Hydrogen supply from North Africa to the EU

Hydrogen supply from

North Africa to the EU

Potentials, costs, and GHG emissions

vorgelegt von

M.Sc. M.Sc.

Sebastian Timmerberg

An der Fakultät III – Prozesswissenschaften

der Technischen Universität Berlin

zur Erlangung des akademischen Grades

Doktor der Ingenieurwissenschaften

- Dr.-Ing. -

genehmigte Dissertation

Promotionsausschuss:

Vorsitzender: Prof. Dr.-Ing. Felix Ziegler

Gutachter:

Prof. Dr. Matthias Finkbeiner

Prof. Dr.-Ing. Martin Kaltschmitt

Prof. Dr. Martin Wietschel

Tag der wissenschaftlichen Aussprache: 22. September 2020

Zusammenfassung

Die Weltgemeinschaft hat sich mit dem Klimaabkommen von Paris im Jahr 2016 darauf

ver-ständigt, die Klimaerwärmung auf maximal 2 °C gegenüber vorindustriellen Temperaturen zu

begrenzen. In diesem Rahmen hat sich die EU das Ziel gesetzt, ihre Treibhausgasemissionen

(THG-Emissionen) zu senken und bis zum Jahr 2050 Treibhausgasneutralität zu erreichen. Eine

zentrale Maßnahme zur Erreichung des Ziels ist ein zunehmender Einsatz von erneuerbaren

Energien. Ihr Anteil am Endenergieverbrauch soll von 20 % im Jahr 2020 auf 32 % im Jahr

2030 steigen. Absehbar werden Windkraftanlagen und PV-Systeme einen deutlichen Beitrag

dazu leisten. Neben erneuerbaren Energien können potenziell auch andere Energiequellen

eingesetzt werden, insofern diese zu geringen THG-Emissionen führen.

Die EU verfügt über ein eingeschränktes Potenzial zur Nutzung erneuerbarer Energien u. a.

durch eine relativ geringe Verfügbarkeit an nutzbaren Flächen zur Stromproduktion in Relation

zur gegebenen Energienachfrage. Im Vergleich weisen nordafrikanische Länder eine deutlich

vorteilhaftere Relation auf. Auf dieser Grundlage untersucht diese Arbeit die Erzeugung von

elektrischer Energie durch Windkraftanlagen und PV-Systeme in Nordafrika für die Erreichung

der Klimaziele in der EU. Aufgrund der beschränkten Transportkapazitäten für elektrische

Energie zwischen Nordafrika und der EU, aber auch aufgrund der vielfältigen

Einsatzmöglichkeiten wird Wasserstoff als Speicher- und Transportmedium betrachtet.

Außerdem werden weitere Wasserstoffproduktionsmöglichkeiten untersucht, die potenziell zu

geringen THG-Emissionen führen. Dabei stehen Untersuchungen zu Potenzialen, Kosten und

THG-Emissionen im Mittelpunkt.

Das technische Potenzial in Nordafrika zur Stromerzeugung auf Basis von Windkraftanlagen

und PV-Systemen, das Flächennutzungsbeschränkungen z. B. durch Siedlung berücksichtigt,

beläuft sich auf über 670 PWh/a (85 % durch PV-Systeme, 15 % durch Windkraftanlagen).

Dem steht eine vergleichsweise geringe Inlandsnachfrage nach Strom aus erneuerbaren

Energien gegenüber. Werden in den nordafrikanischen Ländern Marokko, Algerien, Tunesien,

Libyen und Ägypten die bestehenden politischen Ziele für den Ausbau erneuerbarer

Energienutzung vollständig umgesetzt, würde dies im Jahr 2030 einer Stromerzeugung von

220 TWh Strom durch Windkraftanlagen und PV-Systemen mit einer Gesamtleistung von 63

bis 100 GW entsprechen; d. h. die absehbare Inlandsnachfrage liegt um mehr als drei

Größenordnungen unter dem technischen Potenzial. Daher erscheint es möglich, dass nicht nur

die Inlandsnachfrage in nordafrikanischen Ländern gedeckt werden kann, sondern potenziell

auch große Mengen an elektrischer Energie aus erneuerbaren Energien für Exportzwecke zur

Verfügung stehen können.

Wasserstoff kann in einer kostenoptimalen Kombination von Windkraftanlagen, PV-Systemen

und Elektrolyseuren heute zu Erzeugungskosten ab 13 bis 23 €/GJ an vorteilhaften Standorten

in Nordafrika erzeugt werden

_{. Die niedrigsten Wasserstoffgestehungskosten ergeben sich an}

Standorten mit einem sehr guten Windenergieangebot, das zu hohen Volllaststunden der

Stromerzeugung führt. An derartigen vorteilhaften Standorten werden die Kosten minimal,

wenn die Kapazität von Windkraftanlagen um den Faktor 1,6 bis 2,2 größer ausgelegt werden

als die Elektrolyseurleistung (zusätzlich PV-System Kapazitäten mit dem Faktor 0 bis 0,2). Die

THG-Emissionen einer solchen Wasserstofferzeugung sind gering mit 6,2 g CO

-äq./MJ. Die

THG-Emissionen sind somit um 93 % geringer als eine konventionelle Wasserstoffproduktion

mittels Dampfreformierung (86,7 bis 91,1 g CO

-äq./MJ).

Alternativ existieren technische Möglichkeiten, Wasserstoff auf Basis der vorhandenen

Erdgasreserven in Nordafrika mit reduzierten THG-Emissionen zu erzeugen. Beispielsweise

wird bei der Methanpyrolyse das eingesetzte Methan in seine Elemente Wasserstoff und

Kohlenstoff zerlegt; d. h. mithilfe derartiger Pyrolyseprozesse kann Wasserstoff aus Erdgas

ohne direkte CO

-Emissionen bereitgestellt werden. In einer Lebenszyklusbetrachtung treten

jedoch weiterhin deutliche THG-Emissionen (28,0 bis 79,4 g CO

-äq./MJ) insbesondere durch

die Bereitstellung der Prozessenergie sowie durch die Erdgasversorgung auf. Die

THG-Emissionen am unteren Rand dieser Spannbreite kommen zustande, wenn die für die

Methanspaltung benötigte Prozessenergie mittels erneuerbarer Energien bereitgestellt wird. Die

THG-Emissionen der Methanpyrolyse sind damit mehr als vier- bis fünfmal höher als für

Wasserstoff, der auf Basis von Windkraft- und PV-Anlagen erzeugt wurde.

Eine weitere Alternative ist die Wasserstoffproduktion mittels Dampfreformierung inklusive

CO

-Abscheidung

und

-Speicherung

(CCS).

Gegenüber

der

konventionellen

Dampfreformierung können durch eine CO

-Abscheidung die THG-Emissionen im

Lebenszyklus auf 27,4 bis 32,5 g CO

-äq./MJ reduziert werden. Die hier verbleibenden

THG-Emissionen sind insbesondere auf die Erdgasbereitstellung (d. h. Vorkette) sowie die CO

-Emissionen zurückzuführen, die aus Kosteneffizienzgründen nicht abgeschieden werden.

Wasserstoff kann durch die Dampfreformierung inklusive CCS zu deutlich niedrigeren

THG-Vermeidungskosten

_{von 24 €/t CO}

2

produziert werden als durch die Methanpyrolyse (122 bis

278 €/t CO

). Die geringeren THG-Emissionen bei der Wasserstoffproduktion auf Basis von

PV-Systemen und Windkraftanlagen in Elektrolyseuren können aber nicht die höheren

Wasserstoffgestehungskosten ausgleichen, sodass hier vergleichsweise hohe

THG-Vermeidungskosten von 219 bis 271 €/t CO

entstehen.

Für einen Transport von Wasserstoff aus Nordafrika in die EU existiert bisher keine

großtechnische Infrastruktur. Es bestehen jedoch vier Erdgaspipelines. Eine potenzielle

(begrenzte) Zumischung von Wasserstoff in den Erdgasstrom ermöglicht bereits heute einen

Wasserstofftransport. Technisch betrachtet kann Wasserstoff bis ca. 10 Vol.-% ohne

wesentliche Anpassungen an der vorhandenen Infrastruktur zugemischt werden. Dies würde

den Transport von 35 bis 84 PJ/a Wasserstoff aus Nordafrika in die EU ermöglichen. Die

Zumischung von Wasserstoff erhöht den Energieverbrauch der Verdichterstationen im

Vergleich zum Transport der gleichen Energiemenge in Form von Erdgas. Daraus ergeben sich

drei- bis viermal höhere Transportkosten für Wasserstoff (2,4 und 5,6 €/GJ) als für Erdgas.

Es kann alternativ auch eine Wasserstoffinfrastruktur neu aufgebaut werden. Dann würde der

Wasserstoff die EU als reines Gas und nicht als Gasgemisch erreichen.

 Wasserstoff kann als komprimiertes Gas in Wasserstoffpipelines transportiert werden. Der

Energiebedarf für die Verdichtung auf den Pipelinedruck sowie die Verdichtung zur

Über-windung des Druckabfalls in den Pipelines zwischen Nordafrika und der EU beträgt 8 bis

9 % bezogen auf den Brennwert von Wasserstoff. Daraus ergibt sich eine maximale

Energieeffizienz der gesamten Versorgungskette von der Stromerzeugung bis zur

Wasserstoffbereitstellung von ca. 68 bis 70 %. Es ergeben sich die geringsten

Wasserstoffversorgungskosten von rund 66 €/GJ der betrachteten Optionen. Voraussetzung

für diese niedrigen Kosten ist der Einsatz von Kavernen zur Wasserstoffspeicherung.

 Wasserstoff kann als Flüssigkeit bei sehr niedrigen Temperaturen von -253 °C bei

Umgebungsdruck gelagert und transportiert werden. Die Verflüssigung von Wasserstoff

benötigt etwa 17 % des Energiegehalts des Wasserstoffs. Trotz starker Wärmeisolierung

von

Flüssigwasserstofftanks

führen

Verdampfungsverluste

zu

erheblichen

Wasserstoffverlusten. Deshalb ist die Energieeffizienz der gesamten Versorgungskette über

Flüssigwasserstoff niedriger als bei den anderen Optionen und liegt nur bei ca. 46 %.

Entsprechend sind auch die Wasserstoffversorgungskosten mit 93 €/GJ höher als beim

Transport über Pipelines.

 Wasserstoff kann auch in flüssigen organischen Wasserstoffträgern (LOHC) gespeichert

und transportiert werden. Dazu wird der Wasserstoff in Nordafrika in einem LOHC

chemisch gebunden, als solcher z. B. mit Schiffen transportiert und der Wasserstoff am Ort

des Verbrauchs freigesetzt. N-Ethylcarbazol (NEC), Dibenzyltoluol (DBT), Toluol (TOL)

und Methanol (MET) werden hier als LOHCs untersucht. Der Wärmebedarf für die

Dehydrierung der LOHCs ist entscheidend für die Energieeffizienz und die Kosten der

Wasserstoffversorgung. Wird diese Wärmenachfrage durch die Verbrennung von

transportiertem Wasserstoff gedeckt, liegt die Energieeffizienz der gesamten

Versorgungskette – je nach eingesetztem LOHC – zwischen 55 und 66 %. Die Verwendung

von Methanol weist dabei die höchste Energieeffizienz auf, da Methanol u. a. die geringste

Dehydrierungsenergie benötigt.

Die Wasserstoffproduktion mittels Elektrolyse auf Basis von erneuerbaren Energien führt zu

geringen und den geringsten THG-Emissionen der betrachteten Erzeugungsoptionen. Die

hohen ungenutzten Potenziale erneuerbarer Energien in Nordafrika ermöglichen langfristig

auch die Produktion großer Mengen über diesen Produktionsweg. Kurzfristig ist jedoch die

verfügbare Transportkapazität beschränkt. Eine Beimischung in Erdgaspipelines ist eine

energiewirtschaftlich darstellbare Option, bei der jedoch ein Erdgas-Wasserstoffgemisch in die

EU transportiert wird und somit kein reiner Wasserstoff für Anwendungen wie Brennstoffzellen

zur Verfügung steht. Für den Transport großer Mengen reinen Wasserstoffs ist der Aufbau einer

Transportinfrastruktur notwendig. Hierfür bestehen eine Reihe an technischen Möglichkeiten.

In einem eingeschwungenen Zustand mit einer ausreichenden Auslastung weist insbesondere

der Transport über Wasserstoffpipelines Vorteile in Bezug auf Energieeffizienz und Kosten auf.

Summary

The nations of the world have set targets to keep the increase in global average surface

temperature below 2 °C above pre-industrial levels. Accordingly, the EU has set the goal of

reducing its greenhouse gas (GHG) emissions and becoming greenhouse gas neutral by 2050.

A key measure to achieve this goal is the increased use of renewable energy. Their share of

final energy consumption is to rise from 20% in 2020 to 32% in 2030. Wind turbines and PV

systems will make a significant contribution to this. Additionally, other energies can potentially

be used, if they lead to low life cycle GHG emissions.

The EU has a limited potential for harvesting domestic renewable energies, largely due to the

relatively low availability of usable land for electricity production in relation to the given energy

demand. In comparison, North African countries have a much more advantageous relation. On

this basis, this paper investigates the generation of electrical energy by wind turbines and PV

systems in North Africa in the context of the EU climate targets. Due to the limited transport

capacities for electrical energy between North Africa and the EU and the manifold application

possibilities, hydrogen is considered as a storage and transport medium. In addition, further

hydrogen production options using energy resources in North Africa are investigated, which

potentially lead to low GHG emissions. The focus lays upon the consideration of potential,

costs and GHG emissions.

The technical potential for electricity generation in North Africa based on wind turbines and

PV systems, taking into account land use restrictions such as settlement, amounts to over

670 PWh/a (85% from PV systems, 15% from wind turbines). This contrasts with a

comparatively low domestic demand for electricity from renewable energies. The North African

countries of Morocco, Algeria, Tunisia, Libya and Egypt proclaimed political targets for the

expansion of renewable energy. If they are fully implemented, this would correspond to the

generation of 220 TWh of electricity by wind turbines and PV systems with a total capacity of

63 to 100 GW in 2030; i.e. the foreseeable domestic demand is more than three orders of

magnitude below the technical potential. Therefore, not only domestic demand in North African

countries can be met, but potentially large amounts of electricity from renewable energy sources

can also be made available for export purposes.

Hydrogen can be produced today

_{in a cost-optimal combination of wind turbines, PV systems}

and electrolysers with production costs from 13 to 23 €/GJ in advantageous locations in North

Africa. The lowest hydrogen production costs are found at locations with a very good wind

energy supply, which leads to high full load hours of electricity generation. At such

advantageous locations, the costs become minimal when the capacity of wind turbines is 1.6 to

2.2 times greater than the electrolyser capacity (plus PV system capacities with a factor of 0 to

0.2). The GHG emissions of such hydrogen production are low at 6.2 g CO

-eq./MJ. GHG

emissions are therefore 93% lower than conventional hydrogen production by steam methane

reforming (86.7 to 91.1 g CO

-eq./MJ).

Alternatively, there are technical possibilities to produce hydrogen with reduced GHG

emis-sions on the basis of existing natural gas resources in North Africa. In methane decomposition

processes, for example, the methane (natural gas) is decomposed into the elements hydrogen

and carbon; i.e. hydrogen can be provided from natural gas without direct CO

emissions by

means of such decomposition processes. In a life cycle perspective, however, significant GHG

emissions (28.0 to 79.4 g CO

-eq./MJ) occur, particularly as a result of the provision of process

energy and natural gas supply (i.e. upstream emissions). Lower end GHG emissions occur when

the process energy required for methane decomposition is provided by renewable energy

sources. Thus, GHG emissions from methane pyrolysis are at least 4 to 5 times higher than for

hydrogen produced on the basis of electricity from wind turbines and PV systems.

Another alternative is hydrogen production by steam methane reforming with CO

capture and

storage (CCS). Compared to conventional steam methane reforming, a CO

capture can reduce

the life cycle GHG emissions to 27.4 to 32.5 g CO

-eq./MJ. The remaining GHG emissions are

mainly due to the supply of natural gas (i.e. upstream) and CO

emissions, which are not

captured due to cost efficiency reasons. Hydrogen can be produced by steam methane reforming

with CCS at significantly lower GHG abatement costs of 24 €/t CO

than by methane pyrolysis

(122 to 278 €/t CO

). However, the lower GHG emissions from hydrogen production based on

PV systems and wind turbines in electrolysers cannot compensate for the higher hydrogen

production costs (219 to 271 €/t CO

).

So far, there is no large-scale infrastructure for transporting hydrogen from North Africa to the

EU. However, there are four natural gas pipelines. A potential (limited) blending of hydrogen

into the natural gas flow allows a hydrogen transport today. Hydrogen can be injected up to

approximately 10 % by volume without any major adjustments to the existing infrastructure.

This would enable the transport of 35 to 84 PJ/a hydrogen from North Africa to the EU. The

blending of hydrogen increases the energy consumption of the compressor stations compared

to transporting the same amount of energy in the form of natural gas. This results in transport

costs for hydrogen (2.4 and 5.6 €/GJ) that are 3 to 4 times higher than for natural gas.

Alternatively, a new hydrogen infrastructure can be installed. In this case, hydrogen would

reach the EU as a pure gas and not as a gas mixture.

 Hydrogen can be transported as compressed gas in hydrogen pipelines. The energy required

for compressing the hydrogen to the pipeline pressure and to overcome the pressure drop in

the pipelines between North Africa and the EU is 8 to 9 % based on the higher heating value

of hydrogen. A hydrogen supply via pipelines shows an energy efficiency of ca. 68 to 70 %

for the entire supply chain from power generation to hydrogen supply. This results in the

lowest hydrogen supply costs of around 66 €/GJ among the considered options. A

prerequisite for these low costs is the use of caverns for hydrogen storage.

 Hydrogen can be stored and transported as a liquid at very low temperatures of -253 °C at

ambient pressure. The liquefaction of hydrogen requires about 17 % of the energy content

of hydrogen. Despite strong thermal insulation of liquid hydrogen tanks, evaporation losses

lead to considerable hydrogen losses. Therefore, the energy efficiency of the entire supply

chain via liquid hydrogen is lower than with the other options and is only about 46 %.

Accordingly, the hydrogen supply costs of 93 €/GJ are also higher than for a transport of

hydrogen via pipelines.

 Hydrogen can also be stored and transported in Liquid Organic Hydrogen Carriers (LOHC).

In North Africa, hydrogen is chemically bound in a LOHC, transported as such e.g. by ships

and released at the point of consumption. LOHCs are N-ethylcarbazole (NEC),

dibenzyltol-uene (DBT), toldibenzyltol-uene (TOL) and methanol (MET). The heat required for dehydrogenation

of the LOHCs is a crucial factor for determining the energy efficiency and the cost of

hydrogen supply. If this heat demand is covered by the combustion of transported hydrogen,

the energy efficiency of the entire supply chain - depending on the LOHC used - is between

55 and 66 %. The use of methanol has the highest energy efficiency, since methanol requires

the least dehydration energy.

Hydrogen production by electrolysis on the basis of renewable energies leads to the lowest

GHG emissions of the considered generation options. Therefore, this production method has a

long-term right to exist in terms of GHG reduction targets. The high unused potential of

renewable energies in North Africa also enables the production of large quantities via this

production route. In the short term, however, the available transport capacity is limited.

Blending hydrogen in natural gas pipelines is a viable option from an energy perspective.

However, a natural gas-hydrogen mixture is transported to the EU and pure hydrogen is

therefore not available for applications such as fuel cells. For the transport of large quantities

of pure hydrogen, the development of a transport infrastructure is necessary. There are a number

of technical possibilities for this. In a steady state with sufficient capacity utilisation, transport

via hydrogen pipelines in particular has advantages in terms of energy efficiency and costs.

List of publications

Following publications (publisher’s version) are implemented in this thesis in chapter 3.

Publication I:

Timmerberg, S.; Sanna, A.; Kaltschmitt, M.; Finkbeiner, M. (2019):

Re-newable electricity targets in selected MENA countries – Assessment of

available resources, generation costs and GHG emissions. In: Energy

Reports 5, S. 1470–1487. DOI:

10.1016/j.egyr.2019.10.003

.

Publication II:

Timmerberg, S.; Kaltschmitt, M.; Finkbeiner, M. (2020): Hydrogen and

hydrogen-derived fuels through methane decomposition of natural gas –

GHG emissions and costs. In: Energy Conversion and Management: X

7, S. 100043. DOI:

10.1016/j.ecmx.2020.100043

.

Publication III:

Timmerberg, S.; Kaltschmitt, M. (2019): Hydrogen from renewables:

Supply from North Africa to Central Europe as blend in existing pipelines

– Potentials and costs. In: Applied Energy 237, S. 795–809. DOI:

10.1016/j.apenergy.2019.01.030

.

Publication IV:

Niermann, M.; Timmerberg, S.; Drünert, S.; Kaltschmitt, M. (2021):

Liquid Organic Hydrogen Carriers and alternatives for international

transport of renewable hydrogen. In: Renewable and Sustainable Energy

Reviews 135, S. 110171. DOI:

10.1016/j.rser.2020.110171

.

Table of contents

Zusammenfassung ... I

Summary ... IV

List of publications ... VII

1

Introduction ... 1

1.1

Transition of the EU’s energy system ... 3

1.2

Hydrogen as energy carrier ... 6

2

Research objective and outline ... 13

3

Results ... 18

3.1

Publication I ... 18

3.2

Publication II ... 37

3.3

Publication III ... 53

3.4

Publication IV ... 69

4

Synthesis ... 85

4.1

Energy resources ... 85

4.2

Hydrogen production ... 89

4.3

Hydrogen transport ... 95

4.4

Critical discussion ... 99

5

Conclusion ... 106

6

Further research questions ... 110

1 Introduction

With the Paris Agreement from 2016, the nations of the world have declared the target to hold

the increase in global average surface temperature below 2 °C above pre-industrial levels.

Fur-thermore, it was agreed that efforts shall be pursued to limit the increase to 1.5 °C in order to

“significantly reduce the risks and impacts of climate change” [1]. The reduction of greenhouse

gas (GHG) emissions is declared as the primary measure to limit global warming. In this

context, a remaining anthropogenic CO

budget was determined between 420 and 1,170 Gt

,

which is the estimated amount of CO

that can be emitted leading to a temperature increase of

1.5 or 2 °C, respectively. Under the assumption that current global emission levels remain

constant, this budget would be exhausted in the year 2028 or 2046 [2]. Thus, significant and

fast action is necessary to hold these challenging targets.

The European Union

_{(EU) is committed to the Paris Agreement. Thus far, the EU is a major}

emitter of GHGs with a share of 8 % of globally emitted GHGs in 2017 [3]. Between 1990 and

2018, the EU energy sector caused between 75 to 76 % of EU’s annual GHG emissions

_[4].

The existing GHG targets and strategies therefore focus on the reduction of GHG emissions

primarily within the energy sector. One central measure to achieve this goal is to increase the

use of renewable sources of energy. Thus, a share of 32 % of the EU’s final energy is targeted

to come from renewable sources by 2030 [5].

However, the renewable energy potential in the EU is limited and contrasts a high energy

demand. The energy consumption per surface area is high with 4 to 86 TJ/(a km²) (Figure 1).

Thus, the land area available for harnessing renewable energy with conversion technologies

such as wind turbines and photovoltaic (PV) systems is low compared to the energy

consumption. Furthermore, the EU member states are highly populated (16 to 414 people/km²

[6, 7]) and thus, large settlements and other restrictions limit the land area available for energy

generation systems using renewable sources of energy.

The EU’s neighbouring countries in North Africa are characterized by significantly different

circumstances. Area-specific primary energy consumption in Morocco, Algeria, Libya and

Egypt are between 1 to 4 TJ/(a km²) and thus, much lower than in many EU countries. Also the

population densities are lower (18 to 98 people/km²) [6, 7]. Thus, a high potential for harnessing

renewable energies contrasts a comparatively low energy demand. Thus, making use of North

African energy potentials for providing renewable energy to the EU is the central idea pursued

in this thesis.

For the transport of renewable energy from North Africa to the EU this thesis focus’ on

hydrogen. Hydrogen can be produced with a high energy efficiency (> 60 %) by water

electrolysis powered by electricity e.g. from wind turbines or photovoltaic (PV) systems [8–

11]. As such, hydrogen can be deployed as a carrier for renewable energy associated with low

4

_{Related to 67}

_{percentile of transient climate response [2].}

_{EU-27 is considered if not stated differently.}

GHG emissions [12] and thus used to contribute to two central energy policy targets of the EU:

decreasing the amount of GHG emissions from the energy sector and increasing the share of

renewable energies.

Figure 1: Area-specific energy consumption in Europe and North Africa in 2018, data from [6, 7]

Besides being a carrier for energy from renewable sources, hydrogen can also be produced with

reduced GHG emissions from fossil fuel energy; North African countries show substantial

proved reserves especially for crude oil and natural gas [7]. For example, CO

capture and

storage can be applied to a steam methane reforming process, thereby reducing the CO

emis-sions of hydrogen production from natural gas [13]. Another alternative is to produce hydrogen

by methane decomposition. The process yields solid carbon and emits in theory no CO

into

the atmosphere [14]. Thus, hydrogen produced by such processes from fossil fuel energy can

potentially be used to contribute to achieve EU’s GHG emission reduction targets. Rrenewable

energy and fossil-based hydrogen production pathways might compete with one another at least

within a transition period.

However, the transport of hydrogen from North Africa to the EU can be challenging. No

designated infrastructure for transporting large amounts of hydrogen exists or is planned.

Several technological approaches compete against one another, each showing distinct

advantages and disadvantages regarding costs or energy demand [15, 16]. For example,

hydrogen can be stored within liquid organic hydrogen carrier (LOHC) to be transported in

ships or trucks; i.e. in conventional (existing) transport chains. However, the installation of

plants for the loading of the LOHC in North Africa and the unloading of these LOHCs within

the EU are still required. Hydrogen can also be transported as liquid hydrogen at very low

temperatures. This import option requires a designated transport infrastructure to maintain the

very low temperatures throughout the full supply chain. However, the hydrogen reaches the EU

in a pure form, thus, ready to be used after re-gasification. Additionally, the transport of

compressed hydrogen in pipelines is a potential transport option, but requires the installation of

several thousand kilometres of pipelines.

Large pipelines already connect North Africa and the EU to transport natural gas. Natural gas

is a gas mixture consisting mainly of methane; but also trace elements like hydrogen may be

contained within the natural gas [17]. Increasing this share is another potential way transporting

hydrogen to the EU that is already in place. However, adding hydrogen to natural gas can

0 - 4

4 - 14

14 - 38

38 - 86

National primary energy

consumption by surface

area [TJ/(a km²)]

require adjustments to the infrastructure and might change transport capacities of existing

pipe-line systems [18].

Against this background, this thesis investigates North African energy resources, their use for

the production of hydrogen and its subsequent transport to the EU. The following introductory

sections give more details about the energy supply and demand in the EU, the potential role of

hydrogen towards an energy sector with lower GHG emissions including various hydrogen

production and transport options. The outline of this dissertation follows in chapter 2.

1.1

Transition of the EU’s energy system

The EU climate change mitigation targets are cornerstones for developments in the energy

sector. The EU targets a reduction of

 20 % lower GHG emissions in 2020 compared to 1990

 40 % lower GHG emissions in 2030 compared to 1990

 Net-zero GHG emissions in 2050 [5]

The GHG reduction targets are also incorporated into the EU’s energy policy with three out of

five main aims directly relating to the reduction of GHG emissions for the energy provision

[19]. The “2030 climate & energy framework” includes EU-wide targets and policy objectives

for the period from 2021 to 2030. Besides the GHG emission reduction target, a minimum share

of 32 % renewable energy in the final energy consumption is proclaimed. This target was

revised from 27 % upwards in 2018 and will be reviewed again in 2023 for another potential

upward revision [5].

The historical development of EU’s GHG emissions and the share of renewable energy since

1990 is shown in Figure 2. The 2020 GHG target of the EU is likely to be met and the GHG

emissions decreased already by 19 % in 2017 compared to 1990. The preceding GHG targets

require a reduction of 20 % within 10 years and another reduction of 60 % in the following 20

years, always in reference to the GHG emissions in 1990. The required speed to reduce GHG

emissions increases from the 2020, 2030 to the 2050 targets and strong changes in the energy

provision system are necessary to reach these speeds.

As means of GHG emission mitigation, the final energy share provided on the basis of

renewable sources of energy rose from 10 % in 2004 to 19 % in 2018 (Figure 2). This share is

close to the 2020 target of 20 % renewable energy related to the final energy consumption [5]

which this target is expected to be reached. The next EU target is 32 % of renewable energies

related to the final energy consumption by 2030 [5]. No targets regarding the use of renewable

energies have been published yet for the period after 2030.

The growth of renewable energy within the EU is particularly realised through an increasing

use of electricity provided by renewable sources of energy. Especially electricity production

from wind turbines and PV systems increased significantly; e.g. the amount of electricity

produced from wind turbines grew 13 %/a between 2004 to 2018 [4]. A total wind turbine

capacity of 205 GW has been in operation in 2019 and 15.4 GW have been newly installed in

this year [20]. The total PV capacity is lower with 117 GW by the end of 2018 [21]; however,

the growth rate is much higher than for wind turbines with 44 %/a between 2004 to 2018 [4].

The newly installed capacity of PV systems summed up to 17 GW in 2019 [21] and therefore,

more PV than wind turbine capacity has been installed in 2019. Currently, wind turbines

pro-duce roughly the same amount of electricity as hydropower stations, which was the major

producer of renewable electricity within the EU and still is on a global scale. As electricity

production from hydropower stations stays on a similar level [4], it can be expected that in 2020

more electricity will be produced from wind turbines than from hydropower stations for the

first time.

Figure 2: Share of fuels in final energy consumption and political targets in the EU, data from [4, 5]

A strong expansion of electricity production from wind turbines and PV systems is likely to

continue in an accelerated manner in order to fulfil the GHG reduction targets. The final

required amount of electricity produced from renewable sources of energy in 2050 depends

(e.g.) on developments such as the energy demand, the energy efficiency and the costs of

alternative energy conversion technologies able to provide energy with low GHG emissions.

Accordingly, assumptions about these developments show a strong impact on the estimations

for future renewable energy installations; thus, the results of published assessments vary

significantly and show a wide bandwidth. For scenarios with a high share of renewable

electricity in the EU in 2050 the required wind and PV capacity is estimated between 231 and

1,489 GW [22]. For a 100 % renewable energy scenario, i.e. including the full energy demand

of all sectors to be covered by renewable energy, more than 8 TW are derived [23].

Large suitable areas must be available for the installation of these large amounts of wind

turbines and PV systems. However, technological and land cover conditions limit the capacities

that can be installed per area. Technological constraints for the installation of wind turbines and

PV systems are e.g., the interference between individual system components such as the wind

turbulences adjacent turbines exert on each other [24, 25]. The installable capacity per area –

called the power density – of onshore wind turbines and utility-scale PV systems are 3 and

48 MW/km², respectively [26, 27]. Besides these technological restrictions, also the land cover

constrains the installable capacities. Restrictions can be geological circumstances such as high

slopes. Additionally, the current land use can limit the installation of wind turbines or PV

0%

50%

100%

0%

50%

100%

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

G

HG

e

m

iss

io

n

s

re

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te

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to

1990

S

h

ar

e

of

f

in

al

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co

n

su

m

pt

io

n

Renewables and biofuels

Electricity

Solid fossil fuels

Natural gas

Oil and petroleum products (w/o biofuel)

Heat

Other fuels

Share of renewables

GHG emissions

Political targets

systems considerably; e.g. one significant limiting factor in highly populated areas are

settle-ments [24].

The EU covers 4.2 Mio. km², counts more than 446 Mio. inhabitants, and consumes 43 EJ final

energy (status 2018). The respective population density of 106 people/km² and area-specific

energy demand of 10.2 TJ/(a km²) is significantly higher than in other industrialized regions

such as within the USA (33.6 people/km² and 6.6 TJ(a km²)) [4, 6, 28]. Accordingly, the EU

areas suitable for exploiting renewable energy are under high pressure to be used for energy

generation purposes, if a high share of renewable energies is targeted to achieve the GHG

reduction targets. Germany is an extreme example of illustrating the difficulty: Germany shows

a final energy consumption of 9.3 EJ in 2018 [4]. It contrasts a technical potential for electricity

production by wind turbines and PV systems of 1.2 EJ/a (wind) and 1.1 to 2.6 EJ/a (PV),

respectively [25]. Thus, Germany’s domestic technical renewable energy potentials are clearly

below the current final energy consumption. Accordingly, if a high share of renewable energy

in Germany’s final energy consumption is targeted to achieve the GHG reduction goals outlined

above, the import of renewable energy from other countries seems inevitable. However, on an

EU level, the domestic renewable energies suffice the energy demand, but a high pressure to

exploit the existing renewable energy resources remains [22, 29].

Some neighbouring countries of the EU show a comparatively relaxed ratio of energy

consumption, surface area, and population; i.e. the pressure on renewable energy sources is

comparatively low. For example, the North African countries Morocco, Algeria, Libya, and

Egypt consume 82 % less final energy than the EU [4, 28]. They cover 5.5 Mio. km² exceeding

the land surface of the EU and the population is 59 % smaller than the EU population [6]. Thus,

more area is potentially available for harnessing renewable sources of energy.

The surface area and the population are a rough estimate for the pressure to exploit renewable

energy potentials and e.g. neglect the availability of the renewable energy resource. However,

North African countries also show a beneficial resource availability: wind turbines and PV

systems can provide electricity above 3,000 h/a and 2,000 h/a, respectively, in large regions at

full load [30, 31]. In Germany, the full load hours are clearly lower; on average onshore wind

turbines and PV systems produce 1,797 h/a and 980 h/a at full load [32]. Additionally, the

beneficial renewable energy resources in North Africa lead to a high utilization of wind turbines

and PV systems, allowing for lower energy provision costs compared to the use of such systems

within the EU.

The North African countries have a tradition of exporting energy to the EU; fossil energy

exports are a very important revenue for the respective domestic economy [33]. In 2017,

Algeria, Egypt, Libya, and Tunisia exported 4.3 EJ of fossil energy carrier to the EU. Their

exports covered 6 % of the crude oil and fossil fuel-based petroleum products and 10 % of the

natural gas imported by the EU (Figure 3) [4]. Algeria shows the highest energy exports to the

EU. Also Libya exported large quantities, but since 2010 the energy exports from Libya are

strongly influenced by the political instability [4].

Thus, fossil energy supply chains and associated infrastructure are well established being a

potential starting point for an export of a molecular energy carrier produced on the basis of

renewable sources of energy. However, such a potential export of renewable energy must also

consider the domestic energy demand, which increased considerably in the past [6, 34] and will

probably also grow in the years to come due to e.g. an ongoing population growth [6].

Further-more, North African countries aim for an increase use of renewable sources of energy [35]

mainly due to economic considerations [33]. Additionally, they also signed the Paris Agreement

and, therefore, must decrease the GHG emissions of energy provision [1]. However, the export

of renewable energy is a potential future revenue source after phasing out the export of fossil

fuel energy within a de-fossilized world.

Figure 3: Development of energy transports from North Africa to the EU (NG: natural gas, Oil: oil and

petroleum products, data from [4], energy conversion factors according to [7])

1.2

Hydrogen as energy carrier

Hydrogen is seen as an important linking element enabling an efficient GHG neutral energy

system [36–38].

 Hydrogen can be produced based on a variety of

o

energy carrier (electrical energy, liquid and gaseous fuels, etc.) and of

o

processes with low direct CO

emissions (electrolysis, methane decomposition, etc.).

 Hydrogen can be stored (pressure tanks, caverns, etc.) enabling to

o

balance situations of shortages or excess of non-dispatchable energy sources and to

o

transport energy (as LOHC, liquid hydrogen, etc.) in large quantities.

 Hydrogen can be used

o

in many energy conversion technologies (fuel cells, internal combustion engines, etc.)

leading to low direct GHG emissions as well as for a

o

large range of applications (stationary electricity production, mobile electricity

production for vehicles, heating, etc.).

Accordingly, hydrogen can be a link between the energy sectors electricity, transport, and

industry. The coupling of these sectors is a widely discussed strategy towards GHG neutral

energy systems as it enables an efficient integration of non-dispatchable renewable energy

sources with a high energy efficiency [39]. Sector coupling extends and support the strategy of

electrification [37, 40].

0

500

1,000

1,500

2,000

2,500

3,000

1990

1995

2000

2005

2010

2015

E

n

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[P

J]

Algeria (NG)

Egypt (NG)

Libya (NG)

Algeria (Oil)

Electrification as one of the most important measures for GHG reduction aims primarily at a

wide use of electricity-based energy applications [41–43]. One reason is that electricity is

basi-cally pure exergy allowing for a high theoretical efficiency for the transformation into other

forms of useable energy; i.e. substituting conventional energy-based with electricity-based

end-use applications can potentially reduce the overall energy consumption [39, 40]. Furthermore,

electrical energy can be produced directly by wind turbines and PV systems and therefore, on

the basis of renewable sources of energy characterized by a high global potential [41–43].

However, a wide-scale application of electrical energy applications leads to several challenges

that hydrogen can potentially offset. The electrical energy system requires a balance between

electricity generation and consumption at any point in time. Hydrogen can be produced with a

temporal flexibility through water electrolysis – and this during times when the electricity

supply exceeds the demand [44]. Hydrogen can also be used to supply energy when the

electricity demand exceeds the supply from non-dispatchable renewable energy. For such

purposes, hydrogen can be stored with a high energy efficiency on a large scale e.g. in

geological formations [45]; thus, longer periods with limited availability of a renewable source

of energy can be balanced.

Moreover, certain existing energy applications cannot be powered by electricity directly. For

example, current and foreseeable battery technology shows an energy density too low to power

commercial sea shipping or long-distance flights [8, 39, 46]. The application of hydrogen as a

final energy carrier is one potential alternative to power such applications. Alternatively,

hydrogen can also be used as a feedstock for the production of liquid or gaseous fuels with

specific fuel characteristics, i. e. used within the transportation sector. For example, a

Fischer-Tropsch process can be applied to produce liquid and gaseous hydrocarbons; however, a carbon

source (e.g. CO

) is necessary. Based on theses processes fuels similar to gasoline, diesel, or jet

fuel can be produced partly based on process technology operated already on large scale (e.g.

crude oil refineries). As part of such a standardized fuel, hydrogen can be used indirectly within

existing internal combustion engines and thus, within the current transport fleet [47, 48].

Furthermore, hydrogen based applications can contribute to mitigating GHG emissions in the

industrial sector such as the steal, glas, or chemical industry. In certain industrial processes

hydrogen can replace current energy carrier. For example, current steel production by the blast

furnace process uses coke for the reduction of iron ore leading to considerable CO

emissions.

In the direct reduction process, the iron ore is reduced by hydrogen, which directly avoids CO

emissions [49].

Despite these potential benefits of hydrogen for the transformation of the energy system (and

the industrial sector) towards lower GHG emissions, hydrogen shows a strongly limited market

penetration as an energy carrier. Most of the hydrogen produced globally is used in industrial

applications, i.e. for the production of fertilizer and fuel. In 2018, 51 % of global hydrogen

production (38.2 Mt) has been used for refining purposes and 42 % for ammonia production.

Other applications, including the use of hydrogen as an energy carrier, are clearly of minor

significance and use only 6 % of the globally produced hydrogen [50].

Production. Low GHG emissions of the hydrogen production are a prerequisite for an

increas-ing use of hydrogen in an energy system transformincreas-ing towards GHG-neutrality. In general,

hydrogen production is realised in thermo-chemical or electro-chemical processes, which use

hydrocarbons (C

H

) or water (H

O) as feedstock. As hydrogen is a secondary or final energy

carrier, a primary energy source is necessary for hydrogen production [12, 36, 37].

A wide range of hydrocarbons such as natural gas or coal can serve as feedstock for hydrogen

production. These types of feedstock deliver hydrogen as well as (partly) the energy for the

production process. Water is in some cases added in order to increase the hydrogen yield. Most

prominent production processes are steam methane reforming, autothermal oxidation, and

partial oxidation. All of these processes yield hydrogen and carbon monoxide (CO) or carbon

dioxide (CO

) [36, 51, 52].

Currently, steam methane reforming is the global dominant hydrogen production process and

natural gas serves as the most important methane source [40]. CO

capture and storage

technologies (CCS) can be applied to reduce the production related GHG emissions. CCS

systems capture can remove approximately 90 % of the CO

produced within a steam methane

production processes [52, 53]. However, 10 % of the CO

emissions remain, as well as the GHG

emissions in the natural gas supply chain may still lead to substantial GHG emissions associated

with the hydrogen production process [51].

Methane decomposition is an alternative thermo-chemical process to produce hydrogen using

this hydrocarbon as a feedstock. This endothermic process does not produce CO

but solid

carbon (CH

 C + 2 H

). The process can be realised in different configurations. One option

is to apply a plasma torch to provide the energy for the reaction. Other configurations apply a

molten metal reactor or a conventional gas reactor. Natural gas can be combusted to provide

the process heat needed to maintain the chemical reaction [14, 54, 55]. Since CO

emissions

are not produced from the overall process, low life cycle GHG emissions can potentially be the

consequence. However, the GHG emissions related to the supply of the process energy and

related to the natural gas supply remain so that still hydrogen related GHG emissions occur

[51].

Water electrolysis is an electro-chemical process to produce hydrogen from water. The process

applies a conductive electrolyte and electrodes. Here an electrical potential higher than the

decomposition voltage splits water into hydrogen and oxygen [36]. Different configurations of

water electrolysis have been realised to be distinguished by the electrolyte: alkaline, polymer,

and solid-oxide are the major electrolyte types used so far. Alkaline electrolysis is the most

mature technology, followed by polymer electrolyte membrane (PEM) electrolysis. Especially,

the latter electrolyser can be efficiently operated with a flexible electricity supply making them

well suitable for a direct combination with wind turbines and PV systems [8, 12, 36, 44]. The

overall water splitting process causes no direct CO

emissions. However, the electricity supply

needed to operate the electrolyser can be a significant source for GHG emissions. Thus, a

hydrogen production with very low GHG emissions is only possible if electricity associated

with very low GHG emissions is used (e.g. electricity produced by wind turbines or PV

systems) [51].

Using such systems based on wind and solar radiation to power electrolysis can be

economi-cally challenging. The investments for electrolyser are high (370 to 1,300 €/kW in 2020 [11])

so that a high utilization, i.e. high full load hours of the electrolyser is required for hydrogen

production at low specific production costs [56]. However, wind turbines produce electricity

only with a limited amount of full load hours (e.g. 3,000 h/a in good spots), and a direct coupling

with an electrolyser would result in a similar amount of full load hours. In this example, the

electrolyser investments are levelized by a hydrogen production considerably lower than a

continuous electrolyser operation would allow. However, applying a hybrid system including

wind turbines and PV systems for electricity production can clearly increase the full load hours.

A further increase is possible, if the capacity of the installed wind turbines and PV systems are

selected to be higher than the electrolyser capacity [39]. However, under these circumstances

excess electricity production increases. Thus, choosing the capacities of wind turbines and

photovoltaic systems to power an electrolyser can be treated as an economic optimization

problem influenced e.g. by the temporal availability of the renewable energy resource in a

certain location / area.

The production of hydrogen based on renewable sources of energy competes against a

production based on fossil fuel energy, if both processes lead to low GHG emissions. In this

case, the costs of the production can be a decisive factor for the selection of the respective

production process. Currently, electricity production from fossil fuel energy and from

renewable sources of energy lead to similar cost ranges [35, 57]. As the production of hydrogen

from electricity requires an electrolyser leading to extra energy conversion losses and extra

investments, the costs for hydrogen production based on renewable sources of energy tends to

be higher (Figure 4). However, higher costs contrast potentially lower GHG emissions. CO

abatement costs can be used as an assessment criterion to relate differences in GHG emissions

to cost differences.

Figure 4: Hydrogen production starting from fossil (grey) and from renewable energy sources (green),

dashed area indicates current cost parity between electricity production from fossil and from

renewable energy sources (energy efficiencies η)

Cost parity

En

er

gy

co

n

te

n

t

Fossil energy chain

Renewable electricity chain

energy source

Electricity Hydrogen Natural gas / Oil product Fossil energy source

En

er

gy

co

n

te

n

t

100 %

100 %

η, cost

η, cost

η, cost

η, cost

η. cost

Transport. Under standard conditions (1.013 bar and 0 °C) hydrogen shows a low volumetric

energy density of 0.01 GJ/m³. Commercial transport options involve the conditioning of

hydro-gen by physical or material-based means in order to increase the energy density (Figure 5).

Three major storage forms of hydrogen can be distinguished so far.

 Compressed hydrogen. The pressure of hydrogen is increased e.g. to 200 to 500 bar for

transporting hydrogen e.g. within trailer [12]. The compression shows an energy demand

of approximately 5 % of the higher heating value (HHV) of hydrogen (from 1 to 350 bar)

[16]. The volumetric energy density of the compressed hydrogen increases to 3.4 GJ

/m³

but remains low in comparison to other energy carrier such as oil products with ca.

35 GJ

/m³. A standard trailer stores ca. 1,100 kg of hydrogen [12] and thus is far away

from the payload of a heavy truck (ca. 40 t in the EU). Accordingly, the transport of

compressed hydrogen via trucks is only economically viable for short-distances.

Compressed hydrogen is also transported in pipelines. The pipeline diameter, the flow rate

and the hydrogen pressure are decisive parameters determining the transport capacity of the

respective pipeline. Pipelines have been realised with pressures between 3 to 300 bar. The

pressure drop in the pipelines requires compressor stations every 30 to 200 km [15].

 Liquid hydrogen. The boiling point of hydrogen at atmospheric pressure is -253 °C. Below

this very low temperature (only 20 °C above the absolute zero), hydrogen is liquid and the

energy density increases to 10.0 GJ/m³ [12]. Cryogenic liquefaction systems are usually

based on multi-stage compression refrigeration circuits. They differ mainly in the number

of stages, the coolant used and the design of the equipment. Liquefaction plants consist of

an upstream gas purification system, the liquefaction plant and a storage system. The

specific energy demand for such a liquefaction is high and can reach 30 % related to the

HHV of hydrogen [58]. Potential boil-off losses add up to this, and thus, the transport of

hydrogen within a liquid status shows a significant energy demand. The transport of liquid

hydrogen is additionally economically challenging as, e.g. only 4 t of liquid hydrogen can

be transported by one truck designed for a payload of 40 t [12].

 Hydrogen stored in carrier materials. Additionally, hydrogen can be stored in another

substance and transported bound within this carrier substance. One carrier group is so-called

liquid organic hydrogen carrier (LOHC). LOHCs are organic compounds that are usually

liquid and chemically stable under standard conditions. They show an unloaded

(dehydrogenated) and a loaded state (hydrogenated). The unloading of the carrier, i.e. the

release of hydrogen from the LOHC, is an endothermic reaction and requires thermal

energy. Vice versa, the loading process is exothermic and provides heat. The chemical

process for loading and unloading of the LOHC are catalyst-supported reactions taking

place at different temperature levels. Depending on the LOHC-substance, dehydrogenation

is conducted at 30 to 50 bar and 200 to 450 °C, whereas hydrogenation provides heat at

slightly lower temperatures [12, 59]. Several LOHCs are under discussion such as

N-ethylcarbazole (NEC), dibenzyltoluene (DBT), toluene, or methanol [60]. An ideal LOHC

shows a high hydrogen absorption capacity and is a cheap substance easily handled without

any safety risks. In principle, LOHC allow for a long-term energy storage without leakages

such as boil-off or other hydrogen losses.

Figure 5: Technical possibilities for a large-scale hydrogen transport

The above discussed hydrogen storage forms can be transported by different modes of transport

requiring specific infrastructure (Figure 5). The hydrogen can be transported by vehicles

(mo-bile transport means) and/or by pipelines (stationary transport means).

A transport of hydrogen by vehicles is currently limited to a small scale or regional hydrogen

supply. Tube, container, and liquid hydrogen trailer are designed to transport hydrogen in a

compressed or liquid form with conventional trucks or trains [12]. A sea transport of liquid

hydrogen is under discussion and a first demonstration project was launched in 2019; here a

conventional diesel-powered vessel has been enabled to carry 1,250 m³ of liquid hydrogen [61].

Hydrogen can also be transported and stored inside a liquid organic hydrogen carrier (LOHC).

Since LOHCs are liquids with similar properties as conventional fuels or other liquids, existing

trailers and ships can easily be used. However, LOHCs are in an early stage of application and

only first demonstration projects have been carried out. For example, a hydrogen transport chain

using toluene as LOHC has been demonstrated in 2020. Within this project the LOHC has been

loaded with hydrogen in Brunei and then shipped 4,000 km to Japan. After the release of

hydrogen, the unloaded LOHC has been sent back [61].

Thus far, large-scale and long-distance transport of hydrogen is realised in pipelines. Hydrogen

pipelines are already operated commercially for decades, but so far, only within clearly regional

networks. The most widespread hydrogen pipeline network is operated in Western Europe with

a length of 1,351 km [62]. The installation of a more widespread hydrogen pipeline network is

discussed e.g. in Germany [15, 63, 64]. However, the discussions focus’ on production and

distribution of hydrogen within national borders.

The EU already implemented a widespread pipeline infrastructure for natural gas, which

potentially opens the opportunity to also transport hydrogen. The natural gas pipeline network

is more than 217,000 km long and more than 116 million customers are connected to this grid

[65]. Four pipelines connect North Africa and the EU. The first pipeline was the

Trans-Mediterranean pipeline commissioned in 1983 [66]. The Maghreb Europe Gas, the Medgaz and

the Greenstream pipelines followed. These pipelines depart from Algeria except the

Greenstream pipeline starts in Libya. The pipelines show a combined a capacity for transporting

63.5

G

m

_{/a of natural gas [67]. However, in 2015, only 25.1}

_G

_m

_{have been transported [4].}

A hydrogen transport in the existing natural gas infrastructure is conceivable by two

approaches.

Mode of

transport

Stationary

(pipeline)

Mobile (e.g. truck, ship)

Compressed

Liquefied

(cryogenic)

Hydrogen

state

Stored in

_carrier

 Blending hydrogen into the natural gas stream. Natural gas might contain traces of hydrogen

and the existing transport infrastructure can accept a limited share of hydrogen within the

gas to be transported [68]. However, a higher share of hydrogen within the natural gas

stream might require adjustments of at least some of the infrastructure components within

gas transport, storage, measurement and control, delivery, and end-use applications. The

lowest hydrogen tolerance is seen for gas turbines, transport- and storage compressors, and

CNG vehicle tanks (ca. 2 % hydrogen by volume) [68]. Natural gas transport pipelines can

potentially bear higher hydrogen contents; however, hydrogen can decrease the durability

of pipeline materials and increase fracture toughness and fatigue crack [18]. The potential

impact of hydrogen within the natural gas infrastructure is a function of the hydrogen share;

i.e. with an increasing share of hydrogen, step-wise more and more components of the

in-frastructure are affected [18, 68, 69]. Additionally, if hydrogen is blended into the existing

gas infrastructure, the end-users receive a gas mixture. For a use in applications designed

for the use of pure hydrogen (e.g. fuel cells), hydrogen must be separated from the

respective gas mixture. Such a separation technologically can be energy intensive and is not

economical in many cases [18].

 Reassigning natural gas pipelines for hydrogen. Reassigning the natural gas infrastructure

to transport pure hydrogen is the extreme case of blending hydrogen into the natural gas

infrastructure. Four concepts for adjusting the pipelines can be distinguished: Pipelines are

used without modification, the surfaces in contact with hydrogen are coated, gaseous

inhibitors are added to the hydrogen stream, or a pipe-in-pipe approach is applied (i.e.

specialised hydrogen pipelines are installed inside existing natural gas pipelines) [70]. The

benefit of a reassignment is that high purity hydrogen is delivered to the end-users; i.e. also

the use of devices requiring pure hydrogen (e.g. fuel cells) can easily be applied. However,

it requires that all infrastructure elements must be able to operate with pure hydrogen.

The text above and the following chapters focus on energy resource potentials, GHG emissions,

and costs of different hydrogen supply options. However, a potential implementation of

hydrogen in the context of sustainable development (this thesis aims to contribute to)

encompasses the three dimensions society, economy, and environment and thus many more

aspects than investigated here. The concepts of life cycle sustainability assessment could

provide a framework for such a comprehensive investigation [71, 72] (chapter 6).

2 Research objective and outline

Against the background outlined above, the overarching research objective of this thesis is to

investigate the potential role of a hydrogen production in North Africa for an energy supply of

the EU under a climate change mitigation perspective. The focus lays upon using the high and

basically untapped resources of renewable energy sources existing in North African countries.

To achieve the overall goal of this thesis the following aspects are tackled in detail:

 The electricity generation potentials and the domestic demand of the untapped resources of

wind power and solar radiation in North Africa are investigated first.

 Then, the hydrogen production potentials and the GHG emissions as well as the economics

of competing hydrogen production options are considered.

 Finally, the transport of hydrogen to the EU within the existing and the potentially newly

installed infrastructure is investigated (Figure 6).

Figure 6: Research objective and research targets

Research questions. These three aspects of the research objective are transferred into three

research questions. These research questions are further elaborated below each split up into

research targets specifying the content of this thesis.

1. Research question:

What is the export potential of renewable (and fossil) energy in North Africa?

a. Estimation of the renewable (and fossil) energy resource potential in North Africa

North African countries show different potentials of renewable source of energy for

electricity production. These potentials are determined (e.g.) through the availability

of land and the technically possible electricity generation through the application of

different electricity generation technologies. Furthermore, some North African

countries show substantial fossil energy resources. These sources of energy are

sum-marized per country.

b. Estimation of the domestic demand in renewable energies on the basis of existing

energy targets

In order to mitigate climate change, local as well as global anthropogenic GHG

emissions need to decline. Thus, the potential of renewable sources of energy in

North African countries must exceed the domestic demand significantly so that

1 - Energy resources in

North Africa

2 - Hydrogen production

- Technical potentials

- Domestic energy

consumption

- GHG emissions and

costs of energy

- Fossil and renewable

energy based

technologies

- GHG emissions and

costs of energy

3 - Hydrogen transport to

the EU

- Transport options in

existing and new

infrastructure

- GHG emissions and

costs of supply

Hydrogen production in North Africa for an energy supply of the EU

(surplus) energy production for an export to the EU (and potentially to other parts

of the world) is available. Political targets are considered in order to estimate the

local demand.

c. Estimation of the GHG emissions and cost associated with the provision of energy

respectively electricity

Hydrogen can only contribute to achieve the GHG reduction goals if throughout the

full life cycle of the supply chain a clear GHG reduction can be realized compared

to the respective competing options. Thus, the GHG emissions associated with the

production of electricity from wind power and solar radiation in North Africa are

investigated. As the EU also targets “affordable” energy supply, costs are considered

[5].

2. Research question:

Which technologies allow hydrogen production with low GHG emissions and costs?

a. Identification of relevant parameters of hydrogen production technologies

potentially emitting low GHG emissions

Besides the production of hydrogen based on electricity from renewable sources of

energy through electrolysis other hydrogen production pathways exist that are

potentially associated with low GHG emissions. Steam methane reforming as the

currently dominating hydrogen production technology can be combined with CO

capture and storage technology allowing GHG emissions to be reduced. Another

alternative is methane decomposition. This conversion option does not lead to direct

CO

emissions based on the main chemical reaction. Relevant process parameters

are identified.

b. Estimation of GHG emissions, costs and CO

abatement cost of hydrogen

production

The full life cycle of the hydrogen supply chain needs to be assessed in order to

estimate the GHG emissions associated with hydrogen production. Depending on

the respective hydrogen production technology, this encompasses the electricity or

natural gas supplies. Furthermore, the installation and manufacturing of the

production plants have to be taken into account. GHG emissions, costs and CO

abatement cost of hydrogen are analysed for the hydrogen production technologies

outlined above.

c. Estimation of costs of hydrogen considering intermittent electricity supply from

renewable sources of energy

PV systems and wind turbines produce electricity with partially strong fluctuations.

This can lead to a capacity factor of an electrolyser clearly below one. Thus, higher

costs result compared to a continuous electricity supply. Combining PV systems and

wind turbines to a hybrid electricity supply system increases potentially the capacity

factor compared to electricity provision either from wind turbines or PV systems.

Determining an optimal combination of PV systems, wind turbines, and electrolyser

are essential to estimate realistic costs associated with hydrogen production. An

optimization is conducted to find cost optimal hydrogen production from renewable

energies in North Africa.