Life Cycle Assessment of the European Natural Gas Chain … · 2017-04-03 · methods on LCA, the...

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)

WG-LCA-12-01 22/06/2011 LCA report

Page 5

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.


Page 7

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


Page 8

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



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


Page 9

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


Page 10

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


Page 11

1 GOAL AND SCOPE DEFINITION


Page 13

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.


Page 14

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.


Page 15

→ 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.


Page 16

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.


Page 17

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


Page 18

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


Page 19

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.


Page 20

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.


Page 21

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.


Page 22

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


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.


Page 23

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


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.


Page 24

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.


Page 25

2 DESCRIPTION OF THE NATURAL GAS

CHAIN - IDENTIFICATION OF

POTENTIAL EMISSION SOURCES


Page 27

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].


Page 28

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;


Page 29

→ 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


Page 30

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


Page 31

2.3 Natural gas processing


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.


Page 32

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.


Page 33

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


Page 34

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


Page 35

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


Page 36

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.



The main atmospheric emissions of the process are3 detailed in Table 6.


NOX, CO, CO2

Emissions due to the use of compressors

Flaring

Boilers

SO2 Desulphurisation

Boilers

CH4

Leakages

Fugitive emissions


exhaust gases from gas engines and combustion facilities

Table 6: Sources of emissions – Processing



Consumptions Source

Natural gas Consumption in the boilers


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.


Page 37

2.4 Natural gas pipeline transmission


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.


Page 38

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.


Page 39

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


Page 40

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.





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



Consumptions Source

Natural gas Compressors

Diesel Diesel emergency power plant

Electricity Compressors and utilities

Oil Lubrication

Odorants Odorisation

Table 9: Sources of consumptions – Transmission


Page 41

2.5 LNG chain


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.


Page 42

→ 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.


Page 43

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.


Page 44

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;


Page 45

→ 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.





SOX Combustion of gasoline for LNG tankers propulsion


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.)





Table 10: Sources of emissions – LNG chain


Page 46



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


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


Page 47

2.6 Storage


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


Page 48

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).





NOX, CO, CO2

Compression

Boilers for treatment

Flares

CH4

Fugitive emissions (small leaks from flanges, pipe equipment, valves etc.)





Table 12: Sources of emissions – Storage


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


Page 49

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]


Page 50





CH4 Fugitive emissions (small leaks from flanges, pipe equipment, valves etc.)

Emissions from third part interference

Table 14: Sources of emissions – Distribution


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


Page 51

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


Page 52

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



NOX, CO, CO2 Emissions due to gas turbines

CH4

Fugitive emissions (small leaks from flanges, pipe equipment, valves, etc.)




from gas engines

Table 16: Sources of emissions –Combined cycle

Figure 14: Combined cycle process schematic


Page 53

2.8.2.2.2 Consumptions


Consumptions Source

Natural gas Consumption in the turbines


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.





NOX, CO, CO2 Boilers

CH4

Fugitive emissions


exhaust gases

Table 18: Sources of emissions –Boiler


Page 54



Consumptions Source


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).


Page 55





NOX, CO, CO2 Boilers

CH4

Fugitive emissions


exhaust gases

Table 20: Sources of emissions – CHP plant



Consumptions Source


Electricity For auxiliary equipments

Catalyst To reduce NOX emissions

Table 21: Sources of consumptions – CHP plant


Page 57

3 METHODOLOGY, MAIN ASSUMPTIONS


Page 59

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.


Page 60

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


Page 61

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)


Page 62

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.


Page 63

4 NATURAL GAS MARKET IN EUROPE


Page 65

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%


Page 66

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%


Page 67

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


Page 68

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)


Page 69

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%).


Page 70

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)


Page 71

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.


Page 73

5 INVENTORY


Page 75

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


Page 76

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


Page 77

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].


Page 78

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.


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].


Page 79


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.


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


Page 80



→ 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.


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.


MJ/MJ [20] [5] [23] This report - [23]


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


Page 81

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.


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.


Page 82

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.


Page 83

• 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]


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.


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


Page 84



→ 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.


European context”, LBST [20].

The following tables show the consumptions figures expressed as % of the natural gas produced

based on the energy content.


MJ/MJ [20] [5] [24] This report –[24]


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%


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.


Page 85

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.


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.


Page 86

Figure 27: Natural gas production in Great Britain



→ 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.


European context“, LBST [20].


Page 87


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]


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.


Page 88


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


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.


Page 89


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


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


Page 90

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.


Page 91

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


Page 92

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).


MJ/MJ [5] This report – [5]


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


Page 93

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.


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.


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.


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


Page 94


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]


Sonatrach dominates natural gas production and wholesale distribution in Algeria, while another

state-owned company, Sonelgaz, controls retail distribution.


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:


Page 95

→ 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.


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].


MJ/MJ [20] [5] [19]

This report –

[5], [19]


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,


Page 96

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.


MJ/MJ [5] This report – [5]


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


Page 97

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.


Page 98

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


Page 99

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


Page 100

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%


Page 101

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%


Page 102

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].


Page 103

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].


Page 104

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,


Page 105

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.


Page 106

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


Page 107

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.


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.


Page 108

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.


Page 109

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).


Page 110

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)


Page 111

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)


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.


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[].


Page 112

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.


Page 113

→ 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]


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


Page 114

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


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:


Page 115

→ 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.


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%


Page 116

Table 52: Collected data – High pressure transmission - Europe


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.


Page 117

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


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




Page 118

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.


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


Page 119

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


Combustion rate 0.000% 0.211% 0.164% 0.122%


Table 55: Collected data – Low pressure distribution – Europe



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


Page 120

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


Page 121

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.


Page 122

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



Lambda1, 30 kWe, condensing gas motor m

g/

MJ i

n

55 500 0.5 45 48 0.15



Stirling micro-CHP,

1 kWe mg/

MJ i

n

55 500 0.5 19.4 14.5 0.1


Page 123

Allocation factors (energy allocation) (%)

Electricity allocation factor 30 15

Heat allocation factor 70 85

Table 61: Allocation factor for a CHP plant


Page 125

6 LCA RESULTS OF THE EUROPEAN

NATURAL GAS CHAIN


Page 127

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.


Page 128

Consumption in primary energy per kWh Unit


Europe


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


Europe


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%.


Page 129

→ 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


Europe


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


Page 130

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


Page 131

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


Page 132

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.


Page 133

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


Page 135

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


Page 136

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.


Page 137

→ 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.


Page 138

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


Page 139

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%



NGCC



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.


Page 140

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:


Page 141

→ 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.


Page 142

7 SENSITIVITY ANALYSES


Page 143

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.


Page 144

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.


Page 145

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%.


Page 146

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%


Page 147

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)


Page 148

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)


Page 149

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.


Page 151

8 CONCLUSIONS


Page 153

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.


Page 154

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 .


Page 155

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


Page 156

[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)


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


Page 159

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


Page 161

APPENDICES


Page 163

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).


Page 165

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


Page 166

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.


Page 167

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.


Page 169

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.


Page 171

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]


Page 172

D399

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


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




Finland Gryazovets, RU Imatra, FI 936

3139 Gryazovets, RU Orsha, BY 872

France


5930

Sumy, UA Velke Kapusany, SK 1216



Waidhaus, DE Medelsheim, FR 467

Germany





Germany

Siberian fields, RU Orsha, BY 3075

4383 Orsha, BY Kondratky, PL 556

Kondratky, PL Frankfurt/Oder, DE 684

Greece


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




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



Page 173

D399



length (km)

Total length

(km)



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


Slovenia




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


Zeebruge, BE Quévy, FR 142

Germany North Sea fields, UK Bacton, UK 473 990


Page 174

D399



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


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


Page 175

D399

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


consumption and good for the others


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


Page 176

D399

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


Page 177

D399

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


Page 178

D399

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


Page 179

D399

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


Page 180

D399

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


Page 181

D399

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).


Page 182

D399

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)”.


Page 183

D399

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.


Page 184

D399

42% 58% 0%

36%

64%

0%

77%

23%

0%

40%

60%

0%0%

20%

40%

60%

80%

100%

120%

NOX SOX NH3 Total

EcoInvent


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.


Page 185

D399

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


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.


Page 186

D399

→ 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.


Page 187

D399

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)


Page 188

D399

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.


Page 189

D399

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

Life Cycle Assessment of the European Natural Gas Chain … · 2017-04-03 · methods on LCA, the...

Documents

Transcript of Life Cycle Assessment of the European Natural Gas Chain … · 2017-04-03 · methods on LCA, the...