# Great Britain’s Hydrogen Infrastructure Development – Investment Roadmap and
its Flexibility

Tatyana Dergunova  Andrew Lyden<EMAIL_ADDRESS>
###### Abstract

Future pathways for Great Britain’s energy system decarbonization have
highlighted the importance of low-carbon hydrogen as an energy carrier and
demand flexibility support. However, the potential application within various
sectors (heating, industry, transport) and production capacity through
different technologies (methane reformation with carbon capture, biomass
gasification, electrolysis) is highly varying, introducing substantial
uncertainties for energy infrastructure development bottlenecking hydrogen
economy growth. This study addresses limitations of previous research by
providing comprehensive modelling of the entire hydrogen system of Great
Britain based on three Net Zero scenarios set out by National Grid utilizing
open-source software. The analysis outcome recommends prioritizing the
establishment of green hydrogen hubs aligning with future synthetic fuels
production, where hydrogen will act as feedstock, unlocking roadmap for up to
10GW (95TW/h) of production capacity. Additionally, low-carbon hydrogen
production for industry and power decarbonization shall follow localised
approach at early development stages to increase future decisions flexibility.

###### keywords:

Green hydrogen , Low-carbon hydrogen , Energy infrastructure , Decarbonization
pathways , Synthetic fuels , Open-source modelling

††journal: INTERNATIONAL JOURNAL OF HYDROGEN ENERGY

[label1]organization=School of Engineering, Institute for Energy Systems,
University of Edinburgh, addressline=Colin Maclaurin Road, city=Edinburg,
postcode=EH9 3DW, country=UK

Low-carbon hydrogen in Great Britain’s future energy system

Decarbonization strategies for ‘no-regret’ decisions

Open-source hydrogen network modelling

##  1 Introduction

Hydrogen is recognized globally as one of the important constitutes of energy
system decarbonization due to its ability to cover periods where renewable
energy sources cannot provide required flexibility to meet demands or
decarbonization cannot be achieved with direct electrification [1]. The 2022
global energy crisis increased the interest for low-carbon hydrogen economy
development in multiple countries with the aim not only to reduce the
emissions but also to decouple from fossil fuels dependency and diversify
energy supply mix [2]. Even though Liquefied Natural Gas (LNG) is currently
the primary solution to meet short-term energy security in the European Union
(EU) [3], hydrogen facilities development can be seen in multiple countries
around the world including export and import ports [4] with intend to
diversity energy supply sources in a long-term run.

The United Kingdom’s (UK’s) abundant onshore and offshore wind resources [5]
and proximity to the EU, the leader in hydrogen market development, could
facilitate the realization of the UK government’s hydrogen ambitions, which
includes 10GW of low-carbon hydrogen production by 2030 to meet local
decarbonization with potential export to continental Europe [6],[7]. However,
current lack of clarity in projections for hydrogen market development holds
back investment decisions which in turn slows down the growth of low-carbon
hydrogen supply chain.

The uncertainties in future local hydrogen market are substantial, with annual
demand forecast ranging from 120TWh per Consumer Transformation scenario to
446TWh per System Transformation scenario in 2050 according to Future Energy
Scenarios (FES) 2023 [8] issued by National Grid. The major driver of hydrogen
consumption difference is residential sector, which is the second largest
energy consumer in the UK after transport sector as of 2021 [9] and may
account for hydrogen consumption between 0TWh and 145TWh in 2050 [10].
Hydrogen application in decarbonization of the industrial sector can take
different directions and be responsible for hydrogen consumption from 11TWh to
88TWh in 2050 [10].

Further, the requirement of hydrogen infrastructure and its economic
feasibility will influence the extent of low-carbon hydrogen adaptation. To
support hydrogen infrastructure development, National Gas (the UK gas system
operator) announced Project Union launch under which about 2,000km of 100%
hydrogen backbone is planned by early 2030s to link production, storage, and
consumption clusters [11]. However, without in depth analysis of all potential
hydrogen adaptation scenarios and economic feasibility, phasing of Project
Union cannot be fully justified.

###  1.1 Key Drivers of Hydrogen Economy in the UK

To support smooth integration of low-carbon hydrogen into energy systems, the
UK government selected ‘twin-track’ approach which supports two major types of
hydrogen production at the early stage of development being: 1) electrolytic
hydrogen production; 2) methane reformation with carbon capture utilization
and storage (CCUS) [6]. At this stage of development, electrolysers have to be
connected directly to renewable energy sources (‘non-networked’ electrolysis)
as the power grid is yet to be decarbonized to introduce ‘networked’
electrolysis as highlighted by [12]. Another type of electrolytic hydrogen
production reviewed by FES-2022 [10] is ‘nuclear’ electrolysis, where more
uncertainties could be seen due to ageing nuclear reactors [13],[14] and
criticism from public on new nuclear power development [15]. Even though the
production side still requires certainties to align with long-term scenarios,
supply chain of any product is primarily dependent on demand; therefore,
hydrogen consumers and infrastructure will play a crucial role in defining the
future scale and pace of low-carbon hydrogen integration into the UK’s energy
system.

####  1.1.1 Demand

Approximately 2.5GW of carbon-intensive hydrogen production capacity is
currently installed in the UK with about two-thirds coming as by-product from
industrial processes (mainly steelworks and refineries) and only one-third
being produced by methane reformation without carbon capture [16]. As of
future market opportunities, the following major sectors are reviewed in FES
scenarios as potential low-carbon hydrogen consumers: 1) heating; 2) industry;
3) power generation; 4) transport; 5) blending (temporary sink to support
hydrogen supply chain development); 6) exports.

_1) Heating: 0-145TWh H 2 in 2050 [10]_

Heating decarbonization has one of the most debatable paths, with extensive
competition between direct electrification (heat pumps) and ‘clean’ gas
(hydrogen boilers). From one hand, the process efficiency of hydrogen boilers
in heating sector is significantly lower than that of heat pumps, accounting
for about 65% and 90% respectively [17]. This fact creates an open debate for
delay in policymaking decision and indirect support of less attractive techno-
economic solution as hydrogen according to [18]. However, [19] highlights
potential constraints of multi-family house (apartment blocks) heating
decarbonization by ground-source heat pumps and economic downsides of air-
source heat pumps which could potentially be used in this application. Another
option for apartment blocks heating is district heating which could be fed by
ground-source heat pumps as summarized by [20], however, techno-economic
feasibility of this option is still to be confirmed. Therefore, heating
decarbonization may still be a mix of hydrogen and electrification.

_2) Industry: 11-88TWh H 2 in 2050 [10]_

The UK industries are concentrated in ‘clusters’ and its decarbonization
strategy was issued in March 2021 by BEIS (Department for Business, Energy &
Industrial Strategy) [21]. Under this strategy a review of potential
decarbonization pathways for each industrial sector is presented. The review
shows that even though hydrogen can be applied in decarbonization of each
industry to a certain extent, the highest potential of hydrogen application is
in clustered sites.

_3) Power Generation: 12-17TWh H 2 in 2050 [10]_

To cover variations in renewable electricity generation, a long-term energy
storage is critical. Different technologies were proposed for energy storage
to cover peak electricity demand and curtailment reduction; however, a single
type of storage cannot provide sufficient system flexibility as indicated by
[22]. According to evaluation by [23] performed for Climate Change Committee
(CCC), power generation sector will be the major hydrogen consumer in the
nearest future with the UK government commitment of electricity grid
decarbonization by 2035 (subject to energy security).

_4) Transport: 83-138TWh H 2 in 2050 [10]_

Transport sector covers road transport, shipping, aviation, and rail. Hydrogen
as fuel is not projected to receive widespread adaptation for light duty
vehicles as per [24], while decarbonization of shipping and aviation is
projected to utilise hydrogen equally in all FES decarbonization scenarios in
2050 accounting for about 70TWh and 10TWh respectively [10]. According to [25]
hydrogen will be used as feedstock for synthetic fuels production for shipping
and aviation industries rather than a fuels in pure form. As for rail sector,
is more likely to proceed with electrification and maximum annual consumption
is predicted to be limited to 2TWh in 2050 [10].

_5) Blending_

One of the short-term solutions for expansions of hydrogen market analysed by
the UK government is hydrogen blending into natural gas networks with up to
20% (by volume), with plans to announce the final decision on this approach in
2023 [6]. Implementation of this strategy may create flexible consumption that
is favourable condition to support low-carbon hydrogen production development
according to [26].

_6) Exports_

At this early stage, the UK exploring opportunities to export hydrogen to
Europe given its long relationships with energy trade and increasing hydrogen
demand [6]. Two potential export interconnectors were identified: 1) Bacton
industrial cluster to Netherlands; 2) South-West border of Scotland to Ireland
[8]. However, the development of low-carbon hydrogen export projects will
depend not only on production capability of the UK but also readiness of the
import countries and economic viability.

####  1.1.2 Infrastructure

The existing gas infrastructure of the UK is not suitable for 100% hydrogen
use and substantial investments will be required in case of decision in its
favour. Project Union [11] is performing a study in which existing pipelines
infrastructure repurpose will be covered along with proposal of new pipelines
construction. One of the limitations for the existing infrastructure repurpose
is transition period where natural gas will still play a significant role and
rely on its historic infrastructure. Alongside with Project Union, feasibility
study for low-carbon hydrogen infrastructure development on a regional level
is also performed being: 1) North-East Network and Industrial Cluster
Development (Operator: SGN) [27]; 2) East-Coast Hydrogen (Operator: NGN,
Cadent) [28]; 3) Capital Hydrogen (Operator: SGN, Cadent) [29]; 4) HyNet North
West Hydrogen Pipeline (Operator: Cadent) [30]. Based on the above ongoing
studies review, it is concluded that early development of hydrogen economy and
phasing selection by specific region will depend not only on resource
availability (renewable energy or natural gas) but also convenience for
hydrogen storage and suitability of infrastructure for CO2 storage in case of
methane reformation with CCUS.

####  1.1.3 Storage

Another obstacle on the way of large-scale hydrogen deployment is storage,
which will be vital to manage the difference in supply and demand patterns.
Evaluation of theoretical capacity of offshore depleted hydrocarbon fields was
done by [31],[32] with potential storage capacity estimated at not less than
2,500TWh considering solely gas reservoirs. Further, study by [33] concluded
that the UK salt caverns can accommodate about 2,000TWh theoretical hydrogen
storage capacity. With maximum hydrogen storage requirement of about 55TWh in
2050 according to ‘System Transformation’ scenario peak [10], the estimated
theoretical capacity of geological storage by far exceeding the requirements.
Even though, the relatively high theoretical storage capacity compared to
requirements could be taken as a positive sign, detailed research on hydrogen
storage in porous media considering biological and geochemical reactions is
still yet to be completed which may cause not only hydrogen contamination but
also losses as emphasized by [34].

###  1.2 Current State of Research

This section reviews the current state of research on hydrogen infrastructure
development in the UK, ranging from initial endeavors to the most recent
studies, with the aim of identifying gaps and promoting further advancements
in this area.

In 2013, an early attempt to model the spatial expansion of hydrogen
infrastructure in the UK within the context of broader energy system
interactions was undertaken by Balta-Ozkan and Baldwin [35]. This study
proposed a geographical infrastructure development plan with ten-year
intervals, spanning from 2020 to 2050. Limitations of this study include:

1) Demand side covers only heating and transport (road and aviation) and
mainly disaggregated based on geographic population density.

2) Scenarios are based on different levels of emission reduction by 2050 with
high reliance on liquid hydrogen import. The scenario with local hydrogen
production does not meet 2050 emission reduction targets.

Further research conducted by [36] in 2017, proposed hydrogen network
development in stages starting from Midlands and expanding across the UK by
2070. Additionally, the study incorporated the development of carbon dioxide
(CO2) pipeline infrastructure from methane reformation to offshore storage.
Limitations of this study include:

1) Hydrogen demand for road transport is covered only (in view of filling
stations).

2) Electrolysis as source of hydrogen production introduced only in 2060.

3) Scenarios are based on discount rate variations (3.5% and 10%).

In 2019, a study conducted by [19] covered crucial elements as electrolysers
location and whether energy transport shall be done via transmission grid or
hydrogen pipelines. This model also accounted for inter-seasonal and daily
demand fluctuations, as well as the intermittent nature of renewable power
generation. Furthermore, it assessed various subsidy levels for upgrading
heating devices within the system optimization framework. Limitations include:

1) Demand side covers consumption by heating only.

2) Hydrogen production from methane reformation, biomass gasification and
nuclear electrolysis is not covered.

3) Various decarbonization scenarios development are not included with heavy
reliance on energy system optimization by software.

One of the most recent studies is performed by [37] under ELEGANCY project.
The project focusing on the transportation and storage of hydrogen and carbon
dioxide from methane reformation process, with the proposal to phase out
investment in hydrogen infrastructure and adjust it based on results of the
first phase outcome. However, based on publicly available information, certain
limitations were identified, including:

1) Demand side covers consumption by heating and transport only.

2) Hydrogen produced mainly by methane reformation with carbon capture
including small share of biomass gasification.

3) Water electrolysis is suggested only to cover peak hydrogen demand in case
if hydrogen storage is not available.

4) Phasing of the development and basis is not provided.

It worth to add, that all the above studies [19],[35],[36] provide a good
basis for further research and developments, however the developed models
could not be found in open access and therefore new studies have to start
modelling from ‘scratch’ investing substantial amount of time for basic data
collection and validation. Even though ELEGANCY project [37] claims to use an
open-source software, the model could not be located in easy access to perform
a critical analysis of the assumptions made.

[38] conducted an extensive study covering the EU and the UK with open-source
model available to public. However, due to large-scale nature of the model, it
provides only a high-level overview of certain critical details, making it
insufficient for making decisions specific to the UK. Furthermore, the model
relies solely on optimization and lacks the flexibility to accommodate various
scenarios that align not only with general system perspectives but also with
individual government targets. In summary, [38] has established a solid
foundation and an openly accessible model that can serve as a basis for
further enhancements for each individual country.

###  1.3 Aim and Contributions

This study aims to provide independent evaluation of Great Britain’s (GB’s)
hydrogen infrastructure development roadmap accounting for flexibility of
future decisions on hydrogen adaptation in various sectors. While policies are
for the UK, this study looking for GB only, as Northern Ireland has a separate
electricity market connected to Republic of Ireland network.

The study performs future GB’s hydrogen system modelling incorporating all
producers and consumers according to FES-2022 scenarios [10] with other
essential inputs sourced from PyPSA-GB [39] \- a future power system model of
GB based on FES. This integration enhances the validity of the model and the
accuracy of the analysis results. The modelling was conducted utilizing
“Python for Power System Analysis” (PyPSA), an open-source energy flow
optimization software [40] providing an opportunity to review and further
improve the modelling.

Furthermore, this study addresses the gaps in the FES-2022 data to improve the
visibility of potential pathways for hydrogen economy development. It also
assesses the sensitivity of the FES-2022 scenarios and highlights potential
minimum and maximum boundaries of hydrogen adaptation in various sectors.

##  2 Methodology

The primary challenge in future energy systems modelling is its heavy
dependence on software-based network optimization, which often introduces
numerous uncertainties and limitations, as emphasized by [41]. In addition,
limited scenarios variety does not represent all potential pathways of energy
systems development making review of the whole system narrowed down to
boundaries set by multiple uncertainties. This section will provide outline of
the methodology utilized in this study, summarizing details of the software
used, scenarios selection, network modeling approach, and assumptions made for
hydrogen supply and demand modelling, while also addressing the study’s
limitations with potential areas for future improvements.

###  2.1 Software

PyPSA-GB-H2 [42] available at https://github.com/tatyanadergunova/PyPSA-
GB-H2.git, covering hydrogen production, consumption, and storage, was built
using open-source tool PyPSA [40]. PyPSA was originally created for modelling
power systems but can also model hydrogen systems. In hydrogen modelling, it
represents hydrogen flows as energy streams and includes components for
hydrogen production, storage, transport, and demand. This allows users to
analyse different energy system scenarios and optimize operation and
investments to minimize costs. The optimization of PyPSA-GB-H2 model will be
run by Gurobi Optimization package [43], which has a limitation being open-
source for academia only.

###  2.2 Scenarios

National Grid annual reports [8] provide potential pathways of GB’s energy
system decarbonization, drawing from ongoing research and development efforts
as well as inputs from various stakeholders. The energy flow estimates from
these reports are available to public and were used as the foundation for
setting hydrogen production and demand capacities in PyPSA-GB-H2 model. Only
FES-2022 workbook data [10] was run in this study and further studies can be
updated utilizing FES-2023 workbook as an input of low-carbon hydrogen
consumption in each scenario [8]. FES reports covering four different
scenarios; however, the scope of this study is limited to evaluation of
‘decarbonization’ scenarios only which are summarized in Table 1.

Table 1: Total hydrogen demand in 2050 (FES-2022) [10] Scenario | Annual Hydrogen Demand in 2050, TWh
---|---
Consumer Transformation | 113
Leading the Way | 244
System Transformation | 431

Early development of hydrogen infrastructure shall account for long-term run
therefore accommodate year 2050, when Net Zero operation is targeted to be
achieved. Once all scenarios evaluated for year 2050, the crossing load
sections on infrastructure can be identified. These sections will be utilized
in future regardless of selected scenario of hydrogen adaption and ‘early’
development of infrastructure around them could be considered as ‘no regret’
decision. Therefore, this study covered year 2050 only.

###  2.3 Network Modelling

The major limitation of FES-2022 scenarios [10] in judgement for hydrogen
infrastructure scale is share of hydrogen supply and demand by regions and
technologies, with 2050 ‘networked’ electrolysis data being the only
exception. The ’networked’ electrolysis is defined as hydrogen production via
water electrolysis with electricity sourced from power grid; therefore, the
location of this producer shall be assigned to a particular region only when
techno-economics of other less flexible hydrogen production technologies,
hydrogen infrastructure and power grid expansion are evaluated.

_Modelled Hydrogen Network (Industrial Cluster Level)_

Figure 2.1: _Industrial clusters and salt caverns plot on GB Distributed
Network Operator (DNO) License Areas map[44]. This Figure is for illustrative
purposes only._

This study introduced geospatial division of hydrogen supply and demand and
identified drivers for flexibility of sectors location on industrial clusters
level. The assumption of industrial cluster level, shown on Figure 2.1, serves
the purpose of this study to identify the ’flexible’ sectors to review minimum
infrastructure requirement. However, higher resolution may be required for
more detailed analysis [Limitation-1].

Hydrogen pipelines between industrial clusters were modelled as energy flows,
disregarding thermodynamic properties and loss of energy associated with
frictional pressure drop. This simplification limits possibility of hydrogen
infrastructure costs evaluation [Limitation-2] which shall include not only
pipelines installation, but also compression stations and operational costs of
electricity demand required for compression which can vary between 0.81-1.1
kWh/kgH2 according to [45]. Furthermore, estimated operating pressure
(average) of salt caverns by [33] is 132-278 barg, what will need additional
compression from hydrogen network operating at 40-80 barg [27],[28] and
therefore capital and operational costs would increase further.

Multiple models including [38], model hydrogen transport as star network.
However, according to hydrogen modelling evaluation performed by [46] star
network are not be representative for actual pipelines loads while tree
network will benefit the study at low computational costs. Therefore, tree
network model was adopted for this study, as shown on Figure 2.1. The network
simulation step of one hour was adopted to cover hourly fluctuations of supply
and demand sides.

###  2.4 Supply

####  2.4.1 Efficiency and Availability

Every energy generation technology, including hydrogen production, has two
major parameters for evaluation of actual output capacity being efficiency and
availability. FES-2022 workbook [10] was reviewed and efficiency and
availability for each hydrogen production technology evaluated which is
summarized in Table 2.

Table 2: Efficiency and availability of hydrogen production technologies (FES-2022) [10] Technology | Availability | Efficiency
---|---|---
Methane Reformation with CCUS | 95% | 74-82%
Biomass Gasification | 90% | 71-78%
’Nuclear’ Electrolysis | 80% | 84-88%
’Non-networked’ Electrolysis | 30% | 84-88%
’Networked’ Electrolysis | 44-50% | 84-88%

_Methane Reformation with CCUS & Biomass Gasification._ Efficiency of hydrogen
production is constant throughout the years but varying in different
scenarios, increasing with higher share of this hydrogen type in total mix.

_’Nuclear’ Electrolysis, ’Non-networked’ Electrolysis & ’Networked’
Electrolysis._ Electrolysis efficiency is increasing through 2030-2050,
assuming wider adaptation and technology maturity increase.

_’Networked’ Electrolysis._ Availability of ‘networked’ electrolysis is
increasing through 2030-2050 assuming increase in flexibility and robustness
of energy supply sources to the power grid. However, it stays steady at 40%
throughout all years in ‘System Transformation’ scenario with high reliance on
hydrogen for heating and high share of methane reformation with CCUS.

####  2.4.2 Geographical Limitations

To account for potential limitations of geographical locations, each
technology dependency on feedstock supply and other requirement were reviewed
with summary presented in Table 3.

Table 3: Geographical limitations of hydrogen production technologies by industrial clusters Technology | Limited to Cluster
---|---
Methane Reformation with CCUS |  | St. Fergus, Grangemouth, Teesside, Humberside, Bacton,
---
Merseyside, Theddlethorpe
Biomass Gasification |  | Bacton, Grain LNG, Southampton,
---
South Wales, Theddlethorpe
’Nuclear’ Electrolysis | Bacton, Grain LNG, South Wales, Merseyside
’Non-networked’ Electrolysis | St. Fergus, Grangemouth, Merseyside
’Networked Electolysis | Proposed location in FES-2022 [10]
Imports | Bacton, Grangemouth

_Methane Reformation with CCUS._ Offshore CO2 storage is assumed at similar
locations as hydrogen storage potential sites investigated by [32]. Therefore,
proximity to depleted oil and gas fields is assumed as beneficial location for
steam reformation with CCUS to reduce CO2 transport infrastructure.

_Biomass Gasification._ Limited to the south part of England and Wales, areas
of higher population density as no major pre-requisites were identified at
this stage.

_’Nuclear’ Electrolysis._ Civilian nuclear fleet of the UK is ageing, and
currently operated nuclear reactors are projected to be decommissioned in
coming years [13],[14]. Therefore, for the purpose of this study potential
location of proposed nuclear power plants was assumed as location of future
‘nuclear’ electrolysis.

_’Non-networked’ Electrolysis._ As PyPSA-GB and PyPSA-GB-H2 will be connected
at a later stage, at this stage potential locations of ‘non-networked’
electrolysis assumed as Scotland and North-West of England [Limitation-3].

_’Networked’ Electrolysis._ The given values in FES-2022 workbook [10]
represent the final installed capacity of ‘networked’ electrolysis by region
and include ‘nuclear’ electrolysis. It is assumed that all indicated capacity
is ‘networked’ electrolysis and generation is split between industrial cluster
based on share for each region. Optimization of ‘networked’ electrolysis
location shall be done in further studies after PyPSA-GB and PyPSA-GB-H2
interconnection [Limitation-3].

_Imports._ Based on Project Union export pipeline interconnections [11]. The
location of potential import points through seaports is excluded from this
study.

###  2.5 Demand

Heating creates substantial seasonal fluctuations and its crutial to model it
dynamically covering not only daily fluctuations but also hourly what will
allow evaluation of peak storage requirement and infrastructure sizing.
Natural gas is still the primary source for heating in the UK, accounting for
74% of households in 2021 according to [47]. Therefore, share of natural gas
consumed by each Local Distribution Zone (LDZ) [48] was split between
industrial clusters obtaining share of total consumption per each cluster.
These shares were further used to calculate annual demand of each cluster
based on total annual hydrogen consumption for heating (residential and
commercial) per FES-2022 workbook [10]. For hourly heat demand fluctuations
hourly ambient temperature fluctuations and type of buildings (single family
house, multifamily house or commercial) were used as an input to produce
annual heat demand per each type of building, see [49] for more details. 2010
temperature profile of the UK was assumed for this study. The proportion of
single ( 80%) and multi-family ( 20%) houses is adopted for 2021 from [50] and
provided as annual heat demand input per buildings type. As output data will
be used to obtain share only, exact heat demand is not considered as critical
and assumed similar to given in [49]. Annual temperature readings were taken
from Renewables Ninja [51].

To estimate energy consumption by industries, daily fluctuations of natural
gas consumption by industries from National Gas transmission data [48] were
used. The obtained share was then divided by 24 hours and multiplied by total
annual energy demand by industry sector from FES-2022 workbook [10]. Further,
all consumption were assigned per industrial clusters adopted for this study.
Even though the roadmap for industrial decarbonization is not defined yet and
may account for some share of electrification, the selected approach is deemed
to be acceptable for this level of study.

For hydrogen power generation hourly output from PyPSA-GB [39] was used and
power plant’s location split between clusters based on geographical proximity.

Share of road transport energy consumption by regions was taken from [52] and
multiplied by total energy consumption from FES-2022 workbook [10]. Hourly
hydrogen consumption assumed to be steady throughout the year considering
buffer storage of liquid hydrogen at consumer side.

For shipping and aviation, hydrogen consumption split among clusters based on
location of airports and major seaports is not accurate as future fuel for
this transportation may not be hydrogen itself but rather its derivatives in
form of synthetic fuels according to [25]. Therefore, hydrogen consumption
shall be related to synthetic fuel production areas which presumably could be
in existing industrial clusters. Based on this, shipping and aviation demand
was combined. Hourly hydrogen consumption assumed to be steady throughout the
year as chemical plants have controlled production and synthetic fuels buffer
storage can be provided for end users demand fluctuation. The same assumption
was adopted for rail as it has relatively low demand compared to other
consumers.

Another demand sector being considered in FES-2022 workbook [10] is blending.
Even though the hydrogen blending into natural gas network is sill pending the
UK government decision, FES-2022 indicate its phase-out by 2043 at the latest,
meaning natural gas network will not be acting as hydrogen sink anymore.
Therefore, this demand type was excluded from this study. This may be added in
future studies where years earlier than 2050 of hydrogen deployment will be
simulated.

FES-2022 does not include exports in demand side [10], therefore supply-demand
balance would not be achieved if exports included in PyPSA-GB-H2 model.
Further, FES-2023 [8] excluded hydrogen exports from all scenarios in
workbook, and there is only a mention of potential hydrogen exports. Based on
above, exports were excluded from PyPSA-GB-H2 model [Limitation-4] and this
shall be addressed in further studies.

Hydrogen consumption by Direct Air Carbon Capture and Storage (DACCS) is
present only in ‘Leading the Way’ scenario of FES-2022 standing at about 25TWh
in 2050 [10]. The purpose of DACCS described in FES reports [8],[17] is to
create a negative emissions source by capturing CO2 from air and storing it at
local storage sites. It is also suggested in FES reports that DACCS shall be
located close to industrial carbon capture and storage infrastructure,
therefore similar approach to location as of methane reformation with CCUS is
adopted.

###  2.6 Storage

Only salt caverns storage was assumed for this study considering potential
contamination and competition with CO2 storage for offshore depleted oil and
gas fields. As highlighted by [34] there is a risk of hydrogen contamination
and biochemical reactions in porous geological media. Further, [53] identified
that CO2 presence in depleted gas fields will cause higher level of hydrogen
conversion to CH4 via methanogenesis. In addition, report issued for CCC on
power system decarbonization [23] assumed only salt caverns and tanks as
hydrogen storage technology. It shall be noted that peak of required hydrogen
storage capacity per FES-2022 workbook [10] is about 55TWh which is by far
smaller than available theoretical storage capacity of the UK salt caverns
estimated by [33] which is summarized in Table 4.

Table 4: Theoretical storage capacity of the UK onshore salt caverns [33] Region | Combined Theoretical Storage of all caverns, TWh
---|---
Cheshire Basin | 129
East Yorkshire | 1465
Wessex Basin | 557

##  3 Results

This section describes PyPSA-GB-H2 modelling results for each scenario and
their comparison with FES-2022 trends. Further, analysis of hydrogen supply-
demand flexibility based on spacial constraints is outlined for each scenario.

###  3.1 Hourly Supply-Demand Trends

Output from PyPSA-GB-H2 for hourly supply-demand trends is presented in Figure
3.1 for each FES-2022 decarbonization scenario.

_(A) - ’Consumer Transformation (B) - ’Leading the Way’ (C) - ’System
Transformation’_

Figure 3.1: _Hourly hydrogen supply and demand by various sectors for three
FES-2022 Net Zero scenarios, year 2050, based on PyPSA-GB-H2 output. Supply-
demand patterns and cluster’s share per methodology of this study._

_’Consumer Transformation.’_ Hydrogen supply in this scenario is predominated
by ‘networked’ electrolysis at about 90% of total production in 2050 followed
by ‘nuclear’ electrolysis at about 7% [10]. Hydrogen production profile by
‘networked’ electrolysis resonates with offshore wind profile, while ‘nuclear’
electrolysis has a steady production. As for demand, it can be observed that
the consumption throughout the year is relatively steady, except of high peaks
in cold season (November-to-March). These sharp peaks are caused by hydrogen
demand for power generation required to cover seasonal gaps in renewable
energy production. Synthetic fuels (shipping and aviation) is the main
consumer in this scenario standing at about 70% in 2050 [10].

_’Leading the Way.’_ The largest share of hydrogen supply in this scenario is
‘networked’ electrolysis accounting for about 50%, followed by ‘non-networked’
electrolysis at about 20% of total annual production in 2050 [10]. ‘Networked’
electrolysis availability was adopted from offshore wind and ‘non-networked’
electrolysis from onshore wind profiles. Fluctuations of hydrogen consumption
throughout the year are more pronounced in this scenario compared to ‘Consumer
Transformation’ as can be seen from Figure 3.1 . This is caused by increased
demand of hydrogen by heating (residential and commercial) and industrial
sectors. Sharp consumption peaks by power generation are also observed in cold
season. Hydrogen demand in this scenario predominated by three sectors:
synthetic fuels production (shipping and aviation) about 30% of total annual
consumption in 2050, followed by heating (residential and commercial) and
industry standing at about 25% and 20% respectively [10].

_’System Transformation.’_ Unlike other FES scenarios, hydrogen supply in
‘System Transformation’ largely come from methane reformation with CCU with
about 50% of total supply in 2050; ‘networked’ electrolysis still plays an
important role with approximately 30% of total supply [10]. In addition,
‘System Transformation’ scenario has the highest fluctuations of demand
throughout the year in comparison to other FES scenarios. This is caused by
higher share of hydrogen for heating (residential) with about 30% of total
annual demand in 2050. Hydrogen consumption for synthetic fuels production
(shipping and aviation) stays the same throughout all scenarios, with hydrogen
to power generation slightly decreasing with total hydrogen consumption
increase, therefore, high peaks becoming less dominant.

###  3.2 Clusters’ Balance and Network Load

Figure 3.2 gives graphical representation of supply-demand spacial flexibility
and Figure 3.3 shows mean hydrogen flows between clusters for each FES
scenario in 2050.

_(A) - ’Consumer Transformation (B) - ’Leading the Way’ (C) - ’System
Transformation’_

Figure 3.2: _FES-2022 scenarios supply-demand geospatial flexibility, year
2050. With increased share of hydrogen adaptation in GB’s energy system demand
side flexibility is dropping bringing the requirement of complex hydrogen
infrastructure. This is mainly caused by dispersed demand of residential
heating and a high developed infrastructure will be required regardless the
increase in supply flexibility.‘Networked’ electrolysis was assigned to
’fixed’ locations as per FES-2022 workbook[10]; however, further evaluation
shall be done upon PyPSA-GB-H2 and PyPSA-GB [39] interconnection._

_‘Consumer Transformation.’_ Even though this scenario has the lowest annual
hydrogen consumption compared to other FES scenarios, hydrogen generation is
not equal to consumption for each cluster. This is mainly related to modelling
limitations in regards of spatial resolution and fixation of future ‘flexible’
demand such as synthetic fuels production. Demand flexibility in this scenario
is governed by synthetic fuels production for shipping and aviation
industries, while methane reformation with CCUS and ‘nuclear’ electrolysis
represent supply flexibility and limited to certain clusters based on
feedstock / additional infrastructure dependency. As for lines loading, a
substantial difference between mean and peak hydrogen flows can be observed in
pipelines connecting clusters and Battery Limits (B/Ls), the points where
hydrogen flow splits to two or more clusters as can be seen on Figure 3.3 .
This is caused by high instantaneous flows of hydrogen to power generation and
model resolution to industrial clusters rather than smaller regions like Grid
Supply Points (GSPs).

_(A) - ’Consumer Transformation (B) - ’Leading the Way’ (C) - ’System
Transformation’_

Figure 3.3: _PyPSA-GB-H2 output for mean and peak hydrogen energy flows
including demand per cluster for three FES-2022 Net Zero scenarios, year
2050._

_’Leading the Way’_ has the medium adaptation of hydrogen, compared to other
FES-2022 scenarios. Figure 3.2 shows the increased difference in supply-demand
balance within one node causing higher hydrogen flows between the clusters.
The higher share of ‘fixed’ supply and demand making ‘Leading the Way’
scenario less flexible compared to ‘Consumer Transformation’. Nonetheless,
strategic location of synthetic fuels production (shipping and aviation) and
DACCS may allow hydrogen infrastructure reduction to regional levels. The
lines loading of ‘Leading the Way’ scenario have similar trends as of
‘Consumer Transformation’ having extreme loading caused by instantaneous flows
to power generators what can be seen in Figure 3.3.

_’System Transformation’_ has the highest hydrogen adaptation particularly in
heating sector, accounting for about 45% of total hydrogen consumption by
commercial and residential sectors in 2050 [10]. This makes demand side less
flexible in view of geographical distribution. Overall, there is still a space
for infrastructure optimization with flexible consumers as synthetic fuels
(for shipping and aviation) production and hydrogen producers as methane
reformation with CCUS, biomass gasification and ’nuclear’ electrolysis.
‘System Transformation’ has the highest difference in mean and peak lines
loading caused not only by power generation peaking but also hydrogen flow for
residential heating due to low temperature peaks.

###  3.3 Storage

_’Consumer Transformation’._ The variation of hydrogen storage profile between
FES-2022 and PyPSA-GB-H2 shown in Figure 3.4 can be explained by the
difference in supply-demand fluctuations. The major differences of PyPSA-GB-H2
from FES-2022 are high peaks of hydrogen demand in cold season (November-to-
March) caused by hydrogen flow to power generation as modelling of this sector
is based on power demand and does not account technological specifics of this
process. In addition, hydrogen production curve in PyPSA-GB-H2 model has
sharper peaks throughout the year associated with ‘networked’ electrolysis
being major hydrogen producer and linked to offshore wind availability only.

_(A) - ’Consumer Transformation (B) - ’Leading the Way’ (C) - ’System
Transformation’_

Figure 3.4: _Hydrogen storage ’state of charge’ - FES-2022[10] vs PyPSA-GB-H2
[42], 2050. Even though a similar trends can be observed, both initial and
peak storage capacity is lower in PyPSA-GB-H2 model compared to FES-2022,
which is caused by difference in supply-demand modelling._

_’Leading the Way’._ Even though a similar trend can be observed, both initial
and peak stage of charge is almost twice lower in PyPSA-GB-H2 model compared
to FES-2022 (Figure 3.4) which is relevant to difference in supply-demand
profile. Hydrogen demand by synthetic fuels (shipping and aviation) and power
generation stays approximately at the same levels as of ‘Consumer
Transformation’ scenario. The consumption spikes in FES-2022 could be
associated with different approach to heating demand modelling: daily
temperature profile and combined electric-hydrogen heating with hydrogen used
for lower temperature peaks only.

_’System Transformation’._ Annual supply-demand profile for ‘System
Transformation’ scenario in PyPSA-GB-H2 modelling is relatively close to
FES-2022. FES-2022 demand curve is smoother compared to PyPSA-GB-H2 what could
be caused by difference in temperature fluctuations andd introduction of local
storage. Hydrogen storage state of charge is also showing high similarity
between FES-2022 and PyPSA-GB-H2 models, with only variation in peak storage
during cold season.

##  4 Discussions

Development of hydrogen infrastructure and hydrogen economy are two
interdependent aspects. From one side, the scale of infrastructure shall be
defined by hydrogen integration in the future energy mix. From another,
hydrogen supply chain growth may be constrained by the absence of facilities
to link potential supply and demand sites. Moreover, the early development
stages in energy sector are typically supported by fair competition therefore
creating progression at dispersed locations increasing the pressure for
infrastructure support.

The uncertainties in hydrogen economy development and the lack of open-source
modelling can lead to substantial investment in complex infrastructure which
may be largely underutilized in the future. Or even more, hydrogen adaptation
may have to be adjusted around the new infrastructure missing out
opportunities for more efficient energy systems development.

In this study, an open-source model, PyPSA-GB-H2 [42], was developed to
simulate Great Britain (GB) future energy scenarios in hydrogen sector,
covering the gaps of the previous studies and including all consumers and
production technologies projected in Future Energy Scenarios (FES) [8]
presented by National Grid. The open-source nature of model and the variety of
covered sectors and scenarios enhances accuracy and transparency in this
research area and laying a foundation for further studies.

This section will cover the study analysis and interpretation of the findings
related to GB’s hydrogen infrastructure development. Additionally, policy
recommendations and outline of the next steps for advancing this work will be
given.

###  4.1 FES Scenarios Analysis

This study evaluated geospatial flexibility of hydrogen producers and
consumers based on FES-2022 [10] workbook and analysis of technical
dependencies with summary presented in Figure 4.1.

Figure 4.1: _Share of geographically ’flexible’ supply and demand sectors,
with capacities per FES-2022 year 2050[10]. As the share of hydrogen
adaptation in GB’s energy system increases, demand side flexibility decreases,
enforcing a more complex hydrogen infrastructure. This is primarily due to
dispersed demand for residential heating, which requires advanced
infrastructure, regardless of increased supply flexibility._

The summary shows decrease of ’flexible’ demand share, which could potentially
be located in proximity to hydrogen production, with increased proportion of
hydrogen in total energy mix while the opposite trend can be seen for supply
side. The major highlights of analysis are summarized below based on specific
sub-area of research.

_1) Hydrogen Infrastructure Scale for FES-2022 Net Zero Scenarios:_

_‘Consumer Transformation’:_ Local hydrogen networks with strategic location
of ‘flexible’ consumers, as synthetic fuels (shipping and aviation) is deemed
to serve the purpose. _‘Leading the Way’:_ Regional networks as not all
demands can be met by local production and some residential heating is added.
Location planning of synthetic fuel production (shipping and aviation) and
Direct Air Carbon Capture and Storage (DACCS) will support reduction of future
hydrogen infrastructure, however it is expected that regional networks would
still be required to cover hydrogen distribution for residential heating.
_’System Transformation’:_ Country scale networks, high reliance on hydrogen
for heating. Overall, this scenario has the highest share of GB’s energy
system reliance on hydrogen and the largest geographical area of consumers to
be covered. Therefore, introduction of complex hydrogen infrastructure is
essential for ‘System Transformation’ scenario.

_2) Residential Heating Decarbonization Debate:_

Emissions reduction in residential heating sector is still encountering major
uncertainties. While ’Consumer Transformation’ scenario relies purely on
domestic heating electrification, ’Leading the Way’ adopts 25%
($\approx$42TWh) and ‘System Transformation’ 50% ($\approx$145TWh) of hydrogen
in total heating energy mix by 2050 [10]. Even though heating heat pumps are
by far more efficient compared to hydrogen boilers [17], temperature
requirement cannot always be met by heat pumps particularly in apartment
blocks [19]. There is a potential for large-scale district heating sourced by
heat pumps as highlighted by David et al. [20], however, further research is
required to justify its feasibility.

_3) Hydrogen in Industry Decarbonization:_

Review of industry sector decarbonization by BEIS [21] shows high range of
potential solutions for emissions reduction in this sector which can also be
indirectly observed in FES scenarios. As example, hydrogen adaptation in
’Consumer Transformation’ is less than 10% ($\approx$11TWh) and ’System
Transformation’ is about 45% ($\approx$ 87TWh) of total energy consumption by
industries in 2050 [10]. Even though future role of hydrogen in industry
sector decarbonization has lack of clarity, the UK industrial sites are mostly
concentrated in clusters which may support localised decarbonization approach
reducing requirement in extensive hydrogen infrastructure.

_4) Balancing Hydrogen Storage Needs:_

Peak hydrogen flows were observed during PyPSA-GB-H2 [42] model runs in each
FES scenario, which are associated with hourly temperature fluctuations and
power generation peaks. These flow peaks shall see a reduction with addition
of pipeline packing and increase in model resolution, however local storage of
hydrogen (potentially in liquefied form) shall be considered for all scenarios
to eliminate high-capacity short-term loads on infrastructure. As for
geological storage, strategy for infrastructure development shall include
geological storage starting from minimum hydrogen adaptation scenario and
feasibility of decentralised approach.

_5) GB’s Net Zero Scenarios Crossroads:_

Shipping and aviation sectors are reaching the same hydrogen consumption in
all FES scenarios by 2050, standing at about 70TWh and 10TWh respectively; in
addition, power generation having a similar requirements in hydrogen among all
FES scenarios with about 15TWh in 2050 [10].

Based on the above, hydrogen infrastructure development shall be phased
starting from localized hubs prioritizing decarbonization of power grid. This
will also allow expansion of low-carbon hydrogen production sector to include
‘networked’ electrolysis. In addition, advanced planning for synthetic fuels
for shipping and aviation shall be reviewed in early phase of low-carbon
hydrogen hubs development. As for the existing industrial sector, it is
evaluated that localized decarbonization without country-scale hydrogen
infrastructure will meet the requirements.

###  4.2 Policy Recommendations

The following areas of improvement are proposed to current policies as outcome
of research completed under this study:

(1) Set priorities for hydrogen production hubs support under government
schemes considering strategic location of future hydrogen power and synthetic
fuel generation facilities.

(2) Further government support to research centers on residential heating,
particularly multi-family house (apartment blocks).

(3) Project Union initiated by National Gas (the UK gas system operator), to
provide roadmap and phasing strategy with emphasis on self-sufficient clusters
decarbonization approach.

(4) If blending strategy is approved, ‘green light’ for hydrogen producers
tapping shall be strictly monitored accounting for future strategic planning
of potential final consumers.

###  4.3 Further Work

The following aspects shall be optimized in future studies of GB’s hydrogen
infrastructure development:

(1) ‘Networked’ electrolysis location suggested by FES-2022 shall be re-
evaluated after interconnection of PyPSA-GB-H2 [42] with PyPSA-GB [39] which
will allow understanding of grid constraints and economic optimization of the
GB’s energy system.

(2) Spatial resolution of PyPSA-GB-H2 model to be increased including
potential location of power generation plants rather than limitation of all
production and consumption to industrial cluster level.

(3) Pipeline packing and provision of local storage for peak loads for both
power generation and heating may be incorporated in PyPSA-GB-H2 model, with
re-evaluation of hydrogen power plants modelling.

###  4.4 Conclusions

FES scenarios presented by National Grid [8] on an annual basis provide
potential directions of hydrogen integration in the GB energy system, however,
the extent of hydrogen application in different sectors and production
capacity by each technology is highly varying between the scenarios. Moreover,
FES scenarios are not providing guarantee of proceeding with one or another
decarbonization scenario, in fact future energy mix will potentially land
somewhere in between. Nonetheless, the scenarios are setting the minimum and
maximum boundaries of potential hydrogen adaptation based on current state of
research and stakeholders involvement. Therefore, these boundaries could act
as a guideline for hydrogen infrastructure development.

This study provided evaluation of Great Britain’s hydrogen infrastructure
development roadmap, considering the adaptability and flexibility of future
hydrogen integration across different sectors. An open-source model PyPSA-
GB-H2 was developed, improving visibility of hydrogen adaptation across
various sectors building up a base for further studies. Furthermore, policy
recommendations were provided highlighting importance of early decisions to
enhance the development of more efficient energy systems.

##  5 Supplementary Material

More details on PyPSA-GB-H2 modelling approach can be found on a public GitHub
repository - https://github.com/tatyanadergunova/PyPSA-GB-H2.git.

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