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Comparisons of Airborne Measurements and Inventory Estimates of Methane Emissions in the Alberta Upstream Oil and Gas Sector



Airborne measurements of methane emissions from oil and gas infrastructure were completed over two regions of Alberta, Canada. These top-down measurements were directly compared with region-specific bottom-up inventories that utilized current industry-reported flaring and venting volumes (reported data) and quantitative estimates of unreported venting and fugitive sources. For the 50 × 50 km measurement region near Red Deer, characterized by natural gas and light oil production, measured methane fluxes were more than 17 times greater than that derived from directly reported data but consistent with our region-specific bottom-up inventory-based estimate. For the 60 × 60 km measurement region near Lloydminster, characterized by significant cold heavy oil production with sand (CHOPS), airborne measured methane fluxes were five times greater than directly reported emissions from venting and flaring and four times greater than our region-specific bottom up inventory-based estimate. Extended across Alberta, our results suggest that reported venting emissions in Alberta should be 2.5 ± 0.5 times higher, and total methane emissions from the upstream oil and gas sector (excluding mined oil sands) are likely at least 25–50% greater than current government estimates. Successful mitigation efforts in the Red Deer region will need to focus on the >90% of methane emissions currently unmeasured or unreported.
Comparisons of Airborne Measurements and Inventory Estimates of
Methane Emissions in the Alberta Upstream Oil and Gas Sector
Matthew R. Johnson,*
David R. Tyner,
Stephen Conley,
Stefan Schwietzke,
and Daniel Zavala-Araiza
Energy & Emissions Research Laboratory, Department of Mechanical and Aerospace Engineering, Carleton University, Ottawa, ON
Canada, K1S 5B6
Scientic Aviation, Inc., 3335 Airport Road Suite B, Boulder, Colorado 80301, United States
CIRES/University of Colorado, NOAA ESRL Global Monitoring Division, 325 Broadway R/GMD 1, Boulder, Colorado
80305-3337, United States
Environmental Defense Fund, 301 Congress Avenue Suite 1300, Austin, Texas 78701, United States
SSupporting Information
ABSTRACT: Airborne measurements of methane emissions
from oil and gas infrastructure were completed over two regions
of Alberta, Canada. These top-down measurements were
directly compared with region-specic bottom-up inventories
that utilized current industry-reported aring and venting
volumes (reported data) and quantitative estimates of
unreported venting and fugitive sources. For the 50 ×50 km
measurement region near Red Deer, characterized by natural gas
and light oil production, measured methane uxes were more
than 17 times greater than that derived from directly reported
inventory-based estimate. For the 60 ×60 km measurement
region near Lloydminster, characterized by signicant cold
heavy oil production with sand (CHOPS), airborne measured
methane uxes were ve times greater than directly reported emissions from venting and aring and four times greater than our
region-specic bottom up inventory-based estimate. Extended across Alberta, our results suggest that reported venting emissions
in Alberta should be 2.5 ±0.5 times higher, and total methane emissions from the upstream oil and gas sector (excluding mined
oil sands) are likely at least 2550% greater than current government estimates. Successful mitigation eorts in the Red Deer
region will need to focus on the >90% of methane emissions currently unmeasured or unreported.
The Government of Canada has proposed new regulations
intended to deliver on its commitment to reduce emissions of
methane from the oil and gas sector by 4045% below 2012
levels by 2025.
The Province of Alberta is Canadas largest
producer of fossil fuel resources, in 2015 accounting for 68% of
Canadian natural gas production,
47% of light crude oil
production, and 80% of all crude oil and equivalent production
(i.e., crude oil, synthetic crude oil, crude bitumen, condensate,
and pentanes plus).
Alberta has separately announced plans to
develop regulations to reduce methane emissions in the oil and
gas sector through a combination of new design standards,
improved measurement and reporting, and regulated stand-
As of this writing, draft federal regulations are under
review, while Albertas proposed regulations are under active
development. Especially important questions for the success of
these regulations include the accuracy of the assumed baseline
methane emission estimates, the accuracy and completeness of
current reporting, and the nature and distribution of sources.
Uncertainty in true methane emission magnitudes, especially
from unreported and fugitive sources, complicates the
identication and implementation of the most eective
methane mitigation options. Several recent studies have
highlighted this challenge, where impacts of vented and leaked
methane can signicantly increase the eective carbon intensity
of one fuel source relative to another.
While much of the
recent focus in the literature has been on determining methane
emissions associated with hydraulically fractured natural gas
methane emissions are an important concern
across the entire upstream oil and gas sector.
To date there have been few measurement studies of
methane emissions from oil and gas developments in Canada. A
notable exception is a very recent mobile survey study of
Received: July 12, 2017
Revised: September 25, 2017
Accepted: October 6, 2017
© XXXX American Chemical Society ADOI: 10.1021/acs.est.7b03525
Environ. Sci. Technol. XXXX, XXX, XXXXXX
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natural gas developments in northeastern British Columbia,
Canada, which found that 47% of active wells emitted
detectable methane.
Another recent study
focused on
collecting detailed activity data (i.e., counts of pneumatic
equipment and numbers of leaks) across dierent regions in
Alberta. Moreover, some resources and operating practices in
the Canadian energy sector are unique in North America. Apart
from oil sands development, this includes production of heavy
oil resources in the Lloydminster region on the border between
Alberta and Saskatchewan as well as the Peace River area of
Alberta. Based on our analysis of production data as further
discussed below, we estimate that in 2016, heavy oil accounted
for 33% of conventional oil production in Alberta (i.e.,
excluding oil obtained through mined oil sands production).
The objectives of this study were to (i) generate an up to
date, spatially resolved, bottom-up inventory-based estimate of
methane emissions from the Alberta upstream oil and gas
sector following the approaches used in the Canadian national
inventory while incorporating current well- and facility-level
volumetric and activity data for 2016 as reported by industry to
the Alberta Energy Regulator (AER), (ii) quantify regional
methane emissions using airborne techniques in two distinct oil
and gas producing regions of Alberta, and (iii) directly compare
these top-down and bottom-up methane emissions estimates.
The methodological comparison has implications both for
understanding the accuracy and completeness of current
emission reporting, and for evaluating the eectiveness of
current federal and provincial regulatory eorts aimed at
reducing methane emissions in this sector.
Ocial inventory estimates of greenhouse gas (GHG)
emissions in Canada are provided in Environment and Climate
Change Canadas (ECCC) National Inventory Report (NIR).
Based on the current ECCC inventory for 2014 (most recent
data available), just over one-quarter (26%) of Canadas total
GHG emissions and 44% of Canadas total methane emissions
are attributed to the oil and gas sector, making it the largest
source of both total GHG and methane emissions in Canada. In
Alberta, approximately half of the provinces total GHG
emissions, and 70% of its total methane emissions, are from
the oil and gas sector. Further analysis of underlying ECCC
methane emissions inventory data are shown in Figure 1,
estimated by production type and general source category.
These are the specic emissions to be addressed by proposed
federal and provincial regulations.
As shown in the left panel of Figure 1, the majority (88%) of
the ECCC estimated 1.26 Mt of methane emissions in the
Alberta oil and gas sector is from upstream natural gas and
conventionaloil production, with the remainder coming from
oil sands mining and upgrading (11%) and downstream
rening and distribution (0.6%). The latter contributions
from mined oil sands operations are generally diuse and
dicult to quantify, and include fugitive methane released
during large-scale surface mining
as well as biogenically
generated methane emitted from tailings ponds.
practical options for mitigating these diuse sources are
understood to be limited, proposed Alberta regulations for oil
sands have focused on setting a future cap on total greenhouse
gas emissions of 100 MtCO2e, leaving approximately 30
MtCO2eofroomfor continued growth beyond current
emissions levels.
Methane emissions from oil sands mining
operations are also notably excluded from the proposed Federal
regulations. Thus, successful cuts in overall methane emissions
will primarily need to be achieved through reductions from
sources outside the mined oil sands.
The right panel of Figure 1 shows the source breakdown of
the 1.11 Mt of methane emissions from upstream oil and gas
production (excluding mined oil sands), as derived from the
current ECCC inventory. A critical observation is that only
one-quarter (24.8%) of the Alberta methane emissions in the
ocial inventory is from directly reported data. This fraction is
ultimately derived from whole-gas venting and aring volumes
from active oil and gas facilities reported by industry to the
Alberta Energy Regulator (AER) in accordance with AER
Directive 60.
It is important to note that the greenhouse gas
emission factors for crude oil and crude bitumen presented by
AER in ST60B
are based only on these reported data, and do
not include the other 75% of unreported source emissions as
estimated in the ECCC inventory.
Furthermore, although oil and gas operators (industry)in
Alberta are required to submit reportable ared and vented
whole gas volumes to AER on a monthly basis, source data used
in the federal ECCC inventory are only fully updated
approximately every ve years, most recently in 2014 using
baseline data for 2011.
In interim years, ocial estimates in
the NIR are generated using projections from the baseline year,
based on activity data available to ECCC (which are generally
less detailed than those maintained by AER in their general well
le and related production accounting data).
Thus, the
methane attributed to reported venting and aring in the
ECCC 2014 inventory data is actually scaled from 2011
reported data, where the methane component of these volumes
is calculated using assumed average gas compositions for
dierent types of wells and xed are eciencies of 98%.
Estimates for the remaining three-quarters of methane
emissions in Figure 1 that are not traced back to reported
volumesbroadly categorized as fugitive emissions, unreported
venting, and methane emissions from combustion sourcesare
derived from a combination of emission factors and reported or
estimated activity data (e.g., numbers of drilled oil or gas wells;
assumed typical numbers of pumps and vessels per site based
on eld survey data; etc.).
These unreported venting sources
may include instrument vent gas, compressor start gas, purge
Figure 1. 2014 Methane emissions from the oil and gas sector in
Alberta as derived from ECCCs National Inventory Report.
The left
panel highlights contributions from dierent production types; the
right panel distinguishes the emission types from natural gas and
conventional oil production (i.e., excluding mined oil sands). Mt =
million metric tonnes, equivalent to one teragram (Tg),
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gas and blanket gas that is discharged directly to the
atmosphere, dehydrator still column o-gasetc. that is not
normally included in reported vented volumes.
sources in the inventory include leaking equipment such as
valves or compressor seals, tank/truck loading and unloading
operations, storage losses, and accidental releases or spills that
are similarly not included in currently reported data.
Measurement Regions. Figure 2 shows the geographic
distribution of industry reported vented whole gas volumes in
the province of Alberta in 2016. As further detailed below,
Figure 2 is based on raw monthly production accounting data
submitted by industry to AER, and obtained directly from AER.
All upstream oil and gas facilities (i.e., oil and gas batteries, gas
plants, gas gathering systems, etc., but excluding mined oil
sands operations) were included in the data set. The actual
reported volumes shown in Figure 2 should closely correspond
to the green 24% reported ventingslice of Figure 1 as
estimated by ECCC. Reported venting is heavily concentrated
in the Lloydminster region of the province, and is associated
with heavy oil production in that area. Except for some elevated
venting east of Peace River that is also associated with heavy oil
production and isolated activity near Grande Prairie, the
remainder of the province shows generally uniform, and about
an order of magnitude lower venting levels.
Two contrasting measurement regions were denedone
near Lloydminster and one near Red Deeras indicated by the
black squares on Figure 2. The Lloydminster region was
dominated by heavy oil production, whereas the Red Deer
region was characterized as a mix of older natural gas and light
oil production. As illustrated in Figure 3, these regions were
selected considering several parameters, including magnitudes
of reported venting, types of oil and gas facilities within the
regions, local density of oil and gas wells, and presence/absence
of other industrial facilities identied using the National
Pollutant Release Inventory (NPRI) database.
methane emissions are not included in the NPRI, the database
is still useful for identifying types and locations of industrial
facilities not associated with oil and gas that emit any one of
more than 300 species of interest (e.g., NOx, PM, CO, VOCs,
212 listed substances of interest, 30 individual PAH species, and
7 dioxin and 10 furan/hexachlorobenzene species) above
required ECCC reporting thresholds. In practice, this includes
a wide range of operations including waste treatment facilities
and mine sites.
The Lloydminster measurement region (Figure 3a,b), was
selected to capture the region of highest reported venting in the
province. The larger area (60 ×60 km), as compared to the
Red Deer region (50 ×50 km), was chosen to ensure well-
dened boundaries based on the distribution of active wells.
Overall there were 2291 heavy oil wells (identied as producing
from a deposit rather than a pool), 214 gas wells, 0 gas plants,
and one in situ oil sands battery/injection facility within the
measurement region. Most, if not all, of these heavy oil facilities
would be expected to be characterized as CHOPS (cold heavy
oil production with sand)
facilities. This type of production is
noteworthy in that it frequently involves venting of methane
from the production casing directly to atmosphere.
the thousands of oil and gas facilities within the nal dened
region, there was one NPRI reporting facility not associated
with oil and gas (a salt production facility), which is not
expected to be a source of methane.
The 50 ×50 km Red Deer measurement region (Figure
3c,d), reported venting levels typical of much of the province.
The density of oil and gas sites was extremely high, and all
NPRI reporting facilities contained within the selected region
were associated with oil and gas production. Overall the Red
Deer region included 2053 gas wells, 613 oil wells, and 11 gas
Regional Bottom-Up Inventory Calculations. Bottom-
up inventory estimates were generated starting from raw
monthly production accounting data submitted by industry to
Petrinex, a production accounting system used for regulatory
reporting and royalty calculations. Petrinex is jointly governed
by the provinces of Alberta and Saskatchewan, and industry as
represented by the Canadian Association of Petroleum
Producers (CAPP) and the Explorers and Producers
Association of Canada (EPAC). These data, obtained in
collaboration with AER, parallel publicly available facility
production information sold in the AER Products and Services
Catalogue. However, the form of the data obtained allowed
volumes reported at individual batteries (i.e., upstream facilities
where raw euenta combination of gas, water, and/or oil
from one or more wells is initially collected, separated for
measurement and sometimes pretreated) and other facilities to
be linked back to individual producing wells, which was critical
for many aspects of the spatially resolved inventory develop-
ment. These facility-level volumetric data were linked with
detailed well activity data available in AERs general well data
le, which allowed identication of types of wells feeding into
batteries. In particular, this allowed venting volumes reported in
aggregate at paper batteries(i.e., groups of disperse, physically
disconnected wells reporting aggregated volume data as if they
were connected at a single battery, as mostly occurs within the
Figure 2. Geographic distribution of industry reported venting
volumes in Alberta in 2016. Selected measurement regions are
indicated with black squares.
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Lloydminster region of Alberta) to be appropriately located
based on individual source wells.
Light and heavy oil
batteries were distinguished based on the types of the pools or
deposits from which wells feeding each battery were producing.
A further distinction between heavy cold production and heavy
thermal production was derived from AER-assigned battery
Under AER Directive 60, operators are required to report
monthly aring and venting (whole gas) volumes exceeding
100 m3/month from active facilities.
Industry is also required
to report volumes of produced gas used for onsite as fuel;
however, since this gas may be ared (i.e., used as purge or pilot
gas in a are system), combusted (e.g., used as fuel in natural
gas compressors), or vented directly to atmosphere (e.g., used
to drive pneumatic equipment), these fuel gas data have limited
utility in emissions estimation and are only used to estimate the
small fraction of methane emitted in the exhaust of combustion
systems. Monthly reported ared and vented gas volumes are
submitted to AER through the Petrinex reporting system,
which AER uses to produce annual summary reports of aring
and venting volumes.
However, industry is not currently
required to report composition or methane content of vented
gas. AER does not currently collect data on greenhouse gas
For the present analysis, site specic gas composition data
were determined starting from an AER data set of individual
well gas analyses containing 312 654 useable samples associated
with 117 206 well segments, each coded with a unique well
identier (UWI). Individual gas compositions at all active oil
and gas batteries in Alberta were estimated using production-
weighted composition data from each UWI feeding into each
battery. Compositions of active UWIs without available direct
gas sample data were calculated by spatial interpolation from
nearby sites with data. Where possible, compositions of
reported ared and vented gas at other facilities (e.g., gas
plants and gas gathering systems) were similarly determined
using a gas-volume-weighted average of the reported gas
receipts from feeding upstream facilities, supplemented by
spatial interpolation where necessary. This procedure allowed
site-specic methane emissions to be calculated at individual
wells, batteries, and other facilities throughout the province.
Gas production-weighted methane and ethane fractions could
then be accurately determined for each measurement region as
further detailed in the Supporting Information (SI). Finally, the
2016 methane emissions from reported aring and venting
volumes were calculated using site-specic composition data.
As noted in the Current Inventories section, the ocial
ECCC national greenhouse gas inventory also includes
provincial estimates of emissions from unreported sources in
Figure 3. Measurement regions of interest near the cities of Lloydminster and Red Deer in Alberta. The background contour grid shows the local
magnitudes of reported venting using the same color scale as Figure 2. Gray dots added in (a) and (c) show nearby nonoil and gas industry facilities
appearing in the National Pollutant Release Inventory (NPRI). Colored triangles appearing in (b) and (d) indicate oil and gas wells, oil and gas
batteries, gas plants, compressor stations, gas gathering systems and other associated upstream oil and gas facilities. Background satellite imagery
source layer credits: Esri, DigitalGlobe, GeoEye, Earthstar Graphics, CNES/Airbus DS, USDA, USGS, AEX, Getmapping Aerogrid,
IGN,IGP,swisstopo, and the GIS User Community.
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the oil and gas sector. Thus, to generate complete and directly
comparable bottom-up inventory data for each measurement-
region, estimates of unreported vented and fugitive emission
sources were also calculated. This was accomplished following
the same approaches used in the development of ECCCs
federal greenhouse gas inventory,
while updating them to
use current AER 2016 activity and production data. For each
operation type (i.e., ECCC sector) and source category
each region, unreported emissions were separately updated by
prorating the relevant ECCC 2011 baseline-year data using
currently derived, up to date and region-specic activity data.
These regionalized data included numbers of existing and new
wells, ared and vented gas volumes, produced gas volumes,
reported fuel volumes, and produced volumes of liquids,
categorized as oil, heavy oil, or crude bitumen. The end result
of this analysis was a current and detailed bottom-up inventory
for each measurement region that included, and separately
identied, methane emissions associated with sources directly
reported to AER, as well as emissions from unreported source
categories listed in the ECCC national inventory.
Airborne Flux Measurements. Regional methane and
ethane emission rates were calculated based on airborne
measurements from a series of ights conducted during
October 27 to November 5, 2016. The measurement and
emission quantication methodology is detailed elsewhere
and is only briey reviewed here. To estimate the magnitude of
a trace gas source at the surface, a ight track consisting of a
series of concentric closed paths around the source of interest is
employed. These paths begin as close as possible to the ground
(usually 150 m) and climb until aircraft is well above the
highest level the plume reaches before crossing the ight path,
which is determined by the absence of signicant upwind/
downwind variability in the methane signal. The instantaneous
vector ux of a target species (i.e., methane or ethane) is simply
the vector wind
multiplied by the species density (kg m3).
Density is computed using the mixing ratios reported by the
ight-ready Picarro CRDS spectrometer along with the
temperature from the Vaisala HMP60 probe and the pressure
from the air data computer (Aspen PFD1000). At each altitude
(individual closed path), the net ux into the region bounded
by the path is simply the sum of the ux normal to the ight
path (dot product of ux vector and ight path). The number
of laps required to obtain a robust estimate varies from 20
close to the source
to 1 if the aircraft is far enough downwind
for the plume to mix throughout the boundary layer.
For the
present case, the plume was well mixed, conrmed by at least
one vertical prole on each lap.
The uncertainty on the measured ux for each lap considered
contributions from the uncertainty in the wind measurement
(0.5 m s1), the uncertainty in the methane or ethane
measurement (1 or 5 ppb), and the uncertainty in the
boundary layer height (50 m). As further detailed in the SI,
each lap was treated as an independent measurement and the
variance of the uxes among laps was used as a direct measure
of the precision uncertainty. The reported 95% condence
intervals in the mean regional emissions ux considered the
combined instrument and precision uncertainties, while
correcting for sample size using the t-statistic.
The relative contributions of oil and gas sector and biogenic
sources to these total measured methane uxes were assessed in
two ways. First, direct attribution of oil and gas sector emissions
was determined using the ratio of the methane and ethane ux
as measured by the aircraft. Given that biogenic sources only
emit methane, the directly measured ratios, combined with
knowledge of the mean methane/ethane ratio of the produced
gas at local oil and gas facilities (see Table 1), allowed the mass
of methane emissions attributable to oil and gas activity to be
determined. For the Red Deer region, with a mean ethane
Table 1. Summary of Derived Bottom-up Emissions Data within the Measurement Regions
region specic inventory data Lloydminster Red Deer
measurement region statistics
GPS coordinates (centroid) 110.517365,
dimensions (km) 60 ×60 50 ×50
no. of active wells in 2016 2631 2672
no. of gas wells/no. oil wells/no. oil wells identied as CHOPS wells 214/2350/2291 2053/613/0
no. of new wells drilled in 2016 52 24
no. of gas/oil batteries (including single-well batteries) 42/1430 773/296
no. of gathering systems/compressor stations/gas plants/other oil and gas facilities 60/29/0/86 144/126/11/50
total volume of gas produced (106m3) 467 3511
total volume of oil and heavy oil produced (103m3) 3906 403
volume weighted mean CH4content of produced gas (by volume) 97.2% 82.1%
volume weighted mean C2H6content of produced gas (by volume) 0.675% 7.65%
Emissions Associated with Directly Reported Sources
industry reported venting in 2016 (1000 m3, whole gas) 60,602 2,540
industry reported aring in 2016 (1000 m3, whole gas) 662 8582
CH4emissions from industry reported venting (tCH4/h) 4.6 0.16
CH4emissions from industry reported aring (tCH4/h) 0.0010 0.011
combined CH4emissions from directly reported aring and venting (tCH4/h) 4.6 0.17
Estimated Additional Methane Emissions Following ECCC Inventory Methodology
CH4emissions from combustion sources (tCH4/h) 0.050 0.13
CH4emissions from unreported venting sources (tCH4/h) (incl. emissions from glycol dehydrators as per Figure 4) 0.66 1.5
CH4emissions from unreported fugitive sources (tCH4/h) (incl. emissions from leaks, gas migration, storage losses,
etc. per Figure 4)1.4 0.93
total estimated methane from unreported sources (tCH4/h) 2.1 2.5
total expected bottom-up methane emissions (including reported and unreported sources) (tCH4/h) 6.7 2.7
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content of 7.65%, the oil and gas attributable (i.e., fossil)
component of the methane ux was estimable in this manner.
However, for the Lloydminster region, where the regional
ethane fraction was more than an order of magnitude lower
(0.68%), the corresponding uncertainties in the measured
ethane ux were more than two times the measured value,
limiting the utility of this method.
In the second approach, spatially explicit (0.1°×0.1°spatial
resolution) methane emission estimates for anthropogenic
sources from the Emissions Database for Global Atmospheric
Research v4.3 (EDGAR)
were used to calculate methane
uxes from sources not associated with oil and gas (i.e., from
enteric fermentation, manure, and landlls and waste) in each
measurement region. Results suggest biogenic methane
emissions of 0.42 tCH4/h in the Lloydminster measurement
region and 0.89 tCH4/h in the Red Deer region. These values
may be slightly conservative since the provincial total EDGAR
methane emissions were noted to be 9% higher than the
available total provincial methane estimates from livestock and
landlls/waste in the ECCC NIR.
However, the EDGAR data
were within the range of published CH4emission estimates
from livestock and landlls/waste sources in U.S. oil and gas
producing basins.
The potential for additional methane
emissions from microbial activity in local wetlands (which are
not included in the EDGAR data) was also considered using six
globally gridded wetland methane emission data sets
). Based on 12 consecutive years of
data from 19932004 (latest years available), average
November wetland emissions were estimated to be 0.0018
±0.0020 tCH4/h in Lloydminster and 0.015 ±0.015 tCH4/h
in Red Deer (uncertainties are standard error of the mean).
The slightly negative emissions in the Lloydminster region
implies that the soil sink is larger than the positive wetland
emissions in November in these models. Combined with the
EDGAR results, this literature analysis suggests expected total
biogenic methane emissions of 0.42 tCH4/h in the
Lloydminster region and 0.91 tCH4/h in the Red Deer region.
Bottom-up Methane Emissions. Table 1 reports
summary statistics and derived bottom-up inventory volumes
for the two measurement regions. Although the total number of
active oil and gas wells in each region was comparable, their
production and methane emission characteristics were quite
dierent. The Red Deer region contained a mix of gas (77%)
and light oil wells (23%) whereas the Lloydminster region was
dominated by heavy oil wells (89%) associated with CHOPS
production. As shown in Table 1, average total methane
emissions from reported venting and aring volumes were 4.6
tCH4/h in the Lloydminster measurement region and 0.17
tCH4/h near Red Deer. Methane emissions from reported
venting volumes were responsible for almost all of these totals
(99.98% in Lloydminster, 93.7% in Red Deer). The signicantly
higher reported emissions in the Lloydminster region are
indicative of the density of CHOPS production sites in the area,
and their associated venting of casing gas. Using pool or deposit
codes of wells feeding into batteries as criteria for identifying
heavy oil production sites, CHOPS production sites accounted
for 39% of all reported venting from oil production in Alberta
(excluding mined oil sands).
Estimates of unreported methane sources were also
generated for each region by combining ECCC baseline
inventory data with up to date, region-specic volume and
activity data, as summarized in the lower rows of Table 1.In
combination with methane emissions derived from directly
reported aring and venting volume data as submitted to AER,
this provides a more up to date and complete bottom-up
inventory estimate of both reported and unreported methane
sources as shown in the nal row of Table 1.Inthe
Lloydminster measurement region, methane from unreported
sources added an additional 47% to that from reported venting,
representing 32% of the total bottom-up methane inventory
estimate in the region. In the Red Deer region, unreported
sources were 15 times larger than reported sources, equating to
94% of the local bottom-up methane inventory.
This is a signicant nding that arms previous studies
reporting similar challenges between inventory estimates and
reporting programs in the U.S.
The available provincial
summary data in the ECCC NIR potentially obscures the fact
that in oil and gas production regions like Red Deer, methane
associated with directly reported data (i.e., as currently reported
to AER under Directive 60) makes up only a small fraction of
total emissions. From the regional methane emission break-
downs shown in Figure 4, unreported venting (e.g., pneumatic
instrument vent gas, purge gas, compressor starts, tank venting,
etc.) and fugitive leaks are responsible for nearly three-quarters
(73%) of bottom-up methane emissions in the Red Deer
region. By contrast, the bottom-up inventory suggests that the
Lloydminster region is dominated by reported venting (68% of
methane emissions) with fugitive leaks and unreported venting
as the next largest sources combining for 20%.
Regional Estimates from Airborne Measurements.
Top-down measured, mean total methane emission rates were
24.5 ±5.9 tCH4/h in the Lloydminster region and 3.05 ±1.1
tCH4/h in the Red Deer region. As further detailed in the SI,
the reported ranges are 95% condence intervals about the
measured mean emission rates. For the Red Deer region, the
aircraft measured ethane ux of 0.53 ±0.38 tC2H6/h, and the
regional ethane fraction of 7.65%, implied that eectively all of
the measured methane (3.07 ±2.2 tCH4/h) was attributable to
oil and gas operations (i.e., fossil). The uncertainty range
includes the estimate of 2.14 tCH4/h that would be generated if
the literature estimate of biogenic methane emissions in the
region were instead assumed. However, the higher value seems
more likely in the context of a recent report by GreenPath
Energy Ltd.
inventorying pneumatic equipment and
associated leaks. In a study region that almost completely
overlaps the Red Deer measurement region, they estimated an
average pneumatic leak rate of 6.54 tCH4/y per well. Applying
Figure 4. Relative importance of sources contributing to the bottom
up methane inventory for the measurement regions near (a)
Lloydminster and (b) Red Deer.
Environmental Science & Technology Article
DOI: 10.1021/acs.est.7b03525
Environ. Sci. Technol. XXXX, XXX, XXXXXX
this emission factor to the 2666 wells in Table 1 suggests a
methane ux of 2.0 tCH4/h just from pneumatic devices alone.
The present aircraft based estimate suggests that other sources
account for an additional 1 tCH4/h.
For the Lloydminster region, oil and gas sources were
similarly responsible for the vast majority of measured methane
emissions, equating to 24.1 ±5.9 tCH4/h. Even considering the
slightly larger measurement area, this is still more than ve
times higher than near Red Deer. Moreover, given the results
for the Red Deer region, the use of the literature-based value
for biogenic source estimation in Lloydminster might be
considered conservative.
Top-Down vs Bottom-up Emissions Comparison.
Figure 5 compares top-down measurements of methane ux
in each measurement region with presently estimated bottom-
up calculations as detailed in Table 1. The pink bar in each
panel represents the total methane ux based on the aircraft
measurements; corresponding 95% condence intervals are
indicated directly on each bar. The red bars represent the net
methane ux attributable to oil and gas development activity
within each measurement region, where the dierence between
the adjacent pink and red bars is the biogenic methane
contribution. As described previously, the biogenic methane
contribution for the Lloydminster region is based on EDGAR
estimates, while for the Red Deer region, it is based on the
directly measured ratio of ethane to methane ux.
The oil and gas sector methane emission rate in the
Lloydminster region of 24.1 tCH4/h is 3.6 times greater than
the current total bottom-up inventory estimate, and 5.3 times
greater than the methane emissions from directly reported
venting and aring. On an annual basis, the high rate of
methane emissions alone within this small 60 ×60 km region
represents GHG emissions of 5.3 MtCO2e (conservatively
evaluated on a 100-year time horizon with GWPCH4 = 25).
Using more recent IPCC GWPCH4 values,
this equates to 18/
6.3 MtCO2e evaluated on a 20/100-year basis.
These results
verify the overwhelming emission contribution of CHOPs
production in this area, while further suggesting signicant
under-reporting or under-estimation of methane emissions to
the atmosphere.
Total Red Deer methane emissions were consistent with the
current regional inventory estimate once reported and
unreported sources were combined, and much lower than the
levels seen in the Lloydminster region. However, the aircraft
measurement based methane ux was still more than 17 times
greater than directly reported data would suggest, arming the
regionally derived inventory result that the vast majority of
methane emissions in this area are from sources not currently
monitored or reported.
Implications. In the context of proposed regulations aimed
at reducing methane emissions in the Canadian oil and gas
sector by 45%, large discrepancies between actual methane
emissions and emissions from currently reported data present a
critical challenge. With unreported emissions in regions like
Red Deer accounting for 94% of the total methane emissions,
the majority of reductions will need to come from sources that
may not yet be identied and/or are not being measured.
Specically, assuming the source breakdown (Figure 4) in the
presently estimated regional inventory for Red Deer, 70% of
methane is likely to come from unreported venting and fugitive
leaks. This strongly suggests a need for policies to address this
reporting gap as these sources represent signicant methane
reductions opportunities. Research performed in U.S. elds
with similar production characteristics has highlighted the
presence of spatial and temporal emission patterns that require
a frequent or even continuous monitoring scheme in order to
control fugitive leaks.
Field measurement statistics from
pneumatic equipment in particular, emphasize the importance
Figure 5. Top-down vs bottom-up comparison of methane emissions in the (a) Lloydminster and (b) Red Deer measurement regions.
Environmental Science & Technology Article
DOI: 10.1021/acs.est.7b03525
Environ. Sci. Technol. XXXX, XXX, XXXXXX
of frequent inspection programs for identifying the subset of
malfunctioning and high-emitting devices responsible for the
large majority of emissions.
In addition, further empirical
measurements at the site and component-level, and more
comprehensive accounting of facilities, major equipment, and
activity data would consistently improve bottom-up estimates.
The discrepancy of a factor of 35 between measured
methane emissions and both the reported and inventory
estimates in the Lloydminster region is noteworthy, and
contrasts with results for the Red Deer region, where combined
reported and unreported emissions essentially matched air-
borne measurements. This suggests that the unexplained
emissions in the Lloydminster region are attributable to unique
operating practices in that area, which is characterized by a large
population of CHOPS sites. The most likely source of the
excess methane emissions in the Lloydminster region is
underreported venting of casing gas from CHOPS sites,
which is generally estimated based on the product of the
measured produced oil volume and an assumed gas to oil ratio
Current regulations require that the GOR be
measured every six months (if the produced gas volumes are
>1000 m3/day), or as infrequently as every 3 years (if gas
volumes are <1000 m3/day).
One interpretation of the
present results is that current measurement and reporting
practices for casing gas venting via periodic GOR measure-
ments are inadequate. This may be especially true given
anecdotal data that produced gas volumes at CHOPS sites can
be highly variable in time.
This temporal heterogeneity
suggests the necessity of regular monitoring if reductions are to
be achieved.
The possibility of underreporting at CHOPS sites presents
important implications at the provincial level given the
dominance of CHOPS region emissions in reported venting
totals for Alberta (Figure 2). If the extra 17.4 tCH4/h of
methane emissions in the Lloydminster measurement region
are assumed to come from CHOPS facilities, and then extended
to other CHOPS production sites in Alberta while leaving
current inventory estimates for all other types of facilities
unchanged, this suggests that total reported venting in Alberta is
low by a factor of 2.5 (range of 2.03.1). Relative to current
inventory estimates of both reported and unreported emissions,
the present results suggest that actual methane emissions from
the upstream oil and gas sector (excluding mined oil sands) are
likely to be at least 2550% greater than currently estimated.
Considering data gathered in other regions suggest fugitive and
vented emissions are underestimated,
it seems probable
that this 38% augmentation may be conservatively low. This
also suggests further investigations would be warranted in other
production regions of Alberta (e.g., Rocky Mountain House,
Grande Prairie, and Peace River regions), as well as in
Saskatchewan and British Columbia. Overall, the present results
suggest that federal and provincial eorts to regulate methane
are timely. A 45% cut in the current Alberta inventory methane
emissions totals from Figure 1 implies a decrease of 500
ktCH4/y. The present results suggest a reduction of 924
ktCH4/y would actually be required to reach the same absolute
emissions target.
SSupporting Information
The Supporting Information is available free of charge on the
ACS Publications website at DOI: 10.1021/acs.est.7b03525.
Details of the airborne measurements and regional gas
compositions (PDF)
Corresponding Author
*Phone: 1 613 520 2600 ×4039; e-mail: Matthew.Johnson@
Matthew R. Johnson: 0000-0002-3637-9919
Daniel Zavala-Araiza: 0000-0002-8394-5725
The authors declare no competing nancial interest.
Funding for this work was provided by the generous supporters
of the Environmental Defense Fund (EDF), Natural Sciences
and Engineering Research Council of Canada (NSERC, Grant
#261966 and 446199), and Natural Resources Canada (Project
Manager Michael Layer). We are especially thankful for the
assistance received from Steve Smyth at Environment and
Climate Change Canada (ECCC) and Gerald Palanca at
Alberta Energy Regulator (AER) in interpreting national
inventory data and retrieving production accounting informa-
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... Direct atmospheric measurements have shown that national inventories of CH 4 emissions from the O&G sector in North America underestimate the problem (Brandt et al., 2014;Johnson et al., 2017;Zavala-Araiza et al., 2018). CH 4 emissions from a defined geographic region can be quantified by using the bottom-up or the top-down approach (Brandt et al., 2014;Harriss et al., 2015). ...
... Information about atmospheric gas dispersion can be obtained either by adopting atmospheric models, that is, the Gaussian plume model (GPM; Hensen and Scharff, 2001;Hensen et al., 2006; and Other Test Method (OTM) 33A (U.S. EPA, 2014), or by releasing a tracer gas (Brantley et al., 2014;Mitchell et al., 2015;Yacovitch et al., 2015;Yacovitch et al., 2017;Robertson et al., 2017;Zavala-Araiza et al., 2018;O'Connell et al., 2019). The top-down approach includes studies that use aircraft, tall towers, ground sampling, and remote-sensing (satellites) to infer CH 4 emissions from a geographic region (Brandt et al., 2014;Schwietzke et al., 2014a;Smith et al., 2015;Johnson et al., 2017). ...
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... Typical vented emissions are the natural gas pneumatics found on the well heads, maintenance emissions (e.g., VRU blowdown and restart), gas slip from the VRUs, venting when the VRUs are overwhelmed, and incomplete combustion of gas by the flare. Flare destruction efficiency is generally accepted to be 98% but has been observed as low as 55% (Johnson and Kostiuk, 2002;Chambers, 2003;Johnson et al., 2017;Zavala-Araiza et al., 2021). ...
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Methane (CH 4) is emitted during extraction, processing, and transport processes in the natural gas industry. As a powerful greenhouse gas, CH 4 releases are harmful to the environment. Operators aim to minimize methane loss, and continuous monitoring using low-cost fence-line sensors are now being developed to observe methane enhancements downwind of operations. However, it is not clear how useful these systems are and whether they can be used to quantify emissions or simply identify the presence of a leak. To investigate this, we deployed 4 calibrated low-cost sensors 30 m from emissions of known rates over a 48-h period. The aims were to determine: (1) how much of the time a fence-line system would detect a leakage event from a single, point source of the size typically seen at oil and gas production well pads and (2) how accurately a fence-line system can estimate CH 4 emissions using a relatively simple downwind dispersion method. Our results show that during a 48-h measurement period, the fence-line sensor network could detect CH 4 releases of 84 g h-1 40% of the time and 100% of the time for emissions greater than 167 g h-1 using an enhancement threshold of 2 ppm. A Gaussian plume inversion based on binned centerline, maximum measured concentrations and the WindTrax Lagrangian particle model were each tested. With these models, average estimated emissions were within ±50% of a known emission rate in 24 h and ±25% in 48 h; however, estimated individual 20-min average emissions vary by more than a factor of 10. A simple Gaussian plume inversion using all of the measured concentrations produced unreasonable average emission estimates because of the inability of the equation to parameterize lateral dispersion at distances less than 100 m when the sensor was on the edge of the plume. This study provides evidence to support the use of low-cost sensors as autonomous fence-line monitoring systems to detect and potentially quantify emissions. If the sensors are properly calibrated and sensor deployment location is optimized for prevailing wind directions at each site, fence-line systems could be used routinely to quantify emissions from oil and gas infrastructure.
... Methane emissions at upstream oil and gas production sites, in particular from atmospheric vents on storage tanks and well casings, have been identified as a potentially underestimated contributor to total industry emissions [1][2][3][4][5]. Vented methane volumes from these sources are challenging to measure directly, as the flows may be both intermittent and transient and the composition (methane fraction) in the emitted gas may vary in time depending on the processes driving the emissions. ...
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An optical sensor employing tunable diode laser absorption spectroscopy with wavelength modulation and 2f harmonic detection was designed, prototyped, and tested for applications in quantifying methane emissions from vent sources in the oil and gas sector. The methane absorption line at 6026.23 cm–1 (1659.41 nm) was used to measure both flow velocity and methane volume fraction, enabling direct measurement of the methane emission rate. Two configurations of the sensor were designed, tested, and compared; the first used a fully fiber-coupled cell with multimode fibers to re-collimate the laser beams, while the second used directly irradiated photodetectors protected by Zener barriers. Importantly, both configurations were designed to enable measurements within regulated Class I / Zone 0 hazardous locations, in which explosive gases are expected during normal operations. Controlled flows with methane volume fractions of 0 to 100% and a velocity range of 0 to 4 m/s were used to characterize sensor performance at a 1 Hz sampling rate. The measurement error in the methane volume fraction was less than 10,000 ppm (1%) across the studied range for both configurations. The short-term velocity measurement error with pure methane was <0.3 m/s with a standard deviation of 0.14 m/s for the fiber-coupled configuration and <0.15 m/s with a standard deviation of 0.07 m/s for the directly irradiated detector configuration. However, modal noise in the multimode fibers of the first configuration contributed to an unstable performance that was highly sensitive to mechanical disturbances. The second configuration showed good potential for an industrial sensor, successfully quantifying methane flow rates up to 11 kg/h within ±2.1 kg/h at 95% confidence over a range of methane fractions from 25–100%, and as low as ±0.85 kg/h in scenarios where the source methane fraction is initially unknown within this range and otherwise invariant.
... Lu21 find higher oil-gas emissions for the US and Canada compared to GFEI v1 with high averaging kernel sensitivities for both countries. Many past studies in the US have found an underestimate of oil-gas emissions in the US national inventory (Alvarez et al., 2018;Cui et al., 2019;Maasakkers et al., 2019Rutherford et al., 2021), and similar underestimates have been shown for Canada's national inventory (Johnson et al., 2017;Atherton et al., 2017;Baray et al., 2018Baray et al., , 2021Chan et al., 2020;Scarpelli et al., 2022;MacKay et al., 2021;Tyner and Johnson, 2021). These underestimates are not addressed in the more recent versions of the national inventories as used in GFEI v2 (Table 2). ...
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We present an updated version of the Global Fuel Exploitation Inventory (GFEI) for methane emissions and evaluate it with results from global inversions of atmospheric methane observations from satellite (GOSAT) and in situ platforms (GLOBALVIEWplus). GFEI allocates methane emissions from oil, gas, and coal sectors and subsectors to a 0.1∘ × 0.1∘ grid by using the national emissions reported by individual countries to the United Nations Framework Convention on Climate Change (UNFCCC) and mapping them to infrastructure locations. Our updated GFEI v2 gives annual emissions for 2010–2019 that incorporate the most recent UNFCCC national reports, new oil–gas well locations, and improved spatial distribution of emissions for Canada, Mexico, and China. Russia's oil–gas emissions in its latest UNFCCC report (4.1 Tg a−1 for 2019) decrease by 83 % compared to its previous report while Nigeria's latest reported oil–gas emissions (3.1 Tg a−1 for 2016) increase 7-fold compared to its previous report, reflecting changes in assumed emission factors. Global gas emissions in GFEI v2 show little net change from 2010 to 2019 while oil emissions decrease and coal emissions slightly increase. Global emissions from the oil, gas, and coal sectors in GFEI v2 (26, 22, and 33 Tg a−1, respectively in 2019) are lower than the EDGAR v6 inventory (32, 44, and 37 Tg a−1 in 2018) and lower than the IEA inventory for oil and gas (38 and 43 Tg a−1 in 2019), though there is considerable variability between inventories for individual countries. GFEI v2 estimates higher emissions by country than the Climate TRACE inventory, with notable exceptions in Russia, the US, and the Middle East where TRACE is up to an order of magnitude higher than GFEI v2. Inversion results using GFEI as a prior estimate confirm the lower Russian emissions in the latest UNFCCC report but find that Nigeria's reported UNFCCC emissions are too high. Oil–gas emissions are generally underestimated by the national inventories for the highest emitting countries including the US, Venezuela, Uzbekistan, Canada, and Turkmenistan. Offshore emissions tend to be overestimated. Our updated GFEI v2 provides a platform for future evaluation of national emission inventories reported to the UNFCCC using the newer generation of satellite instruments such as TROPOMI with improved coverage and spatial resolution. This increased observational data density will be especially beneficial in regions where current inversion systems have limited sensitivity including Russia. Our work responds to recent aspirations of the Intergovernmental Panel on Climate Change (IPCC) to integrate top-down and bottom-up information into the construction of national emission inventories.
The oil and gas industry is Canada’s largest contributor to national methane (CH4) emissions. To quantify the input of active and inactive (suspended and abandoned) oil and gas infrastructure to regional CH4 budgets, we conducted truck-based measurements (transect-based and OTM 33A) with a greenhouse gas analyzer, complimented with optical gas imaging at oil-producing sites of Saskatchewan, including understudied regions. We found that inactive sites regionally accounted for roughly 43% of total measured CH4 emissions in Lloydminster, 9% in Kindersley, and 0% in Swift Current. Thus, CH4 emissions from oil production in southwestern Saskatchewan are underestimated by almost 25% if emissions from inactive sites are ignored. Measured mean CH4 emissions of actively producing oil and gas infrastructure in Lloydminster were at least 50% lower (36 ± 7 m3/day) than found in previous studies potentially due to declines in production schemes, effective implementation of emission reduction approaches, or spatial differences between sampled sites. Unlike previous studies, measured emissions in Lloydminster were lower than reported values (147 ± 10 m3/day). In contrast, measured emissions in Kindersley (64 ± 17 m3/day) and Swift Current (23 ± 16 m3/day) were close to reported emissions despite observed tank vents and unlit flares. Unlit flares emitted at least 3 times more CH4 than other infrastructure types and were the “super-emitters” in this study. Currently, provincial and federal regulations target only active infrastructure, but regulators may consider extending regulations to inactive sites where data suggest significant emission reduction potential.
In carbon-intensive industries like oil and gas production, ESG (Environmental, Social, Governance) reports provide investors with information about carbon intensity performance and there is link between environmental and financial performance. In Canada, ESG reporting is not obligatory, and multiple frameworks are used making performance comparisons across producers challenging. Additionally, methane emissions from the oil and gas industry are underestimated in Canada which also suggests systemic under-reporting of emissions in this key area of carbon intensity. Here we investigate 2019 methane emission intensity gaps for 70 of Canada's largest oil and gas producers, between 1) provincial regulatory submissions, 2) assumed contributions to the federal inventory estimates, 3) a mobile ground laboratory measurement-based inventory, 4) and producer self-published ESG. We de-aggregated existing methane inventory estimates and measurements for Canada's largest producing province, Alberta, and found a greater than 1000-fold variation in methane intensities within the cohort. We also found surprisingly broad agreement in assumed methane emission intensities between (2) and (3), suggesting they capture the same signals. Regulatory submissions captured only a small amount of the total methane inventory and we also observed a low bias in regulatory reporting. In conclusion, we believe that changes to required and voluntary reporting, and associated systems management frameworks are needed to differentiate oil and gas producers and preserve market access based on carbon intensity.
Due to renewed interest in emission accounting and reduction inspired by the adoption of the Paris agreement in 2015, the growth of applications of atmospheric observations and modeling to emission estimates was accompanied by a search for new methods of atmospheric observations and techniques used to estimate emissions, including new inverse modeling, transport modeling approaches, and development of the high-resolution emission inventories. The needs for top-down estimates range from emission accounting and reduction by facility operator, to validation of the emission inventory by regional and national governments. Accordingly, the observing systems are developed depending on the target, such as the use of mobile observatories on ship, car, or aircraft for facility-level emissions, or a combination of the regional and global networks of atmospheric observations for validation of the national scale emission inventories. In this chapter we discuss the development and application of the new top-down methods for the purpose of climate mitigation by supporting accounting and monitoring of the greenhouse gas emissions, including (a) validation of the national greenhouse gas emission inventories, (b) methane leak detection in oil and gas industry based on aircraft, surface, and satellite observations, (c) observations and estimation of the large point source GHG emissions from satellites, (d) development of the new transport modeling and gridded emission inventory techniques, suitable for processing a large amount of the high-resolution observations both ground based and spaceborn.
As oil and gas wells age and the number of wells drilled increases to meet demand, we may see more instances of fugitive soil gas migration (GM) and associated methane (CH4) emissions. Due to the immense spatiotemporal variability of soils and uncertainty in measurement practice, the detection and quantification of GM emissions is a challenge. Two common measurement techniques include the shallow in-soil gas concentration approach and soil surface flux measurements using flux chambers. In this numerical modeling study, both methods were compared to determine how soil texture, environmental conditions (water content, temperature), and CH4 leak rates into the soil profile influenced in-soil CH4 concentration and surface CH4 flux rates. We observed that in-soil CH4 concentration was strongly controlled by soil texture and environmental conditions, whereas surface CH4 flux rates were far less sensitive to those same parameters. Flux measurements were more useful for determining severity of the CH4 leak into the soil and allowed us to differentiate between leak and nonleak scenarios in soils with biological CH4 production which could complicate a GM assessment. We also evaluated field measurements of carbon dioxide from an enhanced oil recovery site to demonstrate how seasonal conditions can influence concentrations of trace gases in shallow soil. Based on our model results and supplemental field measurements, we propose that flux chamber measurements present a more reliable tool to assess the incidence and severity of fugitive GM.
Abandoned, active, and marginally producing (producing <1700 m3/day of natural gas or <1.6 m3/day of oil) oil and gas (O&G) wells emit methane (CH4), a potent greenhouse gas, and hydrogen sulfide (H2S), a highly toxic gas, but measurements to quantify these emission rates are lacking. Here, we conduct 85 measurements of CH4 and H2S emission rates from 63 abandoned, active and marginally producing gas wells and a wetland area overlying a possible undocumented well in Ontario, the Canadian province with the longest history of O&G development. Our measurements show that abandoned wells emitting H2S are some of the highest CH4 emitters (average = 21,400 mg CH4/h/well), followed by abandoned unplugged and marginally producing wells. Abandoned plugged (average = 2100 mg CH4/h/well) and active (average = 6800 mg CH4/h/well) wells are the lowest CH4 emitters. Compared to inventory estimates, CH4 emissions from marginally producing and active wells in Ontario are underestimated by a factor of 2.1, and emissions from abandoned plugged wells are underestimated by a factor of 920. H2S emissions, currently not included in the Canadian Air Pollutant Emissions Inventory, average at 128 mg H2S/h/well. Our findings highlight the importance of conducting measurements from all types of oil and gas wells including H2S emitting wells to understand H2S and CH4 emissions and develop policies to reduce greenhouse gas emissions, improve air quality, and protect human and ecosystem health.
A challenge for mobile measurement of fugitive methane emissions is the availability of portable sensors that feature high sensitivity and fast response times, simultaneously. A methane gas sensor to measure fugitive emissions was developed using a continuous-wave, thermoelectrically cooled, GaSb-based distributed feedback diode laser emitting at a wavelength of 3.27 μm to probe methane in its strong ν3 vibrational band. Direct absorption spectra (DAS) as well as wavelength-modulated spectra (WMS) of pressure-broadened R(3) manifold lines of methane were recorded through a custom-developed open-path multipass cell with an effective optical path length of 6.8 m. A novel metrological approach was taken to characterize the sensor response in terms of the linearity of different WMS metrics, namely, the peak-to-peak amplitude of the X2f component and the peak and/or the integrated area of the background-subtracted quadrature signal (i.e., Q(2f - 2f0)) and the background-subtracted 1f-normalized quadrature signal (i.e., Q(2f/1f - 2f0/1f0)). Comparison with calibration gas concentrations spanning 1.5 to 40 ppmv indicated that the latter WMS metric showed the most linear response, while fitting DAS provides a traceable reference. In the WMS mode, a sensitivity better than 1 ppbv was achieved at a 1 s integration time. The sensitivity and response time are well-suited to measure enhancements in ambient methane levels caused by fugitive emissions.
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Airborne estimates of greenhouse gas emissions are becoming more prevalent with the advent of rapid commercial development of trace gas instrumentation featuring increased measurement accuracy, precision, and frequency, and the swelling interest in the verification of current emission inventories. Multiple airborne studies have indicated that emission inventories may underestimate some hydrocarbon emission sources in US oil- and gas-producing basins. Consequently, a proper assessment of the accuracy of these airborne methods is crucial to interpreting the meaning of such discrepancies. We present a new method of sampling surface sources of any trace gas for which fast and precise measurements can be made and apply it to methane, ethane, and carbon dioxide on spatial scales of ∼ 1000 m, where consecutive loops are flown around a targeted source region at multiple altitudes. Using Reynolds decomposition for the scalar concentrations, along with Gauss's theorem, we show that the method accurately accounts for the smaller-scale turbulent dispersion of the local plume, which is often ignored in other average mass balance methods. With the help of large eddy simulations (LES) we further show how the circling radius can be optimized for the micrometeorological conditions encountered during any flight. Furthermore, by sampling controlled releases of methane and ethane on the ground we can ascertain that the accuracy of the method, in appropriate meteorological conditions, is often better than 10 %, with limits of detection below 5 kg h⁻¹ for both methane and ethane. Because of the FAA-mandated minimum flight safe altitude of 150 m, placement of the aircraft is critical to preventing a large portion of the emission plume from flowing underneath the lowest aircraft sampling altitude, which is generally the leading source of uncertainty in these measurements. Finally, we show how the accuracy of the method is strongly dependent on the number of sampling loops and/or time spent sampling the source plume.
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North American leaders recently committed to reducing methane emissions from the oil and gas sector, but information on current emissions from Canadian unconventional developments is lacking. This study examined the incidence of methane in an area of unconventional natural gas development in northwestern Canada. In August to September 2015 we completed almost 8000 km of vehicle-based survey campaigns on public roads dissecting developments that mainly access the Montney formation in northeastern British Columbia. Six survey routes were repeated 3–6 times and brought us past over 1600 unique well pads and facilities developed by more than 50 different operators. To attribute on-road plumes to infrastructural sources we used gas signatures of residual excess concentrations (anomalies above background) less than 500 m downwind from infrastructural sources. All results represent emissions greater than our minimum detection limit of 0.59 g/s at our average detection distance (319 m). Unlike many other developments in the US for which methane measurements have been reported recently, the methane concentrations we measured at surface were close to normal atmospheric levels, except inside natural gas plumes. Roughly 47 % of active wells emitted methane-rich plumes above our minimum detection limit. Abandoned and under-development well sites also emitted methane-rich plumes, but the incidence rate was below that of producing wells. Multiple sites that pre-date the recent unconventional Montney development were found to be emitting, and in general we observed that older infrastructure tended to emit more often (per unit) with comparable severity in terms of measured excess concentrations on-road. We also observed emissions from facilities of various types that were highly repeatable. Emission patterns in this area were best explained by infrastructure age and type. Extrapolating our results across the Montney development, we estimate that the emission sources we located (emitting at a rate > 0.59 g/s) contribute more than 111,800 tonnes of methane annually to the atmosphere. This value exceeds reported bottom-up estimates of 78,000 tonnes for all oil and gas sector sources in British Columbia, of which the Montney represents about 55 % of production. The results also demonstrate that mobile surveys could be used to exhaustively screen developments for super-emitters, because without our intensive 6-fold replication we could have used single-pass sampling to screen 80 % of Montney-related infrastructure. This is the first bottom-up study of fugitive emissions in the Canadian energy sector, and these results can be used to inform policy development in an era of methane emission reduction efforts.
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Natural methane (CH<sub>4</sub>) emissions from wet ecosystems are an important part of today's global CH<sub>4</sub> budget. Climate affects the exchange of CH<sub>4</sub> between ecosystems and the atmosphere by influencing CH<sub>4</sub> production, oxidation, and transport in the soil. The net CH<sub>4</sub> exchange depends on ecosystem hydrology, soil and vegetation characteristics. Here, the LPJ-WHyMe global dynamical vegetation model is used to simulate global net CH<sub>4</sub> emissions for different ecosystems: northern peatlands (45°–90° N), naturally inundated wetlands (60° S–45° N), rice agriculture and wet mineral soils. Mineral soils are a potential CH<sub>4</sub> sink, but can also be a source with the direction of the net exchange depending on soil moisture content. The geographical and seasonal distributions are evaluated against multi-dimensional atmospheric inversions for 2003–2005, using two independent four-dimensional variational assimilation systems. The atmospheric inversions are constrained by the atmospheric CH<sub>4</sub> observations of the SCIAMACHY satellite instrument and global surface networks. Compared to LPJ-WHyMe the inversions result in a~significant reduction in the emissions from northern peatlands and suggest that LPJ-WHyMe maximum annual emissions peak about one month late. The inversions do not put strong constraints on the division of sources between inundated wetlands and wet mineral soils in the tropics. Based on the inversion results we diagnose model parameters in LPJ-WHyMe and simulate the surface exchange of CH<sub>4</sub> over the period 1990–2008. Over the whole period we infer an increase of global ecosystem CH<sub>4</sub> emissions of +1.11 Tg CH<sub>4</sub> yr<sup>−1</sup>, not considering potential additional changes in wetland extent. The increase in simulated CH<sub>4</sub> emissions is attributed to enhanced soil respiration resulting from the observed rise in land temperature and in atmospheric carbon dioxide that were used as input. The long-term decline of the atmospheric CH<sub>4</sub> growth rate from 1990 to 2006 cannot be fully explained with the simulated ecosystem emissions. However, these emissions show an increasing trend of +3.62 Tg CH<sub>4</sub> yr<sup>−1</sup> over 2005–2008 which can partly explain the renewed increase in atmospheric CH<sub>4</sub> concentration during recent years.
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Terrestrial net CH<sub>4</sub> surface fluxes often represent the difference between much larger gross production and consumption fluxes and depend on multiple physical, biological, and chemical mechanisms that are poorly understood and represented in regional- and global-scale biogeochemical models. To characterize uncertainties, study feedbacks between CH<sub>4</sub> fluxes and climate, and to guide future model development and experimentation, we developed and tested a new CH<sub>4</sub> biogeochemistry model (CLM4Me) integrated in the land component (Community Land Model; CLM4) of the Community Earth System Model (CESM1). CLM4Me includes representations of CH<sub>4</sub> production, oxidation, aerenchyma transport, ebullition, aqueous and gaseous diffusion, and fractional inundation. As with most global models, CLM4 lacks important features for predicting current and future CH<sub>4</sub> fluxes, including: vertical representation of soil organic matter, accurate subgrid scale hydrology, realistic representation of inundated system vegetation, anaerobic decomposition, thermokarst dynamics, and aqueous chemistry. We compared the seasonality and magnitude of predicted CH<sub>4</sub> emissions to observations from 18 sites and three global atmospheric inversions. Simulated net CH<sub>4</sub> emissions using our baseline parameter set were 270, 160, 50, and 70 Tg CH<sub>4</sub> yr<sup>−1</sup> globally, in the tropics, in the temperate zone, and north of 45° N, respectively; these values are within the range of previous estimates. We then used the model to characterize the sensitivity of regional and global CH<sub>4</sub> emission estimates to uncertainties in model parameterizations. Of the parameters we tested, the temperature sensitivity of CH<sub>4</sub> production, oxidation parameters, and aerenchyma properties had the largest impacts on net CH<sub>4</sub> emissions, up to a factor of 4 and 10 at the regional and gridcell scales, respectively. In spite of these uncertainties, we were able to demonstrate that emissions from dissolved CH<sub>4</sub> in the transpiration stream are small (<1 Tg CH<sub>4</sub> yr<sup>−1</sup>) and that uncertainty in CH<sub>4</sub> emissions from anoxic microsite production is significant. In a 21st century scenario, we found that predicted declines in high-latitude inundation may limit increases in high-latitude CH<sub>4</sub> emissions. Due to the high level of remaining uncertainty, we outline observations and experiments that would facilitate improvement of regional and global CH<sub>4</sub> biogeochemical models.
Global warming potentials (GWPs) have become an essential element of climate policy and are built into legal structures that regulate greenhouse gas emissions. This is in spite of a well-known shortcoming: GWP hides trade-offs between short- and long-term policy objectives inside a single time scale of 100 or 20 years ( 1 ). The most common form, GWP100, focuses on the climate impact of a pulse emission over 100 years, diluting near-term effects and misleadingly implying that short-lived climate pollutants exert forcings in the long-term, long after they are removed from the atmosphere ( 2 ). Meanwhile, GWP20 ignores climate effects after 20 years. We propose that these time scales be ubiquitously reported as an inseparable pair, much like systolic-diastolic blood pressure and city-highway vehicle fuel economy, to make the climate effect of using one or the other time scale explicit. Policy-makers often treat a GWP as a value-neutral measure, but the time-scale choice is central to achieving specific objectives ( 2 – 4 ).
Effectively mitigating methane emissions from the natural gas supply chain requires addressing the disproportionate influence of high-emitting sources. Here we use a Monte Carlo simulation to aggregate methane emissions from all components on natural gas production sites in the Barnett Shale production region (Texas). Our total emission estimates are two-thirds of those derived from independent site-based measurements. Although some high-emitting operations occur by design (condensate flashing and liquid unloadings), they occur more than an order of magnitude less frequently than required to explain the reported frequency at which high site-based emissions are observed. We conclude that the occurrence of abnormal process conditions (for example, malfunctions upstream of the point of emissions; equipment issues) cause additional emissions that explain the gap between component-based and site-based emissions. Such abnormal conditions can cause a substantial proportion of a site's gas production to be emitted to the atmosphere and are the defining attribute of super-emitting sites.
Methane has the second-largest global radiative forcing impact of anthropogenic greenhouse gases after carbon dioxide, but our understanding of the global atmospheric methane budget is incomplete. The global fossil fuel industry (production and usage of natural gas, oil and coal) is thought to contribute 15 to 22 per cent of methane emissions1, 2, 3, 4, 5, 6, 7, 8, 9, 10 to the total atmospheric methane budget11. However, questions remain regarding methane emission trends as a result of fossil fuel industrial activity and the contribution to total methane emissions of sources from the fossil fuel industry and from natural geological seepage12, 13, which are often co-located. Here we re-evaluate the global methane budget and the contribution of the fossil fuel industry to methane emissions based on long-term global methane and methane carbon isotope records. We compile the largest isotopic methane source signature database so far, including fossil fuel, microbial and biomass-burning methane emission sources. We find that total fossil fuel methane emissions (fossil fuel industry plus natural geological seepage) are not increasing over time, but are 60 to 110 per cent greater than current estimates1, 2, 3, 4, 5, 6, 7, 8, 9, 10 owing to large revisions in isotope source signatures. We show that this is consistent with the observed global latitudinal methane gradient. After accounting for natural geological methane seepage12, 13, we find that methane emissions from natural gas, oil and coal production and their usage are 20 to 60 per cent greater than inventories1, 2. Our findings imply a greater potential for the fossil fuel industry to mitigate anthropogenic climate forcing, but we also find that methane emissions from natural gas as a fraction of production have declined from approximately 8 per cent to approximately 2 per cent over the past three decades.