ll

p

IOL-049

A Preliminary Inventory of Greenhouse Gas Emissions
Esso Resources Canada Ltd.
Volume 1
May 1991

By: L F Mannix

 1

The debate continues on future Canadian and World response to the threat of
potential global warming and subsequent climate change. As a major producer and
consumer of fossil fuels, Esso Resources Canada Limited (ERCL) is committed to
providing information that can be used in the development of sound public policy on
environmental issues .
In March of 1990, Imperial Oil Limited (IOL) issued a discussion paper on globa l
warming, and identifyed an accompanying seven point work program to be
undertaken within the company during 1990. This report completes the ERCL
commitment for the first work item. That is:
Development of an inventory of greenhouse gases emitted from Esso
Resources operations, and the identification of feasible opportunit ies and
costs to reduce these emissions.

 2

·
ncentration of greenhouse gases has been linked in the
Increasing atmosph~nc ~~ential global warming a~d clim~tic change. _This report
last several ye~rs with P0 f greenhouse gas emissions which were emitted as a result
documents an inventcory da Limited's (ERCL's) operat ions in 1989 , and identifies
Resources ana
.
rtunities and costs for reduction.
of ~sso
feasible oppo
Overall inventory results for 1989 are shown in Figure 1.

4500

4365

4000

Iii coal

3500
3000

2710

kt I yr
C02E 2500

~ Crude Bitumen
[]) Heavy Oil

2000

lloil

1500

.GE

1000
500
100

0

N20

CH4

Figure 1 Total ERCL Emissions
Total greenhouse gas emissions on a 20 year Carbon Dioxide equivalent (C02E )
basis are 10.5 Mt/yr C02E. 1 Carbon Dioxide equivalent emissions based ~n a 20
year time horizon have been included throughout this report for global warming .
comparison purposes, however, emissions may also be viewed under alternate time
horizons. For example, a 100 year time horizon would reduce overall ERCL C0 2E
emissions to 6.3 Mt/yr C02E as a result of lower global warming potential factor~ for
Methane (CH4) and Nitrogen Oxides (NOx). The selection of an overall reduct1_on
.
~trategy for greenhouse gases should recognize these alternative methods of viewing
inventory data.
Carbo~ Dioxide (CO2) emissions of 4.4 Mt/yr are highest in the Crude Bitumen sector,
r~flectmgthe large energy requirements associated with thermal product ion of Crude
Bitumen. CO2 emissions for the Natural Gas production sector are also large, and are

~oat,
~O~E totals.include the estimated global warming contributions
e Organic Compounds (VOCs) .

tor Nitrogen Oxides (NOx) and

 3
related to the gas compression and processing needs for mature gas fields and
associated gas production.
Methane losses on a Carbon Dioxide equivalent basis are significant, with the
majorit~ of these emissions associated with Natural Gas production, and H~a~y Oil
production. Total Methane emissions are very sensitive to the average em1ss1on
factors employed. As such, losses reported in the inventory of 2.7 Mt/yr C02E could
vary up to +/- 30%. Within the Heavy Oil production sector, Methane losses are
almost entirely from the venting of wellhead casing gas. A Methane loss of 0.18°/o of
production (wellhead to pipeline sales) has been calculated for the Natural Gas
sector.
NOx emissions are concentrated within the Natural Gas sector and are largely from
reciprocating engines used in gas compression service. NOx, if present together in
the atmosphere with Volatile Organic Compounds (VOCs), can react to form Ozone, a
direct greenhouse gas. C02E emissions for NOx and voe included in this report are
based on indirect C02E factors for these gases, which recognize their relationship to
the production of Ozone. Considering the large emission total of 2.7 Mt/yr C02E for
NOx, and the lack of understanding of how to apply these indirect C02E factors to
Canadian conditions, research studies aimed at identifying gas plant NOx
contributions to Ozone should be investigated.
Volatile Organic Compound emissions of 0.6 Mt/yr C02E are significantly lower than
Methane losses, and are primarily related to emissions from storage of crude oil in
atmospheric tankage, and from leaking equipment connections.
Nitrous Oxide (N20) emissions for ERCL were calculated as a % of NOx emissions,
and reported emission totals are not considered significant.
Emissions of Chlorofluorocarbons (CFC's) are very small being limited to minor air
conditioning repair volumes. As such no breakdown has been provided.
Further breakdown of overall C02E emission contributions by gas type and by
production sector is shown in Figures 2 and 3 below.

Coal
Heavy Oil

Figure 2 Total ERCL C02E Emissions by
Gas Type

Figure 3 Total ERCL C02E Emissions by
Production Sector

 4
Overall contributions by Major Source category for each gas type are shown in
Figure 4. Combustion emissions are 71°/oof total emissions, followed by Process
Vents (12°/o), Leaking Equipment (11 °/o),Tankage (3°/o),and Other (3o/o).
4500
4 000

EillOther

3500
3000

•

2500
kt I yr
C02E

Tankage

1J Comb.

2000
1500

D

Process Vents

1000

•

Leaking Equ.

500
0
~

Figure 4 Total

NOx

CH4

\CC

N20

ERCL C02E Emissions

by Major Source Category

On an oil equivalent m3 basis, total greenhouse gas production emissions have been
calculated for the various production sectors within ERCL, with values as listed in
Table 1 below . Given the large differences in these total production C02E emissions
per oil equivalent m3, a full life cycle assessment of greenhouse gas emissions for
fossil fuels, and their alternatives in various end uses, is recommended.

Tablel SectorTotaleroducuonco2eEmissionFactors
Production Sector
Heavy Oil
Oil Sands Mining •
Crude Bitumen
Natural Gas Prod**
Oil Prod

Coal

Kg C02E/0Em3

3775
984

510
430
165
200

• Includes upgrading. Emissions not included in inventory total.
•• Includes all emissions associated with the production of NGLs, and associated gas used for gas reinjection or miscible flooding.

 5
For emissi~n comparison _purposes, Esso Resources is currently the largest producer
of Crude 011and Crud~ B_1tumen in Alberta, and the fourth largest producer of Nat.ural
Ga~ a_nd Natural Gas liquids. With the exception of CH4 and voe losses, ERCL s
em1ss1onsr~u~hly correspond with these product market shares for the oil and gas
industry. Within Alberta, ERCL CO2 emissions are 18% of those reported by Alberta
Energy 2 for the overall oil and gas sector in Alberta . This ratio reflects:
ERCL'~ 70% share of Crude Bitumen production
Operations of more mature oil and gas fields
Large compression requirements for the Natural Gas sector
However, ERCL CH4 and VOC emissions are only approximately 5% of those
reported by the Canadian Petroleum Association (CPA) for Alberta and below what
might be anticipated based on product market shares. Significant differences
between this inventory and the CPA inventory 3 are:
ERCL gas instrumentation losses are not as large
ERCL tankage losses are not as large
Opportunities to reduce emissions are summarized in Table 2 below, and are primarily
related to potential reductions for CO2, NOx, and Methane. The majority of potential
reduction opportunities are within the Natural Gas production sector.

Table 2 Summary of Greenhouse Gas Reduction Potential
Reduction Potential

Before Tax Costs (1990$)
Capita I Avg Net Oper. Avg Red.Cost
(M$)
Cost (M$/yr)
Social ($/t)

% 1989*
(%)

C02E
(Kt/yr)

Divestments (Heavy Oil)

9

1100

nta

nla

nla

·Regulatory" Items

1

170

45

0

40

13

1595

20

-9

-4

"Technically Feasible" Items

52

6450

2360

34

**20

Total Excludina Divestments

66

8215

2425

25

**15

Description

·Economic" Items

•

* 1989 basis (12400 kt/yr) includes 1989 inventory results (10500 kt/yr) and associated electrical

CO2 emissions of 1900 kt/yr
** includeshydrocarbon recovery benefits from Enhanced Oil Recovery (EOR)

EnergyEfficiency Branch of Alberta Department of Energy. Energy Related Carbon Dioxide
Emissions In Alberta 1988 - 2005, May 1990.

2

3 PicardDJ Koon KW. An inventory of CH4 and VOC emissions from upstream oil and gas
operations
Alberta, Oct 1990, by Clearstone Engineering for Canadian. Petroluem Association.

in

 6
One of the largest Methane emission sources , conv~nt.io nal Heavy Oil, was divested
in 1990 by ERCL, and as such will reduce ERCL em1s~1onsby 1100 kt/yr C02E.
Reduction plans for another major source, surface ca~mg leaks , are curr~ntly being
developed in response to pending government regulations . These reduction plans
are classified as "Regulatory" in Table 2 above.
"Economically feasible" reductions focus on additional energy conserv ation
measures and other measures which allow for the recovery of a valued product (eg
Methane). Approximately 10% of the Methane loss~s. identi~~d in t h.is i.nventory, are
estimated to be "economically" recoverable from a limited fug1t1veem1ss1ons control
program 4 . However, confirmation of fugitive emission factors is required to confirm
these economics. The potential for economic recovery of other Methane and VOC
losses is not considered significant given the large number of individual sources.
Improvements to air fuel controls for reciprocating engines, represents an
economically feasible energy conservation measure, that has the potential to make
large reductions in NOx .
Significant reduction opportunities that are "technically feasible" include the use of
CO2 for enhanced oil recovery, cogeneration of steam and power, and other
opportunities to reduce NOx.
With respect to overall emissions reduction potential for ERCL, clearly the technology
exists for very significant reductions, but to achieve these reductions the costs are
also extremely large. The majority of these costs are within the ''technically feasible"
category and are linked to the reduction potential associated with enhanced oil
recovery. These ''technically feasible" opportunities are unlikely to be implemented
unless technology development can significantly lower costs.
Given the significant 0/o of total emissions from Methane and the sensitivity of Methane
emissions to average emission factors, field verification of emission factors for the
major Methane and VOC sources is recommended. This includes factors for:
Leaking equipment connections and seals
Reciprocating engine combustion losses
Surface casings losses per well
Gas instrumentation
Single well battery tankage losses
Glycol dehydration off gas losses
For leaki~g equipment connections and seals, it is recommended that an initial series
of screeni~g tests ~.e condu~ed t~ determine the percentage of connections and
· · f t rs
seals leaking. Add1t1onalconf1rmat1onof leaking equipment aver
should follow this first step.
age em1ss1on ac o
ERCL through its participation in industry associations sho Id
f Id
verification of CH4 - voe emissions factors b full
' .. u . co.mp Iete 1~
field verification plans.
Y Y participating in future industry

4 Based on $53/k sm3

 7
Further work is also recommended for significant reduction opportunities that are .
"technically feasible", but fall short of being "economically" feasible at this time. This
work should attempt to identify factors such technology development or other needs
required to make these opportunities economically attractive.
For reduction opportunities identified as having the potential to be "economically
feasible", it is recommended that additional detailed engineering studies be
.
conducted consistent with the intent to implement these opportunities where possible.

 8

VOLUME

1

PREAMBLE
EXECUTIVE SUMMARY
TABLE OF CONTENTS
LIST OF TABLES
LIST OF FIGURES
ACKNOWLEDGEMENTS
INTRODUCTION
Background
Other
METHODOLOGY
Scope
Inventory Reporting Structure
Accuracy
Data Gathering
. CO2 Equivalent Factors
DISCUSSION OF RESULTS
Overall Results (Inventory)
Results by Production Sector
General
Natural Gas Production Sector
Oil Production Sector
Heavy Oil Production Sector
Crude Bitumen Production Sector
Oil Sands Mining Sector
Coal Production Sector
Results by Geographic Area
Comparisons to Other Inventories
Confidence Limits
Reduction Opportunities and Costs
General
Overall Reduction Potential
Potential Reduction Costs
Summary of Reduction Pot r
1
Costs
CONCLUSIONS AND RECOMMENDA;1~'~sand
GLOSSARY OF TERMS

1
2
8
10
11
12
13
13

14
15
15
16

19
19
20
21
21

23
23
25

26
27
28

29
29
30
31

32
33
33

33

35
36
38
40

 9

It\$3l[5 Of CQO~JrE~JS
(Q©HOfd)
APPENDIX 1
Results by Gas Type and Equipment Type
CO2
Methane

voe

43

NOx
N20
CFC

44

APPENDIX 2 (Detailed Methodology)
Methodology All Sectors
Combustion CO2
Combustion CH4
Combustion VOC
Combustion NOx
Combustion N20
Surface Facility Equipment Leaks
Leaks from Surface Casing
Well Servicing
Characterization of Emissions
Natural Gas Sector
Oil Sector
Heavy Oil Sector
Crude Bitumen Sector
Oil Sands Mining Sector
Coal Sector
Other
Data Input Sheet

VOLUME 2
APPENDIX 3 (Summary of Site Specific Data and Assumptions)
Introduction
Summary Results by Division and Area .
Site Specific Assumptions and Calculations
Summary of Social Reduction Cost Data
Sample Social Cost of Service Calculation

VOLUME

41
41
41
42

3

APPENDIX 4 (Detailed Area specific Data )

44
44

45
45
45
46
46
46
4.8
48
53
54
55
58
60
62
62

63
63
64
64

 10

l USJ Of Jf\fal~S
Volume 1
Table 1 Sector Total Production C02E Emissi.on Facto~~ 1
Table 2 Summary of Greenhouse ~as Reduction Poten ia
Table 3 Global Warming CO2 Equivalent Factor.s .
Table 4 Summary of ERCL Greenhouse Gas Em1ss1ons
Table 5 °/oTotal C02E Emissions by Gas Type
.
Table 6 Summary of Total ERCL Emissions by MaJor Source Category
Table 7 Emissions Breakdown by Sector
Table 8 C02E Emission Breakdown (0/o) by Sector for each Gas Type
Table 9 Sector C02E Emission Production Factors
Table 1O Gas Sector Emissions Distribution by Facility Type
Table 11 Gas Sector Emissions by Major Source Category
Table 12 Oil Sector Emissions Distribution by Facility Type
Table 13 Oil Sector Emissions by Major Source Category
Table 14 Heavy Oil Sector Emissions by Major Source Category
Table 15 Crude Bitumen Sector Emissions Distribution by Facility Type
Table 16 Crude Bitumen Sector Emissions by Major Source Category
Table 17 Oil Sands Mining Emissions by Major Source Category
Table 18 Coal Mining Emissions by Major Source Category
Table 19 Total ERCL Emissions by Geographic Area
Table 20 Key Average Emission Factors
Table 21 Summary of Inventory Emission Ranges
Table 22 Summary of Overall Greenhouse Gas Reduction Potential
Table 23 Summary of CO2 Emissions by Equipment type
Table 24 Value of Methane Losses
Table 25 Summary of NOx Emissions by Combustion Source
Table 26 Combustion Reference Data
Table 27 Combustion Emission Factors
Table 28 Summary of NOx Emission Factors
Table 29 Number of Fugitive Emission Sources for Var'
E ·
Table 30 Summary of Gas Plant Fugitive Emission So ious bquipment Typ es
Table 31 Summary of Average Emission Factors (b ur~es Y Process
Y ca egory)
Table 32 Gas Emission Mal Fraction Profiles
Table 33 Average Gas Mol Wt Ratio (M)
Table 34 Summary of Average Mol Wts of Gas E · .
Table 35 Summary of Various Average Emiss·1 missions
Table 36 Summary Gas Equipment Estimation ~n:actors (Gas Secto r)
a ors
Table 37 Tankage Dimension (Typical)
Table 38 Tankage Breathing and Working Losses

5
6
20
21
22
22
24
24
25

26
26
26
27
27

28
28
29
29
30
32
32
36
41
42
44
45
46
47
49
51
53
55
56
57
58
59
61
61

 11

~JSJQE FmGUrRES
Volumel
Figure 1 Total ERCL Emissions

2

Figure 2 Total ERCL C02E Emissions by Gas Type

4

Figure 3 Total ERCL C02E Emissions by Production Sector

4

Figure 4 Total ERCL C02E Emissions by Major Source Category

4

Figure 5 Greenhouse Gas Effect

13

Figure 6 Description of Production Facilities
Figure 7 Total ERCL Emissions

17

Figure 8 Total ERCL Emissions (C02E)

21
21

Figure 9 °/oC02E Emissions by Major Source Category
Figure 10 C02E Emissions by Production Sector

23

Figure 11
Figure 12
Figure 13
Figure 14
Figure 15
Figure 16
Figure 17
Figure 18
Figure 19

30

Total ERCL Emissions by Geographic Area
Estimated C02E Reduction Potential for ERCL
Seriatim of Ranges to Average Reduction Costs (Social)
CO2 Emissions by Equipment Type
Methane Emissions by Major Source
Methane Emissions by Equipment Type
voe Emissions by Major Source
voe Emissions by Equipment Type
NOx Emissions by Combustion Sources

23
33
35
41
42
42
43
43

44

 12

The contributionsof all field operationsstaff and others to the devefopment of this
emissionsinventoryis greatly appreciated.

Specialthanksgo to JL (Julie)Laflammewho compfeted a farge portion of the
dat~baseentry,and to AG (Bob)Auld who provided vafuabfe guidance, and a larg
portionof the Gas Plantdata.
e

 13

In response to the growing environmental issue of climate change , Imperial Oil
Limited issued a position papers in March of 1990, outlining recomme nd~tio~s t?
Governn:ents on "Potential Global Warming". To further understand the 1mp ll_
cat1ons
of potential global warming, a seven point work program was undertaken within the
company. This reports completes the ERCL commitment for the first item , namely:
Development of an inventory of greenhouse gases emitted from Esso
Resources operations and the identification of feasible opportun ities and costs
to reduce these emissions.

Background
In recent years there has been growing concern that near surface atmospheric
temperatures are increasing, primarily as a result of human activities. The
greenhouse effect plays a crucial role in regulating the temperature of Earth, and is
responsible for all life on earth. In the absence of this effect, the average surface
temperature would be -18C vs. the present value of +15C.6
Figure 5 illustrates the key principles involved in the greenhouse gas effect.
Incoming solar radiation from the sun in the form of short wavelength electromagnetic
radiation enters the earth's atmosphere during the day. A small portion of this
radiation is reflected by the upper atmosphere, with the majority striking the earth . In
turn the earth re-emits long wavelength radiation (far infrared). A portion of this far
infrared radiation is prevented from escaping the earth's atmosphere by the so called
greenhouse gases, which trap this energy subsequently altering near surface
atmospheric temperatures.

Atmospheric blanket containing

Greenhouse
Gases

-----

Earth

Figure 5 Greenhouse Gas Effect

5 1"1)erial Oil limited. A Discussion Paper on Potential Global Warming. March 1990 .
6 The Royal Society. The gr~enhouse effect: the scientific basis for policy, 1989 , a submission to the
House of Lords Select Committee.

 14

. . 11 associated with man made
Greenhouse gases of interest are those spe~~~iute gas effect and include for the
activities towards enhancing the natural gre
purposes of this study:
CO2
CH4
VOC's7
NOxS
N20
CF C's

Carbon dioxide
Methane
d
Volatile Organic Compo~n sGenerally NO , and N02.
Nitrogen oxide compoun s.
Nitrous oxide
F r study purpose Halon will also be
All chloroflourocarbons 0
included in the CFC category.

.
.
h re has been increasing steadily since the
The concentration of CO2 in th~ atmosp e.
r k d to the comb ustion of fossil fuels
industrial revolution with the ma1orc~ntnbution ;n t~ gases in part icular Methane
'
decad es
and deforestation. The global warming ef~ect.0 0 er
and CFC's, has also been rapidly increasing in the last severa 1
·

Other
This report represents IOL's first attempt to quantify the gre~nhouse gas. emi~sion
contributions made from Essa's upstream petroleum operations, and to _1
d~nt1fyany
feasible opportunities to reduce these emissions. The scope of gas em1ss1onsthat are
identified has been limited to those generated and produced from compa ny
"operations" . Further clarification of what is included and excluded from company
operations is given in the Methodology section.
Reduction opportunities for CO2 associated with combustion are deta iled separately
in ERCL's global warming energy efficiency paper. Reduction opportunit ies for the
other greenhouse gases are identified where these reductions appear tec hnically and
I or economically feasible.
The report is organized in 3 volumes. Volume 1 contains the summary results and
app~ndices including sample calculations a~d general assumptions. A detailed
section on methodology used to develop estimates has been included in volume 1 for
reference in future invent~ri_e~.Site_s~ecific assumptions, fuel and equ ipment data,
and s~mmary ~rea ~n~ D1v1s1~n
em1s~1.ons
are included in volume 2. Volume 3
contains a detailed listing of site spec1f1cemissions data contained in t he database.
To facilitate compariso~s _toindustry and between fuel sources analy sis of data is
centered around generic items (gas type, production sector t' )
d
t
Operating sites or Divisions.
, e c , an no on

7 Defined as any compound of carbon, excluding (carb
.
.
, ammonium carbonate ~n monoxide , carbon dioxide, carbonic acid,
metallic carbide_s or car!,)<>nates
chloride, and tnchlorotnfluoroethane), that has a Reid' vaethane, 1,1,1-trichloroet hane, methylene ·
or an absolute vapor pressure (AVP) greater than 36
por pressure (RVP) greater than 80 mm Hg,
a Combined with VOC, NOx is considered an Ozone mm Hg at 20 C.
powerful greenhouse gas.
precourser. Ozone itse lf is a relatively

 15

MEJHQPQlOGy
scope
Oil and gas production for Esso Resources is geographically distributed across
Alberta, Saskatchewan, British Columbia, and the North West Territories . Within this
geogra~hic area, the pr~duction or upstream operations consist of natural gas
production and processing, the production of conventional oil conventional heavy
oil and crude bitumen, and the mining of coal.
'
A large number of individual emission sources exists within ERCL's operations, as a
result of the widely varying infrastructure of facilities necessary to support the
company's production of hydrocarbon products. To simplify the inventory process,
emission estimates were restricted to those sources that were felt to be the most
significant. The inventory scope is further restricted to " company operations", as
defined below.

Emissions included:
• From all facilities and fields where Esso is the operator.
• From the wellhead to the custody transfer point.
• Emissions from "normal operations", "upset conditions", and "maintena nce
activities"
Emissions excluded:
• Those associated with ERCL working % in facilities and fields operated by
others.
• Emissions associated with electrical power consumption.
• Emissions associated with contractor operations.
• CO2 volumes in natural gas sales volumes.
• Calgary office and lab
• Emissions associated with transmission, additional processing, and use of our
•
products
Given the limited time available to complete the inventory work, emissions were
calculated and based on average emission factors applied to fuel and equipment
data. Where average emission factors were not available, empirical correlat ions were
developed though the use of other generally accepted industry standards. Where
equipment or fuel data was not available, values were estimated from other typical
operations. To improve the accuracy of future emission inventories, field verification
of some key emission factors associated with CH4 and VOC losses is recommended
in 1991. Further detail on how emissions were calculated for each gas type and
sector is included in Appendix 2.
The base year for all calculations is 1989.
Reduction costs were based on a 10 year 10% social cost and were only calculated.
for the most significant emission sources. Capital and net operat ing costs are in
1990$. Detailed methodology on estimation of costs to reduce has not been included,
however, a listing of input data for social cost calculations is provided in Appendix 3.

 16

Inventory Reportingstructure
.
s readshee t. summary data was then
All calculations were performed in a computer n and retrieva l. To allow for
transferred to a database to allow
easierdsort fhe database is str uct ured so that
determination of feasible opportunities to re uce,
results can be reported by in a number of different ways .

J~r

f

Primary breakdown areas are by:
Greenhouse Gas type
Province or Area
Sector
Facility type
Major Source types
Equipment Source types
Reference should be made to Figure 6 for terminology used to describe production
facilities and emission categories within each production sector. Sector breakdown
includes:
Natural Gas (Gas) Production
Oil Production (conventional)
Heavy Oil Production (conventional)
Crude Bitumen Production (steam stimulated)
Oil Sands Mining (based on ERCL's 25% share of Syncrude Canada Ltd.)
Coal
Facility breakdown includes:
Gas Wells
Gas Gathering
Gas Plants
Oil Wells
Oil Satellite Batteries
Oil Central Batteries
Heavy Oil Wells
Heavy Oil Satellite Batteries
Heavy Oil Central Batteries
Crude Bitumen Wells
Crude Bitumen Satellite Batteries
Crude Bitumen Steam Injection Plants
Major source type breakdown includes the followin

.
g categories (reference Figure 6):

Leaking equipment - Facilities
- Wells
Process vents
- Facilities
- Wells
Combustion sources
Tankage
Other miscellaneous sources (trucking s ,11
, p1 s,etc)

 17
Figure

6

Description

of Production

Gas

Facilities

Water, Crude Bitumen , Gas
Reservoir

Gas

--

Water

Water, Oil, Gas

~'

~

~,

,

Crude Bitumen Wells

Oil or Heavy Oil Wells

Gas Wells

Steam

Single Well Batteries

Gas Gathering

Satellite
Gas Plant

Batteries

Satellite

Central Batteries

Steam Injection Plants

Gas

....
--

Oil

~'
Gas

....

Sales

Batteries

Crude Bitumen

--

 18

Figure 6 Description of Production

Facilities (cont'd)

Major Source Categories:

Equipment Source Type:

Leaking Equipment Facilities

Piping

Process Vents

Wells

Well Surface Casing

Facilities

Field Dehydrat ion
Gas Instrumentation
Gas Operated Pumps

Wells

Crude Bitumen Vent Gas
Heavy Oil Vent Gas

Combus.ttii1001n,-~~~~~~~~~~~~-:::---:--:-:-~~~~~~~
Reboiler
Heaters
Boilers
Flares
Incinerators
Reciprocating Engines
Turbine Engines

I

Tankage

Other

Tankage

Spills
AOF Tests
Vehicles
Trucking

l

 19
Accuracy
The inventory has been structured to provide a scoping level of accuracy with
sufficient data on all greenhouse gases to allow for identification of feasible
opportunities to reduce, and for future baseline comparisons.
The accuracy required for any potential source was determined by:
• The significance of this source to the sum of emissions for the gas type , and
the relationship of this gas type in terms of 0/o of overall ERCL emissions , and
by;
• Degree to which it was felt the emission could be practically reduced
The accuracy of cost data is also of scoping quality (ie best estimates).
To facilitate ease of addition of numbers, one significant digit has been used in most.
tables, and where required, round off of overall numbers has been done. The reader
is cautioned not to associate a high degree of accuracy with any reported emissions
totals.

Data Gathering
Most emission factors were obtained from a recently completed CH4 - VOC study by
the Canadian Petroleum Association, with other factors developed from generally
accepted industry standards and other empirical correlations.
Fuel and equipment data was obtained by facility type from individual field areas . A
sample of one of the data input sheets sheets provided to all field areas is included in
Appendix 2.
In general, fuel volumes were obtained from reporting systems feeding Alberta and
other government "S" reports. Where this data was not available, estimates were
based on ratios to similar operations. Equipment numbers are those for equipment in
operation in 1989. Again, where numbers were not available, estimates were based
on similar operations.
For determination of total emission factors per unit of production, production data for
1989 was obtained from ERCL's "Winner" database.
Cost data was taken from historical ERCL cost information.

 22
Tables % Total co2eEmissions by Gas Type
/o of Tota l

0

Gas

41 °/o
26°/o
26°/o
6°/o
1°/o
<1 °/o

CO2
NOx
CH4

voe
N20
CFC

Carbon dioxide is clearly the predominant greenhouse gas emission. for ER(?L w ith its
production almost entirely associated with energy needs for production o.f 0 11and g.as.
When gas emissions are compared on a 20 year equivalent global warming potential
basis, Methane and NOx are significant emission sources.
Emissions for both voe and Nitrous Oxide are not considered significant. CFC
emissions are extremely minor and as such are not included in most tables and
·
graphs.
Further breakdown of overall emissions by Major Source category is provided in
Table 6, with the 0/o of total C02E emissions for each Major Source type shown in
Figure 9.

Iilble 6 Summa[l! gf Igtal EBCL EmlsSIQDS
bl£ Majg[ SQ!,m:eCategg[ll
(~I ~Q2El~cl

CO2
Leaking Equip.
Process Vents
Combustion
Tankage
Other

4085

Total

4365

NOx

2740

N20

CH4

Total

% Total

279
124
186
21

830
1110
570
150
50

1109
1234
7495
336
351

11
12
71

610

2710

10525

100

100

280
2740

voe

100

3
3

 23

Process
Vents

Combustion

Figure 9 % C02E Emission by Major Source category

Resultsby Production Sector
General
Sector contributions to the overall greenhouse gas totals, are shown in Figure 1O and
listed in Tables 7, and 8. These results indicate that the Natural Gas sector is the main
contributor to overall emissions.

5000

4825

4500
4000
3500
3000
kt/yr
2500
C02E 2000
1500
1000
500
0

Iii. CH4
2589

Ill

\CC

II

N20

DNOx
176

GB

Oil

HeavyOil

Crude
Bitumen

Coal

Figure 10 C02E Emissions by Production Sector

·~

 24
Carbon.dioxide emissionsare highest in the Crude Bitumen sector, reflecting h!gh
e.nergyinput requirementsassociatedwith thermal methods ~sed to produce this
v1scou.s
crude. CO2 emissionsfrom the Natural<:3asProduction sector are ~Isa large,
reflect.mgthe large gas compressionand processingneeds for mature gas fields and
associatedgas production. NOx emissionsare also very high for the Natural Gas
sector as a result of the large numberof reciprocatingengines used in gas
compre~sionservice. Methanelosses are mainly associated with Natural Gas
production:and Heavy Oil production. Heavy Oil production Methane losses are
almost entirely from the ventingof wellheadcasing gas.

Ilbll Z EmllllQD111:11kdQWD
bx S1'1Q[(kl ,a2ELX[)
Sector:

Cs
Oil
Heavy Oil

Crude Bitumen
Coal
Total

CXl!
1740
596
55
1919
55
4365

CXl!

N)x

N20

2080
255
60
280
65
2740

75
9
3
10
3
100

CH4

\CC
50
448
39
70
3
610

\CC

CH4 Total for % Total
Sector
Sector
880
4825
46
525
1833
17
945
1102
10
310
2589
25
50
176
2
2710
10525
100

NOx

N20

40%

32%

8%

76%

76%

14%

19%

73%

9%

9%

35%

6%

2%

3%

11%

10%

10%

2%

2%

100%

100%

 25
Table9
Direct

Sector co2E Em SSIQnerQ~U,IIQD F~ctQrs

Greenhouse

Gases

03

Precursors

kg CO2

kg CH4 (C02E)

kg N20 (C02E)

per OEM3P

per OEM3P

per OEM3P

155

80

5

430

5

185

53

47

1

165

40

23

Heavy Oil

1 85

3241

9

3775

135

205

Crude Bit

378

62

2

510

13

55

Oil Sands
Mining **

721

17

7

984

53

182

64

56

2

200

4

74

kg CO2/
tonne prod.

kg CH4 (C02E)
tonne prod.

32

28

Tot. kg C02E
per OEM3P

kg voe (C02E) kg NOx(C02E)
per OEM3P
per OEM3P

Sector
Gas Procr
Oil Prod

Coal

Coal

kg N20 (C02E} Tot. kg C02E/
tonne prod.
tonne prod.

1

100

kg VOCI
tonne prod.

2

kg NOx
tonne prod
37

• inc~u~ects.
all emi~si~ns associated with the production of NGLs and associated gas used for gas
..r~-m1e ,on or m1sc1bleflooding.
'
includes upgrading

Natural Gas Production Sector
Total e!"issions from the Natural Gas production sector of 4825 kt/yr C02E are
approximately 46°/o of total emissions for ERCL. Primary equipment contributors to
CO2, NOx and CH4 emissions are within gas plants, and include reciprocating
engines, turbine engines, and other fuel users. Approximately 5% of ERCL's total
CO2 emissions are related to capture of CO2 during sour gas processing, and
subsequent atmospheric release.
Significant Methane losses for natural gas production are those associated with
unburned fuel gas used in reciprocating compressors and flares, surface casing
emissions, and with fugitive emissions from leaking equipment. A Methane loss of
0.18% of production (wellhead to pipeline sales) has been calculated for the Natural
Gas sector.
NOx emissions from reciprocating gas engines within the Natural Gas sector account
for approximately 70% of the total NOx emissions for ERCL. Co~sidering this large
emission total and the lack of understanding of how to apply indirect C02E factors for
NOx to Canadian conditions. research studies aimed at identifying gas plant NOx
contributions to ozone should be investigated.

 26
duction and processing are
gdas
ep~oor
approximately 430 kg C02E/ Oil
emissions
for
natural
Total greenhouse gas
E/m of gas pro uc
3
estimated to be 0.43 kg C02 d

equivalent m3 of gas produce ·

.

. . T pe and MaJor
Tables 1o and 11 list emissions by Facility y

Source category for th
e

Natural Gas sector.

- mlllJIO.n~D~tst11tr:1.ttbn.Y1rutt2on.o
J,jb!.J.Y
-1E
Ji!all(.c
wm~1y._
.....
Ty....
p_e
Table10 GassectorEm1ss1oos
(kt C02E/yrl
NOx
N20

Total

CO2

CH4

voe

Gas Plants
Gas Wells
Gas Gathering

1661
78
1

673
180
27

42
7
1

2069
10
1

74
1
0

4519
276

Total

1740

880

50

2080

75

4825

30

Table11 Gassector Emissionsby Major Source Category
CktC02E/yr)
CO2

CH4

voe

Leaking Equip.
Process Vents
Combustion
Tankage
Other

25

1557

436
83
353
8

Total

1740

NOx

N20

Total

461
89

6

18

2080

75

4 083
9

1

183

183
880

50

2080

75

48 25

Oil Production Sector
CO2 emissions associated with conventional Oil production are mainly relat ed to
natural gas used as fuel in treating operations, and with flaring of solution gas. The
Oil production sector is a surprising high emission source of leaking equ ipment CH4
volumes at 24o/oof the total for ERCL. Tankage is a major source of voe emissions,
and tankage emissions are split approximately 70% Central Batteries 18o/o Satellite
'
Batteries, and 12 % for Single Well Batteries.
Total greenhouse gas. emissions for c~n~entional oil production are estimated to be
16 5 kg C02E/m~ of. 011pro.duced. Em1ss1onswithin the Oil Sector are distributed by
Facility Type as indicated in Table 12 and by Major Source category as indicated in
Table 13.

Table 12

onsector EmlsstonsPlstrtbuuonby facmty Type Cktco Etyr}

Central Batteries
Satellite Batteries
Single Wells
Other
Total

2

CO2
419
69
105
3

CH4
278
63
180
4

596

525

voe
221
76
151
0
448

NOx
209
13
30
3
255

N20
7
1
1

-

Total
1133

222

0

467
10

9

1833

-

 27
Table13 QII Sectocl;m1ss1oosby MajocSoucceCatego~ (kl CQ21;
Ln l
CO2

C H4

voe

Leaking Equip.
Process Vents
Combustion
Tankage
Oth er

596

200
220
90
15

213
58
10
166
1

Total

596

525

448

N20

Total

255

9

4 13
278
96 0
18 1
1

255

9

1833

NO x

Heavy Oil Production Sector
EReL h~s _divest~d all conventional Heavy Oil production in 1990 and as such 1990
total em1ss1onswill be reduced by 1102 kt/yr eo2E. Emissions within the
conventional Heavy Oil sector are heavily influenced by Methane losses associated
with wellhead casing gas venting and single well battery tankage. Oil tankage
contributions are also a significant percentage of the total EReL tankage emissions
due to the large number of single well batteries in the Heavy Oil sector, and use of
tankage vapor compositions as reported by Picard for this gas10 which have a high
% Methane vs voe.
Total greenhouse gas emissions for Heavy Oil production are surprisingly high at
3775 kg e02E/m3 of Heavy Oil produced. Of this total, almost 3150 kg e02E/m3 is
related to wellhead venting of Methane and voe. The venting effect has a dramatic
effect on total C02E emissions. Depending on Gas/Oil ratio, the venting effect could
be equivalent to the CO2 from combustion of the fuel itself. Total eo2E emissions for
Heavy Oil should be viewed as very preliminary given our limited confidence levels
in emission factors and global warming potential factors. None-the-less these high
production emissions, point out the need for a full life cycle assessment of all
greenhouse gases for each primary energy source.
Emissions within the Heavy Oil sector are not broken out by Facility Type.
by Major Source type are listed in Table 14.

Emissions

Table 14 HeayY011sectoc1;m1ss1oos
by MajorSourceCatego~
(kl CQ2Elyc>
CO2

LeakingEquip.
ProcessVents
Combustion

55

Tankage

CH4

voe

50
755
10
130

4
17
1
17

945

39

NOx

N20

60

3

60

3

Total

54
772
129
147

Other

Total

55

1102

10 PicardDJ, Koon KW. An inventoryof CH4 and VOC emissions from upstream oil and gas

operations in Alberta, Oct 1990, page 97, table 15

 28
Crude Bitumen Production Sector
. .
Crude Bitume n production sector.
Carbon dioxide emissions are very hi~h in theociated with boile r ope rations within the
These CO2 emissions are almost entire1Y ass
Steam Injection Plants.
.
d th emissions of casing ga s (or vent gas)
Methane emissions are primarily relat~ to e
·t· f r Methane inclu de the
.
from a small number of wells. Reduction opporturn 1es O
collection and combustion or compression of this gas, although econo mic recovery
for either of these methods is not feasible with current technology.
Total greenhouse gas emissions for Crude Bitumen production are estimate d to be
51O kg C02E/m3 of Crude Bitumen produced.
It should be noted that a significant investment has already been made wit hin ERCL
for vent gas compression facilities. Without these facilities the CH4 contr ibutions from
the Crude Bitumen Sector would be 4.5 M t /yr COE , ie greater than current overall
ERCL CH4 contribution, and the production emission factor for Crude Bitume n would
be 1440 kg C02E/m3.
Tables 15 and 16 list Crude Bitumen sector emissions by Facility Type and Major
Source category.
.
Table 1s CrudeBitumenSectorEmissionsDistribution by Faclllty Type
(kt C02Elyr)

Single Well
Satellite Battery
Steam lnj. Plant
Total

CO2

CH4

voe

3
1916

4
280
26

64
6

310

70

1919

Table 1& CrudeBitumen
Sectoremis1

NOx

sons by M
listco2e'Y.rla1or

CO2
· Leaking Equip.
Process Vents
Combustion
Tarbge
Other
Total

1825
94
1919

CH4
68
236
5
1

310

voe
6
62
2

-

70

N20

Total

280

10

4
347
2238

280

10

2589

·

NOx

280

280

sourcecategory
N20

Total

10

74
298
2122
1
94

10

2589

 29
Oil Sands Mining Sector
No breakdown is provided, other than the totals by Major Source category listed in
Table 17. Emissions are 25°/oof those reported by Syncrude Canada Ltd and are not
included in ERCL reported totals.

Table 11 011SandsMiningEmissionsby Majorsource category
(kt C02E/yr}
CO2
Leaking Equip.
Process Vents
Combustion
Tankage
Other

1557

Total

1557

CH4

voe

NOx

397
36

114

36

114

Total

N20

1968

14

150

397

2118

14

Oil Sands Mining totals include upgrading of recovered Bitumen and all onsite
electricity generation emissions.

Coal Production Sector
Total greenhouse gas emissions for Coal in relation to overall ERCL totals are not
significant. Combustion CO2 emissions are almost evenly split between emissions
from diesel fuel needed for mobile mining equipment, and from natural gas used for
coal drying. CH4 losses are primarily those estimated from exposure of the coal seam
during mining operations. NOx emissions are almost entirely from diesel equipment
used for mining operations.
Total greenhouse gas emissions for coal production are estimated to be 100 kg
C02E/tonne of coal produced. No breakdown is provided, other than the totals by
Major Source category listed in Table 18.

Table 1a coal Mining Emissionsby Majorsource category
(kt C02E/yr}
CO2

LeakingEquip.
ProcessVents
Combustion
Tankage
Other

55

Total

55

CH4

voe

NOx

65

50

3

50

3

N20

3

Total

123

53
65

3

176

 30
Resultsby GeographicArea

Fig 11 illustrates the distribution of total emissions by geowaphic area. A summary 01
total ERCL emissions by geographic area is also included in Table 19. Emissions
concentrated in Alberta, reflecting the high proportion of oil and gas production in are
this province .. Methane losses reported in Saskatchewan are almost entirely
associated with Heavy Oil casing vents.

Table19TotalERCLEmissionsby GeographicArea
(kt C02Etyr}
Sask.

Alberta

NOx

130
60

4106
1580
94
<1
400
2580

Total

1286

8780

104
990
2

CO2
CH4
N20
CFC

voe

N.W.T.

B.C.
40
100
2

Total

115
40
2

40
50

40
50

4365
2710
100
<1
610
2740

232

247

10525

100
90

·~

80
70
60

0

50

CH4

40

ml\CC

30

.NOx

20
10
0
Sask.

Alberta

N.W.T.
Figure 11 Total ERCL Eml
sslons b

Y Geograph1c Area

 31

.c_omparisons
to Other Inventories
Esso Resources is currently the largest producer of Crude Oil and Crude Bitumen in
Albert~, ~n~ the fou~h p~oducer of Natural Gas and Natural Gas Liquids. Although
there 1~limited baseline inventory data to compare to, ERCL's emissions, with the
exception of CH4 and VOC, appear to roughly correspond with ERCL's estimated
overall 16°/oshare of the upstream petroleum industry.
Inventory results show that total ERCL Alberta CO2 emissions are 18°/oof those
reported by Alberta Energy for the oil and gas sector in Alberta . This ratio reflects:
* ERCL's large share of Crude Bitumen production
• Operations of more mature oil and gas fields
• Large compression requirements for the gas sector

However, ERCL CH4 and VOC emissions are approximately 5°/oof those reported by
the CPA for Alberta and below what might be anticipated based on product market
shares. Significant differences between this inventory and the CPA inventory are:
• ERCL gas instrumentation losses are not as large
• ERCL tankage losses are not as large
Other reasons for lower estimates of CH4 and voe for ERCL are thought to be:
• Safety and Industrial Hygiene audits over the last several years that
have resulted in improvements to vented hX~~ocarbons
• A higher level of electrification of ERCL fac1ht1es
• More centralized facilities

ERCL NOx emissions for Alberta are approximately 12°/0~f Natural Gas emissions
1
reported for Alberta in the NOx-VOC management plan.

 32
ConfidenceLimits

d voe emissions are highly sens itive
rs for·
As noted earlier, total volumes for Me~h~ne an
·
to average emission factors used. This includes facto
Leaking equipment connections and seals
Surface casings losses per well
Single well tankage
.
Reciprocating engine combustion losses
Gas instrumentation
For leaking equipment connections and seals, it is recommended that a~ initial series
of screening tests be conducted to determine the percentage of connect_1o~sand
seals leaking. Additional confirmation of leaking equipment average em1ss1onfactors
should follow this first step.
Other factors that have an effect on overall results are those used for NOx and N20 .
Table 20 lists out possible ranges for some of the key emission factors used in the
reported numbers. (See Appendix 2 {Methodology} for discussion of these ranges)
The effect on total emissions of these higher and lower factors is detailed in Table 21.
I1bl1 20 Key AllemgeEml&&ltmEa~~n&

factor

LowCase

~

Base Case

High case

sm3/sm3 Gas Prod

0.072

0.72

0.025

m3/d/well

35

136

5

kg/d/job

14

28

3

ppmv flue gas

2000

2500

1000

Leaking Equip
Factors (all)

kg/hr

CPA Factors

CPA Factors

50% CPA Factors

Tankage

kpaa

69

69

58.6

k sm3/yr/km

0.01

0.03

0

20.17

9.9 1

0.07

0.00~

Gas Instruments
Surface Casing
Well Servicing
Recip Eng NOx

Gas Line Maint.
Recip Eng CH4
N20

GasJ:ype

t CH4/ M Sm3 Gas

19.82

ka/ka NOx

0.02

Jable21 summaryot ERCLlnlfentorvEm15
5100BangesCktco2E1yrl

High Case

n/a

BaseCase

4365

Low Case

n/a

3260
2740
1700

482
100
20

610

3550

795

2710

406

2030

 33
fl.eduction Opportunities and

Costs

General
Opportunities to reduc_eeri:,issions ~an be separated into items currently being
considered for _regulation, item~ estimated to be "economically" feasible (ie recover
the cost of ~ap1tal), and Jhose items that are ''technically feasible" (ie contribute
towards em1ss1onreductions but are not economically attractive for ERCL to pursue).
It should also be recognized that the inter-relationships between various greenhouse
gases can provide for synergy in reducing emissions for more than one greenhouse
gas, and can also negate the full effects of efforts to reduce overall emissions.
For example synergy between CO2, NOx, and CH4 emission reductions is possible
for reciprocating engines with the right technology selection, however with the wrong
technology selection, CO2 emissions could rise from efforts to reduce NOx emissions.

Overall Reduction Potential
Recognizing these inter-relationships the estimated net reduction potential for the most
significant reduction opportunities for ERCL are shown in Figure 12 below. Other
reduction opportunities such as credits for CO2 sinks, etc, may be available to ERCL
but are dependant on the use of market based approaches (ie tradeable emission
permits) as a greenhouse gas control mechanism.
Surface Casing Vent Reductions
Enhanced Oil Recovery
Un-Economical Energy Efficiency Items
Cogeneration
Un-Economical Fugitive Emissions
Low NOx Burners
•
Vent Gas Recovery (Crude Bitumen)
Additional Recip. Engine NOx Controls
Recip. Engine Air I Fuel Controls
Economical Fugitive Emissions
Economical Energy Efficiency Uems

0

1000
kt/yr

2000
C02E

3000

(20 year

4000

factors)

Figure 12 Estimated C02E Reduction Potential for ERCL

 34
The largest individual reduction opportunities for ERCL based on a 20 year time
horizon are:
• Enhanced oil recovery (EOR)
. f
• Reciprocating engine NOx reductions
.
• CO2 and NOx reductions that occur from the introduction of air I ue 1
controls on reciprocating engines
The major reduction opportunities (economically and techni.cally feasible), for CO2
are the use of CO2 in enhanced oil recovery and the reduction of CO2 from
increased energy efficiency.
The major reduction opportunities (economically and technically feasible) for
Methane are summarized below:
• Fugitive emission control programs
- Leak detection and repair programs
- Improved fugitive emissions technology and maintenance practices
(Eg. valve packing, mechanical seal replacements, valve back seating
and other operating practices)
• Collection and sale of individual or single point Methane losses
- Eg Crude Bitumen vent gas
• Instrument gas replacement with air or electric instrumentation
• Collections and combustion for minor Methane releases where sale of this
gas is not practical
- Eg Oil Central Battery tankage
• Improved operational and maintenance awareness practices
- Reduced small volume releases
The m.ajor reduction opportunities (economically and technically feasible) for NOx
reduction are:
• Reciprocating engine NOx reductions
• Low NOx burner retrofits for fired heaters and boilers
The major ~eduction opportunities (economically and technically feasible) f
loss reduction are:
or
• Tankage vapor collection
• Reductions obtained from implementation of Methane

voe

d .
.
re uct1on proJects
.
In general it should be noted that control options to reduce N
control options for CH4 reduction will also reduce VOC's.
Ox will reduce N20, and

 35
potential Reduction Costs
There ~xist.s for Esso, a seriatim of increasin 1 .
shown rn Figure 13 . Reduction opportun·r gt higher cost reduction opportunities as
pursue ,"ie current economic opportunit'~i~s
t at make sense in their own right to
1
These opportunities include items such a! '~~v .e reduction costs that are negative.
reduction opportunities associated with re a itional energy efficiency, and other
"valued" product. Reduction op ortunitie covery or r~duced consumption of a
large environmental cost to CO2~ emissi; that a~e highly positive suggest that a
these items could proceed.
ns wou d have to be established before

Potential Range of CO2 Tax
Surface Casing Vent Reductions

:-:-:-:-:-:-:
----------------- --_._..__________________________
_

Enhanced Oil Recovery
Un-Economical Energy Efficiency Items
Cogeneration
Un-Economical Fugitive Emissions
Low NOx Burners
Vent Gas Recovery (Crude Bitumen)
Additional Recip. Engine NOx Controls
Recip. Engine Air/Fuel

Controls

Economical Energy Efficiency Items

-25

-15

-5

5

$/tonne

C02E

15

25

35

45

55

(20 year factors)

Figure 13 Seriatim of Ranges to Average Reduction Costs (S0cial)12
Also shown on Figure 13 for comparison purposes, is the potential range of carbon
taxes that have been proposed for dealing with CO2 emissions. This range is up to
200$/tonne of Carbon or 55$/tonne of CO2. It should be noted that a carbon tax is
only one mechanism that governments may employ to reduce greenhouse gas
emissions.

12Social cost of reduction based on 1Oyears and 10% discount

 36
. 1and costs
Summary of Reduction Potentia
f the most significant
.
otential and costs or low As noted earlier the
A summary of combined reductio~spsho
wn in Table 22_be ot~ntial reductions for CO2
reduction opportunities for ~R~\~ls are associated wiht~ral Gas production sector. '
majority of emission reduction
trated within the a
NOx, and Methane, and are concen

°

T

v•~_mllJ~fil!bQJ~e~G~a~suR~e~d~u~c~t~io
ble
22 Summar~
of overallGreenhous
a
Before Tax Costs 1990$)
1

Reduction Potential

capital
( M $)

Avg Net Oper. Avg Red.Cost
Cost (M$/yr)
Social ($It)

% 1989*
(%)

C02E
(Kt/yr)

n/a

n/a

Divestments (Heavy Oil)

1100

n/a

9
1

170

45

0

40

"Regul atory" Items

13

375
270
950
1595

18
0
2
20

-8
-0 .1
-0.9
-9

-13
-1
-0.5
-4

Additional Recip. Eng. NOx
Vent Gas (Cold Lake)
Low NOx Burners
Additional Fug. Emissions
Co-generation
Un-economical EE Items
Enhanced Oil Recovery
Sub Total "Tech. Feasible" Items

8
5
4
0
70
273
2000
2360

0.2
0
0.1
0.6
-8.9
27
15
34

1
3
3
5

52

1450
270
230
130
270
450
3650
6450

.. 20

Total Excluding Divestments

66

8215

2425

25

**15

Description

Economical EE Items
Fugitive Emissions Controls
Recip. Engine A/F Control
Sub Total "Economic" Items

• 1989 basis (12400 kt/yr) includes 1989 inventory results (10500 kt/yr) and electrical
of 1900 kt/yr
"" includes hydrocarbon recovery benefits from Enhanced Oil Recovery (EOR)

6
30
30

CO2 emissions

One of t~e largest Methane emission sou~ces, conventional Heavy Oil, has been
divested in 1990 by ERCL, and as such will reduce ERCL emissions by 11 ookt/yr
C02E.
"Regulatory" opportunities ~re those measures that are deem d l'k
t b
implemented for other environmental considerations Th '
e I e I~ 0 e
reduction plans for surface casing leaks which are ·cur is t~atbeg_ory
includes d .
eing
develope
in
response to pending ERCB regulations. '
ren Y
"Economically feasible" CO2 reductions focus O
. .
.
measures and other measures such as fu itive n _ad~itional energy conservation
for the recovery of a valued product (eg Mgethaem)ission control programs which alloW
Methane losses, appr~ximately 300 k$/yr is es~~ · Of the estimated 2.7 M$/yr in
recoverable from a hm1tedfugitive emissions
mated to be "economically"
economic recovery of other Methane and v~o;yoi pro~ram. The potential fo~.
asses is not considered significant

 37
iventhe large number of individua l sources . In addition
.
·
tethane recovery are not clearly understood . For exam' i oss1bletra~eotts for
. crease NOx levels. Improvements to air fuel co ntrols
combu.st1on of CH4 will
inngines, represent an economically feasible energy c
to.r reciprocating
fhe potential to make large reductions in NOx .
onservation measure, that has

(i;)•

Significant reduction. opportunities that are "technically feasible" in I d
e fthehuseof
CO2 for enhanced oil recovery' co-generation of steam and powerc u d
·
·
t
reduce
NO
·
·
·
,
an
opportunities o
x in reciprocating engines Other opport 'f urt er
NOx are consistent with the NOx - VOC Manageme nt Plan and ·,ncl udni,tehs
to redu.ce
· · NO th t
b
bt · d
u e e potential
x a may e o ame by low NOx burner retrofit of boiler, and
reductionm
process heaters.
WiJhrespect to ~v~~all emission.s reduction pot~ntial for ERCL , clearly the technology
exists for very s1grnf1cantreductions, but to achieve these reductions the costs are
also extremely larQe. The majority of ~hese cos~s are within the "technically feasible"
category and are hnked to the reduction potential associated with enhanced oil
recovery. These "technically feasible" opportunities are unlikely to be implemented
unless further technology development can significant ly lower costs, allowing these
opportunities to compete with other economic greenhouse gas reduction
opportunities. Considering the limited scope for significant economic reduction
opportunities for ERCL, the cost and benefits of other potential reduction .opportunities
outside of the oil and gas industry will require further study should an em1ss1ons
trading system be established by governments .
Costs to reduce CO2 associated with energy efficiency items and disposal are
outlined in more detail in IOL's global warming energy conservation and CO2
disposal papers.

 38

I 'ilECQIMHNHE
ft ID>
I\ fijQ'I J;;.
•

c arbon Dioxide
.
· ·on source
for ERCL.
t emissions of
is the primary greenhouse g.as emi~si 'f

Methane

and NOx emissions on a 20 year C02E basis are s1gni,can
greenhouse gases for ERCL.

ti

20
~e~e~i~e u~ed.
• When emissions are viewed under alternate time horizons to
(eg 100 year), the effect of greenhouse gas emissions fro~
. x an .
ane is
greatly reduced . A standard approach to emissions reporting is required by
.
governments, as the selection of an overall reduction strategy needs to recognize
these alternate methods of viewing emission data.
• To further assist in the development of effective reduction s~ra!egies, a full li!e cycle
assessment by Imperial Oil or others of greenhouse gas em1ss1onsfrom fossil fuels
and their alternatives in various end uses is recommended.
• Considering the large NOx 20 year C02E total for ERCL, and the l~ck of kn.~wledge
of how to apply indirect C02E factors for NOx emissions to Ca~ad1.ancond1t1ons,
research opportunities aimed at identifying gas plant NOx contributions to
greenhouse gases should be investigated by ERCL's Research and Technology
division.
• Significant reductions in greenhouse gas emissions by ERCL are possible, but to
achieve these reductions the costs are extremely large. Further work is
recommended by ERCL engineering support groups for significant reduction
opportunities such as the use of CO2 for enhanced oil recovery that are
"technically feasible", but fall short of being "economically" feasible at this time.
This work should attempt to identify limiting factors such as technology development
or other needs required to make these opportunities economically attractive.
• The potential for "economically" feasible reduction opportunities is estimated at
13°/o ~f ERCL's ~arbon dioxid_e~quivalent greenhouse gas emissions and
asso_c1ated.electrical CO2 em1ss!ons. Implementation of these opportunities would
requ.1rean invest~ent of ap~rox1mately20 M$. Additional detailed engineering
studies by oper_a_ting
groups 1sr~commended consistent with the intent to implement
these opportunities where possible .
• Economical redu~tion opportunities ~or_CO2appear to be limited to additional
energy conservation
measures at this
·
t·ing engine
·
.
. time · Improvements ·,n rec1proca
performance 1san ene_rgyconservation measure that also has th
t f f
significant NOx reductions. Synergy between co2 NO
e po en ,aI _or.
reductions is possible for reciprocating engines with thex'. ahntdMethane em1ss1~n
.
ng technology selection.
.
• on the basis of current fugitive emission factors a
Methane losses, are thought to be "economically" pproximately 10°/oof total ERCL
fugitive emissions _control~ro~~am. The potential /ecoverabl~ from a limited
losses is not considered s1gnif1cantgiven the la or economic recovery of other
rge number of individual sources.

 39

_voe

• Methane and
~mission totals are highly sensitive to the average emission
factors used tn the inventory. Field verification of these factors, including factors
for fugitive emissions , is required to improve on the estimated +/- 30°/o accuracy for
overall Methane emissions. ERCL through its participation in industry associations,
should complete field verification of CH4 emissions factors by fully
participating in future industry field verification plans.

voe

• Venting of conventional Heavy Oil wells is a major source of Methane emissions.
ERCL has divested all conventional Heavy Oil production in 1990 and as such
1990 ERCL total emissions will be reduced by 1100 kt/yr C02E . The effect of
venting Methane with oil production can have a dramatic effect on total C02E
emissions. Depending on gas to oil ratio, this venting effect could be equivalent to
the CO2 from the combustion of the fuel itself.
• 1989 emissions inventory data can serve as a baseline and reference source for
fuel compositions and other data for future inventories. Clarification on the need for,
timing, and accuracy requirements of future inventories is required by govern ments.
Given the considerable effort a Methane inventory requires, Methane inventories
should be limited to only those necessary to determine progress in emissions
control.

 40

Gl0$$ABY Of J~fBMS (Y@~Yffliil ~@S1
Abbreviations:
AOF
Absolute open flow
CH4
Methane
CO2
Carbon Dioxide
Carbon Dioxide Equivalent
C02E
Comb.
Combustion
. .
Chemical
Manufactures
Assoc1at1on
CMA
Canadian Petroleum Association
CPA
Enhanced Oil Recovery
EOR
Esso Resources Canada Limited
ERCL
Alberta
Energy Resources Conservation Board
ERCB
Environmental Protection Agency
EPA
FG
Fuel Gas
Gas
Processors Suppliers Association
GPSA
Heavy Liquid
HL
Higher Heating Value
HHV
Imperial Oil Limited
IOL
Lower Heating Value
LHV
Light Liquid
LL
Mole
Mol
Molecular Weight
MW
Natural Gas Liquids
NGL
Pressure Safety Valve
PSV
Reciprocating
Recip
Open
Ended
OE
Oil Sands
OS
Ozone
03
Nitrous Oxide
N20
Nitrogen Oxides
NOx
Sample
Smpl
Stock Tank Vapor Recovery
STVR
Total
Hydrocarbon Content
THC
Volatile Organic Compounds
voe
Year
Yr
Units:
k

M

s
t

Thousand
Million
Standard
tonnes

 41

Resultsby GasType and EquipmentType
CO2
The major source of CO2 is combustion (95°/oof total), with approximately 5 °/oof the
total volume associated with CO2 scrubbing and release to atmosphere in sour gas
plants. Breakout of CO2 by Equipment type is illustrated in Figure 14 and Table 23.

Table 23 summary of co2 Emissions
by Equipment Type

Other

source

hlLU

Engines

1290

Flares
Fired Equip

Fired
Equip.

Figure 14 CO2 Emissions by Equipment Type

440
2355

Other

280

Total

4365

 42

Methane

· F
s 15 and 16 by Majo r
Major contributors to Methane losses are shown ,n ,gure
Source category and by Equipment Type .
Other
Other
Leaking
Equ.

Tankage
Fired Equip.
Flares
Engines

Comb .

,::__

-t:-~~~~~~~~~---.

Vent (HO) 1--------~~~-.J
Vent (CB) ~---Dehydration
Well Serv .
Gas Instr.
Surf. Casing•••
Piping

,~!!!~~~~~~~
0

5

10

15

20

J...---1
25 30

O/o

Figure 15
Methane Emissions by Major Source

Figure 16
Methane Emissions by Equipment Type
• Vent (HO) - Venting of conventional Heavy Oil wells
• Vent (CB) - Venting of Crude Bitumen wells

Table 24 shows the most significant Methane loss contributors within equipment
categories and the value of the Methane losses per point source using a Methane
value of $0.0529 I sm3. The before tax cumulative value of all Methane sources is
approximately 2.7 m$.

!able 2! ~aluegf Me1bane
Lgsses
Equipment category
•
•
•
•
•

Combustion losses in recip.engines
Combustionlosses from flaring
Ventingof Heavy Oil wells
Ventingof Crude Bitumenwells
Fugitiveemissionsfrom leaking
equipmentseals and connections
• Surfacecasing leaks
• Venting of off gas from glycol
dehydration
• Gas Instrumentationand gas
driven pump losses
• Well servicing
*Tank

CH4 Value Value/#S
(k$/yr) ($ I yr /#S)

Number of
sources (#S)

CH4 Volume
( k m3/yr)

586
253
300
20
536284

10500
2750
17600
5500
16000

557
146

409
100

3940
470

208
25

1479

1270

67

2402
698

1400
3600

74
191

933
293

846

950

570

31oo

14500
2

500
250
45

 43

voe
Majorcontributors to ':fOelosses are shown in Figure 17
categoryand by Equipment type.
and 18 by Major Source

Other

Other

Tankage
Combustion
Vent (HO)
Leaking
Equ.

Vent (CB)

_t-----'

Dehydration
Well Serv.
Gas Instr.

Combustion

Surf. Casing
Piping

0

5

10

15

20

25
%

Figure 18

voe Emissions by Equipment

Figure 17
voe Emissions by Major source

Type

• Vent (HO) - Venting of conventional Heavy Oil wells
• Vent (CB) - Venting of Crude Bitumen wells

voe emissions are closely associated with Methane and emission volumes are in
turn also highly dependent on average emission factors. Emissions from piping,
tan~age,and other miscellaneous sources are the primary source of voes. Other
emissionthat were not considered significant and were not included in the inventory
are:
Road oiling voe
Land treatment voe
Other waste oil treatment

voe

30

 44
NOx

.
. . d for natural gas and other
e of combustion util!ze hown in Fig 19 and listed
NOx emissions are related to the t Pby Equipment type is s
!uels. The breakdown of NOx tota s
ie
summary of NOx Emtss1~
25
in Table 25.
Iab
.t2Yeombustlon Source

1

~mb, source
Recip Engines
Fired Equip *
Total

kt/yr C02E ~
2300

15.3

440

2.9

2740

18 .2

• Includes Turbines

Figure 19 NOx Emissions by Combustion Sources

Total emissions for NOx range from 1.7 Mt/yr C02E to ~.3 Mt/yr CO~E, depend in~. on
the NOx emissions factors chosen for reciprocating engines. Reduction opportunit ies
for NOx emissions from reciprocating engines include the installation of low NOx
combustion ignition systems, and other low NOx retrofit systems. However further
feasibility analysis of these retrofit systems is required to confirm cost and other
potential tradeoffs including the potential loss of engine efficiency, and hence higher
CO2 emissions.
Furt~er reduction opportunities for NOx emissions from fired heaters are technically
pos~1ble,~ow;ver, 1tshould be noted that the crude bitumen sector already has
relatively low NOx burners, and the c~nventi~nal oil and gas sector does not
appear to have large numbers of potential applications for lower NOx combustion
technology .

N20
Nitrous Oxide emissions are based on a ratio of NO
· .
emissions sources (Major Source and Equipment T x em)issions a~d as such
sources shown above.
ype are consistent with the NOx
CFC
CFC emissions are not broken out due to th . .
ER(?~'s ~F.C's will be consistent with Canade~~sminor
nature . Red uction plans for
add1t~~n
. _it1srec~m,:nendedthat ERCL pro
Green Pla n of December 1990. In
cond1t1onmgrepair firms to use recycle met~o~e recycle of CFC's by requesting air
0 s when conduct·ing
ERCL systems.
. t enance o n
main

-

 .M,ethodology
All Sectors

combustion CO2
combustion CO2 calculations assume stoichiometric conversion of all carbon to
CO2. T~ble 26 lists ~o~bustion and other conversion factors used. For gas
combustion, ~02 em1ss1onswere calculated based on fuel gas compositions (mol%)
supplied by field Areas. Total gas burned includes both fuel gas and flared volumes.
All components heaver than Methane were assumed to be equivalent to Ethane.
Although this is not strictly true, this is considered a close approximat ion given small
volumes of N2 and other components present in most fuel gases. Emission totals
were then adjusted to account for any volumes of CO2 already present in the gas
being burned. As such the gas combustion formula is:
Combustion CO2 ={ fuel gas vol * Mal % CO2 * density of CO2 + fuel gas vol * Mol %
CH4 * kg C02/m3 methane + fuel gas vol * Mal % other * kg
C02/m3 ethane}
Where Propane fuel volumes were reported, these volumes were equated to an
equivalent natural gas volume using a HHV for natural gas of 37.4 MJ/s m3.

Table26 combustionReferenceData
Substance

Methane
Ethane
Propane
Butane
Pentane
Hexane
Carbon dioxide

MW

16
30
44
58
72
86
44

s m3/kg

Density
kg/ s m3

kg CO2/
kg comb

kg CO2/
s m3 comb

HHV
MJ/ s m3

LHV
MJ/ s m3

1.47
0.79
0.54
0.41
0.33
0.27
0.54

0 .68
1.27
1.87
2.46
3.05
3.65
1.86

2.74
2.93
2.99
3 .03
3 .05
3.06

1.86
3.73
5 .58
7.44
9 .30
11.17

37.69
66 .03
93.97
121.80
149.64
177.56

33.94
60 .40
86.46
112.38
138.38
164.40

Sp. Vol

Diesel fuel volumes were converted to CO2 emissions .by us i~g a diesel density of
1
680 kg/m3 and an emission factor of 3.37 kg CO2/kg diesel.

13

. .

f

f

Back calculated from Alberta Energy em1ss1onsac1or O

of 48.1 MJ/kg.

o·07

kg/MJ for diesel , using a HHV

 46
b stlon CH4

com u
4 were developed by app!ylng average emissions
.
.
ns
of
unburned
CHf
factoras
Em1ss10
belowto ueI volumes tor each equipment type.
27
1
· t0 d in Tabe
0
hs
Iable 27 combusuoaEmissionFactora
Equipment

Type
Recip Engines·
Gas Turbines
All Others

CH4

voe

kg/ksm3 fuel

kglk sm3 fuel

19.8

1.08
0 .026
0 .048

0 .255
0 .044

ty

er
ar
st

fe

rr

\J

n
Recip Eng 4 cy
Recip Eng 2 cy
(Taken as 1/3 of 4 cycle)

20 .2

1.64

6 .7

0 .16

n
}
[

Flare = 0.02 m3/m3 gas flared
• Weiohted averaae

** Adaptedfrom Picard CPA Study.

Basedon discussionswith ERCL's machinery specialists, emission factors for
a
reciprocating
engineswere adjusted slightly from those reported by Picardto reflect
largerproportionof 2 cycle engine drivers within Essa's operations. Values reported
in the CPAstudywere felt to reflect conditions appropriate for 4 cycle enginesand
emissionsfrom2 cycle engineswere felt to be considerably lower. To arriveat the
adjustedfactorlistedabove,two cycle engine emissions were assumed to be 1/3of
thosereportedby Picard.
Methaneemissionsfrom flared volumes were calculated by applying a flare efficienc
y
of 98% to total flared CH4 volumes and multiplying by Methane density. All flare
volumeswereassumedto be 100% Methane for purposes of CH4 losses.

Combustionvoe
Giventhe relativelylow e · ·
bl
exceptionof reci ro . missi~nfactors for combustion VOC's (with the n~ta.~ t
Combustionvo6 tof{'"9 engines) , combustion voe emissions are not s,gnitic
an·
abovefor reciprocati~s we~edeveloped by applying the factor listed in table 27 It
9
shouldbe notedthat engines,to the estimated reciprocating engine fuel volume.
combustionvoes. most methods for reducing combustion CH4 will also reduce

CombustionNOx
TO facilitate
·
volume a uniformand re
s for gasfiredequiprr:f:le

fuel

method of calculating NOx emissions /~~:te
e following assumptions were used to ca

 47
. NOXemission factors per unit of fuel consumed T b1
factors and average volume ppm levels assu.me~ ~~8 summarizesNOx
tYP'.ca!on
5'rnewhatlower than corresponding EPA factors used·. the calculatedfactors
ern1s
aresoand values that can be derived from the NOx-VOC ~n e CPA CH4-VOC
studY,
be representativeof average field conditions for ERCLa~agementPlan,but are
feltto
ents
ased on 1989 field
measurem .

b .
meof flue gas products is calculated by using avg 95% c1 and 5o,
10 c 2 .
in com ust1bles
Volu

rn3 flueproducts/m3methane burned

1o.54

(Source GPSA14 )

17.7

m3flueproducts/m3ethane burned

(Source GPSA)

10.90

Avgm3flue products /m3 fuel burned

Density
of N02 relative to air is

1.45 (Source Chem Eng Handbook 15 page 3-18)

Density
of Air (kg/std m3)

1.22 (Source GPSA Fig 16.1)

Density
of N02 (kg/std m3)

1.77

Table2a summaryof NOxEmJssJoo
factors
Fuel Vol Source

Recip Eng
Cold Lake

AllOthers

ppmv in flue gas

std m3 NOx I
kstd m3 fuel

kg NOx I
kstd m3 fuel

2000
100
250

21.80
1.09
2.72

38.56
1.93
4.82

d'
sed in the Coal and Oil
Fordieselcombustion, NOx emission factors used are iscus
SandsMining sector methodology.
·th
vious internal inventories
Overallinventory NOx results have been checked wi pre
~ndare in reasonably close agreement.

-----

.
. DataBook, SI, 1980
is Cas ProcessorsSupplierAssociation, Engineering P rry CecilChilton
hern1ca1
E in
H ndboOk,Fifth Edition, Robert e '

14G -------

 48
combustion N20
d b applying a facto r prov ided by Imperial Oil's Re
Emissions are calc~~~ /kJ NOx To account fo r va riations in fuels being c search
/kg NOx and a lower ra nge of 0 .005 kg N ~fllbuste
k N
Div!sion of 0.02 kg
0
201 9 Nox
a higher range of o.07 g. . 20
.
has been used as a sens1t1v1tycheck.

.

C

surface Facility Equipment Leaks
(

The calculation procedures used to estimate CH4 and \:'OC losse s from surface
equipment leaks, rely on the use of
EPA and _Chem1~al Ma n~factures Association
(CMA) average emission factors 16 _applied to equipment info rmation. Recent studies
by the CMA, including Esso Chemical ~anada sh?w that these ave~age emission
factors when applied to individual chemical_ op.erat1ons may be too high (in the orde
r
of several magnitudes). Unfortunatel_yat this time no other gene rally accepteddata
exists for upstream petroleum operations, and as such these avera ge factors have
been employed. It is recommended that a series of screening tests be conductedfor
Canadian upstream oil and gas operations, to develop specific emission factorsfor
these services.

us_

Th~ total number of potential leaking equipment sources was ca lcu lated by applying
ns.
typical nu~bers for ~alves, etc, to the actual number of fac ilities in ERCL operatio
Ta~le _29lists by equipment type, factors used to estimate the numb er of fugitive
em1ss1onsources in any given facility.
_

 49

gf Euglllie E;ml&&lgo
Sgur~e&fQt Y.ar1QY&EquipmentTypes
:ra121e
29 t:11.1mbec
Equipment
Type
SingleGas W Wellhead
Dehydrator
Lineheater
Separator
Compressor
FacilityType

Gas

OilProd

Steam

# LL
Valves
0
11
0
4
23

# HL
Valves
0
0
0
0
0

#Gas
Fittings
16
54
42
18
174

# LL
Fittings
0
30
0

18
15
6
60
24

11
0
4
23
0

0
0
0
0
0

54
42
18
174
70

30
0
12
178
0

12

178

Gas Gath.

Dehydrator
Lineheater
Separator
Compressor
Meter Stn

SingleWell

Wellhead
Separator
Tankage

0
6
1

6
4
10

0
0
0

0
18
2

14
12
24

Satellite Bat

Test Sep
Treater

6
10

24
9

0
0

18
22

66
20

Central Bat

Test Sep
Treater
Tankage
Compressor

6
10
1
60

44
9
10
23

0
0
0
0

18
22
2
174

120
20
24
178

Wellhead
Tankage

0
10

0
22

9
15

0
22

0
54

Satellite Bat

All

10

24

13

42

84

Central Bat

All

40

111

52

137

237

SingleWell

Wellhead

0

0

9

0

0

20 well

10

24

13

42

84

SatelUteBat

All

202

440

139

659

1145

2 Ph. Plant

Heavy
Oil SingleWell
Conven.

Heavy
Oil

#Gas
Valves
6
18
15
6
60

 50

Table29
Sector
Gas

FacilityType
SingleGasW Wellhead
Dehydrator
Lineheater
Separator
Compressor

0
0
0
0
0

0
1
1
1
2

0
0
0
0
0

0
0
0
0
0

Dehydrator
Lineheater
Separator
Compressor
Meter Stn

0
0
0
0
0

1
1
1
2
2

0
0

0
0
0

Wellhead
Separator
Tankage

0
0
0

0
1
0

0
0
0

0
1

0
0
0

satellite Bat

Test Sep
Treater

0
0

1
1

0
0

1
0

0
0

Central Bat

Test Sep
Treater
Tankage
Compressor

0
0
0
0

1
1
0
2

0
0

0
0

0
0
1
0

0
0
0
0

Wellhead
Tankage

22

38

0
0

0
0

0
1

All

42

0

0

1

120

0

0

2

2

22

0

0

0

0

42

3

0

0

362

11

0

7

Gas Gath.

Oil Prod

Oil Prod

HeavyOil
Conven.

SingleWell

SingleWell
Satellite Bat
Central Bat

HeavyOil
Steam

All

SingleWell

Wellhead

SatelliteBat

20 well

2 Ph.' Plant

All

0
0

0

0
0

0

Abbreviations used in above tables:

HL Heavy Liquid
LL
Light Liquid
Gath Gathering

PSV Pressure safety valve
Smpl Sample
Bat Battery

Ph

w

Sep

Phase
Well
Separator

0
0
0
0
0
0
0
0
0
0

0

 51
ts an estimate of fugitive emission sources was made by applyingtyp·c
forgasplanchedulesby process typ~, to a summary listing of processesusedin I a1
gas plant. Table 30 lists the summary of gas plant fugitiveemission
0quiprne;~~ng
0
0ach P by process.
sources
gf GiUi Pl51n1Fugi11Vi Eml~~IQnSQ!Jr~i~b~PrQ~~H
n121e
aoSumm,ux
# Valves
Gas
compression
Refrigeration
Flexsorb
SE
MEA
DEA
OGA
IronSponge
GlycolDehydration
MoleSieve
Absorption
Ref
TurboExp
Otherliq Recovery (Sep)
Stabilization
Demethanizer
Deethanizer
OtherFrac.
Claus
MCRC
LiqTreat
Steam
Boilers
HotOil
Glycol
DirectAred
Dessicant

56
127
82
82
82
82
31
63
63
82
43
49
14
71
71
92
31
31

NIA
NIA
NIA
NIA
NIA
63

# Valves
LL
23
25
21
21
21
21
7
2
2
21
7
82
86
88
88
160
7
7

NIA
NIA
NIA
NIA
NIA
2

# Valves
HL
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0

NIA
NIA
NIA
NIA
NIA
0

# Flanges
Gas
74
263
200
200
200
200
134
243
243
200
103
93
16
163
163
192
134
134

NIA
NIA
NIA
NIA
NIA
243

# Flanges # Flanges
LL
HL

151
54
46
46
46
46
12
4
4
46
29
143
85
222
222
435
12
12

NIA
NIA
NIA
NIA
NIA
4

0
0
0
0
0
0

0
0
0
0
0
0
0
0
0
0
0

0

NIA
NIA
NIA
NIA
NIA
0

 52
1

a sourcesby process{conrcu

t Fua1t1veEmtss
o

aa
I able ;m summa~ 21 Gase1
Process
Compression
Refrigeration
Flexsorb SE
MEA
DEA
DGA
Iron Sponge
Glyc ol Dehydration
Mole Sieve
Absorpti on Ref
Turbo Exp
Other Liq Recovery (Sep)
Stabilization
Demethanizer
Deethan izer
Other Frac.
Claus
MCRC
Liq Treat
Steam Boilers
Hot Oil
Glycol
Direct Fired
Dessicant

# pSV Gas

# smpl.

2
10
4
4
4
4
1
8
8
4
6
4
4
6
6
1
1
1

0
0
0
0
0
0

Pts •

0
0

0
0
0
0
0
0
0
0
0
0

NIA
NIA
NIA

# Pumps

# Pumps

LL
0
2
1
1
1
1

HL
0
0
0
0
0
0

2
0
0

0
0

1
0
1
1
2

2

0
0
0
0
0
0
0

# Comp .
2
2
0
0
0
0
1
1
1
0
1
1

0
1
1
1

0

0
0

0

0

NIA
NIA

0
0
NIA
NIA
NIA
NIA
NIA

0

2

NIA
NIA
NIA
NIA
NIA

NIA
NIA

NIA
NIA
NIA

NIA
NIA
NIA
NIA
NIA

8

0

0

1

• An average of 1 O sample points m total per gas plant was used.
Comp. - Compressors

Total hydrocarbon leaking equipment rates (LR) for individua l field A reas were then
estimated by using the following formula:

LR=

Summati~n for all catego_ries{(#.fugitive equipment source s in each source
category) (average leaking equipment emission factor for each category)}

Values for the Total H~droc~rbon Components (THC) average emission factors used
for each category are hsted in Table 31 below.
'

 53
Il~II 31 Summ1cxQt A~ir 1g ~ml
1
§Sign

-

THC Factor
Gas Service V

sector

THC Factor
LL Ser. V

Fact

THC Factor
HL Ser. V

..__Qrs {12~
~iHtgQ!l'.}lsglhtlSQM[~
THC Factor
Gas Ser. F

THC Factor
LL Ser. F

THC Factor
HL Ser. F

0.02
0.0268

0.02
0 .0109

0.02
0.00023

0.0011
0.00025

0.00 11
0.00025

0.0011
0.00025

THC Factor
PS V's

THC Factor
Smpl Conn
Gas Serv
0.0133
0.015

THC Factor
Pumps LL

THC Factor
Pumps HL

THC Factor
Compressor

THC Factor
OE Lines

0.063
0.114

0.063
0.021

0.2
0.636

0.022
0.0023

GasProd
All Others

GasProd
All Others

0.19
0 .16

• Adapted from Picard CH4-VOC report Tables 12-14

Abbreviations used above:

V
F

Valves
Flanges

THC
OE

Total Hydrocarbon
Open ended

Leaks from Surface Casing
Emissions ~ue to venting to atmosphere of hydrocarbons from wells equipped with
surface casing vents, are reported under the Leaking equipment "Well" category.
Emissions are based on a recently completed internal ERCL study, which includes a
database on surface casing leaks from all operations within Canada. The database
consists of (among other things), the total number of wells reported to have surface
casing problems, and the estimated total emission rate of vapor for these wells. For
allocation purposes, an average emission factor I well was determined from this data
by first calculating an average rate per well for non serious and serious wells and
then applying these rates to all wells in the data base, (including those with no
reported rates). The average rate for non serious wells used was 4.5 s m3/d/well,
and 96 s m3/d/well for the serious wells. Emissions were then allocated back to each
sector by calculating a new average emissio_nrate per well f?r all the wells and
applying this to the reported number of wells in each sector with_l_eaks. Gas
composition was assumed to be equal to the gas vapor compos1t1onfor the sector.
There is considerable variance possible for the average rate per ~ell given the wide
scatter of data and the limited number of measured volumes vs estimated zero
volumes. For example the average rate per well based on well data for only .t~ose
is 136 s m3/d vs the 35 s m3/d used. In add1t1on
wells withreported volumes>
Picaroreportsan average surface casing release volume of appro~ ~ s m3/d for_
Alberta (baaed on ERCB data). This volume is felt to be the lower hm1tper well, with
136 s m3ta ng the upper.

o,

 54
Well Servicing

It to be restricted to los~es associated
. .
erations were fe
bricator de-pressuring. Volumes
1
Emissions for well se~icing t~~ rig tank, and from ~ed to be small and have not been
with well bore circul~tion t~ -pressuring were assu e calculated as follows:
associated with lubn~ator ke . culation volumes wer
included. Average ng tan cir
Well Servicing emission assumption~:epthof well in ft
3000 avg
in psia
1 5 O avg casing pr~ss
5 inch casing diameter
. h t b'ng
diameter
d
1
2. 5 me u
between de-pressured gas an pressuredga
•
s
0 temperature difference
string
V1

=

=
=
V2 =

P1
P2

V2 =

3 07

Gas volume (ft3 ) in well, ie net volume of casing minus tubing

1 so psia

1 4 psia
3285 Using ideal gas laws

= P1

*

V1/P2

9 3 std m3 gas

o.1s

Assumed lost gas fraction of total gas
1 Assumed density of gas kg/std m3 (based on 73% methane, 21%VO
C)

Mass losVjob

1 4 kg/job

The average loss per job was then applied to the reported number of jobs from field
data with no disti~ction for gas wells or oil wells. A wide variance is possible for the
average rate per Job, and value of 3 kg/job and 28 kg/job are used as sensitivities.

Characterizationof Emissions
Determination of Methane vs. voe losses was a
·
.
.
.
nt
of the inventory. Accordingly typical CO2 C
maJor cons1derat1on m deve 1op~e
were used to characterize emissions wh ' H4 , and VC?C gas r:nol _fraction profiles
conditions was available. Emission
~~s voluf!le mformat1on in standard
32 below. Formulas used were:
ra ion profiles used are presented in Table

motre

*
Gas emission for component= {Total Gase . .
density for commp
iss,on vol • Mal fraction for component
onent}

 55

Table32 Gas E rn1ss1ooMo1f racuoopromes
Sector:
Component :
CO2 GV
CO2 LL V
CO2 HL V
CO2 G F
CO2 LL F
CO2 HL F
CO2 PSVs
CO2 SC
CO2 P LL
CO2 P HL
CO2 Comp.
CO2 OE Lines
CO2 Dehy Off G
CO2 Tank Vap
C1 GV
C1 LL V
C1 HL V
C1 G F
C1 LL F
C1 HL F
C1 PSVs
C1 SC
C1 PU
C1 P HL
C1 Comp.
C1 OE Lines
C1 Dehy Off G
C1 Tank Vap
VOCGV
voe LL V
voe HL v
VoeGF
VoeUF
voe HL F
voe PSVs
voesc
voe P LL
voe P HL
voe Comp.
voe
Line
voe Dehy oo
VoeTankVap

oe

Gas Prod
MH *

Gas Prod 0th .

Oil Prod

Heavy Oil

HO Steam

0 .003
0 .000
0 .000
0.003
0.000
0.000
0.003
0 .003
0.000
0.000
0 .003
0.003
0.037
0.037
0.975
0.000
0.000
0.975
0.000
0.000
0.975
0.975
0.000
0.000
0.975
0 .975
0.875
0.875
0.012
1.000
0.000
0.012
1.000
0.000
0.012
0.012
1.000
0.000
0.012
0.012
0 .029
0.029

0.006
0.000
0.000
0.006
0.000
0.000
0.006
0.006
0.000
0.000
0.006
0.006
0.064
0.013
0.919
0.000
0.000
0.919
0.000
0.000
0.919
0.919
0.000
0.000
0.919
0.919
0.690
0.564
0.068
1.000
0.000
0.068
1.000
0.000
0.068
0.068
1.000
0.000
0.068
0.068
0.216
0.068

0.052
0.003
0.000
0.052
0.003
0.000
0.052
0.052
0.003
0.000
0.052
0.052
0.064
0.003
0.733
0.100
0.000
0.733
0.100
0.000
0.733
0.733
0.100
0.000
0.733
0.733
0.690
0.100
0.210
0.757
0.000
0.210
0.757
0.000
0.210
0.210
0.757
0.000
0.210
0.210
0.216
0.757

0.001
0.007
0.007
0.001
0.007
0.007
0.001
0.001
0.007
0.007
0.001
0.001
0.064
0.007
0.980
0.872
0.007
0.980
0.872
0.007
0.980
0.980
0.872
0.007
0.980
0.980
0.690
0.870
0.017
0.058
0.007
0.017
0.058
0.007
0.017
0.017
0.058
0.007
0.017
0.017
0.216
0.058

0.220
0.220
0.220
0.220
0.220
0.220
0.220
0.220
0.220
0.220
0.220
0.220
0.064
0.220
0.700
0.700
0.700
0.700
0.700
0.700
0.700
0.700
0.700
0.700
0.700
0.700
0.690
0.700
0.080
0.080
0.080
0.080
0.080
0.080
0.080
0.080
0.080
0.080
0.080
0.080
0.216
0.080

* MedicineHat Shallow Gas