In 2012 distillate fuel oil accounted for a record 29
percent of output from U.S. refineries, up from less than 22
percent in 1993.

Rising production of distillate fuel oil to meet increasing
demand for road diesel has come mostly at the expense of
residual fuel oil and gasoline, according to the Energy
Information Administration (EIA).

But growing output from shale formations, which produce
light crudes more suitable for making gasoline than diesel,
threatens to throw the diesel maximisation process into
reverse.

CRUDE SLATE

In the last two decades, U.S. refiners have improved their
processes to maximise diesel production without major capital
expenditure. Some have also invested in expensive hydrocrackers,
able to break up heavy molecules destined for bunker fuel into
lighter and more valuable molecules suitable for use in diesel
or gasoline.

But the crudes they use are more important than a plant’s
process configuration in determining diesel yields, according to
a study prepared by the EIA on “Increasing distillation
production at U.S. refineries” published in December 2010.

The EIA concluded that refiners could boost distillate
yields (including jet fuel) up to a theoretical maximum of 49
percent by processing heavy crudes, optimising their processes
and employing a hydrocracker. Light crudes such as those from
shale would yield a maximum of only 37 percent under the same
conditions.

These are ideal yields. Actual distillate yields would be
lower. But the study illustrates the advantages of processing
medium and heavy crudes to maximise diesel.

EVERY LAST DROP

For more than 50 years, U.S. refiners almost always sold
gasoline at a higher price than diesel and have focussed on
maximising gasoline production. By 1993, refiners were producing
twice as much gasoline as distillate fuel oil.

But over the past two decades, the demand for diesel outside
the United States has been growing much more rapidly than for
gasoline and other refined products.

Dieselisation has been especially pronounced in Europe,
where favourable fuel taxes have pushed the proportion of diesel
cars from 13.8 percent in 1990 to 32 percent in 2000 and 46
percent in 2009.

Dieselisation has unbalanced the world fuel market and left
refineries struggling to produce enough distillate while they
make too much gasoline.

The European Union is set to phase out the tax preferences
for diesel after recognising the constraints on the refining
system.

Meanwhile, U.S. refiners have responded by becoming major
distillate exporters. Between 2004 and 2012, distillate exports
have risen every year, climbing from 110,000 barrels per day to
over 1 million.

U.S. distillate prices have moved to a premium over gasoline
prices since 2005, and refiners have scrambled to wring every
last drop of diesel from the crude they refine (Chart 1).

****************************************

Chart 1: link.reuters.com/pub98t

Chart 2: link.reuters.com/rub98t

****************************************

HYDROCRACKING

The simplest way to boost diesel production is to invest in
a hydrocracking unit. Hydrocrackers take heavy molecules left
over from vacuum distillation, catalytic cracking or coking and
break them apart into smaller molecules by applying heat and
tremendous pressure in the presence of a catalyst and hydrogen.

Hydrocrackers were originally installed to maximise gasoline
production. But by turning down the temperature and selecting
the right catalyst, refiners have been able to repurpose them to
boost distillate.

As a bonus, the hydrogen reacts with any sulphur contained
in the feedstock to form hydrogen sulphide, which can be
removed, so the hydrocracker produces very clean fuel that meets
specifications for ultra-low sulphur diesel (ULSD).

Hydrocrackers have become one of the most useful units in a
modern refinery. U.S. refiners have doubled their hydrocracking
capacity from 900,000 barrels per day in 1982 to 1.9 million in
2012, according to EIA.

In 1982, hydrocrackers could be employed to upgrade just
five barrels out of every 100 fed into a U.S. refinery. By 2012,
that had doubled to 10.5 barrels (Chart 2).

In its “World Oil Outlook 2012,” OPEC predicted the
utilisation rate for hydrocrackers around the world would be
over 90 percent through 2020 to meet the strong demand for
diesel.

Installing a hydrocracker can boost a refinery’s distillate
yield by 4 to 8 percentage points, according to Valero, the
largest independent refiner in the United States.

Unfortunately, hydrocrackers are very expensive. Special
steels are needed to contain the severe conditions needed for
the reaction (up to 2,000 pounds per square inch at 750 degrees
Fahrenheit) and resist intrusion by the hydrogen leading to
brittleness and failure.

Hydrocrackers also give off large amounts of heat, so
careful controls and elaborate quenching systems are needed to
prevent runaway cracking.

PROCESS IMPROVEMENTS

In the short term, many refiners have focused on process
improvements, which can boost diesel yields by 3 to 5 percentage
points without the need for significant capital expenditure.

The simplest change is to expand the range of liquids sent
for middle distillate production, rather than gasoline or heavy
gasoil production, by changing the “cut points” in the
distillation tower and downstream conversion units.

Normally, middle distillates include all streams with a true
boiling point between 400 degrees and 650 degrees Fahrenheit. By
expanding the range slightly to include liquids that boil
between 360 and 700 degrees, some of the liquids previously sent
to gasoline production and heavy gasoil can be retained as
distillates instead.

The problems are potential loss of quality and the need to
have enough hydrotreating capacity to remove sulphur from all
the extra distillate being made so that it meets the
specifications to be sold as road fuel.

Diesel production can also been improved by better
fractionation.

In theory, middle distillates include all molecules boiling
between about 400 and 650 degrees. In practice “the quality of
distillation in commercial refinery units is sloppy”, according
to the EIA. Large numbers of molecules that should be retained
as distillates instead end up in the gasoline pool or as heavy
gasoil.

More accurate separation can boost diesel yields while
improving the quality of gasoline. European refiners have long
had an incentive to squeeze every drop of diesel they can from
the distillation and downstream units. U.S. refiners are still
some way behind.

Nonetheless, in response to a spike in distillate prices in
summer 2008, U.S. refiners have raised diesel yields mostly by
process improvements and cut gasoline yields, according to the
EIA.

MISFIT SHALE

In 2008, refiners squeezed more extra diesel from medium and
heavy crudes than from light ones. Refineries processing light
crudes with an average density of 35 degrees API raised their
distillate yield by 3 percent, but refineries processing heavy
crudes under 28 degrees API boosted their yield by 5 percent.

Shale oil from formations such as Bakken is even lighter
than Brent and WTI, averaging more than 40 degrees API, so it is
not a good fit for refiners aiming to maximise diesel output.

Bakken yields much more gasoline and far less distillate
than other domestic crudes such as Louisiana Light Sweet (LLS)
and Alaska North Slope, according to Continental Resources, one
of the Bakken pioneers.

Process improvements can go only so far to offset the impact
of changes in the crude slate.

U.S. refiners continue to blend shale oil with imported
medium and heavy crudes from Saudi Arabia and other countries to
improve diesel yields. But it may not be enough to produce as
much diesel as they would like to sell.

(editing by Jane Baird)

Nowhere is that more obvious than in changes it has forced
in the official selling prices Saudi Arabia charges to its
customers.

More than half of Saudi Arabia’s crude exports head to
refineries in China and the rest of Asia. Not a single barrel of
U.S. shale oil is sent to the region because of the export ban.

Nonetheless soaring output of light sweet crudes from shales
in North Dakota and Texas has already profoundly affected
selling prices by displacing former imports from Nigeria, Libya
and other light oil producers.

One result has been a sharp narrowing of the former pricing
differential between light and heavy crudes, which has
intensified problems for African light crude producers.

SAUDI GRADES

Prior to 2011, the marginal barrel demanded by refiners
around the world was becoming progressively lighter and sweeter,
while the marginal barrel offered by producers was becoming
heavier and sourer, creating a record price gap between light
and heavy crude oils.

Since 2011, the situation reversed. The marginal barrel
demanded by refineries is heavier and sourer, while the marginal
barrel offered to the market is lighter and sweeter shale oil,
causing the gap to narrow.

The sharp turnaround is evident in the structure of Saudi
official selling prices (OSPs). In June, the OSP for heavy Saudi
crude sold to Asian refiners was just $2.70 below the price for
light crude, compared with a gap of almost $6 two years ago (link.reuters.com/hek88t).

Saudi Arabia exports various crude grades, each of which is
a blend of output from different fields and priced separately,
under a formula system of premiums and discounts linked to
international benchmarks. Sales of Arab Light, Arab Medium and
Arab Heavy to refiners in Asia are all benchmarked against
Oman/Dubai crude and ultimately Brent.

All Saudi crudes are denser and contain more sulphur than
international markers like Brent and West Texas Intermediate
(WTI).

Vacuum distillation of Arab Medium and Arab Heavy leaves 60
percent heavy residues compared with just 40 percent for Brent,
according to an assay published by researchers from Lukoil and
Bulgaria’s University of Chemical Technology and Metallurgy
(“Evaluation of crude oil quality” Feb 2010).

Both Saudi crude grades contain a large share of asphaltenes
and other large molecules that can’t be used in gasoline, diesel
and jet fuel. Vacuum residues must therefore be processed
further, which is expensive, or sold at a loss for use as road
cover or in marine bunker fuels and industrial boilers.

Arab Medium and Arab Heavy also contain 7 times more sulphur
than Brent, and substantially more nickel and vanadium which
poison (deactivate) refinery catalysts. This also makes them
much more difficult and expensive to handle.

MIND THE GAP

Until 2008, increasingly stringent regulations for sulphur
in gasoline and diesel sent refiners chasing after light low
sulphur feedstock.

At the time, all of the world’s spare capacity was held by
Saudi Arabia, in the form of fields that could only produce
heavier and sourer oils.

The resulting squeeze on light sweet crude availability sent
Arab Light to an increasing premium, while denser and sourer
oils like Arab Medium and Arab Heavy were offered at discount,
reflecting the greater difficulty that refining them presented.

By the middle of 2008, Arab Heavy was being offered to
refiners in Asia more than $8 per barrel below Arab Light, and
the gap briefly touched $10 in June.

Sharply reduced demand for all crudes amid the recession in
2009 crushed the differential. The gap began to re-emerge in
2010 and early 2011 as the global economy recovered.

Since the middle of 2011, soaring output of light sweet
crudes from U.S. shale formations have saturated the light end
of the market, while new refineries in Asia and the Middle East
have come onstream designed to handle heavier crudes.

In 2012 the United States reported the largest one-year
increase in oil production for any country on record. Almost all
of this extra oil has been light and sweet from shale formations
like North Dakota’s Bakken and Eagle Ford in Texas.

Surging production of shale oil has backed out an equivalent
amount of light sweet oil imports from Nigeria and Algeria,
which are now being offered into Asia instead.

Iran’s exports have been cut by sanctions, which has
tightened supply at the heavy sour end of the market.

In theory, Saudi Arabia should be able to extract higher
prices for its oil during third quarter, when soaring summer
temperatures at home cause a peak in crude burning to meet
electricity demand, and the availability of crude for export
should be tightest.

Instead, this year mounting competition from rival
medium-sour producer Iraq as well as light-sweet producers such
as Nigeria and Algeria, has forced Saudi Arabia to offer its
customers more attractive official selling prices for all crude
grades in July to defend market share.

Shale is pitting OPEC’s Middle Eastern and African members
against one another.

(Editing by Anthony Barker)

Centrica announced Thursday that it has bought a 25
percent stake in Petroleum Exploration and Development Licence
(PEDL) 165 which covers the Bowland shale in Lancashire, from
Cuadrilla Resources and AJ Lucas.

Centrica will pay £40 million in cash now, with a further
£60 million payable if the company elects to continue into the
development phase.

In the meantime, Centrica will also pay up to £60 million to
cover the cost of drilling exploration and appraisal wells to
establish whether shale gas can be produced commercially in the
area.

BOWLAND SHALE PLAY

Like its main rival, IGas, Cuadrilla holds attractive
exploration and development licences covering areas in both
northwest and southeast England that have already produced oil
and gas from conventional wells, and are known to have extensive
shale formations which might produce far more if they were
stimulated using hydraulic fracturing.

However, so far Cuadrilla has only drilled three wells in
Bowland, and only one of them has been fractured, at Preese
Hall.

Initial drilling confirmed the thickness of the formation
and the presence of gas. Cuadrilla has estimated there could be
200 trillion cubic feet of gas in place in its licence area.

But the company was forced to suspend hydraulic fracturing
after attempts to stimulate the Preese Hall well induced a
series of small seismic tremors from nearby fault in 2011.

The moratorium was lifted by the government in December,
allowing fracturing operations to resume, subject to a strict
monitoring process.

CASH AND RISK-SHARING

Before committing to large-scale development, many more
wells need to be drilled and fractured to confirm the extent of
the play, its organic content, the proportion converted to gas,
and flow rates following fracturing, as well as identify any
particularly productive sweet spots for development.

In practice, Cuadrilla and IGas are both “concept
companies.” They have successfully marketed the potential of
Britain’s shale to investors and politicians, but lack the
financial resources to undertake the cost and risk of an
extensive drilling programme. Both need strong financial
partners to scale up exploration programmes and turn theoretical
resources into proved reserves.

Cuadrilla and IGas have each produced credible but
optimistic estimates for the potential amount of gas locked away
in the country’s main shale formations. In its own licence area,
which borders Cuadrilla’s, IGas claims there could be up to 172
trillion cubic feet of gas in place.

These ambitious estimates seem likely to win a cautious
endorsement from the British Geological Survey (BGS) when it
publishes its own updated estimates this summer, which are
expected to show a big upward revisions of the amount of gas in
place.

Cuadrilla and IGas have worked hard to rally support from
Britain’s business establishment and elements of its political
class behind the idea shale gas could provide much needed jobs,
tax revenue and energy as the country’s conventional oil and gas
resources decline.

Both companies have some experience navigating the complex
permitting regime that governs drilling and fracturing, which
requires at least 10 different licences from four different sets
of authorities, according to a recent pro-shale report by the
Institute of Directors (“Getting shale gas working” May 2013).

Cuadrilla sponsored the IOD report as part of its effort to
convince policymakers of the benefits of shale and encourage
them to remove the barriers to development, particularly in the
regulatory area.

IGas has revenues from conventional oil and gas wells. But
neither company has the financial resources to undertake a
substantial drilling programme that entails a high risk of
failure.

It has always seemed inevitable that Cuadrilla and IGas
would need to bring in partners with bigger balance sheets to
fund more drilling and share the risk.

CREDIBILITY AND EXPERIENCE

Centrica makes a particularly attractive partner because it
brings with it credibility as a major gas producer, extensive
expertise with drilling, safety and environmental compliance,
and its own network of contacts with politicians and regulators.

Cuadrilla will remain the operator, and Centrica’s
experience is mostly with conventional gas, but its involvement
lends the engineering reputation, compliance and assurance
systems that will be needed to convince politicians and local
communities shale can be developed in a safe and non-disruptive
manner.

In exchange, Centrica gets a fairly cheap option on one of
Britain’s most promising shale plays.

Britain’s last onshore licensing round was held in 2008,
before the transformational potential of shale was understood
and the country’s resources had been estimated, and drew only
limited interest.

Most of the licences awarded in the 13th round went to small
speculative developers, many of which have subsequently been
consolidated or listed on London’s Alternative Investment Market
(AIM).

The 14th onshore round, due next year, seems likely to draw
keener interest, given the upward revisions to Britain’s shale
resources, though some of the most promising shale blocks have
already been taken ().

Buying into PEDL 165 has given Centrica priority access to
one of the two most promising tracts drilled so far.

Such transactions are inherently strategic and risky, but if
Britain’s shale industry lives up to a fraction of the hopes for
it, Centrica will be a prime beneficiary.

Because methane is so much more potent than carbon dioxide as
a greenhouse gas, even small emissions can have a huge impact.
Depending on the time horizon, 1 tonne of methane has the same
global warming potential as 25-72 tonnes of carbon dioxide,
according to the Intergovernmental Panel on Climate Change.

As shale becomes progressively more important (it accounted
for 40 percent of all U.S. natural gas production in 2012),
accurate estimates of just how much methane is being lost into
the atmosphere become essential, yet the data remain
surprisingly sparse.

Shale critics have seized on a 2011 research paper by a team
from Cornell University that estimated as much as 3.6-7.9
percent of the methane from shale production escapes into the
atmosphere over the lifetime of a well.

These fugitive methane emissions make the global warming
potential of shale gas greater than for conventional gas or oil
and as bad or even worse than coal, according to the Cornell
team.

“The large greenhouse gas footprint of shale gas undercuts
the logic of its use as a bridging fuel,” the team concluded.
“Shale gas isn’t clean and shouldn’t be used as a bridge fuel.”

In 2011, the U.S. Environmental Protection Agency (EPA)
weighed in with its own revised estimates for emissions from gas
wells, which showed that the problem was much worse than
originally thought, and began pushing for stricter regulation
under the Clean Air Act.

Now the industry is hitting back by accusing the EPA of
“mismeasuring” methane leaks. “EPA’s methodology for estimating
these emissions lacks rigour and should not be used as a basis
for analysis and decision-making,” according to a report
prepared by consultants IHS CERA.

“The assumptions underlying EPA’s methodology do not reflect
current industry practices,” the report claimed. “As a result
its estimates of methane emissions are dramatically overstated.”

WELL SITE EMISSIONS

For both conventional and shale gas, most of the life-cycle
emissions come when it is burned, but production, processing,
transportation and distribution also result in small but
significant emissions of methane and carbon dioxide.

In 2011, methane and carbon dioxide emissions from
production, processing, transmission and storage amounted to the
equivalent of 177 million tonnes of carbon dioxide, about 2.6
percent of all U.S. emissions, according to the EPA’s “Inventory
of greenhouse gas emissions and sinks”.

Gas wells, rather than leaks from processing plants and
pipelines, are the largest source. Emissions from well sites
accounted for about 36 percent of the total in 2011, according
to the EPA, with smaller shares from processing plants (23
percent), transmission and storage (25 percent) and distribution
(18 percent).

Conventional gas wells release methane during workovers and
also when water and other liquids are periodically removed from
the well to improve gas flow. The precise amount is disputed;
EPA puts it more than 10 times higher than the industry’s
estimate.

But the real controversy centres on how much methane is
released when unconventional wells are drilled and fractured.
“Methane emissions are at least 30 percent more and perhaps more
than twice as great as those from conventional gas,” the Cornell
team warned.

FLOWBACK PERIOD

Once a well has been hydraulically fractured, it enters a
flowback period, lasting three to 10 days, when natural pressure
in the reservoir pushes the drilling and fracking fluids back to
the surface before gas production begins.

Initially the flowback stream is mostly water, but over time
the well produces an increasing proportion of gas, until the
proportion eventually rises high enough and the well is finally
connected up to the gas-gathering system.

The question is what happens to the methane that is produced
during the flowback period.

Flowback fluids are diverted to an open pit or enclosed
tank. In the past, methane was allowed to separate and escape
into the atmosphere, a process known as cold venting. Most
states now require the methane to be flared, which converts it
to less harmful carbon dioxide, or captured and sent for
processing.

“Cold venting is no longer industry standard practice …
although it was common as recently as a decade ago,” IHS CERA
admits. “Awareness of the harmful effects of cold venting has
caused the practice to fall out of favour.”

The EPA has been pushing the concept of reduced emissions
completions (RECs), also known as green completions. “Portable
equipment is brought on site to separate the gas … produced
during the high-rate flowback and produce gas that can be
delivered into the sales pipeline,” according to the agency.

But IHS CERA says that “for the most part, the proposed
regulations are already standard practice” and “the proposed
standards have the potential to codify good operating practice”
but they are unlikely to reduce emissions much further.

FLARING AND CAPTURING

Estimates for methane emissions from shale wells vary so
much because of different assumptions about exactly how much gas
is vented, flared and captured.

“Significant opaqueness surrounds real world gas handling
practices in the field, and what proportion of the gas produced
during well completions is subject to which handling
techniques,” according to researchers at the Massachusetts
Institute of Technology (MIT) Joint Programme on the Science and
Policy of Climate Change.

The Cornell team assumed all flowback methane was vented and
estimated that methane emissions could be up to 3.2 percent of
all gas produced from the well over its lifetime. EPA’s
estimates assumed a proportion was flared and some was captured,
but still underestimated the captured share, according to MIT.

The MIT researchers assumed that 70 percent of potential
fugitive emissions are captured, 15 percent are vented and 15
percent are flared, which they claim reflects “current field
practice”. If the MIT assumptions are correct, the figures for
emissions from shale gas wells would be cut by between
two-thirds and three-quarters.

MONEY TO BURN?

There are strong safety and economic reasons to limit
venting.

Gas is flammable and in some circumstances explosive. If all
the gas being produced during flowback were vented, it would
create a toxic and hazardous situation around the well site, and
fires and explosions would be common. But the shale revolution
has not been accompanied by a sudden upsurge in exploding wells,
CERA notes, which calls into question whether the Cornell and
EPA assumptions about widespread venting are correct.

Venting flowback gas would also make little sense
financially. If up to 3.2 percent of all the methane eventually
produced from shale wells were indeed vented during completion
and flowback, as the Cornell team claims, that would amount to
losses of almost 7 million cubic metres of methane per well,
according to MIT.

At wellhead prices of $4 per million British thermal units,
revenue losses would amount to $1.2 million per well, which
exploration and production companies could ill afford.
Industry-wide losses would run into hundreds of millions of
dollars per year.

According to MIT, the costs for capturing potential fugitive
methane are modest.

“For the vast majority of contemporary shale gas wells, the
revenues gained from using reduced emissions completions to
capture the gas produced during a typical flowback cover the
cost of executing such completions,” MIT concluded. That would
tend to support industry contentions that cold venting is no
longer common.

Given estimates that the vast majority of completion
emissions are already being captured, then “the production of
shale gas … (has) not materially altered the total greenhouse
gas emissions from the natural gas sector”, the MIT study said.

The only way to settle the controversy is to compile more
data on how flowback methane is handled.

EPA, the American Petroleum Institute (API) and America’s
Natural Gas Alliance (ANGA) have all begun to collect more data,
but it will be some time before robust and comprehensive
emissions estimates are available.

(editing by Jane Baird)

Shale will extend recoverable oil resources by only 11
percent but boost recoverable gas resources by 47 percent,
according to the agency’s report on “Technically recoverable
shale oil and gas resources: an assessment of 137 shale
formations in 41 countries outside the United States”.

Shale formations could produce an extra 345 billion barrels
of crude with current technology. But that is a relatively small
increment compared with the 1,642 billion barrels of already
proved oil reserves and 1,370 billion barrels of as-yet unproved
resources that are thought to be available from other sources.

Global oil consumption is currently running around 33
billion barrels per year, so shale would extend the current
resource base by around 10 years at present rates of use.

By contrast, shale gas could extend gas resources by 7,302
trillion cubic feet, comparable to existing proved reserves of
6,741 trillion cubic feet and unproved resources of 8,842
trillion cubic feet.

Shale would extend the life of gas reserves by 60 years.

In terms of energy content, shale has pushed up global gas
resources from the equivalent of 2.7 trillion barrels of oil to
almost 4 trillion, while crude resources have risen from 3.0
trillion to 3.4 trillion.

The implication is that hydraulic fracturing will have a
much bigger impact on the availability of gas and could help
cement the current cost advantage of using gas as a transport
fuel as well as a cheap source of power generation.

VISCOUS OIL

The main reason why hydraulic fracturing and horizontal
drilling are expected to have a bigger impact on gas is that gas
flows much more easily through fractured rock formations.

“Based on U.S. shale production experience, the recovery
factors used in this report for shale gas generally ranged from
20 percent to 30 percent,” EIA wrote.

“Because of oil’s greater viscosity and capillary forces,
oil does not flow through rock fractures as easily …
Consequently, the recovery factors for shale oil are typically
lower than they are for shale gas, ranging from 3 percent to 7
percent of the oil in place,” the agency wrote.

Even in the best shale plays, such as Bakken in North Dakota
and Eagle Ford in Texas, producers have recovered less than 10
percent of the oil and liquids originally in place.

Shale formations outside the United States could contain as
much as 5.8 trillion barrels of crude and liquids, according to
EIA, but just 287 billion may be recoverable, an average
recovery factor of 5 percent.

DISTRIBUTION

“Much of the shale resource exists in countries with limited
endowments of conventional oil and gas …(or) countries where
conventional hydrocarbon resources have largely been depleted,”
according to the study.

Exploiting shale could therefore reduce these countries’
risks of intentional or unintentional disruptions due to war or
embargoes.

Shale oil and gas resources are more widely distributed than
their conventional counterparts. But a slightly larger share of
the shale oil resource is concentrated in countries such as
Russia, Libya and Venezuela that are already major conventional
producers, whereas more gas is concentrated in countries that
are big importers such as China.

Assuming countries without large conventional deposits have
a stronger incentive to develop shale, the distribution suggests
shale gas could be developed slightly more quickly than oil.

The distribution of resources also suggests growing shale
gas supplies will continue to pose a strong challenge to oil
producers and exert long-term downward pressure on prices.

CHEAPER GAS

In the United States, gas currently costs less than a
quarter of crude after differences in their energy content are
taken into account.

Much of that advantage stems from the gas drilling boom in
2004-2008 as well as the relative isolation of the U.S. gas
market. Unlike oil, which trades in a global market, the
international gas market is small, and gas prices show big
regional variations.

Gas and oil prices are much more closely aligned in the rest
of the world. Even in the United States, the gap is likely to
narrow once a new set of LNG terminals awaiting regulatory
approval are built.

Nonetheless, if the shale report is right, natural gas
should still retain some of its cost advantage in the medium and
long term.

Seasoned industry observers have already noted that the
current differential is unsustainable. “Something’s got to give
if that differential stays around for too long,” Total
Chief Executive Christophe de Margerie said last year
.

Until now it has not been clear whether the gap will close
mostly through a rise in the price of gas, a fall in the price
of oil or some combination of the two. The comparative abundance
of shale gas suggests oil prices are much more likely to
converge down to gas, rather than the other way around.

Given the geological differences, natural gas looks set to
be the lower cost way of adding reserves over the next couple of
decades.

Many international oil companies already have significant
gas assets. Natural gas accounted for 50 percent of Shell’s
total production in 2012.

At some point, the international oil companies will need to
find better ways to monetise their gas assets. The majors have
the resources to push gas deeper into the transport market by
helping pay for infrastructure and promoting gas-fuelled
vehicles, according to one analyst.

Shale oil resources may delay the transition to the more
widespread use of gas as a transport fuel, but given the
relative abundance of the two fuels, some switch to gas seems
inevitable in the longer term, and the threat will help keep a
lid on long-term oil prices.

Exploration and production (E&P) activities have been hit by
shortages of everything from drilling rigs and pressure pumping
equipment to the guar gum used for hydraulic fracturing,
experienced geologists and drill team leaders.

The result has been soaring cost inflation. But with oil
prices now in the eleventh year of a bull market, the supply
situation is starting to improve, shortages are easing and
upward pressure on costs is beginning to abate.

TIME AND MONEY

Oil production is subject to long cycles. Part of the
problem stems from the long lead times for large capital
investments. It can take 7-10 years from discovery to put a
major offshore oilfield into production and a similar time to
design and build a gas-to-liquids plant.

However, some of the most intractable challenges lie in the
supply chain. Oil and gas exploration and production require
substantial amounts of equipment and specialist personnel, few
of which are shared with other industries.

E&P budgets have to sustain a complex eco-system of prime
contractors and sub-contractors to provide drilling, surveys,
chemicals, specialty steel tubing, pressure pumping equipment
and more mundane items like guar gum and fracturing zeolites.

Many of the problems that have hampered production over the
last 10 years stem from decisions made during the prolonged
period of low oil prices in the 1990s to slash budgets, lay off
skilled engineers, drillers and geoscientists, and cut
recruitment.

The result was a rapidly ageing workforce and badly reduced
supply chain which struggled to respond to the sudden return of
demand from E&P companies.

Shell’s outgoing chief executive, Peter Voser, explained the
long-cycle dynamic in a recent interview with my colleague Andy
Callus.

“One learning out of all this, for every person in this
organisation now, is you spend capex through the cycle. Don’t
try to read it, don’t slow down. It will cost you more when you
want to grow afterwards,” Voser warned.

“I know a lot of investors and analysts. They all think they
can read the market … slow down, grow later, shrink to grow,
all these buzzwords, but one thing in our industry is very
clear; it takes you five to seven years to recover a strategic
slowdown… The market changes its views in three to six months,
and you can’t change that fast in our industry.”

Rebuilding supply chain takes both time and money.
Fortunately, the oil industry now has plenty of both.

Using Brent as a benchmark, average crude prices have risen
in 10 of the 11 years between 2002 and 2012, with only a brief
decline in 2009 (Chart 1).

High prices mean buoyant cash flows. In 2013, oil and gas
companies will spend a record $678 billion on exploration and
production, up 10 percent from 2012, according to a recent
survey by Barclays Capital.

***************************************

Chart 1:

Chart 2:

Chart 3:

***************************************

GLOBAL DRILLING

In the early years of the bull market fears about a return
to low prices restrained capital expenditure. As the boom has
endured, however, E&P companies have become more confident and
shown more willingness to undertake spending programmes that
will take years to pay back.

The drilling boom has been most obvious in the shale plays
of North America, where it has also resulted in a big build out
in the supply chain for everything from modern drilling rigs and
seismic crews to pressure pumps and fracturing sand.

But the drilling boom is gradually going global. E&P budgets
outside North America are predicted to rise by 13 percent in
2013, compared with just 2 percent in North America itself,
according to the Barclays survey.

The gradual globalisation of the E&P boom is reflected in
monthly rig counts published by oilfield services company Baker
Hughes.

The number of onshore rigs actually drilling for oil and gas
outside Canada and the United States has almost doubled to 960
in the first five months of 2013, from just 500 in 2002. (Chart
2)

The biggest increase has been concentrated in the Middle
East, where traditional producers such as Saudi Arabia, Abu
Dhabi and Kuwait are now drilling much harder to replace
declining output from their aging fields.

But drilling activity has more than doubled in both Europe
and Africa, according to Baker Hughes. Onshore drilling in
Europe and Africa is at the highest level since the beginning of
the 1990s and around 80 rigs are now working in both regions
(Chart 3).

BUILDING CAPACITY

Because wages and prices have been escalating, the activity
has risen more slowly than E&P budgets let alone output, which
has erroneously led some analysts to conclude that the finding
and lifting costs of oil and gas are inexorably rising.

In fact, cost inflation is the inevitable price for
rebuilding a shrunken supply chain and labour pool. E&P firms
have paid premium prices to attract new workers and suppliers
into the oil and gas patch. But as the rebuilding of the supply
chain is completed, cost inflation should slow, and prices in
some areas are likely to come down.

Different elements of the supply chain have been built out
at different speeds.

The volume of pressure pumping equipment in the United
States has grown so rapidly the market was suffering from 25
percent overcapacity by the end of 2012, according to one
estimate by a market intelligence firm. In other areas,
shortfalls persist and prices are still rising rapidly.

Cost inflation therefore remains problematic for the major
E&P companies, but there are signs it has started to decelerate,
and it should slow further in 2014 and 2015 as the investment
cycle matures.

So far the evidence remains thin. Only a tiny number of
shale wells have actually been fractured outside North America.

In the United States, shale production has come from nowhere
to account for more than 30 percent of gas output, and more than
a 1 million barrels per day of crude and condensates, in under a
decade.

The U.S. Energy Information Administration (EIA) estimates
global shale gas resources could amount to 6,600 trillion cubic
feet, similar to conventional gas resources, effectively
doubling the resource base. Shale oil resources could be
similarly large, though no comprehensive global estimates have
yet been published.

In a landmark 2011 study, EIA identified 48 major shale
basins in 32 countries, including massive shale plays in China,
Argentina, South Africa, Poland, France and the Maghreb. The
study did not assess shale basins in the Persian Gulf region or
the Russian Federation but these are likely to contain even more
oil and gas (“World shale gas resources: an initial assessment
of 14 regions outside the United States” Apr 2011).

Many estimates are still being revised higher. The EIA study
put the United Kingdom’s technically recoverable shale gas
resources at 20 trillion cubic feet. The British Geological
Survey more conservatively estimated potential reserves at 5.3
trillion cubic feet (“Unconventional hydrocarbon resources of
Britain’s onshore shale gas” 2010).

More recently, however, shale driller IGas has claimed there
could be as much as 172 trillion cubic feet of gas initially in
place in just one 300 square mile block in the northwest of
England where it has acquired exploration and development
rights.

Of course, gas initially in place is not the same as
technically recoverable let alone economically recoverable
reserves. But if even a tenth of the estimated gas resources is
producible with current technology and prices, the potential
reserve base would far exceed previous estimates.

BGS is scheduled to update its own estimates this summer,
and they are expected to show large upward revisions.

GUARDED OPTIMISM

These high estimates have sharply split the oil and gas
community.

Sceptics doubt whether the U.S. experience can be repeated
elsewhere on any significant scale, and include many prominent
oil analysts, as well as conventional producers like Saudi
Arabia.

Enthusiasts are convinced the rapid rise in oil and gas
output in the United States is merely the beginning of a
worldwide revolution that will dramatically alter the outlook
for the availability and price of fossil fuels.

The International Energy Agency (IEA) notes cautiously that
“fossil fuels are abundant in many regions of the world and they
are in sufficient quantities to meet expected increasing
demands” but that “resources are not reserves.”

“A key role for the industry is to convert resources into
reserves” through investment and innovation.

MORE DRILLING NEEDED

Optimistic estimates rest on a very thin base of evidence.
Experience with shale development remains confined to a handful
of plays in the United States.

The EIA has identified 20 large shale gas and oil plays in
the United States, but almost all production so far has come
from just a handful of them (including Bakken and Eagle Ford for
oil, Barnett and Haynesville for gas).

Drilling and fracturing in other plays has so far been
modest, and the results have been disappointing. The same is
even true abroad.

Poland has drilled fewer than 50 wells and fractured only 4;
flow rates have been disappointing and some energy companies
have given up.

China has drilled a couple of dozen wells in the Sichuan
basin, its most promising area, but shale gas development lags
far behind the government’s ambitious programme.

Argentina has drilled only a handful of wells into its giant
Vaca Muerta (Dead Cow) formation. France has banned fracking in
the Paris Basin, the largest prospect shale play in Western
Europe.

For all the hype about its abundant shale gas resources,
Britain has only drilled and fractured one well so far, though a
second will be fractured this summer.

SHALES ARE NOT ALIKE

The problem is that shales (and other tight oil and
gas-bearing rock formations) vary tremendously so it is perilous
to draw analogies from one to another.

Gas and oil are diffused throughout the rock in much the
same way water is diffused through a sponge. But shales exhibit
tremendous variety in terms of the size of the oil and
gas-containing pores, how much of the pore space is taken up by
water, how much organic material they contained in the first
place and how much has been converted into oil and gas by being
buried and heated to just the depth and temperature.

These variations matter when it comes to estimating how much
oil and gas the shale contains (and how much is recoverable) as
well as deciding what techniques to employ to produce it.

In most cases, resource estimates have been done by taking
the average thickness and extent of the shale formation to
calculate its total volume, then applying estimates of its
average porosity, total organic content and thermal maturity to
estimate how much oil and gas it might contain.

But without drilling dozens or even hundreds of wells to
explore, appraise and develop formations most of these
“geology-based estimates” remain subject to tremendous
uncertainty. No amount of professional guessing can substitute
for actually drilling holes in the field.

The characteristics of an individual formation matter even
more in the production stage. Many analysts have focused on the
problems associated with producing from unusually deep or thin
formations, but clay content can be an even bigger problem.
Clayey formations are much harder to fracture and prop open,
leading to disappointing flow rates.

A host of other characteristics such as faulting and
discontinuities contribute to what geologists and drillers term
“complex” formations that are tricky to produce.

In the main U.S. shale formations, exploration and
production companies and their field service agents have been
able to determine the most efficient way to develop the
formation by drilling thousands of holes using a trial and error
process.

Play-specific knowledge includes how long the horizontal
portion of the well should be, how many separate stages should
be fractured, what pressure to use, how much water to employ,
what amount of frack sand, and what chemical cocktail to use to
maximise recovery.

For other plays, the industry is still at the very beginning
of the learning curve for other shale plays in the United States
and overseas, and not climbing it very quickly.

The potential of shale gas and oil is clear, but how much
can be produced and at what cost is still poorly understood.

Both sceptics and enthusiasts have been too quick to draw
sweeping conclusions on the basis of a handful of plays.
Cautious optimism is a more appropriate stance until we have
more information.

The only way to find out how much shale gas and oil might be
available is to start actually drilling and fracturing and see
just how much the wells flow.

(Editing by James Jukwey)

“It’s one thing to have fracking in the vast plains of
America,” according to one Conservative Member of Parliament
quoted in the Financial Times recently. “It’s a whole different
matter when people will see gas production in the rolling hills
of Surrey.”

The newspaper noted the petroleum-rich Wessex Basin
corresponds with the heartland of Britain’s ruling Conservative
Party. “No fewer than 38 out of 62 MPs in the region have land
with existing oil and gas drilling licences – and 35 of them are
Conservatives” (“Britain’s Tory MPs face fracking challenge” May
19).

The political subtext is that while fracking might be
acceptable in northern counties that have struggled to recover
from the collapse of the coal industry and heavy manufacturing
in the 1980s, which tend to support the opposition Labour Party,
it may not be welcome in prosperous rural areas of the south.

The recent Institute of Directors’ report on “Getting shale
gas working” concentrated on the benefits in the north, and was
silent about the south. It noted “jobs could be created in parts
of the country that need them most,” contrasting the 15 percent
rate of out-of-work benefit claims in the north west with less
than 9 percent in the south east.

So it might come as a surprise to many people that southern
England is already the largest producer of onshore oil and gas
in the United Kingdom.

ONSHORE OIL AND GAS

More than 2,000 onshore wells have been drilled across the
country, with major drilling booms during the Second World War
and then again in the 1980s after the oil shocks, according to
well records published by the Department of Energy and Climate
Change (DECC).

Onshore fields have produced more than 500 million barrels
of oil, although that compares with 23 billion barrels produced
offshore since 1975, and the pattern is repeated for natural
gas.

Onshore fields tend to be small by offshore standards. But
the capital expenditure required to develop them is also smaller
and they continue to provide economically attractive targets,
according to the British Geological Survey (BGS) in a report on
“Onshore oil and gas” published in March 2011.

Onshore petroleum output is dominated by fields in the
Wessex Basin underneath the counties of East and West Sussex,
Hampshire, Dorset and the Isle of Wight, extending into the
English Channel.

Oil has also been produced from the East Midlands underneath
Lincolnshire, Leicestershire and Nottinghamshire, and gas from
North Yorkshire and the West Lancashire Basin (Charts 1 and 2).

By far the largest onshore field, however, is Wytch Farm, in
the heart of the Wessex Basin, discovered in 1979, with
estimated recoverable reserves of almost half a billion barrels
of crude.

************************************************************

UK onshore oil and gas wells: link.reuters.com/ryq68t

Location of wells by county: link.reuters.com/tyq68t

************************************************************

WESSEX/CHANNEL BASIN

Wytch Farm’s output peaked at around 100,000 barrels per day
in 1996. It is the largest onshore field in Europe, and ranks in
the top 10 UK oil fields, including those offshore, according to
BGS.

Located on the edge of the Jurassic Coast World Heritage
Site, production comes from dozens of wells on several sites,
including some of the longest horizontal wells in the world,
stretching up to 11 kilometres underground beneath Poole Bay,
beneath some of the most expensive real estate in the country.

Wells are screened by thousands of trees to minimise the
visual impact.

Some employ traditional nodding-donkey beam pumps, carefully
painted in forest colours to camouflage them, and with sound
boxes to limit noise to less than 33 decibels. Most, however,
use downhole electric submerged pumps and are virtually
invisible on the surface.

Oil is transported to a loading terminal by a 90-kilometre
pipeline that skirts the southern fringes of the New Forest
National Park.

Wytch Farm is on a unique scale, but there are other oil
fields in production elsewhere in the Wessex Basin, stretching
from Wareham in Dorset to Goodworth, Stockbridge, Avington,
Horndean and Lasham in Hampshire, and Singleton and Storrington
in West Sussex.

Other reservoirs in use for gas storage and/or oil
production stretch as far north as Palmers Wood, Bletchingley
and Lingfield in the county of Surrey.

These reservoirs are small but not negligible. Estimates put
oil originally in place at 170 million barrels at Stockbridge,
70 million at Singleton and 43 million at Lasham, though the
amount of oil that will eventually be produced will be much
smaller.

Most reservoirs lie within the boundaries of the South Downs
National Park or Areas of Outstanding Natural Beauty (AONB),
where development is strictly controlled. But well sites are so
well camouflaged they are invisible and virtually unknown, even
to local inhabitants.

More onshore wells have been drilled in the southern
counties of Dorset (264), Hampshire (117) and Sussex (82) than
other part of Britain except Nottinghamshire (575), Lincolnshire
(343) and Lancashire (115), according to DECC.

The full extent of oil and gas production across southern
England is revealed in an extraordinary blog compiled by
geologist Ian West, retired from the University of Southampton
(www.southampton.ac.uk/~imw/Oil-South-of-England.htm).

NOT IN MY BACK YARD

Given that southern England is one of the biggest existing
centres of oil and gas production, it is ironic that it has also
become a centre of opposition to hydraulic fracturing for shale
gas.

Balcombe in the middle of the South Downs National Park has
become a cause celebre for environmentalists and residents’
groups opposed to fracking. It is also in the heart of the
Wessex Basin and one of the most promising sites for shale gas.

One well has already been sunk in Balcombe, by Conoco in
1986, but it was plugged and abandoned after initial flows
proved disappointing and amid depressed oil and gas prices in
the late 1980s and 1990s. Now Cuadrilla Resources has a
petroleum exploration and development licence covering the area
and hopes to achieve better results by drilling and fracturing
the formation.

The company suspended its fracturing programme after
pressure pumping one well at Preese Hall in the northern county
of Lancashire, near to a faulted area, triggered a series of
small earth tremors. But it has announced plans to resume
fracturing at another well in the county, and wants to drill,
but not yet fracture, an exploration well in Balcombe later in
2013.

“Drilling work will commence in the summer,” the company
announced on May 8. “Cuadrilla plans to drill and take samples
of the underground rock in a vertical well drilled to
approximately 3,000 feet. A possible horizontal leg of 2,500
feet may also be drilled … neither … will be hydraulically
fractured,” the company added.

There is intense concern about the impact that widespread
drilling and fracturing might have on local communities.

“Because of the much more intense nature of the shale gas
extraction process it is associated with much more negative
impacts than conventional drilling. These include leaking
methane, water contamination, air pollution, radioactive
contamination, massive industrialisation of the landscape,
worsening climate change and earthquakes,” the Frack Free Sussex
campaign complains on its website.

But given the intense care local authorities have taken to
ensure that conventional oil and gas drilling does not blight
local communities, it seems unlikely they will be any less
careful with unconventional shale production.

Drilling multiple wells from the same site, and employing
long laterals with multi-stage fractures, with careful screening
and camouflaging, could in theory enable relatively large
volumes of oil and gas to be recovered in an acceptable manner.
The main problem is likely to remain traffic management.

There is some doubt about whether shale oil and gas could
ever be produced on a sufficiently large scale to transform
Britain’s economic prospects, but there ought to be no barrier
to developing a small but significant industry, even in the
sensitive political and natural landscapes of southern England.

(Editing by Anthony Barker)

The unexpectedly rapid growth in shale oil output has
rightly been termed a supply shock by seasoned observers, but it
is also a quality shock.

“U.S. light tight oil is distinctive in that rising
production is causing an unexpected quality shift in the global
crude mix,” the International Energy Agency (IEA) said last
month.

“The shockwaves of rising U.S. shale gas and light tight oil
… are reaching virtually all recesses of the global oil
market,” the IEA wrote in its 2013 Medium-Term Oil Market
Report.

“These powerful forces are redefining the way oil is being
produced, processed, traded and consumed around the world. There
is hardly any aspect of the global oil supply chain that will
not undergo some measure of transformation over the next five
years,” the agency concluded.

TURNED AWAY

In the first three months of 2013, U.S. refiners cut their
crude imports to just 681 million barrels, down from 785-800
million barrels in the same period in 2012 and 2011.

The reduction has fallen entirely on light grades, those
that compete most directly with similar domestic production from
shale plays such as the Bakken and Eagle Ford. Imports or medium
and heavy crudes have actually risen over the past two years.

According to the Energy Information Administration (EIA),
imports of light crudes with an API gravity of 35 degrees or
more fell to just 76 million in the first quarter of 2013 from
130 million in the same quarter in 2012 and from 162 million a
year before that.

***************************************

Chart 1: link.reuters.com/zyh68t

Chart 2: link.reuters.com/caj68t

***************************************

Imports from Nigeria, which produces mostly very light low
sulphur oils, have fallen more than 52 million barrels, while
crudes from Algeria were down by 21 million barrels.

By contrast, imports of medium and heavy grades testing 30
degrees API or lower are slightly higher since 2011 (Charts 1
and 2).

Legal restrictions prevent U.S. oil production being
exported.

But by displacing an equivalent volume of light crude from
Nigeria and Algeria, and forcing those countries to find new
markets in Europe and Asia, U.S. shale oil is effectively making
its way onto the global market.

In consequence, the global crude slate is becoming lighter
(and sweeter), radically altering the pricing relationship
between light-sweet and heavy-sour oils, and slashing the
traditional premium refiners have to pay for light grades such
as Brent.

At the same time, demand from refiners is shifting to
heavier oils which yield more diesel, as improved vehicle fuel
efficiency and ethanol blending mandates nibble away at gasoline
consumption in the United States.

QUALITY SHOCK

North American shale production is expected to expand
another 2.3 million barrels per day by 2018, and account for
well over 25 percent of global incremental output, according to
IEA.

Before the shale revolution, the consensus view was that the
global crude slate would become heavier and sourer, as dwindling
output from high-quality fields in the North Sea and elsewhere
forced refiners increasingly to rely on marginal supplies of
heavy, tarry crudes from Saudi Arabia, Venezuela and Canada.

Refiners in the United States and Asia responded by
investing heavily in units to strip out the undesirable sulphur
and convert the heavy residuals left over from processing
heavier and sourer crudes.

Shale has upended all those calculations. Crude from the
Bakken typically tests at 40 degrees API or even more. Saudi
oils are often 30 degrees or lower. Venezuela’s crude is often
below 20 degrees and sometimes as low as 10.

Shale oil is a “good fit for some U.S. refineries which had
seemed on the brink of closure, (but) the supply boom is proving
a challenge as well as an opportunity for others, which had bet
on a widening heavy-light price spread and invested massively in
upgrading capacity,” according to the IEA.

The impact is not confined to the United States. As light
crudes from Nigeria and Algeria are displaced from North
American refineries, they must find new markets in Europe and
Asia, where they compete with local supplies such as Brent and
Malaysia’s Tapis.

The unexpected lightening of the crude slate has thrown a
lifeline to refineries on the U.S. East Coast and in Europe
which had failed to invest in expensive conversion equipment. It
has also shifted the balance of power within OPEC even further
away from light producers in Africa and towards the heavier oil
producers in the Gulf.

Rather than selling into the Atlantic Basin, African light
oil producers are being forced to reorient their exports towards
Asia, where shipping routes are longer, and refiners have more
flexibility and can drive a harder bargain, eroding the
traditional premiums which their exports have commanded.

(Editing by Jason Neely)

Journalists and analysts have traditionally characterised
light sweet crudes as “high quality” and heavy sour ones as “low
quality,” with light crudes more scarce and valuable than their
heavy sour counterparts.

That simple characterisation no longer holds true.

The marginal barrel supplied to the market comes from North
American shale plays and is light and sweet, while the marginal
barrel demanded by refiners comes from the new complex mega
refineries in Asia, equipped with crackers, cokers and
desulphurisation equipment, and is much heavier and sourer.

The result is a growing mismatch between the crude slate on
offer from oil producers and that demanded by refiners.

ALL CHANGE, PLEASE

Conventional premiums for light sweet crudes were the result
of specific circumstances: (1) strong demand for gasoline rather
than diesel; (2) limited refinery capacity to process heavier
molecules; (3) limited capacity to strip sulphur from feedstock;
and (4) limited supplies of light sweet crudes compared with
abundant supplies of heavier and more sulphurous oils.

Each of these factors has now shifted substantially. It was
only a matter of time before the shift in crude supplies and
refinery demand transformed the traditional pricing
relationships between different crude grades.

The market for light sweet oils is now increasingly
oversupplied, while heavy sour grades are seeing stronger
demand. Conventional premiums for light sweet crudes have
eroded, and in some cases light crudes are even trading at a
discount.

The price adjustment will continue until it makes sense for
Asia’s complex refineries to start buying light sweet crudes and
forego the technological advantage of utilising their cokers and
desulphurisation units fully.

It is already changing the balance of power among oil
producers. Countries that produce heavier higher-sulphur crudes
like Saudi Arabia and Iraq are the main winners, while countries
like Nigeria and Libya with abundant light low sulphur supplies
that compete directly with U.S. shale oil lose out.

The shift is helping prop up struggling simple refineries in
Europe and on the East Coast of North America, blunting
competition from complex modern refineries in Asia and the U.S.
Gulf Coast, which no longer reap as much advantage from their
heavy investment in coking and desulphurisation plants.

A QUESTION OF QUALITY

All crudes are mixtures of different molecules. But light
crudes have a higher proportion of the light molecules used to
make premium fuels like gasoline, naphtha and to some extent
diesel, while medium and heavy crudes have a higher proportion
of molecules that can only be used to make diesel or sold at a
discount to ships and power producers as residual fuel oil.

Simple refineries that separate different molecules by
distillation have always prized light crudes because they yield
a higher proportion of more valuable products, especially
gasoline, which explains why light crudes traditionally
commanded large premiums.

Modern complex refineries, however, can convert and upgrade
the heavy residuals left over from distillation into lighter and
more valuable molecules by cracking and coking, squeezing out
more premium products from gasoline and naphtha to jet fuel and
road diesel.

Complex refineries also have some flexibility to decide
whether to crack large molecules into very small ones to make
gasoline or slightly larger ones to make diesel. Complex
refineries can therefore tailor their output to meet seasonal
variations in demand – maximising gasoline production to meet
summer driving demand in the United States, and diesel
production in the winter heating season.

Crucially, complex refineries can also make a strategic
decision to upgrade a large proportion of the residuals from
atmospheric and vacuum distillation into diesel rather than
gasoline all year round.

Dieselisation policies in the European Union and strong
demand for diesel as trucking fuel in emerging markets has left
the global refining system producing too much gasoline and not
enough diesel.

By processing medium and heavy crudes, which yield
relatively small amounts of gasoline, and then upgrading the
residuals into diesel, complex refineries can maximise diesel
production and generate higher returns from every barrel of
crude they process.

The same story can be told about sulphur, which must be
removed from finished fuels like gasoline and diesel to meet
quality specifications and increasingly stringent environmental
regulations.

Simple refineries preferred low sulphur (sweet) crudes, but
as more refineries have invested in hydrotreating units that
strip sulphur from feedstock by reacting it with hydrogen, the
advantage for sweet crudes has reduced and the price premium
that they command has fallen.

Light sweet oils may always have a small advantage over
heavy sour ones because conversion and desulphurisation require
extra energy and add to refineries’ operating costs, but the
margin is likely to be much smaller than before.

(Editing by Anthony Barker)