3. OIL & GAS
Changing asset integrity to meet
the needs of the oil and gas industry
Market leader in asset integrity management services
to the oil and gas industry, the EM&I Group has
seen increased demand for its services because of its
innovative approach to solving challenges faced by the
floating-production and drilling sectors
world’s floating production projects
are planned.
Mr Constantinis explains the
growth of EM&I: “When we started
the business 30 years ago, we set
out to be the world’s leading asset
integrity service provider and this
meant doing things differently.
Rather than providing a commod-itised
service, we chose to focus on
high added value innovations. While
this required greater investment,
the growth in revenue and profits
justifies our strategy.”
EM&I has always believed that
strong partnerships with industry
and regulators are key foundations
for long-term success. Joint ventures
and alliances with Odebrecht, Stan-tec,
Bureau Veritas and others have
proven the value to both EM&I and
their partners. EM&I’s leadership of
the HITS (hull inspection techniques
and strategies) joint industry project
is an example of how EM&I brought
all sectors of the industry together
to identify challenges and develop
innovative solutions. One challenge
was the need to reduce diver-based
inspection of floating installation hulls
which included floating production
and mobile offshore drilling units.
ODIN™, EM&I’s Diverless UWILD
(underwater inspection in lieu of
dry-docking) is a major part of
EM&I’s “No dry-dock” strategy.
David Mortlock, EM&I’s chief techni-cal
officer, explains: “Our Diverless
UWILD methodology changes the
way floating assets are inspected.
We built a validation centre in the UK
to demonstrate the new methodol-ogy
to classification societies, regu-lators
and operators.
“As a result, ODIN was success-fully
implemented on two FPSOs
[floating production storage and
offloading units] in Brazil within a
few months of it becoming avail-able.
We are now planning a fleet-wide
approach with one of the larg-est
operators, and are negotiating
contracts with several drilling con-tractors
and floating LNG [liquefied
natural gas] operators.”
ODIN is a complete hull structural
integrity package comprising engi-neering,
planning and site implemen-tation,
including a patented means of
The number of floating offshore
installations (FOIs) and mobile off-shore
drilling units (MODUs) is
increasing as oil and gas reserves
are discovered in ever-deeper
waters. Currently there are 333
FOIs and 700 MODUs in service or on
order, a 69 per cent increase over the
last decade. Many operational FOIs
and MODUs are based in deep water,
on long-life projects with no dry-dock
intended for 25 years or more.
EM&I recognised the challenges
that operators and owners of these
increasingly complex units would
have to face to ensure their assets
complied with safety regulations
while optimising production efficiency.
Chief executive of the EM&I Group
Danny Constantinis believed that
fundamental changes were needed
in the way FOIs and MODUs were
designed, operated, maintained
and inspected to avoid the signif-icant
penalties associated with
unplanned dry-docking.
“The industry has recognised cost
and lost production consequences
when coming off station for many
weeks to dry-dock” he says. “But no
one had developed a holistic solu-tion
that met the requirements of
the operators, classification socie-ties
and regulators.
“We have spent the last ten years
developing and implementing a
comprehensive ‘No Dry-dock…
Safely’ package. This ensures com-pliance
with regulatory and clas-sification
society requirements,
provides our clients with the tools
to manage the integrity of their
assets while on station and pro-ducing
safely for extended periods,
and we have reduced the number
of people required to undertake the
offshore element of the work.”
EM&I has been a best-in-class
provider to the oil and gas industry
for more than 30 years with addi-tional
customer demand contributing
to the company’s growth and geo-graphic
expansion. Having previously
established bases in North Amer-ica,
South-East Asia, Australia and
Northern Europe, EM&I has addi-tionally
established bases and won
long-term contracts in Brazil and
West Africa where 43 per cent of the
inspecting critical safety valves, with-out
divers while giving better quality
and more accurate data on valve con-dition.
EM&I’s life cycle and holistic
capability of finding and fixing anoma-lies
at an early stage helps operators
run their plant efficiently and safely.
“EM&I’s diverless approach has
changed the way this type of inspec-tion
will be carried out in the future,”
adds Alexander Constantinis, chief
financial officer. “Our long-standing
relationships with classification
societies and regulators are a result
of working together at all stages
of the solution development. This
brings benefits to the industry by
replacing the old periodic method
of underwater inspections with the
ODIN continuous approach.”
EM&I’s chief operating officer Pat
Lawless comments: “We have been
in the business for many years so
have a clear understanding of what
our clients need and how we can
help solve their challenges. We con-tinue
to conceive innovative solu-tions
to improve asset integrity for
high capital value projects. We work
closely with classification societies,
regulators and industry bodies, and
understand the value and impor-tance
of their input and acceptance.
“Our work with R&D organisations
and knowledge of other industries
expedites solutions. Our policy of
continuous improvement, exploring
new markets, and transferring our
knowledge and expertise into other
areas of the industry, keeps our
people energised and motivated.”
EM&I is not standing still, as chief
executive Mr Constantinis notes:
“We have further developments
underway and significant interest is
being shown in another of our clas-sification
society accepted innova-tions,
HullGuard™. This diverless,
retro-fittable, impressed current
cathodic protection (ICCP) system
protects the hull against corrosion
for an extended period and avoids
the risk of having to dry-dock to
repair coating or the hull structure.
“We have been managing gas
plant integrity for many years and,
with the requirement for politically
stable supplies, it is a strong part
of our business. Recent develop-ments
in floating LNG production
and regasification correspond well
with our expertise, and we are
working with these operators and
classification societies to adapt our
existing systems. In addition, we
have developed new physics, in col-laboration
with a number of univer-sities,
to make sure we stay ahead
of the game.”
For many in the oil and gas indus-try,
EM&I’s name is synonymous
with delivering integrity through
innovation – and that fits very well
with EM&I’s vision and culture.
For more information on the EM&I
Group and its services go to
www.emialliance.com
We have spent the last ten years
developing and implementing a
comprehensive ‘No Dry-dock…
Safely’ package
TIME FOR A FRACKING
CHARM OFFENSIVE?
It has split public opinion and tempers are still rising. Fracking for shale
gas is a contentious issue, but supporters claim it holds huge potential
benefits for the UK economy, as Jim McClelland reports
SHALE GAS
ȖȖPerfect for puns on placards and
front pages, fracking is the media-friendly
short-form name for
hydraulic fracturing, the process of
extracting shale gas from layers of
rock by drilling down and injecting
fluid at high pressure.
The technology has faced vocal
and widespread opposition from
“fractivists”, including public fig-ures
and celebrities, from Green
MP Caroline Lucas to Hollywood
actor Mark Ruffalo, star of the
Incredible Hulk.
The campaign against fracking is
focused primarily on environmen-tal
issues: big-picture concerns
about climate-change impacts
of fossil-fuel consumption; plus
local-community fears for poten-tial
groundwater contamination
and air pollution.
The two most high-profile UK
test-drilling locations have seen
protesters marching in their thou-sands
and camped on site. In
North-West England, at Barton
Moss, campaigners won a stay of
eviction in March. Two month
earlier, in the Sussex village of
Balcombe, energy firm Cuadrilla
announced it will not now frack
the besieged site, due to unfavour-able
geology.
These flashpoints have kept the
bad-press bandwagon rolling since
fracking-related earth tremors
shook Blackpool in 2011.
Given such a controversial track
record, has the global oil and
gas industry been deterred from
entry into the UK market? It most
definitely has not, says founder,
president and chief executive of
Texas-based Breitling Energy
Corporation, Chris Faulkner – the
self-styled “Frack Master” – who
describes commercial attitudes
and investor confidence as robust.
“The UK is likely to become the
next shale revolution, and many
companies are looking closely at
the country as the government
makes steps towards encouraging
the industry through new trespass
laws and tax incentives,” he says.
With strong positive signals from
key political quarters, the business
case is being built on emerging
data. The numbers are big and get-ting
bigger.
Recent reports from the British
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Geological Survey have seen origi-nal
estimates for total UK reserves
revised upwards substantially to
1,300 trillion cubic feet (tcf), lifting
expectations for amounts which
are economically recoverable.
Additional data for the Bowland
Basin region, which stretches from
Cheshire to Yorkshire, now make it
perhaps the largest such reserve in
the world.
“It is early days, but the UK
shows every sign of following the
example of the United States,”
says Mr Faulkner. “Estimates of
recoverable oil and gas are being
upgraded as more detailed sur-veys
are conducted and test drill-ing
completed.”
Taking a conservative recov-ery
ratio of 10 per cent, fracking
advocates calculate 130tcf of gas
extracted could provide anything
up to 52 years’ UK supply.
If figures for reserves and recov-erability
remain works in pro-gress,
those quoted for poten-tial
employment are open to
even more debate. Estimates for
jobs to be created have ranged
from 74,000 (Cuadrilla), down to
24,000 (AMEC) and back up to
64,000 (EY).
A fracking boom had at one point
also been touted by Prime Minister
David Cameron as having “real
potential” to drive UK energy bills
down, only for the suggestion to be
dismissed by economist Professor
Lord Nicholas Stern as “base-less
economics”.
On the matter of price, chief
scientist at Greenpeace UK Doug
Parr argues it is vital to understand
market differences either side of
the Atlantic. “The situation in the
US is radically different from the
UK. We have much smaller land
area to supply a denser population,
stronger public environmental
concerns and an open gas market.
Conditions are the opposite of
those in the US, where a fracking
boom in a closed market led to a gas
glut and collapse in prices,” he says.
“No energy expert sees the same
price falls happening in Europe.
The impact on gas costs is actu-ally
likely to be marginal or non-existent.”
1,300trn
CUBIC FEET OF UK
SHALE GAS RESERVES
52 years
OF UK SHALE
GAS SUPPLY
Source: British Geological Survey
64,000
UK JOBS TO BE
CREATED DIRECTLY
AND INDIRECTLY BY
2032
Source: EY
bility of fracking in the energy
mix, might shale gas offer an
interim means to wean the UK off
coal addiction and reduce emis-sions
in the medium term, while
other, cleaner forms of generation,
including renewables and nuclear,
achieve critical mass?
According to Dr Parr at Green-peace,
such pragmatism is not
credible in terms of timeframes
for delivery, even putting aside
environmental concerns and social
resistance. “Given that shale gas
production will not become signifi-cant
for well over a decade, it is no
quick fix for anything. It will play
little or no role in displacing coal
out of the UK power system. Coal
should be mostly gone by the time
shale ever becomes substantial,”
he says.
There is neither consensus nor
compromise on how fracking will
play out in the UK. Depending
which side of the police cordon you
stand, the potential is as strong as
the protest. The only aspect on
which both sides might agree is
that the pitch, marketing fracking
to communities, has been found
wanting so far.
As Mr Faulkner concludes: “Gen-erally
in Europe, the industry has
handled the public relations very
badly. The ‘bunker mentality’ of
putting up barricades and getting
on with it was not right. Engag-ing
with communities, helping
them understand shale explora-tion,
fracking and the actual risks
involved, hearing their views, is
an approach used in the US, and it
has worked.”
If little else about the future of
fracking in the UK can be forecast
with certainty, the local “sell” can
be predicted to change. Expect a
charm offensive.
A police officer patrols the
perimeter of the Cuadrilla
test drill site at Balcombe,
West Sussex
Fundamental differences
between US and UK regulatory
frameworks are also highlighted
by Mike Pocock, a partner at law
firm Pinsent Masons. “In the US
there is no national statutory
framework for land-use planning,
except for certain environmental
laws and some enabling legislation.
By contrast, the UK has a statutory
plan-led system subject to both
local consultation and independ-ent
examination. Nine separate
applications make fracking one of
the most regulated activities in the
energy sector,” he says.
Blamed for exacerbating drought
conditions in the US, water
abstraction demands for fracking
represent one issue where UK
understanding has changed, as
head of corporate affairs at Water
UK Neil Dhot explains. “Overall,
the potential amount of water
needed in the fracking process
was a big question raised very early
on. However, all the studies and
work we have seen in the last few
months point to the amount of
water needed being manageable,”
he says.
So, looking at the strategic via-
Data for the Bowland Basin
now make it perhaps the
largest such shale gas
reserve in the world
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4. OIL & GAS OIL & GAS
SINK OR SWIM
AS WAVE OF
DECOMMISSIONING
APPROACHES
Of the estimated £500 billion spent by the UK
offshore oil and gas industry between 1970
and 2012, just £2 billion was channelled into
decommissioning. The clean-up represents an
enormous engineering challenge, one that will
take decades and cost tens of billions, writes
Rohan Boyle
DECOMMISSIONING
ȖȖProduction may have been in
decline since 2000, but the final
chapter in the North Sea oil and
gas saga, that in which the vast
assemblage of ageing platforms
and pipes is pulled up and taken
back to shore, has hardly begun.
The benefits to the UK from
the once-prolific North Sea fields
have been enormous. Between
1970 and 2012, it is estimated that
the UK Continental Shelf (UKCS)
produced 42 billion barrels of oil
equivalent (boe), according to
industry body Oil and Gas UK.
Although total recoverable
reserves stand at somewhere
between 15 and 24 billion boe, a
growing number of ageing offshore
installations will soon have to be
decommissioned.
A strict legal framework of
national, regional and interna-tional
regulations governs what
happens to offshore facilities at the
end of their life.
In 1995, Royal Dutch Shell pro-voked
widespread outrage with
plans, approved by the UK govern-ment,
to abandon the floating oil
storage facility Brent Spar in deep
Atlantic water.
The controversy led 15 European
states, members of the Convention
for the Protection of the Marine
Environment of the North-East
Atlantic, to ban “the disposal of
offshore installations at sea, as
well as requiring all the topsides
of all installations to be returned
to shore”.
Over the next 30 years, virtually
all the oil and gas infrastructure on
the UKCS will have to be removed
from the sea and decommissioned
on shore. This amounts to some
475 offshore installations of all
types, 10,000 kilometres of pipes,
15 onshore terminals and 5,000
wells. Some 470,000 tonnes of
material will have to be retrieved
between 2013 and 2022 alone.
To put this in perspective, the
contract for removal of nine plat-forms
from the Norwegian Ekofisk
oilfield, between 2008 and 2014,
amounted to 113,500 tonnes or
three times the weight of all the
cabs in London.
Exactly how much all this will
cost to implement is difficult
to calculate as there are many
unknowns and fluctuations. How-ever,
Oil and Gas UK estimates the
total will amount to £10.4 billion
between 2013 and 2022, with the
total bill climbing to a cumulative
£31.5 billion by 2040. New invest-ment
in probable developments
would add £3.5 billion to the total,
Economic
forecasting
Page 08
but much of this would be incurred
after 2040.
Not all this will have to be borne
by the industry. The UK govern-ment
will incur more than half the
cost through a 50 per cent tax relief
mechanism – 75 per cent for older
fields – making the taxpayer one of
the most important stakeholders
in the process.
A view widely held in the indus-try,
according to the Royal Acad-emy
of Engineering, is that a tax
rebate to offset decommissioning
expenditure was always an essen-tial
condition of oil and gas compa-nies’
involvement in the North Sea.
Such is the importance of this
measure that any hint of uncertainty
over its future is enough to put off
new investment in older fields and
dissuade new market entrants.
The government therefore acted
to bolster confidence last October
when it issued the first decommis-sioning
tax relief deeds to seven
oil and gas companies operating in
the North Sea. These guarantee the
tax relief a company will receive, so
that even if a future government
makes tax changes they can still
claim a “difference payment”.
Also recently, the government
took steps to streamline the
lengthy decommissioning process
by issuing a standard template
that will allow the regulator, the
Department for Energy & Climate
Change, to ratify plans more
quickly and easily.
First to trial the template was BP
with its Schiehallion decommis-sioning
programme. “It took seven
months from initiation to approval,
compared to up to three years in
the case of the Miller oilfield. Also,
the document ended up only 42
pages in length. This equates to a
major saving in man-hours,” says
Alistair Corbett, BP’s decommis-sioning
projects manager.
With so many fields reaching the
end of their life, there are rising
concerns the supply chain has
neither the capacity nor the work-force
to handle the large, heavy
offshore platforms.
“There’s an opportunity for
us [the UK industry]. Billions of
pounds of work is coming to us
in the North Sea,” according to
Trevor Garlick, head of BP’s North
Sea operations. “At the moment,
there is not the technical capac-ity
or supply chain to meet it. We
need to meet it, or Norway, Spain
or others will.”
Current figures indicate that the
UK faces a major shortage of the
necessary skilled workers unless
there is a significant increase in
engineering and technical gradu-ates
as well as sustained retention
of experienced workers within
the industry.
As part of a push to fill this gap,
the oil and gas industry skills
body OPITO has launched a drive
to recruit suitable ex-military
personnel.
Innovation will also play a role
in meeting the decommissioning
challenge. Edward Heerema, chief
executive of engineering group All-seas,
is hoping a 382-metre-long,
124-metre-wide catamaran he
commissioned will capture a large
part of the business.
The giant craft, strong enough to
lift four Eiffel Towers, is scheduled
to set off from a South Korean
shipyard later this year. The suc-cess
of Mr Heerema’s $3-billion
bet will depend on timing. He is
hoping that oil companies will be
queuing up for its services by the
time it arrives in the North Sea.
Decommissioning represents
a significant opportunity as well
as a challenge for the UK off-shore
oil and gas industry. The
North Sea is not the only place
that will be dismantling such
infrastructure and the lessons
learnt here could potentially be
transferred abroad.
Prime Minister David
Cameron visits the Total
Oil depot shale-drilling
site in Gainsborough,
Lincolnshire
Removal of nine platforms from
the Norwegian Ekofisk oilfield
amounted to 113,500 tonnes or
three times the weight of all the
cabs in London
CASE STUDY
EX-MILITARY PERSONNEL
HELP BRIDGE SKILLS GAP
The UK oil and gas industry faces a skills
shortage across all sectors and not just in the
area of decommissioning. A report by OilCa-reers.
com and Air Energi estimates that it will
require more than 120,000 skilled personnel
over the next decade to realise the full potential
of renewed investment in the North Sea and
recent shale discoveries.
“Specialist disciplines are in very short supply.
Graduate programmes are not attracting the
right amount of people into the industry and,
where good graduates are found, it’s often a
case of too little, too late,” the report says.
In a recent survey of the industry by Barclays
Bank, 66 per cent of those polled highlighted the
skills shortage as the biggest challenge facing
the industry.
At the same time, the armed forces are down-sizing,
creating a potentially sizable source of
new recruits. “We’re not going to find a lot of
geologists or drilling engineers, but there will
be quite a number of people in the military who
we think have skills and qualifications that are
transferable to our industry,” says Alix Thom,
employment and skills policy manager at indus-try
body Oil and Gas UK.
“The armed services are a good source of tech-nicians,
such as mechanics and electricians,
while submariners are currently in demand for
certain kinds of subsea work,” she says.
The oil and gas industry is already a popular
career choice for former soldiers, sailors and
airmen, according to training standards body
OPITO. Between 2011 and 2013, some 2,500
found jobs in the industry.
“They are generally well trained, safety
conscious and very dependable,” says Morven
Spalding, skills development director at OPITO.
“In addition, their work ethic and familiarity with
operations allow them to fill jobs in all sectors of
the industry, including offshore positions.”
With 20,000 posts to go in the regular Army
by 2020, on top of the 18,000 to 20,000 armed
services leavers in any normal year, the number
of potential recruits could increase.
To better co-ordinate the hoped-for jobs
transfer, the government launched a nationwide
programme last year run by the Ministry of
Defence, Oil and Gas UK, plus OPITO and the
Career Transition Partnership, which helps
resettle demobbed service personnel.
One of its top priorities is to increase the level
of understanding, both of the experience and
skills that ex-services personnel possess, and
the skills that are needed in oil and gas. The
scheme runs awareness events at military
bases as well as training courses.
Some of the larger oil and gas companies
already run their own programmes targeting
ex-military people. GE Oil & Gas holds career
fairs aimed at the military and has what it calls
a junior officers leadership programme, while
Wood Group PSN runs a course that fast-tracks
skilled technicians from the armed forces into
the industry.
Oilfield services company Petrofac is also
actively recruiting ex-servicemen and women. It
uses the Career Transition Partnership to iden-tify
candidates who are enrolled on a training
programme as a first step in their new careers.
On successful completion of the course, they
will go into permanent positions, with some
ready to go offshore in just eight weeks.
Starting salaries in the industry are between
£35,000 and £40,000, according to Dominic
Simpson, head of sales at industry website
rigzone.com. “Lack of supply and increased
demand for qualified staff is putting huge infla-tionary
pressure on wages in the oil and gas
industry,” says Kevin Forbes, chief executive of
Oilandgaspeople.com.
“There is a lot of press coverage around North
Sea oil being in decline, but the truth is there is
still 30 to 40 years left in the North Sea, and that
estimate increases all the time as new fields are
discovered and come online. Anyone looking to
get into the industry now will enjoy a career that
will easily last their lifetime,” says Mr Forbes.
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5. OIL & GAS OIL & GAS
FORECASTING THE OIL
AND GAS ECONOMY
ENERGY MIX
ȖȖOil accounts for around 40
per cent of current global energy
mix, with natural gas accounting
for a further 23 per cent. While,
under existing policies, the Inter-national
Energy Agency (IEA)
expects renewable energy genera-tion
to double by 2035, world pri-mary
energy demand is on track
to increase 43 per cent over the
same period.
BP estimates that renewable
energy will make up 27 per cent of
the growth in global energy supply
to 2030, just ahead of growth in
coal, at 26 per cent, and gas, at 21
per cent. So what does this mean
for the oil and gas economy?
Marc van Loo, head of energy
& utilities and senior investment
analyst at ING Investment Man-agement,
says: “Barring any new
black-swan-like energy source,
energy trends will cause some
market share loss for fossil fuels,
down from 87 per cent of primary
energy supply today, but still
remaining a material part of the
primary energy mix within the
next 25 years.”
Surprise black-swan events
could be economic, technologi-cal
or political. A decade ago, the
development of US shale gas and
tight oil would have been such an
event. In a previously unimagina-ble
shift, the United States is set
to become one of the major global
sources of oil and gas, with the
IEA projecting the US will replace
Saudi Arabia as the world’s largest
oil producer by 2015.
Despite that growth, the margin
of error in the global oil markets
remain thin, at about two to
three million barrels a day, as
disruptions affect production in
Iraq, Libya, Angola and while gas
markets remain unsettled by the
Russia-Ukraine impasse.
David Hemming, commodities
portfolio manager at Hermes Fund
Managers, says: “While US pro-duction
growth is matching growth
in global demand, all the major
producing areas are going to run
into issues with higher depletion
rates, especially in tight oil plays.”
A result of high oil demand
forecasts and decreasing supply
has been the exploration of new
higher- risk areas of oil and gas
supply, ranging from Canada’s tar
sands, pre-salt reserves off the
coast of Brazil and in the Gulf of
Guinea, and the Arctic.
Success in Canada has become a
global model for the exploitation
of tar sands and oil shale. Both the
Middle East and China are inter-ested
in their domestic potential,
while Israel is estimated to have
potential reserves equivalent to
260 barrels of oil (bbl). The energy
intensity of the technology means
that such sources require high oil
prices for the projects to be viable.
While the last few years have seen
Brent oil prices at a cyclical high,
there are concerns from investors
about the impact on return if the
oil price falls. Mr Hemming says
that, while the projects have a high
marginal cost, they have easy-to-model
resource boundaries, which
helps in planning.
Following the 2007 discovery
of oil off the coast of Brazil, there
were predictions that output could
double to five million barrels a day
by 2013, making Brazil the world’s
fourth largest oil producer. Recent
finds off the coast of Angola, Cam-eroon,
Congo, Equatorial Guinea
and Gabon have encouraged hope
that Africa’s reserves will be as
strong. Yet in 2014, Brazil’s output
has increased by only 20 per cent,
with only 350,000 barrels a day
coming from the pre-salt fields.
Political and structural challenges
have been an issue, but it is fail-ings
in Brazil’s infrastructure and
domestic skills-base that have
been cited as pushing up costs. The
marginal cost of the oil is around
$30 to 40bbl, which makes these
fields an exciting opportunity.
Shell has estimated that the Arc-tic
holds around 30 per cent of the
world’s undiscovered natural gas
and 13 per cent of its yet-to-find oil.
Russia has already shipped its
first oil from offshore Arctic
waters, though the challenge with
Arctic drilling is the technical and
environmental unknowns, but
a big discovery could mean rela-tively
cheap oil, again at $30
to 40bbl.
The mixture of global energy
supply, both in terms of type
and origin, is likely to remain a
function of demand, supply and
economic cost. Mark Henderson,
director of oil and gas at West-house
Securities, says if these new
areas of exploration are proved to
be economic, “there will be a gold
rush”, but it is economics that
will dictate the viability of new
exploration, nothing else. The oil
market is cyclical and he says that
the continuation of supply growth
could see marginal costs in the oil
industry fall below $40 bbl.
Everything that impacts
on future energy mix
depends on China – its
attempts to reduce the
country’s dependence on
coal are already beginning
to impact on the rest of
the world
Existing conventional sources
could also provide the necessary
supplies to meet demand growth,
especially if the continuing high
price of oil has its expected impact
on energy efficiency. Mr Hender-son
points out that energy inten-sity
in Organisation for Economic
Co-operation and Development
countries is now a third of what
it was before the oil shocks of the
seventies and eighties, mean-ing
lower consumption per unit
of GDP.
And there are signs of a similar
path in China, where energy
intensity is slowing faster than
Future exploration and production
of oil and gas depend on sustainable
prices in the global energy market,
as Felicia Jackson reports
predicted. Emma Wild, head of
upstream advisory at professional
services company KPMG, says:
“Everything that impacts on future
energy mix depends on China – its
attempts to reduce the country’s
dependence on coal are already
beginning to impact on the rest of
the world.”
Arthur Hanna, global manag-ing
director of energy business
at Accenture, says that different
predictions are dependent on
views on the likelihood of different
interventions, ranging from fossil-fuel
subsidies to a carbon price. Mr
Hanna says: “The future energy
mix is not dominated by one form
of supply, which has never hap-pened
before.” He warns though
that predictions are still “missing
energy demand management, and
the impact and sources of innova-tion,
local content, jobs and so on”.
These latter elements are what
enable the balance of economic,
social and environmental concerns
in energy policy.
Laszlo Varro, IEA director of gas
and power, says that in order to
understand potential change in the
energy mix, we need to understand
what drives demand for differ-ent
fuels. According to Mr Varro,
energy demand can be effectively
split into three areas: electricity
(where the most important source
is coal); transport (predominantly
oil); and heating (mainly gas).
He says that it’s useful to look at
the dominant form of supply for
each and how that might change.
“Outside of transport, oil is being
pushed out of every other sector in
the economy,” he says. “On the other
hand, you would need an astonish-ing
shift in the fleet to challenge oil
in the transportation sector.”
Coal in fact provided around half
the growth in electricity demand
in the past decade and is expected
to remain the largest single source
of power by 2035 – and its growth
is of far more concern than oil. Mr
Varro says that the world is adding
a UK’s worth of electricity demand
every nine months or a
Germany every year. In terms of
emissions, this is a critical issue.
What’s significant for new areas
of oil exploration is that a fall in
the marginal cost of oil could have
a major impact on high-risk pro-jects.
According to Mr Hemming,
current oil projects have an inter-nal
rate of return (IRR) of 15 to 20
per cent, so the question of how
long those IRR’s can be maintained
becomes ever-more important. He
also believes that demand is man-ageable
within existing reserves.
“These new areas of exploration
and production will only work at
a certain price,” he concludes.
PREDICTING GLOBAL ENERGY SUPPLY
COAL-TO-GAS SWITCHING AND RENEWABLE POWER GROWTH
ARE THE PRINCIPAL TRENDS IN EUROPE*
*Data is indexed to 2008. CAGR is compound annual growth rate.
RES is renewable energy supply
DIFFERENT SCENARIOS RESULT
IN VARYING GENERATION
CAPACITY NEEDS BY 2030
HITTING THE TARGET
High degree of political
cohesion and direction
supports record investment
in power sector and drives
down carbon emissions to
achieve 2030 target
GAS IS KEY
Moderate commitments
to limit greenhouse gas
emissions and competitively
priced gas supplies
dissuade investors from
financing new coal-fired
power stations, resulting in
all gas-fired fossil plants
AUSTERITY REIGNS
Absolute prioritisation of
economic growth and fiscal
stability in a UK economy
which has seen stagnation
followed by anaemic growth
SOLAR PV
OFFSHORE WIND
ONSHORE WIND
NUCLEAR POWER
CARBON CAPTURE
STORAGE
UNABATED GAS/
BIOGAS
UNABATED COAL/
BIOMASS
18%
12%
6%
0%
2035
18
12
BILLION
TOE
6
0
Source: IEA (New policies scenario)/Vivid Economics
1995 2000 2010 2015 2020 2025 1995 2030 2035
TOTAL ENERGY GAS ELECTRICITY COAL OIL NUCLEAR RES
2013 UK
ENERGY MIX
2040 WORLD TARGET
SUSTAINABLE ENERGY
DISTRIBUTION
200%
150%
100%
50%
0%
2014 WORLD
ENERGY MIX
31,9%
5.6%
2.3%
10.5%
33%
10%
11%
3%
RES 3.4%
ELECTRICITY
0.7%
GAS 0.5%
ENERGY 0.0%
NUCLEAR 0.0%
OIL -0.9%
COAL -2.5%
38%
28%
20.6%
29.1%
17%
16%
8%
2%
2%
11%
21%
Coal Nuclear Hydro Renewables Oil Gas Wind Geo Bio Other
Source: Vivid Economics
NEW SOURCES
HELP TO SUPPLY
SUFFICIENT ENERGY
Source: Energy Outlook 2035, BP 2014
NEW ENERGY FORMS*
*TOE is tonnes of oil equivalent
1990
PRIMARY ENERGY PRODUCTION
FORMER SOVIET UNION STATES
SOUTH & CENTRAL AMERICA
NORTH AMERICA
MIDDLE EAST
EUROPE
ASIA-PACIFIC
AFRICA
1990
2005
2005
2020
2008- 2035 CAGR
RENEWABLES SHALE GAS TIGHT OIL,
2020
2035
HITTING
TARGET
GAS IS
KEY
AUSTERITY
REIGNS
120
100
80
60
40
20
0
GENERATION CAPACITY IN 2030 (GW)
3
2
BILLION
TOE
1
0
3
2
1
0
% OF TOTAL
(RHS)
OIL SANDS,
BIOFUELS
Solar
8 raconteur.net twitter: @raconteur raconteur.net twitter: @raconteur 9
6. Gas, natural and manufactured Commodities and transactions Non-ferrous metals
Coal, coke and briquettes Crude materials, inedible Iron and steel Non-commodities
Source: UNCTAD
4.2% 4.9% 1.4% 1.5%
3.7% 5.2% 1.4% 1.8%
2.8% 4.6% 1.5% 2.4%
2.8% 3.5% 1.7% 2.2%
FOREIGN DIRECT INVESTMENT
INFLOWS INTO AFRICA BY
SECTOR (US$m)
Real GDP growth
Resource contribution to growth
Non-resource contribution to growth
Nigeria
Chad
Tanzania
Ghana
Zambia
Rep. Congo
Cameroon
South Africa
Dem. Congo
Niger
Namibia
Botswana
Mali
Guinea
Gabon
C. African Rep.
2011 2012
2,940
3,151
2,316
2,227
1,886
1,426
1,511
Mining, quarrying
& petroleum
Electricity,
gas & water
Coke, petroleum
prod. & nuclear fuel
Metals & metal
products
Transport, storage &
communications
Motor vehicles &
transport equipment
Food, beverages
& tobacco
Business services
Finance
Source: IMF, African Department Database Source: UNCTAD, based on information from
The Financial Times, fDi Markets
facility’s production - now at 3.4
million metric tonnes per annum
- and a multi-billion-dollar gas
pipeline project to connect Nige-ria,
Cameroon and Equatorial
Guinea gas fields to the plant.
The government has partnered
with a US company to develop
the petrochemical sector to meet
domestic and regional industrial
demands, create jobs and grow
the economy.
Africa –
from petrodollars
to progress
MAPPING RESOURCES IN AFRICA
The shift in approach by a growing number of
African states to the exploitation of their oil and gas
resources could help transform Africa’s economies.
Jason Kerr, Joshua Siaw and Anthony Elghossain
of global law firm White & Case explain
African states rich in resources
are striving to increase domes-tic
involvement in their econo-mies
– especially in oil and gas.
In attempting to increase domes-tic
participation throughout the
value chain, some African states
have begun introducing local
content laws, supporting indus-trial
diversification and creating
a broader economic base for the
future. If effective, these meas-ures
could provide a framework
to enable resource-rich states
to benefit from Africa’s potential
and transform their economies.
Africa holds around 8 per
cent of the world’s oil and nat-ural
gas reserves. Some states
have developed their oil and
gas sectors significantly. Nige-ria
and Angola, in particular,
have established themselves as
exporters and borrowers in the
international market, and rank
as the top two producers in sub-
Saharan Africa. Buoyed by sig-nificant
new energy finds, other
states, such as Ghana, the Ivory
Coast, Kenya, Tanzania, Uganda,
Mozambique and Chad, offer new
opportunities. In 2012, about half
the world’s discoveries of con-ventional
oil and gas were in East
Africa alone.
Natural resource exploita-tion
provides important sources
of revenue for African states
through investments, sales and
commodities-backed borrow-ings.
But this investment has not
necessarily broadened the eco-nomic
base, promoted employ-ment
or added value domesti-cally.
African governments have
reaped financial rewards with-out
maximising residual ben-efits,
such as ownership, skills
development and the growth of
related sectors.
With their new policies, how-ever,
African states will look to
encourage international inves-
Despite moving towards local
ownership and participation in the
value chain, African states must
overcome common challenges.
Although policies on local con-tent
and diversification could be
transformational, African states
and local businesses - even in
relatively established markets
such as Nigeria or Angola - have
struggled to raise capital, acquire
new technologies and improve
inadequate infrastructure.
While states with new discover-ies
may seek to learn from history
and avoid the “resource curse”
that confronted some of the more
established oil and gas produc-ers,
they will also face chal-lenges.
States such as Tanzania
and Mozambique have found that
their plans to monetise natural
gas reserves will require exten-sive
international participation to
succeed, given the high-risk and
capital-intensive nature of these
projects. Mozambique, in particu-lar,
may find it difficult to finance
and develop massive new gas
finds, which could require initial
investments of more than $50 bil-lion.
Newer resource-rich states
will need to balance the desire to
promote these policies against
the need to attract international
investment if they are to maximise
their natural resource potential.
In pursuing their policies, African
states must avoid deterring inter-national
investors who can provide
funds, management expertise and
technical knowhow necessary to
achieve their goals. Indeed, local
content laws could have counter-productive
effects as international
investors m ay e lect t o e ngage
other states or regions with less
onerous requirements, such as
taxes, training, procurement and
other costs of conformity. And
because these laws and related
policies are relatively new, inves-tors
may prefer to engage states
with legal frameworks seen as
more established and predictable.
Despite these risks, African states
will continue to explore new ways
to manage their natural resources
and resultant windfalls. They will
seek to grow domestic industry,
build institutions, and develop
services to allow industry and
agriculture to flourish. As local
companies continue to increase
their participation in domes-tic
industry, they will gradually
develop necessary experience and
expertise. International investors
must understand that the land-scape
is changing and push for-ward
partnerships with domestic
participants. If successful, the oil
and gas industry could help Africa
achieve its potential.
operations in the relevant fields.)
In a deal demonstrating the
potential effect of local content
laws, including on political and
operational risks, Shoreline Nat-ural
Resources, a joint venture
between UK-listed Heritage Oil
and local company Shoreline
Power Company, acquired a sig-nificant
interest in a major Niger
Delta oil-producing block from
a consortium led by Shell. As
Nigeria’s largest-ever upstream
acquisition financed by interna-tional
banks, the deal was origi-nally
bridge-financed and sub-sequently
completed through a
reserves-based loan arranged
by Standard Bank.
Other African states have
adopted simi lar measures.
Ghana, for example, has legis-lated
to increase local participa-tion
in terms of equity, employ-ment,
training and ser vices.
Beyond those requirements, Gha-naian
legislators have also estab-lished
parameters for minimum
equity participation by indigenous
companies. Without this partici-pation,
petroleum-related agree-ments
and licences will be inva-lid.
Since passing local content
laws in 2013, Ghana has awarded
several oil blocks to consortiums,
including Ghanaian companies,
and has seen related services in
insurance and finance grow.
PROVEN RESERVES OF CRUDE OIL IN AFRICA 2012 TOP AFRICAN EXPORTS BY PRODUCT 2009-12
Levels of crude oil
(billion barrels)
10.000+ (High)
1.000+ (Medium)
0.010+ (Low)
No data
Alongside the enactment of local
content laws, African states and
citizens have begun harnessing
reserves to support industrial
diversification and broaden their
economic base. For decades,
outside investors have extracted
resources and the value derived
from processing and manufactur-ing
as African states have raked
in petrodollars without increas-ing
their stakes in the value chain.
Nigeria, for example, imports
95 per cent of its diesel, subsi-dised
Cameroon
0.200
Tunisia
0.425
Gabon
2.000
Ghana
0.660
Equatorial
Guinea
1.100
Congo
(Brazzaville)
1.600
at great expense with crude
oil exports, and has historically
flared much of its natural gas,
in part because of inadequate
infrastructure. To move forward,
Nigeria has sought to develop its
refining capacity, for petroleum
products such as diesel and fer-tilisers,
and monetise its natural
gas reserves. While several for-eign
firms have failed to deliver on
oil refineries announced over the
last 15 years, the Nigerian Dan-gote
Group is poised to construct
a major refinery and related pet-rochemical
and fertiliser plants.
Once complete, at a projected cost
of $9 billion, the refinery will have
a production capacity of 445,000
Source: US Energy Information Administration, Oil and Gas Journal
barrels a day and employ thou-sands
of workers.
Similarly, having exported liq-uefied
natural gas (LNG) for more
than a decade, Nigeria has passed
laws that require oil producers to
supply natural gas for domestic
uses such as power generation or
petrochemical production. Oper-ating
under these laws, Indorama
Eleme, a Nigerian poly-olefins
producer, owned by the Indorama
Corporation based in South East
Asia, has sold 95 per cent of its
production domestically since
2006. Building on that success,
Indorama Corporation closed on
the financing of a large-scale fer-tiliser
project in 2013. The new
Petroleum and related
materials
2012
2011
2010
2009
RESOURCE AND NON-RESOURCE
CONTRIBUTION TO REAL GDP
GROWTH 2000-11 (%)
plant will be the largest of its kind
in Africa, and will benefit from
competitive feedstock pricing and
a growing domestic market.
In Ghana, meanwhile, the gov-ernment
spends roughly $1 bil-lion
a year importing crude oil to
fuel power plants. To reduce reli-ance
and allow public and private
entities to benefit from cheaper
power, the Ghana National Gas
Company is building a $1.4-bil-lion
gas processing plant to sup-ply
the domestic market with
natural gas from the nearby
Jubilee Field. Equatorial Guinea
is also building a new LNG train,
which will add 4.4 million met-ric
tonnes a year to an existing
tors and Africans to progress
in shaping the continent’s eco-nomic
destiny.
In recent years, states such as
Nigeria, Ghana and Uganda, have
passed local content laws. By
encouraging domestic partici-pants
to become stakeholders in
a range of enterprises relating to
oil and gas, African states have
sought to ensure that their citi-zens
increase their role in devel-oping
the broader economy.
In 2010, for example, Nigeria
enacted local content laws. Oil
and gas deals now require cer-tain
types of domestic partici-pation,
including profit-sharing,
equity involvement, training and
employment. Nigerians have
since benefited from 38,000
jobs in exploration and produc-tion,
engineering, transportation
and logistics, in large part due
to local content requirements.
In that time, local companies
have increased their participa-tion
in the oil and gas business
from 10 per cent to more than
30 per cent.
Partnerships between local
businesses and junior oil compa-nies
are growing in the upstream
oil sector of exploration and pro-duction,
especially in more acces-sible
fields that may not require
significant capital or new tech-nologies.
Arguably, local partic-ipation
has yielded benefits that
would have been absent other-wise.
Production in some places
has increased by 40 per cent,
according to some estimates, and
interruptions are down signifi-cantly.
(By responding effectively
to community concerns and build-ing
on their domestic relation-ships,
local companies may have
reduced the interruptions that
plagued foreign oil companies’
E. Guinea
Angola
Sierra Leone
20
15
10
5
0
International investors
must understand that the
landscape is changing and
push forward partnerships
with domestic participants
Investment has not necessarily
broadened the economic base,
promoted employment or added
value domestically
1009 raconteur.net twitter: @raconteur raconteur.net twitter: @raconteur 1011
7. OIL & GAS OIL & GAS
SUBSEA INNOVATION
ȖȖThe world’s oceans are the plan-et’s
last great frontier. Only around
10 per cent of the sea floor has been
mapped and we probably know
more about the dark side of the
moon than the seas that cover 71
per cent of the Earth’s surface. But
one thing is certain – there is still
much subsea oil and gas to recover.
Offshore drilling is technically
difficult and expensive, and is set
to become even more so as the
industry is forced into deeper,
ever-more remote waters to coun-terbalance
declining production in
mature shallow-water basins.
While there is no cheap and easy
technological solution to these
challenges, operators are gradually
adopting changes that are enabling
them to cost-effectively target
reservoirs over a much wider area,
tying back subsea wells both to
fixed platforms in shallow waters
and to floating infrastructure in
deeper water.
A combination of high oil prices
coupled with rising surface facil-ity
costs and advances in technol-ogy
have helped fuel a boom in
so-called subsea developments
in recent years. In the UK, for
instance, the sector has 53,000
employees, more than 750 com-panies
and is worth £8.9 billion in
products and services.
Globally, investment in ultra-deep
water developments, which
can be up to 3km below the sur-face,
is expected to capture 48 per
cent of total subsea capital expend-iture
from 2013 to 2017, in contrast
to 37 per cent between 2008
and 2012, according to UK-based
industry analysts Infield Systems.
Some of this investment is being
channelled into development of
new technologies and materials
that will make oil and gas extrac-tion
at great depths financially
viable yet safe both for operating
personnel and the environment.
In recent years, operators have
focused on bringing many of the
processes formerly carried out at
the surface down to the seafloor.
One of the first examples of the
current generation of subsea tech-nologies
appeared in 2007 when
US engineers FMC Technologies
supplied a full-scale commercial
subsea separation, boosting and
injection system to Norway’s Sta-toil.
The device separates out the
seawater, cleans it and injects it
into a low-pressure aquifer, while
boosting the pressure of recovered
oil and gas mixture to 1,000psi for
the 16-mile trip to the Gullfaks
field for processing.
We are looking at
new materials,
new construction
methods, new
welding techniques,
as well as higher
strength steels, as
projects go deeper
and encounter
higher pressures
North Sea oil fields now depend
heavily on enhanced oil recovery
(EOR) techniques, and in this case
the FMC system boosted total
recoverable oil by 19 million barrels.
Next year, Statoil hopes to install
the next generation of technol-ogy,
the world’s first subsea gas
compression station in the Åsgard
field off the coast of Norway. Two
advanced 11.5-megawatt compres-sors
will boost falling gas pressures
in the Midgard and Mikkel satellite
reservoirs, thereby prolonging
the life of the field and increasing
gas recovery by the equivalent
of 280 million barrels of oil. The
developers say the project avoids
the need to build a new, large semi-submersible
platform and will
reduce operating costs.
However, this technology was
dealt a blow last month when
Royal Dutch Shell postponed a
project to provide subsea compres-sion
at Ormen Lange, the second-largest
Norwegian gas field. “The
oil and gas industry has a cost
challenge,” says Odin Estensen,
chairman of the Ormen Lange
management committee. “This,
in combination with the maturity
and complexity of the concepts
and production volume uncer-tainty,
makes the project no longer
economically feasible.”
Although the pioneering subsea
compression system, also designed
by Aker Solutions, promises to
reduce capital and operating costs,
and enable greater production, it
still faces considerable techno-logical
challenges. It will have to
pump gas from wells at a depth of
2,790 to 3,600 feet some 75 miles
to onshore processing plants and
be available 97.6 per cent of the
time, with maintenance taking
place only every four or five years.
A daunting challenge even for
compressors based onshore.
Low-salinity water flooding of
oil reservoirs is another EOR
technique that is gaining ground.
Normal seawater creates electrical
charges, because salt is a conductor
of electricity, causing oil to stick to
the rock walls, thus reducing the
quantity that can be recovered.
But if low-salinity water is used
instead, the charge is lowered and
the oil is more easily liberated
from the rock. The International
Energy Agency estimates that an
additional 42 million barrels of
North Sea oil could be recovered
using this technique.
One of the biggest problems
facing subsea projects is the pro-vision
of a reliable, safe power
supply to drive and control the
pumps, compressors, separators
and other processing equipment
that has traditionally been kept
on platforms on the surface. Ger-man
multinational engineering
and electronics conglomerate
Siemens has developed what it
calls a subsea power grid that
combines electricity transmission
with control and communications
elements, while Swiss engineering
giant ABB has entered a five-year
programme with Statoil to develop
a similar system.
Subsea engineering firms are
working on a range of new tech-nologies.
“We are looking at new
materials, new construction meth-ods,
new welding techniques, as
well as higher strength steels, as
projects go deeper and encounter
higher pressures. We are also
witnessing the emergence of com-posites
and carbon fibre,” says
John Mair, technology develop-ment
director at engineering firm
Subsea 7. “You are going to see
new developments in underwater
communications, fibre optics and
acoustics, especially for the Arctic.”
If the polar ice cap continues to
recede, large-scale drilling in the
Arctic Circle will soon become
a reality and could account for
as much as 20 per cent of the
world’s undiscovered but recover-able
oil and natural gas resources.
Indeed, by 2030, the majority of
oil reserves will be in as yet unde-veloped
or undiscovered fields and
extracted using additional EOR
techniques, according to the Inter-national
Energy Agency.
Advanced technologies look
set to play a pivotal role in the
future, but will only do so if they
are cost efficient. This will depend
on continued high oil prices and
therefore seems likely, but is far
from assured.
15.5%
12 raconteur.net twitter: @raconteur raconteur.net twitter: @raconteur 13
3
of rising oil prices in unconven-tional
plays, adopting proactive
approaches. Adaptability is key, and
by better integrating functions and
operations, overall performance
can be improved, from selection of
locations to flowing the well.
As costs rise, reserves decline and
infrastructure ages, “business as
usual” is no longer a viable strategy.
Change is challenging, but instead of
regarding it as a burden, the North
Sea oil sector must use it as an
opportunity to innovate and improve
efficiency, and thus become a more
attractive investment opportunity.
If it doesn’t, companies’ futures and
thousands of jobs will be at stake.
Gavin Hall has more than 25
years of management consulting
experience serving exploration and
production clients across the globe.
He is currently managing director
of MTG Europe, specialising in
operations improvement.
www.mtgconsulting.com
Adapt or die:
Challenge for
North Sea
oil industry
Latest figures from Oil & Gas UK
show that predicted reserves are in
the region of 24 billion barrels of oil
equivalent. Production declined by
14.5 per cent in 2012 and, although it
is expected to rise slightly this year,
there has been an overall downward
trend since 2000.
At the same time, costs are
increasing. 2013 saw operating
expenditure rise by 15.5 per cent to a
record £8.9 billion and it is predicted
to be higher this year.
Declining production and increased
costs are not necessarily terminal as
long as prices rise accordingly. This
cannot be relied upon, so a better
option is to find new oil and/or extract
existing reserves more effectively.
The problem with finding new
reserves is they are becoming more
economically challenging. The past
three years have seen the low-est
exploration levels in history
and project performance has been
poor, in terms of cost, schedule and
promised volumes.
There is also scope to extract
existing reserves more effectively
either by reducing field lifting costs
by focusing on profitability over
production, which will require a
fundamental change of mindset,
or by concentrating on production,
not just by improving efficiency, but
also understanding true production
potential and driving to deliver that.
New technology will play an impor-tant
role, but the sector must also
revise its approach. The development
of deeper, service level-based rela-tionships
will help promote long-term
investment in technology, and govern-ment
must provide a framework that
supports investment in R&D and its
application in a mature market.
These factors require a long-term
view of asset development, which is
often at odds with the shorter time-frame
of shareholders wanting a
return on investment.
All of the above are possible, but
having spent the past 25 years work-ing
in exploration and production,
I know their implementation is not
going to be easy. As an industry, we
aren’t known for proactively adapt-ing
to changing circumstances. This
is no better evidenced than in the UK
sector, where high staff turnover and
localised wage inflation are a conse-quence
of reluctance by the industry
to address the root causes of a clear
skills shortage.
But it can be done. Our clients,
particularly those in the United
States, have taken advantage
COMMERCIAL FEATURE
North Sea oil reserves are declining.
Though there is still a wealth of oil and gas
out there, the “easier-to-access” reserves
are becoming depleted, says Gavin Hall,
managing director of MTG Europe
Adaptability is
key, and by better
integrating functions
and operations,
overall performance
can be improved, from
selection of locations
to flowing the well
rise in operating
expenditure in the oil
and gas sector
Curse
or cure?
Page 15
CASE STUDY
SUBSEA COMPRESSION
IN NORWAY’S ÅSGARD FIELD
Last summer, 125 miles off the coast of Norway, a
30,000-square-foot steel structure was sent plunging to
the ocean floor. By next year it will house a giant compres-sor
that will pump an estimated £18 billion worth of gas
from a mature offshore field.
Analyses show that, towards the end of 2015, the pressure
in the Midgard and Mikkel gas reservoirs in the Åsgard
field will fall below levels required to sustain a stable, high
level of production.
Until now the solution has been to install gas compres-sors
on an existing platform or to build a new staffed
compression platform. Instead, Statoil and Aker Solutions
are developing a subsea gas compression unit that will be
installed on the seabed next year – the first time this has
been attempted anywhere in the world.
By situating the compressor close to the wellheads, recov-ery
rates will be better than if it were on the surface, and
cheaper to build and operate, according to Acker Solutions.
“The technology represents a quantum leap that can
contribute to significant improvements in both recovery
rates and lifetime for a number of gas fields,” the company
says. It is expected that the project’s two state-of-the-art
11.5-megawatt (MW) subsea compressors will increase
recovery by around 280 million barrels of oil equivalent,
similar to the output from a medium-sized North Sea
gas field.
Qualification testing began in 2005, followed by a lengthy
testing programme at Statoil’s Kårstø laboratory facilities
from 2008. Most recently, a water-filled test pit was built at
the same laboratory to simulate subsea conditions.
The project is estimated to cost 15 billion Norwegian
crowns (£1.5 billion), about the same price as a compres-sor
on a new platform. However, a semisubmersible
platform weighs in at around 30,000 tonnes, some five
times more than the subsea compressioan station. It will
also require far less energy to operate, 25MW compared
with 41MW for a platform.
There will be no atmospheric emissions or discharges into
the sea from the subsea station, further reducing its envi-ronmental
footprint. Power-related annual CO2 emissions
will be around 109,000 tonnes compared with 200,000
tonnes for a platform.
Furthermore, the subsea station will be safer as it is oper-ated
remotely and will not, like a surface platform, require
a full-time on-board crew.
Technical barriers, the high capital cost and difficulties
with integration into existing infrastructure have held back
subsea production for years. Although the new technology
has yet to earn the full confidence of operators, as Shell’s
decision to postpone its Ormen Lange compression project
demonstrates, the decision by Statoil to press ahead with a
fully sanctioned, commercial project should set a valu-able
precedent.
BREATHING NEW LIFE
INTO OLD OIL FIELDS
There is still plenty of oil and gas under the
oceans and we need to recover it if we are to
satisfy rising global energy consumption,
writes Rohan Boyle
Brazil's Petrobras
oil-drilling platform,
Guanabara Bay,
Rio de Janeiro
AFP/Getty Images
Statoil
8. OIL & GAS OIL & GAS
ARE OIL AND GAS RESERVES
AN ECONOMIC CURSE OR CURE?
When governments and other national
stakeholders take control of oil and gas
reserves, there can be disadvantages
as well as the seemingly obvious
advantages, writes Jim McClelland
and technology” no longer hangs
together. They can raise finance
directly, and hire management and
technology from the service com-panies.
These “mixed” companies,
state-controlled but with listings
on public stock exchanges, now
supply about 13 per cent of world
liquid production.
There remains a large section
of the industry, controlling about
50 per cent of world oil reserves,
where private companies partici-pate
RESHAPING
THE OIL
AND GAS
INDUSTRY RESOURCE NATIONALISM
OPINION
John V. Mitchell, associate research fellow
at Chatham House, the Royal Institute of
International Affairs, sketches the changing
shape of the global oil and gas industry –
and concludes that there are no certainties
ȖȖIt is easy to assume newly discov-ered
oil and gas reserves represent
a no-lose situation for a country or
government, as well as commercial
partners. However, with increased
export duties, restrictions and
measures, such as legislated local
ownership, all potentially impact-ing
supply and viability, there can
be pitfalls and risks.
Rather than boosting politi-cal
independence and sovereign
wealth, reactive approaches to
resource nationalism can have
unintended, adverse consequences
for energy security.
“A degree of resource national-ism
can be a good thing,” says
Sam Wills, research fellow at the
Oxford Centre for the Analysis of
Resource-Rich Economies. “Har-nessed
properly, it makes countries
better places to do business, plus it
helps bring the greatest economic
and social benefit to the popula-tion.
However, taken too far, it
forgoes benefits of foreign finance
and expertise, limits transparency,
and can lead to corruption, poor
investments and inflation.”
The poster child for resource
nationalism is Norway. The coun-try
has transitioned from a 10 per
cent royalty on 1969 North Sea
oil, to collecting 78 per cent of
oil and gas revenues in taxes and
a sovereign wealth fund worth
more than $100,000 per capita.
If Norway is the past and present,
East Africa could be the future, as
Dr Wills suggests:
“In November 2013, leaders
of the East African Community
endorsed a move towards mon-etary
union. However, the past
three years have seen huge oil and
gas discoveries in Kenya, Uganda
and Tanzania.
“Confining this wealth within
each country would see them
grow at vastly different rates.
Resource nationalism could mean
the difference between a vibrant,
emergent East Africa and instabil-ity
in a developing region of 150
million people.”
Potential pitfalls of resource
nationalism are many, as global oil
& gas transactions leader at profes-sional
services firm EY, Andy Bro-gan,
explains. “Oil and gas ‘crowds
out’ other activity, leading to a
lopsided economy which becomes
vulnerable to shocks. Inadequate
local engagement and content can
also mean employment and long-term
investment is imported, giv-ing
rise to very narrow distribution
ȖȖThe oil and gas industry is
changing to a “multipolar” struc-ture.
This comes after the “bipolar”
model of the international oil com-panies
and OPEC (Organization of
Petroleum Exporting Countries)
which dominated the last quarter
of the 20th century, and the ear-lier
monopolistic regime of the
so-called “seven sisters” oil giants.
These structures floated on the
geopolitics of imperial and colo-nial
power in the 30s, the rising
nationalism of the 60s and 70s
in developing countries, and will
now ride on the current integra-tion
of Russia and China into the
world economy. The strategic local
choices of industry players will
decide who gains and loses in the
new game.
The industry now faces:
• Higher oil prices – around $100
a barrel – which open the door to
new suppliers and substitution
• Application of new supply tech-nologies,
which reduce the effect
of depletion and cut off the peak of
“peak oil”
• Flattening and even reversal
of growth in demand for oil in
developed countries, as a result
of higher prices, new technology
in the automobile and other user
industries, and above all in the
increasing strength of policies to
restrict greenhouse gas emissions
• New focus of downstream
growth questions of security of
supply in Asia rather than in
the Organisation for Economic
Co-operation and Development
(OECD)
• Mismatch between the oppor-tunities
for investment, the funds
available, and corporate structures
through which funds and opportu-nities
are brought together.
The balance within the oil indus-try
is changing. The advantages
of the largest international oil
companies lie in the past. They
have strong generation of funds,
but their opportunities are limited
geographically to high-cost and
difficult exploration and produc-tion.
The strength of local and
national companies excludes them
from most of the downstream
growth in developing markets.
In 2006 there were six interna-tional
private sector companies
among the world’s top ten oil
producers. In 2012 there was one.
There are now only 19 private
sector companies in the top 50 oil
producers and their share of pro-duction
has dropped by 5 per cent
to below 20 per cent, less than the
growing share of smaller, private
sector companies outside the top
50. The share of production from
the wholly-owned state companies
in the top 50 has fallen slightly, to
around 46 per cent, though the
biggest companies have increased
their part of it.
More and more large state-controlled
companies are being
partially listed in financial mar-kets;
for them the traditional
international company package
of “money plus management
as contractors to state com-panies.
These do not offer the kind
of “bookable reserves” which large
international companies have
been seeking, but small and mid-cap
[mid-market capitalisation]
companies have been successful
in striking new deals with new
producers outside OPEC.
The critical factor for success is
to match local needs and institu-tions
with appropriate foreign
resources. The smaller private
sector and state companies may
find it easier to focus than big,
bureaucratic corporations whose
bureaucracies may not offer the
same continuity of attention.
About 70 per cent of world gas
consumption is supplied from
within each consuming country.
Growth depends on finding prices
in each market which simultane-ously
expand demand and supply
to that market. Transportation
costs separate markets. Investors
in the international gas trade face
volume and price risks from the
different government policies for
power generation from renewables
or nuclear energy.
The key uncertainties for the
major players are do the no-growth
OECD downstream businesses add
value, and are upstream invest-ments
cornered into high-cost
projects, which will be vulnerable
if in fact global demand levels off
and eventually declines?
Investors can no longer assume
an escalator in oil demand or prices.
It is not difficult to generate sce-narios
in which strong emissions
policies lead to oil being left in the
ground at the end of the century. It
will be the most expensive oil in the
world, on the books of those com-panies
who invested in it.
The critical factor for success is to
match local needs and institutions
with appropriate foreign resources
of economic gains,” he says.
Not necessarily just about the
money, there is more to resource
nationalism than export restric-tions
and tax revenues alone, he
argues. “Governments don’t just
want economic exposure, but
much greater involvement in the
supply chain and operations. This
can be positive, but also negative
if there is inadequate local supply
of people, services or kit,” he says.
“International oil companies
[IOCs] need to become experts
in local stakeholder engagement
and in partnering with national oil
companies on a more equal basis.
IOCs are successful when they can
articulate the benefit they bring –
historically this used to be capital,
but now it needs to be much more.”
While cash might not always be
king, what if the resource value
cannot be realised and numbers
stop adding up?
Depending on quite how the
game plays out, countries or
companies sitting on ill-chosen or
badly-managed fossil-fuel assets
are increasingly in danger of
being left holding expensive,
unplayed cards.
Divestment campaigns are
upping the ante, as Ben Caldecott,
director of the stranded assets
programme at Smith School of
Enterprise and the Environment,
University of Oxford, points out.
“Countries with relatively high-cost
reserves may never be able to
extract them profitably as new fac-tors
continue to place downward
pressure on demand and price.
These include significant develop-ments
in renewables deployment,
shale gas, efficiency, air pollution,
water stress and social factors such
as divestment, as well as climate
policies,” he says. “All things being
equal, fossil-fuel divestment will
put higher-cost reserves at more
risk of becoming stranded assets.”
The global grassroots movement
of the divestment campaign is
growing, particularly in church
and on campus. Endorsed by reli-gious
leaders, communities and
multi-faith groups, it is also mobi-lising
support across universities,
schools and colleges, particularly
in the United States, as evidenced
at Harvard by an open letter,
signed by nearly 100 faculty mem-bers,
calling for divestment of the
$33billion university endowment.
Author and environmentalist
Bill McKibben, founder of 350.
org, which has led the campus
divestment campaign, is direct in
his description of new discovery
issues. “Finding new hydrocarbons
is a serious Midas problem. We
can’t burn them without wreck-ing
the planet, but each new mine
or field creates a small group of
potential billionaires who will do
anything to get them out,” he says.
The prognosis is apocalyptic
in his forecast of what the future
holds for fossil-fuel assets.
“It all depends on whether the
world ever takes global warming
seriously. If it does, they’ll take a
bath, and if it doesn’t, well, then
we’ll all take a different kind
of bath.”
Oil and gas professionals not yet
persuaded by the rhetoric to take
divestment seriously, might be
interested to learn which nation
opened debate this year on pulling
its $840-billion wealth fund out
of fossil-fuel stocks – the country
is Norway.
Stakes just rose for resource
nationalism.
Fighting in South
Sudan has cut oil
production, the country's
economic lifeline
Governments don’t just want
economic exposure, but much
greater involvement in the
supply chain and operations
78
%
OF NORWAY’S OIL
AND GAS REVENUES
COLLECTED IN TAXES
Source: Statoil
$840bn
TOTAL WEALTH FUND
DEBATED FOR FOSSIL-FUEL
DIVESTMENT
Source: Thomson Reuters
$33bn
VALUE OF HARVARD
UNIVERSITY ENDOWMENT
Source: Harvard Magazine
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