Post on 23-Aug-2020
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Compositions and Greenhouse Gas Emission Factors of Flared and Vented
Gas in the Western Canadian Sedimentary Basin
Matthew R. Johnson* and Adam R. Coderre
Energy & Emissions Research Laboratory, Mechanical & Aerospace Engineering, Carleton
University, Ottawa, ON, Canada, K1S 5B6
This is an authors’ preprint of an article whose definitive form has been published in the Journal of the Air &
Waste Management Association © 2012 Taylor & Francis (doi: 10.1080/10962247.2012.676954)
The article should be cited as:
M.R. Johnson and A.R. Coderre (2012) Compositions and Greenhouse Gas Emission Factors of
Flared and Vented Gas in the Western Canadian Sedimentary Basin, Journal of the Air & Waste
Management Association, 62(9):992-1002 (doi: 10.1080/10962247.2012.676954).
* Corresponding author: Email: Matthew_Johnson@carleton.ca; Office: (613) 520 2600 ext. 4039; Fax: (613) 520 5715
ABSTRACT
A significant obstacle in evaluating mitigation strategies for flaring and venting in the upstream oil and
gas industry is the lack of publicly available data on the chemical composition of the gas. This
information is required to determine the economic value of the gas, infrastructure and processing
requirements, and potential emissions or emissions credits, all of which have significant impact on the
economics of such strategies. This paper describes a method for estimating the composition of solution
gas being flared and vented at individual facilities, and presents results derived for Alberta, Canada,
which sits at the heart of the Western Canadian Sedimentary Basin. Using large amounts of raw data
obtained through the Alberta Energy Resources Conservation Board, a relational database was created
and specialized queries were developed to link production stream data, raw gas samples, and geography
to create production-linked gas composition profiles for approximately half of the currently active
facilities. These were used to create composition maps for the entire region, to which the remaining
facilities with unknown compositions were geographically linked. The derived data were used to
compute a range of solution gas composition profiles and greenhouse gas emission factors, providing new
insight into flaring and venting in the region and enabling informed analysis of future management and
mitigation strategies.
IMPLICATIONS
Accurate and transparent determination of environmental impacts of flaring and venting of gas associated
with oil production, and potential benefits of mitigation, are severely hampered by the lack of publically
available gas composition data. In jurisdictions within the Western Canadian Sedimentary Basin,
frameworks exist for regulating and trading carbon offset credits but current potential for mitigation is
limited by a lack of standardized methods for calculating CO2 equivalent emissions. The composition and
emission factor data derived in this paper will be useful to industry, regulators, policy researchers, and
entrepreneurs seeking statistically significant and openly available data necessary to manage and mitigate
upstream flaring and venting activity and estimate greenhouse gas impacts.
2
INTRODUCTION
In the energy and petrochemical industries,
excess or unwanted flammable gases are often
disposed of by flaring or venting. Flaring is the
process of combusting the gases in an open-
atmosphere flame, and provides a means of
disposing of flammable gases in a cost-effective
manner. If stable combustion of surplus gas is
not possible, for instance if the flow rates are too
low or too intermittent, or if the heating value of
the gas is too low to sustain combustion, or if the
gases are deemed uneconomic to recover and
regulations permit, the gases are instead vented,
meaning they are simply released to atmosphere.
The U.S. Energy Information Administration,
based on reports from individual countries,
estimates that global flaring and venting totalled
122 billion m3 in 2008
1. By contrast,
examination of visible light images captured by
orbiting satellite suggests that global flaring
alone exceeds 139 billion m3 annually, and that
these volumes have been relatively stable over
the past fifteen years 2. Vented gas is not as
readily detected and to the authors’ knowledge,
accurate estimates of global venting volumes do
not exist. However, for the case of Alberta,
Canada, a mature oil and gas producing region
with extensive pipeline infrastructure, a recent
analysis of production data shows venting
volumes similar to flared volumes as well as a
trend toward proportionally greater amounts of
venting as more heavier oils are produced 3.
The majority of global flaring and venting
occurs during upstream production of oil and gas
resources. The production of conventional oil is
nearly always accompanied by the production of
flammable gases, even when no gas is initially
present in the reservoir. This is because the
hydrocarbons are contained in sub-surface
geological formations under high pressure,
which allows for volatile chemical species to
equilibrate and dissolve in the formation liquids.
When these liquids are produced and brought to
the surface, the pressure acting on them is
reduced from formation to atmospheric, causing
these dissolved gases to come out of solution.
These evolved gases are commonly referred to
as solution gas. The term associated gas, is
perhaps even more commonly used, although in
general associated gas is understood to refer to
the combination of solution gas and gas that
exists separate from the oil at reservoir
conditions. In the upstream oil and gas industry,
solution gas is the source for the majority of all
flaring and venting activity that takes place.
From an air emissions management perspective,
the practice of flaring and venting is a concern
due to the scale at which it takes place. In
addition to carbon dioxide (CO2), an important
greenhouse gas, flares can produce airborne
pollutants such as particulate matter in the form
of soot 4,5
, unburned fuel and carbon monoxide 6,7
(especially if the heating value of the flare gas
is low 8), and potentially other by-products of
incomplete combustion 9. When the raw flare
gas contains hydrogen sulphide (H2S), the major
pollutant sulphur dioxide (SO2) is also produced.
Although direct venting of gas precludes
combustion related emissions, from a
greenhouse gas (GHG) perspective, venting of
high-methane content gas associated with
petroleum production is even worse. This is
because methane (CH4) has a 100-year global
warming potential that on a mass basis is
twenty-five times more potent than CO2 10
.
Predicting impacts of flaring and venting on a
broader scale requires knowledge of gas
compositions being flared and vented. As well,
the viability of any potential mitigation
strategies such as collection of gas into pipelines
or the use of the gas to generate heat and
electricity, are highly dependent on chemical
composition of the gas, especially in terms of
energy and H2S content. The lack of statistically
significant, published data on compositions of
3
flared and vented associated gas is thus a
significant impediment to engineering analysis
of impacts and mitigation options. Successful
regulation and trading of carbon offset credits
from flaring and venting mitigation projects are
further hampered by a lack of consistently
applied and transparently derived greenhouse
gas (GHG) emission factors. The objective of
this paper is to address this gap in knowledge
through comprehensive analysis of available
production and reservoir data for a significant
petroleum production region of the world. The
derived results are subsequently used to estimate
a range of gas composition-based emission
factors to predict greenhouse gas emissions from
flaring and venting activities.
Petroleum Production in the Western
Canadian Sedimentary Basin
The Western Canadian Sedimentary Basin
(WCSB) is a vast geological formation of
sedimentary rock that spans several western
Canadian Provinces, bordered by the Rocky
Mountains to the west and the Canadian Shield
to the east. The bulk of Canada’s oil and gas
resources lie within this basin, including the vast
quantities of oil sands that place Canada’s
proved oil reserves third highest in the world,
behind Saudi Arabia and Venezuela 12
. More
than 97% of Canada’s proven reserves are in the
form of oil sands deposits, while conventional
reserves in the WCSB account for nearly 2% 13
.
However, conventional sources in the WCSB
account for a much greater fraction of current
production. In 2009, roughly 3% of global oil
production was sourced from the WCSB, of
which approximately half (55%) originated from
oil sands deposits 14,12
. The province of Alberta
sits at the heart of the WCSB, and is a mature
and very active oil and gas production region.
Alberta is by a wide margin the largest producer
of oil in gas in Canada, accounting for roughly
68% of Canada’s 2008 crude oil and equivalent
production and 76% of gross natural gas
production 15
.
Upstream Flaring and Venting in Alberta,
Canada. Much of the conventional oil in
Alberta is produced from smaller-volume wells
connected to “battery” sites, i.e. surface facilities
in which reservoir fluids, including solution gas,
are separated and measured. Oil and bitumen
batteries in Alberta produced nearly 15 billion
m3 of solution gas in 2008
16, the latest year for
which data were available. The large majority
(95.3%) was conserved, meaning that it was
either used onsite as fuel or directed into natural
gas pipelines for processing and sale. The
remainder was disposed of by flaring or venting.
Although 4.7% is a relatively small fraction of
the total amount of solution gas produced, it still
represents a significant volume of gas which
totalled 687 million m3 in 2008
3. Upstream
flaring and venting from all sources in Alberta
totalled 1.11 billion m3 in 2008
16, or
approximately 0.9% of the 122 billion m3 global
flaring and venting estimate from the U.S.
Energy Information Administration 1.
The body that regulates the upstream oil and gas
industry in Alberta is the Energy Resources
Conservation Board (ERCB). ERCB’s Directive
60 contains guidelines for the decision-making
process pertaining to solution gas conservation
options that industry operators are required to
follow17
. Whereas ERCB Directive 007
mandates that operators submit monthly
production reports through the Petroleum
Registry of Alberta (PRA)18
, Directive 60 further
specifies that “volumes of gas greater than or
equal to 0.1·103 m
3/month (adjusted to 101.325
kPa(a) and 15°C) that is flared, incinerated, or
vented” are to be included 17
. However, the
composition of the gas being flared or vented is
not included in these reports.
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Origins and Production of Solution Gas
A discussion of solution gas composition begins
with some background and basic hydrocarbon
reservoir terminology. According to the
generally accepted organic theory, hydrocarbons
were formed when sediments including organic
matter were buried by geological shifts, and
subjected to intense temperatures and pressures
over periods of geological time 19
. These
combined factors converted the organic matter to
the fluids found in reservoirs today, and
converted the sand, mud, and silt sediments to
rock. Hydrocarbon fluids, being less dense than
water, were displaced upwards through porous
and permeable rock, until they either breached
the surface or were trapped by an impermeable
layer of rock (called a cap rock) that prevented
further upward migration. However, the pores
in the rock are small enough that surface
wettability and capillary forces prevent complete
segregation of the fluids. Thus, hydrocarbon
reservoirs consist of porous and permeable rock,
the pore space of which is filled with mixtures of
water, oil, and gas phases, partially segregated to
form a gradient of fluid saturations (i.e. the
fraction of pore space filled with each fluid
phase) from primarily gas just underneath the
cap stone, to a primarily oil further down, to
primarily water toward the bottom.
The composition of solution gas can vary
considerably, comprising differing mixtures of
light hydrocarbon species (primarily alkanes
such as methane), non-flammable gases such as
nitrogen and carbon dioxide, and toxic
impurities such as hydrogen sulphide (H2S).
H2S content has a particularly significant impact
on the economics of flaring and venting
mitigation. As specified in the Alberta Pipeline
Act20
, gas with more than 10 mol/kmol (i.e. 1%
by volume) H2S is designated “sour” (as
opposed to “sweet”). Sour gas is handled and
regulated separately from sweet gas and has
different infrastructure requirements, meaning
that it must be directed to specialized sour gas
pipelines and processing facilities before
entering a sales gas line. It should be noted that
in practice, several different H2S content
thresholds for defining sour gas are also
common. For example, the Alberta Oil and Gas
Conservation Act21
and Directive 6017
define
sour gas simply as gas “containing” H2S. Other
ERCB guidelines tend to differentiate sour sites
based on potential release rates of sulphur, rather
than by raw volume concentrations of H2S in the
gas stream22,23
.
Therefore, to evaluate the economics of any
potential mitigation strategies and to determine
the GHG contributions of solution gas flaring
and venting, the composition of the gas must
first be determined. This is problematic in that
the composition often goes unmeasured,
particularly at smaller production facilities. This
paper presents a strategy for assigning estimated
solution gas compositions to production
facilities in the WCSB. The derived results were
used to determine volume- and site-weighted
solution gas composition ranges, and to calculate
GHG emission factors for flaring and venting
activities under a range of scenarios. In
addition, separate maps for flared and vented
solution gas in the Province of Alberta were
developed to assess the geographic distribution
of gas compositions within the Province. These
new data enable proper estimation of
environmental impacts and to support
quantitative evaluation of mitigation strategies
for upstream flaring and venting activities in the
WCSB. Finally, the methodology developed
herein could be usefully applied to other mature
oil and gas producing regions of the world.
METHODOLOGY
Figure 1 defines key terms used in oil production
at batteries in Alberta. An oil field, or simply a
field, refers to the surface area above an
underground hydrocarbon reservoir. A pool
refers to the hydrocarbon reserve itself, whether
5
a geological pool, which refers to an actual
underground geological hydrocarbon-containing
formation as discussed above, or a comingled
pool (sometimes also called an administrative
pool) which describes some combination of
geological pools that are tapped by an individual
well. The term ‘administrative pool’ is primarily
used for production accounting purposes.
Figure 1: An illustration of hydrocarbon reservoir
terminology
In the simplistic representation seen in Figure 1,
a battery is present in a field, and produces from
three wells. Well 1 and Well 2 produce from
Pool 1 and Pool 2, respectively, which are each
distinct geological pools. Well 3 produces from
both Pool 1 and Pool 2; this combination would
then be assigned a separate administrative pool
code.
Industry-reported monthly production data from
more than 18,000 oil and bitumen batteries in
the Province of Alberta, spanning the years
2002-2008, were obtained in collaboration with
the ERCB. These data are a raw form of the
ERCB ST-60 series reports available for public
purchase24
and are the basis of the volumetric
production and battery location data used in this
work. Also obtained through the ERCB were a
large number (60,000+) of gas samples from
wells attached to non-confidential pools, which
contained molar fractions of 13 chemical groups
including hydrocarbons by carbon content (C1,
C2, C3, IC4, NC4, C5, C6, C7+), combustible
non-hydrocarbon species (H2, H2S), as well as
non-combustibles (He, N2, CO2). Similarly,
these data are a raw form of the “Individual Well
Gas Analysis Data” files available for public
purchase24
. These gas analyses originate from
industry supplied reports to the ERCB, and
although they do not contain details of the
specific analysis procedure used, it is understood
that they are almost exclusively obtained using
gas chromatography with extracted samples, and
are reported with a mole fraction precision of
0.0001 as per ERCB Directive 01722
. Given the
reported precision of the gas samples, overall
uncertainties in the present analysis will be
dominated by site to site variability which is
presented in terms of percentile limits and
considered in more detail in the results section.
Finally, the ERCB provided production stream
data for nearly 9,000 non-confidential batteries,
which link those batteries to the reservoirs from
which they produce via numeric field and pool
identification codes, including the proportions of
production attributed to each pool for multi-well
batteries (see Figure 1). These linkages are
continually updated as production patterns
change, and the data considered in the present
analysis reflect linkages in place in June 2008.
All data were merged into a large relational
database created to analyze results using scripted
queries.
To meet the key objectives of estimating battery-
specific and volume-weighted average
compositions of gas flared and/or vented in the
province, several pieces of information needed
to be connected. Since the available gas analysis
data contained only limited location information
(i.e. each gas analysis identified a pool code and
sometimes a field code, but was otherwise not
6
attached to a specific location), the most direct
way to link a gas sample to a specific battery
(and its known geographic location) was through
the production stream data. These production
stream data contained a numeric identification
code for the field in which each battery was
located (rather than specific location information
such as latitude and longitude) and one or more
code numbers for the pool(s) (i.e. hydrocarbon
reservoir(s)) from which it produced. Coupled
with battery specific production data (which
included location data and monthly volumes of
gas flared and/or vented), composition of gases
being flared and/or vented could be determined
and directly linked with gas volumes.
Preliminary analysis revealed that of the
60,000+ gas samples available, only a small
subset could be matched for both the field and
pool codes associated with any particular
battery. However, given the geological time
scales the fluids had to equilibrate within a pool,
it was deemed reasonable to assume that
solution gas compositions (as opposed to liquid
compositions) would not vary significantly
within a single geological pool, and available
gas samples for a given pool could be averaged.
Indeed, for geological pools with multiple
samples, half had standard deviations in C1
concentration of less than 5.2% of the mean
value within the pool, and 75% of the pools had
standard deviations in C1 of less than 8.3% of
the mean. Similarly, half of all
administrative/comingled pools with multiple
samples had standard deviations in C1
concentration of less than 5.6% of the mean and
75% had standard deviations less than 8.6% of
the mean. This compares to a standard deviation
of C1 concentration of 9.7% of the mean for all
available gas samples, and 10% among the
means for each pool. Thus, although the limits
of available data necessitated neglecting spatial
and temporal variations in gas composition
within a pool, the analysis suggests that this is a
reasonable assumption for an aggregate analysis.
While this would be a relevant source of
uncertainty in attempting to assign gas
compositions to individual batteries, the data
further suggest that uncertainties in C1 mole
fraction of less than 0.05 would be typical.
To further verify the validity of this approach,
statistical analysis using Levene’s test for
equality of variances was completed to compare
the variations among gas samples from a single
pool with variations among all gas samples.
Calculations were performed for each of the
three pools with the most available data (i.e. two
geological pools with 323 and 337 available gas
samples, and one administrative pool with 2529
available gas samples), and results easily
showed that the differences among the variances
were statistically significant. Thus, multiple
samples within a common pool had statistically
less variation than the set of all gas samples, and
it was reasonable to combine them for the
purpose of the aggregate analysis.
Under this assumption, two batteries located in
different fields but producing from the same
pool would be expected to have similar solution
gas compositions, and production stream data
could then be linked to gas samples by matching
only the pool codes within the database.
Because most pools had multiple available
corresponding gas samples, the impacts of any
solution gas variability within the pools was
further minimized in the aggregate analysis.
Of the 60,000+ gas samples obtained through
the ERCB, approximately 8500 distinct pools
(whether geological or
comingled/administrative) were represented,
indicating that the gas from many pools had
been sampled multiple times. With respect to
comingled pools, using available data reported
to ERCB, there is unfortunately no satisfactory
method to determine the proportions produced
from each geological pool within a comingled
pool, or even whether those proportions would
remain constant over time. Gas compositions
7
from comingled pools were therefore similarly
assigned the arithmetic average of all associated
composition samples. Once the compositions of
individual geological and
comingled/administrative pools were identified,
solution gas composition profiles were then
assigned to individual batteries using available
production stream information, weighted by the
fraction of production attributed to each pool.
This method allowed composition profiles to be
directly assigned to roughly 6000 separate
batteries.
For the remaining facilities, in the absence of
additional gas samples, compositions were
estimated based on geographic location. Gas
composition maps were created by first
overlaying a spatial grid on the Province with
elements that measured 0.15° latitude by 0.2°
longitude such that they were approximately
square over Alberta’s latitudes. The average
composition of each element was determined as
the arithmetic mean of the available composition
profiles from any facilities within that element.
The grid size was chosen to be much smaller
than the typical pool dimension, and as small as
possible while still enabling the available data to
be extended to regions without available
measurements using filtering techniques as
described below. Based on analysis of the
distances between batteries connected to the
same pool, the median and average pool sizes
(i.e. the horizontal dimension of the pool) were
~90 and ~145 km or ~4-7 times larger than the
grid element size.
Since regulatory distinction is made between
flared and vented gas, separate composition
maps were generated using data for facilities that
have reported venting activity and facilities that
have not (i.e. those that exclusively flare). This
distinction was made under the assumption that
average compositions of gas vented and flared
could be expected to be different. For example,
because of the extreme toxicity of H2S, one
would expect to find the vented gas had lower
average H2S concentrations relative to flared
gas. The resulting maps for C1 (methane)
concentration are shown in Figure 2 for (a)
exclusively-flaring batteries and for (b) batteries
reporting any amount of venting.
The data shown in Figure 2 were then smoothed
and extended into grid elements without
assigned compositions through the application of
spatial low-pass filters. Digital low-pass filters
provide a method of smoothing that reduces
noise in an array of data while largely
maintaining its integrity 25
. Such tools are
commonly used in digital image processing to
remove noise, and work by assigning a value to
each individual element (or pixel) based on the
values of the surrounding elements 25
. The
number and position of the surrounding elements
to consider are defined by the filter kernel, with
larger kernels leading to greater degrees of
smoothing, and hence loss of high-frequency
data. Different filter types are primarily
identified by the operation used to assign a value
to a cell. Common examples include mean and
median filters, which replace the value of the
cell being filtered with either the mean or
median value of all elements within the kernel
(including itself). The use of mean filtering was
chosen since it offers low-pass smoothing while
preserving the constraint that the component
fractions must sum up to unity. Although mean
filtering is commonly used when differences in
neighboring cells are due to random noise rather
than from separate sources (as is nominally the
case here, where different batteries would be
producing from different well(s) that may be
drawing from different proportions of pools), for
the grid scale at which the filter was applied
(which is ~4-7 times smaller than the relevant
scale of a typical pool as noted above),
compositions variations can be considered
random for the purposes of interpolation.
Potential effects of this averaging procedure are
further considered in the results section below.
8
Figure 2: Map showing binned C1 concentrations at (a) exclusively-flaring batteries and (b) batteries that
reported any amount of venting.
When implementing the filtering operation for
interpolation, a kernel size of 3x3 was chosen,
such that only the values held by each element’s
immediate neighbours were considered. Two
sequential passes were made over the entire
Province to fully encompass the necessary
interpolation area. Each battery with an
unmeasured composition was then assigned the
appropriate average composition of the grid
element in which it was located, and using
different source data depending on whether that
battery predominantly flared or vented. The
resulting spatial concentration profiles are
presented with the results.
RESULTS
Based on the approaches outlined above, the
solution gas composition of each oil or bitumen
battery in Alberta active in 2008 was determined
either by direct linkage to gas analyses for pools
tied to that battery, or by geographic proximity
to other batteries that were themselves linkable
to measured pool composition data and
segregated by flaring or venting activity. Of all
the batteries active in 2008, slightly more than
half were directly linkable to pool gas samples.
Considering only the subset of batteries that
reported flaring and venting in 2008, again
slightly more than half these (representing
slightly less than half of the total volume of gas
flared or vented) were directly relatable to
9
measured pool composition data. The
proportions of flared and vented volumes
directly linkable to pool composition data were
less even. Roughly two-thirds of gas flared in
2008 could be linked with pool gas samples,
compared to only a quarter of the vented gas.
This difference is considered further below.
Figure 3 shows mean gas composition profiles at
sites with linked samples compared with sites
where composition data was interpolated from
maps, with error bars to represent the 10th and
90th percentile concentration values for each
component gas species. The inset graph shows
histograms of H2S concentrations for the two
categories. Overall, the solution gas
compositions being flared or vented are heavily
dominated by methane (note the broken vertical
axis on the figure necessary to plot mole
fractions of methane alongside mole fractions of
other species). Although subsequent figures
reveal noticeable variability among sites and
across regions of the Province, the 10th and 90
th
percentile limits in Figure 3 suggest the
variability is confined within a reasonably
narrow range of the mean compositions (mole
fraction variation of <±0.067 for C1 and
<±0.024 for all other species). Table 1 provides
a detailed statistical summary of the composition
data shown in Figure 3, aggregated from all
active batteries in the Province that reported
flaring and/or venting between 2002 and 2008.
These data are further segregated to calculate
separate composition profiles for batteries that
exclusively flared and batteries that reported any
amount of venting. For each case the mean, 10th
percentile, and 90th percentile component
fractions and gross heating values (GHV) are
shown.
Figure 3: Mean composition profiles for data
linked to samples and interpolated (geographically
linked) from maps. Note the broken vertical axis
to permit plotting of methane concentrations
alongside concentrations of other species. Error
bars represent 10th
and 90th
percentile values for
each species. Inset graph shows histograms of H2S
concentration for both groups.
On average, the interpolated profiles shown in
Figure 3 closely match the directly linked
profiles, with mean mole fraction deviations of
less than 0.01 for most species. The interpolated
samples do show a slight (+0.027 mole fraction)
shift toward greater C1 concentrations compared
to the directly linked samples, which is
consistent with the larger proportion of vented
gas represented by this category, predominantly
from heavy oil production. On the other hand,
the inset H2S histogram in Figure 3 reveals a
slight bias towards higher H2S contents within
the 0-1% mole fraction range at sites with
compositions assigned via interpolation, even
though the larger full figure shows a negligibly
small decrease in the overall mean H2S
concentration at these same sites. This is most
likely an effect of spatially smoothing the
inherently high-frequency H2S data (i.e. the raw
H2S data in particular show sharp geographic
variations). Although this effect appears to be
10
limited to values below the sour threshold of
10 mol/kmol20
, this does indicate a potential bias
toward falsely labelling some interpolated sites
as sour. However, within the context of the
overall mean H2S concentration remaining
constant after interpolation, this effect can be
considered conservative both from a health
perspective and in terms of potential mitigation
costs (since sour gas processing equipment is
typically more expensive than sweet). As is
stressed throughout this paper, it is therefore
crucial that non-aggregate (i.e. site-by-site)
evaluation of mitigation options be informed by
accurate site-specific measurements of solution
gas composition.
Table 1: Summary of composition profiles as assigned to oil and bitumen batteries in Alberta. Composition
values in mole fractions, Gross Heating Value (GHV) and Lower Heating Value (LHV) in MJ/m3 of solution
gasa.
All Batteries Venting Batteriesb Non-Venting Batteries
c
Mean 10th 90
th Mean 10
th 90
th Mean 10
th 90
th
H2 0.0001 0.0000 0.0003 0.0001 0.0000 0.0002 0.0002 0.0000 0.0003
He 0.0006 0.0002 0.0008 0.0006 0.0003 0.0009 0.0005 0.0002 0.0009
N2 0.0335 0.0162 0.0510 0.0354 0.0190 0.0516 0.0311 0.0131 0.0496
CO2 0.0141 0.0055 0.0262 0.0126 0.0055 0.0232 0.0181 0.0068 0.0314
H2S 0.0033 0.0000 0.0088 0.0022 0.0000 0.0060 0.0063 0.0000 0.0166
C1 0.8579 0.7862 0.9201 0.8672 0.7913 0.9215 0.8351 0.7756 0.8910
C2 0.0475 0.0217 0.0706 0.0433 0.0214 0.0687 0.0564 0.0378 0.0754
C3 0.0239 0.0076 0.0399 0.0215 0.0074 0.0380 0.0291 0.0160 0.0433
IC4 0.0042 0.0017 0.0069 0.0038 0.0016 0.0062 0.0051 0.0031 0.0079
NC4 0.0068 0.0019 0.0116 0.0061 0.0019 0.0109 0.0085 0.0043 0.0127
C5 0.0045 0.0017 0.0075 0.0041 0.0017 0.0074 0.0053 0.0029 0.0076
C6 0.0016 0.0006 0.0026 0.0015 0.0006 0.0025 0.0020 0.0011 0.0028
C7P 0.0019 0.0006 0.0032 0.0017 0.0006 0.0029 0.0023 0.0012 0.0035
GHV 38.236 36.890 39.640 37.981 36.863 39.465 38.747 37.648 39.962
LHV
34.567 33.359 35.746 34.337 33.335 35.620 35.036 34.064 36.132 a Heating values calculated at a pressure of 101.325 kPa and temperature of 15°C.
b Venting batteries include all batteries that report any amount of venting (i.e. batteries that
vent exclusively as well as batteries reporting both flaring and venting) c Non-venting batteries reported flaring exclusively
The maps shown in Figures 4–6 represent the
smoothed geographical distribution of C1
concentration, H2S concentration, and the gross
heating value of solution gas throughout the
Province of Alberta, segregated by batteries that
flared exclusively versus those that reported any
amount of gas venting activity. As noted above,
this distinction was made since it is reasonable
to assume that gas that is vented as well as flared
might logically be different from gas that is
flared exclusively, especially with respect to
content of toxic H2S.
Several broad trends are apparent from these
distributions. Methane concentrations, seen in
Figure 4, are generally higher near the city of
Lloydminster, where predominantly heavier oils
are produced, and lower in the northwest of the
11
Province. These differences also correspond
with the relative amounts of flaring and venting
in these areas, where much greater proportions
are venting are correlated with the heavier oil
production in the Lloydminster region 3. Given
the greater proportion of samples linked to
flaring sites than venting ones, this implies
proportionally fewer measurement-linked gas
compositions in the Lloydminster region, and
the results for this region therefore rely
particularly heavily on geographical linking.
Figure 4: Map showing smoothed C1 concentrations at (a) exclusively-flaring batteries and (b) batteries that
reported any amount of venting.
Higher H2S concentrations are noted near the
cities of Edmonton, Calgary, Grande Prairie, and
in the northwest region of the Province, while
low concentrations are seen near Lloydminster,
Brooks, and in the mid-west of the Province.
(Note that the H2S maps seen in Figure 5 use
different colour contours than the other figures
to highlight the “sour” threshold of
10 mol/kmol.) As expected, this figure also
shows that H2S concentrations are generally
lower in gas that is vented as well as flared,
although the in some cases it appears non-
negligible. However, as discussed above, a
smaller proportion of vented gas is linked to
measurements, and the significant impacts that
such small quantities of H2S have on mitigation
options further necessitates measurements on a
case-by-case basis.
12
Figure 5: Map showing smoothed H2S concentrations at (a) exclusively-flaring batteries and (b) batteries that
reported any amount of venting.
Gross heating values seen in Figure 6 are
reasonably well-distributed throughout the
Province, with lower values seen near
Lloydminster and in the area south of Calgary
and Brooks. From Table 1, net or lower heating
values (LHV) would be lower in all cases by
approximately 3.5 to 4 MJ/m3. It is noted that
the heating values of solution gas flared at
upstream sites are consistently well above the
20 MJ/m3 minimum lower-heating value
threshold for permitted flaring as specified in
ERCB Directive 60 17
, and thus well above the
range of heating values shown to lead to poor
flare conversion efficiencies 7,8
. There appears
to be little difference between the heating values
of gas that is flared or vented.
13
Figure 6: Map showing smoothed gross heating values (GHV) at (a) exclusively-flaring batteries and (b)
batteries that reported any amount of venting.
Calculation of Greenhouse Gas Emission
Factors
Greenhouse gas emission factors can be
determined from composition of the gas being
either flared or vented. As discussed above, and
assuming ideal stoichiometric combustion,
flaring the gas results in oxidation of any carbon
atoms present in the fuel to produce CO2. This
is expressed by the generalized hydrocarbon
combustion reaction shown as eq (1):
OH2
COO2
HC 222
yx
yxyx
(1)
From inspection of eq (1), the number of moles
of CO2 produced by the flare depends only on
the carbon content of the raw flare gas.
Therefore, a mole of methane (CH4) produces
one mole of CO2, a mole of ethane (C2H6)
produces two moles of CO2, and so on.
Considering also any CO2 present in the raw
flare gas, the total number of moles of CO2
emitted (2COn ) per mole of raw flare gas
( gas flaren ) can be calculated as in eq. (2), where
i is the mole fraction of species i in the raw
flare gas and the C7+ category is conservatively
assumed to contain only C7 species.
2
2
76
544
321
76
54
32
COPCC
CNCIC
CCC
gas flare
CO
n
n
(2)
Invoking the ideal gas model, it is possible to
compute a GHG emission factor for a flare
( fEF ) according to eq (3), evaluated as
14
kilograms of emitted CO2 per cubic metre of
flare gas (equivalent to tonnes per 103 m
3), and
for the moment still assuming 100% flare
conversion efficiency (i.e. that all carbon bound
up in hydrocarbons within the fuel stream are
converted to CO2 in the products):
TR
PM
n
nEF
CO
gas flare
CO
f22 (3)
where P and T are pressure and temperature (for
all calculations in this paper these are specified
at industry standard values of 1 atm and 15°C),
2COM the molar mass of CO2, and R is the
universal gas constant.
Emission factors for vented gas depend only on
the concentrations of GHGs present in the fuel,
namely methane (C1) and CO2. Some C2–C4
species can also be considered GHGs as they
have been implicated as having indirect warming
effects, however the magnitude of these effects
are small compared to that of methane
(particularly so given their comparatively small
concentrations in solution gas) and are subject to
significant uncertainties 10
. The potential
indirect GHG contributions of these species have
thus been omitted. In this case, a GHG emission
factor for venting ( vEF ) can be determined
according to eq (4), where 4CHGWP is the mass-
based global warming potential factor of
methane, and all other variables are determined
as above:
22441 COCOCHCHCv MGWPM
TR
PEF
(4)
Categorized flaring and venting emission factors
are reported in Table 2, assuming 100-year time
horizons for the cited GWP values 10
. In
practice, however, the combustion efficiency of
flares is dependent on many factors, such as
cross-wind speed, gas exit velocity, flare exit
diameter, composition of the gas, and steam
assist rate (when relevant) 7,8,26-28
. To better
reflect real-world conditions, emission factors
were also calculated in Table 2 for cases of non-
ideal combustion. For this calculation, it was
assumed that unburned gases retained their
initial compositions; that is, the emission factor
for a flare with 98% efficiency is a linear
combination of 98% flaring and 2% venting.
This scenario inherently assumes that
inefficiencies are dominated by stripping of
unburned fuel 6.
Finally, the GWP of methane as published by
the Intergovernmental Panel on Climate Change
(IPCC)10
, has seen some revision between
publication cycles. In the most recent
assessment report, AR4, the 100-year horizon
GWP value is 25, whereas in AR2 the value was
21 10
. Even more recent analysis 11
, in which
direct and indirect effects of aerosol responses to
oxidant changes associated with methane
emissions are also considered, suggests that
actual 100-year horizon GWP values for
methane may be 10-40% higher than the AR4
value. Nevertheless, due to legacy issues and
legal frameworks, some government bodies
continue to require the use the methane GWP
value from AR2 (despite the fact that these data
are currently more than fifteen years out of
date). Recognizing this reality, emission factors
for venting were separately derived using both
AR4 and AR2 GWP values and included in
Table 2 to extend its potential applicability. For
the emission factors derived for flaring, the
variation associated with using different GWP
values was not significant (there is no difference
if 100% carbon conversion efficiency is
assumed), so only the most recent IPCC GWP
value for methane was considered.
15
Table 2: Summary of GHG emission factors in tonnes of CO2 equivalent per 103m
3 of solution gas
a evaluated
on a 100-year horizon derived using data from all batteries, from batteries reporting any amount of venting
batteries, or from batteries that flared exclusively.
All Batteries Venting Batteriesb
Exclusively Flaring
Batteriesc
Mean 10th 90th Mean 10th 90th Mean 10th 90th
EFf (100%)d 2.10 1.90 2.28 2.07 1.90 2.25 2.16 2.03 2.31
EFf (98%)d 2.35 2.13 2.55 2.32 2.13 2.51 2.40 2.25 2.56
EFf (95%)d 2.72 2.48 2.95 2.70 2.48 2.92 2.77 2.59 2.95
EFv (25)e 14.58 13.38 15.62 14.73 13.45 15.64 14.20 13.20 15.13
EFv (21)e 12.25 11.24 13.12 12.38 11.30 13.14 11.93 11.09 12.71
a All volumes assume a pressure of 101.325 kPa and temperature of 15°C.
b Venting batteries include all batteries that report any amount of venting (i.e. batteries that vent
exclusively as well as batteries reporting both flaring and venting) c Exclusively flaring batteries did not report any amount of venting
d Percentages shown refer to flare combustion efficiency; calculations performed assuming incomplete
combustion emissions occur via a fuel stripping mechanism5 and a GWP for methane of 25.
e Value refers to GWP of methane used in the calculation.
Though GWP values are most commonly quoted
assuming a 100-year time horizon, this is not
universally the best choice. For short-lived
climate forcers such as CH4, which has a steady
state lifetime in the atmosphere of about 9
years29
, the 100-year time frame understates the
opportunity for near-term climate forcing
reductions11
. Unlike emissions of CO2 which
once released may persist in the atmosphere for
centuries, mitigation of CH4 emissions would
lead to near-term reductions in atmospheric
concentrations and consequent climate forcing
within 10-20 years 30,31
. Table 3 compares mean
GHG emission factors for flaring and venting
calculated using 20- and 100-year time horizons.
These results show that near-term climate
forcing impacts from venting are much more
severe than for flaring. Conversely, this
difference illustrates a significant opportunity
for near-term mitigation of climate forcing, and
shows how substitution of flaring for venting
leads to a factor of ~20 reduction in CO2
equivalent emissions per unit volume of solution
gas over a 20-year time horizon.
16
Table 3: Comparison of Mean GHG Emission Factors for Flaring and Venting Evaluated over 20- and 100-
year Time Horizonsa derived using data from all batteries, from batteries reporting any amount of venting
batteries, or from batteries that flared exclusively.
All Batteries Venting Batteriesb
Exclusively Flaring
Batteriesc
Time Horizon 20-year 100-year 20-year 100-year 20-year 100-year
EFf (100%)d 2.10 2.10 2.07 2.07 2.16 2.16
EFf (98%)d 2.92 2.35 2.89 2.32 2.93 2.40
EFf (95%)d 4.14 2.72 4.13 2.70 4.09 2.77
EFv 42.86 14.58 43.27 14.73 40.72 14.20 a Emission factors are presented in units of tonnes of CO2 equivalent per 103m3 of solutions gas (all volumes
assume a pressure of 101.325 kPa and temperature of 15°C). Calculations assume GWP values for CH4 of 25
(100-year time horizon) and 72 (20-year time horizon) as given in IPCC AR410. b Venting batteries include all batteries that report any amount of venting (i.e. batteries that vent exclusively as
well as batteries reporting both flaring and venting) c Exclusively flaring batteries did not report any amount of venting d Percentages shown refer to flare combustion efficiency; calculations performed assuming incomplete
combustion emissions occur via a fuel stripping mechanism5.
Estimation of GHG Emissions from Flaring
and Venting in Alberta
In 2008, 5945 batteries in Alberta reportedly
flared or vented solution gas. Flaring activity
was reported by 2360 of these batteries, totalling
305106 m
3 of gas flared. Conservatively
assuming ideal combustion and using the 100-
year time horizon emission factor derived for
exclusively flaring (i.e. non-venting) sites, this
implies GHG emissions totalling 0.664 Mt of
CO2 equivalent from solution gas flaring at
upstream battery sites. Venting activity,
reported by 4263 batteries, totalled a similar raw
gas volume of 382106 m
3. The GHG impact of
venting, however, was an order of magnitude
greater at 5.74 Mt. The combined total 2008
GHG emissions from solution gas flaring and
venting at battery sites in Alberta was thus found
to be at least 6.41 Mt. GHG emissions from all
upstream flaring and venting sources in Alberta
(i.e. including additional flaring during well-
tests and at gas plants, etc. which raised total
flare and vent volumes to 1.11 billion m3 in
200816
) were approximately 7.64 Mt in 2008.
Finally, assuming that the provincial average
flaring emission factor is reasonably
representative of associated gas worldwide, the
estimated global total of 139 billion m3 of gas
flared as determined by satellite imagery 2
translates to an annual emission of 292 Mt of
CO2 equivalent. Given the lack of detailed
information on global venting volumes in the
literature, for the purpose of making a very
rough estimate, if venting trends in Alberta
could be considered representative of worldwide
activity, then the GHG contribution of
worldwide associated gas venting would be on
the order of 2 Gt of CO2 equivalent. While the
uncertainty inherent in this type of gross
estimate should not be understated, GHG
emissions of this magnitude would represent
significant source globally (~5% of the world
total of 38.75 Gt in 2005)32
. Uncertainties in
sources of this potential magnitude highlight the
need for closer analyses of industry reported
data and ultimately for better direct flow and
composition monitoring of flared and vented gas
streams globally, and are a further example of
the challenges faced in reconciling bottom-up
global GHG reporting with top-down estimates
derived from atmospheric measurements 33
.
17
CONCLUSIONS
A method has been developed to estimate the
composition of the solution gas produced at each
of the 13,144 oil and bitumen batteries in the
Province of Alberta that reported flaring or
venting activity between January 2002 and
December 2008. Measured gas samples from
specific sources were tied to geographic location
through production facilities, and this
information was then used to estimate the
compositions of nearby sites lacking measured
samples. For this most significant production
region within the Western Canadian
Sedimentary Basin, analysis revealed that gas
flared and vented has reasonably consistent
composition with a site-weighted mean methane
concentration of 85.8% with 10th and 90
th
percentile concentrations of 78.6% and 92.0%
respectively. Heating values were also found to
be well above the 20 MJ/m3 minimum limit
linked in regulation to poor flare combustion
efficiencies. Composition variations are
apparent across the region, with higher methane
content gas linked with heavy oil producing
regions in particular. Greenhouse gas emission
factors were derived under various scenarios,
assuming different composition ranges and
different assumed flare combustion efficiencies.
For a reference case assuming 100% flare
conversion efficiencies, GHG emissions from
flaring and venting at batteries in Alberta were
determined to amount to 6.41 Mt in 2008, and
7.64 Mt including all reported upstream flare
and vent sources. Applying these emission
factors globally, the 139 billion m3 of flaring
estimated from satellite data would equate to
292 Mt of GHG emissions annually. The
derived data and methods can be used in efforts
to quantify and manage flaring and venting
emissions and to better assess mitigation
opportunities.
ACKNOWLEDGMENTS
This project was supported by Natural Resources
Canada CanMET Energy (Project manager
Michael Layer), and would not have been
possible without the invaluable support and
cooperation of James Vaughan, Jim Spangelo,
Jill Hume, Harvey Halladay, and Jim Dilay of
the Alberta Energy Resources Conservation
Board (ERCB).
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ABOUT THE AUTHORS
Adam Coderre has an M.A.Sc. degree in
Mechanical Engineering from Carleton
University and worked as a research engineer in
the Energy & Emissions Lab within the
Mechanical & Aerospace Engineering
19
department of Carleton University. He is
currently a Project Engineer at Clearstone
Engineering Ltd., Calgary, AB. Matthew
Johnson is the Canada Research Chair in Energy
& Combustion Generated Pollutant Emissions
and an associate professor at Carleton University
where he heads the Energy and Emissions
Research Lab. Please address correspondence
to: Matthew Johnson, Mechanical and
Aerospace Engineering, Carleton University,
1125 Colonel By Drive, Ottawa, ON, Canada,
K1S 5B6; phone: +1-613-520-2600 ext. 4039;
fax: +1-613-520-5715; email:
matthew_johnson@carleton.ca.