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EcofysKanaalweg 16-G
P.O. Box 8408
3503 RK Utrecht
The Netherlands
T: +31 (0)30 662 3300
F: +31 (0)30 662 3301
W: www.ecofys.com
October 2009
Eliane Blomen, Ann Gardiner
Ecofys
Financial support from the DGRTD (European Community Sixth Framework Programme) and DGENV of the
European Commission as well as of the Dutch and German ministries of Environment (VROM and BMU) is
acknowledged. The SERPEC paper reflects the opinion of the authors and does not necessarily reflect the
opinion of the European Commission, VROM and BMU on the results obtained.
Sectoral Emission Reduction Potentials and Economic
Costs for Climate Change (SERPEC-CC)
Methane from fugitive emissions
I
Executive Summary
The aim of the project Sectoral Emission Reduction Potentials and Economic Costs for
Climate Change (SERPEC-CC) is to identify the potential and costs of technical control
options to reduce greenhouse gas emissions across all European Unions sectors and Member
States in 2020 and 2030.
In this SERPEC sectoral report, we present emission abatement opportunities and associated
costs for fugitive emissions from fuels sector, in the European Union. Fugitive emissions
from fossil fuels are intentional or unintentional releases of greenhouse gases (GHGs) from
the production, processing, transmission, storage, and delivery of fossil fuels. Due to the
large share of methane in total emissions (82% in the EU), this report focuses mainly on the
reduction of methane emissions (except when flaring is concerned, as these emissions are
mainly CO2).
Fugitive emissions contributed approximately 2% to the overall greenhouse gas (GHG)
emissions in the EU27 in 2005. As oil, coal and natural gas production are all forecasted to
decline in the EU, the (frozen technology) reference level forecasts a decline in emissions up
to 2030. Against this reference level, we identified an abatement potential of 33 Mt CO2-eq
in 2030 (see Figure 1). This is a 49% reduction compared to the baseline. Out of this
abatement potential, 12.6 Mt CO2-eq can be realised in the solid fuels (coal mining) sector.
This is 50% of the projected 2030 value for this subsector. The emission reduction potential
for reducing emissions in the oil and natural gas sector is 21 Mt CO2-eq. This is 49% of the
projected 2030 value for this sector.
0
20
40
60
80
100
120
140
2000 2005 2010 2015 2020 2025 2030
FTRL (D ire ct) Reduction (D irect)
Mt CO2eq
F igure 1 Emiss ion curves for fug i t ive emiss ions in the EU27, showing the Frozen
Technology Reference development (FTRL) and the abatement potent ia l
identi f ied in th is s tudy.
Table 1 below presents emission abatement opportunities in the solid fuels sector and the oil
and natural gas sector and associated costs in €/tCO2-eq assuming a discount rate of 4% and
no taxes (see also Figure 2). Negative costs means that when the measure is applied, over the
lifetime of the measure if yields more money than it costs. Approximately 10 Mt of CO2-eq
emissions in the European Union can be reduced against negative costs and an extra 20 Mt of
CO2-eq emissions can be reduced at low costs (below 3 € per tonne of CO2-eq). The last 3 Mt
of emission reduction will cost between 3 and 11 € per tonne of CO2-eq.
-4
-2
0
2
4
6
8
10
12
0 5 10 15 20 25 30 35
Mt CO2eq
€ / t CO2eq
F igure 2 Abatement potentia l and spec i f ic cost of options to abate fug i t ive
emiss ions in the fue ls sector in the EU27 in 2030. The abatement
potent ia l i s re lat ive to the f rozen techno logy reference scenar io.
III
Table 1 Opt ions to abate fug it ive emiss ions in the fue ls sector: abatement
potent ia l and speci f ic costs in 2020 and 2030. Abatement potentia l i s
re leat ive to the Frozen Technology re ference leve l.
Sector Name abatement potential (kt-CO2-eq)
Specific costs (Euro/t-CO2)
2020
Coal mining Enhanced Degasification 1,558 -2.2
Coal mining Degasification 3,241 -1.8
Coal mining Oxidation of Ventilation Air Methane 1,527 1.2
Oil and natural gas
Chronic leaks (pipelines, distribution facilities, other) natural gas
9,045 2.1
Oil and natural gas
Chronic leaks (pipelines, distribution facilities, other) oil 187 2.1
Oil and natural gas
Reducing flaring emissions 868 2.8
Oil and natural gas
Elimination of venting 230 10.8
2030
Coal mining Enhanced Degasification 3,117 -2.2
Coal mining Degasification 6,483 -1.8
Coal mining Oxidation of Ventilation Air Methane 3,054 1.2
Oil and natural gas
Chronic leaks (pipelines, distribution facilities, other) oil 373 2.1
Oil and natural gas
Chronic leaks (pipelines, distribution facilities, other) natural gas
18,091 2.1
Oil and natural gas
Reducing flaring emissions 1,736 2.8
Oil and natural gas
Elimination of venting 460 10.8
V
Table of contents
Executive Summary i
1 Introduction 7
1.1 The SERPEC project, fugitive emissions from fuels sector 7
1.2 Method 9
2 Options to reduce CH4 emissions from the sol id
fuels sector 14
2.1 Introduction 14
2.2 Results 16
2.3 Conclusion and discussion 18
3 Options to reduce CH4 emissions from the oi l
and natural gas sector 19
3.1 Introduction 19
3.2 Results 25
3.3 Conclusion and discussion 29
4 Conclusions 30
References 34
7
1 Introduction
1.1 The SERPEC project , fug i t ive emiss ions f rom fue ls
sector
The SERPEC project
The aim of the project Sectoral Emission Reduction Potentials and Economic Costs for
Climate Change (SERPEC-CC) is to identify the potential and costs of technical control
options to reduce greenhouse gas emissions across all European Unions sectors and Member
States in 2020 and 2030. The results are presented in so-called cost-abatement curves that
provide a least-cost ranking of options across technologies, sectors and countries in the EU.
In general, cost-abatement curves provide strategic information for policy makers.
Nearly all identified abatement options refer to technologies that are applied already today.
To identify their abatement potentials we estimated the maximum feasible implementation
rates, often governed by the rate of turnover of existing technology stocks. Costs of already
matured technologies were generally assumed constant over time, whereas either costs or
performance of relatively new technologies, e.g. wind turbines, were allowed decrease over
time due to economies of scale and technology learning.
Fugitive emissions from fuels sector
Fugitive emissions from fossil fuels are intentional or unintentional releases of greenhouse
gases (GHGs) from the production, processing, transmission, storage, and delivery of fossil
fuels. This report deals with these emissions, i.e. from the oil and natural gas sector and the
coal mining sector, in the European Union. Within these two sectors, emissions from
methane form the largest contribution to the greenhouse gas emissions in most countries (see
Figure 3). Due to the large share of methane in total emissions (82% in EU), this report
focuses mainly on the reduction of methane emissions. Emission reduction of CO2 will only
be considered for flaring.
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
GBR
PO
LDEU
ROM IT
ACZE
FRA
ESP
HUN
NLD
BGR
GR
CPRT
SVK
AUT
EST
SW
EBEL
DNK
SVN
LTU
FINLV
AIR
LLU
X
kto
nn
e C
O2eq
share of N20
share of Ch4
share of Co2
F igure 3 Shares of CO2 , CH 4 and N2O emiss ions (measured in CO2-equ iva lents o r
CO 2 e q) in total fug it ive GHG emiss ions in EU countr ies 1
Figure 4 shows the country shares in EU fugitive emissions (in CO2-equivalents). The graph
shows that Great Britain, Poland and Germany are the largest contributors (all together 47%
of EU emissions). Countries with the smallest shares in emissions are Latvia, Ireland and
Luxembourg (together 0.4%).
0,0%
2,0%
4,0%
6,0%
8,0%
10,0%
12,0%
14,0%
16,0%
18,0%
GBR
PO
LDEU
RO
MIT
ACZE
FRA
ESP
HUN
NLD
BGR
GR
CPRT
SVK
AUT
EST
SW
EBEL
DNK
SVN
LTU
FINLV
AIR
LLU
X
F igure 4 Country shares ( in %) in tota l EU fug i t ive emiss ions
1 Due to lack of National Inventory submissions (UNFCCC, 2008) for Malta and Cyprus,
these countries are not included in this report.
9
1.2 Method
1.2 .1 Reference case- f rozen technology re ference leve l
The emission reduction potential for 2030 is calculated using an emission reference level
based on frozen technology development. This frozen technology reference level is based on
change in physical activity assuming no improvement in reducing greenhouse gas emissions
from the activity (constant emission factors). The frozen technology reference level is
calculated in three steps:
1. Obtain 2005 activity levels per country.
2. Use oil, gas, coal primary production forecasts per country to project activity data
until 2030.
3. Multiply activities with 2005 intensities (emission factors) to get ‘frozen’ emissions
per country.
The 2005 base year activity levels (for instance: PJ of oil refined, m3 of gas consumed, Mt of
coal produced) are taken from the Common Reporting Format (CRF) tables that countries
have to submit to the UNFCCC (UNFCCC, 2008). These base year activity levels are
projected until 2030 using oil, gas and coal production forecasts from the PRIMES model
(PRIMES, 2008), see Figure 5 and Table 2. Primes production data is available on a country-
level. ‘Coal’ includes both coal and lignite. Multiplying the activity levels with 2005
emission factors, gives us forecasted ‘frozen’ emissions until 2030.
Any application of emission reduction measures after 2005 is therefore not taken into
account in the frozen technology reference level, but considered in the potential of the
emission reduction options.
Table 2 H isto r ic data and fo recasts o f coal p roduct ion in EU27 (PRIMES, 2008)
All emission data is presented in units of CO2-equivalents (CO2-eq). While all the data is
available for each country, all the data in this report will be presented at EU level.
Primary Production (Mtoe) 1990 1995 2000 2005 2010 2015 2020 2025 2030
Coal 366 278 214 196 165 152 142 134 126
Oil 128 169 169 127 105 77 53 44 41
Natural gas 162 189 208 188 168 129 115 98 85
0
50000
100000
150000
200000
250000
300000
350000
400000
1990 1995 2000 2005 2010 2015 2020 2025 2030
kto
e
Coal
Oil
Natural gas
F igure 5 Pro ject ions for o i l , gas, and coa l product ion, EU27 average (PRIMES,
2008)
Figure 5 shows that coal production in EU countries is forecasted to decline with 36%, from
196 Mtoe in 2005 to 126 Mtoe in 2030. Oil and gas production are also forecasted to decline
over time. Oil will decline with 68% from 127 Mtoe in 2005 to 41 Mtoe in 2030. Natural gas
production will decrease with 46% from 188 Mtoe in 2005 to 85 Mtoe in 2030.
Data is available on 2005 emissions of Latvia (UNFCCC, 2008), but activity data in the
fugutive emissions from fuels sector is missing. Therefore, emissions are assumed to stay
constant in the future. Also for countries where primary production (Primes, 2008) of one or
more sectors (e.g. coal, oil, gas) is zero (for instance: Luxembourg and Portugal have no
primary production at all), emissions of that particular sector are assumed to stay constant in
the future.
There is a small discrepancy between primary production in a country, and fugitive emissions
in a country. Therefore, is it not entirely correct to forecast fugitive emissions purely on the
basis of primary production forecasts. This would mean that when primary production of a
fossil fuel is forecasted to go down to zero, emissions are also forecasted to go down to zero.
In order to correct for this, we have assumed a maximum percentual reduction in emissions
of 80%, and 0% change afterwards. The reason for the small discrepancy is that even when
countries do not produce fossil fuels, they do need them. This means that there are emissions
associated with for instance refining, distribution, transport, etc.
It is also possible that the described situation occurs the other way around. For instance,
Primes reports that Finland had a primary coal production of 2 Mtoe in 2005, while the CRF
11
tables for Finland report no coal emissions in 2005. For countries where this played a role,
the same methodology was used as for other countries. This means that in the case of
Finland, the CRF data is used, meaning that no coal production and emissions are assumed in
2005 and therefore also in future years.
The resulting frozen technology reference scenario is presented in Figure 6.
0
20.000
40.000
60.000
80.000
100.000
120.000
2005 2010 2015 2020 2025 2030
kto
nn
e C
O2eq
B. Fugitive Emissions from Fuels
1. Solid Fuels
2. Oil and Natural Gas
F igure 6 Frozen technology reference scenario for so l id fuels (coa l and l igni te),
o i l , natural gas, and total fug it ive emiss ions from fue ls in the EU
Figure 6 shows that emissions from solid fuel production and oil and natural gas production
(including venting and flaring) are forecasted to decrease over time. Total emissions are thus
also expected to decline over time.
Figure 7 shows the breakdown of fugitive emissions from fuels in the EU. The largest share
of emissions in 2005 is caused by the natural gas sector (44%), followed by coal mining and
handling (35%). In the frozen technology reference scenario in 2030, the natural gas sector
will still be the largest contributor, but the absolute emissions will have decreased
considerably due to a forecasted decrease in primary production. Venting and flaring in the
oil and gas industry are included as separate items.
0
20.000
40.000
60.000
80.000
100.000
120.000
2005 2030
kto
nn
e C
O2
eq
Other oil and natural gas related emissions
Flaring
Venting
Natural gas
Oil
Other solid fuel-related emissions
Solid Fuel Transformation
Coal Mining and Handling
F igure 7 Contribut ion of subsec tor to total CO2-eq emiss ions in 2005 and 2030 fo r
tota l EU.
1.2 .2 Abatement measures and costs
In this study we identify the following measures to reduce GHG fugitive emissions in the
fuels sector: i) recovery of methane emissions from coal mining through degasification,
enhanced degasification or oxidation of ventilation air methane, and ii) the reduction of
methane emissions from chronic leaks, and reduction of emission from venting and flaring.
Emission reduction potentials of these measures are estimated with respect to the frozen
technology reference scenario, and are calculated for each country seperately. The emissions
to which the measures apply, differ per country, but the measures are the same (also the
reduction efficiencies). Since the baseline is a frozen technology reference level, emission
reduction options apply to 2030 frozen baseline emissions. For instance: 2030 frozen
baseline emissions for a certain subsector (e.g. venting) are multiplied by the share of CH4
(e.g. 80%), and then multiplied by the reduction efficiency and the implementation potential
of a measure. This results in an emission reduction potential. This potential is subtracted
from the 2030 frozen baseline emissions in order to get remaining CO2-eq emissions in 2030.
To calculate the low emissions scenario from 2010 to 2030, we assume a linear
implementation of the measure, from 2010 onwards.
Cost estimates are based on existing literature, mainly the EMF21 study (Weyant et al., 2004
and Hendriks & De Jager, 2001). Costs are presented in €/tCO2eq. As costs in Weyant et al.
(2004) are reported in 2000 $/tC-eq (metric tonne of carbon equivalent), we had to convert.
For conversion from $ 2000 to €, we used the following exchange rate: 1 US$2000 to 1.0516
€ (exchange rate on 3 July 2000 according to Yahoo Finance). For conversion from €/tC-eq
to €/tCO2-eq, we multiplied by 3.664 (44.009/12.011). The time scale of the EMF21 study is
2020. However, since the reduction potentials are quite ambitious, we have assumed that the
Comment [d1]: Maybe in the future, use more official source for currency exchange rates, such as BoE, ECB,etc.
13
costs (weighted with 2020 emission reduction potentials) also hold for 2030 (the lifetime of
all measures is 15 - 16 years) – we assume that a higher implementation potential corrects for
this. For all measures, an implementation potential of 80% was assumed (both correcting for
the fact that measures cannot be applied at all locations, and the fact that some measures may
already be in place at certain locations). For each measure, the weighted average of EU15
and Eastern Europe costs was taken.
Three different cost estimates are presented per measure: using a discount rate of 4%, 5% and
10% (and no taxes).
The costs of the measures depend highly on the local situation at the various sites (e.g.
differences between on- and offshore production), so they may strongly differ from
installation to installation. Furthermore, specific investments (in € per tonne of methane
mitigated) also depend on the throughputs of the installation: in installations with larger
throughputs the costs per tonne of methane avoided will generally be smaller (Hendriks & De
Jager, 2001). Besides, investments may be smaller for new installations (notably for offshore
production platforms) than for retrofit situations (Hendriks & De Jager, 2001). It should be
noted that the figures presented here are examples or mean values for a mix of installations.
Also, as many meausures are available and we group these measures, costs are merely highly
indicative.
2 Options to reduce CH4 emissions from the
solid fuels sector
2.1 Introduct ion
Worldwide, the coal mining industry liberated more than 377 million tonnes (Mt) of CO2-eq,
which accounted for 3.3% of total anthropogenic methane emissions in 2000. China, the US,
India, and Australia account for more than 56% of coal mining CH4 emissions (USEPA,
2006).
Total EU coal production amounted to 214 Mtoe (million tonne of oil equivalent) in 2000. In
2005 total production had declined to 196 Mtoe. The production of coal is estimated to
decrease to 126 Mtoe in 2030.
In 2005, production of solid fuels led to 39 Mt CO2-eq emissions in the EU (36% of fugitive
emissions from fuel emissions). Per country 2005 emissions due to solid fuels and oil and gas
are presented in Figure 8.
0
2.000
4.000
6.000
8.000
10.000
12.000
14.000
16.000
18.000
20.000
GBR
PO
LDEU
RO
M ITA
CZE
FRA
ESP
HUN
NLD
BG
RG
RC
PRT
SVK
AUT
EST
SW
EBEL
DNK
SVN
LTU
FINLV
AIR
LLU
X
kto
nn
e C
O2eq
2005 oil and gas
2005 solid fuels
F igure 8 Fug it ive emiss ions from fuel s in 2005 fo r EU countr ies. Emiss ions are
d iv ided into so l id fue ls and o i l and gas emiss ions.
Figure 8 shows that the division between emissions from solid fuels and liquid/gaseous fuels
differs per country. Countries that are the largest contributors to emissions from solid fuels
are: Poland, Germany and the Czech Republic. Countries that are the largest contributors to
emissions in the oil and gas sector are: Great Britain, Romania, and Italy.
15
With constant emissions factors, in 2030, Figure 9 shows that the shares of countries in
fugitive emissions will have changed (compare with 2005 in Figure 8). Countries that will be
the largest contributors to emissions from solid fuels will be different than in 2005: Poland,
Germany and Romania. The largest contributors to the oil and gas sector will change to:
Romania, Italy, and Germany.
0
2.000
4.000
6.000
8.000
10.000
12.000
14.000
16.000
18.000
GBR
POL
DEU
RO
MIT
ACZE
FRA
ESP
HUN
NLD
BGR
GRC
PRT
SVK
AUT
EST
SWE
BEL
DNK
SVN
LTU FINLV
AIR
LLU
X
kto
nn
e C
o2
eq
2030 oil and gas
2030 solid fuels
F igure 9 Fug it ive emiss ions from fuel s in 2030 fo r EU countr ies. Emiss ions are
d iv ided into so l id fue ls and o i l and gas emiss ions ( inc lud ing vent ing
and f lar ing).
2.1 .1 Emiss ion sources
USEPA (2006) describes the emission sources of methane in coal mining: Methane is
produced during the process of converting organic matter to coal. The CH4 is stored in
pockets within a coal seam until it is released during coal mining operations. The largest
source of emissions occurs during mining, but emissions also occur during the processing,
transport, and storage of coal, since coal continues to emit gas even after it has been mined,
although more slowly than during the coal breakage stage (IPCC, 2006).
The quantity of methane released depends on many factors, such as the gas content of the
coal, the permeability and porosity of the coal seams, the method of mining used, and the
production capacity of the mining operation (USEPA, 2006). The depth of a coal seam and
the type of coal determine the amount of CH4 present (or the gas content) in and around the
coal seams. Deep coal seams generally have large amounts of CH4 because of greater
overburden pressures. As a result, more than 90% of fugitive CH4 emissions from the coal
sector come from underground mining (USEPA, 2006).
After mining has ceased, abandoned coal mines may also continue to emit methane (IPCC, 2006).
2.2 Results
In this section, the abatement opportunities within the solid fuels sector are described, after
which the emission reduction potentials are presented and the associated costs.
2.2 .1 Abatement opportuni t ies
Three abatement opportunities that are currently available to the coal mining sector are:
1. Degasification (Measure 1501)
High-quality CH4 can be obtained from coal seams by drilling vertical wells up to 10 years in
advance of a mining operation, or by dilling horizontal boreholes up to 1 year before mining.
Most mine operators drain gas for 6 months or less. In some cases, high-quality CH4 can also
be obtained from gob wells (USEPA, 2006)
.
The gas recovered can be injected into a natural gas pipeline requiring virtually no
purification in the initial stages of production, but some treatment over time is needed to
upgrade the gas to pipeline quality. In the US, of the CH4 recovered from degasification, 57%
can be direcly used for pipeline injection. It is also possible to use the high-quality CH4 on-
site, for instance for heat or electricity production (Weyant et al., 2004).
2. Enhanced degasification (Measure 1502)
In enhanced degasification, CH4 is recovered in the same way as in degasification, using
vertical wells, horizontal boreholes, and gob wells. In addition, the mine invests in
enrichment technologies such as nitrogen removal units and dehydrators, primarily to
enhance medium-quality gob well gas. This option also assumes tighter well spacing to
increase recovery (USEPA, 2006).
The enrichment process and tighter spacing improve recovery efficiency 20% or more than
measure 001 (depending on whether pipeline injection or power production is assumed;
Weyant et al., 2004). It is assumed that 77% of the CH4 captured can be injected into the
natural gas pipeline system.
3. Oxidation of VAM (Measure 1503)
Ventilation Air Methane (VAM) has very low CH4 concentration (typically below 1%), and
therefore it is not economically feasible to sell this gas to a pipeline. However, VAM can be
oxidized to generate CO2 and heat, which in turn may be used direcly to heat water or to
generate electricity (USEPA, 2006).
17
If oxidizer technology were applied to all mine ventilation air with concentrations greater
than 0.15% CH4, approximately 98% of the CH4 from the ventilation air could be mitigated
(Weyant et al., 2004).
2.2 .2 Emiss ion reduct ion ca lcu lat ion
To calculate the emission reduction potential of the three different measures in the solid fuels
sector, assumptions per measure are taken. In this section we will describe the assumptions
taken.
• Degasification (Measure 1501)
It is assumed that the CH4 captured by degasification is either injected into nearby pipelines
and sold, or used on-site to fire a gas turbine. The reduction efficiency of this measure is 57%
for the former, and 30, 50 or 70% for the latter (depending on the type of gas turbine, Weyant
et al., 2004). We will assume the weighted average of these four measures as reduction
efficiency (weighted with the estimated emission reduction reported by Weyant et al., 2004):
this is 62%. The measure is assumed to apply to underground mines only (the emission share
of this source differs per country). Of emissions in underground mining, it is assumed that
80% is due to CH4 that can potentially be captured by degasification, and 20% due to CH4
that can be captured by oxidation of VAM (Measure 1503).
• Enhanced degasification (Measure 1502)
As this measure is an intensification of Measure 1501, it means that either Measure 1501 or
Measure 1502 can be applied. If both are applied, calculations correct for double-counting by
subtracting the effect of measure 1501 from the total effect of measure 1502. Compared to
Measure 1501, Enhanced Degasification has a higher reduction efficiency, namely 77%.
Other assumptions are the same as for Measure 1501, except that only pipeline injection is
considered for this measure (Weyant et al., 2004).
• Oxidation of VAM (Measure 1503)
Oxidation of VAM has a reduction efficiency of 98% (meaning that 98% of methane
emissions from this source can potentially be reduced applying this measure). This measure
only applies to ventilation air methane. Of emissions in underground mining, it is assumed
that 20% is coming from VAM.
2.2 .3 Cos ts
Cost estimates are based on the EMF 21 study (Weyant et al., 2004). This study distinguishes
eight different measures within the coal sector. Here we have reduced the amount of
measures to three. This means that cost estimates were calculated using weighted averages
(weighted with the estimated 2020 emission reduction potential of the EMF21 study).
Measure 1501 is an aggregation of the following EMF21 measures: degasification and
pipeline injection, degasification and power production A, B and C. Measure 1502 is the
same as the Enhanced degasification measure in EMF21. Measure 1503 is the same as
Catalytic Oxidation in EMF21, the one applicable to EU countries.
Since the application of measures is very much site-dependent and represents averages, cost
estimates should be seen as very approximate.
Table 3 Emiss ion reduction measures in the coa l sector, reduct ion e f f ic ienc ies and
costs. Costs in brackets are negat ive.
2.3 Conc lus ion and d iscuss ion
Total emission reduction potential for the solid fuels sector is 12.7 Mt CO2-eq. This is 50%
of the projected 2030 value (see Figure 10).
0
10.000
20.000
30.000
40.000
50.000
60.000
70.000
80.000
90.000
100.000
1990 1995 2000 2005 2010 2015 2020 2025 2030
kt
CO
2e
q
1. Solid Fuels - low demand
1. Solid Fuels - frozen
F igure 10 Emiss ion reduct ion potentia l o f measures in the so l id fuels sector.
Total costs of applying all three measures in the solid fuels sector: -€14.6 million in 2030 –
so applying these three measures would actually lead to cost savings. Average costs per
tonne of CO2-eq reduced would be -1.2 €/tCO2-eq.
Costs
Measure no. Measure name Reduction efficiency d=4% d=5% d=10%
Measure 1501 Degasification 62% €(1.8) €(1.5) €(0.2)
Measure 1502 Enhanced degasification 77% €(2.2) €(2.0) €(1.2)
Measure 1503 Catalytic Oxidation 98% €1.2 €1.4 €2.1
19
3 Options to reduce CH4 emissions from the
oil and natural gas sector
3.1 Introduct ion
Natural gas systems are a principal source of anthropogenic CH4 emissions, accounting for
more than 970 Mt CO2-eq worldwide in 2000, which is 8% of total global CH4 emissions.
Russia, the United States, Africa, and Mexico accounted for more than 43% of the world’s
CH4 emissions in the natural gas sector in 2000 (USEPA, 2006). Oil production contributes
significantly less to worldwide methane emissions, namely 57 Mt CO2-eq in 2000, which is
approximately 0.5% of total global methane emissions (USEPA, 2006). Combined, Mexico,
Eastern Europe, the United States, and China accounted for approximately 67% of the
world’s CH4 emissions from oil (USEPA, 2006).
In the EU, production of natural gas amounted to 208 Mtoe in 2000, which declined to 188
Mtoe in 2005. The production of natural gas is estimated to decline further to 85 Mtoe in
2030. Production of oil amounted to 169 Mtoe in 2000, which declined to 127 in 2005. The
production of oil is estimated to decline further to 41 Mtoe in 2030.
In 2005, oil and natural gas production including venting and flaring led to 67 Mt CO2-eq
emissions in the EU (64% of fugitive emissions from fuels). The share of emissions from oil
production in 2005 was 11%, the share of emissions of natural gas production 44%, and the
share of venting and flaring 9% of total fugitive emissions from fuels. Per country 2005
emissions due to oil and gas are presented in Figure 8.
Countries that are the largest contributors to emissions in the oil and gas sector in 2005 are:
Great Britain, Romania, and Italy. In 2030, the largest contributors will be Romania, Italy
and Germany.
3.1 .1 Emiss ion sources
IPCC (2006) and USEPA (2009a) describe the emission sources in the oil and gas system:
methane emissions occur throughout the oil and gas system; during exploration, in
production, through processing and tranmission, during transport and distribution. The
sources of fugitive emissions in oil and gas systems include amongst others: equipment leaks,
evaporation and flashing losses, venting, flaring, incineration and accidental releases (e.g.,
pipeline dig-ins, well blow-outs and spills). While some of these emission sources are
intentional (e.g., tank, seal and process vents and flare systems), and therefore relatively well
characterised, the quantity and composition of the emissions is generally subject to
significant uncertainty. This is due, in part, to the limited use of measurement systems in
these cases, and where measurement systems are used, the typical inability of these to cover
the wide range of flows and variations in composition that may occur.
3 .1 .1 .1 Vent ing and f l a r i ng
Defining venting and flaring correctly is important, as definitions differ from source to
source. Since this analyis makes use of the CRF tables (UNFCCC, 2008), it is very important
that we define venting and flaring according to IPCC (2006).
The IPCC (2006) definition of venting is as follows: “Venting comprises all engineered or
intentional discharges of waste gas streams and process by-products to the atmosphere,
including emergency discharges. These releases may occur on either a continuous or
intermittent basis, and may include the following:
• Use of pressurized natural gas instead of compressed air as the supply medium for
pneumatic devices (e.g., chemical injection pumps, starter motors on compressor engines
and instrument control loops).
• Pressure relief and disposal of off-specification product during process upsets.
• Purging and blowdown events related to maintenance and tie-in activities.
• Disposal of off-gas streams from oil and gas treatment units (e.g., still-column off-gas
from glycol dehydrators, emulsion treater overheads and stabilizer overheads).
• Gas releases from drilling, well-testing and pipeline pigging activities.
• Disposal of waste associated gas at oil production facilities and casing-head gas at heavy
oil wells where there is no gas conservation or re-injection.
• Solution gas emissions from storage tanks, evaporation losses from process sewers, API
separators, dissolved air flotation units, tailings ponds and storage tanks, and biogenic
gas formation from tailings ponds.
• Discharge of CO2 extracted from the produced natural gas or produced as a process
byproduct. “
The IPCC (2006) definition of flaring is as follows: “Flaring means broadly all burning of
waste natural gas and hydrocarbon liquids by flares or incinerators as a disposal option rather
than for the production of useful heat or energy.”
21
Whether waste gas is vented or flared depends largely on the amount of gas to be disposed of
and the specific circumstances (e.g., public, environmental and safety issues as well as local
regulatory requirements). Most of the time, venting only takes place if the waste gas is non-
odourous and non-toxic and even then, gases are sometimes flared. Flaring mostly occurs at
production, processing, upgrading and refining facilities (IPCC, 2006).
Disadvantages of flares:
• Flares have < 100% combustion efficiency resulting in un-combusted methane
emissions (Fernandez, 2008).
• Flames can be extinguished by weather, intermittent flow, or low heat-content gas
resulting methane venting.
• Flaring keeps saleable methane from reaching markets worldwide.
3 .1 .1 .2 Oi l
CH4 emissions in the oil system are associated with equipment leaks, storage losses, pipeline
breaks, well blowouts, land farms, gas migration to the surface around the outside of
wellhead casing, surface casing vent bows, biogenic gas formation from tailings ponds and
any other gas or vapour releases not specifically accounted for as venting or flaring. Figure
11 shows a breakdown of emissions from the oil system into ‘exploration’ (oil well drilling,
drill stem testing, and well completions), ‘production’ (from the oil wellhead or the oil sands
or shale oil mine through to the start of the oil transmission system), ‘transport’ (transport of
marketable crude oil to upgraders and refineries), ‘refining/storage’ (at petroleum refineries),
‘distribution of oil products’ (transport and distribution of refined products), and ‘other’.
Assuming that reporting of emissions by member countries is done correctly in the CRF,
emissions from venting and flaring are excluded.
0%
20%
40%
60%
80%
100%
GBR
POL
DEU
RO
MIT
ACZE
FRA
ESP
HUN
NLD
BGR
GRC
PRT
SVK
AUT
EST
SWE
BEL
DNK
SVN
LTUFIN
LVAIR
LLU
X
oil
em
iss
ion
s
exploration production transport refining/storage distribution of products other
F igure 11 Breakdown o f emiss ion from the o i l system in 2005, exc luding vent ing
and f lar ing
According to Figure 11, the largest share of methane emission in the oil sector in the EU
appears to be due to refining and storage. Looking at it in absolute terms, the greatest
contributions come from production and refining/storage (Figure 12), together accounting for
97% of emissions from the oil system.
Oil system breakdown total EU
23%
2%
74%
0%1%
0%
exploration
production
transport
refining/storage
distribution of products
other
F igure 12 Breakdown o f o i l system emiss ions in 2005 in absolute terms.
Refineries process crude oils, natural gas liquids and synthetic crude oils to produce final
refined products (e.g., primarily fuels and lubricants) (IPCC, 2006). There are two main
sources of fugitive emissions from refineries: process and fugitive emissions. Process
emissions result from the production of hydrogen as well as from process vents (The Green
Lane, 2009). Fugitive emissions are a result of equipment leaks, wastewater treatment,
cooling towers, storage tanks, and loading operations (The Green Lane, 2009).
Fugitive emissions from oil production (excluding venting and flaring) occur at the oil
wellhead or at the oil sands or shale oil mine through to the start of the oil transmission
system (IPCC, 2006). This includes fugitive emissions related to well servicing, oil sands or
shale oil mining, transport of untreated production (i.e , well effluent, emulsion, oil shale and
oilsands) to treating or extraction facilities, activities at extraction and upgrading facilities,
associated gas re-injection systems and produced water disposal systems (IPCC, 2006).
23
3 .1 .1 .3 Natu ra l gas
Fugitive emissions at natural gas facilities originate from equipment leaks, storage losses,
pipeline breaks, well blowouts, gas migration to the surface around the outside of wellhead
casing, surface casing vent bows and any other gas or vapour releases not specifically
accounted for as venting or flaring. Methane emissions occur from normal operations in four
segments of the natural gas industry: ‘exploration’ (from gas well drilling, drill stem testing
and well completions), ‘production/processing’ (from the gas wellhead through the tie-in
points on gas transmission systems), ‘transmission’ (from systems used to transport
processed natural gas to industrial consumers and natural gas distribution systems, and
natural gas storage), and ‘distribution’ (from the distribution of natural gas to end users), see
Figure 13.
0%
20%
40%
60%
80%
100%
GBR
POL
DEU
RO
MIT
ACZE
FRA
ESP
HUN
NLD
BGR
GRC
PRT
SVK
AUT
EST
SWE
BEL
DNK
SVN
LTU
FINLVA
IRL
LUX
na
tura
l g
as
em
iss
ion
s
exploration production/processing transmission distribution other leakage
F igure 13 Breakdown of emiss ions from the natura l gas system in 2005, exc lud ing
vent ing and f lar ing
Figure 13 shows that in relative terms, distribution, transmission and production/processing
appear to play the largest role in emissions from the natural gas system. Looking at it in
absolute terms (see Figure 14) we see the same: distribution, transmission, and
production/processing are the largest contributors (together account for 89% of EU
emissions).
Natural gas system breakdown total EU
1%
17%
23%
49%
10%
exploration
production/processing
transmission
distribution
other leakage
F igure 14 Breakdown o f natura l gas system emissions in 2005 in absolute terms.
Equipment/pipeline chronic leaks are the primary sources of CH4 emissions in the natural gas
sector (UNFCCC, 2008) and account for about 86% of emissions from this system. From
wellhead to end user, the gas moves through hundreds of valves, processing mechanisms,
compressors, pipes, pressure-regulating stations and other equipment. Whenever the gas
moves through valves and joints under high pressure, methane can escape to the atmosphere.
25
3.2 Resu lts
3.2 .1 Abatement oppor tuni t ies
Abatement opportunities in the oil and gas sector are divided into those measures that apply
to venting and flaring, and those that apply to emissions due to ‘leakages’.
3 .2 .1 .1 Vent ing and f la r i ng
Many measures are applicable to emissions from venting and flaring. As the contribution of
venting and flaring emissions in the EU is rather small (13% of emission in the oil and
natural gas sector, 8% of fugitive emissions from fuels), and the technical and economic
feasibility of these measures very much depends on the conditions at location (OGP, 2000),
we will restrict ourselves to two measures to reduce emissions from venting and flaring. For
a more elaborate account of emission abatement options for venting and flaring, see Hendriks
& De Jager (2001) or USEPA (2008).
Venting
Only 2% of EU 2005 fugitive emissions from fuels can be attributed to venting. This low
contribution of venting is mainly due to environmental legislation. There are many sources of
vented methane (see 3.1.1.1), and therefore also many reduction opportunities. Some
examples:
• Using hydraulically powered valve actuators and pneumatic devices instead of powered
with natural gas
• Recompression of gas during maintenance, or using surge vessels that avoid venting
methane
• Dry seals on centrifugal compressors
• Reduced flushing of engines at start-up and shut-down
• Installation of electric starters on compressors
Bottom line is that the best option from an environmental point of view is to prevent venting
methane, the second best is to recover the methane and either use it or store it for future use
(e.g. sell it, or use it for enhanced oil recovery or energy generation), and the third best
option is to flare the methane (best is to sequester the CO2 produced). When off-gases are
flared instead of vented, methane emissions are reduced by about 95 to 99.8%, depending on
the flare efficiency. Which option is the best and the cheapest, depends on the location. The
actual implementation potential of the options are limited by technical, environmental and
safety constraints (Hendriks & De Jager, 2001).
Flaring
Similar to venting, the best option from an environmental point of view is to recover the
methane that would otherwise be flared and either use it or store it for future use, and the
second best option is to flare it using a very efficient flare and sequester the CO2 produced.
There are several different options for utilising otherwise flared natural gas, including
collection and re-injection of the gas in a storage facility (e.g. for reservoir pressure
maintenance and enhanced oil recovery), utilising it in micro-turbines (Smith, 2008), using it
in small-scale liquefaction (Jakobsen, 2008), or (conversion to another product and)
collection for consumption in domestic and/or international markets (e.g. Richards, 2008),
see Figure 15. Many of these emerging small-scale technologies are still under development.
Recover and subsequent storage or re-injection of the gas is the most attractive alternative
from an environmental perspective, as there are relatively low emissions associated with
these processes. Second option is to flare the methane and sequester the CO2 produced.
Norway has pioneered efforts to explore the potential for re-injection of CO2 in the Sleipner
West field in the North Sea. Annually, in Norway, approximately 1 million tonnes of CO2 are
separated from natural gas production and re-injected into an aquifer, as opposed to being
released into the atmosphere. In addition to sequestration in aquifers, as is the case in
Norway, the otherwise flared gas also may be stored in oil wells, salt caverns or re-injected
further downstream into the system (IEA, 2003).
F igure 15 Gas ut i l izat ion and monetizat ion routes (Seguineau, 2008)
27
3 .2 .1 .2 Oi l and na tu r a l ga s
Abatement opportunities in the oil and natural gas systems (excluding venting and flaring)
are focused on the largest emissions source, namely chronic leaks (see 3.1.1.3). These
emissions constitute on average 86% of total emissions in the oil and natural gas sector. The
abatement option is:
• Chronic leaks (e.g. pipelines, distribution facilities, etc.)
A directed inspection and maintenance option involves surveying pipelines, ships,
distribution facilities, compressor stations, etc. to identify sources of leaks and performing
maintenance on leaks that are most cost-effective to repair. This can be done by increasing
the frequency of inspections and/or by directly measuring gas concentrations along the
network or by monitoring system pressures in possible risk areas (Hendriks & De Jager,
2001). Modern equipment includes infrared methane emissions imaging (Robinson, 2008;
Snider, 2008).
In exploitation and transport larger leakages are easily detected, since they will cause the
formation of ice on the flanges outer surface. This ice is a result of a drop in temperature, due
to the expansion of the gas from about 80 bar to atmospheric pressure. Smaller chronic leaks
are hard to address, since they may occur throughout the system. Leaking emissions during
distribution are much harder to assess. In some cases emissions they can be estimated from
differences between input and output of the system. But due to measures inaccuracies, this
method is rather unreliable (Hendriks & De Jager, 2001).
3.2 .2 Emiss ion reduct ion ca lcu lat ion
To calculate the emission reduction potential of the measure in the oil and natural gas sector,
some assumptions are necessary. Here we will describe the assumptions taken. As many
small- and medium-scale measures are technically available and the applicability and
associated costs of these measures are to a high degree location-dependent, emission
reduction calculations need to be taken as highly indicative.
• Reducing methane emissions from venting (Measure 1601)
Mitigation options for venting depend on the exact conditions at a certain location, as do the
costs. Therefore, we opted for a generic measure. It is assumed that the reduction efficiency
is a weighted average of the following measures from the EMF21 study (Weyant et al.,
2004): Altering start-up procedures of compressors during maintenance, installation of flash
tank separators, portable evacuation compressor for pipeline venting, reducing the glycol
circulation rates in dehydrators, replace high-bleed pneumatic devices with low-bleed or
compressed air, dry seals on centrifugal compressors, fuel gas retrofit for blowdown valve,
installation of flash tank separators, static-pacs on reciprocating compressors, flaring instead
of venting, and using associated gas for other purposes (e.g. consumption on platform,
conversion to LPG). The latter two are oil sector measures, the rest are gas sector measures.
This results in a weighted average reduction efficiency of 81%.
• Reducing emissions from flaring (Measure 1602)
Also for flaring, (the costs of) mitigation options depend on the exact conditions at a certain
location. We will assume that (mainly CO2) emissions from flaring can be reduced by 95% at
a location (Weyant et al., 2004).
• Reducing methane emissions from chronic leaks (Measure 1603, 1604)
Emissions from chronic leaks constitute on average 86% of emissions from the oil and
natural gas system in the EU, but this is different for each country. Measures reducing these
emissions can thus contribute significantly to emission reduction in the fugitive emissions
sector. Here, we separately target leaks in the oil sector, and leaks in the gas sector.
Reduction efficiency is calculated using a weighted average of all Inspection and
maintenance (I&M) options from the EMF21 study (Weyant et al., 2004), and Electronic
monitoring at large surface facilities. This results in a reduction efficiency of 66%.
3.2 .3 Cos ts
Cost estimates are based on the EMF 21 study (Weyant et al., 2004). This study distinguishes
35 different measures within the natural gas sector, and four different measures within the oil
sector. Here we have reduced the total amount of measures for the oil and gas industry
(including venting and flaring) to four; one measure on venting, one measure on flaring, one
measure reducing chronic leaks in the oil sector, and one measure reducing chronic leaks in
the gas sector. This means that cost estimates were calculated using weighted averages
(weighted with the estimated emission reduction potential of the EMF21 study). Several
measures from the EMF21 study were excluded from the weighted average. Using gas
turbines instead of reciprocating engines, and Catalytic convertors both reduce emissions that
fall under the energy sector according to IPCC definitions. Measures that were excluded
because they were too expensive (>800 €/tCO2): Installation of electric starters on
compressors, installing plunger lift systems in gas wells, surge vessels for station/well
venting, replacement of cast iron/unprotected steel pipelines, and replacement of unprotected
steel services.
Weighted average costs per measures are presented in Table 4.
29
Table 4 measures in the o i l and natura l gas sector ( includ ing vent ing and
f lar ing), reduct ion e f f ic ienc ies and costs. Cos ts are presented for three
d i f fe rent discount rates: 4%, 5%, and 10%.
Costs
Measure no. Measure name Reduction efficiency d=4% d=5% d=10%
Measure 1601 Reducing methane emissions from venting
81% €10.8 €11.4 €14.3
Measure 1602 Reducing emissions from flaring
95% €2.8 €3.3 €5.7
Measure 1603 + 1604
Reducing methane emissions from chronic leaks
66% €2.1 €2.2 €3.0
3.3 Conc lus ion and d iscuss ion
Total emission reduction potential for the oil and natural gas sector is 20.7 Mt CO2-eq. This
is 49% of the projected 2030 value (see Figure 10).
0
10.000
20.000
30.000
40.000
50.000
60.000
70.000
80.000
90.000
100.000
1990 1995 2000 2005 2010 2015 2020 2025 2030
kt
CO
2e
q
2. Oil and Natural Gas - low demand
2. Oil and Natural Gas - frozen
F igure 16 Emiss ion reduct ion potentia l o f measures in the o i l and natural gas
sector.
Total costs of applying all measures in the oil and natural gas sector: €48.3 million in 2030.
Average costs per tonne of CO2-eq reduced would be 2.3 €/tCO2-eq.
4 Conclusions
In this section we present the summarised data on the overall EU reduction potentials and
cost of the abatement options and we shortly discuss the results.
Figure 17 shows 2005 emissions, projected 2030 emissions in the frozen technology
reference level (the middle bar), and remaining emissions in 2030 after application of
emission abatement options in the shown subsectors of the fugitive emissions from fuels
sector. The figure shows that the largest remaining emissions sources in 2030 when all
abatement options are pursued will be: ‘natural gas’ (47% of total emissions in 2030) and
‘coal mining and handling’ (34% of total emissions in 2030). The ‘oil’ subsector will
contribute 12% in 2030. Venting and flaring emissions can be reduced to 2% of total 2030
emissions.
0
20.000
40.000
60.000
80.000
100.000
120.000
2005 2030 Remaining emissions 2030
kt
CO
2e
q
Other oil and natural gas related emissions
Flaring
Venting
Natural gas
Oil
Other solid-fuel related emissions
Solid fuel transformation
Coal mining and handling
F igure 17 Breakdown o f fug i t ive emissions f rom fue ls emiss ions in 2005, 2030
f rozen techno logy re ference leve l, and remaining emiss ions in 2030
after emiss ion abatement.
31
Table 5 and Figure 18 specify the abatement potentials of the individual measures. The
abatement options with the largest emission reduction potential are the reduction of chronic
leaks in natural gas transport (18.1 Mt CO2-eq reduction potential) and degasification of
methane from coal mining (6.5 Mt CO2-eq reduction potential), together accounting for 75%
of the overall abatement potential.
Table 5 Opt ions to abate fug i t ive emiss ions in the fuels sector: abatement
potent ia l and spec i f ic costs in 2020 and 2030. Abatement potent ia l is
re lat ive to the Frozen Techno logy Reference Leve l.
Sector Name abatement potential (kt-CO2-eq)
Specific costs (€/t-CO2)
2020
Coal mining Enhanced Degasification 1,558 -2.2
Coal mining Degasification 3,241 -1.8
Coal mining Oxidation of Ventilation Air Methane 1,527 1.2
Oil and natural gas
Chronic leaks (pipelines, distribution facilities, other) natural gas
9,045 2.1
Oil and natural gas
Chronic leaks (pipelines, distribution facilities, other) oil 187 2.1
Oil and natural gas
Reducing flaring emissions 868 2.8
Oil and natural gas
Elimination of venting 230 10.8
Total 16,656
2030
Coal mining Enhanced Degasification 3,117 -2.2
Coal mining Degasification 6,483 -1.8
Coal mining Oxidation of Ventilation Air Methane 3,054 1.2
Oil and natural gas
Chronic leaks (pipelines, distribution facilities, other) oil 373 2.1
Oil and natural gas
Chronic leaks (pipelines, distribution facilities, other) natural gas
18,091 2.1
Oil and natural gas
Reducing flaring emissions 1,736 2.8
Oil and natural gas
Elimination of venting 460 10.8
Total 33,314
0
40.000
80.000
120.000
160.000
200.000
1990 1995 2000 2005 2010 2015 2020 2025 2030
kt
CO
2e
q
Frozen Technology
Historic emissions
Low emissions scenario
M1501
M1502
M1503
M1601
M1602
M1603
M1604
F igure 18 Emiss ion reduct ion potent ia l fo r fug i t ive emiss ions from fue ls,
breakdown per measure is shown, as wel l as the f rozen technology
re ference level.
Taking costs into account, a marginal abatement cost curve (MACC) can be drawn which
shows the emission reduction on the x-axis, and associated costs on the y-axis (see Figure
19). Important message that can be drawn from the curve is the amount of Mt CO2-eq that
can be reduced against negative cost. Approximately 10 Mt of CO2-eq emissions in the
European Union can be reduced against negative costs in the fugitive emissions from fuels
sector. An extra 20 Mt of CO2-eq emissions can be reduced at low costs (below 3 € per tonne
of CO2-eq). The last 3 Mt of emission reduction will cost between 3 and 11 € per tonne of
CO2-eq.
33
-4
-2
0
2
4
6
8
10
12
0 5 10 15 20 25 30 35
Mt CO2eq
€ / t CO2eq
F igure 19 Abatement potent ia l and spec if ic costs of opt ions to abate fug i t ive
emiss ions in the fue ls sector in the EU27 in 2030. The abatement
potent ia l i s re lat ive to the frozen techno logy reference scenar io.
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