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Life Cycle Assessment of the
European Natural Gas Chain
focused on three
environmental impact
indicators
FINAL REPORT
Authors: Marion Papadopoulo (GDF SUEZ)
Salam Kaddouh (GDF SUEZ)
Paola Pacitto (GDF SUEZ)
Anne Prieur Vernat (GDF SUEZ) With the support of Marcogaz Working Group on LCA: Alessandro Cigni (Marcogaz), François
Dupin (DVGW), Dirk Gullentops (Synergrid), Stefania Serina (Snam Rete Gas), Tjerk Veenstra
(Gasunie), Juergen Vorgang (E.ON Ruhrgas)
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INTRODUCTORY NOTE
The Health, Safety and Environment (HSE) Joint Group of Eurogas, the European union of the
natural gas industry, and Marcogaz, technical association of the European natural gas industry, has
set up in 2004 a Working Group on Life Cycle Assessment (LCA). This Working Group was in charge
of assessing the environmental performances of natural gas by establishing the life cycle
assessment of the natural gas distributed in Europe as well as three natural gas applications,
addressing electricity generation, heat production and combined heat and power production.
All the information used as well as the assumptions made to perform the LCA are gathered in this
document. This LCA report is a working document and shall not be released as such.
A peer review of the LCA study has been realized in 2010 to check and ensure the consistency of
Eurogas–Marcogaz study with the ISO standards 14040 and 14044. The conclusion of the final
critical review note is presented in appendix. In parallel of the reviewing process, Marcogaz
Working Group on LCA and Eurogas–Marcogaz HSE Joint Group will start the discussions about the
format, layout and content for the publication of the LCA results.
Note: data collection being a time-consuming process, several years were necessary to complete
Eurogas–Marcogaz study. Marcogaz Working Group on LCA therefore decided to keep the year
2004 as the reference year for the first version of the LCA study. As a result this report is a picture
of the gas industry and technologies at this time. In particular, the geographic borders are those of
EU-25 and company names have not been changed following mergers that have taken place since
2004.
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ABSTRACT
Life cycle thinking – an industry concern
In a context of development of life cycle oriented
regulations and the launching of the "International
Reference Life Cycle Data System" (ILCD) project
supporting business and policy making in Europe
and abroad with reference data and recommended
methods on LCA, the Eurogas–Marcogaz Joint
Group on Health, Safety & Environment has set up
a working group on LCA. Its task was to determine
the environmental footprint of the whole natural
gas chain, utilization included, by establishing the
LCA of the European natural gas chain focused on
three environmental impact indicators.
A restrained scope for more relevance
The Eurogas–Marcogaz study, which started in
2004, covers all the steps of the natural gas chain,
from production to utilization. It includes transport
by pipelines and tankers, liquefaction, gasification
and distribution of natural gas. Infrastructures
(buildings and plants) have been excluded. The
natural gas applications addressed are the
following:
→ Electricity production with a natural gas
combined cycle;
→ Heating with condensing boilers
(domestic/industrial use);
→ Combined heat and power production
(domestic/services & buildings).
Only the main environmental impacts of the
systems studied, for which Marcogaz can provide a
real added value, have been studied:
→ Climate change: alteration of the Earth’s
climate due to change in greenhouse gases
concentration (CO2, CH4, etc.);
→ Acidification: increase in rain acidity due to the
release of acidic man-made emissions such as
SO2;
→ Non renewable energy demand: depletion of
non renewable energy sources (gas, oil, coal,
and uranium).
An update of the environmental impact of
natural gas
The results of Eurogas–Marcogaz LCA give an
update of the environmental impact of natural gas
used as a fuel in the European context. One kWh of
useful heat produced from natural gas with a
condensing boiler generates about 230 g eq. CO2
on its whole life cycle; the kWh of electricity
produced with a natural gas combined cycle emits
393 g eq. CO2.
Summary of Eurogas–Marcogaz LCA results
(reference year 2004)
The utilization phase is predominant in terms of
greenhouse gas emissions (more than 85% of the
GHG emissions), whereas the acidifying emissions
are shared among the combustion step (37 to 42%
Need for a critical review
A critical review is a process intended to
ensure consistency between a life cycle
assessment and the principles and
requirements of the International Standards on
life cycle assessment: ISO 14040 and 14044.
It enables to enhance the credibility of the
study by involving objective external experts
and is recommended by the ISO standards.
A peer review of the Eurogas-Marcogaz LCA
results was subcontracted in 2010.
For 1 kWh
Climate change
(g eq. CO2)
Acidification
(mg eq. SO2)
Non renewable
energy
depletion (kWh)
Heat at boiler - Domestic use 238 96 1.12
Heat at boiler - Industrial use 225 87 1.09
Heat at CHP - Domestic use 245 126 1.15
Heat at CHP - Services and
tertiary buildings 232 140 1.07
Electricity at CHP - Domestic
use 245 126 1.15
Electricity at CHP - Services
and tertiary buildings 232 140 1.07
Electricity at combined cycle
plant 393 180 1.90
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of the emissions), the utilization of electricty for
auxiliaries (e.g. thermostat) (up to 22% of the
acidifying emissions) and the upstream chain (52
to 63% of the emissions).
Contribution of the different natural gas chain
steps to global warming and acidification
The results in term of acidification show the
importance of distinguishing the environmental
burden associated with the natural gas itself and
the auxiliary systems (e.g. electricity used in the
auxiliaries of the natural gas conversion systems).
Finally the moderate differences that can be
noticed between supply chains1 are mostly due to
the difference of transmission distance, and to the
performances of transmission systems to a smaller
extent.
Four main priorities to improve the natural
gas chain environmental performances
The natural gas performances could be further
improved by:
→ Developing high efficiency gas conversions
systems as the utilization phase plays a key
role in the overall performances of the natural
gas systems.
→ Improving the efficiency of liquefaction units,
the liquefaction step being the main burden of
LNG chains.
1 Transport by pipeline from not far away countries
(Western Europe producing countries), transport by
pipeline from further away countries (mainly
Russia) or LNG chains from Africa and Middle-East.
→ Improving compressor efficiencies for long
distance transmission.
→ Reducing gas flaring during production on
associated fields.
A need to provide reliable data that could be
used in European regulations
Eurogas–Marcogaz LCA results support the figures
used in existing generic LCA databases for global
warming and non-renewable energy depletion.
However, important differences with existing
generic LCA databases have been noticed,
particularly for CH4 and SOX emissions, which can
be overestimated in some databases. The
differences observed highlight the importance not
to base environmental decisions on generic
databases without first assessing their relevance
and applicability.
A study to be updated and supplemented
The political, technological and economic context is
evolving fast. Since the launching of the Working
Group in 2004, the supplies and technologies have
evolved, the political borders of Europe have been
extended to 27 countries and several mergers have
taken place in the gas industry. That is the reason
why an update of this LCA should be undertaken.
Moreover the current scope of the study
guarantees the quality of the results for the three
impact categories considered but also limits the
use of Eurogas–Marcogaz data set. As the
regulations tend to consider more than the three
impacts mentionned before, other essential
substances will have to be included in the valuation
in the future to allow a more comprehensive
assessment of the environmental performance of
natural gas systems.
0%
20%
40%
60%
80%
100%
Heating - Domestic use
Electricity production at
NGCC
Heating - Domestic use
Electricity production at
NGCC
Global warming Acidification
30% 28%
20% 19%
85% 88%
37% 42%
Production Pipeline transmission Liquefaction
Export by LNG tanker Gasification in EU Storage in EU
HP transmission in EU LP distribution in EU Utilization
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TABLE OF CONTENTS
1 GOAL AND SCOPE DEFINITION .............................................................. 11
1.1 Goal definition ................................................................................................. 13
1.2 Scope of the study ........................................................................................... 14
2 DESCRIPTION OF THE NATURAL GAS CHAIN - IDENTIFICATION OF
POTENTIAL EMISSION SOURCES ................................................................. 25
2.1 Exploration ..................................................................................................... 27
2.2 Offshore / Onshore production .......................................................................... 28
2.3 Natural gas processing ..................................................................................... 31
2.4 Natural gas pipeline transmission ....................................................................... 37
2.5 LNG chain ....................................................................................................... 41
2.6 Storage .......................................................................................................... 47
2.7 Distribution ..................................................................................................... 49
2.8 Utilizations ...................................................................................................... 51
3 METHODOLOGY, MAIN ASSUMPTIONS .................................................... 57
3.1 Methodology used for estimating consumptions and emissions along the chain ........ 59
3.2 Modelling of the gas chain ................................................................................. 60
4 NATURAL GAS MARKET IN EUROPE ........................................................ 63
4.1 Biggest European producers .............................................................................. 65
4.2 Biggest European consumers ............................................................................ 66
4.3 Main trade movements in Europe ....................................................................... 67
5 INVENTORY ........................................................................................... 73
5.1 Production and processing ................................................................................ 75
5.2 Transmission by pipeline ................................................................................... 98
5.3 Liquefaction ................................................................................................... 106
5.4 Transportation of LNG ..................................................................................... 108
5.5 Gasification .................................................................................................... 112
5.6 Regional high pressure transmission ................................................................. 114
5.7 Storage ......................................................................................................... 117
5.8 Low pressure distribution ................................................................................. 118
5.9 Utilization ...................................................................................................... 119
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6 LCA RESULTS OF THE EUROPEAN NATURAL GAS CHAIN ........................ 125
6.1 Results of the upstream chain .......................................................................... 127
6.2 Results after utilization .................................................................................... 136
7 SENSITIVITY ANALYSES ...................................................................... 142
7.1 Identification of the sensitive parameters .......................................................... 143
7.2 Results of the sensitivity analyses ..................................................................... 145
8 CONCLUSIONS ..................................................................................... 151
REFERENCES ............................................................................................. 155
ABBREVIATIONS ....................................................................................... 159
APPENDICES ............................................................................................. 161
APPENDIX 1: composition and characteristics of the natural gas ...................................... 163
APPENDIX 2: Emission factors .................................................................................... 165
APPENDIX 3: Type of compressors used during transmission .......................................... 169
APPENDIX 4: National Electricity mix considered during transmission............................... 171
APPENDIX 5: Transmission distances – Details .............................................................. 172
APPENDIX 6: INVENTARY – Summary .......................................................................... 175
APPENDIX 7: Inventory results of no characterized flow ................................................. 181
APPENDIX 9: Synthesis of the peer review ................................................................... 187
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1 GOAL AND SCOPE DEFINITION
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1.1 Goal definition This study presents the life cycle assessment of natural gas supplied in the EU-25 in 2004, from
production to utilization. Three different natural gas utilizations have been addressed:
→ electricity generation with a natural gas combined cycle (NGCC) power plant (800 MWe);
→ heat production using a condensing modulating boiler (10 kWth for domestic use and
>100 kWth for industrial use);
→ combined heat and power generation from small natural gas combined heat and power
units (Stirling micro CHP 1 kWe for domestic use and gas motors CHP for services &
buildings).
This study is focused on three environmental impact indicators. Thus, only emissions for
which there is a real added value are followed.
The LCA results are given for an average place in the EU-25 in 2004 and do not give details
country by country for confidentiality reasons. Intermediate results regarding high and low
pressure natural gas are also provided and analysed in details.
The aim of the LCA study is to give figures validated by the gas industry concerning the
environmental performances of the natural gas chain in order to improve the knowledge of the
natural gas chain, identify the main contributors and define improvement solutions. Therefore the
results of Eurogas–Marcogaz study may be used by LCA practitioners to model the gas
chain in the EU-25. Thus, it will be tried to collaborate with other databases like ELCD
and ecoinvent. However, as this study has a specific scope, the collaboration will be only
realized on accurate data. This study could also be a basis for a scientific communication,
either done in an oral form at a congress or workshop, or in the form of a scientific
article in an appropriate journal.
Since LCA is a standardised tool, this study aims to adhere to the ISO standards designed
for LCA: ISO 14040 [1] and 14044 [2]. The most important consequence of adhering to an ISO
standard is the need for careful documentation. A second consequence of adhering to the
standards is the need to include a peer review by independent experts, as described in ISO
14040 [1] and ISO 14044 [2]. A peer review has been realized in 2010. The main conclusion are
presented in appendix.
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1.2 Scope of the study
1.2.1 Functional unit
The database is divided into seven “boxes” or “steps” that can be assembled or disassembled
easily. As a result each box has its own functional unit. The functional unit of each sub-
system is described along with the sub-system in a following paragraph.
The final functional unit is either “to deliver 1 kWh of electricity with the best available
technologies” (combined cycle or CHP) or “to deliver 1 kWh of useful heat with the best
available technologies” (condensing boiler or CHP).
An intermediate functional unit is used to describe the upstream natural gas chain. It is “to
deliver 1 MJ of natural gas to consumer in the EU-25 in 2004”. This intermediate functional
unit will also be presented in kWh which is another energy unit used for natural gas (for
example in the customer’s bill). Two different cases are distinguished:
→ Low pressure natural gas at consumer in Europe;
→ High-pressure natural gas at consumer in Europe.
1.2.2 System boundaries
→ Exploration
This LCA does not integrate data from exploration.
Indeed, exploration is made by petroleum companies and for both oil and gas. It is very hard to
allocate the impacts of an exploration campaign, when neither oil nor gas is found. Even if that is
possible, data concerning the impacts (energy consumption, emissions to environment) of the
exploration stage are not known by gas companies, but only by petroleum companies.
→ Building and decommissioning of gas equipments
A study on transmission sub-systems made by Snam Rete Gas and Gaz de France in 1998 shows
that building and pipe decommissioning are negligible or at least very low compared to the activity
of transmission: it represents between 0.5 and 5% of the total emissions or consumptions for each
step of the system. For that reason, the study does not take into account natural gas
infrastructures. It should be noticed that, according to a recent study [3], the share of capital
equipment and infrastructures on the total acidification impact related to the natural gas supplied
to the user, could be more significant (between 5 and 10%) than considered here. Indeed as the
natural gas combustion has a relatively lower contribution to acidification than to the other followed
impacts, the contribution of steel production (main contributor of infrastructures) to acidification
would be proportionally higher than to the other impacts if taken into account. But if the
contribution is less than 10%, this study considers that the infrastructure share is minor and thus
negligible.
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→ Buildings and vehicles
The study does not take into account data relative to buildings and vehicles. For example, Gaz de
France calculated greenhouse gas emissions from buildings and vehicles in 2005: they represented
less than 2% of the total greenhouse gas emissions of the company that same year [4].
For that reason, we do not collect data on that part of activity.
→ Incidents
Usual incident such as small gas leakages (leakages during distribution step for example) are taken
into account in this LCA.
Usually, large incidents are not taken into account in LCA. But, for natural gas companies,
methane leakages from incidents are counted as a part of total leakages: it can be an
important part of the impact of the gas chain. So it was decided to include incidents in this LCA.
1.2.3 Geographic borders
The geographic borders of the study are those of the EU-25. The following map shows the
countries of interest.
Figure 1: EU-25 Borders - Geographic frontiers of the study
The following countries are included: Belgium, France, Germany, Italy, Luxembourg, the
Netherlands, Denmark, Ireland, United Kingdom, Greece, Spain, Portugal, Austria, Finland,
Sweden, Cyprus, Czech Republic, Estonia, Hungary, Latvia, Lithuania, Malta, Poland, Slovakia and
Slovenia.
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1.2.4 Modelling of the natural gas chain
Figure 2 below gives a general overview of the natural gas chain studied here.
Production Treatment
Transport by LNG tankerTransmission by pipeline from producing countries
National transmission (high pressure)
Storage
National distribution (low pressure)
Liquefaction
Gasification
Electricity production at NGCC
Heat production at boilers and CHP units
Production Treatment
Transport by LNG tankerTransmission by pipeline from producing countries
National transmission (high pressure)
Storage
National distribution (low pressure)
Liquefaction
Gasification
Electricity production at NGCC
Heat production at boilers and CHP units
Figure 2: Description of the system for natural gas chain, from production to utilization, addressing
electricity production, heat generation and combined heat and power generation for both domestic
and industrial use
1.2.5 Data sources and quality
1.2.5.1 Data sources
Only highly reliable data are used. The four following types of data are concerned, from the best
quality to the worst:
→ Data from gas companies;
→ Data from the literature (only from well known institutes);
→ Data from official documents;
→ Other LCAs made by non-gas companies.
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The main data sources used in this study are the following:
→ Data from Eurogas–Marcogaz Working Group on LCA: a collection of environmental
performance indicators was launched in 2004. This data is used in this study.
→ Data from sustainable development reports published by gas companies. However it
has to be noted that data reporting differs from one company to another. In the future, it
would be useful to harmonize the reporting practices in order to obtain reliable and uniform
data and to avoid double counting.
→ ecoinvent 2.0, 2007 [5]: The Swiss Centre for Life Cycle
Inventories was founded in 2000 and currently includes several
institutes and departments of, among others, the Swiss Federal
Institutes of Technology Zurich (ETHZ) and Lausanne (EPFL), of the
Paul Scherrer Institute (PSI). The Swiss Centre for Life Cycle
Inventories funded the development and programming of the ecoinvent database and its
current operation. Its members were in charge with LCI data compilation and updating
within the project ecoinvent 2007.
1.2.5.2 Data quality
The quality of the data collected for this study has been assessed during the inventory phase
considering the following criteria:
Data quality GOOD MEDIUM WEAK
Time period Less than 5 years 5 – 10 years >10 years
Geographic area Same country Same region of the
world Different region
Representativeness More than 70% 40%-70% <40%
Type of data Primary data Secondary data Theoretical calculations
Table 1: Data quality
The data quality has been detailed in appendix 6 where the summary of inventory data is
presented.
Concerning the criteria listed above for the notation of data quality, additional information are
given :
• The representativeness of data refers the most often to the market share of the collected
data compared to the studied system.
• Concerning the type of data, primary data correspond to measured data collected directly
to the production site, secondary data correspond to aggregated data, some of which are
not included into the system boundaries, and theoretical calculations are not measured
data but calculated ones from various hypothesis.
• If for one data, the different criteria don’t correspond to the same level, the worst one is
chosen. In the specific case of Norwegian processing data used for various geographic
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areas, as 3 criteria are good and only one weak, it has been decided to chose the level
medium.
1.2.6 Allocation modes
Many processes have more than one function or output. The environmental load of that
process needs to be allocated over the different functions or outputs. There are different
ways to make such an allocation.
ISO recommends the following procedure in order to deal with allocation issues:
→ Avoid allocation, by splitting the process in such a way that it can be described as two
separate processes where each one has a single output.
→ Another way to avoid allocation is to extend the system boundaries by including processes
that would be needed to make a similar output. For example, if a usable quantity of steam,
produced as a by-product, is used in such a way that it avoids the production of steam by
more conventional means, one may subtract the environmental load of the avoided steam
production. A practical problem is often that it is not always easy to say how the steam
would be produced alternatively.
→ If it is not possible to avoid allocation in either way, the ISO standard suggests allocating
the environmental load based on a physical causality, such as mass or energy content of
the outputs. For example if the sawdust represents 40% of the mass, one can allocate 40%
of the environmental load to sawdust. In the case of allocating steam, we believe that the
mass of the steam is not a very relevant basis.
→ If this procedure cannot be applied, ISO suggests using a socio-economic allocation basis,
such as the economic value. For example if the sawdust represents 20% of the value
generated by the saw mill one can allocate 20% of the environmental load to this output.
Allocation rules need to be defined for the following sub-systems:
→ Production of natural gas: in some case, oil, condensates and gas are produced from the
same field and with the same equipments. Data on energy consumption and emissions are
then relative to the joint production of oil, condensates and gas. Since it is not possible to
differentiate what is due to oil or to gas production, we have chosen to apply an
allocation based on the energy content of the respective co-products (based on
Lower Heating Value – LHV). Allocation factors have been calculated for natural gas
produced in Norway and in the Netherlands. For other countries, the allocation is included
in the data used to describe the production step (see chapter 5 for further details).
→ Sweetening: No impact has been allocated to the sulphur produced during sweetening of
natural gas. Indeed, it has a low (and sometimes even negative) economic value, so it may
be considered as a waste flow (cf. 5.1.6.2.2).
→ Liquefaction: during the step of natural gas liquefaction, some co-products may also be
produced, such as sulphur, LPG, gasoline, and sometime helium. These products have a
commercial value and a part of the impact of liquefaction shall be allocated to them. Since
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it is not possible to differentiate what is due to one product or the other, we have chosen
to apply an allocation based on the energy content (LHV). It should be noted that,
as at the sweetening step, no impact is allocated to sulphur (cf. 5.1.6.2.2) .
→ Combined Heat and Power plants: when the natural gas is used to produce heat and
power, a rule has to be defined to allocate impacts to the two co-products. Again, energy
content allocation is chosen in the present study (this choice is further elaborated in
5.9.3.4).
1.2.7 Impacts and substances considered
Life cycle impact assessment is defined as the phase in the LCA aiming at understanding and
evaluating the magnitude and significance of the potential environmental impacts of a product
system.
The impact assessment methods themselves are described in ISO 14040 [1] and ISO 14044 [2]. In
these standards a distinction is made between:
→ Obligatory elements, such as classification and characterisation;
→ Optional elements, such as normalisation, ranking, grouping and weighting.
This means that, according to ISO, every LCA must at least include classification and
characterisation.
The inventory result of an LCA usually contains hundreds of different emissions and resource
extraction parameters. Therefore it has been decided to focus on the main impacts of
natural gas activities that are:
→ Atmospheric emissions: carbon dioxide, methane, nitrogen oxides, sulphur dioxide,
carbon monoxide, dinitrogen monoxide, particulates, non methane volatile organic
compounds (NMVOC);
→ Energy consumptions: natural gas, oil, coal, uranium, hydraulic and other renewable
energy.
It has to be noticed that some flows are only followed as primary data :
→ Carbon monoxide, particulates and non methane volatile organic compounds (NMVOC)
Thus, they are not currently used for the calculation of impacts assessment.
The following LCIA methods and specific midpoints have been applied for the LCA study:
→ Global Warming Potential (IPCC GWP 100 years);
→ ReCiPe 2008 – Terrestrial Acidification Potential;
→ Cumulative Energy Demand (CED) non renewable.
NB : As carbon monoxide, particulates and non methane volatile organic compounds (NMVOC) are
not characterized, the inventory results of these flow are only presented in appendix 7.
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1.2.8 Global warming
1.2.8.1 Phenomenon description
The Earth's climate is driven by the balance of energy transferred from the sun and lost by the
earth. The primary energy is lost through heat radiation. Several gases in the atmosphere,
called greenhouse gases, can reflect some of this heat back to the Earth. This effectively
warms the Earth and may modify the climate over time as the concentration of these
gases increases in the atmosphere.
A greenhouse gas indicator, the global warming potential (GWP), is used to compare the ability of
different greenhouse gases to trap heat in the atmosphere. It is derived from two basic properties
of each gas, compared to those of carbon dioxide:
→ The first is its radiative efficiency (heat-absorbing ability);
→ The second is its decay rate (the amount removed from the atmosphere over a given
number of years).
Most of the methods used in Life Cycle Impact Assessment (LCIA) are based on the International
Panel on Climate Change (IPCC).
1.2.8.2 Main substances from the gas industry contributing to global
warming
1.2.8.2.1 CO2
Carbon is naturally cycled between various atmospheric, oceanic, land biotic, marine biotic and
mineral reservoirs. The largest fluxes occur between the atmosphere and terrestrial biota, and
between the atmosphere and surface water of the oceans. In the atmosphere, carbon
predominantly exists in its oxidised form as CO2. Atmospheric carbon dioxide is part of this global
carbon cycle, and therefore its fate is a complex function of geochemical and biological processes.
1.2.8.2.2 Methane
In the gas industry, methane is emitted during the production and distribution of natural gas and
petroleum, and is released as a by-product of incomplete fossil fuel combustion. Figure 3 shows the
contribution of the various human activities to anthropogenic methane emissions.
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Figure 3: Breakdown of anthropogenic sources of methane emissions (taken from [6]).
Methane is removed from the atmosphere by reacting with the hydroxyl radical (OH) and is
ultimately converted to CO2. Minor removal processes also include reaction with chlorine in the
marine boundary layer, a soil sink, and stratospheric reactions. Increasing emissions of methane
reduce the concentration of OH, a feedback that may increase methane’s atmospheric lifetime
(IPCC 2001).
1.2.8.3 Characterisation factors: global warming potential (GWP)
The GWP provides a tool for converting emissions of various gases into a common measure, which
allows climate analysts to aggregate the radiative impacts of various greenhouse gases into a
uniform measure denominated in carbon or carbon dioxide equivalents.
The generally accepted authority on GWPs is the Intergovernmental Panel on Climate Change [7].
IPCC Climate change factors considered in this report have a timeframe of 100 years (Table 2).
IPCC characterisation factors for the direct global warming potential of air emissions are:
→ not including indirect formation of dinitrogen monoxide from nitrogen emissions;
→ not accounting for radiative forcing due to emissions of NOX, water, sulphate, etc. in the
lower stratosphere + upper troposphere;
→ not considering the range of indirect effects given by IPCC;
→ including CO2 formation from CO emissions;
→ considering biogenic CO2 uptake as negative impact.
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Compound Global Warming Potential (kg eq. CO2/kg)
CO2 1
CH4 25
N2O 298
Table 2: Global warming characterisation factors (IPCC 2007 100 years)
1.2.9 Acidification
1.2.9.1 Phenomenon description
Natural rain is slightly acidic due to the presence of various acids in the air that are washed out by
rain. However, a number of man-made emissions are either acidic or converted into acid by
chemical processes in the air. Examples of such emissions are sulphur dioxide (which becomes
sulphuric acid) and nitrogen oxides (which become nitric acid).
As a result, the acidity of rain can be substantially increased by anthropogenic emissions and in a
number of areas, the soil and water have a limited capacity to neutralize the resulting acids. If
water becomes too acidic, an increasing number of aquatic species are harmed and the ability of
plants to grow and thrive is harmed if the soil becomes too acidic.
An acidification indicator is derived by assuming that 100% of an emission is converted into acid
and falls into a sensitive area. The acidity of each emission is converted into equivalent amounts of
sulphur dioxide. All emissions are then added into an overall acidification indicator score that
represents the total emission of substances that may form acids.
1.2.9.2 Main substances from the gas industry contributing to
acidification
1.2.9.2.1 NOX
Nitrogen oxides are mainly emitted by burning fossil fuels. Combustion of natural gas in gas
turbines or gas engines therefore contributes to the acidification potential.
1.2.9.2.2 SO2
Naturally poor in sulphur, natural gas is not an important source of SO2 emissions; however, in a
perspective of comparison to others fuels, like fuel oil – a biff emitter of SO2, it is an important
substance to consider for a further comparison.
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1.2.9.3 Characterisation factors: acidification potential (AP)
The impact assessment method used to characterise the acidification activity is the following:
ReCiPe 2008 –terrestrial acidification potential [8].
Compound Acidification Potential (kg eq. SO2/kg)
SO2 1
NOX 0.56
Table 3: Acidification characterisation factors (ReCiPe 2008 : terrestrial acidification)
NB : The chosen method : terrestrial acidification from ReCiPe 2008 takes into account acidification
generated only by air emissions with consequences on soil.
It has to be noticed that 3 scenarios of acidification from ReCiPe exist, a egalitarian (E), a
hierarchist (H) and an individualist (I)[70].
• Perspective I is based on the short-term emission, impact types that are undisputed,
technological optimism as regards human adaptation.
• Perspective H is based on the most common policy principles with regards to time-frame
and other issues.
• Perspective E is the most precautionary perspective, taking into account the longest time-
frame.
The default ReCiPe midpoint method is hierarchist version. During the rest of the report, this
indicator will be named simply acidification.
1.2.10 Non renewable energy depletion
1.2.10.1 Phenomenon description
The Earth's natural resources are vital for the survival and the development of the human
population. Some of these resources such as fossil fuels are limited; others are renewable (e.g.
wind or solar energy).
Although many effects of over-exploitation are felt locally, the growing interdependence of nations
and international trade in natural resources make their management a global issue.
1.2.10.2 Main substances from the gas industry contributing to
resource depletion
Natural gas is the main contributor to energy consumption for the gas industry. However some
other fuels like diesel, heavy fuel oil or electricity may be used at several stages of the life cycle;
that is the reason why we also follow oil, coal and uranium.
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1.2.10.3 Characterisation factors
The energy consumption gives an indication about the amount of used energy. More the quantity is
important more the stock is decreased. However, the chosen method doesn’t take into account the
depletion of the resources, i.e the still available stock. The impact assessment method used to
characterize the non-renewable energy consumption is the Cumulative Energy Demand (CED) non-
renewable [9]. This indicators is used in two different ways. For the upstream chain (until the
distribution), the results are expressed in kJ surplus which means that only the additional energy
required to produce 1 MJ of natural gas are given. The delivered natural gas is not expressed.
Concerning the total chain (with utilization), the results are expressed in primary energy
consumption.
The lower heating values of the main fuel are (in MJ/kg):
• Natural gas2 : 40.3 (in MJ/Nm3)
• Oil : 45.8
• Hard coal : 19.1
• Brown coal : 10
• Uranium : 560 000
2 The lower heating value detailed by country are presenting in the appendix n°1.
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2 DESCRIPTION OF THE NATURAL GAS
CHAIN - IDENTIFICATION OF
POTENTIAL EMISSION SOURCES
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2.1 Exploration This paragraph is given as information even if it is excluded from the boundaries of the study.
In the search for natural gas reservoirs, the subsoil is analyzed essentially by geophysical methods.
Geophysics can use different methods (magnetic, gravimetric, seismic),
but the seismic survey is the main tool, and has undergone a
considerable development in recent years.
Explosives were earlier used to generate the seismic waves. This
method was harmful to the environment, and fishes were killed in the
vicinity of the charge. The method has now been totally discarded, and today seismic waves are
most commonly generated by air guns, which discharge compressed air into the water.
This method has reduced the environmental impact substantially compared to the use of
explosives.
The drilling technique used for exploration and developing boreholes is
essentially the same as for oil. In the exploration phase, either jack-up or
floating drilling rigs are used depending on the water depth and
environmental impact. A drilling fluid (mud) is pumped into the drill pipe,
and the fluid consists of water, clay, polymers and suspended materials for
density control.
The purpose of the drilling fluid is to cool the drill bit, lubricate, remove the
cuttings to the surface, counterbalance the reservoir pressure and deposit
a clay cake at the wall to consolidate the drill hole and prevent the drilling
fluid from entering the formation.
Traditionally, the return drilling fluid has been dumped
at the seafloor near the rig. Different types of chemicals
are added to the drill fluid, and there has been a
continuous improvement over the later years to reduce
the pollution and environmental impact from drill fluids.
Risk based analysis methods have been developed to quantify the pollution
gradients. In special sensitive areas, the drill fluid is collected, and
transported onshore for disposal.
Once an exploration well has been drilled, and the presence of commercially viable quantities of
natural gas has been verified, the next step is actually lifting the natural gas out of the ground and
processing it for transportation [10].
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2.2 Offshore / Onshore production
2.2.1 Process description
In developing offshore gas fields, the first generation rigs for
production drilling and processing were platforms standing at the sea
floor. Still today, the majority of offshore natural gas production
platforms are of this type.
As the field development over time moved to larger seawater depths,
a new generation of floating drilling- and production platforms was
developed.
The third step in offshore oil and gas production development has been to drill the production wells
by dedicated floating drilling rigs, and installing the required equipment at the seafloor completes
the wells. The wells are then tied back through flow-lines to a gas processing platform or ship.
Further development of sub-sea production facilities, automating the installations, improving
reliability and reducing the environmental impact, are major development guidelines for the future.
[10]
2.2.1.1 Well Completion
After a production well is drilled, the well must be 'completed' to allow natural gas to flow out of
the formation and up to the surface. The process includes strengthening the well hole with casing,
evaluating the pressure and temperature of the formation, and then installing the proper
equipment to ensure an efficient flow of natural gas out of the well.
There are three main types of conventional natural gas wells
→ Oil wells: since oil is commonly associated with natural gas deposits, a certain amount of
natural gas may be obtained from wells that were drilled primarily for oil production. In
some cases, this "associated" natural gas is used to help in the production of oil, by
providing pressure in the formation for the oils extraction.
→ Gas wells: the associated natural gas may also exist in large enough quantities to allow its
extraction along with the oil. Natural gas wells are wells drilled specifically for natural gas,
and contain little or no oil.
→ Condensate wells are wells that contain natural gas, as well as a liquid condensate. This
condensate is a liquid hydrocarbon mixture that is often separated from the natural gas
either at the wellhead, or during the processing of the natural gas.
Depending on the type of well that is being drilled, completion may differ slightly. It is important to
remember that natural gas, being lighter than air, naturally rises to the surface of a well. Because
of this, in many natural gas and condensate wells, lifting equipment and well treatment are not
necessary.
Completing a well consists of a number of steps:
→ installing the well casing;
→ completing the well;
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→ installing the wellhead;
→ installing lifting equipment or treating the formation should that be required.
2.2.1.2 The Wellhead
The wellhead consists of the pieces of equipment mounted at the opening of the well to regulate
and monitor the extraction of hydrocarbons from the underground formation. It also prevents
leakages of oil or natural gas out of the well, and prevents blowouts due to high-pressure
formations. Formations that are under high pressure typically require wellheads that can withstand
a great deal of upward pressure from the escaping gases and liquids. These wellheads must be able
to withstand pressures of up to 20,000 psi (pounds per square inch). The wellhead consists of
three components: the casing head, the tubing head, and the 'Christmas tree'.
The 'Christmas tree' is the piece of equipment that fits atop the casing and tubing heads, and
contains tubes and valves that serve to control the flow of hydrocarbons and other fluids out of the
well. It commonly contains many branches and is shaped somewhat like a tree, thus its name,
Christmas tree. The Christmas tree is the most visible part of a producing well, and allows for the
surface monitoring and regulation of the production of hydrocarbons from a producing well.
2.2.1.3 Lifting and Well Treatment
Once the well is completed, it may begin to produce natural gas. In some
instances, the hydrocarbons that exist in pressurized formations naturally rise
up through the well to the surface. This is most commonly the case with
natural gas. Since natural gas is lighter than air, once a conduit to the surface
is opened, the pressurized gas rises to the surface with little or no
interference. This is most common for formations containing natural gas alone,
or with a light condensate. In these scenarios, once the Christmas tree is
installed, the natural gas flows to the surface on its own.
In order to more fully understand the nature of the well, a potential test is typically run in the early
days of production. This test allows well engineers to determine the maximum amount of natural
gas that the well can produce in a 24-hour period.
When a well is first drilled, the formation is under pressure and produces natural gas at a very high
rate. However, as more and more natural gas is extracted from the formation, the production rate
of the well decreases. This is known as the decline rate.
In some natural gas wells, and oil wells that have associated natural gas, it is more difficult to
ensure an efficient flow of hydrocarbons up the well.
2.2.1.4 Well Treatment
Well treatment is another method of ensuring the efficient flow of hydrocarbons out of a
formation. Essentially, this type of well stimulation consists of injecting acid, water or gases into
the well to open up the formation and allow the petroleum to flow through the formation more
easily. Acidizing a well consists of injecting acid (usually hydrochloric acid) into the well. In
limestone or carbonate formations, the acid dissolves portions of the rock in the formation, opening
up existing spaces to allow for the flow of petroleum. Fracturing consists of injecting a fluid into the
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well, the pressure of which 'cracks' or opens up fractures already present in the formation. In
addition to the fluid being injected, 'propping agents' are also used. These propping agents can
consist of sand, glass beads, epoxy, or silica sand, and serve to prop open the newly widened
fissures in the formation. Hydraulic fracturing involves the injection of water into the formation,
while CO2 fracturing uses gaseous carbon dioxide. Fracturing, acidizing, and lifting equipment may
all be used on the same well to increase permeability.
These techniques are mostly applicable to oil wells, but have also been used to increase
the extraction rate for gas wells. Because it is a low-density gas under pressure, the
completion of natural gas wells usually requires little more than the installation of casing, tubing,
and the wellhead. Unlike oil, natural gas is much easier to extract from an underground formation.
However, as deeper and less conventional natural gas wells are drilled, it is becoming more
common to use stimulation techniques on gas wells.
2.2.2 Sources of emissions and consumptions
2.2.2.1 Atmospheric emissions
The main atmospheric emissions of the process are detailed in Table 4.
Direct emissions Source
NOX, CO, CO2
Emissions due to the use of compressors
Flaring
Boilers
SO2 Boilers using sour gas
CH4
Leakages
Fugitive emissions
Incomplete combustion emissions, that are caused by unburned methane in the
exhaust gases from gas engines and combustion facilities
Table 4: Sources of emissions – Production
2.2.2.2 Consumptions
Natural resources used in the process are detailed in Table 5.
Consumptions Source
Natural gas Natural gas extracted and consumption in the boilers
Electricity Facilities
Hydrochloric acid Well treatment
Methanol Used to avoid freezing
Table 5: Sources of consumption - Production
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2.3 Natural gas processing
2.3.1 Process description
Natural gas processing consists of separating all or some of the fluid components at the well exit,
such as water, acid gases and heavier hydrocarbons.
Due to the cost of offshore installations, some of the natural gas produced offshore has to be
handled at onshore facilities. In such cases, the offshore processing is limited to make the gas
transportable by pipelines to an onshore processing facility.
Natural gas, as consumers use it, has a different composition from the natural gas that is brought
from underground up to the wellhead. Although the processing of natural gas is in many respects
less complicated than the processing and refining of crude oil, it is equally as necessary before its
use by end users.
The natural gas used by consumers is composed almost entirely of methane. However, natural gas
found at the wellhead, although still composed primarily of methane, is by no means as pure.
Whatever the source of the natural gas, once separated from crude oil (if present) it commonly
exists in mixtures with other hydrocarbons: mainly ethane, propane, butane, and pentanes. In
addition, raw natural gas contains water vapour, hydrogen sulphide (H2S), carbon dioxide, helium,
nitrogen, and other compounds in various concentrations that have to be removed [10].
2.3.1.1 Water removal
In addition to separating oil and some condensates from the wet gas stream, it is necessary to
remove most of the associated water. Most of the liquid free water associated with extracted
natural gas is removed by simple separation methods at or near the wellhead.
However, the removal of the water vapour that exists in solution in natural gas requires a more
complex treatment. This treatment consists of 'dehydrating' the natural gas, which usually involves
either absorption or adsorption.
2.3.1.1.1 Glycol dehydration
An example of absorption dehydration is known as Glycol Dehydration. In this process, a liquid
desiccant dehydrator is used to absorb water vapour from the gas stream. Glycol, the principal
agent in this process, has a chemical affinity for water. This means that, when in contact with a
stream of natural gas that contains water, glycol extracts the water out of the gas stream.
Essentially, glycol dehydration involves using a glycol solution, usually either diethylene glycol
(DEG) or triethylene glycol (TEG), which is brought into contact with the wet gas stream in what is
called the 'contactor'. The glycol solution absorbs water from the wet gas. Once absorbed, the
glycol particles become heavier and sink to the bottom of the contactor where they are removed.
The natural gas, having been stripped of most of its water content, is then transported out of the
dehydrator. The glycol solution, bearing all of the water stripped from the natural gas, is put
through a specialized boiler designed to vaporize only the water out of the solution. While water
has a boiling point of 100°C, glycol does not boil until 204°C. This boiling point differential makes it
relatively easy to remove water from the glycol solution, allowing it to be reused in the dehydration
process.
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A new innovation in this process has been the addition of flash tank separator-condensers. As well
as absorbing water from the wet gas stream, the glycol solution occasionally carries with it small
amounts of methane and other compounds found in the wet gas. In the past, this methane was
simply vented out of the boiler. In addition to losing a
portion of the natural gas that was extracted, this
venting contributes to air pollution and the greenhouse
effect. In order to decrease the amount of methane and
other compounds that are lost, flash tank separator-
condensers work to remove these compounds before
the glycol solution reaches the boiler. Essentially, a
flash tank separator consists of a device that reduces
the pressure of the glycol solution stream, allowing the
methane and other hydrocarbons to vaporize ('flash').
The glycol solution then travels to the boiler, which
may also be fitted with air or water-cooled condensers,
which serve to capture any remaining organic
compounds that may remain in the glycol solution.
Figure 4: Glycol dehydratation process
2.3.1.1.2 Solid-desiccant dehydration
Solid-desiccant dehydration is the primary form of dehydrating natural gas using adsorption, and
usually consists of two or more adsorption towers, which are filled with a solid desiccant. Typical
desiccants include activated alumina or a granular silica gel material. Wet natural gas is passed
through these towers, from top to bottom. As the wet gas passes around the particles of desiccant
material, water is retained on the surface of these desiccant particles. Passing through the entire
desiccant bed, almost all of the water is adsorbed onto the desiccant material, leaving the dry gas
to exit the bottom of the tower.
Solid-desiccant dehydrators are typically more effective than glycol dehydrators, and are usually
installed as a type of straddle system along natural gas pipelines. These types of dehydration
systems are best suited for large volumes of gas under very high pressure, and are thus usually
located on a pipeline downstream of a compressor station. Two or more towers are required due to
the fact that after a certain period of use, the desiccant in a particular tower becomes saturated
with water. To 'regenerate' the desiccant, a high-temperature heater is used to heat gas to a very
high temperature. Passing this heated gas through a saturated desiccant bed vaporizes the water
in the desiccant tower, leaving it dry and allowing for further natural gas dehydration.
2.3.1.2 Separation of natural gas liquids
Natural gas coming directly from a well contains many natural gas liquids that are commonly
removed. In most instances, natural gas liquids (NGLs) have a higher value as separate products,
and it is thus economical to remove them from the gas stream. The removal of natural gas liquids
usually takes place in a relatively centralized processing plant, and uses techniques similar to those
used to dehydrate natural gas.
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There are two basic steps for the treatment of natural gas liquids in the natural gas stream. First,
the liquids must be extracted from the natural gas. Second, these natural gas liquids must be
separated themselves, down to their base components.
There are two main techniques for removing NGLs from the natural gas stream:
→ the absorption method;
→ and the cryogenic expander process.
According to the Gas Processors Association, these two processes account for around 90% of total
natural gas liquids production.
2.3.1.2.1 The absorption method
The absorption method of NGL extraction is very similar to using absorption for dehydration. The
main difference is that, in NGL absorption, absorbing oil is used as opposed to glycol. This
absorbing oil has an 'affinity' for NGLs in much the same manner as glycol has an affinity for water.
Before the oil has picked up any NGLs, it is termed 'lean' absorption oil. As the natural gas is
passed through an absorption tower, it is brought into contact with the absorption oil, which soaks
up a high proportion of the NGLs. The 'rich' absorption oil, now containing NGLs, exits the
absorption tower through the bottom.
It is now a mixture of absorption oil,
propane, butanes, pentanes, and
other heavier hydrocarbons. The rich
oil is fed into lean oil stills, where the
mixture is heated to a temperature
above the boiling point of the NGLs,
but below that of the oil. This process
allows for the recovery of around
75% of butanes, and 85 - 90% of
pentanes and heavier molecules from
the natural gas stream.
Figure 5: NGL recovery unit
The basic absorption process above can be modified to improve its effectiveness, or to target the
extraction of specific NGLs. In the refrigerated oil absorption method, where the lean oil is cooled
through refrigeration, propane recovery can be upwards of 90%, and around 40% of ethane can be
extracted from the natural gas stream. Extraction of the other, heavier NGLs can be close to 100%
using this process.
2.3.1.2.2 The cryogenic expansion process
Cryogenic processes are also used to extract NGLs from natural gas. While absorption methods can
extract almost all of the heavier NGLs, the lighter hydrocarbons, such as ethane, are often more
difficult to recover from the natural gas stream. In certain instances, it is economic to simply leave
the lighter NGLs in the natural gas stream. However, if it is economic to extract ethane and other
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lighter hydrocarbons, cryogenic processes are required for high recovery rates. Essentially,
cryogenic processes consist of dropping the temperature of the gas stream to around –50°C.
There are a number of different ways of chilling the gas to these temperatures, but one of the most
effective is known as the turbo expander process. In this process, external refrigerants are used to
cool the natural gas stream. Then, an expansion turbine is used to rapidly expand the chilled
gases, which causes the temperature to drop significantly. This rapid temperature drop condenses
ethane and other hydrocarbons in the gas stream, while maintaining methane in gaseous form.
This process allows for the recovery of about 90 to 95% of the ethane originally in the gas stream.
In addition, the expansion turbine is able to convert some of the energy released when the natural
gas stream is expanded into recompressing the gaseous methane effluent, thus saving energy
costs associated with extracting ethane.
The extraction of NGLs from the natural gas stream produces both cleaner, purer natural gas, as
well as the valuable hydrocarbons that are the NGLs themselves.
2.3.1.3 Natural gas liquid fractionation
Once NGLs have been removed from the natural gas stream, they must be broken down into their
base components to be useful. That is, the mixed stream of different NGLs must be separated out.
The process used to accomplish this task is called fractionation. Fractionation works based on the
different boiling points of the different hydrocarbons in the NGL stream. Essentially, fractionation
occurs in stages consisting of the boiling off of hydrocarbons one by one. The name of a particular
fractionator gives an idea as to its purpose, as it is conventionally named for the hydrocarbon that
is boiled off. The entire fractionation process is broken down into steps, starting with the removal
of the lighter NGLs from the stream. The particular fractionators are used in the following order:
→ Deethanizer - this step separates the ethane from the NGL stream;
→ Depropanizer - the next step separates the propane;
→ Debutanizer - this step boils off the butanes, leaving the pentanes and heavier
hydrocarbons in the NGL stream;
→ Butane Splitter or Deisobutanizer - this step separates the iso and normal butanes.
By proceeding from the lightest hydrocarbons to the heaviest, it is possible to separate the
different NGLs reasonably easily.
2.3.1.4 Sulphur and carbon dioxide removal
In addition to water, oil, and NGL removal, one of the most important parts of gas processing
involves the removal of sulphur and carbon dioxide. Natural gas from some wells contains
significant amounts of sulphur and carbon dioxide. This natural gas, because of the rotten smell
provided by its sulphur content, is commonly called 'sour gas'. Sour gas is undesirable because the
sulphur compounds it contains can be extremely harmful to breath. Sour gas can also be extremely
corrosive. In addition, the sulphur that exists in the natural gas stream can be extracted and
marketed on its own. Sulphur exists in natural gas as hydrogen sulphide (H2S), and the gas is
usually considered sour if the hydrogen sulphide content exceeds 5.7 milligrams of H2S per cubic
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meter of natural gas. The process for removing hydrogen sulphide from sour gas is commonly
referred to as 'sweetening' the gas.
Figure 6 : Sweetening process
The primary process for sweetening sour natural gas is quite similar to the processes of glycol
dehydration and NGL absorption. In this case, however, amine solutions are used to remove the
hydrogen sulphide. This process is known simply as the 'amine process’. The sour gas is run
through a tower, which contains the amine solution. This solution has an affinity for sulphur, and
absorbs it much like glycol absorbing water. There are two main amine solutions used,
monoethanolamine (MEA) and diethanolamine (DEA). Either of these compounds, in liquid form,
absorbs sulphur compounds from natural gas as it passes through. The effluent gas is virtually free
of sulphur compounds, and thus loses its sour gas status. Like the process for NGL extraction and
glycol dehydration, the amine solution used can be regenerated (that is, the absorbed sulphur is
removed), allowing it to be reused to treat more sour gas.
Although most sour gas sweetening involves the amine absorption process, it is also
possible to use solid desiccants like iron sponges to remove the sulphide and carbon
dioxide.
Sulphur can be sold and used if reduced to its elemental form. Elemental sulphur is a bright yellow
powder like material, and can often be seen in large piles near gas treatment plants. In order to
recover elemental sulphur from the gas processing plant, the sulphur containing discharge from a
gas sweetening process must be further treated. The process used to recover sulphur is known as
the Claus process, and involves using thermal and catalytic reactions to extract the elemental
sulphur from the hydrogen sulphide solution.
In all, the Claus process is usually able to recover 97% of the sulphur that has been removed from
the natural gas stream. Since it is such a polluting and harmful substance, further filtering,
incineration, and 'tail gas' cleanup efforts ensure that well over 98% of the sulphur is recovered.
Gas processing is an instrumental piece of the natural gas value chain. It is instrumental in
ensuring that the natural gas intended for use is as clean and pure as possible. Once the natural
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gas has been fully processed, and is ready to be consumed, it must be transported from those
areas that produce natural gas, to those areas that require it.
2.3.2 Sources of emissions and consumptions
2.3.2.1 Atmospheric emissions
The main atmospheric emissions of the process are3 detailed in Table 6.
Direct emissions Source
NOX, CO, CO2
Emissions due to the use of compressors
Flaring
Boilers
SO2 Desulphurisation
Boilers
CH4
Leakages
Fugitive emissions
Incomplete combustion emissions, that are caused by unburned methane in the
exhaust gases from gas engines and combustion facilities
Table 6: Sources of emissions – Processing
2.3.2.2 Consumptions
Natural resources used in the process are detailed in Table 7.
Consumptions Source
Natural gas Consumption in the boilers
Electricity Facilities
Activated carbon,
amines Sweetening
Oil NGL separation
Glycol Drying
Table7: Sources of consumptions - Processing
3 Refrigerant are used at this step, in general propane, as it is directly available. Some leakages may occur, nevertheless those flows are not taken into account here as they don’t contribute to the impacts studied (e.g. propane contributes to photochemical oxidant formation). Moreover, such leakages can be considered as negligible, as propane is used in closed loops.
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2.4 Natural gas pipeline transmission
2.4.1 Process description
The main pipeline system and many of regional transmission systems are configured as ring mains:
if any part of the system fails gas can be directed round another way. During the summer, the gas
in the main pipelines moves along at walking pace, sometimes as slow as 5 km/h. In winter on the
other hand, when a lot of gas has to be delivered the gas velocity may exceed 50 km/h. The drag
of the pipe wall on the fast-flowing stream of gas soaks up energy, resulting in a pressure drop.
Located at strategic intervals across the different countries there are accordingly compressor
stations to maintain the desired pressure in the main transmission pipelines. In summer, the
compressors on the transmission grid are seldom required. The parts in the transmission system
that transport gas to the power stations and industrial users are much less subject to seasonal
fluctuations.
In summer, the basic system has almost always an adequate capacity, and spare gas can be fed
into storage systems to build up a stock for the winter. As already explained, however, when
demand rises with falling temperatures, compressor stations are needed to pump energy into the
main transmission grid and maintain the pressure.
2.4.1.1 Pipelines
Main transport pipelines are like a network of gas highways. The pipes range in diameter from 140
cm down to 30 cm (56" down to 12"). They are made of various grades of steel and there is a
cathodic protection system to prevent corrosion. The gas highways have 'link roads' at various
points along their length. Interlinking enables different parts of the system to be connected
together or to substitute for each other.
Valve systems allow us to open up additional transmission capacity (more lanes on highway) or to
isolate sections of the line so that the gas flow can be shut off and diverted if a pipe ruptures or
some other fault occurs. It may also be necessary to close a link between two pipelines for other
reasons.
Shutoff valves are fitted at switching points and other locations. The main shutoff valves in the
pipeline incorporate smaller by-pass valves so that pressure differences can be equalized gradually
before the main valve is opened.
The contracts with the producers require the gas to be supplied in clean condition. Sand, water,
condensate and other impurities are accordingly removed by the producers in gas conditioning
installations before the gas is transferred to the main pipelines. Despite this processing, the gas
can still contain a very small amount of condensate, which manifests itself as a thin mist in the
pipeline. This mist has a tendency to precipitate in certain parts of the system. To prevent
condensate from entering the transmission system installations, special condensate traps are fitted
at various points.
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2.4.1.2 Compressors
The job of the compressor station is to restore pipeline pressure to the desired level if it falls too
low. We have already seen that the gas has to travel at high speed through pipeline in order to
keep up with winter demand. The pressure loss obviously depends on the distance travelled, but
the more important factor is the rate of flow, so
the pipeline pressure drops rapidly in cold
weather. To ensure that the gas is delivered to the
customers at an adequate capacity the pipeline
pressure has to be raised again roughly every 150
km. Each compressor station has different types of
compressor, which at some stations can be
operated to give either single-stage or two- stage
compression.
Figure 7: Compressor station
There are centrifugal compressors powered by gas turbines and reciprocating
compressors driven by gas-powered piston engines. The compressor stations are designed to
provide maximum flexibility for matching demand. Most of them run on natural gas. The installed
compressor power per station can vary from less than 10 MW to more than 200 MW.
2.4.1.3 Blending stations and/or control quality
Sometimes different kinds of gases are transported. The gases purchased are mixed at blending
stations -complex arrays of pipelines several hundred meters long, along with the necessary
instrumentation and valves. The job of blending stations is to blend two (and sometimes more)
gases together to obtain gas with the required calorific value or Wobbe number. The blending
stations have sophisticated control systems to monitor automatically the resultant gas blend. If the
quality of the blended gas strays outside certain set limits, the blending station is automatically
shut down.
2.4.1.4 Metering and/or pressure-regulating stations
The metering and pressure-regulating stations form the link between the main transmission grid
and the regional grid.
The pressure in the regional grid ranges from 40 bars down to 16 bars. As the pressure in the main
transmission grid is higher than this, it has to be reduced using pneumatically controlled
governors. If the governors should fail and the pressure in the regional grid threatens to rise too
high, a safety system trips in automatically to restore control of the outlet pressure, and a standby
run of control equipment takes over. As the name suggests, metering and pressure-regulating
stations measure the gas volume as well as controlling the pressure. This metering is purely for
operational purposes: the Dispatching Centre needs to know how many cubic meters of gas at
what pressure are being fed from the main transmission grid into the regional grid.
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Another task performed at the metering and pressure- regulating stations is odorisation. As it
comes from the well, natural gas has practically no smell, so that any leaks would not be
immediately apparent. To eliminate the risk of undetected leaks, odorant (tetrahydrothiophene or
sulphur free) is injected at an adequate rate. This chemical compound gives to the gas its
characteristic smell. Unodorised gas is only supplied in some countries to a few large industrial
users whose processes require it. Although metering and pressure-regulating stations are relatively
small compared to compressor stations, the equipment needed to switch gas from the main
transmission grid to the regional grid is fairly bulky.
2.4.1.5 Custody transfer/City gate stations
The points at which gas is delivered to customers are custody transfer stations, also called city gate
stations. At these custody transfer stations, the product is fed into the systems operated by the
utility companies and large consumers or power plants. These stations could also be combined with
metering and regulating stations. At the transfer station the gas pressure is reduced to that
required by the customer for either onward distribution or immediate consumption. If the customer
is a distribution company, the gas transferred from the regional grid is reduced in pressure to the
pressure, which the distributor needs to carry the gas onward to its customers. If the transfer
station is fed direct from the main transmission grid, the pressure generally has to be reduced,
though there are some customers whose gas is delivered at a higher pressure.
Without additional heating, the rapid pressure drop at the custody transfer station would cause the
temperature of the gas to fall sharply (0.5 °C/bar) and freezing point would soon be reached.
Preheating the gas prevents icing and condensate formation: a special heating system at each
custody transfer station ensures that the gas leaves the station at a temperature of 5-10 °C.
Transfer stations are relatively modest in size and are of standard design; the equipment is housed
in a building mostly owned by the customer. Large stations have more than one parallel governor
runs, one of which is on standby. Each run of equipment includes filters, pre-heaters, governors
and pressure relief valves. The transfer stations are in effect the 'last stops' on the transmission
system. They are also the points where the volume of gas delivered to the customer is metered for
the purpose of calculating how much the customer owes. Metering systems for billing purposes
have to be calibrated and approved.
2.4.1.6 Export/import stations
Like the custody transfer stations, export/import stations, too, are end-points on the transmission
grid. The export stations are located at strategic points on the border, delivering gas destined for
abroad. They supply a wide range of gases. The customers receive gas 'made to measure': the
right quality at the right pressure and at the right rate. Export stations are basically outdoor meter
runs consisting of a length of pipe extending to several tens of meters and a few small buildings
housing the high-tech instrumentation to measure pressure, quality and flow rate. Modern
equipments such as gas chromatographs are used; the gas quality can be measured on the spot.
Ultrasonic metering is a new technique for measuring the volume of gas being delivered. This
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system is already being used at the large export stations, backed up by conventional turbine gas
meters. This approach enables a very high level of accuracy to be attained. The small stations
operate solely with turbine meters. The export stations are almost entirely unmanned.
2.4.2 Sources of emissions and consumptions
2.4.2.1 Atmospheric emissions
The main atmospheric emissions of the process are detailed in Table 8.
Direct emissions Source
NOX, CO, CO2
Compressor stations
Gas heaters
Diesel emergency power plants
SO2 From diesel emergency power plants
CH4
Fugitive emissions (small leaks from flanges, pipe equipment, valves, etc.)
Emissions from pneumatic devices
Vented emissions from maintenance events and incident events
Incomplete combustion emissions caused by unburned methane in the exhaust gases
from gas engines and combustion facilities
Table 8: Sources of emissions – Transmission
2.4.2.2 Consumptions
Natural resources used in the process are detailed in Table 9.
Consumptions Source
Natural gas Compressors
Diesel Diesel emergency power plant
Electricity Compressors and utilities
Oil Lubrication
Odorants Odorisation
Table 9: Sources of consumptions – Transmission
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2.5 LNG chain
2.5.1 Process description
Liquid Natural Gas (LNG) is simply natural gas that has been reduced to a liquid state by cooling it
to minus 162°C. The transformation to a liquid is accompanied by a volume reduction of
approximately 600 to one. LNG density is slightly less than half that of water. [11]
The LNG chain is divided into three steps: liquefaction of natural gas, sea-transport of LNG, and
gasification.
Figure 8: LNG chain description
2.5.1.1 Liquefaction
There are different processes for liquefaction of natural gas.
2.5.1.1.1 Liquefaction processes
There are many liquefaction processes. For example, in Algeria three different processes are
used in the three main liquefaction plants. The plant at Arzew uses the classical cascade process,
the two plants at Bethioua use the APCI propane precooled mixed refrigerant cascade process and
the plant at Skikda uses the TEAL process.
The power requirements and compression equipment needed to produce LNG is different for each
of the commercial liquefaction processes.
The choice of the equipments depends on the molecular weight of the streams, the compression
ratio and the flow rates.
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→ Classical cascade process
The classical cascade process uses three refrigerants – methane, ethylene and propane – all
circulating in closed cycles. The methane and the propane are available from the feed. The
ethylene must be furnished separately. The cascade process has the highest thermal efficiency of
the common liquefaction processes, but keeping the refrigerants separate results in a complex
system.
→ Mixed refrigerant cascade (MRC)
The mixed refrigerant is typically a hydrocarbon-plus-nitrogen mixture of relatively wide boiling
range. All these components can be recovered from natural gas in a separate apparatus. Another
system is the propane precooled mixed refrigerant cascade process (APCI). In essence, the system
is a dual refrigerant cascade in which the
precooling cycle uses pure propane and
the lower boiling fluid is a mixed
refrigerant made up of nitrogen,
methane, ethane and propane. The
cascade combination with propane
makes it possible to reduce the boiling
range of the mixture refrigerant
substantially, which improves the
thermodynamic efficiency over that of
the straight MRC process.
Figure 9: Mixed refrigerant cascade process
→ TEAL process
The TEAL process, developed by Air Liquide in association with Gaz de France, incorporates one or
two stages of condensation using a mixed refrigerant.
→ PRICO process
The PolyRefrigerant Integral Cycle Operation, or PRICO process, employs a single mixed refrigerant
loop to accomplish the gas liquefaction. The refrigerant is a mixture of nitrogen and hydrocarbons
ranging from methane to isopentane. Refrigerant components are typically extracted from
the feedstock except for nitrogen, which comes from an air separation unit. The process
typically uses a single refrigeration compression system. The compressor can be a single case
compressor without intercooling or can be intercooled to reduce the power requirements. This
greatly simplifies the piping, controls, and equipment arrangement for the liquefaction unit. The
process cools the natural gas feed from ambient conditions to gas liquefaction temperatures and
then further cool the gas to minimize vaporisation when sending the LNG to atmospheric storage
tanks.
2.5.1.1.2 Storage
Underground and aboveground storage tanks are used to store LNG, either after liquefaction and
before it is loaded onto an ocean carrier, or after it is unloaded from an ocean carrier or before it is
regasified.
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Underground tanks are usually made of concrete, and are applicable for large storage quantities of
LNG. Above ground tanks are double walled. Both underground and aboveground tanks must be
heavily insulated to prevent vaporisation of LNG while it is in storage.
2.5.1.2 Sea transportation of LNG
Historically, the LNG vessels have been using steam turbines for propulsion and for auxiliary
energy requirements. A key feature of most carriers is the insulation system that maintains the
cargo at – 162°C. In one type of ship, the cargo is carried in separate tanks constructed of a thin
welded membrane of special steel. The small fraction of the cargo that boils off because of heat
leakage is used as boiler fuel for the propulsion of the ship. On a loaded voyage, this may provide a
large part of the fuel needed. The ships are ballasted for the return voyage with seawater carried in
separate wing tanks. Some LNG is left in the cargo tanks to ensure a non-explosive gaseous
atmosphere and to keep the tanks cool for the next voyage. Again, boil-off gas provides part of the
propulsion fuel.
The rest of energy needed for the propulsion of the tanker is usually fuel oil or diesel, used in diesel
generators. New propulsion technologies, with higher efficiencies, have emerged for LNG
transportation at the beginning of years 2000, with electric diesel powered vessel (e.g. in 2002
with Alstom Shipyard in France by Gaz de France) or more recently gas turbines or diesel electric
systems (including reliquefaction of the boil off gas).
2.5.1.3 Gasification
Upon arrival at the receiving facility, LNG is transferred into specially designed storage tanks where
it is stored as a liquid at near atmospheric pressure and minus 162°C.
The LNG remains in storage until it is demanded for redelivery. At that time it is pumped from the
tanks and subjected to both heat and pressure to return it to a gaseous state for transportation by
pipeline.
A gasification terminal usually consists of the sections below described:
→ Reception;
→ Storage;
→ Gasification;
→ Auxiliary installations.
2.5.1.3.1 Reception section
The reception section is made up of a berth for the gas tanker vessels, discharge arms and an
insulated transfer pipeline.
The LNG is offloaded from the gas tanker vessels with the inboard-submersed pumps and is
transferred to onshore storage tanks with discharge arms and through an insulated transfer
pipeline.
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During the discharge operations some of the boil-off vapours can be sent to the gas tanker vessels,
in order to compensate the pressure decrease in the gas tanker vessels caused by the liquid
drawing and in order to avoid the discharge in the atmosphere.
2.5.1.3.2 Storage section
The LNG is stored up in some onshore storage tanks, vertical cylinder-shaped with dual
containment at a temperature of approx minus 160°C and under normal atmospheric pressure. It
is then pumped to the gasification section from the tanks with submersed pumps.
Because of the continuous heat exchange with the environment there is a slow and continuous
vaporisation of the LNG (boil-off) stored in the tanks.
Some of the boil-off vapours are compressed and sent to the gas tanker vessels; the other part of
the boil-off vapours is compressed with a bank of compressors and is sent to a regeneration
system.
The regeneration system of the boil-off vapours is made with an adsorption column that receives
the LNG from the top and the gas from the bottom and works at a pressure of 27 bars.
In case of emergency the boil-off vapours can be vented in the atmosphere.
2.5.1.3.3 Gasification section
The LNG taken from the storage tanks is sent to a first group of centrifugal primary pumps, which
take the LNG to a pressure of 25 bars. After the primary pumps, there is a second group of pumps
(secondary pumps) that take the LNG to the gasification system at a pressure of about 70 bars.
The LNG that comes from the absorption column is mixed with the LNG that comes from the
primary pumps, is pumped to the secondary pumps and is sent to a system of evaporators. There
are two main types of evaporator used in Europe:
→ Submersed flame type: each evaporator has a burner that uses the gas taken
downstream the evaporators as fuel. The combustion products of the burners scrub in a
water bath with a temperature of the bath between 15 and 30°C. The bath is used as a
heat exchange medium to vaporize and to heat the LNG that flows in a tube nest.
→ Some evaporators do also gasify the gas through the flow of sea water. There are
therefore no energy consumptions for these types of evaporators, but cooler water has to
be released at the sea.
The natural gas is then sent to the main transmission network after an energetic measure.
If the natural gas that is produced from the evaporators does not respect the data sheet of
interchange ability with the network gas, it is corrected with the addition of a fluid with no heat
value, which is compressed air.
2.5.1.3.4 Auxiliary installations
The auxiliary installations of the plant are:
→ electricity system;
→ fresh water system;
→ cooling water system;
→ fireproof system;
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→ vent of the plant;
→ safety and control system.
All the plant is checked and controlled by a remote automation system. The electricity for the plant
comes from the national network. In case of absence of electricity from the national grid a diesel
emergency power plant starts working automatically in order to assure the safety of the plant.
The cooling water system uses both sea and fresh water and is used to cool all the auxiliary
installations.
2.5.2 Sources of emissions and consumptions
2.5.2.1 Atmospheric emissions
The main atmospheric emissions of the process are detailed in Table 10.
Direct emissions Source
SOX Combustion of gasoline for LNG tankers propulsion
Diesel emergency power plants
NOX, CO, CO2
Extracted CO2 from pre-treatment of liquefaction step
Compressors for the cooling system
Combustion of sub-products of the liquefaction
Flares
Combustion of natural gas of the boil-off for LNG tankers propulsion
Combustion of gasoline for LNG tankers propulsion
LNG compression
Combustion of natural gas in the burners of the evaporators for the regasification
Flares
CH4
Fugitive emissions, (small leaks from flanges, pipe equipment, valves etc.)
Emissions from pneumatic devices
Vented emissions from maintenance events and incident events
Incomplete combustion emissions caused by unburned methane in the exhaust gases
from gas engines and combustion facilities
Table 10: Sources of emissions – LNG chain
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2.5.2.2 Consumptions
Natural resources used in the process are detailed in Table 11.
Consumptions Source
Natural gas
Boil-off – Propulsion of the LNG tanker
LNG compression
Plant operations
Electricity LNG compression and utilities
Pumps and compressors
Diesel
Propulsion of the LNG-tanker
Diesel emergency power plants
Industrial and civil use
Nitrogen Isolation for the LNG-tankers
Transfer line between the ship and the tank for unloading
Refrigerants Liquefaction process
Table 11: Sources of consumptions – LNG chain
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2.6 Storage
2.6.1 Process description
The natural gas demand varies along the year. However the production cannot be easily adjusted
to the demand. It is therefore necessary for gas companies to regulate the difference between
production and consumption. This regulation is made, in particular, through natural gas storage.
[12]
These storages can be:
→ Aquifer storage: in that case, natural gas is stored inside a non-drinkable aquifer at a
depth of a few hundred meters. The principle of aquifer storage is to create an artificial gas
field by injecting gas into the voids of an aquifer formation. For this reason, the following
geological conditions are necessary: an anticline with sufficient closure, a porous and
permeable reservoir, and an excellent quality cap rock.
→ Depleted oil or gas field. This type of
storage is similar to aquifer storage. The
principle of a storage facility in a depleted
reservoir is simple, because the reservoir
formerly contained gas or oil. Hence it
satisfies the permeability and porosity
conditions required for storage. However,
before developing gas storage in a depleted
field, it is indispensable to check whether it
corresponds to the required production goals
(high throughputs over short periods), the
imperviousness of the cap rock (impervious
formation on top of the storage area).
→ Salt cavity storage: in that case, natural gas is stored under pressure in big empty
cavities, dug inside salt layers. The principle consists in dissolving the salt with fresh water
and removing the brine via a single well,
which then serves for gas injection and
withdrawal. These reservoirs serve to
store relatively smaller quantities of gas
than those that can be stored in aquifers
or depleted reservoirs. The storage
capacity for a given cavity volume
(several hundreds of thousands cubic
meters) is proportional to the maximum
operating pressure, which depends on
the depth. Salt caverns are not merely a
useful complement to the large porous
Figure 10: Underground storage
Figure 11: Salt cavity storage
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reservoirs. They also offer several advantages: high deliverability, high degree of
availability, short filling period, low percentage of cushion gas, total recovery of cushion
gas.
These different types of storage are based on different technologies, and consequently generate
different impacts on environment. Most impacts come from:
→ the compression of gas to send it inside the storage, using engine, turbines or electrical
compressors;
→ the drying of gas outside the storage, using TEG process;
→ the possible desulphurisation, using activated carbon or methyldiethanolamine (MDEA)
process;
→ the possible odorisation with tetrahydrothiophene (THT) or mercaptans (R-SH).
2.6.2 Sources of emissions and consumptions
2.6.2.1 Atmospheric emissions
The main atmospheric emissions of the process are detailed in Table 12.
Direct emissions Source
NOX, CO, CO2
Compression
Boilers for treatment
Flares
CH4
Fugitive emissions (small leaks from flanges, pipe equipment, valves etc.)
Emissions from pneumatic devices
Vented emissions from maintenance events and incident events
Incomplete combustion emissions caused by unburned methane in the exhaust gases
from gas engines and combustion facilities
Table 12: Sources of emissions – Storage
2.6.2.2 Consumptions
The main natural resources used in the process are detailed in Table 13.
Consumptions Source
Natural gas
Cushion gas
Compression
Treatment
Electricity Utilisation of compressors and auxiliaries
Methanol Used to avoid freezing
Activated carbons,
amines Desulphurisation
Glycol Drying
Table 13: Sources of consumptions – Storage
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2.7 Distribution Distribution is the final step in delivering natural gas to end-users. While some large industrial,
commercial, and electric generation customers receive natural gas directly from high capacity gas
pipelines (usually contracted through natural gas marketing companies), most other users receive
natural gas from a local distribution company (LDC).
The delivery of natural gas to its point of end use by a distribution utility is much like the
transportation of natural gas discussed in the Transportation section. However, distribution
involves moving smaller volumes of gas at much lower pressures over shorter distances to a great
number of individual users. Small-diameter pipe is used to distribute natural gas to individual
consumers.
While natural gas flowing through transmission gas pipelines is generally compressed at a pressure
above 65 bars, natural gas flowing through the distribution network is normally operated at a
pressure below 16 bars. The natural gas to be distributed is typically depressurized.
Traditionally, rigid steel pipe was used to construct distribution networks. However, new technology
is allowing the use of flexible
plastics up to 8 bars in place of
steel pipe. These new types of
plastics, mainly polyethylene,
allow cost reduction and
installation flexibility. The current
trend is to use new polyethylene
pipes at pressures even above 8
bar and in some countries,
polyethylene pipes are already
operated at a pressure up to 10
bars.
Figure 12: Low pressure distribution
Distribution network is equipped with a high number of valves (safety valves and operating
valves). Meters and customer lines are also part of the distribution network. Another innovation in
the distribution of natural gas is the use of electronic meter-reading systems. The natural gas that
is consumed by any one customer is measured by on-site meters, which essentially keep track of
the volume of natural gas consumed at that location. Traditionally, in order to bill customers
correctly, meter reading had to be installed to record these volumes.
Supervisory control and data acquisition (SCADA) systems are also used by distribution companies.
These systems can manage gas flow control and measurement with other accounting, billing, and
contract systems to provide a comprehensive measurement and control system for the LDC. This
allows accurate, timely information on the status of the distribution network to be used by the LDC
to ensure efficient and effective service at all times. [12]
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2.7.1 Sources of emissions and consumptions
2.7.1.1 Atmospheric emissions
The main atmospheric emissions of the process are detailed in Table 14.
Direct emissions Source
CH4 Fugitive emissions (small leaks from flanges, pipe equipment, valves etc.)
Emissions from third part interference
Table 14: Sources of emissions – Distribution
2.7.1.2 Consumptions
Resources used in the process are detailed in Table 15.
Consumptions Source
Natural gas Natural gas losses due to the leakages and interference
Table 15: Sources of consumptions – Distribution
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2.8 Utilizations
2.8.1 Systems overview
The figure below describes the link of each conversion technology considered in this study to the
gas supply chain. Thus appliances used for domestic purpose (boiler 10 kW and CHP units) are
linked to the low pressure network whereas industrial boiler (>100 kW) and NGCC power plant are
connected to the high pressure network.
Figure 13: Conversion technologies and link to gas supply chain
It was chosen to study the best available technologies. This technologies are the last available
evolution but they are currently used (e.g. DK6), thus this evaluation brings environment data to
these technologic innovations. The different conversion technologies are described more into
details in the following paragraphs.
2.8.2 Electricity production with a combined cycle
2.8.2.1 Design Principle
A natural gas fired combined cycle plant is designed to produce electricity in an efficient and
environmental friendly way, in particular by comparison to less recent technologies.
Electricityat power plant
Power plant(operation)
Natural gaslow pressureNatural gaslow pressure
MaterialsMaterials
Cogeneration plant(operation)
Cogeneration plant(operation)
Electricityat cogen
Heatat cogen
Allocation
Electricityat cogen
Heatat cogen
Allocation
MaterialsMaterials MaterialsMaterials
Natural gashigh pressureNatural gas
high pressure
Heating(operation)
Heatat boiler
Heating (operation)
Heatat boiler
GdF with validation
PSI with GdF support
Materials
Heating (operation)
Heat at boiler
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A natural gas combined cycle power plant comprises both a gas turbine and a steam unit. The gas
turbine uses the hot gases released from natural gas burning to turn a turbine and generate
electricity. The waste heat from the gas-turbine process is directed towards generating steam,
which, in turn, is used to turn a turbine and generates electricity. Because of this efficient use of
the heat energy released from the natural gas, combined-cycle plants are much more efficient than
steam units or gas turbines alone [13].
In single shaft plants, the gas turbine and steam turbine are connected as one drive train, driving
the same generator. In multi shaft plants (as shown on Figure ), the gas turbine and steam turbine
are independent of each other, each driving its own generator.
2.8.2.2 Sources of emissions and consumptions
2.8.2.2.1 Atmospheric emissions
The main atmospheric emissions of the process are detailed in Table 16.
Direct emissions Source
NOX, CO, CO2 Emissions due to gas turbines
CH4
Fugitive emissions (small leaks from flanges, pipe equipment, valves, etc.)
Emissions from pneumatic devices
Vented emissions from maintenance events and incident events
Incomplete combustion emissions caused by unburned methane in the exhaust gases
from gas engines
Table 16: Sources of emissions –Combined cycle
Figure 14: Combined cycle process schematic
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2.8.2.2.2 Consumptions
Natural resources used in the process are detailed in Table 17.
Consumptions Source
Natural gas Consumption in the turbines
Electricity Facilities
Table 17: Sources of consumptions –Combined cycle
2.8.3 Heat production with condensing boilers
2.8.3.1 Design principle
In this study heat is generated by a condensing modulating boiler representing state-of-art
technology. A condensing boiler is a high efficiency boiler that incorporates an extra heat
exchanger so that the hot exhaust gases lose much of their energy to pre-heat the water in the
boiler system. When working at condensing efficiency, the water vapour produced in the
combustion process condenses back into liquid form – hence the name of condensing boiler -
releasing the latent heat of vaporisation [14].
The boiler produces warm water that is then pumped through small pipes installed in walls and/or
floors. The heat carried by the water is transferred from the walls and/or floor by radiative effect,
ensuring a steady, even heating.
Moreover new burning technologies (e.g. cooling of flame, burning design) enable a significant
reduction of emissions, particularly NOX.
2.8.3.2 Sources of emissions and consumptions
2.8.3.2.1 Atmospheric emissions
The main atmospheric emissions of the process are detailed in Table 18.
Direct emissions Source
NOX, CO, CO2 Boilers
CH4
Fugitive emissions
Incomplete combustion emissions, that are caused by unburned methane in the
exhaust gases
Table 18: Sources of emissions –Boiler
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2.8.3.2.2 Consumptions
Natural resources used in the process are detailed in Table 19.
Consumptions Source
Natural gas Consumption in the boilers
Electricity For auxiliary equipments
Table 19: Sources of consumptions –Boiler
2.8.4 Combined heat and power generation
2.8.4.1 Design Principle
Combined Heat and Power (CHP) generation is the simultaneous generation of usable heat and
power (usually electricity) in a single process. CHP systems can be employed over a wide range of
sizes, applications, fuels and technologies. In its simplest form,
it employs a gas turbine, an engine or a steam turbine to drive
an alternator and the resulting electricity can be used either
wholly or partially on-site. The heat produced during power
generation is recovered, usually in a boiler and can be used to
raise steam for a number of industrial processes, or to provide
hot water for space heating.
Figure 15: Combined heat and power plant
Because CHP systems make extensive use of the heat produced during the electricity generation
process, they can achieve overall efficiencies in excess of 70% at the point of use. In contrast, the
efficiency of conventional gas-fired power stations, which discard this heat, is typically around
48%. Electric and thermal efficiencies are adjustable to optimise the combined production of
electricity and heat.
CHP systems are typically installed onsite, supplying customers with heat and power directly at the
point of use, therefore helping avoid the significant losses (which occur in transmitting electricity
from large centralised plant to customer) [15].
A three-way-catalyst can be installed in some cases to reduce NOX emissions. The emission
depends on operation modes but, more importantly, on catalyst performance. While a new catalyst
reduces NOX emissions to 1 mg/m3 (5%O2), they are continuously increasing with the age of the
catalyst. It has to be replaced approximately every 5 years, giving average NOX emissions of
140 mg/m3 (5% O2).
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2.8.4.2 Sources of emissions and consumptions
2.8.4.2.1 Atmospheric emissions
The main atmospheric emissions of the process are detailed in Table 20.
Direct emissions Source
NOX, CO, CO2 Boilers
CH4
Fugitive emissions
Incomplete combustion emissions, that are caused by unburned methane in the
exhaust gases
Table 20: Sources of emissions – CHP plant
2.8.4.2.2 Consumptions
Natural resources used in the process are detailed in Table 21.
Consumptions Source
Natural gas Consumption in the boilers
Electricity For auxiliary equipments
Catalyst To reduce NOX emissions
Table 21: Sources of consumptions – CHP plant
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3 METHODOLOGY, MAIN ASSUMPTIONS
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3.1 Methodology used for estimating consumptions and emissions along the chain
3.1.1 Input Data Quality
The description of the natural gas chain in Chapter 2 gives qualitative details on the various
technologies and associated energy consumptions and sources of emissions contributing to the
environmental impacts studied here. However, accurate quantitative data for each technology as
well as weighted average of technologies used are not available for the whole European natural gas
chain. The choice was thus made to use as far as possible data coming from European gas
companies. Those data are most of the time given without any detail on the technologies used, so
it was not possible to link the data used in the Life Cycle Inventory and the qualitative description
of Chapter 2.
Data published by gas companies in their annual and sustainable reports are of different frames:
→ Some gas companies publish their consumptions for fuel, flares and even fugitive
emissions;
→ Some publish their emissions in grams (CO2, methane, etc);
→ Some publish the results of their impact assessment in grams equivalent CO2;
→ Others publish both consumptions and emissions.
In this study it is chosen to focus on consumption figures whenever possible in order to
avoid losses of information. Emissions figures are indeed often aggregated figures where it is
difficult to know whether these emissions do comprise indirect emissions from electricity production
and in which proportion they come from gas or other consumed fuels such as diesel of heavy fuel
oil for example. There is a great risk to double counting or mistakes. Moreover emissions figures
are often incomplete: CO2 is always followed, but it is not the case for other flows like particles or
carbon monoxide.
Preference is therefore given to consumption data, which are called primary data. Once
these consumption data have been found, consequential emissions are calculated on the basis of
emission factors adapted on gas composition and type of consumption (fugitive emission,
combustion in gas turbine, combustion in gas motor, etc.). As a result, emissions for gas venting or
gas combustion are different from a country to another because of the differences of gas
composition.
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3.1.2 Type of energy and material flows used in this study
In this study are given, for each step, the following rates:
→ Combustion rate : percentage of natural gas used for combustion in gas turbines, gas engines of boilers in MJ/MJ;
→ Flaring rate : percentage of natural gas burned in flares for safety reasons in MJ/MJ;
→ Fugitive emission rate : percentage of natural gas vented from incidents or safety measures and all small leaks from flanges, pipe equipment, valves, joints, etc. that are more or less continuous sources in MJ/MJ;
→ Diesel and heavy fuel oil consumption in energy percentage (%): energy percentage of diesel and heavy fuel oil burned in boilers or emergency generators in MJ/MJ;
→ Electricity consumption in energy percentage (% in MJ/MJ) when the process from ecoinvent database is directly used, without the collection of specific data, a comment has been added after the table of consumptions with the name of the ecoinvent process, in the other case, the electric mix is detailed in appendix 4;
→ Material consumption in kg/MJ of gas: other consumptions like chemicals or materials are also taken into account.
If such figures are not available as it is often the case, the consumption data are deduced from emissions figures. These data are therefore considered as secondary data.
In the future, it would be useful to harmonize the reporting practices among the different companies in order to obtain reliable and uniform data to avoid double counting.
3.2 Modelling of the gas chain
3.2.1 Design of each step
Each step of the natural gas chain is designed as described in Figure 16.
Figure 16: Design of a step
INPUT DATA
OUTPUT DATA
(1+FL+Fu+Co) MJ 1 MJ
STEP
Emissions from non gas fuels
Non-gas energy consumptions (electricity, heavy fuel oil, diesel, etc.)
Emissions from vents & fugitive emissions
Emissions from gas as a fuel
Emissions from flaring
Material consumptions (chemicals, water, etc…)
FL : Flaring rate in MJ/MJout Fu Fugitive emission rate in MJ/MJout Co : Combustion rate in MJ/MJout
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3.2.2 Methodology used for the construction of the chain
3.2.2.1 Assembly of two steps
In order to take the whole consumption into account, it is necessary, when assembling two steps,
to consider that the natural gas consumed during the step “i” comes from the step “i-1”.
As a result, if the processing step has a natural gas consumption of AProcessing = 1 + FL+Fu +Co, it
has in fact a global consumption in primary energy equal to AProcessing = (1 + FL+Fu +Co)* AProduction
, where AProduction is the natural gas consumption of the production step.
Figure 17 illustrates this chain structure.
3.2.2.2 Assembly of N steps
When assembling N steps, the methodology is the same. Figure 18 illustrates the structure of the
chain.
Figure 18: Assembly of N steps
STEP
1 MJ
STEP
STEP
Total gas
consumption for N
(…)
N steps
Figure 17: Assembly of two steps
(1+FLi-1+V i-1+GF i-1) *(1+FLi+V i+ GF i)
(1+FLi+V i+ GF i)
STEP i-1
1
STEP i (1+FLi-1+Fui-1+Coi-1)
*(1+FLi+Fui+Coi) (1+FLi+Fui+Coi)
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3.2.2.3 Modelling of the chain
The European natural gas mix consists of the national productions and the imports of natural gas
from the European and non-European exporting countries.
The following modelling is used for transportation:
Starting from a producing country, natural gas is transported via pipeline directly to the border of
the EU-25. If liquefied natural gas (LNG) is imported, the produced natural gas is transported via
pipeline to the next liquefaction unit in an exporting country, liquefied and exported via LNG tanker
to Europe. Then LNG is gasified in a gasification unit in Europe.
For national transmission, storage and distribution via pipeline to the consumer in Europe, data
taking into account the global consumption and losses, and an average distance of transmission
and distribution in Europe are given by European companies.
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4 NATURAL GAS MARKET IN EUROPE
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4.1 Biggest European producers
Figure 19: European producers in 2004
Gas production in the EU-25 covers more than
40% of its supply requirements.
United Kingdom is the biggest European
producer with 46% of the total EU-25
production in 2004. The Netherlands comes
second with 33% of the global gas production.
[16]
With 40 billion cubic meters (bcm), ExxonMobil
ranked first in the region (18% of the total) in
2004. The other producers, including Shell, the
Dutch company EBN, Total, Eni, BP and Centrica,
each produced a volume exceeding 10 bcm in
2004. Over 70% of production inside Europe is
therefore in the hands of these seven
companies.
For most oil and gas companies, Europe represents a strategic target market and it absorbs a large
percentage of their total production (35% or more for ExxonMobil, Shell, Eni and BG in 2004).
Denmark5% Germany
8%Italy6%
Netherlands33%
Poland2%
United Kingdom
46%
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4.2 Biggest European consumers
Natural gas consumption in 2004 amounted to 458.3 bcm [16].
At the end of year 2004 more than 95 million customers were connected to the European natural
gas grid, which represents more than 240 million people using natural gas.
Natural gas consumption is increasing across
Europe, but the rate of change varied
between countries. Well above average
developments were recorded in Greece,
Luxembourg, Spain and Portugal with growth
rates between 10% and 23%. Some gas
consuming countries showed a slight
decrease (Denmark, Finland, Hungary and
Slovakia).
Figure 20: European consumers
Eurogas expects a steady increase of gas consumption of around 2% per year and looks forward to
a positive development in the demand of natural gas in the coming half-decade.
The increased dependency of the EU towards imports is confirmed (233 bcm for 2004 compared to
221 bcm in 2003). This underlines the global dimension of the natural gas business.
Austria2%
Belgium4%
Czech Republic2%
France10%
Germany19%
Hungary3%
Italy16%
Netherlands9%
Poland3%
Spain6%
United Kingdom
21%
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4.3 Main trade movements in Europe
The gas consumed in Europe can result from one of the three following sources and movements:
indigenous, gaseous trade and LNG trade. In the following paragraphs, all the gas movements are
described for the year 2004 [16].
4.3.1 Indigenous consumption
About 26% of the gas consumed in Europe comes from an indigenous production. The indigenous
consumption for each producing country is summed up in the Table 22.
Producing country Indigenous
consumption
Germany 1.4%
Italy 2.7%
Netherlands 4.2%
United Kingdom 17.6%
TOTAL - major countries 25.9%
Table 22: Indigenous consumption (% of the European consumption in 2004, bcm/bcm)
4.3.2 Gaseous movements
The remaining gas consumed in Europe comes from imports, either from EU-25 countries (~15%)
or non-EU-25 countries (nearly 60%). From the 60% coming from non-European countries, 85% is
brought as gas and the 15% left is imported as liquefied natural gas (LNG).Table 23 sums up the
natural gas trade movement from producing countries to Europe in % of the total consumption of
natural gas in Europe. It has to be noticed that Malta and Cyprus are not included in this table as
they are not supplied with natural gas
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UK Germany Netherlands Norway Russian Fed. Algeria Total
Austria 0.2% 0.2% 1.3% 1.7%
Belgium 0.0% 0.3% 1.7% 1.6% 0.0% 3.7%
Czech Republic 0.6% 1.6% 2.2%
Denmark 0.0%
Finland 1.0% 1.0%
France 0.2% 2.1% 3.3% 2.5% 8.1%
Germany 0.7% 4.9% 5.9% 8.4% 19.8%
Greece 0.5% 0.5%
Hungary 0.2% 2.1% 2.3%
Ireland 0.8% 0.8%
Italy 2.0% 1.6% 4.7% 5.3% 13.5%
Latvia 0.3% 0.3%
Lithuania 0.6% 0.6%
Luxembourg 0.2% 0.2%
Netherlands 0.4% 1.0% 1.0% 0.6% 3.0%
Poland 0.1% 0.1% 1.8% 2.0%
Portugal 0.5% 0.5%
Slovakia 1.6% 1.6%
Slovenia 0.1% 0.1% 0.2%
Spain 0.5% 1.7% 2.2%
Sweden 0.0%
United Kingdom 0.1% 0.1% 2.0% 2.3%
Estonia - - - - 0.2 - 0.2%
Imported gas / distributed gas 2.2% 2.1% 10.8% 16.7% 27.2% 7.5% 66.6%
Table 23: Gaseous trade movements (% of the European consumption in 2004, bcm/bcm)
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4.3.3 LNG trade movements
Of the 74.5 % imported gas (from European and non-European countries) 7.9 % is imported in
liquid form (LNG). The following table sums up the LNG trade movement from producing countries
to Europe in % of the total consumption of natural gas in Europe.
Oman Qatar Algeria Libya Nigeria Total
Austria 0.0%
Belgium 0.6% 0.6%
Finland 0.0%
France 0.0% 1.5% 0.2% 1.7%
Greece 0.1% 0.1%
Italy 0.5% 0.8% 1.3%
Portugal 0.3% 0.3%
Spain 0.3% 0.9% 1.5% 0.1% 1.1% 3.9%
Imported LNG / distributed gas 0.3% 0.9% 4.2% 0.1% 2.4% 7.9%
Table 24: LNG trade movements (% of the European consumption in 2004, bcm/bcm)
4.3.4 Synthesis of main trade movements in Europe
Table 25 proposes a synthesis of the main trade movements in Europe, by presenting the part of
indigenous consumption (26%), the part of gas imported from Europe (15%), the part of gas
imported from non-European countries (51%) and the part of LNG imported from non-European
countries (8%).
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Indigenous consumption
Gaseous movement
LNG trade movement
Country consumption/
Europe consumption
Austria 1,7% 0,0% 1,7% Belgium 3,6% 0,6% 4,2%
Czech Republic 2,2% 2,2% Denmark 0,0% 0,0% Finland 1,0% 0,0% 1,0% France 8,2% 1,7% 9,9% Germany 1,40% 19,9% 21,3% Greece 0,5% 0,1% 0,6% Hungary 2,3% 2,3% Ireland 0,8% 0,8% Italy 2,70% 13,6% 1,3% 17,6% Latvia 0,3% 0,3% Lithuania 0,6% 0,6%
Luxembourg 0,2% 0,2%
Netherlands 4,20% 3,0% 7,2% Poland 2,0% 2,0% Portugal 0,5% 0,3% 0,8% Slovakia 1,6% 1,6% Slovenia 0,2% 0,2% Spain 2,2% 3,9% 6,1% Sweden 0,0% 0,0%
United Kingdom 17,60% 2,2% 19,8% Cyprus 0,0% Malta 0,0% Estonia 0.2% 0,0%
Total 26% 66% 8% 100%
Table 25: Main trade movements in Europe (% of the European consumption in 2004, bcm/bcm)
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Figure 21 shows the main trade movements in Europe in % of the imports.
Figure 21: Main trade movements
in Europe
The European map shows
the main natural gas trade
movements in Europe:
Russia is the main exporter
to Europe; the imports of
gas from Russia to
Germany represent 8.4% of
the total volume of
imported gas to Europe.
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5 INVENTORY
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5.1 Production and processing
5.1.1 Introductory comment
In chapter 2, a detailed description is given separately for the production and processing of natural
gas. However, data used in the inventory are based on aggregated assessments for a given plant.
In particular, for the processing step, it was not possible to identify clearly the respective
contributions of water removal, separation of natural gas liquids, natural gas liquids fractionation
and sulphur and carbon dioxide removal. As a consequence, all those operations are included
within the boundaries of the studies. Thus, this assumption contributes to an overestimate of the
impacts.
5.1.2 Production and processing in Russia
5.1.2.1 Production in Russia
Russia holds the world’s largest natural gas proven reserves, nearly twice the reserves in the next
largest country, Iran. Accordingly, in 2004 Russia was the world’s largest natural gas
producer as well as the world’s largest exporter [17].
5.1.2.1.1 Main actors
Gazprom controls almost 60% of the Russian gas reserves and produces about 90% of
Russian gas. Gazprom is 100% founder of 58 subsidiaries (as of September 1, 2002). It also
participates in authorized capital of
almost 100 Russian and foreign
companies. Gazprom consists of
eight production associations.
The largest production companies
are Urengoygazprom (around the
Urengoy field),
Yamburggazdobycha (Yamburg
field) and Nadymgazprom
(Medvezye field). These companies
produce 86% of Russia’s gas. In
addition to Gazprom, several oil
companies and ITERA also produce
gas but their share is only 6% of
the total gas production. Figure 22: Natural gas production in Russia
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5.1.2.1.2 Major production fields
About 97% of the production comes
from 21 very large fields (gas volumes
more than 500 bcm) and 118 large
fields (gas capacity between 30 and
500 bcm).
The main gas production regions are
Siberian-Ural region (92% of the total
gas production) and the Orenburg
region (5% of the total gas
production).
The remaining 3% are distributed
among numerous regions. Source: Gazprom environmental report 2005
Figure 23: Natural gas production in Russia per region
Three major fields (called the 'Big Three') in Western Siberia-Urengoy, Yamburg, and Medvezhye
comprise more than 70% of Gazprom's total natural gas production, but these fields are now in
decline.
5.1.2.1.3 Collected data
Several sources of data have been studied:
→ Gazprom did produce an environmental report [18], in which some data about
atmospheric emissions are available. According to this report, total atmospheric emissions
in 2005 are estimated to 2,308 thousand tons, but these emissions do not only cover
Gazprom gas production activities, but all activities of Gazprom including oil production,
sulphur production, gas transportation and oil transportation. Thus, it was not possible to
use the data from Gazprom in the study as emissions related only to gas production could
not be explicitly separated from emissions related to other activities..
→ The ecoinvent 2.0 database [5]: data on the Russian gas production are mostly based
on standard data, as only little information on the Russian production is available. Data are
based on average data and therefore not specific for the country, except for leakage data.
Leakage in exploitation is estimated at 0.38% and production 0.12%. A global leakages
rate of 0.50% is therefore assumed for the production and processing steps. Energy
demand is based on 2000 Norwegian data, quantity of flared gas on 1991 German data,
leakages on 2000 data, and water emissions on 1991 German data.
→ The study from the Wuppertal Institute (2005) [19] indicates a leakage rate of 0.11%
for the production and processing in Russia. This figure stems from a previous report
(1996/1997) that indicated a leakages rate of 0.06%. This figure is based on
measurements made on the Yamburg production field. Between these two reports, no new
measurements have been made, but a more cautious assessment of the data collected in
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1996 has been carried out This rate is significantly lower than the one used in the
ecoinvent database (0.50%).
→ “Well-to-wheel analysis of future automotive fuels and power trains in the
European context“, LBST [20]. This study does not give details of the given gas
consumption which seems really high (7.4%). Without further details this would be
considered as bad quality data and are not utilised.
In this report, data for Russia have been taken from the ecoinvent database, except for the
leakages rate that stems from a recent and high quality study made by the Wuppertal Institute
[19]. All the rates are expressed as % of natural gas produced based on the energy content as
indicated in the methodology (see §3).
Rate and consumption in
MJ/MJ [20] [5] [19]
This report –
[19]- [5]
Fugitive emissions rate N/A 0.375% 0.11% 0.11%
Flaring rate N/A 0.25% N/A 0.25%
Combustion rate 7.40% 0.989% N/A 0.989%
Diesel consumption N/A 0.11% N/A 0.11%
Electricity consumption N/A N/A N/A 0%
Table 26: Collected data - Production – Russia
Remark: a preliminary study indicates that the choice of this specific fugitive emission rate during
production in Russia over other values found in the literature has a negligible impact on the global
GHG emissions (less than 4% of the GHG emissions associated with low pressure natural gas and
less than 1% after utilization).
The diesel consumption is modelled with a process from ecoinvent database : “Diesel, burned in
diesel-electric generating set/GLO U” which take into account diesel consumption, emissions and
infrastructure for the use of diesel in electric generating sets. This process has been used for each
diesel consumption in this study.
Concerning the electricity consumption, the mix used and the modelling is described in appendix 4
for all the countries.
5.1.2.2 Processing in Russia
5.1.2.2.1 Major existing plants
Gazprom operates six gas and gas condensate refineries, which purify natural gas and gas
condensate, dehydrate natural gas and prepare it for transportation, stabilise and process gas
condensate and oil, and provide a wide range of refining products [21].
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Gazprom’s 100%-owned subsidiaries include the following gas refineries:
→ Astrakhan Gas Refinery is an integrated refinery, the first stage of which came on-
stream in 1986 and the second one in 1997. The Astrakhan Gas Refinery processes natural
gas with a high sulphur content and gas condensate extracted from the Astrakhan gas
condensate field. The refinery’s products include dry market-grade natural gas, stable gas
condensate, liquefied natural gas, motor gasoline, diesel, furnace fuel oil, natural gas-
derived sulphur and odorants.
→ Orenburg Gas Refinery came on-stream in 1974 and is one of the world’s largest gas
refineries. It processes natural gas with a high sulphur content and gas condensate. Its
products include dry market-grade natural gas, stable gas condensate, liquefied natural
gas, natural gas-derived sulphur, odorants, etc.
5.1.2.2.2 Collected data
According to the annual report of Gazprom [21], 5.9% of the natural gas produced by Gazprom is
sour and has to be sweetened. In comparison, the ecoinvent database estimates the part of sour
natural gas produced in Russia to be 20%.
For the study, 100% of the gas produced in Russia is dried and 5.9% sweetened. Since no data are
available on this step, we adapt data from others countries to the Russian context:
→ For dehydration, data from the Kårstø plant in Norway are adapted to the Russian context
(see 5.1.3.2). The Kårstø unit being more aged (Kårstø started in 1985), we assume that it
is more representative of the Russian treatment plants than the Kollsnes unit in terms of
efficiency and emissions including fugitive emissions and leakages.
→ For sweetening, we consider data (consumption + emissions) from the Grossenkneten plant
in Germany (see 5.1.6.2).
5.1.3 Production and processing in Norway
5.1.3.1 Production in Norway
Norway had 2 084 billion cubic meters (bcm) of proven natural gas reserves as of January 2005.
The North Sea holds the majority of these reserves, but there are also significant quantities in the
Norwegian and Barents Seas. Norway is the eighth-largest natural gas producer in the world,
producing 73 bcm in 2003 [22].
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5.1.3.1.1 Main actors
As is the case with the oil sector, Statoil and
NorskHydro dominate natural gas production in
Norway. Several international majors, such as
ExxonMobil and BP, also have a sizable presence in the
Norwegian continental shelf gas sector, although they
often work in partnership with Statoil or NorskHydro.
5.1.3.1.2 Major production fields
A small group of fields accounts for the bulk of
Norway's total natural gas production. The single
largest field is Troll, which produced 26.33 bcm in
2004 and represents about one-third of Norway's total
natural gas production. Other important fields include
Sleipner Ost, Asgard, and Oseberg. These four fields
compose over 70% of Norway's total gas production.
Despite the maturation of its major natural gas fields in
the North Sea, Norway has been able to sustain annual
increases in total natural gas production by
incorporating new fields.
Figure 42: Major production fields and
operator in Norway
Figure 25: Natural gas production in Norway
Source: Exxonmobil website
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5.1.3.1.3 Collected data
Several sources of data have been studied:
→ Collected data from Statoil (2004) [23]. They concern the whole Statoil Norwegian
continental shelf (NCS), including the Troll A, Sleipner, Statfjord and Asgard fields. All
energy consumptions (fuel gas, heavy fuel oil and electricity) are given directly as input
data. Leakages rate has been deduced from the methane emissions.
→ The ecoinvent database [5]: data come from OLF (2001) considering the Norwegian
continental shelf. Emissions and discharges from 49 producing fields and 178 exploration
and production/injection wells are included. All fields with production facilities located on
the NCS have been included. Fuel consumption and emissions are stable. The processing of
gas is assessed separately. All the data used are from year 2000. As production is
changing, no average is built with other years.
→ “Well-to-wheel analysis of future automotive fuels and power trains in the
European context“, LBST [20]. This study gives a surprising low consumption rates
expressed as % of the natural gas produced based on the energy content for Norway
regarding the others sources.
Rate and consumption in
MJ/MJ [20] [5] [23] This report - [23]
Fugitive emissions rate N/A 0.013% 0.023% 0.023%
Flaring rate N/A 0.287% 0.223% 0.223%
Combustion rate 0.7% 1.298% 1.737% 1.737%
Diesel consumption N/A 0.139% 0.097% 0.097%
Electricity consumption N/A N/A 0.001% 0.001%
Table 27: Collected data - Production – Norway
In this report, we consider the values from Statoil 2004, because they are well documented and
more recent.
Data presented in table 27 have already taken into account allocation between natural gas and oil
and condensates production. Impact allocation is based on the energy content of the various
coproducts, based on data collected from Statoil.
Source : Statoil,
2004 [23] Volume produced LHV Density
Natural gas 60 300 000 000 m3 34 MJ/m3
Oil and
condensates
82 600 000 m3 42.3 MJ/kg 840 kg/m3
Table 28 Data used for impact allocation
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Global energy consumption could seem particularly high regarding the energy consumption in the
Netherlands; however, this can be explained by two factors:
→ Some Norwegian installations are being aged;
→ Figures for the transportation from the offshore production sites (Troll, Asgard, Sleipner) to
the onshore processing plants are included in these figures. The average distance of
transmission between production fields and processing plants is 300 km.
5.1.3.2 Processing in Norway
5.1.3.2.1 Main existing plants
Norwegian produced gas has non-negligible CO2 and water contents. The produced gas is
processed in the two onshore processing complexes in Norway:
→ The processing facilities at Kollsnes in Øygarden local authority west of Bergen treat
gas from the Troll field in the North Sea at a rate of up to 120 million standard cubic
meters (scm) per day. The Kollsnes plant separates natural gas liquids (NGL) from the
methane-rich Troll gas, and compresses the latter for pumping by large compressors
through various pipelines to continental Europe.
→ The Kårstø complex north of Stavanger plays a key role in the transport and
processing of gas and condensate (light oil) from important areas of the Norwegian
continental shelf. Its original purpose was to receive and treat gas from fields in the
northern part of the Norwegian North Sea via the Statpipe trunk line system, and this
remains a major function. Processing facilities at the complex separate natural gas liquids
from rich gas arriving by pipeline.
5.1.3.2.2 Collected data
Several data sources have been studied:
→ Collected data from Statoil (2004) [23]. Data collected come from the Kollsnes plant
and the Kårstø facilities. As it is the case for the production step, all energy consumptions
(fuel gas, heavy fuel oil and electricity) are given directly as input data. Leakages rate has
been deduced from the methane emissions. Detailed figures on the chemical consumptions
are also available.
→ The ecoinvent database [5]: data come from Statoil (2001) and concern the Kollsnes
and Kårstø processing plants. An average of both plants is taken.
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Rate and consumption in MJ/MJ [5] [23] - Kollsnes [23] - Kårstø This report [23]
Fugitive emissions rate 0.002% 0.0044% 0.006% 0.0052%
Flaring rate N/A 0.053% 0.102% 0.0789%
Combustion rate 0.746% 0.029% 1.886% 1.0071%
Diesel consumption 0.001% N/A 0.0003% 0.0002%
Electricity consumption N/A 0.433% 0.053% 0.2332%
Chemicals [5] [23] - Kollsnes [23] - Kårstø This report [23]
Monoethylene glycol (kg/MJ) 4.46E-8 9.01E-7 N/A 4.27E-7
Methanol (kg/MJ) N/A N/A 2.75E-8 1.45E-7
Ammonia (kg/MJ) N/A N/A 3.51E-8 1.85E-8
Sodium hydroxide (kg/MJ) 5.17E-8 N/A 1.16E-7 6.10E-8
Hydrochloric acid (kg/MJ) N/A N/A 1.56E-7 8.21E-8
Other chemicals (kg/MJ) 1.30E-7 N/A N/A N/A
Table 29: Collected data - Processing – Norway
In this report, we use the figures from Statoil 2004 [23], because they are more recent.
A weighted average of the Kollsnes and Kårstø data are calculated considering that Kollsnes
processes 47.4% of the produced gas and it is assumed that Kårstø processes the rest of natural
gas produced in Norway, that is to say 52.6%.
We can observe an important difference between the two processing complexes. This can be
explained by three factors:
→ Kårstø started in 1985, Kollsnes in 1996. The difference of age of the equipments can
partly explain the difference of energy consumptions;
→ The Kollsnes unit processes gas from the Troll field, which contains less water and carbon
dioxide;
→ Moreover, more electricity is used in the Kollsnes plant when less natural gas is consumed.
Concerning the modelling of the chemicals, the used processes from ecoinvent database are
described below :
• Monoethylene glycol : “Ethylene glycol, at plant/RER” which includes precursors, transports
and infrastructure
• Methanol : “Methanol, at regional storage/CH” which includes raw materials, average
transport to Switzerland, emissions to air from tank storage, estimation for storage
infrastructure.
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• Ammonia : “Ammonia, liquid, at regional storehouse/CH” which mostly present state of the
art technology used in European ammonia production plants.
• Sodium hydroxide : “Sodium hydroxide, 50% in H2O, production mix, at plant/RER” which
includes process establishing an average European sodium hydroxide production from the
three different electrolysis cell technologies (mercury, diaphragm, membrane)
• Hydrochloric acid : “Hydrochloric acid, 30% in H2O, at plant/RER” which includes precursor
compounds, auxiliary materials, transports and infrastructure.
Even if the title of ecoinvent processes presents a dilution factor, the processes describe the
production of the pure chemicals. Without any information concerning the dilution level of the
different chemicals, these processes have been used directly without dilution factors.
5.1.4 Production and processing in the Netherlands
5.1.4.1 Production in the Netherlands
While its oil reserves in the North Sea are of little importance, the Netherlands is the second-
greatest natural gas producer in the European Union and the ninth greatest in the world,
accounting for more than 33% of EU total annual gas production in 2004. [16]
5.1.4.1.1 Main actors
NAM (Nederlandse Aardolie Maatschappij), a consortium of ExxonMobil and Royal Dutch Shell, is
now the largest gas producer in the Netherlands, with a production of around 57 bcm in
2004.
A little over half of this gas (31.6 bcm) comes from the Groningen field and the rest from various
smaller fields elsewhere on the mainland (13.6 bcm) and in the North Sea (12.1 bcm). Gas
produced by NAM covers around 75% of Dutch demand.
5.1.4.1.2 Major production fields
The onshore Groningen field, located in the north-east of the
country, accounts for about one-half of total Dutch natural gas
production; the remaining production is spread across small
fields both onshore and in the North Sea. The largest offshore
field is K15. NAM operates both K15 and the Groningen field.
Figure 26: Natural gas production in the Netherlands
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5.1.4.1.3 Collected data
Several sources of data have been studied:
→ Collected data come from the environmental report of NAM (2004) [24]. These data
cover therefore approximately 75% of Dutch gas production. The following data also
include gas processing and transmission from the offshore production fields to the onshore
processing plants.
→ The ecoinvent database [5]: the data used in the ecoinvent database stem from the
environmental report of NAM for the year 2001. These data also include gas processing and
transmission from the offshore production fields to the onshore processing plants. In the
ecoinvent database, a distinction has been made between offshore and onshore production.
The data of the NAM report are collected for onshore and offshore production; the
atmospheric emissions are allocated to the onshore respectively offshore production on the
basis of the energy content of the production. The processing stage is included in the data.
→ “Well-to-wheel analysis of future automotive fuels and power trains in the
European context”, LBST [20].
The following tables show the consumptions figures expressed as % of the natural gas produced
based on the energy content.
Rate and consumption in
MJ/MJ [20] [5] [24] This report –[24]
Fugitive emissions rate N/A 0.026% 0.020% 0.020%
Flaring rate N/A 0.090% 0.058% 0.058%
Combustion rate 0.60% 0.455% 0.416% 0.416%
Diesel consumption N/A 0.023% 0.034% 0.034%
Electricity consumption N/A 0.009% 0.137% 0.137%
Chemicals [20] [5] [24] This report –[24]
Methanol (kg/MJ) N/A 1.02E-6 1.01E-7 1.01E-7
TEG (kg/MJ) N/A 6.39E-7 1.61E-8 1.61E-8
Table 30: Collected data - Production and processing - the Netherlands
We may remark that the data on Dutch gas production are very consistent from a year to another
and from a source to another, except for chemicals consumptions. We consider the more recent
values: values from NAM 2004 report [24].
The processing data are included in the production data given by NAM. Independent data for
treatment processes are not available.
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Data presented in table 30 have already taken into account allocation between natural gas and oil
and condensates production. Impact allocation is based on the energy content of the various
coproducts, based on data collected from NAM.
Source : Statoil,
2004 [23] Volume produced LHV Density
Natural gas 5.74 1010 m3 34.9 MJ/m3
Oil and
condensates
1.15 106 m3 42.3 MJ/kg 840 kg/m3
Table 31: Data used for allocation
5.1.5 Production and processing in United Kingdom
Since 1997, the UK has been a net exporter of natural gas. However, as is the case with the
country's oil reserves, most natural gas fields have already reached a high degree of maturity, and
the UK government estimates that the country will again become a net importer of natural gas by
the end of the decade.
The UK produced 103 bcm of natural gas in 2003 according to the UK Department for Business
Enterprise & Regulatory Reform [25], the same as the previous year, but less than the peak value
of 109 bcm reached in 2000. The country is the fourth-largest producer of natural gas in the world,
behind Russia, the United States, and Canada.
5.1.5.1.1 Main actors
Most of the leading oil companies in the UK are also the leading natural gas producers, including
BP, Shell, and Total. The major gas distribution companies in the UK, such as Centrica and BG
Group, also have a presence in the production sector. Like the oil industry, smaller independents
have been able to acquire some maturing assets from larger operators, who find it difficult to
profitably operate these older, declining fields.
5.1.5.1.2 Production sites
The UK held an estimated 592 bcm of proven natural gas reserves in 2005, a 6 % decline from the
previous year. Most of these reserves occur in three distinct areas:
→ associated fields in the UK continental shelf;
→ non-associated fields in the Southern Gas Basin, located adjacent to the Dutch sector of the
North Sea;
→ non-associated fields in the Irish Sea.
The largest concentration of natural gas production in the UK is the Shearwater-Elgin area of the
Southern Gas Basin.
The area contains five non-associated gas fields, Elgin (Total), Franklin (Total), Halley (Talisman),
Scoter (Shell), and Shearwater (Shell). U.K. gas production is relatively concentrated with
the top ten fields representing around 50% of total production. The majority of these fields
are associated gas with only Morecambe North & South, Leman and Hamilton being dry gas fields.
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Figure 27: Natural gas production in Great Britain
5.1.5.1.3 Collected data
Several sources of data have been studied:
→ From the United Kingdom Offshore Operators Association [26] - the trade association
for the UK offshore oil and gas industry (UKOOA). Information on UKOOA members' total
emissions for 1999 covers five main emission streams. Within the Oil and Gas Industry,
emissions generally arise from generating the energy needed to carry out operations
offshore, from transporting the oil and gas, and from gases produced from the reservoir
but which cannot be marketed for technical reasons.
→ The ExternE national implementation report for Great Britain [27]: data comes from
the site of Caister in the UK North Sea Southern Basin (150 km away from the coast); little
information is available; only CO2 and methane emissions are given. Data also include
treatment and in-between transportation.
→ The ecoinvent database [5]: the figures consider production of oil and gas and transport
by pipeline to the coast. The multi output-process 'combined offshore gas and oil
production' delivers the co-products crude oil and natural gas. Allocation for co-products is
based on heating value. Data are from 1998-2000.
→ “Well-to-wheel analysis of future automotive fuels and power trains in the
European context“, LBST [20].
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Rate and consumption in
MJ/MJ [20] [5] [26] [27]
This report –
[26]
Fugitive emissions rate N/A N/A 0.046% 0.174% 0.174%
Flaring rate N/A N/A 0.9% 0.051% 0.051%
Combustion rate 0.50% 4% 3.08% 1.536% 1.536%
Diesel consumption N/A 0.481% N/A N/A 0.000%
Electricity consumption N/A N/A N/A N/A 0.000%
Table 32: collected data - Production and processing - Great Britain
Great differences can be seen between the different sources. In this report, we consider the
ExternE values [27], because they are really close from the Norwegian figures. Both fields are
situated in the North Sea, so we assume they have close consumptions and emissions.
Moreover a preliminary study shows that the choice of this specific fuel gas consumption over the
values stemming from ecoinvent or the UKOOA has a negligible impact on the global GHG
emissions (less than 4% of the GHG emissions associated with low pressure natural gas and less
than 1% after utilization).
Processing data are included in the production data given by the ExternE implementation report for
UK and no independent data for treatment processes have been found. As no information on
chemicals consumptions is available, chemicals consumptions for both production and
processing in UK is adapted from the Dutch context.
5.1.6 Production and processing in Germany
5.1.6.1 Production in Germany
In 2003, Germany produced 780 billion cubic feet (Bcf) of Natural Gas. The country is the third
largest producer in the EU, behind the United Kingdom and the Netherlands. [28]
5.1.6.1.1 Main actors
Private operators control Germany’s natural gas production. BEB, jointly owned by Royal Dutch
Shell and Esso (a subsidiary of ExxonMobil), controls about half of domestic natural gas production.
Other important players include Mobil Erdgas-Erdoel (also a subsidiary of ExxonMobil), RWE, and
Wintershall.
BEB is the largest natural gas producer in Germany and supplies some 20% of Germany's demand.
It is involved in the exploration and production, import, storage and transport of natural gas. BEB
is also involved in domestic oil production and sulphur production.
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5.1.6.1.2 Major production fields
Almost all of Germany’s natural gas reserves and production occur in the Northwestern state of
Lower Saxony, between the Wesser and Elbe rivers.
Germany’s sector of the North Sea also contains sizable natural gas reserves, currently supporting
the A6-B4 production project (see below). However, environmental regulations have curtailed the
complete exploration of the area.
The major German production fields are
Söhlingen (1980), Bötersen (1978),
Hemmelte (1980) Siedenburg/Staffhorst
(1963), Hemsbünde (1986), Visbeck
(1963), Hengstlage (1963),
Goldenstedt/Oythe (1959),
Klosterseelte/ Kirchseelte (1985) and
Mulmshorn/Borchel (1984).
Figure 28: Natural gas production in Germany
5.1.6.1.3 Collected data
Two sources of data have been studied:
→ The ecoinvent database [5]: the data were collected in the environmental report of BEB
(2001). Data of BEB is extrapolated for Germany. BEB produces about 50% of the German
natural gas. BEB produces as well oil and sulphur out of sour gas. Data in the
environmental report is already allocated to gas. About 50% of the produced gas is sour.
The processing of gas is already included in the ecoinvent process, by including chemicals
consumption for Netherlands (NAM 2001 [5]). Emissions due to the use of natural gas as
energy source and of the flares are included. Based on the environmental report of the
company RWE, which also produces gas in Germany, the part of electricity in energy used
is assumed to be 20%.
→ BEB environmental reports [29]: both BEB environmental reports that have been found
concern BEB production in Germany as well as outside of Germany. It is therefore
impossible to allocate the declared emissions to one country or another.
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Rate and consumption in
MJ/MJ [5] – For production only This report – [5]
Fugitive emissions rate 0.048% 0.048%
Flaring rate 0.084% 0.084%
Combustion rate 0.397% 0.397%
Diesel consumption N/A 0.000%
Electricity consumption 0.099% 0.099%
Chemicals For dehydration [5] This report [5]
Methanol (kg/MJ) 1.01E-6 1.01E-6
TEG (kg/MJ) 6.24E-7 6.24E-7
Table 33: Collected data - Production and processing – Germany
In this report, we therefore use the ecoinvent values, expressed as % of the natural gas
produced based on the energy content. Sweetening has been excluded from the ecoinvent process
in order to distinguish impacts due to production and impacts due to sweetening.
5.1.6.2 Sweetening in Germany
5.1.6.2.1 Major existing plants
About 50% of the German gas reserves contain varying concentrations of hydrogen sulphide that
has to be removed before it can be put to commercial use. BEB therefore operates a gas
desulphurisation plant at Grossenkneten located
south of the city of Oldenburg. At the plant the
hydrogen sulphide is removed from the natural gas
and then converted to elemental sulphur. Emissions
result from gas sweetening plants only if the acid
waste gas from the amine process is flared or
incinerated. Most often, the acid waste gas is used as
a feedstock in nearby sulphur recovery or sulphuric
acid plants.
Figure 29: Aerial view of Grossenkneten desulphurisation plant
5.1.6.2.2 Collected data
Data concerning the dehydration are included in the production figures. The data collected by
ecoinvent for sweetening come from the Grossenkenten plant (2001). Looking into the detailed
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inventory of ecoinvent, according to our interpretation, some inconsistency appears between
emissions and energy consumption (Table 34 and 35)4.
4 During the study, ecoinvent (Mireille Faist-Emmennegger, in charge of the ecoinvent database on natural gas) has been contacted to discuss those data. Following this discussion, the ecoinvent centre published changes on its process “Sweetening, natural gas DE, [Nm3]” in the following report: “Documentation of changes implemented in ecoinvent Data v1.2 and v1.3” [30]. A flaring rate of 3.25% was considered but ecoinvent did not detail the changes made in their report. Yet it was not possible to fully understand the calculations used in ecoinvent.
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General informations Source Comments
Assumptions
[1] Volumic mass (after treatment) 0,76 kg/m3[2] Methane content (after treatment) 0,69 kg/m3[3] CO2 content before treatment 0,1 kg/m3 ecoinvent, 2003, Table 3.4[4] CO2 content after treatment 0,002 kg/m3[5] LHV (after treatement) 35 MJ/m3[6] EF in flares, sour - SO2 4,86E-03 kg/MJ[7] EF in flare - CO2 0,056 kg/MJ
Energy consumptions
[8]Natural gas, sour,burned in gas turbine
0,944 MJ/Nm3 ecoinvent, 2003, Table 6.53
If ecoinvent EF for SO 2 is applied to this natural gas consumption,SO 2 emissions should be as high as 4,59E-3 kg/Nm 3. As data from Gossenkneten give SO 2 emission of 7,21E-4 kg/Nm 3 at the plant, we have decided to assume that part of the gas burned is sour and part of it is sweet, in order to be coherent with the plant SO 2
emission level.
Emissions
[9] CO2 total emissions 0,149 kg/m3 ecoinvent, 2003, Table 6.53
[10] Direct CO 2 emissions 0,098 kg/m 3 deduced: [3]-[4]Assumption: CO 2 removed from the raw gasis released after solvant regeneration on the same site.
[11]CO 2 from flaring& natural gas consumption
0,051 kg/m 3 deduced: [9]-[10]Consistent with EF of CO 2 and amount of natural gas burned in gasturbine ([7]*[8]=0,053 kg/Nm 3).
[12] CH4 0,00002 kg/m3 ecoinvent, 2003, Table 6.53[13] SO2 0,000721 kg/m3 ecoinvent, 2003, Table 6.53
Chemical consumption
[14] Organic chemicals 2,65E-06 kg/Nm3ecoinvent, 2003, Table 6.53
Energy consumptions (% of natural gas sweetened)
[15] Vents 0,003% deduced: [12]/[2][16] Fuel gas consumption & flaring 2,697% deduced: [8]/[5][17] Of which sour gas 0,42% deduced: ([13]/[6])/[5][18] Of which sweet gas 2,27% deduced: [16]-[17][19] Diesel consumption 0% ecoinvent, 2003, Table 6.53[20] Electricity consumption 0% ecoinvent, 2003, Table 6.53
ecoinvent, 2003, Table 3.6
ecoinvent, 2003, Table 3.6
ecoinvent, "natural gas,sour, burned in production flare"
Data from Grossenkneten plant (BEB, 2001), in use since 1972.Part of the emissions are due to change in gas compositionduring CO2 removal
Table 34: Data used for the calculation of energy consumption and emissions at the sweetening step – Germany
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As we think that the flaring rate proposed in the updated version of ecoinvent (3.25%) is
overestimated, we deduced the energy consumptions from our own interpretation of the
BEB 2001 figures. We considered a global autoconsumption rate of 2.697% as deduced by
ecoinvent from BEB data. We calculated the part of sweet and sour gas burned on Grossenkneten
installations from the SOX emissions indicated in the BEB report [5]: 84% of the gas burned is
sweet and only 16% is sour. We allocated the global consumption rate to flares to be in accordance
with the value for total SOX emission given by BEB, based on the SO2 emission factor. This choice
may have an important impact on the acidification results and a sensitivity analyse will be
performed in a following part.
The following table present the collected data from the ecoinvent database (BEB 2001).
Rate and consumption in
MJ/MJ [5] This report – [5]
Fugitive emissions rate 0.003% 0.003%
Flaring rate 3.25% 2.697%
Combustion rate 2.697% N/A
Diesel consumption N/A N/A
Electricity consumption N/A N/A
Table 35: Collected data - Sweetening – Germany
More recent data have not been found. Therefore this data will be used in our study.
An allocation based on the energy content between natural gas and sulphur produced
during sweetening has been studied.
Indeed, the LHV of sulphur is around 9 MJ/kg5, and with hypotheses from ecoinvent database, the
sour gas contains 0.084 kg of sulphur per Nm3 of sour natural gas6.
With those assumptions, the allocation between natural gas and sulphur in Germany is
98% for natural gas and 2% for sulphur.
The same order of magnitude could be found with economical allocation.
Thus, it has been decided not to take into account allocation between natural gas and sulphur.
5 http://www.eia.doe.gov/cneaf/coal/quarterly/co2_article/co2.html 6 Sulphur total = Sulphur before sweetening – sulphur after sweetening – emission of SO2 during sweetening
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5.1.7 Production and processing in Italy
5.1.7.1 Production in Italy
Italy has proved natural gas reserves estimated (as of January 2005) at about 5-8 trillion cubic
feet (tcf), which is less than a twenty-year supply at current production rates. Italy is the world's
ninth-greatest consumer of natural gas (and third-greatest in the EU), accounting for about 2.8%
of the world's annual natural gas consumption.
5.1.7.1.1 Main actors
Eni controls over 90% of Italy's domestic natural gas
production, with the company reporting that it
produced 432 bcf in 2003. Another actor of the Italian
gas production is Edison.
5.1.7.1.2 Major production fields
Almost half of the company's production comes from
offshore fields in the Adriatic Sea, including Barbera,
Porto Garibaldi/Agostino, Angela/Angelina,
Cervia/Arianna, and Porto Corsini Mare Ovest. The
company also operates the Luna field in the Ionian
Sea, which produced 35 Bcf in 2003. In 2005, Eni
planned to bring additional offshore fields on-stream,
including Panda, off the coast of Sicily, and the
Tea/Arnica/Lavanda project in the Adriatic Sea.
5.1.7.1.3 Collected data
Three sources of data have been studied:
→ The Eni environmental report (2004) [31]. The data concern not only the Italian gas
production but also the Eni production outside Italy. The Italian gas production represents
only 32% of the total world gas production for Eni. Moreover, data are aggregated and
difficult to use.
→ An EniTecnologie publication, “tpoint”, from January 2005 [32]: the article presents
the results of an LCA of the natural gas used in Italy in 2005. These data were given for
each production land, like Italy. These data are therefore considered as better quality and
more complete than the data available in the Environment report of Eni. These data also
include the processing steps and transmission of the gas from the production fields (often
offshore fields) and the Italian mainland. No information on chemicals consumptions is
available.
→ The ExternE national implementation report for Italy [33]: data are given by AGIP
(Eni) on the production in the Adriatic Sea (offshore gas fields of Barbara) and the
treatment in the Falconara plant. In-between transport by pipeline over a distance of 60
km is included.
Figure 30: Natural gas production in Italy
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Rate and consumption in
MJ/MJ [32] [33] This report - [32]
Fugitive emissions rate 0.094% N/A 0.094%
Flaring rate 1.989% 1.602% 1.989%
Combustion rate
Diesel consumption N/A N/A 0.000%
Electricity consumption N/A N/A 0.000%
Table 36: Collected data - Production and processing - Italy
Collected data show close values for production and treatment in Italy. We consider the more
detailed values of “tpoint” [32]. As no information on chemicals consumptions is available,
chemicals consumptions for both production and processing in Italy are adapted from the Dutch
context.
5.1.8 Production and processing in Algeria
5.1.8.1 Production in Algeria
Algeria is a significant producer of natural gas and liquefied natural gas (LNG). Algeria had the
eighth-largest natural gas reserves in the world. [17]
5.1.8.1.1 Main actors
Sonatrach dominates natural gas production and wholesale distribution in Algeria, while another
state-owned company, Sonelgaz, controls retail distribution.
5.1.8.1.2 Major production fields
Algeria's largest gas field is the super-giant Hassi
R'Mel, discovered in 1956 and holding proven
reserves of about 2,4 Tcm. Hassi R'Mel accounts
for about a quarter of Algeria's total dry gas
production.
Figure 31: Natural gas production in Algeria
The remainder of Algeria's gas reserves, both
associated and non-associated fields, are located
in the south and southeast regions of the country:
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→ In South-eastern Algeria, the Rhourde Nouss region holds 368 bcm of known reserves in
the Rhourde Nouss, Rhourde Nouss South-east, Rhourde Adra, Rhourde Chouff, and
Rhourde Hamra fields;
→ Also in South-eastern Algeria, near the Libyan border, the In Amenas region contains the
Tin Fouye Tabankort, Alrar, Ouan Dimeta, and Oued Noumer fields;
→ The In Salah region in southern Algeria holds smaller, less-developed reserves.
5.1.8.1.3 Collected data
Data concerning gas production in Algeria can be highly variable, particularly on methane
emissions and flaring rate on production fields. No emissions measurement campaign has
been realized at this day.
Three sources of data have been studied:
→ The ecoinvent database [5]: data on the Algerian gas production are deduced from data
from others countries by analogies. ecoinvent data include gas exploration and production
onshore. Data for Algeria is mostly based on standard data, because only little information
is available as it is the case for Russia. Data is based on average data and therefore not
specific for the country,. Leakage in exploitation and production comes from different
literature sources from several counties relevant from the 90’s. It is estimated at 0.06% for
exploitation and 0.13% in processing. Thus, the global leakages rate used in ecoinvent for
natural gas production and processing in Algeria is 0.19%. Energy demand is based on
2000 Norwegian data, quantity of flared gas on 1991 German data, leakages on 1990
respectively 1989 German data for exploitation respectively processing.
→ The study from the Wuppertal Institute (2004) [19] gives a leakages rate of 0.11% for
the production in Russia. We extended this fugitive emission rate to the production in
Algeria.
→ “Well-to-wheel analysis of future automotive fuels and power trains in the European
context“, LBST [20].
Rate and consumption in
MJ/MJ [20] [5] [19]
This report –
[5], [19]
Fugitive emissions rate N/A 0.19% 0.11% 0.11%
Flaring rate N/A 0.250% N/A 0.250%
Combustion rate 1.2% 1.059% N/A 1.059%
Diesel consumption N/A 0.118% N/A 0.118%
Electricity consumption N/A N/A N/A 0.000%
Table 37: Collected data - Production and processing - Algeria
As there are no real differences between the three sources of literature, we consider that the
ecoinvent data are representative of the Algerian situation. In this report, we use the ecoinvent
data, except for the leakage rate that is adapted from the values used for Russia,
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because the study is more recent. [19]. Both studies show the same order of size for leakages
rates during production and processing (0.11% [19] versus 0.19% [5]).
5.1.8.2 Treatment in Algeria
Hassi R'Mel gas is wet. 100% of the gas has to be dehydrated. Hassi R'Mel has processing facilities
installed mostly in the 1970s and 1980s.
No data has been found on the specific unit of Hassi R’Mel. We therefore adapt the values of the
Norwegian dehydration units to the Algerian context. The Kårstø unit being more aged (Kårstø
started in 1985, we assume that the Algerian treatment plant presents the same efficiency and
emissions than the Kårstø one.
Remark: fugitive emissions and leakages considered during the processing steps adapted from
Kårstø are added to the leakages rate for production and processing considered here (0.11%). This
could be considered as a double counting. However, due to the uncertainty of the leakages values
in Algeria, we consider the leakages rate for production and processing for the production step and
add the leakages rates for processing. Moreover, leakages rate considered for processing in
Norway are much lower. Thus, the global leakages rate for processing and production in Algeria is:
0.11% +0.006% = 0.116%.
5.1.9 Production and processing in Nigeria
Data are taken from the ecoinvent database [5]. They stem from two different companies
operating in Nigeria and concern mainly onshore production in the Niger delta and a small part of
offshore production. They relate to the years 1999-2000.
Rate and consumption in
MJ/MJ [5] This report – [5]
Fugitive emissions rate 1.850% 1.850%
Flaring rate 10.130% 10.130%
Combustion rate 2.987% 2.987%
Diesel consumption N/A 0.000%
Electricity consumption N/A 0.000%
Chemicals (kg/MJ) [5] This report [5]
Chemicals organics 1.96E-8 1.96E-8
Chemicals inorganics 2.62E-8 2.62E-8
Table 38: Collected data - Production and processing - Nigeria
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5.1.10 Production and processing in Qatar, Oman and Libya
Qatari, Omani and Libyan LNG imports represent less than 1.5% of the natural gas consumed by
EU-25 countries (see §4). As little or no information is available on gas production and processing
in these different countries, some simplifications are made: production and processing steps as
well as the transmission to liquefaction unit are adapted from the Algerian gas chain (see 5.1.8).
5.1.11 Summary of the production and processing step
A table presenting all the data used for the inventory of the production and processing step is
presented in the appendix 6.
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5.2 Transmission by pipeline
5.2.1 General data: energy consumption estimation
Natural gas has to be recompressed every 100-150 km to avoid pressure drop.
To estimate energy consumption during transmission by pipeline, three sources of data have been
studied:
→ The ecoinvent 2.0 database [5]: several studies have been collected and studied in this
database, giving a range of energy consumption for pipeline transmission from 1.4%/1,000
km to 3%/1,000 km. Two different cases have been considered in the ecoinvent database:
o Transmission from Russia to Europe with a global energy consumption of
2.7%/1,000 km on the overall distance from Russia to Europe – including the
transit through countries like Ukraine, Poland or Belarus.
o Transmission from European Countries – the Netherlands, Great Britain, Norway
and Germany - to Europe with a global energy consumption of 1.8%/1,000 km.
→ The “Well-to-wheel analysis of future automotive fuels and power trains in the
European context“, LBST [20].
→ Internal calculations based upon standard calculations. A different approach is used:
for each transit country, energy consumption is calculated based on the efficiencies of
compressors used.
o In Russia, according to the Gazprom/VNIIGAZ study, installed compressors have
efficiency of about 24-28%. That is low in comparison with the efficiency of modern
compressors [19].
o In Ukraine, according to Naftogaz, installed compressors have efficiency of about
30-34%.
o In Western Europe, installed compressors are supposed to have efficiencies of
about 34-38% or even 40% [5].
Consumption rates per 1,000 km are deduced from the efficiency of compressors used
using standard formulas based on a compression ratio of 1.4 (Pressure out of compressor
station/Pressure in compressor station = 70/50=1.4).
From these three countries, we defined a model of energy consumption for natural gas
transmission based on analogies between the considered countries. Three zones have been
delimited as shown on the following map. The first zone, supposed to have a transmission
network similar to the Russian network, includes Russia, African and Middle Eastern
countries (Algeria, Libya, Nigeria, Oman and Qatar); the second zone, whose network is
assimilated to the Ukrainian network, includes Eastern and Central Europe countries, the
third zone includes west European countries.
The hypotheses concerning the efficiencies of compressors in Africa assimilated to the
Russian performances and the efficiencies of compressors in Western Europe (34-38%) can
be considered as rather conservative. On the other hand, the assumption adopted for the
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Central and Eastern European countries can overestimate the real efficiency of their
networks as some of these countries have a limited amount of money to invest into their
infrastructures. A sensibility analyses on this parameter is performed in a following part.
There are three types of compressors during transmission: the gas turbines, the gas motors and
electric engines. Two kinds of energy may thus be used for compression during natural gas
transmission: natural gas or electricity. The shares of utilisation of these three types of compressor
have been collected. When no data were found, it was decided to use a default value, i.e. to
consider that all compressors are driven by gas turbines (cf. Appendix 3).
Remark: Data are adapted to each transit countries by using the national electricity mix given in
the ecoinvent database or found on the World perspective website [36] to power the compressors
when necessary.
Figure 32: Map of energy consumption for compression during transmission by pipeline
5.2.2 General data: leakages during transmission by pipeline
5.2.2.1 Values chosen for leakages rate in Russia and Eastern Europe
There are numerous studies on the Russian transmission system [35]:
→ In the framework of the World Bank financed project "Gas Distribution
Rehabilitation and Energy Efficiency Project", a preliminary report gives a mass
balance for the Russian gas industry from 1992 to 2000. According to this report, methane
leakages during gas transport in Russia reached 3% in 2000.
→ In 1995, the EPA and Gazprom conducted a joint measurement program at four
compressor stations in the Saratov and Moscow regions. The main goal of this
program was to start improving methane emission estimates from the transmission
segment and test the applicability of the EPA emission estimating methodologies in Russian
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conditions. Another goal was to identify profitable ways to reduce natural gas losses. Under
the program, preliminary estimates of compressor methane emissions were developed. EPA
and Gazprom estimated emissions in billion cubic meters of methane only for Russian
compressor stations. Their total estimate is 2.1 bcm. It does not cover compressor exhaust
or engine start and stop emissions and, therefore, total emissions may be higher. EPA and
Gazprom provided a detailed report of their project, including component counts, as well as
calculated preliminary emission and activity factors for many compressor station
components.
→ In 1996 and 1997, Gazprom and Ruhrgas conducted measurements on two
pipelines and two compressor stations in the Tyumen and Volgograd regions, and
on three gas processing plants in the Tyumen region and then extrapolated the results to
the whole sector. They provided estimates for different segments of the sector, as well as
an estimate for the whole sector. These estimates are available in several articles, but no
publication provides detailed information on the number of components covered by
measurements in each segment or the number of measurements conducted. Gazprom and
Ruhrgas estimated emissions from compressor stations as 3.1-3.7 bcm of which leaks
comprised 2.1 bcm and intentional emissions comprised 1-1.6 bcm. For pipelines and gas
processing facilities these estimates were 1.15 and 0.1 bcm respectively. Gazprom and
Ruhrgas included information about the extrapolation methodology they used, but did not
estimate any emission and activity factors.
→ On behalf of E.on Ruhrgas, the Wuppertal Institute for Climate, Environment and
Energy and the Max Planck Institute for Chemistry conducted a measurement
campaign on the network of three of subsidiaries of Gazprom between 2003 and
2005. According to this study, fugitive emissions represent approximately 1% to the
German border. Taking uncertainties into account, they also indicate a range of fugitive
emissions rate between 0.6% and 2.4%. A well-documented report is publicly available:
“Greenhouse Gas emissions from Russian natural gas export pipeline system – Results and
extrapolations of measurements and surveys in Russia” [19].
Table 39: Leakage rates during international transmission by pipeline from Russia to Europe
In this report, we consider the mean value indicated by the Wuppertal Institute in 2005,
because they are the more recent data and stem from direct measurements of gas operators.
However, this point is highly sensitive in estimating the impact of the natural gas upstream chain.
Rate in MJ/MJ Gazprom/
EPA (1995)
Gazprom/
Ruhrgas
(1997)
World Bank
financed
project
[5] [19] This report
– [19]
Fugitive emission rate during
transmission by pipeline 0.36 % 1.2% 3% 1.4%
0.6% to
2.4% 1%
Fugitive emission rate during
international transmission by
pipeline over 1,000 km
N/A 0.17% N/A 0.23% 0.18% 0.18%
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Even the Wuppertal Institute indicates a wide range of possible values for leakages rate in Russia
(from 0.6% to 2.4%). Therefore, we perform a sensitivity analysis at the end of the report.
5.2.2.2 Value for EU-25 countries
Several sources have been compared:
→ The environmental performance indicators (EPI) collected by Marcogaz: several
European companies gave their leakage rate and an average of this information weighted
with the transported volume of natural gas is given in the table below. They are also
available in the IGU report “Natural gas - Toward a global life cycle assessment” [37].
→ The ecoinvent 2.0 database [5]: calculations are based on German data (Ruhrgas 2001).
Table 40: Leakage rates during international transmission by pipeline from European countries to
Europe
Both sources are consistent. We consider the data from EPI [37] because they are more recent and
refer to several gas companies in Europe whereas ecoinvent only refers to Ruhrgas.
5.2.2.3 Extrapolation of leakages rates
The following map presents the leakages rate used in European and transit countries for the
pipeline transmission. We differentiate Western Europe and Central Europe, which is assimilated to
the ex-USSR countries. Indeed, the leakages rate indicated in the Wuppertal Institute study [19]
concerns
both Russia
and Central
Europe :
leakages
are
calculated
from Russia
to the
German
border.
Figure 33: Map of leakage rates during transmission by pipeline
Rate in MJ/MJ [37]EPI [5] This report –
[37]EPI
Fugitive emission rate during international
transmission by pipeline over 1,000 km 0.019% 0.026% 0.019%
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We have assimilated the African and Middle East transmission networks to the Russian/Eastern
Europe networks as a conservative assumption.
5.2.3 Estimation of transmission distances
5.2.3.1 Export from Russia
Russian gas is mainly produced in the
Siberian-Ural region. Two main
corridors, operated by regional gas
companies that belong to Gazprom,
export Russian gas to Europe:
the Northern Corridor covering a
distance of 3,075 km from Russia to
Western Europe through Belarus;
the Central corridor covering
3,376 km from Russia to Western
Europe through Ukraine [19].
Figure 34: Transmission pipelines
from Russia
Different transportation routes for natural gas have been studied by the European Regulators’
Group for Electricity and Gas and the assessment summary gives useful information regarding
pipeline lengths in some transit countries [38]. When no information has been found, pipeline
lengths have been measured on a pipeline map [39].
5.2.3.2 Export from Norway
Norwegian state-owned limited company, Gassco, operates numerous natural gas pipeline connects
with continental Europe and UK. Some connections run from production facilities directly to
receiving terminals in export markets, while others connect Norway's onshore processing facilities
to these markets.
Many pipelines run through riser platforms in the North Sea, hubs that allow different pipeline
systems to interface and provide pressure regulation and quantity metering; the most important
platforms are the Draupner, Sleipner, and Heimdal platforms [40].
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Figure 35: Transmission pipelines from Norway
5.2.3.3 Export from the Netherlands
As the onshore Groningen field accounts for about one half of total Dutch natural gas production,
we consider that the onshore production entirely comes from Groningen. The Groningen field is
about 40 km from the German border and about 400 km from the Belgium border [41].
5.2.3.4 Export from UK
Two main pipelines link UK with its importers:
→ The Interconnector, from Bacton, England to Zeebruge, Belgium. It is operated by a
consortium of companies, led by BG, Ruhrgas, and Distrigas. It is 230 km long and its
current export capacity from the UK is 1.9 Bcf per day [42]. It can be used reverse flow to
import or export gas to/from the UK.
→ The UK-Eire Interconnector, connecting Moffat, Scotland with Dublin, Ireland [43].
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Without any information on the specific provenance of UK exports, we assume that all the gas
arriving at Bacton is exported to continental Europe via the Interconnector. Gas to be exported to
Ireland is considered as coming from St Fergus and Teesside facilities.
5.2.3.5 Export from Germany
Almost all of Germany’s natural gas reserves and production occur in the Northwestern state of
Lower Saxony, between the Weser and Elbe rivers. Transmission distances from production field to
importing countries have been estimated on a pipeline map [39].
5.2.3.6 Export from Algeria
Algeria's domestic pipeline system is centred on the Hassi R'Mel gas field. The largest pipeline
systems connect Hassi R'Mel to liquefied natural gas (LNG) export terminals along the
Mediterranean Sea.
→ a 507 km-long pipeline runs from Hassi R'Mel to Arzew,
→ a 579 km -long system connects Hassi R'Mel to Skikda.
Figure 36: Transmission pipelines in Algeria
Without any information on the volume of natural gas from Hassi R'Mel going to Arzew and Skikda,
the highest value for transmission distance (579 km) is used for the calculations. It is
therefore a pessimistic value.
Regarding international exports, two natural gas pipelines connect Algeria and Europe:
→ the 1078-km Trans-Mediterranean (Transmed, also called Enrico Mattei) line runs from
Hassi R'Mel to mainland Italy, via Tunisia and Sicily [45];
→ the 1609-km, Maghreb-Europe Gas pipeline(MEG, also called Pedro Duran Farell)
completed in 1996 and operated by an international consortium, led by Spain's Enagás,
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Morocco's SNPP, and Sonatrach. It connects Hassi R'mel with Cordoba, Spain via
Morocco [46].
5.2.3.7 Summary for data used by transmission by pipeline
5.2.3.7.1 Summary for transport distances
According to the modelling adopted in our study, the transport distances for natural gas imported
to the EU-25 countries are summed up in the following table. National transmission (e.g. from
German production site to the German consumer) is not included in this part but is the object of a
following paragraph (see §0).
UK Germany Netherlands Norway Russia Algeria
Austria 848 2,090 5,062
Belgium 703 400 400 1,382 6,111
Czech Republic 1,890 5,062
Denmark
Finland 3,139
France 845 560 1,408 5,930
Germany 990 40 1,106 4,845
Greece 5,392
Hungary 1,184 4,592
Ireland 687
Italy 1,049 2,227 5,442 1,078
Latvia 3,187
Lithuania 3,779
Luxembourg 600
Netherlands 783 200 1,162 6,159
Poland 456 1,730 3,699
Portugal 1,873
Slovakia 4,592
Slovenia 5,325 2,502
Spain 2,568 1,313
Sweden 720
United Kingdom 917 710 356
Table 41: Transmission distances to Europe in km– Summary
5.2.3.7.2 Summary for energy consumption and leakages
The following table summarize the data used for energy consumption and fugitive rate during the
transmission by pipeline. In order to get further details about the countries concerned by the three
areas used in the table, refer to the figures 31 and 32.
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Western
Europe
Central and
Eastern Europe
Russia and
Africa
Energy consumption (MJ/MJ for 1000 km) 2,05% 2,3% 2,84%
Fugitive emission rate during international transmission
by pipeline over 1,000 km (MJ/MJ) 0,019% 0,18%
Table 42: Energy consumption and fugitive rate during transmissions – Summary
5.3 Liquefaction
5.3.1 Main actors – LNG exporters
With the start-up of the Arzew GL4Z plant in 1964, Algeria became the world's first producer of
liquefied natural gas (LNG) and it is the second largest exporter of LNG (behind Indonesia), with
around 17% of the world's total. Most of Algeria's LNG exports go to Western Europe, especially to
France. Sonatrach has LNG export contracts with Gaz de France, Belgium's Distrigaz, Spain's
Enagás, Turkey's Botas, Italy's Snam Rete Gas, and Greece's DEPA. In 2003, Algeria exported 53.4
Bcf of LNG to the United States, representing about 11% of total U.S. LNG imports. Algeria's
largest LNG export terminal is the Arzew facility, whose two facilities produce a combined 840
Bcf/d of LNG. Other important terminals include Skikda (275 Bcf/d) and Algiers.
Country Lead plant operator Start-up date
Algeria
Arzew GL1Z Sonatrach 1978/1997
Arzew GL2Z Sonatrach 1981
Arzew GL4Z Sonatrach 1964
Skikda GL 1K Sonatrach 1972/1981
Libya Marsa el Brega Sirte Oil Company 1970/1993
Nigeria Bonny Island Nigerian LNG Ltd 1999
Bonny Island train 3 Nigerian LNG Ltd 2002
Oman
Qalhat 1 Omani government, ONGC,
and Union Fenosa
2000
Qalhat 2 2000
Qalhat 3 2006
Qatar Two trains Qatargas, Rasgas 1998
Table 43: Main liquefaction facilities in the European natural gas upstream chain [47]
5.3.2 Collected data
Four sources of data have been studied:
→ A Sonatrach publication on the LNG1 plant revamping project [48]: the Liquefied Natural
Gas complex GL.1Z is situated in the industrial area of Arzew, on Algeria’s north west
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coast. The complex GL.1Z uses the APCI Multi Component Refrigerant (MCR) process. As
discussed earlier, renovation of GL.1Z LNG Complex was necessitated since the grass root
Plant commissioned in February 1978, never achieved its design production capacity. With
the aim of simultaneous improvement in Algeria’s economic condition, to meet the
customer’s demand and to further augment Algeria’s contribution in the competitive world
LNG trading, Sonatrach initiated and successfully completed the renovation of GL.1Z
Liquefied Natural Gas Complex with all six trains in operation with effect from 5 May 1997.
→ The IGU report “Natural gas - Toward a global life cycle assessment” [37]. This report is
the result of a group of IGU’s studies during the Dutch Triennium 2003-2006. The aim was
to perform a life cycle assessment of the natural gas chain and collect data from industries
on consumptions and emissions along the life cycle of natural gas. The report describes the
initiation of the life-cycle inventory. Data are given for several countries such as Nigeria,
Qatar and Oman.
→ The ecoinvent database [5]: the process is normalised on the gaseous form of natural
gas. Data on energy used for the liquefaction stems from a reference book published in
1999 (Cerbe et al. 1999).
→ The “Well-to-wheel analysis of future automotive fuels and power trains in the European
context“, LBST [20].
The following table sums up the various data obtained for liquefaction facilities in different
countries.
Rate and consumption in
MJ/MJ
Algeria Oman Nigeria Rasgas Qatargas
[5] [20] [48] [37] [37] [37] [37]
Fugitive emissions rate N/A 0.01% N/A N/A N/A N/A N/A
Flaring rate N/A N/A N/A 0.2% 0.4% 0.3% 0.4%
Combustion rate N/A N/A N/A N/A N/A N/A N/A
Global gas
autoconsumption 15.00% 13.00% 15.00% 9.90% 11.50% 12.50% 12.90%
Diesel consumption N/A N/A N/A N/A N/A N/A N/A
Electricity consumption N/A N/A N/A N/A N/A N/A N/A
Table 44: Collected data - Liquefaction
For Algeria, Sonatrach data [48] have been preferred. Concerning Nigeria, Qatar and Oman, data
from the IGU report have been used [37]. No specific data about Libya were found: an average fuel
gas consumption value of 12.9% was used.
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Remark: supplies from Norway as LNG out of the Snøhvit liquefaction facility will begin in 2008.
Thanks to the technology of this new facility and the weather conditions in Norway, fuel
consumption rate in this unit will be reduced to 6%.
5.4 Transportation of LNG
5.4.1 Transmission by pipeline before liquefaction
Before liquefaction, the gas has to be transported from the production field to the liquefaction
plant.
Country Gas fields Facility Pipeline length
(km) Source
Algeria Hassi R’Mel Skikda 579
[46] Arzew 507
Nigeria Obiafu/Obikrom,
Obite, Soku Bonny Island 134 [49]
Qatar North Gas field Ras Laffan 92 [50]
Oman Saih Rawl Qalhat 352 [51]
Libya Depa Marsa El Brega 120 [52]
Table 45: Transmission by pipeline from fields to liquefaction facilities
Concerning the modelling of energy consumption and fugitive emissions, the data described in 5.2
have been used. For reminders, they were detailed below :
Africa
Energy consumption (% in MJ/MJ for 1000 km) 2,84%
Fugitive emission rate during international transmission
by pipeline over 1,000 km (% in MJ/MJ for 1000 km) 0,18 %
Table 46: Energy consumption and fugitive rate during transmissions
5.4.2 Sea transportation
Since the Methane Princess and Methane Progress were built in 1964, all LNG ships have generated
most of their power, for both propulsion and ship services, through steam boilers. The steam has
driven both the main engines and the generators as well as powering many auxiliaries
(compressors, pumps, fans, etc.) and providing the heat source for fuel tanks, air conditioning, etc.
In the same period of time, we have seen the development of dual-fuel diesel-electric power
generation on many ship types. These power generation solutions have been taken up and
developed by the world’s major naval fleets, to the exclusion of steam power. Only the Century,
providing Greece with Algerian LNG, uses diesel engine.
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Remark: in our study LNG carriers with diesel-electric propulsion are not taken into account as of
the fleet in 2004.
5.4.3 Fleet of LNG tankers providing Europe
The following table lists all the operating LNG tankers providing Europe, as well as their
characteristics. It should be noted that in 2005, the fleet was mostly composed of vessels with a
propulsion system based on steam turbine (only one vessel with a diesel engine).
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Ship Name Ship-owner Delivery Power Plant Cargo System Capacity
(cu.m.) Original exporter Charterer Primary Trade Route
Methania Distrigas 1978 S GT NO 85 131,235 Sonatrach Suez LNG Algeria-Spain
Descartes Messigaz 1971 S TZ Mk. I 50,000 Sonatrach Gaz de France Algeria-France
LNG Lagos Bonny Gas Transport 1976 S GT NO 85 122,000 Nigeria LNG Enagás/GdF/BOTAS Nigeria-Spain/France
LNG Port Harcourt Bonny Gas Transport 1977 S GT NO 85 122,000 Nigeria LNG Enagás/GdF/BOTAS Nigeria-Spain/France
Mourad Didouche SNTM-Hyproc 1980 S GT NO 85 126,130 Sonatrach Suez LNG Algeria-Belgium
Ramdane Abane SNTM-Hyproc 1981 S GT NO 85 126,130 Sonatrach Gaz de France Algeria-France
Edouard L.D. Dreyfus/Gaz de France 1977 S GT NO 85 129,299 Sonatrach Gaz de France Algeria-France
Tellier Messigaz 1974 S TZ Mk. I 40,081 Sonatrach Gaz de France Algeria-France
Hassi R'Mel SNTM-Hyproc 1971 S GT NO 82 40,850 Sonatrach Various
Isabella Chemikalien Seetransport 1975 S GT NO 82 35,500 Sirte Oil Enagás Libya-Spain
Annabella Chemikalien Seetransport 1975 S GT NO 82 35,500 Sirte Oil Enagás Libya-Spain
Cinderella Taiwan Marine 1965 S Worms 25,500 Sirte Oil Enagás Libya-Spain
LNG Palmaria ENI 1969 S Esso 41,000 Sonatrach ENI Algeria-Italy
LNG Elba ENI 1970 S Esso 41,000 Sonatrach Gaz de France Algeria-France
LNG Portovenere ENI 1996 S GT NO 96 65,000 Sonatrach ENI Algeria-Italy
LNG Lerici ENI 1998 S GT NO 96 65,000 Sonatrach ENI Algeria-Italy
Century Bergesen WG 1974 D Moss 29,588 Sonatrach DEPA Algeria-Greece
Norman Lady Hoegh LNG 1973 S Moss 87,600 Atlantic LNG Enagás Trinidad-Spain
Khannur Golar LNG 1977 S Moss 126,360 QatarGas British Gas Qatar-Spain
Laieta Auxiliar Maritima 1970 S Esso 40,000 Sonatrach Enagás Algeria-Spain
Castillo de Villalba Elcano 2003 S GT NO 96 138,000 Sonatrach Enagás Algeria-Spain
Cadiz Knutsen Knutsen/Marpetrol 2004 S GT NO 96 138,826 Engas Union Fenosa Egypt-Spain
Madrid Spirit Teekay LNG Partners 2005 S GT NO 96 138,000 Engas Repsol/YPF Egypt-Spain
Catalunya Spirit Teekay LNG Partners 2003 S GT NO 96 138,000 Atlantic LNG Enagás Trinidad-Spain
Bilbao Knutsen Knutsen/Marpetrol 2004 S GT NO 96 138,000 Atlantic LNG Repsol/YPF Trinidad-Spain
Methane Polar BG International 1969 S GT NO 82 71,500 Sonatrach Enagás Algeria-Spain
Methane Arctic BG International 1969 S GT NO 82 71,500 Atlantic LNG Enagás Trinidad-Spain
LNG Bonny Bonny Gas Transport 1981 S GT NO 88 133,000 Nigeria LNG Enagás/GdF/BOTAS Nigeria-Spain/France
LNG Fimina Bonny Gas Transport 1984 S GT NO 88 133,000 Nigeria LNG Enagás/GdF/BOTAS Nigeria-Spain/France
Table 47: LNG tankers in 2005 (Propulsion type: S Steam turbine; D: Diesel engine)
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5.4.4 Distances of sea transportation
Distances of transportation were given in an article in Integrated Oil Research [54]. Distances are
expressed in nautical miles.
LNG imports Oman Qatar Algeria Libya Nigeria
Belgium 1,667
France 5,192 901 3,990
Greece 1,135
Italy 606 4,178
Portugal 3,340
Spain 4,773 4,840 346 1,239 3,567
Table 48: LNG shipping distances to Europe (in nautical miles)
5.4.5 Collected data
As already underlined in 5.4.3, the most representative technology for LNG vessels propulsion in
2004 is the steam turbine. Two sources of data have been studied:
→ “LNG Carrier Propulsion by ME Engines and Reliquefaction”, MAN B&W [53]: one of
the purpose of this paper is to compare two types of propulsion for LNG tanker: steam
turbine and two-stroke Diesel Engines with reliquefaction systems. A very accurate set of
data concerning the steam turbine driven LNG tankers is available in the appendix of the
document. Data are differentiated for loaded and ballast voyage. An average of both
voyages has been made. Both voyages (loaded and ballast) have to be included in the
calculations.
→ “Electric propulsion for LNG carrier”, ABB [55]: this article was published in 2004 in
the LNG journal. It shows a comparison between the steam turbine - driven LNG tankers
and other tankers (two-stroke diesel engines and electric engines). Figures are less
accurate (no mention of fugitive emissions or leakages) and consumptions have to be read
on the graphs.
Rate and consumption in
MJ/MJ
Loaded voyage
[53]
Ballast voyage
[53] Voyage [53] Voyage [55]
This report -
[53]*
Fugitive emission rate
(%/1,000 km) 0.00022% 0.00011% 0.00017% N/A 0.00017%
Fuel gas consumption
(%/1,000 km) 0.13% 0.07% 0.10% 0.12% 0.10%
Heavy fuel oil consumption
(%/1,000 km) 0.17% 0.25% 0.21% 0.17% 0.21%
Table 49: Collected data - Sea transportation of LNG
*The average between the loaded and the ballast voyage has been calculated.
Both sources are consistent. However, the more precise data source is kept: MAN B&W 53[].
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The heavy fuel oil consumption is modelled with a process from ecoinvent database : “Heavy fuel
oil, burned in industrial furnace 1MW, non-modulating/RER” which take into account direct air
emissions from combustion, infrastructure, fuel consumption, waste and auxiliary electricity use.
Remark: it is considered that LNG tankers mostly are propelled by heavy fuel oil; only the boil-off
gas is used for propulsion. In fact, this can be highly dependent on the prices of the fuels.
5.5 Gasification
5.5.1 Main actors and gasification plants
Atlantic basin importers, including the United States, received 1.7 Tcf (37 million tons) in 2002,
32% of total world LNG trade. Regasification capacity continues to grow as most Atlantic basin
importers are planning expansions.
→ France is Europe’s largest LNG importer, with imports of 511 Bcf (10.7 million tons) in 2002.
State-owned Gaz de France operates two terminals at Fos-sur-Mer near Marseilles and Montoir-
de-Bretagne, near Nantes. ExxonMobil has announced plans to build an additional terminal at
Fos-sur-Mer with a start up date in 2006. The terminal would receive LNG from Qatar. Gaz de
France has proposed an additional terminal at Fos Cavaou to receive gas from Egypt’s Idku
project.
→ Spain has one of the world’s most rapidly growing natural gas markets. LNG imports increased
by 30% in 2002, with nearly half of the volume imported from Algeria. The balance was
supplied by Qatar, Oman, the UAE, Libya, Nigeria, Trinidad and Tobago, Australia, and Brunei
Darussalam. State-owned Enagás operates regasification terminals at Barcelona, Cartagena,
and Huelva, all of which are being expanded. Bilbao, operated by a consortium of BP,
Iberdrola, Repsol YPF, and EVE, received its first LNG shipment from the UAE in August 2003.
When fully operational, the terminal will have an annual capacity of 131 Bcf (2.7 million tons)
and would receive most of its LNG from Trinidad and Tobago. Two more plants are under
construction at El Ferrol and Sagunto with estimated start-up dates in 2006 and 2007.
→ In Italy, GNL Italia, owned by Snam Rete Gas, operates a 130-Bcf-per-year (2.6-milliontpy)
facility in Panigaglia that receives LNG from Nigeria and Algeria. Several other projects are
being explored, including a gravity-based offshore regasification terminal in the northern
Adriatic.
→ Belgium’s sole regasification terminal at Zeebruge received 124 Bcf (2.7 million tons) of LNG,
mostly from Algeria, in 2002. Operator Fluxys LNG is considering increasing capacity at the
terminal as early as 2007.
→ Greece began importing LNG in 2000, under a 21-year contractual agreement with Algeria.
Greece’s sole LNG terminal at Revithoussa, near Athens, has an annual capacity of 93 Bcf (2.0
million tons).
→ Portugal began receiving LNG in 2002 under a 20-year contract with Nigeria LNG. The LNG
was received through Spanish terminals until October 2003, when the Sines terminal went
online. The plant has a capacity of 146 Bcf (3.3 million tons) per year.
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→ In 1964, the United Kingdom was the first country to import LNG but dismantled its terminal
on Canvey Island in 1990 following the arrival of North Sea oil and gas. The UK has now a
single LNG import terminal, though there are several in various planning stages. NGT operates
the Isle of Grain LNG terminal, a converted natural gas storage facility in southern England.
The terminal has a natural gas processing capacity of 470 Mmcf/d, with plans to eventually
increase capacity to 1.5 Bcf/d. The terminal received its first delivery of LNG in July 2005 from
Algeria.
Country Facility
Plant capacity
(106 tons LNG
per year)
Lead plant operator Start-up date
Belgium Zeebruge 4.8 Fluxys LNG 1987
France Fos-sur-mer 5.9 Gaz de France 1972
Montoir de Bretagne 8.3 Gaz de France
Greece Revithoussa 1.9 DEPA 2000
Italy Paniglia 2.7 Snam Rete Gas 1971
Portugal Sines 3.0 Gas de Portugal 2003
Spain
Barcelona 6.4 Enagás 1968
Huelva 2.9 Enagás 1988
Cartagena 2.7 Enagás 1989
Bilbao 2.7 BP, RepsolYPF, Iberdrola, EVE 2003
UK Isle of grain NGT 2005
Table 50: Gasification units in Europe [47]
5.5.2 Collected data
Environmental performance indicators (EPI) have been collected by Eurogas–Marcogaz LCA
working group. Three companies have given data about their gasification processes representing
Figure 37: Map of LNG terminals
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approximately 65% of the European market. A weighted average by the amount of gasified natural
gas by each of the three companies has been realized to obtain data for Marcogaz.
Rate in MJ/MJ 1 2 3
Marcogaz -
Europe
Fugitive emissions rate 0.008% 0.021% 0.0004% 0.009%
Combustion rate 0.11% 1.22% 0.48% 0.38%
Electricity consumption 0.087% 0.097% N/A 0.077%
Table 51: Collected data - Gasification
In order to model electricity consumption the process representing the average mix in Europe from
ecoinvent database has been used : “Electricity, medium voltage, production UCTE, at grid/UCTE”.
5.6 Regional high pressure transmission
5.6.1 Main actors
According to Gas Transmission Europe, there are more than 50 transmission companies in Europe.
Figure 38: Map of the gas transmission and storage companies in Europe
The biggest transporters in Europe are:
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→ Gaz de France Réseau de Transport (GrDF) (France): Under the 1946 Nationalisation
Law, Gaz de France, which is 100% state-owned, has a legal monopoly over transportation of
natural gas by pipeline. Since the Privatisation Act of 1993, companies, which are at least 30%
directly or indirectly controlled by the state, can also undertake transportation activities in
compliance with provisions contained in a Concession Convention to be negotiated with the
State.
→ Snam Rete Gas (Italy): A dominant position on gas transportation is held by Snam Rete Gas,
which can be attributed to the role of ENI in domestically produced gas and its investment and
involvement in the import pipelines. There is no law, which grants Snam Rete Gas an exclusive
monopoly on transmission, therefore a third party would be allowed to build a pipeline to
deliver imported gas into Italy
→ Gasunie (the Netherlands): Gasunie is half state-, half privately owned. It imports and
exports under approval of the Minister of Economic Affairs in the Netherlands. Gasunie owns
and operates the 11 429 km pipeline network in the Netherlands, through which most of the
natural gas is transported. The local network, which was laid to link individual consumers to the
main network, is owned mainly by local distribution companies. Gasunie transports gas to
power stations, large industrial users and to the monopoly distribution companies.
→ National Grid Transco (United Kingdom): NGT own and operate the high pressure gas
National Transmission System in Britain consisting of approximately 6 700 km of underground
high pressure gas pipelines and 24 compressor stations. The NGT also own and operate the
high-voltage electricity system in England and Wales; the NGT local distribution networks
deliver gas to some 11 million homes, offices and factories in Britain.
→ E.on Ruhrgas (Germany) : The gas industry is controlled by the private sector; there is no
state-owned monopoly in Germany. E.on Ruhrgas, a private German company, is the dominant
long distance transportation company. It operates 10,340 km (80%) of the transmission
network E.on Ruhrgas has great influence over the transportation of gas in Germany; it has a
share in the North/South (TENP) and East/West (MEGAL) European gas pipelines.
5.6.2 Collected data
EPI have been collected by Eurogas–Marcogaz LCA working group. Six companies gave data about
their transmission processes in 2003, representing approximately 47% of the European market.
Two other companies gave data from 2002 but those are not consistent, for example one company
presented a 0% leakage rate in 2002. They are not included in the calculation of the weighted
average.
Rate in MJ/MJ 1 2 3 4 5 6
Marcogaz-
Europe
Fugitive emissions rate 0.016% 0.002% 0.005% 0.041% 0.0010% 0.017% 0.019%
Combustion rate (from
compression) 0.475% 0.074% 0.122% 0.206% 0.157% 0.715% 0.237%
Electricity consumption 0.0025% 0.0020% N/A 0.0019% 0.036% 0.0083% 0.012%
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Table 52: Collected data – High pressure transmission - Europe
In order to model electricity consumption the process representing the average mix in Europe from
ecoinvent database has been used : “Electricity, medium voltage, production UCTE, at grid/UCTE”
A weighted average by the amount of transported natural gas by each of the six companies has
been realized to obtain data for Marcogaz.
These numbers, expressed as the % of the total gas transported in 2004 based on the energy
content, can be discussed as they are based on data coming from Western Europe companies only.
They certainly underestimate the fugitive emissions as generally transmission networks in Central
Europe are more obsolete. It would improve further the study if a more representative average
could be calculated including data from Central Europe countries.
Remark: the data are given by cubic meter transported. No average distance of transportation is
given. Therefore, the bigger the country is, the more transmissions consume energy. That is the
reason why energy consumptions can vary from the simple to seven in the previous table.
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5.7 Storage
5.7.1 Main actors
Transmission companies have often gas storage capacities and have dedicated a subsidiary
company (Gaz de France Grandes Infrastructures, Dong Storage, Centrica Storage) to operate
these gas facilities. Some others such as Latvijas Gaze, Plinacro or BEB still do both activities.
The main storage companies in Europe are:
→ Gaz de France’s Direction des Grandes Infrastructures has Europe's second largest storage
capacity, consisting of 12 facilities with a working capacity of 9.2 bcm in France in 2004;
→ E.on Ruhrgas (Germany) has a storage capacity of about 4.2 bcm in 2004;
→ Centrica Storage.
Country Number of storage Working gas (109 m3)
Austria 5 2.8
France 15 10.5
Germany 37 19.1
Italy 8 12.7
Others 10 6.5
Czech Republic 4 1.6
Hungary 3 1.9
Poland 4 0.7
Romania 3 0.7
Slovakia 1 1.9
Others 2 0.8
Table 53: Storage facilities by country
5.7.2 Collected data
EPI have been collected by Eurogas–Marcogaz LCA working group. Two companies gave data about
their storage processes, representing approximately 13% of the European market (based on their
respective working gas capacities as compared to total capacity in Europe). They are expressed as
% of the total volume distributed out of the storage facilities in 2003 based on the energy content.
Rate in MJ/MJ 1 2
Marcogaz-
Europe
Fugitive emissions rate 0.109% 0.023% 0.105%
Combustion rate (from
compression) 0.514% 0.136% 0.494%
Electricity consumption 0.126% 0.396% 0.14%
Table 54: Collected data - Storage – Europe
In order to model electricity consumption the process representing the average mix in Europe from
ecoinvent database has been used : “Electricity, medium voltage, production UCTE, at grid/UCTE”.
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The share of transmitted natural gas coming from storage facilities is evaluated based on the
following calculation:
% of NG coming from storage = (NG injected in storage facilities + NG extracted from storage facilities)/Total
NG transmitted
This calculation is jugged acceptable by experts of storage activities even if they rarely need to
calculate the share of natural gas coming from storage.
The result of this calculation is 20%.
5.8 Low pressure distribution
5.8.1 Main actors
The distribution practices are very different from a country to another:
→ in some countries, major companies dominate the distribution market (e.g. Spain, France);
→ in other countries, numerous local distribution companies are responsible for the gas
distribution (e.g. Germany, Belgium).
The main distribution networks in Europe are at the time of writing this document:
→ France: Gaz de France is the main gas supplier and sells around 80% of the gas sold to the
final consumer. A few small private companies and some companies owned by local public
authorities, which were already distributing gas before the Nationalisation Act of 1946, are still
entitled to distribute gas(20% of the gas distributed), provided they do not extend beyond a
certain volume and geographical area.
→ Germany: In the distribution sector there are more than 700 companies which market gas to
end customers. The ownership of these companies is mixed, some are private and some public.
Under agreements between these companies, local monopolies exist where the utility company
has exclusive rights to supply.
→ Italy: The distribution sector is dominated by Italgas (a subsidiary of ENI). Italgas currently
supplies Rome, Florence, Naples, Turin and Venice and plans to supply to 40% of all
households by 2000. In addition to Italgas, there are some 700 local and regional distribution
companies, which are both privately and municipally owned and which supply gas to
residential, commercial and small industrial users. Italgas supplies approximately 27% of the
retail market. In 1997, ENI sales of natural gas, which were primarily related to distribution,
totalled approximately 90% of Italian consumption.
→ Netherlands: Distribution is controlled by companies that are owned by local and regional
municipalities.
5.8.2 Collected data
EPI have been collected by Eurogas–Marcogaz LCA working group. Two companies gave data about
their distribution processes representing approximately 27% of the European market. Another
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company gave data from 2002, the three of them representing near 48% of the volume of the
distributed gas. The representativeness can be considered as high.
Rate in MJ/MJ 1 2 3
Marcogaz -
Europe
Fugitive emissions rate 0.373% 0.678% 0.593% 0.539%
Combustion rate 0.000% 0.211% 0.164% 0.122%
Electricity consumption N/A 0.024% 0.029% 0.020%
Table 55: Collected data – Low pressure distribution – Europe
In order to model electricity consumption the process representing the average mix in Europe from
ecoinvent database has been used : “Electricity, medium voltage, production UCTE, at grid/UCTE”.
5.9 Utilization
5.9.1 Natural gas combined cycle
Two solutions were studied for the modelling of large natural gas combined cycle plant of a net
electric capacity of 800 MW by the Paul Scherrer Institut (PSI)
[59] European Life Cycle Database:
http://lca.jrc.ec.europa.eu/lcainfohub/datasetArea.vm
56]. Both solutions, either two single shafts or a multi shaft have
the same overall efficiency (58%) using two turbines of the same
type. However it has been argued that a combination of two single
shaft plants has advantages in terms of operation flexibility. As a
result a combination of two 400 MW single–shaft units was considered for the purpose of the study.
Figure 39:Siemens SGT5-4000F gas turbine
Direct power plant emissions to the atmosphere are relatively low. The characteristics of natural
gas as a fuel allow especially low SO2 and particle emissions.
Airborne emissions
CO2 SO2 NOX CO PM2.5 Source
Emission limit in Europe
mg/N
m3
(15%
O2)
n.s. n.s. 50 n.s. n.s. [57]
Emission limit in France
mg/N
m3
(15%
O2)
n.s. 10 50 85 10 [58]
Power plant emission
mg/N
m3
(15%
O2)
n.s. 0.6 29.7 2.55 0.6
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Airborne emissions
CO2 SO2 NOX CO PM2.5 Source
mg/M
J in
55 500 0.5 25.5 2.2 0.5
Table 56: Collected data – Key airborne emissions for 0.16 kWh of electricity produced by MJin -
Natural gas CC plant
NB : the reference unit mg/Nm3 does not refer to a Nm3 of natural gas consumed, it refers to a
Nm3 of fumes emitted by the installation, so we cannot compare the emission values, even if
results have the same order of magnitudes.
Remark: The combined-cycle efficiency depends on the mode of operation: base-load operation
allows a yearly average net efficiency of 57.5% while part-load operation results in a reduced net
efficiency of 51%. Only the full load operation is studied.
5.9.2 Condensing boiler
A 10 MWth boiler has been considered for households. It is fired with low pressure natural gas,
whereas the industrial unit (>100 MWth) is connected to the high-pressure network. Both boilers
have a yearly average efficiency on their whole lifetime of 102% based on the Lower Heating Value
(LHV) of the natural gas [59] European Life Cycle Database:
http://lca.jrc.ec.europa.eu/lcainfohub/datasetArea.vm
[56]. As for electricity production at natural gas CC power plants, direct emissions to air are
relatively low.
Table 57: Collected data – Key airborne emissions for 1.02 MJ of heat produced by MJin- Boilers
The working of boilers needs the use of electricity. The consumption of electricity of the two kind of
boilers studied are detailed in the following table [56]:
Table 58: Collected data – Electricity consumption for 1.02 MJ of heat produced by MJin- Boilers
Key airborne emissions
CO2 SO2 NOx CO PM2.5
Boiler, 10 kW mg/
MJ i
n
55 500 0.5 10 4 0.1
Boiler >100 kW
mg/
MJ i
n
55 500 0.5 12.9 2.9 0.1
Electricity consumption
Boiler, 10 kW kWh/MJin 0.00278
Boiler >100 kW kWh/MJin 0.00111
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This electricity consumption is modelled with a process from ecoinvent database : “Electricity, low
voltage, production UCTE, at grid/UCTE” which presents a average production mix for Europe.
5.9.3 Combined heat and power (CHP) generation
Two CHP models have been studied in order to present an industrial used, for services and buildings, and a domestic use.
5.9.3.1 Small gas motor CHP
Several types of CHP units in the range of 10-50 kWe are available on the market today. As high
environmental performance is one of the aspired characteristics of new installed units, a lambda-
1- motor CHP condensing plant with three-way-catalyst for emissions reduction has been chosen as
reference technology by the PSI [56].
The electric efficiency of the unit modelled is 31.5%, the thermal efficiency is 72.3%, resulting in a
total efficiency of 103.8% (LHV) according to the manufacturer. It is assumed that the small CHP
plants are attached to the low-pressure gas network.
The three-way-catalyst is installed in order to reduce NOX emissions. The actual emissions depend
on the mode of operation and – more importantly – on the performance of the catalyst, which in
turn depends on its age. While a new catalyst reduces the NOX emissions to 1 mg/m3 (5% O2),
they are continuously increasing with the age of the catalyst till its replacement after about
5 years. This behaviour results in average NOX emissions of 140 mg/Nm3 (5% O2).
5.9.3.2 Stirling motor micro-CHP
For single households 1 kWe Stirling motors are an interesting option: they allow small-scale
electricity production at relatively low additional investment costs in combination with heat
production. Moreover they have a high global efficiency. The reference system chosen is a
condensing unit available on the market by 2009. It has an efficiency of about 100% relative to the
net calorific value of natural gas and is attached to the low-pressure gas network. The device
consumes electricity during standby mode (approximately 6760 hours/year). In the near future it is
expected that the power consumption of a micro-CHP plant will be reduced to 60 W during
generation (2,000 hours/year) and 9 W during standby. [56]
The working of Stirling motor micro-CHP needs the use of external electricity at the difference of
small gas motor CHP which use directly its electricity production.
Thus, the consumption is 0.0038 kWh /MJin [56] and it is modelled with a process from ecoinvent
database : “Electricity, low voltage, production UCTE, at grid/UCTE” which presents a average
production mix for Europe.
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5.9.3.3 Emission factors
The airborne emissions associated with natural gas burned in CHP units are indicated in the table
below:
Table 59: Collected data – Key airborne emissions for 0.315 MJ of electricity and 0.723 MJ of heat
produced by 1 MJin– CHP units
Table 60: Collected data – Key airborne emissions for 0.15 MJ of electricity and 0.85 MJ of heat
produced by 1 MJin – CHP units
5.9.3.4 Allocation factors
The data for the combined heat and power plants are given per unit of natural gas input. In order
to estimate burdens associated to electricity production or to heat generation, two standard
allocation factor schemes (chosen among the several possible) are used for calculations in the PSI
report [56]: energy and exergy. In this study, only the energy allocation is used.
An overview of the calculated allocation factors for energy allocation is shown in the following
table:
Lambda1, 30 kWe,
condensing gas motor
Stirling micro-CHP,
1 kWe
Efficiency
Electric efficiency 0.315 0.15
Thermal efficiency 0.723 0.85
Key airborne emissions
CO2 SO2 NOx CO PM2.5
Lambda1, 30 kWe, condensing gas motor m
g/
MJ i
n
55 500 0.5 45 48 0.15
Key airborne emissions
CO2 SO2 NOx CO PM2.5
Stirling micro-CHP,
1 kWe mg/
MJ i
n
55 500 0.5 19.4 14.5 0.1
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Allocation factors (energy allocation) (%)
Electricity allocation factor 30 15
Heat allocation factor 70 85
Table 61: Allocation factor for a CHP plant
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6 LCA RESULTS OF THE EUROPEAN
NATURAL GAS CHAIN
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6.1 Results of the upstream chain
6.1.1 Global results
6.1.1.1 Results of the inventory
The following table presents the overall results of the average European natural gas chain for high
pressure natural gas – used by industrial units or electricity production plants – and low pressure
natural gas – intended to residential clients for heating, cooking, etc.:
→ Consumptions are expressed in primary energy consumptions (primary energy from
natural gas, oil, coal, etc.) per MJ of natural gas distributed. The consumption of natural
gas is expressed in kJ surplus. That wants to say that is only the energy necessary to
distribute 1 MJ of natural gas, without taking into account the natural gas distributed.
→ Emissions are expressed in mass of component (carbon dioxide, methane, nitrogen
oxides, etc.) per MJ of natural gas distributed.
Consumption in primary energy per MJ
Unit
High pressure natural gas at consumer in
Europe
Low pressure natural gas at consumer in
Europe
Energy from natural gas kJ surplus 91.0 98.5
Energy from coal kJ 2.3 2.6
Energy from oil kJ 2.5 2.6
Energy from uranium kJ 2.7 3.0
Emissions per MJ Unit
CO2 g 5.22 5.35
CH4 g 8.57E-02 1.87E-01
N2O g 8.19E-05 8.40E-05
NOx g 1.87E-02 1.89E-02
SOx g 3.86E-03 4.01E-03
Table 62: Inventory results for 1 MJ of natural gas distributed in Europe in 2004
In the table presented below, the consumptions and the emissions are expressed per kWh
of natural gas distributed.
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Consumption in primary energy per kWh Unit
High pressure natural gas at consumer in
Europe
Low pressure natural gas at consumer in
Europe
Energy from natural gas kJ surplus 328 355
Energy from coal kJ 8.3 9.4
Energy from oil kJ 9.0 9.4
Energy from uranium kJ 9.7 10.8
Emissions per kWh Unit
CO2 g 18.8 19.3
CH4 g 3.09E-01 6.73E-01
N2O g 2.95E-04 3.02E-04
NOx g 6.73E-02 6.80E-02
SOx g 1.39E-02 1.44E-02
Table 63: Inventory results for 1 kWh of natural gas distributed in Europe in 2004
We may notice that the main differences between high pressure and low-pressure gas are methane
and NMVOC emissions.
Natural gas is the main fuel (more than 90%) used on its whole life cycle.
6.1.1.2 Results of the impact assessment
The following table presents the results of the impact assessment of the average natural gas chain
in Europe:
Impact per MJ Unit
High pressure natural gas at consumer in
Europe
Low pressure natural gas at consumer in
Europe
Non renewable energy depletion kJ surplus 98.6 107
Climate change g eq. CO2 7.39 10.1
Acidification mg eq. SO2 14.3 14.6
Table 64: Impact assessment results for 1 MJ of natural gas distributed in Europe in 2004
→ The greenhouse gases emissions reach 7.39 g equivalent CO2 per MJ of high-pressure
natural gas and 10.1 g equivalent CO2 per MJ of low-pressure natural gas. Carbon dioxide
is the main substance responsible for global warming, representing 71% of the GHG
emissions associated to high pressure gas and to 53% of the GHG emissions associated for
low pressure natural gas.
→ Acidifying emissions reach about 15 mg eq. SO2 for both high and low pressure
natural gas, SOX representing 27% of the acidifying emissions and NOX 73%.
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→ Energy consumption varies between 9.9% for high-pressure natural gas and
10.8% for low-pressure natural gas. Natural gas is the main fossil resource used,
representing approximately 92% of the global energy consumption. Uranium and oil
represent each 2.8% of the non-renewable energy resources utilization.
In the table presented below, the impact assessment result are expressed for 1 kWh of natural gas
delivered.
Impact per kWh Unit
High pressure natural gas at consumer in
Europe
Low pressure natural gas at consumer in
Europe
Non renewable energy depletion kJ surplus 355 385
Climate change g eq. CO2 26.6 36.4
Acidification mg eq. SO2 51.6 52.5
Table 65: Impact assessment results for 1 kWh of natural gas distributed in Europe in 2004
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6.1.2 Results by step
6.1.2.1 Global warming potential
The following table presents the absolute contribution of each step for each country7 to GHG emissions. In bold are highlighted the steps most contributing to
climate change.
Producing countries
Germany Italy Netherlan
ds
UK Norway Russia Algeria
(gas)
Algeria
(LNG)
Libya Nigeria Oman Qatar Europe Total by
step
Supplies from the
producing countries in the
European mix
3.5% 2.7% 15.0% 19.8% 16.7% 27.2% 7.5% 4.2% 0.1% 2.4% 0.3% 0.9% - -
Production/Processing 1.2% 0.4% 0.9% 3.3% 3.6% 8.5% 2.0% 1.3% 0.0% 4.5% 0.1% 0.3%
25.9%
Transmission by pipeline 0.1%
0.5% 0.2% 0.6% 31.3% 2.1% 0.7% 0.0% 0.1% 0.0% 0.0%
35.8%
Liquefaction
3.7% 0.1% 1.6% 0.2% 0.7%
6.2%
Export by LNG tanker
0.3% 0.0% 0.7% 0.1% 0.3%
1.4%
Gasification in Europe
0.3% 0.3%
Storage in Europe
2.0% 2.0%
High pressure transmission
in EU-25 2.5% 2.5%
Low pressure distribution in
EU-25 25.9% 25.9%
Total per country 1.3% 0.4% 1.4% 3.5% 4.2% 39.8% 4.1% 5.9% 0.1% 6.9% 0.4% 1.3% 30.7% 100%
Table 66: Absolute contribution of each step to global warming potential for low pressure natural gas distributed in Europe in 2004
7 The country may be a supply country like Algeria or Russia regarding its contribution to the European average supply mix in 2004, or Europe for the steps that take place in Europe
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The natural gas chain has been divided into four blocks:
→ Russian gas: it arrives in the EU-25 in gaseous state and accounts for 27% of the total
European supplies. The steps considered for this chain are the following: production and
processing and transmission by pipeline to European borders.
→ Other gas imports in gaseous form: it includes all the supplies coming to the EU-25 in
gaseous form except Russian gas (Germany, Italy, the Netherlands, UK, Norway and Algeria).
These supplies account for 65% of the total in 2004. The steps considered for this chain are the
following: production and processing and transmission by pipeline to European borders.
→ LNG: it includes all the supplies coming as LNG to Europe (from Algeria, Nigeria…).
Approximately 8% of the European natural gas supplies arrive in Europe as LNG. The steps
considered for this chain are the following: production and processing and transmission by
pipeline to liquefaction units, liquefaction, and sea transportation of LNG to European
gasification units.
→ Europe: it includes the steps that physically take place in Europe (gasification, national
transmission (high pressure), storage and distribution to consumer).
0%
5%
10%
15%
20%
25%
30%
35%
Europe
LNG imports
Gaseous imports from Russia
Gaseous imports (except Russia)
Figure 40: Contribution of each step to global warming potential for low pressure natural gas
distributed in Europe in 2004
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The main conclusions are the following
→ 65% of natural gas supplies (indigenous natural gas and natural gas coming by
pipelines from close regions) account for 15% of the global warming potential of
the natural gas distributed in Europe. This low contribution can be explained by the limited
transmission distances from production fields to European borders as well as by the overall
quality of European natural gas networks and facilities.
→ Russia and LNG chains representing respectively 27% and 8% of the supplies have a
major impact on the global warming: they respectively contribute to 40% and 15% of the
GWP. Long transmission distance from Russia (more than 5,000 km) and the high
autoconsumption rate of liquefaction units are respectively responsible for the high
contribution of the chains considered. For reminders, high uncertainties are existing on the
data used for leakages (factor 3 between the various found sources), thus this comment
should be used carefully.
→ Steps taking place in Europe do not participate greatly to the climate change
except for the distribution phase. This latter represent about 25% of the total GWP of
the natural gas distributed in Europe. However the uncertainty can be very high
considering the low representativity of some data.
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6.1.2.2 Acidification potential
The following table presents the absolute contribution of each step for each country8 to acidification potential. In bold are highlighted the steps most
contributing to acidification.
Producing countries
Germany Italy Netherlan
ds
UK Norway Russia Algeria
(gas)
Algeria
(LNG)
Lybia Nigeria Oman Qatar Europe Total by
step
Supplies from the
producing countries in the
European mix
3.5% 2.7% 15.0% 19.8% 16.7% 27.2% 7.5% 4.2% 0.1% 2.4% 0.3% 0.9% - -
Production/Processing 5,9% 0,4% 1,2% 2,5% 5,9% 22,8% 2,9% 1,8% 0,0% 4,4% 0,1% 0,0% 47,9%
Transmission by pipeline 0,1% 0,6% 0,3% 0,5% 27,1% 2,0% 0,7% 0,0% 0,1% 0,0% 0,4% 31,8%
Liquefaction 5.0% 0,1% 2,2% 0,2% 0,9% 8,5%
Export by LNG tanker 0,9% 0,0% 2,4% 0,4% 1,2% 4,9%
Gasification in Europe 0,3% 0,3%
Storage in Europe 3,2% 3,2%
High pressure transmission
in EU-25 2,1% 2,1%
Low pressure distribution in
EU-25 1,3% 1,3%
Total per country 6,0% 0,4% 1,8% 2,7% 6,4% 50.0% 4,9% 8,4% 0,2% 9,1% 0,8% 2,5% 6,9% 100%
Table 67: Absolute contribution of each step to acidification potential for low pressure natural gas distributed in Europe in 2004
8 The country may be a supply country like Algeria or Russia regarding its contribution to the European average supply mix in 2004, or Europe for the steps that take place in Europe
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As it has been done previously, the natural gas chain has been divided into four different supply
chains:
→ Russian gas and German gas, which have a high sulphur content and need to be partly
dehydrated: they account respectively for 27% and 4% of the total European supplies.
→ Other gas imports in gaseous form: it includes all the supplies coming to Europe in gaseous
form except Russian and German gas.
→ LNG: it includes all the supplies coming as LNG to Europe.
→ Europe: it includes the steps that physically take place in Europe.
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
50%
Europe
LNG imports
Gaseous imports from Russia and Germany
Gaseous imports (except Russia and Germany)
Figure 41: Contribution of each step to acidification potential for low pressure natural gas
distributed in Europe in 2004
The main conclusions are:
→ 62% of natural gas supplies (indigenous natural gas and natural gas coming by pipelines)
account for only 16% of the acidification potential of the natural gas distributed in Europe.
→ Russia, Germany and LNG chains representing respectively 27%, 4% and 8% of the
supplies have a major impact on acidification: they respectively contribute to 50%, 6%
and 21% of the acidification potentiel. SOX emissions, traditionally low for the gas industry,
are due to the processing of sour gas in Russia and Germany and the use of fuel oil
for LNG carriers.
→ Steps taking place in Europe do not participate greatly to the acidification: they contribute
to about 7% of the total acidification potential
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6.2 Results after utilization
6.2.1 Global results
6.2.1.1 Inventory results
The following tables present the overall results of the inventory and the impact assessment for heat and/or electricity production in an average place of
consumption in Europe in 2004:
Consumption in primary
energy per kWh Unit
Heat produced
at boiler -
Domestic use
Heat produced
at boiler -
Industrial use
Heat produced
at CHP -
Domestic use
Heat produced
at CHP - Service
and buildings
Electricity
produced at CHP
- Domestic use
Electricity
produced at CHP
- Services &
buildings
Electricity
produced at
combined cycle
plant
Energy from natural gas kWh 1.08 1.07 1.11 1.06 1.11 1.06 1.88
Energy from coal kWh 0.014 0.007 0.019 0.003 0.019 0.003 0.004
Energy from oil kWh 0.004 0.003 0.005 0.004 0.005 0.004 0.004
Energy from uranium kWh 0.016 0.008 0.021 0.003 0.021 0.003 0.005
Emissions per kWh Unit
CO2 g 220 216 227 211 227 211 377
CH4 g 6.75E-01 3.13E-01 6.92E-01 7.27E-01 6.92E-01 7.27E-01 5.39E-01
N2O g 2.23E-03 2.12E-03 2.34E-03 8.96-03 2.34E-03 8.96E-03 6.72E-03
NOX g 1.11E-01 1.15E-01 1.51E-01 2.22E-01 1.51E-01 2.22E-01 2.74E-01
SOX g 3.42E-02 2.27E-02 4.18E-02 1.64E-02 4.18E-02 1.64E-02 2.71E-02
Table 68: Inventory results for natural gas systems in an average consumption place in Europe in 2004
NB : For reminders, CHP for domestic use corresponds to a Stirling micro CHP and CHP for Service and building corresponds to a gas motor CHP.
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→ CO2 and N2O emissions are due predominantly to the combustion of natural gas in the
conversion system (respectively 85% and 79%). These emissions are therefore mainly linked
to the energetic efficiency of the conversion system. That is the reason why, electricity
production in a NGCC emits more CO2 per kWh electricity produced than the CHP: its overall
efficiency reaches 58% whereas CHP units enable to reach much higher global energetic
efficiencies.
→ Regarding CH4 emissions, they occur on the natural gas upstream chain. About 50% of
these emissions occur during the low-pressure distribution phase in Europe. That is the reason
why methane emissions are lower for systems directly connected to the high-pressure
transmission grid (Heat, natural gas, at boiler condensing modulating >100 kW, Electricity,
natural gas, at combined cycle plant 800 MWe).
→ For SOX, emissions are due to the electricity consumed as auxiliary in the conversion
system. Indeed electricity is partly produced from coal and oil, the different contribution
depending greatly on each country. The more a conversion system consumes electricity as
auxiliary, the more its emissions of SOX will be high. It has to be noted that CHP for services
and buildings does not consume electricity from the grid, because it is using its own-produced
electricity. As a result, its emissions are lower than other heat production systems.
→ Concerning NOX emissions, they are due to both combustion phase and the natural gas
upstream chain. These emissions are also very dependent on the conversion system
considered. NOX emissions are especially high for CHP for services and buildings because of the
choices made for the renewal of the three-way catalyst used to reduce NOX emissions. While a
new catalyst reduces NOX emissions to 1 mg/m3 (5% O2), they are continuously increasing with
the age of the catalyst till its replacement after 5 years approximately. In average, NOX
emissions amount to 140 mg/Nm3 (5% O2). The base case considered has been chosen
because it is a good compromise between exploitation costs and NOX emission levels but NOX
emissions could be further reduced by changing the catalyst more frequently.
→ All energy consumptions, except for natural gas, are due to the production of electricity
consumed as auxiliary in the conversion system. As it is the case for SOX emissions, they are
therefore greatly dependent on the electricity production mix.
Natural gas consumption is mainly linked to the energetic efficiency of the conversion system.
→ Material consumptions, like lubricating oil or chemicals do not contribute significantly to the
flows considered.
Remark: no direct comparison is possible between the different systems because of the
differences of scale and type of use: for example, a micro-CHP does not provide the same amount
of electricity as a natural gas combined cycle.
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6.2.1.2 Impact assessment results
The following table presents the overall impact assessment results for heat and/or electricity
production with the different conversion systems studied in an average place of consumption in
Europe in 2004:
Table 69: Summary of Eurogas–Marcogaz LCA results for natural gas systems in an average
consumption place in Europe in 2004
For reminders, the non renewable energy depletion is expressed in primary energy and not
anymore in kWh surplus as for the upstream chain.
For 1 kWh
Climate change
(g eq. CO2)
Acidification
(mg eq. SO2)
Non renewable
energy
depletion (kWh)
Heat at boiler - Domestic use 238 96 1.12
Heat at boiler - Industrial use 225 87 1.09
Heat at CHP - Domestic use 245 126 1.15
Heat at CHP - Services and
tertiary buildings 232 140 1.07
Electricity at CHP - Domestic
use 245 126 1.15
Electricity at CHP - Services
and tertiary buildings 232 140 1.07
Electricity at combined cycle
plant 393 180 1.90
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6.2.2 Results by step
The following figure presents the contribution of the different steps for heat production with a
condensing boiler and electricity generation with a NGCC to global warming and acidification.
0%
20%
40%
60%
80%
100%
Heating - Domestic use
Electricity production at
NGCC
Heating - Domestic use
Electricity production at
NGCC
Global warming Acidification
26% 24%
17% 16%
85% 88%
47% 51%
Production Pipeline transmission Liquefaction
Export by LNG tanker Gasification in EU Storage in EU
HP transmission in EU LP distribution in EU Utilization
Figure 42: Contribution of the different steps to global warming and acidification for natural gas
systems in an average place of consumption in Europe in 2004
→ As shown on the figure above, the utilization phase (combustion at power plant or
boiler) is predominant in terms of greenhouse gas emissions. Its contribution exceeds
85% of the total GHG emissions. CO2 is by far the main substance contributing to climate
change, accounting for about 95% of the GHG emissions, while methane emissions account for
the remaining 5%.
→ Concerning acidification, the utilization phase and the upstream chain have each one
a significant contribution on the acidification potential.. During the utilization step,
almost 25% of the emissions are due to the combustion process of the natural gas devices, the
electricity for auxiliaries when they exist amounting to ~25% of the total emissions. NOX
emissions occurring during natural gas combustion in power plants and boilers as well as in
compressor drivers for liquefaction and pipeline transmission account for about 65% of the
acidifying emissions, SOX emissions representing the 35% left. SOX emissions take mainly
place during production/sweetening of the sour natural gas produced in Russia and Germany,
as well as during LNG transport through the use of heavy fuel oil as propulsion energy.
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6.2.3 Results by supply chains
The supply chain of natural gas in Europe is very diversified. Three major supply chains with
specific particularities are distinguished:
→ Europe – natural gas coming through short-distance pipelines from European countries
(Norway, Great Britain, Germany, the Netherlands)
→ Russia – natural gas coming through pipelines from the Siberian fields over thousands of
kilometres
→ LNG – natural gas brought as LNG from various countries, mostly from Africa and Middle-
East (Algeria, Nigeria, Egypt)
In order to evaluate the various impacts of these 3 supply chains, it has been chosen to calculate
the GHG emissions for heat production with a domestic condensing boiler using these 3 upstream
chain and to compare them with the European mix. Thus, the European mix is the reference (total
amount of 100%) and the contribution of the utilization step is always the same in absolute terms
(same assumption for all chains). However, its relative contribution to the 3 different supply chains
is different (Figure 43).
0%
20%
40%
60%
80%
100%
120%
European mix European gas chains
Russian chains
LNG chains
85%92%
77%73%
Utilisation
Low pressure distribution in EU
High pressure transmission in EU
Storage in EU
Gasification in EU
Export by LNG tanker
Liquefaction
Transmission by pipeline
Production/Processing
Figure 43: Comparison of the repartition of GHG emissions among life cycle stages for heat
production with a domestic condensing boiler depending on the supply chains
Eurogas–Marcogaz study highlights the fact that the natural gas coming from far away countries
such as Russia or under liquefied state has a greater environmental impact than the natural gas
produced and consumed in Europe:
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→ The production of heat with a domestic condensing boiler from natural gas coming to
Europe as LNG emits about 27% more GHG than heat production with natural gas coming
from European countries through conventional pipelines. This is mostly due to the high
energetic consumption of existing liquefaction units and shows the strategic
importance of investing in highly efficient liquefaction plant projects, such as Snøhvit
liquefaction plant in Norway, which should be two times less energy consuming than the
existing liquefaction plants.
→ Heat production from Russian natural gas emits about 20% more GHG than heat
production with natural gas coming from European countries. This is mainly due to the
distance covered from the Siberian fields to EU-25 (about 5,000 km); in comparison,
the distance covered from the European production fields is 500 km in average. In the
literature a large range of values can be found for the leakage rate on the Russian
transport system (0.43% /1,000 km against 0.18%/1,000 km for the baseline case).
However the leakage rate does not influence greatly the overall results: an increase of
barely 2% of the total GHG emissions can be noticed when considering the higher value.
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7 SENSITIVITY ANALYSES
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7.1 Identification of the sensitive parameters During the inventory phase, several parameters were identified as critical:
→ One of the major sources of criticism concerning the environmental balance of natural gas
is the question of methane emissions on the Russian export pipeline system during
transportation from Russia to the EU borders. Since 2000, numerous studies on methane
emissions on the Russian transmission system have been published. They estimate the
leakage rate on the whole pipeline system (about 6,000 km) between 0.36% and 3%. This
LCA uses the values indicated by the Wuppertal Institute in 2005 [19] as baseline case,
because they are the most recent data and stem from direct measurements of Gazprom
subsidiaries on their networks. According to this study, fugitive emissions represent
approximately 1% of the transmitted natural gas from Siberian fields to the German
border. Taking uncertainties into account, a range of fugitive emissions rate between 0.6%
and 2.4% is also indicated. This point being a highly sensitive issue in estimating the
impact of the natural gas upstream chain, a sensitivity analysis has been performed to
assess the impact of this choice on the final results.
→ The global autoconsumption rate during sweetening process in Germany: ecoinvent
may have interpreted falsely data contained in BEB company’s report and we think that the
global autoconsumption rate has been overestimated. We therefore chose to apply a value
of 2.7% in our study. However this could have an important impact on the acidification
results and a sensitivity analysis considering the energy consumption rates calculated by
ecoinvent has been performed.
→ Compressor efficiencies in the Central and Eastern European countries (CEEC): in this
study, the infrastructure in Russia, Algeria, Middle-Eastern and African countries have been
considered as less efficient, with ageing compressors and pipelines - according to Gazprom,
the efficiency of its compressors lies between 24 and 28%. Compressor efficiency in
Central and Eastern Europe countries (CEEC) have been supposed to be comprised
between 30 and 34%. This hypothesis could be discussed. A sensitivity analysis has
therefore been performed taking into account efficiencies of 24-28% for CEECs as well.
→ Representativeness of European data is sometimes weak. Representing on average 44%
of the European market, sensitivity analyses on the data concerning the steps taking place
in Europe (gasification, storage, national transmission and distribution) has been performed
to assess its influence on LCA overall results.
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Value used in this study
Value min Value max
Methane leakage rate on the Russian export pipeline system during transportation
0,18% 0,11% 0,44%
Global autoconsumption rate during sweetening process in Germany
2.697% 2.697% 5.95%
Compressor efficiencies in CEECs 2.30% 2.30% 2.84%
Gasification → Vents → Fuel gas consumption → Grid electricity consumption
0.009% 0.38% 0.078%
0.006% 0.288% 0.051%
0.013% 0.676% 0.085%
Storage → Vents → Fuel gas consumption → Grid electricity consumption
0.105% 0.494% 0.141%
0.037% 0.197% 0.130%
0.108% 0.511% 0.339%
National transmission → Vents → Fuel gas consumption → Grid electricity consumption
0.019% 0.237% 0.012%
0.010% 0.151% 0.006%
0.031% 0.491% 0.025%
Distribution → Vents → Fuel gas consumption → Grid electricity consumption
0.539% 0.122% 0.021%
0.418% 0.033% 0.006%
0.640% 0.187% 0.027%
Table 70: Summary of the sensitivity analyses performed
→ During the peer review realized in 2010, one of the remarks concerned the
representativeness of the data 6 years after. Indeed, the year reference of this study is
2004, a long time was needed to finish this study because of the large system taken into
account. So, as the main aim is to communicate about the result and the different data
used in this study, the question of the representativeness of the study in 2010 was asked.
The main difference between 2004 and 2009 is the origin of the natural gas (percentage of
LNG or coming from Russia). It was considered that changes on technologies wasn’t
significant during this period.
Thus, the origin of natural gas consumed in Europe in 2009 was collected and a sensitivity
analysis made to evaluate the representativeness of the result.
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7.2 Results of the sensitivity analyses
7.2.1 Low pressure natural gas
The results of the different sensitivity analyses on impact assessment results associated to low
pressure natural gas are illustrated in the figure below:
0%
20%
40%
60%
80%
100%
120%
140%
Leakage rate in Russia
Desulfuration in Germany
Compressor efficiencies in CEECs
Data in Europe
Climate change Acidification Non renewable energy depletion
Figure 44: Results of the sensitivity analyses on the impact assessment results for low pressure
natural gas
The choice of a specific leakage rate on the Russian export pipeline system has
potentially a large influence on climate change results: considering a rate of
0.44%/1,000 km results in an increase of 18% of the burden on climate change compared to the
baseline case (0.18%/1,000 km) as methane has an impact 25 higher than the CO2 on climate
change. The energy depletion varies accordingly to the leakage rate as the natural gas lost has to
be produced in the first place, but to a much lesser extent than climate change results.
The low representativity of data collected for the steps taking place in Europe affect
significantly the results in terms of GHG emissions because of the large variations in the
energy consumptions that can be observed: the uncertainties range between -14% and +27%. The
energy consumptions vary accordingly. Regarding the acidifying emissions, they vary with the
electricity consumptions as coal and oil, beef emitters of SOX and NOX, are used in the European
electric mix (respectively 36% and 5%).
The acidification results are finally slightly dependent on the global autoconsumption
rate during the sweetening process: they increase by less than 10% when the
autoconsumption rate doubles. Indeed, when the global autoconsumption increases, the part of
sour gas burned increases as well, this results in higher NOx and SOX emissions, knowing that NOx
emissions contributes to around 65% of the total impact, and SOx emissions to around 35%.
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On the contrary, compressor efficiency in the Central and Eastern European countries is
not a critical parameter (less than 2% of differences). It will not be studied in the following part.
Globally the confidence gaps for low pressure natural gas results are important:
Min Max Climate change -14% +28%
Acidification -3,4% +6,5%
Non renewable energy depletion -0,6% +1,2%
Table 71: Global confidence gap of the results associated to low pressure natural gas
However the major part of the uncertainties is ironed out when the utilization step is taken into
account.
7.2.2 After utilisation: example of a domestic boiler
The results of the different sensitivity analyses on the impact assessment results of heat production
with a domestic boiler are illustrated in the figure below:
0%
20%
40%
60%
80%
100%
120%
Leakage rate in Russia Desulfuration in Germany
Data in Europe
Climate change Acidification Non renewable energy depletion
Figure 45: Results of the sensitivity analyses on the impact assessment results of the heat
production with a domestic boiler
After the utilisation step, the influence of the parameters studied (leakage rate on Russian
transportation system and representativity of the data concerning the steps taking place in Europe)
is much lower on results: the uncertainties ranges between -2% and +4% compared to the
baseline scenario. The results in terms of climate change, acidification and non renewable
energy depletion can therefore be considered as reliable.
On the other hand, regarding the acidification results when the worst case is considered, it would
be useful obtain more information from ecoinvent to be able to reduce the uncertainties associated
with those.
Min Max Climate change -2,1% +4,2%
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Min Max Acidification -1,8% +3,3%
Non renewable energy depletion -0,5% +1,2%
Table 72: Global confidence gap of the results associated to heat production with a domestic boiler
7.2.3 Representativeness of data in 2009
Data of natural gas production was collected on the same way than for 2004. Thus, the summary of inventory data for 2009 is given below :
Production in 2009 bcm % Total 452,2 Indigenous production 74,0 18%Gas trade movement : pipeline 322,8 70%Gas trade movement : LNG 55,4 12%
Table 73: Summary of production of natural gas in 2009 with various types of supply
Indigenous production :
Indigenous production
bcm %
Denmark 4,42 1,0%
Germany 0,83 0,2%
Italy 7,44 1,6%
Netherlands 13,79 3,0%United Kingdom 47,48 10,5%
Total Europe 73,95 16,4%
Table 74: Indigenous consumption (% of the European consumption in 2009)
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Gas trade movement : Pipeline
To Belgium Denmark France Germany NL Norway Spain U.K. Russia Algeria Libya Pipeline
Austria - - - 0,3% - 0,2% - - 1,2% - - 1,7%
Belgium - - - 0,2% 1,4% 1,4% - 0,4% - - - 3,2% Czech Republic - - - - - 0,7% - - 1,4% - - 2,0%
Estonia - - - - - - - - 0,2% - - 0,2%
Finland - - - - - - - - 0,9% - - 0,9%
France 0,2% - - 0,7% 1,4% 3,5% 0,2% 0,1% 1,8% - - 7,7%
Germany - 0,3% - - 5,0% 6,7% - 0,8% 7,0% - - 19,0%
Greece - - - - - - - - 0,5% - - 0,4%
Hungary - - 0,04% 0,2% - - - - 1,6% - - 1,7%
Ireland - - - - - - - 1,1% - - - 1,1%
Italy - - - 0,3% 1,7% 1,3% - 0,1% 4,6% 4,7% 2,0% 14,2%
Latvia - - - - - - - - 0,3% - - 0,3%
Lithuania - - - - - - - - 0,6% - - 0,6%
Luxembourg 0,2% - - 0,1% - - - - - - - 0,3%
Netherlands - 0,4% - 0,6% - 1,7% - 0,3% 0,9% - - 3,7%
Poland - - - 0,1% - - - - 1,6% - - 1,6%
Portugal - - - - - - 0,1% - - 0,3% - 0,3%
Slovakia - - - - - - - - 1,2% - - 1,2%
Slovenia - - - - - - - - 0,1% 0,1% - 0,2%
Spain - - 0,03% - - 0,4% - - - 1,5% - 1,9%
Sweden - 0,3% - 0,02% - - - - - - - 0,3% United Kingdom 0,2% - - - 1,4% 5,2% - - - - - 6,6% Pipeline exports 0,6% 0,9% 0,1% 2,5%
10,8% 21,1% 0,2% 2,7% 24,8% 6,6% 2,0% 70,0%
Table 75: Gaseous trade movements (% of the European consumption in 2009, bcm/bcm)
Gas trade movement : LNG
To Belgium Norway Oman Qatar Algeria Egypt Libya Nigeria LNG
Belgium - 0,0% - 1,3% - 0,0% - 0% 1,4%
France - 0,1% - 0% 1,7% 0,4% - 0,5% 2,7%
Greece - - - - 0,1% 0,0% - - 0,2%
Italy - - - 0,3% 0,3% 0,0% - - 0,6%
Portugal - - - - 0% - - 0,5% 0,5%
Spain 0,0% 0,3% 0,3% 1,1% 1,1% 0,9% 0,2% 1,1% 4,9% United Kingdom - 0,1% 0,0% 1,3% 0,4% 0,1% 0,0% 0,0% 1,8%
LNG exports 0,0% 0,5% 0,3% 4,0% 3,5% 1,4% 0,2% 2,0% 11,8%
Table 76: LNG trade movements (% of the European consumption in 2009, bcm/bcm)
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The grey cells indicate the chains which are not taken into account in 2004, thus hypothesis were taken to associate those chains to chains already modeled :
• Production and consumption in Romania and Bulgaria which belong to Europe in 2009 have not been taken into account in order to conserve the same geographic border.
• Indigenous production in Denmark has been associate to production in Norway, indeed in these two countries, the production take place offshore.
• Consumption from Lybia by pipeline has been assimilate to consumption from Algeria. Consumption from Belgium and Denmark have been assimilate to consumption from Netherland.
• Concerning LNG, consumption from Egypt has been assimilate to consumption from Lybia.
• When the production country was modeled but not the consumption country, another consumption country from the same production one has been chosen searching at the conservation of distance transportation.
Results of this sensitivity analysis on the distribution of 1 MJ of natural gas in Europe are presented below :
Damage category Unit 2004 2009 Variation 2004/2009
Climate change g eq. CO2 10,04 10,03 -0,1%
Acidification mg eq. SO2 14,58 14,96 2,6% Non renewable energy depletion kJ surplus 107 120 12,9%
Table 77: Results of the sensitivity analysis on the three followed impact assessments with two
years of reference for supply
The results show that variations have not an important impact on climate change and acidification. Concerning non renewable energy depletion, the variation is more important but this can be explain by the fact that results are expressed in kJ surplus.
The slightly variation can be explain by the large geographic border follow for this study. The main differences are the augmentation of LNG part (+50%), the increase of natural gas supply from Norway (+26%) and the decrease of natural gas supply from Russia (-9%). Thus, these variations should be cancelled each other.
This sensitivity analysis shows that the results of the study are always representativeness of the environmental impacts of the natural gas chain in Europe even if data are from 2004.
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8 CONCLUSIONS
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The four main priorities to improve the natural gas chain environmental performances
Eurogas–Marcogaz LCA results present a detailed analysis of the environmental performances of
natural gas as a fuel for three impact indicators: cumulated energy demand, global warming
potential and acidification potential. Despite the improvements already achieved along the gas
chain since several years, the natural gas results could be further improved by:
→ Developing high efficiency gas conversions systems: the utilization phase plays a key
role in the overall performances of the natural gas systems: it accounts for more than 85%
of the GHG emissions and about 50% of acidifying emissions. By developing new
applications with higher efficiency rates (heat pumps, micro-CHP and natural gas combined
cycle), the natural gas industry promotes its energy.
→ Improving the efficiency of liquefaction units: the liquefaction step is the main burden
of LNG chains and the gas industry is massively investing in high efficiency liquefaction
units. Currently operating liquefaction plants have an energetic consumption ranging
between 9% and 15%, depending on their age and other factors like external temperature
for example. However, the future liquefaction units will be much more efficient, like the
Snøhvit liquefaction plant started in 2008, whose energetic consumption is about 6%.
→ Improving compressor efficiencies for long distance transmission: the new
projected pipelines as well as the programs on the reconstruction and technical upgrading
of existing gas transmission facilities will allow improving the environmental performances
of long distance chains. The gas industry makes significant investments in such programs:
in Russia, annual investments in the reconstruction of gas compression units until 2030 are
evaluated to be more than USD 2 billion [69].
→ Reducing gas flaring during production on associated fields: flaring during natural
gas production is not a common practice. The flaring rate during gas production on
associated gas and oil fields is generally situated between 0.1 and 0.5%. However, this
percentage in much higher in Nigeria9. In spite of a ruling by the Federal High Court of
Nigeria that forbade flaring in 2005, gas flaring is still frequently used at current time.
Moreover Eurogas–Marcogaz study enables to focus on the right priorities. Indeed some emissions
(SOX and particulate matters for example) are not due to the natural gas itself but to the use of
electrical auxiliaries of the conversion systems. Such distinctions have to be made in regulations.
A study to be updated, supplemented and reviewed
9 Data used in this study were taken from two different companies operating in Nigeria [5]. These data concern
mainly onshore production in the Niger delta and a small part of offshore production, both associated
production of oil and gas. According to theses sources, about 10% of the natural gas produced is flared. In fact,
10% of the global energy produced on the production field is flared and have been allocated to both oil and gas
production.
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This study allows quantifying LCA results specific to the European context and shows the limitations
of using generic European LCA databases for national policies. The political and economic context
evolves fast. Indeed since the launching of the Working Group in 2004, the political borders of
Europe have been extended to 27 countries and several mergers have taken place in the gas
industry. Along with these transformations, some progresses have been made from a technological
point of view (e.g. diesel-electric engine). As a result an update of this LCA should be undertaken
in order to keep up with the evolution of both natural gas industry and technologies used along the
natural gas chain. Furthermore, this update would be an opportunity to improve the
representativity of the study when new data is available (cf. 0).
In the future, other essential substances will have to be included to allow a more comprehensive
evaluation of the environmental performance of natural gas systems. The current scope of the
study guarantees the quality of the results for the three impact categories considered but also
limits the use of our data. The comparison with other energy carriers is limited to only these three
indicators and excludes some essential aspects like for example ecotoxicity, waste (inert,
radioactive…), or ozone depletion. Another way of improvement is to include the impacts
associated to the infrastructures, as they are neglected in the current version of the study.
The ISO standards recommend undertaking a peer review. A critical review is a process intended to
ensure consistency between a life cycle assessment and the principles and requirements of the
International Standards on life cycle assessment, ISO 14040 and 14044, and enhance the
credibility of the study. This peer review has been realized in 2010-2011 and the synthesis of this
peer review is presented in appendix 9 .
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REFERENCES [1] ISO 14040 Environmental management - Life cycle assessment - Principles and framework.
Brussels: ISO 14040:1997, European Committee for Standardization (1997)
[2] ISO 14044 Environmental management - Life cycle assessment - Requirements and
guidelines Brussels: ISO 14044:2006, European Committee for Standardization (2006)
[3] Frischnecht R., Althaus H.-J., Bauer C., Doka G., Heck T., Jungbluth N., Kellenberger D.
and Nemecek T. The Environmental Relevance of Capital Goods in Life Cycle Assessments of
Products and Services. Int. J. LCA (2007)
[4] Internal study: Estimation des Emissions de GES Tertiaire et transports salariés de Gaz de
France sur l'année 2005 (2005) (confidential)
[5] ecoinvent v2.0
[6] Kerr Tom and Hershman Michelle, Energy Sector Methane Recovery and Use - The
Importance of Policy, report from the International Energy Agency (2009)
[7] Intergovernmental Panel on Climate change IPCC Third Assessment Report – Climate
Change 2001: The Scientific Basis (2001)
[8] IMPACT2002+, Ecole Polytechnique Fédérale de Lausane -Aquatic Acidification (2002)
[9] Frischknecht R., Jungbluth N., et al. Implementation of Life Cycle Impact Assessment
Methods. Final report (2003)
[10] Natural Gas Supply association website: www.naturalgas.org
[11] Panhandle Energy website: www.panhandlaenergy.com/property_lng.asp
[12] Chabrelie M.-F., Dussaud M., Bourjas D. and Hugout B. Underground gas storage:
technological innovations for increased efficiency
[13] Siemens website: http://powergeneration.siemens.com/products-solutions-services/power-
plant-soln/combined-cycle-power-plants/
[14] National Energy Foundation website: http://www.nef.org.uk/energysaving/boilers.htm
[15] Combined Heat and Power Association website: www.chpa.co.uk
[16] BP Statistical Review of World Energy (June 2004)
[17] Energy Information Administration website: http://www.eia.doe.gov
[18] Gazprom environmental report (2005)
[19] Wuppertal Institute, Greenhouse Gas Emissions from the Russian Natural Gas Export
Pipeline System (2005)
[20] LBST, GM Well-to-Wheel analysis of energy use and Greenhouse Gas emissions of
advanced fuel/vehicle systems - a European study (2002)
[21] Gazprom annual report (2002)
[22] Natural Gas Reserves in Norway, Oil and Gas ( published August 26, 2006)
[23] Statoil annual report and accounts (2004)
[24] NAM environmental report (2004)
[25] Department for Business Enterprise and Regulatory Reform website: Energy Markets
outlook
[26] UKOOA website
WG-LCA-12-01 22/06/2011 LCA report
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[27] ExternE national implementation report: Power generation and the Environment - a UK
Perspective (1998)
[28] Oil&gas website: http://www.oilgasarticles.com
[29] BEB environmental report (2001)
[30] Documentation of changes implemented in ecoinvent data v1.2 and v1.3
[31] Eni environmental report
[32] tpoint EniTecnologie (January 2005)
[33] ExternE national implementation report - Italy (1997)
[34] OECD, African Economic Outlook: Nigeria (2004)
[35] Popov I., Estimating Methane Emissions From the Russian Natural Gas Sector (March 2001)
[36] World perspective website, Statistics on electricity production mix in the world
[37] Croezen H.J. and Sevenster M.N. The natural gas chain - Toward a global life cycle
assessment (2006)
[38] European Regulator's Group for Electricity and gas, Assessment summary on selected
Transportation Routes
[39] GIE map
[40] Gassco website: http://gcweb04.gassco.no/sw3044.asp
[41] Data from Gasunie, given by Tjerk Veenstra to Marcogaz LCA working group
[42] Data from Synergrid, given to Marcogaz LCA working group
[43] Interconnector Limited website: http://www.interconnector.com/mediacentre/statistics.htm
[44] Bord Gais website:
http://www.bordgais.ie/files/corporate/library/20060505121056_bordgais_2025
[45] Eni factbook 2003 Gas and power
[46] Energy Information Administration, Algeria’s analysis brief:
http://www.eia.doe.gov/emeu/cabs/index.html
[47] Energy Information Administration, The Global Liquefied Natural Gas market: Status and
Outlook
[48] Sonatrach, LNG-12, Paper 3.2: GL1Z Plant Revamping Project
[49] Eni publication: Eni in Nigeria
[50] Demand in Asia the major factor shaping Qatari oil and gas boom, Volume 1999, Issue 1
(January 1999)
[51] Petrol Development Oman website: www.pdo.co.om
[52] Sirte Oil Company website: www.soc.com.ly (information not available anymore)
[53] Man B&W, LNG Carrier Propulsion by ME engines and Reliquefaction
[54] Simmons & Company International, Integrated Oil Research, April 7,2005
[55] Hansen J.F., and Lysebo R., ABB AS Marine Group, Electric propulsion for LNG Carriers,
LNG jounal (2004)
[56] Heck T., Dones R. and Bauer C. Life cycle assessment of new natural gas conversion
systems in France (2007)
WG-LCA-12-01 22/06/2011 LCA report
Page 157
[57] DIRECTIVE 2001/80/EC OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL of 23
October 2001 on the limitation of emissions of certain pollutants into the air from large combustion
plants (2001)
[58] JORF n°281 du 4 décembre 1999, texte n° 27, Arrêté du 11 août 1999 relatif à la réduction
des émissions polluantes des moteurs et turbines à combustion ainsi que des chaudières utilisées
en postcombustion soumis à autorisation sous la rubrique 2910 de la Nomenclature des
installations classées pour la protection de l'environnement (1999)
[59] European Life Cycle Database: http://lca.jrc.ec.europa.eu/lcainfohub/datasetArea.vm
[60] Gasum annual report (2006)
[61] Data from Gaz de France
[62] CESI, Ramboll, Mercados and Comillas, Study for DG Trans-European Energy Network
“TEN-ENERGY-Invest” (2005), page 221
[63] International Energy Agency, Optimising Russian Natural Gas (2006)
[64] Spp website (data are not available anymore)
[65] IBE consulting engineers website: http://ocs-
v3.ibe.si/portal/page?_pageid=54,128608&_dad=portal&_schema=PORTAL
[66] Transitgas website: http://www.transitgas.ch/en/transp_compression_Ruswil.htm
[67] Oxford Institute for Energy studies, Ukraine ‘s gas sector (June 2007)
[68] Department for Trade and Industry, Project on “EU Emissions Trading Scheme (ETS) Phase
II – UK New Entrants Spreadsheet revisions” (2006)
[69] Ananenkov A.G. Transmission infrastructure development in Russia (Response to Natural
Gas Demand Growth) 23rd World Gas Conference, Amsterdam 2006
[70] Goedkoop M. and Cie, ReCiPe 2008, Report 1 : Characterisation, January 2009
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ABBREVIATIONS AP Acidification potential
BAT Best available technology
Bcm Billion cubic meters
CC Combine cycle
CED Cumulative energy demand
CHP Combined heat and power
CML Centre for Environmental Studies
DEA Diethanolamine
EPI Environmental performance indicator
eq. equivalent
GHG Greenhouse gas
GT Gas turbine
GWP Global Warming Potential
IGU International Gas Union
IPCC Intergovernmental panel on climate change
LBST L.B. Systemtechnik
LCA Life cycle assessment
LCI Life cycle inventory
LCIA Life cycle impact assessment
LDC Local Distribution Company
LNG Liquefied natural gas
MDEA Methyldiethanolamine
MEA Monoethanolamine
MRC Mixed refrigerant cascade
NCS Norwegian continental shelf
NG natural gas
NGL Natural gas liquid
NMVOC Non-methane volatile organic compound
PSI Paul Scherrer Institut
SCADA Supervisory control and data acquisition
SCR Selective catalytic reduction
ST Steam turbine
Tcf Trillion cubic feet
TEG Triethylene glycol
THT Tetrahydrothiophene
UKOOA United Kingdom Offshore Operators Association
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APPENDICES
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APPENDIX 1: composition and characteristics of the natural gas
Natural gas Unit The
Netherlands
United
Kingdom Germany Italy Norway Russia
Algeria/Nigeria/
Egypt/Qatar Marcogaz
Methane kg/Nm3 0.67 0.67 0.69 0.71 0.72 0.72 0.65 0.69
Ethane kg/Nm3 0.023 0.041 0.008 0.00065 0.074 0.006 0.1 0.041
Propane kg/Nm3 0.003 - 0.001 - 0.019 0.002 0.016 0.007
Butane kg/Nm3 0.001 - - - 0.006 0.001 0.0027 0.002
Other hydrocarbons kg/Nm3 - 0.035 - - 0.002 0.001 - 0.008
CO2 kg/Nm3 0.008 0.0059 0.002 0.00059 0.013 0.001 - 0.005
N2 kg/Nm3 0.118 0.036 0.062 0.00663 0.007 0.007 0.0063 0.031
H2S kg/Nm3 2.00E-06 2.00E-06 2.00E-06 2.00E-06 2.00E-06 2.00E-06 2.00E-06 2.00E-06
Density kg/Nm3 0.82 0.79 0.76 0.72 0.84 0.74 0.78 0.78
Lower heating value MJ/Nm3 34.9 37 35 33.85 40.8 36.4 38.5 37.2
The different compositions of natural gas are used to model the emissions of natural gas vented after a possible sweetening treatment for which one special
emissions data are used (detailed in appendix 2).
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APPENDIX 2: Emission factors
Composition of natural gas, with sour part before
treatment
Natural gas Unit
Sour gas,
before
treatment
Sweet, gas
before
treatment
Methane kg/Nm3 0.5 0.61
Ethane kg/Nm3 0.11 0.04
Propane kg/Nm3 0.1 -
Butane kg/Nm3 - -
Other hydrocarbons kg/Nm3 0.04 0.04
CO2 kg/Nm3 0.1 0.02
N2 kg/Nm3 0.06 0.13
H2S kg/Nm3 0.09 -
From ecoinvent report, part V, table 3.4
BOILERS
g/MJ Natural gas, burned in industrial
furnace >100kW
CO2 5,60E+01
CO 2,00E-03
N2O 1,00E-04
CH4 2,00E-03
Particulates 2,00E-04
NMVOC 0,00E+00
NOX 1,79E-02
SO2 5,50E-04
ECOINVENT 2
FLARES
g/MJ Emissions due to natural gas
burned in production flare, sour
Emissions due to natural gas
burned in production flare, sweet
CO2* 5,60E+01 5,60E+01
CO 1,50E-02 1,50E-02
N2O 0,00E+00 0,00E+00
CH4 6,97E-03 6,97E-03
Particulates 5,46E-03 5,46E-03
NMVOC 8,28E-04 8,28E-04
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FLARES
g/MJ Emissions due to natural gas
burned in production flare, sour
Emissions due to natural gas
burned in production flare, sweet
NOX 3,37E-01 3,37E-01
SO2 4,86E+00 0,00E+00
ECOINVENT 6 ECOINVENT 4
ECOINVENT 1 Diesel, burned in diesel-electric generating set/GLO U
ECOINVENT 2 Natural gas, burned in industrial furnace >100kW/RER S
ECOINVENT 3 Natural gas, burned in gas motor, for storage
ECOINVENT 4 natural gas, sweet, burned in production flare
ECOINVENT 5 natural gas, burned in gas turbine, for compressor station
ECOINVENT 6 natural gas, sour, burned in production flare
EPI
Theoretical data
Data from ecoinvent
As a reminder, the emissions for sour natural gas are used during the production of natural gas in
Germany (50% of sour gas) and in Russia (5,9%) and during the sweetening process (16% of sour
gas and 84% of sweet gas) and finally for dehydration of the Russian natural gas.
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MOTOCOMPRESSORS10
g/MJ Emission from
gas engines - Algeria
Emission from
gas engines - Russia
Emission from
gas engines - GB
Emission from
gas engines - Germany
Emission from
gas engines - Netherlands
Emission from
gas engines - Italy
CO2 5,60E+01 5,52E+01 5,74E+01 5,52E+01 5,60E+01 5,76E+01
CO 6,00E-02 6,00E-02 6,00E-02 6,00E-02 6,00E-02 6,00E-02
N2O 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00
CH4 1,70E-02 1,70E-02 1,70E-02 1,70E-02 1,70E-02 1,70E-02
Particulates 2,00E-03 2,00E-03 2,00E-03 2,00E-03 2,00E-03 2,00E-03
NMVOC 8,00E-03 8,00E-03 8,00E-03 8,00E-03 8,00E-03 8,00E-03
NOX 2,00E-02 2,00E-02 2,00E-02 2,00E-02 2,00E-02 2,00E-02
SO2 5,50E-04 5,50E-04 5,50E-04 5,50E-04 5,50E-04 5,50E-04
ECOINVENT 3 (specific to each country respectively : DZ, RU, GB, DE, NL)
TURBOCOMPRESSORS
g/MJ
Emissions from
gas turbine -
Algeria
Emissions from
gas turbine
sweet- Russia
Emissions from
gas turbine-GB
Emissions from
gas turbine
sweet -
Germany
Emissions from
gas turbine-
Netherlands
Emissions from
gas turbine-
Norway
Emissions
from
gas turbine-
Italy
Sour gas, burned
in gas turbine for
production,
Norway
Sweet gas,
burned
in gas turbine,
production
Norway
Emissions from
gas turbine for
gasification-
Europe
Emissions
from
gas turbine
for
transmission-
Europe
Emissions
from
gas turbine
for storage-
Europe
Emissions
from
gas turbine
for
distribution-
Europe
CO2 5,60E+01 5,52E+01 5,74E+01 5,52E+01 5,60E+01 5,74E+01 5,76E+01 5,60E+01* 5,60E+01* 5,55E+01 5,55E+01 5,55E+01 5,55E+01
CO 4,00E-02 4,00E-02 4,00E-02 4,00E-02 4,00E-02 4,00E-02 4,00E-02 1,25E-01 1,25E-01 4,00E-02 4,00E-02 4,00E-02 4,00E-02
N2O 1,00E-03 1,00E-03 1,00E-03 1,00E-03 1,00E-03 1,00E-03 1,00E-03 2,50E-04 2,50E-04 1,00E-03 1,00E-03 1,00E-03 1,00E-03
CH4 4,50E-03 4,50E-03 4,50E-03 4,50E-03 4,50E-03 4,50E-03 4,50E-03 2,43E-04 2,43E-04 4,50E-03 4,50E-03 4,50E-03 4,50E-03
Particulates 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00 0,00E+00
NMVOC 1,00E-03 1,00E-03 1,00E-03 1,00E-03 1,00E-03 1,00E-03 1,00E-03 3,07E-03 3,07E-03 1,00E-03 1,00E-03 1,00E-03 1,00E-03
NOX 1,95E-01 1,95E-01 1,95E-01 1,95E-01 1,95E-01 1,95E-01 1,95E-01 1,99E-01 1,99E-01 5,83E-02 1,77E-01 4,98E-01 ?
SO2 5,50E-04 5,50E-04 5,50E-04 5,50E-04 5,50E-04 5,50E-04 5,50E-04 4,86E+00 5,50E-04 5,50E-04 5,50E-04 5,50E-04 5,50E-04
ECOINVENT 5 (specific to each country respectively : DZ, RU, GB, DE, NL, NO, NO ,NO)
10 It has to be noted that NOx emission factors are lower by one order of magnitude than those of turbines, which is surprising. However, as motocompressors represent only a very small part of the
compressor fleets of the different countries (see Appendix 3) and due to the lack of additional information, the difference has not been further investigated.
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APPENDIX 3: Type of compressors used during transmission
Type of compressors Source
Gas turbines Gas motors Electric engines
Algeria 100% - -
Austria 100% - -
Belarus 100% - -
Belgium 85% 6% 9% [42]
Bulgaria 100% - -
Czech Republic 100% - -
Denmark 100% - -
Finland 100% - - [60]
France 80% 20% - [61]
Germany 100% - -
Greece 100% - -
Hungary 100% - -
Ireland 100% - -
Italy 100% - -
Latvia 100% - -
Lithuania 100% - -
Luxembourg - - -
Norway - - 100% [62]
Netherlands 86% 14% - [41]
Poland 100% - -
Portugal 100% - -
Russia 85% 1% 14% [63]
Romania 100% - -
Slovakia 79% - 21% [64]
Slovenia 100% - - [65]
Spain 100% - -
Switzerland 100% - -
[66]
Ukraine 63% 14% 23% [67]
United Kingdom 100% - - [68]
Default value: when no information was found, it was assumed that 100% of the compressors in
a specific country are driven by gas turbines.
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APPENDIX 4: National Electricity mix considered during transmission
Hard coal Hydro (power
plant)
Hydro (pumped
storage)
Lignite Industrial gas Natural gas Nuclear Oil Wind Cogeneration Photovoltaic
Austria 7,7% 77,1% 2,6% 2,2% 0,46% 8,2% 1,6% 0,13%
Belgium 15,3% 0,58% 1,6% 3,7% 18,9% 57,6% 0,94% 0,019% 0,32%
Bulgaria 46,1% 7,6% 3,6% 40,6% 2,0%
Belarus 0,013% 0,11% 87,3% 12,6%
Switzerland 57,7% 1,3% 38,0% 0,0046% 1,7% 0,015%
Czech Republic 7,5% 2,5% 0,80% 63,8% 1,0% 4,3% 18,6% 0,50% 0,70%
Germany 24,9% 4,3% 0,52% 25,7% 2,1% 8,9% 30,4% 1,1% 1,7% 0,29% 0,17%
Algeria 0,80% 97,0% 2,2%
Spain 25,7% 14,8% 1,2% 11,3% 1,2% 7,5% 30,5% 4,8% 2,3% 0,2% 0,012%
France 4,9% 12,9% 0,94% 0,074% 0,66% 2,0% 76,6% 1,4% 0,015% 0,2%
Greece 7,3% 0,82% 63,4% 10,9% 16,4% 0,90% 0,000019%
Hungary 0,54% 27,3% 0,33% 18,8% 40,2% 12,5% 0,0085%
Italy 9,1% 18,3% 2,5% 2,9% 35,6% 30,7% 0,21% 0,0024%
Latvia 66,4% 30,6% 3,1%
Netherlands 25,2% 0,17% 3,2% 57,6% 4,4% 3,5% 1,0% 1,0% 0,0090%
Norway 0,026% 99,1% 0,44% 0,076% 0,14% 0,0059% 0,021% 0,15%
Poland 56,6% 1,5% 1,5% 36,7% 1,3% 0,71% 1,3% 0,0037% 0,15%
Romania 38,5% 29,2% 18,5% 9,8% 4,0%
Russia 17,3% 18,9% 45,3% 15,6% 2,9%
Slovenia 29,5% 32,1% 2,1% 35,6% 0,38% 0,21%
Slovakia 10,8% 16,1% 0,85% 7,1% 0,17% 10,8% 53,5% 0,65%
Ukraine 24,7% 6,5% 20,7% 47,8% 0,33%
United Kingdom 31,8% 1,4% 0,72% 1,2% 40,2% 21,7% 1,6% 0,26% 1,2%
Data from ecoinvent (process "Electricity, production mix AT/AT U" respectively BE, CH, CZ, ES, FR, GR, HU, IT, NL, NO, PL, SI, SK)
Data from World perspective website [36]
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APPENDIX 5: Transmission distances – Details
Exports Transit countries
From To From To Transit pipeline
length (km)
Total length
(km)
Russia
Austria
Siberian fields, RU Sumy, UA 3376
5062 Sumy, UA Velke Kapusany, SK 1216
Velke Kapusany, SK Baumgarten, AT 470
Belgium
Siberian fields, RU Sumy, UA 3376
6111
Sumy, UA Velke Kapusany, SK 1216
Velke Kapusany, SK Lanzhot, CZ 470
Lanzhot, CZ Waidhaus, DE 401
Waidhaus, DE Eynatten, BE 648
Czech Republic
Siberian fields, RU Sumy, UA 3376
5062 Sumy, UA Velke Kapusany, SK 1216
Velke Kapusany, SK Lanzhot, CZ 470
Finland Gryazovets, RU Imatra, FI 936
3139 Gryazovets, RU Orsha, BY 872
France
Siberian fields, RU Sumy, UA 3376
5930
Sumy, UA Velke Kapusany, SK 1216
Velke Kapusany, SK Lanzhot, CZ 470
Lanzhot, CZ Waidhaus, DE 401
Waidhaus, DE Medelsheim, FR 467
Germany
Siberian fields, RU Sumy, UA 3376
5307 Sumy, UA Velke Kapusany, SK 1309
Velke Kapusany, SK Lanzhot, CZ 470
Lanzhot, CZ Waidhaus, DE 401
Germany
Siberian fields, RU Orsha, BY 3075
4383 Orsha, BY Kondratky, PL 556
Kondratky, PL Frankfurt/Oder, DE 684
Greece
Siberian fields, RU Sumy, UA 3376
5392 Sumy, UA Isaccea, RO 1056
Isaccea, RO Negru Voda, BG 200
Negru Voda, BG Kula, GR 760
Hungary Siberian fields, RU Sumy, UA 3376
4592 Sumy, UA Beregdaroc, HU 1216
Italy
Siberian fields, RU Sumy, UA 3376
5442 Sumy, UA Velke Kapusany, SK 1216
Velke Kapusany, SK Baumgarten, AT 470
Baumgarten, AT Tarvisio, IT 380
Latvia Torzhok, RU Korneti, LV 552
3187 Torzhok, RU Orsha, BY 440
Lithuania Siberian fields, RU Orsha, BY 3075
3779 Orsha, BY Vilnius S, LT 704
the Netherlands Siberian fields, RU Sumy, UA 3376
6159 Sumy, UA Velke Kapusany, SK 1216
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Exports Transit countries
From To From To Transit pipeline
length (km)
Total length
(km)
Velke Kapusany, SK Lanzhot, CZ 470
Lanzhot, CZ Waidhaus, DE 401
Waidhaus, DE Zevenaar, NL 696
Poland Siberian fields, RU Orsha, BY 3075
3699 Orsha, BY Kondratky, PL 624
Slovakia Siberian fields, RU Sumy, UA 3376
4592 Sumy, UA Velke Kapusany, SK 1216
Slovenia
Siberian fields, RU Sumy, UA 3376
5325 Sumy, UA Velke Kapusany, SK 1216
Velke Kapusany, SK Baumgarten, AT 470
Baumgarten, AT Murfeld, SI 263
Norway
Austria North Sea fields, NO Emden/Dornum, DE 1106
2090 Emden/Dornum, DE Oberkappel, AT 984
Belgium North Sea fields, NO Zeebruge, BE 1382 1382
Czech Republic North Sea fields, NO Emden/Dornum, DE 1106
1890 Emden/Dornum, DE Olbernau, CZ 784
France North Sea fields, NO Dunkerque, FR 1408 1408
Germany North Sea fields, NO Emden/Dornum, DE 1106 1106
Italy
North Sea fields, NO Emden/Dornum, DE 1106
2227 Emden/Dornum, DE Bocholtz, DE/NL 456
Bocholtz, DE/NL Wallbach, CH 500
Wallbach, CH Griespass, IT 165
the Netherlands North Sea fields, NO Emden/Dornum, DE 1106
1162 Emden/Dornum, DE NL 56
Poland North Sea fields, NO Emden/Dornum, DE 1106
1730 Emden/Dornum, DE Frankfurt/Oder, DE/PL 624
Spain North Sea fields, NO Dunkerque, FR 1408
2568 Dunkerque/FR Col de Larnau, FR/ES 1160
UK North Sea fields, NO St Fergus, UK 356 356
the Netherlands
Belgium Groningue, NL Poppel, BE 400 400
France Groningue, NL Poppel, BE 400
560 Poppel, BE Blaregnies, FR 160
Germany Groningue, NL DE 40 40
Italy
Groningue, NL Bocholtz, DE 384
1049 Bocholtz, DE Wallbach, CH 500
Wallbach, CH Griespass, IT 165
UK
Groningue, NL Zelzate, BE 400
710 Zelzate, BE Zeebruge, BE 80
Zeebruge, BE Bacton ,UK 230
UK
Belgium North Sea fields, UK Bacton, UK 473
703 Bacton, UK Zeebruge, BE 230
France
North Sea fields, UK Bacton, UK 473
845 Bacton, UK Zeebruge, BE 230
Zeebruge, BE Quévy, FR 142
Germany North Sea fields, UK Bacton, UK 473 990
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Exports Transit countries
From To From To Transit pipeline
length (km)
Total length
(km)
Bacton, UK Zeebruge, BE 230
Zeebruge, BE Raeren, DE 287
Ireland
North Sea fields, UK St Fergus/Teesside, UK 237
687 St Fergus/Teesside, UK Moffat, UK 190
Moffat, UK IE 260
the Netherlands
North Sea fields, UK Bacton, UK 473
783 Bacton, UK Zeebruge, BE 230
Zeebruge, BE Zelzate, NL 80
Germany
Austria Lower Saxony, DE Oberkappel, AT 848 848
Belgium Lower Saxony, DE Eynatten, BE 400 400
Hungary Lower Saxony, DE Oberkappel, AT 848
1184 Oberkappel, AT Mosonmagyamvar, H 336
Luxembourg Lower Saxony, DE Remich, LU 600 600
the Netherlands Lower Saxony, DE 200 200
Poland Lower Saxony, DE Mallnow, PL 456 456
Sweden Lower Saxony, DE Malmö, SW 720 720
UK
Lower Saxony, DE Eynatten, BE 400
917 Eynatten, BE Zeebruge, BE 287
Zeebruge, BE Bacton, UK 230
Pipeline lengths found in the literature
Transit distances measured on a pipeline map
Remark: When different transportation routes are possible, the longest one is chosen when no
information on capacity of each route was found. Otherwise a weighted average is calculated
Algeria
Italy
Hassi R'mel, DZ DZ/TN border 552
1078 DZ/TN border Mediterranean coast, TN 371
Mediterranean coast, TN Mazara del Vallo, IT 155
Slovenia
Hassi R'mel, DZ DZ/TN border 552
2502 DZ/TN border Mediterranean coast, TN 371
Mediterranean coast, TN Mazara del Vallo, IT 155
Mazara del Vallo, IT Gorizia, SL 1424
Spain Hassi R'mel, DZ Cordoba, ES 1609
1313 Tarifa, ES Cordoba, ES 296
Portugal Hassi R'mel, DZ Tarifa, ES 1313
1873 Tarifa, ES Badajoz, PT 560
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APPENDIX 6: INVENTARY – Summary PRODUCTION AND PROCESSING
UK NL NI IT DE RU
Production+Processing Production + processing Sweetening
Production+Processing Production Processing Sweetening
Production+Processing
in Nm3/Nm3
Vented 1,74E‐03 2,00E‐04 1,85E‐02 9,40E‐04 4,80E‐04 3,00E‐05 4,95E‐04 1,10E‐03 6,00E‐05 3,00E‐05 1,16E‐03
NG burned in flares - production - sweet 5,10E‐04 5,80E‐04 1,01E‐01 4,20E‐04 4,20E‐04 2,35E‐03 2,35E‐03
NG burned in flares - production - sour 4,20E‐04 4,20E‐04 1,48E‐04 1,48E‐04
NG burned in flares - processing 2,70E‐02 1,35E‐02 1,02E‐03 2,70E‐02 1,18E‐03
Combustion rate (in compressor or turbine) 1,54E‐02 4,16E‐03 2,99E‐02 1,99E‐02 3,97E‐03 3,97E‐03 9,89E‐03 1,89E‐02 2,88E‐02
kg/NM3 Diesel 2,86E+01 9,24E‐01 2,77E‐03 9,27E‐01 kWh/Nm3 Electricity 1,37E‐01 9,90E‐04 9,90E‐04 0,00E+00 5,31E‐04 5,31E‐04
en kg/Nm3
Methanol 3,52E‐06 3,52E‐06 3,52E‐06 3,57E‐05 3,57E‐05 1,12E‐06 1,12E‐06
Ethylene Glycol 5,63E‐07 5,63E‐07 5,63E‐07 2,22E‐05 2,22E‐05
Chemicals organics 7,54E‐07
Chemicals inorganics 1,01E‐06
Ammonia 1,43E‐06 1,43E‐06
Sodium Hydroxyde 4,71E‐06 4,71E‐06
Hydrochloric Acid 6,36E‐06 6,36E‐06
Emission de CO2 9,80E‐02 4,90E‐02 9,80E‐02 5,78E‐04
Data quality
Medium for chemicals
consumption and good for the others Good Good
Medium for chemicals
consumption and good for the others
Medium for chemicals
consumption and good
for the others Good
Good for leakages, weak for flares and
medium for the others Medium Weak
police bleu 0,16% sour, 0,84 : sweet police violette 100% sweet
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NO DZ
Production Processing Kollnes
Processing Karsto
Production+Processing (47.4% Kollnes and 52.6% Karsto) Production Processing
Production+Processing
in Nm3/Nm3
Vented 2,30E‐04 4,40E‐05 6,00E‐05 2,82E‐04 1,10E‐03 6,00E‐05 1,16E‐03
NG burned in flares - production - sweet 2,23E‐03 2,50E‐03 2,50E‐03
NG burned in flares - production - sour
NG burned in flares - processing 5,32E‐04 1,02E‐03 7,89E‐04 1,02E‐03 1,02E‐03
Combustion rate (in compressor or turbine) 1,74E‐02 2,90E‐04 1,89E‐02 2,74E‐02 1,06E‐02 1,89E‐02 2,95E‐02
kg/N
M3
Diesel 8,15E‐01 2,77E‐03 8,16E‐01 9,91E‐01 2,77E‐03 9,94E‐01
enkW
h/N
m3
Electricity 1,00E‐05 4,33E‐03 5,31E‐04 2,34E‐03 5,31E‐04 5,31E‐04
en kg/Nm3
Methanol 1,12E‐06 5,89E‐07 1,12E‐06 1,12E‐06
Ethylene Glycol 3,68E‐05 1,74E‐05
Chemicals organics
Chemicals inorganics
Ammonia 1,43E‐06 7,52E‐07 1,43E‐06 1,43E‐06
Sodium Hydroxyde 4,71E‐06 2,48E‐06 4,71E‐06 4,71E‐06
Hydrochloric Acid 6,36E‐06 3,35E‐06 6,36E‐06 6,36E‐06
Emission de CO2
Data quality Good Good Good
Weak for flares and leakages and medium for the
others Medium
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TRANSMISSION BY PIPELINE
Distance in km UK Germany Netherlands Norway Russia Algeria
Austria 848 2 090 5 062
Belgium 703 400 400 1 382 6 111
Czech Republic 1 890 5 062
Denmark
Finland 3 139
France 845 560 1 408 5 930
Germany 990 40 1 106 4 845
Greece 5 392
Hungary 1 184 4 592
Ireland 687
Italy 1 049 2 227 5 442 1 078
Latvia 3 187
Lithuania 3 779
Luxembourg 600
Netherlands 783 200 1 162 6 159
Poland 456 1 730 3 699
Portugal 1 873
Slovakia 4 592
Slovenia 5 325 2 502
Spain 2 568 1 313
Sweden 720
United Kingdom 917 710 356
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Rate and consumption in Nm3/Nm3 for 1 000 km Western
Europe
Central and Eastern Europe
Russia and Africa
Energy consumption 2,05% 2,30% 2,84%
Fugitive emission rate during international transmission by pipeline over 1,000 km
0,02% 0,18%
Data quality Medium Weak
LIQUEFACTION
Rate and consumption in Nm3/Nm3 Algeria Oman Nigeria Qatar/Lybian
Flaring rate N/A 0.2% 0.4% 0.4%
Global gas autoconsumption 15.00% 9.90% 11.50% 12.90%
Pipeline length (km) 579 and 507 352 134 Q : 92 L :
120
Data quality Good TRANSPORTATION OF LNG LNG shipping distances to Europe
LNG imports : in nautical
miles Oman Qatar Algeria Libya Nigeria
Belgium 1 667
France 5 192 901 3 990
Greece 1 135
Italy 606 4 178
Portugal 3 340
Spain 4 773 4 840 346 1 239 3 567
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Rate and consumption in Nm3/Nm3
Sea transport
Fugitive emission rate (%/1 000 km) 0,00017%
Fuel gas consumption (%/1 000 km) 0,10%
Heavy fuel oil consumption (kg/Nm3/1 000 km) 1,76
Data quality Good OTHER STEPS
Rate in Nm3/Nm3 Gasification HP
transmission Storage LP
distribution
Fugitive emissions rate 0,009% 0,019% 0,105% 0,539%
Combustion rate 0,380% 0,237% 0,494% 0,122%
Electricity consumption (kWh/m3) 2,15E-04 3,39E-05 3,90E-04 5,65E-05
Data quality Good Medium Weak Medium UTILIZATION
Airborne emissions
CO2 SO2 NOX CO PM2.5 Data quality NGCC Power plant emission mg/MJin 55 500 0.5 25.5 2.2 0.5
Good
Boilers
Boiler, 10 kW mg/MJin 55 500 0.5 10 4 0.1
Boiler >100 kW mg/MJin 55 500 0.5 12.9 2.9 0.1
CHP
Lambda1, 30 kWe, condensing gas motor mg/MJin 55 500 0.5 45 48 0.15
Stirling micro-CHP, 1 kWe mg/MJin 55 500 0.5 19.4 14.5 0.1
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Allocation factors for CHP plant
Lambda1, 30 kWe,
condensing gas motor
Stirling micro-CHP,
1 kWe
Efficiency
Electric efficiency 0.315 0.15
Thermal efficiency 0.723 0.85
Allocation factors (energy allocation) (%)
Electricity allocation factor 30 15
Heat allocation factor 70 85 CONVERSION FACTORS USED IN THE STUDY
LHV of Natural gas from NL 34,9
MJ/Nm3
LHV of Natural gas from UK 37 LHV of Natural gas from DE 35 LHV of Natural gas from IT 33,85 LHV of Natural gas from NO 40,8 LHV of Natural gas from RU 36,4 LHV of Natural gas from DZ/NG/EG/LY 38,5 Average LHV of Natural gas from Marcogaz 37,2
LHV of diesel 840 kg/Nm3 Connection between energetical unit 3,6 MJ/kWh
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APPENDIX 7: Inventory results of no characterized flow
Unit
High pressure natural gas at consumer in Europe
Low pressure natural gas at consumer in Europe
Emissions per MJ
CO g 4.94E-03 4.99E-03
Particulates g 5.19E-04 5.51E-04
NMVOC11 g 8.13E-03 1.65E-02
Emissions per kWh
CO g 1.78E-02 1.80E-02
Particulates g 1.87E-03 1.98E-03
NMVOC g 2.93E-02 5.94E-02
Inventory results for the natural gas distributed in Europe in 2004
Emissions per kWh CO Particulates NMVOC
Unit g g g Heat produced at boiler - Domestic use 3.30E-02 7.18E-03 6.89E-02 Heat produced at boiler - Industrial use 2.82E-02 4.14E-03 3.89E-02 Heat produced at CHP - Domestic use 6,23E-02 8,45E-03 6,03E-02 Heat produced at CHP - Industrial use 1.85E-01 2.49E-03 6.56E-02 Electricity produced at CHP - Domestic use 1,10E-02 1,49E-03 1,06E-02 Electricity produced at CHP - Services & buildings 1.82E-01 2.45E-03 6.45E-02 Electricity produced at combined cycle plant 4.43E-02 3.25E-03 7.74E-02
Inventory results for the natural gas systems in an average consumption place in Europe in 2004
11 It should be noted that this flow may be slightly underestimated, because no leakage of NMVOC has been taken into account (propane used as refrigerant during the upstream part of the natural gas chain).
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APPENDIX 8 - Comparison with Ecoinvent and with the
European Life Cycle Database (ELCD)
General statements
Results obtained for the three impact categories studied are compared here with two reference
databases: Ecoinvent12 [5] - with and without the impacts associated to the infrastructures - and
the European Life Cycle Database13 [59] (Figure 6).
0
10
20
30
40
50
60
70
80
90
100
Global Warming Acidification Non renewable resource depletion
%
Ecoinvent
Ecoinvent (w/o infrastructure)
ELCD
Marcogaz
Figure 6: Comparison of the results for the 3 impact categories studied with Ecoinvent and ELCD
(Results obtained with Ecoinvent set at 100%).
The following comments can be made from a global point of view:
• The Ecoinvent database results in higher impacts (even when infrastructures are not taken
into account) in the 3 categories and in relatively high proportions (respectively 32 and
34% lower for ELCD and Marcogaz).
• Regarding global warming and non renewable energy depletion, Marcogaz and the ELCD
seem to be very close.
• Regarding acidification however, the results from ELCD are closer to those from Ecoinvent
than from Marcogaz results.
The comparison of the three sources is further elaborated for each impact category in the following
paragraphs.
12 The data used refer to 1 MJ 'Natural gas, low pressure, at consumer/RER U' in the Ecoinvent database (version 2.0). 13 The data used refer to the dataset “Natural Gas; from onshore and offshore production incl. pipeline and LNG transport; consumption mix, at consumer; desulphurised (en)”.
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Detailed comparison for global warming
There is a significant difference regarding global warming potential associated to 1MJ of natural gas
distributed in the Ecoinvent database on the one hand and in the ELCD and Marcogaz on the other
hand. Figure 7 gives the respective contribution of each greenhouse gas in the three studies.
51%49%
0%
62%
38%
0%
53%
51%
0%
49%
47%
0%
0%
20%
40%
60%
80%
100%
120%
CO2 CH4 N2O Total
EcoInvent
EcoInvent(w/o infrastructure)
ELCD
Marcogaz
Figure 7: Comparison of the contribution of each individual flow to global warming. Percentages
above the each bar indicate, in each study, the contribution of a given flow to the total impact.
N2O has a negligible impact in all the studies, whereas CO2 and CH4 are the main contributors.
Differences can be observed both on CO2 and on CH4 emissions:
• CO2 emissions in the ELCD are 18% lower than in Ecoinvent and 31% in the Marcogaz
study.
• CH4 emissions are the lowest in the ELCD (48% lower than in Ecoinvent) and are 36%
lower in the Marcogaz study if compared to Ecoinvent. An explanation can be found in the
different leakage rates assumed in Ecoinvent and in Marcogaz during pipeline
transportation of the natural gas (cf. Table 24 and Table 25). Assumptions made in the
ELCD are not detailed, so it is not possible to compare the leakage rates.
Detailed comparison for acidification
Impacts in terms of acidification potential are significantly different in the three studies: again
Ecoinvent has the higher impact, followed by the ELCD (21% lower) and the Marcogaz study (57%
lower). The Figure 8 shows the detailed contributions of each individual flow to acidification.
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42% 58% 0%
36%
64%
0%
77%
23%
0%
40%
60%
0%0%
20%
40%
60%
80%
100%
120%
NOX SOX NH3 Total
EcoInvent
EcoInvent(w/o infrastructure)
ELCD
Marcogaz
Figure 8: Comparison of the contribution of each individual flow to acidification. Percentages above
the each bar indicate, in each study, the contribution of a given flow to the total impact.
NOX and SOX are the two main contributors to acidification. NH3 is not followed in the Marcogaz
study, but even if it is taken into account, in the Ecoinvent or in the ELCD inventory, its
contribution to the acidification potential is negligible. The main difference between the three
studies is related to the SOX emissions: Ecoinvent and the ELCD show comparable results, whereas
in the Marcogaz study, SOX emissions are significantly lower (83% lower than in Ecoinvent). The
main parameter explaining this difference is the assumption made on sour gas proportion for
natural gas produced in Russia: Ecoinvent assumes a rate of 20% of sour gas whereas the
assumption in the Marcogas study is 5.9%14.
Detailed comparison for non renewable energy depletion
As it was observed for climate change, the ELCD and the Marcogas study show similar results
regarding non renewable energy depletion, significantly below the results from Ecoinvent
(respectively 54% and 58% below). For the three studies, this impact is linked mainly to the
natural gas consumed (for energy production or because of leakages) along the chain (Figure 9):
natural gas represents 92% of the total impact in the Marcogaz study, and respectively 94 and
95% of the total impact in Ecoinvent and in the ELCD.
14 Both studies use an assumption of50% of sour gas in Germany.
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1% 2%95%
1%
0%1%
99%
0%
1%
4%
95%
0%
2%
2% 92%
3%
0%
20%
40%
60%
80%
100%
120%
140%
160%
Coal(Brown+hard)
Crude oil Natural gas Uranium Total
EcoInvent
EcoInvent(w/o infrastructure)
ELCD
Marcogaz
Figure 9: Comparison of the contribution of each individual flow to non renewable energy depletion.
Percentages above the each bar indicate, in each study, the contribution of a given flow to the total
impact.
Various parameters can explain the difference between Ecoinvent and the Marcogaz assessment,
among wich:
• Assumptions made about the leakage rates.
• Energy consumption at each step of the chain and type of energy used (in particular the
splitting between diesel oil, coal, natural gas and electricity).
• Accounting or not for the infrastructures.
A need to provide reliable data that could be used in European
regulations
Generally the LCA results support the figures for global warming and non-renewable energy
depletion used in existing generic LCA databases such as ecoinvent or the ILCD project. However,
important differences between Eurogas-Marcogaz LCA results and those databases have been
noticed for some emission data, particularly for CH4 and SOX emissions:
→ Methane emissions on the transmission and distribution grids are 2 to 8 times higher in
ecoinvent than the fugitive emission rates measured on the networks of different European
companies. This results in a reduction by a third of the total methane emissions associated
with the domestic systems assessed in this study compared to other databases.
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→ The ILCD database overestimates SOX emissions by a factor 2 and the ecoinvent model
for the European natural gas supply was based on a share of sour gas of 10.2%,
representing the average European supply in 2000. However, in 2004, the estimated part
of sour gas only reached 3.4%. This explains that the domestic systems assessed in this
study emit less SOX on their whole life cycle than the corresponding systems in the
ecoinvent database.
The differences noticed highlight the importance not to base environmental decisions on generic
databases without first assessing their relevance and applicability.
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APPENDIX 9: Synthesis of the peer review
1. Introduction
The aim of this critical review was to optimize the quality and to strengthen the credibility of the life cycle assessment of the European Natural gas chain performed by Eurogas and Marcogaz.
The critical review was carried out by a reviewing committee with experts from different scientific backgrounds suitable with the challenges of this LCA study:
- Yannick Le Guern, Manager at BIO Intelligence Service, expert in LCA,
- Charlotte Petiot, Project leader at BIO Intelligence Service, expert in LCA,
- Dominique Marchio, Professor and senior scientist at MINES Paris Tech, expert in the field of natural gas and energy.
Following ISO 14 044, the reviewing committee checked if:
‐ the methods used to carry out the LCA were consistent with the International Standard,
‐ the methods used to carry out the LCA were scientifically and technically valid,
‐ the data used were appropriate and reasonable in relation to the goal of the study,
‐ the interpretations of the results reflected the limitations identified and the goal of the study,
‐ the study report was transparent and consistent.
The critical review was conducted between September 2010 and June 2011. A meeting, several telephone conferences and several discussions by e-mail took place during this period.
The exhaustive list of comments from the reviewing committee and the answers from Eurogas and Marcogaz are presented in appendix.
The following chapters present the summary of the critical review.
2. Consistency with ISO standards
The LCA report is compliant with the requirements of the standards ISO 14040 and
14044.
During the critical review, the title and the objective of the study were improved to
reflect in a better way the scope of the study and the fact that this LCA report is
focused on three environmental impacts indicators.
The different functional units are consistent with the goal of the study: “to deliver 1
MJ of natural gas to consumer in the EU-25 in 2004”, “to deliver 1 kWh of electricity
with the best available technologies”, “to deliver 1 kWh of useful heat with the best
available technologies”. These functional units reflect the fact that the supplied gas is
representative of natural gas consumed in Europe (current mix of technology)
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whereas the use phase is representative of best available technologies (natural gas
combined cycle, condensing modulating boiler, combined heat and power
generation).
The scope of the study and the system boundaries are clearly defined with a detailed
description of the natural gas chain.
The interpretation of the results follows the recommendations of the standards
concerning transparency of assumptions, sensitivity analysis and limitations.
Concerning the limitations, the reviewing committee points out that the 2 main
limitations of the study are the following:
- This study is focused on 3 environmental impact indicators (climate change, acidification, non renewable energy demand) and does not cover all environmental impacts of the natural gas chain.
- This study does not take into account infrastructures.
3. Scientific and technical validity of the methods
The methodology used for estimating consumptions and emissions along the gas
chain is clearly detailed in the report.
The presentation of the allocation procedures carried out at the different life cycle
steps were improved during the critical review. Most of the allocations are based on
energy content, which is considered appropriate considering the goal and scope of
the study.
a. Appropriateness of data
An important work of bibliography was conducted to compare the available data and
select the most relevant data considering the objective of the study.
Data quality was assessed on the basis of the following criteria: time period, geographic area,
representativeness (market share of the collected data), type of data (measured data, aggregated
data, theoretical data).
Data used mainly come from publications of oil and gas industries, international organisations,
environmental agencies and from the ecoinvent database. They are judge appropriate and
reasonable in view of the goal of the study.
During the critical review, an valuable appendix was added to the report in order to present a
summary of all the data used for the calculation of the life cycle inventory.
b. assessment of the interpretation in view of limitations and goal and scope
Check conducted by the reviewing committee allows to state with reasonable assurance that the
results do not contain significant errors.
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The results are analyzed in depth.
Regarding the sensitivity analysis, the choice of sensitive parameters is clearly explained and the
effects of parameter variations on results are detailed. These analysis allow to assess the
robustness of the results.
The conclusion and the abstract present in an objective way:
- the contribution of the different life cycle steps to the overall environmental impact of the natural gas chain,
- the main priorities to improve the natural gas chain environmental performance.
c. Transparency and consistency of the report
The report is clearly structured and well readable. It is acknowledged as transparent and
consistent.
d. Conclusion of the critical review
The critical review was constructive and helped enhance the quality of the LCA report.
Following this process, the reviewing committee certifies that:
‐ the LCA report complies with the requirements of the ISO standards 14040 and 14044,
‐ the goal and scope are appropriately defined,
‐ the methods used are scientifically and technically valid,
‐ the data used are appropriate and reasonable in view of the goal and scope of the study,
‐ the conclusion is consistent with the results, the sensitivity analysis and the limitations mentioned in the report,
‐ the report is complete, clearly structured and well-readable.
For the update of the study, the reviewing committee recommends achieving a more
comprehensive evaluation of the environmental performance of natural gas chain:
‐ by studying more flows and including more environmental impact indicators (like photochemical oxidation, abiotic depletion,ecotoxicity…),
‐ by including the impacts of the infrastructure of the natural gas chain.
June 2011
The reviewing committee:
- Yannick Le Guern
- Charlotte Petiot
- Dominique Marchio