THE ENERGY INDUSTRY TIMES - OCTOBER 2019
13
Industry Perspective
H
ydrogen production is a pos-
sible key mechanism to a
zero-carbon energy system.
Currently available mature technolo-
gies for hydrogen production are
electrolysis from water and reform-
ing of natural gas. As power genera-
tion from renewable sources increas-
es, it is possible to anticipate a time
in the near future when peak output
will regularly exceed demand. Sur-
plus power can be converted to hy-
drogen. Hydrogen from renewables
is described as ‘green’. Production
of hydrogen from fossil fuels, using
techniques such as steam methane
reforming (SMR), is termed ‘brown’
if by-produced CO and CO
2
are sim-
ply discharged into the environment.
Marrying H production with carbon
capture, usage and storage (CCUS)
makes it ‘blue’ hydrogen, with car-
bon monoxide and dioxide. This too
can be compatible with a net-zero
carbon energy system by.
But so far, hydrogen for energy is
conceptually and technically in its
infancy. In the UK, some work on
adaptation of domestic appliances
and conversion of some industrial
thermal energy applications is under
way. There are limited plans for hy-
drogen fuel-cell vehicles and small-
scale power-to-gas. Two proposals
for bigger steam methane reforming
(SMR) with CCUS plants are in
train. However, there are no utility
scale hydrogen production projects
up and running anywhere, globally.
Rapid acceleration is required to
develop the systems we need to meet
2050 zero-carbon commitments.
More radical action by government
and industry is required to drive de-
velopment of a hydrogen-based en-
ergy system forward. Only by dem-
onstrating and scaling up the
systems, and guaranteeing a market,
can a robust and investable hydrogen
economy be created.
Clearer and more consistent poli-
cies would reduce risk for private in-
vestors. There is already a ban on in-
ternal combustion engine vehicles
from 2040 in the UK. This should be
accompanied by similar deadlines in
other consuming sectors, including a
commitment to run all combined cy-
cle gas turbines (CCGT) – the work-
horses of the current power system –
on hydrogen say by 2035. Direct
state involvement may even be need-
ed in the construction of major key
elements of hydrogen infrastructure,
such as new gas transmission and
distribution grids.
There are signs that the system can
work. Carbon taxes, market incen-
tives, the availability of cheap re-
newables, and half hourly pricing
that reects variation in the power
supply and demand balance, are al-
ready encouraging some hydrogen
output in northwest Europe. Hydro-
gen is becoming more valuable at
peak times due to its potential for
conversion to power in CCGTs and
fuel cell power plants.
Perhaps the most promising imme-
diate opportunity for hydrogen is for
energy storage. Renewables are
dogged by intermittency. When sup-
ply is high, prices fall. Indeed, sup-
pliers can be penalised for exceeding
demand. Meanwhile, there are peri-
ods when renewable power output
falls short of demand.
Converting surplus electricity to
hydrogen and using it in a gas tur-
bine or fuel cell to generate electrici-
ty would produce a hybrid solution
capable of evening out power supply
and maximising revenue. Cheap ex-
cess renewable electricity and vari-
able power prices in Europe have led
electrolysis unit manufacturers and
hydrogen production advisers, in-
cluding Air Liquide, Hydrogenics,
ITM Power, Nel Power and Siemens
to invest in such technologies.
But existing hydrogen production
units based on electrolysis are small.
Air Liquide’s largest, used in the
EU’s agship electrolysis project in
Austria, is only 6 MW.
Co-ordinated planning as well as
capital investment are needed in
electrolysis at scale, brown hydro-
gen with CCUS, hydrogen utilisa-
tion, and transmission, distribution
and storage.
Japan offers an interesting example
of the benet of government support.
It has yet to introduce carbon penal-
ties or price power in real-time and
has less cheap renewable power
available than the UK. But there
have been more extensive state
sponsored efforts to push hydrogen
development in tandem with private
companies.
In the UK and Europe, the state
could also play a key role by getting
directly involved. To date, govern-
ment has had to remove risk from
major private energy investment
projects, to attract private investors.
For example, the $20+ billion Hin-
kley C nuclear power project has a
government-guaranteed price for
power of £92.50/MWh.
One option now being considered
for large energy projects is the Regu-
lated Asset Base (RAB) model. The
state, acting through the energy regu-
lator, would ensure security of cash-
ows to private sector asset owner-
operators, so reducing the cost of
capital. This approach is favoured
for proposed SMR projects in the
UK. Their backers have different
motives for involvement, but all are
waiting for central government to
adapt the regulatory environment in
line with the national policy commit-
ment to net-zero carbon emissions
by 2050.
For the biggest hydrogen projects,
there may be just too much risk for a
private company or consortium, and
direct state funding and ownership
(as least initially) may be required.
This was the case when the existing
natural gas systems were established
in the 1970s. Such projects might in-
clude, in the UK, a 3000 km, multi-
billion-pound dedicated hydrogen
national transmission grid.
So far SMR with CCUS project
proposals have been far bigger than
electrolysis proposals. On the draw-
ing board are the Hynet Northwest
Partnership on the Mersey estuary,
backed by a consortium of gas dis-
tributor Cadent, oil and gas giant
Shell, and developer/port operator
Peel. In the northeast, a consortium
is backing a Teesside plant that will
supply Leeds. On Humberside, a
third SMR/CCUS hub is proposed
by oil and gas company BP with en-
ergy rms Centrica, Ørsted, Equi-
nor, Engie and Northern Gas Net-
works. In North Yorkshire,
generator Drax, Equinor and Na-
tional Grid Ventures (the transmis-
sion rm’s new energy technologies
arm), are aiming to develop a large-
scale hydrogen demonstrator on the
Drax site by the mid-2020s, com-
bining carbon capture from SMR
hydrogen production as well as
from thermal power production.
Some hydrogen-only pipelines
have already been built in Europe,
including Air Liquide’s pipeline
from France to Belgium, and a 210
km network in Germany. Up to 20
per cent hydrogen can be safely
blended with natural gas in existing
gas transmission and distribution
pipelines. Blending pilot projects are
going ahead at Keele and Leeds in
the UK.
In addition to SMR, several small
electrolysis plants are operating at
reneries, including Shell’s 10 MW
electrolysis plant in the Rhineland
renery in Germany (partnering with
ITM Power). Shell says it aims to
test the technology on an industrial
scale in order to develop new busi-
ness models, but its investments so
far are modest. BP has a similar re-
nery-based electrolysis project in
the Netherlands.
Blue hydrogen produced using
SMR with CCUS is an attractive in-
termediate step in the development
of a hydrogen-based energy system.
It provides a near-term market for
gas, helping oil and gas companies
to transition their businesses from
predominantly hydrocarbon-based to
renewable: The storage, transmission
and distribution infrastructure need-
ed for a functioning blue hydrogen
system will be the same as for green.
There are already green hydrogen
plants running on tidal energy in Or-
kney, as well as solar and wind else-
where. Various nuclear operators are
investigating the possibility of using
nuclear power to produce hydrogen
when prices are low (converting low
cost power into hydrogen via elec-
trolysis would enable it to be con-
verted back or sold on as a fuel when
prices rise). Norway plans to pro-
duce hydrogen from hydropower for
sale to Japan at a target price that
will outcompete a rival coal-fed
SMR project based in Australia.
Because hydrogen is such a low-
density gas, transportation is an issue
at scale. So, as well as local gas
pipeline and storage networks, other
transportation mediums need to be
considered. Options under develop-
ment include cryogenic liquefaction
of hydrogen – although this has ma-
jor costs and risks. A carrier process
using ammonia is more practical.
Splicing nitrogen and hydrogen to-
gether to create ammonia (NH
3
) is a
simple and easily reversible chemi-
cal engineering process. An ammo-
nia trading network already exists
globally, serving the fertiliser indus-
try, although existing networks
would need to be expanded dramati-
cally and modied to include con-
version facilities.
Hydrogen molecules can be chemi-
cally bonded into a class of materials
known as hydrogen carriers (HC),
which come in both liquid and solid
forms. Liquid organic HCs enable
transportation in regular tankers and
pipelines; solid HCs can be trans-
ported as freight. These HCs can be
non-toxic and fully inert, and very
cheap if produced at mass scale.
HCs can be charged and depleted re-
peatedly. The cost comes in the pro-
cess of bonding and separating hy-
drogen from them – hydrogenation
and dehydrogenation – and from
transporting the depleted HC back to
source for recharging.
Development of high capacity, low
cost, transportation is feasible – tech-
nically no more challenging than the
intercontinental transportation of
natural gas is today. Overcoming
that barrier would open up the possi-
bility of producing cheap solar pow-
er in the world’s deserts for con-
sumption in remote locations.
The transition towards a renew-
ables-hydrogen system is benetting
from the increasing number of inves-
tors acting on traditionally non-com-
mercial priorities. A quarter (or $20
trillion) of the world’s professionally
managed investments take account
of environmental, social and gover-
nance criteria. Fossil fuels increas-
ingly do not meet them.
Meanwhile, investors and insurers
are looking to reduce their exposure
to climate risks. The risk premium
for holding hydrocarbon stocks is
rising with every extreme weather
event. Meanwhile, emissions-free
hydrogen power is well aligned with
urban transport policies that address
the link between poor air quality and
harm to public health.
A comprehensive hydrogen sys-
tem, encompassing domestic and in-
dustrial power and heat, plus trans-
port, would support full energy
security. Building up stores of hy-
drogen would enable cities, regions
– perhaps entire countries – to ride
out inter-seasonal uctuations in re-
newable energy output, reducing re-
liance on fossil fuels imported from
abroad.
Large scale networks need to be
developed by the governments,
backed up by regulations based on
timelines for an accelerated growth.
Such projects can then be sold to the
private sector. Relying on energy
majors and private sector via RAB
models may be a mistake in the long
run as the current snail pace will
continue into the 2030s.
Further the public should be made
aware of the benets of using hydro-
gen to the society in addition to cli-
mate change. We can continue to
drive and y and let the next genera-
tion also experience the wonders of
the world. All of these milestones
can be achieved. Doing so involves
imparting some initial energy to the
hydrogen economy, to get it ready
to roll.
Dr Paramjit Mahi is Development
and Innovation Director, Energy
Sector, Mott MacDonald.
Progress towards
net zero carbon will
eventually require
the end of the use of
natural gas for all but
a small number of
critical applications.
Although hydrogen is
not an energy source,
it is a potentially
leading energy
vector.
Dr Paramjit Mahi
explores how to
accelerate the
hydrogen economy.
Dr Mahi: the public should be made aware of the additional
benets of using hydrogen to the society
H
2
and a zero-carbon world