## 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

- 001 32100, 350

– 7 th 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 9 8 p er 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 membe rs are an important part of a $7 5

- 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 ri sk, 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 (H 2 

## S) 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 2004i 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 Cont ent 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 Actu al 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 34ii 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 UNI NTENTIONAL 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 A ssociated 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 Inve rt 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 68iii 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/Me dium 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 Cent ral 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 / Liquif ied 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 INVENT ORY RESULTS TO THE PERIOD 1990

TO 1999 98

11.0 REFERENCES CITED 105

11.1 Other Information Sources 111ivv 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 Mi nisters of the Environment

CGA - Canadian Gas Association

CH 4 - methane

CO 2 O - carbon dioxide form atmospheric oxidation

CO 2 E - carbon dioxide equivalent

CSA - Canadian Standards Association

EC - Environment Canada GHG - greenhouse gases

GRI - Gas Research Institute GTC - Gas Technology Canada

H 2 S - 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

N 2 O - nitrous oxide

NBS - National Bureau of Standards NMHC - non-methane hydrocarbon

NPRI - National Pollut ant Release Inventory

PM 2.5 - particulate matter ≤ 2.5 μm in aerodynamic diameter

PM 10 - particulate matter ≤ 10 μm in aerodynamic diameter POM - polycyclic organic matter ppm - parts per million SEPAC - Small Explorers and Pro ducers 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 compoundvi 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 m 2 = 10.7639 ft 2 1 ft 2 = 0.092903 m 2

Volume 1 m 3 = 35.3134 ft 3
1 L = 0.2641720 U.S. gal 1 ft 3 = 0.02837 m 3
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/m 3 = 0.06243 lbm/ft 3 1 lbm/ft 3 = 16.018 kg/m 3

Force 1 N = 0.2248 lb f 1 lb f = 4.4482 N

Mass 1 kg = 2.20462 lb

m 1 lb

m = 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/m 2 = 0.317 Btu/h·ft 2 1 Btu/h·ft 2 = 3.154 W/m 2

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/m 3 = 0.096623 Btu/h·ft 3 1 Btu/h·ft 3 = 10.35 W/m 3

Energy/Unit Mass 1 kJ/kg = 0.4299 Btu/lb

m 1 Btu/lb

m = 2.326 kJ/kg

Specific Heat 1 kJ/kgoC = 0.23884 Btu/lb

m oF 1 Btu/lb

m ·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/m 2 C = 0.1761 Btu/h·ft 2

· o oF 1 Btu/h·ft 2 ·oF = 5.6782 W/m 2 ·oC1 1.0 INTRODUCTION

This volume describes the methodology which ha s 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 us ed to develop quantitative estimates of the uncertainty in the inventory results,

• identify the sources of informati on used to compile the inventory,

• highlight the key assumptions us ed 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 c oncerning the initial planning and design of the inventory.

• Section 3 describes the a pproach taken for assessing emissions from combustion sources. The source types considered in clude: natural gas-fuelled compressor engines, process heaters and boilers, indus trial space heaters, flares and thermal

oxidizers.

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

• Sections 5 and 6 detail emissions related to venting of formation CO 2 and natural gas, respectively.

• Section 7 delineates the procedures for es timating emissions from fugitive sources, including equipment leaks, storage ta nks and tanker activiti es, and accidental releases, respectively.

• Section 8 presents the procedures us ed 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 descrip tion 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 result s and the actual activity data for each year and province/territory.

• Section 11 lists all referen ces 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 deve loped using a bottom-up approach, beginning with individual facilities and their equipmen t, and the following primary types of GHG

emissions sources:

• fuel combustion

• flaring,

• formation CO 2 , 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 a pplied to each facility and its equipment was determined on a case-by-case basis, with the objec tive being to obtain the most reliable estimate possible from the information available. The ba sic 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 repor t their atmospheric emissions of certain

substances. The use of actual emission mon itoring 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 dehydr ators and US EPA TANKS to predict evaporation losses from storage tanks. Thes e 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 pr edict 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 proce ss 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:

ER i = EF i × AR × (1 – CF i )3 where,

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

EF i = 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).

CF i = 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 sour ces have no special controls.

The use of emission factors is often an ove r simplification which may be subject to very high uncertainties (e.g., orders of ma gnitude) when applied to a single source, but becomes a statistically valid approach when considering aggregate emissions from large numbers of sources. The availabl e 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 polluta nt emission factors).

• Destruction and Removal Efficiencies (DREs) – The emissions of individual substances input to a combustion device ma y 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 com bustion) and/or removed by that device. This is done using a relation of the form:

DRE = (1 – ERi/IRi) x 100

where,

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

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

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

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

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

2.2 Units of Measure and Reference Conditions

In the general literature, emissi ons and source parameters may be expressed usi ng a wide range of units, formats, classifications and terminology. He rein, every effort has been made to maintain4 a consistent convention to allow convenient comparisons and aggreg ation of results, and to be consistent with applicable national an d international repo rting 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 expresse d in cubic metres at standard reference

conditions of 101.325 kPa and 15oC. The conversion ta ble 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 natura l gas” is used to indicate a natural gas containing 0.01 moles or more of H 2 S per kmole of total gas (i.e., 10 ppmv H 2 S) as defined by AEUB Guide 56. Petroleum liquid pr oduction 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 H 2 S). Substances

that contain less than these lim its are referred to as sweet.

2.3 Data Collection

Regardless of the techniques employed, a certain am ount of source and activit y data is needed to support the assessment effort. The key challenges in clude: 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 cons umed 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 faci lities provided by oil and gas pr oducers. A complete listing of the different government sources used for the di fferent oil and gas producing regions in Canada is provided in a Volume 5 of this report.5 Compilation of the required source data involved de veloping a detailed inve ntory 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, pi gging 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 inferre d 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 system s), typical design and ope rating 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 c onsistent or convenient format,

• reliable and accurate data entry,

• verification of database accu racies and completeness,

• development of special applica tions 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 indivi dual 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 pr imary tables within the database, a description of the type of data the table contains and the number of records in eac h table. In addition to these, there are a number of tables that contai n emission factors, equi pment schedules, control factors and lookup tables with definitions for codes used in the main tables.

As part of the deliverables for the project, a de tailed facility level database of GHG emissions was prepared. The database contai ns the fields listed in Table 2..

Notwithstanding this, some elements of the inventory work were done externally in spreadsheet applications and using other applic ations (for example, to pre-pro cess, 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 f acility (from provincial regulatory agencies) 421 917

Facilities name, facility type, sector a nd location for each facility (also contains facilities that are not currently active) 273 780

Sources a list of all sources lo cated at each facility 364 382 Speciation Profiles facility sp ecific composition data 321 145

Emission Detail emission results fo r 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, Fugi tive Equipment Leaks, Venting, etc. Emission Compound CO 2 , CH 4 , N 2 O, CO 2 E, CO 2 O, NMHC

Total Emissions Total emissions in tonnes Lower Uncertainty Aggregated uncertainty fo r the source expressed as a fraction of 1. Upper Uncertainty Aggregated uncertainty fo r 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 subject ed 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 draf t results were dissemina ted, 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 no minated by the study

sponsors.

Where possible, the results were compared to pr evious 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 inte rnal review conducted are:

• Confirmation that all useful sources of the required emission source, activity and emission factor data, calculation procedur es and test methods are identified and7 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 th eir emission and energy intensities to help identify

anomalies.

• Checks to ensure that point source contri butions 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 assi gned 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 corresp onding published totals where available.

• Manual checks of each type of calculati on 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 compar ed to facility throughputs.

2.6 Uncertainties

Uncertainties in inventor ies 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 va riability of the process that produces the emission,

• Uncertainties from the assessmen t of the process or quantity, including, depending on the method used: (i) uncertaint ies from measuring, (ii) uncer tainties from sampling, (iii) uncertainties from reference data that may be incompletely described, and (iv)

uncertainties from e xpert judgement.

For the purposes of this study, uncertainties fr om definitions are assumed to be adequately controlled through the applied QA/QC procedur es, and therefore, negligible. Quantitative uncertainty estimates to account fo r the later two contributions we re 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 uncertain ties 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 t ypically the product of an emission factor and a corresponding activity value. The overall uncertainty in the su m of the individual emission estimates is determined using the following relati on (this expression is ex act for uncorrelated or independent variables):8 

### ( )( ) 

### ( )

x x x x U x U x U U

n n n

total + + + • + + • + •

=

... ...

2 1 2 2

2 2 2

1 1 (1)

Where:



### U

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



### U x i

i 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 em ission factor and activity parameter using the following relation (this is approximate for all random variables):

2 2

2 2

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

Where the activity parameter for a source is c ontinuous (e.g., gas thro ughput 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 c ount or integer value (e.g., number of equipment components, number of stations, number of compre ssors, etc.), Equation 1 is used to evaluate the aggregate uncertainty for N sources of the same type and average stre ngth, and Equation 2 is used to

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

2.6.2 Determination of Primary Data Uncertainties

The uncertainties assigned to each type of activity data, emission f actor 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 applicab le, divide each factor or parameter into its constituent elements, then determine the uncertain ty 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 a ccounting techniques used

to determine the input quantity, and in any related extrapolations or in terpolations of these values.

When deriving uncertainty values from measuremen t data, a Student-t distribution is assumed for sample sizes of less than 30 and a normal dist ribution is assumed for larger sample sizes.9 The primary source of published uncertainty values is the report on meth ane losses from the US natural gas industry sponsored by US EPA/GRI (1996) . Additional uncertaint y values are taken from IPCC (2000).

Where suitable data or published values are una vailable, it is necessary to use professional judgement and solicit inform al input from applicable experts to provide uncertainty values. The application of formal protocols for expert elicitatio n is beyond the scope of this work. Rather, values are estimated by the project team and through info rmation discussions industry experts. The formal review of this document by the Project Steering Committee and other external reviewers is deemed to provide a reasonable mech anism 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 correlate d. This is not consistent with the assumptions inherent in Equations 1 and 2 used for combin ing uncertainties, namely that the

variables are uncorrelated with a standard deviati on of less than about 30% of the mean, but under these circumstances, the presented relations may still be used to ob tain an approximate result (IPCC, 2000).

The inventory uncertainty is expressed by gi ving 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 wide r 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 th e uncertainty probability function for each quantity being combined. IPCC (2000) good practice is been fo llowed in this regar d, which is to assume either a normal or lognormal distribution depending on which provides the most realistic resu lts (i.e., results in positive non-zero confidence limits ). Other distributions should only be used where there are compelling reasons, either from empirical observatio ns or from expert ju dgement ba cked by theoretical argument.

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

function is assumed re sulting in a symmetric distribution about the mean (i .e., a balanced uncertainty of ± U i ). Wherever the percent un certainty for a quantity is greater than 100%, the uncertainty value is taken to be (100/ U i )*100 when determinin g the lower limit and +U i when determining the upper limit resulting in an unbalanced uncertainty. This is e quivalent to assuming a lognormal distribution and is done , where applicable, to avoid a negative or zero lower confidence limit for the target quantity. Th ese rules concerning ba lanced and unbalanc ed uncertainties are applied appropriately to each qu antity before combining uncertai nties 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 th e value applicable for

evaluation of the lowe r confidence limit.10 For example, a quantity, x, that is determined to have an upper un certainty bound of U Upper = +50%

would be assumed to have a lower uncertainty bound of U Lower = -50%. In comp arison, a quantity

that is determined to have an upper un certainty bound of U Upper = +125% would be assumed to have

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

bound of U Upper = +200% would result in a lower uncertainty bound of U Lower = (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 re spect 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 nega tive 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 di fferent 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 cat egories. The percentage uncertainty in the aggregate emission estimate for a categor y will tend to decrease by a factor of 1/N 0. 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 emissi on 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 sour ce (e.g., venting). In general the uncertainties associated with GHG emissions from a specific facility are re latively large but when the emissions from many hundreds or thousands of f acilities are aggregated the overall uncertainty may be very low. For example, for gas proc essing plants the aver age 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 acc ount for all releases of carbo n to the atmosphere as CO 2 except unoxidized carbon emitted in a solid (o r stored) form such as partic ulate 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 (CH 4 ), or non-methane hydrocarbons (NMHC) is evaluated separa tely from, and in addition to, the CO 2 emission assessment. This apparent double counting allows for the fact that these non-CO 2 compounds all

oxidize to CO 2 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-CO 2 gases is implicitly accounted for in the applied factors. The CO 2 emission11 factors for fuels assume complete conversion of all carbon to CO 2 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-CO 2 emissions are not explicitly stated in either IPCC methodology manua l or good practice guidanc e, but are currently being emphasized through the UNFCCC Secretariat’ s national inventory re view process. Here

contributions due to atmo spheric oxidation of non-CO 2 emissions by non-combustion sources are calculated and reported separately as CO 2 O (i.e., equivalent CO 2 emissions due to atmospheric

oxidation of non-CO 2 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 pro cedures described by Re id et al. (1987). Sitespecific composition data was used wherever av ailable, otherwise i ndustry 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 pur chased electric power, steam and hydrogen. This part of the project relie d 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 s ector. In 2000, purchase of steam is limited to two sites which operate cogeneration facilitie s to simultaneously produce steam and electric

power.

Purchase of electric power for use by prime m overs (i.e., pump and compressor drivers) and ancillary equipment (e.g., lighti ng, etc.) is pervasive thro ughout the UOG sector. Purchased electric power use at individual facilities may rang e 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 elec tric 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 or ganize their data in a format that would allow easy extraction of electric power co nsumption data at a facility leve l. Short of obtaining lists of all power accounts for each facili ty (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 ta ken 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 di sposition of this fuel by type of device is presented in Table

3 below.

Table 3. Disposition of burned fuel ga s 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, supplementa l fuel for incinerators to achieve good

destruction efficiencies and/or to maintain th e 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 storag e tanks, and the supply medium for gas operated devices (e.g., instrument contro l 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). Pu rchased propane is sometimes used for small compressors, pumpjack engines and portable heaters and torches.

The following subsections delineate the methods us ed to prorate reported fuel gas consumption (i.e., fuel gas taken from the process). The volum es of the different types of purchased fuels consumed (e.g., natural gas, propane and diesel) are estimated base d on available trend data for a representative cross-se ction of the industry.13 3.1.1 Important Considerations

Operators are required, as part of normal producti on 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 type s 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 fu el-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 comple xities in fuel gas metering and accounting are

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

At many facilities, a single flow meter is installed to measure th e total amount of reportable fuel withdrawn from the process. Sometimes seconda ry meters are installe d to determine fuel disposition by major fuel-use cat egories but this additional information is usually only for

internal use at such facilities and is not car ried 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 pa ckaged compressor units to be supplied with a dedicated fuel gas meter. A fac ility 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, re boilers, 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 bla nket 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 valu e for stable flaring of the stream.

At small field installations (e.g., meter stations, fi eld dehydrators and line he aters), 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 th e well-site level. With the implementation of the petroleum registry in Alberta, th is 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 dete rmine 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 contamin ants such as CO, NO

x , and PM,14 since the emission factors for these substances va ry 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 CO 2 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 va ry significantly with the type of combustion device and may contribute up to 17 pe rcent of fuel-use GHG emissions. N 2 O emissions from fuel combustion are a much less important contribut or to fuel-use GHG emissions. Moreover, N 2 O emission factors are not generally availa ble 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 type s of gas streams (e.g., raw gas, processed gas, tank vapours and dehydrator vent gas). For processed natural ga s, 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 en countered regarding reported fuel use at indivi dual facilities:

• Information is available on the number, type s and sizes of combus tion equipment at the site. In these cases, calculati ons 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 a nd sizes of combustion equipment at the site, but based on the type of facility it coul d 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 assu med that all fuel is consumed by one or more reciprocating engines. At an oil pr oduction facility with no gas conservation, the fuel could reasonably be assumed to be a ll consumed by process and tank heaters.

• No information is available on the number a nd sizes of combustion equipment at the site and it is likely that more than one type of co mbustion device is being used. In these cases, the fuel use is prorated using the average pror ation 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 theo retical fuel use is done using the following equation:

where,

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

é

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

k

N

= normalization correction factor (dimensionless).

The value of k N is determined using the following equation: k e = e N F F i

i ⋅ ′15 where,

e F

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

e F C

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

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

é

Fnc = calculated/theoretica l fuel gas usage by all non-combustion devices at the site (GJ/y).

The procedures for calculati ng 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 info rmation, 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 appropria te thermal efficiency, load fact or and operating factor as given by the following equation:

where,

e F

= rate of fuel consumption expr essed as an energy flow rate and based on the higher heating value of the gas (GJ/y),

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

k

L = fractional loading of the combus tion device when it is operating (dimensionless) (see Table 5 for default values),

t O = 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),

HHV F

= higher (gross) heating va lue of the fuel gas (MJ/m 3 ),

LHV F

= lower (net) heating value of the fuel gas (MJ/m 3 ), and

g

c = 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

′ ∑ ′

∑

g e LHV

HHV 100

8760

t k = e c
F F O

L F ⋅ ⋅        

⋅ ⋅ max η16 Table 4. Typical input heat rates and therma l 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 28 1

325 to 600 11 250 32 1

600 to 2250 10 000 35 1 Reciprocating Engines

>2250 9 474 38 1

Turbine Engines All 10 909 33 2

<375 (Natural Draft) 4 736 76 3

<375 (Forced Draft) 4 500 80 2 Industrial and Commercial

Heaters and Boilers

≥ 375 4 500 80 2

Residential Water Heaters All 7 500 48 4

Residential Furnaces All 5 143 70 5

Vented Outdoors 4 500 80 6 Catalytic Heaters

Vented Indoors 3 600 100

Thermoelectric Generators All 100 000 3.6 2

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 pro cess 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 periods 1

.

Source Type Load Factor (k L ) (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 0.79 1 6920 Turbine Engines 0.81 1 7096

Industrial and Commercial

Heaters and Boilers <29 MW 0.50 2 4380

Industrial and Commercial

Heaters and Boilers >29 MW 1.0 8760

Residential Water Heaters 0.17 3 1489

Residential Furnaces 0.25 4 2190 Catalytic Heaters 0.50 5 4380

Thermoelectric Generators 0.95 6 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 fu el gas consumption based on the available power output of a device, fuel consump tion is estimated based on the am ount of work or heat output as indicated by available process data (e.g., temperat ures, pressures and flows) and allowing for the efficiency of the device. The calculation procedur es and process data us ed depended on the type of combustion device, and are delineat ed in Sections 3.2 and 3.3, accordingly.

Equipment manufacturers typically report specific fuel requirem ents 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 pe rformance 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 t ypically 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 compressi on 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, compressi on ratio, fuel composition and emission control technology can change the rating of a given engi ne. So, where actual configuration data are available unit-specific performance and emission factor data are applied.

Optimum combustion conditions (maximum power) ar e obtained when the air-fuel ratio is close to stoichiometric. Current natural gas engines ar e 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 effici ency varies as a functio n of actual power output and engine speed.19 Unfortunately, the conditions th at tend to promote maximum powe r output and fuel efficiency also create the highest combustion temperat ure, which promotes the formation of NO

x emissions. The common method to limit emissions on ga s 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 combusti on chamber. Excess air reduces combustion temperatures resulting in lower NO

x but higher CO, CH 4 and total hydrocarbons (THCs) when compared with the rich-burn engine. Itis 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 pro cessing and transmission rather than gathering applications.

The rated thermal efficiency of turbine engines is typically 30 to 35 percen t and can be as high as 42 percent for new gas turbine models with smalle r units tending to the lower end of the range. The input heat rates required to achieve the ma nufacturer’s published power outputs for each unit

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

derated to site conditions. Differences in ambien t air temperature, altitu de, barometric pressure and humidity should all be accounted when maki ng 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 similarl y rated reciprocating engi nes). 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 NO

x emissions produced by turbine engine s is a function of the fuel burned, firing temperature, exhaust discharge temperatur e and residence time in the combustion zone. Since the trend towards high turbine efficiencies leads to higher pressu re ratios and firing temperatures, the emission rates of NO

x are higher for these units.

The normal method for reducing NO

x formation in turbines is to reduce combustion temperatures. Maintaining an operating temper ature in the combustor at 1500oC or below virtually eliminates production of NO

x ; however, this is not achievable by conventional

combustion control methods such as steam or wa ter injection, or premixing air and natural gas prior to entering the combustor (this process is referred to as lean premix or dry-low-NO

x [DLN]). Presently, the low combustion temper atures are only achieved through catalytic combustion (e.g., the XONON combustion system by Catalytica Combustion Systems Inc.).20 The most common post-combustion NO

x reduction treatment is selective catalytic reduction (SCR). This reduces NO

x 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 engine s have been retrofit with NO

x emission control features. But

little information is available to document th e extent of these actions. Furthermore, where catalytic converters (3-way cat alytic converters can reduce NO

x , CO and CH 4 emissions) have been installed few companies have implemented fo rmal programs to maintain these systems so their average performance is uncertain. As a likely c onservative approximation, NO

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

Additionally, the general experi ence from performance tests c onducted on engines used in the UOG industry has been that those at larger manne d facilities are better maintained and tuned

than those at small manned facilities. This contri butes 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 availabl e 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 h eaters, reboilers and utility heaters. These are mainly indirect fired units.

3.3.1 Source Characterization

Two general types of fired heat ers and boilers are used in th e natural gas industry (GPSA, 1987):

watertube and firetube. Watertube units are designed to pass wate r 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 h eat transfer. Firetube units are de signed 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, a nd operation of firetube heaters va ries widely from vary simple natural draft designs to well-in strumented forced air units. G ood fuel efficiency is achieved through low stack temperatures, low exce ss air, and insula tion 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-o ff 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-NO

x burners and internal flue gas re circulation (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 usua lly set up with 10 to 20 percent excess air (2 to 4 percent excess O 2 ). NO

x controls that require higher excess air levels can re sult in fuel being used to heat the air rather than converting it to usable energy.

Table 7. Emission factors for CACs fr om stationary natural gas-fuelled reciprocating engines 1

.

Substance 2-Stroke Lean-Burn (ng/J) 4-Stroke

Lean-Burn (ng/J) 4-Stoke

Rich-Burn (ng/J)

NO

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

N 2 O 7 5.72 5.72 5.72 CO 166 (152) 2 136 (240) 2 1600 (1509) 2

CO 2 3,6 49 300 49 300 49 300

SO 2 4,6 0.25 0.25 0.25

TOC 705 632 154

VOC 52 51 13

Methane 624 538 99

PM 10 (Filterable) 16.5 0.033 4.1

PM 2.5 (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 CO 2 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/10 3 m 3

. 5. Considered less than 1 μm in aerodynamic diameter. 6. Where fuel compositions are known, CO 2 and SO 2 are calculated based on fuel carbon and sulphur content assuming 99.9 percent of carbon is converted to CO 2 (the remainder is soot) and 95.5 percent of the sulphur

is converted to SO 2 ( the remainder is unburned). 7. Adapted from CAPP (1999): A Detailed Inventory of CH 4 and VOC emissions from Upstream Oil and Gas Operations in Canada. CAPP Pub. # 1999-0010.22 Table 8. Summary of U.S. EPA average em ission factors for different types of natural gas-fuelled turbine engines 1,2

.

Technology NO

x (ng/J) N 2 O (ng/J) CO (ng/J) CO 2 4,5

(ng/J)

Uncontrolled 138 1.29 35 3 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 NO

x . NO

x emissions decrease at lower load conditions, while CO emissions increase at lower lo ad conditions. Test data indicate that as much as 30 percent NO

x reduction and 200 percent CO increase are po ssible 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 CO 2 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, CO 2 is calculated based on fuel carbon and sulphur content assuming 99.995 percent of carbon is converted to CO 2 (the remainder is soot).

Table 9. Emission factors for CACs and GHGs from natural gas-fuelled turbines 1

.

Substance Emission Factor (ng/J)

CO 2 2,7 49 300

N 2 O 1.29
TPM, PM 10 , PM 2.5 4 0.82

SO 2 5,7 0.25

CH 4 3.69

THC 4.73

VOC 0.90

NMHC 6 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 CO 2 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 PM 2.5 or PM 10 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/10 3 m 3

. 6 Calculated as the difference between THC and methane emission factors. 7. Where fuel compositions are known, CO 2 and SO 2 are calculated based on fuel carbon and sulphur content assuming 99.995 percent of carbon is converted to CO 2 (the remainder is soot) and 99.5 percent of the sulphur is converted to SO 2 ( the remainder is unburned).23 3.3.2 Important Considerations

Except where unit-specific emission factors are know n, 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 factor s presented by one manufacturer for common air

contaminants from low-NO

x 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 (NO

x ), carbon monoxide (CO) and carbon dioxide (CO 2 ) from natural gas-fuel led heaters and boilers 1

.

Source Types Size (MW) Emission Controls NO

x (ng/J) 2 CO (ng/J) CO 2 4,5

(ng/J)

Uncontrolled - Pre-NSPS 3 118 35 49 550

Uncontrolled - Post-NSPS 3 80 35 49 550

Controlled - Low NO

x Burners 59 35 49 550 >29

Controlled - Flue Gas Recirculation 42 35 49 550

Uncontrolled 42 35 49 550

Controlled - Low NO

x Burners 21 35 49 550 Wall-fired

Units

≤ 29

Controlled - Low NO

x Burners/Flue

Gas Recirculation 13 35 49 550

Uncontrolled 72 10 49 550 Tangential-

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 NO 2 . For large and small wall-fired boilers with SNCR control, apply a 24 percent reduction to appropriate NO

x emission factor. For tangential-fired boilers with selective non-catalytic reduction (SNCR) control, apply a 13 percent reduction to the appropriate NO

x 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 CO 2

. 5. Where the fuel composition is known, CO 2 is calculated based on fuel carbon and sulphur content assuming 99.995 percent of carbon is converted to CO 2 (the remainder is soot).24 Table 11. Emission factors for CACs and GHGs from natural gas combustion by

heaters and boilers 1

.

Substance Emission Factor (ng/J)

CO 2 2,5 49 550

N 2 O (Uncontrolled) 0.93

N 2 O (Controlled-low-NO

x burner) 0.27

TPM, PM 10 , PM 2.5 3 0.80

SO 2 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 CO 2 for a typical natural gas composition at

the Alberta/Saskatchewan border. 3. All PM (total, condensable and filterable) is a ssumed to be less than 1.0 micrometres in diameter. Therefore, the PM emission factors presented here may be used to estimate PM 10 , PM 2.5 and PM 1 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/10 3 m 3 (4.57 g/10 3 m 3 ). 5. Where the fuel composition is known, CO 2 and SO 2 are calculated based on fuel carbon and sulphur content assuming 99.995 percent of carbon is converted to CO 2 (the remainder is soot) and 99.5 percent of the sulphur is converted to SO 2 ( the remainder is unburned).

Table 12. Manufacturer’s emission factors for common air contaminants from natural gas-fuelled commercial fi retube boilers for different NO

x control

levels.

Emission Factors (ng/J) Substance

Uncontrolled 1 60 ppm 2

NO

x 30 ppm 2

NO

x 25 ppm 2

NO

x 20 ppm 2

NO

x CO 64 64 17/47 3 17/47 3 64

CO 2 4 49 550 49 550 49 550 49 550 49 550

NO

x 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 NO X 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 CO 2 for a typical natural gas composition at

the Alberta/Saskatchewan border.25 Table 13. Emission factors for LPG-fuelled heaters and boilers 1

.

Butane-Fuelled Units 2 Propane-Fuelled Units 2

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, PM 10 , PM 2.5 3 2.5 0.07 2.1 0.06 2.8 0.07 1.9 0.05

SO 2 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

NO

x 5 87 2.5 63 1.8 90 2.3 66 1.7

N 2 O 3.8 0.1 3.8 0.1 4.3 0.1 4.3 0.1

CO 2 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

CH 4 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/m 3 for liquid butane and 25.394 MJ/m 3 for liquid propane. Assumes emissions (except SO 2 and NO

x ) are the same, on a heat inpu t basis, as for natural gas

combustion. The NO

x emission factors have been multiplied by a correction factor of 1.5, which is the approximate ratio of propane/butane NO

x emissions to natural gas NO

x 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 w ith similar combustion characteristics, all PM is less than 10 μm in aer odynamic equivalent diameter (PM 10 ). 4. S equals the sulphur content of the of the fuel expressed in grains/100 ft 3 of vapour. 5. Expressed as NO 2

. 6. Assuming 99.5 percent conversion of fuel carbon to CO 2

. 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 emer gency disposal of a hazardous waste gas stream. There are a variety of different t ypes 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 aninitiative to substantially reduce flaring of all kinds in Alberta, particularly flaring of solution gas at crude oil production fac ilities. Initi ally, this initiative was primarily driven by concerns about toxic products of partial or incomplete combustion that may be formed in flares. Th e 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, th e reduction of the New Oil Well Production Period (NOWPP) flare limit set out in Informational Letter (IL) 87-92 to 300 x 10 3 m 3 /month (0.000911 Mt CO 2 E/month) from 500 x 10 3 m 3 /month (0.001518 Mt CO 2 E/month)(a 40 percent reduction), implementation of a maximum gas oil ratio (GOR) criterion of 3000 m 3 /m 3 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 th e gas sweetening process employe d at natural gas processing plants. Depending on the composition of the raw gas stream, acid gas is typically composed of

CO 2 and H 2 S with small amounts of residual hydrocarbons. If the acid gas does not contain regulated concentrations of H 2 S the acid gas may be vented to th e atmosphere. This is sometimes the case at sweet gas processing plants that must remove CO 2 to meet pipeline specifications. More frequently, however, the ac id gas contains significant H 2 S and must be flar ed, processed by a sulphur recovery unit or disposed of by in jection into a suitable underground formation, depending on the regulatory requirements, costs involved and site-speci fic constraints. The

formation CO 2 in acid gas streams passes through each of these disposal/treatment systems unchanged and, with the exception of disposal by unde rground injection, is ultimately released to the atmosphere.

The amount of acid gas production is usually metered and the CO 2 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 tr eatment of acid gas (EUB ID 2001-03). At new plants, acid gas may be flared if the sulphur inlet rate is less th an 1 tonne per day, otherwise the acid gas must be processed by a sulphur recovery unit. The requ ired design sulphur recovery efficiency varies between 70 a nd 99.8 percent, depending on the sulphur inlet ra te. The higher27 the sulphur inlet ra te the greater the required recovery efficienc y. Existing facilities are being gradually de-grandfathered over time.

Acid gas injection is an alternative approach to meeting the sulphur reco very requirements that has an effective recovery efficiency of nearly 100 per cent if operated succe ssfully. 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), a nd consequently, is the preferred choice for new gas processing faci lities in these situations. At existing facilities, the economics generally do not favour switching to acid gas in jection 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, encl osed flares and incinerators. Enclosed flares and incinerators are distinguished by their use of a refractory-lined cham ber to contain the flame heat to create a finite post flame combusti on 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 contro l. An incinerator has at least stack-top temperature and oxygen control and may also featur e a continuous stack emission monitoring system.

Properly designed and operated open- flame flares are able to achiev e 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 effici ency are due to the fo rmation of products of partial or incomplete combustion. The amount and types of incomplete combustion products formed is depended on a number of factors in cluding: burner/flare tip design, exit velocities, wind conditions, amount of condens ation or liquid carry-over thr ough to the flare tip, and the waste gas composition. Presently, there is no reliab le 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 inco mplete 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 system s are primarily used for disposal of waste gas volumes from purging and blowdown events, and, gene rally, are only used if the gas is odourized or is sour. Otherwise, common practice for many companies is to dispose of the waste gas by28 controlled venting. Small enclosed flares or in cinerators 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 beco ming more common. On emergency flare systems the issue has been avoiding the use of obstructive flow meters (e.g., or ifice meters) that could cause plugging or introduce excessive back pressure in the system, and fi nding meters that can provide accurate results over the wide range of flow rate s that may occur. Ultrasonic flow meters have been gaining popularity in these applications and use of continuous tr acer-based systems has successfully implemented as well.

Where flows are not known, excessive flaring is us ually noticed only when the flame size at the flare tip increases substantially or valves connect ed 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 losse s may occur into a flare system without triggeri ng either of these two crude indicators, and such flows no rmally 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 fl ares at sour facilities are assumed to be operated continuously and consume approxi mately 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 fa ctors have been published by U.S. EPA (1995) for quantification of some of the primary contam inants formed. These factors are presented in Tables 14 and 15. The first table gives the factor s 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 fr om tests using heavier-than-methane hydrocarbons, they are deemed to be useful for obtaining ro ugh estimates of the amount of emissions from natural gas flaring.29 Table 14. Emission factors for flare operations 1,2

.

Component Emission Factor (ng/J)

THC 3 60

CO 2 4 48 560

CO 159

NO

x 29

N 2 O ND

TPM, PM 10 , PM 2.5 5 57

VOC 6 22

CH 4 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 CO 2

. 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 CH 4

.

Table 15. Hydrocarbon composition of flare emissions 1,2

.

Composition Component
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 (CO 2 ) is naturally occurring CO 2 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 app lied speciation profile s (see Section 9).

Most emissions of formation CO 2 result from the processing of acid gas streams at sulphur recovery plants or from aci d gas disposal by vent or flare systems. Formation CO 2 may also be emitted as a waste by-product of deep cut extr action processes at these same natural gas processing plants. In the latter two cases, the amount of CO 2 emissions are taken directly from survey responses provided by industry for indivi dual facilities, or, in the absence of any responses, are estimated based on a mass balance that considers the total amount of formation

CO 2 in the facility inlet and sales streams, and the fate of the removed formation CO 2 . The

concentrations of formation CO 2 in the inlet gas streams are calculated based on the sources and amount of production linked to each facility an d the corresponding pool-specific gas analyses available from regulatory agencies and produc tion accounting registries. If the sales gas concentrations were not provided by the industry survey, the sales ga s at each facility is assumed

to contain less than 0. 25 percent formation CO 2 (a typical value obs erved 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. Mu ch of this discussion also app lies to flaring ac tivities (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 emissi ons are delineated in Section 6.3. Venting from glycol dehydrators (i.e., still-co lumn off-gas emissions) is addr essed 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: inte rmittent and continuous. Intermittent applications may include the disposal of waste volumes from emergency pressure re lief episodes, operator initiated or instrumented depressurization events (e.g., depressurization of process equipment for inspection or maintenance purposes, or depressuri zation of piping for tie-ins), plant or system upsets, well servicing and testing, pigging even ts, 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 wh ere 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 ga s sweetening units, and sometimes stabilizer overheads), and vent gas from gas-operated devi ces where natural gas is used as the supply medium (e.g., instrument control loops, chemi cal 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 cons erve 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 w ith 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 una cceptable fire or explosion hazard on or off the facility lease.

• Venting of gas containing H 2 S to the atmosphere must not result in exceedance of Alberta Ambient Air Quality Guidelines for H 2 S or Occupational Exposure Levels for H 2 S.

• 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 H 2 S per kilomole of gas must be burned.32 • Continuous venting of gas containing H 2 S and other odourous compounds must not result in odours outside the lease boundary.

• The true vapour pressure of hydrocarbon prod uct stored in atmospheric storage tanks shall not exceed 83 kilopascals where such tanks are vented to the atmosphere.

• Vented gas from gas dehydrator s 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 em issions 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 commissi oned after six months from the issuance of this guide; or

o 5.0 tonnes per year for faciliti es commissioned prior to the issuance of this guide, effective 1 January 2001.

In May of 2002 AEUB issued General Bulle tin GB 2002-05, which further defines the requirements for evaluation of solution gas vent gas conservation. Initiall y, the emphasis is on vents larger than 800 m 3 /day (0.886 kt CO 2 E/year), and then by 2003 to 2004 vents down to 500

m 3 /day (0.554 Mt CO 2 E/year) are targeted.

For purposes of the current inventory, venting ha s been separated into those forms that are generally reported and those which are not.

• Reported venting is the sum of all vented volu mes 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 th e sum of all miscellaneous vented volumes not normal ly included in reported vented volumes and not otherwise accounted for in the developed emissions inventory. This may include instrument vent gas, compressor star t gas, purge gas and blanket gas that is discharged directly to the atmosphere, de hydrator still co lumn 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 10 3 m 3 /month (0.304 x 10 -3 kt CO 2 E/month), adjusted to 101.325 kPa and 15 ° C, as part of routine production accounting procedures. The requi rement to report all gas vented (or flared) includes emissions from routine operations, em ergency conditions, and the depressuring of pipeline, compression, and processing systems. Vented gas excludes fugitive emissions from piping and equipment leaks.

Typically, separate reports are s ubmitted to the provinc ial governments for crude oil and natural gas production facilitie s, natural gas gathering systems, and natural gas processing plants. Some venting (and flaring) data and other information on oil and natural gas transmission systems and33 natural gas distribution systems ar e also reported to Statistics Canada and the National Energy Board. The production accounting repor ting 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 ve nted (and flared) volumes. The main sources of uncertainty are as follows:

• There are inconsistencies in what individua l companies are actually including in their reported vented and flared volumes. In some cas es 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 hea vy crude oil wells in Saskatchewan but are in Alberta). In other cases, it is due to a l ack 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 la rger continuous vent or flare systems, if at all. Wher e there is

no measurement data the volumes must be es timated. 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., freque ncy and details of equipment or piping blowdown events, frequency of compressor engi ne starts, etc), and differences in which sources individual operators are even considering.

In Alberta, the AEUB has established standa rds for measurement of flaring at pipeline and natural gas processing facilities (i.e., AE UB 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 (w here 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 faci lities where annual averag e flared volumes exceed

500 m 3 /day (1.52 x 10 -3 kt CO 2 E/day), and

o solution gas flared from heavy crude o il or crude bitumen production facilities within designated oil sands areas where a nnual average flared or vented volumes

exceed 2000 m 3 /day (5.12 x 10 -3 kt CO 2 E/day for flaring and 18.2 x 10 -3 kt

CO 2 E/day for venting), based on general metering requirements specified in IL

91-09.

Routine flare sources are define d as those sources that, by proc ess 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 oi l 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 si gnificant impact on the total CO 2 -equivalent (CO 2 E)

emissions from these activities since unburned CH 4 contributes approximately 7.7 times more radiative forcing on a 100-year time horizon than fully combusted CH 4 . Production accounting forms for production facilities, th e major source of venting and flaring, provide separate cells for repo rting 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 soluti on gas factors. An informal review of the production accounting sy stems of several oper ators 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 na tural 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 summari ze the emission factors used to estimate emission contributions by the sources and activ ities 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 ca tegories of blowdowns at oil and gas facilities:

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

o unit blowdowns (for blowdown of indivi dual compressor or pr ocess units), and

o pipeline blowdowns (for depressu rization 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

Volume 1

(10 3 m 3 /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 Vents 2 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 pi ping 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 emi ssions depends on the sampling rate and the characteristics of the analyzer. A value of 0.0985 m 3 /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 emissi ons if the supply medium is natural gas. The common types of devices at oil and gas faciliti es 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 bleedin g instrument components, the number of actuators, the design of these componen ts, and the level of control activity.

Typical gas consumption rates for a variety of standard and low-bleed types of pneumatic instruments are prov ided in Table 17.36 Table 17. Typical gas consumption rates for a variety of standard and low-bleed types of pneumatic instruments 1

.

Supply Pressure: 140 kPa g Supply Pressure: 240 kPa g Type
Steady-state (m 3 /h) Max.

Exhaust

(m 3 /h) Steady-state (m 3 /h) Max.

Exhaust

(m 3 /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 a pplications where gas-driven pumps may be used are:

 injection of methanol and othe r 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 r od assembly which in turn drives the pump plunger. The e xpanded supply gas is then vent ed to atmosphere or into a collection system and the cycle repeated. Pump ing capacities of less than 3 L/d to more

than 3 m 3 /d, and injection pre ssure capabilities of up to 62 000 kPa g are available through a range of pump sizes and models.

Some gas-driven pumps are designed to ope rate off low uniform supply pressures of

345 kPa g or less and others are designed to oper ate off high or erratic pressures up to

10 340 kPa g .

The amount of gas consumption is determined by the change in pressu re of this gas in passing through the gas motor, the pumping ra te and the required chemical injection pressure. As much as 7.5 m 3 of gas may be require to pum p each litre of liquid; however, most applications will require much less gas th an this (i.e., typically only half as much).37 Recent work sponsored by GRI/U.S EPA (Mye rs and Harrison, 1996) indicates Kimray pumps (the most commonly used type of gl ycol circulation pump ) exhaust about 0.178

m 3 of natural gas per 10 3 m 3 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 ope n to the atmosphere; although, sometimes it may be connected to a flare system.

Specific starting gas requirements for engine-d riven 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 comp ressor may require as much as 225 m 3 of natural gas for each start attempt. Consequently, if st art 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 ve nting are estimated usin g the emission factors

summarized in Table 18. In the ab sence of temperature an d pressure data, the so lution gas emission

factors in Table 18 are used to estimate the amoun t of gas that flashes fr om the oil when it first

enters the stock tanks.

Table 18. Summary of the fact ors used to estimate gas venting and flaring rates.

Emission Source THC Emission

Factor Units

Glycol Dehydrators 1

- Still Column Of f-Gas (Flash Tank)

- Still Column Of f-Gas (No Flash Tank) - Stripping Gas Factor - Pump Factor

Instrument Controllers 2
Chemical Injection Pumps 3 0.00357

0.1751

0.670

0.1777

0.354

0.236 m 3 /m 3 of gas production

m 3 /m 3 of gas production

m 3 /m 3 of gas production

m 3 /m 3 of gas production

m 3 /h/controller

m 3 /h/pump

1 Estimated based on simulation results for conditions of 28 o C and 7000 kPa in the absorber column, a glycol circulation rate of 45 L/kg of H 2 O removed. It is assumed that no flash tank or stripping gas are used.

2 Based on measured vent rates for continuous- and inte rmittent-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 conti nuous liquid desiccant pr ocess in which water or water vapour is removed from hydrocarbon streams by selective abso rption and the glycol is regenerated or reconcentrated by thermal desorp tion. The use of triethylene glyc ol (TEG) and ethylene glycol (EG) are standard for de hydration of natural gas.

This process is widely used in gas producti on 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 th e rich glycol, and use of stripping gas in the reboiler. These sources are th e focus of this sec tion. Other sources of methane emissions on a glycol dehydrator incl ude fugitive equipment leaks (see Section 7.0), venting by gas-operated devices (see Section 6.3.4), and combus tion emissions if it has a gasfired reboiler (s ee Section 3.0).

The basic TEG dehydration process is as follows. Wet gas is brought into co ntact 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 fl ows 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 regenerate d 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 remo ved, the temperature and pressure in the tower, actual purity of the glycol at the inlet to the co ntactor, number of trays or packing height in the contactor, and the desired dew point depr ession (API, 1990). Typical values for plant applications are 17 to 50 L TEG/kg H 2 O removed. At 6900 kPa g , glycol can absorb up to 7.5 standard litres of gas for every litr e of glycol circulated (Sams, 1992).

A low-pressure flash separator is sometimes inst alled between the contactor and the regenerator (reboiler) to release any solution gas that may be entr ained in the rich (wet) glycol, especially if a glycol energy exchange pump is used in the syst em. This type of pump uses pressure energy in the rich glycol to pump lean gl ycol into the contactor. The gas separated in the flash separator may be used to supplement the fu el and stripping gas required fo r 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 st ripping still attached to the top of a reboiler. In the still column, the wet glyc ol flows down to the reboi ler 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 175 o to 205 o 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 th e reboiler to help strip water vapour from the glycol. The water vapour rises through the strippi ng 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 th e 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 de hydration process, the program also provides

information on the amount of me thane and other organic emissions. Furthermore, the program can assess the emission reduction that may be ach ieved 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 ava ilable on a site-by-site basis, GRI-GLYCalc is used here to develop average em ission factors for application to glycol dehydrators in different segments of the upstream oil and gas industry. Th ese 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 la rge, 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 pr ocess fluids to the environment past seals, packings, valve seats and mechanical connecti ons (e.g., compressor s eals and rod packings, valve-stem packing, block-valve seats, etc.). Mo st 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 stat us of an equipment component is expressed in terms of the maximum concentration (screening valu e) of organic material that can be measured at the leakage point (or interf ace) 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 st reams) (Wetherold and Provost, 1979). However, there is no clear relationship betw een the size of a com ponent and the rate of leakage (U.S. EPA, 1983).

• The potential for leakage increases with ope rating pressure and ambient temperature, but is generally independent of operati ng temperature or el evation above grade (Langley et al., 1981).

• Control valves have a greater potential to leak than bloc k 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 (especia lly 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 th at 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 emissi ons measured were from the single largest source at each of the 183 sites surveyed. Simila r trends have also been observed in the

U.S.

Leakage may often be an indicati on of wear, damage, defects, se vere process conditions, abusive environments, inadequate design, or improper in stallation. Some component s, like mechanical seals, are designed to leak a small amount to provi de some lubrication of, as well as remove heat and debris from, the contact the su rfaces. Seal designs can be imple mented 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 pl us 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 equi pment leaks are estimated using the average emission factor method (U.S. EPA, 1995b). This approach consis ts of applying average total hydrocarbon (THC)42 emission factors to an inventory of all potential f ugitive emission sources (i.e., leaking equipment components) using the equation below:

where,

and,

LR = THC leak rate (kg/h) for all potential sources,

∑

LR i,j = THC leak rate for all type i comp onents (e.g., valves, flanges, pumps, etc.) in service j (gas/vapour , light liquid, heavy liquid),

OT = average operating factor for th e target source category (i.e., the

fractional amount of time that the aff ected equipment is in service during the year),

EF i,j = average uncontrolled emission factor (kg/h/source) for type i equipment components in service j (see Table 19),

N

i,j = total number of type i pote ntial sources in service j,

CF i = average leakage control factor for components of type i, and

The inventory of sources is co mpiled by applying ty pical equipment sche dules to the total population of process units and major equipment items. Each item in these sche dules is classified by type of component (e.g., valves, pump seals, flanges, etc.) and by ty pe of service (gas/vapour, light liquid and heavy liquid). All components with a no minal pipe size of 0.5 inches or greater are counted. Equipment is exclud ed only if it was isolated from the process stream.

Methane and VOC emissions are estimated by sp eciating (see Section 8) the calculated THC

emissions.

The average emission factors for equipment leaks are different for differ ent segments of the industry, namely: natural gas production and proce ssing, crude oil production and transmission, and natural gas transmission. These ar e summarized in Tabl e 19. The values show that valves and connectors at gas facilities tend to leak more, on average, than those at oil f acilities. Also, the leak control efficiency for these components is greater at sour natural gas facilities than that at sweet natural gas facilities OT LR = LR j i, ⋅ ∑

) CF

- (1.0 N EF = LR i j i, j i, j i, ⋅ ⋅43 Table 19. Summary of average emission factor s 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 Seals 2 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 Valves 1 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 Seals 2 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 Valves 1 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 Valves 1 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 Valves 1 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 Valves 1 2.81E-03 0.17 0.1744 Table 19. Summary of average emission factor s for uncontrolled fugitive THC emissions (kg/h/source) at UOG fa cilities (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 Seals 2 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 Valves 1 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 Seals 2 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 Valves 1 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 Valves 1 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 Valves 1 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 15 o C. HL Heavy Liquid: the process fluid is a hydrocarbon liqui d at the operating conditions a nd has a vapour pressure of

less than 0.3 kPa at 15 o 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 applicab le 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 presen ted in Table 19 are developed based on results of a field studies conducted by Clearstone Engineering over th e period 1992 to 2003 for oil and gas facilities in Western Canada. All these fact ors account for the fact th at only a small portion of the potential sources actually leak. Furthermore, they reflect the current level of control inherent with the present opera ting and regulatory environment in Canada. This environment may be characterized as one in which safety inspections, routine visu al inspections, area monitoring and regular facility turn-arounds are conducted. However, there are no specific programs to detect leaks on a regular basis usi ng a portable organic analyzer, and there are no policies for immediate repair of these leaks.

Control factors are used to accou nt for facility/process- specific emission contro ls achieved through the use of special equipment modi fications (see Table 20). The most commonly-occurring of these modifications are the use of caps, plugs, blinds or a second valve on op en-ended lines. Pressure

relief devices connected to contin uously-operating flare systems are assumed to have a control value of 1. All pressure relie f devices at s our facilities are assumed to be connected to flare systems.

An operating factor of 1.0 is used for all facilities. This assume s that facilities are continuous sources of fugitive emissions. Even when a f acility has no throughput, it is generally still under pressure and subject to equipment leaks.46 Table 20. Summary of typical control efficiencies 1 (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

1 2

1 2

1 2

1 2

0.6 3

1

1 4

1

1

1

1 U.S. EPA. 1980. VOC Fugitive Emissions in Synthetic Organic Chemicals Manufacturing Industry - Background Information for Proposed Standards. Re port 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 syst em 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 devi ces 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 st oring hydrocarbon liquids (oil and condensate) in the upstream oil and gas industr y. Limited use of floating-roof tanks also occurs (primarily at pipeline terminals, large oil sa nds facilities and larger gas proce ssing 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 develope d by API (1993 and 1994). If a tank is equipped with a vapour collection system, no storage losses o ccur. 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 (Fugiti ve Equipment Leaks).

The storage losses from fixed-roof ta nks comprise contributions from three different types of losses: breathing/standing, working (i.e., filling and em ptying) and flashing. Flashing losses occur at production sites where unstable products (i.e., pr oducts that have a vapour pressure greater than local barometric pressure) are pro duced 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 componen ts vaporize). The materi al that vaporizes dur ing this process is called solution gas.

Breathing and working losses occur for both stable and unstable products. Ho wever, if the product is unstable, the latter type of loss is obscured by th e 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 termin als (i.e., facilities stor ing stable products) were taken to be the sum of breathing an d working losses.

7.2.2 Important Considerations

Unless information to the contrary was provided by th e industry survey, all storage tanks used at oil and gas production facilitie s 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 e ach tank size are assumed to be those presented in Ta ble 21 and the colour of the tank s 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 mi xture of fixed-roof and floa ting-roof tanks are in use.

The use of underground storage ta nks and the resulting emissions are assumed to be negligible.

7.2.3 Default Emission Factors

Flashing losses are estimated us ing the Vasquez and Be ggs correlation (CAPP, 2001) given below. Breathing losses and working loss es are estimated using the AP I method for fixe d-roof tanks48 (1991). For the purposes of the br eathing loss calculations , the tanks are assumed to be, on average, about half full during standing peri ods. The dimensions of the tank s 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 p C R

o C

g S 4 3

1 exp 2 γ γ

where:

876

. 0 <

o γ 876

. 0 ≥

o γ

C 1 3.204 × 10 -4 7.803 × 10 -4

C

2 1.1870 1.0937

C

3 1 881.24 2 022.19

C

4 1 748.29 1 879.28

R

s = solution gas factor (m 3 solution gas/m 3 oil),

o γ = oil specific gravity with re spect to water (dimensionless),

= API o + 5

. 131 5

. 141

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).

v o S F MW Q R E

⋅ × = − 5 10 229

. 4

where: Q

o = oil throughput (m 3 /y), and

MW

v = tank vapour molecular weight (kg/kmole).

Table 21. Summary of the commonly used ta nk sizes in the oil and gas industry,

and the dimensions of these tanks.

Nominal Capacity
(bbl) (m 3 ) 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

7.62049 7.3 Handling Losses - Tankers

7.3.1 Source Characterization

The losses from tankers ar e classified based on the type of pr oduct 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 speci al high-pressure storage systems to contain these products. Certain losses occur dur ing the loading and unloading of these vehicles (i.e., venting of the gauge assemb ly 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, condensa te and pentanes-plus. Emissions result from evaporation losses du ring loading and transit activities. The amount of emissi ons depends on the vapour pressure of the liquid product, the rece nt 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 tr ansit due to leaking equipment components (e.g., valves, and flanged and threaded connections); however, these are likely sma ll 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 procedur es, the loading and unloading losses are determined using the following developed equations:

and,

where,

ER L,i

, ER U, = total emissions associated with loading (L) and unloading (U) of liquefied type i material (kg/y), 1.5)] TF + (1 EF + EF [ LF Q = ER i S, i L, i G, i i S, i L, ⋅ ⋅ ⋅ ⋅

1.5) TF + (1 EF LF Q = ER i R, i U, i i R, i U, ⋅ ⋅ ⋅ ⋅50 Q

S,i

, Q R,I

= volume of liquefied type i material shipped (S) and received (R), respectively (m 3 /y),

LF i = number of rail cars typically used per unit volume of liquefied type i material transported (i.e. load factor) (cars/m 3 ),

EF G,I

= average emission factor for gauging losses during loading of liquefied type i material (kg/car),

EF L,i , EF U,i = average emission factors for losse s from depressurizing the transfer line upon completion of loading (L) and unloading operations (U) involving liquefied type i material, and

TF S,i , TF R,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 ab ove 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 presente d in Table 23 for liquefi ed ethane, propane and

butane.

7.3.3.2 Low Vapour Pressure Carriers

The loading losses are calculated the equation presented below an d factors published by U.S. EPA (1995a). Losses that occur during the transit of LVP products ar e not evaluated. (There are no known factors or procedur es available for estimating losses from transport of crude oil or natural gas liquids by tanker vehicles.)

where,

i L = 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),

M

v = molecular weight of the vapour (kg/kmole),

T

= bulk temperature ( o C), Q

= annual volume loaded (m 3 ), and

CF = average control factor (dimensionless).

Crude oil is assumed to have a va pour pressure of 35 kP a and the molecular wei ght of the vapour is assumed to be 80 kg/kmole. NGL and pentanes-plus are given the properties of pentane. CF)

- (1.0 273.15) + (T Q M P S 0.120

= 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 vehi cle contains 60 percent as much organic material as it can hold at thermodynamic equilibrium).

Loading losses are controlled usi ng vapour exchange or va pour recovery systems. These devices are not widely used in the up stream 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 LP G products (ethane, propane and butane).

Emission Factors (kg/car) Liquefied

Petroleum

Gas Load

Factor 1

(cars/m 3 ) Trucking

Factor 1

(m 3 /m 3 ) Gauging 2

Assembly Loading

Line 3 Unloading

Line 3

C 2

C 3

C 4 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) 34.8 6

34.8

11.2 2.10

2.99

3.38 2.10

0.21

0.07

1 Estimated based on data supplied by Transport Dange rous 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 adap ted 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 comp arable to those from loading of propane.52 7.4 Accidental Releases

7.4.1 Source Characterization

Accidental releases are uninten tional 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 natu ral gas emissions in this categor y 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 accident al releases are accounted for in the related environmental reporting by fac ilities 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 pr ocess emissions to dete rmine the amounts of specific substances emitted (e.g., CH 4 , CO 2 , VOC, and H 2 S) is done using site-spe cific composition data, where available, and the default profiles presented in Ta bles 24 to 29. Tables 30 and 31 provide typical compositions of processed natura l gas compositions by province.

Almost 25 000 speciation profiles were derive d from company supplied data, well gas and oil analyses and pool average gas and oi l analyses. The default profiles in Tables 24 to 29 are used only if one of these profiles could not be linked to a sp ecific 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 ga s are assumed to be sweet.

• Conventional oil, heavy oil and crude bitumen pr ofiles are applied to the corresponding production and ba ttery facilities.

The profiles are implemented using the equation below.

where,

ER k = average emission rate (kg/h) of the chemical compound k,

ER = total mass emission rate (kg/h),

Y

k = mole fraction of component k in the effluent stream,

M k = molecular weight of component k, and

M = average molecular weig ht of the bulk fluid.

Total emissions are determined for each of the chemical species in the applied speciation profiles. By including inorganic co mpounds in the profiles it is assumed that the es timated emission rates (except those from equipment leak s and from combustion activities) are total mass emissions on a

moisture-free basis. As the em issions from equipment leaks ar e expressed as THC, they are speciated based on the normalized hydrocarbon por tion of the profiles (inorganic emissions from equipment leaks are calculated in appropr iate proportion to the THC emissions). M M Y ER

= ER k k

k ⋅ ⋅54Table 24. Speciation profiles (on a moisture-free basis) for dry and sweet gas production and processing facilities.Dry GasSweet GasGas1Light Liquid2Dehy Off-Gas3Gas4Tank Vapours5Light Liquid2Dehy Off-Gas3ComponentMole%Mass%Mole%Mass%Mole%Mass%Mole%Mass%Mole%Mass%Mole%Mass%Mole%Mass%N21.7099 2.9153 0.01 0.0050 6.0450 9.3101 0.6793 1.0865 2.9668 2.9436 0.01 0.0050 3.0220 3.5883CO20.2646 0.7088 0.05 0.0394 3.6656 8.8694 0.5814 1.4610 1.3436 2.0944 0.05 0.0394 6.3865 11.914H2S 0.0000 0.0000 0.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.00 0.0000 0.0000 0.0000C197.291 94.998 0.59 0.1695 87.460 77.143 91.88084.163 56.421 32.060 0.59 0.1695 68.9410 46.881C20.7009 1.2828 31.52 16.975 2.8296 4.6780 5.4263 9.3166 15.222 16.212 31.52 16.975 11.4083 14.541C30.0295 0.0792 21.61 17.067 0.0000 0.0000 1.0490 2.6412 11.630 18.165 21.61 17.067 3.7118 6.9379i-C40.0012 0.0041 9.60 9.9936 0.0000 0.0000 0.1291 0.4284 2.6504 5.4564 9.60 9.9936 3.2751 8.0689n-C40.0020 0.0069 10.06 10.473 0.0000 0.0000 0.1949 0.6468 5.5796 11.487 10.06 10.473 3.2751 80.689i-C50.0006 0.0026 0.83 1.0725 0.0000 0.0000 0.0254 0.1046 1.2562 3.2103 0.83 1.0725 0.0000 0.0000n-C50.0005 0.0020 0.99 1.2793 0.0000 0.0000 0.0296 0.1219 1.5784 4.0336 0.99 1.2793 0.0000 0.0000C60.0001 0.0003 5.87 9.0601 0.0000 0.0000 0.0060 0.0295 0.9312 2.8424 5.87 9.0601 0.0000 0.0000C7+0.0001 0.0003 18.87 33.866 0.0000 0.0000 0.0000 0.0000 0.4215 1.4960 18.87 33.866 0.0000 0.0000Mole Wt 16.430 16.430 55.835 55.83518.189 18.189 17.514 17.514 28.23328.233 55.835 55.835 23.5920 23.5921Based on a dry gas analysis taken downstream of a straddle plant.2Average composition for liquids from gas fields in Alberta (EUB, 2003d)3Estimated by simulating dehydration of the gas (G) at water-saturated conditions, 28oC and 7 000 kPa.4Based on a gas analysis taken at an appropriate transmission point (Picard et al., 1987a).55Table 25. Speciation profiles (on a moisture-free basis) for sour gas production and processing facilities and for natural gastransmission facilities.Sour GasNatural GasGas1Tank Vapours2Light Liquid3Gas4ComponentMole %Mass %Mole %Mass %Mole %Mass %Mole %Mass %N20.6552 1.0140 2.9668 2.9436 0.01 0.0050 0.7791 1.2500CO20.5608 1.3635 1.3436 2.0944 0.05 0.0394 0.6160 1.5527H2S 3.5460 6.6755 0.0000 0.0000 0.00 0.0000 0.0000 0.0000C188.6210 78.5447 56.4205 32.0598 0.59 0.1695 92.5394 85.0226C25.2339 8.6947 15.2219 16.2121 31.52 16.9753 4.5125 7.7709C31.0118 2.4649 11.6300 18.1646 21.61 17.0671 1.0904 2.7538i-C40.1245 0.3998 2.6504 5.4564 9.60 9.9936 0.1498 0.4985n-C40.1880 0.6037 5.5796 11.4867 10.06 10.4725 0.2103 0.7000i-C50.0245 0.0977 1.2562 3.2103 0.83 1.0725 0.0415 0.1716n-C50.0286 0.1140 1.5784 4.0336 0.99 1.2793 0.0358 0.1478C60.0058 0.0276 0.9312 2.8424 5.87 9.0601 0.0170 0.0839C7+0.0000 0.0000 0.4215 1.4960 18.87 33.8656 0.0084 0.0482Mole Wt 18.1011 18.1011 28.2333 28.2333 55.8345 55.8345 17.4613 17.46131 The H2S-free composition is based on an analysis taken atan 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.56Table 26. Speciation profiles (on a moisture-free basis) for light/medium crude oil and primary heavy crude oil productionfacilities.Light/Medium Crude OilHeavy Crude Oil (Primary)Gas1Tank Vapours2Light Liquid3Gas4Tank Vapours4Light Liquid4ComponentMole %Mass %Mole %Mass %Mole %Mass %Mole %Mass %Mole %Mass %Mole %Mass %N20.6190 0.7723 13.9989 8.8642 0.1316 0.0464 0.1817 0.3030 6.3477 8.9364 0.1046 0.0353CO25.2430 10.2765 0.3303 0.3286 0.3240 0.1794 0.0859 0.2250 0.6892 1.5243 0.7665 0.4069H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0002 0.0000 0.0000 0.0000 0.0000C173.2524 52.3386 10.0100 3.6300 9.7419 1.9668 98.0137 93.6026 87.2337 70.3327 7.6718 1.4844C211.9708 16.0314 15.7274 10.6900 3.6464 1.3798 0.9062 1.6221 2.2616 3.4177 2.7538 0.9987C35.3198 10.4477 24.1601 24.0821 4.9064 2.7227 0.0408 0.1071 0.1905 0.4222 3.8341 2.0392i-C40.8778 2.2723 6.6404 8.7244 1.9516 1.4275 0.0564 0.1951 0.1324 0.3868 1.8191 1.2752n-C41.7027 4.4077 16.6022 21.8126 4.0430 2.9572 0.0351 0.1214 0.1137 0.3321 3.5935 2.5191i-C50.3570 1.1472 4.2113 6.8682 3.0507 2.7699 0.0501 0.2152 0.1400 0.5076 2.4084 2.0958n-C50.3802 1.2217 4.5447 7.4120 3.6626 3.3255 0.0433 0.1860 0.1230 0.4460 2.7543 2.3968C60.2446 0.9388 2.9655 5.7767 18.1649 19.6995 0.0927 0.4755 0.3494 1.5132 17.9750 18.6830C7+0.0327 0.1459 0.7997 1.8113 50.3769 63.5253 0.4940 2.9467 2.4188 12.1808 56.3190 68.0654Mole Wt 22.4536 22.4536 44.2399 44.2399 79.4647 79.4647 16.7990 16.7990 19.8981 19.8981 82.9121 82.91211 Based on an analysis of the gas from a large solution-gas gathering system in central Alberta (Picard et al., 1987b).2Adapted from an analysis of the vapours from an oil storage tank in northeastern B.C (Site No. 2) (Picard and Colley, 1987a).3Average composition for liquids from conventional oil fields in Alberta (EUB, 2003d)4Adapted from results presented by Ullman et al. (1987).57Table 27. Speciation profiles (on a moisture-free basis) light/medium crude oil and primary heavy crude oilproduction facilities.Sour Crude OilSour Solution Natural Gas1Sour Light Liquid1ComponentMole %Mass %Mole %Mass %N23.2898 4.0741 0.1081 0.0385CO23.5298 6.8675 0.3733 0.2089H2S 3.2898 4.9558 0.8527 0.3695C171.7705 50.9011 7.4364 1.5172C29.0895 12.0828 3.8033 1.4544C35.3197 10.3703 6.0853 3.4126i-C40.8010 2.0581 1.9617 1.4500n-C41.6399 4.2138 5.8751 4.3427i-C50.3920 1.2503 3.5331 3.2418n-C50.4100 1.3077 4.6140 4.2336C60.2490 0.9485 19.9173 21.8257C7+0.2190 0.9701 45.4395 57.9049Mole Wt 22.6218 22.6218 78.5652 78.56521 Based on the average pool analysis for sour conventional oil operations (Alberta pool average gas and oil analyses, EUB 2003d).58Table 28. Speciation profiles (on a moisture-free basis) forthermal conventional heavy crude oil and cold bitumenproduction.Thermal Conventional Heavy Crude OilCold BitumenGas1Tank Vapours1Light Liquid2Gas3Tank Vapours/LightLiquid3ComponentMole %Mass %Mole %Mass %Mole %Mass %Mole %Mass %Mole %Mass %N20.1932 0.1767 3.3516 3.0552 0.1044 0.0353 0.6130 0.6343 0.0000 0.0000CO22.6094 3.7485 16.1140 23.0772 0.7652 0.4066 28.5280 46.3771 22.0000 41.5226H2S 0.0150 0.0167 0.1439 0.1596 0.1744 0.0718 0.2490 0.3134 0.0000 0.0000C172.9361 38.1942 66.6600 34.8000 7.6584 1.4834 63.9410 37.8919 70.0000 48.1609C21.9370 1.9012 0.9490 0.9286 2.7490 0.9980 1.2070 1.3407 8.0000 10.3165C33.0956 4.4558 0.5394 0.7740 3.8274 2.0377 0.9160 1.4921 0.0000 0.0000i-C41.0807 2.0504 0.1922 0.3635 1.8159 1.2743 0.2640 0.5668 0.0000 0.0000n-C42.3889 4.5323 0.3678 0.6957 3.5872 2.5173 0.9520 2.0440 0.0000 0.0000i-C51.9994 4.7088 0.4541 1.0662 2.4042 2.0943 1.3020 3.4700 0.0000 0.0000n-C52.2733 5.3539 0.5829 1.3686 2.7495 2.3951 1.1310 3.0143 0.0000 0.0000C65.8086 16.3394 2.1914 6.1454 17.9436 18.6696 0.8970 2.8554 0.0000 0.0000C7+5.6628 18.5221 8.4539 27.5661 56.2207 68.0166 0.0000 0.0000 0.0000 0.0000Mole Wt 30.6359 30.6359 30.7306 30.7306 82.8268 82.8268 27.0719 27.0719 23.3179 23.31791Adapted from results presented by Ullman et al. (1987).2Average 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-fr ee basis) for British Columbia sweet and sour natural gas production and processing facilities.

Sweet Natural Gas Sour Natural Gas

Gas 1 Gas 2 Component

Mole % Mass % Mole % Mass %

N 2 1.8871 2.7999 1.1827 1.5942

CO 2 2.2141 5.1611 6.4801 13.7225

H 2 S 0.0751 0.1355 7.0611 11.5776

C 1 87.4553 74.3132 79.1579 61.1052

C 2 5.0650 0.8067 3.5884 5.1920

C 3 1.8830 4.3980 1.3349 2.8324

i-C 4 0.3001 0.9239 0.2249 0.6290

n-C 4 0.5387 1.6584 0.4362 1.2199

i-C 5 0.1544 0.5900 0.1321 0.4586

n-C 5 0.1574 0.6015 0.1472 0.5110

C 6 0.1319 0.6021 0.1259 0.5221

C 7+ 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., H 2 S concentrations < 1.0 mole percent) (B.C. EMPR, 1997a).

2 Average gas composition for sour gas fields (i.e., H 2 S concentrations ≥ 1.0 mole percent) (B.C. EMPR, 1997a).

Table 30. Typical compositions (mol percent) of processed natural gas by province.

BC AB SK MB ON Component

WA

Border Empress SK

Border BC

Border AB

Border Regina MN

Border Dawn

C 1 95.9490 92.8690 97.1294 95.6400 95.2128 95.0600 94.8890 94.7089

C 2 2.4160 4.0556 0.2579 2.5800 2.4306 0.4940 2.4740 2.4805

C 3 0.5440 1.1112 0.0201 0.0700 0.1374 0.0670 0.2130 0.2501

i-C 4 0.0710 0.1601 0.0005 0.0100 0.0043 0.0120 0.0130 0.0300

n-C 4 0.1130 0.2180 0.0005 0.0100 0.0043 0.0110 0.0200 0.0400

i-C 5 0.0190 0.0496 0.0008 0.0000 0.0013 0.0040 0.0050 0.0200

n-C 5 0.0110 0.0389 0.0004 0.0000 0.0010 0.0030 0.0080 0.0100

C 6 0.0260 0.0225 0.0001 0.0100 0.0012 0.0070 0.0030 0.0100

C 7+ 0.0000 0.0126 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.1250 0.6334 0.2618 0.5400 0.5552 0.1290 0.6560 0.6201

N 2 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.

BC AB SK MB ON Component

WA

Border Empress SK

Border BC

Border AB

Border Regina MN

Border Dawn

C 1 91.7957 85.4537 94.7955 91.7267 91.0242 91.3750 90.2786 89.8694

C 2 4.3324 6.9946 0.4718 4.6379 4.3553 0.8900 4.4118 4.4117

C 3 1.4306 2.8104 0.0539 0.1845 0.3611 0.1770 0.5570 0.6523

i-C 4 0.2461 0.5337 0.0018 0.0347 0.0149 0.0418 0.0448 0.1031

n-C 4 0.3917 0.7268 0.0018 0.0347 0.0149 0.0383 0.0689 0.1375

i-C 5 0.0818 0.2053 0.0035 0.0000 0.0056 0.0173 0.0214 0.0854

n-C 5 0.0473 0.1610 0.0018 0.0000 0.0043 0.0130 0.0342 0.0427

C 6 0.1336 0.1112 0.0005 0.0515 0.0062 0.0361 0.0153 0.0510

C 7+ 0.0000 0.0724 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000

CO 2 0.3281 1.5988 0.7009 1.4207 1.4561 0.3402 1.7121 1.6142

N 2 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 brie f description of the different emi ssion sources in each subject oil and gas activity, the assumptions used to estimate the number of these sour ces 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 b een delineated in Sectio ns 3 throug h 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 invent ory efforts sponsored by CAPP (Picard et al. , 1992, Ross et al., 1999). Each emission so urce was assumed to be important ( due to size or nu mber) until proven

otherwise.

9.1 Well Drilling and Associated Testing

The drilling of wells for crude oil an d natural gas in Canada is a seasonal activity that is highly

variable in terms of the numbers of wells drilled, th e geographic areas of activ ity, the target resource (light/medium crude oil, conventiona l heavy crude oil, bitumen or na tural gas), the classification of the well (sweet, sour, criti cal sour), the depths that are drilled, and the geol ogical conditions that are

encountered. Each of these variab les impacts the drilling pr ocedures that are used and, in turn, the type, source and amount of emissions that occur. In general, the emissions ma y be ascribed to fuel consumption by the drilling rigs, dr illing fluids and ven ting and flaring activities during drill-stem

tests.

9.1.1 Drilling Rigs

There are two potential sources of emissions associated with drillin g rigs: fugitive emissions due to leaking equipment components, a nd combustion emissions from operation of the engines and heaters used by the rigs a nd 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 ba sed on fuel consumption data reported by CAODC (1989, 1995). These statistics give the average amoun t of diesel fuel consumed by engines and by boilers according to the depth range of the hole. Dr illing depth and duration da ta are available for all wells drilled These data are presen ted in Table 32, below. Emission factors are used to estimate the amount of fuel that pa ssed through the combustion devices unburned.62 Table 32. Summary of drilling rig activity p resented 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 Territories 1 140 17 65 177 161 ---- ----

British Columbia 2 1 312 5 171 9 334 7 624 5 315 1 054 978

Alberta 3 31 572 22 469 13 572 18 339 16 730 9 496 6 277

Saskatchewan 4 9 325 2 204 2 2 94 3 541 1 026 221 ----

Manitoba 5 ---- 1 700 ---- ---- ---- ---- ----

Ontario 6 1 730 407 127 806 133 162 ----

Nova Scotia 7 ---- ---- ---- ---- ---- 126 227

Newfoundland 8 ---- ---- ---- ---- ---- 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. Ontari o 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 Boar d. Hibernia Development Wells. www.cnopb.nfnet.com/resource/product/hwells.htm

9.1.2 Drilling Fluids

There are two potential causes fo r GHG emissions from drilling flui ds: entrainment of solution natural gas and volatilization of invert drilling flui ds. These are described in the sections below; however, a brief descripti on of drilling flui ds and their use is given first.

As a hole is being drille d, 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 hol e). 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, nitr ogen or natural gas may also be used (under bala nced drilling). The purposes of the fluid include removal of cuttings from the hole, cool ing of the bit, lubrication of the hole and balancing of down-hole pres sures. At the surface, the return ing fluid flows into a tank (the mud tank) where it is bro ught to atmospheric pressure and the cuttings are removed by screening. Chemicals and clay material s may be added to adjust the rheologi cal 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-balan ced wells have been drilled in Ca nada (PTTC, 2003). No records63 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, th ere is a potential for some natural gas to dissolve in, or become entrained with, the dr illing fluid. When the fluid is br ought to atmospheric pressure in the mud tank, this gas separates from the drilling fluid. If it is anticip ated that sour natural gas zones will be encountered, vapour s from the mud tank are collected a nd subsequently fl ared. Otherwise, the vapours are typically vented to atmosphere.

The total amount of solution gas from a drilling operation is rela tively small as the flows are normally too low to maintain a fl are except when gas zones are fi rst penetrated. Th e 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 increas es markedly with depth. Consequently, significant amounts of heat may be transferred to the drilling fl uid 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. Us ually, 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 calculatin g the evaporation rate in the mud tanks, and applying the result to the total number of operating hour s accumulated in the reference year. The evaporation rate is estimated using th e API correlations for fi xed-roof storage tanks (1991). It is assumed that each rig has three active m ud tanks; each tank has a rectangular surface

area of 22.3 m 2 , and the average temperature of the fluid in the tanks is 60 o 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. Th e number of wells drilled, and the average number of days re quired to drill a well are taken from appropriate provincial statistics.

Where this information is not ava ilable, 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 emi ssions from the industry in Alberta) no further effort was made to determin e if the use of invert drilling fluids had changed since that time. Accordingl y, invert drilling fluids are assumed to be used for five percent of all

wells drilled.64 Table 33. Summary of number of wells drille d and the average numb er of drilling days per well for each province or terri tory for the reference year 2000.

Province or Territory Wells Drilled Average Drilling Days

Northwest Territories 1 20 28.0

British Columbia 2 952 32.3

Alberta 3 15 517 7.6

Saskatchewan 4 3 897 4.8

Manitoba 5 68 25.0

Ontario 6 92 36.6

Nova Scotia 7 7 50.4

Newfoundland 8 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. Ontari o 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 Boar d. 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 regul atory bodies in Alberta, British Columbia and Saskatchewan. For all other provinces, these volumes are estimated based on the number of wells drilled, and if av ailable, the depth of wells drilled.

During a test, the zone is produced through the cen tre of the drill stem. At the surface, the gas and liquid phases are separated a nd measured. If it is a sour we ll, the gas phase is flared; otherwise, the gas is often vented to the atmos phere. Although the test re sults are reported, the well effluent is not treated as production. C onsequently, the data are not reflected in any production disposition analyses publi shed by the regulatory agencies.

Furthermore, before a drill-stem test is conducte d, 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 preliminar y assessment of the flow potentia l may be performed using a flow prover (an orifice meter). If the well shows potential, the proper se paration 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 fr om reported drill stem te sts 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 ope rators, 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 completi ons, testing, workovers and abandonments. The emissions produced by these activ ities are perhaps evaluated best in terms of the fuel consumption by the majo r types of equipment that are employed (service rigs, pumping

units and wireline un its) and specific ven ting that occurs.

9.2.1 Service Rigs

The total number of hours logged by service rigs in western Cana da 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 rema inder is consumed by reciprocating engines. Also, small amounts of propan e are used in the winter for space heating. On an annual basis, this amounts to abou t 1.9 L per hour of operation (Picard et al ., 1992).

9.2.2 Pumping Units

Pumping units are used in the supp ly of cementing and ch emical treatment services. In the previous inventory, pumping units were determined to be a relatively insi gnificant source of CH 4 and VOC emissions (i.e., < 0.002 percent of Alberta’s THC emissions) (Picard et al ., 1992). Th erefore, no

further effort was made to bette r quantify these emissions. Inst ead, the 1989 fuel consumption values for Alberta is extrapolat ed to 2000 values based on th e number of wells drilled in each province or territory. This information is pr esented 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 an d instruments down hole for repair, inspection, retrieval and testing purposes. In Alberta, the indu stry is dominated by one large company, followed by several medium sized companies and many sm aller companies. Unfort unately, there was not enough information available to evaluate fu el consumption by this source category.

9.2.4 Venting During Well Servicing

The emissions from venting during well servicing ar e divided into two categories based on the type of service operations: convention al service work (i.e., well re pairs and inspections, cementing operations, and formation treatments), and blowdow n 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 co ntains 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 s ections 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-servi cing operations by circulating an

inhibited fluid such as water or oil downhole to counter-balance the pressures in the producing formation. This helps co ntrol the well and greatly reduces the po tential for emission s. The emissions that occur are usually li mited to the release of some solution gas from the mud tank s. Typically, the gas is vented if it is sweet, and flared if it is sour. The vol umes involved ar e 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 at mosphere 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 si mple wireline work is to be perf ormed (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 se al around the wire line as the wo rk is performed. Each time the

wireline tool is remove d 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 atmosphe re. Unfortunately, there was not enough information available to assess th e extent to which lu bricators are used.

Depressurization of the we ll is practical for some steam-stimu lated 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 to67 20 minutes or until casing pr essure drops to accept able 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 emissi ons from these wells; howe ver, the resultant valu e is anticipated to be small. Furthermore, much of the material that is emitte d 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 (l ess than 1000 m d eep), low-pressure (less than 2000 kPa) gas wells. There are three different blowdo wn treatments that are applied to these wells: unassisted blowdowns, swabbing an d coiled tubing clean-outs.

During an unassisted bl owdown, 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 co nsists of lifting wa ter mechanically from the well using an endless tubing unit. A coiled tubing clean-out involves injecting comp ressed 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 equi pped with flares. Thus, the natural gas that is discharged during the su bject blowdown operations is releas ed to the atmosphere unburned. These wells are located mainly in the Medicine Hat and Milk River areas of southeastern Alberta and the Area III ga s fields of southwestern Sa skatchewan. Some we lls 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 atmosphe re is about the same as the average rate of productio n per well. (The emission rates will be much lower than this at the start of a blowdown period an d will be much hi gher at the end.)

 An unassisted blowdown treatment takes betwee n 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 id entified from the available well data files based on the type of ef fluent and the reported well depth.

9.2.5 Fugitive Emissions From Well Servicing

Except during tests performed to determine the abso lute open flow (AOF) po tential of a well, there are few (if any) lines containi ng hydrocarbon gases and/or li quids during well servicing and associated testing. Therefore, it is assumed there is no significan t 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 pr oduction time, and the equipment that is br ought on site is insignificant compared to the exis ting production equipment. Ther efore, fugitive emissions from

AOF tests are also assu med to be negligible.

9.3 Light/Medium Crude Oil Production

The production of light- and medium-d ensity crude oils (i.e., crude o ils with a density of less than 900 kg/m 3 ) 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 capabl e light/medium crude oil wells in the Canada. A provincial breakdown of th ese wells is shown below in Table 35.

Each of these wells is a source of emissions from equipment le aks. These are estimated using emission factors and typical equipment schedule s. Also, some pumping wells are a source of combustion emissions (i.e., those that are driven by internal combustion en gines). Emissions from natural gas combustion are es timated 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 emissi on factors summari zed 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. Ontari o Digital Well Data. Available from www.ogsrlibrary.com

7 Canada-Newfoundland Offshore Petroleum Boar d. Hibernia Development Wells. www.cnopb.nfnet.com/resource/product/hwells.htm Table 35. Summary of light/medium crude o il production facilities presented by province for the year 2000.

Province Wells Single Well

Batteries Satellite

Batteries Group/Central

Batteries

Northwest Territories 1 159 ---- ---- 1

British Columbia 2 1 754 44 10 252

Alberta 3 30 452 4 088 1 143 133

Saskatchewan 4 25 223 1 681 ---- 913

Manitoba 5 1 436 ---- ---- 72

Ontario 6 662 53 ---- 70

Newfoundland 7 10 ---- ---- 1

Total 59 696 5 866 1 153 1 44269 9.3.2 Light/Medium Crude Oil Flow Lines

There are two potential sources of emissions associated with crude o il flow lines: piggi ng 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 trea ted 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 assu med 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, e ach satellite battery has a trap and a launcher, and each batter y 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., N 2 or H 2 O) 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 wher e the production from a crude oil well(s) is separated into its constituent phases (natural gas, crude oil and water) for metering and appropriat e disposition.

The natural gas is either vented, flared, re-inj ected, 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 comp ression 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 wi th solution natural gas co nservation is taken to be part of natural gas production.

The crude oil is pumped into a nearby crude oil pi peline, or is shipped by truck to a location where this may be done. A treater is used to remove any emulsified water fr om the crude oil before it is put in the crude oil pipeline.

A single-well crude oil battery is th e simplest type of crud e oil battery. It is estimated that there are

about 5 866 of these in Canada (see Table 35 above for a provinci al breakdown). Ty pically, each is inspected once per day; otherwise, it is unattend ed. As a minimum, it is equipped with separation, metering, storage, load ing and flaring fa cilities. Depending on the amount and nature of the production, it may also comprise selected treatment, pum ping and compression facilities.

The emission sources that may occur at a single-we ll crude oil battery and the methods that are used to assess these emissions are given below:

(1) Combustion Equipment - Emissions from the use of com bustion equipment (e.g., glycol reboilers, treaters and flares) are asse ssed as described in Section 9.6.2.70 (2) Venting - Venting emissions are attributed to th e 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 as sumed that fuel gas is used as the supply medium for all gas-operated devices (i.e., compressed air is unava ilable). The number of

controllers on site is determined based on th e 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 na tural gas pipeline.

As a conservative estimate, gas-operated devices are assumed to be in continuous operation throughout the year.

The volume of waste ga s released by glycol dehydrators is determined as described in

Section 9.6.2. The resultant am ount is assumed to be vented, not flared. (As indicated in Item (1), it is presumed that dehydrator s 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 deli veries are assumed to be conserving solution natural gas and, therefore, to have compression facilities. Further, if th e battery is sweet and is conserving natural gas, it is assumed to have a glycol deh ydrator on site to dry the natural gas. If it is sour and the natural gas is conser ved, it is assumed that the natural gas gathering system is a heated type and that the line heat ers are already taken in to 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 trea ter). All other crude o il 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 co nnected 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 storag e 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 na tural 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 hatch71 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 th ief 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 additi onal leakage points are omitted for simplificatio n purposes.

The solution natural gas emissions are esti mated by applying the Vasquez and Beggs correlation (see Section 7.2) to the volume of oil th at is produced at each battery. The appropriate temperature and pressure used in the correlation is base d on whether oil-treating

facilities are used on site.

The evaporation losses are estimated using em pirical correlations published by American Petroleum Institute (API 1991). These correlati ons relate evaporation losses to tank size, type of tank, throughput and certain design, and environmental factors.

The total number of crude oil st orage tanks in use and the size s 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 on e crude oil over-flow tank.

• Batteries that have oil-trea ting 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 ab ove 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 batte ries 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 comm on tank sizes for conventio nal oil production are 100, 400, 750, 1000, 1500 , and 2000 bbl.

All crude oil storage tanks are assumed to be above-ground and ha ve fixed roofs. The amount of throughput for each is estimated by prorating total crude o il production according to storage capacities.

9.3.4 Satellite Light/Medium Crude Oil Batteries

A satellite crude o il battery is an intermediate production facil ity. 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 used72 to compile proration data on the commingled effluent from all but one of the group of wells. The

other is used to test the rema ining well. A regular te st 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 si mplicity, it is assumed there are no dehydrator s at satellite batteries.

Typically, there are no st orage nor treatme nt facilities at satellite batte ries, and no natural gas is flared. Consequently, the only sources of emissions are equipment leaks and th e use of fuel gas to operate instrument controllers. The emissions from these sources are asse ssed as described in

Section 9.3.3. It is assumed ther e are no chemical injection pumps.

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

A group (or central) battery is th e same as a single-well battery ex cept that it receives production

from more than one well and is usually much larg er. Often, it is manned continuously during the day. The sources of emissions are the same as thos e 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 gr eater than, or equal to, 900 kg/m 3
(or alternately expressed, an API gr avity of less than , or equal to, 25 o ). Crude oil with a density of greater than, or equal to, 1000 kg/m 3 (or alternately expressed, an AP I gravity of less than, or equal to, 10 o ) is often termed bitumen. He avy crude oil which is lighter than bitumen is often termed conventional heavy crude oil.

Although it flows with greater diff iculty than light or medium crude oil at normal temperature and pressure, conventional heavy crud e 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 Li ndbergh areas of east central Albert a 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 n on-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 ther mal recovery techniques to produce. However, some of this crude bitumen may be recovered by prim ary or secondary (i.e., non thermal) recovery techniques. This “crude bitumen” (produced using n on-thermal recovery techniques) is often referred to as “cold

bitumen”.73 Figure 1. Designated Oil Sands Areas of Alberta74 9.4.1 Cold Production Heavy Crude Oil Wells

There were 35 950 capable cold pr oduction 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 requir e pumps to bring the crude oil to the surface.

There are two potential sources of emissi ons 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 char acterized by low reservoir pressu res (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 typi cal 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 produc tion accounting for Alberta heavy crude oil and cold bitumen operations.

 Company supplied GOR data for fields pr imarily in Saskatchewan. Producers in Saskatchewan often report casin g 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. Si nce these data were determined to be more representative of actual casing gas ve nting 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 m 3 /m 3 and is based on the production weighted average of all comp any 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 dispos ition 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 he avy 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 crud e 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 o il to a cleaning plant (central battery) where it is

treated to remove sand and wate r. The water is disposed of by deep-well injection. The sand and tank bottoms are placed in ecology pits and the heav y 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 si ngle-well batteries.

(3) Storage Tanks - Each battery usually is equipped w ith 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 pro duced oil. If crude oil property data were supplied by facility operator, th ey were used. Otherwise, defa ult values from Table 22 in Section 7.3 were used. Solution natural gas emissions are estimated based on the flashing

loss calculation method de scribed in Section 7.2.

9.4.4 Cold Production Heavy Crude Oil Satellite Batteries

The emissions from these facilities are attributed to equipment leak s and to the venting of casing natural gas. The use of incinerators to dispose of casing natural ga s is assumed to be negligible.76 Heavy oil satellite batteries are functionally identical to light/medium oil sate llite 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 automa tic 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 facilitie s at satellite batteries, and no natural gas is flared. Conseque ntly, 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 chem ical injection pumps.

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

A cleaning plant is a group heavy crude oil ba ttery that is equi pped with facilities for removing sand and water from the heavy oil. The typical proces s flow is as follows:

• The combined (oil, gas and wa ter) from the single well or satellite batteries enters the facility via pipeline or is trucke d by tanker. Any produc tion that is trucked in will consist of predominantly oil and water; mo st of the solution gas will have evolved upstream of this point.

• The production is pumped into a free-water k nock-out which is usua lly heated. Here the majority of produced water and most of the remaining solution gas ar e separated. Depending

on the amount of solution gas present in the ra w oil, the solution gas may be simply vented to the atmosphere. If it is not vented it may be either fl ared or conserved.

• The oil phase usually still contains some wate r 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 th ese facilities are asse ssed as follows:

(1) Combustion Equipment - The combustion equipm ent at a cleaning plant include emulsion treaters, tank heaters, glycol reboilers and flare systems. The emi ssions 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 op erate instrument controllers an d chemical pumps. Thus, there are no venting emissions.

(3) Equipment Leaks - These emissions are assessed by a pplying 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 cent ral 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 clea ning 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. Th e conserved natural gas is sent to the cleaning facility by pipeline for use as fuel. Since the steam generation demands ar e 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 pipelin e 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 Albert a and Saskatchewan (determined from the well control data file). Although, emissions from thes e 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 describe d in Section 9.3.1 for li ght/medium crude oil wells. The pumpjack on each well is usua lly 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 ga thering systems that are used to conserve casing natural gas from

some satellite batteries ar e 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 cl eaning plants. The resultin g 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 produc tion accounting purposes, each sate llite serves as a control point for selectively cycling wells between injection and production cycles. Th is is done using an elaborate valving system. Up to 30 wells are tied into each satellite battery. Ea ch 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 operatio ns is aggregated to the main cleaning plant, emi ssions from the satellites ha ve 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 clea ning plants have oil, gas and water separation equipment, emulsion treating, o il and water storage, water disposal and o il shipping equipment. However, most of the emissions at thermal heavy o il cleaning plants result from the generation of the steam used in the thermal recovery of the oil by natural gas fire d 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 cas es, production from nearby shallo w gas wells can be used for supplemental fuel. As purchase d fuel is not reported in pr oduction data reported to the government, actual fuel use by the site was ta ke from the industry su rvey. Emissions from the steam generators (and other combustion equi pment that may be on s ite) are estimated by applying the equations described in Sectio n 3. Since the produced fuel may contain significant CO 2 , actual fuel analyses wee us ed to estimate combustion CO 2 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 us ed 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 sa me for all plants. A typical equipment schedule and appropriate emi ssion factors are then applied to the total

number of modules.

(4) Storage Tanks – Unless the operator indicated othe rwise in the industry survey, it is assumed that all storage tanks have vapour co llection systems and that the collected gas is flared. Also, it is assumed that some leakage occurs around th e 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 nu mber 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 f acilities. The material in these pits is re latively 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 prim arily 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 pump79 seals and combustion emissions wh ere a gas-driven engine is us ed to drive the pumpjack). However, the use of pumpjacks on natural gas well s 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 t ypical schedule of equipment comp onents. Two different schedules are provided in Volu me 5 of this report: one fo r shallow wells and one for high pressure natural gas wells (the latter type ty pically comprising more e quipment components). To be consistent with the reporting procedures used by EUB in Alberta, each producing zone is treate d as a separate well.

The numbers of sweet, sour and shal low natural gas wells in each prov ince is presented in Table 37.

The sweet or sour status of a well was determin ed by linking the available well databases to

databases of the available gas analyses by pool. Agai n, shallow natural gas we lls were iden tified as natural gas wells with a total de pth of less than 1000 metres.

In British Columbia, 62 .3 percent of natural gas we lls are high pressu re 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 na tural 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 per cent 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 fr om light and medium crude oil production facilities, cold heavy crude oil production facilities and th ermal crude oil operations. The data for these types of fa cilities are presented in Ta ble 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 us ed to gather production from the low pressure natural gas wells described in Section 9.6.1. These systems ar e 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 s pots. Periodically, it becomes necessary to remove the water from these lines. On long sec tions of pipeline this is done by pigging (i.e., a specially-designed obstruction is pl aced in the line, and upstream na tural gas pressure is used to push it and any liquid in front of it through to an appropriate discharge poi nt). However, due to the low operating pressures of th ese pipelines, sometimes it is necessary to open the discharge end of the pipeline to atmosphere. This crea tes enough pressure differe ntial 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

Yukon 1 ---- 7 ---- 7

Northwest Territories 2 ---- 5 2 7

British Columbia 3 2 313 1 075 324 3 712

Alberta 4 24 144 1 865 40 338 66 347

Saskatchewan 5 5 756 ---- 21 007 26 763

Ontario 6 53 ---- 2 022 2 075

Nova Scotia 7 12 ---- ---- 12

Newfoundland 8 4 ---- ---- 4

Total 32 282 2 9 52 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. Ontari o 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 Bo ard. 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 Territory 1 ---- ---- ---- 1

British Columbia 2 83 316 ---- ----

Alberta 3 2 000 2 990 1 747 3 378

Saskatchewan 4 85 185 344

Manitoba 5

---- ---- ---- ---- Ontario 6 3 ---- 4 2

Nova Scotia 7 ---- ---- ---- 3

Total 2 171 3 306 1 936 3 728

1 Based on data from the operator.

2 Based on system counts and infrastru cture data from B.C. OGC (2003).

3 Based on system counts and infrast ructure data from EUB (2003i).

4 Based on system counts and infrast ructure 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, Ga s 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 atmos phere through a storage tank. This is called "pulling back on the pipeline".

Both approaches result in natural gas being vented to the atmosphere. Add itionally, natural gas is vented to atmosphere when sections of pipeline ar e 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 ar e limited to low-pr essure 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 perfor med per month per well and each results in the release of approximately 0.6 m 3 of natural gas.

The total number of shallow natu ral gas wells is determined as described in Section 9.6.1.

As a close approximation, it is assumed there ar e 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 batter ies (see Section 9.6.4).

9.6.2.2 Heated Gathering Systems

Hydrate control is an important consideration in the design of high-press ure natural gas gathering systems. Hydrates are solid crys talline ice-like structures comp osed of water and hydrocarbon molecules that can form in pipelin es 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 syst ems guard against the formation of hydrates by maintaining the natural gas temperature above so me critical value. This critical value is dependent on the composition and pressure of the natural gas; conseq uently, it varies from one system to the next.

The emissions from heated system s are assessed as follows:

(1) Combustion Equipment – Combustion emissions result from fuel consumption by line heaters and certain flaring activ ities. These emissions are estimated at the facility level using appropriate emission factors, and fuel consumpt ion 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 usi ng disposition factors derived from fuel consumption data supplied by ten ma jor gas producers. These data are used to determine the amounts used by boilers, reci procating 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 cont rollers and chemical injection pumps). The only emissions that result from pigging a high-pressure natural gas pipeline

occur when the launch and recei ver chambers are opened for in sertion/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 pi peline by pigging are captured using a separator, and the natural ga s 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 ope ning 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 sou r) are pigged. For these, the pigging frequency varies from once per week to on ce per year. The average frequency is from four to six times per year. Based on these low percentages and th e small volume of emissi ons that results for each occurrence, total emission s from pigging of high-press ure natural gas pipelines are considered to be insignificant and, so, ar e disregarded for simplification purposes.

Chemical injection pump s (small gas-operated plunger pumps) are a source of emissions if the supply gas is vented to at mosphere after use, and fuel ga s 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 li ne heater and field inst allation to help protect the pipeline. Also, faciliti es 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 pum ps in active service. In doing this it is assumed that:

 Corrosion inhibitor is injected at every line heater.

 Compressed air is unavaila ble 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 a ssociated emissions to be significant.

(Note: some pumps are powered by electricity and in some applications me thanol is injected on a continuous basis.)

The resultant volume of vented na tural gas is correcte d 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 Albert a 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 contro llers is estimated in the same

manner as described for chemic al injection pumps. However, it is assumed there is only one83 controller associated with each line heater. Th is controller is used to operate a pressure control valve (choke).

In some applications low-bleed or no-bleed in strument controllers have been installed. However, based on a limited survey of operators an d 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 su pply of instrument ga s may not be assured. At least one major inst rument vendor has discontinued supp ly of low-bleed controllers for

these reasons.

(3) Equipment Leaks – The emissions from leaking equipm ent components are determined by applying emission factors to a schedule of equipmen t components for a t ypical line heater. The results then are applied to an estimate of th e 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 oper ator) that about 50 perc ent of the wells that

are tied into sour natu ral gas gathering systems have a line heater.

9.6.2.3 Dehydrated Gathering Systems

This type of gathering system prevents the form ation of hydrates by removing water vapour from the process natural gas. There are several di fferent dehydration technologies that are used: absorption using diethylene or triethylene glycol; adsorption using solid desi ccants such as activated alumina, gels, or molecular sieve; and the ch em-sorption process using calcium chloride. The glycol-based absorption proces s is the most widely used.

For simplification purposes, it is as sumed that glycol dehydrators are used on all dehydrated natural gas gathering systems. The location and number of dehydrators is determ ined 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 system s 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 li quids from the gas before dehydrat ion. Liquids from the separator

are assumed to be stored in an un derground 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 heat er may be provided to prevent hydrates fro m forming across the choke. The dehydrator is locat ed downstream of the choke.

An inherent problem with glycol de hydrators is that in addition to absorbing water from the process gas, the glycol has a strong affinity for BTEX (b enzene, toluene, ethylben zene, and xylenes) and hydrogen sulphide. TEG has a strong er 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 pr esence of even sm all amounts of H 2 S in the process gas can result in dangerous concentrations of H 2 S being released from the regene rator still column. Thus, the use84 of dehydrated systems is usually limited to sweet natural gas applications. If dehydrators are used

where H 2 S is present, a flare or in cinerator often is used to dispose of the waste gas.

Glycol dehydrators are targeted by a government initia tive to reduce atmosp heric emissions of benzene (a toxic compound as defined by the Ca nadian Environmental Protection Act). EUB has issued specific source performance standards for glycol dehydrator s (EUB Information Letter IL2001-07). As well, CAPP currentl y 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 assu med 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 me thods and assumptions used to estimate these

emissions are listed below.

(1) Fuel Consumption – Fuel is consumed by both the lin e heaters and the glycol reboilers

where these are used. The resu lting emissions are es timated based on pr oration 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 chemi cal injection pumps), to the venting of waste gas from the dehydrator and to the depressuri zation of pipeline segments for repair/tie-in purposes. The emissions from the first sour ce are estimated by applying appropriate emission factors and a typical schedule of ga s-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-ga s emissions. All still-column of f-gas from the de hydrators is assumed to be vented, not fl ared. The amount of hydrocarbon s released is estimated by applying an emission factor (s ee Section 6.4) to the natural gas throug hput of the system.

All field dehydration units are assumed to use energy exchange glycol pumps (e.g., Kimraystyle pumps) to pump lean gl ycol 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 facilit ies tend to use electric-drive glycol pumps which have no as sociated gas ve nting. Some facilities al so may use gas-drive pumps; however, these have hi gh gas consumption/venting ra tes and therefore are usually

avoided.

When a new well is connect ed 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 su ch a location does not exist or is too far away, it is necessary to cut into the pipeli ne. This may be done using a hot85 tap procedure (a method of some risk that allo ws a tie-in to be perfor med while the line is under pressure). Often, however, the target line is isolated an d depressurized to allow a cutout to be performed. It is estimated by one major operating company that, on average, some

4 000 m 3 of natural gas is released each time pa rt 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 gatherin g 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 conservativ e since sometimes multip le wells may be tied into a system at once, thus, re quiring 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 c ondensate at various points along the gathering system (e.g., at well sites and co mpressor stations) are accounted for at the location the condensate is reported in the produ ction accounting data. This is usually at the gas gathering system level or at a gas battery (s ee Section 9.6.3).

9.6.2.4 Other Gathering System Field Installations

In addition to line heaters and dehy drators, there are some other type s of field installations that may occur on natural gas gathering systems. These in clude injection stations (i.e., gas reinjection facilities), meter/regulator stations, meter stations and regulator stations. In formation on the types

and numbers of these facilities is available for British Columbia, Alberta and Saskatchewan (B.C. OGC 2003, EUB 2003i, SI R 2003a). For all other provinces th e 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 fiel d facilities presen ted by province/ territory for the reference year 2000.

Province or

Territory Injection

Plants Meter/Reg

Stations Meter

Stations Regulator

Stations

British Columbia 1 2 ---- 111 ----

Alberta 2 897 431 1 722 4 745

Saskatchewan 3 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 iden tified field fac ilities are assessed as follows:

(1) Venting – Venting may result from th e use of fuel gas to operat e 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 typi cal schedule of gas oper ated devices to each facility. The resultant value is corrected to account for the am ount 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 in cineration is assumed to be negligible.

Not all field facilities have flar e systems. When the equipmen t 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 atmo sphere. There was not enough information available to assess the amount of ga s that is discharged in this manner. Those

volumes that are flared are as sumed to have been measured and taken into account in the reported flaring statistics.

(2) Equipment Leaks – Each type of installation is cons idered to be a source of equipment

leaks. The emissions from thes e are estimated based on typi cal equipment schedules and average emission factors.

(3) Storage Tanks – Some compressor statio ns 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 producti on unit that is used when natura l gas processing is not required. Only compression and treating (e.g ., dehydration or sweetening) may be needed to upgrade raw natural gas to market specificatio ns. Typically, this type of natu ral gas comes from low-pressure, shallow natural gas wells. It is characterized by low concentrati ons of non-methane hydrocarbons and is called "dry gas."

The basic functions of a natural gas battery are to separate the efflue nt from one or more natural gas wells into natural gas and water, measure the flow rate of each of these phas es 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 eac h province is presented in Table 38. Each of these is assumed to comprise separation, meteri ng, dehydration, compre ssion and water storage facilities. Data regarding the num bers of single-well and group natural ga s batteries and the associated equipment located at them is availa ble for British Columbia (B.C. OGC, 2003), Alberta87 (EUB, 2003f), and Saskatchewan (SIR, 2003a, b). Other data sources and assumptions are

delineated below.

 For Alberta, an average number of compressor units per sing le-well or group battery is determined from information supplied by operator s. These averages are applied to the total number of each type of batte ry identified in the Battery Code Listing (EUB, 2003f).

 The number of dehydration uni ts at natural gas batteries was determined by crossreferencing CAPP’s dehydr ator database with fa cility locations. Natura l gas batteries that could not be located in the CAPP dehydrator database were still assumed to have a dehydrator. This may tend to ove r-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 batt eries 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 fu el 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 schedul es to each battery.

(4) Storage Tanks – The results of a process simulation indicate that virtually no hydrocarbons are released as solution gas fr om the water storage tanks, ev en for high pressures in the separator. Some emissions may occur due to th e entrainment of hydroca rbon 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 H 2 S emissions in so ur applications.

9.7 Natural Gas Processing

A natural gas proce ssing plant is a facility fo r extracting condensable h ydrocarbons from natural gas, and for upgrading the quality of the natural gas to market specifications (i.e., removing

contaminants such as H 2 O, H 2 S and CO 2 ). Some compression may also be required. Each facility may comprise a variety of treatment and extraction pr ocesses, and for each of these there is often a range of technologies that may be used.

There are basically five t ypes of natural gas pr ocessing facilities: sweet plan ts, 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 firs t four types are fed by natural gas gathering systems and prepare natural gas for transmissi on to market. The last type is located on major natural gas transmission88 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 H 2 S. Conversely, gas processing plants are designated as sour when the H 2 S concentration in the inlet gas contains greater than 0.01 mole/kmole. Sour plants are further classified by ho w they handle the acid ga s stripped from the raw inlet gas. The simple st method of acid gas disposal is by flar ing. Acid gas flaring plants are limited by regulations on the SO2 emissions that arise from combustion of th e acid gas. When the acid gas volume (and H 2 S concentration) is sufficient to preclude acid gas flarin g, two options are left; the plant may inject the acid gas (predominantly CO 2 and H 2 S) into a suitable reservoir or it may operate a sulphur recovery unit to produce elemental sulp hur. When a sulphur recovery unit is used

SO 2 emissions are greatly reduced (by 70 to 99 percent depending on the total inlet sulphur rate) but

the CO 2 in the acid gas (formation CO 2 ) is still released to the at mosphere through the tail gas

incinerator stack.

The emissions from each type of plant are attributed to:

(1) Combustion Equipment – All combustion emissions ar e assessed at the individual facility level as described in Section 9.6.2.2.

(2) Venting – Venting may result from th e use of fuel gas to operate instrument controllers and chemical injection pumps, from the use of glycol dehydrator s (i.e., venting of waste gas from the still column), and from purging activities during plant turnarounds and

maintenance work. Formation CO 2 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 schedu le 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 ga s 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 Mm 3 /d) use air for devices and all small plants (design capacity below 0.7 Mm 3 /d) use fuel gas for this purpose. Overal l, about 16 percent of gas processing plants use fuel ga s 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 emi ssions are estimated by applying calculated emission f actors (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 mainte nance 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 ex plosive gases. A similar procedure may be performed to remove air before the system is put back in se rvice. Depending on the plant and the procedures that are used , the flame at the flare stack ma y 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 CO 2 emissions are estimated as described in Section 2.8.

(3) Equipment Leaks – These are assessed base d on the total number of plants and the types of process units that are used at each plant. A typical equi pment schedule and appropriate emission factors are applied to each un it at each plant. The number of equipment components associated with a gi ven type of unit is assumed to be constant and, thus, is independent of design capacity. (Usually, desi gn 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 proc essing 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 emission s are estimated using co rrelations published by API (1991) for evaporation losses from fi xed-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 pent anes-plus produced at each plant, and the corresponding numbers and sizes of storage tanks that are us ed. The volumes of produced pentanes-plus are determined from the gas plant production statistics where data are

available. The numbers a nd sizes of storage tanks are estimated by assuming:

• Each plant has a minimum of two tanks (one ship ping tank and one overflow tank).

• The tanks are sized for a mini mum of 24 hours ofstorage 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, 15 00, and 2000 bbl are used.

(5) Surface Impoundments – Some plants have evaporatio n ponds where surface run-off, sludge and small amounts of pr oduced 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 sale s-quality natural gas fro m 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 accommoda te fluctuating differences between gas supply and demand rates. These facilities usually feature an unde rground 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 faciliti es for removal of any moisture the gas may have picked up in the cavern. In some cases the re-produced natural gas ma y 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 featur e a liquefaction plant at the inlet to the storage vessels and a vapourizer and compression at the outlet to th e vessels.Natural gas transmission systems transport processed natural gas to market.

The emission estimates for gas tr ansmission, storage and distribution presented in this report were prepared for CGA by ICF Consulti ng 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 fr om the use of pipelines and tanker vehicles to move crude oil, natural gas liquids (NGLs) and liquified petroleu m gas (LPG). The associ ated 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 emissi on factors available for the products that are considered in this category.

9.9.1 Crude Oil Transportation Systems

Crude oil pipeline facilitie s are regulated by both the National Energy Board, for inter-provincial pipelines, and provincial agenci es (e.g., Alberta Energy and Utiliti es 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 f acilities were supplied by individua l operators. Vol untary Challenge and Registry (VCR) reports were also used to supp lement and update this in formation. For all other provinces, the Alberta data were used to estimate the numbers of pipeline fa cilities not associated with inter-provincial pipelines.

The emissions from crude oil pipeli ne facilities are evaluated as de scribed in Section 9.9.3 for LVP pipelines.91 9.9.2 Natural Gas Liquid / Liquifi ed Petroleum Gas Systems

Three types of petroleum gases ar e marketed in liquefied form: et hane, propane, and butane. Each of these substances has a high vapour pressure (HVP) (6 000, 1 341, and 377 kPa, respectively at

40 o C); therefore, it must be stored and tran sported in pressurize d 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 assu med to be shipping LPGs by pipeline. Otherwise, rail or truck

tankers are assumed to be used and loading/unloading emission s are included. These emissions are

calculated as described below and have been attributed to the natural gas pro cessing plant.

Table 40. Summary of LPG producti on presented by province for 2000.

Production (10 3 m 3 )

Product British

Columbia 1 Alberta 2 Saskatchewan 3 Ontario 3 Nova Scotia 3

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 pressuri zed 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 an d 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 us ing an inert material (e.g., nitrogen or steam). The liquids are recovere d and later recycled. The wast e vapours from the last two steps are flared/incinerated. Appr oximately 1100 LPG cars were processed in this manner in

Alberta in 1989. It is estimate d, based on information provided by the two repair yards, that the average initial pressure in eac h car is about 350 kPa (actual values range from 0 to about 700 kPa), and the volumetric capacity of each car is about 130 m 3 . Flaring emissions for 2000 have been calculated by pr orating 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 tran sfer hoses at the end of each loading or92 unloading operation. These activities are deli neated below. The amoun t 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 tr ansportation. During loading operations, a gauging assembly is used to monitor the le vel of the liquid prod uct. This assembly comprises a graduated length of pipe (the gauge rod) that extends vertically into the rail car vessel. A clamping mechanis m 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 spec ial orifice). During the filling operation, the gauge is adjusted to the desired fill level, and the valve is opened slightly (about 25 percent). Initially, va pour product escapes through the va lve. 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 va pour 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 load ing operation it is usua lly filled with liquid product, and at the end of an unloading operation it is usuall y filled with va pour product.

When the hose is disconnected th e material inside the line is released to the atmosphere. At some plant locations the transfer lines may be depressurized to a flar e 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 pressuri zed tanker vehicles. Transport Canada, in conjunction with CN Rail and CP Rail, ha s studied the problem of leaking rail car equipment. However, the data is of a qualitative nature and no t suitable for determining the amount of emissions. Some qua litative data are given below.

An unpublished study conducted by CN Rail id entified 19 potential leakage points on LPG rail cars (Note: the visible leaks are de noted by an L): liquid eduction valve (L), vapour eduction valve (L), load ing valve, thermometer well, gauging device assembly (L), heater coils, sampling line valve (L), safe ty 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 pe riod (1984 to 1987) visible leaks were reported for ten of the categories. The most freque ntly-occurring leaks we re from the liquid eduction valve, vapour eduction va lve and gauging device assembly.

9.9.2.2 High Vapour Pressure Pipelines

LPG products are transported un derground by HVP pipelines. Th e 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. Conseque ntly, there are no combustion emissi ons. 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 affect ed segment using an inert material (e.g., N 2 ). Therefore, no emissions occur when the line is opened.

(3) Equipment Leaks – The pipeline attribute file is us ed 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 esti mated based on the Alberta da ta 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-press ure (LVP) product that is produced primarily by gas processing plants. It may be stored and tr ansported 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 a ttribute file) and the pro duction of pentanes-plus by plant indicate that about 83 percent (6 187 (10 3 ) m 3 ) of the total amount produced in 2000 was moved by surface transportation and about 17 perc ent (1 306 (10 3 ) m 3 ) was moved by pipeline. The Alberta disposition was applied to pentan es-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 pipe line for transport to market. The emissions that result from the surface transportati on are attributed to loading and transit losses. Some emissions may be a ssociated with the unloadi ng of the material. These are either taken into account by the LVP pipeline system (see Section 7.3), or ar e assumed to be part of the downstream oil and gas industry; thus, they are excluded from this study.

The loading and transit losses are estimate d using emission factors published by U.S. Environmental Protection Agency (U.S. EPA) (1995a) for transpor t and marketing of petroleum liquids. In applying th ese 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 a nd rail tank cars, so it is not necessary to assess the disposition of pr oduct by mode of surface transportation.

9.9.3.2 Low Vapour Pressure Pipelines

Operating LVP pipelines is very similar to ope rating HVP pipelines, with the exception that LVP systems have storage tanks at each terminal. The emissions from all source s, except from storage tanks, are assessed as described in Section 7.3. The emissions fr om storage tanks are estimated using empirical correlations published by AP I (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 du e to human error and extraordinary equipment failures (that is, it excludes leakage at connections, se als and packings). The emission s are classified by type of incident or failure: pipeline r uptures, 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 lis tings are also available for sp ills and pipeline ruptures in Saskatchewan, Manitoba, British Columbia, Northwest Territories, Nova Scotia and Newfoundland. Pipeline ruptures, well bl owouts and spills for the re maining provinces are assumed to be negligible.

For pipeline ruptures and spills, both the total spill vol ume and volume recovere d are reported. All unrecovered volumes of hydrocarbons are as sumed to eventually enter the atmosphere.

9.10.2 Surface-Casing Vent Flows

Surface casing is a steel liner used to protect the in tegrity of the well bore as the hole is being drilled and to prevent contamination of any aquifers that ma y be a source of potable water. It is installed during the initial stages of the drilling program an d 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 so me shallow wells). When the we ll is completed, the production casing is run down the centre of the surface casing a nd cemented in place in a similar manner. Current practice is to leave the surface open at the bottom. This allows any ga s 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 th e outside of the surface casing an d possibly contaminate aquifers above. To allow easy mon itoring for leaks, a vent and pressure gauge are inst alled at the well head.

If a vent flow occurs, the exact cause of the flow may be difficu lt to determine and the required repairs are often costly. Th e material emitted from a vent flow ma y 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 th e vent is blocked in and pressure is allowed to build-up in the casing.

Only Alberta and British Columbia have readily accessible data regard ing surface casing vent flows. Therefore, the average surface casi ng venting rate per capable well is assumed to be constant across Canada. The average rate per ca pable well is about 1 731 m 3 /y or about 3.42 kg/d.

Emissions are assumed to result onl y from the release of ga s (all liquids are assu med to be collected and properly contained). Only flow rates for vents not being produc ed 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 ga s 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 EU B indicate that approximately 7.8 percent of heavy oil wells have gas migration problems.

Husky Oil Operations conducted a se ries 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 methan e flow rate of 3.85 m 3 /d per well has been determined. Emissions are calculated by applying the average em ission factor to the total number of wells with identified gas migration problems. Since the numb er 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 bo ttoms, 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 wa stes may be ascribed to four source categories: transportation contractor s, waste reclaimers, land farms, and road oiling. Unfortunately, very little information exists on the amount or type of waste ma terial that is disposed of. Consequently, the resulting emissions could not be assessed; however, th ey are likely small compared to those from other source-categories.

The following sections de lineate each source categor y and identify some rele vant studies that have

been conducted.

9.11.1 Oilfield-Waste Transporters

Unpublished data compiled by Monenco Consultant s Limited (provided by W.A. Siemieniuk, June 21, 1990) indicate that there ar e 16 contractors that transport oi lfield wastes. Some of these companies operate from mo re than one location.

9.11.2 Waste-Oil Reclaimers

Waste-oil reclaiming facilities ar e regulated by EUB. According to EUB Gene ral Bulletin GB 95- 07, there are currently (as of 2003) 71 approved oilfield waste management facilities in Alberta. Due to the nature of the produc ts 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 produc ts that are formed may be rele ased to the atmosphere through normal evaporation. A current concern in the Un ited States is that th e resulting emissions may contain high concentrations of volatile hazardous air contaminants. A st udy by Woodward-Clyde Consultants (1989) showed mass emissions of m onoaromatic compounds (b enzene, toluene, total xylene, and ethylbenzene) at one site to be 8 to 17 percent of th e applied waste load.

Alberta Environment has publishe d a set of guidelines for land treatment of industrial wastes (AENV, 1988), and mainta ins 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 disp osed of in the Provin ce by land treatment. Furthermore, detailed

characterization data for these wa stes 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 se condary highways. EUB, however, does not consider the su bstitution of oil-containing wastes in these applications to be an acceptable long-term wast e-disposal strategy (Information Lette rs 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. Ta ble 41 provides a summary of the typical composition of the hydrocarbon content of thes e wastes. The characterization criteria for oily by-product material applied to road s are as follows (EUB IL 95-04):

• No free water.

• Oil shall have a density greater than 920 kg/m 3 . Material with less than five percent residual hydrocarbon is un acceptable as road mix.

• pH ≥ 6.

• Total salts (loading limits): Na ≤ 5 500 kg/ha

Cl ≤ 7 000 kg/ha

• Total metals (concentra tion 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 di sposal of wastes on roads has not been an issue. The primary concer ns are related to the leaching of some waste materials (e.g., metals and salts) and to future recl amation problems where wastes are applied to lease sites.97 Table 41. Composition of the organic frac tion of Lloydminster petroleum wastes 1

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 Enviro nmental Affects of Heavy Oil Waste Disposal: An Assessment of the Characteristics of Lloydminster Pe troleum Wastes. Report of the Analysis and Toxicity Project Group to the Sask-Alta Waste Dispos al 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 estimat e emissions for the 1990 through 1999 time period. Since the compilation of detailed emission inventor ies is far beyond the scope of this project, a less rigorous approach was selected.

The 2000 inventory results have been grouped in to 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 em issions from the 2000 inventory results is:

2000

, , 2000

, , , ,

p c y

p c

i p c y

i

p c A A E E × =

where,

y

i p c E

, , = estimated emissions for category c , province p , compound i and year y (tonnes),

2000

, , i p c E = 2000 inventory emissions for category c , province p and compound i

(tonnes),

y

p c A

, = activity factor for category c , province p and year y , and

2000

, p c A = activity factor for category c , province p and year 2000.

This equation is applied for each category, provi nce, 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 inve ntory 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 ava ilable or emissions from the particular source category were not expected to change with ti me, the activity values were set to 1. This effectively sets emissions equal to th e 2000 value throughout the period 1990 to 1999.99 Table 10.1 Summary of emission categor ies 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 Dehydrat or Off-Gas Light/medium oil production Light/Medium Oil Production Loading/Unload ing 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/Unloadi ng Losses Raw gas production Gas Production Reported Venting Raw gas production Gas Production Storage Losses Raw gas production Gas Production Unreported Ve nting 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 Dehydrat or Off-Gas Raw gas production Gas Processing Loading/Unload ing Losses Raw gas production Gas Processing Formation CO 2 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 Eq uipment Leaks Heavy oil production Heavy Oil Cold Production Glycol De hydrator 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 production100 Table 10.1 Summary of emission categor ies 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 drilled101Table 10.2 Summary of activity data used to estimate emissions for the time period 1990 to 1999.ProvinceYearGasProduction(106m3)Light/MediumOilProduction(103m3)Heavy OilProduction(103m3)CrudeBitumenProduction(103m3)Fuel Gas(106m3)Flared Gas(106m3)WellsDrilledSpills +Ruptures +BlowoutsCapableWellsLight/Medium +Heavy +CrudeBitumenProduction(103m3)Heavy +CrudeBitumenProduction(103m3)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 72 321.00 62 407.20 16 850.20AB 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 73 909.00 60 828.80 17 966.60AB 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 75 375.00 59 202.80 18 304.20AB 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 77 212.00 60 534.70 20 430.60AB 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 80 968.00 62 232.60 20 117.20AB 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 85 736.00 63 007.00 20 429.00AB 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 89 640.00 64 024.70 22 742.50AB 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 94 881.00 64 279.80 24 717.10AB 1997 168 094.00 37 315.80 15 502.60 13 805.90 12 327.30 2 200.90 13 225.00 19 805.39 102 453.00 66 624.30 29 308.50AB 1998 172 643.80 35 242.70 14 531.60 16 363.70 12 576.60 1 919.40 8 175.00 87 143.80 107 301.00 66 138.00 30 895.30AB 1999 175 279.40 31 332.20 14 209.40 14 171.10 13 152.00 1 683.90 9 444.00 19 805.76 112 770.00 59 712.70 28 380.50AB 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 91 816.00 60 284.80 30 603.20BC 1989 13 353.10 1 912.90 595.30 28.40 223.00 221.69 1 420.00 1 912.90 0.00BC 1990 12 748.60 1 912.90 889.30 98.10 285.00 123.02 1 436.00 1 912.90 0.00BC 1991 14 731.80 2 014.50 535.00 20.60 220.00 173.05 1 533.00 2 014.50 0.00BC 1992 16 197.10 2 032.80 346.20 63.20 171.00 125.20 1 578.00 2 032.80 0.00BC 1993 17 446.30 2 012.10 266.80 47.60 338.00 341.94 1 679.00 2 012.10 0.00BC 1994 19 189.60 1 986.90 863.80 164.70 525.00 221.69 1 750.00 1 986.90 0.00BC 1995 21 936.20 2 038.50 1 180.60 224.70 449.00 344.42 1 899.00 2 038.50 0.00BC 1996 22 434.60 2 235.50 1 250.10 288.50 504.00 221.69 2 035.00 2 235.50 0.00BC 1997 23 003.90 2 552.20 1 334.40 280.70 616.00 221.69 2 347.00 2 552.20 0.00BC 1998 24 296.40 2 763.70 1 603.30 235.10 683.00 221.69 2 573.00 2 763.70 0.00BC 1999 25 362.50 2 347.60 1 689.20 162.80 678.00 221.69 2 847.00 2 347.60 0.00BC 2000 25 362.50 2 552.30 1 749.50 154.80 846.00 221.69 3 310.00 2 552.30 0.00MB 1989 722.842 722.842 722.84 722.84 52.00 1.00 1 581.00 722.842 0.00MB 1990 737.455 737.455 737.46 737.46 78.00 1.00 1 483.00 737.455 0.00MB 1991 712.792 712.792 712.79 712.79 54.00 1.00 1 567.00 712.792 0.00MB 1992 656.415 656.415 656.42 656.42 28.00 1.00 1 547.00 656.415 0.00MB 1993 634.561 634.561 634.56 634.56 87.00 1.00 1 563.00 634.561 0.00MB 1994 657.87 657.87 657.87 657.87 67.00 1.00 1 568.00 657.87 0.00MB 1995 642.65 642.65 642.65 642.65 43.00 1.00 1 556.00 642.65 0.00MB 1996 616.10 616.10 616.10 616.10 41.00 1.00 1 531.00 616.10 0.00MB 1997 636.70 636.70 636.70 636.70 109.00 1.00 1 535.00 636.70 0.00102Table 10.2 Summary of activity data used to estimate emissions for the time period 1990 to 1999.ProvinceYearGasProduction(106m3)Light/MediumOilProduction(103m3)Heavy OilProduction(103m3)CrudeBitumenProduction(103m3)Fuel Gas(106m3)Flared Gas(106m3)WellsDrilledSpills +Ruptures +BlowoutsCapableWellsLight/Medium +Heavy +CrudeBitumenProduction(103m3)Heavy +CrudeBitumenProduction(103m3)MB 1998 634.10 634.10 634.10 634.10 49.00 1.00 1 509.00 634.10 0.00MB 1999 581.10 581.10 581.10 581.10 41.00 1.00 1 494.00 581.10 0.00MB 2000 624.30 624.30 624.30 624.30 76.00 1.00 1 516.00 624.30 0.00NL 1990 0.00 0.00NL 1991 0.00 0.00NL 1992 0.00 0.00NL 1993 0.00 0.00NL 1994 0.00 0.00NL 1995 0.00 0.00NL 1996 0.00 0.00NL 1997 0.00 0.00NL 1998 904.10 3 783.80 79.80 810.00 1.00 12.00 3 783.80 0.00NL 1999 1 434.70 5 785.80 112.40 359.00 11.00 1.00 12.00 5 785.80 0.00NL 2000 2 393.40 8 394.30 137.70 93.10 13.00 1.00 12.00 8 394.30 0.00NS 1989 0.00 0.00NS 1990 0.00 0.00NS 1991 0.00 0.00NS 1992 581.59 0.00 0.00 1.00 1.00 581.59 0.00NS 1993 1 051.63 0.00 0.00 1.00 1.00 1 051.63 0.00NS 1994 1 313.42 0.00 0.00 1.00 1.00 1 313.42 0.00NS 1995 1 241.21 0.00 0.00 1.00 1.00 1 241.21 0.00NS 1996 1 065.50 0.00 0.00 1.00 1.00 1 065.50 0.00NS 1997 774.70 0.00 0.00 1.00 1.00 774.70 0.00NS 1998 955.10 0.00 0.00 1.00 1.00 955.10 0.00NS 1999 348.60 0.00 0.00 6.00 1.00 1.00 348.60 0.00NS 2000 3 597.20 0.00 79.90 12.70 22.00 1.00 1.00 0.00 0.00NT 1989 225.86 1 832.20 1 832.20 29.711 10.00 1.00 1.00 1 832.20 0.00NT 1990 202.90 1 864.60 1 864.60 24.107 10.00 1.00 1.00 1 864.60 0.00NT 1991 221.00 1 926.20 1 926.20 25.836 10.00 1.00 1.00 1 926.20 0.00NT 1992 214.90 1 878.60 1 878.60 21.958 10.00 1.00 1.00 1 878.60 0.00NT 1993 234.20 1 846.40 1 846.40 23.403 10.00 1.00 1.00 1 846.40 0.00NT 1994 189.80 1 783.80 1 783.80 15.54 10.00 1.00 1.00 1 783.80 0.00NT 1995 195.40 1 775.10 1 775.10 15.488 10.00 1.00 1.00 1 775.10 0.00NT 1996 179.60 1 656.30 1 656.30 14.45 6.00 1.00 1.00 1 656.30 0.00NT 1997 169.50 1 599.90 1 599.90 1.60 13.00 1.00 1.00 1 599.90 0.00NT 1998 158.70 1 561.70 1 561.70 1.10 12.00 1.00 1.00 1 561.70 0.00103Table 10.2 Summary of activity data used to estimate emissions for the time period 1990 to 1999.ProvinceYearGasProduction(106m3)Light/MediumOilProduction(103m3)Heavy OilProduction(103m3)CrudeBitumenProduction(103m3)Fuel Gas(106m3)Flared Gas(106m3)WellsDrilledSpills +Ruptures +BlowoutsCapableWellsLight/Medium +Heavy +CrudeBitumenProduction(103m3)Heavy +CrudeBitumenProduction(103m3)NT 1999 112.40 1 549.20 1 549.20 1.10 15.00 1.00 1.00 1 549.20 0.00NT 2000 754.20 1 434.20 1 434.20 2.90 16.00 1.00 1.00 1 434.20 0.00ON 1989 492.50 247.20 492.50 492.50 50.00 1.00 1.00 247.20 0.00ON 1990 449.10 247.20 449.10 449.10 50.00 1.00 1.00 247.20 0.00ON 1991 428.40 235.00 428.40 428.40 50.00 1.00 1.00 235.00 0.00ON 1992 427.10 224.30 427.10 427.10 50.00 1.00 1.00 224.30 0.00ON 1993 411.20 253.40 411.20 411.20 50.00 1.00 1.00 253.40 0.00ON 1994 428.80 263.10 428.80 428.80 50.00 1.00 1.00 263.10 0.00ON 1995 456.30 285.40 456.30 456.30 50.00 1.00 1.00 285.40 0.00ON 1996 307.00 267.90 307.00 307.00 60.00 1.00 1.00 267.90 0.00ON 1997 269.00 220.60 269.00 269.00 77.00 1.00 1.00 220.60 0.00ON 1998 275.50 218.60 275.50 275.50 107.00 1.00 1.00 218.60 0.00ON 1999 421.70 238.30 421.70 421.70 81.00 1.00 1.00 238.30 0.00ON 2000 580.00 231.20 580.00 580.00 142.00 1.00 1.00 231.20 0.00QB 1989 0.00 0.00QB 1990 0.00 0.00QB 1991 0.00 0.00QB 1992 0.00 0.00QB 1993 0.00 0.00QB 1994 0.00 0.00QB 1995 0.00 0.00QB 1996 0.00 0.00QB 2000 0.00 0.00SK 1989 6 155.8933 8 273.0852 3 422.5282 627.40 375.10 1 497.00 1.00 26 952.00 11 695.6134 3 422.5282SK 1990 6 938.9438 8 460.3715 3 793.0813 743.90 213.50 1 380.00 1.00 27 946.00 12 253.4528 3 793.0813SK 1991 7 319.923 8 548.5241 3 871.5596 792.60 229.20 1 133.00 1.00 28 960.00 12 420.0837 3 871.5596SK 1992 7 474.1172 8 771.5194 4 597.992 757.80 212.50 837.00 1.00 29 525.00 13 369.5114 4 597.992SK 1993 7 666.7924 9 702.2838 5 271.0995 1 032.90 263.50 2 274.00 1.00 31 861.00 14 973.3833 5 271.0995SK 1994 8 519.4158 11 356.3973 5 847.2218 1 154.00 248.60 2 402.00 1.00 33 888.00 17 203.6191 5 847.2218SK 1995 8 714.8734 11 838.4515 6 907.6856 1 258.00 322.70 2 134.00 1.00 35 529.00 18 746.1371 6 907.6856SK 1996 7 912.10 13 129.20 7 653.70 1 124.8226 446.2258 2 601.00 1.00 38 045.00 20 782.90 7 653.70SK 1997 7 817.6031 13 646.4027 9 808.2609 1 197.4597 491.8893 4 055.00 1.00 41 186.00 23 454.6636 9 808.2609SK 1998 7 686.4265 13 774.4044 9 376.5101 1 172.7329 557.6111 1 744.00 1.00 42 425.00 23 150.9145 9 376.5101SK 1999 7 907.9499 12 360.6899 9 347.9914 1 236.1929 443.5041 2 522.00 1.00 44 741.00 21 708.6813 9 347.9914SK 2000 8 147.8192 12 657.285 11 585.3838 1 324.5739 446.665 3 839.00 1.00 48 136.00 24 242.6688 11 585.3838YT 1989 0.00 0.00104Table 10.2 Summary of activity data used to estimate emissions for the time period 1990 to 1999.ProvinceYearGasProduction(106m3)Light/MediumOilProduction(103m3)Heavy OilProduction(103m3)CrudeBitumenProduction(103m3)Fuel Gas(106m3)Flared Gas(106m3)WellsDrilledSpills +Ruptures +BlowoutsCapableWellsLight/Medium +Heavy +CrudeBitumenProduction(103m3)Heavy +CrudeBitumenProduction(103m3)YT 1990 0.00 0.00YT 1991 227.1855 34.0886 0.7293 227.1855 1.00 1.00 0.00 0.00YT 1992 506.9095 34.0886 0.7293 506.9095 1.00 1.00 0.00 0.00YT 1993 492.3659 31.4722 1.7121 492.3659 1.00 1.00 0.00 0.00YT 1994 471.1034 30.9634 1.1968 471.1034 1.00 1.00 0.00 0.00YT 1995 442.9721 30.7556 0.9722 442.9721 1.00 1.00 0.00 0.00YT 1996 427.465 29.0091 0.689 427.465 1.00 1.00 0.00 0.00YT 1997 404.50 30.40 1.20 404.50 1.00 1.00 0.00 0.00YT 1998 451.90 35.40 0.90 451.90 1.00 1.00 0.00 0.00YT 1999 628.70 35.30 0.50 628.70 1.00 1.00 0.00 0.00YT 2000 569.50 32.40 0.20 569.50 1.00 1.00 0.00 0.00105 11.0 REFERENCES CITED

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