

well site.

6.3 Default Emission Factors

The following subsections and Section 7 summarize the emission factors used to estimate 

emission contributions by the sources and activities which are assumed to be generally 

unaccounted for in a facility’s reported vented or flared volumes. 

6.3.1 Blowdowns

There are three general categories of blowdowns at oil and gas facilities: 

o station blowdowns (for depressurization of yard piping and process equipment), 

o unit blowdowns (for blowdown of individual compressor or process units), and 

o pipeline blowdowns (for depressurization of pipeline segments). 

Pipeline blowdowns occur very infrequently for the section of pipe between any two successive 

block valves but may create a significant amount of waste gas as is shown in Table 16. 
35

Table 16. Example of potential waste gas volumes and frequencies for blowdowns, 

purges and other venting activities from pipeline segments and at 

compressor stations. 

Blowdown/Venting 

Event 

Location Waste Gas 

Volume1

(103 m3/event) 

Frequency of 

Occurrence 

Mainline Block-Valve 

Blowdown 

Pipeline 0.3 to 2,770+ Very infrequently for 

any given segment (say 

once every 20 years). 

Pipeline Purge Pipeline 0.1 to 150 Very infrequently for 

any given segment (say 

once every 20 years). 

Station Blowdowns Compressor Station 0.3 to 1.5 Several times per year or 

less. 

Scrubber Blowdowns Compressor Station 0.1 to 1.1 Typically, less than once 

per year. 

Booster Vents2 Compressor Unit 0.1 to 5.5 Monthly. 

Compressor Starts Compressor Unit 0.01 to 1.2 Usually at least several 

times per month. 

Source: Adapted from Picard (1995), .Table 1, page 4. 

1 Based on the range of values observed for one gas transmission company. 

2 This accounts for the gas released when the piping and cylinders on the compressor unit itself are 

depressurized.

6.3.2 Gas Analyzers

An online gas analyzer normally draws a continuous stream of sample. It uses some fraction of 

this stream and then vents both the unused and spent portions to the atmosphere. Depending on 

the type of analyzer, the used portion of sample may be released unchanged or as products of 

combustion. Consequently, the amount of emissions depends on the sampling rate and the 

characteristics of the analyzer. A value of 0.0985 m3

/h was determined for one analyzer system 

on a natural gas transmission pipeline (unpublished report). 

6.3.3 Gas-Operated Devices 

Use of gas-operated devices is a direct source of emissions if the supply medium is natural gas. 

The common types of devices at oil and gas facilities include the following: 

o Gas-operated Control Loops - The total amount of gas emitted by a single control loop 

is determined by the number of bleeding instrument components, the number of 

actuators, the design of these components, and the level of control activity. 

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

instruments are provided in Table 17. 
36

Table 17. Typical gas consumption rates for a variety of standard and low-bleed types 

of pneumatic instruments1. 

Type Supply Pressure: 140 kPag Supply Pressure: 240 kPag

Steady-state 

(m3/h) 

Max. 

Exhaust 

(m3/h) 

Steady-state 

(m3/h) 

Max. 

Exhaust 

(m3/h) 

Transmitter 0.12 0.72 0.20 1.20 

Controller 0.40 to 0.80 4.5 to 5.5 0.60 to 1.00 7.0 to 8.5 

I/P Transducer 0.60 15.0 0.80 20.0 

P/P Positioner 0.32 4.4 0.46 7.6 

Standard 

Consumption 

Devices 

I/P Positioner 0.40 5.0 0.60 8.0 

Transmitter 0.08 0.4 0.1 0.45 

Controller 0.10 0.45 0.14 0.5 

I/P Transducer 0.10 9 0.13 12.0 

P/P Positioner 0.15 0.45 0.20 7.5 

Low 

Consumption 

Devices 

I/P Positioner 0.20 0.5 0.25 7.5 

1 Source: Picard and Sarkar (1993), Table 2-2, page 2-4. 

o Small gas-driven pumps - Some of the most common applications where gas-driven 

pumps may be used are: 

 injection of methanol and other chemicals into gas pipelines, 

 high-pressure bearing lubrication, 

 lubrication of mechanical seals, 

 circulation of glycol on glycol dehydrators, and 

 odourization systems. 

The basic unit comprises a unitized gas motor and pump. The gas motor operates by 

expanding the supply gas against a diaphragm or piston and rod assembly which in turn 

drives the pump plunger. The expanded supply gas is then vented to atmosphere or into a 

collection system and the cycle repeated. Pumping capacities of less than 3 L/d to more 

than 3 m3

/d, and injection pressure capabilities of up to 62 000 kPag are available through 

a range of pump sizes and models. 

Some gas-driven pumps are designed to operate off low uniform supply pressures of 

345 kPag or less and others are designed to operate off high or erratic pressures up to 

10 340 kPag. 

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

passing through the gas motor, the pumping rate and the required chemical injection 

pressure. As much as 7.5 m3

 of gas may be require to pump each litre of liquid; however, 

most applications will require much less gas than this (i.e., typically only half as much). 
37

Recent work sponsored by GRI/U.S EPA (Myers and Harrison, 1996) indicates Kimray 

pumps (the most commonly used type of glycol circulation pump) exhaust about 0.178 

m3

 of natural gas per 103 m3 of gas processed at gas plants. This factor assumes that 33 

percent of the dehydrators are equipped with flash tanks and that 10 percent have 

combustion vent controls (also see Section 6.4). 

o Gas-driven motors - are widely used to start the reciprocating or turbine engines on 

natural gas compressors. The supply medium is the natural gas from the pipeline. The 

vent from the starter motor is usually open to the atmosphere; although, sometimes it may 

be connected to a flare system. 

Specific starting gas requirements for engine-driven compressors will vary according to 

the pressure of the start gas, the size of the compressor and the condition of the engine. A 

larger (10 MW) gas turbine-driven compressor may require as much as 225 m3

 of natural 

gas for each start attempt. Consequently, if start sequences are initiated more than a few 

times during the year, significant amounts of gas may be vented to the atmosphere. 

6.3.4 Other

The emissions from other types of process venting are estimated using the emission factors 

summarized in Table 18. In the absence of temperature and pressure data, the solution gas emission 

factors in Table 18 are used to estimate the amount of gas that flashes from the oil when it first 

enters the stock tanks. 

Table 18. Summary of the factors used to estimate gas venting and flaring rates. 

Emission Source THC Emission 

Factor 

Units 

Glycol Dehydrators1

 - Still Column Off-Gas (Flash Tank) 

 - Still Column Off-Gas (No Flash Tank) 

 - Stripping Gas Factor 

 - Pump Factor 

Instrument Controllers2

Chemical Injection Pumps3

 

 0.00357 

 0.1751 

 0.670 

 0.1777 

 0.354 

 0.236 

m3

/m3 of gas production 

m3

/m3 of gas production 

m3

/m3 of gas production 

m3/m3 of gas production 

m3/h/controller 

m3

/h/pump 

1 Estimated based on simulation results for conditions of 28o C and 7000 kPa in the absorber column, a glycol 

circulation rate of 45 L/kg of H2O removed. It is assumed that no flash tank or stripping gas are used. 

2 Based on measured vent rates for continuous- and intermittent-bleed controllers at oil production facilities. 

3 Based on measurements performed at oil and gas production facilities. 
38

6.4 Glycol Dehydrators

6.4.1 Source Characterization

Glycol dehydration is a continuous liquid desiccant process in which water or water vapour is 

removed from hydrocarbon streams by selective absorption and the glycol is regenerated or 

reconcentrated by thermal desorption. The use of triethylene glycol (TEG) and ethylene glycol 

(EG) are standard for dehydration of natural gas. 

This process is widely used in gas production and processing operations for removing water 

vapour from natural gas, but, normally, it is not required during the subsequent transmission and 

distribution stages. However, if the processed gas is placed in an underground storage cavern 

enroute to market, it may be necessary to re-dehydrate the gas upon removal from the cavern. 

The primary causes of organic emissions from a glycol dehydrator are secondary absorption/ 

desorption by the glycol, entrainment of some gas from the contactor in the rich glycol, and use 

of stripping gas in the reboiler. These sources are the focus of this section. Other sources of 

methane emissions on a glycol dehydrator include fugitive equipment leaks (see Section 7.0), 

venting by gas-operated devices (see Section 6.3.4), and combustion emissions if it has a gasfired reboiler (see Section 3.0). 

The basic TEG dehydration process is as follows. Wet gas is brought into contact with a 

counterflow of lean TEG in a vertical trayed contactor (or absorption column) to promote 

absorption of the water by the TEG. The wet gas flows in at the bottom of the tower and leaves 

at the top as dry gas, while the lean TEG enters at the top of the tower and exits at the bottom as 

rich TEG. The rich TEG is subsequently regenerated by the addition of heat in the reboiler and is 

returned to the top of the tower to repeat the circuit. The TEG circulation rate is determined by 

the gas flow rate, the amount of water to be removed, the temperature and pressure in the tower, 

actual purity of the glycol at the inlet to the contactor, number of trays or packing height in the 

contactor, and the desired dew point depression (API, 1990). Typical values for plant 

applications are 17 to 50 L TEG/kg H2O removed. At 6900 kPag, glycol can absorb up to 7.5 

standard litres of gas for every litre of glycol circulated (Sams, 1992). 

A low-pressure flash separator is sometimes installed between the contactor and the regenerator 

(reboiler) to release any solution gas that may be entrained in the rich (wet) glycol, especially if a 

glycol energy exchange pump is used in the system. This type of pump uses pressure energy in 

the rich glycol to pump lean glycol into the contactor. The gas separated in the flash separator 

may be used to supplement the fuel and stripping gas required for the reboiler. Any excess flash 

gas is discharged through a back-pressure valve to atmosphere. 

From the flash separator, the rich glycol then flows to a packed stripping still attached to the top 

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

gases (mostly water vapour and glycol) rising up from the reboiler. The mixing of these two 

streams helps to preheat the wet glycol and to condense and recover any glycol vapours before 

the gases are vented from the top of the still. 
39

In the reboiler the glycol is heated to approximately 175o to 205o

C to remove enough water 

vapour to reconcentrate it to 99.5 percent or more. Sometimes a small amount of natural gas (i.e., 

stripping gas) is injected into the bottom of the reboiler to help strip water vapour from the 

glycol. The water vapour rises through the stripping still and the lean glycol, finally, is cooled 

and returned to the top of the absorber column. 

6.4.2 Important Considerations

It is assumed that still-column off-gas emissions typically are not included in reported vented and 

flared volumes at oil and gas facilities. 

6.4.3 Default Emission Factors

Perhaps the most convenient method of estimating venting emissions from a glycol dehydrator is 

to use the simulation program GRI-GLYCalc (Thompson et al., 1994). GRI-GLYCalc is 

primarily presented as a tool for estimating the amount benzene, toluene, ethyl benzene and 

xylene (BTEX) emitted by a glycol dehydrator (significant amounts of this material may be 

preferentially absorbed by the glycol and released off the flash tank and still column). However, 

in performing a rigorous simulation of the dehydration process, the program also provides 

information on the amount of methane and other organic emissions. Furthermore, the program 

can assess the emission reduction that may be achieved from use of selected control devices 

(e.g., condensers and incinerators). 

The required input data includes: 

 gas composition and flow rate, 

 glycol circulation rate, 

 temperature and pressure in the absorber column, 

 type of glycol pump, 

 operating pressure of the flash tank (if one is used) and amount of flash gas used by 

the process (if at all), 

 type of glycol (TEG or DEG), and 

 stripping gas usage. 

Since the above information is generally not available on a site-by-site basis, GRI-GLYCalc is 

used here to develop average emission factors for application to glycol dehydrators in different 

segments of the upstream oil and gas industry. These factors are summarized above in Table 18. 
40

7.0 FUGITIVE AND OTHER UNINTENTIONAL RELEASES

7.1 Equipment Leaks

7.1.1 Source Characterization

Fugitive emissions from equipment leaks are a large, if not the largest, source of organic 

emissions at most crude oil and natural gas facilities. 

Equipment leaks may be defined as any loss of process fluids to the environment past seals, 

packings, valve seats and mechanical connections (e.g., compressor seals and rod packings, 

valve-stem packing, block-valve seats, etc.). Most equipment components leak to some extent. 

However, only a few percent of the potential sources at a site actually leak sufficiently at any 

time to be in need of repair or replacement. If the number of excessive leakers is less than two 

percent of the total number of potential sources, the facility is normally considered to be well 

maintained and equipment leaks properly controlled. 

In Canada and the United States, the leak status of an equipment component is expressed in 

terms of the maximum concentration (screening value) of organic material that can be measured 

at the leakage point (or interface) using a portable organic vapour analyzer. The current CCME 

(1993) Code of Practice for the measurement and control of fugitive VOC emissions from 

equipment leaks at chemical plants and refineries considers a component to be leaking if it has a 

screening values of 10 000 ppm or more. 

The following are some of the noteworthy characteristics of equipment leaks: 

• There is a strong correlation between the rate of leakage and the type of service (e.g., 

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

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

of leakage (U.S. EPA, 1983). 

• The potential for leakage increases with operating pressure and ambient temperature, 

but is generally independent of operating temperature or elevation above grade 

(Langley et al., 1981). 

• Control valves have a greater potential to leak than block valves. For block valves, 

the gate design has the most potential for leakage, while plug and ball designs have 

the least potential. 

• Off-line compressor units that have been depressurized and are left open to the 

atmosphere through the vent line leak more than ones that have not been 

depressurized or that are online (especially for reciprocating compressors) (Hummel 

et al., 1996). In the first case, the leakage is past the seats of upstream and 

downstream block valve. In the latter case, it is past the seat of the blowdown valve. 
41

• Repaired components usually achieve a normal leak potential if the leaks do not recur 

during the first few weeks after repair (Eaton et al., 1980). 

• At natural gas facilities it is noteworthy that most of the fugitive emissions from 

equipment leaks often come from only one or two problem leakers at a given site 

rather than many small to moderate leaks. The results of a measurement program 

sponsored by Gas Technology Canada member companies (Ross and Picard, 1996) 

determined that 42 percent of total emissions measured were from the single largest 

source at each of the 183 sites surveyed. Similar trends have also been observed in the 

U.S. 

Leakage may often be an indication of wear, damage, defects, severe process conditions, abusive 

environments, inadequate design, or improper installation. Some components, like mechanical 

seals, are designed to leak a small amount to provide some lubrication of, as well as remove heat 

and debris from, the contact the surfaces. Seal designs can be implemented for some services that 

do not normally transmit any hydrocarbons directly to the atmosphere (i.e., leaked fluid can be 

collected and directed to a control device). 

The primary types of equipment components that may produce leaks in the oil and gas industry 

are: 

• reciprocating compressor packing systems, 

• centrifugal compressor seals, 

• valves (i.e., the stem packing system plus fittings and seams on the valve body), 

• pump seals, 

• connectors (i.e., threaded, flanged or gasketed surfaces), 

• pressure regulator diaphragms, 

• pressure-relief devices (i.e., the seated surfaces), and 

• open-ended valves and lines (i.e., valve seats where there is process fluid on one side 

and the other side is open to the atmosphere). 

A description of each of these emission sources is provided in the glossary in Volume 5 of this 

report. 

7.1.2 Important Considerations

An important feature of the UOG industry is that much of the equipment in hydrocarbon service 

tends to be associated with many smaller facilities and field installations rather than a few large 

plants. As a result, fugitive emissions are widely dispersed and often difficult to adequately 

quantify and control.

7.1.3 Default Emission Factors

The fugitive emissions from equipment leaks are estimated using the average emission factor 

method (U.S. EPA, 1995b). This approach consists of applying average total hydrocarbon (THC) 
42

emission factors to an inventory of all potential fugitive emission sources (i.e., leaking equipment 

components) using the equation below: 

where, 

and, 

LR = THC leak rate (kg/h) for all potential sources, 

∑LRi,j = THC leak rate for all type i components (e.g., valves, flanges, pumps, 

etc.) in service j (gas/vapour, light liquid, heavy liquid), 

OT = average operating factor for the target source category (i.e., the 

fractional amount of time that the affected equipment is in service during 

the year), 

EFi,j = average uncontrolled emission factor (kg/h/source) for type i 

equipment components in service j (see Table 19), 

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

CFi = average leakage control factor for components of type i, and 

The inventory of sources is compiled by applying typical equipment schedules to the total 

population of process units and major equipment items. Each item in these schedules is classified by 

type of component (e.g., valves, pump seals, flanges, etc.) and by type of service (gas/vapour, light 

liquid and heavy liquid). All components with a nominal pipe size of 0.5 inches or greater are 

counted. Equipment is excluded only if it was isolated from the process stream. 

Methane and VOC emissions are estimated by speciating (see Section 8) the calculated THC 

emissions. 

The average emission factors for equipment leaks are different for different segments of the 

industry, namely: natural gas production and processing, crude oil production and transmission, and 

natural gas transmission. These are summarized in Table 19. The values show that valves and 

connectors at gas facilities tend to leak more, on average, than those at oil facilities. Also, the leak 

control efficiency for these components is greater at sour natural gas facilities than that at sweet 

natural gas facilities 

LR= ∑ LRi, j ⋅OT

LR = EF N (1.0 - CF ) i, j i, j i, j i ⋅ ⋅
43

Table 19. Summary of average emission factors for uncontrolled fugitive THC emissions 

(kg/h/source) at UOG facilities. 

Factor 

Group Sweet/Sour Service Equipment Component Type 

Emission 

Factor 

(kg/h) 

Lower 

Uncertainty 

Upper 

Uncertainty 

GAS ALL Fuel Gas Connectors 8.18E-04 0.32 0.32 

GAS ALL Fuel Gas Chemical Injection Pumps 1.62E-01 0.60 0.60 

GAS ALL Fuel Gas Controllers 2.38E-01 0.27 0.27 

GAS ALL Fuel Gas Compressor Seals2 7.13E-01 0.36 0.36 

GAS ALL Fuel Gas Control Valves 1.62E-02 0.27 0.27 

GAS ALL Fuel Gas Open-Ended Lines 4.67E-01 0.58 1.72 

GAS ALL Fuel Gas Pressure Relief Valves 1.70E-02 0.98 0.98 

GAS ALL Fuel Gas Pressure Regulators 8.11E-03 0.72 2.38 

GAS ALL Fuel Gas Compressor Starts 6.34E-03 0.25 0.25 

GAS ALL Fuel Gas Valves1 2.81E-03 0.17 0.17 

GAS ALL Gas/Vapour Connectors 7.06E-04 0.31 0.31 

GAS ALL Gas/Vapour Chemical Injection Pumps 1.62E-01 0.60 0.60 

GAS ALL Gas/Vapour Controllers 2.38E-01 0.27 0.27 

GAS ALL Gas/Vapour Compressor Seals2 7.13E-01 0.36 0.36 

GAS ALL Gas/Vapour Control Valves 1.46E-02 0.23 0.23 

GAS ALL Gas/Vapour Open-Ended Lines 4.27E-01 0.62 1.61 

GAS ALL Gas/Vapour Pressure Relief Valves 1.70E-02 0.98 0.98 

GAS ALL Gas/Vapour Pressure Regulators 8.11E-03 0.72 2.38 

GAS ALL Gas/Vapour Valves1 2.46E-03 0.15 0.15 

GAS ALL Light Liquid Connectors 5.51E-04 0.90 1.11 

GAS ALL Light Liquid Control Valves 1.77E-02 0.45 0.45 

GAS ALL Light Liquid Open-Ended Lines 1.83E-02 0.79 1.27 

GAS ALL Light Liquid Pressure Relief Valves 5.39E-03 0.80 0.80 

GAS ALL Light Liquid Pump Seals 2.32E-02 0.74 1.36 

GAS ALL Light Liquid Valves1 3.52E-03 0.19 0.19 

GAS SOUR Gas/Vapour Connectors 1.36E-04 0.72 0.72 

GAS SOUR Gas/Vapour Control Valves 9.64E-03 0.04 0.04 

GAS SOUR Gas/Vapour Open-Ended Lines 1.89E-01 0.79 1.27 

GAS SOUR Gas/Vapour Pressure Regulators 4.72E-05 0.74 1.26 

GAS SOUR Gas/Vapour Valves1 1.16E-03 0.31 0.31 

GAS SWEET Gas/Vapour Connectors 8.18E-04 0.32 0.32 

GAS SWEET Gas/Vapour Control Valves 1.62E-02 0.27 0.27 

GAS SWEET Gas/Vapour Open-Ended Lines 4.67E-01 0.58 1.72 

GAS SWEET Gas/Vapour Pressure Regulators 8.39E-03 0.72 2.39 

GAS SWEET Gas/Vapour Valves1 2.81E-03 0.17 0.17 
44

Table 19. Summary of average emission factors for uncontrolled fugitive THC emissions 

(kg/h/source) at UOG facilities (concluded). 

Factor 

Group Sweet/Sour Service Equipment Component Type 

Emission 

Factor 

(kg/h) 

Lower 

Uncertainty 

Upper 

Uncertainty 

OIL ALL Fuel Gas Connectors 2.46E-03 0.15 0.15 

OIL ALL Fuel Gas Chemical Injection Pumps 1.62E-01 0.60 0.60 

OIL ALL Fuel Gas Controllers 2.38E-01 0.27 0.27 

OIL ALL Fuel Gas Compressor Seals2 8.05E-01 0.36 0.36 

OIL ALL Fuel Gas Control Valves 1.46E-02 0.21 0.21 

OIL ALL Fuel Gas Open-Ended Lines 3.08E-01 0.78 1.29 

OIL ALL Fuel Gas Pressure Relief Valves 1.63E-02 0.80 0.80 

OIL ALL Fuel Gas Pressure Regulators 6.68E-03 0.72 2.38 

OIL ALL Fuel Gas Compressor Starts 6.34E-03 0.25 0.25 

OIL ALL Fuel Gas Valves1 1.51E-03 0.79 0.79 

OIL ALL Gas/Vapour Connectors 2.46E-03 0.15 0.15 

OIL ALL Gas/Vapour Chemical Injection Pumps 1.62E-01 0.60 0.60 

OIL ALL Gas/Vapour Controllers 2.38E-01 0.27 0.27 

OIL ALL Gas/Vapour Compressor Seals2 8.05E-01 0.36 0.36 

OIL ALL Gas/Vapour Control Valves 1.46E-02 0.21 0.21 

OIL ALL Gas/Vapour Open-Ended Lines 3.08E-01 0.78 1.29 

OIL ALL Gas/Vapour Pressure Relief Valves 1.63E-02 0.80 0.80 

OIL ALL Gas/Vapour Pressure Regulators 6.68E-03 0.72 2.38 

OIL ALL Gas/Vapour Valves1 1.51E-03 0.79 0.79 

OIL ALL Heavy Liquid Connectors 7.50E-06 0.90 1.11 

OIL ALL Heavy Liquid Pressure Relief Valves 3.20E-05 0.80 0.80 

OIL ALL Heavy Liquid Pump Seals 3.20E-05 0.74 1.36 

OIL ALL Heavy Liquid Valves1 8.40E-06 0.19 0.19 

OIL ALL Light Liquid Connectors 1.90E-04 0.90 1.11 

OIL ALL Light Liquid Control Valves 1.75E-02 0.44 0.44 

OIL ALL Light Liquid Open-Ended Lines 3.73E-03 0.79 1.27 

OIL ALL Light Liquid Pressure Relief Valves 7.50E-02 0.80 0.80 

OIL ALL Light Liquid Pump Seals 2.32E-02 0.74 1.36 

OIL ALL Light Liquid Valves1 1.21E-03 0.19 0.19 

G/V Gas/Vapour: the process fluid exists as a gas or vapour at the operating conditions (temperature and pressure) 

and contains less than 50 percent hydrogen by volume. 

LL Light Liquid: the process fluid is a hydrocarbon liquid at the operating conditions and has a vapour pressure of 

0.3 kPa or more at 15o

 C. 

HL Heavy Liquid: the process fluid is a hydrocarbon liquid at the operating conditions and has a vapour pressure of 

less than 0.3 kPa at 15o

 C. 

1 The emission factors for valves account for leakage from the valve body and around the valve stem. Leakage 

down the pipe (e.g., leakage past the valve seat) is accounted for using the emission factor for open-ended lines. 

2 The emission factors for compressor seals are only applicable for uncontrolled sources (i.e., systems that do not 

use seal-leakage capture systems [e.g., use of barrier fluids with degassing reservoir and vent-to-flare system]). 
45

The oil and gas production emission factors presented in Table 19 are developed based on results 

of a field studies conducted by Clearstone Engineering over the period 1992 to 2003 for oil and 

gas facilities in Western Canada. All these factors account for the fact that only a small portion 

of the potential sources actually leak. Furthermore, they reflect the current level of control 

inherent with the present operating and regulatory environment in Canada. This environment 

may be characterized as one in which safety inspections, routine visual inspections, area 

monitoring and regular facility turn-arounds are conducted. However, there are no specific 

programs to detect leaks on a regular basis using a portable organic analyzer, and there are no 

policies for immediate repair of these leaks. 

Control factors are used to account for facility/process-specific emission controls achieved through 

the use of special equipment modifications (see Table 20). The most commonly-occurring of these 

modifications are the use of caps, plugs, blinds or a second valve on open-ended lines. Pressure 

relief devices connected to continuously-operating flare systems are assumed to have a control value 

of 1. All pressure relief devices at sour facilities are assumed to be connected to flare systems. 

An operating factor of 1.0 is used for all facilities. This assumes that facilities are continuous 

sources of fugitive emissions. Even when a facility has no throughput, it is generally still under 

pressure and subject to equipment leaks. 
46

Table 20. Summary of typical control efficiencies1 (fractional) for various equipment 

modifications. 

Source Equipment 

Modifications 

Control 

Efficiency 

Pumps 

Compressors 

Safety Relief 

Valves 

Open-ended 

Lines 

Sampling 

Connections 

In-line Valves 

Sealless pumps 

Double mechanical seals/closed vent system 

Closed vent system on seal area 

Double mechanical seal/closed vent system 

Closed vent system on seal area 

Closed vent system 

Rupture Disk 

Caps, plugs, blinds, or second valves 

Closed loop sampling 

Diaphragm valves 

Bellows-sealed valves 

1 

12

12

12

12

0.63

1 

14

1 

1 

1 

1

 U.S. EPA. 1980. VOC Fugitive Emissions in Synthetic Organic Chemicals Manufacturing Industry - 

Background Information for Proposed Standards. Report No. EPA-450/3-80-033a. Table 4-7. Page 4-24. 2

 This control efficiency is not attained in all cases but it is achievable in some. 

3

 This control efficiency reflects that a closed vent system is normally sized for emergency relief, and therefore, 

may not perform well on the low flows (e.g., due to inleakage and purge gas) that occur during non-emergency 

periods. 4

 This control efficiency reflects the use of these devices downstream of an initial valve with VOC on one side 

and atmosphere on the other. 
47

7.2 Storage Losses

7.2.1 Source Characterization

Fixed-roof tanks are the primary equipment for storing hydrocarbon liquids (oil and condensate) in 

the upstream oil and gas industry. Limited use of floating-roof tanks also occurs (primarily at 

pipeline terminals, large oil sands facilities and larger gas processing plants). The storage losses 

from the first type of tank are estimated as described below. The losses from floating-roof tanks are 

estimated using the empirical correlations developed by API (1993 and 1994). If a tank is equipped 

with a vapour collection system, no storage losses occur. Rather, the tank is a source of equipment 

leaks (mostly due to leakage around the thief hatch). The amount of leakage is assessed as described 

in Section 7.1 (Fugitive Equipment Leaks). 

The storage losses from fixed-roof tanks comprise contributions from three different types of losses: 

breathing/standing, working (i.e., filling and emptying) and flashing. Flashing losses occur at 

production sites where unstable products (i.e., products that have a vapour pressure greater than 

local barometric pressure) are produced into vented storage tanks. When an unstable product first 

enters a tank a rapid boiling or flashing process occurs as the liquid tends towards a more stable 

state (i.e., the volatile components vaporize). The material that vaporizes during this process is 

called solution gas. 

Breathing and working losses occur for both stable and unstable products. However, if the product 

is unstable, the latter type of loss is obscured by the flashing losses. Accordingly, storage losses at 

oil batteries were taken to be the sum of breathing and flashing losses. Storage losses at gas 

processing plants and pipeline terminals (i.e., facilities storing stable products) were taken to be the 

sum of breathing and working losses. 

7.2.2 Important Considerations

Unless information to the contrary was provided by the industry survey, all storage tanks used at oil 

and gas production facilities and at gas processing plants are assumed to have fixed roofs. The 

number and sizes of these tanks are estimated based on typical design practices and on the 

maximum throughput reported for each facility. The physical dimensions of each tank size are 

assumed to be those presented in Table 21 and the colour of the tanks is assumed to be white (unless 

these data were provided on the industry survey). 

Tanks used at terminals on crude oil and LVP pipelines are delineated based on data provided by 

the operating companies. A mixture of fixed-roof and floating-roof tanks are in use. 

The use of underground storage tanks and the resulting emissions are assumed to be negligible. 

7.2.3 Default Emission Factors

Flashing losses are estimated using the Vasquez and Beggs correlation (CAPP, 2001) given below. 

Breathing losses and working losses are estimated using the API method for fixed-roof tanks 
48

(1991). For the purposes of the breathing loss calculations, the tanks are assumed to be, on average, 

about half full during standing periods. The dimensions of the tanks are assumed to be those given 

in Table 21 and the chemical properties of the tank vapours are those in Table 22. 















 = − T

C

T

C R C p

o

C

S g

3 4

1 exp 2

γ

γ

where: 

γ o < 0.876 876 ≥ 0. o γ

C1 3.204 × 10-4 7.803 × 10-4

C2 1.1870 1.0937 

C3 1 881.24 2 022.19 

C4 1 748.29 1 879.28 

Rs = solution gas factor (m3 solution gas/m3 oil), 

o γ = oil specific gravity with respect to water (dimensionless), 

= 

API o 131.5 +

141.5

g γ = specific gravity of the solution gas with respect to air (dimensionless). 

T = temperature of interest (K), and 

p = absolute pressure in the vessel of interest (Pa). 

EF RS Qo MWv = × ⋅ −5 4 .229 10

where: 

Qo = oil throughput (m3

/y), and 

MWv = tank vapour molecular weight (kg/kmole). 

Table 21. Summary of the commonly used tank sizes in the oil and gas industry, 

and the dimensions of these tanks. 

Nominal Capacity 

(bbl) (m3) 

Diameter 

(m) 

Height 

(m) 

100 

200 

400 

500 

750 

1000 

1500 

2000 

17.077 

32.033 

64.065 

79.711 

120.093 

160.116 

243.372 

320.238 

2.438 

3.658 

3.658 

4.877 

4.572 

6.096 

7.315 

7.315 

3.658 

3.048 

6.096 

4.267 

7.315 

5.486 

5.791 

7.620 
49

7.3 Handling Losses - Tankers

7.3.1 Source Characterization

The losses from tankers are classified based on the type of product moved: high vapour pressure 

(HVP) or low vapour pressure (LVP). 

7.3.1.1 High Vapour Pressure Carriers

Rail tank cars and tank trucks that transport HVP products use special high-pressure storage systems 

to contain these products. Certain losses occur during the loading and unloading of these vehicles 

(i.e., venting of the gauge assembly and loss of material that is left in the transfer lines). 

7.3.1.2 Low Vapour Pressure Carriers

These carriers may transport crude oil, condensate and pentanes-plus. Emissions result from 

evaporation losses during loading and transit activities. The amount of emissions depends on the 

vapour pressure of the liquid product, the recent loading history and the method of loading. 

Submerged loading and dedicated normal service are assumed. 

7.3.2 Important Considerations

Some losses may occur during transit due to leaking equipment components (e.g., valves, and 

flanged and threaded connections); however, these are likely small by comparison and, therefore, 

are neglected. 

7.3.3 Default Emission Factors

7.3.3.1 High Vapour Pressure Carriers

In the absence of appropriate published procedures, the loading and unloading losses are determined 

using the following developed equations: 

and, 

where, 

ERL,i, ERU, = total emissions associated with loading (L) and unloading (U) of 

liquefied type i material (kg/y), 

ER = Q LFi [ EF G,i + EFL,i (1+TFS,i 1.5)] S,i L,i ⋅ ⋅ ⋅ ⋅

ER = Q LF EF (1+TF 1.5) i U,i R,i R,i U,i ⋅ ⋅ ⋅ ⋅
50

QS,i, QR,I = volume of liquefied type i material shipped (S) and received (R), 

respectively (m3

/y), 

LFi = number of rail cars typically used per unit volume of liquefied type i 

material transported (i.e. load factor) (cars/m3

), 

EFG,I = average emission factor for gauging losses during loading of 

liquefied type i material (kg/car), 

EFL,i, EFU,i = average emission factors for losses from depressurizing the transfer 

line upon completion of loading (L) and unloading operations (U) 

involving liquefied type i material, and 

TFS,i, TFR,i = fraction of the volume of liquefied type i material that is shipped or 

received by truck. 

The numeric value of 1.5 in the above equations accounts for the fact a tank truck must make two to 

three times as many trips as a rail car to move the same volume of liquefied material. Values for the 

load, emission, and trucking factors are presented in Table 23 for liquefied ethane, propane and 

butane. 

7.3.3.2 Low Vapour Pressure Carriers

The loading losses are calculated the equation presented below and factors published by U.S. EPA 

(1995a). Losses that occur during the transit of LVP products are not evaluated. (There are no 

known factors or procedures available for estimating losses from transport of crude oil or natural 

gas liquids by tanker vehicles.) 

 where, 

Li = loading loss (kg/y), 

S = normal saturation factor to account for the effects of the method of 

loading (dimensionless), 

P = true vapour pressure of the loaded liquid (kPa), 

Mv = molecular weight of the vapour (kg/kmole), 

T = bulk temperature (o

 C), 

Q = annual volume loaded (m3

), and 

CF = average control factor (dimensionless). 

Crude oil is assumed to have a vapour pressure of 35 kPa and the molecular weight of the vapour is 

assumed to be 80 kg/kmole. NGL and pentanes-plus are given the properties of pentane. 

(1.0 -CF) (T +273.15)

0.120 S P M Q L = v

i ⋅ ⋅ ⋅ ⋅ ⋅
51

The saturation factor for submerged loading of rail tank cars and tank trucks under normal dedicated 

service is 0.60 (i.e., the gas that is displaced from the tank vehicle contains 60 percent as much 

organic material as it can hold at thermodynamic equilibrium). 

Loading losses are controlled using vapour exchange or vapour recovery systems. These devices are 

not widely used in the upstream oil and gas industry; therefore, a control factor of zero is used for 

the emission calculations. 

Table 22. Liquid product properties used in tank flashing and loading/unloading 

emission estimates. 

Liquid Product Reid Vapour Pressure 

(RVP) (kPa) 

Mv – Vapour Molecular 

Weight (kg/kmole) 

Condensate 76.6 50.0 

Light/Medium Crude Oil 54.8 44.2 

Heavy Crude Oil 40.5 19.9 

Thermal Crude Oil 40.5 30.6 

Cold Bitumen 39.7 23.3 

Table 23. Summary of the factors for estimating emissions from rail tank cars due 

to the loading and unloading of LPG products (ethane, propane and 

butane). 

Liquefied Emission Factors (kg/car) 

Petroleum 

Gas 

Load 

Factor1

(cars/m3) 

Trucking 

Factor1

(m3/m3) 

Gauging2

Assembly 

Loading 

Line3

Unloading 

Line3

C2

C3

C4

0.0048 

0.0085 

0.0085 

0.00 (S)4

0.00 (R)5

0.49 (S) 

0.87 (R) 

0.18 (S) 

0.42 (R) 

34.86

34.8 

11.2 

2.10 

2.99 

3.38 

2.10 

0.21 

0.07 

1

 Estimated based on data supplied by Transport Dangerous Goods Directorate, Transport Canada (1987) on 

LPG movements by CP Rail and CN Rail in Alberta during 1986. 2

 Calculated using the universal gas sizing equation adapted for vapours. It is assumed that the gauge vents 

through a needle valve with a 1/4" port size. Furthermore, the valve is 25 percent open and the loading takes 1.5 

hours. The effects of friction in the gauge rod are neglected. Actual values may vary greatly, depending on the 

valve design and the size of the valve opening. 3

 The values reflect loss of material when the transfer line are depressurized and disconnected. The line is 

assumed to be 3 m long, 5 cm in diameter, filled with liquid at the end of a loading procedure and filled with 

vapour at the end of an unloading procedure. 4

 S denotes shipments. 

5

 R denotes receipts. 

6

 Losses are arbitrarily assumed to be comparable to those from loading of propane.
52

7.4 Accidental Releases

7.4.1 Source Characterization

Accidental releases are unintentional releases that are not part of normal operational or 

maintenance activities and that the system has not been designed for (that excludes such releases 

as, for example, relief valve emissions). 

The only significant types of natural gas emissions in this category are those from pipelines as a 

result of ruptures, spills of hydrocarbon liquids, well-blowouts, gas migration around the outside 

of the well casing and surface casing vent flows. 

7.4.2 Important Considerations

It is assumed that all emissions from accidental releases are accounted for in the related 

environmental reporting by facilities to government agencies. 

7.4.3 Default Emission Factors

Emissions from accidental releases are taken to be the total of reported unrecovered spills and 

releases to the environment. 
53

8.0 SPECIATION OF EMISSIONS

The speciation of fugitive and process emissions to determine the amounts of specific substances 

emitted (e.g., CH4, CO2, VOC, and H2S) is done using site-specific composition data, where 

available, and the default profiles presented in Tables 24 to 29. Tables 30 and 31 provide typical 

compositions of processed natural gas compositions by province. 

Almost 25 000 speciation profiles were derived from company supplied data, well gas and oil 

analyses and pool average gas and oil analyses. The default profiles in Tables 24 to 29 are used only 

if one of these profiles could not be linked to a specific facility. 

Use of the default profiles is described below. 

• Dry gas profiles are applied to low-pressure gas gathering systems and to gas batteries. 

• Sweet gas profiles are used for dehydrated gas gathering systems and sweet gas processing 

plants. 

• Sour gas profiles are dedicated to heated gas gathering systems and to sour-gas processing 

plants; however, all fuel gas are assumed to be sweet. 

• Conventional oil, heavy oil and crude bitumen profiles are applied to the corresponding 

production and battery facilities. 

The profiles are implemented using the equation below. 

where, 

ERk = average emission rate (kg/h) of the chemical compound k, 

ER = total mass emission rate (kg/h), 

Yk = mole fraction of component k in the effluent stream, 

Mk = molecular weight of component k, and 

M = average molecular weight of the bulk fluid. 

Total emissions are determined for each of the chemical species in the applied speciation profiles. 

By including inorganic compounds in the profiles it is assumed that the estimated emission rates 

(except those from equipment leaks and from combustion activities) are total mass emissions on a 

moisture-free basis. As the emissions from equipment leaks are expressed as THC, they are 

speciated based on the normalized hydrocarbon portion of the profiles (inorganic emissions from 

equipment leaks are calculated in appropriate proportion to the THC emissions). 

M

ER Y M ER = k k

k

⋅ ⋅
54

Table 24. Speciation profiles (on a moisture-free basis) for dry and sweet gas production and processin

Dry Gas Sweet Gas 

Gas1 Light Liquid2 Dehy Off-Gas3 Gas4 Tank Vapours5 Light Liqu

Component Mole 

% 

Mass 

% 

Mole 

% 

Mass 

% 

Mole 

% 

Mass 

% 

Mole 

% 

Mass 

% 

Mole 

% 

Mass 

% 

Mole 

% 

M

N2 1.7099 2.9153 0.01 0.0050 6.0450 9.3101 0.6793 1.0865 2.9668 2.9436 0.01 0CO2 0.2646 0.7088 0.05 0.0394 3.6656 8.8694 0.5814 1.4610 1.3436 2.0944 0.05 0H2S 0.0000 0.0000 0.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.00 0C1 97.291 94.998 0.59 0.1695 87.460 77.143 91.880 84.163 56.421 32.060 0.59 0C2 0.7009 1.2828 31.52 16.975 2.8296 4.6780 5.4263 9.3166 15.222 16.212 31.52 1C3 0.0295 0.0792 21.61 17.067 0.0000 0.0000 1.0490 2.6412 11.630 18.165 21.61 1i-C4 0.0012 0.0041 9.60 9.9936 0.0000 0.0000 0.1291 0.4284 2.6504 5.4564 9.60 9n-C4 0.0020 0.0069 10.06 10.473 0.0000 0.0000 0.1949 0.6468 5.5796 11.487 10.06 1i-C5 0.0006 0.0026 0.83 1.0725 0.0000 0.0000 0.0254 0.1046 1.2562 3.2103 0.83 1n-C5 0.0005 0.0020 0.99 1.2793 0.0000 0.0000 0.0296 0.1219 1.5784 4.0336 0.99 1C6 0.0001 0.0003 5.87 9.0601 0.0000 0.0000 0.0060 0.0295 0.9312 2.8424 5.87 9C7+ 0.0001 0.0003 18.87 33.866 0.0000 0.0000 0.0000 0.0000 0.4215 1.4960 18.87 3Mole Wt 16.430 16.430 55.835 55.835 18.189 18.189 17.514 17.514 28.233 28.233 55.835 5

1 Based on a dry gas analysis taken downstream of a straddle plant. 2 Average composition for liquids from gas fields in Alberta (EUB, 2003d) 3 Estimated by simulating dehydration of the gas (G) at water-saturated conditions, 28o C and 7 000 kPa. 

4 Based on a gas analysis taken at an appropriate transmission point (Picard et al., 1987a). 
55

Table 25. Speciation profiles (on a moisture-free basis) for sour gas production and processing facilitie

transmission facilities. 

Sour Gas 

Gas1 Tank Vapours2 Light Liquid3 

Component 

Mole % Mass % Mole % Mass % Mole % Mass % Mo

N2 0.6552 1.0140 2.9668 2.9436 0.01 0.0050 0.7CO2 0.5608 1.3635 1.3436 2.0944 0.05 0.0394 0.6H2S 3.5460 6.6755 0.0000 0.0000 0.00 0.0000 0.0C1 88.6210 78.5447 56.4205 32.0598 0.59 0.1695 92.C2 5.2339 8.6947 15.2219 16.2121 31.52 16.9753 4.5C3 1.0118 2.4649 11.6300 18.1646 21.61 17.0671 1.0i-C4 0.1245 0.3998 2.6504 5.4564 9.60 9.9936 0.1n-C4 0.1880 0.6037 5.5796 11.4867 10.06 10.4725 0.2i-C5 0.0245 0.0977 1.2562 3.2103 0.83 1.0725 0.0n-C5 0.0286 0.1140 1.5784 4.0336 0.99 1.2793 0.0C6 0.0058 0.0276 0.9312 2.8424 5.87 9.0601 0.0C7+ 0.0000 0.0000 0.4215 1.4960 18.87 33.8656 0.0Mole Wt 18.1011 18.1011 28.2333 28.2333 55.8345 55.8345 17.

1 The H2S-free composition is based on an analysis taken at an appropriate transmission point (Picard et al., 1987b). 

2 Based on an analysis of the vapours from an condensate tank in northeastern B.C. (Picard and Colley, 1987a). 3 Average composition for liquids from gas fields in Alberta (EUB, 2003d) 4 Based on a dry gas analysis taken upstream of a straddle plant. 
56

Table 26. Speciation profiles (on a moisture-free basis) for light/medium crude oil and primary heavy 

facilities. 

Light/Medium Crude Oil Heavy Crude Oil (Prim

Gas1 Tank Vapours2 Light Liquid3 Gas4 Tank Vapours4 

Component 

Mole % Mass % Mole % Mass % Mole % Mass % Mole % Mass % Mole % Mass % 

N2 0.6190 0.7723 13.9989 8.8642 0.1316 0.0464 0.1817 0.3030 6.3477 8.936CO2 5.2430 10.2765 0.3303 0.3286 0.3240 0.1794 0.0859 0.2250 0.6892 1.524H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0002 0.0000 0.000C1 73.2524 52.3386 10.0100 3.6300 9.7419 1.9668 98.0137 93.6026 87.2337 70.332C2 11.9708 16.0314 15.7274 10.6900 3.6464 1.3798 0.9062 1.6221 2.2616 3.417C3 5.3198 10.4477 24.1601 24.0821 4.9064 2.7227 0.0408 0.1071 0.1905 0.422i-C4 0.8778 2.2723 6.6404 8.7244 1.9516 1.4275 0.0564 0.1951 0.1324 0.386n-C4 1.7027 4.4077 16.6022 21.8126 4.0430 2.9572 0.0351 0.1214 0.1137 0.332i-C5 0.3570 1.1472 4.2113 6.8682 3.0507 2.7699 0.0501 0.2152 0.1400 0.507n-C5 0.3802 1.2217 4.5447 7.4120 3.6626 3.3255 0.0433 0.1860 0.1230 0.446C6 0.2446 0.9388 2.9655 5.7767 18.1649 19.6995 0.0927 0.4755 0.3494 1.513C7+ 0.0327 0.1459 0.7997 1.8113 50.3769 63.5253 0.4940 2.9467 2.4188 12.180Mole Wt 22.4536 22.4536 44.2399 44.2399 79.4647 79.4647 16.7990 16.7990 19.8981 19.898

1 Based on an analysis of the gas from a large solution-gas gathering system in central Alberta (Picard et al., 1987b). 2 Adapted from an analysis of the vapours from an oil storage tank in northeastern B.C (Site No. 2) (Picard and Colley, 1987a). 3 Average composition for liquids from conventional oil fields in Alberta (EUB, 2003d) 4 Adapted from results presented by Ullman et al. (1987). 
57

Table 27. Speciation profiles (on a moisture-free basis) light/medium crude oil and primary 

production facilities. 

Sour Crude Oil 

Sour Solution Natural Gas1 Sour Light Liq

Component 

Mole % Mass % Mole % 

N2 3.2898 4.0741 0.1081 CO2 3.5298 6.8675 0.3733 H2S 3.2898 4.9558 0.8527 C1 71.7705 50.9011 7.4364 C2 9.0895 12.0828 3.8033 C3 5.3197 10.3703 6.0853 i-C4 0.8010 2.0581 1.9617 n-C4 1.6399 4.2138 5.8751 i-C5 0.3920 1.2503 3.5331 n-C5 0.4100 1.3077 4.6140 C6 0.2490 0.9485 19.9173 C7+ 0.2190 0.9701 45.4395 Mole Wt 22.6218 22.6218 78.5652 

 1 Based on the average pool analysis for sour conventional oil operations (Alberta pool average gas and oil analyses, EUB 2
58

Table 28. Speciation profiles (on a moisture-free basis) for thermal conventional heavy crude o

production. 

Thermal Conventional Heavy Crude Oil Cold Bit

Gas1 Tank Vapours1 Light Liquid2 Gas3 

Component 

Mole % Mass % Mole % Mass % Mole % Mass % Mole % Mass % 

N2 0.1932 0.1767 3.3516 3.0552 0.1044 0.0353 0.6130 0.6343 CO2 2.6094 3.7485 16.1140 23.0772 0.7652 0.4066 28.5280 46.3771 H2S 0.0150 0.0167 0.1439 0.1596 0.1744 0.0718 0.2490 0.3134 C1 72.9361 38.1942 66.6600 34.8000 7.6584 1.4834 63.9410 37.8919 C2 1.9370 1.9012 0.9490 0.9286 2.7490 0.9980 1.2070 1.3407 C3 3.0956 4.4558 0.5394 0.7740 3.8274 2.0377 0.9160 1.4921 i-C4 1.0807 2.0504 0.1922 0.3635 1.8159 1.2743 0.2640 0.5668 n-C4 2.3889 4.5323 0.3678 0.6957 3.5872 2.5173 0.9520 2.0440 i-C5 1.9994 4.7088 0.4541 1.0662 2.4042 2.0943 1.3020 3.4700 n-C5 2.2733 5.3539 0.5829 1.3686 2.7495 2.3951 1.1310 3.0143 C6 5.8086 16.3394 2.1914 6.1454 17.9436 18.6696 0.8970 2.8554 C7+ 5.6628 18.5221 8.4539 27.5661 56.2207 68.0166 0.0000 0.0000 Mole Wt 30.6359 30.6359 30.7306 30.7306 82.8268 82.8268 27.0719 27.0719 

1 Adapted from results presented by Ullman et al. (1987). 2 Average composition for liquids from heavy oil fields in Alberta (EUB, 2003d) 3 Provided by an operator of a major crude bitumen facility. 
59

Table 29. Speciation profiles (on a moisture-free basis) for British Columbia sweet and 

sour natural gas production and processing facilities. 

Sweet Natural Gas Sour Natural Gas 

Gas1 Gas2 Component 

Mole % Mass % Mole % Mass % 

N2 1.8871 2.7999 1.1827 1.5942 

CO2 2.2141 5.1611 6.4801 13.7225 

H2S 0.0751 0.1355 7.0611 11.5776 

C1 87.4553 74.3132 79.1579 61.1052 

C2 5.0650 0.8067 3.5884 5.1920 

C3 1.8830 4.3980 1.3349 2.8324 

i-C4 0.3001 0.9239 0.2249 0.6290 

n-C4 0.5387 1.6584 0.4362 1.2199 

i-C5 0.1544 0.5900 0.1321 0.4586 

n-C5 0.1574 0.6015 0.1472 0.5110 

C6 0.1319 0.6021 0.1259 0.5221 

C7+ 0.1412 0.7494 0.1318 0.6355 

Mole Wt 18.8802 18.8802 20.9667 20.9667 

1 Average gas composition for sweet gas fields (i.e., H2S concentrations < 1.0 mole percent) (B.C. EMPR, 

1997a). 

2 Average gas composition for sour gas fields (i.e., H2S concentrations ≥ 1.0 mole percent) (B.C. EMPR, 1997a). 

Table 30. Typical compositions (mol percent) of processed natural gas by province. 

Component BC AB SK MB ON 

WA 

Border 

Empress SK 

Border 

BC 

Border 

AB 

Border 

Regina MN 

Border 

Dawn 

C1 95.9490 92.8690 97.1294 95.6400 95.2128 95.0600 94.8890 94.7089 

C2 2.4160 4.0556 0.2579 2.5800 2.4306 0.4940 2.4740 2.4805 

C3 0.5440 1.1112 0.0201 0.0700 0.1374 0.0670 0.2130 0.2501 

i-C4 0.0710 0.1601 0.0005 0.0100 0.0043 0.0120 0.0130 0.0300 

n-C4 0.1130 0.2180 0.0005 0.0100 0.0043 0.0110 0.0200 0.0400 

i-C5 0.0190 0.0496 0.0008 0.0000 0.0013 0.0040 0.0050 0.0200 

n-C5 0.0110 0.0389 0.0004 0.0000 0.0010 0.0030 0.0080 0.0100 

C6 0.0260 0.0225 0.0001 0.0100 0.0012 0.0070 0.0030 0.0100 

C7+ 0.0000 0.0126 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 

CO2 0.1250 0.6334 0.2618 0.5400 0.5552 0.1290 0.6560 0.6201 

N2 0.7260 0.8291 2.3284 1.1400 1.6519 4.2130 1.7190 1.8304 

Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 

Source: Unpublished data from the files of Clearstone Engineering Ltd. 
60

Table 31. Typical compositions (mass percent) of processed natural gas by province. 

Component BC AB SK MB ON 

WA 

Border 

Empress SK 

Border 

BC 

Border 

AB 

Border 

Regina MN 

Border 

Dawn 

C1 91.7957 85.4537 94.7955 91.7267 91.0242 91.3750 90.2786 89.8694 

C2 4.3324 6.9946 0.4718 4.6379 4.3553 0.8900 4.4118 4.4117 

C3 1.4306 2.8104 0.0539 0.1845 0.3611 0.1770 0.5570 0.6523 

i-C4 0.2461 0.5337 0.0018 0.0347 0.0149 0.0418 0.0448 0.1031 

n-C4 0.3917 0.7268 0.0018 0.0347 0.0149 0.0383 0.0689 0.1375 

i-C5 0.0818 0.2053 0.0035 0.0000 0.0056 0.0173 0.0214 0.0854 

n-C5 0.0473 0.1610 0.0018 0.0000 0.0043 0.0130 0.0342 0.0427 

C6 0.1336 0.1112 0.0005 0.0515 0.0062 0.0361 0.0153 0.0510 

C7+ 0.0000 0.0724 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000 

CO2 0.3281 1.5988 0.7009 1.4207 1.4561 0.3402 1.7121 1.6142 

N2 1.2128 1.3321 3.9680 1.9091 2.7575 7.0712 2.8557 3.0328 

Total 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 

Source: Unpublished data from the files of Clearstone Engineering Ltd. 
61

9.0 AN OVERVIEW OF EMISSION SOURCES BY ACTIVITY

The following sections give a brief description of the different emission sources in each subject oil 

and gas activity, the assumptions used to estimate the number of these sources and determine their 

characteristics and activity levels in the absence of reported values, and some general comments 

regarding the emission assessment procedures which have been applied. The detailed emission 

calculation procedures and emission factors have been delineated in Sections 3 through 8 above. 

In evaluating each subject activity, an effort was made to be as thorough and complete as possible 

and to build upon the previous inventory efforts sponsored by CAPP (Picard et al., 1992, Ross et al., 

1999). Each emission source was assumed to be important (due to size or number) until proven 

otherwise. 

9.1 Well Drilling and Associated Testing

The drilling of wells for crude oil and natural gas in Canada is a seasonal activity that is highly 

variable in terms of the numbers of wells drilled, the geographic areas of activity, the target resource 

(light/medium crude oil, conventional heavy crude oil, bitumen or natural gas), the classification of 

the well (sweet, sour, critical sour), the depths that are drilled, and the geological conditions that are 

encountered. Each of these variables impacts the drilling procedures that are used and, in turn, the 

type, source and amount of emissions that occur. In general, the emissions may be ascribed to fuel 

consumption by the drilling rigs, drilling fluids and venting and flaring activities during drill-stem 

tests. 

9.1.1 Drilling Rigs

There are two potential sources of emissions associated with drilling rigs: fugitive emissions due to 

leaking equipment components, and combustion emissions from operation of the engines and 

heaters used by the rigs and any associated camps. 

The first source is assumed to be negligible due to the lack of hydrocarbon-containing lines, except 

for the brief period during which drill-stem tests are conducted. 

The latter source of emissions is assessed based on fuel consumption data reported by CAODC 

(1989, 1995). These statistics give the average amount of diesel fuel consumed by engines and by 

boilers according to the depth range of the hole. Drilling depth and duration data are available for all 

wells drilled These data are presented in Table 32, below. Emission factors are used to estimate the 

amount of fuel that passed through the combustion devices unburned. 
62

Table 32. Summary of drilling rig activity presented by province for the reference year 

2000. 

Drilling Days for a Depth Range Province or 

Territory < 950 m 951 – 

1400 m 

1401 – 

1850 m 

1851 – 

2450 m 

2451 – 

3050 m 

3051 – 

3700 m 

>3700 

m 

Northwest Territories1 140 17 65 177 161 ---- ---- 

British Columbia2 1 312 5 171 9 334 7 624 5 315 1 054 978 

Alberta3 31 572 22 469 13 572 18 339 16 730 9 496 6 277 

Saskatchewan4 9 325 2 204 2 294 3 541 1 026 221 ---- 

Manitoba5 ---- 1 700 ---- ---- ---- ---- ---- 

Ontario6 1 730 407 127 806 133 162 ---- 

Nova Scotia7 ---- ---- ---- ---- ---- 126 227 

Newfoundland8 ---- ---- ---- ---- ---- 26 ---- 

Total 44 079 31 968 25 392 30 487 23 365 11 085 7 482 

1 Northern Oil and Gas Report. Available at www.ainc-inac.gc.ca/oil 

2 Petroleum Information Management System (PIMS) (BC OGC 2000). 

3 EUB General Well Data File: Drilling Occurrence Data (EUB, 2003b). 

4 Mineral Statistics Yearbook: 2001 (SIR, 2000). 

5 Oil Activity Review: 2000 (MEM, 2001).

6 Ontario Oil, Gas and Salt Resources Library. Ontario Digital Well Data. Available from www.ogsrlibrary.com

7 Canada Nova Scotia Offshore Petroleum Board. Weekly Status Report – Drilling Activity

www.cnsopb.ns.ca/activityreports 

8 Canada-Newfoundland Offshore Petroleum Board. Hibernia Development Wells. 

www.cnopb.nfnet.com/resource/product/hwells.htm

9.1.2 Drilling Fluids

There are two potential causes for GHG emissions from drilling fluids: entrainment of solution 

natural gas and volatilization of invert drilling fluids. These are described in the sections below; 

however, a brief description of drilling fluids and their use is given first. 

As a hole is being drilled, fluid is injected down the centre of the drill stem and allowed to return up 

the annulus (the space between the drill stem and the walls of the hole). The drill stem is a column 

of steel pipe that transfers torque generated by the rig to the bit. The fluid is usually water or an 

aromatic-based mixture; air, nitrogen or natural gas may also be used (under balanced drilling). The 

purposes of the fluid include removal of cuttings from the hole, cooling of the bit, lubrication of the 

hole and balancing of down-hole pressures. At the surface, the returning fluid flows into a tank (the 

mud tank) where it is brought to atmospheric pressure and the cuttings are removed by screening. 

Chemicals and clay materials may be added to adjust the rheological properties of the fluid before it 

is recirculated. 

The effect of the use of under-balanced drilling on total industry emissions is expected to be small 

since fewer than 1000 under-balanced wells have been drilled in Canada (PTTC, 2003). No records 
63

are currently kept regarding the volume and composition of any GHGs released during the drilling 

process. 

9.1.2.1 Entrainment of Solution Natural Gas

When natural gas bearing zones are encountered, there is a potential for some natural gas to dissolve 

in, or become entrained with, the drilling fluid. When the fluid is brought to atmospheric pressure in 

the mud tank, this gas separates from the drilling fluid. If it is anticipated that sour natural gas zones 

will be encountered, vapours from the mud tank are collected and subsequently flared. Otherwise, 

the vapours are typically vented to atmosphere. 

The total amount of solution gas from a drilling operation is relatively small as the flows are 

normally too low to maintain a flare except when gas zones are first penetrated. The net emissions 

from entrainment of solution gas are therefore considered to be insignificant compared to those 

from other sources at the drill site (e.g., drill stem tests [see Section 9.1.3]), regardless of whether 

the solution gas is flared or vented. 

9.1.2.2 Volatilization of Invert Drilling Fluids

Typically, the temperature of the ground increases markedly with depth. Consequently, 

significant amounts of heat may be transferred to the drilling fluid as the hole deepens. This 

heating of the drilling fluid has the potential to volatilize any aromatic compounds used in the 

fluid. Drilling fluids that use an aromatic base are called invert fluids. Usually, invert fluids are 

composed of about 80 percent diesel fuel and 20 percent water, by volume. 

The emissions from use of invert fluids are estimated by calculating the evaporation rate in the mud 

tanks, and applying the result to the total number of operating hours accumulated in the reference 

year. The evaporation rate is estimated using the API correlations for fixed-roof storage tanks 

(1991). It is assumed that each rig has three active mud tanks; each tank has a rectangular surface 

area of 22.3 m2

, and the average temperature of the fluid in the tanks is 60o C. 

The total hours of operation are estimated based on the number of wells drilled, their average 

drilling time and the percentage of wells that used invert fluids. The number of wells drilled, and the 

average number of days required to drill a well are taken from appropriate provincial statistics. 

Where this information is not available, the Alberta data is used to estimate the number of wells 

drilled based on the ratio of producing wells in the province to the number in Alberta. A summary 

of this information is presented in Table 33. Based on the relative contribution of this source to total 

THC emissions in the 1989 inventory (i.e., 0.0003 percent of total THC emissions from the industry 

in Alberta) no further effort was made to determine if the use of invert drilling fluids had changed 

since that time. Accordingly, invert drilling fluids are assumed to be used for five percent of all 

wells drilled. 
64

Table 33. Summary of number of wells drilled and the average number of drilling days 

per well for each province or territory for the reference year 2000. 

 

Province or Territory Wells Drilled Average Drilling Days 

Northwest Territories1 20 28.0 

British Columbia2 952 32.3 

Alberta3 15 517 7.6 

Saskatchewan4 3 897 4.8 

Manitoba5 68 25.0 

Ontario6 92 36.6 

Nova Scotia7 7 50.4 

Newfoundland8 13 2.0 

1 Northern Oil and Gas Report. Available at www.ainc-inac.gc.ca/oil 

2 Petroleum Information Management System (PIMS) (BC OGC 2000). 

3 EUB General Well Data File: Drilling Occurrence Data (EUB, 2003b). 

4 Mineral Statistics Yearbook: 2000 (SEM, 2001). 

5 Oil Activity Review: 2000 (MEM, 2001).

6 Ontario Oil, Gas and Salt Resources Library. Ontario Digital Well Data. Available from www.ogsrlibrary.com

7 Canada Nova Scotia Offshore Petroleum Board. Weekly Status Report – Drilling Activity

www.cnsopb.ns.ca/activityreports 

8 Canada-Newfoundland Offshore Petroleum Board. Hibernia Development Wells. 

www.cnopb.nfnet.com/resource/product/hwells.htm

9.1.3 Drill-Stem Testing

When the target zone is reached, a drill-stem test may be performed to determine the production 

potential. The results of these tests are available from the provincial regulatory bodies in Alberta, 

British Columbia and Saskatchewan. For all other provinces, these volumes are estimated based 

on the number of wells drilled, and if available, the depth of wells drilled. 

During a test, the zone is produced through the centre of the drill stem. At the surface, the gas 

and liquid phases are separated and measured. If it is a sour well, the gas phase is flared; 

otherwise, the gas is often vented to the atmosphere. Although the test results are reported, the 

well effluent is not treated as production. Consequently, the data are not reflected in any 

production disposition analyses published by the regulatory agencies. 

Furthermore, before a drill-stem test is conducted, a clean-up operation is performed. This consists 

of producing the well overnight to allow any drilling fluid and debris that may have penetrated the 

zone to be removed. A preliminary assessment of the flow potential may be performed using a flow 

prover (an orifice meter). If the well shows potential, the proper separation and metering facilities 

required for a drill-stem test are brought on site. The volumes from these clean-up operations and 

preliminary flow test are not in the data reported to regulatory agencies. 

To assess the emissions from reported drill stem tests it is assumed that: 

 The average gas flow rate during the test is equal to the average of the maximum and 

minimum flows reported for the test. 
65

 The average flow during clean-up is equal to the minimum flow reported for the test. 

 The duration of the test is as reported. 

 The duration of the clean-up operation and preliminary flow test is twelve hours. 

 Based on information supplied by several operators, approximately 88.4 percent of DST 

gas is flared and the remainder is vented. 

9.2 Well Servicing and Associated Testing

This component of well-related activities comprises well completions, testing, workovers and 

abandonments. The emissions produced by these activities are perhaps evaluated best in terms of 

the fuel consumption by the major types of equipment that are employed (service rigs, pumping 

units and wireline units) and specific venting that occurs. 

9.2.1 Service Rigs

The total number of hours logged by service rigs in western Canada for 2000 were obtained from 

the Canadian Association of Oilwell Drilling Contractors (CAODC, 2003). Based on data supplied 

by two service rig operators, service rigs consume about 29.1 L of diesel per hour of operation. 

Approximately 35 percent of this fuel is consumed by boilers and the remainder is consumed by 

reciprocating engines. Also, small amounts of propane are used in the winter for space heating. On 

an annual basis, this amounts to about 1.9 L per hour of operation (Picard et al., 1992). 

9.2.2 Pumping Units

Pumping units are used in the supply of cementing and chemical treatment services. In the previous 

inventory, pumping units were determined to be a relatively insignificant source of CH4 and VOC 

emissions (i.e., < 0.002 percent of Alberta’s THC emissions) (Picard et al., 1992). Therefore, no 

further effort was made to better quantify these emissions. Instead, the 1989 fuel consumption 

values for Alberta is extrapolated to 2000 values based on the number of wells drilled in each 

province or territory. This information is presented in Table 34. 

Table 34. Summary of estimated diesel fuel consumption by pumping units presented 

by province for the reference year 2000.1,2 

Province or Territory Wells Drilled Pumping Unit Diesel Fuel (kL) 

Northwest Territories 20 61 

British Columbia 952 2 889 

Alberta 15 517 47 094 

Saskatchewan 3 897 11 827 

Manitoba 68 206 

Ontario 92 279 

Nova Scotia 7 21 

Newfoundland 13 39 

Total 20 566 62 418 

1 Pumping unit fuel consumption is assumed to be 3035 L per well drilled (CAPP, 1999). 

2 See Table 32 for the sources of the number of wells drilled for each province. 
66

9.2.3 Wireline Units

Wireline units are used to lower special tools and instruments down hole for repair, inspection, 

retrieval and testing purposes. In Alberta, the industry is dominated by one large company, followed 

by several medium sized companies and many smaller companies. Unfortunately, there was not 

enough information available to evaluate fuel consumption by this source category. 

9.2.4 Venting During Well Servicing

The emissions from venting during well servicing are divided into two categories based on the type 

of service operations: conventional service work (i.e., well repairs and inspections, cementing 

operations, and formation treatments), and blowdown treatments for shallow natural gas wells. 

The volumes of natural gas flared or vented during absolute open flow (AOF) tests are reported as 

production by the operator. For Alberta, emissions from AOF tests have been calculated based on 

the data in the AOFP database (EUB, 2003k). This file contains the test rate and duration and 

provides a flag that indicates whether the test gas is flared, vented or conserved. For other provinces 

the emissions from these activities are taken into account in sections that follow on crude oil and 

natural gas production and natural gas processing (Sections 9.3 to 9.7). 

9.2.4.1 Conventional Service Work 

A well is normally killed at the start of any conventional well-servicing operations by circulating an 

inhibited fluid such as water or oil downhole to counter-balance the pressures in the producing 

formation. This helps control the well and greatly reduces the potential for emissions. The emissions 

that occur are usually limited to the release of some solution gas from the mud tanks. Typically, the 

gas is vented if it is sweet, and flared if it is sour. The volumes involved are small and are 

considered to be negligible. An additional source of emissions occurs on some oil wells where gas 

pressure may be relieved to the atmosphere prior to injecting the kill fluid (this helps prevent gas 

from being released during the rig operations). However, the extent of this practice is not known. 

A well may not be killed if only simple wireline work is to be performed (especially if there is a 

potential for damage to the formation), or if the well can be depressurized quickly and easily by 

venting it to atmosphere (e.g., some heavy oil wells). 

If the wireline work is performed under pressure, a device, called a lubricator, is mounted on the 

wellhead and used to maintain a seal around the wire line as the work is performed. Each time the 

wireline tool is removed from the hole, the master valve on the wellhead is closed to isolate the 

lubricator, then, the lubricator is opened to the atmosphere to depressurize. For each 

depressurization event about 10 m of pipe is vented to the atmosphere. Unfortunately, there was not 

enough information available to assess the extent to which lubricators are used. 

Depressurization of the well is practical for some steam-stimulated crude bitumen wells. Initially, 

the well is vented to atmosphere to determine if pressure support from neighbouring wells is 

occurring. Based on data provided by one operator, a typical blowdown time to atmosphere is 15 to 
67

20 minutes or until casing pressure drops to acceptable limits, and this procedure is performed 

annually on about 3.6 percent of crude bitumen wells. There is not enough pressure and/or flow rate 

data available to assess the emissions from these wells; however, the resultant value is anticipated to 

be small. Furthermore, much of the material that is emitted is suspected to be steam. 

9.2.4.2 Blowdown Treatments for Natural Gas Wells 

Some natural gas wells must be blown down periodically to remove water that has accumulated in 

the production tubing. These are primarily shallow (less than 1000 m deep), low-pressure (less than 

2000 kPa) gas wells. There are three different blowdown treatments that are applied to these wells: 

unassisted blowdowns, swabbing and coiled tubing clean-outs. 

During an unassisted blowdown, the well is opened to atmosphere so the down-hole pressures may 

blow the water from the tubing. Sometimes, sticks of soap are inserted down the production tubing 

beforehand. This causes a frothing action to occur when the well is opened, which helps to remove 

the water. The swabbing process consists of lifting water mechanically from the well using an 

endless tubing unit. A coiled tubing clean-out involves injecting compressed gas down-hole to help 

lift the water by increasing the effective pressure in the well. 

Shallow gas wells are typically sweet and usually are not equipped with flares. Thus, the natural gas 

that is discharged during the subject blowdown operations is released to the atmosphere unburned. 

These wells are located mainly in the Medicine Hat and Milk River areas of southeastern Alberta 

and the Area III gas fields of southwestern Saskatchewan. Some wells also occur in the Cold Lake 

area of east central Alberta. To estimate the amount of emissions that result from blowdown 

procedures it is assumed (based on data provided by one operator) that: 

 The average gas emission rate while the well is venting to the atmosphere is about the same 

as the average rate of production per well. (The emission rates will be much lower than this 

at the start of a blowdown period and will be much higher at the end.) 

 An unassisted blowdown treatment takes between 0.2 and 2.0 hours or, on average, about 

0.79 hours, and approximately 0.14 of these treatments are performed per month per well. 

 Swabbing takes an average of 0.5 hours and the well is able to vent to atmosphere about 50 

percent of this time (the rest of the time flow is restricted by the mandrel in the hole), and 

approximately 0.05 such operations are performed per month per well. 

 A coiled tubing clean-out requires about 2 hours and approximately 0.05 of these operations 

are performed per month per well. 

The shallow natural gas wells in each province and territory are identified from the available well 

data files based on the type of effluent and the reported well depth. 

9.2.5 Fugitive Emissions From Well Servicing

Except during tests performed to determine the absolute open flow (AOF) potential of a well, there 

are few (if any) lines containing hydrocarbon gases and/or liquids during well servicing and 

associated testing. Therefore, it is assumed there is no significant potential for fugitive emissions 

from leaking equipment components. 
68

The equipment used for AOF tests may include a portable test separator, flare and temporary 

storage tanks. However, the frequency and duration of AOF tests typically amount to much less 

than one percent of a well's production time, and the equipment that is brought on site is 

insignificant compared to the existing production equipment. Therefore, fugitive emissions from 

AOF tests are also assumed to be negligible. 

9.3 Light/Medium Crude Oil Production

The production of light- and medium-density crude oils (i.e., crude oils with a density of less than 

900 kg/m3

) is discussed in this section. 

9.3.1 Light/Medium Crude Oil Wells

As of the end of the year 2000, there were a total of 59 696 capable light/medium crude oil wells in 

the Canada. A provincial breakdown of these wells is shown below in Table 35. 

Each of these wells is a source of emissions from equipment leaks. These are estimated using 

emission factors and typical equipment schedules. Also, some pumping wells are a source of 

combustion emissions (i.e., those that are driven by internal combustion engines). Emissions from 

natural gas combustion are estimated at the source-category level based on reported fuel 

consumption statistics. Pumping units are occasionally fuelled with propane. These combustion 

emissions are calculated using the emission factors summarized in Section 3. 

1 Prorated from British Columbia, Alberta and Saskatchewan totals based on provincial oil production. 

2 Facility counts from B.C. OGC (2003b). 

3 Facility counts are from EUB (2003f). 

4 Facility counts are from SIR (2003a). 

5 Manitoba Oil Activity Review. 

6 Ontario Oil, Gas and Salt Resources Library. Ontario Digital Well Data. Available from www.ogsrlibrary.com

7 Canada-Newfoundland Offshore Petroleum Board. Hibernia Development Wells. 

www.cnopb.nfnet.com/resource/product/hwells.htm 

Table 35. Summary of light/medium crude oil production facilities presented by 

province for the year 2000. 

Province Wells Single Well 

Batteries 

Satellite 

Batteries 

Group/Central 

Batteries 

Northwest Territories1 159 ---- ---- 1 

British Columbia2 1 754 44 10 252 

Alberta3 30 452 4 088 1 143 133 

Saskatchewan4 25 223 1 681 ---- 913 

Manitoba5 1 436 ---- ---- 72 

Ontario6 662 53 ---- 70 

Newfoundland7 10 ---- ---- 1 

Total 59 696 5 866 1 153 1 442 
69

9.3.2 Light/Medium Crude Oil Flow Lines

There are two potential sources of emissions associated with crude oil flow lines: pigging operations 

and well tie-ins. 

The emissions from pigging operations are attributed to the opening of pig traps and pig launchers. 

For simplification purposes, these sources are treated as equipment leaks. A calculated emission 

factor is used to estimate the amount of gas that is liberated when each canister is opened (see 

Section 5). The liquid phase is assumed to be collected. To estimate the total number of canisters, it 

is assumed that: each well that is connected to a flow line has a launcher, each satellite battery has a 

trap and a launcher, and each battery has a trap. The number of batteries is determined as described 

in Sections 9.3.3, 9.3.4 and 9.3.5. 

If an active pipeline must be cut to tie a well in, normally it is drained and purged with an inert 

material (e.g., N2 or H2O) beforehand. Consequently, there are no noteworthy sources of emissions 

associated with this activity. 

9.3.3 Single-Well Light/Medium Crude Oil Batteries

A crude oil battery is a unit where the production from a crude oil well(s) is separated into its 

constituent phases (natural gas, crude oil and water) for metering and appropriate disposition. 

The natural gas is either vented, flared, re-injected, or compressed into a nearby natural gas 

gathering system, depending on the type of oil recovery scheme and the economics of the situation. 

The last two options would require that compression and, possibly, dehydration facilities be 

installed. The water is re-injected as part of an enhanced recovery scheme, or is shipped to a nearby 

disposal well. Equipment associated with solution natural gas disposal or re-injection is taken to be 

part of crude oil production. Equipment associated with solution natural gas conservation is taken to 

be part of natural gas production. 

The crude oil is pumped into a nearby crude oil pipeline, or is shipped by truck to a location where 

this may be done. A treater is used to remove any emulsified water from the crude oil before it is put 

in the crude oil pipeline. 

A single-well crude oil battery is the simplest type of crude oil battery. It is estimated that there are 

about 5 866 of these in Canada (see Table 35 above for a provincial breakdown). Typically, each is 

inspected once per day; otherwise, it is unattended. As a minimum, it is equipped with separation, 

metering, storage, loading and flaring facilities. Depending on the amount and nature of the 

production, it may also comprise selected treatment, pumping and compression facilities. 

The emission sources that may occur at a single-well crude oil battery and the methods that are used 

to assess these emissions are given below: 

(1) Combustion Equipment - Emissions from the use of combustion equipment (e.g., glycol 

reboilers, treaters and flares) are assessed as described in Section 9.6.2. 
70

(2) Venting - Venting emissions are attributed to the use of fuel gas to operate instrument 

controllers and chemical injection pumps, and to the venting of waste gas from glycol 

dehydrators. As a close approximation, it is assumed that fuel gas is used as the supply 

medium for all gas-operated devices (i.e., compressed air is unavailable). The number of 

controllers on site is determined based on the number of each major equipment type (e.g., 

separator, treater, dehydrator, compressor, etc.) and the number of controllers usually 

associated with each of these. If the natural gas is sour and to be conserved, it is assumed 

that there is one chemical injection pump in continuous operation to inject corrosion 

inhibitor into the natural gas pipeline. 

As a conservative estimate, gas-operated devices are assumed to be in continuous operation 

throughout the year. 

The volume of waste gas released by glycol dehydrators is determined as described in 

Section 9.6.2. The resultant amount is assumed to be vented, not flared. (As indicated in 

Item (1), it is presumed that dehydrators are used only in sweet applications.) 

(3) Equipment Leaks - The total number of potential leakage points is determined by applying 

a minimum equipment schedule to each single-well crude oil battery, and by making certain 

site-specific allowances for any additional equipment that may be in use. 

Batteries that are reporting natural gas deliveries are assumed to be conserving solution 

natural gas and, therefore, to have compression facilities. Further, if the battery is sweet and 

is conserving natural gas, it is assumed to have a glycol dehydrator on site to dry the natural 

gas. If it is sour and the natural gas is conserved, it is assumed that the natural gas gathering 

system is a heated type and that the line heaters are already taken into account in Section 

9.6.2. 

Crude oil batteries that are connected to a crude oil pipeline are assumed to have two treaters 

on site (one test treater and one production treater). All other crude oil batteries are assumed 

to typically have only separation and storage facilities (i.e., no oil treating facilities). In these 

cases the crude oil is treated at a suitable off-site location where a crude oil pipeline may be 

accessed (usually another battery). 

The number of single-well batteries that are connected to a crude oil pipeline is determined 

by cross-referencing the battery code listing with the pipeline attribute file (EUB, 2003e). 

The total production through these batteries is determined from the historical well 

production and injection file (EUB, 2003b). The ratio of crude oil transported from singlewell batteries by pipeline to that by surface (i.e., tanker trucks) is assumed to be the same for 

all other provinces. 

(4) Storage Tanks - The emissions from crude oil storage tanks are estimated in two parts. 

First, the amount of solution natural gas that is released when produced crude oil is 

brought to stock tank conditions is determined. Then, the amount of normal evaporation 

losses are estimated. The resultant volume of natural gas is assumed to be flared if it is 

sour, and vented if it is sweet. If the vapours are collected and flared then the thief hatch 
71

on the storage tanks is treated as a potential leakage point. An emission factor is used to 

estimate the amount of leakage, and the result is added to the total for leaking equipment 

components. 

Some sour water storage tanks may be connected to the flare system and may have fuel gas 

blanketing to prevent oxygen ingress. The thief hatches on these tanks are also potential 

leakage points. However, the number of such tanks and, consequently, the amount of 

emissions, is considered to be small. Thus, these additional leakage points are omitted for 

simplification purposes. 

The solution natural gas emissions are estimated by applying the Vasquez and Beggs 

correlation (see Section 7.2) to the volume of oil that is produced at each battery. The 

appropriate temperature and pressure used in the correlation is based on whether oil-treating 

facilities are used on site. 

The evaporation losses are estimated using empirical correlations published by American 

Petroleum Institute (API 1991). These correlations relate evaporation losses to tank size, 

type of tank, throughput and certain design, and environmental factors. 

The total number of crude oil storage tanks in use and the sizes of these are estimated based 

on the following assumptions: 

• Each battery has a minimum of four tanks: one pop tank, one water storage tank, one 

crude oil storage tank and one crude oil over-flow tank. 

• Batteries that have oil-treating facilities on site have one additional tank, an oil 

recycle tank. 

• The pop tank has a capacity of either 100 bbl or 400 bbl and is sized for a minimum 

of 24 hours of storage capacity up to the 400 bbl limit. (Batteries above this size tend 

to be manned continuously during the day and, thus, require less storage capacity.) 

• All other tanks are 400 bbl in size, or larger. 

• Batteries that are tied into crude oil pipelines have a minimum of 24 hours of 

production capacity; otherwise, the batteries have a minimum of 3 days of 

production capacity. 

• Standard tank sizes are used in all applications. According to a local tank 

manufacturer, the most common tank sizes for conventional oil production are 100, 

400, 750, 1000, 1500, and 2000 bbl. 

All crude oil storage tanks are assumed to be above-ground and have fixed roofs. The 

amount of throughput for each is estimated by prorating total crude oil production according 

to storage capacities. 

9.3.4 Satellite Light/Medium Crude Oil Batteries

A satellite crude oil battery is an intermediate production facility. It is located between a group of 

wells and a group (or central) crude oil battery, and, usually, it is inspected once per day. There are 

two separators and associated sets of metering equipment at each satellite battery. One train is used 
72

to compile proration data on the commingled effluent from all but one of the group of wells. The 

other is used to test the remaining well. A regular test is performed on each of the wells. 

After separation and measurement, the production is often recombined into a single flow line for 

shipment to the central battery. Sometimes, however, each phase is transported in a separate 

pipeline. In this case a dehydrator may be required for the gas pipeline. For simplicity, it is assumed 

there are no dehydrators at satellite batteries. 

Typically, there are no storage nor treatment facilities at satellite batteries, and no natural gas is 

flared. Consequently, the only sources of emissions are equipment leaks and the use of fuel gas to 

operate instrument controllers. The emissions from these sources are assessed as described in 

Section 9.3.3. It is assumed there are no chemical injection pumps. 

9.3.5 Group (or Central) Light/Medium Crude Oil Batteries

A group (or central) battery is the same as a single-well battery except that it receives production 

from more than one well and is usually much larger. Often, it is manned continuously during the 

day. The sources of emissions are the same as those for a single-well battery and they are evaluated 

as described in Section 9.3.3. 

9.4 Heavy Crude Oil From Cold Production

Crude oil is generally designated as heavy if it has a density of greater than, or equal to, 900 kg/m3

(or alternately expressed, an API gravity of less than, or equal to, 25o

). Crude oil with a density of 

greater than, or equal to, 1000 kg/m3

 (or alternately expressed, an API gravity of less than, or equal 

to, 10o

) is often termed bitumen. Heavy crude oil which is lighter than bitumen is often termed 

conventional heavy crude oil. 

Although it flows with greater difficulty than light or medium crude oil at normal temperature and 

pressure, conventional heavy crude oil is often produced using non-thermal (that is, “cold”) 

recovery techniques. Conventional heavy crude oil is produced in Canada primarily from wells in 

the Lloydminster and Lindbergh areas of east central Alberta and west central Saskatchewan. 

The Province of Alberta has delineated areas in northeastern Alberta (see Figure 1) and labelled 

them designated oil sands areas, wherein all non-natural gas and non-coal hydrocarbon resources 

are deemed to be “crude bitumen”. Most so deemed “crude bitumen” would qualify as bitumen and 

so requires the application of thermal recovery techniques to produce. However, some of this crude 

bitumen may be recovered by primary or secondary (i.e., non thermal) recovery techniques. This 

“crude bitumen” (produced using non-thermal recovery techniques) is often referred to as “cold 

bitumen”. 
73

Figure 1. Designated Oil Sands Areas of Alberta 
74

9.4.1 Cold Production Heavy Crude Oil Wells

There were 35 950 capable cold production heavy crude oil wells in Alberta and Saskatchewan 

in 2000 (determined from the well control data file [EUB, 2003c] and Saskatchewan Well 

Database [SIR, 2003d]). All of these wells require pumps to bring the crude oil to the surface. 

There are two potential sources of emissions associated with each type of well: 

(1) Venting – Cold production heavy crude oil wells are relatively shallow (typically 300 to 

900 m deep) and, thus, are characterized by low reservoir pressures (typically 4000 kPa or 

less). To achieve reasonable flow potential it is necessary to relieve natural gas pressure 

from the well bore (down-hole pressure of about 250 kPa is maintained). Appropriately, the 

wells usually are not equipped with a production packer (a device that isolates the annulus 

from the formation). This allows the well pressure to be controlled using the casing vent. 

The total amount of casing natural gas that is produced is estimated based on a moisture-free 

basis by applying typical gas-to-oil ratios (GORs) to the total amount of crude oil 

production. A number of sources of GOR data were used: 

 Data reported to EUB as part of production accounting for Alberta heavy crude oil 

and cold bitumen operations. 

 Company supplied GOR data for fields primarily in Saskatchewan. Producers in 

Saskatchewan often report casing gas venting as flared gas. As it is known that these 

types of facilities rarely flare gas unless it is sour, the reported flared gas volumes 

were disregarded (except for sour facilities). Over the past several years significant 

effort has been expended by the major heavy oil producers in Saskatchewan to better 

quantify the GORs from heavy oil fields. Since these data were determined to be 

more representative of actual casing gas venting than the values reported as flaring 

in 2000, the field level GOR values were used to estimate casing gas venting from 

Saskatchewan heavy oil wells. 

 Default GOR data for fields in Saskatchewan where no reported volumes where 

available. 

The default GOR for Saskatchewan data is 55.7 m3

/m3 and is based on the production 

weighted average of all company supplied and SIR reported data. The volume of casing 

natural gas vented is taken to be the reported vented volume or is calculated using the GOR 

described above and the disposition factors in Table 36. 

(2) Equipment Leaks - These emissions are estimated as described in Section 9.3.1 for light/ 

medium crude oil wells. 
75

Table 36. Summary of western Canadian heavy crude oil operating practices for the 

year 2000 (CAPP, 1999). 

Type Primary/Secondary 

Production (%) 

Vented 63.17 

Flared 18.68 

Casing Gas 

Conserved 18.15 

9.4.2 Cold Production Heavy Crude Oil Flow Lines

It is assumed that cold production heavy crude oil is typically moved by truck and that any 

emissions that may result from the use of pipelines are insignificant. Furthermore, it is assumed that 

volatile material in this crude oil is released in the storage tanks so there are no emissions associated 

with the loading and unloading of trucks. 

9.4.3 Cold Production Heavy Crude Oil Single-Well Batteries

At single-well batteries, the cold production heavy crude oil is stored in a heated tank located on 

site. Tank trucks are used to haul the heavy crude oil to a cleaning plant (central battery) where it is 

treated to remove sand and water. The water is disposed of by deep-well injection. The sand and 

tank bottoms are placed in ecology pits and the heavy crude oil is shipped to market, normally by 

pipeline. 

The sources of emissions at these batteries are: 

(1) Combustion Equipment - Emissions are attributed to the use of tank heaters. These 

emissions are assessed as described in Section 9.6.2.2. 

(2) Equipment Leaks - These emissions are assessed by applying published emission factors 

and typical equipment schedules to the total number of single-well batteries. 

(3) Storage Tanks - Each battery usually is equipped with a single storage tank (typically a 500 

or 750 bbl tank). The emissions from each tank are attributed to the release of solution 

natural gas. Evaporation losses are calculated using the API correlations (see Section 8.0) 

and appropriate physical properties for the produced oil. If crude oil property data were 

supplied by facility operator, they were used. Otherwise, default values from Table 22 in 

Section 7.3 were used. Solution natural gas emissions are estimated based on the flashing 

loss calculation method described in Section 7.2. 

9.4.4 Cold Production Heavy Crude Oil Satellite Batteries

The emissions from these facilities are attributed to equipment leaks and to the venting of casing 

natural gas. The use of incinerators to dispose of casing natural gas is assumed to be negligible. 
76

Heavy oil satellite batteries are functionally identical to light/medium oil satellite batteries. They are 

located between a group of wells or a well pad and a central battery or cleaning plant. They are 

comprised of a valve header to direct the flow from one well to the test train and the commingled 

flow to the group train. The well flow directed to the test train is typically changed daily either by 

manually switching valves on the inlet header or by means of an automatic multi-way valve. 

After separation and measurement, the production is often recombined into a single flow line for 

shipment to the central battery. Typically, there are no storage nor treatment facilities at satellite 

batteries, and no natural gas is flared. Consequently, the only sources of emissions are equipment 

leaks and the use of fuel gas to operate instrument controllers. The emissions from these sources are 

assessed as described in Section 9.3.3. It is assumed there are no chemical injection pumps. 

9.4.5 Cold Production Heavy Crude Oil Central Batteries (Cleaning Plants)

A cleaning plant is a group heavy crude oil battery that is equipped with facilities for removing sand 

and water from the heavy oil. The typical process flow is as follows: 

• The combined (oil, gas and water) from the single well or satellite batteries enters the 

facility via pipeline or is trucked by tanker. Any production that is trucked in will consist of 

predominantly oil and water; most of the solution gas will have evolved upstream of this 

point. 

• The production is pumped into a free-water knock-out which is usually heated. Here the 

majority of produced water and most of the remaining solution gas are separated. Depending 

on the amount of solution gas present in the raw oil, the solution gas may be simply vented 

to the atmosphere. If it is not vented it may be either flared or conserved. 

• The oil phase usually still contains some water in emulsion. Therefore, it is passed through 

an emulsion treater where heat and residence time break the emulsion and separate out the 

remaining water. 

• The sales oil is then pumped into heated storage tanks and the produced water into water 

storage tanks. The oil is typically shipped to market via pipeline and the produced water is 

disposed of by underground injection. 

The emissions from these facilities are assessed as follows: 

(1) Combustion Equipment - The combustion equipment at a cleaning plant include emulsion 

treaters, tank heaters, glycol reboilers and flare systems. The emissions from these are 

assessed as described in Section 9.6.2.2. 

(2) Venting – Unless otherwise specified in the industry survey, it is assumed that all cleaning 

plants use compressed air to operate instrument controllers and chemical pumps. Thus, there 

are no venting emissions. 

(3) Equipment Leaks - These emissions are assessed by applying a typical equipment schedule 

and appropriate emission factors to the equipment located at cleaning plants. 
77

9.5 Heavy Crude Oil From Thermal Production

The production of heavy crude oil and bitumen using thermal recovery techniques occurs mainly in 

the Wolf Lake and Cold Lake areas of east central Alberta, in the Peace River area of northwest 

Alberta, and in west central Saskatchewan. 

A typical heavy crude oil thermal production scheme comprises many satellite batteries that feed 

into a large central cleaning facility. Each satellite is fed by a small cluster of pumping wells 

(typically 20 to 30) at a well pad. The casing gas is either vented/incinerated at each satellite or 

conserved using an electric-drive compressor. The conserved natural gas is sent to the cleaning 

facility by pipeline for use as fuel. Since the steam generation demands are very large, produced 

fuel gas usually needs to be supplemented with purchased fuel. The produced heavy crude oil is 

moved to a cleaning plant by pipeline where it is cleaned and then shipped, normally by pipeline, 

to a petroleum processing facility (upgrader or refinery). 

9.5.1 Thermal Production Heavy Crude Oil Wells

There are 2 584 thermal production heavy crude oil wells in Alberta and Saskatchewan (determined 

from the well control data file). Although, emissions from these wells are predominantly from 

equipment leaks, some locations may vent or flare the casing gas. The amount of emissions from 

fugitive equipment leaks is estimated as described in Section 9.3.1 for light/medium crude oil wells. 

The pumpjack on each well is usually driven by an electric motor; therefore, there are no direct 

combustion emissions. 

9.5.2 Crude Oil Flow Lines and Natural Gas Gathering Systems

The crude oil flow lines and the gathering systems that are used to conserve casing natural gas from 

some satellite batteries are primarily sources of equipment leaks. However, virtually all the pertinent 

equipment components are located at the ends of the pipelines. Therefore, these components are 

treated as part of the satellite batteries and cleaning plants. The resulting emissions are accounted 

for in Sections 9.5.4 and 9.5.5, respectively. 

9.5.3 Thermal Production Heavy Crude Oil Satellite Batteries

Satellite batteries are the type most often used in thermal recovery schemes. In addition to providing 

test separation facilities for production accounting purposes, each satellite serves as a control point 

for selectively cycling wells between injection and production cycles. This is done using an 

elaborate valving system. Up to 30 wells are tied into each satellite battery. Each well is connected 

to the satellite battery by a flow line and a steam line. A steam line, fuel gas line and flow line 

connect the satellite to a central cleaning plant where the oil is cleaned, steam is generated and 

natural gas is dehydrated for fuel. Since production for thermal operations is aggregated to the main 

cleaning plant, emissions from the satellites have been accounted for at that level (see Section 

9.5.4). 
78

9.5.4 Thermal Production Heavy Crude Oil Cleaning Plants

As with cold heavy oil production, thermal cleaning plants have oil, gas and water separation 

equipment, emulsion treating, oil and water storage, water disposal and oil shipping equipment. 

However, most of the emissions at thermal heavy oil cleaning plants result from the generation of 

the steam used in the thermal recovery of the oil by natural gas fired steam generators. The 

emissions are attributed to: 

(1) Combustion Equipment – Since solution gas production from these operations is generally 

not sufficient to meet the fuel demands of the steam generators, supplemental fuel must be 

either purchased. In some cases, production from nearby shallow gas wells can be used for 

supplemental fuel. As purchased fuel is not reported in production data reported to the 

government, actual fuel use by the site was take from the industry survey. Emissions from 

the steam generators (and other combustion equipment that may be on site) are estimated by 

applying the equations described in Section 3. Since the produced fuel may contain 

significant CO2, actual fuel analyses wee used to estimate combustion CO2 emissions. 

(2) Venting – Unless the industry survey indicated otherwise, it was assumed that no process 

venting occurs at these facilities, and that compressed air is used to operate all gas-operated 

instruments and devices. 

(3) Equipment Leaks – These are assessed by assuming that each plant may be subdivided into 

one or more modules (or phases), and that the size of each module is the same for all plants. 

A typical equipment schedule and appropriate emission factors are then applied to the total 

number of modules. 

(4) Storage Tanks – Unless the operator indicated otherwise in the industry survey, it is 

assumed that all storage tanks have vapour collection systems and that the collected gas is 

flared. Also, it is assumed that some leakage occurs around the thief hatch on each tank. The 

amount of leakage is estimated as described in Section 9.5.3 for storage tanks at thermal 

heavy oil batteries. The total number of tanks is determined based on a typical equipment 

schedule for a single module. 

(5) Surface Impoundments – Ecology pits are used to store sedimentary material that has been 

removed from the oil and some facilities. The material in these pits is relatively nonvolatile. 

Thus, negligible emissions are considered to occur. 

9.6 Natural Gas Production

Natural gas production comes from natural gas wells, as well as light/medium crude oil, and heavy 

crude oil production units with natural gas conservation schemes. 

9.6.1 Natural Gas Wells

Natural gas wells are primarily sources of fugitive emissions due to leaking seals and fittings on the 

well head. Additional sources are introduced if pumpjacks are used on the well (i.e., leaking pump 
79

seals and combustion emissions where a gas-driven engine is used to drive the pumpjack). 

However, the use of pumpjacks on natural gas wells is rare and, so, is assumed not to occur. 

The amount of fugitive emissions from each wellhead is estimated by applying appropriate emission 

factors (see Section 7.1) to a typical schedule of equipment components. Two different schedules 

are provided in Volume 5 of this report: one for shallow wells and one for high pressure natural gas 

wells (the latter type typically comprising more equipment components). To be consistent with the 

reporting procedures used by EUB in Alberta, each producing zone is treated as a separate well. 

The numbers of sweet, sour and shallow natural gas wells in each province is presented in Table 37. 

The sweet or sour status of a well was determined by linking the available well databases to 

databases of the available gas analyses by pool. Again, shallow natural gas wells were identified as 

natural gas wells with a total depth of less than 1000 metres. 

In British Columbia, 62.3 percent of natural gas wells are high pressure sweet, 29.0 percent are high 

pressure sweet and 8.7 percent are shallow natural gas wells. 

In Alberta, there were a total of 66 347 capable natural gas wells in 2000. Of these, 36.4 percent are 

high pressure sweet, 2.8 percent are high pressure sour and the remaining 60.8 percent are shallow 

gas wells. 

For Saskatchewan, 78.5 percent are shallow and 21.5 percent are high pressure sweet. 

9.6.2 Natural Gas Gathering Systems

There are basically three types of natural gas gathering systems used: low-pressure, heated and 

dehydrated. Natural gas may also be conserved and gathered from light and medium crude oil 

production facilities, cold heavy crude oil production facilities and thermal crude oil operations. The 

data for these types of facilities are presented in Table 38. A description of the types of natural gas 

gathering systems is presented in the sections that follow. 

9.6.2.1 Low-Pressure Gathering Systems

There is a substantial network of pipelines used to gather production from the low pressure 

natural gas wells described in Section 9.6.1. These systems are often operated at very low 

pressures (e.g., less than 525 kPa). As the natural gas is produced, some lines have a problem 

with water condensing and accumulating in low spots. Periodically, it becomes necessary to 

remove the water from these lines. On long sections of pipeline this is done by pigging (i.e., a 

specially-designed obstruction is placed in the line, and upstream natural gas pressure is used to 

push it and any liquid in front of it through to an appropriate discharge point). However, due to 

the low operating pressures of these pipelines, sometimes it is necessary to open the discharge 

end of the pipeline to atmosphere. This creates enough pressure differential to drive the pig.
80

Table 37. Summary of natural gas well counts presented by type of well and province 

or territory for the year 2000. 

Province or 

Territory 

High Pressure 

Sweet Wells 

High Pressure 

Sour Wells 

Low Pressure 

Shallow Wells 

Total 

Wells 

Yukon1 ---- 7 ---- 7 

Northwest Territories2 ---- 5 2 7 

British Columbia3 2 313 1 075 324 3 712 

Alberta4 24 144 1 865 40 338 66 347 

Saskatchewan5 5 756 ---- 21 007 26 763 

Ontario6 53 ---- 2 022 2 075 

Nova Scotia7 12 ---- ---- 12 

Newfoundland8 4 ---- ---- 4 

Total 32 282 2 952 63 693 98 907 

1 Northern Oil and Gas Report. Available at www.ainc-inac.gc.ca/oil 

2 Gas well counts adapted from B.C. OGC (2003a). 

3 Aggregate of values from EUB (2003b, 2003c). 

4 Adapted from SIR (2003d) by assuming all wells less than 1000 m deep are low-pressure shallow wells and all 

other wells are high-pressure sweet wells.

5 Oil Activity Review: 2000 (MEM, 2001).

6 Ontario Oil, Gas and Salt Resources Library. Ontario Digital Well Data. Available from www.ogsrlibrary.com

7 Canada Nova Scotia Offshore Petroleum Board. Weekly Status Report – Drilling Activity

www.cnsopb.ns.ca/activityreports 

8 Canada-Newfoundland Offshore Petroleum Board. Hibernia Development Wells. 

www.cnopb.nfnet.com/resource/product/hwells.htm

Table 38. Summary of natural gas gathering systems presented by province for the 

reference year 2000. 

Province or 

Territory 

Gathering 

System 

Compressor 

Station 

Single-Well 

Gas Batteries 

Group Gas 

Batteries 

Yukon Territory1 ---- ---- ---- 1 

British Columbia2 83 316 ---- ---- 

Alberta3 2 000 2 990 1 747 3 378 

Saskatchewan4 85 185 344 

Manitoba5 ---- ---- ---- ---- 

Ontario6 3 ---- 4 2 

Nova Scotia7 ---- ---- ---- 3 

Total 2 171 3 306 1 936 3 728 

1 Based on data from the operator. 

2 Based on system counts and infrastructure data from B.C. OGC (2003). 

3 Based on system counts and infrastructure data from EUB (2003i). 

4 Based on system counts and infrastructure data from SIR (2003a). 

5 Based on system counts and infrastructure data from MB IT&M (2003). 

6 Estimated based on data from ON Oil, Gas and Salt Resources Library (2003). 

7 Based on data from Canada Nova Scotia Offshore Petroleum Board (2003). 
81

On short sections of pipeline, water may be removed effectively by simply venting the pipeline 

briefly (about 10 seconds) to atmosphere through a storage tank. This is called "pulling back on the 

pipeline". 

Both approaches result in natural gas being vented to the atmosphere. Additionally, natural gas is 

vented to atmosphere when sections of pipeline are depressurized for repairs or to tie new wells into 

the system. To estimate the total amount of natural gas that is vented from low-pressure natural gas 

systems, it is assumed (based on data provided by one operating company) that: 

 The described venting activities are limited to low-pressure natural gas gathering systems. 

 About 43 m of 88.9 mm diameter pipe with an average pressure of 525 kPa is vented to 

atmosphere per year per well due to pigging operations, pipeline tie-ins and repair work. 

 About 0.1 pull-backs are performed per month per well and each results in the release of 

approximately 0.6 m3

 of natural gas. 

The total number of shallow natural gas wells is determined as described in Section 9.6.1. 

As a close approximation, it is assumed there are no dehydrators or line heaters on low-pressure 

natural gas gathering systems. Any dehydration that is required to meet market specifications is 

done at natural gas batteries (see Section 9.6.4). 

9.6.2.2 Heated Gathering Systems

Hydrate control is an important consideration in the design of high-pressure natural gas gathering 

systems. Hydrates are solid crystalline ice-like structures composed of water and hydrocarbon 

molecules that can form in pipelines and stop the flow. There are two main designs that are used: 

heated and dehydrated systems. The latter type is addressed in Section 9.6.2.3. 

Heated natural gas gathering systems guard against the formation of hydrates by maintaining the 

natural gas temperature above some critical value. This critical value is dependent on the 

composition and pressure of the natural gas; consequently, it varies from one system to the next. 

The emissions from heated systems are assessed as follows: 

(1) Combustion Equipment – Combustion emissions result from fuel consumption by line 

heaters and certain flaring activities. These emissions are estimated at the facility level using 

appropriate emission factors, and fuel consumption and flaring statistics. In doing this, the 

fuel data are first corrected to exclude the total amount of fuel gas used by pressureactivated devices. The resulting fuel volume is prorated using disposition factors derived 

from fuel consumption data supplied by ten major gas producers. These data are used to 

determine the amounts used by boilers, reciprocating engines and turbine engines (see 

Section 3). Also, the flaring data are corrected to exclude the amount of natural gas that is 

vented, not flared. 
82

(2) Venting – Venting may be attributed to pigging operations and the use of fuel gas as the 

supply medium for gas-operated devices (e.g., instrument controllers and chemical injection 

pumps). The only emissions that result from pigging a high-pressure natural gas pipeline 

occur when the launch and receiver chambers are opened for insertion/removal of the pig. 

(Each type of chamber is about 1 m long and 5 cm larger in diameter than the pipeline). 

Unlike low pressure systems, the liquids that are cleared from the pipeline by pigging are 

captured using a separator, and the natural gas is conserved. Typically, one launcher is 

located on each trunk line and a single receiver is located at the plant. The amount of natural 

gas that is released from opening the launchers and receiver may be determined based on the 

operating pressure of the system, the volume of each canister, the number of canisters and 

the frequency of the pigging operation. A survey of about a third of the plants indicated that 

only 40 percent of all systems (sweet and sour) are pigged. For these, the pigging frequency 

varies from once per week to once per year. The average frequency is from four to six times 

per year. Based on these low percentages and the small volume of emissions that results for 

each occurrence, total emissions from pigging of high-pressure natural gas pipelines are 

considered to be insignificant and, so, are disregarded for simplification purposes. 

Chemical injection pumps (small gas-operated plunger pumps) are a source of emissions if 

the supply gas is vented to atmosphere after use, and fuel gas is the medium that is used. 

Fuel gas is used only if compressed air is not available. On sour systems, it is common 

practice to inject a corrosion inhibitor at each line heater and field installation to help protect 

the pipeline. Also, facilities may be provided for injecting methanol to help prevent hydrates 

from forming during start-ups. 

The total amount of gas vented by chemical injection pumps is estimated by applying an 

appropriate emission factor (see Section 6.3) to the total number of pumps in active service. 

In doing this it is assumed that: 

 Corrosion inhibitor is injected at every line heater. 

 Compressed air is unavailable and fuel gas is used as the supply medium. 

 Methanol injection only occurs during start-ups and these occasions are too brief and 

infrequent for the associated emissions to be significant. 

(Note: some pumps are powered by electricity and in some applications methanol is injected 

on a continuous basis.) 

The resultant volume of vented natural gas is corrected to account for the amount of time the 

pumps are in operation. It is assumed that the pumps are only operating when the natural gas 

processing plants are on stream. This approach may be conservative since not all wells are 

necessarily operated when the associated plants are operated. From the monthly natural gas 

processing plant production statistics for Alberta EUB, 2000c,d), it is estimated that the 

average plant was processing natural gas about 95 percent of the time. 

The amount of natural gas that is vented from instrument controllers is estimated in the same 

manner as described for chemical injection pumps. However, it is assumed there is only one 
83

controller associated with each line heater. This controller is used to operate a pressure 

control valve (choke). 

In some applications low-bleed or no-bleed instrument controllers have been installed. 

However, based on a limited survey of operators and manufacturers, the use of these 

controllers is not common. Experience has been that they are costly, less rugged and more 

maintenance intensive that normal-bleed instruments, and can be problematic, particularly in 

field applications where a reliable high-quality supply of instrument gas may not be assured. 

At least one major instrument vendor has discontinued supply of low-bleed controllers for 

these reasons. 

(3) Equipment Leaks – The emissions from leaking equipment components are determined by 

applying emission factors to a schedule of equipment components for a typical line heater. 

The results then are applied to an estimate of the total number of line heaters used on heated 

systems. The total population of line heaters is estimated by assuming that heated natural 

gas gathering systems are only used if the natural gas is sour, and that all sour natural gas 

systems are heated. This is not strictly true but is considered to be a good approximation. 

Also, it is assumed (based on data from one operator) that about 50 percent of the wells that 

are tied into sour natural gas gathering systems have a line heater. 

9.6.2.3 Dehydrated Gathering Systems

This type of gathering system prevents the formation of hydrates by removing water vapour from 

the process natural gas. There are several different dehydration technologies that are used: 

absorption using diethylene or triethylene glycol; adsorption using solid desiccants such as activated 

alumina, gels, or molecular sieve; and the chem-sorption process using calcium chloride. The 

glycol-based absorption process is the most widely used. 

For simplification purposes, it is assumed that glycol dehydrators are used on all dehydrated natural 

gas gathering systems. The location and number of dehydrators is determined in part from results of 

CAPP’s annual dehydrator survey. Further, it is assumed (based on data provided by one operator) 

that a dehydrator is located at 50 percent of the well sites connected to dehydrated gathering 

systems. The rest of the wells on these systems are assumed to either utilize other dehydration 

facilities on the system or not required dehydration. Accompanying each dehydrator is a separator to 

remove any free water and other liquids from the gas before dehydration. Liquids from the separator 

are assumed to be stored in an underground storage tank or a single fixed-roof storage tank (100 bbl 

storage capacity). At high-pressure well sites where a choke is required to reduce the gas pressure to 

pipeline conditions, a small line heater may be provided to prevent hydrates from forming across the 

choke. The dehydrator is located downstream of the choke. 

An inherent problem with glycol dehydrators is that in addition to absorbing water from the process 

gas, the glycol has a strong affinity for BTEX (benzene, toluene, ethylbenzene, and xylenes) and 

hydrogen sulphide. TEG has a stronger affinity than DEG for these compounds. When the glycol is 

regenerated the absorbed substances are released as a waste gas. Typically, the waste gas is vented 

to the atmosphere; however, the presence of even small amounts of H2S in the process gas can result 

in dangerous concentrations of H2S being released from the regenerator still column. Thus, the use 
84

of dehydrated systems is usually limited to sweet natural gas applications. If dehydrators are used 

where H2S is present, a flare or incinerator often is used to dispose of the waste gas. 

Glycol dehydrators are targeted by a government initiative to reduce atmospheric emissions of 

benzene (a toxic compound as defined by the Canadian Environmental Protection Act). EUB has 

issued specific source performance standards for glycol dehydrators (EUB Information Letter IL2001-07). As well, CAPP currently maintains an inventory of glycol dehydrators and their 

associated benzene emissions. 

To determine the location of the dehydrators not identified in the CAPP inventory, some 

assumptions are required. As a close approximation, it is assumed that dehydrated gathering 

systems comprise all sweet high-pressure natural gas gathering systems and virtually no lowpressure (as defined in Section 9.6.2.1) or sour natural gas gathering systems. The sources of 

emissions on each dehydrated system, and the methods and assumptions used to estimate these 

emissions are listed below. 

(1) Fuel Consumption – Fuel is consumed by both the line heaters and the glycol reboilers 

where these are used. The resulting emissions are estimated based on proration of actual 

reported fuel consumption and application of published emission factors (see Section 3.0). 

(2) Venting – Emissions are attributed to the use of fuel gas to operate pressure-activated 

devices (e.g., instrument controllers and chemical injection pumps), to the venting of waste 

gas from the dehydrator and to the depressurization of pipeline segments for repair/tie-in 

purposes. The emissions from the first source are estimated by applying appropriate 

emission factors and a typical schedule of gas-operated devices to the total number of 

dehydrators. The resultant value is corrected to reflect the actual amount of operating time as 

described in Section 9.6.2.2. 

Glycol dehydrators include both conventional systems that utilize an absorption tower or 

contactor, and systems that inject glycol into the pipeline to provide hydrate control in 

refrigeration plants. In both cases, the glycol is recovered and regenerated which ultimately 

results in still-column off-gas emissions. All still-column off-gas from the dehydrators is 

assumed to be vented, not flared. The amount of hydrocarbons released is estimated by 

applying an emission factor (see Section 6.4) to the natural gas throughput of the system. 

All field dehydration units are assumed to use energy exchange glycol pumps (e.g., Kimraystyle pumps) to pump lean glycol from the reboiler back to the absorber column. 

Accordingly, a glycol pump gas consumption factor is also applied to the total throughput. 

Dehydrators located at plants or at larger production facilities tend to use electric-drive 

glycol pumps which have no associated gas venting. Some facilities also may use gas-drive 

pumps; however, these have high gas consumption/venting rates and therefore are usually 

avoided. 

When a new well is connected to an existing gathering system it is preferable to do so at a 

location where valving may be used to isolate the tie-in point. If such a location does not 

exist or is too far away, it is necessary to cut into the pipeline. This may be done using a hot 
85

tap procedure (a method of some risk that allows a tie-in to be performed while the line is 

under pressure). Often, however, the target line is isolated and depressurized to allow a cutout to be performed. It is estimated by one major operating company that, on average, some 

4 000 m3

 of natural gas is released each time part of a gathering system is depressurized. 

This is equivalent to depressurizing about 3 km of 168.3 mm diameter pipeline that has an 

initial pressure of 7 000 kPa. For sweet gathering systems, it is assumed that the released 

volume of gas is usually vented. For sour gathering systems, it is assumed that it is flared. 

As a first order approximation, it is assumed that one tie-in is required for each sweet natural 

gas well drilled in 2000. This is conservative since sometimes multiple wells may be tied 

into a system at once, thus, requiring only a single depressurization event, and some wells 

may be tied directly into a new facility without the need for a depressurization event. 

(3) Equipment Leaks – These emissions are evaluated as described in Section 9.6.2.2. 

(4) Storage Tanks – The emissions from storage of condensate at various points along the 

gathering system (e.g., at well sites and compressor stations) are accounted for at the 

location the condensate is reported in the production accounting data. This is usually at 

the gas gathering system level or at a gas battery (see Section 9.6.3). 

9.6.2.4 Other Gathering System Field Installations

In addition to line heaters and dehydrators, there are some other types of field installations that may 

occur on natural gas gathering systems. These include injection stations (i.e., gas reinjection 

facilities), meter/regulator stations, meter stations and regulator stations. Information on the types 

and numbers of these facilities is available for British Columbia, Alberta and Saskatchewan (B.C. 

OGC 2003, EUB 2003i, SIR 2003a). For all other provinces the number and types of field facilities 

is negligible. Table 39 provides a summary of the types and numbers of natural gas production field 

facilities. 

Table 39. Summary of natural gas production field facilities presented by province/ 

territory for the reference year 2000. 

Province or 

Territory 

Injection 

Plants 

Meter/Reg 

Stations 

Meter 

Stations 

Regulator 

Stations 

British Columbia1 2 ---- 111 ---- 

Alberta2 897 431 1 722 4 745 

Saskatchewan3 6 ---- 339 ---- 

Total 905 431 2 172 4 745 

1 Facility counts from B.C. OGC (2003b). 

2 Facility counts from EUB (2003f). 

3 Facility counts from SIR (2003a). 
86

The emissions from the identified field facilities are assessed as follows: 

(1) Venting – Venting may result from the use of fuel gas to operate pressure-activated devices 

(chemical injection pumps and instrument controllers), depressurization and purging 

activities, and start-up of compressors. 

The total amount of gas that is vented from pressure-activated devices is estimated by 

applying appropriate emission factors and a typical schedule of gas operated devices to each 

facility. The resultant value is corrected to account for the amount of time that the facilities 

are operating (see Section 9.6.2.2). Fuel gas is assumed to be used as the supply medium at 

all field facilities. Conservation of the vented gas or disposal by flaring or incineration is 

assumed to be negligible. 

Not all field facilities have flare systems. When the equipment at these facilities must be 

depressurized for repair/maintenance work, a temporary flare system may be employed. 

Frequently, however, the gas is simply vented to atmosphere. There was not enough 

information available to assess the amount of gas that is discharged in this manner. Those 

volumes that are flared are assumed to have been measured and taken into account in the 

reported flaring statistics. 

(2) Equipment Leaks – Each type of installation is considered to be a source of equipment 

leaks. The emissions from these are estimated based on typical equipment schedules and 

average emission factors. 

(3) Storage Tanks – Some compressor stations will have a tank for storing liquids from the 

suction and interstage scrubbers. For simplicity, it is assumed that these liquids are produced 

into tanks at the natural gas processing plants and that the emissions may be adequately 

accounted for at that level. 

9.6.3 Natural Gas Batteries

A natural gas battery is a production unit that is used when natural gas processing is not required. 

Only compression and treating (e.g., dehydration or sweetening) may be needed to upgrade raw 

natural gas to market specifications. Typically, this type of natural gas comes from low-pressure, 

shallow natural gas wells. It is characterized by low concentrations of non-methane hydrocarbons 

and is called "dry gas." 

The basic functions of a natural gas battery are to separate the effluent from one or more natural gas 

wells into natural gas and water, measure the flow rate of each of these phases from each well, and 

provide any treating and compression that may be required. The water then is disposed of and the 

marketable natural gas is sent to market. 

The number of single-well and group batteries in each province is presented in Table 38. Each of 

these is assumed to comprise separation, metering, dehydration, compression and water storage 

facilities. Data regarding the numbers of single-well and group natural gas batteries and the 

associated equipment located at them is available for British Columbia (B.C. OGC, 2003), Alberta 
87

(EUB, 2003f), and Saskatchewan (SIR, 2003a, b). Other data sources and assumptions are 

delineated below. 

 For Alberta, an average number of compressor units per single-well or group battery is 

determined from information supplied by operators. These averages are applied to the total 

number of each type of battery identified in the Battery Code Listing (EUB, 2003f). 

 The number of dehydration units at natural gas batteries was determined by crossreferencing CAPP’s dehydrator database with facility locations. Natural gas batteries that 

could not be located in the CAPP dehydrator database were still assumed to have a 

dehydrator. This may tend to over-estimate the actual number of dehydrators in use and is a 

conservative assumption. 

 In Yukon, Northwest Territories and Ontario all natural gas is assumed to be dehydrated at 

central natural gas processing facilities. 

The emissions from natural gas batteries are assessed as follows: 

(1) Combustion Equipment – Combustion emissions are evaluated as described in Section 

9.6.2.2. 

(2) Venting – Venting is attributed to the use of fuel gas to operate instrument controllers 

and compressor starters. These emissions are assessed using emission factors and typical 

instrument schedules. 

(3) Equipment Leaks – These are estimated by applying appropriate emission factors and 

typical equipment schedules to each battery. 

(4) Storage Tanks – The results of a process simulation indicate that virtually no hydrocarbons 

are released as solution gas from the water storage tanks, even for high pressures in the 

separator. Some emissions may occur due to the entrainment of hydrocarbon liquids and gas 

bubbles in the water; however, these emissions are assumed to be small. Water storage tanks 

are more important as a source of H2S emissions in sour applications. 

9.7 Natural Gas Processing

A natural gas processing plant is a facility for extracting condensable hydrocarbons from natural 

gas, and for upgrading the quality of the natural gas to market specifications (i.e., removing 

contaminants such as H2O, H2S and CO2). Some compression may also be required. Each facility 

may comprise a variety of treatment and extraction processes, and for each of these there is often a 

range of technologies that may be used. 

There are basically five types of natural gas processing facilities: sweet plants, sour plants that flare 

acid gas, sour plants that re-inject acid gas, sour plants that extract the elemental sulphur from acid 

gas, and straddle plants. The first four types are fed by natural gas gathering systems and prepare 

natural gas for transmission to market. The last type is located on major natural gas transmission 
88

lines and is used to extract residual ethane and heavier hydrocarbons from the natural gas in the 

pipeline. 

Gas processing plants are designated as sweet when the raw inlet gas to the plant contains less than 

0.01 mole/kmole (10 ppm on a volume basis) of H2S. Conversely, gas processing plants are 

designated as sour when the H2S concentration in the inlet gas contains greater than 0.01 

mole/kmole. Sour plants are further classified by how they handle the acid gas stripped from the raw 

inlet gas. The simplest method of acid gas disposal is by flaring. Acid gas flaring plants are limited 

by regulations on the SO2 emissions that arise from combustion of the acid gas. When the acid gas 

volume (and H2S concentration) is sufficient to preclude acid gas flaring, two options are left; the 

plant may inject the acid gas (predominantly CO2 and H2S) into a suitable reservoir or it may 

operate a sulphur recovery unit to produce elemental sulphur. When a sulphur recovery unit is used 

SO2 emissions are greatly reduced (by 70 to 99 percent depending on the total inlet sulphur rate) but 

the CO2 in the acid gas (formation CO2) is still released to the atmosphere through the tail gas 

incinerator stack. 

The emissions from each type of plant are attributed to: 

(1) Combustion Equipment – All combustion emissions are assessed at the individual 

facility level as described in Section 9.6.2.2. 

(2) Venting – Venting may result from the use of fuel gas to operate instrument controllers and 

chemical injection pumps, from the use of glycol dehydrators (i.e., venting of waste gas 

from the still column), and from purging activities during plant turnarounds and 

maintenance work. Formation CO2 stripped from the inlet gas at sour natural gas processing 

plants may also be vented. 

The total amount of gas that is vented from gas-operated devices is estimated by applying 

appropriate emission factors to a typical schedule of instrument controllers and chemical 

injection pumps to each process unit. The resultant value is corrected to account for the 

extent to which fuel gas is used as the supply medium. Information from the industry survey 

provided data on the use of air and natural gas for pneumatic devices and on the use of lowbleed and no-bleed devices. In the absence of company specific data all large and medium 

plants (design capacity of more than 0.7 Mm3

/d) use air for devices and all small plants 

(design capacity below 0.7 Mm3

/d) use fuel gas for this purpose. Overall, about 16 percent 

of gas processing plants use fuel gas to operate pneumatic instruments. 

In the absence of specific information, all plants that dehydrate gas are assumed to use 

glycol systems. The gas production is assumed to be dehydrated in the field for sweet plants 

(see Section 9.6.2.3) and at the plants for sour facilities. The emissions are estimated by 

applying calculated emission factors (see Section 6.3) to the relative amounts of production. 

All glycol dehydration units at gas processing plants are assumed to be equipped with a 

flash tank and electric glycol pumps. Therefore, these units are not sources of emissions 

from glycol pumps. 
89

When a process unit is depressurized for maintenance or repair work, the gas in the vessels 

and piping is normally flared. However, before any vessels are opened, the system usually is 

purged to remove any residual toxic or explosive gases. A similar procedure may be 

performed to remove air before the system is put back in service. Depending on the plant 

and the procedures that are used, the flame at the flare stack may be extinguished as a safety 

precaution during certain periods (e.g., when fuel gas is used to purge air from the system). 

This may result in some organic material being emitted. Unfortunately, there was not 

enough information available to assess these emissions. 

Formation CO2 emissions are estimated as described in Section 2.8. 

(3) Equipment Leaks – These are assessed based on the total number of plants and the types of 

process units that are used at each plant. A typical equipment schedule and appropriate 

emission factors are applied to each unit at each plant. The number of equipment 

components associated with a given type of unit is assumed to be constant and, thus, is 

independent of design capacity. (Usually, design capacity only impacts the size of the 

equipment components and not the number of components on a given process unit.) 

 The processes used at each natural gas processing plant were determined from: 

• Industry survey, 

• EUB and BC OGC databases, and 

• Canada’s Gas Plant Directory (1997). 

(4) Storage Tanks – These are used at natural gas processing plants to store produced water 

and pentanes-plus. The results of process simulations show that there are virtually no 

hydrocarbon emissions from the water tanks; however, significant emissions may occur 

from storage of pentanes-plus. These emissions are estimated using correlations published 

by API (1991) for evaporation losses from fixed-roof storage tanks. Pentanes-plus is a 

stabilized product so there are no solution gas emissions. To apply the correlations it is 

necessary to determine the amount of pentanes-plus produced at each plant, and the 

corresponding numbers and sizes of storage tanks that are used. The volumes of produced 

pentanes-plus are determined from the gas plant production statistics where data are 

available. The numbers and sizes of storage tanks are estimated by assuming: 

• Each plant has a minimum of two tanks (one shipping tank and one overflow tank). 

• The tanks are sized for a minimum of 24 hours of storage capacity (the design pentanesplus production rates specified in the Oilweek gas plant listing are used for this purpose). 

• Standard API tank sizes of 100, 400, 750, 1000, 1500, and 2000 bbl are used. 

(5) Surface Impoundments – Some plants have evaporation ponds where surface run-off, 

sludge and small amounts of produced water may be disposed of. The emissions that result 

from these activities are considered to be small and are not estimated. 
90

9.8 Natural Gas Transmission, Storage and Distribution

The natural gas transmission system conducts sales-quality natural gas from the producers (i.e., 

from gas batteries, gas processing plants and imports at the border) to market (i.e., gas 

distribution systems, the border for export, and direct sales to end customers). 

The storage facilities accommodate fluctuating differences between gas supply and demand 

rates. These facilities usually feature an underground cavern with multiple wells for injection/ 

removal of the gas. In addition, they include compressors to recompress stored gas when it is 

removed from the cavern, and dehydration facilities for removal of any moisture the gas may 

have picked up in the cavern. In some cases the re-produced natural gas may also contain natural 

gas liquids that must be extracted prior to re-introduction of the gas into the transmission system. 

There are also some storage facilities in Canada where natural gas is liquefied and stored in 

spherical vessels. These types of storage facilities are normally located near the start of gas 

distribution systems. They feature a liquefaction plant at the inlet to the storage vessels and a 

vapourizer and compression at the outlet to the vessels.Natural gas transmission systems transport 

processed natural gas to market. 

The emission estimates for gas transmission, storage and distribution presented in this report were 

prepared for CGA by ICF Consulting Canada Inc. Refer to ICF 2003 for a description of the 

methodology used to prepare these estimates. 

9.9 Petroleum Liquids Transportation

This category addresses emissions from the use of pipelines and tanker vehicles to move crude oil, 

natural gas liquids (NGLs) and liquified petroleum gas (LPG). The associated emissions in the 

present inventory are from the loading and unloading of tanker vehicles and from sampling 

activities. Emissions from transit losses may also occur but these have not been included here as 

there are no established procedures nor emission factors available for the products that are 

considered in this category. 

9.9.1 Crude Oil Transportation Systems

Crude oil pipeline facilities are regulated by both the National Energy Board, for inter-provincial 

pipelines, and provincial agencies (e.g., Alberta Energy and Utilities Board) for pipelines entirely 

within one province. The numbers and types of pipeline facilities (e.g., pipeline terminals, tank 

farms and pump stations) were determined from NEB and EUB data. Data regarding the types of 

equipment associated with the facilities were supplied by individual operators. Voluntary Challenge 

and Registry (VCR) reports were also used to supplement and update this information. For all other 

provinces, the Alberta data were used to estimate the numbers of pipeline facilities not associated 

with inter-provincial pipelines. 

The emissions from crude oil pipeline facilities are evaluated as described in Section 9.9.3 for LVP 

pipelines. 
91

9.9.2 Natural Gas Liquid / Liquified Petroleum Gas Systems

Three types of petroleum gases are marketed in liquefied form: ethane, propane, and butane. Each 

of these substances has a high vapour pressure (HVP) (6 000, 1 341, and 377 kPa, respectively at 

40o

 C); therefore, it must be stored and transported in pressurized vessels. NGLs/LPG are 

transported by road, rail and pipeline. 

Table 40 provides a summary of LPG production by province. Natural gas processing plants 

connected to LPG pipelines are assumed to be shipping LPGs by pipeline. Otherwise, rail or truck 

tankers are assumed to be used and loading/unloading emissions are included. These emissions are 

calculated as described below and have been attributed to the natural gas processing plant. 

Table 40. Summary of LPG production presented by province for 2000. 

Production (103 m3) 

Product British 

Columbia1 Alberta2 Saskatchewan3 Ontario3 Nova Scotia3

Ethane 0.00 14 469 0.00 0.00 0.00 

Propane 448.8 5 601 150.0 48.2 36.9 

Butanes 325.5 3 279.5 104.2 78.1 40.3 

1. Production of by-products at B.C. gas plants (BC OGC, 2003). 

2. Alberta gas plant liquids production (EUB ST-21). 

3. Product Disposition Summary Report. (NEB, 2003). 

9.9.2.1 Surface Transportation (Road and Rail)

Since LPG is contained in pressurized systems, there are no storage or transit losses. The emissions 

here result from equipment leaks, venting procedures and purging of equipment prior to performing 

service work. 

(1) Combustion Equipment – There are currently two facilities in Alberta where LPG rail cars 

are repaired and serviced: one in Edmonton and one in Red Deer. The operating procedures 

at each facility are quite similar. 

 Before any service work is performed on an LPG car, the vessel is drained of residual 

liquids, depressurized and subsequently purged using an inert material (e.g., nitrogen or 

steam). The liquids are recovered and later recycled. The waste vapours from the last two 

steps are flared/incinerated. Approximately 1100 LPG cars were processed in this manner in 

Alberta in 1989. It is estimated, based on information provided by the two repair yards, that 

the average initial pressure in each car is about 350 kPa (actual values range from 0 to about 

700 kPa), and the volumetric capacity of each car is about 130 m3

. Flaring emissions for 

2000 have been calculated by prorating 1989 results based on the volumes of LPG products 

transported by tanker. 

(2) Venting – Venting of LPG material may result from gauging activities during loading 

operations, and from depressurization of transfer hoses at the end of each loading or 
92

unloading operation. These activities are delineated below. The amount of emissions that 

occur is estimated by applying calculated emission factors (see Section 7.3) to the amount of 

each type of material that is moved by surface transportation. During loading operations, a 

gauging assembly is used to monitor the level of the liquid product. This assembly 

comprises a graduated length of pipe (the gauge rod) that extends vertically into the rail 

car vessel. A clamping mechanism on the vessel may be adjusted to allow the gauge to be 

moved up or down. The rod has a 1/4" needle valve at the top which normally is kept 

closed (some valves may be fitted with a special orifice). During the filling operation, the 

gauge is adjusted to the desired fill level, and the valve is opened slightly (about 25 

percent). Initially, vapour product escapes through the valve. When liquid product begins 

to spew out, the tank is filled. Typically, 1 to 1.5 hours are required to load a rail car, and 

the gauge assembly is vented during this entire period. The amount of material that is 

vented is dependent on the vapour pressure of the product, friction losses in the gauge 

rod, and the flow coefficient for the open valve. 

 The hose that is used during product transfers is typically 3 m in length and has an inside 

diameter of about 5 cm. At the end of a loading operation it is usually filled with liquid 

product, and at the end of an unloading operation it is usually filled with vapour product. 

When the hose is disconnected the material inside the line is released to the atmosphere. At 

some plant locations the transfer lines may be depressurized to a flare system; however, this 

is assumed to be uncommon. 

(3) Equipment Leaks – There are no known emission factors available for estimating 

emissions due to equipment leaks on pressurized tanker vehicles. Transport Canada, in 

conjunction with CN Rail and CP Rail, has studied the problem of leaking rail car 

equipment. However, the data is of a qualitative nature and not suitable for determining the 

amount of emissions. Some qualitative data are given below. 

An unpublished study conducted by CN Rail identified 19 potential leakage points on 

LPG rail cars (Note: the visible leaks are denoted by an L): liquid eduction valve (L), 

vapour eduction valve (L), loading valve, thermometer well, gauging device assembly 

(L), heater coils, sampling line valve (L), safety valve (L), tank shell (L), manway cover 

bolts (L), manway cover gasket (L), safety vent (L), bottom outlet cap, bottom outlet 

gasket, bottom outlet valve, frangible disk, bottom outlet connections, unloading valve 

and other location (L). Over a four-year period (1984 to 1987) visible leaks were reported 

for ten of the categories. The most frequently-occurring leaks were from the liquid 

eduction valve, vapour eduction valve and gauging device assembly. 

9.9.2.2 High Vapour Pressure Pipelines

LPG products are transported underground by HVP pipelines. The emissions that result from 

operating these systems are evaluated as follows: 

(1) Combustion Equipment – Typically, the pumps used on these systems are driven by 

electric motors. Consequently, there are no combustion emissions. The use of fuel for spaceheating requirements is assumed to be negligible. 
93

(2) Venting – Before any work is performed that may require a line to be opened, all product is 

pigged from the affected segment using an inert material (e.g., N2). Therefore, no emissions 

occur when the line is opened. 

(3) Equipment Leaks – The pipeline attribute file is used to determine the total number and 

type of installations used on HVP pipelines in Alberta. For all other provinces, the number 

and type of facilities is estimated based on the Alberta data and total provincial LPG 

production. The emission factors for natural gas processing plants and typical equipment 

schedules are applied to these installations. 

9.9.3 Pentanes-Plus Systems

Pentanes-plus is a low-vapour-pressure (LVP) product that is produced primarily by gas processing 

plants. It may be stored and transported at atmospheric conditions. In Alberta, pentanes-plus is 

moved by both surface transportation and LVP pipelines. An analysis of plants that are connected to 

pentanes-plus pipelines (according to the pipeline attribute file) and the production of pentanes-plus 

by plant indicate that about 83 percent (6 187 (103

) m3) of the total amount produced in 2000 was 

moved by surface transportation and about 17 percent (1 306 (103

) m3) was moved by pipeline. The 

Alberta disposition was applied to pentanes-plus production in all other provinces. 

9.9.3.1 Surface Transportation 

Typically, this mode of transportation is used to move LVP material to LVP pipeline terminals 

where it is loaded into tanks and subsequently pumped into the pipeline for transport to market. The 

emissions that result from the surface transportation are attributed to loading and transit losses. 

Some emissions may be associated with the unloading of the material. These are either taken into 

account by the LVP pipeline system (see Section 7.3), or are assumed to be part of the downstream 

oil and gas industry; thus, they are excluded from this study. 

The loading and transit losses are estimated using emission factors published by U.S. 

Environmental Protection Agency (U.S. EPA) (1995a) for transport and marketing of petroleum 

liquids. In applying these factors it is assumed that all tank vehicles are filled by submerged loading 

(dedicated normal service). The factors are the same for both tank trucks and rail tank cars, so it is 

not necessary to assess the disposition of product by mode of surface transportation. 

9.9.3.2 Low Vapour Pressure Pipelines

Operating LVP pipelines is very similar to operating HVP pipelines, with the exception that LVP 

systems have storage tanks at each terminal. The emissions from all sources, except from storage 

tanks, are assessed as described in Section 7.3. The emissions from storage tanks are estimated 

using empirical correlations published by API (1991, 1990 and 1994). Data on the types 

(floating-roof or fixed-roof), design, number of tanks at each terminal, and volume of material 

handled by the tanks were provided by several operators. These data are used to extrapolate to 

the rest of the system. 
94

9.10 Accidents and Equipment Failures

This section addresses emissions due to human error and extraordinary equipment failures (that is, it 

excludes leakage at connections, seals and packings). The emissions are classified by type of 

incident or failure: pipeline ruptures, well blow-outs, spills, surface casing vent flows and gas 

migration to the surface. 

9.10.1 Pipeline Ruptures, Well Blowouts and Spills

EUB produces a database containing information on oil and gas well blowouts, pipeline ruptures 

and spills in Alberta. Similar listings are also available for spills and pipeline ruptures in 

Saskatchewan, Manitoba, British Columbia, Northwest Territories, Nova Scotia and Newfoundland. 

Pipeline ruptures, well blowouts and spills for the remaining provinces are assumed to be negligible. 

For pipeline ruptures and spills, both the total spill volume and volume recovered are reported. All 

unrecovered volumes of hydrocarbons are assumed to eventually enter the atmosphere. 

9.10.2 Surface-Casing Vent Flows

Surface casing is a steel liner used to protect the integrity of the well bore as the hole is being drilled 

and to prevent contamination of any aquifers that may be a source of potable water. It is installed 

during the initial stages of the drilling program and is cemented in place by pumping cement down 

the centre of the pipe and forcing it to return up around the outside wall. The depth to which the 

surface casing extends is determined by regulations and the geological conditions at the site (surface 

casing may not be required on some shallow wells). When the well is completed, the production 

casing is run down the centre of the surface casing and cemented in place in a similar manner. 

Current practice is to leave the surface open at the bottom. This allows any gas or other fluids that 

may flow out from the surrounding formation or up from below to flow into the casing annulus 

rather than migrate up around the outside of the surface casing and possibly contaminate aquifers 

above. To allow easy monitoring for leaks, a vent and pressure gauge are installed at the well head. 

If a vent flow occurs, the exact cause of the flow may be difficult to determine and the required 

repairs are often costly. The material emitted from a vent flow may consist of gas, oil, fresh water, 

salt water or drilling mud. Some vent flows eventually die out. In some cases the vent flow is 

produced, in others either it is vented/flared or the vent is blocked in and pressure is allowed to 

build-up in the casing. 

Only Alberta and British Columbia have readily accessible data regarding surface casing vent flows. 

Therefore, the average surface casing venting rate per capable well is assumed to be constant across 

Canada. The average rate per capable well is about 1 731 m3

/y or about 3.42 kg/d. 

Emissions are assumed to result only from the release of gas (all liquids are assumed to be collected 

and properly contained). Only flow rates for vents not being produced are counted. It is assumed 

that the resultant volume is vented, not flared. 
95

9.10.3 Gas Migration to the Surface

This emission source results from by the flow of gas around the outside of a well. The flow may 

be caused by a leak in the production string at some point below the surface casing, or by the 

migration of material from one or more of the gas bearing zones that were penetrated (e.g., a coal 

seam). The problem is most pronounced in the Lloydminster region of east central Alberta and 

west central Saskatchewan. Data compiled by EUB indicate that approximately 7.8 percent of 

heavy oil wells have gas migration problems. 

Husky Oil Operations conducted a series of 119 tests to measure gas migration from 34 wells in this 

area (Erno and Schmitz, 1996 and Schmitz et al., 1996). Based on the data presented in these 

papers, an average methane flow rate of 3.85 m3

/d per well has been determined. Emissions are 

calculated by applying the average emission factor to the total number of wells with identified gas 

migration problems. Since the number of wells with gas migration problems in Saskatchewan is not 

available, it is estimated as 7.8 percent of total capable heavy oil wells (i.e., the same fraction as for 

Alberta). 

9.11 Waste Oil Reclaiming and Disposal

Efforts by government and industry are underway to reduce the volumes of oily wastes being 

generated, and to recover as much of the oil or crude bitumen as possible. The types of wastes 

that may occur include tank bottoms, treater bottoms, scrapings from pigging operations, sludge 

from vessels, sludge from surface impoundments, drilling fluids, oil spill debris, and oily sand 

and sedimentary material. 

The emissions that result from the disposal of these wastes may be ascribed to four source 

categories: transportation contractors, waste reclaimers, land farms, and road oiling. Unfortunately, 

very little information exists on the amount or type of waste material that is disposed of. 

Consequently, the resulting emissions could not be assessed; however, they are likely small 

compared to those from other source-categories. 

The following sections delineate each source category and identify some relevant studies that have 

been conducted. 

9.11.1 Oilfield-Waste Transporters

Unpublished data compiled by Monenco Consultants Limited (provided by W.A. Siemieniuk, June 

21, 1990) indicate that there are 16 contractors that transport oilfield wastes. Some of these 

companies operate from more than one location. 

9.11.2 Waste-Oil Reclaimers

Waste-oil reclaiming facilities are regulated by EUB. According to EUB General Bulletin GB 95-

07, there are currently (as of 2003) 71 approved oilfield waste management facilities in Alberta. 

Due to the nature of the products generally handled by these facilities (i.e., low volatility waste and 

sludges), emissions from this sector are expected to be negligible. 
96

9.11.3 Land Treatment Facilities

Land treatment facilities dispose of oily wastes by biodegradation which is achieved through 

controlled application to designated land areas. However, a significant amount of the applied 

material and the degradation products that are formed may be released to the atmosphere through 

normal evaporation. A current concern in the United States is that the resulting emissions may 

contain high concentrations of volatile hazardous air contaminants. A study by Woodward-Clyde 

Consultants (1989) showed mass emissions of monoaromatic compounds (benzene, toluene, total 

xylene, and ethylbenzene) at one site to be 8 to 17 percent of the applied waste load. 

Alberta Environment has published a set of guidelines for land treatment of industrial wastes 

(AENV, 1988), and maintains design and operating data on land treatment facilities in Alberta. 

Unfortunately, this information is not currently in an easy-to-use format. Consequently, it is not 

clear how much waste is being disposed of in the Province by land treatment. Furthermore, detailed 

characterization data for these wastes are not readily available. 

9.11.4 Road Oiling

The application of heavy asphaltic oils to roads is an accepted treatment for suppressing dust and 

enhancing the road surfaces. It is done on both municipal roads and secondary highways. EUB, 

however, does not consider the substitution of oil-containing wastes in these applications to be an 

acceptable long-term waste-disposal strategy (Information Letters IL 85-16 and IL 95-04). As a 

result, only selected disposal programs of this type are approved. These programs are limited 

primarily to the use of waste crude bitumen and heavy oil. Table 41 provides a summary of the 

typical composition of the hydrocarbon content of these wastes. The characterization criteria for oily 

by-product material applied to roads are as follows (EUB IL 95-04): 

• No free water. 

• Oil shall have a density greater than 920 kg/m3. Material with less than five percent 

residual hydrocarbon is unacceptable as road mix. 

• pH ≥ 6. 

• Total salts (loading limits): Na ≤ 5 500 kg/ha 

Cl ≤ 7 000 kg/ha 

• Total metals (concentration in sample): Cd ≤ 3 mg/kg 

Pb ≤ 375 mg/kg 

Ni ≤ 150 mg/kg 

Cu ≤ 150 mg/kg 

Zn ≤ 600 mg/kg 

The amount of atmospheric emissions that may result from the disposal of wastes on roads has not 

been an issue. The primary concerns are related to the leaching of some waste materials (e.g., metals 

and salts) and to future reclamation problems where wastes are applied to lease sites. 
97

Table 41. Composition of the organic fraction of Lloydminster petroleum wastes1 

Concentration (weight %) Component Number of 

Samples Average Range 

Asphaltenes 

Resins 

Acids 

Bases 

Neutral Nitrogens 

Aromatics 

Aliphatics 

9 

7 

9 

7 

7 

7 

7 

15.0 

13.3 

1.8 

0.4 

16.5 

17.5 

36.6 

5 to 19 

9 to 25 

0.1 to 13 

0.4 to 1 

12 to 25 

11 to 23 

28 to 39 

1

 Varmen, M.L., and K.S. Ng. 1983. Potential Environmental Affects of Heavy Oil Waste Disposal: An 

Assessment of the Characteristics of Lloydminster Petroleum Wastes. Report of the Analysis and Toxicity 

Project Group to the Sask-Alta Waste Disposal Co-operative Technical Sub-Committee.
98

10.0 EXTRAPOLATION OF 2000 INVENTORY RESULTS TO THE PERIOD 1990 

TO 1999 

To ensure consistency of emission estimates throughout the period 1990 through 2000, the 2000 

inventory results have been used to estimate emissions for the 1990 through 1999 time period. 

Since the compilation of detailed emission inventories is far beyond the scope of this project, a 

less rigorous approach was selected. 

The 2000 inventory results have been grouped into several categories for which relatively 

accessible activity data could be collected. These activity data were compiled for each year for 

each province/territory and for Canada as a whole. Table 10.1 summarizes the emission 

categories and the activity data used to estimate emissions for that category. A summary of the 

compiled activity is provided in Table 10.2. 

The general equation used to estimate emissions from the 2000 inventory results is: 

2000

,

2000 ,

, , , ,

c p

y

c p

c p i

y

c p i A

A

E = E ×

where, 

y Ec, p,i = estimated emissions for category c, province p, compound i and year y

 (tonnes), 

2000 Ec, p,i = 2000 inventory emissions for category c, province p and compound i 

(tonnes), 

y Ac, p = activity factor for category c, province p and year y, and

2000 Ac, p = activity factor for category c, province p and year 2000. 

This equation is applied for each category, province, compound and year except for Nova Scotia. 

Since the UOG industry in Nova Scotia went from all oil production over the period 1992 

through 1999 to all gas production in 2000, the 2000 inventory data could not be used as the base 

year for estimating emissions of all other years. Instead, the 1995 inventory data (CAPP, 1999) 

were used to extrapolate over the period of 1990 to 1999. 

In cases where activity data were either not available or emissions from the particular source 

category were not expected to change with time, the activity values were set to 1. This 

effectively sets emissions equal to the 2000 value throughout the period 1990 to 1999. 
99

Table 10.1 Summary of emission categories and activity data categories. 

Emission Sector Category Emission Source Category Activity Data 

Accidents/Equipment Failures Spills, Ruptures, Blowouts Total mass of spills, ruptures 

and blowouts 

Accidents/Equipment Failures Surface Casing Vent Flows, 

Gas Migration 

Total number of capable wells 

Light/Medium Oil Production Fuel Combustion Fuel gas volume 

Light/Medium Oil Production Flaring Flared gas volume 

Light/Medium Oil Production Fugitive Equipment Leaks Light/medium oil production 

Light/Medium Oil Production Glycol Dehydrator Off-Gas Light/medium oil production 

Light/Medium Oil Production Loading/Unloading Losses Light/medium oil production 

Light/Medium Oil Production Reported Venting Light/medium oil production 

Light/Medium Oil Production Storage Losses Light/medium oil production 

Light/Medium Oil Production Unreported Venting Light/medium oil production 

Well Drilling Fuel Combustion Wells drilled 

Well Drilling Venting Wells drilled 

Gas Production Fuel Combustion Fuel gas volume 

Gas Production Flaring Flared gas volume 

Gas Production Fugitive Equipment Leaks Raw gas production 

Gas Production Glycol Dehydrator Off-Gas Raw gas production 

Gas Production Loading/Unloading Losses Raw gas production 

Gas Production Reported Venting Raw gas production 

Gas Production Storage Losses Raw gas production 

Gas Production Unreported Venting Raw gas production 

Gas Processing Fuel Combustion Fuel gas volume 

Gas Processing Flaring Flared gas volume 

Gas Processing Fugitive Equipment Leaks Raw gas production 

Gas Processing Glycol Dehydrator Off-Gas Raw gas production 

Gas Processing Loading/Unloading Losses Raw gas production 

Gas Processing Formation CO2 Raw gas production 

Gas Processing Reported Venting Raw gas production 

Gas Processing Storage Losses Raw gas production 

Gas Processing Unreported Venting Raw gas production 

Heavy Oil Cold Production Fuel Combustion Fuel gas volume 

Heavy Oil Cold Production Flaring Flared gas volume 

Heavy Oil Cold Production Fugitive Equipment Leaks Heavy oil production 

Heavy Oil Cold Production Glycol Dehydrator Off-Gas Heavy oil production 

Heavy Oil Cold Production Loading/Unloading Losses Heavy oil production 

Heavy Oil Cold Production Reported Venting Heavy oil production 

Heavy Oil Cold Production Storage Losses Heavy oil production 

Heavy Oil Cold Production Unreported Venting Heavy oil production 
100

Table 10.1 Summary of emission categories and activity data categories. 

Emission Sector Category Emission Source Category Activity Data 

Well Service Fuel Combustion, Flaring, 

Venting 

Wells drilled 

Heavy Oil/Bitumen Thermal 

Production 

Fuel Combustion Fuel gas volume 

Heavy Oil/Bitumen Thermal 

Production 

Flaring Flared gas volume 

Heavy Oil/Bitumen Thermal 

Production 

Fugitive Equipment Leaks Heavy oil and crude bitumen 

production 

Heavy Oil/Bitumen Thermal 

Production 

Loading/Unloading Losses Heavy oil and crude bitumen 

production 

Heavy Oil/Bitumen Thermal 

Production 

Reported Venting Heavy oil and crude bitumen 

production 

Heavy Oil/Bitumen Thermal 

Production 

Storage Losses Heavy oil and crude bitumen 

production 

Heavy Oil/Bitumen Thermal 

Production 

Unreported Venting Heavy oil and crude bitumen 

production 

Product Transportation Flaring Fuel gas volume 

Product Transportation Fugitive Equipment Leaks Light/medium, heavy oil and 

crude bitumen production 

Product Transportation Venting Light/medium, heavy oil and 

crude bitumen production 

Product Transportation Storage Losses Light/medium, heavy oil and 

crude bitumen production 

Well Testing Flaring Wells drilled 

Well Testing Venting Wells drilled 
101

Table 10.2 Summary of activity data used to estimate emissions for the time period 1990 to 1999. 

Province Year 

Gas 

Production 

(106 m3) 

Light/ 

Medium 

Oil 

Production 

(103 m3) 

Heavy Oil 

Production 

(103 m3) 

Crude 

Bitumen 

Production 

(103 m3) 

Fuel Gas 

(106 m3) 

Flared Gas 

(106 m3) 

Wells 

Drilled 

Spills + 

Ruptures + 

Blowouts 

Capabl

Wells 

AB 1989 117 205.40 45 557.00 9 367.40 7 482.80 7 492.70 2 228.90 4 462.00 3 138.25 72 321AB 1990 117 205.40 42 862.20 10 110.60 7 856.00 7 729.20 2 246.10 4 142.00 6 632.83 73 909AB 1991 121 676.10 40 898.60 11 190.90 7 113.30 7 727.60 2 301.40 3 483.00 2 358.26 75 375AB 1992 134 179.60 40 104.10 13 068.60 7 362.00 8 485.20 2 298.10 3 885.00 2 575.43 77 212AB 1993 145 788.20 42 115.40 12 432.10 7 685.10 9 322.70 2 337.50 6 622.00 6 081.82 80 968AB 1994 155 798.30 42 578.00 12 619.00 7 810.00 9 988.10 2 237.20 9 126.00 3 398.01 85 736AB 1995 162 098.00 41 282.20 14 112.80 8 629.70 10 411.00 2 341.80 8 481.00 5 818.38 89 640AB 1996 167 235.80 39 562.70 15 212.20 9 504.90 10 846.70 2 190.80 10 335.00 84 091.86 94 881AB 1997 168 094.00 37 315.80 15 502.60 13 805.90 12 327.30 2 200.90 13 225.00 19 805.39 102 453AB 1998 172 643.80 35 242.70 14 531.60 16 363.70 12 576.60 1 919.40 8 175.00 87 143.80 107 301AB 1999 175 279.40 31 332.20 14 209.40 14 171.10 13 152.00 1 683.90 9 444.00 19 805.76 112 770AB 2000 176 145.80 29 681.60 13 822.30 16 780.90 13 366.90 1 947.20 13 543.00 60 669.08 91 816

BC 1989 13 353.10 1 912.90 595.30 28.40 223.00 221.69 1 420BC 1990 12 748.60 1 912.90 889.30 98.10 285.00 123.02 1 436BC 1991 14 731.80 2 014.50 535.00 20.60 220.00 173.05 1 533BC 1992 16 197.10 2 032.80 346.20 63.20 171.00 125.20 1 578BC 1993 17 446.30 2 012.10 266.80 47.60 338.00 341.94 1 679BC 1994 19 189.60 1 986.90 863.80 164.70 525.00 221.69 1 750BC 1995 21 936.20 2 038.50 1 180.60 224.70 449.00 344.42 1 899BC 1996 22 434.60 2 235.50 1 250.10 288.50 504.00 221.69 2 035BC 1997 23 003.90 2 552.20 1 334.40 280.70 616.00 221.69 2 347BC 1998 24 296.40 2 763.70 1 603.30 235.10 683.00 221.69 2 573BC 1999 25 362.50 2 347.60 1 689.20 162.80 678.00 221.69 2 847BC 2000 25 362.50 2 552.30 1 749.50 154.80 846.00 221.69 3 310

MB 1989 722.842 722.842 722.84 722.84 52.00 1.00 1 581MB 1990 737.455 737.455 737.46 737.46 78.00 1.00 1 483MB 1991 712.792 712.792 712.79 712.79 54.00 1.00 1 567MB 1992 656.415 656.415 656.42 656.42 28.00 1.00 1 547MB 1993 634.561 634.561 634.56 634.56 87.00 1.00 1 563MB 1994 657.87 657.87 657.87 657.87 67.00 1.00 1 568MB 1995 642.65 642.65 642.65 642.65 43.00 1.00 1 556MB 1996 616.10 616.10 616.10 616.10 41.00 1.00 1 531MB 1997 636.70 636.70 636.70 636.70 109.00 1.00 1 535
102

Table 10.2 Summary of activity data used to estimate emissions for the time period 1990 to 1999. 

Province Year 

Gas 

Production 

(106 m3) 

Light/ 

Medium 

Oil 

Production 

(103 m3) 

Heavy Oil 

Production 

(103 m3) 

Crude 

Bitumen 

Production 

(103 m3) 

Fuel Gas 

(106 m3) 

Flared Gas 

(106 m3) 

Wells 

Drilled 

Spills + 

Ruptures + 

Blowouts 

Capabl

Wells 

MB 1998 634.10 634.10 634.10 634.10 49.00 1.00 1 509MB 1999 581.10 581.10 581.10 581.10 41.00 1.00 1 494MB 2000 624.30 624.30 624.30 624.30 76.00 1.00 1 516

NL 1990 NL 1991 NL 1992 NL 1993 NL 1994 NL 1995 NL 1996 NL 1997 NL 1998 904.10 3 783.80 79.80 810.00 1.00 12NL 1999 1 434.70 5 785.80 112.40 359.00 11.00 1.00 12NL 2000 2 393.40 8 394.30 137.70 93.10 13.00 1.00 12

NS 1989 NS 1990 NS 1991 NS 1992 581.59 0.00 0.00 1.00 1NS 1993 1 051.63 0.00 0.00 1.00 1NS 1994 1 313.42 0.00 0.00 1.00 1NS 1995 1 241.21 0.00 0.00 1.00 1NS 1996 1 065.50 0.00 0.00 1.00 1NS 1997 774.70 0.00 0.00 1.00 1NS 1998 955.10 0.00 0.00 1.00 1NS 1999 348.60 0.00 0.00 6.00 1.00 1NS 2000 3 597.20 0.00 79.90 12.70 22.00 1.00 1

NT 1989 225.86 1 832.20 1 832.20 29.711 10.00 1.00 1NT 1990 202.90 1 864.60 1 864.60 24.107 10.00 1.00 1NT 1991 221.00 1 926.20 1 926.20 25.836 10.00 1.00 1NT 1992 214.90 1 878.60 1 878.60 21.958 10.00 1.00 1NT 1993 234.20 1 846.40 1 846.40 23.403 10.00 1.00 1NT 1994 189.80 1 783.80 1 783.80 15.54 10.00 1.00 1NT 1995 195.40 1 775.10 1 775.10 15.488 10.00 1.00 1NT 1996 179.60 1 656.30 1 656.30 14.45 6.00 1.00 1NT 1997 169.50 1 599.90 1 599.90 1.60 13.00 1.00 1NT 1998 158.70 1 561.70 1 561.70 1.10 12.00 1.00 1
103

Table 10.2 Summary of activity data used to estimate emissions for the time period 1990 to 1999. 

Province Year 

Gas 

Production 

(106 m3) 

Light/ 

Medium 

Oil 

Production 

(103 m3) 

Heavy Oil 

Production 

(103 m3) 

Crude 

Bitumen 

Production 

(103 m3) 

Fuel Gas 

(106 m3) 

Flared Gas 

(106 m3) 

Wells 

Drilled 

Spills + 

Ruptures + 

Blowouts 

Capabl

Wells 

NT 1999 112.40 1 549.20 1 549.20 1.10 15.00 1.00 1NT 2000 754.20 1 434.20 1 434.20 2.90 16.00 1.00 1

ON 1989 492.50 247.20 492.50 492.50 50.00 1.00 1ON 1990 449.10 247.20 449.10 449.10 50.00 1.00 1ON 1991 428.40 235.00 428.40 428.40 50.00 1.00 1ON 1992 427.10 224.30 427.10 427.10 50.00 1.00 1ON 1993 411.20 253.40 411.20 411.20 50.00 1.00 1ON 1994 428.80 263.10 428.80 428.80 50.00 1.00 1ON 1995 456.30 285.40 456.30 456.30 50.00 1.00 1ON 1996 307.00 267.90 307.00 307.00 60.00 1.00 1ON 1997 269.00 220.60 269.00 269.00 77.00 1.00 1ON 1998 275.50 218.60 275.50 275.50 107.00 1.00 1ON 1999 421.70 238.30 421.70 421.70 81.00 1.00 1ON 2000 580.00 231.20 580.00 580.00 142.00 1.00 1

QB 1989 QB 1990 QB 1991 QB 1992 QB 1993 QB 1994 QB 1995 QB 1996 QB 2000 

SK 1989 6 155.8933 8 273.0852 3 422.5282 627.40 375.10 1 497.00 1.00 26 952SK 1990 6 938.9438 8 460.3715 3 793.0813 743.90 213.50 1 380.00 1.00 27 946SK 1991 7 319.923 8 548.5241 3 871.5596 792.60 229.20 1 133.00 1.00 28 960SK 1992 7 474.1172 8 771.5194 4 597.992 757.80 212.50 837.00 1.00 29 525SK 1993 7 666.7924 9 702.2838 5 271.0995 1 032.90 263.50 2 274.00 1.00 31 861SK 1994 8 519.4158 11 356.3973 5 847.2218 1 154.00 248.60 2 402.00 1.00 33 888SK 1995 8 714.8734 11 838.4515 6 907.6856 1 258.00 322.70 2 134.00 1.00 35 529SK 1996 7 912.10 13 129.20 7 653.70 1 124.8226 446.2258 2 601.00 1.00 38 045SK 1997 7 817.6031 13 646.4027 9 808.2609 1 197.4597 491.8893 4 055.00 1.00 41 186SK 1998 7 686.4265 13 774.4044 9 376.5101 1 172.7329 557.6111 1 744.00 1.00 42 425SK 1999 7 907.9499 12 360.6899 9 347.9914 1 236.1929 443.5041 2 522.00 1.00 44 741SK 2000 8 147.8192 12 657.285 11 585.3838 1 324.5739 446.665 3 839.00 1.00 48 136

YT 1989 
104

Table 10.2 Summary of activity data used to estimate emissions for the time period 1990 to 1999. 

Province Year 

Gas 

Production 

(106 m3) 

Light/ 

Medium 

Oil 

Production 

(103 m3) 

Heavy Oil 

Production 

(103 m3) 

Crude 

Bitumen 

Production 

(103 m3) 

Fuel Gas 

(106 m3) 

Flared Gas 

(106 m3) 

Wells 

Drilled 

Spills + 

Ruptures + 

Blowouts 

Capabl

Wells 

YT 1990 YT 1991 227.1855 34.0886 0.7293 227.1855 1.00 1YT 1992 506.9095 34.0886 0.7293 506.9095 1.00 1YT 1993 492.3659 31.4722 1.7121 492.3659 1.00 1YT 1994 471.1034 30.9634 1.1968 471.1034 1.00 1YT 1995 442.9721 30.7556 0.9722 442.9721 1.00 1YT 1996 427.465 29.0091 0.689 427.465 1.00 1YT 1997 404.50 30.40 1.20 404.50 1.00 1YT 1998 451.90 35.40 0.90 451.90 1.00 1YT 1999 628.70 35.30 0.50 628.70 1.00 1YT 2000 569.50 32.40 0.20 569.50 1.00 1
105

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