EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN Antonio Taglia, Manager Consultant Altran Italia, (39) 348 8004912, [email protected] Nicola Rossi, Technical Consultant Altran Italia, (39) 333 7555274, [email protected]

1. Abstract Natural gas imports to Europe will increase with a constant annual rate of 4,5% due to both the reduction of internal production and the constant increase in gas demand. As a consequence the total amount of gas to be imported to Europe in 2025 is forecasted to be around 600 bcm, doubling the current value. This element, supported by the supply diversification that European Union is pursuing, is pushing towards the construction of new regasification terminals leading to an increase of possible gas suppliers. Gas is imported into Europe by two ways: through pipeline in gaseous form or alternatively by LNG supply chain, it is liquefied, transported in vessels and finally regassified in Europe. These two chains differ not only from the physical and economical point of view, but also from the environmental one. In order to transport the gas from the production fields to Europe, energy is required and its overall amount differs according to the way and the path the gas is imported. Furthermore other factors, like methane fugitives and nitrous oxide emissions, are affected not only by the physical characteristics of the chain, but also from the technology used and from obsolescence of installations. The aim of this paper is to analyse from the environmental and economical point of view the global impact of the gas that enters into Europe, investigating the contribution of all the chain steps, starting from the production of the gas until the consumption in a “combined cycle gas turbine” (CCGT) plant for power generation. Six different real cases are studied: three regard a pipeline-based transport and three regard LNG production, transport through tankers and regasification. These six real cases are compared to the GHG emissions of a reference case: power generated in a CCGT plant in North Africa and imported to Europe. The six cases studied are: 1. Case A1: gas production in the Yamburg and Urengoj fields (Russia), transport through Central and Northern Corridor pipelines and consumption in Germany 2. Case A2: gas production in Bahr Essalam field (Libya), transport through Greenstream pipeline and consumption in Italy 3. Case A3: gas production in Krechba, Teg and Reg fields (Algeria), transport through Maghreb Europe Pipeline and consumption in Spain 4. Case B1: gas production in West Delta Deep Marine (Scarab and Saffron fields) concession (Egypt), liquefaction in Segas LNG plant (Egypt), regasification in Panigaglia (GNL Italia) and consumption in Italy 5. Case B2: gas production in North field (Qatar), liquefaction in Qatargas 2 LNG plant, regasification in Adriatic LNG plant and consumption in Italy 6. Case B3: gas production in Dolphin field (Trinidad and Tobago), liquefaction in Atlantic LNG plant (Trinidad), regasification in Bahia de Bizkaia (Bilbao) and consumption in Spain The average value of the chain emissions is around 13 kgCO2eq/mmbtu (mmbtu = million British thermal unit) of natural gas imported, but the overall emissions could be up to 19 kgCO2eq/mmbtu (+45%) in the pipeline chain A1 (Russia – Germany). Considering that the CO2 emissions from the combustion of the natural gas is around 54 kgCO2eq/mmbtu, the emissions of the supply chain increase the overall emissions near by 25%. Along the supply chain the steps that give the most important contribution to the emissions are the treatment and the transport (pipeline and liquefaction+shipping), while the emissions from the production and regasification activities are limited. From an analysis of the results, we highlight that several factors strongly affect the GHG emissions of the gas supply chain:
The efficiency of the liquefaction and regasification process: different technologies show widespread values of thermal efficiencies.
The efficiency of the midstream step of the chain: performance of the LNG tanker engine (older/newer technology, motor size, fuel used) and performance of pipelines (pressure, diameter, natural gas leakages).
CO2 concentration in the raw gas (production fields can have a CO2 content up to 14%mol of the raw gas compared to a worldwide average of 2%mol) In conclusion, this analysis gives an outlook of the economical and environmental impact of the different supply chains for gas import to Europe. Till now the decisions about the supply have been based on economical or political factors, neglecting the environmental impact. However, Europe, which aims to cut GHG emissions, should consider also the supply chain emissions, given that a remarkable reduction of overall emissions would be feasible (a decrease of 15% in the 2025 gas supply chain emissions would cut around 55 Mton CO2, 1% of the total European 2005 CO2 emissions).

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

2. Introduction Natural gas imports to Europe will increase with a constant annual rate of 4,5% due to both the reduction of internal production and the constant increase in gas demand. As a consequence the total amount of gas to be imported to Europe in 2025 is forecasted to be around 600 bcm, doubling the current value [1]. This element, supported by the supply diversification that European Union is pursuing, is pushing towards the construction of new regasification terminals leading to an increase of possible gas suppliers. Gas is imported into Europe in two ways: through pipeline in gaseous form or it can be liquefied, transported in vessels and finally regassified in Europe. These two different import ways continue to exist because for shorter distances, pipelining is usually more economical than LNG processing. Moving LNG by tanker requires costly liquefaction and regasification processing, regardless of the distance over which the gas has to be moved. Therefore, although the costs of moving the LNG over distance, once liquefied, are less than those of pipeline gas, short-haul LNG (less than 3000 km) is usually not competitive with pipelining. Pipeline transmission Production

EUROPEAN BORDER

Processing NG Liquefaction

Natural Gas LNG UPSTREAM

Tanker transport MIDSTREAM

LNG regasification DOWNSTREAM

Figure 1 – Potential Gas supply chains to Europe

These two chains differ not only from the physical and economical point of view, but also from the environmental one. In order to transport the gas from the production fields to Europe, energy is required and its overall amount differs according to the way and the path the gas is imported. Furthermore other factors, like methane fugitives and nitrous oxide emissions, are affected not only by the physical characteristics of the chain, but also from the technology and its obsolescence.

3. Study objectives The aim of the paper is to analyse from the environmental and economical point of view the global impact of the gas that enters into Europe, investigating the contribution of all the chain steps, starting from the production of the gas until the consumption in a “combined cycle gas turbine” (CCGT) plant for power generation. Six different real cases are studied: three are about a pipeline-based transport and three about LNG production, transport through tankers and regasification. These six real cases are compared to the GHG emissions of a reference case: power generated in a CCGT plant in North Africa and imported to Europe. The six cases studied are: 1. Case A1: gas production in the Yamburg and Urengoj fields (Russia), transport through Central and Northern Corridor pipelines and consumption in Germany 2. Case A2: gas production in Bahr Essalam field (Libya), transport through Greenstream pipeline and consumption in Italy 3. Case A3: gas production in Krechba, Teg and Reg fields (Algeria), transport through Maghreb Europe Pipeline and consumption in Spain 4. Case B1: gas production in West Delta Deep Marine (Scarab and Saffron fields) concession (Egypt), liquefaction in Segas LNG plant (Egypt), regasification in Panigaglia (GNL Italia) and consumption in Italy 5. Case B2: gas production in North field (Qatar), liquefaction in Qatargas 2 LNG plant, regasification in Adriatic LNG plant and consumption in Italy 6. Case B3: gas production in Dolphin field (Trinidad and Tobago), liquefaction in Atlantic LNG plant (Trinidad), regasification in Bahia de Bizkaia (Bilbao) and consumption in Spain

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

Case A1 Natural gas is produced in the Yamburg and Urengoj fields, two giant gas fields with a YAMBURG FIELD (RUSSIA) combined production of about 370 bcm/y, and lightly treated locally thanks to the low CO2 Northern corridor URENGOJ FIELD content (less than 3%vol) [2]. Part of the produced 4300 km (RUSSIA) gas (112 bcm/y) is sent in the two export corridor GERMANY Central Corridor (Northern Corridor and Central Corridor), in 5500 km order to deliver the gas to the central Europe. The pipelines of the Central Corridor, built during the 80’s and 90’s, consist for the most part of 4-6 parallel pipe runs with diameter of 54 inch with a working pressure of 75 bar. Instead the older Northern Corridor, built around 1970, consist of 2-4 parallel pipes of 40 inch with a working pressure of 55 bar. Part of the gas is distributed in the transit countries and about 30 bcm/y is delivered to Germany. Case A2 The natural gas produced in Bahr Essalam field, an offshore field located 110 km off the Libyan coast, has an high concentration of CO2 (about 13,5%vol) [3][4], so it needs a strong pre-treatment to reach the specification for the delivery. The treatment is done in the Mellitah plant, where 89% of CO2 is removed from the raw gas, in order to reach the desired CO2 content of 1,5%vol. Then, gas is sent to Italy (Gela, in Sicily) through the Greenstream pipeline, the longest underwater pipeline ever laid in the Mediterranean Sea: it has a diameter of 32 inch, and it is around 520 km length and it crosses the sea at a maximum depth of 1127 meters. The pipeline working pressure is around 148 bar (high pressure pipeline); it was built in 2003-2004 and delivers 8 bcm/y of gas to Italy.

BAHR ESSALAM FIELD ITALY MELLITAH TREATMENT PLANT

GreenStream 520 km LIBYA

Case A3 Natural gas from Krechba, Teg and Reg, that have a CO2 content up to 9%vol (average 5,5%vol) [4], is collected and treated in Khrechba plant in order to meet the specification of CO2 content in the gas of 0,3%vol to enter in SPAIN the main export pipeline. The CO2 separated, To Hassi instead to be vented to atmosphere, is re- Maghreb Europe Hassi R’Mel R’Mel injected in the Khrechba reservoir for long Pipeline - 1830 km KRECHBA time sequestration, eliminating about 1 Mton FIELD CO2 per year [5]. The treated gas from In Salah Area TEG FIELD (ALGERIA) Khrechba is sent to Hassi R’Mel (380 km) and REG FIELD then in the Maghreb–Europe Gas Pipeline (MEG), a 1450 kilometres long natural gas pipeline that transports 8,6 bcm/y up to Cordoba in Andalusia (Spain) where it is connected with the Spanish and Portuguese gas grids. The pipeline's Algerian, Moroccan and Andalusian sections are 48 inches in diameter and the underwater sections consist of two 22 inch lines. The pipeline working pressure is around 70 bar (low pressure) and was commissioned in 1996.

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

Case B1 SCARAB and SAFFRON FIELD (EGYPT) Scarab and Saffron are two gas field located in the West Delta Deep Marine (WDDM) 250 km Concession area north of the Nile Delta, 90km GNL ITALIA SEGAS LNG offshore of Egypt and at a water depth of (ITALY) 650m. The produced gas is primarily methane, with no H2S and less than 1%vol of CO2 [6]. 1276 nautical miles The produced gas is sent to Idku, where is treated to reach Egyptian gas distribution specification, and then to Segas LNG Plant EGYPT (Damietta), where is liquefied with a C3-MR process (licensed by APCI [7]). The total capacity of the liquefaction train is around 5,1 Mton/y of LNG. In this case we assume to transport the gas with a fleet composed by 4 vessels with a capacity between 41.000 and 66.000 m3, all equipped with steam turbine propulsion, that use boil-off gas (about 40%) and heavy fuel oil (about 60%) as fuel. The LNG is regasified in the GNL Italia terminal, located in Panigaglia, near La Spezia. In operations since 1971 with a send out capacity of 3,5 Bcm/y, this onshore terminal is equipped with Submerged Combustion Vaporization system to regassify the LNG (some gas is burn to heat the LNG). Case B2 South Pars (IRAN) Natural gas is produced in the offshore North Field, which is the world’s largest non100 km NORTH FIELD (QATAR) associated natural gas field, with a low quantity QATARGAS 2 ADRIATIC LNG (ITALY) of CO2 (2,2%vol) [8] and sent to the Ras Laffan treatment and liquefaction (Qatargas 2) plant with a 100 km subsea pipeline. The Qatargas 2 include two liquefied natural gas 4378 nautical miles (LNG) trains with the new Air product’s QATAR proprietary APX process technology [7], each with a capacity of 7,8 Mton/y. The fleet, that cover the 4378 nautical miles between the liquefaction plant and the regasification plant in the offshore of Rovigo (Italy), is composed by vessels of about 140000 m3 of capacity. The tankers, build between 1998 and 2007 are moved by a steam turbine propulsion system (eg. case A1). The LNG is regasified in the new offshore regasification terminal built 15 km offshore Rovigo (Italy). The terminal (8 bcm/y send out) is a large gravity based structure (GBS) resting on the seabed at 29 meters mean sea level. The terminal is equipped with four Open Rack Vaporizers (ORV's) which use seawater as the heating source to regasify LNG. Case B3 Gas is produced in the Cannonball field, located 50 km off the southwest coast of Trinidad in 80 meters water depth. The gas, with a very low content of CO2 (about BAHIA DE BIZKAIA LNG (SPAIN) 0,43%vol) [9] is sent to Port Fortin where is ATLANTIC LNG CANNONBALL 140 km FIELD treated and liquefied in the Atlantic LNG (train 4) train 4 plant. The liquefaction process of this train is based on Phillips Optimized Cascade [10], that can supply 5,2 Mton/y of LNG. The 3645 nautical miles fleet that is used for the transport in Europe is based on vessels of about 130000 m3, built TRINIDAD and TOBAGO mainly after 2000. All the vessels have a propulsion system based on steam turbine. The LNG is regasified in the Bahia de Bizkaia regasification plant, near Bilbao, that has a capacity of 7,4 bcm/y and was commissioned in 2003. The regasification is done, in ordinary operations, with Open Rack Vaporizers that uses the condensed water of the connected Combined Cycle Power Plant.

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

4. Methodology The study encompasses five steps: 1. Definition of the main current and future European gas suppliers. This activity deals with: analysis of the current gas/LNG flows, analysis of the supply contracts, development of new import and export infrastructures. 2. Set up of six different scenarios of supply, on the base of the analysis of the step 1. Three cases are based on pipeline transport and three on LNG production, transport through vessels and regasification, as presented in the figure 1. 3. GHG’s emissions analysis of the six different gas chains, considering for each part of the chain: fuel consumption (and resulting CO2, methane and NOx emissions), natural gas venting from leakages, CO2 venting (e.g. for natural gas sweetening in the treatment facilities), gas flaring. This data are calculated by taking into account: efficiency of technologies in the different chain steps, site specific characteristics of the production fields (e.g. CO2 content in the raw gas), transport distance and type of gas chain (LNG or pipeline). 4. Analysis of the results and comparison of the six scenarios from the environmental point of view (energy consumption, GHG emissions). 5. Economical comparison of the six cases in order to underline the gas supply cost as a function of the distance among the production field and the European border.

4.1. Limits of the study This study identifies and quantifies all significant sources of greenhouse gas emissions linked to the delivery of the gas through the six chains on the European border. The boundaries begin with the production of natural gas in an existing field and end with the gas in the distribution network. In this study are so included not only the methane emissions from leaks, maintenance works and breakdown, but also the emissions of carbon dioxide and nitrous oxide from the use of energy for gas production, treatment, transportation. In this study are excluded: • Emissions from the production of materials embodied in the supply chain (eg. steel for tanker construction, concrete for plant construction, etc.) • Emissions due to energy consumption from shipyards, engine manufacturers, plant engineers and due to the construction of the pipelines and the regasification, liquefaction, production and treatment facilities. • Emissions from operational and management personnel travel, supply vessels, etc. • Emissions from the heating of buildings, motor vehicle are negligible and are not investigated in detail here.

4.2. GHG emissions calculation methods The core of this study is the evaluation of the GHG emissions and, as a consequence, the calculation methodology is a fundamental step to be described. In Figure 2, is reported the gas supply chain with the detail of all the GHG emissions considered in the study. In this study the Greenhouse gas emissions (GHG) are calculated in terms of Carbon Dioxide Equivalents (CO2 Eq), in which all of the GHGs are converted to an equivalent basis relative to their “global warming potential” (GWP). The considered greenhouse gases are CO2, CH4, and N2O with the following GWP value: 1, 21, and 310. Combustion exhaust Fugitive

Combustion exhaust Fugitive Flaring

Production ENERGY

Combustion exhaust Fugitive CO2 Venting

Processing

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Combustion exhaust Fugitive

Combustion exhaust

Combustion exhaust Fugitive

NG Liquefaction

Tanker transport

LNG regasification

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ENERGY

ENERGY

UPSTREAM

ENERGY

MIDSTREAM

ENERGY

DOWNSTREAM

Figure 2 – Gas supply chain main emissions

With the term “fugitive” we have considered the following primary types of emissions, as reported in [11]: • fugitive equipment leaks • process venting (excluding the CO2 venting in the “Processing” step) • evaporation losses • disposal of waste gas streams (excluding the Flaring activities in the “Production” step) • accidents and equipment failures. While methane (CH4) is the predominant type of greenhouse gas emitted as a fugitive emission in the oil and gas sector, noteworthy fugitive emissions of carbon dioxide (CO2) and, to a much lesser extent, nitrous oxide (NOx), may also occur. CO2 venting are excluded from the fugitive category only because CO2 is present as a natural constituent of produced natural gas and

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

it is considered separately because often occurs in high concentrations: as a consequence it is stripped from the produced gas during the processing phase and it’s interesting to analyze this amount because its high grade of purity and its easiness to be managed. For the same reason we have separated the flaring emissions in the Production phase. The calculation methodology is based on a combination of a “bottom-up” technique for the main emissions factor (eg. emissions from energy production) and a more general “top-down” approach for the elements with a minor impact on the total emissions. The GHG emissions analysis of the six gas supply chains encompasses the following steps, corresponding to the different chains: Production, Processing, Pipeline transmission, NG Liquefaction, Tanker transport, LNG regasification: 1. The GHG emissions calculation for the gas production is done in the following way: • The energy spent (measured in amount of gas) for the gas Production is estimated as a rate of the total gas produced. This rate, that vary from 1% to 2,2% of the total gas produced, differs in each chain due to the following elements, as reported in [12][13]: distance from the treatment plant, fields spread, location (onshore or offshore), presence of water injection to enhance the gas production, gas characteristics (presence of heavier hydrocarbons). • The emissions from methane venting (mainly from pneumatic device and dehydration vents) and the fugitive emissions of all the gas fields (mainly due to equipment leaks like Xmas tree and connections) are calculated as a rate on the total gas production based on the factors reported in [14]. • The leakages from the gathering pipelines that connect the gas field to the treatment plant are estimated as a rate based on the distance and the gas transported taken from [15] and [33] respectively for onshore (0,497 mg CO2eq/MJ*km) and offshore pipelines (0,124 mg CO2eq/MJ*km). The emission factor of the offshore pipeline is about 75% less than the onshore due to the limited number of gas compressions station, where are concentrated most of the fugitive emissions. • Flares are used to manage the disposal of hydrocarbon products from routine operations, upsets, or emergencies via combustion. Combustion efficiency, and therefore flare performance, is highly variable, primarily dependent on the flare types (eg. small open-ended pipes at production wellheads, large horizontal or vertical flares with pilots) and flame stability. This depends on the gas velocity, heat content, and wind conditions. General industry practice relies on the widely accepted data that properly operated flares achieve at least 98 percent combustion efficiency (98% of natural gas is converted to CO2) [14]. For gas production flares, where greater operational variability exists, CH4 emissions may be based on an assumed value of 2% non combusted. Very little information is available for N2O emissions from petroleum industry flares, but these emissions are likely negligible compared to CO2 emissions from flares. The amount of gas flaring are estimated as a rate on the total gas production taken from [14] taking into consideration pilot flare and a percentage of unplanned events. • Inside the GHG emission model, this first step of the supply chain shows the greater uncertainty due to the difficulty to find reliable information about gas fields (eg. geographical distribution, number of wells, artificial lift system, start up date, ..) and production facilities (eg. installed power, performance, combustion efficiency, amount of gas flared,.. ) 2. The GHG emissions calculation for the gas processing (removal of the acid gas, CO2 and H2S, from the raw gas) is done in the following way: • The energy needed for the treatment facility is calculated as a rate on the total gas production based on the factor inside [14] and adjusted with the extra amount of energy that is needed for the amine regeneration (the CO2 and H2S removal from the raw gas is done with an amine based process) [16]. • The removed CO2 from the raw gas (calculated as difference between the CO2 concentration in the raw gas and the output gas CO2 concentration) is vented in the air for all the chains, apart from the chain A3, where the CO2 is reinjected in a reservoir for long time sequestration. • The natural gas fugitive emissions are calculated with proportional factors based on the treated gas that are inside [14]. 3. The GHG emissions from the gas transmission through pipeline (calculated for the chain A1, A2 and A3), are calculated as: • The emissions from energy consumption are calculated either starting from the installed power in the compression stations (for the chain A2 and A3) or taking the results from a detailed study [2]. The installed power, the efficiency and the emissions factors are taken from the internet site of the gas turbine suppliers: General Electrics [17] and Rolls Royce [18] that provides the equipment for the construction respectively for the Greenstream pipeline and the Maghreb-Europe pipeline. • The CH4 and NOx emissions from the combustion of the gas in the turbines (respectively 4,1 g/GJ and 14 g/GJ) are taken from average values of gas turbine combustion in [19] [20]. • The leakages from the pipeline are estimated as a rate based on the distance and the gas transported taken from [15] and [33] respectively for onshore (0,497 mg CO2eq/MJ*km) and offshore pipelines (0,124 mg CO2eq/MJ*km). The emission factor of the offshore pipeline is about 75% less than the onshore due to the limited number of gas compressions station, where are concentrated all the fugitive emissions).

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

4.

The GHG emissions calculation for the natural gas liquefaction is performed in the following way: • The energy consumption is calculated starting from the analysis of the liquefaction process and the type of gas turbine used for compressor energy supply. The efficiency of the gas turbines is taken from the internet site of the suppliers (Hitachi [21] and General Electric [17]). • The CH4 and NOx emissions from the combustion of the gas in the turbine (respectively 4,1 g/GJ and 14 g/GJ) are taken from average values of gas turbine combustion in [19] and [20]. • The fugitive emissions from the liquefaction plant are estimated as a rate (equal for all the three cases) taken from [22] (we consider the “average” value). The GHG emissions calculation for the natural gas LNG transport is performed in the following way: • The energy consumption is calculated starting from the analysis of the fleet used in the different route and the definition of an “average” vessel for each fleet (if the fleet is homogenous). Then, for each average vessel, the installed power is calculated through [23][24][25]. The GHG emission for each average vessel is then calculated from factors inside [34] that differ for each propulsion systems due to the large spread of efficiency of the propulsion type and the different fuel employed. Moreover, the emissions due to the berthing activities (three tugs for each berth), set equal for the three cases, is taken from [26]. • The main fugitive emissions are concentrated during LNG loading and unloading phases (arms purging), while during the transport are negligible. As a consequence we don’t consider fugitive emissions for this step of the chain and we assign the unloading fugitive emissions to the regasification step and the loading fugitive emissions to the liquefaction step. The GHG emissions calculation for the LNG regasification is performed in the following way: • The energy consumption is calculated starting from the study of the different regasification technologies, and considering the electric energy supply method (by gas turbine – self produced or by purchase from the network). • The fugitive emissions are estimated as a rate (0,005% of the throughput gas) taken from [11].

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LHV (mmbtu/kg)

Natural Gas Composition 100%

Methane Ethane Propane Buthane and Penthane Other CO2 LHV

Natural gas CO2 emission LHV (kgCO2/kgNG) (mmbtu/kg) Russia raw 43.148 2,58 A1 Russia imported 46.634 2,71 Libya raw 33.533 2,27 A2 Lybia imported 44.557 2,27 Algeria raw 37.714 2,37 A3 Algeria imported 42.723 2,56 Egypt raw 44.620 2,62 B1 Egypt LNG 47.420 2,76 Qatar raw 41.972 2,51 B2 Qatar LNG 46.832 2,79 Trinidad raw 46.850 2,74 B3 Trinidad LNG 47.337 2,76

Figure 3 – Natural gas composition, lower heating value and resulting emission factor for the gas in the 6 supply chains.

The conversion from energy consumption to CO2 emissions is done considering the fuel used and the combustion technology. Often in the natural gas chain energy is produced through the combustion of natural gas (in gas turbine or boiler) and the consequent emissions are related to the natural gas composition. Natural gas consists primarily of methane, but sometimes contains significant quantities of ethane, propane, butane, and pentane as well as carbon dioxide, nitrogen, helium and hydrogen sulfide produced from the well (Figure 3). These differences in the composition of the natural gas affect both the Heating Value of the gas and the CO2 emission factor (details in table of Figure 3).

5. GHG emissions from the gas chain 5.1. GHG emissions comparison The GHG emissions for the six gas chains, analysed in this study, are presented in the graph of Figure 4. Our results show a different environmental impact as to the different chains. The average value of the chain emissions is around 13 kgCO2eq/mmbtu of natural gas imported, but the overall emissions could be up to 19 kgCO2eq/mmbtu (+45%) in the pipeline chain A1 (Russia – Germany). Considering that the CO2 emissions from the combustion of the natural gas is around 54 kgCO2eq/mmbtu, the emissions of the supply chain increase the overall emissions by 25%. Along the supply chain the steps

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

GHG emission - kg/mmbtu

affecting more the emissions are the gas treatment and the transport (through pipeline or liquefaction+shipping), while the emissions from the production and regasification activities are limited. 60

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Libya Italy

Algeria Spain

Egypt Italy

Qatar Italy

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Figure 4 – GHG emissions divided by step for the six supply chain cases.

Analyzing the same results, but considering the GHG emissions by source (Figure 5), it is possible to underline the following considerations: • In the six cases analyzed, the chains based on pipeline transport have higher fugitive emissions than chains based on LNG. • The flaring emissions are very limited for all the chains. • The emissions in the chain A2 (Lybia – Italy) are strongly influenced by the CO2 concentration in the raw gas (the share of CO2 venting in the raw gas processing step is about 26% of the overall emissions). GHG emissions

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Figure 5 - GHG emissions divided by source for the six supply chain cases . Results in CO2eq/mmbtu of Natural Gas.

5.2. Gas production Even if the environmental impact of this step of the chain is limited in comparison with the total supply chain emissions (around 10%), it is interesting to analyze the differences among the six chains (Figure 6). The divergence among the chains is given mainly by the different amount of energy needed for the gas production (dehydrate the gas and sent it to the treatment plant, guarantee the energy supply to the facilities and enhance the production with water injection). The main elements that influence the energy consumption (and as a consequence the emissions) are the characteristics of the production fields (distance from the treatment plant, wells distribution, gathering pipeline network, artificial lift system) and the produced gas characteristics (heating value, gas composition, density). As highlighted in Figure 6, the cases A2 (Libya), B1 (Egypt) and B3 (Trinidad) have an higher emission factor compared to the other ones, mainly because they are remote offshore fields (more than 100 km to reach the treatment plant).

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN Gas Production 1,6

GHG emissions - kg/mmbtu

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ScarabSaffron (Egypt)

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Figure 6 – GHG emissions in the gas production step. Results in CO2eq/mmbtu of Natural Gas.

The ratio of the CO2 that comes from the combustion is around 80% of the overall emissions: the residual 20% is related to gas flaring (5%) and fugitive emissions (15%). This high concentration of fugitive emissions is due to: • Methane venting: dehydration vents, pneumatic devices, chemical injection pumps, vessels, compressors start-up (non-routine), compressor blow downs (non-routine), pressure relief valves (emergency). • Methane leakages: methane from equipment leaks, sumps. Unfortunately, these emissions are difficult to quantify with a high degree of accuracy and some uncertainty remains in the values reported by the producing countries. The amount of gas flaring is as difficult to evaluate as the fugitive emissions, because the lack of reliable data from the producing countries (National Oil Company) or International Oil Company. However in gas fields the flared gas is very limited compared to the one in the oil field, and the emissions are due to the pilot flare and purge activities, that have to be maintained for safety reasons.

5.3. Gas treatment The emissions from this step of the chain are strongly affected by the amount of CO2 in the raw gas. Natural gas has a wide range of acid gas concentrations, from parts per million to 50 volume percent and higher, depending on the nature of the rock formation from which it is generated. Because of the corrosiveness of H2S and CO2 combined with water and because of the toxicity of H2S and the lack of heating value of CO2, sales gas is required to be sweetened to contain a defined level of CO2 and H2S, depending on the sale contract. 16%

6,00

14% 12%

5,00

10% 4,00 8% 3,00 6% 2,00

4%

1,00

2%

-

CO2 content in the raw gas (%vol)

CO2eq - kg/mmbtu

Gas treatment 7,00

CO2 venting Fugitive Combustion CO2 content

0% Russia

Libya

Algeria

Egypt

Qatar

Trinidad

A1

A2

A3

B1

B2

B3

Figure 7 - GHG emissions in the gas treatment step and CO2 content in the raw gas (2nd axes). Results in CO2eq/mmbtu of Natural Gas.

Figure 8 – Impact of the concentration of carbon dioxide in the raw gas on the GHG emissions. Results in CO2eq/mmbtu of Natural Gas.

The most widely used processes to sweeten natural gas are those using the alkanolamines (MEA, DEA, MDEA, etc). They are used as aqueous solvents to selectively absorb H2S and CO2 from raw natural gas streams. The application of heat, about 7000 mbtu/kgCO2 [16] to be treated, enables the solvents to be stripped of the acid gases. The amine, again lean, is circulated back at the top of the sweetening process. As a consequence, higher is the amount of CO2 and H2S that has to be separated, higher is the energy needed. Furthermore, higher is the CO2 concentration, higher will be the energy needed for pumping the gas removed. The combination of these two elements allows to explain the spread among the emission from combustion in Libya and Trinidad (Figure 7). Usually the removed CO2 is vented, but in the case A3 (Algeria), the acid gas in reinjected in the Krechba reservoir, for long term sequestration, avoiding completely the CO2 emissions from venting.

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

The emissions in this step of the chain could be utilized, especially for fields with high concentration of CO2, thanks to the easiness of treatment and the quite high purity of the CO2 that is separated from the raw gas. Two main Oil & Gas application can be done with the current technologies: EOR – Enhanced Oil Recovery and CCS – Carbon Capture and Storage. For example, the sequestration of the CO2 vented in the treatment plant of Mellitah (Libya) could reduce the emissions up to the 42% of this step of the chain and 26% of the overall Libyan gas supply chain (Figure 8). Obviously, the CO2 sequestration will bring limited shadow emissions of CO2, because some energy is needed for the compression and injection of the CO2 in the reservoir or aquifer.

5.4. Gas Liquefaction The GHG emissions from this step of the chain are strongly affected by the liquefaction technology process, because 95% of the emissions are related to the combustion of the gas in the turbines to drive the refrigerant compressors (Figure 9). Currently there are several liquefaction processes available, but the most used is the APCI technology process: out of 100 liquefaction trains on-stream or under-construction, 86 trains, with a total capacity of 243 Mton/y have been designed based on the this kind of process. The second most used is the Philips Cascade process which is used in 10 trains with a total capacity of 36,16 Mton/y. The Shell DMR process has been used in 3 trains with total capacity of 13,9 Mton/y; and, finally, the Linde/Statoil process is used only in the Snohvit 4,2 Mton/y single train. The three LNG-based chains analyzed in this study are based on the following technologies: • Case B1 (Segas LNG – Egypt): the liquefaction technology is the C3MCR (APCI) Process, that uses two different cooling phases, the first one with propane and the second one with a mixed refrigerant (MR). This plant employs “Air Products Split MR” compressor/driver arrangement that guarantee a higher send out (5,1 mton/train). • Case B2 (Qatargas 2 – Qatar): the liquefaction technology is based on the AP-X (APCI) process, an evolution of the C3MR process. This solution with the addition of the sub-cooling cycle using nitrogen as working fluid reduces the propane refrigeration and mixed refrigerant compression duty per tonne of LNG. Moreover each LNG train can reach the capacity of 7.5 mton/y with the use of two or three frame 9 gas turbines. • Case B3 (Atlantic LNG - Trinidad): the liquefaction technology is based on the ConocoPhillips Optimised Cascade, which consists in successive chilling cycles using different refrigerants: propane, ethylene and methane. Gas Liquefaction

CO2 eq - kgCO2/mmbtu

7 6 5

Fugitive Combustion

4 3 2 1 0 Segas LNG (Egypt)

Qatargas 2 (Qatar)

Atlantic LNG train 4 (Trinidad)

B1

B2

B3

Figure 9 - GHG emissions in the gas liquefaction step. Results in CO2eq/mmbtu of Natural Gas.

The selection of gas turbines to provide power for liquefaction is just as important as the choice of process cycle. The thermal efficiency of the turbine in the three cases analyzed has minimum of 29% and a maximum of 35% (Figure 10). The relative energy consumption (MWel/Mton of LNG) is similar for the three processes (gap of about 2% among the energy needs). The element that enhances the difference in the GHG emissions is the gas turbine type used in each plant: the spread among the energy consumption in Qatargas 2 and the Atlantic LNG rise up to 15%. Fugitive emissions at LNG facilities (about 5% of the total GHG emissions) may be associated with cold vents, pipes, valves, connections, flanges, packings, open-ended lines, pump seals, compressor seals, pressure relief valves, and vents from loading activities.

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

LNG plant

Capacity (Mton/y)

Segas LNG

5,1

C3MR/splitMR

51,5

Qatargas 2 Atlantic LNG

15,6

AP-X ConocoPhillips Optimized Cascade

50,1

2 x GE frame 7 (33,0%) + 5x Hitachi H-25 (33,0%) 6 x GE frame 9 (34,6%)

50,2

8 x frame 5D (29,4%)

5,2

Liquefaction Technology

Energy consumption** (MWel/MtonLNG)

Gas turbine and efficiency

Energy consumption** (MWth/MtonLNG)

CO2 emission (tonCO2/tonLNG)

156

0,252

145

0,240

171

0,277

Figure 10 – LNG technologies comparison. **These values include the consumption of all the utilities (nitrogen, air compression, water, light,..)

5.5. LNG shipping Emissions from this step of the supply chain consist in the result of the conversion of the propulsion fuel into carbon dioxide (plus some methane and nitrous oxide). The main factors that affect the energy consumption and, as a consequence, the emissions, are: carrier capacity, propulsion technology and, predominantly, the distance from liquefaction plant to regasification terminal. If the energy required is proportional to the carrier capacity and the distance to cover [27] (considering a fixed speed, 19 knots in this analysis), it is interesting to analyze the impact of the different propulsion system on the final emissions. In the LNG industry, the vessels propulsion systems are based on: • Steam turbine propulsion (ST): this class of vessels burns a combination of boil off gas (about 2/3) and HFO – Heavy Fuel Oil (about 1/3) in order to produce steam that is sent to the turbines. The overall thermal efficiency is low (about 27%). Worldwide 85% of the LNG cargos are equipped with this type of propulsion (but only the 20% of the vessels under construction will be equipped with this system). [25] • Dual fuel diesel electric (DFDE) propulsion: this class of vessels is equipped with diesel engines that burn boil off gas with marine diesel oil as a pilot fuel engines connected to electricity generators and electric motors. Engines can also run on 100% marine diesel or heavy fuel oil as well. They have high fuel efficiency of about 43%. In the last years (since 2004) few LNG carriers with this technology were built, but now, thanks to the high thermal efficiency, 45% of the vessels under construction will be equipped with this technology. [25] • Slow speed diesel propulsion with reliquefaction (SSD-Reliq): this class of vessels is equipped with diesel engines, which burn Heavy Fuel Oil, directly connected to the propeller. This kind of engines cannot burn boil off gas, so ship must be equipped with reliquefaction system. They have high fuel efficiency of about 43%. The first vessel built with this technology was delivered in 2007, now 23% of the vessels under construction will be equipped with this propulsion. [25] LNG Shipping 6,0

4,0 Steam Turbine propulsion

2,0

1,0

0,0 0

1000

2000

3000

Dual Fuel Diesel Electric propulsion

B2 - QATAR - ITALY

B3 - TRINIDAD - SPAIN

3,0 B1 - EGYPT- ITALY

GHG emissions - kg/mmbtu

5,0

4000

5000

Distance - nautical miles

Figure 11 - GHG emissions in the LNG shipping with the ST propulsion vessels (dark blue points) and with DFDE propulsion system (light blue points). Results in CO2eq/mmbtu of Natural Gas.

In this study all the chains are based on LNG carriers with Steam Turbine (ST) propulsion, and the graph of Figure 11 explains the proportional link between the emissions and the distance covered. In the graph is presented also the hypothetical emissions of the same vessels, but equipped with a more efficient Dual Fuel Diesel Electric system. The reduction in the emissions of this step of the chain could be almost 30% (in the case B3, with higher capacity vessels). NOx, in this step of the chain, contributes for the 26% of the overall emissions, due to the use of Heavy Fuel Oil, that containing an amount of nitrogen up to 0,5%weight, produce fuel-bound NOx emissions. Moreover, another element affecting the NOx emissions is the obsolescence of the vessels: older carriers aren’t equipped with low-NOx burner, causing an increase in

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

NOx (thermal type). Few companies (eg. Eni in [24]) are monitoring this kind of emissions and real cases could be dramatically worst than the ideal ones.

5.6. LNG Regasification The emissions from the regasification phase are influenced by the process used to heat the LNG for the conversion in natural gas. Two technologies can be implemented to heat the LNG: Open Rack Vaporisers (ORV) that use seawater to heat and vaporise the LNG and Submerged Combustion Vaporisers (SCV) that use send-out gas as fuel for the combustion that provides vaporising heat. From the environmental point of view, the use of submerged combustion vaporisers leads to environmental concerns because higher carbon dioxide and NOx emissions. From the economical point of view, due to the high cost of the seawater system, ORV installations tend to have a higher installed capital cost while the SCV installations have a higher operating cost because of the fuel charge. In the three LNG chains studied in this paper, two are based on ORV technology: • Case B1 – Panigaglia (Italy): based on SCV technology, about 1,2% of the send out gas is burn for the regasification process. Electric demand is 27 MW and it is supplied from national electric network. • Case B2 - Adriatic LNG (Italy): the terminal is equipped with four ORV which use seawater to regasify LNG. Electric demand is 30 MW and is supplied by a gas turbine located in the terminal. • Case B3 – Bahia de Bizkaia (Spain): based on ORV technology. Electric demand is 30 MW and the electric energy is supplied by the near combined cycle. As presented in the graph of Figure 12, the emissions of a SCV based regasification process is four time an ORV-based; the difference among the other two regasification terminal emissions are due to the efficiency of energy production (33 % for electric generation in a gas turbine and 55,6% in the combined cycle connected with the Regasification terminal in Bilbao [28]). The fugitive emissions in the regasification terminal are very limited (less than 5% of the emissions), and are given mainly by the unloading operations, emergency shutdown and boil off compressors venting. LNG regasification

GHG emissions - kg/mmbtu

2,5

2,0

1,5 Fugitive Combustion 1,0

0,5

0,0 Panigaglia (Italy)

Adriatic LNG (Italy)

Bahia de Bizkaia (Spain)

B1

B2

B3

Figure 12 - GHG emissions in the gas regasification step. Results in CO2eq/mmbtu of Natural Gas.

5.7. Gas transport through pipeline The emissions of this step of the chain can be divided into technologically discharges (due to the combustion of fuels for energy production) and fugitive emissions due to leaks, vents and possible technical problems. The energy utilized for the transport of gas in a pipeline is required, not only to overcome frictional losses as is the case with oil, but also to maintain the density of the fluid in the line. This amount of energy is affected by pipeline length, diameter, working pressure, network configuration (frequency of bends, valves, tee, compressor stations, ..) and finally the steel grade. The most important element is the pipeline length: as shown in Figure 13, the Russian combustion emissions are three times the Algerian one, mainly because the distance covered by the Northern and Central Corridor (Russia) is about 5000 km and the length of the MEG (Algeria) pipeline is about 1800 km. In the Greenstream (pipeline from Libya to Italy), the emissions from combustion are low, but considering the distance covered (only 530 km), the relative emissions (kgCO2/km*mmbtu) are double in comparison with the other two pipeline (the slope of the curve is nearly double in Figure 13). This can be explained by the different working pressure (148 bar for the Greenstream, and about 70 bar for the Russian and Algerian pipeline) that imply an increase of the energy required (with a fixed flow rate). The choice to work at high pressure is forced in the Greenstream pipeline because it’s impossible to put compression stations along the route from Libya to Italy (offshore and deep water). The number of compression stations strongly affect the fugitive emissions, because leaks can occur at fittings (valves, assemblies, flanges,..), that are concentrated in compression stations. Other important elements that influence the fugitive emissions are the working pressure (higher pressure, higher fugitive emissions) and the location of the pipeline (offshore

13

EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

pipelines are less exposed to fugitive emissions thanks to the lower gap between inside and outside pipes pressure). In the Northern and Central Corridor of the Russian pipeline, the share of the fugitive emissions are higher, in comparison with the MEG pipeline: this value is taken from [2][2] and can be justified by the obsolescence of some of the equipment and pipeline installed (most of the pipelines are built around 1980). GHG emissions vs distance

14,0 12,0

FUGITIVE EMISSIONS

10,0

Combusion Total emissions

8,0 COMBUSTION EMISSIONS

6,0 4,0 2,0 0,0 0

1000

2000

3000

4000

RUSSIA -> GERMANY

GHG emissions - kg/mmbtu

16,0

ALGERIA -> SPAIN

LIBYA -> ITALY

18,0

5000

6000

lenght - km

Figure 13 - GHG emissions in the gas transport through pipeline. Results in CO2eq/mmbtu of Natural Gas.

6. Economical analysis With regard to the economical comparison of the six chains, we focussed our analysis on the transport of the gas, leaving out the production and treatment step of the supply chain because in different countries, due to different fiscal regulation and local gas demand, gas prices (that are the only values available in literature) don’t reflect the real characteristics of the upstream section of the chain. This paper aims to analyze the GHG emissions and the transportation cost as a function of the distance, in order to underline which is the best solution between LNG and pipeline gas transport at different distances. From the environmental point of view, as underlined in the graph of Figure 14 (crosses among blue and yellow lines), after 3000 km it is better to set up chains based on LNG. Furthermore, if the gas has to come crossing the sea, the distance that allows to discriminate among LNG and pipeline get down to 1800 km. In this study we try also to define the more efficient LNG chain that can be built with the current technologies, choosing the most efficient liquefaction process (AP-X process supplied by frame 9 turbine), shipping vessels equipped with dual fuel diesel electric propulsion system, regasification terminals equipped with an optimized SCV system. The forecasted emissions of this hypothetical chain (red points and line in the graph), are 8% lower: after 2300 km an efficient LNG chain is environmentally more friendly than one based on pipeline transportation system. GHG emissions - Gas Transport 18,0 A1

16,0 B3

GHG emissions - kg/mmbtu

offshore - HP

14,0 onshore - LP

B2

12,0 GHG Emissions - Pipeline GHG Emissions - LNG GHG emissions - LNG (best)

10,0 8,0 B1

6,0 4,0 A3

2,0 A2

0

1000 2000 3000 4000 5000 6000 7000 8000 9000 distance (km)

Figure 14 – Emissions of the gas transportation (excluding emissions from production and treatment) for the six cases and with an hypothetical more efficient LNG chain.

From the economical point of view, Figure 15 illustrates the costs of transporting gas as a function of distance for the six cases analyzed. As can be seen, gas-transport economics are particularly sensitive to economies of scale. Large diameter pipelines and large LNG projects minimize long-haul transport costs. For shorter distances, pipelining is usually more economical than LNG processing, because moving LNG by tanker requires costly liquefaction and regasification processing, regardless of the distance over which the gas is to be moved.

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

In the graph are reported two costs for the chain B2 (Qatar --- Italy) because we would like to underline the importance of the regasification cost in that particular chain. The regasification terminal in Italy is the first offshore GBS terminal, and due to the high CAPEX (around 2 billion euro) the regasification fee, since in Italy is regulated, is around 1,4 $/mmbtu, three times higher than a standard onshore terminal fee. If we set the regasification fee at 0,5 $/mmbtu, the total cost of the chain B2, fall down to 2,1 $/mmbtu, highlighting the efficiency of the large liquefaction trains in Qatar. Considering the costs, defining which is the best solution between LNG and pipeline at different distances is more complicated than in the environmental case due to the impact of the economies of scale. However it is more advantageous to transport gas through LNG after 1000 km if the alternative is an offshore pipeline in High Pressure, but the LNG become more advantageous after 4500 km if the alternative is an onshore pipeline in low pressure. These results highlight that a chain based on a 4000 km onshore pipeline could be more economical than one based on LNG, but from the environmental point of view, the emissions will be 35% higher. If we suppose to transport 10 bcm/y of gas, the emissions of the pipeline based chain will be about 1,5 Mton/y higher than the emissions of a chain based on LNG of the same distance. Cost - Gas Transport

B3

3,50 onshore - LP (48")

offshore - HP (32")

3,00

onshore - LP (56")

Cost - Pipeline

Cost - $/mmbtu

2,50

Cost - LNG 2,00

B2 - different regasification

B3

1,50 A1

1,00

B1 A3

0,50 A2

0,00 0

1000

2000

3000

4000

5000

6000

7000

8000

9000

distance - km

Figure 15 – Cost of gas transportation (excluding emissions from production and treatment) for the six cases and with the change in the regasification cost of the case B2. Costs are taken from [29][30][31][32], and then are discounted at 2009.

7. Gas to wire In this paragraph some considerations regarding the so called “gas to wire” alternative are reported. An alternative to importation of gas to be burned in order to produce power, is to burn gas locally where produced and to import power. By doing so all the emissions due to logistics are avoided. This alternative is called “gas to wire”: it is feasible for short and medium distances (up to 3000 km). It is based on HVDC (High Voltage Direct Current) technology. Any technical and economical details will not be reported, since the scope of this paragraph is just to give a figure of GHG emissions for such alternative. The factor to be considered in our analysis is the overall efficiency of power transportation through HVDC cables. Power losses of course depend from distance quite linearly, plus a fix contribution due to AC-DC conversion and vice versa. Referring to a case with 1200 MW to be transmitted, losses can be estimated to 4% for 500 km length, 6% for 1000 km and approximately 25% for a distance of 5000 km [35]. Such values correspond to the emissions of gas transport by pipeline due to energy consumption for compression. So the “gas to wire” alternative does not present significant advantage from the point of view of GHG emission; for long distance of course the alternative of LNG keeps its advantages. Anyway it could be considered a valid alternative in situations where additional emissions could be important: • Long offshore stretches • High CO2 content in raw gas (if burned in a gas turbine, less purification is needed) It is important to highlight that recent technical developments (more efficient power electronic devices) allow transmission with dramatically reduced losses (near halved) [36]: in next future gas to wire will became a valid alternative for energy transportation with reduced environmental impact from GHG emissions.

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EUROPEAN GAS IMPORTS: GHG EMISSIONS FROM THE SUPPLY CHAIN

8. Conclusions Environmental impact of energy production from gas has to be fully evaluated analyzing also the impact of the supply chains: it can reach the 20% of the CO2 emissions from gas combustion, indeed. From a preliminary analysis of the results, we highlight that several factors strongly affect the GHG emissions of the gas supply chain:
The efficiency of the liquefaction and regasification process: different technologies show widespread values of thermal efficiencies.
The efficiency of the midstream step of the chain: performance of the LNG tanker engine (older/newer technology, motor size, fuel used) and performance of pipelines (working pressure, diameter, natural gas leakages).
CO2 concentration in the raw gas (fields can have a CO2 content up to 14%mol compared to a worldwide average of 2%mol) In conclusion, this analysis allows to have an outlook of the economical and environmental impact of the different supply chains for gas import to Europe. Till now the decisions about the supply have been based on economical or political factors, neglecting the environmental impact. However, Europe, which aims to cut GHG emissions, should consider also the supply chain emissions, given that a remarkable reduction of overall emissions would be feasible (a decrease of 15% in the 2025 gas supply chain emissions would cut around 55 Mton CO2, 1% of the total European 2005 CO2 emissions [1]).

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