www.teitimes.com
September 2020 • Volume 13 • No 5 • Published monthly • ISSN 1757-7365
THE ENERGY INDUSTRY TIMES is published by Man in Black Media • www.mibmedia.com • Editor-in-Chief: Junior Isles • For all enquiries email: enquiries@teitimes.com
Green ammonia
Digital transitions
Is green ammonia the answer to
a carbon free future?
Page 13
GE’s Linda Rae discusses how
digitalisation can help address
the challenges facing energy
companies. Page 14
News In Brief
Utilities’ H1 operating
performance reveals impact
of Covid-19
Several European utilities have
reported robust rst-half (H1)
operating prots but performance
has been dragged down by the
impact of Covid-19 on the second
quarter.
Page 2
USA to exploit up to 28 GW
of offshore wind by 2030
Up to 28 GW of offshore wind
power in US waters off of four states
could be auctioned for development
over the next two years.
Page 4
Pakistan moves to bring
down electricity costs
Pakistan is looking to reform its
power sector while calling on the
private sector in an effort to lower
the cost of generation.
Page 5
UK nuclear plans unclear
Indecision is hanging over the
UK’s plans for nuclear power
development, as uncertainty shrouds
the future of the Wylfa Newydd and
Bradwell power stations.
Page 6
Egypt cancelling solar power
projects as demand falls
In a surprising move that is likely
to have consequences in a post-
pandemic recovery, Egypt is
cancelling plans for the installation
of several solar power projects.
Page 7
Rolls-Royce remains
cautiously optimistic
With signs of a recovery in some
markets, Rolls-Royce is cautiously
optimistic about its outlook, despite
being severely impacted by the
Covid-19 pandemic.
Page 8
Meeting the challenge of
integrating renewables
Assessing the technologies to
make renewables integration as
environmentally-friendly and
efcient as possible.
Page 12
Technology Focus: Really
cool storage
Liquid air energy storage, a large-
scale form of long duration storage
that some call “pumped hydro in
a box”, is preparing for the rst
commercial project.
Page 15
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With falling oil prices and the pressure to meet emissions targets, oil and gas majors are
accelerating the move to renewable energy and lowering their carbon footprints. Junior Isles
UK offshore wind prices soon to undercut
fossil generation
THE ENERGY INDUSTRY
TIMES
Final Word
Making a star can be
problematic, says
Junior Isles.
Page 16
The shock to the global economy and
energy markets from Covid-19, which
saw a massive fall in oil prices, has
caused several international oil and gas
majors to rethink their future energy
strategy.
In August, BP announced that it will
need to invest tens of billions of dol-
lars over the next decade and may
have to accept lower returns than it
can get from oil if it is to meet its target
of becoming one of the world’s largest
renewable power generators. The oil
and gas company wants 50 GW of re-
newables such as wind, solar and hy-
dropower in its portfolio by 2030, up
from just 2.5 GW now
In a strategy update on its 2050 net
zero ambition, BP said it would cut
its oil and gas output by 40 per cent
by 2030 and spend $5 billion a year
on low carbon projects. It is also
planning to sell oil and gas assets that
would not be economically viable
with lower oil prices to raise $25 bil-
lion by 2025 to help fund its transi-
tion to cleaner energy.
It said in statement: “Within 10
years, BP aims to have increased its
annual low carbon investment 10-
fold to around $5 billion a year, build-
ing out an integrated portfolio of low
carbon technologies, including renew-
ables, bioenergy and early positions in
hydrogen and CCUS. By 2030, BP
aims to have developed around 50 GW
of net renewable generating capacity
a 20-fold increase from 2019 – and
to have doubled its consumer interac-
tions to 20 million a day.
“Over the same period, BP’s oil and
gas production is expected to reduce
by at least one million barrels of oil
equivalent a day, or 40 per cent, from
2019 levels. Its remaining hydrocar-
bon portfolio is expected to be more
cost and carbon resilient.”
European oil majors are under
pressure from activists, banks, inves-
tors and some governments to shift
away from fossil fuels and are trying to
nd business models that offer higher
margins than the sole production of
renewable energy would generate.
Analysts say large offshore wind
farms probably offer the quickest
route for BP to scale up but as they can
take years to develop, and have high
start-up costs, it may have to turn to
acquisitions. With renewable power
companies trading at high price-to-
earnings ratios, analysts say BP could
Continued on Page 2
A dramatic drop in the cost of offshore
wind power could soon see electric-
ity from offshore wind projects in the
UK being cheaper than fossil fuelled
generation. Coupled with a slight rise
in wholesale power prices, rapidly
falling costs could mean the newest
wind farms coming online in the UK
will soon operate with negative sub-
sidies, nds new analysis.
According to recent research by Im-
perial College London, published in
the journal Nature Energy, record low
prices of around £40/MWh agreed in
contracts last year combined with ex-
pected electricity price rises mean that
UK offshore wind providers will
likely start passing on those gains to
consumers in reduced energy bills by
2023.
Lead researcher Dr Malte Jansen,
from the Centre for Environmental
Policy at Imperial, said: “Offshore
wind power will soon be so cheap to
produce that it will undercut fossil-
fuelled power stations and may be the
cheapest form of energy for the UK.
Energy subsidies used to push up en-
ergy bills, but within a few years,
cheap renewable energy will see them
brought down for the rst time. This
is an astonishing development.”
The analysis examined the future
electricity price trends and found that
from the mid-2020s onwards, the con-
tracted prices were likely to be below
the UK wholesale price over the life-
time the latest wind farms would pro-
duce electricity.
Dr Iain Staffell, from the Centre for
Environmental Policy at Imperial,
said: “The price of offshore wind
power has plummeted in only a mat-
ter of a decade, surprising many in
the eld. The UK auctions in Sep-
tember 2019 gave prices that were
around a third lower than those of the
last round in 2017, and two-thirds
lower than we saw in 2015. This
amazing progress has been made
possible by new technology, econo-
mies of scale and efcient supply
chains around the North Sea, but also
by a decade of concerted policymak-
ing designed to reduce the risk for
investing in offshore wind, which
has made nancing these huge bil-
lion-pound projects much cheaper.”
Researchers found decreasing costs
when looking at a series of govern-
ment auctions for offshore wind farms
between February 2015 and Septem-
ber in the UK, Germany, the Nether-
lands, Belgium and Denmark.
The rapid fall in the cost of offshore
wind has seen a dramatic rise in the
demand for projects worldwide. New
research published in late July by Re-
newableUK shows the global pipeline
of offshore wind power projects
which are either operational, under
construction, consented or being
planned, has soared by 30 per cent in
the last twelve months from 122 GW
to 159 GW.
Its latest ‘Offshore Wind Project
Intelligence’ report shows that the UK
has retained its top spot, dominating
the market with a pipeline of 38.9 – a
quarter of the global total. China has
moved up from 4th to 2nd place with
19.3 GWan increase of 7.3 GW, up
60 per cent.
The USA stays in 3rd place, up from
15.7 GW to 17.8 GW, an increase of
13 per cent, while Germany has
dropped from 2nd to 4th place as its
total of 16.5 GW has remained almost
the same over the last 12 months, add-
ing just 68 MW. Taiwan stays 5th with
its project pipeline growing by 28 per
cent from 8.9 GW to 11.4 GW.
Oil majors ramp
Oil majors ramp
up shift to low
up shift to low
carbon energy
carbon energy
BP Chief Executive Bernard Looney: aiming for 50 GW of renewables by 2030
THE ENERGY INDUSTRY TIMES - SEPTEMBER 2020
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THE ENERGY INDUSTRY TIMES - SEPTEMBER 2020
7
International News
Between now and 2030, over 205 GW
of new offshore wind capacity will be
added globally, as a result of policy
ambition, declining technology costs,
and international commitments to de-
carbonisation.
In August, GWEC Market Intelli-
gence predicted that, despite the im-
pacts of the Covid-19 crisis, around 6.6
GW of offshore wind will be installed
in 2020. Currently, around 29 GW is
installed worldwide, with 6.1 GW of
new capacity installed during 2019.
It is also highly likely that offshore
wind will be a major contributor to post-
Covid economic recovery, said GWEC
as several governments are planning
major efforts in the offshore market.
Europe is currently the leading region
for installations, but the Asia-Pacic
region looks set to show a tremendous
increase in demand for offshore wind.
China will become the global leader in
new capacity, with Taiwan, Vietnam,
Japan, and South Korea also set to be-
come major markets, accelerating in
installed capacity to 2030.
China is expected to have 52 GW of
new offshore wind capacity installed
by 2030. Taiwan will be the second
largest offshore wind market, with a
goal of 5.5 GW by 2025, and an ad-
ditional 10 GW by 2035. Vietnam,
Japan, and South Korea are expected
to install 5.2 GW, 7.2 GW, and 12 GW
of offshore wind capacity, respec-
tively. North America currently has
just 30 MW of offshore wind capacity
in operation, but installation and de-
ployment will accelerate, with 23 GW
forecast to be installed by 2023.
Notably, oating offshore wind will
reach full commercialisation by 2030,
with at least 6 GW installed globally.
Turbine technology will improve in
both efciency and resilience.
Feng Zhao, Strategy Director for
GWEC, said: “The industry’s outlook
has grown more promising as more
countries are waking up to the im-
mense potential of offshore wind. In-
novations in the sector such as oating
offshore wind, larger and more ef-
cient turbines, as well as power-to-X
solutions, will continue to open new
doors and markets for the sector and
place the offshore industry in an in-
creasingly better position to drive the
global energy transition. Offshore
wind has already proven itself as an
affordable, scalable, zero-carbon
technology. We are only beginning to
unlock the full clean energy potential
of offshore wind.”
GWEC predicted that the top ve
markets for offshore wind installa-
tions in 2030 would be: China (58.8
GW); UK (40.3 GW); USA (22.6
GW); Germany (20 GW); and the
Netherlands (11.4 GW).
Policy ambition and falling cost
drive offshore wind
South Africa will continue to face load
shedding problems for the foreseeable
future as it struggles to replace and
upgrade its aged generation infra-
structure. The country has been strug-
gling with rotating blackouts for some
years, as debt-laden Eskom deals with
years of maintenance neglect at old
plant.
At the time of writing, despite a drop
in demand due to Covid-19, Eskom
had implemented three rounds of load
shedding since the Covid-19 outbreak
in early March. The latest round was
the result of breakdowns at four gen-
erating units, combined with a delay
to the expected return to service of
another unit under maintenance.
Eskom says it implements load shed-
ding as a last resort to prevent the
national grid from a total collapse and
urged South Africans to help reduce
electricity usage. Andre de Ruyter,
CEO of Eskom, said that load shed-
ding was likely to continue until Sep-
tember 2021.
To help with the post Covid-19 re-
covery, Eskom has oated a tender for
a battery energy storage system
(BESS) with a minimum 80 MW/320
MWh usable capacity at the Skaapvlei
substation, near the 100 MW Sere
Wind farm. Eligible bidders have
seven months (extendible to a maxi-
mum of nine months) to submit bids.
Eskom said in a statement: “We have
received nancing for the project from
the World Bank, as well as the African
Development Bank and New Devel-
opment Bank. The Skaapvlei project
represents Eskom’s rst large-scale
BESS project.”
The plan is seen as part of plans to
diversify the country’s energy mix in
a move away from coal, which is used
for about 85 per cent of the country’s
power generation. Eskom is speci-
cally considering green funding to
offset debt and to re-purpose coal
plants.
No end in sight for load shedding, says Eskom
Offshore wind capacity will increase to over 234 GW by 2030 despite the slowdown caused by the global Covid-19
pandemic. David Flin
In a surprising move that is likely to
have consequences in a post-pandem-
ic recovery, Egypt is cancelling plans
for the installation of several solar
power projects. It says the cancella-
tions are due to falling power demand
resulting from actions taken to reduce
the impacts of Covid-19.
In July plans for a 200 MW solar
park due to be installed in Egypt’s west
Nile area were cancelled by the Egyp-
tian Electricity Transmission Com-
pany (EETC). It cited falling power
demand as the reason for the cancel-
lation. EETC has also cancelled a
tender for a 100 MW concentrated
solar power (CSP) project in the same
region.
EETC said that Egypt has achieved
a surplus of capacity in the grid follow-
ing the completion of a number of
thermal and renewable energy projects
over the last three years.
Egypt had been planning to develop
a mix of solar, CSP and wind power in
the west of Nile area, with bids rst
requested in September 2015. This
drive came as a result of political unrest
resulting from, among other things,
power shortages and outages in 2014.
At present, with demand depressed
by Covid-19, the west of Nile region
has a generating surplus. However,
prior to the pandemic, power demand
was rising, with GDP growth consis-
tently above 5 per cent.
Egypt set targets for renewable en-
ergy to contribute 20 per cent and 42
per cent of total energy produced by
2022 and 2035, respectively. Achiev-
ing these targets will require contin-
ual efforts to develop renewable
schemes. Signicant progress had
been made, but this looks to be in
danger of stalling.
However, wind projects are still be-
ing developed in Egypt. Egypt’s New
and Renewable Energy Authority
(NREA) and a consortium led by Ves-
tas have signed an agreement to de-
velop a 250 MW wind project in the
Gulf of Suez, costing $270 million. The
wind farm should be operational by
August 2023.
As demand for solar power rises, Tur-
key will move from being a net im-
porter of solar panels to a net exporter.
The country plans to boost its wind and
solar capacity by 10 000 MW each year
over the coming decade, as well as
becoming a net exporter of solar pan-
els.
The rst step in this process was car-
ried out when it opened its rst inte-
grated solar panel facility in Ankara’s
Baskent Organised Industrial Zone on
19 August 2020. The $400 million So-
lar Technologies Factory was built by
Kalyon Holding. The plant will manu-
facture ingot, wafer, module, and cell
units with a capacity of 500 MW per
year.
Fatih Dönmez, Turkey’s Energy and
Natural Resources Minister, said: “Our
factory, which came to life with an
investment of $400 million, will be the
world’s only fully-integrated solar
panel plant operating under one roof.”
He added that following the commis-
sioning of the plant, the share of solar
energy in electricity production in Tur-
key will increase by 25 per cent. He
emphasized that solar power was going
to be an area of major growth, and that
Turkey needed to be in the forefront of
manufacturing panels.
Egypt cancelling solar
power projects as demand
falls
Turkey to export solar panels
Battery rms
Battery rms
to quadruple
to quadruple
output
output
Global lithium-ion cell manufacturing
capacity will quadruple to 1.3 TWh by
2030, with China doubling pipeline
capacity during this period.
Accordiing to a recent report from
Wood Mackenzie, there are currently
119 battery manufacturing facilities
that are operational, under constuction,
or announced, with over 50 vendors.
It says the growth is being driven by a
demand for energy storage to balance
out uctuations in supply from vari-
able renewable supply.
Mitalee Gupta, Senior Analyst with
Wood Mackenzie, said: “Manufactur-
ing capacity in Asia Pacic accounts
for 80 per cent of global capacity
pipeline. The region will remain as
the leader of lithium-ion battery pro-
duction for the next decade. Within
Asia-Pacic, China dominates the
pipeline capacity and is expected to
double its capacity from 345 GWh in
2020 to over 800 GWh by 2030. In
addition to local vendors’ rapid ex-
pansion in China, foreign manufac-
turers such as LG Chem, Samsung
SDI and SK Innovation have also been
adding new lines after they became
eligible for subsidies from the Chi-
nese government in 2019.”
Europe will increase capacity sig-
nicantly over the next decade, reach-
ing 25 per cent of global pipeline
capacity in 2030, up from 7 per cent
currently. Asian manufacturers are
investing heavily in new plants in
Europe: CATLs Erfut Plant, LG
Chem’s Wroclaw Plant, and Samsung
SDI’s Goed Plant. In addition, local
manufacturers such as Northvolt and
ACC have put forward ambitious
plans to scale up production in
Europe.
Hydrogen gains momentum as Europe
makes serious plans for implementation
Turkey discovers gas in Black Sea but
challenges remain
Gary Lakes
There are plenty of skeptics and hy-
drocarbon industry diehards, but hy-
drogen is a hot word in energy circles
as the world plans an economic re-
bound from the consequences of
Covid-19.
Over the course of 2020, the focus of
concern has not only been about im-
proving the health of the human popu-
lation, but improving the health of
Planet Earth as well, and this has
brought much discussion on the pluses
of moving away from carbon and im-
plementing a hydrogen economy.
The energy transition as currently
planned may not happen as quickly as
many would like, but the European
Commission in July adopted a hydro-
gen strategy for a carbon neutral Eu-
rope by 2050. Hydrogen is the most
abundant element in the universe and
once harnessed and produced in large
quantities, it will be applied to trans-
port, industry, power generation and
other sectors of human activity.
In the paper outlining its hydrogen
programme, the EC noted that only
small amounts of hydrogen are cur-
rently produced, and that is made by
using coal and natural gas as feedstock
for the electricity needed for the elec-
trolysis process, which according to the
EC, results in the production of 70-100
tons of CO
2
emissions annually.
“For hydrogen to contribute to cli-
mate neutrality, it needs to achieve a
far larger scale and its production must
become fully decarbonised,” the EC
paper states, and it pointed out that the
list of planned global investment in
hydrogen production projects is
growing on a weekly basis and the
number of companies joining the In-
ternational Hydrogen Council is
steadily increasing.
The European Union is expected to
invest between €180 billion to €470
billion in hydrogen by 2050.
This summer Germany announced a
€9 billion investment in a National
Hydrogen Strategy and the UK
launched the Hydrogen TaskForce.
Meanwhile, Russia is also looking at
investment in hydrogen to meet future
European market demand.
Germany plans to have 5 GW of
hydrogen production capacity by
2030 and another 5 GW added to this
by 2040. The programme is part of a
€130 billion stimulus designed to con-
tribute to economic recovery from the
coronavirus pandemic. The invest-
ment in hydrogen production is part
of €40 billion marked for climate-
related spending and could result in
providing hydrogen to produce 10 per
cent of Germany’s total electricity
capacity.
The technical methods of producing
hydrogen are colour-coded: brown
and grey hydrogen come from hydro-
gen that is produced by coal and
natural gas. These produce about 95
per cent of the world’s hydrogen. Blue
hydrogen is produced from natural
gas, using carbon capture and storage
(CCS) to capture and store the CO
2
.
Green hydrogen is produced by re-
newable energy sources and emits no
carbon during production. The pro-
cess separates hydrogen from water
using electrolysis and ultimately is the
stage that the world wants to reach.
Germany is looking to accelerate
green hydrogen production but the
technology requires a huge ramp-up
in wind and solar energy output. Once
renewable energy production is sol-
idly established and widespread,
green hydrogen will be available for
power stations, heavy industry and to
replace fossil fuels for home heating
and transportation.
The UK’s Hydrogen Taskforce an-
ticipates the release of a government
hydrogen strategy in 2021 in which
the production target for 2035 will be
125.3 TWh, 80 per cent of which will
be blue hydrogen and 20 per cent
green. The Taskforce further argues
that moving to hydrogen will not only
reduce carbon emissions but also
boost the economy through the cre-
ation of new jobs. It projects that by
2035 the UK’s hydrogen economy
will be worth £18 billion and create
75 000 jobs. Furthermore, it states that
much of the infrastructure currently
used in the natural gas industry can be
adapted to transport hydrogen and that
many jobs within the oil and gas in-
dustry can easily t into hydrogen
operations.
Russia’s Ministry of Energy an-
nounced in July that it will produce
‘clean’ hydrogen in 2024 by using
nuclear energy in a partnership be-
tween gas company Gazprom and
nuclear energy rm Rosatom. Gaz-
prom has forecast that the EU hydrogen
market will be worth €153 billion by
2050 and wants to participate in sup-
plying the new fuel. The company has
suggested that it will be able to supply
a gas mixture containing 70 per cent
hydrogen to Germany using the yet to
be completed Nord Stream 2 pipeline.
Russian sources report that the coun-
try wants to be capable of supplying
15 per cent of global hydrogen produc-
tion by 2035 by using its huge hydro-
carbon resources as a bridging technol-
ogy for hydrogen production.
Gary Lakes
The Republic of Turkey on August 21
announced the discovery of a natural
gas resource in the Black Sea and es-
timated its size at around 320 billion
cubic metres (around 12 trillion cubic
feet). The discovery, located near the
exclusive economic zones (EEZs) of
Bulgaria and Romania, is signicant
for Turkey, which until now has had
no sizeable oil or gas discoveries in
its territory.
The discovery at the Tuna-1 well, if
developed, could have an important
impact for the Turkish economy, which
relies on energy imports. Turkey uses
45-50 bcm annually of natural gas,
virtually all of which is imported from
Russia, Iran and Azerbaijan. The coun-
try imports LNG from Algeria and
Nigeria, and with the price of LNG
currently low on the global market, it
has been importing LNG from the spot
market through four Floating Storage
Regasication Units (FSRUs) in-
stalled at various locations along its
coast. Gas imports last year cost Turkey
some $40 billion.
Turkish President Recep Tayyip Er-
dogan announced the gas discovery
on Turkish TV signifying the impor-
tance of the discovery to Turkey, and
validating his efforts to push Turkish
Petroleum (TPAO) to discover any-
thing, anywhere.
Erdogan’s policy of encroaching on
the internationally recognised terri-
tory of littoral countries in the East
Mediterranean has seriously ratcheted
up tensions with Greece, Cyprus,
Egypt and even Israel.
Turkey’s claim to a continental shelf
in the East Mediterranean and a ‘Blue
Homeland’ that includes half of the
Aegean Sea and vast expanses of the
Mediterranean as far as the coastlines
of the Greek islands of Rhodes and
Crete, and to the edge of Libyan ter-
ritorial waters has led to diplomatic
alarm within the European Union and
with France in particular.
Turkey has long claimed most of the
Cypriot EEZ and frequently interfered
with exploration efforts there by
France’s Total and Italy’s Eni. Turkish
drillships, including the Fatih, which
made the Tuna-1 discovery, drilled
several wells in the Cypriot EEZ over
the last year and currently the Yavuz
drillship and a seismic vessel are in the
area.
Turkey stated recently that it will
send its third drillship into the East
Mediterranean soon, but has not said
where. If the ship should enter Greek
territory, then tensions are expected
to reach a tipping point. The EU has
already warned Ankara to remove its
ships from Greek and Cypriot waters,
but Turkey has chosen to ignore the
warning.
Gloating over the gas discovery,
which has been renamed ‘Sakarya’,
Erdogan said that Turkey hoped to
bring the resources into development
by 2023, the centennial of the found-
ing of the Turkish Republic. Erdogan
called it an “historic day” saying:
“Turkey has made its biggest natural
gas discovery,” adding that it gives
Turkey a “new era.”
Certainly, once the gas is owing
it will contribute signicantly to
Turkey’s energy security, but it will
not solve all the country’s problems.
Some in Turkey have already fallen
into the gas dreams scenario that a new
discovery often conjured up. Turkish
Finance Minister Berat Albayrak, Er-
dogan’s son-in-law, called it a nan-
cial game changer. “It will remove the
current account decit,” he said. “We
will be soon talking about current ac-
count surpluses.”
Bringing the eld on-stream will
require many more appraisal and de-
velopment wells and billions of dol-
lars in investment. Also, the deep-
water environment will pose
challenges of its own. It is unclear if
TPAO actually has the expertise to
bring a project like this into operation,
since it has not done this before, and
will likely require a partner. Consider-
ing the fact that a huge market for the
gas is already there in Turkey, a part-
ner or two might not be hard to nd.
But with gas prices so low amid
global oversupply, it may be some
time before developing the eld
would be worth the investment. Some
analysts have said that it could take
seven to 10 years to develop the eld.
In the region, only two reservoirs have
been fast-tracked: the Tamar eld off-
shore Israel and the giant Zohr eld
offshore Egypt. In both cases it was
because the countries were in dire
need of gas supplies.
One thing is certain, Turkey will con-
tinue its neo-Ottoman approach to gas
exploration in the East Mediterranean,
where most exploration – with the ex-
ception of Turkey – has stopped due to
the coronavirus pandemic.
However, Total and Eni, which in
partnership hold seven licenses in the
Cyprus EEZ, are due to resume drill-
ing some time in 2021. So too will
ExxonMobil, which holds the license
to Cyprus Block 12, where in January
2019 it announced the Glaucos-1 dis-
covery. Chevron Corp in July pur-
chased Noble Energy, which includes
Israel’s 22 tcf Leviathan eld and
Cyprus’s 4.5 tcf Aphrodite eld.
Those companies cannot be ex-
pected to be held at bay by Turkey
forever.
Hydrogen
Gas
For hydrogen to contribute to climate neutrality, it needs to achieve a far larger scale and its production
must become fully decarbonised but the list of planned global investment in projects is growing on a
weekly basis.
The huge natural gas discovery at the Tuna-1 well could have a massive impact for the Turkish economy
but the investment that will be needed, combined with political tension in the region, means it could be some
time before it reaps the potential rewards.
THE ENERGY INDUSTRY TIMES - SEPTEMBER 2020
11
Fuel Watch
THE ENERGY INDUSTRY TIMES - SEPTEMBER 2020
12
Industry Perspective
A
s more renewable power
sources join to gradually re-
place carbon-based energy,
we need to ensure our grids remain
resilient and become more exible
as they adapt to fast-changing de-
mands and increasing decentralisa-
tion. While the growth of renewable
energy must be celebrated, there’s no
denying it will add to the challenges
of managing what is mostly a legacy
grid and will therefore require some
changes in how power is transmitted
and distributed in the future.
The challenges faced by grid oper-
ators vary depending on if the re-
newable power enters the grid at the
distribution or the transmission level.
The big offshore wind farms are usu-
ally integrated at the transmission
level with a single point connection,
meaning there is less redundancy in
the setup with potentially a long con-
nection line in between load centres.
Onshore wind farms are in the range
of hundreds of megawatts so they
can connect in the distribution grid
where the controllability is not en-
sured; it is a stochastic uctuation of
the loads that makes ensuring stabili-
ty a challenge.
The interconnected continental sys-
tem is well matched during regular
operations. When you have a weak-
ened operation because of line out-
ages or splits of the system, it can
potentially be a big challenge and
with increased renewables will be al-
most unmanageable in the future.
With the digital transformation
having a positive impact on the
power sector, as it is throughout the
rest of the industrial world, there
are numerous technology solutions
available. These include high volt-
age direct current (HVDC), thyris-
tor-controlled series compensation
(TCSC), phase-shifting transform-
ers (PST), distributed series com-
pensation and even unied power
ow controllers (UPFC); with the
best solution being dependent on
each particular challenge.
The PST is well established in the
continental system, particularly
around the Benelux regions where
they need to cope with the high
power ows from north to south.
They are inexpensive compared to
other options, but they are only suit-
able for steady-state control. If you
go more into dynamic response of
the grid where you require a re-
sponse in under a second, then they
are not sufcient. In those instanc-
es, you need series compensation of
lines with TCSC or UPFC; howev-
er, market acceptance of the latter
solution is not high. When it comes
to UPFC, there is no market for this
kind of innovation in the European
system, so you will not nd it in-
stalled anywhere.
At the same time, TCSC is not the
answer when it comes to managing
an increased load of renewable ener-
gy to the grid. Instead, it is a method
of optimising what is already avail-
able, with lower gains. For the com-
ing years, we need to build up capac-
ity in the grid.
The HVDC option, pioneered by
Hitachi ABB Power Grids, is more
attractive because it allows you to
introduce new lines that are more
controllable and will increase the
transfer capacity. It is also the most
environmentally-friendly technology
as it can provide more power per
square metre over greater distances
with lower losses, meaning that
more power reaches the consumer
more efciently. Another signicant
advantage is that you can modulate
the active power transmitted.
What we see as a big market for
HVDC is the integration of offshore
wind, a role that it is already lling.
The next step will be to combine in-
terconnections and offshore wind
connections with building up con-
necting networks such as the UK to
the Continental system or Scandina-
via. This will be the next growth area
for HVDC as hybrid interconnectors
or multi-purpose systems.
The biggest drawback for HVDC
lines, as is also true for AC lines,
particularly onshore, is the lengthy
planning processes with the associat-
ed environmental concerns and pub-
lic opposition involved in getting
new lines constructed. This can
sometimes be mitigated by clever
routing. For example, the connection
between Italy and France runs in
parallel with a motorway. However,
the distances involved there are short
compared to the north-south corridor
required in Germany. The systems
and procedures for planning are
there in Europe in its Ten Year Net-
work Development Plan, but it takes
a long time to build up this new in-
frastructure. When you work within
an existing substation, you do not
have all these issues, but when you
want to touch a line or build up a
new line, it can be a lengthy process.
Theoretically, you can transform an
existing overhead line for use with
HVDC; there is one reference case
within Europe which is now in exe-
cution. The problem, however, is the
reason to do this is to increase capac-
ity on a line that is fully loaded but
to carry out this work you have to
cease operation for some time. The
challenge is how to schedule that
within the operational constraints
that you may have.
There was a push in 2016 with a
so-called network code for HVDC
from the European Commission. The
Network Code on HVDC species
requirements for long-distance direct
current (DC) connections. The idea
behind that network code was to har-
monise their requirements for
HVDC systems, no matter what
country they are connecting, promot-
ing interconnections. Unfortunately,
what we could see afterwards was
that during national implementation
these codes diverged again. This is
increasing the risk for the technology
moving ahead with multi-terminal
systems or even HVDC for offshore
wind connection. Grid codes must be
developed soon to close this gap.
A good example of the benets of
HVDC is in the Baltic Sea. The 600
MW Danish Kriegers Flak offshore
wind farm, which comes online in
2022, will consist of two parts: the
western Kriegers Flak A (KFA) with
a total capacity of 200 MW and the
eastern Kriegers Flak B (KFB) with
a total capacity of 400 MW.
The Kriegers Flak combined grid
solution project will connect the
Danish region of Zealand with the
German state of Mecklenburg-West-
ern Pomerania via two offshore
windfarms – German Baltic 2 and
Danish Kriegers Flak. It is an inno-
vation in the context of the energy
transition, as it is the world’s rst
project combining grid connections
to offshore wind farms with an inter-
connector between two countries.
The interconnector will allow
electricity to be traded in both direc-
tions – from Denmark to Germany
and from Germany to Denmark. En-
erginet is currently building the grid
connection of the future Kriegers
Flak offshore wind farm (600 MW).
The Kriegers Flak (Denmark) and
Baltic 2 (Germany) wind farms are
less than 30 km apart, and both wind
farms are linked through two sea ca-
bles with a transmission capacity of
400 MW, forming the interconnector.
The frequencies of the Danish and
German transmission systems use a
slightly different phase, which
means they need to be matched at
the interface. This will be enabled by
two serially connected voltage
source converters (VSC). One con-
verter transforms the alternating cur-
rent (AC) from the Nordic intercon-
nected system to direct current (DC).
The other converter transforms this
direct current back to alternating cur-
rent – only now adapted to the Con-
tinental Europe Synchronous Area.
This so-called back-to-back convert-
er will be installed in Bentwisch,
near Rostock in Germany.
With the provision of reactive pow-
er, you can also make sure that you
have voltage support at the point of
connections. However, this is a bit
limited because the further away you
get from the node the HVDC con-
verter is connected, the less effective
such reactive support is. Overall, we
believe that the setup in the future
for maximum renewables integration
is going to be a combination of
HVDC, TCSC for optimised line
loading, Static Synchronous Com-
pensators (Statcoms) for voltage
control, and PSTs for steady state
optimisation of power ows.
In terms of the next challenges, it is
about managing the longer power
ows. The market will become more
volatile with more renewables,
which is where HVDC came into its
own from the beginning. HVDC
plays a crucial role in the transition
to a stronger, smarter and greener
grid powered by renewable energy
sources, which typically require long
distance transmission. It is particu-
larly effective, for example, for
bringing wind power from remote
offshore wind farms to mainland
grids. With WindEurope estimating
that Europe’s offshore wind capacity
will reach 450 GW by 2050, HVDC
technology will be instrumental in
efforts to keep the extent of global
warming below 1.5°C.
Andreas Berthou is Global Head of
HVDC of Grid Integration business,
Hitachi ABB Power Grids.
Meeting the challenge of
Meeting the challenge of
integrating renewables
integrating renewables
Berthou: The challenges
faced by grid operators
vary depending on if the
renewable power enters the
grid at the distribution or the
transmission level
With the increasingly urgent drive to decarbonise the power system, renewable energy will play an ever expanding
role. However, we need to ensure that the renewables integration is as environmentally-friendly and efcient as
possible in order to full our vision of ensuring affordable and clean energy, sustainable living and a world t for all our
next generations. Andreas Berthou
THE ENERGY INDUSTRY TIMES - SEPTEMBER 2020
13
Energy Outlook
T
he coronavirus pandemic has
been a hard time for everyone
across the globe, and as things
begin to return to a new state of
‘normal’, there are some lessons we
should take from our time in lock-
down. Because of the restricted
movement, shutting down of build-
ings and remote working policies
forcing most of us to stay within the
connements of our own homes, our
carbon emissions have rapidly de-
pleted. In fact, the UK reached the
milestone of not having used coal-
powered electricity for two whole
months for the rst time in 140 years
during the lockdown.
Statistics already suggest that as re-
strictions are easing, and the popula-
tion is beginning to get back to nor-
mality, carbon emissions are rising
once again. Although it’s been re-
ported that they’re 5 per cent lower
than they were during the same time
in 2019, the rapid return of such high
levels of carbon emissions is ex-
tremely worrying. If the government
is to reach its target of zero carbon
emissions in the next 30 years, there
is still some way to go.
While the move away from coal
represents good progress in reducing
carbon emissions from the power
sector, renewable sources still only
account for around 20 per cent of our
electricity generation. And similar
progress in other energy-intensive
sectors such as industry, transport
and heat remain, as yet, elusive. This
brings about the questions of what
exactly our future energy systems
look like? How will we continue to
provide easy access to affordable en-
ergy, and avoid the causes of climate
change? This is where green ammo-
nia comes in, offering a low cost,
carbon free solution to help battle
the global ght against climate
change.
Some of the most popular and
well-known renewable power sourc-
es offer carbon-free energy, but the
problem is their intermittency. We
can’t control when the sun shines, or
when the wind blows – yet we want
(and are used to) the freedom to
choose when we use this energy.
Recent analysis from the Depart-
ment for Business, Energy and In-
dustrial Strategy shows that in 2019,
37 per cent of the UK’s electricity
generation came from renewable
sources such as wind turbines and
solar, four percentage points higher
than 2018. However, this is still not
enough to reach net zero using re-
newables alone, so a reliable storage
technique is needed.
Energy storage is often presented
as the solution to this intermittency
problem, but the challenge is to store
energy in sufcient quantities and
at low enough costs – to meet our
needs which are growing all the
time. Energy is, of course, already
stored in vast quantities today – it is
just that the energy stores we are
used to come in the form of fossil fu-
els such as oil (and its derivatives)
and natural gas. These chemical en-
ergy vectors are ubiquitous for a rea-
son – carbon-based fuels are stable,
energy dense, and are easy to store
and transport.
The issue lies with the CO
2
emitted
when we burn them. So, what if
there was an alternative? What if we
could synthesise a carbon-free fuel
using renewable energy, which could
be used to store and transport that
energy in bulk, without the carbon
emissions associated with its fossil-
based counterparts?
Ammonia (NH
3
) is a promising
candidate for just such a carbon-
free, synthetic fuel. An ammonia
molecule is made up of one nitro-
gen atom and three hydrogen atoms
– in some ways similar to natural
gas (methane, CH
4
) which has one
carbon atom plus four hydrogen at-
oms – and can be synthesised from
abundant raw materials, namely air
and water.
Nitrogen comprises 78 per cent of
the atmosphere, and may be readily
separated out from air; water may be
split back into its constituent ele-
ments via an electrochemical process
called electrolysis.
Once the hydrogen and nitrogen
are produced, they can be combined
in a reaction called the Haber-Bosch
process to produce ammonia. If re-
newable energy is used to power
these processes, then that energy be-
comes locked up in the ammonia
molecule, without any direct carbon
emissions.
The nal step, energy release from
this “green ammonia”, can be
achieved by cracking the ammonia
back into nitrogen and hydrogen,
and then using the hydrogen in a fuel
cell – such as in a fuel cell electric
vehicle. Another way is to use it in
combustion – in exactly the same
way as we burn carbon-based fuels
today – such as in a gas turbine, for
example.
In this way, green ammonia offers
the enticing prospect of reducing
carbon emissions not just in electri-
cal power generation, which has so
often been the limit of our current
best efforts to decarbonise, but also
other sectors such as transport and
industry.
By switching to renewable electric-
ity to make ammonia, it’s possible
that we could save more than 40 mil-
lion tonnes of CO
2
each year in Eu-
rope alone, or over 360 million
tonnes worldwide. With the govern-
ment’s continued commitments to
meet net zero emissions targets by
2050 and the recent announcement
that they are set to invest a further
£350 million to fuel green recovery,
new carbon free fuels such as green
ammonia and green hydrogen will
be needed to decarbonise energy
generation, heat and transport and
industry.
The latest government announce-
ment, and the clarication that £139
million of that budget will be spent
on cutting emissions in heavy indus-
try by supporting the transition from
natural gas to clean hydrogen power
is denitely a step in the right direc-
tion. But the pace of change is still
slow for a solution that is readily
available.
Siemens has shown this process is
possible at the Rutherford Appleton
Laboratory in Oxfordshire, where,
with the Science and Technologies
Facilities Council, the University of
Oxford and Cardiff University, it de-
veloped the world’s rst Green Am-
monia Demonstrator.
The beauty of this is that the tech-
nology required to begin to imple-
ment and use green ammonia al-
ready exists. Industrial air separation
processes to produce nitrogen are
routine; water electrolysis was per-
formed on an industrial basis before
steam methane reforming became a
cheaper source of hydrogen.
Fritz Haber won his Nobel Prize
“for the synthesis of ammonia from
its elements” in 1918, and today the
Haber-Bosch process accounts for
180 million tons of ammonia pro-
duction each year. The infrastructure
required to store and transport it
safely is already widespread and
would make the transition to using
renewable energy sources simpler,
quicker and cheaper than previously
predicted. Green ammonia has the
opportunity to play a vital part in a
future, low-carbon energy system.
Understandably, the pandemic has
meant we are not dealing with “busi-
ness as usual” and it’s right that the
government’s time is dedicated to
this unprecedented issue, especially
as it doesn’t look like it’ll be going
away anytime soon. However, the
need for a climate strategy that is
able to avert the risks of irrevocable
climate change aren’t changing and
cannot be pushed to the side. The so-
lution has already been found; it just
needs to be invested in.
Steve Scrimshaw is Vice President,
Siemens Energy UK&I.
Green ammonia
offers the prospect
of reducing carbon
emissions, not just
in electrical power
generation but also
other sectors such
as transport and
industry.
Steve Scrimshaw
Green ammonia: the answer to
a carbon free future?
Scrimshaw: the technology
required to begin to
implement and use green
ammonia already exists
Power-to-X city: synthesising
a carbon-free fuel using
renewable energy. © Siemens
Energy
Siemens Energy Green Ammonia demonstrator plant at the
Rutherford Appleton Laboratory, Oxfordshire, UK. Image courtesy
of the Science Technology Facilities Council
She added: “We account for factors
such as capacity retirements. We also
look at generation and consumption
patterns and broader factors, such as
GDP growth, that impact consump-
tion of energy over time, and of
course digital penetration. We look at
customer trends, behaviours and pain
points that can be addressed through
digital solutions.”
Rolling out digital solutions requires
an understanding of the utility’s needs
and emerging trends. For GE Digital,
this starts with the deep relationship it
has with the customer, as well as hav-
ing the expertise that comes with be-
ing a sister company to GE Power.
“Because we work with customers
as both an OEM and digital provider,
we understand the issues around reli-
ability, availability of equipment,
O&M costs, worker safety, mobility,
etc. These are all factors in which we
are deeply entrenched with our cus-
tomers,” said Rae.
“We help them understand what the
right scope and approach is for them.
In some instances, it’s a very small
pilot to get them started. In other
cases, some are able to take on a
whole plant or critical assets. We have
a team of experts that works with the
customer through the entire imple-
mentation process.
“We congure a software and ser-
vices portfolio that enables the digiti-
sation of those assets and the plant
operations to optimise the utilisation
and minimise risk.”
Through its long-term R&D invest-
ments and long history in the power
industry, GE Digital has developed a
broad library of digital twins and
equipment blueprints covering about
50 per cent of failure modes and
equipment sites today, and continues
to add to those libraries. “Our strategy
is to maximise the ROI for the cus-
tomer by leveraging the deep exper-
tise that we have,” said Rae.
Digitalisation is certainly proving
its worth in the current pandemic,
which has brought home the impor-
tance of remote operations.
Rae said: “Most of the customers
I’ve talked to during the pandemic
have been operating with skeletal
staff… the indispensability of digital
solutions to ensure business continu-
ity while working with a skeletal and
largely remote staff has been eye-
opening to our customer base and to
us.”
She says there has been a sharp up-
tick in demand for GE Digital’s Re-
mote Operations digital solution,
which allows plant operators to access
the plant and x issues in a remote
and secure manner.
But implementing digital solutions
does not come without its challenges.
According to Rae the biggest of these
is the change management that utili-
ties have to go through as they adapt
their business processes to take ad-
vantage of the digital solutions that
N
avigating the changing energy
landscape is no easy task. In a
world where access to electric-
ity is still not a given for more than a
billion of the world’s population, end-
ing ongoing energy poverty is still a
challenge. Renewables and distribut-
ed energy sources have a role to play
here. Renewables are also key to mak-
ing the all-important transition to a low
carbon economy.
The transition and the inexorable
rise of renewables, however, has seen
utilities and energy companies having
to develop new business models and
draw on new tools to ensure they
continue operating efciently while
delivering reliable, affordable and
cleaner electricity to consumers.
As a major technology partner to
energy companies around the world,
GE Digital sees digitalisation as an
integral part of making that shift.
Linda Rae is General Manager for
the Power Generation and Oil and
Gas businesses for GE Digital. Hav-
ing taken up the position in January
this year she is responsible for run-
ning a segment of the GE Digital
business that is seeing an increasing
reliance on digital solutions to meet
the demands of the industry.
She identied availability of elec-
tricity across the globe, integrating
renewables, and meeting global cli-
mate change targets as the top three
issues driving today’s power genera-
tion sector and outlined the impor-
tance of technology in addressing
those drivers.
Rae noted: “Many corporations
have committed to achieving net zero
emissions by 2050 or earlier. Trillions
of dollars have owed into low car-
bon technology since 2010. Solar and
wind are now quite competitive in
most markets but with the majority of
the world’s power still coming from
fossil fuels, getting to zero emissions
in 30 years is a tremendous challenge.
“It will require tremendous innova-
tion in renewables and in smart grids,
and we believe that digital will play
an important role in that trend.”
Digitalisation is taking place across
the entire power sector value chain –
from generation, through transmis-
sion and distribution, to consumption.
Highlighting some of the key areas,
Rae said: “On the generation side, we
have been working with customers to
help them stay protable in a com-
petitive environment. Many are em-
bracing digitalisation to drive opera-
tional excellence. Operation and
maintenance (O&M) cost reduction
continues to be a major imperative for
our generation customers, and soft-
ware-driven reliability and mainte-
nance is a principle means of driving
O&M costs down. This is not just for
critical assets but also for the balance-
of-plant; so it’s really enterprise-wide
leverage of digital tools and predic-
tive analytics to drive O&M costs
down.
“They’re also looking at opportuni-
ties for business process automation.
This all helps to avoid unforeseen
outages and enable smarter choices
about how to maintain and operate
their assets.”
The New York Power Authority
(NYPA) is America’s largest state
power organisation, with 16 generat-
ing facilities and more than 1400 cir-
cuit-miles of transmission lines. GE
Digital has partnered with NYPA to
enable an innovative energy infra-
structure to forecast and prevent
equipment failures and signicant
outages with its predictive analytics
software. Online remote monitoring
of power plants, substations and
power lines is increasing plant ef-
ciency and productivity, reducing
unplanned downtime, lowering
maintenance costs and minimising
operational risks.
Rae says capacity forecasting and
planning is another way in which
digitalisation is helping utilities.
“Today’s energy market is pretty
complicated; daily decisions have to
be made by generators about what
they will produce and during which
period of time. Digitalisation helps
them understand how they will deal
with trading surpluses and pricing
maximisation over time.”
And at the cutting-edge, GE Digital
says it is seeing greater digitalisation
in areas such as control technologies,
drones and augmented reality for re-
mote maintenance and operation.
This is something that has certainly
been seen more since the Covid-19
pandemic. “Digitalisation is a way for
them to maintain operations with re-
duced stafng in their facilities,” said
Rae.
In transmission and distribution,
most digitalisation efforts have been
in making grids smart to allow more
efcient transmission of electricity,
smart communications between utili-
ties and consumers, as well as in the
integration of renewables.
Rae said: “Digitalisation enables
smarter decisions about when renew-
ables are utilised versus more tradi-
tional sources of energy, as well as
how that energy is passed through the
grid to optimise supply and demand.
And on the consumption side, digital
capabilities help to ensure energy ef-
ciency at the end-point as well as
enabling a potential reduction in peak
load demand.”
With such benets, it’s clear why
digitalisation is big business and
continues to grow. According to 2020
research carried out by Harbor Re-
search, the total Industrial Analytics
Software & Services market (includ-
ing manufacturing & resources seg-
ments) will grow to more than $80
billion by 2025 at a 24 per cent
CAGR. “We expect Power Genera-
tion Software and services to grow to
$6.7 billion by 2025 at about 17 per
cent CAGR,” Rae said.
THE ENERGY INDUSTRY TIMES - SEPTEMBER 2020
Executive Interview
14
Energy companies face a number of challenges as they continue to reinvent themselves in response to the changing
energy landscape. Linda Rae, General Manager for the Power Generation and Oil & Gas businesses for GE Digital,
says digitalisation is the key. Junior Isles
Digital transitions
Digital transitions
they have adopted.
“There are years of entrenched
manual practices and ultimately we
are trying to automate those practices
and ways of doing business. This re-
quires a proactive approach to change
management and helping employees
get through that transition.”
As examples she cited: the chal-
lenges around gathering and under-
standing of data; making decisions
around capital allocation; and deci-
sions around risk versus cost.
“There are cultural challenges as
well as multi-generational challenges.
Many facilities have an older work-
force that aren’t as comfortable with
leveraging digital tools to make deci-
sions, juxtaposed with an inux of
millennials who are naturally tuned to
using digital. This can add to the cul-
tural challenge that customers are
facing.
“Also, the general shift from reac-
tive methods to condition-based
monitoring and maintenance can take
time for users to adapt to.”
Apart from the technology concerns
– the main one probably being cyber
security – Rae adds that a common
concern she hears, is “time to value”.
“It’s a fairly intense investment in
terms of resources and time and
money to undergo a digital transfor-
mation. So the question is always:
‘how do I know I will get the value to
justify this big investment?’ We help
customers understand how they can
shorten their time to value.”
The nal concern, she says, relates
to data – its availability, cleanliness
and the ongoing data maintenance
requirements. She assured, however:
“We work with them to help them
address all of these things.
“And of course we have a customer
success organisation that works with
customers throughout their subscrip-
tion to make sure they have ongoing
support and access to further expertise
and training if they need it. Our com-
mitment is to ensure customers get
the value they signed up for.”
Looking ahead, digitalisation will
no doubt grow as current trends con-
tinue to play-out, although a great
deal of policy and government inter-
vention work has to happen for sus-
tained progress.
Rae concluded: “The inux of re-
newables will continue to grow over
the next 10 years to the point that we
will see a fundamentally different
business model around producer and
consumer – the ‘prosumer – that will
dramatically change the whole energy
marketplace. The impact of decar-
bonisation will radically change the
sources of energy as well as the opti-
misation of capacity and efciency.
There will also be faster growth in
microgrids, more utilisation of data
over time, integration of data through-
out the entire value stream and ulti-
mately we will see a much more digi-
tally mature energy sector.”
Rae: Many corporations
have committed to achieving
net zero emissions by 2050
or earlier… It will require
tremendous innovation in
renewables and in smart grids,
and we believe that digital will
play an important role
THE ENERGY INDUSTRY TIMES - SEPTEMBER 2020
16
Final Word
W
e always tell our children:
“Never give up on your
dreams.” After all, human-
kind would not progress without the
stuff of dreams and the pioneers with
the unwavering determination to
chase them. But the art of balancing
pragmatism versus aspiration is a
tricky one.
Five years ago in an interview with
The Guardian newspaper Steven
Cowley, who was then leading the
UK’s participation in ITER (the Inter-
national Thermonuclear Experimental
Reactor) said the experimental fusion
reactor being built in Cadarache,
France, is “going to show that man can
make a star”.
As ambitions go, they don’t come
much bigger. Yet this incredible dream
took a big step towards reality with the
ofcial start of assembly of what has
been called “the world’s largest sci-
ence project”.
ITER (pronounced “eater”) – Latin
for “the way” – is an international
project with components coming from
35 partner countries. It will be the
world’s largest nuclear fusion device,
designed to show that fusion can
generate power sustainably, and
safely, on a commercial scale. Cru-
cially, it is intended to be the rst fusion
reactor to produce more power than it
consumes. ITER is meant to produce
about 500 MW of thermal power but
as an experimental project, it is not
designed to produce electricity.
John Smith, Director of magnetic
technology at General Atomics says it
will try “to run a fusion experiment for
several hundred seconds, which has
never been done at the power levels
talked about”. He added: “And then
most importantly, they’re going to
show what they call the ‘fusion gain’.
That’s where the power that it takes to
create the fusion reaction, they’ll actu-
ally get 10 times more power out of
the reaction than what they put in.”
Nuclear fusion has long been the holy
grail of energy production – almost
limitless power without any carbon
emissions and very little radioactive
waste. Yet, as with all holy grails, it
always seems to be just out of reach
– fusion has long been dubbed as a
technology that is “always 30 years
away”.
Fusion happens in our sun and every
star, where, under immense tempera-
ture and pressure the nuclei of hydro-
gen atoms, which are protons, fuse to
form a nucleus of helium, releasing
energy. But, due to the repulsive
forces between the protons, it is a
process that takes millions of years
before a star can be born.
To replicate the process on Earth,
scientists therefore usually use two
hydrogen isotopes instead – deuterium
and tritium – that contain one and two
extra neutrons in their nuclei, respec-
tively. Deuterium is abundant in sea-
water and tritium can be made by the
fusion reactor itself. By heating the
deuterium-tritium mixture to well
over 100°C million inside a ring-
shaped vessel, the two elements fuse
to form helium, energy and fast-
moving neutrons. The neutrons will be
absorbed by shielding around the reac-
tor vessel that contains lithium, and
the interaction will create more tritium.
There is a virtually limitless source
of fuel in the world’s oceans to feed
future nuclear fusion reactors. Accord-
ing to the project’s partners, “a pine-
apple-sized amount of fuel is the
equivalent of 10 000 tons of coal”. And
though the process produces some
radioactive waste products, they all
have short half-lives and will become
inert within a few hundred years, as
opposed to the thousands of years for
the radioactive waste from today’s
ssion reactors.
In a statement, the partners said:
“Fusion is safe, with minute amounts
of fuel and no physical possibility of
a run-away accident with meltdown”
as with traditional nuclear power
stations.
At ITER a doughnut-shaped cham-
ber called a Tokamak will heat the
hydrogen mixture until it becomes a
cloud-like ionized plasma, which is
then shaped and controlled by super-
conducting magnets. These magnets
create an overlapping set of elds that
keep the electrically charged gas in-
side from touching the sides of the
Tokamak and thereby losing energy.
Fusion occurs when the plasma
reaches in the region of 150°C million
– 10 times hotter than the sun’s core.
The size and complexity of the facil-
ity is staggering. The main fusion reac-
tor will be built on a attened area of
concrete that would cover 60 football
pitches. The Tokamak vessel will
comprise about a million components,
with some, like the superconducting
magnets, standing as high as a four-
storey building and weighing 360 tons
each. When the main building contain-
ing the reactor is complete, it will be
60 m tall and extend 10 m below the
ground.
As the components arrive from the
project’s partners all over the world,
the task of putting together what is
described as the world’s largest puzzle
begins. Some 2300 people are at work
on site to put the machine together.
ITER’s Director-General Bernard
Bigot, said: “Constructing the machine
piece by piece will be like assembling
a three-dimensional puzzle on an in-
tricate timeline. Every aspect of
project management, systems engi-
neering, risk management and logistics
of the machine assembly must perform
together with the precision of a Swiss
watch. We have a complicated script
to follow over the next few years.”
ITER’s initial demonstration of its
functionality, called “rst plasma” is
scheduled for December 2025 and
could reach full power by 2035.
Whether that timeline will be met is
anyone’s guess. The project is already
running ve years behind schedule and
has seen its initial budget triple to some
€20 billion ($23.4 billion).
Yet I have every condence that
scientists will get there eventually; the
desire is too great. As Smith noted:
“Maybe 15 years ago, I might have
had my doubts about coordinating
such a complex effort. Now that I’ve
seen it being brought together and then
working intimately with the world-
wide group, I have no doubt that it will
come together.”
Nonetheless, ability and determina-
tion is not the problem here. Com-
menting on the potential impact, Smith
added: “It changes, I think, the whole
world’s energy economics entirely if
fusion goes forward.”
‘If is a big word. And fusion will not
get the chance to change the world’s
energy economics. Long before we get
there, it’s more likely energy econom-
ics will change the prospects for fu-
sion.
ITER will continue and most likely
eventually succeed; and no doubt the
various national plans to build com-
mercial reactors will build on its suc-
cess. At the same time dozens of private
companies will carry on pushing for-
ward and raising funds to develop
fusion reactors based on different ap-
proaches to ITER. This work is
mostly due to a genuine belief that
fusion will play a part in the future
energy mix but I suspect that some
national projects may be more about
earning bragging rights.
The challenge will be economics and
urgency. Some argue that with the
climate crisis, fusion has to happen.
The technology, however, will not be
commercial before the crisis is upon
us. And further, where is the incentive
when there are available technologies
and strategies that can do the job at a
fraction of the cost?
Five years ago, Cowley said: “There
are probably, over history, a handful
of historic moments where in a ash
the future changed. In a ash the future
will change with this machine…”
This is certainly true. I fear, how-
ever, that Cowley may not be around
long enough to see it happen. Man may
indeed be capable of making a star but
if the cost of wind and solar keep
falling, this “sun in a box” may never
see the light of day.
Still star gazing
Junior Isles
Cartoon: jemsoar.com