Fugitive emissions report -website

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P.O. Box 8408

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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

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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

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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




Oil and natural gas


Oil and natural gas


18,091 2.1

Oil and natural gas

Reducing flaring emissions 1,736 2.8

Oil and natural gas


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%

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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%

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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

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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

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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

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2005 2030

kto

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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.

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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.

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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

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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




Oil and natural gas


9,045 2.1

Oil and natural gas


Oil and natural gas

Reducing flaring emissions 868 2.8

Oil and natural gas


Total 16,656

2030




Oil and natural gas


Oil and natural gas


18,091 2.1

Oil and natural gas

Reducing flaring emissions 1,736 2.8

Oil and natural gas


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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35

Seguineau, J.-M. (2008) About Gas Valorisation Routes. Presentation on Global Forum on

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Fugitive emissions report -website

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