Leeds
City
Gate

B

H21 Leeds City Gate Team

H21 Leeds City Gate Core Team
Name

Organisation

Project Role

Specialist Area

Dan Sadler

Northern
Gas Networks

Project Manager
and Lead Author

OverallManagement

Al Cargill

Northern
Gas Networks

H21
System Modeller

Gas
Network ModellingMark Crowther

Kiwa
GastecPrinciple Contractor/
Lead Consultant

Hydrogen Appliances,
Annual Demand

Alastair Rennie

Amec
Foster Wheeler

Hydrogen System Design

Hydrogen
SystemJames Watt

Amec
Foster Wheeler

Hydrogen System Design

Locationand Storage

Steve Burton

Amec
Foster Wheeler

Hydrogen
System Design

SMR
DesignMike Haines

Independent
Consultant

SMR and
CCS Expert

SMR
Optimisation

H21 Leeds City Gate Support TeamJon Trapps

Northern Gas
Networks

H21 Financial
Modeller

Regulatory
Finance

Mick Hand

Northern
Gas Networks

Project
Support

H21 Schematicand Prezi Design

Richard Pomroy

Wales andWest Utilities

Project
Representative

WWU Representative,
team meeting input

Karina Haggerty

PSC

Document Production
and Design

Document
DesignIain Summerfield

Kiwa
GastecCarbon Emission
Validation

CarbonVerifier

Michael Evans

Cambridge
Carbon Capture

Carbon Captureand Mineralisation
Utilisation

Specialist
Carbon Captureand Mineralisation

A

Contents

Contents
Executive Summary

1

The Results

3General Considerations8

1. Introduction

10

1.1. UK Gas Transportation Network Operation

11

1.2. UK Gas Transportation Network Ownership16

1.3. H21 Leeds City Gate Project Origins

18

1.4. The Original and Amended H21 Leeds City Gate Project Concept

21

1.5. The Area of Conversion

24

2. Demand vs. Supply

28

2.1. Gas Demand in the Area of Conversion

28

2.2. Supply System Characteristics

43

2.3. Hydrogen Generation Method (Production)

47

2.4. Hydrogen Supply for the Leeds Conversion Area

55

2.5. Storage – Balancing Supply and Demand

61

2.6. Location of the Hydrogen Production Facilities (SMRs) and Salt Caverns 76
2.7. Demand vs. Supply Conclusions3. Gas Network Capacity

83

85

3.1. The Gas Industry Below Seven Bar Planning Software86

3.2. The Steps for Analysis

88

3.3. Natural Gas to Hydrogen Conversion on the MP (blue) Network

94

3.4. Natural Gas to Hydrogen Conversion on the LP (red) Network100

3.5. Network Capacity Conclusions

110

B

Contents

4. Gas Network Conversion

113

4.1. The Process

115

4.2. Network Enabling Costs for Conversion

137

5. Appliance Conversion

139

5.1. Domestic

142

5.2. Non-Domestic (Industry, Public and Commercial)148

5.3. Switchover Cost Estimates – All Sectors

153

5.4. Conclusions

154

5.5. Properties of Hydrogen155

5.6. Types of Hydrogen Combustion

162

5.7. Current Status of Hydrogen Appliances and Equipment

170

5.8. Conclusions

182

6. The Hydrogen Transmission System

184

6.1. HTS Teesside Connections

188

6.2. B and C – The Hydrogen Transmission Pipelines

193

6.3. Connections to the Leeds Distribution Network

201

6.4. Operating Costs (OPEX)

205

6.5. Hydrogen Transportation System Conclusions

206

7. Carbon Capture and Storage

208

7.1. UK Carbon Capture and Storage position

209

7.2. Teesside Collective Report(Taken from the 2015 Industrial CCS on Teesside Business Case)

212

7.3. Carbon Capture from Steam Methane Reformers
Using a Post-combustion Scrub of the Flue Gases

214

7.4. Carbon Footprint of H21 System219

7.5. Conclusion

227

C

Contents

8. Finance and Regulation229

8.1. Summary of Costs for the H21 Leeds City Gate project230

8.2. Hydrogen Conversion – The Regulatory Finance Model

231

8.3. Hydrogen Gas Cost per Kilowatt Hour257

8.4. Cost per Tonne of Carbon Saved263

8.5. Financial Conclusions

265

8.6. Regulatory Considerations

266

9. Next Steps – The Programme of Works

269

10. The H21 Roadmap

275

10.1. The Existing System

278

10.2. Work Package Descriptions

280

10.3. Work Package Summary

319

11. The H21 Rollout Vision

321

11.1. Incremental Hydrogen Economy Rollout

321

11.2. The Impact of Other Forms of Decarbonised Gas

347

11.3. Hydrogen Production – Market ‘Push and Pull’

349

11.4. Carbon Capture353

11.5. H21 Vision Conclusions

361

Schedules

362

Chart Schedule

363

Image Schedule

365

Table Schedule

371

DExecutive
SummaryExecutive Summary

Executive Summary
The UK, as with most other countries around the world, recognises the importanceof meeting the challenge of climate change and has resolved, by 2050, toreduce carbon emissions by 80% of the level in 1990 under the terms of the
Climate Change Act. This is the biggest energy challenge facing the world today
although, to date, there has been little investigation or thought leadership around theopportunity to decarbonise the UK distribution gas network by specifically focusing
on large cities.
Even natural gas (predominantly methane), the lowest carbon dioxide emitter per
unit of energy of any fossil fuel, produces about 180 gm/kWh CO₂ equivalent
whereas hydrogen emits zero (at the point of use). The change over from natural gas
to hydrogen has the potential to provide a very deep carbon emission reduction.
The true carbon footprint of hydrogen depends on its source. For example, grid
power electrolysis has very high emissions whereas hydrogen made from stripping
the carbon atom from natural gas has about 50 gm/kWh CO₂ equivalent including
indirect emissions, a large reduction over the existing unabated natural gas fuel.
Renewable based electrolysis could be used, but for the foreseeable future therequired quantities do not look realistic.
This report suggests that we can significantly decarbonise parts of the existing gas
network at minimal additional cost to consumers. This would significantly contributeto the UK’s 2050 and Paris Agreement commitments, remove the risks of carbon
monoxide poisoning, increase energy storage, potentially remove air pollution fromvehicles, and enable new product development and innovation for manufacturing
and industrial businesses.
The UK gas industry is over 200 years old. For the first 150 years the gas used was
locally manufactured town gas which contained circa 50% hydrogen with smaller
quantities of carbon monoxide and methane. In the early days this was made bydistilling coal and, later, oil. Following the initial discovery of natural gas in the North
Sea, made up predominantly of methane, during the 1960/70s the UK undertook anationwide gas conversion programme converting 40 million appliances, reaching apeak of 2.3 million per year. Over 80% of the UK population now use this gas networkfor heating and cooking. A hydrogen conversion would follow a similar process tothe original town gas to natural gas conversion undertaken so successfully andwithin living memory. The process will involve minimal disruption for the customer(domestic or commercial) and require no large scale modifications to their property.
Since 2002, the UK has been undertaking the Iron Mains Replacement Programme(IMRP), upgrading the majority of its distribution pipes to polyethylene. This is arisk prioritised, Health and Safety Executive mandated initiative due to completein 2032. These polyethylene pipes are considered to be suitable for transporting
100% hydrogen.

1

Executive Summary

The H21 Leeds City Gate project is a study with the aim of determining the feasibility,from both a technical and economic viewpoint, of converting the existing natural gas
network in Leeds, one of the largest UK cities, to 100% hydrogen.
The project has been designed to minimise disruption for existing customers, and todeliver heat at the same cost as current natural gas to customers.
The project has shown that:yy The gas network has the correct capacity for such a conversion
yy It can be converted incrementally with minimal disruption to customers
yy Minimal new energy infrastructure will be required compared to alternatives
yy The existing heat demand for Leeds can be met via steam methane reforming
and salt cavern storage using technology in use around the world today
The project has provided costs for the scheme and has modelled these costs in a
regulatory finance model.
In addition, the availability of low-cost bulk hydrogen in a gas network could
revolutionise the potential for hydrogen vehicles and, via fuel cells, support a
decentralised model of combined heat and power and localised power generation.

2

Executive Summary

The Results
The results of the Project are as follows:

Demand vs. Supply (Section 2)
The energy demands calculated for the area of conversion are:
1. Average yearly gas demand = 678 MW (derived from DECC data)
2. Maximum peak yearly demand = 732 MW (temperature corrected DECC data)
3. Maximum peak hour demand = 3,180 MW (NGN 1 in 20 peak hour demand)
4. Peak day average demand = 2,067 MW (derived from NGN 1 in 20 peak hourdemand design parameter)
5. Total average yearly demand = 5.9 TWh
6. Total peak year demand = 6.4 TWh
This demand would be serviced by the following hydrogen production and storage
facilities: Hydrogen production capacity of 1,025 MWHHV (305,000 Sm³/h) provided
by four Steam Methane Reformers (SMRs) located at Teesside, fitted with 90%
carbon dioxide capture. This CO₂ is then compressed to 140 bar and assumed to beexported ‘over the fence’ to permanent sequestration deep under the North Sea.
Such hydrogen production at large scale is fully proven, with worldwide production
standing at about 50 million tonnes per annum compared to 0.15 million tonnes perannum for the proposed area of conversion.
Additional intraday storage, which together with the SMRs and inter-seasonal
storage, will supply a maximum 1 in 20 peak hour demand of 3,180 MWHHV. This
will be in the form of salt cavern storage located at Teesside, some which may be
repurposed from already existing caverns.
Inter-seasonal storage of 702,720 MWhHHV (40 days of maximum average daily
demand (coldest year), 209 million Sm³ hydrogen). This will be in the form of salt
cavern storage located on the East Humber coast.
A Hydrogen Transmission System (HTS) will connect the SMRs and salt caverns to
the proposed area of conversion (Leeds) and will be capable of transporting at least
the peak supply requirement of 3,180 MW.

Gas Network Capacity (Section 3)
Both the Medium Pressure (MP) and Low Pressure (LP) gas distribution networks
within the area of conversion have been modelled for hydrogen conversion using
the network analysis software and data currently used by Northern Gas Networks.
The conclusion of this modelling is that the gas networks have sufficient capacity toconvert to 100% hydrogen with relatively minor upgrades.

3

Executive Summary

Gas Network Conversion (Section 4)
It is possible for the existing gas network to be segmented and converted fromnatural gas to hydrogen incrementally through the summer months over a three-year
period. This approach would mean minimal disruption for customers during
the conversion.

Appliances Conversion (Section 5)
Hydrogen appliances and equipment for domestic, commercial and industrial sectors
can be developed. There are already a few models on the market, although sales
are extremely low, due to an absence of piped hydrogen. Just with the knowledge ofthis study, several manufacturers are showing real enthusiasm for their development.
A firm long-term plan and significant stimulus would be needed to provide themotivation to develop and produce the wide range of equipment required. This could
potentially be in the form of a national heat policy.

Hydrogen Transmission System (Section 6)
High pressure hydrogen transmission pipelines are operating around the world today.
Similar pipelines have been proposed for carrying hydrogen from the SMR site to
the conversion area and hydrogen storage sites. In addition a connection between
the natural gas transmission system and the SMR has been proposed along with apipeline from the SMR to CCS. Costs for these have been estimated at £230 million
with ongoing OPEX costs of £0.5 million per annum.

4

Executive Summary

Carbon Capture and Storage (Section 7)
The H21 Leeds City Gate project would give the following savings in CO₂ emissions:gm/kWhNG

gm/kWhH₂%
Reduction

UK Carbon budget basis(Scope 1)

184.0

27.0

85%

Including electricity for sequestration(Scope 1+2)

184.0

49.5

73%

Including embodied CO₂ from theproduction and importation of natural gas(Scope 1+2+3)

209.3

85.8

59%

The H21 Leeds City Gate project would sequester 1.5 million tonnes per annum CO₂.
Scope 1, net CO₂ savings for the area of conversion is 927,000 tonnes per year.
Carbon capture and storage technology is well established alongside SMR
operations. An example of which can be seen in the Port Arthur SMR plants operated
by Air Products in the USA.

5

Executive Summary

Financial Model (Section 8)
Total costs associated with the Project are summarised in the table below.
Cost
incurred (£m)

Cost Summary (£m)
Network Capacity and Conversion Preparatory Work
(Section 2.2)

Ongoing costs eachyear (£m)

10

Hydrogen Infrastructure/Conversion Costs
Steam Methane Reformer (SMR) Costs (Section 2.1)

395

Intraday Salt Caverns (Section 2.1)

77

Inter-Seasonal Salt Caverns (Section 2.1)

289

Appliance Conversion (Domestic, Commercial andIndustrial users within area of conversion) (Section 2.3)

1,053

Hydrogen Transmission System (HTS) (Section 2.4)

230

Ongoing OPEX Costs
Carbon Capture and Storage

60

SMR/Salt Cavern/HTS Management

31

SMR Efficiency loss (30%)

48
Total

2,054

139

If the H21 Leeds City Gate project was funded using the current UK regulatory
business plan it would have negligable impact on customers total gas bills.

6

Executive Summary

Next Steps, Programme of Works and H21 Roadmap (Section 9 and 10)
The earliest practical date for the initial hydrogen conversion of a UK city is 2025. Inorder to achieve this, several preparatory actions need to have taken place these are:
1. 2017 to 2022 – Provision of finance to deliver the 16 work packages identified inthis report with an estimated value of between £60m and £80m (See Section 10).
2. 2016/17 – Establishment of the H21 Programme Team to co-ordinate and deliverthe 16 identified work packages.
3. 2018 – Provision of funding to begin the FEED/detailed design of the hydrogenproduction, storage and pipeline systems.
4. 2018 – Clear direction by OFGEM that gas distribution networks need to allow
provision within their GD2 business plans (2021–2029) to facilitate the conversionof the first cities.
5. 2021/22 – A policy decision committing to the strategic, incremental material
conversion of the UK gas grid over an agreed timescale.

The H21 Vision (Section 11)
The H21 Leeds City Gate Project has focused on the provision of heat through a
100% hydrogen gas network conversion for Leeds. Additionally by utilising gas
industry expertise some thought leadership has been provided around the impactof an incremental rollout of such a system across UK cities and/or regions. This has
also considered the potential impact of establishing the first commercial hydrogen
economy in the world.

Two rollout options have been presented and,alongside efficiency savings, both options
could be developed with minimal impact on
customers overall bills

7

Executive Summary

General Considerations
1. The H21 Leeds City Gate Project has shown that the conversion of the UK
gas distribution network to hydrogen would enable a dramatic reduction in
UK emissions with circa 73% reduction from heat but also from transport andpower generation.
2. Converting the UK gas network avoids the need to persuade householders
to raise the funds and give up the space to install other complex low carbon
technology. The absence of hassle for the customer is considered to be very
important in the likely success of any decarbonisation strategy.
3. Leeds with circa 1% of the UK’s population is a sensible starting point becauseof its size and geographical location, near to both Teesside (with its existinghydrogen infrastructure) and the salt beds north of Hull.
4. The use of hydrogen storage addresses inter-seasonal storage, one of the known
problems of trying to use only electricity as the energy vector for heat, This
inherently smooths out:—— The UK’s large variation in inter-seasonal energy demand as hydrogen is produced
and stored ‘downstream’ at a relatively constant rate throughout the year.
—— The production of CO₂ thereby simplifying sequestration.
—— The wholesale natural gas purchases as the demand is relatively constant over theyear for hydrogen production and storage and therefore this reduces the volume ofnatural gas required at periods of high demand (and therefore cost).

5. Low cost pipeline quality hydrogen (99.9%) can be purified to the very highquality gas required by fuel cells. Therefore a UK gas grid conversion tohydrogen could provide feedstock for automotive use, and via fuel cell combined
heat and power open up the opportunity for an alternative to centralised
power generation.
6. All of the individual steps in the hydrogen supply train (except for some
appliances) are proven and widely available by competitive tender.
7. The project could stimulate the Northern Powerhouse bringing economic
benefits to both the North and the UK economy as a whole.
The H21 Leeds City Gate project provides evidence that converting the UK gas
network to hydrogen is technically possible and economically viable. A UK hydrogen
conversion strategy could make a significant contribution towards meeting thechallenge of the Climate Change Act as well as establishing the world’s firsthydrogen economy. It could also create a significant impact on UK GVA and establish
a real anchor project around the Northern Powerhouse concept.

8

SECTION 1

Introduction

Section 1 | Introduction

1. Introduction
The UK Gas Industry History
William Murdoch was the first to exploit the flammability of gas for the practicalapplication of lighting. He worked for Matthew Boulton and James Watt at their Soho
Foundry steam engine works in Birmingham, England, in the early 1790s. In 1798 heused gas to light the main building of the Soho Foundry and in 1802 lit the outside in a
public display of gas lighting, which astonished the local population.
One of the employees at the Soho Foundry, Samuel Clegg, saw the potential of this newform of lighting. Clegg left his job at the Soho Foundry to set up his own gas lighting
business, the Gas Lighting and Coke Company. The first public street lighting with gas
was demonstrated by Frederick Albert Winsor in Pall Mall, London, on 28th January,
1807. In 1812 Parliament granted a charter to the London and Westminster Gas Lightand Coke Company, and the first gas company in the world came into being. Less than
two years later, on 31st December, 1813, Westminster Bridge was lit by gas. (Wikipedia).
For the following 150 years ‘town gas’ companies grew and prospered across the UK
manufacturing gas from coal, then in the later years, oil (post World War Two). At its
peak, before conversion to natural gas, town gas was manufactured across UK towns
and cities using over 26 million tonnes of coal and 0.5 million tonnes of oil per annum(Charles Elliott, The History of Natural Gas Conversion in Great Britain).
There are two important factors which need to be considered when reviewing thisrich history. Firstly, town gas consisted of up to 50% hydrogen (other gases included
carbon monoxide, methane and small quantities of various other gases) and was piped
throughout the distribution system – the same distribution system we are upgrading
today with polyethylene. Secondly, town gas was manufactured and distributed on an
individual town by town basis, no Local Transmission System or National Transmission
System existed (see explanation later in this section).

10Section 1 | Introduction

1.1. UK Gas Transportation Network
Operation
The UK gas transportation industry has evolved over the last 200 years to be thewell-integrated highly robust system that we see today. If we consider the 19th
century to have been dominated by town gas, the 20th century by natural gas,
what if the 21st century could be dominated by hydrogen? To fully understand theimplications of the H21 Leeds City Gate project it is important to understand how thecurrent UK gas transportation network operates.
The UK gas transportation infrastructure is a vast network of pipes (37,000 km in
Northern Gas Networks alone) ranging in diameter from 48 inch (1,200 mm) highpressure mains to 2 inch (50 mm) low pressure mains. The gas used in the UK
system, since the town gas to natural gas conversion between 1966 and 1977, haspredominantly come from the UK’s North Sea gas reserves. In more recent years
there has been an increasing dependence on gas from Europe, or from around theglobe through the process of liquid natural gas transportation.
The current UK gas transportation system has three key component parts:
SystemLevel of Pressure

The National Transmission System (NTS)

45 – 85 bar

The Local Transmission System (LTS)> 7 – 70 bar
7 bar and below which consists of:Intermediate Pressure (IP) (> 2 bar to 7 bar)

The Distribution System

Medium Pressure (MP) (> 75 mbar to 2 bar)
Low Pressure (LP) (not exceeding 75 mbar)

Table 1.1. The UK gas transportation system

Note: A ‘bar’ is approximately the pressure exerted by the atmosphere at sea
level. Strictly, the pressures indicated within this document are barg or bar-gauge,i.e. pressures in excess of local atmospheric pressure. For example, 2 barg isapproximately 3 bar absolute.
By way of analogy, the UK gas transportation system could be compared to the UK
road network, whereby the NTS are major motorways, the LTS minor motorways or‘A’ roads and the distribution system is everything else.

11Section 1 | Introduction

The storage of gas, to ensure that supply is able to meet the demands of end users,
which includes both intraday and inter-seasonal swings, is managed by using
Liquid Natural Gas (LNG), salt caverns/depleted hydrocarbon fields and linepack
within the NTS (intraday only) and LTS (intraday only). The distribution system, whichmainly consists of medium and low pressure pipe networks, does not provide any
significant storage for the system and is designed specifically for an instantaneous
reaction to match peaks in demand.

Breakout: Storage Descriptions
LNG − When natural gas is cooled to −162 °C it becomes a liquid. As a liquid it ispossible to store 600 times the quantity of natural gas than in a gaseous stateof the same volume.
Salt Caverns – There is a long and successful history of storage cavern
utilisation in the UK (over 30 in number) which provide seasonal, diurnal (daily)
and rapid response storage. Salt caverns can be manmade in geographicalareas which have large salt beds which have been washed out using highpressure water jets. They are typically cathedral size, 80 m in diameter and
80 m high.
Linepack – Increasing and reducing the pressure in the transmission pipeline
to store or release additional gas.

Some technical differences:
The UK gas industry is one of the safest industries in the world and has continuously
evolved driven by high levels of technical expertise and stringent regulation. The NTS
and LTS are designed and built to the same technical standards and specifications.
They are constructed using a hard steel (X42, C4Gas PIPO etc.), and as such are notsuitable for the transportation of hydrogen at high pressure. This is due to the well
documented embrittlement problems hydrogen can cause when transported at highpressure through hard steel pipes. These problems are most likely to occur within theoriginal welded joints of the 1960s, but could arise almost anywhere within this highpressure system.
There are two significant differences between the NTS and the LTS. The NTS
uses compressors to move gas throughout the country. There are currently nocompressors on the LTS. The gas transported in the NTS is unodourised (seeBreakout: Gas Odour later in this section).

12Section 1 | Introduction

The UK gas distribution system has evolved since the foundation of the gas industry
over 200 years ago. The pipes within this system historically were iron (cast, spun,ductile) and steel. Since the 2002 there has been a HSE mandated replacement
programme in the UK, referred to as the Iron Mains Replacement Programme (IMRP)
with the purpose of upgrading these pipes with Polyethylene (PE) pipes. The IMRP
is scheduled over a 30 year period, to be completed by 2032. Historically town gas(circa 50% hydrogen by volume, referred to as v/v) was transported through theseiron mains. Due to degradation of these mains over time it is likely a 100% hydrogengas would need to be transported through a predominantly PE pipe network.
Natural gas leakage from the current system is calculated within the Gas Distribution
Networks using a ‘leakage model’. Leakage reduces year-on-year in the industry
as more old metallic mains are upgraded to PE and the IMRP progresses. If theexisting metallic distribution mains were used to transport hydrogen without the
upgrade being undertaken by the IMRP it is reasonable to assume that there would
be an increase in leakage levels. This is due to hydrogen having a low density atonly ⅛ the density of methane. This is not necessarily an increased safety issue fromtoday’s current position when compared directly to the risk associated with naturalgas, but is certainly a commercial problem. It should be noted that hydrogen is nota greenhouse gas, and therefore any associated leakage, unlike methane, does nothave a significant negative impact on climate change. Some academics indicate thathydrogen contributes slightly to a second tier of global warming but it is agreed thiseffect is very small.

Breakout: Gas Odour
Natural gas as it is extracted from the ground has no smell. It is odourised
here in the UK to ensure that ‘gas’ has a recognisable smell, even at low
concentrations – well below the explosive limit – to make the public aware that
there is a gas leak so that the appropriate action can be taken.
The odourant added to natural gas is a group of sulphur based compounds
chosen because of their distinctive and highly concentrated smell.
The odourant is added to the gas at the ‘offtakes’ which are the point oftransition between the NTS and the LTS. This is the most cost effective point to
add the odourant to the gas. This also allows gas in the NTS to be transferred
via interconnectors to continental Europe where odourising regulations
vary considerably.

13Section 1 | Introduction

Today’s gas transportation system is represented simplistically on the map in
Image 1.1.

Gas Rig

Liquid Natural
Gas Storage

Compressor
StationSalt
CavernTerminal

Pressure
ReductionOﬀtakeCompressor
StationPressure
Reduction
StationPower
StationDistrict
Governor

HULL
LEEDS

Image 1.1. Existing UK Transportation System

This transporation system is represented in simple pressure tiers, illustrated in
Image 1.2. As gas is injected from the NTS, it cascades down the pressure tiers, tobe used by the customer at the appropriate point. The majority of gas customers
are located off the medium and low pressure systems (domestic heat demand).
As pressure drops in a lower pressure tier (for example as demand increases), gas‘cascades’ from the pressure tier above to maintain supply. Simplistically if the systemis thought of a series of cascading sinks of water, as the sink at the bottom starts toempty (the plug is pulled out – or gas demand increases) the sink above flows into
the sink below to maintain volume and thereby ensuring security of supply.

14

Section 1 | Introduction

National Transmission System

Distribution Network
Local Transmission
SystemDistribution
System38 barPressure
System
17 barPressure
System
7 bar
Pressure
SystemMediumPressure
SystemVery Large
Industrial
Customers

Low
Pressure
SystemLarge
Industrial
Customers

Signiﬁcantnumbers of
Gas Customers
Domesitc
and Industrial
Majority of
Gas Customers
Domestic
and Industrial

Image 1.2. UK Gas Pressure Tiers

15Section 1 | Introduction

1.2. UK Gas Transportation Network
Ownership
In recent history the ownership of the transportation assets haschanged considerably:
yy 1800s–1948: Around 2,000 independent town gas companies were in operation.
yy 1948–1973: These independent companies were nationalised to form 12
autonomous gas boards.
yy 1973–2000: British Gas Corporation was established and privatised
8th December 1986. This owned the entire UK gas transportation system.
yy 2000–2005: The UK gas transportation operation became Transco (andthen National Grid Transco (NGT)) following the de-merger of the British
Gas Corporation.
yy 2005–present: Four of the eight Gas Distribution Networks (GDNs) within
the gas transportation system were sold. Today the ownership of this UK
gas transportation system is illustrated in the Image 1.3. The NTS remains
in the ownership of National Grid whilst the relevant LTS are owned by therespective GDN.
Today the industry ownership model is referred to as the National Transmission
System and Gas Distribution Networks (GDNs). Rather unhelpfully the later
description often leads to the incorrect assumption that the GDNs only operate the
distribution system (below 7 bar). However the GDNs own and operate both the LTS,
including the major pressure reduction stations where gas is taken from the NTS(offtakes), and the distribution system.

16

Section 1 | Introduction

The ownership model is represented in Image 1.3:

Image 1.3. Current Gas Transportation System Ownership

National Grid own the NTS and there are currently four gas distribution operators
who collectively own the eight gas distribution networks (only the operators
are shown on the map), National Grid Distribution (who own four GDNs),
Northern Gas Networks, Scottish and Southern Gas Networks (who own two GDNs)
and Wales and West Utilities.

17Section 1 | Introduction

1.3. H21 Leeds City Gate Project Origins
The UK, as with most other countries around the world, recognises the importanceof meeting the challenge of climate change. The Climate Change Act seeks toaddress this, with the opening statement “It is the duty of the Secretary of State toensure that the net UK carbon account for the year 2050 is at least 80% lower than
the 1990 baseline”. The UK needs big ideas that work on a practical basis. To quote
David MacKay’s book Sustainable Energy – without the hot air, ‘What is required are
big changes in demand and supply’. To date there has been little investigation or
thought leadership around the opportunity to decarbonise the UK by using hydrogenon a large city scale, a big idea that could work on a practical basis.
The academic concept of 100% hydrogen gas grids and their potential viability
relative to the UK gas networks was presented to DECC by Kiwa Gastec in
February 2012. DECC subsequently supported a piece of work to compare therelative fire risks from natural gas and hydrogen in a Scottish farmhouse (HyHouse).
This had an encouraging outcome, but the idea gained little traction as there
was minimal tangible evidence addressing gas network capacity and conversion
capability, no industry support, no financial model and no practical ‘anchoring’ tothe concept. Following an information meeting between Kiwa Gastec and NGN at
the LCNI conference in Aberdeen in October 2014 the H21 Leeds City Gate project
was developed, the first to address the 100% hydrogen concept in the UK in apractical manner.
When formulating the concept of H21 Leeds City Gate project there were multiple
considerations that needed to be taken into account.
yy Over 80% of customers in the UK use natural gas, rising to 90% in cities.
yy Customers have little money to convert to alternative sources of heat. (SeeWales and West Bridgend study available via the Network Innovation Allowance
portal on the ENA website).
yy There are two challenges to decarbonisation that are particular to cities. Firstly,
the types of existing buildings (over 80% will still be there in 2050) and secondly
the complexities involved with the installation of new network infrastructure.
Beneath the roads and pavements of most major UK cities there are high levelsof congestion with large quantities of utilities already competing for space. The
gas industry has vast experience laying and modifying mains throughout cities
and is experienced in the significant challenges and complexities involved. A
major advantage to using hydrogen gas for transporting energy in cities is thatthe gas pipe network is already in place. Other energy options would require
extensive new infrastructure causing significant disruption.
yy Cities emit the largest quantities of carbon, due to using larger volumes ofnatural gas. Cities therefore represent the most significant opportunity for the
reduction of carbon emissions. Due to the scale of energy demand and age they
are also the most difficult to address.

18Section 1 | Introduction

yy Large inter-seasonal swings in energy demand, of up to 80% in city centres and
99% in suburbs are managed by the gas network through a system that alreadyexists and operates, largely invisibly, to the general public.
yy Hydrogen is not regarded as a conventional greenhouse gas. It is thought to be
involved in some second order effects but these are minute compared to the
known effects of carbon dioxide or methane.
yy There is no shortage of methane due to the long term potential supplyof unconventional gas (shale gas, coal bed methane, biomethane) and
LNG/interconnector availability.
yy If the gas industry is to have a long term future it needs to be able to makesignificant contributions to decarbonisation.
yy If hydrogen could offer the UK a large scale solution to decarbonisation it
will provide opportunities for all the energy vectors (electric, heat and gas) tocontribute. With more options available there is a greater probability in meetingthe challenge of the climate change act.
yy There are only three parts to the end-to-end energy system, as shown in
Image 1.4.

Production

Transportation

Consumption

Where the energy
comes fromHow it gets from where it iscreated to where it is used

How itis usedImage 1.4. End-to-End Energy System

Considering these factors, the key question for the project team in the formulation of
the H21 Leeds City Gate project was:

‘Is it possible to develop and cost a holistic,large scale solution to the decarbonisationof cities with minimal impact on consumers(relative to alternatives) which can consider
the end-to-end energy system?’

19Section 1 | Introduction

Solutions presented to date generally focus on one area of energy, production or
consumption, and often do not take transportation into consideration. No large scale
practical solution has been presented to date to address decarbonisation of heat,
which would involve minimal impact on all three parts of the existing energy system.
The H21 Leeds City Gate project was developed around the following six parameters:
1. A scalable solution to decarbonisation needs to have gas network distributedhydrogen as the gas.
2. Can the current gas network of a large city be converted to 100% hydrogen andsupply the existing energy requirements and can it also be converted in a way
which is acceptable to customers?
3. Can hydrogen production meet the demand requirements and, as importantly,
the profile of those requirements for a large city? Production likely being via
Steam Methane Reformers (SMRs) with the methane feedstock supplied by theexisting NTS/LTS gas networks.
4. All the technologies in the project have to be demonstrable today.
5. The city selected to convert must be of sufficient scale to enable the project tobe used as a reasonable ‘blueprint’ for all major UK cities.
6. Hydrogen would only be introduced to the below 7 bar network (distribution
network) to avoid problems of embrittlement.

20Section 1 | Introduction

1.4. The Original and Amended
H21 Leeds City Gate Project Concept
Leeds was selected as the city on which to undertake the project. This was because
the cities gas grid is large and complex enough to provide a blueprint for all UK cities,
and it is located in the north near the east coast, where the geology is suitable for theconstruction of the salt cavern storage required to manage demand profile variations.

H21 Leeds City Gate

P2G

SMR
Plant

H2
SMR
Plant

Steam Methane
Reformer
(SMR)

CH4

SMR
Plant

H2
H20

It is located withinreasonable proximity
to the White Rose andTeesside Collective
carbon capture projects.
The original projectvision was to construct
a high pressure(17 bar) natural gas ring
main around the city ofLeeds with strategicallylocated SMRs toprovide hydrogen to the
distribution network of
the city.

CO2

Image 1.5. H21 Leeds City Gate – Original Concept

During the initial stages of the project, it became clear that building this option was
not practical or the most economical solution. As a result three more additionalparameters for the project were introduced:
1. The location of the SMRs should be nearer to the potential carbon capture
centres of the White Rose line and/or Teesside. This is due to the advantage oflinepack and/or storage potential in longer hydrogen transmission pipelines andassociated benefits of clustering carbon capture.
2. The SMRs would need to be situated near salt caverns to facilitatehydrogen storage.
3. The SMRs are more likely to be clustered in locations ideally in chemical industry
heartlands to maximise economies of scale and efficient system design, as well
as utilising local skills and acceptability.

21Section 1 | IntroductionMore detail on the location of the SMRs is provided in Section 2, Demand vs. Supply.
The original concept was amended, as shown in Image 1.6.

Gas Rig

Liquid Natural
Gas Storage

Salt
CavernCarbon Captureand Storage

Compressor
StationTerminal

Steam
MethaneReformerPressure
ReductionOﬀtakeCompressor
StationSalt
CavernPressure
Reduction
StationPower
StationSalt
CavernDistrict
Governor

HULL
LEEDS

Image 1.6. H21 Leeds City Gate – Amended Concept

It is important to note that the scope of the H21 Leeds City Gate project was
specifically constrained to converting the city of Leeds. Also importantly, the project
scope only covers the implications of the conversion to hydrogen of the demands forheat. No additional potential benefits associated with vehicle transportation and/or
electrical decarbonisation have been considered.

22Section 1 | Introduction

Additionally all of the design schemes and costs given in this document are
essentially ‘well to sofa’, i.e. they include.
yy Extracting the natural gas from the ground.
yy Processing it.
yy Transporting it to Teesside.
yy Converting it to hydrogen using an SMR plant large enough to meet
annual demand.
yy Storing the hydrogen in salt caverns for both inter-seasonal and intraday demand.
yy Supplying the hydrogen to Leeds.
yy Converting/replacing each appliance in Leeds with a new hydrogen burning
device, at no cost to the householder/business at point of conversion.
yy Converting the Leeds distribution network over three years.
This point is offered in great detail because often other technologies, e.g. wind-farms
or nuclear power, only quote costs of energy at the terminals of the generating
station. To provide heat in the home, such electricity has then to be transmitted (athigh voltage) then through local distribution networks (at lower voltage) to new heatpumps (installed in every home) which frequently require large radiators to operate
at their design efficiency. Because of the integrated nature of the gas industry suchan isolated cost is of little value, but it does make direct comparison of electric andhydrogen heating more challenging. In essence a cost of 10p/kWh for electricity
from a nuclear power station or other renewable energy source makes no allowancefor the real cost of winter peaks (requiring inter-seasonal storage and/or peakgeneration facilities) or getting the energy to a householder’s ‘sofa’.

23Section 1 | Introduction

1.5. The Area of Conversion
In order to undertake the project the team had to define the specific area to beconverted from natural gas to hydrogen. This area is referred to throughout theremainder of this report as ‘the area of conversion’.
Following detailed appraisal (more detail is provided in Section 3, Gas Network
Capacity) the finalised area for conversion contained 264,000 meter points, covering
a population of circa 660,000 people. The area includes the City of Leeds and someof its suburbs, Swillington to Morley to the south of Leeds and Pudsey to Otley/
Burley in Wharfedale to the north west of Leeds.
Image 1.7 shows the area of conversion and the extent of the gas distribution
network. This is taken from the Northern Gas Networks record system for gas
mains locations.

LP Network up to 0.075 bar
MP Network 2 bar to 0.075 bar
Above 7 bar network

Wharfedale
Harrogate

Leeds
Bradford

Halifax, Huddersﬁeld,
Dewsbury, Wakeﬁeld

Swillington/Morley

Image 1.7. Area of Conversion

24Results

The Results
This section details the results of the H21 project. It provides a clear description of
how the work was undertaken, what assumptions were made, what data was used
and the conclusions.
For ease, the results have been split into the following sub-categories:

Section 2: Demand vs. Supply
Section 3: Gas Network Capacity
Section 4: Gas Network Conversion
Section 5: Appliance Conversion
Section 6: The Hydrogen Transmission System
Section 7: Carbon Capture and Storage
Section 8: Financial Model
Section 9: The Next Steps – Programme of Works
These are illustrated on the next page.

25

H21 Leeds City Gate
System Schematic
Section 7
Carbon Captureand Storage

Salt
CavernGas Rig

Liquid Natural
Gas Storage

Section 2
SupplyCarbon Captureand Storage
Terminal

Compressor
StationSection 6
HydrogenTransmission
SystemCompressor
StationSection 3
Gas Network
Capacity

Pressure
ReductionOﬀtakeSteam
MethaneReformer
Section 2
Supply(Intraday Storage)

Salt
CavernPressure
Reduction
StationSection 4
Gas Network
Conversion

Power
StationSalt
CavernDistrict
Governor

HULL

LEEDS
Section 5
Appliance
Conversion

Section 2
DemandSection 2
Supply(Inter-seasonal
Storage)

SECTION 2

Demand vs.
SupplySalt
CavernGas Rig

Liquid Natural
Gas Storage

Section 2
SupplyCarbon Captureand Storage
Terminal

Compressor
StationPressure
ReductionOﬀtakeCompressor
StationSteam
MethaneReformer
Section 2
Supply(Intraday Storage)

Salt
CavernPressure
Reduction
StationPower
StationSalt
CavernDistrict
Governor

HULL

LEEDS
Section 2
DemandSection 2
Supply(Inter-seasonal
Storage)2 | Demand vs. Supply

2. Demand vs. Supply
This section explains how total energy demand for the area of conversion has been
determined and the profile for that demand both intraday and inter-seasonal. It
then explains how this was matched to hydrogen supply to meet these demand
characteristics including the associated energy storage requirements.

2.1. Gas Demand in the Area of Conversion
There are multiple factors which need to be taken into account when designing a
new hydrogen supply to a city.

Daily and Peak Demand
The UK gas industry design, build and maintain the distribution network to supply
a theoretical maximum 1 in 20 year peak 6 minute (Low Pressure (LP) network) andpeak hour (Medium Pressure (MP) network) demands (see Section 3, Gas Network
Capacity and Section 4, Gas Network Conversion). This means a peak in demandthat lasts for 6 minutes/1 hour and theoretically occurring once in 20 years. For theremainder of this project the 1 in 20 peak hour demand will be used as the peakdemand design criteria. This is because the MP is the direct feed from the proposedhydrogen transmission system, see Section 6, The Hydrogen Transmission System.
This peak is most likely to occur at around 18:00 between December and February.
This requirement has been carried over into the modelling of the network supplyinghydrogen, to assess likely reinforcement and operational upgrades which may berequired. As the Network Analysis (NA) models are built around this 1 in 20 peak hourdemand, this is the most accurate source for peak demands (see Section 3, Gas
Network Capacity).

Intraday Demand Profile
This is the amount of gas used hour-by-hour within any given day. This can be low,for example at 02:00, or high, typically around 18:00 in the evening. Understanding
this profile helps determine what level of intraday gas storage is required to manage
these fluctuations.

Inter-seasonal Demand Profile
This is the amount of gas used month-to-month in an area as we move through theyear. In the gas industry, the difference in demand between summer and wintercan be up to six-fold. Understanding this profile allows us to appropriately size theinter-seasonal storage requirements. Simplistically these storage facilities allow
the hydrogen production facility to store gas in periods of low demand (summer)
and use that stored gas to supplement production of hydrogen in periods of highdemand (winter).

28

2 | Demand vs. Supply

Total Annual Gas DemandThis is the total volume of gas required by the area of conversion over the entire
year. This value is important to enable us to set the annual capacity of the hydrogenproduction facility, i.e. the supply.
 nderstanding the demand for the area of conversion is critical to understandingU
how to size the associated supply system (primary hydrogen production facilities andstorage). The figures for inter-seasonal, intraday and 1 in 20 peak hour demand havebeen determined by Northern Gas Networks (NGN) based on their historical data andNA modelling. Figures for annual demand have been obtained using the Office for
National Statistics Middle Layer Super Output Areas (MSOAs) which have then beencross-checked with NGN figures to ensure a high level of confidence. Each of thesedemand requirements are explained below.

2.1.1. 1 in 20 Peak Hour Demand
NGN manages the existing below 7 bar natural gas network using an NA software
package called Synergi. The software is configured to model demand and flow
data for natural gas, predominantly methane, as this is the current gas flowing in
the networks pipes. It is also used for five-year forecasting projection simulations byutilising demand and planning forecast data. All data used by the Synergi softwaremodel is validated as part of a regular cycle by cross-referencing the information
used by Synergi (pressures/flows) with data obtained from network loggers, sourcepressures and demand data from the field and consumer data from Xoserve.
Peak energy demand does not correlate accurately with the average annual
demand requirement in that the off-peak demand, e.g. middle of the night andduring summer, is not typically modelled within the gas industry. The assumptions
required to model off-peak energy demand, particularly with regard to the profilesof commercial and industrial loads, can produce significant margins of error whenscaled over the full year. This variation will also depend on upon the area being
modelled. Areas with large domestic load tend to have less than predicted load insummer while areas with a large commercial load, e.g. laundries or hospitals, tend
to use gas more uniformly over the year. Within the gas industry, it is possible todetermine individual date/time of day demand forecasts throughout the year, thiswill be discussed in Section 2.1.2.
For the area of conversion the 1 in 20 peak hour demand has been determined to be:

1 in 20 peak hour demand:
955,660 Scmh (hydrogen), 3,180 MWh29

2 | Demand vs. Supply

2.1.2. Intraday and Inter-seasonal Demand Profile
Forecast network gas demand levels are based on a proportionate decrease in the 1
in 20 peak demand level determined by scaling factors. These factors are based on
empirical data and were derived by British Gas Research. Two sets of values are used
to predict demand levels within the network. These sets of values allow the forecastof demand levels at a specific date or time of day (Table 2.1) and in combination canbe used to provide a forecast for a specific time and date. For example, the forecast
peak demand in April at 14.00 can be calculated as follows:
1 in 20 peak hour demand = 955,660 Scmh ≡(3,180 MW)
April demand = Peak 955,660 Scmh x 0.70 = 669,000 Scmh ≡(2,230 MW)
Demand at 14:00 = 669,000 Scmh x 0.73 = 488,000 Scmh ≡(1,630 MW)
MONTHLY RATIOSMonthDAILY RATIOS

Average
Turndown

Time

Turndown

Time

Turndown

January

1.00

00:00

0.46

12:00

0.75

February

1.00

01:00

0.36

13:00

0.76

March

0.83

02:00

0.25

14:00

0.73

April

0.70

03:00

0.25

15:00

0.73

May

0.60

04:00

0.25

16:00

0.78

June

0.40

05:00

0.28

17:00

0.93

July

0.35

06:00

0.35

18:00

1.00

August

0.35

07:00

0.55

19:00

0.97

September

0.45

08:00

0.76

20:00

0.92

October

0.65

09:00

0.82

21:00

0.84

November

0.83

10:00

0.78

22:00

0.76

December

1.00

11:00

0.76

23:00

0.64

Table 2.1. Monthly and Daily Turndown Ratios

These factors are used throughout the UK distribution gas industry to forecast
appropriate operational windows for work on the network ensuring security of supply
for customers. For example, they are used to predict operational windows for mains
laying or repair which can have a significant impact on gas supplies in a certain areaof the network.

30

2 | Demand vs. Supply

They are also used to assess response requirements under emergency conditions
on the network, e.g. a major mains break or loss of a district governor. The values are
essentially the highest potential demand levels, which enable long range forecasting– actual demand levels may be lower as the likely forecasted weather will not be thecold extreme predicted by the scaling factors possible for the time of year. Charts 2.1
and 2.2 show how these demand ratios are interpreted in graphical format.
Average Seasonal Demand Scaling Factor

Demand Scaling Factor

1.0

0.8

0.6

0.4

0.2

0
Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sept

Oct

Nov

Dec

Chart 2.1. Scaling of Demand When Considering the Monthly Factors

Hourly Demand Scaling Factor
1.0

Demand Scaling Factor

0.8

0.6

0.4

0.2

0
0:00

2:00

4:00

6:00

8:00

10:00

12:00

14:00

Time of Day

Chart 2.2. Scaling of Demand When Considering the Within Day Ratios

31

16:00

18:00

20:00

22:00

2 | Demand vs. Supply

Breakout: Gas Industry Operation Windows
Demand profiles are used in the gas industry to derive appropriate timeslots forundertaking intrusive works on the network. For example, the analysis giving a 0.2
maximum demand level leads to the recomendations shown in the table below.
Month
November to March

Recommended Time of Day
None

April, May

02:00 to 05:00

June

00:00 to 06:00

July and August

00:00 to 07:00

September

01:00 to 06:00

October

02:00 to 05:00

These recommended operational windows are used by the industry when works canbe planned well in advance, such as maintenance and new connections. However,urgent maintenance and emergency work may require decisions and actions tomade in a much shorter time frame. This allows the use of the prevailing demand
forecast that is issued by NGNs system control, which is usually for five days ahead,and utilises the weather forecast for the period. Therefore, rather than applying the
average turndown factor from Table 2.1 the forecast demand level for the work can beused, e.g. a gas escape occurs on a warm March day and the forecast demand levelis 0.65 – this would then provide an operational window between 02:00 and 05:00 for
the repair to be carried out, assuming the same NA recommendation of 0.2 and below
demand level.
Emergency work can, of course, be carried out as soon as practicable where therisk level requires this, and this would override any of the above recommendations.
NA would then be carried out to provide the best option to reduce the impact of thework on the network (e.g. raising neighbouring district govenors or connection of a
bypass main).

32

2 | Demand vs. Supply

Finally, Chart 2.3 gives a view of combining the inter-seasonal and intraday factors forthe forecasted demand over the year.
Demand Scaling, Seasonal and Temporal Combined
1 in 20
peak demand

1.00

Demandscaling

00:00

04:00

Oct
02:00

08:00

Early hours of themorning through summer- lowest demand

Jul
06:00

12:00

Time of day

Apr
10:00

16:00

Jan
14:00

20:00

18:00

22:00

0.50

Chart 2.3. Combined Inter-Seasonal and Intraday Factors for the Forecasted Demand Over the YearFor comparison with the theoretical values in Charts 2.1, 2.2 and 2.4, show the daily
demand levels for the Yorkshire area between March 2009 and June 2015 baselined
against the 1 in 20 peak hour demand.
Estimated Yorkshire LDZ Peak 6 minute Demand for 2008/09 to 2014/15% LP 1 in 20 peak 6 minute demand100

1 in 20
peak demand2013:
a sustained cold winter

90
80
70
60
50
40
30
20
10
0
Mar 09

Sep 09Mar 10

Sep 10Mar 11

Sep 11

Mar 12

Sep 12

Mar 13Chart 2.4. Yorkshire Actual Daily and Seasonal Demand Levels 2009 to 201533

Sep 13

Mar 14

Sep 14

Mar 15

2 | Demand vs. Supply

Having understood the 1 in 20 peak hour demand and the daily turn down profiles,
it is important to translate the peak hour demand into a peak day demand profile.
This can be established using a very simple calculation (for clarity, these aredesign parameters).
Peak hour demand = 3,180 MW
Average hourly turn down factor (average of all the ratios in Table 2.1) = 0.65
Peak day average demand = 3,180 MW x 0.65 = 2,067 MW
Therefore total peak day daily demand (1 in 20 years) = 2,067 x 24 = 49,608 MWh

Peak day average demand for thearea of conversion: 2,067 MW

2.1.3. Total Annual Demand
Obtaining annual demand figures for the area of conversion via NA proved morechallenging, and it became clear that reliance on the NGN network analysis for thisvalue was not appropriate. Two methods for calculating annual demand for the area
for conversion were considered:

Annual Demand Calculated Using NGN Peak Demand Figures
Using NGN peak demand data and the appropriate turndown ratios it is possible toderive a peak annual network demand for the conversion area. The annual demandusing this methodology would be 9,904 GWh (9.9 TWh or 2,976 million Scmh).
If this hypothetical peak year is plotted against actuals for the last five years (seeChart 2.5) it becomes clear that using this figure would provide an annual demandsignificantly in excess of that required. This is because using the peak demand andturn down ratios assumes every day in a year is a peak for that specific day – clearly
this is not reality. Chart 2.5 shows how using the peak demand and turn down ratios
would contrast to the actual demand used in the network for the period 2009-2015.

34

2 | Demand vs. Supply

Estimated Yorkshire LDZ peak 6 minute demand forMarch 2009 to May 2015 vs. theoretical average% LP 1:20 Peak 6 minute demand

Theoretical average LP peak 6 demand factor

Estimated Yorkshire LDZ % peak 6 minute demand

100

80

60

The diﬀerence between
the 2 lines represents
the overestimation ofannual demand

40

20

0
Mar 09Mar 10Mar 11

Mar 12

Mar 13

Mar 14

Mar 15Chart 2.5. Estimated Yorkshire LDZ peak 6 minute demand for March 2009 to May 2015

The NA models used to produce this value were designed primarily to provide
accurate results under conditions of 1 in 20 peak demand. As the bulk of the year has
a demand level significantly less than this, the model will diverge from the actual as
assumptions regarding off-peak industrial and commercial loads become less valid.
As a result, it was considered that utilising the NGN model to derive overall annual
demand was not an appropriate method. Therefore, for the area of conversion arobust way to determine the annual demand was required. This is necessary to size
the inter-seasonal storage, the SMRs (for hydrogen production) and understanding
the volume of carbon dioxide likely to be produced and sent to long-term storage
under the north sea.

35

2 | Demand vs. Supply

Annual Demand Derived From Middle Layer Super Output Areas(MSOA) Data
In order to do this two data sets were acquired:yy Postcodes for all properties which are located within, or partly within, thearea of conversion. These were acquired through a rigorous process of visualcomparison with NGN network maps.
yy Annual gas demand against MSOA was acquired from the Office for National
Statistics. DECC collect and publish annual GB gas use on the basis of such
MSOA data. This data is primarily based upon ‘cleaned’ Xoserve billing data.
This is the large database that ties 23 million GB consumers with individual gas
suppliers. This MSOA information is accepted by DECC to have an uncertainty ofbetter than +/-5%. DECC provided the demand data for these MSOA areas for theyear 2013. An example of an MSOA area is given in Image 2.1.
Having obtained this data the postcodes werethen meticulously cross-correlated with the
118 MSOA areas that include Leeds and thesurrounding area. The percentage of each
MSOA that fell within the conversion zone
was then estimated. This was often 100%, (i.e.
the whole MSOA fell within the conversionarea), sometimes 0%, (i.e, the whole MSOA felloutside the conversion zone), or sometimes a %had to be judged. In practice, both postcodesand MSOA maps were used to assist with thisprocess, as the percentage was based upon
property numbers rather than simple landarea. This was carried out separately, for both
domestic and non-domestic demand to reflect
the DECC data.
Table 2.2 lists example MSOA districts
and shows how this was adjusted against
postcodes in the area of conversion.

Image 2.1. MSOA Area Example

36

2 | Demand vs. Supply

MSOA
Code

Domestic
Consumption(kWh)% of Area
WithinConversion
Area

Adjusted
Domestic
kWh

Bradford 001

E02002183

42,677,527

1

426,775

Bradford 003

E02002185

41,325,136

100

41,325,136

Bradford 005

E02002187

48,800,644

85

41,480,547

Bradford 010

E02002192

67,792,479

1

677,925

Bradford 013

E02002195

48,855,082

1

488,551

Bradford 017

E02002199

39,920,814

40

15,968,326

Harrogate 018

E02005778

19,328,832

10

1,932,883

Harrogate 021

E02005781

37,555,864

2

751,117

Leeds 001

E02002330

51,748,947

00

Leeds 002

E02002331

37,702,77800

Leeds 003

E02002332

33,766,456

100

33,766,456

Leeds 004

E02002333

50,165,174

100

50,165,174

Location

Table 2.2. MSOA Examples

DECC collates industrial and large commercial meter readings (> 70 kW) and thesubset for the area of conversion was extracted and added to the MSOA domestic
consumption to give a total annual demand for the area of conversion in 2013. At theend of this evaluation process, the annual demand was determined by dividing thetotal kWh for the year by the number of hours in the year, as shown below.
Total demand in the area of conversion in 2013 = 5,940,000,000 kWh (6 TWh)
Number of hours in a year = 8,760
Average demand (2013) = 678,000 kW
Average demand (2013) = 678 MW (c.204,000 Sm³ hydrogen)

Average annual demand for thearea of conversion: 6 TWh/year (678 MW)

37

2 | Demand vs. Supply

We need to be aware that the figure of 678 MW is the average demand for Leeds,
specifically for 2013. 2013 had an average temperature of 9.4 °C against an annual
average, since 1977, of 9.7 °C. This annual average temperature has been calculatedusing data from the ‘Sheffield weather page’ which has published an average yearlytemperature for Sheffield since 1977. Leeds does not have an equivalent data set forannual average temperature. However, noting the close proximity of the two cities(35 miles centre-to-centre), Sheffield’s data set has been considered adequate forthe analysis.
Visual inspection of the Sheffield average annual temperature data since 1977 shows
annual temperatures drop below 8.9 °C very rarely (twice in 30 years to 8.7 °C), i.e.
0.5 °C below average for 2013. Analysis of temperature variances for the domestic
heating season in the last 30 years, (i.e. just considering average annual temperature
for Autumn, Winter and Spring) returns an average temperature of 9.2 °C, less than
0.2 °C below 2013. A design condition of 8.9 °C, as the average annual temperature
was therefore chosen to calculate ‘worst case conditions annual demand’ over the
past 30 years (for Leeds and Sheffield). This is equivalent to 0.5 °C below 2013 or 0.8 °C
against the long-term annual average temperature of 9.7 °C.
This is summarised in Table 2.3.
2013 Annual
Average Temperature(Sheffield)

Annual Average
Temperature forthe Last 30 Years(Sheffield)

Coldest Annual
Average Years(Sheffield)

9.4 °C

9.7 °C

8.9 °C

Table 2.3. Sheffield Average Annual Temperatures

Having a design condition average annual temperature of 8.9 °C, it is necessary toconsider the appropriate scaling factor to adjust the Leeds total average demandof 678 MW for 2013, to produce a ‘worst case condition average demand’ figure
for future demand. In order to effectively make this predication, degree days
methodology was used, (for full details of degree days methodology see Breakout:
Degree Days later in this Section).
Degree days is a recognised method of analysis used to compensate for heat energy
generation in a property from the boiler, in addition to ‘other forms of heat’ (people,
animals, lights etc.). It is accepted that for most properties, 3 °C of heat is provided by‘other forms of heat’. By way of example:
yy The outside temperature is 8 °C.
yy The average internal temperature of the house is 18.5 °C.
yy The heat required is, therefore, 10.5 °C (to go from 8 °C to 18.5 °C).
yy The reference heating temperature (the temperature the boiler needs to heat theproperty to) is, therefore, 15.5 °C (the additional 3 °C is provided by ‘other formsof heat’).

38

2 | Demand vs. Supply

Understanding the concept of degree days it is now possible to calculate therequired adjustment for the average hourly demand figure of 678 MW for Leeds in2013 as follows:

The Leeds annual average temperaturedesign criteria is 8.9 °C
Data was obtained from the www.enmanreg.org website, the official website for UK
degree day data. The data used was for West Pennines, as this was identified as
being the closest in proximity to the area of conversion. The specific degree day data
set used for West Pennines provided a 20 year average degree days figure of 2,231.
Therefore, to calculate the percentage difference adjustment between our 2013
average demand figures of 678 MW the following calculations were made:yy Total degree days: 2,231.
yy Difference in design temperature of 8.9 °C vs. 2013 average temperature of
9.4 °C is 0.5 °C.
yy 2013 adjustment in average temperature = 365 (days in the year) x 0.5 °C = 182.5 °C.
yy 182.5/2,231 = 0.082 = 8%.
This is equivalent to an 8% increase in demand over the year 2013. Therefore theamended ‘worst case average hourly year demand’ is 678 MW x 1.08 = 732 MW.

Maximum (peak) annual demand forthe area of conversion:
6.4 TWh/year (732 MW)

39

2 | Demand vs. Supply

Breakout: Degree Days
Degree Days is the UK recognised method for determining heat requirements over a
year. Simplistically it works as follows:yy Properties in the UK are on average heated to 18.5 °C (over the entire property).
yy 3°C is provided by ‘other forms of heat’ (people, animals, lights, cooking etc.).
yy A boiler will be required to heat the house to 15.5 °C from the outside temperature. As an
example to calculate the ‘Degree Days’ for a given week:
Day

Mon

Tue

Wed

Thu

Fri

Sat

Sun

Average Outside
Temperature (°C)

16

10

12

11

10

15

17

Degree Day, (i.e. Boiler
Required Heat to 15.5 °C)

0

5.5

3.5

4.5

5.5

0.5

0

In this example the total degree days for the week = (0+5.5+3.5+4.5+5.5+0.5+0) = 19.5. If thecalculation for the same week every year for 20 years is made and divided by 20 it is possible
to derive the average degree days for that week, i.e. the average amount of °C that a boiler
would need to provide in heat for that particular week. For the area of conversion, the annual
degree days average (taken over 20 years) for West Pennines was used.
The degree days calculated for the one-week scenario above is 19.5. If we assume, for thisexample, that this is the average for this week over a 20 year period then in order to calculatethe ‘worst case average boiler heat requirement’ for the same week, it could be arrived at byusing the below method. Consider the coldest average week in the last 20 years for that week,
and assume it to be an average of 12 °C. This would give a degree days total for this coldest
week of 24.5 degree days.
Day

Mon

Tue

Wed

Thu

Fri

Sat

Sun

Average
Outside Temperature(°C – Average 9 °C)

12

13

11

10

11

14

13

Degree Day, (i.e. Boiler
Required Heat to 15.5 °C)

3.5

2.5

4.5

5.5

4.5

1.5

2.5

To then calculate the percentage difference from the 20 year average to the coldest
week = 24.5/19.5 = 24% difference. This difference can then be used to adjust the averageenergy demand.
It is fully appreciated that the above explanation is much simplified for the general reader,even degree day websites recommend caution regarding the complexity of the degree day
concept. More comprehensive understanding of the topic can be derived from the website
quoted earlier. The method adopted however is cautious i.e. will give a higher increase in load
than is likely to occur in reality.
Whilst there may be variances in this worst case annual average figure this would be
consolidated as part of the detailed design but is considered in the right order of magnitude
for the stage in this project. Noting production capacity of the proposed SMR’s significantly
exceeds annual demand.

40

2 | Demand vs. Supply

2.1.4. Summary of Demands
Demands have been calculated for the area of conversion and can be summarised
as follows:
yy Average 2013 yearly demand = 678 MW (derived from DECC data).
yy Maximum peak yearly demand = 732 MW (temperature corrected DECC data).
yy Maximum peak hour (18:00) demand = 3,180 MW (NGNs 1 in 20 peak hourdemand for the area of conversion).
yy Maximum peak day demand = 2,067 MW (derived from NGNs 1 in 20 peak hourdemand design parameter).
yy Total average yearly demand = 5.9 TWh.
yy Total peak year demand = 6.4 TWh.
As expected, if the NGN values (used to design the network) are used to calculate
the annual demand, the value is circa 50% larger than that from the DECC data but
it is important, going forward, that major items of capital equipment (e.g. SMR plant)
are not oversized. As such annual demand has been determined using MSOA data,
whereas peak demands have been established using the networks 1 in 20 peak hourmodelling results.

41

2 | Demand vs. Supply

Breakout: Units of Energy Measurement
For those used to dealing with different units, the maximum peak day demand of
2,067 MW equivalent units are:yy 2,067 MJ/s or 1.7 million Therms/d.
yy Hydrogen is 52.5 tonnes H₂/h.
yy 521 MMSCFD of H₂.

The yearly design demand equivalents of 732 MW are:yy 6.4 TWh/y, 23 PJ/y, 551 thousand tonnes oil.
yy Hydrogen is 163,000 tonnes/y, 217,900 Sm³/h, 206,500 Nm³/h.
yy 185 MMSCFD of H₂.

The gas industry works in standard cubic meters rather than kilowatts.
A referenced standard cubic metre or Sm³, is a cubic metre of natural gas at 15 °C,
1 atmosphere pressure (101.325 kpa).
International reference normal cubic metre, Nm³, which is gas at 0 °C and101.3 kpa (1.01325 bar). The difference is 5.5% less energy per cubic metre atstandard temperature.
In this study, the High Heat Value (HHV or GHV) used for natural gas used is39.5 MJ/Sm³ and for hydrogen is 12.10 MJ/Sm³. The hydrogen mass-energy content is141.87 MJ/kgHHV or 39.4 kWh/kg. The report default reference is to HHV rather thanLow Heat Value (LHV or NHV) figures. Some process designs typically use LHV values
with hydrogen 120 MJ/kg LHV. A watt is a joule/second. (W = J/s)yy To convert kWh to Sm³ of natural gas: Y kWh x 3.6/39.5 = X Sm³.
yy To convert kWh to Sm³ of hydrogen gas: Y kWh x 3.6/12.10 = X Sm³.

42

2 | Demand vs. Supply

2.2. Supply System Characteristics
2.2.1. Energy Demand for the Area of Conversion
The demand requirements for hydrogen for the area of conversion are to match thedemand parameters established in Section 2.1, these were:yy Average 2013 yearly demand = 678 MW (derived from DECC data).
yy Maximum peak yearly demand = 732 MW (temperature corrected DECC data).
yy Maximum peak hour demand = 3,180 MW (NGNs 1 in 20 peak hour demand forthe conversion area).
yy Maximum peak day demand = 2,067 MW (derived from NGNs 1 in 20 peak hourdemand design parameter).
yy Total average yearly demand = 5.9 TWh.
yy Total peak year demand = 6.4 TWh.

43

2 | Demand vs. Supply

2.2.2. Choosing the Production and Storage Mix
Having determined the energy demand requirements for the area of conversion
both in terms of overall demand but also inter-seasonal and intraday variations the
project team needed to establish what the appropriate mix of hydrogen production
capability and storage should be to meet these energy requirements. To do this a
combination of hydrogen production through Steam Methane Reformation (SMR) andsalt cavern storage was selected (see Section 2.3 to 2.6 for details and justification).
Intraday storage is required to compensate for the slow turndown rates of the
primary hydrogen production facility (SMRs) which are unable to match the intradayswings in demand, e.g. low demand at 02:00 high demand at 18:00. Inter-seasonal
demand is required to match the significant swings in demand that occur between
winter and summer as domestic heating is turned off.
Average demand is met by the primary hydrogen production process. Choosing theminimum production capacity cannot be less than the design average for the year of
732 MW. A production capacity to match the peak day (2,067 MW) or the peak hour
(3,180 MW) requires significantly more investment and is unpractical. To do this would
require a production facility which is sized at over four times the average demandrequirements (3,180 MW vs. 732 MW).
The storage capacity is more complicated as storage is characterised by:
1. Flow, i.e. fill and empty fast enough to meet the variation in demand not met
by changing the primary production of hydrogen. Flows are a function of thechosen storage technology and sizing.
2. The amount of energy stored, Typically the amount of storage is expressed as apercentage of the whole energy demand over the year or the number of days ofaverage demand.
For example in our case the design average demand is 732 MW.
So say 40 days of that demand is 40 x 24 x 732= 702,720 MWh.
Also, as average yearly demand is 5.9 TWh.
The storage is 12% of demand.

44

2 | Demand vs. Supply

The trade-off between primary production and storage is best depicted in Chart
2.6. This shows required storage capacity in days of average primary hydrogenproduction versus the percentage of overcapacity (amount of production above
732 MW) for the five winters 2009/10 to 2014/15. Any supply combination of primaryhydrogen production and storage above the line will satisfy the demand requirement.
Closer to the line is cheaper, but needs more provision for high availability, further
away from the line is more expensive but more secure to unforeseen events.
Minimum days storage against H2 production to meet demand
Minimum days storage
140
120

Days

100

Safe design area
ensuring security of supply

80
60

Design point
40
20

This would be primaryhydrogen production of
732 MW with no storage

0
1.00

1.10

1.20

1.30

1.40

1.50

1.60

1.70

1.80

1.90

2.00

Multiples of design demandChart 2.6. Minimum Days Storage Against H₂ Production to Meet Demand

The choice of design point is also affected by the relative cost of production, storage
characteristics and infrastructure capital cost. It is further discussed in the SMR
and storage Sections 2.3 to 2.6 and would be revisited as part of a detailed design
process. Initially, the design point shown above is selected for a basic overcapacity
for the hydrogen production factor of 1.4 (that is 732 MW x 1.4 = 1,025 MW, further
discussed in Section 2.4) and a storage capacity of 40 days.

45

2 | Demand vs. Supply

2.2.3. Summary of Supply Requirements
yy Hydrogen production capacity of 1,025 MWHHV (305,000 Scmh) provided
by SMRs.
yy Hydrogen inter-seasonal storage of 702,720 MWhHHV (40 days of maximum
average daily demand, 209 million Sm³ H₂).
yy Additional intraday storage, which together with the SMRs and inter-seasonal
storage shall supply a maximum 1 in 20 peak hour demand of 3,180 MWHHV.
yy The hydrogen production facility shall be capable of capturing CO₂ emissions
and exporting at 120 bar to a suitable CO₂ transport and storage system provided
by others.
yy Hydrogen transmission pipelines to connect the SMRs and stores to the area of
conversion area shall transport at least the peak supply requirement of 3,180 MW
to regulators that limit the distribution network pressure to not more than 7 bar.
Besides meeting the demand requirements detailed in Section 2.2.1 the above
facilities are estimated to have the following features:yy Average energy into the distribution system of 678 MWHHV x 24hrs x 365 days =6 TWh/year as pure hydrogen.
yy Gas storage of 12% of average gas energy use.
yy Capture of 1.49 million tonnes of CO₂ per year (see Section 7, Carbon Captureand Storage).

46

2 | Demand vs. Supply

2.3. Hydrogen Generation Method(Production)
History: Steam Methane Reformation (SMR)
Since the 1960s, the global technology of choice for producing large quantities ofhydrogen is the Steam Methane Reformer or SMR. Common hydrocarbon feedstocks, i.e.
the fuel for the SMR, include natural gas (methane), LPG (propane/butane) or naphtha
and this is usually dictated by neighbouring processes in refinery operations where large
volumes are needed to upgrade and de-sulphurise heavy oils. Roughly 500 large SMRs
are operational around the globe including a single train SMR operated on Teesside.
There is a limit to the size of a single twin cell reformer which approximates to an overallplant capacity of around 110,000 Nm³/h (116,000 Sm³/h) of hydrogen.
There are a number of technology providers for SMRs and the variation between
these technologies focuses on heater design to maximise energy efficiency(operating costs) and maximise run length of the fired heater catalyst tubes(circa 100,000 hours operation). They are often designed and operational in 2-3 years
and are quite standard designs.

47

2 | Demand vs. Supply

2.3.1. Hydrogen Generation Method for the
Area of Conversion
There are around 20 general H₂ production methods, but the choice of sourcefor hydrogen is dependent on the natural resources and competitive advantageof the country, the specific geographic location, and the government policy. For
example, different scales and approaches may apply. If you consider Iceland, it has
no hydrocarbons, but substantial geothermal and hydropower. Indeed, they could
develop exports of 1 GWe of power to the UK from their resources. Germany is driven
by its ‘Energiewende’ policy favouring renewable energy industrial development, andthe UK by its robust transmission grids and geological resources particularly offshore.
The end use for hydrogen can often dictate the production method, i.e. volume
required, quality, demand profile (quantity), distribution method and unit cost.
Generally industrial scale hydrogen production methods fall into one ofthree categories:
1. Electrolysis, ideally from renewable resources. This is one of the older methodsof making hydrogen and, when made from low carbon electricity, is both green
and pure.
2. By-product hydrogen from chlor alkali plants or refineries. The carbon footprintof this can be contentious. Whilst this may be a convenient additional resource it
is not considered as a generic based production source which could act as theanchor for substantial hydrogen supplies. The above options from ‘green and/or
available sources’ may be advantageous, but would be unable to provide thevolume and security of supply required for the decarbonisation of heat for thedemand in the area of conversion.
3. Steam methane reforming and the shift reaction from either natural gas or agasifier. If the latter uses renewable biomass the hydrogen has a small carbon
footprint, if coal a large footprint (without CCS).
After considering the demand profile for the area of conversion the method
selected for hydrogen generation becomes relatively straight forward. The demand
quantities are substantial (732 MW average for design capacity, that is 6.4 TWh/y,with 5.9 TWh/typical year for average costings), Alongside this there is the extreme
inter-seasonal variation, with approximately a factor of 8 between a winter day
maximum demand and a summer day minimum demand, and a factor of 30
between a winter 1 in 20 peak hour demand, (e.g. 18:00 very cold day high demand)
to a summer minimum hour demand, (e.g. 02:00 very warm day). There are only two
established ways to generate such significant volumes of hydrogen; electrolysis
and SMR.

48

2 | Demand vs. Supply

2.3.2. Electrolysers
Historically large (typically 1 to 2.5 MW scale) alkaline electrolysers were used withlocal hydroelectric power for chemicals such as ammonia production; Norsk Hydro
installed units in Norway producing 30,000 Nm³/h by 1940. They can be understoodas the reverse of fuel cells that use hydrogen to make electricity, and advances infuel cell technology open up new electrolyser options. The efficiency of energy
conversion is similar to SMRs, circa 70% (HHV), although values up to 80% havebeen achieved.
The increase in non-fossil fuel generation is renewing interest in the conversion of
low-value electricity to hydrogen, especially for transport use. Further research anddevelopment are needed to decrease capital cost and increase efficiencies, but
generally, the high value of export to the UK grid makes this the preferred option.
Curtailed electricity (when wind farms are paid not to generate) offers a theoreticalroute to low-cost hydrogen but, in practice, the hours per year during which this isavailable are currently very limited.
28 alkaline electrolysers,
type S-556 for a
production of 21,000
Nm³/h H₂ and 10,500
Nm³/h O₂ in Zimbabwe.
www.iht.ch In use for over
35 years since built in 1973.
(1.9 t/h, 74 MW, 2.6 MW
each H₂ HHV basis)
Image 2.2. 21,000 Mc³/h H₂
Electrolysis Plant49

2 | Demand vs. Supply

Given that a typical large alkaline electrolyser has a cost of circa £0.7m per MWeor an efficient Polymer Electrolyte Membrane (PEM) electrolyser has a cost of circa£1.1m per 1 MWe, excluding installation and civils costs, bulk hydrogen production
via electrolysis for the area of conversion, it was not considered practical for thefollowing reasons:yy Bulk grid electricity at 6 p/kWh results in about 10 p/kWh for hydrogen at theelectrolyser, without storage and transmission costs. This is expensive hydrogen.
yy To produce 6 TWh of decarbonised electricity to subsequently turn intohydrogen would require the generation of decarbonised electricity on a hugescale. As an example, the 630 MWe London Array wind farm covering a 100 km2
area, currently one of the largest offshore in the world, has a yearly output of over
2 TWh. Taking account of the 20-30% efficiency loss across the electrolyser aswell as the design point hydrogen production demand of 1,025 MW, if hydrogenfor decarbonising the area of conversion was produced via electrolysis it would
require four to five London Arrays. To match wind production that is about 1,000 x
2.6 MW electrolysers.
yy Assuming electricity was available as required 400 x 2.6 MW electrolysers would
be needed to meet the design point hydrogen supply of 1,025 MW.
yy Land footprint considerations for both the decarbonised electrical generation
and associated electrolysers would be significant.
yy Due to the variability and intermittency of wind power significantly more storage(possibly by a factor of three) would be required vs. the SMR solution.
yy Significant amounts of new electrical transmission and distribution infrastructure
would be required if the grid was required to meet the heat load as well as
power demand.
Whilst not economic or low carbon when supported by the current deep pool of
the UK electricity grid, electrolysers can remain an option in a portfolio of hydrogen
supply in a hydrogen distribution system (see Section 4, Gas Network Conversion).
They may be used for electrical system balancing converting constrained electricalenergy to hydrogen for use in a future hydrogen grid and might also provide a loadbalancing function for nuclear power stations.
As a result, the use of electrolysers as the anchor load for the area of conversion was
not considered a practical option.

50

2 | Demand vs. Supply

2.3.3. The Steam Methane Reformer
Since the 1960s, the technology of choice for producing large quantities of hydrogenis the Steam Methane Reformer or SMR. Steam methane reforming can utilise a wide
range of feedstocks, including refinery offgases, LPG and light distillates (naphthas).
Fuel for the SMR would ideally be a low-value waste offgas, but if this is not available
natural gas is commonly used.
Natural gas is widely used as both feedstock and fuel and requires significantly lesspretreatment than alternatives and is typically available at high pressure such thatno feed gas compression is required. The overwhelming commercially preferredreforming option is to use natural gas in an SMR to produce large volumes ofhydrogen at low cost.

Image 2.3. A Typical SMR Plant – Picture Image 2.4. Existing BOC 36.4 MMSCFD (c. 150 MW) SMR
Courtesy of BOC
at Teesside

The existing SMR plant at Teesside consists of two twin cell reformers but has acommon feed gas pre-treatment and syngas cooling train. There is a limit to thesize of a single twin cell reformer which approximates to an overall plant capacityof around 110,000 Nm³/h of hydrogen. More typically, though, the size of SMRs forrefinery operations are in the range 150-250 MW. The largest SMR designed to dateby Amec Foster Wheeler has a capacity of 110,000 Nm³/h (equivalent to 338 MW)
and this is limited by the physical size of equipment.

51

2 | Demand vs. Supply

Without space optimisation the overall footprint of the multiple required SMRs is
about 445 m x 665 m including access and utilities, similar to a large power station,with vents about 50 m tall. The Terrace Wall reformers are taller in structure (typically
27 m high) but occupy a small footprint. Routine operations are likely to be remote,with a shift maintenance team on site plus service providers for major maintenance.
The SMR hydrogen generation option was selected for the project for thefollowing reasons:yy The high energy output (typical 250 MW per unit) versus the demand
732 MW criteria.
yy A proven commercial technology.
yy A small footprint (versus other options).
yy Availability of feedstock.
yy Ability to add carbon capture using by-product steam from the SMR to export
to carbon capture and storage in the region (see Section 7, Carbon Captureand Storage).
The SMR, therefore, represents local and established technology at the right scale
for the initial design study for Leeds.

52

2 | Demand vs. Supply

Breakout: Energy balancing in the UK
Natural gas is a high purity feedstock with low sulphur content and therefore pretreatment of the feedstock is simple. The gas is preheated using waste heat from theoutlet of the SMR to circa 350-370 °C and passed to a desulphurisation reactor. This
traps all sulphur present in the feedstock which would otherwise poison the mainreformer catalyst. The gas is combined with an excess of steam in a ratio of 3:1 andenters the reformer catalyst tubes at the top of the firebox. The firebox is fired by purgegas (offgas/tailgas) recovered from Pressure Swing Adsorption (PSA) technology,
supplemented with make up fuel gases. This heats the reformer catalyst tubes, rapidly
reforming the natural gas in the presence of a nickel-based catalyst which facilitates
the main reactions.

Radiant Section of an Amec Foster Wheeler Terrace Wall Reformer
The gas leaving the bottom of the reformer fired heater is in excess of 800 °C and must
be cooled to prevent loss of hydrogen yield. This is achieved by introducing steam at
high-pressure circa 40-45 bar. The synthesis gas (or syngas) as it is now, contains H₂,
CO and excess water. The synthesis gas passes through a second catalyst bed (shift
reactor) which targets the conversion of CO to CO₂ and in doing so yields additionalhydrogen from the excess water.
After cooling to recover heat the synthesis gas is cooled in an air fin exchanger andthe excess water is condensed and removed.
The synthesis gas contains CO₂ and methane which are removed in a PSA unit toyield pure hydrogen (> 99.9% vol). The very low pressure PSA offgas which contains
unconverted methane, CO₂ and some hydrogen is recycled to the reformer firebox asfuel. The PSA offgas has a low calorific value and is fired through dedicated burner
ports. The majority of the fired heat duty is obtained by burning the PSA offgas (up to
75% thermal basis) and the balance of fuel which is used for control is natural gas. The
natural gas is burned in low NOx burners at the bottom of the radiant section.
The flue gases from the firebox pass through the convection section of the reformer
fired heater which recovers as much of the waste heat as possible.

53

2 | Demand vs. Supply

Breakout: SMR Operation
Natural gas is a high purity feedstock with low sulphur content and therefore pretreatment of the feedstock is simple. The gas is preheated using waste heat from theoutlet of the SMR to circa 350-370 °C and passed to a desulphurisation reactor. This
traps all sulphur present in the feedstock which would otherwise poison the mainreformer catalyst. The gas is combined with an excess of steam in a ratio of 3:1 andenters the reformer catalyst tubes at the top of the firebox. The firebox is fired by purgegas (offgas/tailgas) recovered from Pressure Swing Adsorption (PSA) technology,
supplemented with make up fuel gases. This heats the reformer catalyst tubes, rapidly
reforming the natural gas in the presence of a nickel-based catalyst which facilitates
the main reactions.

Radiant Section of an Amec Foster Wheeler Terrace Wall Reformer
The gas leaving the bottom of the reformer fired heater is in excess of 800 °C and must
be cooled to prevent loss of hydrogen yield. This is achieved by introducing steam at
high-pressure circa 40-45 bar. The synthesis gas (or syngas) as it is now, contains H₂,
CO and excess water. The synthesis gas passes through a second catalyst bed (shift
reactor) which targets the conversion of CO to CO₂ and in doing so yields additionalhydrogen from the excess water.
After cooling to recover heat the synthesis gas is cooled in an air fin exchanger andthe excess water is condensed and removed.
The synthesis gas contains CO₂ and methane which are removed in a PSA unit toyield pure hydrogen (> 99.9% vol). The very low pressure PSA offgas which contains
unconverted methane, CO₂ and some hydrogen is recycled to the reformer firebox asfuel. The PSA offgas has a low calorific value and is fired through dedicated burner
ports. The majority of the fired heat duty is obtained by burning the PSA offgas (up to
75% thermal basis) and the balance of fuel which is used for control is natural gas. The
natural gas is burned in low NOx burners at the bottom of the radiant section.
The flue gases from the firebox pass through the convection section of the reformer
fired heater which recovers as much of the waste heat as possible.

54

2 | Demand vs. Supply

2.4. Hydrogen Supply for the Leeds
Conversion Area
Design Parameters
The area of conversion requires hydrogen production capacity of 1,025 MWHHV(305,000 Sm³/h) provided by SMRs. The supply basis of using natural gas from the
NTS is a simple application of the SMR operation described in the above box.
The design accounts for variation in natural gas quality over the year, and a typicalcomposition is used for this initial concept. The process yields pure hydrogen(> 99.9% volume) and flue gases of inert gases including CO₂. The hydrogen from the
PSA is compressed for export to either storage or immediate use via the transmission
pipelines at 40 bar. The quality of the hydrogen is suitable for heat applications as
discussed in Section 5, Appliance Conversion.
Image 2.5 is a block diagram of an SMR with an associated Carbon Capture Plant(CCP) to capture that CO₂. The CCP uses heat (steam) from the SMR to capture(typically) 90% of the CO₂ by scrubbing the flue gas in an absorber tower by contact
with MEA (monoethanolamine), a liquid which preferentially binds with CO₂. The
MEA is regenerated and re-used by heating, enabling the CO₂ to be separated,
dehydrated, and compressed for export. The process is described in more detail in
Section 7, Carbon Capture and Storage.
Vent Gas

CO₂
Capture Plant
CO₂
captureFlue
Gas

Dehydration
and Compression

CO₂
Export

CCP
Utilities

Hydrogen
Plant

SMR Steam
ExportNTS Natural
Gas Feed

SMR

HMU
Utilities

Shift

PSA

Tail Gas

Image 2.5. Simple Block Flow of an SMR and CO₂ Capture Plant

55

Electricity Import,
Export if no CCS

HydrogenExport2 | Demand vs. Supply

2.4.1. Number and Configuration of SMRs
After several iterations in SMR train configuration, the optimum number for the
H21 Leeds City Project was determined to be four parallel SMR trains of 256 MW
each. When considering the configuration of the SMRs, production reliability is ofhigh importance. Planned maintenance must be carried out typically every four years
to replace catalysts and inspect equipment for regulatory reasons. The catalysts
do not contain rare earth metals and therefore spent catalysts are replaced and notregenerated. This replacement and inspection work takes three weeks and would
be planned during the summer months when the work can be undertaken without
adversely affecting the reliability of hydrogen supply.
In a four train SMR configuration, the design can be optimised to provide two PSA
units for the four SMRs.

SMR#1
CCU#1
Feed
Pretreatment
SMR#2
CCU#2

SyngasCooling

PSA

PSA Oﬀgas (Recycle)
SMR#3
CCU#3
Feed
Pretreatment

SyngasCooling

Hydrogen

PSA

SMR#4
CCU#4

CO₂
Compression

Storage

Image 2.6. H21 Leeds City Gate SMR Train Configuration

Indicatively future design development may indicate an overall site footprint ofcirca 10-20 hectares for this production facility.

56

2 | Demand vs. Supply

2.4.2. Production Output Flexibility
One of the most important drivers for this study is to propose a design that achieves
as close to 100% overall availability as reasonably practicable. In order to do thiswithout relying on storage of hydrogen would require over-capacity to be installedin the SMRs. Moreover, the daily demand profile is such that having no hydrogenstorage isn’t technically viable because the SMR output cannot be changed rapidly
for mechanical and safety reasons.
SMRs have a good turndown capability and can be designed so they are able tooperate down to 30% design output. The total natural gas flow varies non-linearlywith hydrogen production rate. Most of the natural gas is consumed to producehydrogen and this is a linear relationship. However in order to maintain reaction
temperatures, the burner fuel consumption flat lines below 70% turndown andtherefore impacts overall efficiency.
SMRs are able to increase and decrease output at a maximum of 5% of design
capacity per hour. In addition, restarting an idled SMR from cold is a relatively slow
process and takes around 24 hours. This is because the refractory lined firebox within
the SMR cannot be heated up rapidly without risk of mechanical damage. During
this 24 hour period, fuel is consumed but no hydrogen is produced and this has
significant operating cost if performed on a frequent basis. For mechanical reliability
purposes, the SMRs should not be started and stopped more than a few times
per year.
Based on these two design parameters it is clear that the daily demand profile
cannot be met by the SMRs on their own and some reliance on storage will be
required to smooth the peaks and troughs in demand. The aim of hydrogen storage
should be a rapid response (minutes) to provide the time needed to ramp up/down
reformer production capacity. Reformer production capacity should, therefore, be
considered as a function of seasonal demand, keeping stopping and starting of
SMRs to a minimum.
In winter all four SMR trains would need to be online and operate near maximum
output. In summer a minimum of two SMR trains would be online and operate ataround 70% of their individual output capacity. The spare capacity in summer isuseful because this can be utilised to top up storage prior to a maintenance event.
Also the two idled trains will be offline for a longer period and there is less likelihoodof frequent stop/starting which is undesirable. The annual average operating mode
for the facility is three trains working at 90% output. This configuration of SMRs allows
reformer outputs between 70-100% to meet the seasonal demand requirements.
These parameters ensure the SMRs maintain operation in their most efficient
output window.

57

2 | Demand vs. Supply

Chart 2.7 shows the SMR supply profile against the demand profile (as defined in
Section 2.1) with the maximum output from four, three, and two SMRs operating
between 70-100% of each unit’s 256 MW capacity.

MWh

Demand and SMR Production Proﬁles MWh/day

45,000Leeds H₂ demand MWh/day

Max SMR production MWh/d

Min SMR production MWh/dModelled SMR production with stores

Out ofstorage

40,00035,00030,0004

25,00020,0003

15,0002

10,0005,000

0Jun 10

Numberof SMRs
in useIntostorage
Dec 10Jul 11

Jan 12

Aug 12

Feb 13

Sep 13

Apr 14

Oct 14

May 15Chart 2.7. SMR Supply vs. DemandChart 2.7 shows that four SMRs provide a sensible capacity to match the foreseen
supply requirements, minimising the number of shutdowns and enabling operation in
their most efficient range. The period where all SMRs are online is only about 50% of
the year.

58

2 | Demand vs. Supply

A detail of the 2013 winter, the largest demand for winter storage, is shown below.

MWhDemand and SMR Production Proﬁles MWh/day
40,000Leeds H₂ demand MWh/day
Minimum SMR production MWh/d

Max SMR production MWh/dModelled SMR production with stores

35,00030,0004 SMRs at 1,025 MW= 24,600 MWh per day

4

25,000Out ofstorage

20,00015,000Into
storage

10,0005,000

0
Sep 12

Nov 12

Jan 13

Feb 13

Apr 13Chart 2.8. 2013 Winter Storage Demand59

Jun 13

Jul 13

Sep 13

2 | Demand vs. Supply

2.4.3. SMR Conclusions
The SMR configuration chosen for baselines cost comprises:
yy Four SMRs each of 256 MW capacity.
yy Associated utilities and compression to deliver 99.9% pure hydrogen at 40 bar.
yy Integrated carbon capture to capture 90% of produced CO₂ for export at 120 bar.
The plant can operate without CO₂ capture.
yy An overall site footprint of circa 10-20 hectares per GW.
yy Whilst can provide a flexible output production level through both ‘turndownand off-line capability there is still need to provide storage for inter-seasonal andintraday demand profile management.
yy An average year would see production of:—— 5.94 TWh (5.9 million MWh, 151,000 tonnes, 1,770 million Sm³) of hydrogen.
—— 1.5 million tonnes of CO₂.

60

2 | Demand vs. Supply

2.5. Storage – Balancing Supply
and Demand
History: Salt Caverns
Salt caverns are washed voids in deep geological strata of salt, typical of those seenin the Cheshire salt mines. They are used for storage of many sorts of gases as the salt
is an excellent seal and is resilient to fractures. Underground storage of natural gas indeep saline formations is already undertaken in the region at Attwick/Hornsea andAldborough, and the storage of hydrogen is proven at scale in the UK. Three caverns
are licensed for operation on Teesside. Each cavern is 70,000 m³. Operated by SABIC,the facilities support hydrogen distribution to chemical plants in the Teesside chemicalcomplexes and have done so for over 30 years. The caverns operate at 45 bar at a
depth of 400 m with a total storage tonnage of 700-1000 tonnes and are adjacentto the BOC SMR. The quantity of hydrogen stored in any one cavern is dependent its
pressure (which is, in turn, a function of depth) and size of the washed cavern on thestrata which determines the design pressures used in the store.
Salt caverns are secure stores given the high tightness of the salt rock mass, relatively
low unit construction costs and the small footprint required above ground. A typicalstore is above 100,000 m³ in geometrical volume and up to 200 bar maximum
operating pressure.
The technology isdirectly comparable tothe storage of natural
gas for seasonal loadbalancing, shut-downreserve, reservedfor extreme weather
conditions, and as a
trading reserve.

Image 2.7. Salt Dome Salt Cavern

Image 2.8. Salt Caverns At Teesside

The Praxair hydrogen storage cavern facility at the Moss Bluff salt dome in Texas is
integrated into Praxair’s 310 mile hydrogen pipeline, serving more than 50 refineries
and chemical plants from Texas City, Texas, to Lake Charles, Louisiana. This facility
has a storage capacity of 70 million Nm³ and a working capacity of 40 million Nm³. It
is a cushion gas system with a working pressure of 55 to 150 bar. The maximum fill rateis 2 million Nm³/day, with the withdrawal rate being storage pressure dependent. To
put the scale of these types of caverns into context, the Eiffel Tower could fit inside asingle cavern.

61

2 | Demand vs. Supply

2.5.1. Design Parameters for Hydrogen Storage
The hydrogen supply analysis in Section 2.1 determined a design point for the areaof conversion that requires a hydrogen inter-seasonal storage of 702,720 MWhHHV(40 days of average daily demand, 209 million Sm³ H₂) and additional intraday
storage. These two forms of storage (inter-seasonal and intraday) together with the
SMRs and toned to supply a maximum day demand of 2,067 MW and a 1 in 20 peakhour demand of 3,180 MW.
Natural gas storage is an established method to assist in matching supply todemand. The same issues of managing variations in demand to basic gas production
apply to hydrogen for Leeds.
With the selected SMRs and given the need to be very secure about the supply to
Leeds, the design of the system looks to closely tie the primary production assets
with the storage assets to ensure security of supply of gas to match demand. Having
established the SMR train configuration and hydrogen production facility capacity
it is important to now understand the associated storage requirements to allow theoverall system to match the intraday and inter-seasonal demands. A by-product of
this is that:yy The hydrogen stores will effectively add to the UKs overall gas storage.
yy The SMR operator can source some lower cost natural gas in the summer.
yy The profile of the export CO₂ remains relatively constant throughout the year,
certainly more constant than would be the case for some power stations.
The north east of England is an area with good and proven storage assets. In
particular, proven types of geological storage used for natural gas can be considered
for hydrogen storage. The potential is also present to repurpose natural gas
storage for hydrogen. Gases, including hydrogen, are also stored in vessels, either
in compressed and or liquefied states, and new technologies are being developed
for hydrogen bound into matrices. However, this applies to smaller volumes andnot even the most cutting edge university research large scale solid state storage
competing at the inter-seasonal scale.
When considering the requirement for intraday versus inter-seasonal storage wemust consider the overall energy use of the system to store and then extract thegas. In a sub optimised design, the inter-seasonal store may be able to also act as
an intraday store. This would require significant amounts of additional compression
into inter-seasonal caverns operating at circa 200 bar vs. smaller intraday caverns
operating at between 20 and 60 bar. It may be the case that on the detailed design
a more optimised intraday option than the one presented in this report could beavailable utilising pressurised containers around converted cities. For example linepressure containers may be able to meet the ideal intraday storage requirements,
but location and safety considerations could prove prohibitive for this option. To put
this option into context, to store the volume required for the intraday profile in thearea of conversion at transmission pressure would require approximately 31 km of
56 inch pipe.

62

2 | Demand vs. Supply

2.5.2. Methods of Storage
There are in effect three deployed storage technologies applicable to hydrogen.

Storage of Gaseous Hydrogen in Pressurised Containers
Scaled up from gas cylinders at 125 bar to 800 bar high pressure storage, down
to 12 bar for scales of up to around 150,000 Nm³ of H₂. Such storage would only
be relevant for intraday storage. Location and safety considerations could prove
prohibitive to this option. This technology is inappropriate for bulk hydrogen.

Storage of Liquid Hydrogen in Refrigerated Containers
Typically used for rockets, it is relatively expensive to liquefy but is an option
for shipping, similar to shipping LNG, although the liquefaction of hydrogen isconsiderably more complex.

Storage of Gaseous Hydrogen in Underground Formations
With ambient temperature and pressure related to geological conditions. Storage indepleted hydrocarbon fields would require other process treatment, not just waterdew point control. The hydrogen product must be free of contamination from waterand hydrocarbon fluids.
Whilst geological storage is the usual high volume option it requires the rightgeology. There are a number of techniques including depleted hydrocarbon fields,
aquifer formations and solution mined halite/salt caverns. In the north of England, it
is salt caverns that offer the best solution as they are extremely gas tight and the salt
is inert in contact with the hydrogen. In operating a salt cavern the stored gas can be
maintained at a lower pressure range by varying liquid (brine) volumes in the cavern,
or by a cushion gas limiting the minimum storage pressure.
As part of a detailed design for the project, the choice of brine or cushion gas
should be further examined. If the storage facility were to be supported with brineas the cushioning fluid (a fluid which is used to drive the gas out of the cavern) thenassociated brine ponds, pumps and conditioning equipment would be required,although this equipment could be the same solution as that used to mine newcaverns in the first place. However, the choice at this stage is a cushion gas design
because it is less influenced by scale, brine storage details and planning consent.
The costs are based on total costs for similar sized cushion gas stores so is areasonable approach to take at this stage of facilities definition.

63

2 | Demand vs. Supply

Conveniently the region has excellent opportunities for salt cavern gas storage.

Teesside
Leeds

Triassic saltﬁelds

Permian saltﬁelds

Image 2.9. Local Salt Deposits and Salt Cavern Storage(Extract from ETI Report)

64

Image 2.10. Local Large Natural Gas Salt
Cavern Storage (Courtesy of SSE)

2 | Demand vs. Supply

2.5.3. Size of Storage
For the inter-seasonal storage (totalling 702,720 MWh) the flow rates in and out of thestore, and the rate of change of flow rates are important design parameters. Chart 2.9
shows the flow in MWth per day in and out of the store contrasted with the design
supply to Leeds and the production from the SMRs.
Demand and Seasonal Storage Changes MWh/day

Leeds H₂ Demand MWh/day

To/From Seasonal Store MWh/day

SMR Production MWh/day

Thousands

50
Additional demandrequirements met byinter-seasonal storage40

SMR peakoutput

30

20

10

0

-10

-20
Jul 10Surplus supply into
inter-seasonal storage
Dec 10Jul 11

Jan 12

Aug 12

Feb 13Chart 2.9. Demand and Seasonal Storage Changes MWh/day

65

Sep 13

Apr 14

Oct 14

May 15

2 | Demand vs. Supply

This illustrates how the inter-seasonal store works with the SMRs to deliver the
daily demand.
yy The modelled maximum energy into the store is 16,343 MWh over a day, seen in
July 2011 in Chart 2.10.
yy The maximum withdrawal is 25,013 MWh modelled from the 1 in 20 year
peak demand, reference earlier Section 2.1. That defined peak day demandof 49,608 MWh for that day is an average of 49,608 / 24 = 2,067 MW, met by
1,025 MW of SMR production, and 1,042 MW from the inter-seasonal store over
24 hours, a total of 1,042 x 24 = 25,013 MWh from the store.
The inter-seasonal storage fills up during spring and summer, and discharges over
winter, as detailed in the following profile for 2013.

2013 Demand and Seasonal Storage Changes MWh/day
Stored gas
reduces over time

Stored gas
reﬁlls over spring

Gas storenearly full
800

40

700
30
600
20
500

400

10

300
0
Oct 12

Dec 12

Feb 13

Apr 13

Jul 13

Aug 13
200

-10
100

-20

0

To/from seasonal store MWh/day

SMR production MWh/day

Leeds H₂ demand MWh/day

Inter-seasonal stored working gas MWh (right hand axis)

Chart 2.10. Seasonal Storage

66

Thousands

Thousands

Gas storenearly full

2 | Demand vs. Supply

The characteristics of the inter-seasonal storage are therefore as follows.
702,720 MWh

Total capacity as design point

25,013 MWh

From store on peak day

1,042 MW

From store peak day average

1,607 MW

From store max flow

16,343 MWh
674 MW

Into store max day during year
Into store max flow

Table 2.4. Inter-seasonal Storage

There are other store characteristics used in design such as the rate of change offlow rates, which influence the detailed design of both each inter-seasonal store andthe intraday stores.

67

2 | Demand vs. Supply

2.5.4. Managing the 1 in 20 Peak Day
The above flow rates are the average supply over a day from inter-seasonal storage.
Intraday storage is at this stage modelled as starting with zero stored, filling up
overnight, and discharging during the day to meet the load variation within a single
day. The main inter-seasonal store also has the ability to vary the amount supplied
to the area of conversion during the day, which is to discharge less than the averagerate between 00:00 and 08:00, and discharge more than average between 08:00
and 00:00, still keeping to the required average for the day whilst minimising
compression costs and reacting to demand variations.
This varying of the discharge during the day can reduce the need for the intraday
storage to meet the peak hourly flows which are typically at their greatest around18:00. This opportunity is used in the analysis of the intraday storage. For the peakday, all four SMRs are operational, having a constant output of 1,025 MW. The supply
required for a peak day hourly flows over the maximum day average flow of 2,067
MW and a maximum peak demand (circa 18:00) of 3,180 MW. Chart 2.11 show the
supply profile for the peak design day.

1 in 20 Year Peak System Design Hour MW

43

Intraday starts andﬁnishes with zero storage
Peak demand
3,180 MW

Thousands MW

3
2

SMR+Intraday+Inter-seasonal store= Peak demand

2
1
1
0
-1

00:00

03:00

06:00

09:00

12:00

15:00

18:00

21:00

24:00

Peak day demand 3,180 MWInter-seasonal store average out 1,048 MW

SMR production 1,025 MW

Intraday store ﬂow in and out, net 0 MW

Chart 2.11. Supply Profile For Peak Day Design68

2 | Demand vs. Supply

The inter-seasonal store contributes an output at an average of 1,042 MW, butvarying between 402 MW and 1,607 MW, to give a total for the day of 25,013 MWh. Its
maximum hourly delivery rate is around 18:00 as shown in Chart 2.11. This leaves theintraday store with the residual tasks within a day of:
yy Energy amounts into storage vary from 0 MW to 632 MW (02:00 in the morning
on a peak day) over the period from about 00:00 to about 08:00. The total energy
into storage is 3,892 MWh.
yy Delivering from storage 0 MW to 548 MW over the period from about 08:00 toabout 00:00. The total from storage peaks at 3,892 MWh. The peak flow ratearound 18:00 is about 548 MW.
Therefore, the intraday store ends the day with the same storage as it started with.
For the peak flow, it can contribute 548 MW.
The total at 18:00 is 3,180 MW, made up by SMRs = 1025 MW, inter-seasonal store =1,607 MW, intraday store = 548 MW.
The intraday store is able to support meeting the peak as it has been filled up
during the early hours of the day from the excess of production over demand, theproduction being the steady production of the SMRs and the decanting of gas fromthe high pressure inter-seasonal store.
Using the above information the storage parameters for intraday storage areas follows:
Minimum Storage

3,892 MWhNet Daily Flow

0 MWh

Peak Inflow Rate

632 MW

Peak Extraction Rate

548 MW

Table 2.5. Intraday Storage Meeting Peak Day Demand

Note that these reflect the peak day issues and other factors may influence somedesign details, including the relative pressure difference between the storage
pressures and the delivery pipeline pressure.

69

2 | Demand vs. Supply

2.5.5. Specific Storage Configuration
With geologically proven salt beds caverns in and around Teesside and to the east of
Leeds it is suggested storage should take the form of:yy Inter-seasonal 702,720 MWh (209,150,000 Sm³) plus.
yy Intraday 3,892 MWh (1,158,000 Sm³).
The intraday store is effectively providing the linepack that is missing whencompared to conventional natural gas designs due to the low calorific value ofhydrogen. As noted elsewhere, this linepack could be provided by running muchof the hydrogen through the high pressure inter-seasonal store, but this would be
wasteful of compression energy. Other options as noted above would be checkedagain when the project moves to the next stage.
The actual size and number of caverns have been chosen based on thefollowing factors:
yy Available depth of the salt strata, determining the viable pressure range forthe store.
yy The supply pressure of the supply to and from the store.
yy The need for cushion gas (in this case rather than brine support) to achieve theminimum storage pressure.
yy Minimisation of the compression required to inject gas to storage.
yy Flow rates in and out of storage.
yy Minimisation of the mining work; because a higher pressure store holds moreenergy per actual cubic metre than a low pressure stores.
yy Maintainability and reliability of the cavern and associated well andsurface facilities.
As can be observed these objectives are sometimes in conflict, and at this stageengineering judgement is used to determine a reasonable combination of actual size,
operating pressure range and a number of caverns for both types of stores.
yy A choice was made to have the intraday storage in Teesside where the shallower
salt and relevant operating experience is best known at that scale, and thepressure difference with the transmission pipeline is least. As only one store isessential a second store is used to ensure availability.
yy For the inter-seasonal storage to be in East Riding, east of Hull, where the samebut deeper salt is associated with existing similarly sized natural gas stores. For
the long term storage, the compression costs are less critical and minimising theactual salt cavern size is more important. The security of the stores is allowed
for with an additional cavern to ensure availability and peak use maintenance ofthe facilities.

70

2 | Demand vs. Supply

It is also worth noting that on typical days the operators have flexibility to match
supply to demand by varying the amount of production from the SMRs, the amountto or from both intraday stores, and the amount to and from any of the inter-seasonal
stores over any hour of the day.
The direct staff on site maintain the compressors and gas clean up equipment
including the disposal of removed material from the recovered gas. Power is themain consumable. The operating cost is dependent on the actual store designs andoperational choices. At this stage, a typical total operating cost is assumed.
The safe operation of both of these sorts of gas stores is well established. The
area presently used for gas storage in Teesside and East Riding show theirrelative isolation.

Image 2.11. Teesside and East Riding Underground Gas Storage71

2 | Demand vs. Supply

The chosen scale of salt caverns to support the required supply for the initial concept
costs is as the outlined in Table 2.6.
Store typeInter-seasonal

Intraday

Total

7

2

9

400,000

240,000

122,100 MWh

5,552 MWh

36,334,000 Sm³

1,652,000 Sm³

203,500,000

1,850,000

Total working
capacity (MWh)854,000

11,100865,000

Online caverns

6

1

7

Online working
storage (MWh)732,000

5,552

737,000

Location

Hull area

Teesside

No
Cavern Capacity
actual size (m³)
Working capacity each
Cushion gas allowance
total (Sm³)

Table 2.6. H21 Leeds City Gate Storage Requirements72

2 | Demand vs. Supply

2.5.6. Salt Cavern Operational RequirementsyyBreakout: Construction of salt caverns(courtesy of SSE)

yy Seawater is pumped into the 9⅝ inch
yy The leaching process continues
diameter well
for approximately 2 years
yy The seawater dissolves the salt at depth
yy When the cavern is the correctand creates brine solution
shape and size, leaching is
stoppedyy A blanket of nitrogen being progressively
raised helps to create the cavern shapeyy The cavern is ready to be filledwith gasyy The brine solution is pumped from the wellyy Gas is injected into the cavern, pushing
the brine out, a process is known as
dewateringyy The cavern is now storing gas, ready forcommercial use

yy Multiple completed caverns(Aldborough at Hull)73

2 | Demand vs. Supply

There are minor differences between hydrogen and natural gas caverns, primarily
concerning the selection of materials in the access well and the cavern head at thesurface. High pressure gas caverns function by compression and decompression
between a minimum and a maximum pressure. The maximum pressure
approximately corresponds to 80% of the initial formation pressure at the depth of thecavern roof, whilst the minimum pressure is around 30% of the maximum pressure.
For example, a design pressure of 250 bar would allow a maximum cavern pressureof 200 bar and a minimum pressure of 75 bar. The cavern always retains a volume
of gas at a set pressure to maintain cavern integrity and this ’cushion gas’ remains
unrecoverable unless removed by a fluid. This removal method is also deployedon natural gas and hydrogen stores. Gas fill rate is limited by compressor size andemptying rate by the need to avoid spalling of the inside walls.
In addition filling the cavern will require compression, particularly for deeper storage.
A halite (rock salt) formation will inevitably be wet, and if solution mined the residual
brine in the cavern takes a number of operations to evaporate and the ingress ofmoisture is also possible. Therefore, dehydration equipment will be required, in
addition to pressure raising/control and subsequent temperature control.

74

2 | Demand vs. Supply

Breakout: Energy balancing in the UK
Managing supply and demand swings in the UK has been undertaken by the gas
industry at a significant scale since the town gas to natural gas conversion. Prior tothis, most winter heating was made with coal (in rural areas) or coke (in urban areas).
In the UK we have been in the privileged position of being able to manage significant
variations in gas demand requirements, (energy buffers) by using our natural gas
reserves as our demand vs. supply swing ‘buffer’. However, as these reserves are
depleting, the UK has a growing need to develop additional storage capability. Today
this is being managed by a growing reliance on gas in the form of Liquid Natural Gas(LNG) or gas via the interconnectors to and from mainland Europe.
The chart below shows the actual gas storage as a percentage of annual
consumption for the key EU countries.
Actual gas storage as a percentage ofannual consumption for the key EU countries
29.4%

27.5%

26.1%
20.8%
16.2%
10.9%

5.3%=
19 daysaverage
supply5.3%

Denmark

FranceGermany

Italy

PolandSpain

UK

Historically, the gas industy could manage intraday (within same day demandvariations) capacity with the use of gas holders to ‘peak shave’ demand by acting as alocalised supply. The gas holders were filled during off peak hours, (ususally throughthe middle of the night) and then utilised during peak hours.
Natural gas has a calorific value approximately twice that of town gas and in
conjuction with additional storage capacity coming from transmission networks,
which have evolved over the last 50 years, the need for gas holder storage
has reduced to the point of where they are gradually being decommissioned
and demolished.

75

2 | Demand vs. Supply

2.6. Location of the Hydrogen Production
Facilities (SMRs) and Salt Caverns
Having understood the method of hydrogen production, the demand vs. supply
characteristics and optimised salt cavern configuration it is now possible todetermine the optimal geographical arrangement. In order to do this, the first things
to identify are the constraints, e.g. location of infrastructure. For the project there arethree fixed points:
1. The areas of conversion – Leeds;
2. The area where salt exists for salt cavern development; and3. The area where CCS is available, i.e. at the coast (see Section 7,
Carbon Capture and Storage).
The elements which are less fixed are:yy The locations of the hydrogen production facilities (SMRs);yy The connecting pipelines; andyy The potential location of new salt caverns within the confines of the areas withgeological salt availability.
The context of a specific set of elements also influences the further design of the
new hydrogen facilities.
yy Check on security of supply of the whole system.
yy Issues of implementation.
yy The value added as a consequence of the concept for Leeds.
In order to provide a price for the overall system design the project team needed toestablish a geographically realistic ‘conceptual design’. The final recommendation inthis report would clearly be subject to a detailed design but the project team believe
the locations are the most practically viable outcome considering all the known
parameters which will be discussed in this section of the report.
The detailed study went through a five-level mapping process:1. Defined connection points to Leeds, salt storage and CCS systems. Note that it
was found that the NTS and utilities connections were not top level drivers as theregion is well served with respect to these inputs to SMRs.
2. Local area searches covering planning and environmental sensitivities.
3. Existing pipelines and area classifications.
4. Site nominations, size and pipe access.
5. Outline options. About 23 were considered for screening.

76

2 | Demand vs. Supply

The SMR site was the most complicated facility to locate. The main features toconsider in the plant design and location is feedstock supply, power connection andsite access, the impact on the local area, control of Greenhouse Gas (GHG) emissions,
including NOxs and the other quality parameters for the hydrogen. The mostimportant is the ability to export captured CO₂ for sequestration. This combination
aims for the lowest unit cost of hydrogen to consumers.
Despite the current issues with the funding of CO₂ disposal under the North Sea, twolayouts were considered worthy of investigation:
yy The SMR+CCS and all storage near Hull with CO₂ disposal along the National Grid
White Rose line.
yy Location of the SMR+CCS at Teesside together with intraday storage, withinter-seasonal storage near Aldeburgh. CO₂ disposal through the TeessideCollective line.
Consideration of other factors made the second arrangement more favourable:
yy All new facilities have been proposed, however Teesside offers more re-use (butunconfirmed) options for intraday storage.
yy The existing SMR at Teesside offers (unconfirmed) options to assist in additional
security of supply and commissioning.
yy The existing H₂ network at Teesside offers options to test, trial and demonstrate
low pressure conversions from natural gas to hydrogen distribution, houseconversions, and appliance demonstrations.
yy The existence of new hydrogen production on Teesside may assist industrial CCS
concepts which are ongoing in the area.
yy The cost difference in pipe sizing is not a major consideration given the costbenefits of having intraday stores near the SMRs and inter-seasonal (highpressure) stores down the coast. Such a layout also enables multiple options forsmaller parts of the local distribution system more or less near the pipelines tobe served with hydrogen if that was desired in the future.
Both the Humber and Teesside areas have experienced workforces and public
understanding of power, industrial and chemical plants. The project’s discussions
with key stakeholders showed considerable enthusiasm for a Teesside location,with support from Tees Valley Unlimited and linkage to the work of theTeesside Collective.
An interface with the existing hydrogen network is not confirmed but is highly
desirable. The final recommendation in this report would clearly be subject to adetailed design but the project team believe the locations are the most practically
viable outcome considering all the known parameters further to the broad
acceptance of this report.

77

2 | Demand vs. Supply

Strategic Locational Analysis
Before trying to establish the specific locations of the salt caverns andhydrogen production facility (SMRs) it is important to firstly understand the UKs
available resources.

Teesside
Leeds

Triassic saltﬁelds

Permian saltﬁelds

Image 2.12. UK Salt Deposits andSalt Cavern Storage(From ETI Report on Hydrogen)

Image 2.13. UK Carbon Capture Availability(From ‘Strategic UK CCS Storage Appraisal Project)

It is clear from Image 2.12 and 2.13 that the east coast offers significant advantages
for the following reasons:yy The nearest coast to Leeds.
yy The largest UK salt area.
yy Significant industrial heartlands exist within this region of salt at Hulland Teesside.
yy The UKs current hydrogen caverns are located at Teesside.
yy The UKs existing SMR plant is located at Teesside.
yy There is significant carbon capture and storage availability (see Section 7, Carbon
Capture and Storage for more details).
As a result, the study was constrained to locational analysis of the hydrogenproduction facility and associated storage to near the east coast, rather than in theproximity of Leeds.

78

2 | Demand vs. Supply

2.6.1. The Location of the Hydrogen Production
Facility (SMRs)
The main factors to consider in the plant design and location are feedstock supply,
the impact on the local area, control of the embodied greenhouse gases (GHGs) andthe other quality parameters, which include the ability to export captured CO₂ forsequestration, all at the lowest unit cost of hydrogen to consumers.
The consideration of location options is critical to the overall cost and reliability ofany project. For the location of infrastructure such as in this report, there are multiple
elements to consider. Here we are considering a production unit that feeds hydrogento a network, but also to storage and rejects carbon dioxide to a CCS infrastructure. In
addition it requires a fuel route and utility connections.
Whilst several areas were considered for the location of the SMRs Teesside wasselected. As part of a detailed design, this could be revisited as Hull also offers goodpotential for hydrogen production facilities. The main reasons for the selection of
Teesside are described in the following pages.

Fuel Supply: Natural Gas
Hydrogen production via reforming requires significant volumes of natural gas
typically 1:4 by mass. Therefore, the reformer site needs to connect to a suitable
natural gas source at a suitable pressure. Typically as reforming takes place at 20-30
bar this means that any reformer must be supplied by a natural gas pipeline in
the National Transmission System (NTS) operated by National Grid or by the Local
Transmission System (LTS) operated by the Local Distribution Zone (LDZ) – in thiscase Northern Gas Networks.
Both the Teesside and Hull areas have easy access to a range of both NTS and
LTS pipelines reducing connection costs and expensive pipeline infrastructure.
In Teesside pipeline access for natural gas is already established and chemical
pipelines (ethylene) already leave the area to feed chemical sites in Hull.

Potential for Carbon Capture
Delivery points for carbon dioxide have to be assumed as no infrastructure currently
exists. Instead, we consider existing plans such as those in the Humber and Teesside
regions (Section 7, Carbon Capture and Storage). The Humber CO₂ transport andstorage infrastructure is proposed by National Grid Carbon in support of the White
Rose CCS project. The Teesside project, led by Tees Valley Unlimited, is considering
the development of a CCS network to support industry in the region under the
Teesside Collective project.
In both cases, the proposed projects aim to provide infrastructure to accommodate
regional activity, not just a single emitter. Therefore, this project considers either
location to be a viable target for consideration.
Additionally, it was considered potentially more contentious and costly to build alarge CO₂ capture pipeline to these hydrogen production facilities. It is more practicalto locate the hydrogen production facility in close proximity to CCS cutting cost for
the transportation of carbon and also planning considerations.

79

2 | Demand vs. Supply

Regional Acceptability
When considering the construction of four SMR plants regional (and public)
acceptability have to be taken into consideration. Both Teesside and Hull have vast
industrial areas and, as such, high levels of infrastructure and experience. In addition,
Teesside already has an SMR production facility and associated salt cavern storage.
Extensive stakeholder engagement has been undertaken with Tees Valley Unlimited
and there is a real appetite for the project.
Public acceptance of the project may be aided by it’s impact on regional
employment. The Tees Valley area recently lost its steel industry and therefore
has a skilled workforce ready and available should this area become a centre forhydrogen production.

SMR Plant Footprint
Whilst relatively speaking SMRs are ‘small’ industrial plant they are still not likely to
be positively welcomed in people’s back yards. Industrial heartlands such as thoseat Hull and Teesside offer the best opportunity for location when considering all
the other factors above. To put this into context Image 2.14 show the Seal Sands
industrial area at Teesside, the existing SMR and the additional SMRs required for theLeeds conversion area hydrogen demand.

Existinghydrogensalt caverns

SMRs required for
Leeds demand.
Illustrative only

Image 2.14. Seal Sands Industrial Area80

2 | Demand vs. Supply

SafetySafety constraints apply to SMRs as for all chemical plants. The location has toconsider the impact of the development on the surroundings and the environmental
factors that may impact on the development. In the case of SMRs, they generally do
not fall under the COMAH regulations in the UK (Seveso directive in EU) given thatthe volumes of single units are low in terms of tonnage of hydrogen contained in theequipment. But a multiple SMR site will have a larger inherent volume. The COMAH
designations for hydrogen are 10 tonnes for lower tier and 50 tonnes for the uppertier. This ranking applies for hydrogen storage as well, but not the pipelines which
are viewed under a different regulation. The addition of a carbon capture plant has toalso be considered. Depending on the process this may also fall under COMAH.
Therefore, the site selection must consider at this stage the impact of being classed
as a COMAH site. COMAH applies a safety case, including how to interface withneighbouring facilities and the risk outside the boundary is considered. Without
a specific process in hand at a high level, a recommended separation distance isapplied. Industry guidelines would suggest a distance from the processing unit toproperty outside of the boundary as 61 m, with further consideration given for toxic
and flammable effects. This stand-off distance is applied here to enable initial siting.

Location of the Salt Caverns
The locational selection for the salt caverns becomes relatively straight forward
based on the geology of the east coast. The geological storage of hydrogen in
the region is feasible as discussed previously. Hydrogen storage already occurs inTeesside at the Seal Sands salt field that is an extension of a wider salt layer thatreaches far to the south and eventually is utilised by the Hornsea/Attwick andAldborough gas storage facilities.
In addition hydrocarbon exploration is common south of the Humber with a depleted
field at Saltfleeby and Hatfield Moor already proposed or in use for natural gas
storage. Offshore the Rough hydrocarbon field is also converted to natural gas
storage and is the UK’s largest. Whilst the hydrocarbon facilities are still producing
they are mature and can be expected to cease production in the near future.
As discussed earlier, there are additional considerations when utilising formerhydrocarbon stores for hydrogen so they have not been used in this initial study but
could be considered as part of a detailed design or even as part of an expandinghydrogen network over time.
The chemical complex on North Tees already hosts hydrogen storage in brine
supported salt caverns at around 400 m depth up to a mass stored of 1,000 tonnes.
Assuming the implementation of the CCS network, and the ability to supply natural
gas through the NTS feeder the area would be ideal, with only a single hydrogenpipeline leaving the area.
High pressure storage for large volumes, however, would still need to be supplied in
East Riding. The available caverns on Teesside are not high pressure and so capacity
limited to meet the inter-seasonal requirements.

81

2 | Demand vs. Supply

As a result, the two intraday caverns have been located at Teesside providing theability to take advantage of part of the existing caverns. The inter-seasonal storage
could be based at Aldborough near Hull as this already has a planned ‘phase two’ inplace and represents the most viable option for the purposes of this study.

2.6.2. Summary of Locational Analysis
The facilities configuration taken forward for costing was therefore as listed below:
yy SMRs at a site in the Seal Sands and surrounding area at Teesside.
yy Intraday storage in the Seal Sands area.
yy Inter-seasonal storage in the East Riding near the coast.
yy Interconnecting pipelines (see Section 6, The Hydrogen Transmission System)
between Leeds, Teesside and Hull.

82

2 | Demand vs. Supply

2.7. Demand vs. Supply Conclusions
The demand profile for the conversion area has been robustly calculated using a
combination of NGN and MSOA data from the Office of National Statistics. This results
in an average hourly demand requirement of 732 MW. (6.4 TWh for the year).
The supply to meet these requirements has been designed based on a train of foursteam methane reformers with a combined output of 1,025 MW meeting a design of
140% capacity allowing for optimised storage size, operational flexibility, security ofsupply and maintenance requirements.
The intraday and inter-seasonal variations in demand will be managed through two
240,000 m³ storage caverns and seven 400,000 m³ storage caverns.
The hydrogen production facility will be located at Teesside along with the intraday
storage cavern. The inter-seasonal caverns will be located at Hull.
Whilst all these assumptions would be subject to a detailed design the project
team feel they are all realistic and more important technically and politically
viable. In addition, they also represent a ‘worst case’ option for pricing as they are
geographically at the extremities of the required hydrogen pipeline network (seeSection 6, The Hydrogen Transmission System).

2.7.1. Costs
The following costs for SMR+CCS reflect the full cost of the system described above,
based on existing facilities costs and high level operating costs, including energy
used to run the hydrogen production system. These require further development of
the designs to reduce the normal uncertainty of costs at this stage.
CAPEX Cost
Incurred (£m)

Cost Summary
Steam Methane Reformer Costs

395

Inter-seasonal Salt Caverns

289

Intra-day Storage

77

OPEX Cost
Year One (£m)

Carbon Capture and Storage

60

SMR/Salt Cavern Management

31

Additional Energy Used for Hydrogen Production
and Carbon Capture

48

Total
Table 2.7. Hydrogen Production System Cost Summary

83

761

139

SECTION 3

Gas Network
Capacity

Gas Rig

Liquid Natural
Gas Storage

Salt
CavernCarbon Captureand Storage

Terminal

Compressor
StationPressure
ReductionOﬀtakeCompressor
StationSection 3
Gas Network
Capacity

Steam
MethaneReformer
Salt
CavernPressure
Reduction
StationPower
StationSalt
CavernDistrict
Governor

LEEDS

HULL

Section 3 | Gas Network Capacity

3. Gas Network Capacity
The History
As explained in Section 2, Demand vs. Supply, the gas industry manages its MP
networks such that they can maintain supply to customers during 1 in 20 peak hourdemand conditions ensuring the security of supply during extreme weather. This is doneusing computer modelling software which is validated against data obtained by physicalapparatus in the field. For clarity a ‘one in twenty years, peak hour’ event indicates the
maximum hourly demand that occurs (theoretically) on the network once every 20 years. A
general misconception is that this event occurs during the coldest period in a twenty year
time frame. However, it is a point in time where not only is it cold but events also conspire
to produce the biggest draw on the network. For example, if the coldest day in 20 years
was on Christmas Day this might not generate a peak hour demand. This is because large
numbers of consumers, such as industrial and commercial customers, have a low demand
as a result of Christmas shut down periods.
The modelling used by NGN for analysing the below seven bar network, which is wherethe vast majority of customers are located, has evolved over the years and NGN now uses
the Synergi modelling software for managing and forecasting gas distribution network
demands. All UK gas networks use modelling to design and carry out reinforcements,
replacements and maintenance to ensure they meet their licence obligation for the securityof supply to gas customers. The H21 Project has used Synergi for the analysis of thehydrogen gas network and as such there is a high level of confidence in the results.

This section will explain how Northern Gas Networks (NGN) has assessed its existing gas
network capacity in the area of conversion – specifically, analysing if this network, once
converted to hydrogen, can still meet the existing 1 in 20 peak hour demand design
requirement. Simplistically are the pipes that are currently in the ground in the area of
conversion large enough to transfer the same energy demand when using hydrogen as
they currently do for natural gas?

85Section 3 | Gas Network Capacity

3.1. The Gas Industry Below Seven Bar
Planning Software
A key element to understanding the feasibility of converting the existing gas
network to 100% hydrogen was determining if the existing gas distribution network
has adequate capacity, when transporting hydrogen, to meet the same design
parameters, i.e. 1 in 20 hour peak demand.
NGN manages the below 7 bar natural gas network using a network modelling
software package called Synergi. This is used to model demand and flow data
for natural gas (predominantly methane) as this is the current gas flowing in the
networks pipes.
This software package is used to design reinforcement and replacement projects.
Reinforcement involves increasing network capacity to an area which is forecasted
to have pressure constraints due to, for example, demand growth and is usuallyachieved by laying additional mains or connecting additional sources of gas.
Replacement modelling is used, for example, to design the projects for the large
package of work currently in progress to replace 8 inch and below iron mains. It isalso used for quotations for new load requests on a five-year forecasting horizon.
Synergi models are validated as part of a regular cycle by cross-referencing theinformation in Synergi (modelled pressures/flows) with data obtained from loggers at
both sources and extremity points on the network and demand data obtained frommetering/billing via Xoserve.

Image 3.1. Screenshot Synergi

Image 3.2. Network Data Logger

To put the information held by of this design software into context, Synergi models
are populated with every below 7 bar gas main including diameter and material aswell as associated pressure reduction equipment in the network. This amounts tocirca 37,000 km of gas mains and 2,355 district governors for NGN alone.

86Section 3 | Gas Network Capacity

For the H21 Leeds City Gas project Image 3.3 shows the area considered and theextent of the gas distribution network. This is from the NGN record system forgas mains.

LP Network up to 0.075 bar
MP Network 2 bar to 0.075 bar
Above 7 bar network

Leeds

Image 3.3. Map of Leeds

8787

Section 3 | Gas Network Capacity

3.2. The Steps for Analysis
Step One: Defining the Isolation Area
To undertake the Synergi modelling the first task was to determine the area
which could practically be isolated from the existing natural gas network forconversion to hydrogen. This is particularly challenging as adjacent areas often haveinter-dependencies for gas supply between them, i.e. one area ‘feeds’ another areagas. The area of isolation needed to be defined such that any ‘disconnected’ mains,i.e. gas mains that flow between areas, do not create a problem for natural gas
supplies in the area not converted to hydrogen.
As a result of this complexity a larger isolation area than that defined in the original
concept for H21 Leeds City Gate was selected. This allowed a much more efficientand practical design. The finalised area for analysis and isolation rose from theoriginal area of approximately 190,000 meter points to 264,000 meter points
covering a population of approximately 660,000 people. The area now included theCity of Leeds and some of its suburbs, Swillington to Morley to the south of Leeds
and Pudsey to Otley/Burley in Wharfedale to the north-west of Leeds.

LP Network up to 0.075 bar
MP Network 2 bar to 0.075 bar
Wharfedale

Above 7 bar network
Harrogate

Leeds
Bradford

Halifax, Huddersﬁeld,
Dewsbury, Wakeﬁeld

Swillington/Morley

Image 3.4. Map of Area of Conversion

88Section 3 | Gas Network Capacity

Step Two: Changing the Synergi Model Parameters
Once the isolation area had been identified the Synergi model, currently configured
to model based on natural gas parameters, needed to be amended to hydrogen.
This is necessary as the physical properties relevant to modelling a gas network
utilising hydrogen differ significantly from those used to model natural gas. The
following parameters were changed in the Synergi model summarised in Table 3.1
and evidenced in the model screen shots below.

Image 3.5. Synergi Model Natural Gas Parameters

Image 3.6. Synergi Model Hydrogen Parameters

Natural Gas

HydrogenHeat content (MJ/m³)

37.26

11.98

Specific gravity

0.60

0.07

Viscosity (cP)

0.01038

0.0086

Table 3.1. Properties of Natural Gas and Hydrogen

A key consideration for the H21 Project team was the accuracy of the Synergi model
when modelling for hydrogen. To validate the accuracy and ensure NGN retained ahigh level of confidence in the results two checks were undertaken:
1. A test model was configured in Synergi using the above process and theresults were then compared and validated by tests results produced by the
Synergi software owners DNVGL.
2. Sample pipe/load combinations were set up and run using Synergi
configured to hydrogen and the results compared with those obtained using a
Mears Wheel.
A Mears Wheel was the historical ‘long hand’ method the UK gas industry used forpipe sizing design before being superseded by modern analysis software. It can still
be considered suitable for single pipe modelling.
The results of these checks gave the H21 Leeds City Gate project team a high level ofconfidence that the Synergi modelling of hydrogen was accurate.

89Section 3 | Gas Network Capacity

Step Three: Modelling the medium (blue) and low (red) pressure
networks for hydrogenOnce the Synergi model was validated for accuracy in converting from natural gas tohydrogen the next step was to produce medium and low pressure Synergi models
for the area of conversion.

National Transmission System

When considering the gas distribution system one has to consider where the‘injections points’ into the relevant pressure system are in relation to demand. If
we first consider the gas industry
pressure tiers
simplistically, each pressure tier isDistribution
Network
supplied by the pressure tier above.
Local Transmission
SystemDistribution
System38 barPressure
System
17 barPressure
System
7 bar
Pressure
SystemMediumPressure
SystemVery Large
Industrial
Customers

Low
Pressure
SystemLarge
Industrial
Customers

Signiﬁcantnumbers of
Gas Customers
Domesitc
and Industrial
Majority of
Gas Customers
Domestic
and Industrial

Image 3.7. Pressure Tier Cascade

90Section 3 | Gas Network Capacity

In reality this is a complex web of gas mains and pressures when considering a city.
The gas system does not operate as a single point for cascade as it has to manage
varying supply and demand characteristics across the city and its associatedsuburbs. If we consider the Leeds system, the medium pressure is shown in blue,
supplied at multiple points from the above 7 bar systems via Pressure Reduction
Stations (PRSs). These ‘injection points’, have been identified with blue circles on
the map.
LP Network up to 0.075 bar
MP Network 2 bar to 0.075 bar
Above 7 bar network

17 to 2 bar(Menston)

Image 3.8. Map of Leeds Gas Network Indicating PRS Locations

It is important to note that the above 7 bar (LTS) pipelines often do not terminate atthese points, they continue to supply other points of the medium pressure system
across the Gas Distribution Network (GDN) area.
In a similar manner the Low Pressure (LP) system (red), is supplied by the Medium
Pressure (MP) system via district governors, known as Pressure Reduction Units(PRUs) located extensively across the city. The LP system is designed to meet a
1 in 20 peak 6 minute demand but offers no storage capability and therefore it needs
many injection points to ensure supply can be maintained.
By way of analogy the network can be thought of as a large swimming pool whichcontains just one inch depth of water. If this swimming pool has a gigantic plug at thebottom of the pool, which is subsequently removed, a single hosepipe would not beable to maintain the water level in the pool.

91Section 3 | Gas Network Capacity

Similarly in the gas industry as the ‘plug’ comes out of the LP system (domestic users
turning on heating for example) multiple district governors (hosepipes) are required
from the MP system to maintain pressure and therefore supply.
In the area of isolation there are currently circa 120 district governors maintaining
supply to the LP system as shown with the purple arrows in Image 3.9.
TypicalDistrict Governor

Image 3.9. Map of Leeds Gas Network District Governor Locations

To produce the MP and LP models for analysis new hydrogen injection points wereincorporated into the MP system. In some instances these would be via the existing
PRU locations, while in others they would be new PRU locations taken directly fromthe High Pressure (HP) hydrogen transmission pipeline coming from Teesside.
Following these steps the Synergi LP and MP models could now be ‘run’ forhydrogen on the existing gas network for the area of isolation. These models werebased on the FY5 (forecasting demand on a five-year horizon) natural gas models
used by Northern Gas Networks. The results of this analysis are detailed below andshow, for the gas network in the area of conversion (including pipes and pressure
reduction equipment), that the MP and LP networks could supply the volume ofhydrogen necessary to meet the energy requirement for a 1 in 20 peak hour/peak 6
minute demand with relatively ‘minor’ additional infrastructure.

92

Section 3 | Gas Network Capacity

The Results
The key results from the Synergi model are pressure and velocities of the gas in themains. The design parameters used by Northern Gas Networks on the distribution
network are defined in standard NGN/PL/NP18 Policy for Network Planning (similar
policies are in use by the wider UK gas industry). For the MP and LP systems thecurrent pressure and velocity parameters are shown in Table 3.2.

SystemMaximum
OperatingPressure (MOP)

Minimum
Operating Pressure

Current
Maximum Velocity

2 bar

0.35 bar*

40 m/s

0.075 bar0.021 bar

40 m/sMedium Pressure
Low Pressure

Table 3.2. Current UK Gas Network LP and MP Design Parameters*Minimum pressure is the statutory pressure which the network should not
drop below under a 1 in 20 winter scenario. However, typically 500 mbar is therecommended minimum to allow for service design and load growth.

DG

PRU
High Pressure

Medium Pressure

Low Pressure

40 m/s

40 m/s2bar
MOP

0.35 0.075
bar bar
MOP

0.021
bar

Image 3.10. Existing Design Parameters for UK Distribution Networks

The results that follow are all based around maintaining these parameters for a
1 in 20 peak demand.

93Section 3 | Gas Network Capacity

3.3. Natural Gas to Hydrogen Conversion on
the MP (blue) Network
Pressures:
The Synergi results for the MP network within the area of conversion indicatethat pressures on the MP network running as hydrogen largely remain above therecommended minimum of 500 mbar. Results from Synergi are presented in a ‘nodal’
format, i.e. points on each pipe in the model are shown and colour coded to indicate
the pressure range they fall within for a 1 in 20 peak hour demand.
Image 3.9 and 3.10 below represent the results of the Synergi analysis for the Leeds
MP system when modelled using natural gas (the Synergi model used in the network
today) compared to the results of the analysis when modelled using the five-year
forecast energy demand data with a hydrogen gas network.
HydrogenNatural Gas

Area withpotential
pressure
problems
Image 3.11. Synergi Analysis MP Network(Pressures) – Natural Gas

Area withpressure
problems

Image 3.12. Synergi Analysis MP Network(Pressures) – Hydrogen

A red node indicates an area which would drop below the 500 mbar design
recommendation under a 1 in 20 winter conditions scenario. In the network operatingon natural gas there is one node modelling below 500 mbar. For the same network
operating on hydrogen there are 21 nodes below 500 mbar.
The model outputs in these images are based on the injection points (PRSs)
configured as they are at present. With minor amendments to these input locations(which may be required for strategic reasons) only 11 nodes below 500 mbar remain
within the MP network. To reinforce the MP to remove this pressure constraint would
require approximately 1 km of mains reinforcement.

94Section 3 | Gas Network Capacity

The difference between hydrogen with the current injection points and hydrogenwith amended injection points is shown in Image 3.13 and Image 3.14.
Hydrogen existing
PRU positions

Hydrogen amended
PRU positions

PRU injection
positions

Image 3.13. Synergi Analysis MP Network(Pressures) – Hydrogen with Existing PRU Positions

Image 3.14. Synergi Analysis MP Network(Pressures) – Hydrogen with Amended PRU Positions

The costs associated with these amended PRU positions have been incorporated
into Section 6, The Hydrogen Transmission System.

In conclusion there are no significant pressure
problems associated with converting the
medium pressure system to hydrogen95Section 3 | Gas Network Capacity

Velocities
The Synergi results for the MP network within the area of conversion indicate that
there are some velocities concerns on the MP network when converted to hydrogen.
Image 3.15 and 3.16 represent the velocity results of the Synergi analysis for theLeeds MP system when modelled using natural gas compared to the results of theanalysis when modelled as a hydrogen gas network.
It is important to understand why the gas industry has historically capped velocity
in the distribution system. Velocities in the gas network have been capped for
two reasons:
1. To reduce pressure loss, i.e. maintain extremity pressures; and2. To prevent the gas picking up significant amounts of dust in the old metallic
network which could lead to erosion of pipes and damage or malfunctions ininfrastructures such as meters or pressure reduction equipment.

Natural Gas

Hydrogen

Image 3.15. Synergi Analysis MP Network (Velocities)– Natural Gas

Image 3.16. Synergi Analysis MP Network (Velocities)– Hydrogen

In the images green represents velocities below 40 m/s, blue represents velocities
between 40 and 80 m/s and red represents velocities above 80 m/s under 1 in 20
peak hour demand conditions.

96Section 3 | Gas Network Capacity

As in the pressure modelling scenario the model outputs in these images are basedon the injection points (PRSs) configured as they are at present. When considering
the new injection points to the MP system the velocity concerns significantly
decrease. This can be seen in Image 3.17 and Image 3.18.
Hydrogen existing
PRU positions

Image 3.17. Synergi Analysis MP Network (Velocities)– Hydrogen with Existing PRU Positions

Hydrogen amended
PRU positions

Image 3.18. Synergi Analysis MP Network (Velocities) –Hydrogen with Amended PRU Positions

It is important to understand that all the modelling presented is based on the worst
case scenario, i.e. 1 in 20 peak hour demand design parameters. These worst casescenarios may only occur theoretically once every 20 years and it is important to put
into context what the velocities in the system are for the vast majority of the time.

97Section 3 | Gas Network Capacity

Table 3.3 represents the velocities in the system for a range of winter demand
scenarios (100% being a 1 in 20 winter peak hour demand). It is also important toremember that peaks in demand are also not continuous throughout a winter but
may happen for a short ‘time snap’ of two or three days over the entire winter period.
In a ‘typical’ winter (based on an average of the last six winters in the network)
demands more than 90% of a 1 in 20 peak hour demand are not common.
DEMAND LEVEL (% OF PEAK)
Velocity

100%

95%

90%

85%

80%

75%

70%

Length (m) > 40 m/s

52,08742,15537,32632,96626,99920,75814,407

Length (m) > 60 m/s

16,41812,726

9,852

7,177

3,808

1,111

510

Length (m) > 80 m/s

3,101

1,926

546

506

506

354

254

Length (%) > 40 m/s

21.77%

17.62%

15.60%

13.78%

11.29%

8.68%

6.02%

Length (%) > 60 m/s

6.86%

5.32%

4.12%

3.00%

1.59%

0.46%

0.21%

Length (%) > 80 m/s

1.30%

0.81%

0.23%

0.21%

0.21%

0.15%

0.11%

Table 3.3. Pipe Velocities by Percentage Peak Demand Level

This is represented graphically in Chart 3.1.
MP mains velocity (% of total MP mains length) at various demand levels(% of peak 1 in 20 demand)
22%

Length (%) > 40 m/s

Length (%) > 60 m/s

Length (%) > 80 m/s

Mains length above velocity / %18%

Most common winter conditions

16%
14%

11%
9%
7%

6%

5%
4%
3%
1%
100%

2%

1%
95%

0%
90%

0%
85%

0%
80%

MP demand level (% of peak 1:20 demand)

Chart 3.1. MP Mains Velocity (% of Total MP Mains Length) At Various Demand Levels(% of Peak 1 in 20 Demand)

98

0% 0%

0% 0%

75%

70%

Section 3 | Gas Network Capacity

From Table 3.3 and Chart 3.1 is it clear that the vast majority of the MP network
has no velocity problems and there are limited areas which operate above 60 m/s
or 80 m/s. These would all be easily rectified through strategic reinforcements,
or it may even be considered reasonable for the short periods of time that thesevelocities occur.
It has already been established that the pressure drop when converting the existinggas grid to hydrogen does not pose a significant problem in the medium pressure
system. Additionally as the metallic pipes in the distribution system are being
replaced by PE, dust becomes a less significant issue, as it is not produced in a PE
system. It is proposed that velocities up to 80 m/s in the MP system may well beconsidered reasonable and acceptable from an engineering integrity point of view.
Providing some additional evidence for this may be beneficial and is identified in
Section 10, H21 Roadmap, under Work Package 11. The opinion of the H21 project
team is this will not be a concern and is an acceptable parameter for the hydrogengas network.
If progressing on the assumption that 80 m/s should be acceptable in a hydrogen
network only 3.1 km of existing MP main would have ongoing velocity problems.
This is approximately 1.30% of all mains and would be easily corrected via
strategic reinforcement.

In conclusion there are no significant velocity
problems associated with converting the
MP system to hydrogen99Section 3 | Gas Network Capacity

3.4. Natural Gas to Hydrogen Conversion on
the LP (red) Network
Pressures
The Synergi results for the LP network within the area of conversion indicate that
there are several areas where pressures on the existing LP network could cause
concern. These areas would fall below the 0.021 bar standard for a 1 in 20 peak 6
minute demand. As with the MP model results, from Synergi are presented in a
‘nodal’ format.
Image 3.19 and Image 3.20 represent the results of the Synergi analysis for theconversion area low pressure system when modelled using natural gas compared to
the results of the analysis when modelled using hydrogen.
HydrogenNatural Gas

Areas withpressure problems
Image 3.19. Synergi Analysis LP Network(Pressures) – Natural Gas

Image 3.20. Synergi Analysis LP Network(Pressures) – Hydrogen

There are areas within the area of conversion already showing signs of potential
pressure problems under a 1 in 20 6 minute peak demand scenario using natural gas.
This becomes more critical when converting to hydrogen. These areas are indicatedby amber/red on the maps. Operating on natural gas there are 174 nodes modelled
at below the recommended minimum of 0.021 bar. With the network modelled ashydrogen, there are 5,394 nodes with a forecast pressure below 0.021 bar.
However, it is important to understand that the network has some options available
to reduce this deficit with minimal impact. District Governors (DG) are currently set
well below the maximum operating pressure (0.075 bar) of the LP network. This isbecause pressure and leakage are directly linked and the GDNs are incentivised tokeep leakage to a minimum via OFGEM leakage model. This is a significant driver toreducing DG supply pressures to the lowest practicable values required to supply the
network while meeting all regulatory required pressures.

100Section 3 | Gas Network Capacity

By raising the outlet pressures of all DG by 15% on the hydrogen model, which isstill within the maximum operating pressure of the LP system, the number of nodes
modelling below 0.021 bar drops to 182.
Additionally, as part of the conversion process (see Section 4, Gas Network
Conversion) there will inevitably be a requirement to install additional new DG as well
as new mains to maintain adequate supply as the network is sectorised for isolationand conversion. This addition would likely mean that the global 15% pressure increase
would not be required to restore LP pressures.
Under the current LP network configuration there are several areas that would
begin to exhibit some pressure problems following a direct conversion to hydrogen.
The scale of this problem can only be understood by determining what corrective
measures would need to be put in place to eliminate them. Within the gas industry
reinforcement schemes are undertaken every year to ensure the network canmaintain the security of supply to customers based on ever changing demands.
These reinforcements are generally in the form of pipe modifications and/or
additional supply points from the MP network. Work has been undertaken to
determine the reinforcement requirements associated with 19 of the areas wherepressure problems would occur. It is worth walking through some of these designs toallow the reader to understand the corrective actions available.

1

10
9

11
12

Image 3.21. Five Detailed Areas of Reinforcement101Section 3 | Gas Network Capacity

The following pages provide detail on the reinforcement schemes required to correct
the pressure problem areas identified on the map. For ease of orientation the blue
circles on the maps allow the reader to cross reference the satellite map location
with the Synergi output for each area. The orange rectangles indicate the areaof reinforcement.

102Section 3 | Gas Network Capacity

Area 1 Reinforcement Requirements
Reinforcement Requirements:
175 m of 125 mm diameter PE
low pressure main laid parallelto the existing main.

Estimated Cost:£36,017

Image 3.22. Area 1 Reinforcement

103Section 3 | Gas Network Capacity

Area 9 Reinforcement Requirements
Reinforcement Requirements:
New district governor (MP/LP)
150 m of 125 mm PE MP inlet.
15 m of 250 mm PE LP outlet.
320 m of 180 mm PE LP
main laid parallel.

Estimated Cost:£184,591

Image 3.23. Area 9 Reinforcement

104Section 3 | Gas Network Capacity

Area 10 Reinforcement Requirements
Reinforcement Requirements:
330 m of 250 mm PE mainlaid parallel.

Estimated Cost:£123,887

Image 3.24. Area 10 Reinforcement

105Section 3 | Gas Network Capacity

Area 11 Reinforcement Requirements
Reinforcement Requirements:
89 m of 250 mm PE maincross connection.
20 m of 90 mm PE maincross connection.

Estimated Cost:£45,641

Image 3.25. Area 11 Reinforcement

106Section 3 | Gas Network Capacity

Area 12 Reinforcement Requirements
Reinforcement Requirements:
New district governor (MP/LP).
30 m of 180 mm PE MP inlet.
10 m of 355 mm PE LP outlet.

Estimated Cost:£72,494

Image 3.26. Area 12 Reinforcement

107Section 3 | Gas Network Capacity

The total costs of reinforcement (worst case scenario based on a desktop
assessment) to correct any enhanced pressure problems when converting the lowpressure system to hydrogen are summarised below. Remember that some of theseareas could ultimately require these specific reinforcements within the natural gas
network as they are beginning to exhibit pressure problems – the hydrogen network
simply accelerates these requirements.
Area of LP Reinforcement

Cost

1

£36,0179£184,591

10£123,88711£45,64112£72,494

Sub Total (A)£462,630

Average£92,526

14 remaining reinforcements at £92,526 (B)£1,295,364

Reinforcements required (A+B)£1,757,994

Table 3.4. Reinforcement Costs

These 19 schemes (A+B) remediate approximately 50% of the nodes below 0.021 bar
and therefore if the above costs are scaled by 2.5 this should provide a reasonableindication of the costs for reinforcing the LP network. For simplicity, a total
reinforcement estimate of £5 m has been determined for the H21 Leeds City Gate
project area of conversion.

Total LP reinforcements required£5,000,000

In conclusion, it is considered there are no
significant pressure problems associatedwith converting the LP system to hydrogen108Section 3 | Gas Network Capacity

Velocities
There are no significant velocity issues which arise from modelling the LP network
converted to hydrogen. Approximately 0.02% of the total LP mains within the areaof conversion are forecast to be above 40 m/s and less than 0.001% above 80 m/s.
These lengths are easily removed by reinforcement and might be removed as part ofongoing IMRP.

In conclusion, there are no velocity
problems associated with converting
the LP system to hydrogen109Section 3 | Gas Network Capacity

3.5. Network Capacity Conclusions
There are no significant obstacles regarding network capacity to converting the
distribution system, i.e. medium and low pressure, to hydrogen. The network is ofsufficient size for the conversion to take place.
The total costs associated with undertaking any remedial measures are estimated tobe less than £5m for the LP network.
If there is a national decision to move towards a hydrogen conversion programme,
many of these projects could be incorporated into the existing IMRP with minimal
cost impact.
The vast majority of the low and medium pressure networks are being replaced aspart of the IMRP. However there will be an element of retained iron mains under thecurrent strategy. These are generally above 8 inch in diameter and/or have a zero risk
score or will not be replaced under a cost-benefit analysis assessment, (i.e. minimal
leakage history). The relative risks of transporting hydrogen, and any associatedleakage, through these mains needs to be assessed identifies a requirement toquantify the relative risk of hydrogen in these retained metallic mains against thecurrent risk of natural gas. The quantity of retained mains under the current IMRP
within the area of conversion are summarised below
Leeds LP (kms)

Leeds MP (kms)

Total (kms)< = 8 inch T1 zero score pipes

5.9

12.9

18.7

< = 8 inch Steel pipes

142.7

15.1

157.8

2 inch Pipes

47.8

0.26

48.0

> 8 to < 18 inch
non-mandatory pipes

133.2

72.3

205.5

= > 18 inch
non-mandatory pipes

21.8

26.5

48.3

Total

351.3

127.0

478.3

Table 3.5. Remaining Metallic Mains in the Area of Conversion

110Section 3 | Gas Network Capacity

Some points to consider:yy Not all mains are required to be replaced under the current IMRP.
yy If the IMRP continues in its current format, around 480 kms of metallic main
would remain in Leeds.
yy NGN currently replace circa 500 kms of metallic mains per annum so if 480 km
of mains were determined to require replacement it is a manageable amount ofadditional work.
yy These remaining metallic mains currently would not generate a replacement
project (under the IMRP) and could potentially be used to transport hydrogen(they were used to transport town gas which contains circa 50% hydrogen).
Considering the relative density of hydrogen it is likely that the risk due to aleak from a hydrogen main could be lower than that of a natural gas leak. The
assessment of risk from a gas leak is predominantly based on the likelihood of
the escaping gas ‘tracking’ (moving through the ground horizontally) into nearbybuildings. As hydrogen is less than ⅛th the density of methane (the majority
component of natural gas) the likelihood of this occurring is greatly reduced. Thisis a project identified in the Section 10, H21 Roadmap.
yy A key element of the IMRP is replacing mains in an ‘efficient’ manner. In reality
this means that less than 480 kms of mains would remain at the end of the
programme as some of these zero risk scoring mains are often replaced as partof ‘efficient projects’ or are captured as part of diversions.

111

SECTION 4

Gas Network
Conversion

Gas Rig

Liquid Natural
Gas Storage

Salt
CavernCarbon Captureand Storage

Terminal

Compressor
StationPressure
ReductionOﬀtakePressure
Reduction
StationCompressor
StationSteam
MethaneReformer
Salt
CavernSection 4
Gas Network
Conversion

Power
StationSalt
CavernDistrict
Governor

LEEDS

HULL

Section 4. Gas Network Conversion

4. Gas Network Conversion
The History
Conversion from one gas to another is not a new concept to the UK. For the first
150 years of the UK (and European) gas industry, gas was manufactured locally inmost towns and cities and injected directly into the local distribution system. There
were no transmission pipelines and individual gas companies, for example the‘Sunderland Gas Company’, were responsible for the gas supply in their area.
This manufactured gas is referred to as ‘town gas’ and, at its peak, was manufactured
using 26 million tonnes of coal and half a million tonnes of oil each year. The gas
contained up to 50% hydrogen and was distributed around many of the mains that are
still used today in the below 7 bar UK distribution system (much of which is currently
being upgraded to polyethylene).
In August 1959 an Esso/Shell exploration team discovered an enormous natural gas
field at Slochterem in the province of Groningen, Holland. This discovery led to thebelief that similar gas fields could lie under the North Sea. The British government
subsequently granted licences for North Sea oil and gas exploration. In September 1965
British Petroleum struck gas 40 miles off the coast of Grimsby, in what later became
known as the West Sole Field.
In 1962, following the discovery of the Slochterem gas field, the Gas Council began
research into the types of burners which would be suitable for use with this ‘new’
natural gas. This research was undertaken by Watson House, the Gas Councils centre
for research on appliances. In the first half of 1966 a working party was established to
study large-scale conversion and the final decision made in the summer of 1966 thatthe industry would use natural gas. This gas would be supplied directly to customers
after their appliances had been modified and was announced to the public on 21st Juneof that year.
The subsequent conversion from town gas to natural gas occurred between 1966 and1977 and included the conversion of 14 million customers and 40 million appliances, aswell as all industrial and commercial customers. The conversion programme was botha technological and logistical outstanding achievement. From initiation in 1966, by 1969
the conversion of over 400,000 domestic dwellings each year was being undertaken,
with a peak of over 2.3 million per year in 1971/72.
Reference: Charles Elliott’s ‘The History of Natural Gas Conversion in Great Britain’.

113Section 4. Gas Network Conversion

Theoretically, the town of Leeds could be disconnected from the natural gas supply
system and, over several months or years, a large team of gas fitters could convert
the city to 100% hydrogen. This approach, while technically the easiest solution, is notconsidered practical and would result in customers being without any form of gas
supply for several months or the entire network conversion period. A conversion fromone gas to another needs to be designed so as to be incremental, ensuring minimal
disruption to the customer.
A more appropriate solution is presented in this section and demonstrates how thecity needs to be divided into a series of zones, of perhaps 2,500 homes, where thenatural gas can be disconnected and the appliances in this small area replaced or
potentially converted. Each zone is then re-commissioned with hydrogen. Dividing
the area of conversion into zones is a complex but necessary task. It is expected thatany particular house might only be disconnected for one to a maximum of five days,
dictated by the size of the conversion workforce.

114

Section 4. Gas Network Conversion

4.1. The Process
Once it had been established that the existing gas network, with minimal
reinforcement, was adequately sized to supply the heat demands of a city suppliedby hydrogen, see Section 3, Gas Network Capacity, the next challenge was tounderstand what a city scale conversion strategy could involve.

Zones of Influence
The Synergi modelling software not only allows analysis of pressure and flow but
it can be used to determine zones of influence for different ‘injection points’ on thesystem, i.e. where Pressure Reduction Stations (PRSs)/District Governors (DGs) supply
the medium and low pressure networks respectively. This software is used by thegas industry to model isolations on the network. The results of this modelling are
frequently used to underpin the methodology for non-routine operations involving
sectional isolations. A typical network isolation requirements may include:
yy Isolation of areas of the network to allow replacement of old metallic mains aspart of the Iron Mains Replacement Programme (IMRP).
yy Reinforcement on the network due to demand growth in specific areas.
yy Emergency situations, such as a major gas leak incident.
yy Numerous other non-routine operations on the network.
By way of analogy, consider two scenarios where we equate one of the pressure
systems (medium or low) to a large swimming pool which is filled with water by 20
water taps (equivalent to PRSs/DGs).
Scenario One: All taps are positioned at equal intervals across the pool and each
open the same amount allowing the same amount of water to pass through. In thisexample, each tap would have the same zone of influence.
Scenario Two: One tap of the 20 is now fully open, some are shut and the remaining
taps are only 10% open. In this instance the tap which is open fully would provide thelargest amount of water and the water from this tap would be considered its zone ofinfluence – considerably bigger than its zone of influence in the first scenario.

115Section 4. Gas Network Conversion

Examples of zones of influence in the low pressure systems are provided below.
These are the zones of influence for the Otley area in the Wharfevalley. In thefirst picture all the DGs (or taps) are set to the same pressure and they all exhibit
approximately the same zone of influence. In the second example the DGs in thegreen and blue sections are set at a lower pressure than the DG in the red area sotherefore, the red area now has a much larger zone of influence. This is illustrated in
Images 4.1 and 4.2.
District
Governors

Image 4.2. Otley Zones of Influence
Varying Pressures

Image 4.1. Otley Zones of Influence
Same Pressures

PRUs

The medium pressure network is
broadly the same and the zones
of influences associated with theconversion area are shown in
Image 4.3. The different colours
represent the different zones ofinfluence from the respective PRSs.

Image 4.3. Area of Conversion: MP Zones
of Influence116Section 4. Gas Network Conversion

To develop and understand an effective conversion strategy it is important tounderstand the zones of influence from specific injection points. These are thepoints that will be closed or isolated from the current natural gas system thenreconnected to the new hydrogen system. This means that only the customers in the
representative zonal section are converted to hydrogen, which is isolated from theother areas (see Section 4.1.3) which will still operate on methane.

4.1.1. The Principle of Conversion
It is important to understand firstly that zones of influence will dictate the area tobe converted. To convert a gas network the existing gas needs to be removed andreplaced with the ‘new’ gas, as was done in the original natural gas conversion.
Considering the network pressure, the process for conversion needs to be sequentialfrom high (orange) to medium (blue) to low (red).
LP Network up to 0.075 bar
MP Network 2 bar to 0.075 bar
Above 7 bar network

Image 4.4. Map of Gas Network in the West Yorkshire Area

For the project, a sample step-by-step conversion assessment has been completed
to evidence the process required to allow an effective conversion to take place.
This shows that conversion, even in today’s integrated gas grid systems, is stillachievable in a similar fashion to that undertaken in the original town gas to natural
gas conversion. The final conversion strategy for the area of conversion will needthorough detailed analysis coupled with site surveys. This is identified as a key
project in the Section 10, H21 Roadmap.

117Section 4. Gas Network Conversion

4.1.2. The Process for Conversion
The step-by-step approach required for network conversion is described in thefollowing section and includes a specific example for the area of conversion.

The High Pressure Network
On the network map below the existing high pressure natural gas network has beenhighlighted in orange and the current PRSs, which are the injection points to themedium pressure system, have been identified with blue circles.

Existing PRSs

LP Network up to 0.075 bar
MP Network 2 bar to 0.075 bar
Above 7 bar network

Image 4.5. Map of PRS Injection Points to the Area of Conversion

To convert from natural gas to hydrogen, these injection points need to besequentially disconnected from the high pressure network (orange) and connectedto the new hydrogen pipeline that will be coming from the hydrogen production
facility and storage sites at Teesside and Hull. If each of the PRSs was connected atonce the entire medium pressure, and subsequently low pressure systems, would
need to be converted at the same time as there would be no remaining natural gas
supply to the network. This would mean the entire conversion area would be without
gas for a considerable amount of time, as the appliance conversion for the entire areaof conversion would need to take place at the same time.

118

Section 4. Gas Network Conversion

In reality, for conversion to take place the hydrogen transmission pipeline from
Teesside would be laid in place and commissioned, but would not be physicallysupplying hydrogen to the network.
This is shown pictorially in the Image 4.6. Existing PRSs are depicted with dark blue
circles, the new injections points are green circles and the light blue circles areconnection points already scheduled for removal in the 2020s to facilitate the new
High Speed 2 railway line.

Hydrogen pipelinefrom Teesside

LP Network up to 0.075 bar
MP Network 2 bar to 0.075 bar
Above 7 bar network

Image 4.6. Map of Leeds Hydrogen Ring Main and PRSs

When considering the method of transferring the connection from the high pressure
natural gas (orange) network to the new high pressure hydrogen network we mustfirst understand the impact of the medium and low pressure networks. To do this, weneed to identify the zones of influence which will allow us to understand the size ofthe area, and therefore the number of customers, that will need to be converted.

119Section 4. Gas Network Conversion

Medium Pressure (blue) Network
To undertake the conversion analysis the project team made two assumptions.
yy This is that conversion will only occur between the months of April and
September; andyy Will happen over a period of three years.
This will ensure that heating is not affected (as there is low or no demand for heating
during the summer months). These assumptions would be developed further as partof Section 10, H21 Roadmap and detailed conversion strategy assessment.
When considering the medium pressure network against a three-year conversion
strategy we need to understand what the zone of influence of individual injections
points are. Image 4.7 shows the zones of influence for each injection point havebeen combined to enable a three-year isolation strategy for the medium pressure
network. Each of the isolation years has a comparable number of customers but
working in the outlying areas in the first year would allow the conversion team todevelop their strategy in these less densely populated and interconnected zones.
Whilst we know these injection points
could supply gas to customers withinthese zones of influence, we alsoneed to be aware that these zones
in reality are not physically isolated
from each other. If we return to ourswimming pool analogy, the waterfrom each tap will actually mix as it
fills the pool unless the swimming
pool has physical sections built into
it to prevent the water from each tap
mixing with water from adjacent taps.

Year 1
Part 1
Year 2

Year 3

Year 1
Part 2

Year 1
Part 3

Image 4.7. MP Three Year Conversion Strategy

This is common practice in the gas industry, as part of non-routine operations, and isundertaken using a ‘double block and bleed’ valve configuration (Image 4.8).

120

Section 4. Gas Network Conversion

Year 1
Part 1

MethaneYear 2

Year 1
Part 2

Valve One

Valve Two

Bleed vent incase either
valve ispassing gas

HydrogenYear 3

Year 1
Part 3

Image 4.8. Isolation Locations on MP Network and Illustration of Double Block and Bleed Isolation Method

These valves may already exist in the network and this would be determined as partof the H21 conversion roadmap project surveys. Also, these isolations would need toremain in place until the adjacent area was converted and therefore each area would
need to be robust enough to maintain supply through the intervening winters until
the entire conversion was completed.

121Section 4. Gas Network Conversion

Low Pressure (red) Network
While we now understand the year-by-year sequential areas in which the isolationand conversion could take place, this is only part of the picture. Within each year,
the areas would need to be broken down into smaller segments to ensure the levelof disruption to customers is acceptable. Therefore, we would propose dividing the‘yearly zone’ into monthly and, subsequently, weekly isolation zones. This will need
to occur in both the medium and low pressure networks. The reader must rememberthat the vast majority of customers are connected to the low pressure (red) network
which is in turn supplied by the medium pressure network via numerous injection
points (DGs). For the medium pressure isolation shown in Image 4.8 this thensupplies the low pressure network as shown in Image 4.9.

Year 1
Part 1
Year 2

Year 3

Year 1
Part 2

Year 1
Part 3

Image 4.9. LP Yearly Isolation Zones

122

Section 4. Gas Network Conversion

As with the MP network, the LP network DGs have zones of influence which will
require a double block and bleed arrangement. Simplistically this conversion process
is illustrated in the Image 4.10.

HP Methane
PRS

HP Hydrogen
PRS

HP Methane
PRSMPMP Methane
District
Govenors

MP Hydrogen
District
Govenors

MP Methane
District
Govenors

LP
Image 4.10. Conversion Isolation

123Section 4. Gas Network Conversion

4.1.3. The Conversion of the Wharfedale Area
To fully understand the conversion process a detailed example is provided for the
Wharfedale area which would be undertaken in Year One, shown in Image 4.11.

Hydrogen pipelinefrom Teesside

LP Network up to 0.075 bar
MP Network 2 bar to 0.075 bar
Above 7 bar network

Image 4.11. Wharfedale Area of Conversion

When considering the optimum way to convert this area several factors will need tobe considered. These include:
yy Acceptable duration for customers to be without gas;yy The size of the conversion workforce;yy The ability and cost of maintaining temporary supplies through options such as
liquid natural gas and potentially bottled gas for short periods; andyy The number of isolations required.
All these factors were considered as part of the overall conversion strategy identified
in Section 10, H21 Roadmap. By way of example, two detailed conversion strategies
are detailed on the following pages.

124Section 4. Gas Network Conversion

Example One: Incremental Conversion with Zone Isolations
In this example, there would be multiple specific isolations required between
zones of influence. This solution would provide the smallest practicable period forcustomers being without gas.

Starting PositionNewhydrogen
PRU 1
Existing
methanePRU

Principle MP zonal isolation
double block and bleed.
Note: All of the area is suppliedwith natural gas (methane) fromthe existing PRU.
This gas ﬁlls the MP and LP
systems and is all that is available
to the customer.

Newhydrogen
PRU 2

MP

LP

Principle MP
zonal isolation
double block and bleed
Image 4.12. Starting Position

125Section 4. Gas Network Conversion

Step One: Dual area MP/LP Isolations 1st Conversions
Commission
new hydrogen
PRU 1

Methanesupplies
maintained

Conversion notes:
Isolation valves are closed.
Two areas north andsouth are simulataneously
converted to hydrogen fed by
new hydrogen PRU whilst
remaining areas are still supplied
natural gas from the current
HP-MP injection point.

Commission
new hydrogen
PRU 2
Valve assembly already exists would be validated as part of surveys,
others may need installation
MP

LP

LP
isolations

Image 4.13. Maps Step One

126

Section 4. Gas Network Conversion

Step Two: Dual Area MP/LP Isolations 2nd Conversions
Conversion notes:

MP

Next sets of isolation valves
are closed.
The next two areas north and south
are converted to hydrogen whilst
the remaining areas are still
supplied natural gas from thecurrent HP-MP injection point.

LP

Image 4.14. Map Step Two127

Section 4. Gas Network Conversion

Step Three: Dual Area MP/LP Isolations 3rd Conversions
MP

Conversion notes:
Next sets of isolation valves
are closed.
The next two areas north and south
are converted to hydrogen whilst
the remaining areas are still
supplied natural gas from thecurrent HP-MP injection point.

LP

Image 4.15. Maps Step Three

128

Section 4. Gas Network Conversion

Step Four: Dual Area MP/LP Isolations 4th Conversions
Conversion notes:

MP

Four areas would become isolated
from the existing natural gas supply.
Grey areas would need a temporary
supply from LNG or an increase in
the size of the conversion workforce
to cover the larger area.

LP

Image 4.16. Maps Step Four129

Section 4. Gas Network Conversion

Step Five: Triple Area MP/LP Isolations 5th Conversions
MP

Conversion notes:
Next sets of isolation valves
are closed.
Two temporarily supplied grey
areas are converted as well as
the adjacent small southern areas.
The remaining areas are still
supplied natural gas from thecurrent HP-MP injection point.

LP

Image 4.17. Maps Step Five

130

Section 4. Gas Network Conversion

Step Six: Single Area MP/LP Isolations 6th Conversions
Conversion notes:

MP

Next sets of isolation valves
are closed.
The next area south is converted
to hydrogen.
The remaining area is still supplied
natural gas from the current
HP-MP injection point.

LP

Image 4.18. Maps Step Six

131Section 4. Gas Network Conversion

Step Seven: Final Conversion and decommission HP-MP Natural Gas
PRS (Completion)
Operational
new hydrogen
PRU 1

Methanesupplies
decomissionied

Conversion notes:
The ﬁnal area associated withthis MP zone of inﬂuence isconverted. The natural gas
supply is decomissioned.
All areas are supplied byhydrogen. The principle zonal
MP isolation remains in place
until conversion of the zone
to the south commenceswhereupon this could potentailly
be used as one of thehyrodgen sources.

Operational
new hydrogen
PRU 2
MP

LP

LP isolations

Image 4.19. Maps Step Seven

132

Section 4. Gas Network Conversion

Example Two: Minimal Network Interference
It needs to be understood that the conversion strategy provided in example one
while efficient and technically effective is not the only strategy available. If it was
found to be acceptable to customers to be without gas for longer to save enablingcosts then a much simpler network strategy could be adopted. In this example, two
new hydrogen PRSs are not installed as in Example One and instead the hydrogenconnection is made directly into the existing PRS. This solution requires some mains
reinforcement to be carried out to the MP network, but would remove the need tocarry out staged isolations and conversions. However due to the likely extended
conversion timetable unless an extensive conversion workforce were available this isunlikely to be acceptable to customers. This balance would be a key consideration aspart of the detailed conversion strategy development project identified in Section 10,
H21 Roadmap.

133Section 4. Gas Network Conversion

Starting Position
Conversion notes:
Principle MP zonal isolation
double block and bleed.
All of the area is suppliedwith natural gas (methane) fromthe existing PRU.

Existing
methane
PRU

This gas ﬁlls the MP and LP
systems and is all that is available
to the customer.

MP

LP

Principle MP
zonal isolation
double block and bleed
Image 4.20. Example Two Starting Position

134Section 4. Gas Network Conversion

Step One: Decommission Existing Methane PRS and Convert toHydrogen, Conversion of All Areas Complete
Conversion notes:
Principle MP zonal isolation
double block and bleed.
As there would be noalternative natural gas supply
a zonal approach to the conversion
could only be possible withtemporary natural gas, e.g. LNG.

Existing
methane
PRU

Alternatively, the entire area could
be converted at once and thelength of time customers are left
without gas would be dictated by
the aize of the available workforce.

MP

LP

Image 4.21. Map, Example 2, Step 1135Section 4. Gas Network Conversion

4.1.4. Conversion Summary
Now we understand how the conversion is possible in a specific area, recall thethree-year conversion strategy based on the MP network isolations Image 4.22.

Year 1
Part 1

MethaneYear 2

Year 1
Part 2

Valve One

Valve Two

Bleed vent incase either
valve ispassing gas

HydrogenYear 3

Year 1
Part 3

Image 4.22. MP Three Year Conversion Strategy and Double Block and Bleed

By the end of year one, the three orange areas would all be operating on hydrogen
while the purple and beige areas would be operating on natural gas. All areas would
be converted in a similar manner to that identified in the Section 4.1.3 and would betimed to ensure the conversion back to the principle isolation valves, i.e. the valves
that will isolate natural gas areas from hydrogen areas over winter, is complete.

In conclusion, converting the city to hydrogenis possible with minimal modification. It will
require meticulous planning coupled withsite surveys, upfront enabling works, andcomprehensive strategy development

136

Section 4. Gas Network Conversion

4.2. Network Enabling Costs for Conversion
Without undertaking the full conversion strategy including cotnsideration of
workforce size, customer time without gas, temporary supplies etc. it is difficult
to estimate the costs associated with network enabling work. However, to givean indication of the cost an estimate has been provided for H21 based on thefollowing assumptions:yy In the Wharfedale scheme above there are approximately 30 isolations required
across the MP and LP systems.
yy When scaled up to cover the entire area of conversion this has been assumed,with a high level of confidence in the order of magnitude, to be:—— 750 LP isolations (assume none are currently in place or are not available due to roadresurfacing etc.)—— 250 MP isolations (assume ⅓ are in place)—— 25-30 new permanent DGs and associated mains connections to facilitate additional
sector isolations.
—— An 8 inch (200 mm) double block and bleed isolation has been priced by NGNs
commercial department and costs approximately £4,420. To ensure worst casescenario all isolations have been assumed as 8 inches, although in reality, many
mains will be smaller than this. Therefore, the figures presented in Table 4.1 are worst
case scenario.
Work Type

Total Units

Unit Cost (£)

Total (£)

LP isolations (installationof double block and bleed
assembly)

750

4,420

3,315,000

MP isolations (installationof double block andbleed assembly)

170

4,420

751,400

District governors andassociated connections30

50,0001,500,000
Total

Table 4.1. Network Conversion Enabling Works – Cost Summary

137

4,726,400

SECTION 5

Appliance
Conversion

Gas Rig

Liquid Natural
Gas Storage

Salt
CavernCarbon Captureand Storage

Terminal

Compressor
StationPressure
ReductionOﬀtakePressure
Reduction
StationCompressor
StationPower
StationSteam
MethaneReformer
Salt
CavernSalt
CavernDistrict
Governor

HULL

LEEDS
Section 5
Appliance
Conversion

Section 5 | Appliance Conversion

5. Appliance Conversion
Appliance Conversion History
The original town gas to natural gas conversion occurred between 1966 and 1977 andinvolved the conversion of 14 million customers and 40 million appliances plus industrial
and commercial customers. This was a programme of both technological and logisticaloutstanding achievement. From initiation in 1966 by 1969 conversion of over 400,000
domestic dwellings each year was being undertaken with a peak of over 2.3 million peryear in 1971/72.
A key part of the conversion success was the cooperation shown by the manufacturers
in developing and supplying conversion sets for both the domestic and commercial/industrial markets. In addition to the appliance manufacturers (and their joint
organisation ‘the Society of British Gas Industries’ (SBGI)) co-operation to respond to
the need to convert The Gas Councils two research establishments were also pivotal to
the success.
At the time of conversion, the establishment of the unified British Gas Corporation
was some seven years away. Instead the gas industry was made up of 12 essentiallyautonomous area boards, The Gas Council stood between Ministers and these boards
with a statutory role ‘to promote and assist the efficient exercise and performance by
area boards of their functions’. The Gas Councils research bodies, Watson House andMidlands Research Station, by dealing with domestic and industrial sectors respectively,
were pivotal parts in the appliance approval process and ensured agreed standards
were maintained.
In 1966 the Gas Council established a Conversion Executive which had the objective ofreviewing area boards conversion plans, ensuring the appliance industries capabilities
were in line with the conversion programme and that the correct standards were being
observed, and acting as a conduit between the area boards and the Gas Council. A key
policy decision from the conversion executive was to the introduction of new appliances
readily adaptable to both town and natural gas and subsequently to natural gas only.
Technical assistance from Watson House to the appliance industry was essential to thesuccess of the conversion programme. Their role included:yy Testing and approval of conversion sets and new appliances;
yy Development of conversion sets for older appliances particularly where
manufacturers were no longer in operation;
yy Co-ordination of area board surveys to determine numbers and types ofappliances prior to conversion taking place. This was essential to ensure thecorrect numbers of conversion sets could be ordered and manufactured in atimely manner;139Section 5 | Appliance Conversion

Appliance Conversion History (continued)
yy Production of the ‘Watson House identification manual’ with a complete
description and illustration of each of the appliances totalling circa 850 domestic
and nearly 300 catering appliances by the time conversion took place; andyy Provision of a mobile workshop in the area of conversion for in-field supportshould it be required.
One difficulty with which the appliance manufacturers and Watson House had tocontend in the early days was the availability of natural gas with which to test andapprove appliances. This issue has been recognised in the H21 Roadmap and is the key
reason for recommending Teesside for the establishment of an appliance development
and demonstration hub near the UKs only large-scale hydrogen storage salt cavern.
Also, small manufacturers today often do not have research and development
departments and these would need similar levels of support to that provided by Watson
House which could be facilitated by companies in the market like Enertek at Hull.

Appliance conversion programmes are relatively common in the gas industry. The
last major conversion in the UK was town gas to natural gas in the early 1970s but
the Isle of Man only completed the conversion from LPG/air mixtures to natural
gas as late as 2013. The low cost and great variety of modern appliances mean it
is expected that in the domestic sector full appliance replacement is the norm,
although in a commercial or industrial environment burner replacement is more
likely to be viable. Fortunately many boilermakers manufacture to their own
design of common backplate (the component screwed to the wall and via which
the gas and water pipes run) so boiler change over should not be too onerous.
There is considerable enthusiasm from the UK gas appliance industry for such a
conversion programme.
Obviously all of the combustion equipment supplied by a hydrogen network must be
suitable for hydrogen. Consumers cannot choose to remain on natural gas and those
not wishing to convert to hydrogen would have to switch to electricity.
A key issue for the switchover of a network from natural gas to hydrogen is
the conversion of appliances and equipment. There are both financial andresource/timing implications.
These are highly interdependent. Making available the hardware for replacement orconversion of all appliances and equipment within an area of conversion depends
on the equipment suppliers. Particularly at the point when the market is small thiswill have a large effect on the prices. Whether modification or replacement is theavailable option will also have a significant impact on the costs. Coinciding theswitchover of installed hardware and any changes required to the gas delivery
system with the availability of hydrogen to the relevant network section will bechallenging (see Section 4, Gas Network Conversion.)

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Section 5 | Appliance Conversion

To provide a sensible estimate of the appliance conversion costs for the area of
conversion engineering judgement and interpretation needs to be applied to:yy Number of meter points;yy Nature of those meter points (e.g. domestic, commercial or industrial); andyy Likely installed appliances/combustion systems.
DECC publish this for individual Middle Layer Super Output Areas (MSOA) as
conveniently sized geographic areas.
To put this in perspective it is worth summarising the previous results.
yy Average 2013 yearly demand = 678 MW (derived from DECC data).
yy Total average yearly demand (2013) = 5.9 TWh.
yy Total number of meter points in the area of conversion = circa 265,000.
From further interpretation of the MSOA data the demand profile above can be
broken down to domestic and non-domestic usage. Figures are shown in Table 5.1.
Demand% ofTotal Demand

Meter
Points% of Total
Meter Points

Domestic

3.6 TWh63%

261,52299%

Non-Domestic

2.3 TWh

37%

3,126

1%

Usage Type

Table 5.1. Domestic vs. Non-Domestic Split in Area of Conversion

Inevitably with large numbers of sites and different data sources small differences
occur between databases and years. The details of these calculations andassumptions are explained in the following pages as well as how the estimateof appliances type and conversion costs within these respective domestic/
non-domestic sectors has been produced.

141Section 5 | Appliance Conversion

5.1. Domestic
Between 1967 and 1977 about 13 million homes and 40 million applianceswere converted from town gas to natural gas at a cost of (then) £563 million (i.e.
£42/customer, ref National Gas Museum). This is now equivalent to £6 billion (basedon the RPI) or £14 billion (based upon % UK GDP).
A similar programme was recently completed on the Isle of Man. This coston average approximately £3,500 per property, including all work bothwithin the property (reported at about £1,200) and in the street (reported atabout £2,300/property).
The rate at which the switchover could be undertaken is crucial. The development of
the hydrogen resource will inevitably be much more protracted than for the provisionof natural gas. The balance between providing hydrogen supply capacity across thearea of conversion and procurement and installation of the necessary hardware forusers will require careful management. In particular creating sufficient consistent
demand for hardware to persuade manufacturers to mass produce will be vital.
The first conversions to take place, potentially in the mid 2020s, will inevitably be themost expensive. As lessons are learnt, increasing efficiency in the process, coupledwith time to standardise appliance specifics (as recommended below), should reducethese costs significantly especially if and when the conversion is incrementally rolled
out across the country.
To help to prepare for a widespread transition to hydrogen the following actions
could be taken:
1. Boilers: Manufacturers are already using ‘back plates’ or ‘manifolds’ for ease ofboiler change. This should be encouraged (or regulated) to include isolation
valves to connect their boilers to the existing central heating, domestic hot waterand gas supplies. This can be of their own design to suit their particular productcharacteristics. This is expected to reduce boiler average change times to< 2.5 hours.
2. Cookers: Manufacturers should be encouraged (or regulated) to produce
appliances to standard sizes and with gas connection ports in a common location.
This should reduce appliance average change times to < 1 hour.
3. Gas Fires: These sales are predominantly aesthetically driven, the sales
documentation of such appliances could (in future) contain specific reference
as to whether the appliance will be suitable for conversion to hydrogen. If
manufacturers started to develop hydrogen compatible appliances their literature
should begin to contain references as to how they plan to offer hydrogen
conversion/replacement in the event of conversion of the customers’ area.
Such potential for easy change could be promoted in the same fashion as the ‘Digital
Switchover’. Various government energy efficiency schemes could require hydrogenswitch (HySwitch) friendly appliances. These products may be a conventional
appliance, which has a specific easy conversion replacement/modification kit
developed by the manufacturer reducing conversion times to less than 2 hours.

142Section 5 | Appliance Conversion

In the near term manufacturers could designate any existing appliances ‘HySwitch’ ifthey launched a bespoke hydrogen kit such that the conversion of these appliances
could readily be carried out below a designated time threshold. In the longer termeven more conveniently convertible appliances could undoubtedly be designed. This
purposely sets the ‘benchmark’ of the early HySwitch boiler as fairly low. The precise
route by which the appliance could be converted, i.e. by either minor part or near
total replacement, would be the choice of individual manufacturers.

The Conversion Process.
Consideration of the demand profile of the area of conversion has been divided into
the two sectors used by DECC for gas utilisation, i.e. domestic (in practice all sites
with meters < 70 kW) and non-domestic. The total cost is then the sum of these.
Numbers of man-days, elapsed times and staff numbers have been allocated to thedomestic sector, whereas the non-domestic sector has been considered only from afinancial perspective. It is envisaged that the programme will be driven by the timing
and density of the domestic properties (e.g. flats or detached residences) and thatthe non-domestic will then follow. The utility overhead (to manage the process) has
been allocated to the domestic market.

Domestic – Switchover Process and Cost Estimates
For the analysis presented here a zone containing 2,500 properties has been usedas the basis for estimating indicative costs for conversion. The complex issue ofthe number of isolation zones versus the size of the isolated area is considered in
Section 4, Gas Network Conversion.
The basic parameters used are set out in Table 5.2.
AspectIsolation
Zone Definition

Staff Definition

Cost Definition

Parameter

NumberUnits

Properties in isolation zone

2,500

-

Streets per zone

c.42

-

Properties per street

c.60

-

Duration of zone isolation from gas grid

5

Elapsed days

Gas Fitters (obtained from Table 5.3)

939-

Number of Management supervisors*

125-

Staff cost – Gas Fitters

46.30

£/h

Staff cost – Management

73.33

£/h

Table 5.2. Design Parameters for the Management of the Appliance Switchover Process.

*A management to gas fitter ratio has been adopted of 1:8.

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Section 5 | Appliance Conversion

Experience from the SGN ‘Opening up the gas market' project showed that gaining
high levels of consumer involvement can be achieved (approaching 90% active
support and < 1% active refusal) but this takes high levels of street-by-street
canvassing and skilful public relations; this has a significant cost. This is one reason
for the high level of management involvement.
In order to model the effort involved in carrying out the switchover for an isolation
zone of this size assumptions have been made with regards to:yy Appliance population regarding number of properties with gas appliances andthe distribution of appliance types;
yy Appliance population regarding the distribution of appliance types;
yy Average effort required to replace appliances (by type);
yy All staff are on the same pay structure; andyy Time for total zonal conversion is five days.
The values (estimates based on Kiwa-Gastec experience) used in theseassumptions are shown in Table 5.3 and 5.4 which shows the development of theeffort estimate for the switchover process of one isolation zone containing 2,500
domestic properties.
Here it should be noted that the estimated time for switching traditional systemboilers and for conversion of ovens/grills is as follows:
yy Replacement of traditional system boilers (e.g. sitting room back boiler units) is
time-consuming due to the number of components in these systems comparedto those used with modern combi boilers, hence the estimated average time of
11 hours.
yy The time required to change over an oven or grill can be less than 6 hours
for a freestanding appliance, however for integrated appliances this will besignificantly longer. An estimated average of 6 hours is used here.

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Section 5 | Appliance Conversion

Effort (h)Number

Total
Effort (h)CostInitial house visit

1.5

2,500

3,750

£173,625

Replacement
products order

1

2,500

2,500

£115,750

HySwitch readyboiler changeover*

2

1,250

2,500

£115,750

Traditional Combiboiler changeover

6

750

4,500

£208,350

Traditional Systemboiler changeover

11

500

5,500

£254,650

HySwitch readyhob/freestanding
changeover

1

1,000

1,000

£46,300

Traditional hob changeover

13.5

400

5,400

£250,020

Traditional
grill/oven changeover

4

1,200

4,800

£222,240

HySwitch ready fire/simple
fire changeover

2

800

1,600

£74,080

Traditional gas fire(complex) change over

5

700

3,500

£162,050

Pipework adjustment andchange of fiscal meter

1

2,500

2,500

£115,750

37,550£1,738,565

Activity

Boilers

Cookers

Heaters

Other
Parts

ActionTotal
Number of gas fitters
Management(37,550/40)
40(5 days@ 8hrs)

939
125

5,000

£366,650

Grand Total £2,105,215
Cost per property£842.09

Table 5.3. Estimation of Effort Required for Appliance Switchover for One Isolation Zone Containing 2,500
Domestic Properties*A HySwitch product may be a conventional appliance, which has a specific easy
conversion replacement/modification kit developed by the manufacturer reducing
conversion times to less than 2 hours.

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Section 5 | Appliance Conversion

Hardware Cost Estimates Based on Current Prices
Type

Boilers

Cookers

Heaters
Other parts

HardwareNumber

Unit Cost £Total cost

HySwitch ready boiler

1,250

850

£1,062,500

Traditional combi boiler

750

1100

£825,000

Traditional system boiler

500

950

£475,000

HySwitch readyhob/freestanding

1,000

300

£300,000

Traditional hob

400

750

£300,000

Traditional grill/oven

1,200

450

£540,000

HySwitch ready fire/simple fire

800

300

£240,000

Traditional gas fire (complex)

700

450

£315,000

Pipework

2,500

100

£250,000

Total
Average appliance cost per property£4,307,500£1,723

Table 5.4. Summary of Hardware Costs for Appliance Switchover for One Isolation Zone Containing 2,500
Domestic Properties

In a similar fashion to the calculation of the annual gas demand for the area of
conversion (by overlaying MSOAs on the gas network maps see Section 4, Gas
Network Conversion) the number of domestic consumers has been estimated.
This is evaluated as 261,522 domestic meter points in the area of conversion of the264,648 total.
For completeness an extract is shown in Table 5.5.

MSOA
Name

MSOA
Code

Consumption(kWh)

Numberof Meters

Mean
Consumption(kWhper Meter)

E08000035

Leeds 002

E02002331

37,562,331

2,583

14,542

12,532E08000035

Leeds 003

E02002332

33,088,003

2,516

13,151

12,344E08000035

Leeds 004

E02002333

48,734,878

3,556

13,70512,083

Local
Authority
CodeMedianConsumption(kWhper Meter)

Domestic

Table 5.5. Area Meter Information

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Section 5 | Appliance Conversion

An overhead rate covering managerial and regulatory costs have been estimated to
be around 20% of the cost per property. The overall cost build per property, per 2,500
property zone and for the whole sector is given in Table 5.6.
Each

For a Zone of
2,500 Properties

For All 261,522

Manpower£842£2,105,000£220,201,524

Hardware£1,723£4,307,500£450,602,406

GDN
Overhead 20%£513£1,282,500£134,160,786£3,078£7,695,000£804,964,716

Costs

Total

Per property£3,078

Table 5.6. Costs per Property

This gives an overall unit cost per property of £3,078. This per property cost is broadly
consistent with a cost of £3,500/property for the town gas to natural gas conversion
on the Isle of Man in 2010. This final conversion figure per domestic property has
been logically calculated for the area of conversion and seems reasonable assuming
2016 prices, but also the mass manufacture of hydrogen appliances which would be
essential should such a conversion take place. It is appreciated that there may besome optimisation between higher capital cost and reduced hours of conversion,
but this can only be quantified as detailed appliance design progresses. All of thesecosts are for ‘entry level’ hydrogen appliances. It is envisaged that householders will
always be permitted to pay for upgrades to a range of high specification products (forexample catalytic hobs – see later in this section).
It should be noted that while the costs have been derived on a unit cost per
domestic property basis in reality the process of conversion would be run withtwo distinct seasons per year. Through winter the extensive survey work would beundertaken with the subsequent procurement and logistics of hardware. In summer
the conversion would take place with a detailed plan and upfront knowledge on aproperty by property basis to ensure a smooth and swift a changeover as possible.
This occurred on the original towns gas to natural gas conversion.

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Section 5 | Appliance Conversion

5.2. Non-Domestic (Industry, Public
and Commercial)
Customers in these sectors use equipment such as larger boilers (which may be
producing steam or high-temperature high pressure water) Combined Heat andPower (CHP), and process burners.
Separation rules in the gas industry make it hard to identify all of the gas users inthese sectors. Therefore, information about consumption and demand profiles ofthese sites is generally not directly available.
However, for the basis of this study it is necessary to make appropriate engineering
estimates. Efforts have been made to calculate the likely number and type ofusers from these sectors in the area of conversion. This has been achieved
through interrogation of two data sets. Firstly, the NGN largest demand model
extract and secondly, 118 areas of MSOA Non-domestic Gas data. It should be
noted that throughout the gas industry the smallest commercial users (below
70 kW demand) are categorised as ‘domestic’ and contained within the domestic
connection numbers.
There are 3,126 non-domestic sites. To estimate the demand pattern it isnecessary at least to know the type of activity undertaken on a site. It would bevery time-consuming to carry this out for every non-domestic site and therefore
a subset of the largest demands supplied from the MP and LP networks was
obtained from the Synergi models. This gave 38 sites with peak demands greaterthan 100 Scm/h natural gas off the MP and 89 sites with peak demands greaterthan 130 Scm/h natural gas off the LP. These sites were then subjected to thefollowing steps:
yy From the OS grid reference Google Earth, Google Maps and Google Street view
were used to assist in determining the nature of the enterprise on each site. For
example, was a site a large industrial manufacturing site, a CHP installation, ora prison.
yy Based on the above identifications, typical site usage patterns, annual operating
hours and hence annual gas consumption were estimated. The essence of this isshown in Table 5.7.
By way of example for each of the 38 sites fed from the MP, an estimate was made as
to what type of ‘appliance’ it was likely to be using. For example, of the 38 sites it wasestimated that 18 would be using a process boiler, (e.g. was it a fabric mill, or a foodfactory). The capacity of this was then back calculated from its declared installed
load. This totalled 18 MW of demand for process boilers for all 38 sites. Assuming
process boilers operate an average of about 3,500 hrs/y (including the backup boiler)
total usage within these plant is 63,000 MWh/yr. The process was repeated for thefive categories listed in Table 5.7.

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Assessment of Number
Industrial Appliances Using Process Identified Above
NGN
Pressure Tier
Medium Pressure
30 Connections

Low Pressure
89 Connections

Units

Process
BoilersSpace
Heating

CHP

Glass

Process

MW

18

132

15

44

70

hours/year

3,500

1,000

7,000

8,500

3,000

MW/year63,000132,000

350,000

374,000

210,000

MW

9

159

6

-

41

hours/year

3,500

1,400

3,500

-

4,000

MW/year31,500222,600

21,0000

164,000

Total MW

27

291

56

44

11

94,500354,600

371,000

374,000

374,000

Total MWh/year
Grand Total kWh/year

1,568,100,000

Table 5.7. Estimated Annual Commercial and Industrial Energy Demand from the Largest Demand Low andMedium Pressure Network Connections in Leeds

Note: Process boilers: The annual operating hours of space heating has been
reduced to 1,400 hours to allow for plant oversizing. Declared gas demand is often
based upon installed combustion equipment.
Space Heating: The annual operating hours has been reduced to 6,000 hours toallow for non-operation at weekends and Bank Holidays.
CHP for medium pressure, value 15: Mostly Leeds University campus or hospital.
The previous table indicates that projected demand from the 127 largest peakdemand sites is 1,568,100 MWh/yr. The potential for inaccuracy is accepted but thetechnique does yield both reasonable and self-consistent data.

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Section 5 | Appliance Conversion

The 118 Areas of MSOA Non-domestic Gas Data
Of the 3,126 non-domestic meter points in the area of conversion the 127 largest
demand sites consume 1,568,100 MWh/yr leaving a remaining 2,999 sites of
non-domestic consumers. Assuming the total of 3,126 sites consumes thenon-domestic total of 2,326,627 MWh/yr this allows a further 758,527 MWh/yr of
consumption by 2,999 sites.

Numberof Meters

Mean
Consumption(kWhper Meter)

MedianConsumption(kWhper Meter)

41,095,733

75

547,943

142,955

E02002332

5,540,664

7

791,523

124,434

E02002333

8,602,449

44195,510

118,309

Local
Authority
Code

MSOA
Name

MSOA
Code

Consumption(kWh)

E08000035

Leeds 002

E02002331

E08000035

Leeds 003

E08000035

Leeds 004

Table 5.8. Examples of MSOA Non-domestic Data

Further examination provides three interesting points:
yy About 65 areas have fewer than 20 non-domestic meters i.e. they are essentiallyresidential areas;yy Almost 50% of the non-domestic gas (1,151,507 MWh) was consumed in just fourMSOA (out of a total of 2,326,627 MWh, 2013). Between these four areas they
contain 578 individual meter points, a number too large to provide much further
insight. For reference the four areas are Wakefield 014 (E02002451), Leeds 064(E02002393)m Leeds 112 (E02006876) and Leeds 111 (E02006875); andyy On inspection most MSOA areas show a non-domestic annual usage of between
200,000 to 400,000 kWh/yr. It is reasonable to assume that most of this usage
will be required by 200 kW boilers similar to those found in schools, office blocks,
and other large buildings.

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Section 5 | Appliance Conversion

As there are 3,126 non-domestic meter points this would provide an average of
3,126/118 = 26 to 27 meter-points per MSOA. About half the MSOA have 20 sites orless so an equal number probably have 30 to 40 sites. This is all in accordance withsound engineering judgement. Clarifying these values must be a priority during thenext phase of any conversion programme.
Amalgamating these data sources produces the following installed boiler capacity
and annual demand (Table 5.9).
Meter
PointsInstalled
Capacity kW

Annual Use
MWh%Largest Peak Demand Sites(from NGN Data)127

See detail above

1,568,10067%

200 kW Sites(from MSOA Data)

2,999

599,800 (200 kW
x 2,999 sites)

758,527

33%

Description

MSOA Total

3,126

2,326,627

Table 5.9. Installed Non-domestic Capacity

A simple analysis has been performed of the costs of the required replacement equipment,
based upon Kiwa Gastec in-house data. Estimated costs for this are shown in Table 1.10.

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Section 5 | Appliance Conversion

Some process plant will inevitably be affected by the reduction in flame radiance,
but hydrogen flames are hot and so solutions should be possible. The technologies
will tend to be scaled up versions of the domestic options. One of the advantagesof hydrogen is the absence of risk of CO poisoning, and the potential for low NOx
levels so flue systems (always a major cost in I&C installations) should be capable ofmajor simplification.
Conversion
Cost perkW
Gas Capacity

Installed
kW Thermal

Conversion
Cost

Category

ChangeCommercial > 70 kW(from MSOA Data)

Boiler (costed on
basis of200 kW sites)£150.00

600,000£90,000,000

Process Boiler(from NGN Data)

New burner£50.0027,000£1,350,000

Space Heating(from NGN Data)

New boiler£100.00

291,000£29,100,000

CHP*(from NGN Data)

New turbine£1,000.00

56,000£56,000,000

Glass(from NGN Data)

New furnace£1,000.00

44,000£44,000,000

Process(from NGN Data)

New burner£250.00

111,000£27,750,000

Total£248,200,000

Table 5.10. Estimated Costs for the Conversion of Industrial and Commercial Equipment to Hydrogen

Note: CHP – the CHP cost is loosely based upon current natural gas prices.
This is equivalent to an average of £30,000 for each of the 200 kW sites plus £1.25 m
for each of the 128 larger sites. This value appears credible, as some sites will be
expensive (e.g. CHP) and others very modest, e.g. a large steam boiler in a foodfactory with a single burner.

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Section 5 | Appliance Conversion

5.3. Switchover Cost Estimates – All Sectors
The overall estimate has been produced by the summation of the estimates for thedomestic and non-domestic sectors. It is assumed that the accounting for overhead
costs in the domestic sector cost model would be sufficient to cover these costs inthe non-domestic sectors. So no overhead has been included in the non-domestic
cost build.
The totals are given in Table 5.11.
SectorOverall Estimated Cost

Domestic (Table 5.6)£805m

Non-domestic (Table 5.10)

£248m

Total

£1,053m

Table 5.11. Overall Estimates

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Section 5 | Appliance Conversion

5.4. Conclusions
While clearly a considerable sum, the above investment will eliminate the point ofuse carbon emissions from Leeds and can potentially vastly reduce NOx. There arestill some significant challenges regarding encouraging appliance development but
there are also some opportunities that could be taken advantage of to reduce thecosts of conversion over time. The key conclusion should be conversion is possible
but the manufacturing industry needs to be encouraged to produce appropriate
appliances both domestic and commercial/industrial. It is suggested thatgovernment and/or gas industry assistance should be restricted to a basic grade of‘entry level’ appliances. These must be simple, economical and robust; householders
can then be encouraged to upgrade these as they see fit. Recent contact with
manufacturers is very encouraging.

154Section 5 | Appliance Conversion

5.5. Properties of Hydrogen
History of the Combustion of Hydrogen
Hydrogen (composing about half of town gas on volumetric basis) has been used asfuel since 1816, when the town of Preston installed gas street lighting. The following
year the first gas meter was developed and installed at the gas works of the Royal
Mint. In 1874 the writer Jules Verne predicted "yes, my friend I believe that…hydrogen andoxygen…, used singly or together, will furnish an inexhaustible source of heat and light, of
an intensity of which coal is not capable". In 1937, an experimental hydrogen fuelled jetengine was tested at Hirth, and in 1941 besieged Leningrad converted some hundreds ofcars (known as the model GAZ-AA) to provide support to the ground bases of barrageballoons. The term 'hydrogen economy' was first used by John Bockris during a talk hegave in 1970 at General Motors (GM) Technical Centre.
The combustion of hydrogen at atmospheric pressure in an open burner is extremely
simple, so simple that there is a paucity of direct references. It only becomes of interest
where a number of hydrogen appliances have been brought together to demonstrate
the concept of clean technology, for example R.E. Billings, (1978). 'The Hydrogen
Homestead Study'. R.E. Billings converted or built a range of gas appliances to operate
exclusively on hydrogen, and as will be listed below, this trend of DIY hydrogen
appliances, particularly amongst rural US environmentalists continues to this day.
There is no fundamental reason why a hydrogen burning appliance should (in mass
production) be materially different in cost to the equivalent natural gas appliance.
Due to the absence of bulk supplies of low cost hydrogen there is currently no large
scale market and hence no mass manufacturer of hydrogen appliances. There ishowever one fully certified domestic boiler (Giacomini), and a Scottish company(Almaas Technologies Limited) are currently developing a range of cooking andcatering apparatus. A range of industrial burners are also readily available. There arealso a range of fuel cells for the high efficiency production of electricity (at up to 60%
efficiency (HHV), and sometimes electricity plus heat.

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Section 5 | Appliance Conversion

5.5.1. Principles of Hydrogen Combustion
Hydrogen combusts readily releasing considerable quantities of heat. It can be
burnt in air as a very high-temperature flame, or can be catalytically oxidised on
the surface, for example platinum at only marginally above room temperature. Bothmeans of combustion only generate water, although due to the high temperatures
involved some hydrogen flames can generate significant quantities of oxides ofnitrogen. Hydrogen was/is typically 50% of the volume of town gas and hydrogencan be burnt in so-called 1st Family gas appliances. These look very similar toconventional natural gas (2nd Family) or LPG (3rd Family) appliances but are optimised
for the high flame speed of hydrogen. There is no fundamental reason why hydrogen
appliances using flame combustion should be significantly more expensive thanappliances for other gases. Catalytic combustion does involve the purchase of
catalysts which tend to be based upon noble or transition metals which can be
expensive. Apart from the very limited number of commercially available products,
there are several very simple designs of DIY hydrogen appliance on the internet;
these are not held up as ‘good engineering’ but they illustrate that in principle suchappliances are simple and low cost.
Hydrogen is not directly detectable by human senses as it is:yy Odourless;yy Tasteless; andyy Colourless.
It is also:
yy Non-toxic and non-carcinogenic – although it is an asphyxiant;yy Non-corrosive; andyy Is not a direct greenhouse gas, although some authorities indicate possible
second order affects.
At ambient conditions hydrogen is a diatomic gas with a low density of 0.085 kg/Nm³(approximately 11% of that for natural gas) compared to 1.28 kg/Nm³ for air (15 °C and1.013 bar).

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Section 5 | Appliance Conversion

It is the lightest element and in the air its buoyancy causes it to rise and disperse
rapidly (speeds of almost 20 m/s). A comparison of the energy conveyanceproperties of hydrogen and natural gas are summarised in Table 5.12 .
Hydrogen

Methane(Natural Gas)

Air

Molecular Weight

2.02

16.04

28.9

Density 15 °C kg/Nm³

0.08550.6786

1.2227

HHV kJ/kg*

142,000

55,000N/A

HHV kJ/Nm³

12,13537,323

N/A

Wobbe Index kJ/Nm³

45901

50098

N/A

Wobbe Index Ratio

91.6%

100%

N/A

Volumetric Leak Ratio

282%

100%

N/A

Table 5.12. A Comparison of the Energy Conveyance Properties of Hydrogen and Natural Gas*HHV is the higher heating value of the gas, i.e. the energy released when burninghydrogen or natural gas.
Because hydrogen has a much lower density than methane it leaks from orifices
much more quickly (282% of methane), but as its' calorific value is much less, theWobbe Index (used by gas engineers to describe the energy carrying capabilities
of gases) are broadly similar. For the same pressure drop, hydrogen can carry about
92% of the energy down a pipe as natural gas. In practice due to 2nd order effects it isslightly less than this.
Hydrogens high diffusivity when compared to natural gas has other effects:
yy Greater ability to permeate through materials and joints, although the actual
rate of diffusion through pipes is very small. It is calculated that the yearlyloss of hydrogen by leakage through polyethylene (PE) pipelines amount toapproximately 0.0005–0.001% of the total transported volume. (Ref: Division ofEnergy Conversion, University of Leuven (K.U. Leuven), Celestijnenlaan 300A,
3001 Leuven, Belgium).
yy Leaks will disperse more quickly into the air due to its low density and high rateof molecular diffusivity.
As seen in Table 5.12 hydrogens low molecular weight results in it having the highest
energy content per unit mass (thus a kg of H₂ has 250% more energy than a kg ofCH₄) of any fuel. However its low density means that its volumetric energy content
is relatively low (i.e. 1 m³ of hydrogen only contains 31% of the energy than 1 m³ ofmethane). When burned hydrogen releases only one-third as much energy per unit
volume of gas as natural gas at the same pressure.

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Section 5 | Appliance Conversion

Breakout: The Calorific Value of Hydrogen
The heating value (often referred to as the Calorific Value or CV) is the amountof heat energy released by combustion of a fuel. The ‘Lower Heating Value’(LHV or net CV) is based on the assumption that the latent heat of vaporisationin water vapour from the reaction is not released whereas the ‘Higher Heating
Value’ (HHV or gross CV) represents the total energy in the fuel. The HHV unitof energy is used to buy and sell gas in the UK, and has recently become thepreferred unit within the EU.
The Wobbe Index of Hydrogen
The Wobbe Index (WI) or Wobbe number is an indicator of theinterchangeability of fuel gases such as natural gas, Liquefied Petroleum
Gas (LPG), and town gas and is frequently defined in the specificationsof gas supply and transport utilities. Numerically it is the higher calorificvalue/√(relative density)
The WI of hydrogen is about 46 MJ/Nm3, this compares with > 47.20 and< 51.41 MJ/Nm3 of current natural gas (primarily methane). This is because
although hydrogen has only a third of the CV, it has ⅛ of the density. Thissimilarity in WI, can lead to the conclusion that hydrogen can be burnt inconventional natural gas appliances. The much higher flame speed and low
emissivity from hydrogen mean this is not the case. This similarity in WI does
however mean the energy transportation properties of the gases are broadly
similar.
This low volumetric calorific value has implications for storage. To store
equivalent amounts of energy to that currently held in natural gas stores would
require a tripling of either storage volumes or pressures (or some combinationof this).

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Section 5 | Appliance Conversion

5.5.2. Hydrogen Safety
When considering the use of another fuel gas, in this case hydrogen instead of
methane, the relative risks of this alternative fuel gas need to be understood in
addition to whether an appliance can operate on such a gas.
The recent HyHouse project has offered considerable insight into this area. HyHouse
involved injecting substantial quantities of both methane and hydrogen into a two
storey Scottish farmhouse and measuring the relative concentrations.
To summarise, 3.4 times as much hydrogen (on a volumetric basis) was injected
than methane and yet (typically) measured general concentrations were only 140%
to 160% of those with methane. Bearing in mind the stoichiometric concentration,i.e. the optimum gas mixture for combustion, is only 10% v/v for natural gas and 29%
v/v for hydrogen, the independent committee that oversaw the HyHouse work (thisincluded a representative of IGEM), considered that the out-turn risk from unplanned
leakage of hydrogen from a gas network was not that dissimilar to a leak of naturalgas, through a similar hole.

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Section 5 | Appliance Conversion

Breakout: The Safety of Hydrogen
Hydrogen is a flammable gas, with wide flammable limits, but the stoichiometricmixture, (i.e. the perfect mixture for combustion) is circa 29% on a volumetric basis(v/v) in air, compared with 10% v/v for Natural Gas (NG). Therefore, to get the ‘perfectcombustion’ requires about three times the concentration of hydrogen in air. The
HyHouse project showed that due to its low density and high diffusivity it was very
difficult to obtain such high concentrations in a domestic property. In practice despite
releasing about 3.4 times the volume of hydrogen relative to methane into an old
farmhouse, the resulting concentration was only 1.2 to 1.6 times higher (all v/v basis).
Having said this, hydrogen can be very dangerous similar to any flammable gas andthe details of current UK natural gas design codes will certainly need modification tocover hydrogen.
The safety of a flammable gas in a particular situation and the severity of any fire
and/or explosion depends on upon the following:yy The concentration of the flammable gas in the air (measured as %v/v) is relative
to its stoichiometric and flammable limits. This is in turn a function of the gas’s
density and diffusivity.
yy The speed of any consequential flame front. Higher flame speeds produce higher
overpressures which are more likely to be more injurious to buildings and health.
yy Whether the mixture is enclosed or in free air, and the level of obstruction within
the combustion zone.
yy The ignition energy used to fire the mixture.
As indicated in Table 5.13, hydrogen is flammable across a much greater range ofconcentrations than methane, i.e. 4 to 75%, rather than 5.3 to 15%. This would appear
to make hydrogen much more dangerous, but in practice between 4 and 9%, thecombustion is a fairly benign ‘woosh’ whereas natural gas at such concentrations
is effectively a conventional gas explosion, with its ensuing damage. At higher
volumetric concentrations hydrogen can generate substantial overpressures, as canany flammable gas, but as found in the HyHouse experiments even in well-sealed
modern house it is difficult to realistically release enough hydrogen to obtain thesehigh concentrations. The hydrogen just disappears. It is likely all new domestichydrogen conversions would be fitted with an excess flow valve (similar to a fuse inan electrical circuit) that would limit the maximum gas flow. This might be pre-set at
64 kW. Such a flow-rate rate barely achieved 13-14% v/v even in the room of release.
Released at concentrations (usually over 18%) within a box filled containing an arrayof hard objects, (e.g. steel pipes) hydrogen detonations have been reported, which amore serious form of explosion, than a conventional gas explosion or deflagration, but
historically these are exceedingly rare (a hand-full worldwide in last 50 years) and withsound engineering can be completely avoided.

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Section 5 | Appliance Conversion

A summary of the wider physical properties of hydrogen in comparison to methane(CH₄) and natural gas are shown in Table 5.13.
Parameter

Units

Hydrogen

MethaneMolecular Weight

g/mol

2.016

16.04

Mass Density*

kg/Nm³0.09

0.72

Specific Gravity†

Air = 1

0.0696

0.555

K

20.2

111.6

MJ/kg

142

55.5

MJ/Nm³

13

40

MJ/kg

120

50

MJ/Nm³1136

Flammability Limits% volume

4.0-75.0

5.3-15.0

5.3-15**

Detonation Limits% volume

18.3-59.0

6.3-13.5

5.7-14**

Diffusion Velocity in Air

m/s

2

0.51

Buoyant Velocity in Air

m/s

1.2-9.0

0.8-6.0

Boiling Point
Higher Heating Value

Lower Heating Value

Natural Gas

0.78†

52.2†

47.1†

Ignition Energy
0.02

at stoichiometric mixturemJ

at lower flammability limit

mJ

10

20

Flame Temperature in Air

(°C)

2,045

1,875

Flame Velocity in Air

cm/s

265-325

37-45(29% in air)

0.29

Table 5.13. Comparison of Physical Properties of Hydrogen, Methane and Natural Gas

This data is taken from Data extracted from Ogden, 2008 except whereindicated otherwise.
* at Standard Temperature and Pressure.
† from the US DoE Hydrogen Databook.
** from the National Hydrogen Association Factsheet – Hydrogen safety.

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0.29**(9% in air)Section 5 | Appliance Conversion

5.6. Types of Hydrogen Combustion
To provide useful energy hydrogen may be oxidised to release energy andproduce water.
HHV

LHV

Heat Release from
Water Condensation:

kJ/kg

kJ/kg

kJ/kg

Hydrogen

141,790

121,000

20,790

%

100%

85%

15%

Methane55,53050,000

5,530

%

100%

90%

10%

Table 5.14. A Comparison of the Energy Release Properties of Hydrogen and Natural Gas

The most important driver for the use of hydrogen as a fuel is the very low levels ofemissions formed during combustion when compared to natural gas. There is no CO₂
produced and so the only pollutant created during combustion of hydrogen in air areoxides of nitrogen. This can occur as a result of the high flame temperature and thenitrogen content of air however, with careful engineering, this can be minimised oreven eliminated.
For simplicity there are four main routes by which combustion of hydrogen can occur:yy Flame combustion.
yy High temperature catalytic combustion.
yy Low temperature catalytic combustion.
yy Fuel cell.

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Each of these mechanisms has different characteristics which are summarised inTable 5.15.
Combustion
SystemFlame
Combustion

OperatingTemperature (°C)

1200 – 2,100

Positive
Characteristics
Relative to Natural Gas

Negative Characteristics
Relative to Natural Gas

High heat output

Relatively high NOx, unlessspecifically low NOx
technology employed
Risk of lightback

High
Temp Catalytic

500 – 1,200

Always low NOx

None

Low Temp
Catalytic> Roomtemperature –500 °C

Zero NOx.
No risk of fire

Low specific heat output
compared to a flame

Fuel Cell> Roomtemperature –900 °C

Simple and robust
design electric andheat output

None

Very low NOx

Table 5.15. Characteristics of Hydrogen Combustion Systems

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Section 5 | Appliance Conversion

5.6.1. Flame Combustion
When burnt in a bunsen burner, hydrogen and air burn broadly similarly to natural
gas and air, except that hydrogen flame front is moving more quickly so the flame
tends to be smaller.
The absence of carbon means no risk of carbon monoxide or smoke. Its pale blue
flame can be difficult to see, as the flame from entirely pure hydrogen emits little
radiation visible to the eye. However, the presence of impurities (at even the parts per
billion level) may produce a variety of colourations. If it were felt beneficial the flamecan (for example) be coloured red with an extremely dilute strontium (a benign alkali
earth element) solution of concentration 1 in a billion.
As indicated above, the combustion products are water vapour and some NOx. The
amount of NOx produced depends mainly on the flame temperatures.
Flame combustion is a generic system which includes a range of specific types ofburner including non-aerated and aerated (with partial or full pre-mixing of fuel andair). For each type there are a number of possible configurations of combustion ‘head’(shape and size, with nozzles of a range of shapes and size or permeable materials
giving a distributed flame, gas turbine combustion canisters and more) which
provide different combustion conditions, flame temperatures, heat release patterns
and consequently different levels of NOx formation. In terms of flame combustion,hydrogen can be considered as a 1st Family gas comparable with town gas (50-60%
volume/volume H₂).
Traditionally partially pre-mixed flame combustions were variants upon a bunsen
burner, but more recently distributed combustion of a premixed gas/air blend on thesurface of a plaque burner (see Remeha boiler below) can begin to function more
like a catalytic burner, i.e. the hydrogen and oxygen are brought together on a hot
catalytic surface.
The seminal work by British Gas (Jones, H. R. N. (1989)) provides an extensive
discussion of gas-fired combustion appliance design which while focussed onnatural gas also covers some of the implications for combustion of hydrogen in
mixtures or alone.

164Section 5 | Appliance Conversion

The combustion of hydrogen yields about 60% more water per kWh of heat releasethan natural gas, a 10 kW (input) hydrogen appliance will generate about 2.3 kg/h
of water. Such water is not significant regarding local outdoors climate, but shouldbe vented external to the property. Conversely it will create considerable additional
humidity where flueless appliances are used and any subsequent condensation
would be a concern due to the promotion of mould growth. Existing requirements
to limit ventilation has already led to the risks of higher humidity levels in modern
dwellings so this subject is well understood and can be satisfactorily addressed.
Interestingly 'The Hydrogen Homestead Study' presented by R.E. Billings at thesecond World Hydrogen Energy Conference in 1978 did not seem to pick up on thisrisk, and the benign nature of the emissions from hydrogen combustion was cited as
an opportunity to reduce heat loss significantly by decreasing ventilation. Essentiallythe hydrogen flue gas (steam) can be vented externally like a conventional applianceor the whole room can be better ventilated. Both routes have their advantages
and disadvantages.
Heat transfer from hydrogen flames, as for all flames, is split between conduction(which requires flame impingement on the surface of the material being heated),
convection (the flue gas and air heated by the flame move and carry the heat withthem) and radiation, where heat is radiated from materials at higher temperature tomaterials that are at lower temperature.
The water vapour generated in hydrogen flames contributes to their low radiancecompared to hydrocarbon flames even though the flame temperatures may besimilar. Therefore, a higher proportion of the heat from hydrogen flames mustbe transferred by the other mechanisms than is the case for natural gas flames,
but this is not considered problematic, as the excess air level with hydrogen canbe lower, with no risk of CO formation. German tests in identical domestic 20 kW
boilers, reported efficiencies of 87.7% and 87.9% (HHV) with hydrogen and natural
gas respectively.
Ref. Operation of 20 kWth gas-fired heating boilers with hydrogen, natural gas andhydrogen/natural gas mixtures, First test results from Phase 1 (March 1993) of the
Neunburg vorm Wald Solar Hydrogen Project K. Hoelzner A. Szyszka.

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Section 5 | Appliance Conversion

5.6.2. Catalytic Combustion
A catalytic combustion ‘burner’ functions differently to burners with defined flames.
They are based upon the reaction of hydrogen and oxygen on the surface of acatalyst; typically platinum, other noble metal or transition element compound. Theretends to be a continuum between these products and some conventional distributed
flame burners such as the sintered metal fully pre-mixed burners in modern boilers.
Their advantage is operation at much lower temperatures than flame combustion,
so they have lower NOx emissions and the red-hot nature of the catalyst (if operatingthat hot) can assist heat transfer.

Image 5.1. Examples of Distributed Flame Gas Burners from Remeha (left) and Alpha (right)

The British Gas book lists catalytic gas burners key points as having several
key points:
yy Can be diffusion (where pure hydrogen emerges from between the pores of thecatalyst) or pre-mixed, where a hydrogen/air mixture emerges from the catalyst;
yy Frequently consist of a pad of ceramic fibres with catalytic particles distributed
evenly through the pad;yy Require method of initiating ignition source – electric pre-heater/pilot light;
yy Flameless, resistant to drafts and changes in gas composition;
yy High radiant efficiencies (>50%) are achievable; andyy Low NOx.

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Section 5 | Appliance Conversion

Generally speaking, switching from hydrocarbon to hydrogen retains the advantages
and reduces or removes some disadvantages (no possibility of carbon deposition)
Some authors (e.g. Rapport SGC 201 – Catalytic burners in larger boiler appliances
Svenskt Gastekniskt Center – February 2009) even claim catalytic boilers can bemuch smaller. For example in Image 5.2.

Image 5.2. Comparison of Size of Conventional and Catalytic Boilers

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Section 5 | Appliance Conversion

Implications of Different NOx Levels from Flame andCatalytic Combustion
Historically the NOx levels from some domestic gas appliances (burning natural gas)
were quite high, although by 2013 the average had fallen to about 80 mg/kWh (refDECC DUKES and the UK NAEI). This compares to a modern low NOx condensing
boiler of < 40 mg/kWh. If the design average gas demand of the area of conversion(732 MW) were all to be burnt in the 2013 average gas burner this equals about 500
tonnes NOx per year. This in turn can be valued at between £2.8m and £11m per year
at the DEFRA lower and upper NOx valuations respectively (ref Valuing impacts on
air quality: Updates in valuing changes in emissions of Oxides of Nitrogen (NOx) andconcentrations of Nitrogen Dioxide (NO₂) September 2015)
Appropriate catalytic hydrogen appliances can effectively eliminate NOx from thedomestic combustion of gas. Although by nature of their catalysts and ingenious
design, catalytic combustion is currently always more expensive than flame
combustion. Unfortunately, with the current state of knowledge, the cost vs. NOx
curves for hydrogen appliances are not known. With the current high state of interestin hydrogen combustion by manufacturers (to a large degree generated by thisproject) this information should be available in the near future, but in its absence, thismatter is not explored further in this report and conversion costs have been based on
switching to conventional flame combustion.
In conclusion it is possible that on a conversion from natural gas to hydrogen, there
could be an opportunity to upgrade appliances with catalytic appliances which
would reduce (virtually eliminate) NOx emissions. This could be offered on an‘additional payment option’ whereby the homeowner could pay the difference forthis additional upgrade from their traditional flame combustion appliances, although
recent work with appliances manufacturers indicated their preference for DECC and
DEFRA to simply set maximum NOx levels.

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Section 5 | Appliance Conversion

5.6.3. Fuel Cells
At this stage the project is orientated around simple combustion; however low
cost, low carbon hydrogen offers considerable potential for the ‘packaging’ ofhydrogen fuel cells to produce local electricity and heat units, (i.e. CHP). A typical
low-temperature Proton Exchange Membrane (PEM) fuel cell will operate at an
efficiency of 60% electricity and a further 20% heat, (i.e. 80% overall HHV), andrespond within minutes. The potential ramifications of this regarding replacing
central power generation and transmission are very considerable. The pipeline gradehydrogen is unlikely to be of a quality suitable for direct use, but the incentives,
arising from competitive low-cost local hydrogen, should be large enough to drive
the design of sophisticated hydrogen clean up units, that will take the hydrogenfrom the predicted 99.9% (delivered) to 99.9999(9) % purity required for PEM fuelcells. Anecdotally this is already occurring and some automotive fuel cells (which
tend to have fewer operational hours than static cells) are reported to operate at up
15 ppm CO.
The term ‘packaging’ is used because the development of the underlying fuel cell
technology is extremely expensive, and limited to a few worldwide companies.
However many of these companies only wish to sell a raw ‘cell’. The integrationof these into usable products for use in the home or commerce contains very
considerable intellectual property, and the indication is that the UK has a significant
number of companies who could produce such packages. The UK does also
have companies with underpinning fuel cell knowledge and these could beparticularly well placed to launch OEM products. Several manufacturers of thecurrent generation of natural gas fuel cell use miniaturised SMR and shift reactors to
produce hydrogen which is in turn fed to a PEM fuel cell and almost certainly thesecompanies will move into selling just the hydrogen fuel cell.
In conclusion it is possible that, as with catalytic heating systems, on a conversion
from natural gas to hydrogen there could be an opportunity to upgrade applianceswith fuel cell appliances which would support electrical decarbonisation and help
accelerate this technology. This could be offered on an ‘additional payment option’
whereby the homeowner could pay the difference for this additional upgradefrom their traditional flame combustion appliances. Until these producers arecommercially developed this option, while worth considering, is not explored further
in this report and conversion costs have been based on flame combustion ‘switching’.

Testing and Certification of Hydrogen Appliances
The EU Gas Appliance Directive, which regulates the manufacture and sale of gas
appliances within the EU, already encompasses hydrogen appliances, which canbe judged against the essential requirements. There is currently a shortage ofEuronorms that make specific reference to hydrogen combustion, but this is readilysoluble once a market is established. There will be a requirement for IGEM and thegas industry to compile installation standards.

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Section 5 | Appliance Conversion

5.7. Current Status of Hydrogen Appliancesand Equipment
Appliances generally include such things as heaters, boilers and cookers usedin domestic and small commercial settings. Equipment refers to larger scaleequipment including such things as industrial boilers, industrial process burners andgas turbines.
As indicated above there are two general routes to hydrogen combustion – either
flame or catalytic. There are three main questions to ask about using hydrogen as thefuel for appliances and equipment:
yy Can they be operated safely?
yy Do they operate effectively/efficiently with minimal atmospheric emissions?
yy Are they aesthetically acceptable?

Image 5.3. Typical Natural Gas or Hydrogen Partially Premixed Gas Burner ref www. Cielotech.Wordpress.
Com

The first question can be addressed by attention to design, especially ensuring that
potential risks such as lightback are ‘designed out’. Lightback is where the flame
ceases to be located at the exits of the gas-air mixture orifices, but ignites within the‘gas jet’ (i.e. after the injector marked in black).
The second and third questions cover such issues as the effect of the low radianceand small size of hydrogen flames and high water contents of flue gases. Again
design is key.

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Section 5 | Appliance Conversion

Different applications may require different solutions. The main activities for which
natural gas is currently used are:yy Space heating: radiant and convective heaters;
yy Water heating: boilers (for space heating systems andDomestic Hot Water (DHW) production and dedicated water heaters;
yy Cooking: hobs and ovens;yy Process heating: process burners of a wide range of designs for many different
industrial processes, high pressure, high temperature hot water boilers, steam
boilers and steam generators; andyy Power generation: gas turbines.
Hydrogen can replace natural gas in all of these but inevitably using different
designs. Since the 1970s many natural gas appliances have been successfully
converted to hydrogen by academic and industrial researchers as well as by low
carbon minded home enthusiasts. Many of these home conversions have been
published on engineering hobbyist websites or in journals such as 'Home Power'.
Formal studies have also been undertaken such as 'The Hydrogen Homestead Study’
which successfully demonstrated the use of hydrogen fuel as a replacement for
natural gas in a range of appliances, and vehicles.
It is vital to stress that the current range of hydrogen appliances is extremely limited,
and arguably only functional in design, because of the extremely small market forsuch appliances (probably less than 100 units per year). What is important is that theprocess of combustion is well understood and proven. Given bulk supplies of gas
and a large domestic market, more sophisticated product will arrive.

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Section 5 | Appliance Conversion

5.7.1. Domestic AppliancesSpace Heating: Radiant and Convective Heaters
As indicated above the design of hydrogen fired domestic heaters can bevery simple

Image 5.4. Model #GFH6000 Green Flame Heater Hydrogen Fuelled Input 1.3 kW to 1.8 kW

Current designs are not aesthetically acceptable to many householders. However the
UK is Europe’s largest manufacturer of decorative gas fires, and there is no reason
why a range of attractive gas fires could not be developed relatively quickly. Manyelectric decorative fuel effect fires sell well and hydrogen offers the potential of a real
flame, therefore hydrogen could be regarded as less of a challenge than its electricalcounterparts. It has the added benefit over natural gas of not being able to form
carbon monoxide.

Water Heating: Boilers And Dedicated Water Heaters
In modern boilers the need to have accurate control over the combustion process
to minimise energy consumption and pollutant formation has resulted in the use ofburners where the air supply is positively controlled. Thus, the burners are in general
fully pre-mixed forced/induced draft pressure jet or distributed flame types.
An Italian manufacturer, Giacomini, have developed a highly efficient zero NOx
domestic boiler. This 5 kW (nominal heat output) condensing product is fully CE
marked and on the market. It employs a catalytic burner with a reaction temperatureof between 250 °C and 300 °C. Due to these low combustion temperatures theemissions of NOx, which is formed from nitrogen in the combustion air, are zero as
the combustion temperatures are not high enough for the formation mechanism
to occur.

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Section 5 | Appliance Conversion

Technical data of this hydrogen boiler is provided in Table 5.16 and the unit is shownin Image 5.5.
Technical Detail

Unit

Value

Nominal Heat Output

kW

5.01

Nominal Heat Power

kW

5.36

Useful Efficiency (Maximum)

%

106.7

Type of Gas

N/A

H₂

Inlet Gas Pressurebar

5

Purity of Hydrogen

%

99.5

Nm³/h

1.67

Maximum Temperature on Catalysts

°C

400

Average Exhaust Temperature°C

40

Maximum Hydrogen Concentration in the Reaction Channel%

3

Pressure in Reaction Channel

mbar

30

Maximum Condensing Water in Exhaust

l/h

1.34

NOx Concentration

ppm

0

CO Concentrationppm

0Maximum Pressure of Water

bar

3

Water Set Temperature

°C

30-60

Water Inside the Burnerl

2.1

Net Weightkg

40

Length

mm

888

Width

mm

520

Heightmm

314

Hydrogen Consumption at Nominal Power

Table 5.16. Technical Detail of the Giacomini Hydrogen Boiler

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Section 5 | Appliance Conversion

Image 5.5. Giacomini Hydrogen Catalytic Boiler (Giacomini, 2011)

Rated at only 5 kW it would have a very small market in Leeds, essentially limited
to large modern properties with space for a DHW tank. Unusually the unit is floor
mounted but of low profile.
Unfortunately, this product will require some modification for the mass rollout in
Leeds, (for example increasing the kW rating and reducing the required gas pressure)but it does currently sell throughout Europe to the hydrogen enthusiast market andadmirably demonstrates that the principle of commercial hydrogen appliances isalready in existence.
Prototypes of larger boilers have also been built for example report ‘Rapport SGC 201
Catalytic burners in larger boiler appliances Svenskt Gastekniskt Center – February
2009 Fredrik Silversand & Mikael Persson Fredrik Silversand & Mikael Persson Catator
AB’ contains a photograph of a 90 kWth catalytic burner for combustion of hydrogenat minimal excess air, to maximise thermal efficiency.
`

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Section 5 | Appliance Conversion

5.7.2. Cooking: Hobs and Ovens
There is a wide range of hydrogen fired cooking equipment already available on theinternet, mostly from US suppliers, although some in the UK, e.g. ITM Power basedin Sheffield, have marketed a range of hydrogen appliances. The latter was active inappliances until about 2010, when they withdrew from the market due to an absenceof demand. Pure Energy still sells hydrogen appliances.
Production: Two types available, ahydrogen cooker and a barbecue. Use:
Similar to any standard cooker. Thermal
output: from 500 to 5,000 W Emissions:no CO₂ and very low NOx emissions

Image 5.6. DIY BBQ

Hydrogen cooker from the Pure Energy
Centre, Unit 3, Hagdale Industrial
Estate, Baltasound, Unst, Shetland. ZE2
9TW United Kingdom.

Image 5.7. Hydrogen Cooker

Much of the US equipment seems ‘homemade’, but their very presence confirmsthat hydrogen can readily be used for cooking. Examples include DIY hydrogenburners designed and developed by Booth, D. & Pyle, W., (1993) and Pyle, W.,
Dabritz, J. & Healy, J., (1994). Some changes in design will be required particularly
as hydrogen produces considerably more water than natural gas per kWh of heat,
0.23 kg vs. 0.14 kg respectively (see also above). While creating a higher moistureatmosphere which, for example, cooks meat better, however, this can lead towater-logged pastry and bread.

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Section 5 | Appliance Conversion

Cooker manufacturers have always adjusted the ratio of convective to radiantheat transfer to the food being cooked and there is no obvious reason why theperformance on hydrogen should not be optimised.
A particularly interesting quote from the 'Hydrogen Homestead Investigation'is: "Tests of stove top burners indicate that 24 percent less energy is required toheat a pan with a hydrogen flame than with natural gas. This is possible since
the pan is placed directly in the flame without fear of incomplete combustion orcarbon deposition.”An example of a product with a more proven pedigree and better aesthetics is theHydrogen-Fuelled Stove built in Switzerland. The Swiss Federal Laboratory for
Materials Science and Technology (EMPA) have developed a catalytic hydrogenburner based on a highly porous silicon carbide (SiC) ceramic foam with a platinum
catalyst. This burner has been developed into a domestically aesthetic kitchen stovein Image 5.8.

Stove Top
Catalytic Burner
Air

Air Distributor
Catalytic Burner
Hydrogen distributor

Hydrogen

Image 5.8. Integrated Hydrogen Catalytic Burner (Ulrich, V. (EMPA), 2015)

This catalytic burner is formed from porous SiC plates coated with a platinum
catalyst and the air is provided so that combustion only occurs in the SiC layers. The
burner has been integrated into an appliance by placing in a casing with a glass top
to resemble current electrical domestic hotplates. This device also includes a heatexchanger that heats incoming combustion air to improve the product efficiency.
Product schematics are show in Image 5.8.
Almaas Technologies Limited is a small independent clean-tech company
conducting hydrogen burner feasibility work with the aim to develop fit-for-purpose
products of high quality and performance to support the decarbonisation of heatapplications and commercialisation of low/zero carbon energy systems. Almaas
Technologies have already demonstrated the conversion of catering appliances tohydrogen fuel in the UK.

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Section 5 | Appliance Conversion

5.7.3. Conclusions of Hydrogen Fired
Domestic Appliances
The absence of a bulk piped hydrogen means no significant demand or market
for hydrogen appliances and hence no mass market products available but theunderpinning knowledge is well known and given suitable demand products will
arrive within 2 to 3 years. A recent contract for DECC to investigate the potential fora UK hydrogen appliance chain has shown real enthusiasm especially amongst thelargest players. Interestingly Enertek Ltd, probably the UK’s largest outsourced gas
appliance R&D Company, are based in Hull. They would be enthusiastic to provide
development expertise to the large numbers of UK gas appliance manufacturers notlarge enough to have in-house resources.
The detail financial and contractual arrangements for the development of thesehydrogen appliances will need considerable thought. From the end of WW2 to thelate 1980’s three fuel (gas, electric and solid fuel) industries spent in today’s money inthe region of £10m per year on supporting ‘cutting edge’ technology in the domestic
and commercial sectors. Much of this was unsuccessfully spent on devices that,even at the time, looked too complex for the typical British householders use. Several‘advanced technology’ fully private sector projects have similarly failed after very
considerable investment; in two cases approaching £40m was spent. The situation
is different in Germany where people like to showcase their new heating appliance.
Because of the risks of this allocation of effort to the over-complex product, it isrecommended that a simple set of basic and/or budgetary constrained hydrogen
appliances are agreed, and it is the production and installation of these that thispromoted by Government and the gas industry. These can for convenience betermed ‘entry level’. Manufacturers will obviously be free to develop and market theirown more sophisticated models, but for the success of the project it is essential the‘entry level products’ are low cost, efficient, serviceable and reliable.
Obviously entrepreneurs can and will develop exciting ranges of entirely novelhydrogen combustion equipment, but for the viability of the whole project it is felt
much better to a limited but well proven and low-cost range of products. Suchproducts may require a different set of criteria to be eligible for financial support thanthe current understandable desire to only assist the most advanced technology.

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Section 5 | Appliance Conversion

5.7.4. Industrial Use of Gas and Process Burners
The UK is well-known around the world for its forced draft burners and both Dunphy
Ltd and Saake Ltd offer hydrogen fired versions of such units for process use.
Although not as problematic as in the domestic sector, the absence of low costhydrogen means there are few examples of the use of these. However the literature
is full of one-off trials, for example, Hydrogen Firing for a High-Capacity Rotary
Kiln was performed by Coates, R., Smoot, L. & Hatfield, K., (2015). In this paper it isreported that the burners were initially fired with natural gas and then switched overto hydrogen, performing six natural gas tests and thirteen hydrogen tests. Due to thebroad flammability limits of hydrogen-air mixtures, the firing rate was varied from95 MJ/hour to 158 MJ/hour with H₂ air ratios from 0.3 to 3.5. Interestingly Coates,
R., Smoot, L. & Hatfield, K., report that: 'A bright yellow flame, not due to impurities,
allowed for ready detection of the flame, as did the bright glow of a thermocouple
probe on the edge of the flame.'
They also reported that there was no unstable burning, pre-ignition or explosions
observed during the investigation. There are similar published papers on the firingof ceramic kilns etc. The only concerns appear to be potentially high NOx levels,
although some of the commercially available burners claim to overcome this. If
NOx remained a significant problem on an industrial scale (for example from somevery high-temperature furnaces) then a selective non-catalytic reduction (SNCR)
technique could be employed to reduce these levels. This SNCR technique iscommonly used as an NOx abatement technique and involves introducing urea into
the flue gases.
In the town gas era manufacturers of large ovens were aware of the risk of delayed
ignition, and British Gas supported considerable work venting (for example) breadovens. The risks with hydrogen will be greater, and multiple overlaid safety systems
will be necessary.
Whereas the conversion of some types of process firing may be challenging,hydrogen does burn with a flame broadly similar to natural gas. Depending upon
the required temperature, such a conversion will always be easy when compared tofiring with electricity, where temperatures are either limited by the resistive heating
element or, in the case of electric arc heating, by the geometry of the plant.
DECC funding may be appropriate for some ‘entry level‘ products. Some large
manufacturers might wish to accept a cash payment towards the installationof entirely new technology (e.g. a new kiln) that can optimise the advantagesof hydrogen.

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Section 5 | Appliance Conversion

Image 5.9. MAXON Wide-Range (R) Burner Running on Hydrogen. (Source: https://www.maxoncorp.com/
Directory/product/WIDE-RANGE-Burner/38/Natural-Gas-Burner-High)179

Section 5 | Appliance Conversion

5.7.5. Hydrogen in Gas Turbines
Hydrogen or high hydrogen content fuel gases are available from someindustrial processes.
The use of hydrogen as a fuel for large industrial gas turbines has been considered.
Chiesa et al discussed the issues they performed simulations to assess the impacts.
Their work found that it is possible to run gas turbines designed for natural gas onhydrogen, however the stoichiometric flame temperature must be limited to around2,300 K to comply with NOx emission limits without post-combustion flue gas NOx
abatement. Even with limiting the temperature of the flame only minor losses of
efficiency were observed. The flame temperature was limited by introducing adilutant gas into the hydrogen stream; the dilutant gases investigated were steam
and nitrogen. The use of nitrogen as a dilutant led to minor decreases in efficiency. A
considerable amount of work has been carried out on the safety aspects of burninghydrogen in Gas Turbines at the Health and Safety Laboratories at Buxton. The work
is commercially confidential, but it is understood encouraging.
The requirements of LNG plants have already prompted gas turbine manufacturers
to carry out work to extend the ability of their products to operate across wider
ranges of gas specification. There is further discussion of this whole matter within
Aero GT hydrogen burner characteristics. The Fusina Hydrogen project operated a
GE 10 gas turbine (11.44 MWe) on Venice Lagoon in 2011. No significant operational
problems were reported. The hydrogen was derived from the adjacent refinery.

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Section 5 | Appliance Conversion

Breakout: The Purity of Hydrogen.
For the detection of leakage, it is essential that the hydrogen being distributed
be odourised. Unfortunately, current UK odourants, e.g. NB, a blend of T-Butyl
Mercaptan (TBM) and dimethyl sulphide, are poisonous to many catalytic
and fuel cell combustion systems; this is not an issue when using ordinary
flame combustion (an attractive route for Leeds, at least in the short term)
but it is recommended that this matter is addressed right at the beginning ofdeveloping UK hydrogen infrastructure. Similar matters surround ensuring the
distributed hydrogen is of ‘optimum quality’. These are all relatively simple
issues, probably with limited cost implications, but getting the ‘wrong’ odourant
or a very sub-optimal gas quality could radically affect the ability of UK
industry to build upon its expertise.
This matter can probably be most simply addressed either by changing theodourant as currently being investigated in Japan to, for example, cyclohexene or by fitting pre-filters containing, for example, active carbon.
The purity of hydrogen is addressed more thoroughly in Section 2 but for
appliance design purposes it is proposed that the specifications CO, CH₄, andCO2 in hydrogen for the project be set as follows:CO		< 15 ppm

CH₄ 		

< 100 ppm

CO2		

< 10 ppm

H2 purity> 99.98%

Being realistic however, the hydrogen is likely to be saturated with water onan occasional basis, and may contain significant quantities of dust, and otherphysical impurities.

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Section 5 | Appliance Conversion

5.8. Conclusions
The current range of hydrogen appliances is very modest, as there is no bulk supply
of hydrogen, but manufacturers are enthusiastic. Given an agreed hydrogen roll out
plan between DECC, the gas industry and appliance manufacturers, ideally assisted
by appropriately directed UK Innovate funding, there is no reason why a range ofhydrogen appliances should not be available within 2 to 4 years. It is important that
this seed-corn funding be directed towards a limited range of ‘entry level’ productsthat can cost effectively permit the conversion of large numbers of domestic andcommercial properties.
Section 10, The H21 Roadmap identifies a requirement for a hydrogen demonstration
facility at Teesside, and associated trials in non-occupied followed by occupied
properties. Teesside seems the ideal location for this facility as it already has
significant supplies of hydrogen stored in its existing salt caverns. In the original
town gas conversion a significant problem for appliances manufacturers was theavailability of natural gas with which to test and certify their appliances.

182

SECTION 6

HydrogenTransmission
System
Gas Rig

Liquid Natural
Gas Storage

Salt
CavernCarbon Captureand Storage

Terminal

Compressor
StationSection 6
HydrogenTransmission
SystemCompressor
StationPressure
ReductionOﬀtakeSteam
MethaneReformer
Salt
CavernPressure
Reduction
StationPower
StationSalt
CavernDistrict
Governor

LEEDS

HULL

Section 6 | The Hydrogen Transmission System

6. The Hydrogen Transmission
System and Associated Infrastructure
History: UK Pipelining
For the first 150 years of the UK industry gas was manufactured from coal locally andwas referred to as ‘town gas’. However, there was a period in-between conversion fromtown gas to natural gas when both gases were being used in the UK.
In North America readily available natural gas was being used extensively acrossspecific states, notably Pennsylvania, well before the end of the 19th century. By 1950
natural gas accounted for more than 90% of fuel gas sales in the USA and by 1951 it
was reported that a new gas well was being brought into production every 23 minutes.
By the 1940s American gas companies had begun to store natural gas in liquid formby cooling it to -160 ˚C, reducing its volume by 600 times. By 1954 Conch International
Methane Limited had introduced refrigerated barges for transporting liquefied natural
gas over long distances. In February 1959 the first LNG delivery to the UK was made toa purpose built facility at Canvey Island, Essex. Over the next year, 12,000 tonnes of gas
were imported in this trial venture.
In 1961 the Gas Council committed to contracts to import 300,000 tonnes of LNG perannum from a vast gas reservoir that had been discovered beneath the Sahara. At thetime, this infrastructure project was the second biggest in Africa after the Aswan Dam.
Storage facilities at Canvey Island had to be greatly increased to match this new rate ofimport and in May 1966 it was announced an extra 84,000 tonnes of capacity was to beconstructed. This provided the UK with enough LNG to supply 10% of its needs.
Even though this gas was too rich for burners, the relatively small amount of natural
gas available (compared to towns gas) meant the gas could be blended with the town
gas to produce an immediately usable product. This product, however, was only usable
when it could be made available to gas customers. As a result, a high pressure (45 bar)gas transmission pipeline was constructed from Canvey Island to Leeds, a distance of
200 miles. (Charles Elliott – History of Natural Gas Conversion in Great Britain)

Hydrogen Transmission Pipelines
Transmission pipelines transport hydrogen through a pipe as part of the hydrogen
infrastructure. A hydrogen transmission pipeline connects the point of production withthe point of demand. The technology is well established and proven. The Rhine-Ruhrhydrogen pipeline was the first hydrogen transmission pipeline. Constructed in 1938 theinitial pipeline was 240 km long. This has been extended over its operational history andis now 600 km in length and is still in operation today. As of 2004, there are 900 miles(1,450 km) of hydrogen pipelines in the US and 930 miles (1,500 km) in Europe.

184Section 6 | The Hydrogen Transmission System

In order to transport the hydrogen from the production facility and associatedstorage caverns to Leeds, a new hydrogen transmission pipeline will be required.
This system connects the SMRs to the storage sites that support the system andthen onto to the local distribution customers.
It is likely that the production and storage facilities will be located on the east
coast (see Section 2, Demand vs. Supply). Therefore to supply the hydrogen
economically a high pressure pipeline will be required to transport the gas to thearea of conversion. This pipeline will operate at 40 bar to provide enough capacity
for moving the gas and to economically size the pipeline. There will be associatedequipment such as block valves, inspection facilities, and pressure reduction
stations (required to reduce the pressure at the injection points to the medium
pressure system).
Image 6.1 shows an example configuration of the hydrogen transmission system(HTS) and associated pipeline infrastructure required to accommodate the proposedhydrogen production and transportation.

185

Section 6 | The Hydrogen Transmission System

Connection
pipeline to CO₂

A - Teeside
Connection Detail

Methane feed
the National
Transmission
System (1 and 2)
Indicative location for
SMR Facility and salt
cavity storage (4)B - Hydrogen Transmission Pipeline

C - Hydrogen Transmission Pipeline- Pipeline to Inter-Seasonal Storage

1. Indicative route corridor
for the new 17 bar pipeline

Above ground installation
40/17barg pressure
reduction installation /multi-junction withconnection facilities for
future 40/17 barg west
and south expansion.

D - Leeds
Connection Detail

2. Pressure reduction
17/2 barg including
connections to the existing
MP Network (8 locations).

Image 6.1. Indicative Route Corridor of HTS and Associated Connections

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Section 6 | The Hydrogen Transmission System

The HTS can be divided into four discrete components:
1. Connections at Teesside. Connections here are threefold as the production plant
produces hydrogen, carbon dioxide and consumes natural gas.
—— Hydrogen pipeline.
—— Carbon dioxide network connection.
—— Natural gas supply.

2. The hydrogen transmission pipeline to Leeds.
3. The hydrogen transmission pipeline to the inter-seasonal storage facilities.
4. Connections at Leeds. This will include pressure reduction from 40 bar to
17 bar to feed the Leeds ring main and subsequently the 17 bar to 2 bar PRU
connections to the existing MP Leeds distribution network.
High pressure pipelines within the UK are numerous, and the UK has significant
experience building both the NTS and LTS over the last 50 years as well as various
other chemical pipelines to undertake such a task.
Whilst the suggested route corridor is practical for this level of study, the final
location of the hydrogen production facility and associated storage will be
determined as part of future work. This will include other stages such as, front end
design, planning, and economic assessments. In order to provide an indication ofcost, the route corridor for the pipeline has been established based on the locationalparameters identified in Section 2, Demand vs. Supply. Noting these parameters
give the longest reasonable hydrogen pipeline route these costs can be considered
to be an upper estimate of project cost at this level of detail. This pipeline could
be thought of as an additional part of the LTS and, if the hydrogen economy were
to be rolled out incrementally across the UK, could be the start of a hydrogentransmission system.
It should be noted that the route corridors identified and the location of associatedinfrastructure are indicative and have been produced to allow the pipeline costestimates to be developed.

187

Section 6 | The Hydrogen Transmission System

6.1. HTS Teesside Connections
Image 6.2 represents a simplistic diagrammatic representation of the anticipatedconnection and pipeline arrangements at Teesside. This includes:
SectionDescription

1

Minimum Offtake Connection (MOC) to the HP NTS for the SMR natural gas supply

2

High pressure natural gas pipeline connection to the SMR

3Carbon capture pipeline from the SMR to CCS infrastructure

4

Hydrogen pipeline connecting the SMRs to the salt cavity storage(intraday/seasonal storage)

Table 6.1. Assumed Technical Parameters

Connection pipeline toCO2 storage (3)Methane feed the
National Transmission
System (1 and 2)

Indicative location for
SMR Facility and salt
cavity storage (4)Image 6.2. Representation of Connections at Teesside

Aqua Pipeline Map 1 - DS3 | June 2016188

Section 6 | The Hydrogen Transmission System

Section

Pipeline
Description

Product

OperatingPressure (bar)Diameter(mm)

AssumedLength (km)1

Minimum Offtake
Connection (MOC)

Natural gas

70

N/A

N/A

2

Natural gas pipelinefrom LTS/NTS to
Natural gas
SMR facilities

70

250

1

3

CO₂ pipeline from
SMR facilities to
CCS pipeline.

CO₂(supercritical liquid)

140

200

1

4

Hydrogen pipelinefrom SMRs to
intraday storage

Hydrogen

40

200

1

Table 6.2. Technical Parameters – Teesside Connections

Teesside Connection Section 1 Minimum Offtake Connection:
To provide the supply of natural gas to the production facility, a connection will
be required to the high pressure network. This will require the construction of a
Minimum Offtake Connection (MOC), complete with fiscal metering and telemetry.

Breakout: Minimum Offtake Connection
A connection to the NTS is referred to as a minimum offtake connection. Thisis essentially a new valve connected (via a live gas operation) to the NTS toprovide a new gas supply. Most connections will serve one of the UKs GDN
offtakes feeding directly into the LTS. In the H21 Leeds City Gate project, thisconnection would supply gas direct to the hydrogen production facility.

The cost estimate assumes the connection pipelines and associated infrastructure
will be constructed using standard and well established techniques.

189

Section 6 | The Hydrogen Transmission System

MOCs are designed and constructed by the pipeline owner/operator. The developer
submits a request for a connection to the gas network through the Application toOffer (A2O) process, as set out in the Uniform Network Code (UNC). A connection
to the National Transmission System (NTS) currently takes up to three years tocomplete, with costs in the region of £3 m for a typical ‘green field’ site. Costs forconnections to the Local Transmission System (LTS) can be considerably quicker andless expensive. Connections to both the NTS and LTS can be constrained by network
capacity at the connection location and are usually subject to network capacity
studies prior to a connection offer being made.
The NTS Feeder 6 pipeline (30 inch Maximum Operating Pressure (MOP) 85 bar) runs
close to the anticipated location for the SMR facilities; there is also an LTS pipeline (12inch MOP 38 bar) close by. Both pipelines could be suitable to supply the natural gas
required for hydrogen production (subject to network capacity studies).
As a connection to the NTS is less likely to have network capacity constraints, andrepresents the highest cost and longest timescale this option has been used indeveloping the cost estimate for the scheme.

Teesside Connection – Section 2 Natural Gas Pipeline:
To transport the natural gas to the SMR facilities, a short section of pipeline will
be required.
To achieve the flows required to the SMR facilities the initial design calculations
demonstrate that the pipeline will need to be 250 mm diameter, approximately 1 km
in length with a Maximum Operating Pressure (MOP) of 70 bar.
This specific pipeline diameter and length fall outside the threshold to be considereda Nationally Significant Infrastructure Project (NSIP). However, we consider the
pipeline would be viewed as part of the overall scheme and would, therefore, needconsent as part of the required Development Consent Order (DCO) for the entire
project using the NSIP criteria for the entire scheme (i.e. all sections of the HTS could
be considered collectively).
We have assumed the pipeline would be designed and constructed as part ofthe main works design and build contract for the overall hydrogen transmission
system, and would be constructed using ‘main-laying’ techniques by theconstruction contractor. It is usual for this type of contract that the developer wouldpurchase the line pipe required for the project, and this is reflected in the costestimating methodology.

190

Section 6 | The Hydrogen Transmission System

Teesside Connection – Section 3 CO₂ Pipeline:
A by-product from the process of hydrogen production is carbon dioxide (CO₂). It has
been assumed that the CO₂ will be transported to the proposed Teesside Collective
Carbon Capture & Storage (CCS) network.
This will entail the design and construction of a short pipeline, approximately 1 km
in length. The pipeline will transport the CO₂ as a dense phase fluid. Initial design
calculations have identified the pipeline will need to be 200 mm diameter with an
MOP of 140 bar.
As with the natural gas pipeline it has been assumed that this CO₂ pipeline would be
progressed as part of the overall scheme and may, therefore, need consent as partof the Development Consent Order (DCO) for the entire project may be given. Also, aswith the natural gas pipeline, we envisage the CO₂ pipeline design and construction
would form part of the main works design and build contract and be constructed in asimilar manner.

191

Section 6 | The Hydrogen Transmission System

Teesside Connection – Section 4 Hydrogen Pipeline:
It is envisaged that a short length of hydrogen pipeline will be required to connect
the SMR facilities to the intraday salt cavity storage site.
The length of the hydrogen pipeline will be determined by the final location of the
SMR facilities and the salt cavity storage site. However, it is beneficial to site the SMR
facilities as close as is practical to the salt cavity storage site.
The SMR facilities will deliver hydrogen at a predetermined pressure and maximum
flow rate. We have therefore assumed this short section of hydrogen pipeline willneed to be 200 mm diameter and operate at an MOP of 40 bar.
As with the natural gas and CO₂ pipelines it has been assumed that this would beconsented, designed and built as part of the main works contract.

Teesside Connection – Cost Summary:This estimate has been developed as part of a pipeline ‘bottom-up’ cost estimate
process typical to any pipeline estimate undertaken in the gas industry.
Table 6.3 provides a summary breakdown of the CAPEX costs associated with theTeesside connections:
SectionEstimated CAPEX(£’000)Description

1

Minimum Offtake Connection (MOC)£3,0002

Natural gas pipeline from LTS/NTS to SMR facilities£1,4403

CO₂ pipeline from SMR facilities to CCS pipeline.

£1,9304

Hydrogen pipeline from SMRs to salt cavern
storage (intraday)£1,420Sub Total:

Table 6.3. Cost Summary – HTS Teesside Connections

192£7,790Section 6 | The Hydrogen Transmission System

6.2. B and C – The Hydrogen
Transmission Pipelines
To transport hydrogen from the production and storage facilities at Teesside to theLeeds distribution network and to the inter-seasonal storage sites north of Hull crosscountry hydrogen transmission pipelines will need to be constructed.

B - Hydrogen Transmission Pipeline

C - Hydrogen Transmission Pipeline- Pipeline to Inter-Seasonal Storage

Image 6.3. Indicative Route Corridor of HTS

193

Section 6 | The Hydrogen Transmission System

The main hydrogen transmission pipeline (Section B) will originate with a connection
to the hydrogen production facilities/proposed salt cavity storage facility in thevicinity of Seal Sands, and terminate at a Pressure Reduction Installation (PRI), northeast of Leeds. The pipeline will connect to a further hydrogen pipeline (Section
C), through a multi-junction arrangement, connecting the hydrogen transmission
pipeline (Section B) to the proposed inter-seasonal storage facilities to the northof Hull.
It is worth remphasizing that this pipeline route is for the purpose of costestimation only. It would, by necessity, need to be confirmed in later design andplanning phases.
To support the cost estimating process, an indicative schedule was developed.
This was based on typical durations for similar pipeline projects constructed in the
UK over the last decade, and assuming the current consenting processes would
be applied to the scheme. The overall timeline for this programme is simplistically
represented in Section 9, The Next Steps - Program of Works and is anticipated up
to 6 years duration.

Planning and Consents
Under the current regime, a major cross-country pipeline scheme of this nature
would most likely be classified as a NSIP and require a DCO be granted by thesecretary of State.
This requires the developer to carry out surveys to identify all feasible route corridors
for the proposed pipelines, identify landowners and interested parties affected by
the proposed pipeline routes and undertake consultation to determine the preferredroute corridor and final route alignment for the pipelines. Once the preferred route
corridor has been identified a detailed Environmental Impact Assessment (EIA) is
required, from which an Environmental Statement (ES) produced. In parallel withthese activities easement purchase and land compensation negotiations would
be undertaken.
The indicative programme indicates a period of 30 months for these activities. The
pipeline cost estimate has used historical project data from similar cross country
pipeline projects to estimate the likely durations and costs.

194

Section 6 | The Hydrogen Transmission System

Breakout: NSIP Criteria
The following criteria determine if an infrastructure pipeline qualifies as an NSIP,
taken from Section 20 (Planning Act 2008) Gas Transporter pipe-lines.
(1) The construction of a pipe-line by a gas transporter is within Section 14(1)(f)only if (when constructed) each of the conditions in subsections (2) to (5) is
expected to be met in relation to the pipe-line.
(2) The pipe-line must be wholly or partly in England.
(3) Either—a) the pipe-line must be more than 800 millimetres in diameter and morethan 40 kilometres in length, or(b) the construction of the pipe-line must be likely to have a significant effecton the environment.
(4) The pipe-line must have a design operating pressure of more than 7
bar gauge.
(5) The pipe-line must convey gas for supply (directly or indirectly) to at least
50,000 customers, or potential customers, of one or more gas suppliers.
(6) In the case of a pipe-line that (when constructed) will be only partly inEngland, the construction of the pipe-line is within section 14(1)(f) only to theextent that the pipeline will (when constructed) be in England.
(7) “Gas supplier” has the same meaning as in Part 1 of the Gas Act 1986 (c. 44)(see section 7A(11) of that Act).

Technical Assumptions
There are currently no hydrogen pipelines in the UK that run cross country. However,there are pipelines distributing hydrogen to multiple users on Teesside across thechemical complexes at Seal Sands, Billingham, and Wilton. There are hydrogenpipelines in service around the globe. There are also pipelines of similar design for
the transportation of other fluids like ethylene in the UK. Current regulations anddesign standards already encompass hydrogen, and the study is based on thosecurrent regulations such as the Pipeline Safety Regulations and standards such as
British Standards Institutes PD 8010 and BS EN 14161. The guidance also exists fromthe European Industrial Gases Association (EIGA), specifically for the design andconstruction of hydrogen transmission and distribution pipeline networks.

195

Section 6 | The Hydrogen Transmission System

The distance and design of the pipeline are such that pipeline compression, tohelp move the gas through a pipeline, is not required. The production facility will
provide an inlet pressure to the transmission pipeline of 40 bar; initial calculations
demonstrate that the pressure drop on the transmission pipeline will deliver an outletpressure of no less than 20 bar.
A pipeline diameter of 650 mm and a MOP of 40 bar have been calculated toaccommodate the anticipated maximum peak day demand for the scheme, see
Section 2, Demand vs. Supply.
We have assumed that the pipeline and installation design would be awarded toa Main Works Contractor under a Detailed Design and Construct contract. The
indicative programme has an allowance of 6 months for tender and contract award
and a period of 12 months for Detailed Design activities.

Pipeline Materials
The hydrogen transmission pipeline will be built an appropriate steel as defined by
the relevant design codes.
Hydrogen can have different effects on many metallic materials which are wellknown. These include embrittlement which occurs at elevated pressures. These
include steels (especially high strength steels), stainless steel, and nickel alloys.
Therefore, design codes recommend lower strength steel pipe is used for thedesign of hydrogen transmission pipelines although the recommended types ofsteel are already used in pipelines such as API 5L grade X52. Table 6.4 specifies the
anticipated pipe specification for the hydrogen transmission pipeline:
SectionDia(mm)

OperatingPressure bar

Material
Grade

Length
(km)

B

650

40

L360

114

C

450

40

L360

76

Table 6.4. HTS Pipeline Sectional Details

Cost metrics for pipelines are well known and established from historical projects.
Costs can be adjusted using typical factors in the industry based on inflationary
movements, market changes, and material cost changes. Here the cost metrics are
based on established historical norms and have been market tested through initialquotations from a steel pipe manufacturer. The indicative programme developed forthe scheme identifies a period of 18 months for manufacture and delivery of line pipe.

196Section 6 | The Hydrogen Transmission System

Pipeline Construction
Cross country pipelines are usually constructed between April and October to avoid
damage to agricultural land, with advanced activities such as site establishment,
construction of pipe storage facilities and environmental mitigation measures
undertaken in February and March. Due to the length of the transmission pipelines,
it has been assumed that the Main Works Contractor will adopt a two season
build, with pipeline spread ‘winterised’ over the intervening winter period toprovide environmental protection. The pipeline will be constructed using standard
construction methodologies, by an experienced pipeline construction contractor.
Cross-country construction of natural gas pipelines is a well-established techniquethat can be applied to all welded steel pipelines whether they transport natural gas
or hydrogen. Construction is undertaken on a ‘production line’ basis, i.e. by a series ofdifferent specialist ‘crews’ who each perform a specific function and move along thepipeline route in order.
Individual operations can move forward at a rate of 500 m to 1 km a day. Typicallycross country pipeline construction will include the following activities:
yy Working width preparation;
yy Fencing;yy Pre-construction drainage;yy Topsoil strip;
yy Pipe stringing (lay out the pipe along the working width);yy Field bending;yy Pipe welding and inspection;yy Non-destructive weld testing;yy Joint coating;yy Trench excavation;
yy Lower and lay;yy Backfill;yy Pipeline tie-ins;
yy Reinstatement;yy Post-construction drainage;yy Hydrostatic testing; andyy Commissioning (final gauge plate and calliper surveys, drying
and commissioning).
In addition, special crews will be established for operations such as crossings, (e.g.
road, rail, river, and canal).

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Section 6 | The Hydrogen Transmission System

There are several trenchless construction techniques that would be utilised for the
majority of road, rail, river, and canal crossing. These include;
yy Auger boring.
yy Tunnelling (including pipe-jacks).
yy Micro-tunnels.
yy Horizontal Directional Drilling (HDD) (Image 6.4)

Image 6.4. Horizontal Directional Drill (HDD)

Across rural areas the pipeline will be laid to contour at a depth of cover of 1.2 m;
the minimum depth of cover for roads, rivers, and canals is 2 m. The pipeline may belaid deeper at specific locations and crossings. The final depth would be determinedfollowing extensive surveys by the detailed design.
After the pipeline has been laid it will be cleaned and tested. This will take theform of a hydrostatic test (undertaken in sections) which involves filling the pipeline
completely with water and raising the pressure to a predetermined level for a
24 hour period.
Following successful hydrostatic testing of the pipeline the test water will be
removed from the pipeline and the pipeline dried prior to commissioning. This will beachieved by introducing super dry air along the pipeline and vacuum drying until therequired ‘dew point’ is achieved.
To ensure the integrity of the constructed pipeline coating a Cathodic Protection (CP)system will be installed. CP systems work by passing a small electric current throughthe completed pipeline which reverses corrosion currents present in the soil by thecreation of a pipe to soil negative potential at any small defects to the pipeline’s
epoxy coating.

198

Section 6 | The Hydrogen Transmission System

Following commissioning the pipeline will be internally mapped using an in-line
inspection tool, known as a Pipeline Inspection Gauge (PIG). The PIG passes throughthe length of the newly installed pipeline to produce a ‘fingerprint’ to give an
indication of the initial condition within the first twelve months of pipeline operation.
As part of the ongoing maintenance regime, subsequent runs will compare theinformation from the ‘fingerprint’ run with the current condition to give an indication ofand deterioration and maintenance requirements.

Breakout: Pipeline Inspection Gauge (PIG)
Trap Facilities
A pipeline inspection gauge is a mechanical device which is loaded into thepipeline from pipe trap facilities at either end (loading and receiving traps) of apipeline. The PIG travels through the pipeline ‘pushed’ along by the flow of thegas. After its journey, the onboard computer data is downloaded and analysedby pipeline experts to ascertain the condition of the pipeline and establish if
any remediation or maintenance works are required.
This is typically undertaken on a ten yearly cycle. Below is a typical example ofa PIG trap facility.

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Section 6 | The Hydrogen Transmission System

Cost Summary: The Hydrogen Transmission Pipelines(Sections B and C)This estimate has been developed as part of a pipeline ‘bottom-up’ cost estimate
process typical to any pipeline estimate undertaken in the gas industry. Table 6.5
provides a summary breakdown of the CAPEX costs associated with the hydrogentransmission pipelines.
Estimated CAPEX(£’000)SectionDescription

B

Section B – Hydrogen transmission pipeline from the
SMR facilities to the Pressure Reduction Installation (PRI)/
multi-junction situated north east of Leeds£125,090

C

Section C – Hydrogen transmission pipeline from thedeep salt cavity storage facilities (inter-season) to thePressure Reduction Installation (PRI)/multi-junction
situated north east of Leeds£71,000

Sub Total:
Table 6.5. Cost Summary – HTS Pipeline

200£196,090

Section 6 | The Hydrogen Transmission System

6.3. Connections to the Leeds Distribution
Network
To connect the hydrogen production and storage to the customers at Leeds,
connections will be required to the existing Leeds distribution network. This willentail construction of a new 17 bar ring main, with connections to the existing MP
distribution network at strategic points.
Image 6.5 represents a simplistic diagrammatic representation of the anticipatedconnection and pipeline arrangements. This includes:
SectionDescription

1

17 bar hydrogen pipeline from the Pressure Reduction Installation (PRI) at thetermination of the hydrogen transmission pipelines

2Connections to the existing MP Leeds distribution network through new PRSs

Table 6.6. Leeds Connection Elements

1. Indicative route corridor
for the new 17 bar pipeline

Above ground installation
40/17barg pressure reduction
installation / multi-junction
with connection facilities for
future 40/17 barg west andsouth expansion.

2. Pressure reduction
17/2 barg including
connections to the existing
MP Network (8 locations).

Image 6.5. Representation of Connections at Leeds

Aqua Pipeline Map 2 - DS3 | June 2016201

Section 6 | The Hydrogen Transmission System

Section 1 – 17 Bar Pipeline (Distribution Ring Main)
To connect the hydrogen transmission system to the existing Medium Pressure (MP)
network at Leeds, a new ring main will need to be constructed. The ring main will
start at the Pressure Reduction Installation (PRI) at the end of the main transmission
pipeline. The ring main will run around the north and south of Leeds and connect
into the existing MP network at 8 locations around the city. The pipeline will beapproximately 24 km in length. The precise routing of the pipeline and locations forthe connections to the existing Leeds MP network will be confirmed through thedetailed design process.
Initial design calculations demonstrate that a 400 mm diameter pipeline, with a
Maximum Operating Pressure (MOP) of 17 bar, will be required to accommodate thevolumes of hydrogen required for the Leeds area. Although there have been recent
technical advances in the development of HDPE pipeline materials, we have allowed
for the construction of a steel pipeline (grade X52). The pipeline MOP has been
specifically designed to negate the need for pre-heating at the 17 bar/2 bar pressure
reduction facilities. Pre-heating on gas sites is only required for pressure drops
greater than 15 bar and add significant cost and land footprint to pressure reduction
sites. The 17 bar hydrogen distribution ring main would be designed and constructed
as part of the Main Works Contract.
It is important to note that whilst this works has been included in the price for the
HTS system in reality during GD2 (2021 to 2029) NGN will have a requirement to build
an almost identical natural gas ring main around the city to accommodate removal of
the current 17 bar system to facilitate the High Speed 2 rail link.

202

Section 6 | The Hydrogen Transmission System

Section 2 – Connections to the Existing Leeds MP Network
The hydrogen system will require connections to the existing Medium Pressure (MP)
network in Leeds. Hydrogen will then be delivered to end users through the existing
Leeds distribution network.
Initial calculations demonstrate that this can be achieved through eight connection
locations. In the cost estimate, our ‘worst case’ scenario has been priced with theconstruction of seven new PRUs and conversion of one existing facility.
Image 6.6 represents a typical PRU on the natural gas distribution network.

Image 6.6. Typical Distribution Network PRU

203

Section 6 | The Hydrogen Transmission System

Leeds Connection – Cost Summary:This estimate has been developed as part of a pipeline ‘bottom-up’ costestimate process typical to any pipeline estimate undertaken in the gas industry.
Table 6.7 provides a summary breakdown of the CAPEX costs associated with
the Leeds connections.
SectionEstimated CAPEX(£’000)Description

1

17 bar hydrogen pipeline (distribution ring main)£20,5402Connections to the existing MP Leeds distribution networkat eight locations 17 bar to 2 bar (seven new build PRUs andmodifications to one existing PRU)

£5,850Sub Total:£26,390

Table 6.7. Cost Summary: Connections at Leeds

204

Section 6 | The Hydrogen Transmission System

6.4. Operating Costs (OPEX)
Once constructed and commissioned the hydrogen transportation system will incur
ongoing operation and maintenance costs. An assessment has been made of thelikely operational and maintenance costs associated with the scheme. The hydrogenpipeline and associated infrastructure will have a design life of 40 years. Therefore,
OPEX costs have been annualised assuming 40 years of operation with adjustments
for inflation.
The maintenance regime adopted for the hydrogen transportation system and theassociated infrastructure will be determined by legislation. Certain components ofthe system will be subject to inspection regimes specified in legislation, such as the
Gas Safety Management Regulations (GMSR), Pressure System Safety Regulations(PSSR) and Pipeline Safety Regulations (PSR). Table 6.8 details the likely operationand maintenance costs;

Cost (unit)

Design Life
(Yrs)

Annual OPEX
by
Category (£’000)

Management and Administration

per annum

40

42

Surveillance

per annum

40

27

Pigging and On-Line Inspection(OLI) Runs

10-yearly

40

63

Cathodic Protection Surveys

per annum

40

75

CIPS Survey – ‘Dig ups’

per annum

40

126
incl.

Leakage Surveys
per annum

LabourTotal Yearly OPEX

40

168
500

Table 6.8. HTS Operating Costs

205

Section 6 | The Hydrogen Transmission System

6.5. Hydrogen Transportation System
Conclusions
To enable a cost estimate for the HTS and associated infrastructure to be developed
a potential route corridor for the HTS was identified. It should be noted that the route
corridors identified and the location of associated infrastructure are indicative andhave been produced to allow the pipeline cost estimates to be developed.
This estimate has been developed as part of a pipeline ‘bottom-up’ cost estimate
process typical to any pipeline estimate undertaken in the gas industry. The overall
estimate for the hydrogen transmission system is:
Capital Costs

Operating Costs
per annum (£’000s)

Connections at Teesside£7,790

N/A

Section B – Hydrogen transmission pipelinefrom the SMR facilities to the Pressure
Reduction Installation (PRI)/multi-junction
situated north east of Leeds£125,090

N/A

Section C – Hydrogen transmission pipelinefrom the deep salt cavity storage facilities(inter-season) to the Pressure Reduction
Installation (PRI)/multi-junction situatednorth east of Leeds£71,000

N/A

17 bar hydrogen pipeline (distribution
ring main)£20,540

N/A

Connections to the existing MP Leeds
distribution network at eight locations 17
bar to 2 bar (seven new build PRUs andmodifications to one existing PRU)

£5,850

N/A

Operating costs as per Section 6.4

N/A

500

£230,270

500

Cost Summary (£'ooo m)

Total
Table 6.9. Cost Summary – HTS and Associated Connection

A proposed design for the HTS and associatedinfrastructure has been costed at £230 million
CAPEX and £500,000 per annum OPEX

206

SECTION 7

Carbon Captureand Storage

Section 7
Carbon Captureand Storage

Gas Rig

Liquid Natural
Gas Storage

Salt
CavernCarbon Captureand Storage

Terminal

Compressor
StationPressure
ReductionOﬀtakeCompressor
StationSteam
MethaneReformer
Salt
CavernPressure
Reduction
StationPower
StationSalt
CavernDistrict
Governor

LEEDS

HULL

Section 7 | Carbon Capture and Storage

7. Carbon Capture and Storage
History: Summary of Global CCS
Carbon Capture and Storage (CCS) technology is proven and in use around the world,with 15 large-scale CCS projects operational. Statoil has been implementing CCS at the
Sleipner field, Norwegian North Sea, for 10 years. The technology of CO₂ transport andinjection have been in use for more than 30 years for enhanced oil recovery in the UnitedStates. Separation of CO₂ from gases has been an industry standard process for over
40 years. Three CCS projects which started operation in 2015 are summarised below.
Boundary Dam: The world’s first largescale CCS project in the power sector, at
SaskPower’s Boundary Dam facility in
Saskatchewan, Canada, has just celebrated
one year in operation.

Image 7.1. Provided by SaskPower

Quest: Launched in Alberta, Canada in November 2015, the Quest project is capableof capturing approximately 1 Mtpa of CO₂ from the manufacture of hydrogen for
upgrading bitumen into synthetic crude oil.
Quest is the first large-scale CCS project inNorth America to store CO₂ exclusively ina deep saline formation, and the first to doso globally since the Snøhvit CO₂ Storage
Project became operational in Norway
in 2008.

Image 7.2. Provided by Shell

Uthmaniyah: Launched in Saudi Arabia in July 2015, the Uthmaniyah project is thefirst operational large-scale CCS project in the Middle East. The project is capable ofcapturing around 0.8 Mtpa of CO₂ from a natural gas liquids recovery plant for injection
into the Uthmaniyah production unit for Enhanced Oil Recovery (EOR).
2016 and 2017 will be significant years for CCS with seven large-scale CCS projects due
to come on stream. Importantly these will show CCS in action in many different countries
including the United States, Canada, the United Arab Emirates (UAE) and Australia, as
well as across many industrial sectors. It will take the number of large-scale projects inoperation to 22.

208Section 7 | Carbon Capture and Storage

7.1. UK Carbon Capture and Storage
position
The rationale of replacing natural gas with hydrogen is based on the premise ofa significant reduction in carbon emissions. Current economics show the costadvantage of SMR+CCS vs. renewable, but it is accepted that this study presumes
that CO₂ sequestration service is available ‘over the fence’. The timing of thesimultaneous delivery of both the production of hydrogen and disposal of carbon
may be difficult but it is also not essential. SMRs can be retrofit with CO₂ capture
capability so the critical point in any future hydrogen conversion decision is knowingthat CCS is under development. The two do not necessarily have to be available
at the same point in time (see Section 9, Next Steps – The Programme of Worksfor political timelines). Some considerations when reviewing the CCS impact on ahydrogen conversion are provided below:
yy The technology chosen of post-combustion scrubbing of the flue gases means
these SMRs can be operated without the CCS section of the plant commissioned.
yy Hydrogen is a low carbon energy vector, which can be generated from fossil
fuels with CCS, biomass or renewable via electrolysis. Its use is not dependent
upon CCS, but CCS is a good bridgehead to enable the demonstration ofhydrogen distribution at a predicatable price.
yy By providing a long-term base load, not subject to the vagaries of theinternational market (like for example steel), such SMR+CCS plant could act as
the perfect catalyst to bring forward CCS pipelines.

UK CCS Position
The focus to date has been on power generation with CCS. DECC have run twocompetitions between 2007 and present to select a project to fund. Despite many
projects coming forwards, neither competition has resulted in a project being
selected. Most recently in November 2015 funding was withdrawn from Peterhead
and White Rose CCS projects, with value for money being the reason cited.
Front End Engineering Design (FEED) has been completed for six CCS projects;
yy Peterhead to Miller Enhanced Oil Recovery.
yy Don Valley to Endeavour with EEPR funding.
yy Kingsnorth to Hewett in Demo 1.
yy Longannet to Goldeneye in Demo 1.
yy Peterhead to Goldeneye in Demo 2.
yy White Rose to Endeavour in Demo 2.
Two other power CCS projects have been proposed;yy Teesside (Progressive Energy); in various configurations.
yy Caledonia Clean Energy Project (Summit Power) at Grangemouth. A gasified coalproject currently undertaking a feasibility study with DECC funding.

209

Section 7 | Carbon Capture and Storage

The focus for industrial CCS, capturing CO₂ from industrial sources, has beenat Teesside. The Teesside Collective has published several reports which build
into a business case for industrial CCS. Similar studies are getting underway
at Grangemouth.
Pale Blue Dot is currently completing a Strategic UK CCS Storage Appraisal
Study, which has selected and appraised five additional CO₂ storage sites, deep
underground and offshore, around the UK.
The UK is well positioned for CO₂ storage in the southern and central North Sea andEast Irish Sea, with capacity for storing UK emissions and potentially emissions fromother European countries.
Image 7.3, shows the availability of UK carbon capture and storage sites. (From theStrategic UK CCS Storage Appraisal Project).
There are many other candidate storage sites around the UK with significant storage
potential and in summary the key message is 'The UK has lots of storage'.

Image 7.3. UK CCS availability

210

Section 7 | Carbon Capture and Storage

7.1.1. The Reason for the Involvement of the
Public Sector in CO₂ Disposal
There is a very long history of public sector involvement, in both the organisation andoversight of the ‘waste’ disposal sector. This includes domestic refuse, nuclear waste
and flood water. The allocation of costs associated with carbon emissions from large
combustion/process plant have strong political overtones, and this coupled with thevery large investments required and not insignificant technical risk can result withinaction becoming the easiest route.
The advantage of using SMR+CCS plants as the backbone of any sequestration
pipeline then becomes very important. These plants will operate 365 days/year(8,760 hrs/year) and can be designed to have a fairly flat CO₂ export line, (i.e. withmore storage), and the CO₂ is a concentrated source. There are not the impurities
likely to arise from coal gasification plants. The growth in CO₂ to be disposed of could
be planned, especially if it was confirmed that Teesside, as in the H21 Leeds City
Gate project, was to be the centre for hydrogen production for the North East.
It is thought useful to consider the advantages public sector support of Industrial
CCS (such as this) over support for CCS on a power plant operating in a ‘free market’.
By virtue of the substantial energy use and technical complexity of CCS on a
power plant, the economics of the whole generating station must be changed. Thisadjustment is likely to be very material regarding the ‘cost merit’ order of the plant;
this raises the potential of commercial claims from disadvantaged competitors,
and can (in-turn) easily end in over-complex legal documents, especially if the
CCS process itself is relatively unproven in a retrofit situation. Industrial CCS is very
different. The scale is smaller, there is no half-hourly merit order and (for the design
chosen) the CCS is an ‘add-on’. The project should be contractually much simpler,
and there should be little need to involve the market supervision authorities provided
that the whole deal is transparent and viable.

211

Section 7 | Carbon Capture and Storage

7.2. Teesside Collective Report (Taken fromthe 2015 Industrial CCS on Teesside
Business Case)
As discussed in Section 2, Demand vs. Supply, the location of the SMRs (at thisconceptual stage and subject to detailed design) has been selected at Teesside.
This is for three reasons; firstly, it is in the UK’s largest chemical industrial heartland,secondly, it has available salt caverns and finally it has a well-developed proposed
carbon capture scheme. The Teesside and Tees Valley region are one of thelargest industrial clusters in the UK covering a diverse sector base of chemicals,
petrochemicals, steel production, and energy companies. The cluster employs
approximately 12,000 people generating a GDP of £10 bn and exports of £4 bn
per annum. The Teesside collective report has proposed a comprehensive
carbon capture and storage scheme, some of the outputs from that report arepresented below.

Image 7.4. Teesside Collective Report Summary212

Section 7 | Carbon Capture and Storage

This initial study had four industrial partners: Sahaviriya Steel Industries (SSI),
GrowHow, BOC and Lotte Chemicals. The work focused on building a business casefor an industrial CCS (ICCS) network on Teesside beginning with the CO₂ emissions
from the production sites of the four industrial participants. The location of these sites
and the many other industrial sites on Teesside are shown in Image 7.5.
Image 7.6 illustrates the five elements of the ICCS project. In this report all the key
elements of an industrial CCS network: capture, gathering, transportation and storage
are considered.

Image 7.5. The Teesside Collective Five Industrial Partner Locations

Image 7.6. The Five Elements of the ICCS Project213

Section 7 | Carbon Capture and Storage

7.3. Carbon Capture from Steam Methane
Reformers Using a Post-combustion
Scrub of the Flue Gases
The technology chosen for this report recommends post-combustion capture of
the CO₂ and comprehensive details are provided within the Technical Breakout
below. Recovered heat is used within the SMR for pre-heating, but there is an excess
of good quality heat in the form of steam from the process. This can be used to
produce power for site utilities or export.
Additionally, the steam is also very useful when capturing the CO₂ flue gases fromthe process. There are a number of process options and proprietary technologies tocapture the CO₂. For this project the simplest and most common process is to scrub
the mixed gases in an absorber tower by contact with MEA (monoethanolamide),a liquid which preferentially binds with CO₂. The liquid is collected at the bottom,
leaving the flue gases with much lower CO₂ concentrations. A typical economic
design would reduce the CO₂ emissions by a factor of 10.
The MEA liquid, now rich in CO₂, goes into a regenerator tower which is heated by
the excess steam from the SMR. This ‘drives-off’ the CO₂ from the liquid. The MEA issent back to the absorber tower, and the CO₂ gas is dehydrated and compressed forexport from the plant to the shared CO₂ transport system.

214

Section 7 | Carbon Capture and Storage

Technical Breakout
Alternative configurations for carbon capture from SMR plant.
The final recommendations of this report focus entirely on conventional designsof SMR to which carbon capture has been added. This is the correct decision forsuch first generation plants, where the major innovation is the distribution of bulkhydrogen, not the details of its production. However, this short section does detailoptions that could be available in the medium term which may:
reduce costs;
increase SMR thermal efficiency; andincrease % CO₂ capture.
There are two main alternatives for the SMR hydrogen production processwith capture.
1) Post-combustion capture of CO₂. A flue gas scrubbing column is fitted
downstream of a conventional process (the route adopted here). It is the routecurrently recommended by AMECFW.
Post-combustion Capture of CO₂ in SMR Based
Hydrogen Production Process

Power
Gen

CO₂ LeanFlue-gas

CO₂

Power
Steam

Regeneration
Steam

CO₂
CaptureH₂ Product

Methane

CO₂ Rich
Flue-gas

Process Steam

SMR+Shift+Steam Generation
Make up
fuel

PSA
Purge Gas

CO₂/CH₄/H₂

215

Section 7 | Carbon Capture and Storage

Technical Breakout (continued)2). The other is to install capture in the syngas stream, (i.e. the highpressure gas stream within the plant), and to recycle the methane in
the Pressure Swing Adsorption (PSA) off-gas after first separating it in amembrane. This is described as pre-combustion.
Pre-combustion Capture of CO₂ in SMR Based
Hydrogen Production Process

Power
Gen

Power
Steam

CO₂
H₂ Product(Premier Cru)

MethaneRegeneration
Steam

Process Steam

SMR+Shift+Steam Generation

CO₂
CapturePSA(High Recovery)

Purge
Gas

Membrane

CH₄/H₂H₂ Fuel for Reformer

3 StageComp

H₂ Fuel for(Vin du Pays)

Both processes have been roughly simulated with the intention of establishing
the carbon footprint and the overall conversion efficiencies. A secondary
objective was to explore the extent to which the heat and power requirementsof the capture unit could be provided by the waste energy streams from thebasic hydrogen process. Two variants of each process were simulated to gauge
sensitivity to export hydrogen purity/recovery performance of the PSA unit.
A few basic process assumptions were made for the comparative simulations.
These are summarised below
yy For all cases feed is preheated to 600°C in the furnace convection section. The
reformer operates at 20 bara. A steam carbon molar ratio of 3:1 is used. HT and LT
Shift reactions are at about 400°C and 220°C. Recovery of CO₂ for post combustion
cases is 90% and for the pre-combustion case 98%. For the two post-combustion
cases the PSA operates at 80% and 90% recovery of hydrogen respectively.
yy For the two pre-combustion cases the PSA operates at 70% and 90% respectively.
The PSA purge gases are compressed in a three stage reciprocating compressor
to 20 bara at which point they pass through a membrane which separates most of
the hydrogen limited by the partial pressure on the permeate side which operates
at around 1.1 bara.

216

Section 7 | Carbon Capture and Storage

Technical Breakout (continued)
The main results indicate that the pre-combustion cases have a slightly bettercarbon footprint and this is mainly due to the better CO₂ capture efficiency
which more than offsets the slightly lower energy conversion efficiency tohydrogen product. The concept is that the pure hydrogen product from the
PSA will be split into two fractions. The first production from a new on line bed
will be 'premier cru' very pure hydrogen. The tail end production of the beds
approaching breakthrough of other components will be routed to the reforming
furnace as fuel gas.
The pre-combustion case uses a large amount of the product hydrogen forfiring the reformer so this arrangement will allow the export hydrogen to bevery pure. For the post combustion case it will be necessary to partly fire thereformer with hydrogen to the extent that the export hydrogen reaches thenecessary purity. The effect can be achieved also by early bed regeneration
which reduces the hydrogen recovery and increases the hydrogen content
of the PSA purge gas. As the hydrogen directed to fuel for the reformer isonly needed at low pressure there is opportunity to recover some energy byturbo expansion.
The results are summarised in the table below.
Comparison of residual CO₂ emission factors for pre and post-combustion
capture options.
Post Capture
90%
HydrogenRecovery

SyngasCapture 70%
HydrogenRecovery

Post Capture80%
HydrogenRecovery

SyngasCapture 90%
HydrogenRecovery

Fuel supply penalty

0.135

0.135

0.135

0.135

Overall energy
conversion efficiency

0.76

0.70

0.73

0.72

CO₂ emission from fuelsupply (fraction)

0.18

0.19

0.18

0.19

CO₂ emission due
incomplete capture

0.13

0.03

0.14

0.03

CO₂ capture fraction

0.90

0.98

0.90

0.98

0.31

0.22

0.32

0.22

Emission gm/kWh

57.2

40.9

59.4

39.8

NG emission factor(DEFRA 2015 Scope 1)

184.45gm/kWhNG emission factor(DEFRA 2015 Scope 1 +3)

209.28gm/kWhCase Description 

TOTAL CO₂ emitted
as fraction in net feed217Section 7 | Carbon Capture and Storage

Technical Breakout (continued)
These values are self consistent and evaluated to compare different SMR+CCS
cycles. The design of post capture 90% efficiency plant described here is slightly
different to that used in the costed example detailed below, and therefore hasa slightly different carbon footprint, changing the ratio of on-site to purchased
power is also significant.
It should be noted that these figures are for comparison only. Due to heatlosses and other internal process inefficiencies which have not been modelled
the emissions are expected to be slightly higher than these numbers. Notethat Scope 1 emissions are those directly from combustion of a fuel andScope 3 emissions are 'Well To Tank' (WTT) which are the additional emissions
associated with extracting and transporting a fuel.
The energy flows have not been inspected in detail. However it can be expectedthat the surplus energy released in the process will be sufficient to power thecapture process and recycle methane compression requirements. The system
will need to be engineered to produce LP steam for regeneration at appropriate
temperature and pressure and also include a steam turbine powered generator
to convert any surplus steam into power for the CO₂ export and methane
recycle compressors as well as for pumping process liquids.

218

Section 7 | Carbon Capture and Storage

7.4. Carbon Footprint of H21 System
The rationale for any natural gas to hydrogen conversion programme must be a net
reduction in emissions of carbon dioxide and other greenhouse gases, expressed as
their carbon dioxide equivalent in line with the Kyoto Protocol, but quantifying thiscan be complex. When comparing the carbon emissions of any product or service it
is vital to compare like with like, and to define the boundary conditions in a coherent
fashion. Commonly carbon emissions are compared at three different levels and formeaningful discussions it is vital to agree the concepts behind these. Without thissociety can make erroneous decisions. These three levels are:1. Scope 1: These are the direct emissions within the system boundary of theend user and hydrogen production facilities (typically from a boiler or vehicle).
From stationary plant they are usually evaluated at gm/kWh of fuel. For
natural gas they are typically 184 gm CO₂e/kWhHHV (Defra/DECC data set2015). These are the values used in the EU Emission trading scheme (EU-ETS).
They usually make no allowance for the carbon dioxide emitted in transport.
2. Scope 2: Typically allows for these carbon emissions for additional energy
inputs to the system such as electricity from the grid.
3. Scope 3: Goes even further than Scope 2 and endeavours to capture theembodied carbon emitted in material inputs to the system, for example,
liquefying the natural gas in Qatar, transporting it in refrigerated ships, storing it
in LNG depots, re-gasifying it and compressing it into the NTS. Allowing for allthese can raise the ‘true’ carbon footprint of such gas to 230 gm/kWh this is,incorporated in Scope 2 and 3. In practice DEFRA calculate a smaller 'average'
value for current UK gas supplies. Such calculations can easily become
disproportionate but it is important to understand their real importance.
Out of scope emissions are often associated with biomass and land use changes
and are not addressed for this hydrogen production method. For many years it was
believed that burning North American wood imported into the UK was an entirely
benign and carbon neutral concept, until Prof. MacKay (DECC August 2014) pointed
out the possibility of substantial emissions of CO₂ that could be associated with
cutting down of some woodland on fragile eco-systems.
This project avoids all the complexities of ‘sustainable carbon’ and the potential forfood competition from agro-fuels.

219

Section 7 | Carbon Capture and Storage

7.4.1. Establishing the CO₂ Emissions for
H21 Leeds City Gate
In the UK DEFRA publish emission factors which UK organisations should use to
calculate and report their CO₂ emissions. Some of these factors are revised each year
to reflect changes, for example in the energy mix of grid electricity or emissions in
the natural gas supply chain. The latest year for which factors are available is 2015
and these values have been used to evaluate the carbon emissions from burning
natural gas when this is burned as fuel. The Defra/DECC natural gas emission is184.45 gm CO₂e/kWhHHV (Defra/DECC data set 2015, Scope 1 emission) emitted
directly from the combustion of natural gas and a further 24.83 gm CO₂e/kWhHHV(Defra/DECC data set 2015, Scope 3 emission) by the natural gas supply system
making a total of 209.28 gm/kWh for the present natural gas supply. The same
factors have been used to estimate what the emissions from the H21 Leeds City
Gate system will be. This system will take natural gas, convert it to hydrogen andpermanently store most of the carbon content underground as CO₂.

The Carbon Footprint of the H21 System
There are three areas to consider when evaluating the emissions of the H21 system:
1. Scope 1 emissions associated with the production of hydrogen and carbon at
the SMR.
2. Scope 2 emissions include the electrical consumption of the plant and thecompression requirements (both CCS and hydrogen).
3. Scope 3 include the embodied emissions of natural gas outside the systemboundary. The Scope 2 emissions of natural gas are small and assumed to beincorporated in Scope 3.

220Section 7 | Carbon Capture and Storage

Scope 1 Emissions Associated with the Production of Hydrogen andCarbon Dioxide at the SMR
The main emissions from the H21 system will be from the steam methane reforming(SMR) plants which convert natural gas to hydrogen and capture approximately 90%of the carbon in the feedstock. The reported efficiencies of conversion of SMR+CCS
plant are complicated. The highest values for SMR (stand-alone) are reported forplant which export considerable steam (as might be required on a refinery with alarge steam demand), and then there is a trade off between efficiency and capitalcost. The highest practical efficiency (HHV basis) of a simple SMR (without CCS) is
circa 88%, with 11.2% of the energy potentially exported as steam and 76.8% of theenergy exported as hydrogen (ref. Analysis of the Thermal Efficiency Limit of theSteam Methane Reforming Process X. D. Peng* Air Products and Chemicals, Inc., 7201
Hamilton Boulevard, Allentown, Pennslyvania 18195-1501, United States 2012). The
steam rate is 6.5 kg per kg of H₂.
Simulations carried out for this project of the basic SMR process (with CCS) indicatethat 68.4% of the energy in the natural gas feedstock is retained in the hydrogenproduct on an HHV basis. The remaining 31.6% is released as heat much of whichis converted to steam but with some carried away in hot stack gases from thereforming furnace. When carbon capture is added most of the steam is required by
the capture process and the stack gases are fully cooled by the capture process sothat this heat is now rejected by the cooling system. However the overall conversion
efficiency remains the same. As indicated in the Technical Breakout some other SMR
configurations may produce higher efficiencies of conversion to hydrogen but theseare much less proven.
yy The carbon footprint of the SMR+CCS has been evaluated as follows:—— The carbon footprint of the natural gas feedstock = 184 gm/kWh.
—— With no carbon capture capability and an efficiency of 68.4% =269 gm/kWh (184/0.684).

90% of the carbon dioxide will be captured by the CCS system therefore the direct
CO₂ emissions from this process are 26.97 gm/kWh (Scope 1).

221Section 7 | Carbon Capture and Storage

Scope 2 Emissions Include the Electrical Consumption of the Plant
and the Compression Requirements (both CCS and Hydrogen)
The system utilises electric power to drive pumps and fans for the carbon capture
process (CCP) and the large compressors which send the captured CO₂ to storage.
The SMR plant could in principle generate this power from the waste heat producedby the conversion process. However this requires additional equipment and thesimplest concept is to import this power from the UK electrical grid. This would resultin an additional emission of 18.49 gm/kWh (DEFRA emission factor 2015).
The system requires a certain amount of hydrogen to be stored to ensure all
demands in winter and during peak hours during the day are met. The hydrogenhas to be compressed to very high pressure of up to 300 bar for winter storageand intermediate pressure of up to 100 bar for daily peak shaving resulting in
additional power consumption. This compression will be remote from the locationof the conversion plants and will draw additional power from the grid intermittently.
The additional emissions associated with this based on these maximum storage
pressures are 4.07 gm/kWh (DEFRA emission factor 2015). The additional emissions
associated with this based on these maximum storage pressures are 4.07 gm/kWh(DEFRA emission factor 2015) making the total 49.53 gm/kWh.
Total Scope 2 emssions are thus:
yy Hydrogen/carbon production = 26.97 gm/kWh.
yy Electric requirements for SMR plant = 18.49 gm/kWh.
yy Electrical hydrogen compression requirements = 4.07 gm/kWh.
yy Total emissions = 49.53 gm/kWh.
This Scope 2 is believed to be the most honest and transparent comparison with thepresent direct emissions from natural gas. It allows for both the increase in carbon
associated with the loss of efficiency from the SMR process, as well as the reduction
in carbon from CCS.
A general reduction in the carbon footprint of the imported electricity would increasecarbon savings, as would an increase in self-generated electricity from a moresophisticated steam system. This could have the following systems;
yy A high pressure system for power generation followed by.
yy A low pressure steam system for the amine regeneration in the carbon capture
plant (CCP).
The CO₂ capture process has a significant heat demand, for such low grade heatgetting the balance between these two systems, (i.e, HP for power generation andLP for the CO₂ capture), is difficult. HP steam would likely have more value if used
to generate electrical power, which could be used internally or exported to the grid.
The latter will increase plant capital cost and operational complexity, but decrease
Scope 2 emissions. This is not thought likely to materially change the economics of
the whole process.

222

Section 7 | Carbon Capture and Storage

Unfortunately the natural gas used in the UK has significant embodied carbon.
Its production involves the emission of significant quantities of up-stream CO₂
associated with its processing, possible liquefaction and subsequent shipping fromdistant locations around the world. DEFRA include this in their set of factors at a rateof 24.83 gm/kWh The SMR+CCS efficiency of 68.4% then raises this to 36.3 gm/kWh(24.83/0.684) of hydrogen bringing the total emissions to 85.83 gm/kWh. Many ofadditional emissions may occur outside the UK.
Scopeof Emissions

H21 System(gm/kWh)

Natural Gas(gm/kWh)% Reductionin Emissions

Scope 1

26.97

184.4585%

Scope 1+2

49.53

184.4573%

Scope 1+2+3

85.83

209.2859%

Table 7.1. Summary of H21 Emissions Levels by Scope

Comparison of H21 and Existing Natural Gas Emissions(CO₂ emissions in gm per kWh)

Upstream gas supply emissions

36.30

H₂ electric compression emissions
Grid power import emissions

4.07
18.49

SMR emissions

26.97
H21

Chart 7.1. H21 vs. Natural Gas CO₂ Emissions

223

Natural gas
supply emissions

24.83

Natural gas
direct emissions

184.45

Existing Natural Gas

Section 7 | Carbon Capture and Storage

Table 7.2 compares the carbon footprints of several fuels. All are taken from the
DECC/Communities Standard Assessment Procedure (SAP) 2012 used to assess theCO₂ emissions from domestic and commercial buildings. Unfortunately DEFRA use aslightly different value for natural gas. This is included for reference.
Fuelgm/kWhNotes% SAP Natural Gas

Mains gas

216

100%

Mains Gas DEFRA

209

DEFRA data

97%

Bioethanol

140

Any bio source

65%

Biodiesel

123

Any bio source

57%

Biogas98

Inc anaerobic45%

H₂ SMR+CCS

86

Scope 1+2+3, Table 7.140%

H₂ SMR+CCS

49.6

Scope 1+2

23%

Wood pellets

39

18%

Logs

19

9%

Table 7.2. Comparison of the Carbon Footprint of Hydrogen from SMR+CCS with Other Fuels

It can be seen that this SMR+CCS hydrogen (even from plant not optimised for carbon
emission reduction) is substantially less than bio-ethanol, biodiesel and even biogas.
If some hydrogen were to be made from excess renewable electrical energy or evennuclear power it is likely to have a very low or low carbon footprint. Hydrogen itself is
not a greenhouse gas, it has been suggested it can be a second order greenhousegas, (i.e. interfere with some atmospheric processes which reduce greenhouses
gases), but as this will only occur through leakage the effect is minimal. Possibly
the most important factor is that this carbon footprint of hydrogen from SMR+CCS istransparent and readily verifiable. Depending upon the precise source the figures forbiomass related products can have high degrees of uncertainty and the calculations
are still subject to academic debate. The carbon footprint of gas from mixed biomass
and waste streams are particularly complex.

224Section 7 | Carbon Capture and Storage

7.4.2. Total yearly volume of captured carbon
Table 7.3 reports the tonnes per year of CO₂ sent to disposal during a year operating
at design output. Most years will export less than this.
Unit

On-site Emissions

Natural Gas

gm/kWh184

Leeds design (average year)

GWh/yr

5.94

Emissions CO₂

Tonnes/yr

1,093,000

Change with H21

Tonnes/yr

933,000%

68.40%Natural gas to SMR

GWh/yr

8.68

CO₂ Teesside

Tonnes/yr

1,600,000% CO₂ to CCS%

90%

CO₂ to storage

Tonnes/yr

1,440,000

CO₂ to atmosphere

Tonnes/yr

160,000

SMR
Conversion rate

Table 7.3. H21 Leeds City Gate – Total Annual Volume of Captured CO₂

For the purposes of the H21 Leeds City Gate project a £40 price per tonne for carbon
has been assumed on day one. This is in line with the ‘Global status of CCS: 2015
summary report’. As scale is a critical factor in costs for CCS this initial £40 per tonne
is the upper end of any forecast and an appropriate reduction overtime has been
provided for illustrative purposes in Section 11, H21 Vision.

Total costs for carbon capture per annum= 1,500,000 tonnes/yr. x £40/tonne= £60 m pa (Year One)

225

Section 7 | Carbon Capture and Storage

Another example of the advantage of developing CCS using hydrogen from
SMR+CCS is that the storage of hydrogen after production smoothes out the variationof inter-seasonal natural gas demand and CO₂ disposal. Both of these will lower
costs. Gross variations of CO₂ to sequestrate will increase the difficulties of managing
pressures in the underground disposal zone as well as complicate compressor
design. A relatively constant rate of CO₂ production, except early Autumn (whenmaintenance can be carried out) involves less commercial risk which is always an
issue for plant operators.

226

Section 7 | Carbon Capture and Storage

7.5. Conclusion
The assumption of this report has very much been that CO₂ sequestration will
be available ‘over the fence’ as and when required. A recent report by the ETI(Progressing Development of the UK’s Strategic Carbon Dioxide Storage Resource
a Summary of Results from the Strategic UK CO₂ Storage Appraisal Project April2016) highlights that between 3 and 5 million tonnes per year of CO₂ is required forcost effective disposal at between about £11 and £17/tonne. Leeds will produce
about 1.5 million tonnes of CO₂/year, so ideally the planned conversion soon afterof Newcastle upon Tyne or Sheffield would reach this number which really starts tooffer the economies of scale. SMR from natural gas with the subsequent storage ofhydrogen can provide an advantageously constant level of CO₂ for disposal.
The fitting of carbon capture plant to an SMR is a well proven technology, although
there are still a variety of ways of configuring the system circuits. The compression
and disposal of the supercritical CO₂ to under-sea is also becoming more routine.
Unfortunately CCS disposal is one of those technologies that offers very large
economies of scale, so any first scheme is going to be expensive. SMR+CCS howeveroffers a low cost, well proven route to low carbon hydrogen providing a 73% reductionin Scope 1 emissions.

227

SECTION 8

Finance andRegulation

Section 8 | Finance and Regulation

8. Finance and Regulation
History of Regulation
The key legislation is the Gas Act 1986 [this repealed all previous legislation] which has
subsequently been amended as industry arrangements developed but fundamentally
this established the structure. Gas Transporter, Shipper and Supplier licences are issued
by powers under the Gas Act. The introduction of supply competition in 1996 requireda contract between Transco and gas shippers and the Transco Network Code wasintroduced to meet this need. This became the Uniform Network Code when National
Grid sold four distribution networks in 2005. In the following 11 years there have beennearly 600 proposals raised to modify the Uniform Network Code. The Supply Point
Administration Agreement which governs relationships between transporters andsuppliers was introduced in 2006 and the Smart Energy Code in 2010.
Since privatisation, regulated utility companies in the UK have found it relatively easy
to access debt funding from a variety of sources, including sterling bond markets,bank facilities, US Private Placements and loans from the European Investment Bank.
Debt investors are attracted to the low business risk provided by the relatively stableand predictable cash flows and local monopoly status inherent in UK utility companies
as well as the stable regulatory regimes under which they operate. Indeed, in setting
cost of debt allowances regulators have argued that these features have historicallyenabled regulated utility companies to raise debt more cheaply than similarly rated
corporates in other sectors. Whole Business Securitisation (WBS) structures, which offer
lenders security over shares as well as a number of enhanced covenants, have enabledsome utility companies to achieve very high levels of gearing relative to the value of theregulatory asset base.

This section will provide details on financing the H21 Leeds City Gate project via
regulatory finance and the subsequent impact on customers’ bills. It will also provide
a unit cost evaluation of the project in £/kWh if it was not financed using regulatory
business models. Finally, a comparison of the cost per tonne of carbon saved ispresented as well as some additional regulatory considerations.

229

Section 8 | Finance and Regulation

8.1. Summary of Costs for the
H21 Leeds City Gate projectThroughout report we have established the costs associated with all aspects of the
project. These are now summarised in Table 8.1.
Project Area

Cost Incurred (£m)

Network Capacity and Conversion
preparatory work
(Section 3 and 4)

Ongoing Costs
Each Year (£m)

10

Hydrogen Infrastructure/Conversion Costs
Steam Methane Reformer costs(Section 2)

395

Intraday Salt Caverns(Section 2)

77

Inter-season Salt Caverns(Section 2)

289

Appliance Conversion (including all
domestic, commercial and industrial
users) (Section 5)

1,053

Hydrogen Transmission System(Section 6)

230

Ongoing OPEX costs
Carbon Capture and Storage(Section 7)

60

SMR/Salt Cavern/HTS Management(Section 2)

31

Additional Energy Used for Hydrogen
Production and Carbon Capture(Section 2)

48

Total

2,054

Table 8.1. H21 Leeds City Gate Project Costs

230

139

Section 8 | Finance and Regulation

8.2. Hydrogen Conversion –The Regulatory Finance Model
Whilst we have presented all the costs associated with the project we also needto consider the methodology for financing and the real impact on customers’ bills.
In order to do this, we need to understand the current and future levels of gas
distribution network investment, the future level of investment required to convert
Leeds to hydrogen and how the regulatory financing mechanism works in terms ofsocialisation of costs and amortisation of return for the industry.

8.2.1. Existing Investment
The UK gas industry has been undertaking the Iron Mains Replacement Programme(IMRP) REPEX programme, since 2002. This is a 32 year programme which is driven
by the Health and Safety Executive and is essential to reduce risk to life and property
associated with gas leaking from the UK’s gas distribution system. The REPEX
programme is delivered in line with an established industry risk reduction model
which ensures the highest risk gas pipes (mains) are replaced as a priority each year.
These are replaced as part of efficient pipe replacement projects, i.e. the top risk
mains are replaced as well as surrounding lower risk mains to produce economicallyadvantageous schemes. In addition, the gas industry is also financially incentivised,using the OFGEM approved gas industry leakage model, as part of its regulatory
price control obligations to reduce leakage from its network.
The REPEX programme, currently accounts for a significant proportion of UK gas
distribution network costs, note Northern Gas Networks RIIO-GD1 business plan is£1.2 bn over 8 years. As well as reducing risk and greenhouse gas emissions it is also
reducing part of the OPEX associated with gas distribution networks, specificallyleakage repair costs. This is because as more iron mains are replaced there isan associated reduction in the number of leaks on the network, and therefore a
proportionate reduction in the number of repairs required.
In effect, this means that for the majority of the last two decades the gas industry
customers have been funding, via regulatory price controls, the upgrade of the
distribution system reducing risk, reducing leakage (and therefore greenhousegas emissions), and installing a material which will be in a suitable condition totransport hydrogen (polyethylene mains). This programme has been funded as partof the transportation element which makes up gas customers bills utilising the gas
distribution networks ability to ‘borrow money’ against it residual asset value (RAV).

231

Section 8 | Finance and Regulation

8.2.2. A Background to Regulatory FinanceThis section covers:
yy Background on the Gas Distribution Industry (GDI) and the costs involved inrunning the networks
yy How OFGEM regulates the industry through the new RIIO frameworkyy The different expenditure types and how revenue allowances are set
yy Where Gas Distribution Networks (GDNs) get their income from to run theirbusinesses, and how they collect ityy How this impacts end customers

The Gas Distribution Industry
Within the UK there are four GDN companies who own the network of pipes whichtransport the gas to all UK users, each covering an area of the UK as shown in
Image 8.1.

Gas
Distribution
Networks

Image 8.1. Gas Distribution Industry Overview

232Section 8 | Finance and Regulation

GDNs don’t produce or sell the gas, they transport it through a vast network ofunderground pipes. They manage the network to ensure on the worst possible
winter’s day (1 in 20 winter peak – see Section 3, Gas Network Capacity andSection 4, Gas Network Conversion) gas will continue to flow into people’s homes
and businesses.
The networks are faced with three types of costs to maintain this level of service;
yy Operating Expenditure (OPEX) – the costs involved with maintenance,
emergency services, repair costs and back office overhead costs.
yy Capital Expenditure (CAPEX) – equipment, such as Pressure Reduction Units(PRUs) and district loggers will need to be replaced when at the end of theiruseful life and new infrastructure (for example mains and District Governors(DGs)) may be required when new customers connect to the network. Additional
CAPEX is needed to replace vehicles and IT systems as well.
yy Replacement Expenditure (REPEX) – costs involved with replacing old iron pipes
with new plastic pipes. There is an HSE requirement to replace almost all ironmains within 30 metres of a property within a 30 year period (known as the 30/30
programme). The REPEX programme is due to be completed by 31st March 2032.
Please note the REPEX programme and the IMRP are interchangeable for the
purposes of this report.
Across the UK on average TOTEX costs (the collective name for OPEX, CAPEX,
and REPEX) are circa £2 bn per year. In addition to this, there is £0.4 bn per year
to manage the National Transmission System (NTS). As such network companies
receive income to cover these costs which they manage through a regulatory pricecontrol process known as RIIO.

233

Section 8 | Finance and Regulation

RIIO
RIIO stands for: Revenue = Incentives, Innovation and Outputs. OFGEM established
the RIIO framework, which came into effect on 1st April 2013 for GDNs.
The first RIIO GDN ‘price control period’ is running for 8 years having started on
1st April 2013 and ending on 31st March 2021 (this period is also known as RIIO-GD1).
Baseline Revenue allowances were set for each network company which provides
income to cover OFGEMs view on an efficient level of costs to run each network.
The bulk of the allowances relate to TOTEX as detailed above. However, additional
allowances are also given for non-controllable costs (for example business rates,
leakage, OFGEM license fee), financeability costs to cover off capital funding
requirements and also corporation tax. These revenue allowances are what OFGEM
is expecting network companies to charge their customers.
GDNs have the opportunity to earn additional income through a range of Incentives
during RIIO. Customer service improvements and reducing leakage volumes, theamount of gas ‘lost’ predominantly through leakage in the transportation network,
are examples of two of the incentives where extra income can be earned. Delivering
TOTEX costs lower than OFGEM allowances also benefits the GDNs but an elementof the outperformance is shared with their customers as well.
GDNs can receive funding for Innovative projects which deliver long-term
improvements in how they and the industry operate.
There is also a comprehensive list of Output performance measures; categorised
into six key areas:yy Network safety.
yy Network reliability.
yy Customer service.
yy New connections.
yy Social obligations.
yy Protecting the environment.
GDNs receive their income from gas shippers but ultimately this is funded by all UK
gas customers.

234

Section 8 | Finance and Regulation

Expenditure Types and the Link to Revenue Allowances
GDNs know in advance their base revenue allowances for the 8 years of RIIO-GD1.
This was calculated through OFGEM’s Price Control Financial Model (PCFM).
The principles for revenue allowances are largely categorised into two areas
depending on whether the costs being funded are considered to be capital or
operating expenditure.
OPEX: Revenue allowances are given in the year the expenditure is incurred. Areassuch as emergency costs, repair costs, non-controllable OPEX and back officesupport costs are all areas where GDNs incur costs every year and also receive
income in the same year to fund these activities.
OPEX allowances are known as ‘Fast Money’ for revenue purposes.
CAPEX: there are three areas relating to CAPEX as follows;
1. Regulatory Asset Value (RAV) Depreciation: The capital investment returned
to GDNs via a revenue allowance is called RAV Depreciation. It’s returned overthe life of an asset, on average 45 years, on a reducing balance basis (known
as the sum of digits depreciation methodology). Chart 8.1 shows the profile
if £1 m was spent showing the highest amount of income in Year 1 at £43 k
reducing down to nil by Year 45.

CAPEX Investment Allowance Proﬁle45
40£1 million CAPEX investment —allowances would be funded over
45 years in this profile35£k Revenue

30
25
20
15
10
5
0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45

Year

Chart 8.1. RAV Depreciation

CAPEX allowances are known as ‘Slow Money’ for revenue purposes.

235

Section 8 | Finance and Regulation

2. RAV and Return: Any expenditure incurred is added to network’s RAV anddepreciated in line with the above profile. During an asset’s life, GDNs canearn a return to cover costs incurred in financing based on the balance of RAV
outstanding at any given point.
OFGEM’s assumption for the gas distribution industry is that any capital
investment will be funded 65% by debt and 35% by equity. This ratio is used
to calculate the Weighted Average Cost Of Capital (WACC). During an asset’slife, a return is earned to cover off the costs of funding the investment in thisway – i.e. the interest costs linked to the debt and the returns required byequity investors.
The current WACC value (real) as published by OFGEM in November 2015 is:yy Cost of Debt: 2.38%
yy Cost of Equity: 6.70%
yy Notional Gearing: 65.00%
yy WACC: 3.89%
3.89% would be applied to the GDN’s RAV balance to generate the returnelement within the revenue allowances.
Note the treatment of REPEX:
3. REPEX allowances: REPEX is on a transition to be funded in the same manner
as CAPEX. By regulatory Year 2020/21 all of the REPEX investment will befunded as slow money – i.e. any REPEX investment will be funded over a
45 year period through a depreciation allowance and a return on the RAV.
This is a significant change and is being phased equally across the 8 years of
RIIO-GD1, in Year 2013/14 the proportion of REPEX funded through fast moneyis 50% and by Year 2020/21 this will be nil as shown in Table 8.2.
REPEX
FUNDING

13/14

14/15

15/16

16/17

17/18

18/19

19/20

20/21

% funded
fast money

50%

43%

36%

29%

21%

14%

7%

0%

% fundedslow money

50%

57%

64%

71%

79%

86%

93%

100%

Table 8.2. REPEX Funding

It is worth noting at this stage that when the REPEX programme is complete by2032, there will not be an immediate reduction in revenue terms. This is becausefrom Year 2020/21 all REPEX is funded over a 45 year period via the depreciation
and return allowance there will be a gradual reduction over future years. REPEX
will stop, but revenue allowances will continue until 2077 due to the mechanics
described above.

236

Section 8 | Finance and Regulation

Summary of Industry Revenue Allowances
Table 8.3 shows the GDI base allowed revenue for the 8 years of RIIO-GD1 split into
the categories described above. It also shows other areas such as non-controllable
OPEX (rates, leakage, OFGEM licence fee and pension costs), pension deficit funding,
OFGEM income awarded for being at the efficiency frontier and corporation tax.
INDUSTRY REVENUE ALLOWANCES (£M NOMINAL)
13/14

14/15

15/16

16/17

17/18

18/19

19/20

20/21

Fast pot– REPEX

456

398

338

275

215

147

77

-

Fast pot– OPEX

870

848

843

869

889

909

907

912

RAV
depreciation

843

880

836

860

941

1,047

1,161

1,299

Return on
RAV

707

722

734

755

785

818

852

886

Non-controlable
OPEX

683

697

704

716

734

755

776

797

Tax allowance

46

33

211

230

253

256

255

266

Pensiondeficit funding

64

66

67

69

72

74

77

80

Frontier
rewards

18

18

18

19

20

20

20

20

3,688

3,663

3,908

3,972

4,026

4,124

4,124

4,260

TOTEX funding

Other areas

Total BaseAllowed
Revenue £mTable 8.3. Industry Revenue Allowances

237

Section 8 | Finance and Regulation

Where Do GDNs Get Their Income From?
GDNs receive their income monthly to run their businesses. Image 8.2 shows theflow of income from a gas consumer through to a GDN

Customer

Customer has a contract
with a gas supplier who they
will pay to purchase and deliver
gas to their supply point

Gas SupplierSupplier will pay a gas shipper
to deliver gas to the systemand transport it

The ‘Big 6’ energy
companies operate
as both supplier and shipper

Gas Shipper

GDN

Shipper will pay a gas distribution
network for transporting gas
through their system

GDNs collect their ‘allowed’ revenue
by charging gas shippers.
They set their unit rates to collect
only what they are entitled to, i.e. theallowed revenue set by Ofgem.

Image 8.2. GDN income

yy Every month gas shippers will pay GDNs for using their network. The rates thatare set by GDNs are calculated only to collect what they are permitted under the
OFGEM license.
yy Via charges being flowed upstream GDN costs are ultimately passed on to theend customer through their gas bills.
yy GDN charges represent circa 17% as a proportion of an average gas bill based on
current prices. The breakdown of an average gas bill is shown in Chart 8.2.

238

Section 8 | Finance and Regulation

yy On What Basis Do GDNs Collect Their Income?
The method of collecting income is largely linked to the capacity requirements of the
network in order to meet the peak requirement on a 1 in 20 winter’s day. Only a verysmall proportion of GDN revenues are collected based on actual gas usage (circa 3%).
We have seen in recent years that capacity requirements are reducing by circa 3%
per year. Every supply point in the UK has a registered capacity figure which is thepeak 1 in 20 requirement. GDNs charge a unit rate against the supply point’s peakcapacity requirement.
If this capacity requirement drops, or if the number of gas customers drops, GDNs
are still entitled to collect the same amount of allowed revenue. If GDNs did nothing
to their unit rates their income would fall, and they would not collect what they
are entitled. Therefore, GDNs will increase their unit rates to cover any shortfall (orreduce unit rates if a surplus).
Image 8.3 shows an example for one supply point – if a GDN needed to collect £130and had a unit rate of £1. The starting position is a peak day capacity requirement of
130 kWh, but this drops to 126 as shown below.

GDN needs£130and collects£130

GDN needs£130
but only collects£126

GDN adjusts
its unit rates
to collect£130

Supply pointneeds
130 kWhon peak day

Supply point
now needs
126 kWhon peak day

Supply pointneeds
126 kWhon peak day

130 kWh x £1.00

126 kWh x £1.00

126 kWh x £1.03

Capacity drops by 3%
GDN is entitled to claim£130 but because demand
falls will only collect £126.

GDN increases rates
The new peak day requirement
remains at 126 kWh, but GDN
is still entitled to claim £130.
Unit rates are increased to cover the shortfall.

Image 8.3. GDN Capacity Impact

GDNs aim to forecast how much capacity is dropping and build this into their unit
rates to minimise any under or over recoveries in future years.

239

Section 8 | Finance and Regulation

The Breakdown of a Gas Bill
The above summarises the mechanism of GDN charges and how they receive
income to run their businesses. As shown Image 8.3 network costs are ultimately
passed up the chain to form part of an end customer’s gas bill. Chart 8.2 shows thebreakdown of an average gas bill.
Total Customer Gas Bill

5%

4% 2%

Wholesale energy, supply costs and proﬁt margin

6%

17%

Distribution charges (NGN element)
Environmental charges

Distribution
Charge:£130 per annum

VAT
66%
Other costs
Transmission charges

Chart 8.2. UK Gas Bill Component Parts

Based on the current average Annual Quantity (AQ) of 14,200 kWh and a peak day
requirement of 121 kWh for an average domestic property this would generate an
average GDN charge of £130 per year.
Currently, if an average gas bill was £750 then GDN charges would represent
circa 17% of the total gas bill.

240

Section 8 | Finance and Regulation

GDN charges expressed in terms of customer bill impact is a key metricthat is presented in the OFGEM annual report. The latest 8-year forecast for
RIIO-GD1 highlights that GDN charges are falling starting at £134 in Year 2013/14 andforecasted to be £121 by Year 2020/21. Table 8.4 shows the breakdown by GDN as
presented in the 2014/15 OFGEM annual report.
14/15 Prices (£)

13/14

14/15

15/16

16/17

17/18

18/19

19/20

20/21

National Grid:
East of England

126

121

121

112

114

115

113

111

National Grid:
London

146

142

149

142

134

139

135

132

National Grid:
North West

132

123

125

122

114

118

117

115

National Grid:
West Midlands

130

129

124

119

118

122

120

118

NGN

128

131

133

125

122

121

122

123

Scotland

132

133

123

132

122

124

124

123

Southern

147

140

136

136

131

135

131

130

WWU

126

125

119

121

124

123

122

120

134

130

129

126

122

125

123

121

Industry

Table 8.4. GDN Charges 2014/15 OFGEM Annual Report241Section 8 | Finance and Regulation

Key Messages
yy RIIO is the price control framework implemented from 1st April 2013 for
Gas Distribution. The first period is RIIO-GD1 and will run for 8 years.
yy OFGEM regulates the gas distribution industry and sets GDN expenditure
allowances for OPEX, CAPEX, and REPEX. GDNs have the opportunity tooutperform these allowances and earn additional incentives.
yy Revenue allowances are largely split between fast and slow money principles
which distinguish between OPEX and CAPEX.
yy GDNs charge shippers based on their capacity requirements needed on a 1 in 20
winters day. Unit rates are set so that GDNs only collect what they are entitled toas set out in the OFGEM licence.
yy If the capacity requirements of shippers/end customers drop, GDNs will increase
their unit rates, so they collect the same revenue. If the number of gas users
reduces, everyone else will pick up a higher proportion of GDN costs, so they stillcollect the same.
yy GDN costs are ultimately fixed costs passed on to the end customer as part oftheir gas bills.

242

Section 8 | Finance and Regulation

8.2.3. Current Regulatory Finance Long-term
Projections – No Hydrogen Conversion
This section covers:
yy The ‘current’ scenario – if all existing methodologies were rolled forward how
would GDN charges change over a long term horizon.
yy This uses current Price Control Financial Model (PCFM) revenue methodology
extended out to regulatory Year 2052/53 to establish the allowed revenue andcustomer bill each year.
yy For this exercise, it uses Northern Gas Networks data as an illustration only.

Current Scenario Assumptions
Calculating actual/forecast allowed revenues for the RIIO-GD1 period(2013/14 – 2020/21) can be completed through the OFGEM PCFM but for thisexercise, we needed to forecast beyond RIIO-GD1.
The following assumptions were made for this analysis to enable a longer term view– note the base position for this analysis is the November 2015 OFGEM PCFM with all
methodologies extended until Year 2052/53, the last year of RIIO-GD5.
All assumptions and outputs NGN believe to be directionally accurate based on
current methodology/knowledge – however this information has not undergone
strenuous audit as defined by the OFGEM DAG requirements.

243Section 8 | Finance and Regulation

yy Forecast revenues to Year 2020/21 are in line with the latest revenue profile
produced every quarter for gas shippers.
Thereafter:
yy A 5% reduction in TOTEX allowances has been assumed at the start of each
8 year period – this is a conservative assumption. Note that with effect from
regulatory Year 2032/33 REPEX expenditure allowances are nil as the 30/30
programme has been completed.
yy All current PCFM methodologies continue as is:—— Current split of fast/slow money rolled forward (65% fast/35% slow) for OPEX andCAPEX;—— The 45-year sum of digits RAV depreciation method for all new additions, with 100%
REPEX capitalisation from Year 2020/21 onwards; until Year 2031/32 when the REPEX
programme is complete;—— Return on RAV using a WACC with notional gearing at 65%, cost of equity at 6.7% andcost of debt at 1.75% from Year 2021/22 onwards; and—— Long term RPI assumption is +3%.

yy Incentive income continues at the same rate as RIIO-GD1. It does not assume any
outperformance in future years from the TOTEX incentive mechanism.
yy Revenue smoothing has been applied as we exit RIIO-GD1 and enter RIIO-GD2
to remove a large drop at the transition. Revenue smoothing is an activity which
OFGEM completes prior to finalising revenues to ensure a robust profile andremove any potential financing issues as a result.
yy A key assumption throughout all the analysis that follows is that the gas industry
will maintain the same number of customers. For NGN this is 2.7 million supply
points, and nationally this is 21.5 million supply points. This assumes from an
investment perspective that we will need to keep a similar level of CAPEX tomaintain our commitment around 1 in 20 peak conditions.

244

Section 8 | Finance and Regulation

Results Summary from the Current Scenario
yy As expected the revenue profile starts to decline as networks complete the
REPEX programme. Due to the nature of how REPEX is funded, over 45 years
from 2020/21, there is a gradual decline from Year 2032/33 onwards rather thanan immediate reduction in customer bills.
yy Customer bills are quoted for an average domestic property within the NGN
network in line with recent methodology in OFGEMs annual report. The current
domestic annual quantity is 13,967 kWh in the NGN network.
yy Average allowed revenues per year within the RIIO-GD1 period are £400 m
reducing to £299 m in RIIO-GD5 (2015/16 prices).
yy Average bills within RIIO-GD1 are £127. Over the longer term with the completionof the REPEX programme by RIIO-GD5 average bills would be circa £94 (in2015/16 prices).
yy To re-iterate the average bill calculation assumes the same number of gas
users in the NGN network. If the number of users was to fall this would result
in remaining users picking up a larger proportion of the network costs andvice versa.

160

400

140

350

120

300

100

250

Post Repex
Year 2032/33

200

80
60

150

NGN Revenue(on Current Methodology)- Left Hand Scale100

Average NGN Bill
(Domestic) 'Current' 40- Right Hand Scale

20

50
13/14

16/17

19/20

22/23

25/26 28/29

31/32

34/35

Year

Chart 8.3. NGN Revenue Forecast (Current Scenario)

245

37/38

40/41

43/44

46/47 49/50

52/53£ Customer Bill (15/16 prices)£m Revenue (15/16 prices)

NGN Revenue Forecast (Current Scenario)
450Section 8 | Finance and Regulation

NGN (CURRENT) PRICES (2015/16)

Revenue (Avg Yr)
Average GDN
element of
Customer Bill

RIIO-GD1

RIIO-GD2

RIIO-GD3

RIIO-GD4

RIIO-GD5£400 m£383 m£386 m£346 m£299 m

£127

£121

£122

£109

£94

Table 8.5. Customer Bill Impact – Transportation Charge Only

Total Customer Bill Forecast
So far we have focused primarily on the gas distribution element of a gas bill andhow this is forecast to change over time. As shown in the pie chart previously (Chart
8.2) the gas distribution element represents a small proportion of the overall gas bill,
and customers will be faced with a total bill of much higher (circa £750).
Over the longer term horizon, home improvement efficiencies should deliver savingsin the non-distribution element of the gas bill. The introduction of initiatives such as
smart meters, increasing new build properties, insulation, solar energy and otherinitiatives should deliver additional savings.
To demonstrate this the following % saving in the non-distribution element of adomestic bill has been applied:

Saving from current

2016-30

2030-35

2035-40

2040-452045-50

2050+

0.00%

3.00%

6.00%

9.00%

12.00%

15.00%

Table 8.6. Energy Efficiency Over Time

246

Section 8 | Finance and Regulation

Under the current scenario this would result in the following profile:

Total Customer Gas Bill(£) 15/16 prices

800

750

700
Total customer gas bill (15/16 prices)
650
Distribution element saving ‘Current Scenario’ - passed on to end customer
600

550

Further home eﬃciency reductions

13/14

16/17

19/20

22/23

25/26 28/29

31/32

34/35

37/38

40/41

43/44

46/47 49/50

52/53

Year

Chart 8.4. Total Customer Gas Bill

15/16 prices (£)

RIIO-GD1

RIIO-GD2

RIIO-GD3

RIIO-GD4

RIIO-GD5Current averagebill £

750

750

750

750

750

GDN
reduction

-

(5)

(6)

(18)

(33)

Efficiency
savings

-

-

(31)

(66)

(106)

750

745

713

665

611

GDN elementof gas bill

127

121

122

109

94

% of total gas bill

17%

16%

17%

16%

15%

Total Gas Bill

Table 8.7. Total Customer Bill Impact – (Total Bill)yy In Chart 8.4 if the starting point was the current total gas bill of £750; then:
1. As shown previously, the distribution element of the bill will reduce – by2052/53 this will reduce by £39 which will be passed on to end customers.
2. If further home efficiencies were implemented in the above profile, then thecustomer bill would reduce by £118 in 2052/53.
yy The GDN proportion of a gas bill will, therefore, fall from circa 17% in RIIO-GD1 tocirca 15% in RIIO-GD5.

247

Section 8 | Finance and Regulation

Key Messages:
yy There is not an immediate drop in revenue when the REPEX programme finishes
because of how it is funded over 45 years.
yy Average transportation charge in domestic bills would drop by circa 26% from£127 in RIIO-GD1 to £94 in RIIO-GD5.
yy It assumes no reduction in gas users throughout.
yy Analysis has primarily focused on the GDN element of a gas bill – however
efficiency savings have also been considered resulting in the total gas bill fallingby both the GDN reduction and also home efficiency savings.

248

Section 8 | Finance and Regulation

8.2.4. Regulatory Finance Long Term Projections –H21 Leeds City Gate Undertaken in RIIO-GD2
Expenditure Forecast for Leeds City Hydrogen Project
Table 8.8 shows the forecast costs to cover converting 264,000 supply points in thearea of conversion to hydrogen – both in terms of implementation costs and ongoing
OPEX costs.

COSTS SUMMARY

Costs
IncurredPrior

Conversion
Costs

Total

(£m)

(£m)

(£m)

Costs
Year 1(£m)

NGN Funded
CAPEX– reinforcement/readiness10

10

Hydrogen Specific Costs
OPEX– Labour

527

527

OPEX
– Appliances

527

527

OPEX
– SMR Efficiency Loss

-

48

OPEX
– Carbon Capture/Storage

-

60

OPEX
– Maintenance

-

31

CAPEX
– SMRs

395

395

CAPEX
– Salt Caverns

366

366

CAPEX
– HTS

230

230

TOTEX

1,001

1,053

Table 8.8. Expenditure Forecast

249

2,054

139

Section 8 | Finance and Regulation

The SMR efficiency loss has been calculated by assuming that 47% more gas would
be needed to meet consumer demand via hydrogen. Based on Leeds, this would
result in an additional 2.8 Terawatt/95 million therms applied with an assumed costof 50 pence per therm.
50 pence per therm is the actual price NGN has paid to purchase gas, on average, inthe last 3 years, to replace any lost from the network via leakage. It is known within
the industry as the ‘Heren’ price and the charge only relates to the purchase of gas,(i.e. it excludes any other costs in the bill such as transmission/distribution charges).
This section covers:
yy Two options of regulatory finance changing the proportions of fast/slow money.
Each option includes:—— If the above hydrogen expenditure was added to GDN allowances how would this
impact on allowed revenues and customer bills?
—— It also considers which gas customers could pay for the Leeds project – i.e. would
just gas users in the NGN network pay for this scheme or could it be socialised andspread across all UK users?

For simplicity all costs have been forecast from 2023 onwards with conversion
taking place between 2026 and 2029. In reality costs will begin slightly earlier forthe design/build years of the hydrogen production and HTS systems as indicated in
Section 9, The Next Steps – Programme of Works. These are small costs overall andwould not make a material change to the finance modelling presented in this section.

250

Section 8 | Finance and Regulation

Option 1: Using the Current Fast/Slow Money Logic
yy OPEX and CAPEX for the hydrogen project has been applied through the existing
regulatory allowances methodology.
yy For OPEX this means a £1 bn investment is needed in the first 3 years of the
project between 2026 and 2029 for conversion of customers’ appliances andthe associated labour costs of this activity. Thereafter, ongoing OPEX costs ofcirca £139 m (CCS/SMR efficiency loss/SMR/salt caverns/HTS operations) a year
would be funded through the fast money approach.
yy £1 bn of CAPEX investment is needed prior to the project go-live between years
2023 and 2025. This would be funded through the slow money logic returningmonies over a 45 year period via the depreciation and return on RAV logic.
yy Using this logic the Chart 8.5 shows the phasing of hydrogen allowed
revenues needed.

500

Hydrogen Revenue Allowances
NGN
Revenue
Forecast (Current(withCurrent
OPEX/CAPEX
FundingScenario)
Methodology)£m Revenue (15/16 Prices)

450
400
350
300

£1 billion funding for
appliances and labour
needed in these years

250
200
150
100

-

13/14
14/15
15/16
16/17
17/18
18/19
19/20
20/21
21/22
22/23
23/24
24/25
25/26
26/27
27/28
28/29
29/30
30/31
31/32
32/33
33/34
34/35
35/36
36/37
37/38
38/39
39/40
40/41
41/42
42/43
43/44
44/45
45/46
46/47
47/48
48/49
49/50
50/51
51/52
52/53

50

Year

Chart 8.5. Hydrogen Revenue Allowances (with Current OPEX/CAPEX Funding Methodology)

The next section demonstrates how the above revenue profile would impact on
customers bills, if:
1. Hydrogen revenue allowances were just charged to NGN customers(2.6 million users).
2. If the allowances were socialised and spread across all UK customers(21.5 million users).
Because of the logic used there will be a spike in bills in years 2025/26 – 2027/28.
The extent of this spike is impacted by the number of users this will be spread
across, as shown in Chart 8.6.

251

Section 8 | Finance and Regulation

Customer Bill (Transporation Charge Only)- Hydrogen
ImpactPeak Year @ £301

320

Spread across all UK consumers

295(£) 15/16 Prices

270

Charged to NGN consumers only

245

Average NGN bill (domestic) ‘Current’

220
195
170

15/16 Actual £134

145
120
95
70

Peak Year @ £144
13/14

16/17

19/20

22/23

25/26 28/29

31/32

34/35

37/38

40/41

43/44

46/47 49/50

52/53

Year

Chart 8.6. Customer Contribution to Transportation Charge, Option 1

Customer Bills (15/16 prices)
Average Year

RIIO-GD1

RIIO-GD2

RIIO-GD3

RIIO-GD4

RIIO-GD5NGN (current) (£)

127

121

122

109

94

NGN bill if NGN customers fundeverything (£)

127

197

178

153

129

% Increase from current position

0.0%

58.0%

38.5%

35.9%

36.4%

NGN bill if costs socialised
nationwide (£)

127

130

127

114

99

% Increase from current position

0.0%

7.2%

4.8%

4.5%

4.5%

Table 8.9. Customer Bills, Transportation Only (2015/16 prices) Average Year, Option 1

If everything was charged to NGN customers only there would be a significant
increase in the GDN element of the bill, especially in the years where OPEX
investment is needed – peaking at £301 as shown in Chart 8.6.
yy If these costs were socialised and spread across all UK customers then in thepeak year bills would increase to circa £144 in the NGN region. On average in
RIIO-GD2 bills would increase by £9/+7.2% per year when compared with thecurrent scenario. Note this is a 7.2% increase on only the distribution element on
a gas bill, not the entire bill.

252

Section 8 | Finance and Regulation

yy This analysis also excludes any comparisons to a ‘do nothing’ scenario – if we
continued to use gas in the same way for the foreseeable future how manyother costs would be passed on to end customers? I.e. air quality fines from local
councils. Whilst the bill increases in these illustrations it does not compare thisagainst any alternative future scenarios.
yy It also does not take into account any other savings in the total customer
bill because of efficiency measures, e.g. smart metering/home insulation
measures etc.

Option 2: An Alternative Option to Potentially Reduce the Spike in Bills
In both scenarios there is a spike in bills because of the OPEX costs needed. If the
project is implemented then it would form part of a regulated price control process
where all costs and financing factors are considered as a whole, with the focus on
output measures, network financeability and customer bills.
One potential way of reducing the ‘spike’ could be to treat all of the implementation
costs as slow money and receive allowances for these over a 45 year period – via
the depreciation and return on RAV allowances. This would result in the £1 bn of
appliance and labour costs funded over a 45 year period instead of a 3 year period asshown in Option 1.
However this is at odds with how current OPEX costs are funded and is shown here
for illustrative purposes only – a much wider review of the factors mentioned above
would need to be considered with any change in funding method – financeability
issues in particular.
Customer Bill (Transporation Charge Only)- Hydrogen Impact
210

Spread across all UK consumers
Charged to NGN consumers only

Peak Year @ £200

Average NGN bill (domestic) ‘Current’(£) 15/16 Prices

190
170
150

15/16 Actual £134

130
110

Peak Year @ £132

90
70

13/14

16/17

19/20

22/23

25/26 28/29

31/32

34/35

37/38

Year

Chart 8.7. Customer Contribution to Transportation Charge, Option 2

253

40/41

43/44

46/47 49/50

52/53

Section 8 | Finance and Regulation

Customer Bills (15/16 prices)
Average Year(but with OPEX as slow money)

RIIOGD1

RIIOGD2

RIIOGD3

RIIOGD4

RIIOGD5

NGN (current) (£)

127

121

122

109

94

NGN bill if NGN customers fundeverything (£)

127

161

187

161

139

% Increase from current position

0.0%

32.7%

54.0%

48.1%

48.1%

NGN bill if costs socialised
nationwide (£)

127

126

130

115

100

% Increase from current position

0.0%

4.1%

6.7%

6.0%

5.9%

Table 8.10. Customer Bills, Transportation Only (2015/16 prices) Average Year, Option 2

yy In the scenario where NGN funds everything across 2.6 million customers thenbills remain significantly higher than current run rate. The peak year at £200 is still
60% higher than the current scenario.
yy Where costs are socialised, and NGN customers pick up a share of the costs,
then the impact is lower than Option 1. On average during RIIO-GD2 the billwould increase by circa 4.1% compared to 7.2% in Option 1. Note this is a 4.1%
increase on only the distribution element on a gas bill, not the entire bill.

254

Section 8 | Finance and Regulation

Long Term Efficiency Impact on the Total Customer Gas BillAs with the ‘no hydrogen conversion’ scenario we have focused primarily on the gas
distribution element of a gas bill and how this is forecast to change over time. It is
important to also reflect the impact in total gas bill (circa £750) when considering theH21 Leeds City Gate conversion project.
To demonstrate this the following percentage efficiency savings have been assumed(currently circa £750 per annum) as demonstrated below,

Saving from current

2016-30

2030-35

2035-40

2040-452045-50

2050+

0.00%

3.00%

6.00%

9.00%

12.00%

15.00%

Table 8.11. Energy Efficiency Savings Over Time

This would result in the following customer bill profile, please note both Chart 8.8
and Table 8.12 represent the impact on customer bills when costs are socialised
across all UK customers.

Total Customer Gas Bill£m (15/16 Prices)

800
700
600
500
400
300
200

Total Customer Gas Bill (15/16 Prices)
Including GDN Reduction and Eﬃciency Savings
Leeds Hydrogen - Option 1 - Costs Socialised (UK)
Leeds Hydrogen - Option 2 - Costs Socialised (UK)

-

13/14
14/15
15/16
16/17
17/18
18/19
19/20
20/21
21/22
22/23
23/24
24/25
25/26
26/27
27/28
28/29
29/30
30/31
31/32
32/33
33/34
34/35
35/36
36/37
37/38
38/39
39/40
40/41
41/42
42/43
43/44
44/45
45/46
46/47
47/48
48/49
49/50
50/51
51/52
52/53

100

Year

Chart 8.8. Total Customer Gas Bill

255

Section 8 | Finance and Regulation

RIIOGD1

RIIOGD2

RIIOGD3

RIIOGD4

RIIOGD5

Total gas bill (£)

750

749

713

665

611

Leeds hydrogen bill impact – Option 1 (£)

-

8

6

5

4

Revised total gas bill – Option 1 (£)

750

758

719

670

615

Change %

0.0%

1.1%

0.8%

0.7%

0.7%

Leeds hydrogen bill impact – Option 2 (£)

-

5

8

6

5

Revised total gas bill – Option 2 (£)

750

754

721

672

617

Change %

0.0%

0.6%

1.1%

0.9%

0.9%

(15/16 prices)

Table 8.12. Customer Bills (2015/16 prices) Average Year, Option 1/2

The biggest increase from the current scenario is in year 2026/27 where under
Option 1 it adds £22 (2.9%) to the annual bill and £8 under Option 2 (1.1%).

Key Messages:
Two alternative methods of calculating hydrogen allowed revenue have been
considered:yy On the existing methodology which shows allowed revenues earlier in the
project lifecycle because of the upfront OPEX costs needed; andyy As an illustration only and not considering other factors such as network
financeability – if the £1bn of OPEX costs could be treated as slow money which
would spread the funding over 45 years.
We have also considered which customers could pay for the Leeds hydrogen project:
yy Charging the costs just to NGN customers more than doubles the billcontribution to the transportation charge when using current methodology andadds at least 50% in the slow money option.
yy Socialising the costs across all UK customers is the best option to minimise theimpact on customer’s bill.

The impact on the total customer bill has been
considered with the biggest gap being a £22
increase to the annual bill in Year 2026/27
under existing regulatory methodologies

256Section 8 | Finance and Regulation

8.3. Hydrogen Gas Cost per Kilowatt Hour
Although it is likely, and also more affordable, that most of a hydrogen conversion
programme is funded in a regulatory price control model, it is still felt useful to show
the unit cost of hydrogen/kWh if not financed using the regulatory methodology.
Gas supply companies and gas users in Leeds will have the same commercial
relationship and security of supply as they do now, just that the kWh they use will bein the form of hydrogen rather than natural gas. On the way to Leeds, the gas supply
company’s natural gas will be converted to hydrogen as a common transmission
service. The common service would be responsible for procurement of theadditional energy required for the conversion process. Costs noted here are for theservice company.
The following costs for H₂+CCS reflect the full cost of the system described above,
based on existing facilities costs and high level operating costs, including energy
used to run the hydrogen production system. These require further development of
the designs to reduce the normal uncertainty of costs at this stage. It excluded thekWh cost of the energy bought by gas suppliers and passed through as equivalent
kWh in the form of hydrogen.
It is important to note that these are costs for year one, but a scaling hydrogen
economy will see reducing costs per kWh. The following factors will reduce this cost:yy Costs for carbon capture will significantly decline as scale increases.
yy Operating costs for hydrogen production and storage facility will decline withscale from the current 4%.
yy Intraday storage costs will decline as more linepack becomes available in the
expanding hydrogen transmission system.
yy Unit costs of appliances and conversion will decline with scale.
yy As by-product hydrogen and hydrogen via electrolysis (as a result of constrainedenergy) becomes available costs could decrease.
Additionally, no account has been taken for the following which should beconsidered when looking at an incremental UK roll out conversion strategy as well as
H21 Leeds City Gate:
yy Storing hydrogen in summer to re-use from the inter-seasonal store in winterwill significantly improve the cost of the efficiency loss as more gas will be
produced in summer (at lower costs) to fill the store. This gas will then be used tosupplement production in winter.
yy Additional to the declining costs listed above there is the possibility of wholesalegas price increasing over time. It should be noted that in a scaling hydrogen
economy could well have a mixture of SMRs and coal gasifiers/black bin
waste gasifiers producing the hydrogen. This would potentially give the larger
system more operational flexibility and insulate against varying fuel prices fordifferent feedstocks.

257

Section 8 | Finance and Regulation

The costs for hydrogen in the H21 Leeds City Gate project are as follows and havebeen calculated using the design parameters identified in Table 8.13 as described in
Section 2, Demand vs. Supply.
Key Design Parameters

Unit

Value

Comment

Domestic Demand 2013

kWh3,614,000,000

DECC Data

Non-domestic Demand 2013

kWh2,327,000,000

DECC Data

Average Annual DemandkWh5,940,000,000

DECC Data

Annual Hydrogen Production

kWh5,940,000,000

DECC Data

Average Demand

MW

678

Equals Annual divided by hours
in year.

Design Supply SMR+CCS

MW

732

Design based upon 8% uplift

Demand 2013 (Section 2 and 3)

Table 8.13. Key Design Parameters258Section 8 | Finance and Regulation

First we can consider the cost per kilowatt hour for hydrogen excluding the Point ofuse upgrade costs, i.e. the appliance conversion costs. These are shown in Tables
8.14, 8.15 and 8.16.
EXPENDITURE FOR 1ST CONVERSION (PRODUCTION)
Item

Unit

NumberCost £/kWh H₂

Storage LP(Section 2)£

76,641,000

N/A

Includes cushion gas

Storage HP(Section 2)£

289,055,555

N/A

Includes cushion gas

Cost of SMR(Section 2)£

395,000,000

N/A

Excludes commissioning gas
to stores

GAS network additional
work (Section 3)£

10,000,000

N/A

N/A

HTS
(Section 6)£

230,000,000

N/A

N/A

CAPEX Total£

1,000,696,555

N/A

Total investment forhydrogen production andtransportation infrastructure

WACC

%

4.5%

N/A

2015 real costs

Depreciation period

yrs

45

N/A

Network depreciation

Approx. net accounts
finance cost£

30,000,679

0.0051

Excludes allowed returnon capital

AnnualCAPEX depreciation£

22,237,701

0.0037

Cost divided by annual kWh

Annual fixed financecharges TOTAL£

52,238,380

0.0088CAPEX/
Total average demand

Annual O&M(SMR/Salt caverns 4%)£

30,427,862

N/A

N/A

Annual O&M (HTS)£

503,328

N/A

N/A

Annual O&M£

30,931,190

0.0052

O&M cost divided byannual kWh

Sub Total (Production)
Table 8.14. Expenditure for 1st Conversion (Production)259£0.0140 (A)Comment

Production cost/Av
year kWhSection 8 | Finance and Regulation

VARIABLE COSTS
Item

Unit

Number

Cost£/kWh H2

Comment

Cost of natural gas
for SMR use

£/kWh

0.018

N/A

This would likely be cheaper
if the gas network were topurchase this gas using the
Heren price index

Cost of naturalgas (pass-through)

£/kWh

0.018

N/A

Average large user cost of gas
for (using average of DECC
figures for the last 3 years)

Efficiencyof SMR+CCS

%

68.4

N/A

N/A

Cost of natural
gas for conversion
and capture£

49,403,299

0.0083NG bought for processing
and CCS

Pass-through gas
cost (NG to H₂)£

106,936,255

0.0180Gas supplier unit costpass throughTotal use ofnatural gas£/kWh H₂

156,339,554

0.0263Equals cost ofnatural gas for SMR(sum of figures above)

Scope 1 emission
from natural gas

kg/kWh NG

0.184

N/A

The chemical CO₂ footprint of
natural gas

Scope 1 emissions
from conversion

kg/kWh0.269

N/A

Embodied CO₂ footprintof hydrogen

%

90

N/A

Net 0.027 kg/kWh

CO₂ to CCS

kg/kWh H₂

0.2421

N/A

90% of direct emissions

Cost ofsupercritical
CO₂ disposal£/tonne

40.00

N/A

Initial T&S hub charge

Cost of CO₂
disposal£/kWh H₂

0.01

0.0097

Cost of CO₂ disposal

CO₂ emitted by
SMR to atmos:

kg/kWh0.03

N/A

Real emission of CO₂ toatmosphere

Cost of
EU-ETS certificate£/tonne

20.00

N/A

2015 actual cost €7.56
or £5.5/tonne

Cost of CO₂ toatmosphere

£/kWh

0.00

0.0005

CCS efficiency
of collection

Sub Total (Variable Costs) £0.0365 (B)Table 8.15. Variable Costs

260

Cost of emission permit

Section 8 | Finance and Regulation

TOTAL COSTS
Item
Total cost of hydrogen(excluding point of use
conversion, current
distribution+salesetc.) (A+B)

Unit

Number

Cost£/kWh H₂

£/kWh

N/A

0.0505

Includes value ofenergy storage

Comment

Existing ‘gas’
transportation costs

£/kWh

N/A

0.0103

OFGEM cost of delivery
gas to consumers/
kWh. This pays forexisting network

Billing etc.

£/kWh

N/A

0.0052OFGEM costof gas billingto consumers/kWh

Environmental levy

£/kWh

N/A

0.0018

N/A

Cost of retail hydrogen(excluding margin)

£/kWh

N/A

0.0679Sum of figures above

OFGEM average EBDITA%

6.0

0.0041

N/A

Sale price hydrogen excluding point of use conversion
VAT

%

5

Sale price hydrogen excluding point of use conversion
Table 8.16. Total Costs

261£0.072 (C)N/A£0.004

N/A£0.076

N/A

Section 8 | Finance and Regulation

If we now consider the cost of the appliance conversion the cost per kilowatt hour forhydrogen is summarised in Table 8.17 below:
Expenditure for 1st conversion – Appliances (Section 5)
Item

Unit

Number

Cost£/kWh H₂

Conversion ofdomestic property£

805,000,000

N/A

See Section 5

Conversion of
non-domestic£

248,000,000

N/A

See Section 5

Total for Appliance
Conversion£

1,053,000,000

N/A

Free issue and installation ofboilers, burners etc.

Interest at WACC

%

4.5

N/A

N/A

Depreciation
period

yrs.

15

N/A

Prudent life of domestic appliances

Appox. net accounts
finance cost£

27,848,840

0.0047

N/A

AnnualCAPEX depreciation£

70,200,000

0.0118N/A

Annual fixedfinancecharges TOTAL£

98,048,840

0.0165This is annual interest divided
by annual kWhComment

Sub Total (Appliances) £0.0165 (D) N/ASale price of hydrogen including
point of use conversion (C+D)
VAT

%

5

£0.088£0.004

Sale price hydrogen including
point of use conversion£0.093

N/A
N/A
N/A

Table 8.17. Expenditure for 1st Conversion - Appliances

These two costs of hydrogen are essentially ‘well to gas meter’, and ‘well to sofa’
respectively, including full interseasonal storage, allowance for annual maintenanceof the system, etc. These costs should not be compared with either electricity at
the power station terminals or heat at the district heat power plant. Conventionallyneither of the latter contain these full system costs.

262

Section 8 | Finance and Regulation

8.4. Cost per Tonne of Carbon Saved
The conversion of hydrogen has to involve the whole supply chain. At present
comparison of £/tonne carbon saved can therefore only realistically be carried out
against thermal insulation. This is shown in Table 8.18.
Comparative costs

Unit

Cavity Wall

Internal wall

External wall

kWh/yr

1,300

2,100

2,100

£500

£7,000£12,000

kg/kWh

0.184£0.1840.184

Efficiency ofcondensing boiler

%

85

85

85

Footprint of heatkg/kWh

0.22

0.22

0.22

CO₂ saving

tonne/yr

0.28

0.45

0.45

Life time

yrs

25

25

25

WACC

%

4.50

4.50

4.50

Annual cost

£/yr

42.50

595.001,020.00£/tonne

151

1,309

2,244

Insulation
Mean energy saving
Typical cost
Footprint Natural Gas

Cost/tonne carbon saved

Table 8.18. £/Tonne for Scope 1 Emissions Savings for Thermal Insulation

263

Section 8 | Finance and Regulation

HYDROGEN
Item

Unit

Scope 1

Emission from hydrogen

kg/kWh

0.027

Emission from natural gas

kg/kWh0.184

Net hydrogen saving

kg/kWh

0.157

Retail cost natural gas

£/kWh

0.05

Theoretical retail cost hydrogen

£/kWh

0.093

Marginal cost hydrogen

£/kWh

0.046

Cost/tonne carbon saved£/tonne291.94

Table 8.19. £/Tonne for Scope 1 Emissions Savings for H21 Leeds City Gate System

This shows that the cost per tonne of carbon lies above cavity wall insulation but
less than one-third of any solid wall insulation. Hydrogen also offers the potential
for large-scale and deep de-carbonisation. Wall insulation (as above) is unlikely toachieve greater than 20% carbon saving. Considerable care must be taken with sometechnologies) to distinguish between claimed and delivered carbon savings. By thenature of hydrogen technology, this should not be a problem.

264

Section 8 | Finance and Regulation

8.5. Financial Conclusions
yy A hydrogen conversion would almost certainly have to be financed through aregulated price control as was the case with the original town gas to natural
gas conversion.
yy If this was the case the H21 Leeds City Gate project would have minimal
impact on customer bills, a maximum impact being 2.9% (currently financing
methodology) or 1.1% (alternative method for fast slow money) in Year 2026/27.
yy In the scenario presented here, appliances upgrades are included in theregulatory finance. It may be appropriate to consider if this is the mostappropriate mechanism. This is identified on in Section 10, H21 Roadmap.
yy On a standalone project only basis the costs of H21 Leeds City Gate project tothose customers within the area of conversion would be:—— 7.3p/kWh (excluding the appliance upgrade).
—— 10p/kWh (including the appliance upgrade).

yy The impact on GVA and the northern economy and subsequent UK economy
has not been considered in these evaluations. It is recommended that this isundertaken to give an appropriate view on the overall picture. A conversion
programme would create significant numbers of jobs associated with thephysical works and wider supply chain. These jobs would be across England and,initially in the north. This would have enormous benefits for the UK and could be
the anchor of the Northern Powerhouse concept.
yy These costs have not considered the potential for repurposing the Local
Transmission System should an incremental hydrogen conversion take place.
This could allow cost effective connections and a gathering infrastructure to be
developed for unconventional gases as a feedstock to the hydrogen economy.

265

Section 8 | Finance and Regulation

8.6. Regulatory Considerations
When considering the potential conversion of a city to hydrogen, we must consider
the current regulatory obstacles that need to be overcome to allow such a change
to happen. For the purpose of the H21 Leeds City Gate project an overview has been
provided regarding the key changes required however further analysis is identified in
Section 10, H21 Roadmap as part of a specific regulatory project package.
The key points are considered below:

1. The Gas Act:
Section 48 of the Gas Act defines gas:“gas” means—(a) any substance in a gaseous state which consists wholly or mainly of— .
(i) methane, ethane, propane, butane, hydrogen or carbon monoxide;(ii) a mixture of two or more of those gases; or .
(iii) a combustible mixture of one or more of those gases and air; and .
(b) any other substance in a gaseous state which is gaseous at a temperature of
15°C and a pressure of 1013·25 millibars and is specified in an order made by the
Secretary of State.
This means that a hydrogen network is included in the scope of the Gas Act.

2. The Uniform Network CodeThe Gas Transporter Licence is issued under section 7 of the Gas Act and permits
the conveyance of gas. Under their licence, each Transporter has to have a Network
Code. The Uniform Network Code is limited in scope to natural gas and does notinclude hydrogen. Although this definition could be changed a major review of the
UNC would be required to identify any consequential impacts. Some specific areasof consideration in the network code are:General Terms Section C
3 Technical Interpretation
3.1 Gas3.1.1 In the Code, unless the context otherwise requires, “gas” means anyhydrocarbons ora mixture of hydrocarbons and other gases consisting primarily of methane
which at a temperature of 15 °C and an absolute pressure of 1.01325 bar are or is
predominantly in the gaseous state.
The licence also requires Transporters to accede to the Supply Point Administration
Agreement (SPAA) and the Smart Energy Code (SEC). These are predicated onnatural gas as far as gas transportation is concerned and would need a review tocheck whether they need an amendment to apply to hydrogen networks.

266

Section 8 | Finance and Regulation

3. Additional Secondary Legislation
There are a number of pieces of secondary legislation that have significant impacts
on commercial arrangements in the industry for example.
Gas (Calculation of Thermal Energy) Regulations (GCoTER)
GCoTER are regulations made under schedule 3 of the Gas Act 1995 (which
substituted for section 12 and 13 of Gas Act 1986) and therefore would apply tohydrogen networks. However, GCoTER has hard coded values that specifically relate
to natural gas and would need amending to apply to hydrogen networks.
Therefore, although the Gas Act permits gas transporters to transport hydrogen,the Uniform Network Code will require amendment and review together with otherindustry documents and all secondary legislation relating to the gas industry. This is
identified as part of H21 Roadmap, details of which can be found in Section 10.

Conclusion: The Gas Act is, in principle
supportive, but other documents need
to be reviewed and potentially modified

267

SECTION 9

Next Steps The Programmeof Works

Section 9 | The Next Steps - Programme of Works

9. Next Steps –The Programme of Works
It is important to understand the time required to undertake a scheme of thismagnitude and also the regulatory time frames if such an endeavour was to befinanced via a regulatory price control.
There are seven key areas of work that need to be undertaken for a conversion totake place, these include:
1. Delivery of the H21 Roadmap (see Section 10) to provide all the outstanding
technical evidence that such a conversion is possible.
2. Completion of reinforcement and isolation works on the Leeds distribution
system as defined in Section 3, Gas Network Capacity and Section 4, Gas
Network Conversion.
3. Completion of the REPEX programme in the area of conversion.
4. Completion of a FEED/detailed design for the hydrogen supply system(HTS, SMRs, salt caverns).
5. Construction of the hydrogen supply system (HTS, SMRs, salt caverns) readyfor conversion.
6. Hydrogen appliances and equipment development.
7. Conversion of Leeds.
A simplified timeline is provided which represents how these seven work packages
could be progressed. It also identifies critical points in time for both regulatory
business plan development and key policy decisions to be taken.
Additionally, a cost profile is provided against this timeline showing expenditurecommitment both pre and post a policy decision taking place.

269

2013

2016

Regulatory
Price Controls

2018

2021

2026

RIIO-GD1

GD2

1

GD3

H21 Roadmap

UK Gas Industry GDNs/NTS start
to formulate GD2 business plans

2702

Network Reinforcements and Isolation Works

3

Accelerated REPEX Programme (Leeds)

4

5
HTS

4
4

5

SMR and PSA

5Salt Caverns

6

Appliance Conversion

Funding and commitment
required for H21 Roadmapa) GDNs/NTS require OFGEM support
to include works in business plansb) Funding for Work Package 4(Detailed Design) to be in place

Conversion

Government conversion commitment required.
KEY POLICY DECISION, at this point enough evidence
will be present from the H21 Roadmap and commitment tobuild (5) will be required.
POLICY 1: HYDROGEN CONVERSION WILL BE UNDERTAKEN
POLICY 2: CARBON CAPTURE INFRASTRUCTURE WILL BE DEVELOPED

Section 9 | The Next Steps - Programme of Works

7

Image 9.1. Key Elements Timeline2029

Translating this into monetary values results in the following spend profile up to 2029 (note appliance development costs
are not included), this is shown in Chart 9.1.
H21 Leeds City Gate Conversion Spend (£k)
351,000 351,000 351,000
317,250

Key policy decisions
within this period

238,250

157,450

142,400
102,350271

62,300
7,000

2017

2018

2019

2020

2021

2022

2023

2024

2025

7,000

18,50025,50062,300102,350 142,400 238,250 317,250 157,450 351,000 351,000 351,000 2,979.350

Conversion
54,900

SMR/PSA Build
HTS Build

46,000

Salt Cavern Design

18,300

SMR/PSA Design

2028

Total

11,50011,50023,000Accelerated REPEX Programme

91,50091,50073,200311,100

98,750177,750

59,250335,750

46,00046,00023,000161,000
54,90036,60019,750HTS Design

59,25039,50023,00069,000

0

Network Reinforcement and Isolation Works

Chart 9.1. Spend Profile Over Time

2027

351,000 351,000 351,000 1,053,000

Salt Cavern Build

H21 Roadmap

2026

2,000
7,000

7,000

14,00021,00021,000

2,000

2,000

2,000

2,000

10,00070,000Section 9 | The Next Steps - Programme of Works

Total

18,500 25,500

Section 9 | The Next Steps - Programme of Works

Delivery of the H21 Roadmap
The H21 Roadmap, detailed in Section 10, defines a range of projects that need to
be undertaken to provide full confidence that a conversion could take place. This
roadmap, if funded and managed correctly, could be completed in approximately
five years. However, high levels of confidence in the viability of a conversion would beobtained during year’s three to four.

Network Reinforcement and Isolation Works
As described in Section 3, Gas Network Capacity and Section 4, Gas Network
Conversion there are enabling works that would need to be undertaken within thearea of conversion. These relate specifically to:
yy Strategic reinforcement of the low pressure system to ensure ongoing security ofsupply; andyy The installation of isolation valves and associated district governors to enable
conversion to take place.
To do this Northern Gas Networks (and other GDNs if the conversion were to be
incremental across the UK’s major cities) would need to ensure these reinforcement
and isolation works were identified and forecast appropriately in the GD2 submission
to OFGEM. The network would only build this type of expenditure into it's GD2
business plan if there was a recognition from OFGEM that these works were needed.
Undertaking the reinforcement works associated with this scheme would not be
stranded costs if a subsequent decision not to convert took place. This is because
these reinforcements are in areas already indicating pressure problems under thenatural gas system so ultimately reinforcements may be required at some point in
the future.

Accelerated REPEX Programme
For the first city to convert (Leeds), the REPEX programme will need to beaccelerated to ensure all appropriate iron and steel mains have been upgraded to
PE. If the conversion was anticipated in the 2020s the programme would need to bebrought forward from the current end of 2032. This would not necessarily add to theoverall costs, indeed it may reduce due to economies of scale. The HSE mandated
obligations would still need to be maintained unless a deviation was agreed
and approved.
To do this Northern Gas Networks would need to ensure these accelerated works
were identified and forecast appropriately in the GD2 submission to OFGEM. The
network would only build this type of expenditure into its GD2 business plan if there
was a recognition from OFGEM that these works were needed.
It is worth noting undertaking these works would not be a stranded costs if there
is a subsequent decision not to proceed with a hydrogen conversion. This isbecause these works would ultimately be undertaken anyway as part of the REPEX
programme, they would just be undertaken under a longer timeframe.

272

Section 9 | The Next Steps - Programme of Works

Design for the Hydrogen Supply System
A significant area of consideration is progression with a FEED/detailed design,
including appropriate planning considerations, etc. for the hydrogen supply system
which comprises the salt caverns, SMRs, and hydrogen transmission system.
This work would take up to three years to design, and it would be essential that
this was undertaken and in place to enable the build of the system to tie into a
conversion timeline of the mid 2020s. Failure to undertake this work will result in asignificant delay to the onset of hydrogen conversion.
This timeframe also represents a specific funding problem as it is required within
the timeframes of RIIO-GD1. There is currently no funding provision allocated inexisting regulatory business plans to undertake this work. It is recommended thatthese works be progressed, and appropriate funding is provided either via OFGEM oralternative sources.

Construction of the Hydrogen Supply System
Construction of the hydrogen supply system would only commence after thepolicy decision to convert is taken. This ensures a minimum level of expenditure iscommitted prior to such a policy decision taking place.

Hydrogen Appliance and Equipment Development
The conversion would only be able to take place once all the other work packages
were concluded.

Conversion
A critical element of work is the development and certification of a range ofacceptable hydrogen appliances and equipment for the domestic, commercial andindustrial market. Whilst there may be some seed corn funding provided in the H21
Roadmap it is anticipated that a significant amount of this work would be undertakenby the appliance manufacturing industry provided a clear indication was given at UKgovernment level that hydrogen conversion is a real possibility.

273

SECTION 10

The H21 Roadmap

Section 10 | H21 Roadmap

10. The H21 Roadmap
History
As with the original conversion from town gas to natural gas, it is vitally important that
all evidence is acquired to provide confidence that a hydrogen conversion can takeplace and would pose no significant increase in risk to the public.
In the original conversion, the Gas Council established the conversion executive, a teamwhich would oversee the overall conversion process. It also managed various trials andevidence gathering projects over a period of several years.
The H21 Roadmap presented here echoes those lessons of the past for today’s modern
gas industry and considers the most important aspect the establishment of an H21
Programme Team (see Work Package 0). As with the original conversion without
a dedicated team in place the roadmap, delivery will be delayed or inadequately
executed. This will result in delays in the ability to commit to a UK wide hydrogen
conversion programme in line with the Climate Change Act targets.

This section provides a detailed overview of the outstanding technical/evidence
based projects required to provide confidence for the UK to commit to a hydrogen
conversion programme. It provides a comprehensive overview of what is required.
The H21 Leeds City Gate project provides confidence that hydrogen conversion could
be technically possible. However, it is recognised that there are multiple ‘enabling/
confidence gathering’ projects required to provide more robust technical evidence
that conversion is safe and possible. The H21 Roadmap has been developed to cover
three purposes:
yy Investigate any outstanding technical evidence gaps.
yy To prepare the correct regulatory and social frameworks to allow conversion
to happen.
yy To determine the overall strategy for UK wide conversion over time.

275

Section 10 | H21 Roadmap

The work has been split into 16 Work Packages comprising 60 individual projects
summarised below.
Work
Package
Type
Management

Technical
Work Packages

Work
PackagenumberWork
Package
Description

No of Projects

0

H21 Programme Team

1

1

Pressure Reduction

6

2

Below 7 bar Mains Considerations

7

3

Industrial andCommercial Appliances

44

Domestic Considerations

8

5

Multi Occupancy Buildings

2

6

Blending

47

Odourisation/Gas Detection

4

8Technical Standards

1Social/Regulatory
Work Packages

9Regulation

4

10

Public Perception/Education

1

Physical Trials

11

Appliance
Demonstration/Field Trials

4

12

Carbon Capture and Storage

1

13

Hydrogen Transportation

2

14

Electrification (P2G/Micro CHP)

4

15

Unconventional Gas

1

16

UK Wide Development Strategy

6Strategic
Work Packages

Total

60

Table 10.1. H21 Roadmap – Work Package Overview

276Section 10 | H21 Roadmap

Image 10.1 provides an overview of the Work Packages and their key focus area.
Strategic
Work Packages

1

16

Technical
Work Package

2
3

15

4

14
0 - H21
Programme
x
Team

13

5

12

6
11

7
10

Physical
Trials98Social/Regulatory
Work Packages

Image 10.1. H21 Roadmap – Work Package Overview

A work programme of this scale requires commitment, high levels of expertise and a
dedicated team to develop, drive and coordinate the results.
The most critical element of this roadmap is a financial commitment to undertaking
the Work Packages and, crucially, the establishment of the H21 Programme Team.
Without a dedicated team in place, the roadmap delivery will be delayed orinadequately executed. This will result in delays in the ability to demonstrate thecapability for a UK wide hydrogen conversion programme in line with the Climate
Change Act targets.
This multi-year programme of technical/social research and demonstration isneeded to provide all the evidence to de-risk a UK hydrogen conversion.

277

Section 10 | H21 Roadmap

10.1. The Existing System

Gas Rig

Liquid Natural
Gas Storage

Compressor
StationSalt
CavernTerminal

Pressure
ReductionOﬀtakeCompressor
StationPressure
Reduction
StationPower
StationDistrict
Governor

HULL
LEEDS

Image 10.2. The Existing UK Transportation System

The simplicity of the H21 concept is part of its appeal. The practicality of the project
and the realistic ability to undertake the work can be shown simplistically withmodifications to the existing system picture.

278

Section 10 | H21 Roadmap

Gas Rig

Liquid Natural
Gas Storage

Salt
CavernCarbon Captureand Storage

Compressor
StationTerminal

Steam
MethaneReformerPressure
ReductionOﬀtakeCompressor
StationSalt
CavernPressure
Reduction
StationPower
StationSalt
CavernDistrict
Governor

HULL
LEEDS

Image 10.3. Existing System Modifications

The end of the H21 Leeds City Gate project is not the end of the journey to a decision
on conversion. The project has provided confidence that conversion is technicallypossible but multiple Work Packages will need to be completed to develop thestrategy and provide a higher level of confidence.

279

Section 10 | H21 Roadmap

10.2. Work Package Descriptions
The remainder of this section describes the Work Packages and associated projects.
Costs for delivery of all the Work Packages (including the H21 Programme Team)
have been estimated based on sound engineering judgement and are anticipate tocost between £60m and £80m in total. This excludes new appliance development,
for example:
yy Using catalytic combustion to reduce/eliminate NOx levels.
yy Work on levels of ventilation required for fluless hydrogen combustion.
yy The packaging of fuel cells etc.
yy Conversion of certain specialised industrial processes.
Individual costs for each Work Package are not included in this report to ensurecompetitive tenders should funding for this ‘H21 Roadmap’ become available.

Work Package 0. H21 – Programme TeamAs with the original town gas to natural gas conversion, a programme of thisscale and ambition requires a dedicated team (similar to the conversion executive
established as part of the original conversion process) to ensure efficient, high quality
and cost effective delivery. For the projects listed, this team is considered a minimalteam to coordinate the programme.
This programme team is made up of highly competent, qualified individuals required
to drive the programme forward and ensure quality and cost-effective delivery
while shaping and defining (detailed scoping) each project in the Work Packages.
This programme team will also coordinate the results from all the roadmap projects
making the information understandable and accessible to allow strategic decisions to
be made on actual conversion timelines.
It is recommended that this team should be based in Leeds. There are three key
considerations for this recommendation. Firstly, to ensure ongoing support fromthe Leeds City region (which is the first to convert). Secondly to allow effective
communication with Northern Gas Networks who are the principal network in termsof the conversion and intellectual knowledge regarding the original H21 Leeds
City Gate study. Finally, it is expected that, should the conversion ultimately takeplace, this programme team will continue and evolve into the programme team for
managing the conversion process.
The H21 Programme Team has been designed to undertake the Work Packages as
per the colour coding showing in Image 10.4.

280

Section 10 | H21 Roadmap

Programme
Director

SeniorProject Manager

Project
Engineer

Project
Lead

Project
Engineer

Project
Engineer

Project
Engineer

Commercial
Manager

Project
Engineer

Commercial
Assistant

Project
Engineer

Strategic
Work Packages

16

Administrator

1

Technical
Work Package

2
3

15

Project
Engineer

Planner

4

14
0 - H21
Programme
x
Team

13

5

12

6
11

7
10

Physical
Trials98Social/Regulatory
Work Packages

Image 10.4. Proposed H21 Programme Team Structure

In addition to the H21 Programme Team, the Programme Director will also have
responsibility for the associated sub-teams that will be required as part of specificWork Packages and liaison back to central government on roadmap progress.
Programme
Director

H21
Programme
Team

Technical
Standards
Team(See WP 8.1)

Appliance
Testing Hub(See WP 11.1)

Image 10.5. Programme Team Wider Interfaces

281

CentralGovernment
LiaisonSection 10 | H21 Roadmap

The programme team is anticipated to be in place for the duration of the road map
Work Packages delivery anticipated to be completed by 2021/22. In reality, should
the conversion to hydrogen take place this team would extend indefinitely to manage
the conversion process. The cost of this programme team are excluding back officeprovision e.g. finance/accounts, procurement, legal, etc. which have been assumed
as to be provided via DECC/another associated body, for example, an LEP.
It is imperative that this team is established early to ensure cost effective efficientdelivery of the H21 Roadmap projects. Failure to establish this team will lead todelays in delivery and consequentially in the ability to make a decision/policy
commitment to hydrogen conversion.

282

Section 10 | H21 Roadmap

Work Package One: H21 - Pressure Reduction
1.1) H21 – PRU Performance
The operation of existing pressure reduction stations and their individual component
parts needs to be robustly tested for managing hydrogen gas flows. This will include
testing valves, filters, meters, slamshuts and regulators under laboratory conditions
to ensure adequate operability. It will also include testing associated telemetry andpressure monitoring equipment. This project, when fully developed, will look totest different assets individually at different pressures and velocities in laboratory
conditions before a final full Pressure Reduction Station test which could beundertaken on a purpose built skid unit.

Image 10.6. ‘Typical’ Pressure Reduction Station (PRS)

Image 10.7. Instrumentation Equipment

Significant numbers of stakeholders will be required including testing laboratories(potentially universities), industry (networks) and equipment manufacturers.
Consideration should be given by the project team as to whether this project andProject 1.4 should be progressed individually in parallel or run in series to one anotheri.e. Project 1.1 then Project 1.4 or vice versa. This may be dictated by laboratory
availability, logistics of equipment provision for testing, connection complexities and/or individual manufacturer’s proactivity.

283

Section 10 | H21 Roadmap

1.2) H21 – PRU Noise Investigations
PRUs operate in line with current guidance on acceptable noise levels for equipment
as defined in gas design standards and noise regulations. The impact of hydrogenon the noise characteristics of a station will need to be assessed to ascertain
if additional work will be required on existing PRUs to ensure compliance withregulation and design standards. These physical tests, which in part could beundertaken in conjunction with Project 1.1, will require testing of the assets for noiselevels under different operating parameters (pressure, flow, and velocity).
If noise levels are subsequently found to be in excess of acceptable limits new
acoustic enclosures (e.g. regulator housings) or noise attenuation (e.g. regulator
silencers) may need to be installed on some operational equipment. In addition tounderstanding the noise impact of hydrogen on the gas networks pressure reduction
installations this project will develop new guidance on noise considerations for PRU
operations and associated acoustic enclosure modifications/requirements. This
would subsequently be incorporated into Work Package 8 – technical standards.
1.3) H21 – PRU DSEAR Compliance
The Dangerous Substances and Explosive Atmosphere Regulations (DSEAR)
and associated ATEX classifications are complied with via the SR25 IGEM design
standard. These standards detail hazardous zonal classification standards aroundgas sites. A range of physical tests will need to be undertaken to allow the update toSR25. This will result in two ‘SR25’ standards one to be applicable to existing GSMR
standard gas transportation (as is) and a new hydrogen network classification.

Image 10.8. Hazardous Area Classification Drawing (Large Site)

284

Section 10 | H21 Roadmap

1.4) H21 – District Governor Performance and Capacity
The most substantially affected pressure regulating equipment will be district
governors which are extensively located throughout cities. This project will include
testing a range of different district governor types (there are many), including service
governors (MP/LP direct feeds to domestic properties) to ensure operational
functionality is not affected when regulating hydrogen.
This project, when fully developed, will look to test different pressures and velocities
in laboratory conditions. Significant numbers of stakeholders will be required
including testing laboratories (potentially universities), industry (networks) andequipment manufacturers. Consideration should be given by the project team as
to whether this project and Project 1.1 should be progressed individually in parallelor run in series to one another, i.e. Project 1.1 then Project 1.4 or vice versa. This may
be dictated by laboratory availability, logistics of equipment provision for testing,connection complexities and/or individual manufacturer’s proactivity.

Image 10.9. ‘Typical’ District Governors (x2)

The impact on the capacity of these governors under a hydrogen conversion is notclear and ensuring capacity is not affected by the network 1 in 20 design parameter
will also form part of this project. If capacity is found to be an issue, this project will
identify the appropriate measures required to rectify the problem; this could include
partial or full district governor upgrades in areas converted to hydrogen (or could
require no action). If action is required this can be incorporated into gas networks
ongoing district governor replacement programmes. In NGN a number of district
governors are replaced and/or upgraded every year.

285Section 10 | H21 Roadmap

1.5) H21 – District Governor Noise Investigations
District governors (DG) operate in line with current guidance on acceptable noiselevels for equipment as defined in gas design standards and noise regulations. The
impact of hydrogen on the noise characteristics of a DG will need to be assessed toascertain if additional work will need to be undertaken to ensure compliance withregulation and design standards.
These physical tests, which in part could be undertaken in conjunction with Project
1.4, will require testing of current acoustic enclosures (currently designed to NGN/
SP/PRS/35) and DGs for noise levels under different operating parameters (pressure,
flow, and velocity). This project will allow new guidance on noise to be developed forhydrogen DG operations and acoustic enclosure (GRP Kiosk) modifications.
Specifically, for this project gas velocity should be closely considered and the impact
on noise/operability when increasing velocities up to 80 m/s. This could be the new
maximum velocity design parameter recommended as part of the H21 Leeds City
Gate project.
1.6) H21 – District Governor DSEAR Compliance
The Dangerous Substances and Explosive Atmosphere Regulations (DSEAR)
and associated ATEX classifications are complied with via the SR25 IGEM design
standard. These standards detail hazardous zonal classification standards aroundgas sites. A range of physical tests will need to be undertaken to allow the update toSR25. This will result in two ‘SR25’ standards one to be applicable to existing GSMR
standard gas transportation (as is) and a new hydrogen network classification.

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Work Package Two: H21 – Below Seven Bar Mains Considerations
2.1) H21 – Remaining Metallic Mains Assessment
The REPEX programme is currently delivered under a risk scoring methodology
as agreed with the HSE and gas industry. This risk scoring methodology allows
prioritisation of pipes for replacement based on their relative level of risk. An internal(NGN) appraisal of the ‘end of programme position’ needs to be undertaken to
ascertain the number of remaining metallic mains in the Leeds area. This should
identify the quantities by length, diameter and location as well as showing the levelof risk score remaining as defined in the REPEX risk scoring model.
2.2) H21 – Remaining Metallic Mains Hydrogen Leakage Assessment
Under the current REPEX regime, there will be a proportion of metallic mains
retained within the network. These are generally above 8 inch in diameter and/or
have a very low-risk score or have not to be replaced under a cost-benefit analysis
assessment (i.e. minimal leakage history). The relative risks of transporting hydrogen,and any associated leakage, through these mains, needs to be assessed. Whenundertaking this project, it will be important to quantify the relative risk of a hydrogenleak AGAINST the equivalent risk of an existing natural gas leak.
These ‘retained’ mains by default have not been replaced with plastic as a resultof having a low-risk potential or high asset health integrity, i.e. minimal leaks overtime. As a result, they would only need to be replaced for hydrogen transportation
should it be determined that a disproportionately greater risk would occur as a resultof transporting hydrogen. To undertake this project physical trials on existing mains
would need to be undertaken. The gas industry has such mains across its networks
that are either obsolete or can be isolated. Utilising these mains for the trials would
be a cost effective ‘real life’ way to test the impact of hydrogen.
It is important to note that it is not anticipated that hydrogen will pose an increased
risk in retained metallic mains. Indeed, when considering this project the H21
Programme Team should also consider:yy The high diffusivity of hydrogen in air (20 m/s) vs. natural gas.
yy The ability of hydrogen to ‘track’ underground vs. natural gas.
yy The level of risk that is acceptable today for our ‘leaking’ natural gas network,when compared to the natural gas or hydrogen network possible in 2029 (whenconversion may or may not have taken place).
yy Additionally it should be articulated in the overall outputs from this project that,providing hydrogen leaks represent no increase in risk, any future escapes from ahydrogen network have no detrimental impact on climate change vs. the current
level and future levels of natural gas escaping the system.

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2.3) H21 – Accelerated REPEX into Key Areas
To start the conversion process from natural gas to hydrogen the first cities to convert
would need to accelerate their REPEX programmes. The current REPEX programme
is risk-based and, while there is flexibility where to prioritise projects based on the
80/20 design criteria, the programme would not conclude until 2032. As a result,the conversion to hydrogen of the first cities (Leeds/Teesside/Hull (see H21 Vision))
would be unlikely until the mid-2030s. This may be acceptable but does delay theopportunity to decarbonise heat and also shortens the time for the incremental
rollout of the hydrogen conversion programme to meet the 2050 target.
Working with NGN (as the first network requiring conversion in the next pricecontrol period) this project would understand the commercial impact and logisticalchallenges of accelerating its REPEX programme into Leeds, Teesside, and Hullin RIIO GD2. It should also consider any impact on the network meeting its safety
obligations of the 80/20 design guidance for the REPEX programme. It would also
consider the impact of accelerating REPEX into Newcastle, Bradford and Manchester
for the next stage of conversion.
2.4) H21 – Mains Isolations to Support Conversion (See also Work Package 4
Project 4.5a)
As part of the conversion process a detailed conversion plan would need to be
developed (see Work Package 4 Project 4.5). This would require strategic valves tobe installed to allow a double block and bleed configuration to be in place to isolatehydrogen areas from natural gas areas as the conversion takes place. In reality, manyof these valves may exist, but large numbers will need to be installed in preparation
for conversion. Ideally, with early identification, these can be installed as part ofongoing REPEX work, but some will need to be retrofitted once the detailed analysis
in Work Package 4 Project 4.5 has been undertaken.
2.5) H21 – Constrained Velocity/Pressure ‘Problem’ Area.
As part of the conversion to hydrogen, some areas will require some retrospective
reinforcement to maintain pressures through 1 in 20 winters (as per current designcodes). These areas should be analysed by networks in strategic cities UK wide, orminimum in Leeds/Teesside/Hull to ensure the appropriate REPEX replacement
strategy is adopted e.g. open cut, live insertion, etc. This will ensure retrospective
reinforcement costs are kept to a minimum and work is undertaken today bearing in
mind the requirements of tomorrow.

288Section 10 | H21 Roadmap

Image 10.10. LP Network Reinforcement Requirements

2.6) H21 – Hydrogen PE Mains Leakage
Evidence proving the relative level of risk for hydrogen transportation through PE
mains needs to be provided. Specifically, but not limited to, consideration should begiven to:yy Transition fittings i.e. where PE joins retained metallic pipes.
yy Leakage from 3rd party damage i.e. where a third party causes a failure of themain, for example due to hitting it with a mechanical excavator.
yy Diffusion through PE pipe walls of different wall thickness’s. Note early resultsfrom Denmark are encouraging suggesting a very low level of leakage.
yy Diffusion through PE mains of different ages of installation.
These potential risk of these types of leaks from a future hydrogen network should
be quantified against existing methane to understand if there is any increased risk in
a future hydrogen network.

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It should be noted that when considering
the risk of specific leakage paths the H21
Programme Team should also consider the net
risk position for a UK hydrogen network whencompared to the natural gas network of today
and the equivalent natural gas network of thelate 2020s. Indeed, by the time, a hydrogen
conversion takes place nearly all mains will
be PE, which are butt/electrofusion welded.
This in itself gives a significant reduction inrisk to life and property than the network that
we have in the UK today even if that future
network is transporting hydrogen.
2.7) H21 – Summer Flow Modelling
The UK gas industry is designed and managed to meet a 1 in 20 peak hour demand;
all lower demands are based on ratios to reduce this peak usage figure (see Section
2, Demand vs. Supply). When undertaking the H21 Leeds City Gate project, oneof the most significant challenge faced by the project team was establishing what
the actual consumption for low demand conditions, i.e. in summer, was in the areaof conversion.
In order to optimise any future detailed design the UK gas industry should establish
a series of diversification curves for different community archetypes to ensure low
demand, equivalent to 1 in 20 troughs, are robustly understood. Failure to adequately
understand this will result in oversizing and/or undersizing of hydrogen production
and storage facilities. This will result in excessive cost or security of supply issues.
In the first instance, the area of conversion identified in H21 Leeds City Gate shouldhave ultrasonic (or other) meters installed at all the extremity locations. These shouldbe operated for a minimum of two summers, and the actual summer demand should
be calculated for the area of conversion and compared to the original study.
When considering this project the H21 Programme Team should also consider
the results of SGNs ‘real-time networks’ 2015 NIC bid and also the results of NGNs
T-Shale part one and two 2015 Network Innovation Allowance projects.

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Work Package Three: H21 – Industrial and Commercial Appliances
The funding for development of large-scale rollout for industrial and commercial
conversion is anticipated to be extensive. In reality, the appliance manufacturingindustry may part fund (likely with government support) and accelerate thedevelopment of these types of appliance/equipment if a policy decision onhydrogen transpires.
The first task must be to quantify to a reasonable level of accuracy the existing
stock of combustion equipment and determine the minimum range of appliances
necessary to replace them. This may be complex if the existing boiler house or
furnace is effectively ‘time expired’ and needs replacing.
For the commercial heating sector, a sub-work programme will need to beestablished between building owners, local heating and ventilation companies,
and Leeds Council building control. This will need to establish the principles to befollowed for different types of boiler house. Various funding formulae will need tobe agreed.
3.1) H21 – Industrial Gas Applications
The range of industrial gas applications within the Leeds (and other city) areas
needs to be understood in detail. The H21 Leeds City Gate project has considered
this in Section 5, Appliance Conversion but on a desktop exercise basis. It is likely
further work will be required involving multiple stakeholders to help understand theindustrial gas use, appliance type, and potential burner amendment configurations.
In order to undertake this work, a specific Project Manager may be required toengage with the industrial sector and compile a comprehensive range of robust
information. The use of trade bodies/institutions to help facilitate contact as well
as some key manufacturers/academic institutions should also be considered. If
effective when scoping a comprehensive delivery strategy this project manager may
also be able to undertake Project 3.3 concurrently.
This project will also provide information for Work Package 4 Project 4.5 to allow a
clear conversion strategy to be developed with regional industrial users identified.
3.2) H21 – Industrial Conversion
Project 3.2 will build on the initial learning of Project 3.1. The project could
involve physical testing, design, and certification of appropriate modifications to‘upgrade/replace’ industrial gas use applications through the methane – hydrogen
conversion process.
This project could be considered alongside Work Package 11 ‘physical trials’ andcould partly be undertaken at the appliance testing facility Project 11.1. This is likely to
be one of the most technically challenging tasks, especially re-configuring imported
equipment. The latter would have been rare in the original town gas programme.

291Section 10 | H21 Roadmap

3.3) H21 – Commercial Gas Applications
The range of commercial gas applications within the Leeds (and other city) areas
needs to be understood in detail. The H21 Leeds City Gate project has considered
this in Section 5, Appliance Conversion but on a desktop exercise basis. It
is likely further work will be required involving multiple stakeholders to help
understand in detail the commercial gas use, appliance type and potential burneramendment configurations.
See 3.1 for comment on project delivery/management.
3.4) H21 – Commercial Conversion
Project 3.4 will build on the initial learning of Project 3.3 (compiled as part of H21
Leeds City Gate, The project will involve physical testing, design and certification of
appropriate burning modifications to ‘change out’ commercial gas use applications
through the methane – hydrogen conversion process.
This project could be considered alongside Work Package 11 ‘physical trials’ andcould partly undertake at the appliance testing facility Project 11.1.

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Section 10 | H21 Roadmap

Work Package Four: H21 – Domestic Considerations
4.1) H21 – Service Pipes
Following completion of the REPEX programme, under the current replacement
regime, there may be a number of metallic service pipes remaining in the Leeds
conversion area. The volume and condition of these services need to be understood;
this can be done using internal NGN modelling systems, data, and projections.
Tests will be undertaken on actual services of varying materials, diameters andconditions in order to establish the level of risk. It may be appropriate to develop thecurrent REPEX risk modelling methodology for these remaining pipes to understandwhich, if any, may need replacing ahead of a conversion.
4.2) H21 – Service Pipe Testing
The relative risks of transporting hydrogen, and any associated leakage, throughretained metallic services, needs to be assessed. When undertaking this project,
it will be important to quantify the relative risk of a hydrogen leak AGAINST theequivalent risk of an existing natural gas leak.
When developing this project the H21 Programme Team should consider the
information provided following completion of 4.1. In addition to understanding therelative risk of retained metallic service pipes carrying hydrogen vs. natural gas
consideration should also be given to quantify any increase or decrease in risk
associated with a leak from a future PE service pipe. This latter piece of work will
require testing of PE services with simulated leakage for a range of ‘lay’ scenariosand damage impacts. For example, services laid in a garden hit by a shovel atshallow depth or a service laid in a concrete drive hit by a pick axe!
It is anticipated that the gas industry will already have significant information on
service pipe risks both within the REPEX model and wider industry background. The
H21 Programme Team should identify and utilise this information ensuring the correctquestion is answered as part of this project, i.e. ‘what is the relative risk of hydrogen inservices when compared to existing natural gas’.
4.3) H21 – Meter Testing
The current meter population for gas measurement is calibrated for methane.
Tests need to be undertaken across the range of network and domestic meters
to understand the impact of the meter measuring hydrogen. Once the impact onmetering is understood, strategies for corrective action need to be considered. These
could include:
yy Do nothing – the meters still work within acceptable tolerance.
yy Develop a correction factor – for example, if the meters perform from an
integrity point of view (safety) but has an error in terms of measurement, could acorrective factor be established for meters originally designed for methane but
now operating on hydrogen.
yy Partial upgrade alongside the smart metering rollout programme.
yy Upgrade as part of the conversion process.

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Section 10 | H21 Roadmap

4.4) H21 – Smart Metering
As with 4.3, the impact on any approved smart meter needs to be considered.
Will these meters, operate on hydrogen. Consideration should be given to theimpact of the smart meter rollout programme and its relative benefits in thehydrogen economy.
Following results from 4.3 and testing of smart meters on hydrogen (4.4) it may
be recommended that smart meter rollout should start in areas less likely to beconverted to hydrogen in the short term. This would allow time for a hydrogen smart
meter to be developed or testing to establish if existing smart meters are suitablefor hydrogen.

The smart metering programme offers aunique opportunity to undertake customer/
appliance surveys at each property/priority
consideration should be given to undertaking
these surveys at the same time as meter
installation to ensure no duplication ofeffort. Other considerations should also begiven to this customer interaction in terms ofeducation pieces. (See Work Package 10 –public perception)
4.5) H21 – Conversion Strategy
The range of domestic gas appliances within the Leeds (and other city) areas needs
to be understood in detail. The H21 Leeds City Gate project has considered this in
Section 5, Appliance Conversion but only on a desktop exercise basis. It is likely
further work will be required involving multiple stakeholders to help understandin detail the domestic gas use, appliance type and potential burner amendment
configurations. The work undertaken by SGN in Oban should be considered as goodevidence to date for consideration by the H21 Programme Team.

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Section 10 | H21 Roadmap

This will require three significant areas of work:4.5a) H21 – Conversion Modelling, Design and Data Collation
This project will consider the practical conversion strategy for the area of conversion
to 100% hydrogen. The project will include utilising the gas networks Synergi model
to design an appropriate conversion strategy for the area. Additionally, this projectneeds to consider the potential UK rollout strategy (Work Package 16) as it may
transpire that a much larger area of conversion, for example, Leeds and Bradford,
needs to be considered based on a national rollout decision.
The project will include:
yy Understanding lessons of the past town gas conversions—— Literarture review.
—— Interviews.
—— Etc.

yy Designing the isolation strategy utilising the Synergi model for city conversion(Developing on the work presented in 2.2)—— Isolation locations.
—— Reinforcement requirements.

yy For each isolation area understanding the conversion requirements:—— Area demographic e.g. domestic, commercial, industrial numbers.
—— Appliance types – domestic e.g. type/number of boilers, cooking, fires, etc.
—— Appliance types – commercial.
—— Appliance/burner types industrial.

The project will build on the work already undertaken by the network and will besupported by an expert Synergi modeller.
4.5b) H21 – Off Network, On Gas Trials.
As part of the conversion, it may be a requirement, at least for some customers, thatthe isolated areas will be kept supplied with gas for essential services (cooking/hot water) by localised bottled gas supplied to their properties. NGN are alreadyundertaking an initial investigation of this work as part of an existing Network
Innovation Allowance project. This initial project may require additional work toensure the full range of scenarios for isolation are covered to allow any conversion tobe well understood and effectively executed. This could include:
yy Mother/daughter fuelling.
yy Bottle size.
yy Security measures.
yy Connection techniques.

295Section 10 | H21 Roadmap

4.5c) H21 – Appliance Modifications/Development
The range of appliances for boilers, fires and cookers in the UK is extensive.
Significant engagement is required with the appliance manufacturing community
to consider:yy Reconfiguration of existing appliance, i.e. how/if the upgrade of burners is
possible and on which appliances.
yy The design of new appliances taking account of the customer demands on
modern aesthetics. This should also consider the design of new appliances thatcan either be built ready for dual purpose or designed to enable easy conversion
to hydrogen.
This project will be essential as part of the overall conversion strategy. In effectwhen areas are isolated the conversion engineers should know upfront exactly
what is required at each customer’s property, and the logistics should be in place toensure swift replacement of parts/appliances for cost effective, timely conversion.
Bad planning in the upfront stage will have more effect on customers and will
cost significantly more in wasted time for the conversion team versus the cost ofdetailed up front surveys. In reality; this may be some seed-corn funding for entry
level appliances and demonstration purposes for fires, hobs, and cookers. As
with industrial and commercial considerations, it is anticipated that development
in domestic appliances would cost significant amounts of money and would beaccelerated and funded (at least partly) by the appliance manufacturing industry
should a decision to convert to hydrogen transpire.
4.6) H21 – Enhanced Ventilation of Enclosed Spaces/Compartments and Potential
Use of Hydrogen Detectors
A detailed assessment of risk needs to be undertaken across the building stock andremaining metallic mains stock to see if there is any disproportionate increase inrisk (when compared to natural gas) associated with hydrogen escaping from bothinternal and external pipework.
Additional ventilation may be deemed necessary and/or appropriate consideration
could be given to hydrogen detectors being installed at potentially higher risk
locations (should any be identified) at the same time as the conversion is undertaken.
This project should pull together the quantitative risk assessment from projects suchas HyHouse, Hy-Occupancy (see 5.1) and the Project 2.2 and 4.2 on the H21 hydrogen
Roadmap. It may transpire, and in fact is probably more likely, that no or minimal
additional detection either in properties or in strategic street locations is necessary.
Even so, a range of hydrogen detectors should be available to the public should
they wish to procure one for their own piece of mind. Sourcing these detectors andtesting/approving for the UK Market will form part of this project.

296Section 10 | H21 Roadmap

Work Package Five: H21 – Multi Occupancy Buildings
5.1) H21 – Hy-Occupancy
Building on the HyHouse project this project should enable a quantitative risk
assessment to be undertaken of high occupancy buildings, for example blocks offlats. This will ensure that the risks associated with a hydrogen leak in flats/other
Hy-Occupancy buildings are understood.
This work may also extend to strategic commercial and industrial properties wherethe volume etc. of gas release may cause a specific area of concern. For example,
this could include industrial properties with a high pressure (7 bar) gas supply orproperties with specific types of gas application.
5.2) H21 District Heating
Energy efficiency is still an important factor when considering conversion. In
addition, long-term safety considerations for high rise services could suggest district
heating systems, fed from the hydrogen network, for multi-occupancy/high heat
demand buildings may be quite an attractive option. A study should be undertaken
considering strategic areas where building specific district heating systems could beconsidered within the area of conversion identified in H21 Leeds City Gate. Whole lifeand safety reduction impact should be considered and compared to a direct likefor-like replacement to understand if there is merit in upgrading to district heating aspart of the overall hydrogen economy strategy.
As part of this project, consideration could be given to district heat suppliers andavailability of commercial appliances (see Work Package 3). National Grids recent
District heat study (NIA), the various other studies and the Leeds LEP strategic district
heat study should be considered by an independent project manager to determine
if there is any merit in progressing with building specific district heating schemes in
the context of a hydrogen conversion programme. This project manager could workas part of the H21 Programme Team for the duration of the project. Funding formulae
will need to be established.

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Section 10 | H21 Roadmap

Work Package Six: H21 – Blending
The H21 principles are to move to a 100% hydrogen gas network over time. It is
recognised that having a higher hydrogen blend within the existing gas may be
advantageous in some limited scenarios. Whilst this would never provide the typeof carbon saving of an H21 scheme it may be useful to understand some blending
opportunities where system integration between the electric and gas networks orby-product hydrogen usage could be in the interests of the wider UK energy system.
It should also be noted that blending, at any scale, has challenges based on
intraday and inter-seasonal flow rates, billing and potentially safety at the pointof consumption depending on percentage blend. It also only saves ⅓ the carbon
by volume, i.e. blending up to 10% only saves 3.3% carbon (assuming 100% ‘greenhydrogen’) due to the energy content of hydrogen. Ultimately moving to a 100%hydrogen but understanding blending opportunities as a hydrogen economy
grows over time may be beneficial to the UK and should be considered. It is not therecommendation of H21 that a blended UK gas network should be aspired to orindeed that it would significantly support the challenge of the climate change act.
6.1) H21 – Blending Literature Review (Hyready)
The UK GSMR (Gas Safety Management Regulations) currently stipulate a maximum
hydrogen content of 0.1%. A piece of work is currently scheduled to start in Europe(2016) that will try to quantify the risks of increased hydrogen content into the gas
grids, e.g. up to 30%. This work is being funded by a pan-European consortium of up
to 16 partners including of the four UK gas transporters.
The results of this work should be monitored/supported by the H21 Roadmap team.
Blending hydrogen could have two significant benefits
1. reducing carbon emissions in areas still on methane; and2. allowing balancing (supply vs. demand) of the hydrogen infrastructure if
the existing storage is marginally insufficient at times of extreme, e.g. very
mild summers.
It should be noted that blending hydrogen should not have any detrimental impact
on network infrastructure much of which was used with town gas which had 50-60%
hydrogen content. Additionally key considerations for any potential blending needto consider the intraday and inter-seasonal demand profiles, i.e. how to keep at a
set percentage hydrogen and what controls are required as well as flow-weighted
average CV billing parameters (see 6.4).
6.2) H21 – Blending Capacity Analysis
As part of the T-shale Part one scenario modelling capacity requirements on the
network are being modelled for different sources of injection. This analysis should be
extended nationwide to develop a ‘gas blending map’ of the UK showing injection‘hotspots’ for 5/10/20/30% hydrogen blends. This will allow an informed strategy
on managing surplus renewable generation with gas system storage optimising thetransportation infrastructure and integrating the system in the most efficient manner
for the UK.

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Section 10 | H21 Roadmap

6.3) H21 – Blending Testing
Whilst the Hyready project may consider the effect of hydrogen blending on the
network some real life testing will need to be put in place to look at the impact onvarious hydrogen blends on the end-use appliances. This could be undertaken in a
project similar to the Oban project being undertaken by SGN. Trialling will likely beundertaken as part of lab testing and live application testing. It is recommended that
this could be done at the Teesside testing facility (see Work Package 11 Project 11.1).
National Grid has submitted a project to the Network Innovation Competition in2016 which is looking to address some of these issues. If this is awarded, the H21
Programme Team should work closely with this team to coordinate results.
6.4) H21 – Postcode Billing
A significant issue that arises from hydrogen blending, and indeed hydrogendesignated areas, is billing (see Work Package nine). Currently in the UK customers
are billed based on a Flow-Weighted Average Calorific Value (FWACV) for a networkarea. In effect the average level of energy in the gas at all the network offtakes (oversimplified but in principle correct). If hydrogen blending were to be undertaken withlocal injection of hydrogen the energy content in specific areas would drop. Under
the current billing methodology the bills would remain the same based on the
FWACV which would penalise those customers living in a blending area.
The UK gas industry is currently undertaking work to look at localised measurementof calorific value. If this was to be rolled out billing could be undertaken based on
postcode areas to ensure customers are only billed for the energy they use, not the
average energy content. This would require extensive changes to existing shippers
billing system as well as development of a strategy to install measuring devices inareas likely to be affected.
This project would also support the onset of any other unconventional gases and, forexample could remove the need for proponation of biomethane.
In reality this project is likely to be a significant undertaking and currently National
Grid/NGN are proposing putting the project forward for NIC funding in 2016. If the
NIC project is awarded it would be imperative that H21 Programme Team can ensure
the project covers all the possibilities for hydrogen as well as methane CV variations.

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Section 10 | H21 Roadmap

Work Package Seven: H21 – Odourisation/Gas Detection
7.1) H21 – Odourisation ‘Carry’ Potential
Natural gas is currently odourised at the network offtakes. This process is critical to
the network’s safety case and the level of odourant in the gas is monitored by trained
network rhinologists. This ensures the level of odourant does not exceed the industry
recommended level causing undue numbers of reported gas escapes or does notdrop below that standards resulting in insufficient concentrations to identify leaks.
The level of odourisation required in the hydrogen to meet current recommendations
needs to be understood and this will involve physical trials. There are two scenarios
to investigate.
yy If the methane for the Steam Methane Reformer (SMR) is taken from the NTS
the gas is unodourised and as such will need full odourisation at the offtake of
the SMR.
yy If the gas is taken from the Local transmission system it is already odourised andthe impact of the SMR on the odourant level needs to be considered this may
result in additional odourisation required after the SMR process.
7.2) H21 – Alternative Odourant
In the long term the hydrogen network is likely to be used for refuelling vehicles
or micro CHP. The current odourant is a sulphur based compound which would
damage a fuel cell and would therefore require a change. In Japan a new odourant(cyclohexene) has been trialled that is compatible with fuel cell technology, butdoes not have the stench associated with current EU odourants. The level ofthis development needs to be understood and the retrospective impact of any
amendments to the UK odourisation techniques quantified.
Additionally meetings with appliances manufacturers indicate the need to specify
the hydrogen gas characteristics including any colourant and the odourant. Moving
to a non-sulphur odourant presents significant benefits for appliance development
and should be considered from the start of the onset of the hydrogen economy tooptimise hydrogen appliance design.

300Section 10 | H21 Roadmap

7.3) H21 – Operational Hydrogen Detection (Gasco-seeker – Leaks)
As part of the current gas industries safety case the gas transportation companies
operate a 24 hour emergency response service for gas escapes. This involves, inthe first instance, a ‘first call operative’ (FCO) attending site to assess and identify
the most probable location for a gas leak. To do this each FCO has a ‘gasco-seeker’
which is calibrated to detect methane concentrations. For areas converted tohydrogen these pieces of equipment would need to be developed and calibrated forhydrogen. Initial discussions with manufacturers suggest this can be easily done.
In addition availability of parts per million detectors, similar to those used today todetect hard to trace leaks, needs to be established/developed.
7.4) H21 – Network Purging Operations
When commissioning a new gas main (i.e. purging from air to methane) a gasco
seeker is used. This gasco-seeker is located at the opposite end of the pipe to thatwhich the ‘new’ gas is being introduced. A reading of greater than 90% methaneis required before the pipeline is considered purged with gas. Current gasco
seekers would not be able to undertake this task for a 100% hydrogen purge. This
would be essential to the conversion process and also the ongoing operation of ahydrogen network. This new piece (or adapted piece) of apparatus would need to be
developed as part of this project.

301Section 10 | H21 Roadmap

Work Package Eight: H21 – Technical Standards
8.1) H21 – Technical Standards Modifications/Development
The legislation, industry standards and Policies and Procedures (P&Ps) which govern
the gas industry are both extensive and robust. They are vital to ensuring the safe
efficient running of the gas system and range from the networks safety case tosimple engineering instructions.
Following networks sale in 2005 many of the gas industry standards were adopted
and are individually owned by the specific networks. Currently, the suite of standards
broadly applicable to the gas industry can be summarised as follows:
Owner

Quantity

Comment

c. 617

These all started as the same set of documents
but have subsequently been modified/updated
by individual networks over the last ten years.

IGEM

57

These are formally adopted by the Networks if
they choose to do so.

Gas Industry Standards

66

These are collaboratively owned by the gas
industry (all the networks) and are managed via
the technical standards forum.

External Legislation

74

Legislation (for example Pipeline Safety
regulations, Dangerous substances and explosive
atmospheres regulations.)

GDN/IDN(NGN/WWU/NG/SGN)

Total

Over 800

Table 10.2. Key Gas Industry Governing Documents

These documents would need to be updated for hydrogen transportation and would
require industry involvement as well as support from the wider chemicals/petroleum
industries who already transport ‘other’ gas and hydrogen. Whilst many of thesestandards would require little or no amendments, others would require medium tomajor amendments and some total rewrites or indeed a new standard producing.
This piece of work would require a dedicated full-time team (H21 Standards Team)
who could gather and compile all relevant information. This information may comefrom the projects on the roadmap, other industry, and international best practice. It is
anticipated that this would be an extensive piece of work taking five to ten years tocomplete. Initially, a prioritisation system would need to be developed to enable thecritical standards/‘low hanging fruit’ to be addressed first.

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Table 10.3 has been provided to give an indication of the types of documents
involved in this work.
Owner

Reference

Title

Technical Area

NGN

B11

Carbon and carbon manganese steel bends
200 mm and above > 7 bar

AGIs, fitting
and plant

NGN

B12

Steel bends, reducers and cap ends > 7 bar

AGIs, fitting
and plant

NGN

V14

Donkin valves fig. 555

AGIs, fitting
and plant

NGN

V6 Part 1

Steel valves for use with natural gas at
normal pressure above 7 bar Part 1-100 mm
nominal size and above

AGIs, fitting
and plant

NGN

COMAH5Emergency plans for notifiable sites, COMAH
sites and major accident hazard pipelines

Asset

NGN

NP1

Charging point on LTS systems

Asset

NGN

NP40

Network entry requirements

Asset

NGN

SSW8

Unodourised gas installations

Asset

NGN

PWC1 PT1

Acoustic cladding pt 1 pipe and equipment

Coating

NGN

HAZ2

Venting operations (manual) on installation
prior to maintenance

DesignNGN

HAZ3

The zoning of pressure regulating
installations operating below 7 bar

DesignNGN

CD01 pt3

Pipeline and main records, maps
and surveys

Drawings/
Records

NGN

RE7

Network pipe records

Drawings/
Records

NGN

EL6Electrical equipment and system - working
on or near at operational sites

E&I

NGN

GQ6

Odour intensity monitoring

E&I

NGN

SC02

Safe control of operations - issue of permits

H,S&E

NGN

Section 09

Use of contractors

H,S&E

NGN

EM71

Gas escape - dealing with andother emergencies

Operations

NGN

EM71 Supplement

Gas escape procedure - advice

Operations

NGN

TMP6

Flueing and ventilation

Operations

NGN

MAINT 2205

Orpheus series 4 procedure isolation

Operations

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Section 10 | H21 Roadmap

Owner

Reference

Title

Technical Area

NGN

MAINT 3040

Purging

Operations

NGN

ML1

Pipe system construction general requirements

Operations

IGEM

IGEM/SR/25 Ed2

Adoption

IGEM

IGEM

IGEM/TD/1 Ed5

Adoption

IGEM

GIS

L2

Specification for steel pipe 15 mm to 450
mm inclusive nominal size for service atpressures up to 7 bar

GIS

Table 10.3. Document Examples.

It should be noted that IGEM does not currently have the resource (circa 23 staff, mostnone technical or part time) to amend these documents. Additionally, it does not own
the vast majority. It is however recommended that this ‘H21 standards’ team be based
within IGEM reporting back to the H21 Programme Team. IGEM has four key benefits
for adopting this role.
yy Already the universal QA body for all ‘IGE’ standards.
yy Recognised representative body for all the gas networks.
yy Respected industry body.
yy Charitable organisation.

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Work Package Nine: H21 – Regulation
9.1) H21 – Regulation
The gas industry is governed by the uniform network code (UNC) which dictates
what can and can’t be undertaken by a network. This extensive document covers
every aspect of the industry and will need a considerable overhaul in certain areas
to allow network conversion to hydrogen, potentially alterations to billing, capacity
auctioning etc. (see 9.2 and 9.3 below).
9.2) H21 – Billing
Currently in the UK gas distribution networks do not own the gas, they are
responsible for transportation only. If hydrogen conversion were to be undertaken
alternative frameworks for managing the billing of hydrogen should be considered.
To give two examples:
Example One:
Natural gas entering the SMR would currently be owned by multiple shippers. Afterthe SMR process would it be more appropriate for a network to ‘buy the gas (energy)’
from the shipper at the SMR then sell the hydrogen (energy) to the customers
within its hydrogen network location. In the water industry the networks are bothtransporter and billers. Could this be considered for the gas industry for areas
converted to hydrogen.
Example Two:
When considering the efficiency energy loss at the SMR should a network beallowed an OPEX value within its regulatory business plan to fund this loss (ascurrently recommended in Section 8, Financial and Regulation). This would ensure
individual customers within a hydrogen area are not penalised but instead theefficiency loss is socialised across all network customers.
Thought should also be given to the flow-weighted average CV billing methodology
currently adopted in the UK. This allows networks to measure energy content at theirofftakes from the national transmission system and calculate an average energy
content (calorific value which is then used generically for billing in specific areas.
The billing system could be adapted to allow postcode billing i.e. local measurementof CV to give a more accurate area by area billing opportunity. This would allow
postcode billing in hydrogen areas and/or in high blend hydrogen areas without
artificially inflating bills for customers in these regions. FWACV projects are alreadybeing investigated under the NIA provision in the UK gas industry (NGN/NG) but
significant ‘push’ and recognition of the problem needs to come from the regulator.

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When converting areas to hydrogen incentives may be appropriate for a limited
amount of time to support the public acceptance for the conversion. For example, if a‘postcode billing system’ were adopted, it would be possible to provide a time-boundreduction in bills i.e. not paying for all the energy the customer uses. This could be
funded by socialising costs across other regions of the country, which in reality would
have little impact on individual bills nationally. The incentive could then ‘roll’ with theconversion programme essentially meaning all customers receive the benefit in thelong run.
9.3) H21 – Security of Supply/Ownership
Currently networks have to secure capacity off the National Transmission System(NTS) on an annual basis. In a hydrogen economy which organisation would own the
SMRs, the network and the storage? Indeed as the hydrogen economy grows fromcity to city Northern Gas Networks could be supplying cities within other network
boundaries (e.g. Manchester is owned by National Grid North West).
Consideration needs to be given to how the capacity for hydrogen is booked
and secured from the storage/SMR sites and who is booking what from whom.
Considering the SMR/Storage could likely be located directly and intrinsically as
part of the network could it be assumed that the network should own the facility as
their licence to operate is predicated on maintaining gas supplies. This area needs
detailed consideration and will require input from across the gas industry. This should
be managed by the H21 Programme Team.
9.4) H21 – Finance Model Appliance Considerations
The H21 Leeds City Gate financial model recommends paying for applianceupgrades as part of the regulatory finance model. This is what occurred on theoriginal town gas to natural gas conversion. The finance mechanism for this is unclear
for example, the asset is not ultimately the networks so it would currently be dealt
with as ‘OPEX’ however it may be advantageous to consider it as CAPEX to allow
costs to be amortised over a longer period (see Section 8, Financial andRegulation). This needs detailed consideration and will need to be defined andagreed between the network regulator and the gas industry. The ability for the
networks to raise capital to fund this scheme also needs to be considered against
the recommended regulatory finance model.
Noting not all the UK needs to be converted to hydrogen there could be challenges
with upgrading appliances in areas to convert ‘for free’ whilst not upgrading thoseareas retained on natural gas. It may be considered that, as part of the UK rollout
strategy (see Work Package 16), areas which will not convert do not pay for theelement of conversion associated with appliance upgrades. This will need significant
review and consideration to produce acceptable recommendations.

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Work Package Ten: H21 – Public Perception
10.1) H21 – Public Perception
Significant consideration needs to be given to management and engagement withthe public. The H21 Programme team will need to develop a robust strategy for thiskey area of work to ensure a smooth transition to hydrogen and a positive public
attitude towards such a conversion.
yy Areas to consider would include:—— How to manage information regarding physical trials;—— How to engage the media;—— How to engage the public in key areas;—— How to educate the public on hydrogen; and—— How to give confidence in the strategy.

A full stakeholder/customer engagement plan should be developed and isanticipated that an external organisation with expertise in the area would be required
to assist the process. A full review of the lessons learnt from the original town gas tonatural gas conversion should be undertaken as part of this exercise.
Evidence from the SGN Oban trials confirms the importance of this work.

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Work Package Eleven: H21 – Appliance Demonstration/Field Trials
Together with the surveys of Leeds appliances this is one of the absolutely key partsof the programme.
This needs to be carried out in conjunction with the appliance manufacturers, andin a fashion and to a timetable that is mutually beneficial. The cost of customer
conversion is estimated at about half of the total cost of the transition to hydrogen. It
is vital that in any survey the public perceives both the conversion process and new
or modified appliances as satisfactory. It is important the public perception Work
Package liaises closely with these trials as they are all likely to attract significant
media attention.
The following are suggestions based (to an extent) on the 1960s approach. It may bethat manufacturers would seek a different route, but this will need to be agreed andplanned. Particularly important must be the purchasing policy of the GDN operator.
A recent investigation for DECC of the hydrogen appliance supply chain made clear(as a societal investment) this should be managed to assist the UK to optimise its
potential in the hydrogen sector.
As soon as possible an SBGI/HHIC/Gas Industry working party should begin toconsider these complex issues. The output will require regulatory sign-off.
11.1) H21 – Appliance Proving Hub (Teesside/Other Locations, e.g. Elsmere Port)The construction of a hydrogen appliance demonstration and test facility. This will
include a range of domestic, and commercial appliances in separate booths/bays
within a high roof building. The building should also provide a bespoke testing area
for any industrial and/or other appliance nuances. A central water supply and local
control system would provide simulated DHW and CH loads to all of the boiler
products. This would provide information on real appliance performance. An obvious
location for this is Teesside, close to the existing hydrogen line, but an alternative
location could be Elsmere Port. A very large manufacturer might choose to install
their own package hydrogen plant if they felt this might increase the efficiency of
their R&D team.
A central facility at Teesside should also provide the location for a small team ofappliance experts providing the information and support which Watson House
research and development facility supplied to the original conversion process. In
addition to this facilities other product development organisations ,(such as Enertek
a Hull based gas appliance design consultancy) could also be included in the overall
appliance development process. Certification would be via existing UK NotifiedBodies, such as Kiwa Gastec/BSI.

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11.2a) H21 – Non-occupied Trials (Teesside)
As part of the trialling process and prior to undertaking the conversion in an area
occupied by customers it may be prudent to undertake a conversion of ‘real-life’unoccupied buildings. This trial should cover a range of buildings, for example, asmall row of derelict terraces and a derelict high-rise building. This is considered very
important as part of the confidence-building exercise.
The purpose of this exercise would be to undertake a conversion of these properties
then simulate the properties operating as if they were occupied for a period of two
years (two winters minimum). Appropriate monitoring devices would be in place andsecurity staff would be required. These staff could be dual purpose by being based in
the properties for their shifts utilising the hot water, heating, and cooking facilities.
The aim of this trial would be to provide confidence that hydrogen as a fuel within
existing buildings utilising existing plumbing poses no additional risks to that of
traditional natural gas. The H21 Programme Team should consider this as a key pieceof media opportunity to provide the platform to move to a live trial.
The locations of these buildings should be in both Teesside and Leeds to ensure thelocal support in the areas first to convert. The source for the supply of hydrogen willneed to be considered and will likely be by tube trailer (Leeds) or pipeline (Teesside).
Ideally, a range of trials across the full range of buildings would be ideal to ensure
a representative sample of both building type (terrace, flat, old, new, detached, etc.)
and internal pipework condition is assessed. Different trials could be undertaken indifferent parts of the country to ensure national interest and support.
b) H21 – Non-occupied Trials, Internal Pipework, and Ventilation
The purpose of this exercise would be to continue the original Hyhouse work
effectively to investigate the optimum position and size of vents where hydrogen
pipes pass through nominally unvented spaces. It would also validate pressure test
values for internal pipework. Again the work would be comparative with natural gas.
The aim of this trial would be to provide confidence that hydrogen as a fuel within
existing buildings utilising existing plumbing poses no additional risks to that of
traditional natural gas. The H21 Programme Team should consider this as a key pieceof media opportunity to provide the platform to move to a live trial.

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Section 10 | H21 Roadmap

11.3) H21 – Occupied Trials
As with the original town gas to natural gas conversion in the 1960s/70s ‘live’ trials
will need to be undertaken in areas with ‘real’ customers. Ideally, similar to theCanvey Island original trial (8,000 customers) the area should be large enough toprovide a comprehensive understanding of the process.
It may be the case, as with the original conversion, that several small ‘live’ trials are
required to slowly improve the conversion process and compile lessons learnt toensure a swift, efficient conversion when moving to a larger scale. The live trials
should as a minimum provide the following information:yy Evidence that hydrogen as the fuel for existing building stock with the buildings
operated in the normal manner poses no significant increase in risk to life
or property.
yy That conversion/replacement of old appliances can be undertaken efficiently
and safely putting into place all the work undertaken in 11.1.
yy That the network modelling of pressures and velocities within the mains
is accurate.
yy That customers are happy with the conversion and that it effectively makes nochange to their everyday lives.
yy That the network mains/services and district governor operate efficiently andsafely with 100% hydrogen.
It is worth noting that the large ‘Canvey Island’ scale trial would almost definitely
need to be near Teesside as it has large scale hydrogen availability and hydrogensalt caverns. The live trials in this H21 Roadmap do not include (cost wise) this type oflarge scale trial.
This is the type of large-scale trial which needs to be very carefully factored into
the appliance manufacturers plans. The timing needs to ensure that there is a slow
increase in demand for hydrogen appliances, to ensure lessons can be learnt in theevent of problems. A trial also needs to ensure hydrogen appliances future rollout is
not so slow and interrupted that the project loses momentum. This is going to be a
substantial challenge.
The costs and scope of the conversion of such intermediate towns should be given
immediate attention.

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Section 10 | H21 Roadmap

Work Package Twelve: H21 – Carbon Capture and Storage
12.1) H21 – Carbon Capture and Storage
Although Carbon Capture does not need to be in place for the initial commissioning
and start-up for the hydrogen economy ultimately carbon capture will be required toachieve the decarbonisation ambition of the hydrogen economy,
The H21 Programme Team should maintain close links with the CCS community
to ensure the optimised form of carbon capture is adopted, and a clear strategy ofwhen/how is in place. Specific consideration should be given to the Tees Valley
and Whiterose projects as well as a watching brief/technical support to the NIA on
carbon mineralisation being undertaken by NGN/WWU.
The H21 Programme Team should be regarding economies of scale when
considering the onset of carbon capture. For example, if a hydrogen pipeline isbeing laid from Teesside to Leeds could part or all of any carbon infrastructure becompleted at the same time? Similarly, when the SMRs and salt caverns are built andcommissioned could some, part or all the associated carbon capture infrastructure
be completed even if it is ‘hooked up’ at a later date.
It is worth noting that unlike retrofitting CCS to a power station, which in turn will
have to bid within a complex, very time sensitive competitive marketplace, the CO₂
captured from an SMR plant can be almost base load. The hydrogen storage caverns
can address most of the inter-seasonal demand. This should simplify the contractual
arrangements substantially.

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Section 10 | H21 Roadmap

Work Package Thirteen: H21 – Transportation
13.1) H21 – Transport Opportunities
The impact of an uptake in hydrogen vehicles in converted areas needs to beconsidered. The primary considerations for this piece of work are to determine
the likely scenarios for uptake of hydrogen vehicles over time and the associatedpotential demand profiles on the hydrogen grid system.
When undertaking the initial development of the SMRs and storage associated withthe hydrogen conversion a broad understanding of potential future increases indemand is required. This impact could have the ability to reduce the inter-seasonal
deviations in the supply/demand profile i.e. the grid is not just predominantly
supplying a load for heating (winter) and cooking but also all year aroundtransportation demand.
Understanding this will have significant benefits in ensuring future proofing of thehydrogen system (end to end) and will ensure an optimised detailed design isundertaken for the initial configuration of SMR/Storage.
In addition to the above understanding where likely fuelling would be required,for example, if all existing forecourts were converted to hydrogen it would allow
networks to model future demands taking into account new hydrogen-basedtransport loads. This could impact on the current REPEX strategy and may include
some upfront ‘upsizing’ of mains in areas when significant increases in transportdemand would likely cause a pressure problem on the system.
Other considerations will be given to the connections points for hydrogen connection
across the city. These are likely to be high pressure (HTS) connections and would
be the most efficient place to build fuelling stations due to the compression
requirements of hydrogen vehicles.
13.2) H21 – CNG Vehicle and Station Conversion to Hydrogen
An understanding of the ability to convert existing compressed natural gas fuelling
stations and vehicles to hydrogen should be considered. If vehicles can easily beconverted the potential uptake in hydrogen fuel could be rapid, if not it is likely to
be more time with vehicle conversion to hydrogen only taking place at the point ofvehicle replacement.
Similarly, there is a growing recognition of the benefits of CNG vehicles to support
the move towards decarbonisation in transport. It is likely that the next 5 to 10 years
will see an increase in CNG fuelling stations. Understanding how easily these stations
could be converted to hydrogen in future would be advantageous to the work in 13.1
and would enable acceleration of the uptake of hydrogen vehicles if it were possible
to convert/supplement.

312Section 10 | H21 Roadmap

Work Package Fourteen: H21 – Electrification
14.1) H21 – Power to Gas Opportunity
There are 20 ways to produce hydrogen with varying scales, costs, and efficiencies.
One of these is power to gas technology which has the significant advantage ofhelping balance the electrical energy system and reduce constrained costs. Powerto gas is the most powerful example of network integration and the potential for thistechnology to supplement a hydrogen economy, i.e. input directly into the system,
should be considered.
14.2) H21 – Localised Electrical Generation
The impact of hydrogen on electrical generation could be significant in the overall
support for decarbonisation. What is the likely impact of micro-CHP on the overall
electrical losses in the system, (i.e. offsetting electrical generation requirements
nationally) and what is the potential take-up of this technology? This project could beconsidered as part of a scope extension to 13.1 transport opportunities.
14.3) H21 – National Electrical Generation
With the potential for the onset of a hydrogen economy would it be possible
to convert existing (or build new) gas fired power stations with hydrogen as the
fuel? If so what are the costs and could there be a national strategy developed
for converting old/building new power stations off the new expanding HTS?
Understanding the future requirements for the HTS are essential for future-proofing
the initial design thereby reducing long-term costs.
14.4) H21 – Impact of Electrical Generation
As with the transportation Work Package, consideration should be given to the longterm opportunity of electrical generation and the potential impact on the supply
demand profile for the hydrogen system. Taken to its logical conclusion, this could
move the whole of the power sector from centralised to localised production. Thishas the advantage of reducing transmission and distribution losses from the power
network and avoiding their upgrade/replacement costs which are very substantial.
See Project 13.1/13.2.

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Section 10 | H21 Roadmap

Work Package Fifteen: H21 – Unconventional Gas
15.1) H21 – Unconventional Gas
As with Carbon Capture the H21 Programme Team should maintain close links withthe unconventional gas communities to ensure any synergies are maximised. For
example, many unconventional gases may (and likely will) struggle to meet GSMR
regulations. SMRs and the onset of the hydrogen economy could provide a costeffective answer to ranging gas quality as the SMR is able to accept a broad range of
non GSMR specification gas whilst providing the same quality hydrogen. Effectively
unconventional gas could be used as the feedstock for the hydrogen economy. The
environmental benefits of substantially decarbonising unconventional gas should
also be recognised.
The H21 team should consider the significant economic benefits this opportunity may
provide the UK as costly processing/enriching and/or ballasting can be avoided withsignificant savings to UK plc.
This Work Package should also consider the opportunity for repurposing parts of the
LTS as unconventional gas ‘gathering’ systems.

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Section 10 | H21 Roadmap

Work Package Sixteen: H21 – UK Wide Development Strategy
All the work in this Work Package would require support from cross industry sectors
and the UK gas industry and would be managed by the H21 Programme Team.
16.1) H21 – Storage
Storage is a complex issue when considering the supply and demand requirements
for the area of Leeds identified in the H21 Leeds City Gate original study. It becomesless complex, but more uncertain, when trying to consider the wider long-term
implications of a less dramatic fluctuating supply/demand inter-seasonal andintraday profile. This would occur with the onset of hydrogen transportation andelectrical local and national generation.
Additional to this challenge is the storage requirements for an expanding hydrogensystem i.e. as the system moves towards other cities (Bradford, Hull, Newcastle,
Manchester etc). Three key areas for storage need to be considered as part of anational rollout and future-proofing programme, these include:
The Hydrogen Transmission System (HTS). Size and pressure of the primaryhydrogen transportation system, i.e. the pipeline running from the SMRs linking thecities. A larger higher pressure pipeline will have significant linepack benefits when
expanding across the country and, although would increase the upfront costs of thefirst converted city, this would be a small amount in comparison to the potential todramatically reduce the overall system costs when considering national expansion.
Salt Cavern Storage – New vs. Existing. The UK has a significant onshore storage
problem with onshore storage of gas at circa 6% vs. European equivalents of circa
25%. This is a result of having the privilege of relatively flexible north sea gas for thelast 50 years. As the HTS expands to cover more cities nationwide more onshore
storage will be required to maintain supply/demand across the country. Developing
new onshore storage will be essential to the expansion, however, this will beessential for UK gas in the coming years with depleting north sea reserves so is not
an increase in cost associated purely with the hydrogen economy. As part of thisstudy a holistic look at storage associated with a nationwide expansion considering
new, existing and line pack opportunities whilst still maintaining natural gas storage
security (which would diminish as the hydrogen conversion grows) is critical.
Compression – understanding the compression requirements for the HTS (similar
to the current NTS) is important when considering a national rollout. Compression
needs to be considered for both storage requirements and moving the gas along
the HTS.
16.2) H21 – ‘Alternative’ Hydrogen Sources
There are 20 ways to produce hydrogen with varying scales, costs and efficiencies.
Understanding in more detail where, how and when these are appropriate could
have a benefit to the overall hydrogen economy. It is suggested that a study of allhydrogen sources in the Leeds area be considered in the first instance (including P2G(Work Package 13). Gaining this broad understanding of hydrogen production specificto a city will allow interpretation of the impact of these other sources on a national
expansion programme.

315Section 10 | H21 Roadmap

This study could allow a reduction in storage requirements and even SMR reduction
and associated carbon capture if local production could support intraday and evenpart of inter-seasonal demand. This study would also identify areas of system
integration between the electric and gas networks.
The ways to produce hydrogen (known to the author) are provided in Table
10.4 below.
MethodName

1Electrolysis

2

Plasma arc Decomposition

3

Thermolysis

4

Thermochemical Water Splitting

5

Biomass Conversion

6

Biomass Gasification

7

Biomass Reforming

8

PV Electrolysis

9

Photocatalysis

10

Photoelectrochemical method

11

Dark Fermentation

12

High Temperature electrolysis

13

Hybrid Thermochemical Cycles

14

Coal Gasification

15

Fossil Fuel Reforming

16

Bio photolysis

17

Photofermentation

18

Artificial Photosynthesis

19

Photoelectrolysis

Table 10.4. Methods of Hydrogen Production

316Section 10 | H21 Roadmap

16.3) H21 – UK Wide Hydrogen Expansion
As with storage (16.1) when considering the UK-wide rollout of hydrogen conversion
a detailed analysis needs to be undertaken. This is critical to understanding storage
requirements and allowing a timeline with associated costs to be developed. Areas
this study should consider are:Demand profiles for cities to convert – this information would be supplied in thesame manner as that obtained for H21 Leeds City Gate and would require extensive
support from all the UK gas networks.
Natural Gas Vs. Hydrogen infrastructure – A holistic view needs to be provided
considering which cities to convert and when, which areas to leave on natural gas
and which parts of the current natural gas system may become redundant.
Potential opportunities for repurposing any redundant parts of the existing gas
system as expansion of the HTS is undertaken. For example, this could provide feedpipelines for unconventional gas or even carbon capture pipelines for new SMRs
required across the system.
16.4) H21 – UK Wide Rollout Estimate
As part of the overall national expansion, a detailed strategy would be developed forthe rollout of a hydrogen conversion which would need to be timelined and costs
estimated as a minimum up to 2050, for an example see H21 Vision.
16.5) H21 – Detailed Design, H21 Leeds City Gate
As part of the overall rollout, a detailed design needs to be undertaken for the entire
system associated with the first cities to convert i.e. Leeds, Teesside, and Hull. This
will include the end to end system comprising the SMRs, HTS, associated pressure
reduction stations, compression, and storage. This detailed design would allow
costs to be understood for the first conversions likely in the in the mid-2020s. It is
recommended that this is undertaken as a matter of priority to give confidence in theoverall scheme and should be started no later than 2018 (see Section 9, The Next
Steps – Programme of Works).

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Section 10 | H21 Roadmap

16.6) H21 – Rollout Strategy
When considering the lessons of the past, it becomes clear that a well-defined
strategy for when/how rollout will occur is critical. As part of this strategy, thefollowing should be considered:yy When and how to engage the wider supply chain and how to effectively procure
goods, (e.g. appliance conversion kits) from often sole suppliers. Consideration
should be given to the ‘cost yardstick’ approach adopted in the town
gas conversion.
yy When/where and how to train the extensive workforce required forthe conversion.
yy When to engage the UK gas industry networks to ensure they submit works aspart of their RIIO-GD2 business plans. This would require OFGEM engagement
and would be critical to NGN as the initial network and the NTS as the likely
source point for the SMR gas feedstock. Other networks would still need toconsider the impact on their REPEX strategy for where their cities are on theconversion timeline.

318Section 10 | H21 Roadmap

10.3. Work Package Summary
Image 10.11 provides an overview of the Work Packages and their key focus area.
Strategic
Work Packages

16

1

Technical
Work Package

2
3

15

4

14
0 - H21
Programme
x
Team

13

5

12

6
11

7
10

Physical
Trials98Social/Regulatory
Work Packages

Image 10.11. H21 Roadmap – Work Package Overview

10.3.1. Concluding Remarks
A work programme of this scale requires commitment, high levels of expertise anda dedicated team to develop, drive and coordinate the results. Of all the projects
identified within this roadmap, there are none that, on face value, are unachievable toallow a hydrogen conversion to take place in the UK.
The most critical element of this roadmap is a financial commitment to undertaking
the Work Packages and, crucially, the establishment of the H21 Programme Team.
Without a dedicated team in place, the roadmap delivery will be delayed orinadequately executed. This will result in delays in the ability to commit to a UK widehydrogen conversion programme in line with the climate change act targets.

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SECTION 11

H21 Vision

Section 11 | H21 Rollout Vision

11. The H21 Rollout VisionThis section has been provided to help articulate the potential which could be
generated by the establishment of the world’s first hydrogen economy. Additionally
how an incremental rollout of such an economy, i.e. city by city/region by region
conversion, in the UK could be achieved. It has been provided for illustrative
purposes only and whilst figures have been given against documented
assumptions it is recognised that this is a crude extrapolation. However it should
provide an indication of the correct ‘order of magnitude’ of at least two approaches toa hydrogen conversion programme.
Providing vision pieces like this can easily be criticised and alternative notions/recommendations/assumptions put forward. That’s fine! But if nothing else thissection should be considered a starting point for where thought may need to beconsidered to move the principle of H21 forwards.

Summary of H21 Leeds City Gate
The H21 Leeds City Gate project provides strong evidence that conversion of a large,
complex UK city to hydrogen should technically be possible. However, it is unlikelythat such a strategy would be adopted for a single city as this would not meet the
decarbonisation challenge of the Climate Change Act.
This section aims to provide an overview of how an incremental rollout of a hydrogendecarbonisation strategy could proceed. This incorporates decarbonisation ofheat and the inevitable transition towards decarbonisation of transport, electricity
generation and new industrial opportunities that would occur as a consequence of
having large scale decarbonised hydrogen availability at point of use.

11.1. Incremental Hydrogen Economy
Rollout
To provide an idea of what a UK incremental hydrogen rollout may look like two
options have been presented. Option one is based around a rollout across major UK
cities, Option 2 is regionally constrained to NGN customers. Costs for option one
have been provided as part of a regulatory business plan finance model Section 9,
The Next Steps – Programme of Works. Overall capital costs for option two havebeen provided.

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Section 11 | H21 Rollout Vision

11.1.1. Option One, City-by-City
One significant advantage of the H21 project is that roll out across the UK can bedone incrementally. In order to future proof the initial design, i.e. the Leeds conversion
and associated hydrogen supply infrastructure, a clear idea of what the UK rollout
strategy may be is required. For example, if the ambition is to decarbonise all major
cities in the UK with hydrogen the initial HTS pipeline between Teesside and Leeds
would need to be ‘sized’ (a large enough pipe) in order to meet this future expansion.
This would also take into account the future location and growth of additional SMRs
and storage capacity. This would require associated connections and infrastructure
to be in place (or clearly provisioned) so retrospective major modifications to the HTS
are not required.
To provide some clarity on what a rollout strategy could look like an example has
been provided pictorially below. It should be noted that a better and more detailedroll out strategy would be developed as part of the Section 10, H21 Roadmap (WorkPackage 16) and would likely be based on cost and carbon saving parameters. Image
11.1 is for illustrative purposes only.
SMR/CCS Centres
HTS
Aberdeen (2042/45)
Glasgow(2039/42)

Edinburgh (2036/39)
Newcastle (2032/35)
Teesside (2029/32)
Leeds (2026/29)

Manchester (2032/35)

Hull (2029/32)
Sheﬃeld (2035/38)
Leicester(2045/48)

Liverpool (2035/38)

Birmingham (2039/42)

Luton(2045/48)
London(2048/52)

Cardiﬀ (2042/45)
Bristol (2042/45)
Oxford (2045/48)
Image 11.1. H21 Rollout – Large City by City and HTS

322

Section 11 | H21 Rollout VisionThis option is based on a future rollout strategy with the main objective being
to convert major cities, providing big carbon benefits in a relatively short time
whilst ensuring broad UK coverage to encourage wider benefits (transportation/
electrification). As the hydrogen economy grows it would be possible to convert any
smaller cities/towns along the HTS route corridor. Indeed a significant advantage ofthe hydrogen economy is it could accelerate or deccelerate dependent on external
factors. For example, alternative sources of hydrogen, finance/actual costs. Image
11.1 is an indication of a strategy involving key cities covering about 30% of gas users.
It should be noted that all other areas in this scenario could remain on a natural gas/
biogas mix. Importantly, the existing high pressure natural gas network can remain inplace for large industrial users such as power stations.

323

Section 11 | H21 Rollout Vision

Scaling Hydrogen Production and Storage Facilities
As part of any rollout strategy as well as ‘where to convert’ we also need to consider
scaling the hydrogen production facilities (SMRs/Storage) and associated CCS
infrastructure. As the hydrogen economy expands so does the requirement for
additional production and storage. Image 11.2 provides an overview of how thisexpansion could occur for a city by city rollout strategy.

SMRs late
2030/40s

UK CCS
potential
Principal anchor areafor inter-seasonal
storage requirements(deep salt)
SMRs early
2020s

UK CCS
potential

SMRs early
to mid-2030s

UK CCS
potential

SMRs late
2020/30s

Additionalsalt storageas required

Triassic saltﬁelds

Permian saltﬁelds

Image 11.2. Hydrogen Production and CCS Expansion Over TimeAs the hydrogen economy grows the requirement for more hydrogen production
infrastructure increases proportionately. Whilst this is significant it needs to be put
into perspective and also re-iterated that this expansion would be over a long periodof time, up to 40 years.

324

Section 11 | H21 Rollout Vision

For illustrative purposes, Image 11.3, shows a significant increase in SMR production
at the Teesside SMR and CCS location (one of the four – Teesside, Hull , Liverpool
and Peterhead shown in Image 11.2). SMRs have been shown in addition to theexisting facility. The configuration for such an extensive increase in hydrogenproduction, in reality, is likely to be a combination of larger and smaller plants
taking advantage of economies of scale, increased efficiencies, space optimisationand operability to meet growing demand. Additionally this would be coupled withconsiderations for increased linepack within the expanding HTS and intraday/interseasonal storage as well as alternative sources of bulk hydrogen production (suchas gasifiers).

Existinghydrogensalt caverns

SMRs required for
Leeds demand.
Illustrative only.

Image 11.3. Increasing Hydrogen Production Capability at Teesside

If such an expansion were to take place the impact on GVA in the local area for all the
SMR/CCS centres would be dramatic.

325

Section 11 | H21 Rollout Vision

Increasing Intraday/Inter-seasonal Storage Facilities
One of the biggest challenges for decarbonising heat is being able to manage thesignificant intraday and inter-seasonal variations in demand profile. Whilst this has
been determined for the area of conversion in the H21 Leeds City Gate project theoptions when undertaking a UK wide rollout need serious consideration to allow the
optimised solution to be developed.
Storage of hydrogen is not a new concept or one which needs technical evidence.
However as the hydrogen economy grows consideration of the type and sizeof storage that will be required needs to at least be conceptually developed inconjunction with the roll out strategy. We can assume with high levels of engineering
confidence that there are effectively three deployed storage technologies applicableto hydrogen.
yy Storage of gaseous hydrogen in pressurised containers (or linepack in pipelines).
yy Storage of liquid hydrogen in refrigerated containers.
yy Storage of gaseous hydrogen in underground formations (salt caverns and/or
depleted hydrocarbon fields).
There are other technologies being considered but at readiness levels well below
the established techniques or for low storage volume applications such as metal
hydride technology.

Inter-seasonal Storage
1. Salt Cavern Inter-seasonal Storage could be managed by incrementally
increasing the caverns in the deep salt deposits in the Humber area on the
Northeast coast. These are the deepest salt deposits in the UK and therefore
represent the best opportunity for large scale storage.
2. Depleted Gas Field Storage whilst needing some more evidence that thereis the potential to re-use existing hydrocarbon and natural gas storage sites
for hydrogen storage if required. Indeed there is already a published paper
considering the re-use of depleted gas storage fields in the International Journalof Hydrogen Energy ‘Seasonal storage of hydrogen in depleted gas fields’ whichstates ‘There appears to be no insurmountable technical barrier to the storage ofhydrogen in a depleted gas reservoir’.
3. Cryogenic (Liquid) Storage is likely to play a part in the overall system as thehydrogen conversion moves north and south within the country. Cryogenic
storage offers significant opportunities for large scale storage as it is able toprovide up to 600 times the storage by volume capacity of the equivalent
ressurised storage options. It does however have the disadvantage currently of
costs and efficiency losses some of which are thermodynamically unavoidable.
The onset of cryogenic storage could be heavily impacted by hydrogen supply
methods as the hydrogen economy expands (see Section 11.3).

326

Section 11 | H21 Rollout Vision

Intraday StorageIntraday storage can be managed in a variety of ways as the hydrogen economy
expands. Indeed the expansion makes the requirement to manage this demandswing significantly simpler than for a single city. An expanding HTS will provide
large amounts of additional linepack potential that can be used to manage intraday
storage, as is currently undertaken today in the UK gas industry.
Additionally this may be supplemented by salt cavern storage both at Teesside andacross the salt deposits that run down the west side of the country as well as somelocalised high pressure storage near cities.

327

Section 11 | H21 Rollout Vision

Regulatory Finance Model (Option 1)
Whilst NGN have provided a detailed regulatory finance appraisal for the H21 Leeds
City Gate conversion an indicative appraisal has been undertaken for the Option 1 UK
wide rollout scenario.
In order to undertake this analysis the following assumptions have been made. It is
accepted that this is a somewhat crude methodology and will have some errors but
in terms of presenting an ‘order of magnitude’ representation of an incremental rollout it is considered reasonable.
It is also worth considering that these costs are entirely associated with thehydrogen rollout but do not consider:yy Impact on GVA.
yy Impact of smoothing out natural gas demand for the UK which could remove
higher winter costs, i.e. a relatively flat demand as hydrogen production still
occurs in summer.
yy Offset costs for alternative decarbonisation strategies, for example:—— Large costly district heat schemes in cities due for conversion would no longer berequired.
—— Electrical generation system requirements associated with decarbonising heat will
no longer be required.
—— Decommissioning costs and financial compensations associated with the ‘turningoff’ of the gas network will not be required.

328

Costs have been extrapolated as per Table 11.1 presented below.
TIMELINE

329

APPLIANCE CONVERSIONHYDROGENPRODUCTION

HYDROGEN TRANSMISSION SYSTEMHYDROGEN STORAGE

Year
FinishPopulation
guestimate(In area
to convert
in millions)

Proportionalvariationfrom Leeds

Carboncapture using
proportionalvariation
mtcarbon year

Appliance
conversion(£m)

Appliance
conversion
efficiency
factor

Appliance
conversion
costs
(£m)

HTS
approximate
length (miles)

Adjusted
HTS
Costs

Additional
Compression

HTS
Costs
(£m)

SMR
Plant

Salt
Caverns

Adjustment
for alternative
sources/
intradaylinepackwith HTSStorage
Costs
(£m)

Total
(£m)

Leeds

2026

2029

0.66

1.00

1.50

1,053

1.00

1,053

120

230

0

230

395

366

1

366

2,044

Teesside (Greater
Area)

2029

2032

0.56

0.85

1.28

895

1.00

895

0

0

0

0

336

311

1

311

1,542

Kingston Upon
Hull (City)

2029

2032

0.26

0.39

0.59

411

0.90

370

0

0

0

0

154

143

1

143

666

Newcastle(Greater Area)

2032

2035

1.12

1.69

2.54

1,780

0.90

1,602

55

105

30

135

668

618

1

618

3,023

Manchester(Greater Area)

2032

2035

2.41

3.65

5.48

3,843

0.81

3,113

45

86

30

116

1,442

1,335

0.95

1,268

5,939

Sheffield (City)

2035

2038

0.56

0.85

1.28

895

0.73

652

25

48

0

48

336

311

0.95

295

1,331

Liverpool (Greater
Area)

2035

2038

1.71

2.59

3.89

2,727

0.73

1,988

35

67

0

67

1,023

947

0.95

900

3,978

Edinburgh (City)

2036

2039

0.49

0.75

1.13

790

0.73

576

120

230

30

260

296

274

0.95

261

1,393

Glasgow (Greater
Area)

2039

2042

1.14

1.73

2.60

1,822

0.73

1,328

46

88

0

88

683

633

0.95

601

2,701

Birmingham(greater Area)

2039

2042

2.81

4.25

6.38

4,475

0.66

2,936

70

134

30

164

1,679

1,554

0.9

1,399

6,178

Bristol (City)

2042

2045

0.44

0.67

1.01

706

0.66

463

100

192

30

222

265

245

0.9

221

1,170

Cardiff (City)

2042

2045

0.35

0.54

0.81

569

0.66

373

40

77

0

77

213

197

0.9

178

841

Aberdeen (City)

2042

2045

0.23

0.35

0.53

369

0.66

242

145

278

30

308

138

128

0.85

109

797

Leicester (City)

2045

2048

0.34

0.51

0.77

537

0.66

352

44

84

0

84

201

187

0.85

159

797

Luton (City)

2045

2048

0.21

0.32

0.48

337

0.66

221

70

134

30

164

126

117

0.85

99

611

Oxford (City)

2045

2048

0.16

0.24

0.36

253

0.66

166

80

153

0

153

95

88

0.85

75

489

London (Greater
Area)

2045

2052

8.54

12.91

19.37

13,594

0.59

8,027

20

38

0

38

5,099

4,721

0.85

4,013

17,1782,155

13,15011,01350,676

Totals

22.00

Table 11.1. CAPEX Costs per City

24,357

Section 11 | H21 Rollout Vision

City

Year
Start

Section 11 | H21 Rollout Vision

CAPEX costs per city have been calculated by adding appropriate factors in
two areas:yy The population size of each city against the population covered by the area of
conversion in H21 Leeds City Gate.
yy A range of increased efficiency factors against appliance conversion and storageas identified in the table.
yy Costs associated with storage are based on salt caverns but could significantly
reduce if repurposing of existing gas storage facilities (such as Rough) could
be undertaken.
yy No account has been taken of the offset in capital costs from alternative sourcesof hydrogen e.g. by-product, electrolysis, liquid hydrogen, gasification.
yy No account has been taken of reducing SMR costs through economies of scale.

330

TIMELINE

CARBON CAPTURE (MT CARBON/YEAR)

City

331

SMR/SALT CAVERNS

Year
FinishPopulation
guestimate(In area
to convert
in millions)

Proportionalvariationfrom Leeds

Carbon capture using
proportional variation
mtcarbon year

CO₂ £ per tonne
per city

Sequestration
ChargeCumulative Annual
CO₂ Cost(£m)

Maintenance
SMR/Salt Caverns
efficiency
adjustment

AnnualMaintenance
Costs per City

Cumulative
MaintenanceCosts(£m) per annum

Total

Leeds

2026

2029

0.66

1.00

1.50

40

60

4

31

31

139

Teesside (Greater
Area)

2029

2032

0.56

0.85

1.28

40

111

4

26

57

257

Kingston Upon Hull
(City)

2029

2032

0.26

0.39

0.59

30

129

4

12

69

305

Newcastle (Greater
Area)

2032

2035

1.12

1.69

2.54

20

179

4

51

120

488

Manchester(Greater Area)

2032

2035

2.41

3.65

5.48

15

261

3

81

201

827

Sheffield (City)

2035

2038

0.56

0.85

1.28

14

279

3

19

220

904

Liverpool (Greater
Area)

2035

2038

1.71

2.59

3.89

13

330

3

58

278

1,137

Edinburgh (City)

2036

2039

0.49

0.75

1.13

12

343

3

17

295

1,203

Glasgow (Greater
Area)

2039

2042

1.14

1.73

2.60

12

374

2

26

320

1,343

Birmingham (greater
Area)

2039

2042

2.81

4.25

6.38

12

451

2

62

382

1,685

Bristol (City)

2042

2045

0.44

0.67

1.01

11

462

2

10

392

1,738

Cardiff (City)

2042

2045

0.35

0.54

0.81

11

471

2

8

400

1,780

Aberdeen (City)

2042

2045

0.23

0.35

0.53

11

477

1.5

4

403

1,807

Leicester (City)

2045

2048

0.34

0.51

0.77

11

485

1.5

5

409

1,845

Luton (City)

2045

2048

0.21

0.32

0.48

11

490

1.5

3

412

1,869

Oxford (City)

2045

2048

0.16

0.24

0.36

11

494

1.5

3

415

1,887

London (Greater
Area)

2045

2052

8.54

12.91

19.37

10

688

1

91

506

2,792

4,909

22,004

TotalsTable 11.2. OPEX Costs per City

22.00

6,084

Section 11 | H21 Rollout Vision

Year
Start

Section 11 | H21 Rollout Vision

As with CAPEX costs OPEX costs per city have been calculated by adding
appropriate factors in two areas:yy The population size of each city against the population covered by the area of
conversion in H21 Leeds City Gate.
yy A range of increased efficiency factors associated with economies of scale in
OPEX areas.
No account has been taken of the offset in operational costs from alternative sourcesof hydrogen, e.g. by-product, electrolysis, liquid hydrogen, gasification.

332

Section 11 | H21 Rollout Vision

Table 11.3 shows the rollout profile and the associated CAPEX/OPEX costs of
converting each city. In total the CAPEX investment needed is £26 bn and the OPEX
conversion expenditure is £24 bn, with annual OPEX costs thereafter of circa £2.8 bn
per year.
CAPEX

OPEX

Conversion
Years

Labour &Appliances
OPEX
Costs
(£m)

Annual
OPEX
Costs
(£m)

991

26-28

1,053

138

26-28

647

29-31

895

117

Kingston Upon Hull

26-28

297

29-31

370

48

Newcastle

29-31

1,421

32-34

1,602

183

Manchester

29-31

2,826

32-34

3,113

337

Sheffield

32-34

679

35-37

652

77

Liverpool

32-34

1,990

35-37

1,988

231

Edinburgh

33-35

817

36-38

576

66

Glasgow

36-38

1,373

39-41

1,328

139

Birmingham

36-38

3,242

39-41

2,936

340

Bristol

39-41

707

42-44

463

53

Cardiff

39-41

468

42-44

373

42

Aberdeen

39-41

555

42-44

242

27

Leicester

42-44

444

45-47

352

38

Luton

42-44

390

45-47

221

24

Oxford

42-44

323

45-47

166

18

London

42-44

9,151

49-51

8,027

899

24,357

2,779

Years

Total
CAPEX
Investment
(£m)

Leeds

20-25

Teesside

Illustrative
Rollout Profiles
16/17 Prices

Total

26,318

Table 11.3. Illustrative Rollout Profile 2016/17 Prices

333Section 11 | H21 Rollout Vision

The following analysis highlights what the above expenditure means to customer
bills, under both of the options previously presented.
As with the financial modelling of H21 Leeds City Gate two regulatory financemodels have been presented under two options – Option 1 being under the current
regulatory fast/slow methodology and Option 2 treating the conversion OPEX costs
all as slow money. This is followed by a holistic view of the actual impact in thecustomers bill.

Option 1: Using the Current Fast/Slow Money Logic
Chart 11.1 shows the revenues as a result of converting each city. This follows asimilar profile as shown in Section 8, Finance and Regulation, with a large spike inrevenues needed initially to fund the appliance and labour costs with ongoingrevenue streams after for annual OPEX costs.

Chart 11.1. Option 1 Hydrogen Revenue Allowances – Rollout Illustration

334

Section 11 | H21 Rollout Vision

yy With the exception on converting London revenue allowances under thismethodology would peak at £3.2 bn in regulatory Year 2039/40. Every time acity is converted there is the initial spike for conversion costs then followed
by on-going OPEX maintenance costs and CAPEX monies returned over a
45 year period.
yy The impact on customer bills follows a similar trend with the above monies being
spread across all UK users and added on top of the current scenario as shown inChart 11.2.
yy The REPEX programme is completed by 2032, but there isn’t an immediate dropas the costs are funded over a 45 year period. As in Chart 11.2 there is a gradualdrop in bills from 2033, but this isn’t enough to offset the hydrogen programme if
the rollout was funded in this way. It should be noted that these costs are only forthe transportational element of the bill.

Customer Bill - Rollout Illustration
330£ (15/16 Prices)280

0. Current Scenario

5. Edinburgh

1. Leeds

6. Glasgow & Birmingham

2. Teesside & Kingston

7. Bristol, Cardiﬀ & Aberdeen

3. Newcastle & Manchester

8. Leicester, Luton & Oxford

4. Sheﬃeld & Liverpool

9. London

230

180

80

13/14
14/15
15/16
16/17
17/18
18/19
19/20
20/21
21/22
22/23
23/24
24/25
25/26
26/27
27/28
28/29
29/30
30/31
31/32
32/33
33/34
34/35
35/36
36/37
37/38
38/39
39/40
40/41
41/42
42/43
43/44
44/45
45/46
46/47
47/48
48/49
49/50
50/51
51/52
52/53

130

Year

Chart 11.2. Option 1 Customer Bill – Rollout Illustration

335

Section 11 | H21 Rollout Vision

Option 2: An Alternative Option to Potentially Reduce the Spike in Bills
As described in Section 8, Finance and Regulation an alternative method could be
used to fund the large scale implementation costs as slow money returned to GDNs
over a 45 year period. The main differences with this approach is that it pushes
income into the future rather than an initial spike. As stated in Section 8, Finance andRegulation this in an illustration only and much wider factors around network
financeability would need to be considered.

4,000

Hydrogen Revenue Allowances - Rollout Illustration

3,000
1. Leeds
2,500

2. Teesside & Kingston
3. Newcastle & Manchester

2,000
1,500
1,000
500

-

4. Sheﬃeld & Liverpool
5. Edinburgh
6. Glasgow & Birmingham
7. Bristol, Cardiﬀ & Aberdeen
8. Leicester, Luton & Oxford
9. London

13/14
14/15
15/16
16/17
17/18
18/19
19/20
20/21
21/22
22/23
23/24
24/25
25/26
26/27
27/28
28/29
29/30
30/31
31/32
32/33
33/34
34/35
35/36
36/37
37/38
38/39
39/40
40/41
41/42
42/43
43/44
44/45
45/46
46/47
47/48
48/49
49/50
50/51
51/52
52/53

£m Revenue (15/16 Prices)

3,500

Year

Chart 11.3. Option 2 Hydrogen Revenue Allowances – Rollout Illustration

yy With a large scale rollout programme there is still a significant impact on
customer bills if funded in either mechanism. Even under Option 2 in the peakyears the GDN element of a customer bill would increase by circa £153 as shown
below (excluding London period).

336

Section 11 | H21 Rollout Vision

Customer Bill - Rollout Illustration£ (15/16 Prices)

280

230

0. Current Scenario

5. Edinburgh

1. Leeds

6. Glasgow & Birmingham

2. Teesside & Kingston

7. Bristol, Cardiﬀ & Aberdeen

3. Newcastle & Manchester

8. Leicester, Luton & Oxford

4. Sheﬃeld & Liverpool

9. London

180

80

13/14
14/15
15/16
16/17
17/18
18/19
19/20
20/21
21/22
22/23
23/24
24/25
25/26
26/27
27/28
28/29
29/30
30/31
31/32
32/33
33/34
34/35
35/36
36/37
37/38
38/39
39/40
40/41
41/42
42/43
43/44
44/45
45/46
46/47
47/48
48/49
49/50
50/51
51/52
52/53

130

Year

Chart 11.4. Option 2 Customer Bill (Transportation Element Only) – Rollout Illustration

The difference in customer bills between the two options is shown below(transportational part of bill only):

GDN Customer BillDiﬀerence Between Options 1 and 2
400
Option 1(£) 15/16 Prices

350

Option 2

300
250
200
150
100

13/14

16/17

19/20

22/23

25/26 28/29

31/32

34/35

37/38

Year

Chart 11.5. GDN Element of Customer Bill – Difference Between Options

337

40/41

43/44

46/47 49/50

52/53

Section 11 | H21 Rollout Vision

Impact with Long Term Efficiency Savings on the Total Customer
Gas Bill
The analysis shows the increase in the GDN expenditure needed as a result ofhydrogen implementation; it does not take into account any changes in other areas of
the total customer bill.
To demonstrate this percentage efficiency savings in the overall bill have been
projected against the increase in regulatory expenditure to provide a view of net
impact over time. As in Section 8, Finance and Regulation the efficiency savings
have been assumed as follows.

Savingfrom current

2016-30

2030-35

2035-40

2040-452045-50

2050+

0.00%

3.00%

6.00%

9.00%

12.00%

15.00%

Table 11.4. Energy Efficiency Savings Over Time

(Currently gas bills are circa £750 per annum).
Total Customer Gas Bill

1,000

£m (15/16 Prices)

800

600

400

Total Customer Gas Bill (15/16 Prices)
Including GDN Reduction and Eﬃciency Savings
Leeds Hydrogen - Option 1 - Costs Socialised (UK)-

Leeds Hydrogen - Option 2 - Costs Socialised (UK)

13/14
14/15
15/16
16/17
17/18
18/19
19/20
20/21
21/22
22/23
23/24
24/25
25/26
26/27
27/28
28/29
29/30
30/31
31/32
32/33
33/34
34/35
35/36
36/37
37/38
38/39
39/40
40/41
41/42
42/43
43/44
44/45
45/46
46/47
47/48
48/49
49/50
50/51
51/52
52/53

200

Year

Chart 11.6. Total Customer Gas Bill

338

Section 11 | H21 Rollout Vision

RIIOGD1

RIIOGD2

RIIOGD3

RIIOGD4

RIIOGD5

Total gas bill (as per section 2*) (£)

750

749

713

665

611

Revised total gas bill – Option 1 (£)

750

761

800

788

779

Change %

0.0%

1.5%

12.1%

18.4%

27.5%

Hydrogen rollout bill impact Option 2 (£)

-

6

59

126

167

Revised total gas bill – Option 2 (£)

750

756

773

792

778

Change %

0.0%

0.9%

8.3%

19.0%

27.3%

(15/16 prices)

Table 11.5. Total Gas Bill

Section 2 total gas bill shows customer bill inclusive of both GDN savings
yy After including efficiencies in the total customer bill and a full scale hydrogen
rollout customer bills would increase over the 30 year period by circa 15% inOption 1 and circa 14% under Option 2.
yy The peak year under Option 1 is 49/50 @at £855 per annum and under Option 2
is 43/44 @ at £806 per annum.
yy It is worth noting that whilst Option 2 will remove any initial spikes, it is pushing
more income and charges for the customer into later years.
yy The % reduction applied in the non-distribution element of the customer bill
is a key part of this analysis and is a large factor in mitigating the impact of ahydrogen rollout.

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Section 11 | H21 Rollout Vision

Key Messages:
yy With a large scale rollout programme there is a significant impact in the GDN
element of customer bills over the longer term under either of the options in linewith the current regulatory funding framework. Option 1 has an initial spike on
implementation whilst Option 2 has a gradual increase over time.
yy To implement a large scale rollout programme there would need to be a full
review of alternate funding mechanisms to minimise the customer bill impact
whilst also considering networks financeability issues.
yy However this analysis excludes any other impacts customers will be facing overthe longer term – i.e. if we ‘do nothing’ how much additional cost will customers
be facing vs. the hydrogen costs above, i.e. air quality penalties passed on to all
UK customers, electrification of heat etc.
yy The total customer bill when applying an assumed efficiency saving showslevels circa 15% above current levels when a UK hydrogen rollout programme iscompleted. A 3% saving is assumed from 2030 growing to a 15% saving by 2050
due to energy efficiency measures which helps partially offset the GDN hydrogenbill increase.

340Section 11 | H21 Rollout Vision

11.1.2. Option 2 – Regional Rollout
This second is less ambitious and is based on a conversion of 90% of the 2.6 million
customers within NGN.

Image 11.4. UK Gas Distribution Networks

This could include conversion of most of Berwick on Tweed, Rothbury, Carlisle,
Whitehaven, Haltwhistle, Sunderland, Morpeth, Newcastle, Gateshead,
Durham, South Shields, Darlington, Hartlepool, Middlesbrough, Harrogate, York,
Bradford, Leeds, Halifax, Ripon, Hull, Goole, Wakefield, Barnsley, Hebden Bridge
and Todmorden.
This area contains approximately 6 million people, i.e. roughly the population of
Denmark or Finland. It therefore offers a technology suitable for worldwide roleout. Conversion of local transport to hydrogen would reduce the cost per kWh ofhydrogen delivered. Assuming that the SMR reactors were placed at Teesside, thencarbon dioxide to CCS would be about 13 million tonnes/year. This is projected to be
sufficient volume to reduce the cost of CO₂ disposal to £10/tonne.

341Section 11 | H21 Rollout Vision

Scaling Hydrogen Production and Storage Facilities
As part of a regional rollout strategy we also need to consider the hydrogenproduction facilities (SMRs/Storage) and associated CCS infrastructure. As thehydrogen economy expands so does the requirement for additional storage andproduction. For a regional approach like this it is likely that the hydrogen production
facilities identified in Image 11.2 would only occur at Teesside and the Humber
area as the hydrogen economy in this scenario would not reach the Liverpool andPeterhead CCS/industrial centres.

Scaling Intraday/Inter-seasonal Storage Facilities
As with Option 1 the storage requirements for both intraday and inter-seasonal
demand would likely be a combination of available storage technologies but
anchored with the original salt cavern concept. If re-purposing of the Rough natural
gas storage facility to hydrogen could be undertaken and/or use of various depletedhydrocarbon storage sites in the area could be developed this could significantly
decrease the costs.

342

Section 11 | H21 Rollout Vision

Capital Costs (Option 2)
Simple extrapolation from the H21 Leeds City Gate model (about 260,000
connections) would indicate a capital investment of the following;yy Total number of NGN customers = circa 2,600,000
yy Converting 90% of those customers = 2,340,000

Conversion of Appliancesyy H21 Leeds City Gate costs for conversion of appliances = £1,053 m (for
260,000 connections)yy Therefore 2,600,000 connections = 10,530 m @ 90% = £9,048 m

Hydrogen Infrastructure (SMRs/Salt caverns/HTS)yy H21 Leeds City gate costs for conversion of appliances = £1,000 m (for
260,000 connections)yy Therefore 2,600,000 connections = 10,000m @ 90% = £9,000 m

Total costs for Option 2
Item

Cost (£)

Appliance conversion 90% all NGN customers£9,048,000,000

Hydrogen infrastructure£9,000,000,000
Total£18,048,000,000

Table 11.6. Total Capital Costs Regional Rollout

Note, these figures take no account of economies of scale, alternative storage etc.
By comparison this investment is very similar to the Hinckley C nuclear power station,
but provides full ‘well to sofa’ conversion. The nuclear power station option excludes
the cost of any inter-seasonal storage, power transmission/distribution infrastructureor the conversion of homes and industry to electric heating. Preliminary design works
could be started in 2018 and conversion finished by the mid 2030s.

343Section 11 | H21 Rollout Vision

11.1.3. Hydrogen Economy Rollout, Additional
Considerations
When designing a rollout strategy like this the following additional considerations
would need to be resolved:
yy What high pressure industrial users, currently connected to the high pressure(above 7 bar) natural gas network, could be converted to hydrogen along the
HTS route corridor. Or, should these users be retained on the natural gas local
transmission system until their operation is due for upgrade as part of a normal
plant lifecycle costs.
yy Should the major cities rollout, option one, have provision for parallel conversion
of smaller cities and towns. For example at the same time as converting
Sheffield/Liverpool also retrospectively start converting Wakefield/Dewsbury
etc. in the West Yorkshire area. This could support maintaining local conversion
work force levels whilst also allowing national coverage as quickly as possible.
yy Should a strategy focus on major cities (Option 1) or major urban centres (Option2) or both? For example all of West Yorkshire (Leeds/Bradford/Wakefield/
Dewsbury/Huddersfield/Castleford/Halifax etc.), then all of the North West,(Manchester/Stockport/Rochdale/Bolton/Wigan/Blackburn/Preston etc.).
This may reduce overall costs for conversion as the work is focused in strategicareas. It could also significantly delay reaching the two largest cities, Birmingham
and London, due to resources availability and practical considerations for UK
pipelining and SMR/storage design and build timelines.
yy Should a conversion strategy consider the installation of Micro-CHP units whereappropriate as part of a ‘part/contributory funded’ option for customers? This
could rapidly accelerate the uptake of this technology whilst providing a real
economic benefit to customers in converted areas. It would also accelerate thewider decarbonisation of electricity through offsetting generation requirements
and removing the 7% network losses.
yy Could the HTS be designed and built as quickly as possible down to London
along the route identified in Image 11.1. This may allow accelerated connectionof hydrogen refuelling stations and therefore the onset of hydrogen vehicles.
Effectively this would mean building all the hydrogen transmission network firstalongside a slower city by city conversion programme. This option may not beseen as appropriate as it may not provide a no regrets incremental rollout. If, inthe unlikely event the conversion was halted half way down the country, the HTS
could be significantly oversized and underutilised.
yy Having a much larger HTS designed for future expansion could significantly
offset the requirement for intraday storage as linepack availability becomes
more viable.

344

Section 11 | H21 Rollout Vision

There are of course many variations of how a rollout strategy could be establishedand this needs significant consideration guided by practical industry involvement
over the next few years.
The above considerations are very much gas industry lead, but it may well beappropriate to consider the implications of availability of CCS. The assumption of thisreport has very much been that CO₂ sequestration is available ‘over the fence’ as
and when required. A recent report by the ETI (Progressing Development of the UK’s
Strategic Carbon Dioxide Storage Resource a Summary of Results from the Strategic
UK CO₂ Storage Appraisal Project April 2016) highlights that between 3 and 5 million
tonnes per year of CO₂ is required for cost effective disposal at between about £11and £17/tonne. Leeds will produce about 1.5 million tonnes of CO₂/year, so ideally theplanned conversion soon after of Newcastle or Sheffield would reach this number
which really starts to offer the economies of scale. SMR from natural gas with thesubsequent storage of hydrogen can provide an advantageously constant level ofCO₂ for disposal.
Appliance conversion will become logistically easier and significantly cheaper as
lessons are learnt from the early cities and hydrogen compatible (HySwitch) and/or
dual fuel appliances begin to take a firm foothold in the market. To allow flexibility
in a rollout programme it is critical that the HTS is designed in a way to ensure it is‘broadly’ future proof. For example retrospective conversion of cities would be easily
achievable providing connection points from the HTS to these cities (or regions) havealready been put in place and the HTS pipes have been sized accordingly.
It has been established that the start of the hydrogen economy practically needs to
be in the north of England making use of the salt caverns for inter-seasonal storage,
CCS availability and chemical heartlands. It could then expand West/South/Northto suit any strategy, including as many (or as few) urban areas as desired bearing in
mind practicalities of workforce availability and logistics.

345

Section 11 | H21 Rollout Vision

Chart 11.7 shows how decarbonisation of heat can be achieved over time. The
gradient of the graph will be determined by the rollout strategy underpinned by therequirement for higher or lower levels of decarbonisation which can be determinedby the funding availability. When considering a rollout strategy too high a rate may bebad as it will overload suppliers and training, and lessen learning. Too slow and theexecution fails to impact 2050 target or even the Paris Agreement timescale. A slow
rate may not support supplier and skills or may not drive product innovation and new
business plans.

Carbon Savings Over Time

Carbon Saving

40
35
30

Ongoing say
upto 2070 following
a long term strategic
rollout plan

25
20
15
10
5
0
2025

2030

2035

2040

2045
Year

Chart 11.7. Carbon Savings Over Time

346

2050

2055

Section 11 | H21 Rollout Vision

11.2. The Impact of Other Forms ofDecarbonised Gas
When considering a future rollout strategy we must also consider the potential
expansion in the availability of the ‘bio’ forms of methane. These primarily
may include:
1. Bio-methane produced through anaerobic digestion.
2. Bio-SNG – produced via 100% black bag waste gasification.
3. Bio-gas produced via gasification with associated carbon capture and use ofbio fuel feedstock. This option is considered less likely due to availability of thefeedstock. Additionally if the UK were developing a hydrogen economy thegasifier would be more beneficial producing hydrogen.
If there is a significant rise in the availability of decarbonised methane supplies it
may be appropriate that the conversion to hydrogen only includes the major cities
as presented in Option 1. It should be noted however that the process for bio–SNG
production in the first shift reaction produces hydrogen. This is then ‘upgraded’ tomethane in a process which loses an addition 16% of the energy. It would seem
more sensible to use black bag waste gasification to produce hydrogen to add to ahydrogen economy than methane.
The incremental nature of the hydrogen conversion rollout allows the strategy
to be amended and modified to react to new technologies, or significant shifts inavailability of bio-methane supplies (say up to 15% of UK gas demand) which may or
may not become available.
It is important to remember that the strategy adopted needs to meet the challengeof the Climate Change Act, i.e. an 80% reduction in carbon emissions by 2050. To
achieve this all UK gas consumers do not need to be converted to hydrogen andindeed the overall UK strategy needs to consider all the energy requirements from a
UK gas mix, for example:
If the UK gas demand landscape in 2050 is comprised of the following:yy 60% hydrogen.
yy 10% bio-methane.
yy 30% natural gas.

347

Section 11 | H21 Rollout VisionThis mix could still meet (or surpass) the challenge of the climate change act when
considering the whole energy system. For example as well as low carbon heat areas
to consider would be:yy Transportation (offsetting diesel/petrol emissions)—— What is the uptake in hydrogen vehicles?
—— What is the uptake in methane fuelled vehicles?
—— What are the other opportunities within the hydrogen economy (ferrys, trains, planesetc.).

yy Electrification—— What is the uptake in local generation from hydrogen, i.e. Micro-CHP offsetting
national generation requirements and removing 7% loses in the electrical networks?
—— National generation; what is the UK position on hydrogen fuelled CCGTs supporting
decarbonisation of electric generation.

yy Energy efficiency – what percentage reduction in net energy requirement has theUK achieved?
yy Additional gas grid users. As the costs of regulatory finance are shared by all
customers connected to the grid increasing grid demand (for example for roadtransport and local electric generation) will further reduce the cost impact in theoverall bill of a hydrogen conversion, more users of the gas grid results in moreability to share the cost of conversion?
Additionally after the 2050 target the hydrogen economy can still continue to growand hydrogen generation may have become available from alternative sources
around the world. This is discussed further in Section 11.3.

348

Section 11 | H21 Rollout Vision

11.3. Hydrogen Production – Market‘Push and Pull’
In order to start the decarbonisation of heat through hydrogen conversion the only
viable way is to produce the large amounts of hydrogen required through steam
methane reformation. However, as the rollout of the hydrogen economy grows there
will be other options that could become available.

The Market-push EffectThinking about this simplistically, a significant barrier to a hydrogen economy is masshydrogen availability at point of use. In order to address this issue government policy
is required, in the same way it was required for the original towns gas to natural
gas conversion, to effectively ‘push’ the UK energy market towards a hydrogen
conversion, For example, a policy statement could be:‘The UK is committed to an incrementalhydrogen conversion. This will be in line withthe strategy being developed for a hydrogen
conversion programme rollout up to 2050. The
heating fuel in the gas grids within the areas
identified for conversion will be a gas of 99.9%
purity hydrogen’
Having generated this initial push which could then be managed and fundedthrough regulatory business plans, see Section 8, Finance and Regulation there
could
be a retrospective market pull across the hydrogen supply chain as certainty of ahydrogen economy would have been established.

The Market-pull EffectOnce a definite move towards a hydrogen economy is established it would
inevitably create a retrospective market pull both nationally and globally. This
market pull is likely to affect all ends of the hydrogen supply chain includinghydrogen production and hydrogen utilisation technologies. Hydrogen utilisation
technologies would include anything and everything that can be fuelled via
hydrogen. This is not discussed further in this report but more detail can be found in
Innovate UK’s 2016 hydrogen roadmap project.

349

Section 11 | H21 Rollout Vision

Supplementary Hydrogen Production
Hydrogen can currently be produced in circa 20 ways which vary in terms ofvolume, cost and technology readiness levels. The decarbonisation of heat via
hydrogen is most practically achieved with Steam Methane Reformers (SMR) as theprincipal source. However, as the hydrogen economy grows there will be additionalhydrogen production methods including those currently available and those notyet commercially developed that are likely to contribute. Some examples areprovided below.
yy By-Product hydrogen: A number of production methods rely on anotherrequired product, such as in refineries and chlor alkali plants. Locally this may
be economic but is not a secure supply. Such a process, if without embodied
CO₂ is ideal, but is dependent on the viability of the primary process. As thehydrogen economy grows areas with significant by product hydrogen availability(generally larger industrial areas including Teesside, Liverpool and Grangemouth)
will be able to utilise their hydrogen by injecting it directly into the hydrogengas grid system. This could become an additional resource and will provide a
supplementary supply which can help support/offset capital costs of SMRs andstorage requirements.
yy Electrolysers: Whilst not currently economic or low carbon when supportedby the deep pool of the current UK electricity grid, electrolysers remain an
option in a portfolio of hydrogen supply for a hydrogen distribution system. For
example a low cost, offshore wind farm of gigawatt scale may find that rather
than sell electricity it should export its energy in the form of piped hydrogen toa hydrogen grid with its intrinsic energy storage. This is likely to offer significant
balancing capability to a decarbonised electricity grid. A hydrogen gas system
would remove the significant existing barrier which currently prevents theopportunity for system integration between the UK electric and gas grid systems
imposed by current gas quality standards and billing methodologies.
yy Nuclear: An undeveloped approach is use of very high temperature nuclear
reactors to dissociate hydrogen in water, but this is not yet available.
yy Gasifiers: Represent another large scale form of hydrogen production in atechnology established across the world. Gasifiers have up to 500 MW output
and designs use a range of feedstocks including coal, residual black bag
waste, and bio fuels. The potential for gasifiers producing hydrogen should be
investigated further especially as a mix of gasifier technology and SMR hydrogenproduction in an expanding hydrogen economy would provide insulation fromfeedstock price fluctuations, i.e. the cost of natural gas vs. alternatives.

350Section 11 | H21 Rollout Vision

Bulk ‘Green’ Hydrogen Production
Whilst the UK is limited in its capabilities to produce hydrogen at large scale via
renewable technology there are areas of the world that have almost unlimited
capability. It is possible to imagine a world where, following a market-push within theUK, a global market pull for hydrogen production could occur.
Areas of the world with large land availability and significant sunlight hours, but
without an equivalent demand for the potential decarbonised electricity, could
begin to produce hydrogen at large scales via electrolysis to be shipped in liquidform. This would be achieved in a similar way to how liquid natural gas is commonly
shipped around the world today. In the longer term future this large scale ‘green’hydrogen could reduce the requirement for fossil fuel feedstock and carbon capture
from SMRs. It could also significantly reduce the UK’s capital cost commitment
to its expanding hydrogen economy as the hydrogen production facilities aredelivered ‘elsewhere’.
If this system were to transpire it could allow areas with surplus electrical energy
availability to balance their system whilst creating a secure, sustainable feedstock forother areas of the world.
Additionally this Liquid Hydrogen Gas (LHG) industry would support the interseasonal storage requirements of the UK as the hydrogen conversion develops. For
illustrative purposes this has been represented pictorially below.

UK H₂ Market Pull

Areas of vast ‘available’land and signﬁcantsunlight hours

Liquid Hydrogen Shipping

Image 11.5. Liquid Hydrogen Economy

351

Section 11 | H21 Rollout Vision

Whilst this worldwide hydrogen production economy may seem a long way off
there are already projects emerging around the world investigating the possibility.
The most notable being in Norway where NEL ASA (NEL), SINTEF, Statoil, Linde
Kryotechnik, Mitsubishi Corporation, Kawasaki Heavy Industries, NTNU and The
Institute of Applied Energy, among others, initiated the project Hyper, a feasibility
study of the potential for large scale hydrogen production in Norway for export to theEuropean and Japanese markets. The project has received a 14 MNOK grant from the
ENERGIX-programme of the Research Council of Norway.
SINTEF Energy Research is the host organisation and the lead research partner for
project Hyper. The aim of the project is to study the feasibility, as well as enable
the planning, construction, and operation of a commercial decarbonised hydrogenproduction, liquefaction, and export facility based on Norwegian fossil andrenewable energy resources.
Hyper has Kawasaki Heavy Industry as one of the partners, this will be useful forthe transport of bulk liquid hydrogen by ship. Hyper should build on design studies
already carried out by Japan and Australia, which are considering very similar scaleof shipments at about 250,000 tonnes per year into Japan. This would use brown coalgasification with CCS, and H₂ delivered cost is estimated as 30 Yen/Nm³.
https://www.iea.org/media/workshops/2014/asiahydrogenworkshop/1.17_
IEAWSKHIR2_Kawasaki.pdf

352

Section 11 | H21 Rollout Vision

11.4. Carbon Capture
Carbon Capture and Storage UK Potential
Whilst the H21 principle is to dispose of the carbon dioxide ‘over the fence’ it isimportant to understand the scale of CCS availability in the UK. Whilst it is not within
the scope of this report to provide comprehensive details, such details can be foundin the recently published ETI report ‘Progressing Development of the UK’s Strategic
Carbon Dioxide Storage Resource – A Summary of Results from the Strategic UK CO₂
Storage Appraisal Project (April 2016)’
The full report details the capacity related to the mapping of 579 store sites. An
extract from the ETI report says:“In 2012, the ETI and its partners completed a study to build an inventory of all thepotential CO₂ Storage locations in the UKCS”. This UK Storage Appraisal Project
was the source of a national CO₂ storage resource database called CO₂ stored now
made publicly available and being further developed by the Crown Estate and British
Geological Survey. Through a systematic process, this work identified almost 600
potential storage sites and developed an outline description and the first nationwide
assessment of the CO₂ storage capacity resource using a consistent methodology.
In total some 78 GT of potential CO₂ storage resource was identified. Whilst almost
all of this potential has been discovered by existing drilling, very little (circa 140 MT)of this resource has been matured through appraisal characterisation towards being
FID ready. The outcome of this project moves much more of this resource from being
an unclassified contingent resource to a classified contingent resource with a viable
development plan and thereby significantly improving confidence regarding its
availability for deployment.
A step in the report was screening on known, accessible data, of representative
structures. The report references 37 specific sites which met the high hurdle toqualify as potentially strategic storage sites. Beyond this there were many otherexcellent sites which present a rich diversity of storage resource. Together thequalified inventory had a combined CO₂ stored capacity of 8.3 GT (average 224 MT
per site). This 8.3 GT is then quite similar to the targets further examined.
In the context of a UK wide hydrogen rollout relying predominantly on SMR with CCS
production of hydrogen a 100 mt/y x 2 cycles of 40 year assets = 8 GT is entirely
reasonable therefore providing 80 years with of hydrogen production viability which,over time, will inevitably be produced via diverse sustainable sources.

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Section 11 | H21 Rollout Vision

The relative attractions of grid conversion for CCS are:yy The flow rates of CO₂ from heat decarbonisation can be much less variable thanfrom power, (due to having H₂ storage to smooth peaks and troughs).
yy Decarbonising heat is the most efficient use of CO₂ transport and storage
systems in terms of £CO₂ stored/kWh energy to consumer.
yy Heat enables decarbonised hydrogen for transport, which is then an evenmore effective use of CO₂ storage, to address all vehicle emissions and city air
quality problems.
yy Most importantly – distributed low carbon hydrogen unlocks innovation for
end users and further leverages the UK’s comparative advantages in low
carbon energy.

To summarise there is no shortage of CCS
availability in the UK to progress a UK
incremental rollout of hydrogen for long term
decarbonisation of the UK Gas grid.
Carbon Capture Utilisation
Whilst carbon capture utilisation is in its infancy it is important to keep the prospectsof this technology within the long term vision of a UK hydrogen conversion rollout
strategy. Cambridge Carbon Capture Ltd, (CCC), are developing technology thatcan potentially capture CO₂ profitably by converting it to a mineral by-product withcommercial uses. It can be used to capture CO₂ either pre or post combustionand does not rely on the availability of geological CO₂ storage or CO₂ pipeline
infrastructure. CCC are also developing technology that can generate electricity
whilst capturing and converting CO₂.

354

Section 11 | H21 Rollout Vision

11.4.1. Description of Carbon Capture andMineralisation
Carbon Capture and Mineralisation (CC&M) is a method of permanently capturing
CO₂ using mineral carbonation, effectively converting CO₂ into a stable andcommercially useful mineral. Carbon mineralisation involves reactions of magnesium
or calcium oxides (typically contained in mineral silicates and industrial wastes) with
CO₂ (dilute in the atmosphere or exhaust gases, or as captured pure CO₂) to give inert
carbonates. Due to the lower energy state of carbonates compared to CO₂, thesereactions release significant amounts of energy and, in nature, occur spontaneously(but slowly). It is this energy that CCC’s technology is able to harness and convert toelectricity. Vast amounts of suitable and readily accessible mineral silicates exist –many times more than is needed to sequester all anthropogenic CO₂ emissions.

Image 11.6. Pamukkale Lakes in Turkey, Natural Formation of Calcium Carbonate from Volcanic CO₂

Slow speed of reactions of natural silicate rocks and the large amounts of minerals
that must be handled, typically 2-3 tonnes rock per tonne of CO₂, are the primarychallenges for commercially viable industrial mineral carbonation applications.
Processes that accelerate kinetics and maximise materials values with minimal
additional costs and environmental impacts are the focus of R&D by Cambridge
Carbon Capture and others around the world.

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Section 11 | H21 Rollout Vision

CC&M technologies are still in their infancy; some commercial pilot schemes havebeen developed using calcium carbonation technologies, the most notable being
Skyonics in the US, (http://www.skyonic.com/projects/capitol-skymine-plant).
Cambridge Carbon Capture’s technology is different in that it is much less energy
intensive and produces streams of highly valuable by-products, the sale of which has
the potential of making CO₂ capture a profitable process rather than being a cost toenergy production and use.
CCC’s process is based on low cost and abundant magnesium minerals such as
olivine and serpentine. The overall natural weathering and carbonation of olivine
and serpentine rocks to form silica and magnesium (bi)carbonate occurs in nature
but the natural reactions are extremely slow. CCC’s technology involves the same
overall carbonation reactions, but a very different route. CCC have identified andexperimentally demonstrated the feasibility of a sequence of low-energy treatment
steps that significantly accelerate reaction kinetics and enable easy separationof by-products. CCC’s carbon capture and mineralization technology consumes
magnesium hydroxide, capturing and converting the CO₂ to form magnesium
carbonate. In order to make the process economic at a large scale, a viable sourceof cheap and abundant magnesium hydroxide is required. CCC has developed alow energy route to making magnesium hydroxide from commonly found olivine orserpentine. The process produces a number of valuable by-products including:yy Metals – nickel, iron, chromium.
yy Rare earth metals.
yy Silica oxide powders – Amorphous Precipitated Silica (APS).
yy Magnesium carbonate.
APS has many commercial uses but can be used in the manufacture of vehicle tyres
to reduce rolling resistance, improving vehicle efficiency. Current APS prices limit
the market for these tyres so an abundant supply of low cost APS could lead to avery large market for this mineral. Magnesium carbonate can be used in a numberof industrial applications such as fire retardant plastic fillers, it can also be used asa building material either in block or sheet form where it’s fire retardant properties
and low carbon production would offer significant commercial advantage. Image 11.7
and 1..8 describe CCC’s two-stage process and the direct CO₂ fuel cell generating
electricity from the conversion of CO₂.

356

Section 11 | H21 Rollout Vision

Alkali
RecycleSerpentine/Olvine+Energy

Separation ofMg(OH)₂
from Alkali
Silicate

Digestion of
Serpentine/Olivine

Heat

Mg(OH)₂(Powder)

Precipitationof Silicaand Alkali
Recovery
Water
RecycleSiO₂(Powder)

Image 11.7. CCC’s Process to Produce Low Cost Magnesium Hydroxide for CO₂ Capture

REACTOR

Flue gas

Mg(OH)₂

Production ofmagnesium
carbonatesolids via
Mg(OH)₂
carbonation

De-carbonised ﬂue gas
MgCO₃
Heat or Electricity via direct CO₂ FC

Image 11.8. CCC’s CO₂ Capture Process357

Section 11 | H21 Rollout Vision

Economics
CCC’s technology has the potential to strip CO₂ from industrial flue gases for lessthan the current carbon price, with the potential to offset this cost or even makea profit from sale of semi-precious metals and other mineral by-products fromthe process, see Image 11.9. CCC’s technology is applicable to all land and seabased industrial emitters of CO₂. CCC has further intellectual property enabling thegeneration of electricity from the carbonation process using their patented direct CO₂
fuel cell technology.

Cost

Serpentine
Mine

Revenue

Mg(OH)₂
Refining

Distribution
Network

Ni/SiO₂
By-products

CO₂ Capture
at Emission
Site

Carbon Credits
Aggregates
andElectricity

Image 11.9. Process Cost Model

Integration of CCC’s Technology with SMR Technology
Integration of CCC’s technology would be relatively straightforward. As with the CCS
option, a CCC plant would be built alongside the SMR plant. The main difference
between SMR with CCS and the CCC concept is that the CCC CO₂ scrubber would
take the place of the Pressure Swing Adsorption (PSA) stage. CCC’s CO₂ scrubber
consumes magnesium hydroxide and outputs pure hydrogen and magnesium
bicarbonate. The magnesium bicarbonate would then pass to a further reactor
where it is heated using heat recovered from the SMR exhaust gases to convert itto magnesium carbonate and CO₂. The released CO₂ could either be sold as a byproduct or sent back to the CO₂ scrubber to be re-absorbed. Finally, the flue gases
from the SMR, having first been cooled by the heat recovery stage, pass through asecond CCC CO₂ scrubber before being vented to the atmosphere. The magnesium
bicarbonate solution from this reactor is then fed to the magnesium carbonate
conversion stage of the process alongside the outputs of the hydrogen CO₂ scrubber.
Image 11.10 shows a schematic of the integrated carbon capture and SMR plant.

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Section 11 | H21 Rollout Vision

Integrated Carbon Capture and SMR Plant
Natural gas(Fuel)
HydrogenH₂ recycle

Naturalgas

Feed
Pretreatment

Steam
Reforming

CCC
CO₂
Scrubber

CO -Shift
Conversion

CO₂

Flue gas

Steam process

Mg(OH)₂

Mg(OH)₃

Waste
Heat
RecoverySteam (heat)
Export steam

Mg(OH)₂

MGCO₃
Conversion
ExportCO₂

Flue gas

Demineralised
water

CCC
CO₂
Scrubber

Zero emissions
Flue gas

Image 11.10. Schematic of the Integrated Carbon Capture and SMR Plant

Integration of CCC’s Technology within the H21 Rollout Vision
CCC’s CO₂ capture technology involves the consumption and production of bulk
materials as well as the provision of CO₂ from the SMR process. As a result in an
expanding hydrogen economy the siting of any carbon capture facility utilising CCU
would require good transportation links, either by road, rail or sea.
The CCC process consumes and produces large quantities of materials directly
proportional to the amounts of CO₂ being captured. An example of the quantities
involved in capturing carbon through this process is provided below. Table 11.7
quantifies the inputs and outputs of the CCC capture process based on this CO₂
capture requirement:

359

Section 11 | H21 Rollout Vision

MATERIAL

Input (tonnes)

Output (tonnes)

Transport

CO₂

1,224,000

Pipeline

Magnesium Hydroxide

1,627,920

Road/Rail2,350,080

Magnesium Carbonate
Total

2,851,920

Road/Rail2,350,080

Table 11.7. Total Inputs/Outputs for Capture of Large Scale CO₂ Output

Total tonnage by road and/or rail would therefore be 4 million tonnes per annum,
total tonnage by pipeline 1.2 million tonnes.
In terms of transportation costs, the cheapest form of transport for bulk materials is
by sea, followed by pipeline, rail then road. The comparative costs will vary greatly
with availability and proximity of existing infrastructure, population density andlocal landowner levies. However, it is valid to prioritise locations on the basis of theproximity of seaports and existing rail and road infrastructure whilst minimisingpipeline length and avoiding pipelines through areas of high population density or
crossing significant road or rail infrastructure.
In conclusion it is clear that in the longer term carbon capture utilisation technology
may offer a complementary alternative to CCS requirements. It has potential togenerate revenue therefore reducing costs of hydrogen production and the criteria
for establishing viable sites for this technology, i.e. near ports/rail heads, are met by
the SMR expansion locations as presented in this Section.

360

Section 11 | H21 Rollout Vision

11.5. H21 Vision Conclusions
A hydrogen economy presents many opportunities to decarbonise not just heat but
wider energy and transport.
Whilst the conversion is not free it can be financed in a way which could haveminimal impact on customers’ bills.
An optimised, no regrets, strategy should be developed for the incremental rollout ofa hydrogen UK gas grid conversion programme.
A commitment to a long term hydrogen conversion strategy could act as the catalyst
for the onset of the UK carbon capture and storage industry offering a constant,reliable long term source of carbon to any infrastructure provider. This could thenfacilitate CCS on many other industrial and power generation assets.
Development of a UK hydrogen vision and ultimately a policy decision can beachieved through the H21 Roadmap identified in Section 10. Such a move by the UK
would set it apart as the market leader and could create significant benefits to the
future UK economy.

361

Schedules

Chart Schedule
1. Introduction

10

2. Demand vs. Supply

28

Chart 2.1. Scaling of Demand When Considering the Monthly Factors

31

Chart 2.2. Scaling of Demand When Considering the Within Day Ratios

31

Chart 2.3. Combined Inter-Seasonal and Intraday Factors for the
Forecasted Demand Over the Year

33

Chart 2.4. Yorkshire Actual Daily and Seasonal Demand Levels 2009 to 2015 

33Chart 2.5. Estimated Yorkshire LDZ peak 6 minute demand for March 2009 to May 2015

35

Chart 2.6. Minimum Days Storage Against H₂ Production to Meet Demand

45

Chart 2.7. SMR Supply vs. Demand

58

Chart 2.8. 2013 Winter Storage Demand

59

Chart 2.9. Demand and Seasonal Storage Changes MWh/day

65

Chart 2.10. Seasonal Storage

66

Chart 2.11. Supply Profile For Peak Day Design68

3. Gas Network Capacity

85

Chart 3.1. MP Mains Velocity (% of Total MP Mains Length) At Various Demand Levels(% of Peak 1 in 20 Demand)

98

7. Carbon Capture and Storage

208

Chart 7.1. H21 vs. Natural Gas CO₂ Emissions

223

363

8. Finance and Regulation

229

Chart 8.1. RAV Depreciation

235

Chart 8.2. UK Gas Bill Component Parts

240

Chart 8.3. NGN Revenue Forecast (Current Scenario)

245

Chart 8.4. Total Customer Gas Bill

247

Chart 8.5. Hydrogen Revenue Allowances (with Current OPEX/CAPEX Funding Methodology) 251
Chart 8.6. Customer Contribution to Transportation Charge, Option 1

252

Chart 8.7. Customer Contribution to Transportation Charge, Option 2

253

Chart 8.8. Total Customer Gas Bill

255

9. Next Steps – The Programme of Works

269

Chart 9.1. Spend Profile Over Time

271

11. The H21 Rollout Vision

321

Chart 11.1. Option 1 Hydrogen Revenue Allowances – Rollout Illustration

334

Chart 11.2. Option 1 Customer Bill – Rollout Illustration

335

Chart 11.3. Option 2 Hydrogen Revenue Allowances – Rollout Illustration

336

Chart 11.4. Option 2 Customer Bill (Transportation Element Only) – Rollout Illustration

337

Chart 11.5. GDN Element of Customer Bill – Difference Between Options337

Chart 11.6. Total Customer Gas Bill

338

Chart 11.7. Carbon Savings Over Time

346

364

Image Schedule
1. Introduction

10

Image 1.1. Existing UK Transportation System

14

Image 1.2. UK Gas Pressure Tiers

15

Image 1.3. Current Gas Transportation System Ownership

17

Image 1.4. End-to-End Energy System

19

Image 1.5. H21 Leeds City Gate – Original Concept**

21

Image 1.6. H21 Leeds City Gate – Amended Concept

22

Image 1.7. Area of Conversion*

24

2. Demand vs. Supply28

Image 2.1. MSOA Area Example*

36

Image 2.2. 21,000 Mc³/h H₂ Electrolysis Plant

49

Image 2.3. A Typical SMR Plant – Picture Courtesy of BOC51

Image 2.4. Existing BOC 36.4 MMSCFD (c. 150 MW) SMR at Teesside**

51

Image 2.5. Simple Block Flow of an SMR and CO₂ Capture Plant

55

Image 2.6. H21 Leeds City Gate SMR Train Configuration

56

Image 2.7. Salt Dome Salt Cavern

61

Image 2.8. Salt Caverns At Teesside**

61

Image 2.9. Local Salt Deposits and Salt Cavern Storage (Extract from ETI Report)

64

Image 2.10. Local Large Natural Gas Salt Cavern Storage (Courtesy of SSE)

64

Image 2.11. Teesside and East Riding Underground Gas Storage**

71

Image 2.12. UK Salt Deposits and Salt Cavern Storage (From ETI Report on Hydrogen)

78

Image 2.13. UK Carbon Capture Availability (From ‘Strategic UK CCS Storage Appraisal Project) 78
Image 2.14. Seal Sands Industrial Area**

80

365

3. Gas Network Capacity

85

Image 3.1. Screenshot Synergi

86Image 3.2. Network Data Logger

86

Image 3.3. Map of Leeds*

87Image 3.4. Map of Area of Conversion*

88

Image 3.5. Synergi Model Natural Gas Parameters

89

Image 3.6. Synergi Model Hydrogen Parameters

89

Image 3.7. Pressure Tier Cascade

90

Image 3.8. Map of Leeds Gas Network Indicating PRS Locations*

91

Image 3.9. Map of Leeds Gas Network District Governor Locations92

Image 3.10. Existing Design Parameters for UK Distribution Networks

93

Image 3.11. Synergi Analysis MP Network (Pressures) – Natural Gas94

Image 3.12. Synergi Analysis MP Network (Pressures) – Hydrogen

94

Image 3.13. Synergi Analysis MP Network (Pressures) – Hydrogen with Existing PRU Positions95

Image 3.14. Synergi Analysis MP Network (Pressures) – Hydrogen with Amended PRU Positions 95
Image 3.15. Synergi Analysis MP Network (Velocities) – Natural Gas96

Image 3.16. Synergi Analysis MP Network (Velocities) – Hydrogen

96

Image 3.17. Synergi Analysis MP Network (Velocities) – Hydrogen with Existing PRU Positions97

Image 3.18. Synergi Analysis MP Network (Velocities) – Hydrogen with Amended PRU Positions 97
Image 3.19. Synergi Analysis LP Network (Pressures) – Natural Gas100

Image 3.20. Synergi Analysis LP Network (Pressures) – Hydrogen

100

Image 3.21. Five Detailed Areas of Reinforcement

101

Image 3.22. Area 1 Reinforcement**

103

Image 3.23. Area 9 Reinforcement**

104

Image 3.24. Area 10 Reinforcement**

105

Image 3.25. Area 11 Reinforcement**

106

Image 3.26. Area 12 Reinforcement**

107

366

4. Gas Network Conversion 

113

Image 4.1. Otley Zones of Influence Same Pressures

116

Image 4.2. Otley Zones of Influence Varying Pressures

116

Image 4.3. Area of Conversion: MP Zones of Influence

116

Image 4.4. Map of Gas Network in the West Yorkshire Area*

117

Image 4.5. Map of PRS Injection Points to the Area of Conversion*

118

Image 4.6. Map of Leeds Hydrogen Ring Main and PRSs*

119

Image 4.7. MP Three Year Conversion Strategy

120

Image 4.8. Isolation Locations on MP Network and Illustration of Double Blockand Bleed Isolation Method

121

Image 4.9. LP Yearly Isolation Zones

122

Image 4.10. Conversion Isolation

123

Image 4.11. Wharfedale Area of Conversion*

124

Image 4.12. Starting Position*

125

Image 4.13. Maps Step One*

126

Image 4.14. Map Step Two

127

Image 4.15. Maps Step Three128

Image 4.16. Maps Step Four

129

Image 4.17. Maps Step Five

130

Image 4.18. Maps Step Six131

Image 4.19. Maps Step Seven*

132

Image 4.20. Example Two Starting Position*

134

Image 4.21. Map, Example 2, Step 1*

135

Image 4.22. MP Three Year Conversion Strategy and Double Block and Bleed

136

367

5. Appliance Conversion

139

Image 5.1. Examples of Distributed Flame Gas Burners from Remeha (left) and Alpha (right)

166

Image 5.2. Comparison of Size of Conventional and Catalytic Boilers

167

Image 5.3. Typical Natural Gas or Hydrogen Partially Premixed Gas Burner
ref www. Cielotech.Wordpress.Com

170

Image 5.4. Model #GFH6000 Green Flame Heater Hydrogen Fuelled Input 1.3 kW to 1.8 kW

172

Image 5.5. Giacomini Hydrogen Catalytic Boiler (Giacomini, 2011)

174

Image 5.6. DIY BBQ

175

Image 5.7. Hydrogen Cooker

175

Image 5.8. Integrated Hydrogen Catalytic Burner (Ulrich, V. (EMPA), 2015)

176

Image 5.9. MAXON Wide-Range (R) Burner Running on Hydrogen. (Source: https://www.
maxoncorp.com/Directory/product/WIDE-RANGE-Burner/38/Natural-Gas-Burner-High)

179

6. The Hydrogen Transmission System

184

Image 6.1. Indicative Route Corridor of HTS and Associated Connections

186

Image 6.2. Representation of Connections at Teesside

188

Image 6.3. Indicative Route Corridor of HTS193

Image 6.4. Horizontal Directional Drill (HDD)

198

Image 6.5. Representation of Connections at Leeds

201

Image 6.6. Typical Distribution Network PRU203

7. Carbon Capture and Storage

208

Image 7.1. Provided by SaskPower

208

Image 7.2. Provided by Shell

208

Image 7.3. UK CCS availability

210

Image 7.4. Teesside Collective Report Summary

212

Image 7.5. The Teesside Collective Five Industrial Partner Locations

213

Image 7.6. The Five Elements of the ICCS Project

213

368

8. Finance and Regulation

229

Image 8.1. Gas Distribution Industry Overview

232

Image 8.2. GDN income

238

Image 8.3. GDN Capacity Impact

239

9. Next Steps – The Programme of Works

269

Image 9.1. Key Elements Timeline

270

10. The H21 Roadmap

275

Image 10.1. H21 Roadmap – Work Package Overview

277

Image 10.2. The Existing UK Transportation System

278

Image 10.3. Existing System Modifications

279

Image 10.4. Proposed H21 Programme Team Structure

281

Image 10.5. Programme Team Wider Interfaces

281

Image 10.6. ‘Typical’ Pressure Reduction Station (PRS)

283

Image 10.7. Instrumentation Equipment

283

Image 10.8. Hazardous Area Classification Drawing (Large Site)

284

Image 10.9. ‘Typical’ District Governors (x2)

285

Image 10.10. LP Network Reinforcement Requirements

289

Image 10.11. H21 Roadmap – Work Package Overview

319

369

11. The H21 Rollout Vision

321

Image 11.1. H21 Rollout – Large City by City and HTS

322

Image 11.2. Hydrogen Production and CCS Expansion Over Time

324

Image 11.3. Increasing Hydrogen Production Capability at Teesside**

325

Image 11.4. UK Gas Distribution Networks

341

Image 11.5. Liquid Hydrogen Economy

351

Image 11.6. Pamukkale Lakes in Turkey, Natural Formation of Calcium Carbonate
from Volcanic CO₂

355

Image 11.7. CCC’s Process to Produce Low Cost Magnesium Hydroxide for CO₂ Capture

357

Image 11.8. CCC’s CO₂ Capture Process

357

Image 11.9. Process Cost Model

358

Image 11.10. Schematic of the Integrated Carbon Capture and SMR Plant

359* © Open Street Map and Contributors CC-by-SA** © Google Images

370

Table Schedule
1. Introduction

10

Table 1.1. The UK gas transportation system

11

2. Demand vs. Supply28

Table 2.1. Monthly and Daily Turndown Ratios

30

Table 2.2. MSOA Examples

37

Table 2.3. Sheffield Average Annual Temperatures

38

Table 2.4. Inter-seasonal Storage

67

Table 2.5. Intraday Storage Meeting Peak Day Demand

69

Table 2.6. H21 Leeds City Gate Storage Requirements

72

Table 2.7. Hydrogen Production System Cost Summary

83

3. Gas Network Capacity

85

Table 3.1. Properties of Natural Gas and Hydrogen

89

Table 3.2. Current UK Gas Network LP and MP Design Parameters

93

Table 3.3. Pipe Velocities by Percentage Peak Demand Level

98

Table 3.4. Reinforcement Costs

108

Table 3.5. Remaining Metallic Mains in the Area of Conversion

110

4. Gas Network Conversion 

113

Table 4.1. Network Conversion Enabling Works – Cost Summary

137

371

5. Appliance Conversion

139

Table 5.1. Domestic vs. Non-Domestic Split in Area of Conversion

141

Table 5.2. Design Parameters for the Management of the Appliance Switchover Process.

143

Table 5.3. Estimation of Effort Required for Appliance Switchover for One Isolation Zone
Containing 2,500 Domestic Properties

145

Table 5.4. Summary of Hardware Costs for Appliance Switchover for One Isolation Zone
Containing 2,500 Domestic Properties

146

Table 5.5. Area Meter Information

146

Table 5.6. Costs per Property

147

Table 5.7. Estimated Annual Commercial and Industrial Energy Demand
from the Largest Demand Low and Medium Pressure Network Connections in Leeds

149

Table 5.8. Examples of MSOA Non-domestic Data

150

Table 5.9. Installed Non-domestic Capacity

151

Table 5.10. Estimated Costs for the Conversion of Industrial andCommercial Equipment to Hydrogen

152

Table 5.11. Overall Estimates

153

Table 5.12. A Comparison of the Energy Conveyance Properties of Hydrogen and Natural Gas 157
Table 5.13. Comparison of Physical Properties of Hydrogen, Methane and Natural Gas161

Table 5.14. A Comparison of the Energy Release Properties of Hydrogen and Natural Gas162

Table 5.15. Characteristics of Hydrogen Combustion Systems

163

Table 5.16. Technical Detail of the Giacomini Hydrogen Boiler

173

372

6. The Hydrogen Transmission System

184

Table 6.1. Assumed Technical Parameters

188

Table 6.2. Technical Parameters – Teesside Connections

189

Table 6.3. Cost Summary – HTS Teesside Connections192

Table 6.4. HTS Pipeline Sectional Details

196

Table 6.5. Cost Summary – HTS Pipeline

200

Table 6.6. Leeds Connection Elements

201

Table 6.7. Cost Summary: Connections at Leeds

204

Table 6.8. HTS Operating Costs

205

Table 6.9. Cost Summary – HTS and Associated Connection

206

7. Carbon Capture and Storage

208

Table 7.1. Summary of H21 Emissions Levels by Scope

223

Table 7.2. Comparison of the Carbon Footprint of Hydrogen from SMR+CCS with Other Fuels

224

Table 7.3. H21 Leeds City Gate – Total Annual Volume of Captured CO₂

225

373

8. Finance and Regulation

229

Table 8.1. H21 Leeds City Gate Project Costs

230

Table 8.2. REPEX Funding

236

Table 8.3. Industry Revenue Allowances

237

Table 8.4. GDN Charges 2014/15 OFGEM Annual Report

241

Table 8.5. Customer Bill Impact – Transportation Charge Only

246

Table 8.6. Energy Efficiency Over Time

246

Table 8.7. Total Customer Bill Impact – (Total Bill)

247

Table 8.8. Expenditure Forecast

249

Table 8.9. Customer Bills, Transportation Only (2015/16 prices) Average Year, Option 1

252

Table 8.10. Customer Bills, Transportation Only (2015/16 prices) Average Year, Option 2

254

Table 8.11. Energy Efficiency Savings Over Time

255

Table 8.12. Customer Bills (2015/16 prices) Average Year, Option 1/2256

Table 8.13. Key Design Parameters

258

Table 8.14. Expenditure for 1st Conversion (Production)

259

Table 8.15. Variable Costs

260

Table 8.16. Total Costs

261

Table 8.17. Expenditure for 1st Conversion - Appliances

262

Table 8.18. £/Tonne for Scope 1 Emissions Savings for Thermal Insulation

263

Table 8.19. £/Tonne for Scope 1 Emissions Savings for H21 Leeds City Gate System

264

9. Next Steps – The Programme of Works

269

10. The H21 Roadmap

275

Table 10.1. H21 Roadmap – Work Package Overview

276

Table 10.2. Key Gas Industry Governing Documents

302

Table 10.3. Document Examples.

304

Table 10.4. Methods of Hydrogen Production

316

374

11. The H21 Rollout Vision

321

Table 11.1. CAPEX Costs per Cit

329

Table 11.2. OPEX Costs per City

331

Table 11.3. Illustrative Rollout Profile 2016/17 Prices333

Table 11.4. Energy Efficiency Savings Over Time

338

Table 11.5. Total Gas Bill

339

Table 11.6. Total Capital Costs Regional Rollout

343

Table 11.7. Total Inputs/Outputs for Capture of Large Scale CO₂ Output

360375