HYDROGEN TECHNOLOGYSTATE OF THE ART

Andrew J. Pimm, Junfeng Yang,Katarina Widjaja & Tim T. Cockerill

SEPTEMBER 2019

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Contents

Nomenclature ............................................................................................................. 3

1 Introduction ......................................................................................................... 4

1.1 Current Interest in Hydrogen ......................................................................... 4

1.2 Realising the Potential .................................................................................. 4

1.3 Transitioning to Hydrogen ............................................................................. 4

1.4 Aims and Objectives ..................................................................................... 5

2 Hydrogen Production .......................................................................................... 6

2.1 Steam Methane Reforming ........................................................................... 6

2.2 Electrolysis .................................................................................................... 8

2.3 Gasification of Coal, Biomass and Waste ................................................... 10

3 Hydrogen Projects for Domestic and Industrial Use .......................................... 11

4 Hydrogen Applications in Transport .................................................................. 15

4.1 Hydrogen Refuelling Stations ...................................................................... 17

5 Hydrogen Transportation Methods .................................................................... 18

5.1 Liquid and Gaseous Hydrogen – Truck Transport ....................................... 18

5.2 Gaseous Hydrogen – Pipeline Transport .................................................... 20

5.3 Ship and Rail Transport .............................................................................. 22

6 Hydrogen Storage ............................................................................................. 23

6.1 Cavern Storage ........................................................................................... 23

6.2 Tank Storage ............................................................................................... 27

7 Greenhouse Gas Emissions from Hydrogen ..................................................... 29

8 Energy System Integration of Hydrogen in the UK ............................................ 31

8.1 Questions and Challenges .......................................................................... 31

8.2 Quantities of Hydrogen Required for Applications ....................................... 31

8.3 Interactions with Other Energy Vectors and Resources .............................. 34

8.4 Managing the Transition .............................................................................. 35

9 Conclusions and Key Challenges ...................................................................... 39

References ............................................................................................................... 40

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Nomenclature

AGN Australian Gas Networks

ATR Autothermal Reforming

CAES Compressed Air Energy Storage

CCS Carbon Capture and Storage

CHP Combined Heat and Power

FCEV Fuel Cell Electric Vehicle

FCH JU Fuel Cells and Hydrogen Joint Undertaking

GHG Greenhouse Gas

HGV Heavy Goods Vehicle

ICE Internal Combustion Engine

IMRP Iron Mains Replacement Program

LPG Liquefied Petroleum Gas

NG Natural Gas

PEM Polymer Electrolyte Membrane

SGT Siemens Gas Turbine

SMR Steam Methane Reforming

SOE Solid Oxide Electrolysis

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1 Introduction

1.1 Current Interest in Hydrogen

The potential of hydrogen as a vector for low carbon energy has been apparent for

many years, but it has only recently been recognised as offering a convincing pathway

for the decarbonisation of the heating, transport and industrial sectors. Interest from

UK policy makers has grown rapidly over the last 2-3 years, partly due to a realisation

that wholesale electrification would require transformation of the electricity industry. In

addition, recent announcements [1] of an intention to move to a zero net carbon

economy will necessitate a large decommissioning of natural gas systems over the

next 30 years, providing a 'window of opportunity' for the substitution of sustainably

produced hydrogen.

1.2 Realising the Potential

Realising hydrogen's unquestionable potential represents a formidable challenge,

because it currently plays an almost insignificant role in the energy sector. This

contrasts with some alternatives, such as electrification and bioenergy, which already

have significant supply chains and industrial eco-systems in place. Given the poorly

developed status of hydrogen, it may superficially appear more attractive to scale-up

these alternative vectors rather than develop a set of new technologies. However there

are significant constraints on all the alternatives. Indigenous bioenergy supplies are

intrinsically limited, and if imported, may have substantial environmental impacts. Full

electrification would require roughly 3-fold increase in low-carbon generation capacity,

representing a policy challenge of the same order of magnitude as deploying hydrogen

in place of natural gas. For these reasons the challenge of hydrogen deployment is

worth exploring further, for now at least, while recognising that some current fossil

energy demands may be more effectively satisfied by other sustainable sources.

1.3 Transitioning to Hydrogen

Smoothly transitioning to an energy sector that fully embodies hydrogen will require a

clear understanding of those applications to which it is well-suited and equally of those

to which it is not. A "whole systems" approach is vital therefore, as developing this

understanding touches on the nature of those applications and the characteristics of

other sustainable sources. More widely, the feasibility of any transition plan depends

on the time required, and existence of the appropriate expertise, to develop the

necessary suite of technologies; the existence of appropriate manufacturing

capabilities within the economy; the development of a workforce with specialist trade

skills and the deployment of infrastructure systems.

In these respects, hydrogen represents primarily an integrational, rather than a

fundamental challenge. Most of the low-TRL fundamentals are well understood, with

respect to the physical and chemical properties of the gas, as well as its combustion

behaviour and its interactions with a wide range of materials. A large array of

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engineering research and design expertise is readily available for the development of

new technologies, with much tacit-knowledge that can be carried over from the fossil

based energy, process and other industries. However at the moment sustainable

hydrogen is not available at a scale, there is no distribution infrastructure, and apart

from some industrial niches, application technologies are only available in proof-of-

concept forms. The real challenge therefore is to facilitate this 'integrational transition'

by developing the key elements of a large scale hydrogen eco-system with low

associated greenhouse gas (GHG) emissions.

1.4 Aims and Objectives

The aims of this document therefore is to briefly review the current ‘state of the art’

across most essential technical components of the hydrogen ecosystem, in support of

the Round 1 Strength In Places “Developing the UK Hydrogen Corridor (H2CORE)”

proposal. Our review begins by looking at techniques for hydrogen production.

Sections 3 and 4 consider end users, covering applications in industry, domestic and

transport contexts. Connecting producers and users will be discussed in the next two

sections, which look at transmission and storage. The final two main sections

introduce a wider perspective by summarising the current understanding of GHG

emissions from hydrogen energy systems, as well as approaches for integration into

the energy system at scale.

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2 Hydrogen Production

Globally around 70 Mt of dedicated hydrogen is produced annually, 76% from natural

gas and almost all of the rest (23%) from coal [2]. Because it readily forms covalent

compounds with most non-metallic elements, only tiny amounts of hydrogen exist as

a gas in the Earth’s atmosphere (less than 1 part per million by volume). Instead, it

exists naturally in water (H2O) and natural gas (CH4), so the main approaches to

producing large quantities of hydrogen rely on these resources. Gas reforming takes

natural gas and extracts the hydrogen, leaving a carbon waste stream that, for low-

carbon hydrogen production, must be stored through carbon capture and storage

(CCS). Electrolysis uses electricity to separate hydrogen from water, leaving oxygen

that can either be used elsewhere or vented to atmosphere. Hydrogen can also be

produced through gasification of coal, biomass, and waste, whereby heat is applied to

produce a hydrogen-rich syngas, from which the hydrogen may be separated.

2.1 Steam Methane Reforming

Steam methane reforming (SMR) is the most mature hydrogen production process,

having been used commercially for many decades. It involves a catalytic conversion

of methane to hydrogen and carbon dioxide, and consists of a steam reforming step,

in which methane is reacted with steam at high temperature to produce carbon

monoxide and hydrogen, followed by a water-gas shift reaction, where carbon

monoxide is reacted with steam to produce carbon dioxide and more hydrogen.

Finally, a pressure swing adsorption step removes the carbon dioxide from the gas

stream, leaving pure hydrogen.

Steam reforming: CH4 + H2O → CO + 3H2

Water-gas shift: CO + H2O → CO2 + H2

Steam reforming, which uses water as both an oxidant and a source of hydrogen, is

one of three different types of gas reforming, with the others being partial oxidation

(using oxygen in the air as the oxidant) and autothermal reforming (ATR, which uses

air and water as oxidants). While steam reforming can be conducted using a range of

feedstocks and fuels, natural gas is typically used as both feedstock and fuel as it is

widely available, requires little pre-treatment, and is generally available at high

pressures, reducing the compression load. Nickel-based catalysts are generally used

in the reformers, and must be replaced roughly every four years. SMR is by far the

most widespread reforming technology for hydrogen, though ATR is also in use.

SMRs are typically built in the 150-250 MW capacity range, with the largest to date

built by Amec Foster Wheeler with a capacity of 338 MW [3]. Roughly 500 large SMRs

are operational globally, with a 150 MW SMR plant in Teesside, UK [3]. Large SMR

manufacturers and operators include Air Liquide, BOC and Linde.

In 2017, SMR was selected as the technology of choice to provide hydrogen to heat

the city of Leeds by a consortium including the region’s gas network operator, Northern

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Gas Networks, in the H21 Leeds City Gate project. Four parallel 256 MW SMR trains

were proposed to meet the expected average demand of 732 MW [3]. This decision

was made as a result of SMR’s maturity, low cost, small footprint, and the reliability of

the fuel and feedstock supplies of methane and water (where low carbon electrolysis

would be reliant on variable wind and solar resources, causing issues with security of

supply and production efficiency). The view that reforming of natural gas with CCS is

likely to be the main source of hydrogen production in the UK going forward is also

shared by the Committee on Climate Change [4] and National Grid [5].

SMRs currently achieve efficiencies of around 65%, though it is expected that

advanced gas reforming technologies could achieve efficiencies of up to 85% [4].

Globally, the majority of the CO2 produced in SMR is emitted directly to the

atmosphere [2]. A small amount is reused in the production of urea fertiliser, however

the CO2 is ultimately released to the atmosphere when the fertiliser is spread on soil.

There are several ways that CO2 can be captured at an SMR plant. Capturing CO2

from the high pressure syngas reduces emissions by up to 60%, costing 53 USD/tCO2

with current natural gas prices in Europe. Alternatively, CO2 can be captured from the

flue gas, reducing emissions by up to 90% or more but costing 80 USD/tCO2 [2].

Higher CO2 recovery can be achieved in ATR plants as all the CO2 is produced inside

the reactor, and CO2 can be captured at a lower cost because the emissions are more

concentrated. Several studies have shown that the costs of an ATR plant will be lower

than those of the equivalent SMR plant at CO2 capture levels of 90% or more [6].

Costs

The cost of producing hydrogen through steam methane reforming is largely

dependent upon the natural gas price. It is expected that a SMR built in the UK today

would provide hydrogen at a cost of £32-50/MWh, including fuel costs of £16-34/MWh

and carbon costs of £9/MWh [4]. It is anticipated that the introduction of advanced

reforming and CCS could result in low carbon hydrogen being produced at a cost of

£38/MWh by 2050, based on a gas price of 67 p/therm. A 2017 study of the costs of

producing low-carbon hydrogen is summarised in Figure 1.

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Figure 1 Costs of hydrogen production from low-carbon hydrogen technologies [7].

2.2 Electrolysis

Electrolytic hydrogen production is the process of splitting water (H2O) into hydrogen

(H2) and oxygen (O2) using electricity. Electrolysis produces hydrogen with very low

levels of contaminants (99.999% purity), making it particularly suitable for use in fuel

cells. Electrolysers are modular, and so can be stacked to create larger systems.

Several electrolyser technologies exist at various stages of readiness, however

electrolysis currently accounts for only 2% of global hydrogen production [2]. Leading

electrolyser manufacturers include Nel Hydrogen, Hydrogenics, Proton OnSite, Giner,

and ITM Power. In August 2018, Nel announced that they were constructing the

world’s largest electrolyser production plant, with a nameplate capacity of 360 MW of

electrolysers per year [8].

The most mature and lowest-cost electrolysis technology is alkaline electrolysis,

producing the vast majority of global electrolytic hydrogen. As of 2018, the largest

alkaline electrolysis plant in existence has a 2.5 MW capacity, however plants with

capacities of over 150 MW were built in the last century [2, 7]. These were mostly

decommissioned when SMR became widely used in the 1970s. Alkaline electrolysis

has a number of technological limitations, including limited ability to operate at low

loads and the inability to operate at high pressure.

Polymer electrolyte membrane (PEM) electrolysis, otherwise known as proton

exchange membrane electrolysis, has been developed rapidly in recent years. It was

developed to overcome some of the issues associated with alkaline electrolysis, such

as limited part load operation and low current density. Siemens has operated a 6 MW

PEM electrolysis plant in Germany since 2015 [9]. A 10 MW plant is currently under

construction by ITM Power in Germany in partnership with Shell [10], and will produce

up to 1,300 tons of hydrogen per year [11]. A 20 MW plant is currently being developed

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SMR with CCS Coal Gasification withCCS

Biomass Gasificationwith CCS

Electrolysis

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by Hydrogenics for Air Liquide in Canada, with an expected hydrogen production rate

of almost 3,000 tons per year [12].

Solid oxide electrolysis (SOE) is an emerging technology which differs from alkaline

electrolysis and PEM electrolysis in that the operating temperatures are much higher,

typically 800-1000 °C [13]. As a result, steam must be used as the feed instead of

water. If these temperatures can be reached efficiently, such as by harnessing waste

heat from industry, then SOE can have high efficiencies, however the high

temperatures can cause numerous problems with cell degradation, including poor

long-term stability and interlayer diffusion.

Seawater electrolysis has been proposed for areas with restricted access to fresh

water, either through electrolysis after desalination or by direct electrolysis of seawater

[14-16]. Using reverse osmosis for desalination has only a minor impact on the cost of

hydrogen production (<1% increase) [2]. Direct electrolysis of seawater currently has

issues with corrosion and generation of chlorine, however research is ongoing in this

area.

Hydrogen has a higher energy density per unit mass than petrol and diesel and so

may be used as a low carbon fuel for heavy transport such as heavy goods vehicles

(HGVs) [17], buses [18], trains [19], and ships [20]. With the high purity of electrolytic

hydrogen, combined with the fact that electrolysers can be relatively small and sited

in any location with an electricity grid connection, it is possible that electrolysers will

be particularly attractive alongside refuelling stations for hydrogen vehicles. It is

anticipated that up to 400 hydrogen refuelling stations will be required for HGVs in the

UK alone [4].

Costs

The costs of producing hydrogen using electrolysis are higher than those of SMR are

currently estimated at around £90/MWh H2, but could fall to around £75/MWh H2 with

improvements in efficiency (assuming an electricity price of £51/MWh H2) [4]. A large

proportion (80-86% [4]) of the cost of producing hydrogen using electrolysis is the cost

of the electricity. As a result, the impact of further cost reductions is likely to be limited.

The efficiency of an electrolyser is affected by the load factor at which it is run, so

powering it with an intermittent source such as wind will generally lead to lower output

levels. However, in certain regions a hybrid wind and solar power system could be

used to produce hydrogen using electrolysis at considerably lower costs than in other

regions. Particularly promising regions include Patagonia, New Zealand, North Africa,

the Middle East, Australia, and parts of China and the USA [2]. In the UK, it is expected

that the cost of electricity would need to be below £10/MWh to make electrolysis cost

competitive with SMR+CCS [4].

Research and Development

Electrolysers can be seen as the reverse of fuel cells, and so advances in fuel cells

could contribute to advances in electrolysers. In the area of PEM electrolysis, there is

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considerable ongoing research into the development of new membranes with

improved properties such as increased mechanical strength and higher proton

conductivity.

2.3 Gasification of Coal, Biomass and Waste

Gasification of coal is a mature technology that has been in use for many decades.

It was used for town gas production in the UK until the 1960s, and continues to be

used for ammonia production. Globally there are around 130 coal gasification plants

in operation, over 80% of which are in China, where it is the lowest cost route to

producing hydrogen [2]. As a result, the energy company CHN Energy, which operates

80 coal gasifiers producing around 8 MtH2/yr, is the world’s largest producer of

hydrogen.

The carbon emissions associated with coal gasification for hydrogen production are

around twice those of unabated steam methane reforming, so it must be equipped with

carbon capture for low carbon hydrogen production. Coal gasification produces

hydrogen with a very low hydrogen-to-carbon ratio (around 1/40th that of using

methane) with high levels of impurities in the feedstock. Using coal with CCS is likely

to be the lowest cost option for low carbon hydrogen in China and India in the near

term because of their existing coal mining infrastructure and poor access to natural

gas, however this is not necessarily the case in other countries. In Australia, the

Hydrogen Energy Supply Chain (HESC) Latrobe Valley project is seeking to produce

hydrogen from lignite using partial oxidation, with carbon capture alongside.

Gasification of biomass and waste is a more novel technology that is currently in

the research and development phase. The process is similar to that of coal

gasification, but the feedstock requires more pre-treatment to remove contaminants.

Combining production of hydrogen using biomass with CCS would create a negative

emissions technology, which could potentially play an important role in meeting net

zero emissions targets.

Costs

It is expected that a new coal gasification plant in the UK, including CCS, would provide

low carbon hydrogen at a cost of £68/MWh. It is anticipated that future cost savings

will bring this down to around £61/MWh [4]. Unlike other hydrogen production

technologies, the capital costs of coal gasification plants are greatly affected by

economies of scale. It is expected that the costs of biomass gasification in the UK will

be in the range £64-£127/MWH in 2040 [4].

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3 Hydrogen Projects for Domestic and Industrial

Use

Employing hydrogen in domestic and industrial purposes is one of the crucial

challenges today for decarbonisation. There are many hydrogen and hybrid projects

to reduce or eliminate CO2 gases, mostly focused on areas such as micro- Combined

Heat and Power (CHP). Many programmes are set as a step towards decarbonised

heat. In November 2006, Denmark built a demonstration project on the island of

Lolland in Nakskov town for residential CHP using hydrogen fuel cells [21]. This facility

was developed until 2012 to be able to heat and power 40 homes. The low power fuel

cells are able to feed power by 0.9-2.0 kW and heat by 0.8-2.0 kW.

HyBalance [22] is a Danish project started in 2016 for the purpose of producing green

H2 from water electrolysis to balance the grid electricity and use hydrogen as a storing

agent for industry. This project is due to complete by October 2020.

The (H21) North of England is a project of converting 3.7 million homes and

businesses natural gas network distribution to 100% hydrogen circa 14% of all UK

heat [23]. This project is led by Northern gas networks and in partnership with Equinor,

Cadent, Scottish southern gas networks and Wales and west utilities. It is due to

complete by 2020/21 and it costs £10.3 M.

H21 project aligns to hydrogen relevant programmes [24] like: Hy4heat, Hynet and

H100. Hy4heat [25] is a UK government hydrogen programme which employs

technologies to check the feasibility and provide the safety-based evidence of gas

conversion to hydrogen for domestic and industrial heating. This programme costs £

25 M and due to complete by 2020/21. Petroleum industry company Equinor will be

responsible for natural gas/hydrogen conversion via SMR and ATR processes giving

a capacity of 12.15 GWH2; 8TWh as an inter-seasonal storage. These require an

associate CCS of 20 Mt of CO2 per annum by 2035 Northern gas networks [26].

Hydeploy [27] is also a UK scheme to also check the safe implementing of the

hydrogen blending with 20% by volume with natural gas. This project is funded by

Ofgem (Office of Gas and Electricity Markets) and aims to reduce carbon emissions

in domestic heating and cooking. Hydrogen in this project is going to be injected

unprecedentedly into a natural gas network. This test will be carried out at Keele

University in Staffordshire for 10 months starting from Autumn 2019.

One of the important schemes of UK hydrogen conversion is ‘’UK Hydrogen Corridor’’.

The partnership of this project carried out between different UK universities: Teesside

University, University of Leeds, Durham University integrated with the welding and the

material processing institutes. This project aims to generate H2 in Teesside and use it

for industrial applications as 50% of UK hydrogen is produced from Teesside and also

use it in domestic applications in Leeds city [28].

A project launched in Levenmouth-UK by Bright Green Hydrogen from The Hydrogen

Office Ltd [29] to produce hydrogen depending on a wind turbine (750 kW) and alkaline

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electrolyser (30 kW) in 2016. The hydrogen produced is employed in CHP and service

station.

Project BigHit [30] is due to complete by end of April 2021. This project aims to

produce green H2 relying on renewable electricity source on the islands of Eday and

Shapinsay in Scotland. The hydrogen will be stored in tube trailers to be transported

to Orkney. This will be employed in heating two school and with a 75kW fuel cell to

heat and power marina, three ferries and harbour buildings.

In Germany, Hydrogen Power Storage and Solutions project (HYPOS) has begun the

research projects like (H2Netz) [31] for distributing a network infrastructure for green

H2. This project is funded by Federal Ministry of Education and Research (BMBF).

(H2Home) is also another project works in line with H2Ntez and it will provide a micro-

CHP depending on Green H2 using PEM fuel cell giving up to 5 kW of electrical power

with a peak boiler load of 12 kW in domestic homes [32]. These projects will be

combined in so called (Hydrogen village) project and is due to complete in 2021.

Horizon H2020 framework is the EU research and innovation scheme for promoting

hydrogen projects in Europe integrated with Fuel Cells and Hydrogen Joint

Undertaking (FCH JU) as a supporting private partnership research. (ELECTROU)

project as a one scheme funded by FCH HU is started in Jan 2018 to include district

heat and power by fuel cell at King’s Cross, London. This project has included the

installation of the first MW fuel cell in Europe providing heat and power within the local

building. By 2023, this project is due for completion [33].

Another project supported by FCH HU is (HEATSTACK) which started from April 2016-

2019 focusing on the industrial processes of Hydrogen production components

including air preheaters, the fuel cell stack, and micro-CHP systems. The project was

a collaboration between the research and industrial sides in UK, Czech Republic, Italy

and Germany [34].

A SOFTPACK [35] is funded by Europe Frame Programme (FP7) with the

collaboration between three sides; Ceramic fuel cells GMBH-Germany, Ideal Boilers

LTD-UK and Home Software BV-Netherlands, and has completed in October 2015.

This project was aiming to install fuel cell systems for residential buildings as a micro

CHP. Heat energy provided by the fuel cells are 26 kW for boiler and tank system to

supply domestic heating and hot water. Power supply is up-to 36 kWh daily per each

house

Enertag company in Prenzlau, Germany started a (H2BER) project in 2011 to produce

H2 from wind turbine sources (3 x 2 MW) for storage in tanks or in hydrides at different

pressures and CHP and fuelling station. The waste heat from CHP is used for heating

the nearby town of Prenzlau [36]. [37] project started by implementing a research unit

composed of four wind turbines (10 MW), three electrolysers (2MW x 3) provided by

Siemens and ionic compressor supplied by Linde and two storage tanks for H2 . The

hydrogen produced is used in refuelling station and also injected in natural gas

network grid. (RH2-WKA) project launched in 2013 to initially supply electricity to the

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wind farms from the surplus electricity of 28 wind turbines (140 MW) supplied by

Enercon, and (1MW x 3) Alkaline electrolysers to produce H2. Then, the storage

capacity of hydrogen was able to also operate the CHP units for nearby farm with up

to 28 h at maximum speed [38].

In 2013, a scheme from the (H2Herten) project supplied electricity to industrial and

commercial park (Mini Grid) in Herten, Germany through hydrogen. The surplus

electricity from a wind turbine is used by 280 kW electrolyser to produce H2. 50 kW

fuel cell is employed to supply the electricity to the mini grid [39]. German company

Uniper operated two projects: (WindGas) project for Falkenhagen and for Hamburg.

(WindGas) project for Falkenhagen is inaugurated in 2013 by E.ON Gas Storage and

Swissgas. This considered the world’s first demonstration plant to store wind energy

in natural gas network. This project aims to supply surplus electricity from wind turbine

(400 MW) to six electrolysers (2MW) produce H2. This hydrogen is compressed and

injected to natural gas network (2% H2) and also used for heating. In 2015, the unit is

improved to increase the concentration of hydrogen in natural gas network. 1 MW PEM

electrolysis is used for (WindGas) project in Hamburg and it is still in operation [36].

Thüga group of energy suppliers inaugurated March 2014, a 320 kW electrolyser to

produce H2 to be injected to Frankfurt am Main natural gas distribution network on a

site of Mainova [40].

In 2014, a French initiative project (GRHYD) in the development of hydrogen launched

under the coordination of ENGIE company. This project is supported by the French

government and its target is to supply a blend of up to H2 (20%) and natural gas (80%)

for 200 homes in the Capelle la Grande district of the Dunkirk urban community for

heating and domestic water purposes [36]. The project started its demonstration on

June 2018.

(MYRTE) project located in Corsica (France) started in 2006 by University of Corsica,

the Helion company and the Commission of nuclear energy. The project inaugurated

in 2012 to generate hydrogen from 200 kW electrolysis [41]. The electricity is supplied

from a photovoltaic park of 550 kW. This project was aiming to provide power to

stabilise the electricity grid and an update of using fuel cell to supply extra power in

peak demands.

Gasunie New energy and EnergyStock inaugurated (Hystock) project also in June

2019 near the natural gas storage in Groningen (Netherlands) to produce green H2

from 1 MW electrolyser to be stored and used in industry, transportation [42].

Between 2004 and 2008, green H2 has been produced on the Norwegian island of

Utsira from electricity generated by two wind turbines (2 x 600 kW) to supply power to

ten houses on the island for up to 48 h [43]. This project was launched by StatoilHydro

and Enercon.

From 2007 to 2010, a US project (WIND2H2) led by National Renewable Energy

Laboratory (NREL) provided electricity from 10 kW photovoltaic plant and two wind

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turbines (10 and 100 kW) [44]. Electrolysis is used to produce H2 to be able to feed

power to the utility grids at peak hours in Colorado.

In Kofu city, west Tokyo, the New Energy& Industrial Technology Development

Organisation (NEDO) [45], H2 is produced from the electricity generated by solar

energy and hydropower generator in 2015. H2 is stored to feed Panasonic fuel cell to

be employed as a reserved source in case of a shortage in solar production.

The Swiss public utility, Regio Energie Solothurn (RES) has developed a hybrid plant

Aarmatt [46]. This plant is working on three different networks; electricity, gas and

district heating. Hydrogen is produced from 350 kW PEM electrolyser supported by

Proton Onsite and stored on site in tanks to be injected into the gas grid. The project

is developed to feed 6 MW of power and 12 MW of heat in 2018 under the frame of

the European projects; Horizon 2020 and Store & Go which operates (Ingrid) project

in Italy to balance the highly variable power demand resulted from the intermitting

renewable energy supply [47].

In Canada, a mini grid project introduced by Glencore in 2015 for the Raglan nickel

mine using electrolysis of 315 kW from a 3 MW wind turbine [48]. In this project

hydrogen produced is stored to start up a diesel generator or fuel cell for backup.

Furthermore, a 2 MW electrolyser project in Ontario developed by Enbridge Gas

Distribution in partnership with Hydrogenics Corp. was operated to produce H2 for

storage to compensate the imbalance in the electricity demand[49].

In Thailand, 2018, EGAT introduced the first project in Asia to employ the wind energy

to store the electricity via 1 MW electrolyser and 300 kW PEM fuel cell and power the

new energy centre of EGAT[50].

Australia started the step towards free-carbon environment, these steps included the

project in Kidman park in south Australia [36] for producing hydrogen from 1.25 MW

Siemens electrolyser that will employ renewable energy. Australian Gas Networks

(AGN) is working to establish this project by mid-2020. AGN is hoping to install tubes

and trailer facilities to accomplish the transportation and the injecting of hydrogen into

the gas network and also industry refuelling in partnership with the Australia south

Australian governments.

For a domestic gas boiler applications, a fuel cell boiler Vitovalor 300-P released in

2015 working as micro CHP [51]. It is using a PEM fuel cell in collaboration with

Japanese Panasonic to provide high pressure hot water to houses with a peak load

170 L buffer cylinder and 46 L of domestic hot water tank. An integrated fuel reformer

converts the natural gas into hydrogen and CO2 is released in the flue. The electricity

from this boiler is 0.75 kW and the thermal output is 1 kW.

Further in June 2019, the first world domestic boiler powered by green H2 was put into

operation. This boiler is manufactured in Rotterdam, Netherlands by [52]. The Dutch

project is a collaborative work between Network operator Stedin, the municipality of

Rotterdam and Ressort Wonen.

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4 Hydrogen Applications in Transport

In January 1807, the first car with internal combustion engine (ICE) was invented by

the Swiss: Francoise Isaac de Rivaz to ever work on a mixture of hydrogen and

oxygen. Whistle the first investigation of using liquid hydrogen in propulsion system

launched in 1945 by US. Across the world, the demand for improving the efficiency,

zero emissions power trains using hydrogen as a fuel in transport is increased.

There were some developments in passenger cars powered by pure hydrogen. BMW

tested a luxury BMW Hydrogen 7 [53] in between 2005-2007 as the world’s first

hydrogen powered car. This car is equipped with ICE running on liquid hydrogen to

achieve 187 mph in tests. Early 2010, Aston Martin Rapide S [54] is introduced as an

ICE hybrid car working on hydrogen and gasoline solely or at the same time achieving

190 mph.

An important milestone nowadays is the evolution of fuel cells technology in all sorts

of transportation. The PEM fuel cell is elucidated as a base for hydrogen- powered

cars, buses and light duty vehicles. The key challenges for deploying this technology

economically and financially is the new infrastructure for transportation. The power

required for high mileage is also a key parameter despite the expansion of hydrogen

in transport through fleets and corridors of cars, trucks and buses.

Fuel cell vehicles are considering the future vehicles for a zero-emission environment

and high performance. Toyota Mirai [54] was unveiled in 2014 as a concept vehicle to

be able to travel up to 300 miles in a single full tank of hydrogen achieving 111 mph

top speed giving 153 hp. The refuelling for this car takes from 3-5 minutes. Another

Japanese car released in 2016 is the Honda Clarity [55] and it is estimated to travel

up to 366 miles on a full tank giving a power of 174 hp. Hyundai has released Tucson

as also a fuel cell vehicle to be able to run up to 265 miles [56] before refuelling giving

a horse power of 134 followed by Hyundai Nexo in 2018. Nexo is now achieving 163

hp and can travel up to 380 miles before needing a refuel [56]. Mercedes Benz GLC

F-CELL is released in 2018 [56] but BMW will release x5 in between 2020-2025 [57].

Audi [58] presented h-tron hybrid car delivering a total 308 hp from fuel cell and electric

battery and it claimed that the car could travel up to 372 miles before refuelling. Joining

the hydrogen fuel cell business, trucks showed a great potential in using hydrogen fuel

cells as GM has developed Chevrolet Colorado ZH2 truck [59] powered by pure

hydrogen fuel cell to give 134 hp.

Fuel cell buses have undergone a wide demonstration all over the world. FCH JU’s

program (HyTransit) ended in December 2018, after 6 years of demonstrating a fleet

of six A330 hybrid fuel cell buses daily with hydrogen refuelling station for three years

in Aberdeen, Scotland [60]. The project includes buses from Van Hool (Belgium). This

project aims to run the buses with the same operational performance of an equivalent

diesel engine per day. It hopes to be commercialised making the buses viable. As an

example for the spread of the hydrogen buses; the Solaris Urbino buses [61] which

produced 12 buses to be working in the Italian city of Bolzano. This bus will be

16

equipped with 60 kW fuel cell system. Also, a bus manufactured by Safra Businova

company as the first French hydrogen bus working on a hybrid system (H2/Battery) to

be employed giving a 300 km after 30 minutes charging [62]. FCH-JU [63] reported

that the number of the fleets will increase in Europe from 90 to 300/400 buses by 2020.

Toyota also started to sell its Sora [64] buses that powered by hydrogen fuel cell in

March 2018. It is planning to supply more than 100 buses in the Tokyo metropolitan

area for the 2020. In China, Geely company launched the F12 commercial hydrogen

fuel cell bus to run over 500 km after refuelling [65]. The refuelling takes 10 minutes

and the bus is powered by GCV company.

For Hydrogen-fuelled trains, there is very few application and interestingly, French

TGV-maker Alstom built the world’s first hydrogen fuel cell trains, Coradia iLint, to

replace diesel trains in Germany [66]. The train reached a commercial service to run

up to 100 km between some towns in Northern Germany. The excess energy from the

fuel cell system is stored in i-lithium batteries on the train. Alstom announced a supply

of 14 trains is planned to carry out by 2021.

In Newcastle University (UK), a new concept engine is proposed on the free piston

engine theory [67]. This engine uses H2 as a fuel and it is based on Brayton cycle

using an expander and a compressor. The thermal efficiency of this engine proved to

be higher than IC reciprocating engine. The project is under operational and the testing

for a zero-emission closed-loop cycle engine is ongoing.

Antares DLR-H2 is a fuel cell flight manufactured in 2009 for research purposes using

100% hydrogen. This plane can fly up to 450 miles at 105 mph. But for the large scale,

blending hydrogen with natural gas in the gas turbines is most common and in fact it

is developed throughout the years [68]. Siemens had manufactured different gas

turbines like: SGT 600, 700 and 800 [69] that use hydrogen co-firing capability of 40%.

Moreover, GE company is also employed gas turbine for hydrogen blending (6B.03)

gas turbine [70] . This version used in Spain and South Korea refineries to be able

now to blend up to 90% hydrogen. Siemens in August 2019 announced a target of its

gas turbines to be run on 100% green H2 by 2030 [71].

17

4.1 Hydrogen Refuelling Stations

Japan, Germany and US are leading the race of H2 refuelling stations with a total 91,

45, and 39, [72] respectively, comparing to other countries such as UK and Canada.

In 2017, the Zero Impact Production (ZIP) project is launched in California by

Hydrogenics and StratosFuel. Hydrogen is produced by 2.5 MW PEM electrolyser to

be employed in the refuelling stations owned by StratosFuel [73]. US project

(WIND2H2) [44] as a source of electricity, it is also providing a compressed hydrogen

(400 bar) to a refuelling service station.

In UK, there are 13 hydrogen refuelling stations working [74] and the largest is in

Aberdeen, Scotland, operated by BOC [75] with compressed hydrogen at 700 bar.

According to the project (Hybalance) in Hobro, Denmark, one of the other aims is also

to construct five hydrogen refuelling stations [22].

In Japan, Tokyo planned to increase the hydrogen refuelling stations to 35 by 2020

and 80 by 2025. The project is funded by the metropolitan and central governments.

This plan is put as a result of the announcement of latest Toyota and Honda fuel cell

electric vehicles (FCEVs) [76].

In 2012, the European project (Ingrid) was started in Troia, Italy aiming to produce

green H2 by the electricity generated from a wind farm in this place to be used for

service refuelling station in line with the balancing the electricity grid as mentioned in

Section 3 and the usage in the industry [47].

In Hebei province- China, a project was launched to produce hydrogen from the

surplus wind turbine electricity (200 MW) in 2014. This hydrogen is stored and

employed to refuel (FCEVs) and is planned in 2022 to supply buses operated with

hydrogen fuel cell at the Winter Olympics [77].

H2Nodes [78] started as a hydrogen project until December 2018 for North Sea Baltics

countries: Estonia, Lithuania and Netherlands. The project aims to supply hydrogen

for refuelling station networks. The Estonian partner in (H2Nodes) is (NTBene) project

that depends on renewable energy (wind turbines and solar cells) in supplying

electricity. This project stores hydrogen produced from (1 MW x 3) electrolysers and

compresses it to 200/350/700 bars for service stations.

Many projects under construction like the one in Singapore which is developing a

microgrid hydrogen storage system to power the island of Semakau [79] depending

on the wind energy on the island. This project is sponsored by ENGIE company and

will be able to construct a hydrogen refuelling station. Fruitfully, 80 new H2 refuelling

stations are built in 2018 increasing the total number in the globe to about 376 and it

is expected to increase up to 5000 in 2032 [80].

18

5 Hydrogen Transportation Methods

With the purpose of using hydrogen as a major energy carrier, technologies in storing

and transporting hydrogen are continuously being studied to provide high efficiency in

energy delivery while still being economical [81]. Two common forms of storing

hydrogen for hydrogen deliveries are liquid (LH2) and gaseous hydrogen (GH2), which

are obtained through liquefaction and compression processes respectively. LH2 and

GH2 produced requires different method of transportation. Mainly, the mode of

transport is based on the distance from source, use purpose, time constraints, amount

of energy required, and most importantly the capital and operating cost.

5.1 Liquid and Gaseous Hydrogen – Truck Transport

Compressed gaseous hydrogen is currently the simplest method in storing hydrogen

since the process of compression only requires a compressor and pressure vessel.

The main drawback of compressed gaseous hydrogen is due to its low energy density,

which is one tenth that of gasoline. This necessitates the need for higher storage

pressures which results in an increase in cost while also increasing safety issues.

Thus, a compromise between the increase in storage capability, overall vehicle gross

weight, overall costs (capital and operating), and safety risks from the higher pressures

needs to be evaluated [81].

As an alternative to gas compression, hydrogen can also be stored for transportation

in liquid form through a liquefaction process to increase its energy density when

compared to gaseous hydrogen. Since the critical temperature of hydrogen is at

−239.6°𝐶, liquefaction of hydrogen is an energy intensive process in which the gas

must be compressed and cooled to form a dense liquid. To maintain its liquid form,

storage of the liquid hydrogen requires consistent cooling below −250°𝐶. Furthermore,

depending on the method of transportation, a super-insulated storage tank needs to

be used to avoid significant ‘boiloff’ during storage where heat input from outside the

tank can cause vaporisation of the liquid inside the tank. This increases storage costs

by as much as four to five times when compared to GH2 storage even at a more

efficient transportation cost (higher hydrogen density per truck loaded in liquid

hydrogen transport).

19

Liquid Hydrogen

Capacity 1,450-7,700 pounds (≈660-3,500 kg)

Temperature -423°F (-252.8°C)

below 250°C

Material well insulated tankers with double walled structure

Truck Cost ≈ $625000 (£2019 638,876.42) each tanker.

Other boil-off rate 0.3%

a cooling system developed by Linde was capable of delaying boil-

off time by approximately 12 days by utilising cold hydrogen gas in

liquefying surrounding air (to -191 deg C) which is recycled as a

cooling agent for the storage tank [82]

Gaseous Hydrogen

Capacity 300 kg with net delivery of 250 kg

Temperature 10°C

Material mostly carbon steel which is adapted for high pressure usage

aluminium carbon and composites are being developed for added

safety with minimum leakage

Truck Cost carbon composites storage tanks costs US$1,000/kgH2

(£2019 1,079.6/kg H2) [82]

steel tube trailers for transporting 700 pounds of hydrogen costs

around $165,000

(£2019 160,145.17 or £2019 508.86/kg H2) [83]

Other maximum pressure of 3,600 psig (≈248 barg)

minimum pressure of 30 bar

compressor is needed to unload GH2 to refuelling stations with

common pressure of 6,000~12,000 psig (414~828 barg)

compressor capacity of 251kg/hr to compress hydrogen from 20

bar to 450 bar, costs a total of $950,000 (£2019 922,008.35)

Table 1: Technical Specification of LH2 and GH2 Truck Transport [82, 83].

Energy Consumption

Generally, in comparing these two processes, compression of hydrogen to 5000 psi

(345 bar), depending on its initial pressure, consumes about 4% to 8% of its energy

content, while the liquefaction process consumes approximately 30% to 40% of its

energy content [81, 84].

20

GH2 0.66 kWh/kg from 300 1000 psig (2169 barg)

2.7 kWh/kg in refuelling stations from inlet pressure of 5 to 12 bar to

storage pressure of 250 to 450 bar

LH2 7 to 17.5 kWh/kg

Table 2: Energy consumption for liquefaction and compression of hydrogen [82, 83].

Note that energy consumption of liquefaction plant relies heavily on the scale of

production of the plant. Larger plants consume lesser energy per kg LH2. For

compression, energy requirement is based on a logarithmic relation between the initial

pressures to compression power in which a higher initial pressure results in a lesser

energy requirement [85].

General Use

Due to its high energy density but high energy consumption, liquid hydrogen is most

efficiently used for long-distance delivery with higher delivery volume to maximise

delivery capacity. On the other hand, for short distances with low energy demands,

gaseous hydrogen is preferred since it requires lesser energy to store compared to

LH2 [86].

5.2 Gaseous Hydrogen – Pipeline Transport

A pipeline distribution network is currently the most efficient way of delivering hydrogen

in large quantities. Comparing with natural gas pipelines, hydrogen has a faster flow

rate but lower energy density by volume, meaning that at the same pressure, hydrogen

pipelines require at least 20% larger in capacity than natural gas to carry the same

amount of energy [87].

Material

Due to hydrogen’s small molecular size, leakage throughout the pipeline is more prone

to occur, especially in the joints between pipe sections. Therefore, seals and gaskets

are critical for hydrogen pipeline. With considerations of leakage prevention and added

safety, a percentage of leakage for hydrogen pipeline is about 1.7% [82].

Steel pipes are also vulnerable to cracking due to hydrogen embrittlement which

allows hydrogen to react with steel carbon atoms under certain conditions. Thus,

higher strength carbon steel which content in higher carbon percentage leads to higher

possibility of failure compared to ductile steel [81].

Application

In US and Canada, total hydrogen pipeline length is 1712km with smaller pipelines for

individual customer are mostly built with diameter range of 8 to 12 inches, with

operating pressure of 41 to 62 bars. Larger pipelines for industrial purposes are built

21

up to 14 to 18 inches of pipeline diameter, with highest operating pressure of 138 bars.

These pipelines are made of API 5LX Grade 42, 52, and 60 (low strength carbon steel)

[83, 88].

In Europe, hydrogen pipelines have been operating since 1930 in Germany, followed

by installation in other areas of Europe which are mostly operated by gas distribution

companies such as Air Liquide, Air Products, and Linde.

Country Operator Total

Length

Average operating

Pressure

Pipeline

Material

Germany Air Liquide, Linde 390 km 250 psig (≈17 barg) X42

France to Belgium Air Liquide 916 km 1400 psig (≈96 barg) X52

UK (Teesside) ICI, Linde, Air Products 40 km 5 bar -

Netherland Air Products 50 - -

Sweden 18 0.5 to 2.8 bar -

Table 3: Technical specifications on hydrogen pipelines in Europe [82, 88, 89].

Economic Data

Overall pipeline costs can be categorized to material cost, labour cost, right of way

cost and miscellaneous cost. Comparing each cost category to natural gas pipelines,

Dodds and McDowall [87] estimates that hydrogen pipeline is 20% higher in material

cost due to higher steel price to avoid embrittlement, as well as added sealings and

gaskets to avoid leakage. With an assumed application in the UK, the relative

labour cost is greater by a factor of 1.2 while grassland terrain contributes

to a multiplier of 1.0 [90]. Furthermore, as explained above, hydrogen

pipelines are more prone to leakage and specific sealing and welding skills are

required. Parker, N. [91] suggests an overall +25% multiplier for hydrogen pipeline

labour cost. Right of way and miscellaneous costs are generally similar to natural gas

pipelines, where low or zero right of way cost could happen when there is an existing

pipeline built in the same location. [84] surveyed the installation and right of way cost

for hydrogen pipelines to be £2019 322,653.51 per km for application in rural areas, and

£2019 653,307.03 per km for application in urban areas. Overall, pipeline investment

costs range from £2019 1,245.78 to £2019 3,581 per diameter (m) and length (m),

depending on the area of application (urban areas reflect to higher cost), type of

network (low-pressure network for smaller pipes and low-demand users reflect to

higher cost per diameter and length of pipeline) [87]. Compressor is also needed within

a pipeline network to maintain a high distribution flow rate of hydrogen, compressor

power and maintenance are the major operating cost of pipelines, which can be

approximated in range of £2019 950 to £2019 5,750 per kW depending on the flow rate,

pressure difference, and the efficiency of the compressor itself. Schmid and Krewitt

22

[82] mentioned that energy demand of each compressor ranges from 0.01% to 4.5%

of energy being delivered. High capital expense of pipelines is one of the challenges

of pipeline transport compared to other method of transportation, installing larger

pipelines which able to accommodate from different production plants is one way of

reducing initial cost which was applied in Gulf Coast (US) hydrogen pipelines [81].

5.3 Ship and Rail Transport

Other than truck transport, liquid hydrogen can also be transported via ship for open

sea transport with higher capacity compared to other method of transportation.

Storage tank requirements such as super-insulated walls and working temperature of

below 250°C (similar to truck transport) are critical for ship transport due to longer

delivery time which can take 3-5 days to the destination, meaning higher possibility of

‘boiloff’. Also due to this reason, rail transport is not feasible for liquid hydrogen

because of uncertain transit times of rail system [83]. Companies such as Moss

Maritime, Equinor, Wilhelmsen, and DNV GL have recently developed a design of LH2

bunker vessel with volume of 9,000 m3 [82, 92] and estimates the investment cost for

ship transport to be in the range of £𝑚2019 200 to £𝑚2019 280 depending on the size

and capacity of the vessel. Comparison to liquid natural gas investment cost can also

be used as estimation, with a multiplication factor of 0.8.

23

6 Hydrogen Storage

Hydrogen storage has seen considerable levels of interest in recent years through

hydrogen’s potential to be used for large-scale electricity storage as well as being a

fuel for transport and heating. Being the lightest molecule, hydrogen has a very low

density at atmospheric temperature and pressure, and so its storage is challenging.

Its density is increased through compression, liquefaction, or binding it with other

materials. Due to the small size of hydrogen molecules, it diffuses into many metals

and can cause hydrogen embrittlement, whereby hydrogen diffuses into a hydride-

forming metal, causing the metal to become brittle. This can affect steels, with the

susceptibility of a steel to hydrogen embrittlement increasing with the steel’s strength.

Hydrogen storage can be split into two categories: physical and chemical. Physical

storage of hydrogen involves storing it as a gas or liquid, and chemical storage

involves binding it with other chemicals, such as with nitrogen to form ammonia or with

a metal to form a metal hydride. One chemical storage option is to combine hydrogen

with carbon to form a synthetic hydrocarbon, however this is not considered further

here as the focus is on low carbon hydrogen.

At ambient temperature, hydrogen exists in its gaseous state, and so most hydrogen

is stored as a compressed gas within large tanks and underground caverns. Hydrogen

can also be stored as a compressed gas within distribution and transmission pipelines

(known as “line pack”). In its liquid form, hydrogen’s energy density is roughly equal to

that of its gaseous form at 800 bar pressure. However, because of its extremely low

boiling point (-252.9 °C) and critical point (-239.9 °C and 1.28 MPa [93]), storing

hydrogen as a liquid requires a cryogenic cooling process, and so liquid storage of

pure hydrogen is not used at large scales.

6.1 Cavern Storage

The most economically attractive option to store large quantities of hydrogen is cavern

storage, whereby the hydrogen is stored in large underground caverns at high

pressure. Caverns are already used on a very large scale for natural gas storage, and

it was estimated that in 2018 there was 417 bcm of underground natural gas storage

comprising around 700 facilities, 74% of which was gas field storage, the rest being

aquifer storage (11%), salt cavern storage (9%), and oil field storage (6%) [94].

Salt caverns are often seen as the most suitable underground storage medium for

hydrogen, for a number of reasons. Unlike gas/oil fields and aquifers, salt caverns can

be mined from the surface, are capable of high injection and withdrawal rates, have

relatively low cushion gas requirements [95], and do not have issues with bacterial

growth, which has been identified as the most serious issue facing storage of hydrogen

in porous underground reservoirs [96]. Also, rock salt has low permeability and is inert

to hydrogen. Salt caverns have been used for many years to store a range of gases

including natural gas, compressed air, and hydrogen.

24

Globally there was 36 bcm (billion cubic metres, i.e. 109 m3) of salt cavern storage in

2018. There are six operational salt cavern storage facilities in the UK comprising

around 1.1 bcm of working gas volume, with a further four facilities in the planning

stage [94]. One of these, the Gateway Gas Storage Project under the Irish Sea, would

roughly double the UK’s salt cavern storage volume. Depending upon the storage

capacity required and the local geology, salt caverns are typically on the order of

hundreds of metres tall, tens of metres wide, located 400-3,000 m below ground and

store at pressures of tens or hundreds of bar [97]. Generally, operating pressures are

higher in deeper caverns, as the surrounding lithostatic pressure increases with depth;

typical maximum operating pressure ranges from 0.019 MPa to 0.021 MPa per metre

in depth of overburden [98].

Salt caverns are solution mined by drilling a well into the salt then injecting high

pressure water, into which the salt dissolves to form saturated brine. Gas is then

injected into the cavity in order to return the brine to the surface. A blanket of an inert

gas such as nitrogen is used to control the shape of the cavern during its creation.

Compared with hard rock mining, solution mining is straightforward and low cost, with

no requirements for sinking an access mine shaft, underground tunnelling work, or

cladding of the cavity, and relatively low equipment and labour requirements.

Disposal of the waste brine can be an issue, with brine produced with a volume equal

to approximately eight or nine times the storage volume [97, 98]. As a result, coastal

sites may be preferable as the brine can be pumped into the sea. The brine may also

be used in a brine pond (or “shuttle pond”) for pressure balancing in the cavern during

its operation, ensuring that the gas pressure remains roughly constant over all levels

of fill. Solution mining of a large underground storage cavern can take several years,

however the cavern can then be operated for many decades with minimal

maintenance. At large scales, storage of gas in salt caverns is one of the lowest cost

energy storage technologies in existence [13].

In recent years, salt cavern storage has been the subject of considerable interest as

a result of its potential to store compressed air within compressed air energy storage

(CAES) systems, effectively a large-scale electricity storage technology. To date, two

commercial CAES plants have been constructed at Huntorf, Germany [99] and

McIntosh, AL, USA [100], opening in 1978 and 1991 respectively. Both of these plants

store the compressed air in salt caverns and burn natural gas in the expansion stage.

Subsequent deployment of CAES has largely been held back by market conditions

and the desire to move away from natural gas combustion, however several plants

have been proposed in recent years, typically including thermal energy storage to

avoid burning natural gas, in what is known as adiabatic CAES.

Recently, a system combining CAES with electrolysis has been proposed, whereby

the heat of compression is used to produce hydrogen with high temperature steam

electrolysis [101]. Analysis of this system determined a round-trip exergy efficiency of

35.6%, lower than that of adiabatic CAES (69.5%) and conventional CAES (54.3%),

25

but slightly higher than that of low temperature electrolysis (34.2%). It was found that

CAES with high temperature electrolysis has the highest energy storage density (7.9

kWh per m3 of air storage volume), followed by adiabatic CAES (5.2 kWh/m3) and

conventional CAES and CAES with low temperature electrolysis (both around 3.1

kWh/m3).

Salt deposits are found reasonably close to the surface in many parts of the Earth. In

the UK, Permian salt deposits are situated underneath East Yorkshire and Teesside

and out underneath the North Sea, and Triassic salt deposits are situated underneath

parts of Cheshire, the West Midlands, the south-west of England, and Northern Ireland

[102]. Solution mining has been used for many years in Cheshire to produce salt and

brine, and salt cavern storage of natural gas is used at large scales in East Yorkshire,

Teesside, and Cheshire. An analysis of the UK’s potential salt cavern storage capacity

by researchers at the British Geological Survey, accounting for a buffer zone around

settlements and infrastructure such as roads and railways, found that in the Cheshire

Basin alone there could be up to 166 bcm of working gas volume (at standard

conditions) in the 500-1500m depth range [103]. An extension of this work showed the

UK’s salt cavern storage potential to be around 42 bcm of usable cavern volume, and

that if 1% of this were used for CAES, the total energy storage capacity would be

around 8 TWh [104]. Since the energy density of hydrogen is over 20 times that of

compressed air at similar pressures [105], using 1% of the UK’s salt cavern storage

capacity for hydrogen would give a hydrogen energy storage capacity of over 160

TWh.

There are four existing salt cavern hydrogen storage facilities in the world, with one

facility in Teesside, UK, and three larger facilities in Texas, USA [13]. Details of these

are given in Table 4. The facility at Teesside comprises three caverns connected to a

brine pond. The facilities in Texas do not use brine ponds, and instead must maintain

gas pressure above a minimum level at all times, to ensure that the cavern’s structural

integrity is maintained. The volume of gas in the cavern at the minimum pressure is

known as the cushion gas and the additional gas that can be added until the maximum

pressure is reached is known as the working gas.

26

Teesside (UK) Clemens Dome, Texas (USA)

Moss Bluff, Texas (USA)

Spindletop, Texas (USA)

Salt formation Bedded salt Salt dome Salt dome Salt dome

Operator Sabic Petrochem.

Chevron Phillips Chemical Comp.

Praxair Air Liquid

Commissioned 1972 1986 2007 Not known

Geometrical volume (m3)

210,000 580,000 566,000 906,000

Mean depth (m)

365 1,000 1,200 1,340

Pressure range (bar)

45 70-137 55-152 68-202

Net energy stored (GWh)

27 81 123 274

Amount of H2 (t)

810 2,400 3,690 8,230

Net volume (m3, std)

9.12 x 106 27.3 x 106 41.5 x 106 92.6 x106

Table 4 Metrics of hydrogen caverns in the USA and UK [13].

The H21 Leeds City Gate project, mentioned previously, proposes to convert the gas

network in the city of Leeds, UK, from carrying natural gas to carrying hydrogen. The

initial analysis in this project has determined that there should be 702,720 MWhHHV of

inter-seasonal hydrogen storage (40 days of average daily demand), which is

expected to be caverns operating at pressures of around 200 bar, and 3,892 MWhHHV

of additional intraday storage, expected to be shallower caverns operating at 20-60

bar pressure. Together with the 1,024 MW of SMRs, these should be capable of

supplying a maximum day demand of 2,067 MW and a 1 in 20 year peak hour demand

of 3,180 MW [3].

It is expected that hydrogen caverns of the same type and energy content will be

approximately three times more expensive than natural gas caverns, because of the

lower volumetric energy density of hydrogen [93].

Another option for underground storage of hydrogen is hard rock caverns. In the UK,

Phillips 66 and Calor Gas have operated a liquefied petroleum gas (LPG) storage

facility at Killingholme in North Lincolnshire since 1985 [106, 107]. This acts as inter-

seasonal storage, allowing a roughly constant rate of LPG production over the year

27

while meeting demand which varies between summer and winter. The underground

storage comprises two chalk caverns holding up to 60,000 tonnes of LPG. Lining of

rock caverns is also an option, and a steel-lined rock cavern has been operated at

Skallen, Sweden, since 2004 [95, 108]. Used to store natural gas, this has a height of

52m, diameter of 36m, and a volume of 40,000 m3. The top of the cavern is at a depth

of 115m, and it has a maximum storage pressure of 200 bar. The rock formation

carries the main structural load, while the steel liner acts as a barrier.

6.2 Tank Storage

One of the major downsides of cavern storage is that it requires suitable geology. In

areas where cavern storage is not possible, tank storage is an option. Per unit of

storage capacity, tank storage has higher investment costs than cavern storage,

however it has the advantage that it can be located anywhere. It also ensures that

hydrogen purity is maintained (more of an issue for oil/gas fields and aquifers than for

salt caverns). Maintenance and inspection of aboveground storage is much more

straightforward than for underground storage.

Three types of vessels are used for storage of large amounts of natural gas [95, 109]:

Gas holders, also known as gasometers, with storage pressures slightly above

atmospheric pressure.

Spherical pressure vessels, with maximum storage pressures up to

approximately 20 bar.

Pipe storage, with maximum storage pressures of approximately 100 bar.

Of particular note is pipe storage, since this can be provided by simply operating

existing gas transmission and distribution pipelines at a range of pressures. This is

also known as “linepack”; literally the amount of gas packed into transmission and

distribution pipelines. Linepack is already used on a large scale in the UK to ensure

security of supply of natural gas, with Great Britain’s gas transmission and distribution

networks currently having at least 690 GWh of within-day natural gas linepack

flexibility [110]. Hydrogen has roughly a third of the calorific value of methane, so

depending upon flow rate and pressure, conversion of the gas grid to hydrogen would

result in the loss of at least two-thirds, and possibly over three-quarters, of the linepack

[111]. This could be replaced with additional intraday stores, such as salt caverns or

gas holders [3]. Another option to reduce the loss of linepack would be to operate the

networks at higher pressures, however this could present problems with pipeline

integrity, compressor capacity, and end user compatibility [112, 113].

As mentioned above, hydrogen embrittlement must be taken into account when

considering storage of hydrogen in metal vessels. Many of the UK’s low pressure

distribution pipes are being replaced with polyethylene pipes as part of the Iron Mains

Replacement Program (IMRP), to reduce leakage [114]. Polyethylene does not suffer

the same hydrogen embrittlement issues as iron, so when the IMRP is complete in

2032, much of the low pressure gas network could be used for hydrogen transportation

28

and linepack. It has been recommended that the IMRP is redesigned so that as much

of the network is hydrogen-ready as possible [115].

29

7 Greenhouse Gas Emissions from Hydrogen

One of the main drivers for using hydrogen for heating and transport is that it is low

carbon, however this claim must be carefully considered. No greenhouse gases,

particulates, sulphur oxides or ground level ozone are produced from the use of

hydrogen. However, emissions can arise from the production and transport processes.

As was noted in Section 2, technologies such as methane reforming and coal

gasification split the hydrogen and carbon in a hydrocarbon, resulting in a waste

stream which includes CO2. To make hydrogen a low carbon energy vector, it is

necessary to capture the CO2 from the waste stream and sequester it in underground

storage.

Figure 2 shows estimates of total GHG emissions from hydrogen production, as found

in a study by academics at Imperial College London [116]. Clearly estimates of GHG

emissions vary widely, ranging from -370-642 gCO2eq/kWh H2. Global hydrogen

production in 2018 was estimated by the IEA to be 69 Mt H2/yr, causing CO2 emissions

of 830 Mt CO2/yr [2]. This gives global hydrogen production an average carbon

intensity of 360 g CO2/kWh H21. It can be seen in Figure 2 that this is very close to the

average greenhouse gas emissions intensity of natural gas SMR without CCS. Recent

estimates of the CO2 emissions associated with SMR are given in Table 5, as collected

by E4tech in 2018 [117].

Figure 2 Ranges of estimates of total greenhouse gas emissions associated with hydrogen production from different technologies and

feedstocks, expressed in gCO2eq/kWh hydrogen produced [116]. Notes: NG = natural gas, ATR = Autothermal Reforming, SMR = Steam Methane Reformer,

CCS = Carbon Capture and Storage.

1 Assuming hydrogen has an energy per unit mass (lower heating value) of 120.1 MJ/kg.

30

Study Reference Origin of Data Notes CO2 Emissions (g/kWh H2)

Miller (2017) [118] CA-GREET Centralised 325

Distributed 315

Spath and Mann (2001) [119]

Literature Point emissions from H2 plant only

226

Young et al. (2017) [120]

Operating SMRs in US

Point emissions from H2 plant only

201

Alhamdani (2017) [121]

Bottom-up analysis

Point emissions from H2 plant only

226

Susmozas et al. (2013) [122]

Aspen-plus sim. Point emissions from H2 plant only

215

Ramsden et al. (2013) [123]

Literature Excludes construction of equipment, includes inputs to plant e.g. electricity

296

Edwards et al. (2014) [124]

Literature Excludes construction of equipment, includes inputs to plant e.g. electricity

220

Table 5 CO2 emissions from unabated SMR production of gaseous hydrogen as collected by E4tech in 2018 [117].

Recent analysis at Imperial College London considered the likely costs of three heat

decarbonisation pathways for the UK, namely all-electric, all-hydrogen, and a hybrid

of electric and hydrogen [125]. The cost performance of the pathways for three

different levels of annual CO2 emissions is shown in merit order in Table 6. At all levels

of emissions it was found that the hybrid pathway has the lowest cost, followed by all-

electric and then all-hydrogen. The difference in the cost of the pathways becomes

particularly marked if emissions are to be reduced to zero.

Pathways Cost (£bn/year)

30 MtCO2/yr 10 MtCO2/yr 0 MtCO2/yr

Hybrid 81.6 84.8 88.0

Electric 87.8 89.5 92.2

Hydrogen 89.6 90.2 121.7

Table 6 Cost performance of decarbonisation pathways [125].

31

8 Energy System Integration of Hydrogen in the UK

8.1 Questions and Challenges

Hydrogen is of course not naturally available, and must be manufactured drawing on

one of the primary energy sources (fossil fuel, renewable power and nuclear power).

Scale application of hydrogen as an energy vector will require an extensive expansion

of the UK’s current hydrogen production facilities. Simply replacing the use of natural

gas for domestic heating in Britain would could necessitate nearly a ten-fold increase

in production volumes [126], over the current 0.74 million tonnes. This expansion, in

turn, will have major implications for demand for the primary energy sources from

which hydrogen is made.

Most studies agree that hydrogen will initially be made via methane reforming (MR),

as this is currently the best developed and most economic technology for large scale

production. This approach may well be justifiable to ‘kick-start’ a transition to hydrogen,

but is not sustainable in the long term, as overall GHG emissions per unit of energy

service delivered may in many cases be higher than direct use of the primary source.

Implementing carbon capture and storage (CCS) in conjunction with, say, fossil-fuel

driven steam methane reforming (SMR) can go a long way to reducing GHG impacts,

but brings its own set of problems. Firstly CCS is far from a well proven technology at

scale, and is unlikely to available in the near future. Secondly natural gas supplies are

finite, even taking the emergence of shale into account.

In the longer term, water electrolysis driven by renewably produced electricity but this

in turn brings its own challenges. The gas network currently provides approximately

twice the energy that is transmitted through the electricity system [127], so simply

generating the required electricity would be extremely challenging. If hydrogen is to be

the instrument of decarbonisation, this electricity must be sourced from low carbon

sources which only makes the challenge more difficult.

This report has already identified hydrogen offers potential in the difficult to

decarbonise energy sectors of transport, domestic heating and industrial combustion.

These are likely to be the first areas of deployment, but a further question is how far

should any hydrogen system extend? There are many further potential applications

for hydrogen, such as local electricity production via fuel cells. Exploring this potential

is important, as most energy systems exhibit clear economies of scale. If that is true

here then more widely hydrogen is deployed, the lower end user costs are likely to be.

However other vectors may well be better suited to particular applications and offer

better economics in those cases.

8.2 Quantities of Hydrogen Required for Applications

A simple analysis based on high level government data can indicate the scale of the

challenge of transitioning to hydrogen for complete decarbonisation of selected

32

sectors. In the following indicative calculations we have made the following

assumptions:

Final end use demand for hydrogen will be the same as for that of the replaced

fuel, as reported in Energy Consumption in the UK 2019 [128]

End use conversion efficiencies (i.e. fuel supplied to service delivered) are the

similar for hydrogen as for the fossil fuel replaced

The calorific value of hydrogen at taken as the HHV (141.88 MJ/kg) and

similarly the calorific for natural gas is taken as 52 MJ/kg

Self-consumption of the hydrogen supply systems is ignored, together with any

losses during transmission

Time fluctuations, and the implications for production capacity (or storage),

have been neglected except where described.

In the light of these assumptions, the calculated values represent lower bounds on the

quantity of hydrogen infrastructure required.

Current Energy Demands

Table 7 indicates the total fossil supplied UK final annual energy demand across the

three key difficult to decarbonise sectors. For the domestic sector, all fossil derived

heat demand is accounted for including coal, oil and natural gas, the latter of which is

by far the largest. The values for the transport sector consider only road vehicles and

commercially operated tail vehicles fuelled by petroleum, with coal, electricity, biofuels

omitted. For the purposes of this indicative analysis shipping and aviation have been

excluded. In the industrial sector all demands currently supplied by natural gas, coal

or oil have been included but no others.

Sector Final End Use Fossil Demand

TWh Percent

Domestic 351 37

Land Transport 465 49

Industry 124 13

Total 940 100

Table 7 Final end use fossil energy demands across three sectors for 2018.

Indication of Future Hydrogen Production Capabilities

Table 8 illustrates the quantities of hydrogen required to meet the demands shown in

Table 7. These have been calculated using the assumptions outlined at the beginning

of this section, assuming the hydrogen completely replaces fossil fuels.

33

Sector Annual Hydrogen (Gg)

Domestic 8,913

Land Transport 11,791

Industry 3,139

Total 23,843

Table 8 Annual end user demand for hydrogen by sector.

The scale of the hydrogen production infrastructure necessary, and associated

CAPEX is set out in Table 9. The data assumes that either electrolysis, or steam

methane reforming is used to meet the entirety of the demand. In practice of course a

mixture of the sources would be employed, but investigating the details of this is

beyond the scope of this short report. Most of the key performance data utilised for the

calculations is taken from a study carried out by E4Tech for the Committee on Climate

Change [129], and is shown in Table 10. Maximum individual plant capacities

represent the largest plant planned for the near future as identified from a review of

recent announcements [130, 131].

Parameter SMR Electrolysis

No of Plant 202 22,500

Total CAPEX (£ Billions)

72 266

Table 9 Required hydrogen production infrastructure.

In establishing the total installed capacity, and hence the number of plant, required,

some rudimentary account has been taken of peaking considerations, but without any

explicit treatment of storage capacity. We have followed an approach adopted by

some analysis for the H21 Leeds City Gate (Sadler et al, 2017) project, which identified

that a peaking capacity factor of 1.4 would be appropriate, where the peaking capacity

factor 𝑐𝑓 is defined as:

𝑐𝑓 =𝐶𝑝𝑒𝑎𝑘

𝐶𝑎𝑣𝑒𝑟𝑎𝑔𝑒

with 𝐶𝑝𝑒𝑎𝑘 being the plant capacity necessary to meet peak demands, while 𝐶𝑎𝑣𝑒𝑟𝑎𝑔𝑒

is the plant capacity required assuming constant equal demand over the entire year.

This methodology has been used to evaluate the plant capacity for domestic and

industrial demands, where it is likely that demand patterns will follow existing trends.

It is more challenging to predict trends in the transport sector, where for example there

may be significant local storage at hydrogen filling stations, and thus for this sector

only a peaking capacity factor of 1 was assumed.

34

Electrolysis SMR

Efficiency 47 KWh(elec in) / kg H2

80% Energy (H2) / Energy (Nat Gas)

Availability 0.98 0.9

CAPEX 468 £/kW(elec in) 445 £/kW(H2)

Plant Size 148 kg(H2)/hour 18023.6 kg(H2)/hour

Table 10 Key plant parameters.

8.3 Interactions with Other Energy Vectors and Resources

Irrespective of the technique used to manufacture hydrogen, significant primary

energy resources will be drawn on to power the conversion process. In both cases

there will also be a demand for water. This section builds on the analysis to indicate

the implications for resources arising from conversion of the three sectors entirely to

hydrogen. The assumptions of the previous analysis remain true here, meaning again

that we are producing lower-bound estimates. In view of the intentions of this analysis

the electrical demand of SMR has been neglected, although it will be non-trivial.

Similarly there will be non-trivial water consumption by SMR but this has been

neglected here. The water consumed by electrolysis has been calculated assuming a

minimalistic stoichiometric relationship although there is some evidence that practical

levels may be nearly twice this.

Electrolysis SMR Units

Annual electricity consumption

1121 - TWh

Peak electrical power 311 - GW

Annual Nat Gas Consumption

0 1175 TWh

Peak Nat Gas consumption 0 344,459 m3/day

Annual water consumption 214,587,000 - m3 water

Table 11 Resource demands.

Our results are shown in Table 11, with a hyphen indicating a value that has not been

calculated. Comparing these results with the UK’s current supply statistics will indicate

the degree of challenge associated with the large scale deployment of hydrogen.

One thing that really stands out is the impact that large scale electrolysis would have

on the electricity supply system. Current installed generating capacity is approximately

106 GW [132] meaning that a four-fold increase would be required to power both a

new fleet of electrolysers and existing demands. This new capacity would all have to

be low carbon, and given that only approximately 50% of current capacity falls in to

this category, an extremely challenging 4.8 fold increase in this type of generation

would be essential. These latter values of course represent the estimated peak draw,

which it might be possible to ameliorate through storage located in the electricity

and/or the hydrogen systems. Nevertheless the annual electrolysis consumption of

35

1121 TWh is approximately 2.6 times the total UK electricity consumption of 332.9

TWh in 2018. Meeting these demands will require a transformation of the electrical

supply system.

The estimated water consumption for electrolysis is approximately 214 million cubic

metres per year, which can be compared to the UK’s total annual consumption of 840

million cubic metres [133]. Superficially this appears to be less challenging than the

electrical demands, however this lower bound must be interpreted with the context

that UK water demand increases annually, and there are concerns about the long-

term security of supply as the climate begins to change.

Turning to SMR, the challenges, although still significant, appear less formidable. The

problem is also eased by the fact that the produced hydrogen will replace a large

portion of current natural gas demand, although this effect has not been considered

here. SMR annually will draw 1175 TWh of natural gas, which compares fairly

favourably with 2018 consumption of 874 TWh, and the 2004 record high of 1125 TWh.

While a peak natural gas consumption rate has been calculated, this is of much less

importance than for electricity thanks to significant explicit and implicit storage (e.g.

line packing) in the gas network.

Taken as whole, these simplistic results demonstrate that it will be much less

challenging to build an initial large scale hydrogen system using SMR technology

rather than electrolysis. However in the longer term there will have to be a relatively

rapid transition to electrolysis, or other low-GHG technologies, as gas reserves are

depleted and if long-term GHG reduction objectives are to be met.

8.4 Managing the Transition

Short Term

Short term challenges in introducing significant hydrogen are centred around

developing initial schemes from which a wider network can develop, and over-coming

uncertainties many stakeholders have about the future role of hydrogen. Both of these

are essential to build experience and confidence so that stakeholders become willing

to make increasingly large investments in deploying hydrogen technologies.

Industrial co-location and ecosystem

Hydrogen is already used in many process industries, so a proposed first step is to

build a small hydrogen ecosystem geographically centred on a hydrogen

producing/consuming industrial plant, thereby providing a stand-alone local market

[134]. An obvious opportunity is for industrial neighbours to share hydrogen production

facilities via a limited pipeline network, but a carefully thought through scheme could

also provide hydrogen to near-by domestic consumers and filling stations for vehicles.

The latter would have limited commercial value, as hydrogen vehicles would only be

able to travel to destinations from which they could return to the local filling stations,

however this would allow scope for local fleet operators (e.g. bus, local delivery and

civic fleets) to adopt hydrogen, and there is plenty of appetite for this (e.g. [135, 136]).

36

With respect to localised domestic adoption, several public trials are proposed in the

UK over the next two years [137] which would be facilitated by integration with a local

hydrogen ecosystem.

Metropolitan conversion

A logical step up from local clustering would be a metropolitan scale conversion. The

Leeds City Gate H21 project [3] has formulated a credible, detailed strategy for

decarbonising Leeds’s gas network using hydrogen. Follow-up studies have

developed more ambitious proposals for expanding hydrogen more broadly, reaching

3.7 million properties covering a swathe of the North of England [138] from Liverpool

to Newcastle. This proposed network would be driven by a 12.5GW SMR facility with

CCS, coupled with storage in salt caverns to ensure peak demands could be met. The

study estimates that the conversion would cost £22.7bn, and avoid 12.5 million tonnes

of CO2(e) emissions annually.

100% vs blending

A major debate in the hydrogen transition is whether to make (a) phased,

geographically-limited, switches from natural gas to pure hydrogen, as with the H21

proposals, or (b) adopt a blending strategy of gradually introducing an increasing

proportion of hydrogen into the existing natural gas networks. There are of course

advantages and disadvantages to both strategies.

A blending approach avoids the ‘shock’ of a complete conversion, as much existing

combustion equipment designed for methane can operate with a low proportion of

hydrogen in the supply [139]. The proportion of hydrogen can potentially reach 28%

without causing problems for some domestic equipment, although many industrial

processes are likely to be less tolerant, particularly gas turbines. There is therefore

potential for a limited ‘quick-win’ by introducing smaller proportions of hydrogen into

the existing gas network. Blending is not a long-term solution therefore, as it merely

defers the ‘step change’ in end user equipment that will be eventually required for a

move to 100% hydrogen.

The Wobbe Index (WI) is one important indicator of the interchangeability of fuel gases

in combustion equipment: if two fuels have identical WI values then for a given supply

pressure and valve setting, they will deliver the same rate of energy output. As it turns

out, both pure hydrogen and methane have similar WIs and hence in principle it should

be possible to design a burner that can operate on either of the two gases

interchangeably, with minimal (if any) reconfiguration. This potentially allows some

staging of the introduction of new hydrogen compatible equipment in the domestic

sector at least. Work to design dual-fuel compatible equipment [140] is already

underway, and if successful, regulation could mandate that all future new installations

on this existing methane network should be of this type. A future switch to 100%

hydrogen could then take place without the need for wholescale equipment

replacement in the domestic sector at least.

37

Studies indicate that it is not possible to design a dual fuel burner that will also run well

on a H2/CH4 blend with a high proportion of hydrogen. Unfortunately therefore, this

solution cannot be employed in parallel with a transitory blending approach, which

would otherwise seem to offer an ideal way forward.

A number of technologies for the downstream extraction of good quality hydrogen from

H2/Methane mixes (de-blending) have been explored, including Pressure Swing

Absorption (PSA), Membrane Separation, and Electrochemical Hydrogen Separation.

These could facilitate a strategy that starts with a low-proportion H2 blended approach

to move to 100% hydrogen, with individual localities being converted on a gradual

basis using hydrogen extracted from the gas network. However de-blending plant

would represent an additional investment with a relatively short commercial lifetime,

and may not represent a financially attractive proposition.

Long Term

This section has set out some of the broad whole system technical challenges in

introducing hydrogen at scale into the UK energy system. There remain many techno-

policy questions as to the specific objectives for introducing hydrogen, beyond

facilitating decarbonisation, such as

Which demands, and what proportion of them, should be met by hydrogen?

Over what timescales should hydrogen be introduced?

How should other parts of the energy system be developed to complement the

introduction of hydrogen?

In this final section we will briefly review two UK studies that provide some insight into

these points.

National Grid, in their 2019 Future Energy Scenarios document [141], highlighting the

need for whole systems decision making, examine four scenarios. Of these, the ‘two

degree scenario’ sees the highest growth in hydrogen by 2050, with one-third of UK

homes relying on the fuel for heating, along with 1m vehicles powered by hydrogen or

natural gas. The vast majority of the hydrogen is produced by SMR with CCS, and is

coincident with a 50% increase in electricity demand, but a 30% reduction in methane

demand.

The ‘steady progression’ scenario sees a lower potential, with hydrogen introduced

via widespread methane blending, such that less than 20% of domestic properties

have a low-carbon heating solution in 2050. The production technology is again SMR

with CCS, though demands are much reduced in part because electrification emerges

as the decarbonisation solution for transport. The remaining two scenarios

(‘community renewables’ and ‘consumer evolution’) see almost no role for

hydrogen relying predominately on electrification approaches.

A 2015 study for the Committee on Climate Change [129], led by E4Tech, analyses

two hydrogen scenarios. The ‘critical path’ scenario concentrates on keeping open

the option to use hydrogen in certain key end-use sectors, specifically those that

appear hard to decarbonise by other means. Results see a steady growth in hydrogen

38

production from around 2020, reaching approximately 140 TWh per year by 2050. The

majority of this hydrogen is manufactured using large scale SMR+CCS, with an about

an additional 10% from electrolysis and almost negligible quantities from small-scale

SMR and from Biomass with CCS.

The ‘full contribution’ scenario represents a much more bullish approach to the

uptake of hydrogen across the whole economy. There is strong government and cross-

sector commitment, facilitating strategic anticipatory infrastructure investments such

that supply leads demand. The scenario is characterised by an early policy decision

to decarbonise UK heat provision with hydrogen, which then provides some of

infrastructure required to introduce Fuel Cell Electric Vehicles in the transport sector.

With these assumption, significant growth in H2 demand begins in 2025, growing

steadily to nearly 900 TWh per year in 2050. Almost all of the required hydrogen is

manufactured using large scale SMR+CCS, with a small proportion from electrolysis

and a negligible amount from small scale SMR.

39

9 Conclusions

Recent interest in hydrogen has been largely driven by its potential as a low carbon

energy vector for heating and transport. It is of particular interest in areas which

currently rely on natural gas for heating, allowing the gas network infrastructure to

continue to be used to transport hydrogen, and for large vehicles and transport

applications where rapid refuelling is required.

The lowest cost low carbon hydrogen production method is currently steam methane

reforming with carbon capture and storage, though it is expected that autothermal

reforming may become a lower cost option in future. However, these two technologies

require the use of natural gas, which is a finite resource, and they require carbon

capture to be low carbon, which does not have 100% effectiveness. Unless carbon

capture rates increase in future, it is possible that the UK may not be able to meet its

2050 net zero emissions target if it relies on natural gas reforming. In this case, water

electrolysis would need to be used, however the required levels of electricity

generation and water would be substantial. Therefore carbon capture rates must be

increased if gas reforming is to be a viable long-term option for a net zero future.

Hydrogen can be transported using a number of methods, including pipelines, trucks,

rail and ships. Pipeline transport is the most efficient method, however a number of

challenges surrounding leakage and embrittlement must be overcome. In transmission

and distribution networks, polyethylene pipes can be used to deal with the

embrittlement problems affecting metals, and the UK is currently replacing its iron

pipes with polyethylene pipes within the Iron Mains Replacement Programme. In terms

of truck transport, gaseous truck transport has lower costs and energy requirements

than liquid truck transport on a per unit energy basis, even accounting for the higher

energy density of liquid hydrogen.

Storage of hydrogen can largely build on natural gas storage technologies, and the

lowest cost bulk hydrogen storage technology is salt cavern storage. In the UK, salt

caverns are already used for natural gas storage on a large scale, and it is expected

that salt caverns would be used for inter-seasonal hydrogen storage. Because of

hydrogen’s lower volumetric energy density than natural gas at the same pressure,

replacing natural gas with hydrogen in the gas network would lead to a loss of

approximately 75% of the intraday linepack storage capacity, which would need to be

replaced. Either salt cavern storage or tank-based storage would be used for intra-day

storage, with tank-based storage having a higher cost but no geological limitations.

There remain a number of outstanding challenges surrounding a transition to a future

where hydrogen is used for low carbon heating and transport. While there are

technological challenges, such as how to economically provide the CO2 capture rates

that would be required for a net zero future, there are also significant challenges

around policy and how to develop schemes that may lead to a future where whole

cities are converted to hydrogen while minimising costs and disruption.

40

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