Compositions and Greenhouse Gas Emission Factors of Flared...

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1 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 authorspreprint 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: [email protected] ; 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 CO 2 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.

Transcript of Compositions and Greenhouse Gas Emission Factors of Flared...

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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: [email protected]; 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.

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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

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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

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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

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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

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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.

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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

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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

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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

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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.

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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.

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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

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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.

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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.

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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

.

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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

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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:

[email protected].