how the energy industry works 13

2013www.energy-future.com

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i found

ran a whole lot

Because geology’s a natural science, our work is complex and unpredictable. We never have all the

information, so the real challenge is fi lling in gaps.

Despite the 5am start, it was incredibly exciting when we called ‘total depth’ on the drilling of an offshore well. Weeks of studying data had gone into this single moment, but it’s only when all the rig’s eyes are on you that you understand just how important this decision really is.

It’s being involved in these big decisions that keeps me coming back for more every day.

my responsibilitiesmy responsibilitiesdeeper

seb turner, geologist, SUNBURY

035490-210x148-HTEIW.indd 1 24/10/2012 17:02

How the Energy Industry WorksThe ultimate guide to energy

Publisher: Silverstone Communications Ltd

London, [email protected]

ISBN: 978-0-9555409-8-1

© Silverstone Communications Ltd, 2013

Editor and co-founder: Tom Nicholls Co-founder: Edouard de Guitaut Writers: Derek Brower, Ian Lewis, Tom Nicholls, Mark RuddyLayout: Andrew Makin

Silverstone Communications Ltd. Directors: Tom Nicholls, Edouard de Guitaut, Caroline de Guitaut, Ana López

2 – www.energy-future.com

How the Energy Industry Works

Introduction1.1 Can I speak to an engineer, please? 4

Oil and gas supply and markets2.1 The price of oil matters 8

The oil value chain 14

Map: world oil reserves 16

2.2 Gas trading: Let’s talk about the weather 18

Oil and gas reserves: Are we running out? 22

Technology3.1 The hills (and seas) are alive with the sounds of seismic 24

3.2 Unconventional oil: A peak into the future 28

3.3 Refiningtechnology:Cartagena–topsforbottoms 35

3.4 Offshore technology: the pressure’s on 46

3.5 Solarenergy:Nearlyoutoftheshade 54

Future fuels4.1 Biofuels:Sowingtheseedsofsustainablefuels 61

4.2 GTL: Newish kid on the block 71

4.3 Naturalgasvehicles:FromAtoBwithouttoomuchC 75

Natural gas: special report The natural gas value chain 80

5.1 Whatisnaturalgas? 82

Measuring natural gas 88

5.2 Liquefiednaturalgas:Chilledenergy 91

5.3 Usesofnaturalgas:Bridgetoalow-carbonfuture 97

World natural gas reserves 100

5.4 Gettinggastomarket 103

5.5 Methanehydrates:Iceonfire 111

The directory of leading employersBP 117Chevron 119Gazprom M&T 121Repsol 123Schlumberger 125Technip 127

Contents


1.1 – Introduction

Can I speak to an engineer, please?The energy industry, and the world, need the best scientists, engineers and thinkers – and they need them now

With January temperatures that sit around -20 degrees – not including

the wind-chill factor – it isn’t much of a win-ter holiday destination. As for the summers, they’re hot and you’ll need to pack your mosquito spray.

It’s not a place for wimps.But revolutionaries are made of steely

stuff. And a job working in the Bakken oil-field of North Dakota would put you in the vanguard of an upheaval that is shaking up business and politics the world over.

People are moving to the state in droves. Since the dark days of 2008, when the US plummeted into recession, North Dakota has defied the country’s gloom, becoming a job- and wealth-creating machine. In 2011, its economy grew by a whopping 13%, out-pacing not just the rest of the US, but even China, India and the other fast-rising nations of the East.

Oil is the reason. Geologists have known since the 1950s that North Dakota’s weather-beaten plains sat above billions and billions of barrels of high-quality crude oil. Until 2008, though, no-one really thought the stuff could be brought to the surface and sold for a profit.

Fracking cleverTechnology changed that (see p28).

Advances in extraction techniques – like hydraulic fracturing, which busts open the Bakken’s vast shale beds, and horizontal drilling, which sends pipes remotely into the ground at inconceivable angles – have freed North Dakota’s oil.

Four years ago, the state produced barely 100,000 barrels a day, or about 0.5% of America’s oil needs. Now output is around 700,000 barrels a day – mainly from the Bakken – and just keeps on growing.

The same technologies have boosted oil and gas production in many other parts of the US – underpinning a revival in the world’s biggest economy that could drag it out of the slough and put its finances back in order.

It’s a remarkable transformation. Less than a decade ago, the US was facing an energy crunch. Natural gas supplies were dwindling and companies were building expensive new port facilities to bring in energy supplies from as far away as the Middle East. North Dakota: not a place for wimps



Politicians were fretting about where Americans would get the oil they needed to keep their cars on the road. The spectre of peak oil – depletion of the world’s most im-portant commodity – was haunting our pe-troleum-dependent way of life. America’s decline was imminent.

It’s all about the scienceBut the ingenuity of engineers and ge-

ologists put paid to that. According to the International Energy Agency (IEA), a multi-government think tank, the US will become the biggest oil producer in the world around the end of this decade, overtaking Saudi Arabia. In natural gas, it will knock Russia off its perch, too.

It is no exaggeration to say that fracking is one of the most important advances in dec-ades: a truly disruptive technology.

And what happens in America tends to be repeated elsewhere, too: the ripple effects of the Bakken and the US shale-gas bo-nanza are just beginning.

Take China. Its thirst for oil, gas and coal has been a big theme in the global economy in the past decade. China’s competition for these supplies has forced prices up, damag-ing some other oil-consuming economies – like those in the West – which had grown lazily dependent on a steady stream of cheap oil.

Yet with oodles of its own oil and gas sup-plies to draw on, the US won’t need to com-pete with China and other big economies for energy.

And that’s before other countries roll out the same fracking techniques used to such great effect in the lower 48. China’s trapped natural gas trove is thought to be among the biggest in the world.

It’s not just China, either. Middle East and North African countries, long home to some of the world’s largest conventional oil depos-its – meaning the stuff that was easy to ex-tract using older techniques – are stepping up their own hunt for unconventional resources.

Even England is joining the game. Near Blackpool, a resort famous for donkey rides and amusement arcades, a company is about to start drilling a shale-gas reservoir whose endowment could rival the dwindling reserves in the North Sea, once an energy-producing powerhouse.

But the beauty of the fracking revolution isn’t just its promise of vast new pools of en-ergy for the world. It is also the way it has hap-pened. Governments didn’t figure out frack-ing – forward-thinking companies, spurred by higher oil and gas prices, were behind it.

Fracking is one of the most important advances in decades: a truly disruptive technology

Blackpool has recently gone higher tech



Like the internet and smartphones, un-conventional energy is the product of sci-ence – and scientists.

There are some big caveats. The prom-ise of plenty may have ended worries about looming supply crunches, but it has created new problems, too.

An energy career is where it’s atFor a start, the supply potential outside the

US is still just a twinkle in the eye of hope-ful drillers. Internationally, there may be no shortage of energy in the ground, but above it there there’s a shortage of engineers, ge-ologists, welders, pipe fitters, economists, chemists and all the others on whom this revolution depends.

It is hard to see that problem lasting. Few other industries can guarantee clever young graduates such well paid, globetrotting ca-reers. Whether the lure is a role in reshap-ing global geopolitics; bringing energy to the world’s poor; or the intellectual challenge of cracking tricky ecological problems, an oil and gas career is where it’s at.

But there’s another problem associated with the new abundance: burning it all.

US greenhouse gas emissions have plum-meted as new supplies from shale-gas depos-its have replaced coal – which, when burned, generates twice as much carbon dioxide (CO2) as gas – in the country’s power stations.

Yet global greenhouse gas emissions last year set another record high. All that coal the US wasn’t using was exported to Asia and Europe, where shale revolution has yet to take off.

Substituting gas for coal in Chinese power stations would deal with some of this. In fact, the oil and gas professionals now working to replicate the US drilling boom in China will go further in solving that country’s emissions problem than delegates at an-other UN climate-change conference. After all, the US didn’t even ratify the Kyoto cli-mate-change protocol – but it has slashed its emissions anyway.

Phase one of the great 21st century energy upheaval (more oil and gas)

Using oil and gas more efficiently will free up supplies that will help drag people out of poverty



Oil supplies may be plentiful, too, but ek-ing out ways to use each barrel more effi-ciently makes sense for political, economic and environmental reasons.

For engineers, that may be one of the big-gest and most important jobs on the planet. The IEA reckons efficiency could end the re-lentless growth of oil demand, which would peak by 2020 and settle beneath 2011 lev-els by 2035. That’s a lot of CO2 – and money – saved. The problem? It needs clever peo-ple to make it happen: wise lawmakers, sure. But above all: scientists.

Making car engines more efficient, for ex-ample, is another of those Bakken-style jobs that would send ripples across global politics and economics. It’s simple maths: in 2010, the average American drove about 9,500 miles. So your 20-mile-per-gallon car would have used 475 gallons of gas – at prices at the start of 2013, costing you about $1,600. Doubling the efficiency of that vehicle would halve your spending and reduce the amount of oil your country needs to import.

That’s important for consumer nations, many of which desperately want to improve their trade balances.

It’s also crucial for the rest of the world. We depend on oil to drive to college or work or when we hit the highway for our vacation. But we also need oil to keep ambulances on the road, hospitals running, factories purring and, quite simply, to ensure our economies add more jobs.

And given that about a fifth of the world’s population doesn’t have basic ac-

cess to energy, using oil and gas more ef-ficiently will free up supplies that will help drag people out of poverty. Prosperity de-pends on energy.

Renewables: the next phaseNot all of that energy needs to come

from oil, gas or coal. As the world’s need for fuel rises in the coming decades, bring-ing renewable sources into the mainstream is phase two of the great 21st century en-ergy upheaval.

It’s another revolution in need of armies – armies of scientists. Figuring out ways to store wind power on still days; to capture the awesome electric potential of tides; to develop transmission lines that can trans-mit electricity from solar panels to light switches hundreds of miles away; to make nuclear fission safe – the scope for change is immense.

A career in energy might need you to brave some weather or travel in some of the remotest corners of the globe. But an en-ergy-thirsty world needs you. v

There may be no shortage of energy in the ground, but above it there’s a shortage of engineers, geologists, welders, pipe fitters, economists, chemists and all the others on whom this revolution depends

Sunny side up (phase two of the great 21st century energy upheaval)


2.1 – Oil supply and markets

The price of oil mattersWhat to expect from oil prices in 2013 – and why

Whether you live in Shanghai or Chicago, the price of oil affects you. And be-

cause oil is a globally traded commodity, anything that affects the world’s crude mar-ket – be it a fire at a refinery in Venezuela, a war in North Africa, or a jump in Chinese demand for fuel – will ripple through to the prices at your local gas station.

So you’ve probably noticed that oil is now – by any historical measure – a pricey com-modity. Take Brent crude, an oil bench-mark that derives its name from a field in the North Sea but helps set the price for most other oils around the world.

Since about 2003, Brent has been on a flier, bringing most other oil prices into the strato-sphere with it. A decade ago, Brent cost just over $25 a barrel. Last year, it averaged over $111 a barrel, its highest average price ever.

For producers of oil, these are boom times. Organization of the Petroleum Exporting Countries (Opec), a club of 12 producers that between them claim to own more than four-fifths of the world’s crude oil reserves and produce about a third of its oil, scooped more than $1 trillion in net oil-ex-port revenue last year.

That may be the high-water mark for these exporters, though, because 2013 ought to see oil prices begin a steady retreat – boost-ing consumer economies, which have been wilting under rising fuel bills.

The old adage is that the cure for high prices is … high prices (because high prices boost supply and erode demand simultane-ously; more supply + lower demand = lower prices). That finally seems to be ringing true for the oil market, where two important shifts are taking place.

The supply sideThe first is on the supply side. High oil

prices have spurred drillers to find more oil, especially in so-called unconventional de-posits, which were once too costly and dif-ficult to reach. America’s oil and gas re-vival is the best example. US production had been in rapid decline since the 1970s. This year, however, the Energy Information Administration forecasts a rise to 7.3 million barrels a day and next year to 7.9 million barrels a day, which would be the highest level since 1988. Later this decade, the US may even overtake Saudi Arabia to become the world’s biggest producer.

Non-Opec producers from Russia to Rio are feeding lots more oil into the global supply system. Platform offshore Angola, West Africa

© C

hevron



Russia, which has also been vying with Saudi Arabia for top spot, is producing more oil, too. Last year, its output reached a post-Soviet high of 10.4 million barrels a day. Other non-Opec producers are also chomp-

ing at the bit. Brazil, Kazakhstan, Canada, new producers in West Africa – all home to technically difficult but abundant reserves – should all begin adding big slugs of produc-tion to global supply.

The lifespan of the reserves that remain to be extracted is also growing. Despite world consumption of almost 90 million bar-rels a day, the number of years’ worth of oil remaining has been steadily increasing, to about 55 years.

A lot of the new oil has come from fresh discoveries (and, reversing another trend, the average size of these new oilfields has been growing lately, too). But even more oil has been added by deploying better technol-ogy to recover more oil from older fields.

It all adds up to a profound and positive shift in world supply dynamics.

The demand sideJust as important, though, is the trend in

demand. Recessions weaken oil consump-tion, because fewer people drive to work, factory output slumps and trade (shipping goods from one place to another) declines. So when the global economy nosedived in 2008, so did demand for oil.

And there’s a funny thing about oil de-mand: when it goes, it tends to stay gone. No-one replaces an SUV with a more fuel-efficient car because gas prices are high one year and then trades the Prius in for a gas-guzzler when fuel costs come back down the next.

Figure 1. Brent oil price: what a difference a decade makes

Source: Platts

US

dolla

rs

Tepid demand and buoyant supplies this year should bring prices down, blowing wind into the sails of economic recovery



So when economies begin recovering from recessions, they tend to use oil more efficiently. Economists talk of this in terms of energy intensity: how much oil it takes to cre-ate one unit of GDP. This intensity is falling across the world, but especially in the rich, economically mature countries of the West.

That doesn’t mean oil demand will stop rising. The International Energy Agency (IEA), an international think tank, estimates consumption is likely to rise from around 88 million barrels a day in 2011 to around 100 million barrels a day in 2035 (this is the fig-ure given for the New Policies Scenario, one of three energy futures described by the IEA – see Figure 2). In fast-growing economies in Asia, which will account for most of the

extra demand, millions of people still don’t own cars. Even if all of them buy hybrids, they’ll still need more oil.

But the pace of this demand growth is slowing down. Oil producers used to count on consumption rising by about 1.5% a year. Now the number is more like 0.5%. And, says the IEA, there are big energy sav-ings that could be made, too: if governments introduced the kind of efficiency measures it recommends, oil demand in 2035 could ac-tually be lower than it was last year.

The king of swingThose kinds of trends are a worry for big

Middle Eastern producers like Saudi Arabia, which realise that high oil prices are push-

Figure 2. The IEA’s view of how oil and liquids supply might evolve

Source: IEANotes: CAGR = Compound annual growth rate (between 2010 and 2035).The three scenarios, updated annnually by the IEA, describe three possible energy futures. The New Policies Scenario assumes green energy policies already announced by govern-ments will be introduced. The Current Policies Scenario – a business-as-usual case – shows what would probably happen if energy policies were to remain unchanged. The 450 Scenario, which would see the sharpest reduction in fossil-fuel use, sets out an energy pathway consist-ent with the goal of limiting the global increase in temperature to 2°C by restricting the con-centration of greenhouse gases in the atmosphere to around 450 parts per million of CO2.

CAGR 0.5%CAGR 0.8%

CAGR -0.4%

Mill

ion

barr

els a

day

New Policies Scenario Current Policies Scenario 450 Scenario



ing their consumers to change their behav-iour. The kingdom is using its power as a swing producer – meaning it has the abil-ity to increase or reduce exports to affect prices – to try to weaken the market. Its oil minister, Ali Al-Naimi, thinks oil prices can be brought into a sweet spot where con-sumers don’t find them too onerous and ex-porters can be happy, too. He talks of $100 a barrel being a fair price – though some say Saudi Arabia would happily see Brent fall below that level, too.

In line with this strategy, the kingdom has been pumping at record highs for the past year. In 2013, all this excess oil could begin to hang over the oil market, eventu-ally driving prices lower – especially if the world economy continues to stutter, damp-ening demand.

It will also remove one of the market’s biggest worries in recent years: that Opec doesn’t have enough spare production ca-pacity to cater for supply interruptions else-where. If Opec is producing 31 million bar-rels a day, runs this argument, and can only increase this number to around 33.5 million barrels a day, then a hurricane, war or some other unforeseen disaster that wipes out production elsewhere, would leave Opec scrambling to replace the loss. It happened in 2011, when Libya’s war shut down its oil sector and caused international oil prices to spike – prompting Western countries to release oil from their emer-gency stockpiles.

Just the threat of this happening again has helped buoy oil prices. But with slug-

gish demand around the world and rising supplies – Opec itself says its members are spending $270 billion to increase its net ca-pacity by 5 million barrels a day by 2016 – that worry is fading rapidly.

Meanwhile, global oil-demand growth this year of around 900,000 barrels a day is likely to be matched – and then some – simply by the rise in non-Opec production. Throw in the rapid growth in Iraq’s output and markets could be awash in oil in the coming months.

The hottest of hot potatoesThen there’s Iran, historically one of the

world’s big oil exporters. The EU and US, suspicious of Iran’s nuclear ambitions, have imposed stringent sanctions on its oil exports, which have probably removed at least 1 million barrels a day of Iranian oil from the market. (No-one knows for sure, because Iran’s oil data don’t exactly amount to the world’s most comprehen-sive statistical document.) Tightening this embargo or – much worse – precipitating a conflict could cause oil prices to spike. Conversely, negotiations could bring a res-olution and a lifting of the sanctions, send-ing more oil into the market. In that event, prices would plummet.

In theory, cheaper oil prices would be good for consumers and their economies. The less money each driver spends on fuel – much of it imported from abroad – the more he or she can spend on other goods produced locally.

Things aren’t, alas, that simple. Today’s historically high oil price has many posi-tives. The renaissance of US oil produc-tion, the growth of Canada’s oil sands, and progress in many deep-water projects de-pend – for now – on robust oil prices. A price collapse, however unlikely, would make these technically difficult and pricey projects more challenging. That’s what hap-pened in the 1980s, the last time soaring oil prices spurred drillers to begin tapping un-conventional deposits.

No-one replaces an SUV with a more fuel-efficient car because gas prices are high one year and then trades the Prius in for a gas-guzzler when fuel costs come back down the next

The Strait of HormuzThe Strait of Hormuz, a 34-kilometre-wide (21 miles) stretch of water between Oman and Iran, is one of the world’s most economically important and militarily sensitive areas of ocean. If this narrow channel were closed to sea traffic, the global oil trade would immediately struggle to meet demand. Just a hint of a problem there can cause the oil price to soar. In 2011, 17 million barrels of oil a day was exported through the Strait – 35% of the maritime oil trade. More than 85% of it was heading for big Asian markets, such as China, Japan, India and South Korea.The international gas trade is heavily dependent on the Strait too: some 2 trillion cubic feet of liquefied natural gas (LNG), about 20% of world trade, go south through the Strait from Qatar every year.With Iran locked in a dispute with the West over Iran’s alleged nuclear weapons programme, the Strait of Hormuz has become a geopolitical flashpoint. Iran has threatened to close it to shipping; the West has threatened military action if it does.The US Fifth Fleet is stationed permanently in the area to safeguard passage through the Strait. The US thinks this is a big enough deterrent to dissuade Iran – or any other country – from trying to close the Strait.So why don’t the region’s energy producers export their oil and gas by a different route? Although some hydrocarbons are exported from the region by pipeline, there just isn’t enough pipeline capacity to cope with the large volumes the region ships through the Strait. The world is stuck with this volatile maritime chokepoint for the foreseeable future – and stuck with all the potential dangers that go with it.

The sink that might be filling up © London Array Limited

© Lond

on Arra

y Limited

Over a third of the world’s seaborne oil trade must squeeze through this 21-mile gap


Industry facts



It’s not a likely outcome: unconventional oil is here to stay. But any slow-down in the development of US oil, for example, would put the onus for supply back on the Middle East, where oil can be extracted more cheaply than anywhere else.

That would make the global oil-sup-ply system less stable. Aside from Libya, Middle Eastern and North African oil pro-ducers have been largely unscathed by the unrest of the past two years. But to keep do-

mestic upheaval at bay, countries like Saudi Arabia have been spending vast portions of their oil wealth on social programmes. Many Middle East producers now depend on an oil price well above $100 a barrel to keep their economies afloat. Any prolonged dip in the market would spell trouble for their budgets.

It leaves global oil markets balanced precariously. Tepid demand and buoy-ant supplies this year should bring prices down, blowing wind into the sails of eco-nomic recovery. But to keep upstream in-vestment ticking over, augment the trend towards efficiency and, at the same time, ensure vital new supplies remain profita-ble, no-one should be hoping for the mar-ket to slump. v

The lifespan of the reserves that remain to be extracted is growing

Even if they change this for a hybrid, it’ll still mean more oil is needed

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6.3 – The fundamentals: oil reserves



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The Oil value chain1 Oil discovery 2 Extraction 3 Gas (if associated) 4 Crude oil pipeline 5 Crude oil tanker 6 Crude oil storage 7 Refinery 8 Product storage 9 Product pipeline 10 Product carrier 11 Intermediate bulk storage 12 Road 13 Barge 14 Rail 15 Pipeline 16 Petrochemicals 17 Regional storage 18 Transportation 19 Industry 20 Residential (heating, power & cooking) 21 Commercial (heating and power) 22 Power 23 Agriculture

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Oil reserves, production and consumption


Oil reserves, production and consumption

Saudi Arabia

UAE

Oman

Yemen

Qatar

Kuwait

IranIraq

Red Sea

Persian Gulf

Asia-Paci�c41.3 billion barrels

Europe and Eurasia 141.1 billion barrels

World oil reserves, 2011Source: BP Statistical Review of World Energy 2012

North America 217.5 billion barrels

S. & C. America 325.4 billion barrels

Africa 132.4 billion barrels

Middle East 795.0 billion barrels

LegendOil reserves (Billion barrels)

200+ 100 to 199

50 to 99 25 to 49

0.5 to 24 Negligible

World total World oil reserves: 1,652.6 billion barrelsOil production: 83.6 million barrels a dayOil consumption: 88.0 million barrels a dayReserves-to-production ratio: 54.2 years

Top 10 producers, 2011Country Thousand barrels a day1. Saudi Arabia 11,1612. Russian Federation 10,2803. US 7,8414. Iran 4,3215. China 4,0906. Canada 3,5227. United Arab Emirates 3,3228. Mexico 2,9389. Kuwait 2,865

10. Iraq 2,798

Top 10 consumers, 2011Country Thousand barrels a day1. US 18,8352. China 9,7583. Japan 4,4184. India 3,4735. Russian Federation 2,9616. Saudi Arabia 2,8567. Brazil 2,6538. South Korea 2,3979. Germany 2,362

10. Canada 2,293

Notes: Provided reserves of conventional oil- generally taken to be those quantities that geological and engineering information indicates with reasonable certainty can be recovered in the future from known deposits under existing economic and operating conditions.


2.2 – Gas trading

Let’s talk about the weatherGas trading is a vital process in getting gas from the point of production to the consumer. HTEIW visited Gazprom M&T’s London trading floor

How do methane molecules produced in Russia, Norway or North Africa find

their way into power stations and homes in Germany, the UK or Italy?

The simple answer is pipelines. The real-ity, of course, is much more complex. There aren’t just a few pipelines: there’s a labyrin-thine network of them, operating at differ-ent pressures, crossing borders and feeding

different parts of the market, from domestic consumers to factories and power stations. There are gas-treatment facilities to clean the gas up and pumping stations to keep it moving to wherever it’s needed.

Market intelligenceThe companies that operate each na-

tional network need to know how much gas is in a pipeline at any given time, who put it in there, where it’s flowing and who’s taking it out. Traders need to know about volumes and flows too; and they need to know – or predict – who needs what and when.

A glance at the seven or eight moni-tors fixed around every desk on the central London trading floor of Gazprom Marketing & Trading (the international trading division of the Russian gas company) gives you an in-sight into the web of variables that contribute to decisions about buying, selling and distrib-

You’ll need to become more than an amateur


2.2 – Gas trading

uting commodities. Each screen is riddled with flickering numbers, prices at delivery points across Europe for a wide range of future de-livery dates “along the curve” – anything from a few hours to a few years ahead. The voices of brokers can be heard yelling out price up-dates over the dealer-boards – squawk boxes for traders; speaking to them is as important as the screen for gleaning market intelligence.

There are currency fluctuations to con-sider too: UK and Belgian gas is priced in UK pence per therm, but the rest of Europe talks in terms of euros per megawatt hour. (Therms and megawatt hours are units of heat energy; a therm is equal to 100,000 British thermal units, roughly equivalent to burning 100 cubic feet of gas; a megawatt hour is the work done by the power of one million watts over one hour).

“It’s a lot to take in,” says one trader.In the simplest terms, the aim is to pur-

chase a commodity at one price and sell it at a higher price hours, days, months or even years later. A small amount of that trade takes place on futures exchanges such as the IntercontinentalExchange. But most business involves real buyers and sellers of gas, and real physical movements of it.

Between production and delivery gas is typically traded about eight times. Sometimes more. And trading strategies will often change right up until the gas is due to be delivered.

When physical delivery becomes imminent, the trader – perhaps an energy producer like BP, a supplier like Centrica or Gazprom M&T or a hedge fund taking a speculative financial position in commodities – directs the grid op-erator to flow the right amount of gas to the right place at the right time.

It’s all about finding a favourable spread (a differential), between prices in different geographical locations or prices for different delivery times. Or both.

A European trader might, for example, spot an attractive spread between prices in the UK and in an overseas market: if French consumers were paying more for their gas

There’s nothing simple about getting gas to market

© Gazprom

Weather is one of the biggest causes of price changes in natural gas markets because gas is used predominantly for heating and power generation


2.2 – Gas trading

than the combined cost of purchasing gas in the UK and piping it through one of the links to mainland Europe, it might be worth sending volumes east across the North Sea to Belgium and from there through the pipeline network to France.

Or perhaps the weather’s about to turn cold: in that case, you might make a profit by having your gas injected into a storage facil-ity (see box) for a few days before releasing it to a freezing and high-paying local market.

Indeed, weather is one of the biggest causes of price changes in natural gas mar-kets because gas is used predominantly for heating and power generation (Gazprom M&T even has its own, in-house meteor-ologist). During the winter, even a one-de-gree change in temperatures can have gas prices zigzagging all over the charts.

Rough winterYou’d keep an eye on the Bloomberg

news terminal and the specialist trade press for other reasons, too – for problems such as interruptions or outages in gas-processing plants, producing or storage facilities, which can affect supply and, by extension, prices.

In early 2006, for example, a fire at the North Sea’s Rough field, a depleted offshore gas reservoir that now serves as the UK’s main gas-storage facility, knocked out much of the country’s storage capacity. That, com-

bined with a cold snap, caused prices to quad-ruple in less than a week. With gas-network operator National Grid warning large industrial consumers that it might have to ration their supplies, prices rose from about 60 pence a therm to 255 pence a therm over a crazy four-day period in the middle of March of that year.

That was an extreme case of volatility. Yet even scheduled maintenance outages can affect prices. The Interconnector (a big natural gas pipeline connecting the UK with mainland Europe) shuts down for two weeks in the summer, changing the dynam-ics of how the countries that would normally rely on its flows receive their gas.

The secret is second-guessing, ahead of the competition, how events such as these will affect gas supply and demand. Oh, and remembering to balance your books: trad-ers are obliged to put into a gas system the same amount of gas that they take out. If the grid operator has to top up on your be-half, you’ve been “cashed out”. And being cashed out is as expensive as it sounds. v

Natural gas storage might not be the most glamorous-sounding bit of the energy world. But it is an integral part of the gas-supply chain.

It provides the market with gas when supplies run short, helping networks cope when volumes of gas coming through im-port pipelines or from domestic gas fields fall short of consumer needs.

Storage can also help traders get the best price possible for their gas by giv-ing them breathing space when prices are low. The more flexible a trader’s system – the greater the access he has to pipeline routes, volumes of gas and storage – the more money he can make.

Gas storage consists of special facilities underground, such as disused oil and gas fields or airtight salt caverns. v

Gas storage: does exactly what it says on the tin

The Rough field, once a North Sea gas field and now the UK’s main gas-storage facility

© Centrica

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Are we running out?How much oil and gas does the world have left? And how much of it can we retrieve?These important questions affect energy prices, economies and government policies, but can be surprisingly difficult to answer. The graphic shows estimates from 2011 and 2012 of the amount of gas and oil that could be technically produced. To put these figures in context, oil and gas consumption in 2011 is also shown. At present levels of demand, these resource estimates indicate there might be enough natural gas to last nearly 250 years and enough oil for maybe 180 years. But there’s lots of uncertainty in these figures.Resource estimates depend upon the limitations of the technology available to extract oil and gas, and information from geoscience on the location and size of deposits. Because technology and geological knowledge are constantly changing, so are resource estimates. In recent years, there has been a steep rise in the amount of unconventional fossil fuels – such as shale gas, light tight oil and extra-heavy oil – thought to be accessible. Unconventional resources are potentially larger than conventional ones, but geological and technical uncertainties mean that estimates of their size are more tentative than those of conventional fossil fuels.Methane hydrates – ice-like crystals in the seabed and permafrost that contain methane molecules – could be a vast resource of natural gas. But information on their location and nature is lacking, and the technology used to exploit them is still in its infancy (see p111). The wide range in hydrate resource estimates reflects these uncertainties. Methane hydrates are unlikely to be a serious energy option for a long time.

Conventional2,906

Conventional2,678

Shale1,258

EHOB1,880

Kerogen1,073

Tight509

296

296

240Coalbed methane

Light tight oil

Oil and gas consumption: 2010 32 billion barrels 20 billion barrels of oil equivalent

GasBillion barrels of

oil equivalent

OilBillion barrels

Natural gas4,969

Maximum56,989

Methane hydrates

Minimum

Oil5,871

Notes: EHOB = extra-heavy oil and bitumen. Oil resources are shown in billions of barrels of oil and gas in billions of barrels of oil equivalent to facilitate comparison; 1 trillion cubic metres of gas is assumed to be equivalent to 6.29 billion barrels of oil.

Source: International Energy Agency; Global Energy Assessment – Toward a Sustainable Future; BP

Estimated technically recoverable global oil and natural gas resource

Reserves versus resourcesAlthough the exact definitions may vary – depending on the company, institution or country – the terms reserves and resources refer to different aspects of the size of the store of remaining oil and gas.Reserves are the oil and gas deposits we can be pretty confident can be brought to the surface using existing technologies, using the geological information available, and given economic conditions.Resources are the reserves plus oil and gas that is yet to be found or that is known to exist but is likely to be producible only in the event of further technological advances being made or economic conditions changing.

22 – www.energy-future.com 23 – www.energy-future.com

Industry facts Industry facts


3.1 – Seismic imaging

The hills (and seas) are alive with the sounds of seismicSeismic imaging is a vital tool in oil and gas exploration

Imagine being able to see into the ground beneath your feet. Being able to peel

away the different layers of rock deep in the Earth’s crust and maybe, just maybe, re-vealing a huge reserve of oil in the process. This sounds a bit like science-fiction. But it's something that geoscientists are able to do with a technology called seismic surveying.

Seismic surveying uses the same prin-ciple that dolphins or bats use to see the world around them. These animals emit sound waves and listen for echoes to visual-ise objects in their surroundings.

Seismic surveys also send out pulses of sound, but into the ground. At boundaries between different types of rock some of this

sound energy is reflected back, because dif-ferent types of rock respond differently to sound – a property called impedance. By lis-tening for reflections, and timing when they are received, geophysicists build a picture of the shape and size of rock units and their relationships. And by looking at the shape of reflected sound waves it's even possible to say what the rocks are made of and whether they might hold hydrocarbons.

If that brief explanation makes the proc-ess sound straightforward, it isn’t; time and a lot of expensive technology are needed to gather good-quality seismic data. It's a cost that oil and gas companies are will-ing to bear, however. A good seismic sur-vey decreases exploration risk, saving lots of money on drilling wells.

Data, data, dataSeismic data can take many forms. The

oldest and simplest type is two-dimen-sional (2D) seismic, which gives a single cross-section through the Earth. It's still col-lected in some circumstances but has gen-erally been superseded by 3D (three-dimen-sional) surveys. 3D seismic is made up of tightly spaced 2D lines – commonly 12.5 or 25 metres apart – that are knitted together

Where the real processing power is

© CGGVeritas



to form a three-dimensional cube. More than 90% of seismic data today are 3D be-cause, even though they need a step-up in computer power, they render the subsurface in much greater detail.

If 3D surveys are taken repeatedly over months or years a 4D seismic is the result. 4D can be useful for monitoring production from a well. By comparing time-lapsed im-ages of a reservoir, geologists can monitor how it is being drained and whether new ap-proaches, such as enhanced oil recovery, are needed to boost production.

Whether onshore or offshore, shooting a seismic survey needs two basic things: a source to create a pulse of sound energy and a set of receivers to detect reflections.

On land, an explosive charge buried in the ground can be used as a source. This fairly crude approach actually produces a nice sharp, powerful wavelet, ideal for detailed imaging of the subsurface. But dynamite cannot be used in populated areas and may pose a security risk. More often, the sound source comes from fleets of large trucks – called thumper or vibroseis trucks. These are fitted with a heavy iron plates slung un-derneath that make contact with the ground and vibrate rapidly for a few seconds.

Land surveys use receivers called geo-phones to pick up seismic signals. These are sensors on long spikes that are stuck in the

ground. Typically they are connected by ca-bles that can be 20 miles or more long for a 3D survey of a few square kilometres. Laying out this much cable can be a logistical head-ache, depending on the terrain. Up to half the acquisition time can be spent repairing damaged line, much of it caused by chewing rodents, cattle and even – in Canada – Arctic foxes. If the environment proves too rough, wireless geophones can be an option.

Offshore seismic surveys are in some ways easier than land ones because large areas can be covered relatively quickly. However, this larger scale, the hostile weather encountered, and technical issues with shooting seismic at sea offer an extra set of challenges.

Marine seismic is done by trailing both source and receivers a few metres under-water behind a ship as it sails along a pre-cisely defined racetrack of lines called a swath. The source is an array of air-guns im-mediately behind the vessel; the receivers – called hydrophones – are packed into neu-

The seismic industry is probably the biggest civilian user of high-performance computing in the world

Two of these animals visualise the world using something a bit like seismic. Two of them have been known to chew seismic cables



trally buoyant cables, streamers, which are towed further behind.

Multiple streamers, several kilometres long, with hundreds of hydrophones are now common in 3D surveys. But single-streamer 2D surveys are still employed in places like the Arctic where floating ice prevents a multi-streamer set-up from being used. To make sense of reflections, the position of each hy-

drophone needs to be known. Streamers are fitted with vanes and attached to buoys to steady them in the water. But modern hy-drophones are also equipped with GPS for added precision.

The industry’s need to gather large amounts of high-quality data, more quickly from increasingly challenging environments is driving significant investment in seismic ships and surveying technology. Norwegian offshore specialists PGS have ordered two

revolutionary, bespoke seismic vessels at a cost of $250 million. These Ramform Titan-class ships, due for delivery this year, will be 70 metres wide at the stern to allow 24 streamers to be deployed. This will increase the width of each swath and allow survey ar-eas to be covered more rapidly.

A raw seismic dataset – a recording of the frequency, wavelength and amplitude of re-flected sound – needs to be processed into a form that geoscientists can use. This involves cleaning reflected waves of external noise and converting signals so they measure real depth below the surface rather than the time taken for sound to travel. Corrections are also made for effects like ghosting, a type of interference in offshore surveys caused by source and reflected pulses bouncing off the surface of the ocean. If boreholes were drilled in the survey area, it may even be possible to link rock types found in them to specific seismic waveforms and so infer rock-types across the whole study area – a process called inversion.

In offshore seismic, some processing occurs on board ship so any holes in the data can be filled while the acquisition is in progress. But the bulk of the work happens after the survey.

Processing the large amounts of data in each survey, with complex algorithms and

Seismic offshore and onshore© PGS

© CGGVeritas

Wide-azimuth seismic shoots sound energy at low angles over a wide area to see underneath salt layers – like stepping away from a car to see what’s underneath it



mathematical calculations, requires a ter-rific amount of computing power. Indeed, the oil and gas industry is probably the big-gest civilian user of high-performance com-puting (HPC) in the world. BP – whose computing needs have increased a thou-

sand-fold since 1999 – is spending $100 million on a HPC facility in Houston, which should start operating this year. The cen-tre will use more than 67,000 CPUs. It will have 536 terabytes of memory and 23.5 petabytes of disk space – equivalent to 147,000 160 GB Apple iPods. In 2012, Total commissioned a supercomputer ca-pable of performing 150 trillion floating point operations per second. The machine will increase processing power at Total’s Jean Féger Scientific and Technical Centre located in Pau, southwest France.

Time to do some geologyAfter processing, geologists can finally get

stuck into interpreting what the reflections mean, using the data to extrapolate a model of the subsurface. Even salt deposits – com-

mon traps for oil and gas but notoriously diffi-cult for sound waves to penetrate – can now give up their secrets thanks to wide-azimuth seismic, a technique that shoots sound en-ergy at low angles over a wide area to get underneath the salt – like stepping away from a car to see what’s underneath it.

Interpretations are done on compu-ter workstations or in special visualisation rooms using software that projects seismic data as a 3D cube that can be spun, sliced or exploded, almost like the graphics in a computer game.

But this is not Nintendo geology: the most important element in successful seismic is the knowledge and expertise of the geolo-gist, not the gizmos. Without geological un-derstanding, seismic data would be of lit-tle value; geologists apply their knowledge to pick out features in the cube that corre-spond to types of rock and structures – such as faults – that together might indicate hy-drocarbons potential.

Today, seismic is a vital tool for compa-nies exploring and producing oil and gas. Very few exploration wells are now commis-sioned before a 3D seismic survey is car-ried out or bought from ever-growing librar-ies of surveys held and compiled by special-ist companies. And with wells costing up to $100 million to drill, the investment in a seis-mic survey is more than worth it. v

Geophysicists in a 3D data room© RWE DEA

Without geological understanding, seismic data would be of little value


3.2 – Unconventional oil

A peak into the futureThe US is showing the world how to unlock new oil reserves. But economics and environmental considerations will decide whether the revolution keeps going

Oil is the backbone of developed and emerging economies. It powers soci-

eties and is the raw material for countless chemicals and plastics. But it is a finite re-source: the rate of discovery of relatively easily accessible conventional oil has de-clined, and the idea of peak oil – where de-mand outstrips supply, creating shortages and high prices – has been worrying con-sumers for decades.

But North America’s energy landscape is being transformed by a surge in production of homegrown unconventional oil.

What’s unconventional about it?Unconventional oil is oil that doesn’t

spontaneously flow from its geological res-ervoir into a well and to the surface. Special technology and extra effort are needed to get it out of the ground, making the resource more difficult – and usually more expensive – to exploit. Over half of the world’s remain-ing recoverable resources of oil are clas-sified as unconventional, according to the International Energy Agency (IEA).

Unconventional oil comes in several guises. These include extra-heavy oil (found in large quantities in Venezuela), natural bi-tumen (concentrated in Canada’s prolific oil-sands region) and kerogen (in dense shale rocks around the world).

But it is shale oil that has grabbed the headlines recently because of rapid produc-tion growth in the US.

Shale oil is found in fine-grained rocks like shales or siltstones that often contain oil as well as natural gas. But because the spaces between grains within these rocks (pore spaces) are small and unconnected, any oil present is trapped or has difficulty

Drilling operations in the Marcellus shale. Light tight oil production might account for a fifth of projected US oil production by 2025

© C

hevron


Profile – Jennifer Rothfuss

Name: Jennifer RothfussCompany: ChevronPresent job: Operations GeologistAge: 27Nationality: USADegree: Geology, Allegheny College; MSc, Geological Sciences, University of Alabama

I’m an Operations Geologist in Chevron’s Pittsburgh, Pennsylvania office, planning wells in the Marcellus and Utica Shales – large, hydrocarbon-prone formations in the Appalachian Basin, which underlie much of the northeastern United States.

It’s only in the last few years that our industry has begun to tap North America’s shale reservoirs for oil and gas, so I’m working on some of the region’s newest plays. In many respects, how the industry drills and completes the Marcellus and Utica Shales will provide the basis for how we consider optimizing future wells in other unconventional plays around the world.

My role involves the planning and execution of wells. In these shale plays, we drill vertically to depths of approximately 8,000 feet. Before reaching the target formation, we may drill through coal seams, groundwater aquifers, or shallow sandstone layers containing natural gas. I research and identify these and other potential geological hazards before we drill a well. It’s imperative that we avoid contaminating groundwater aquifers while we’re drilling, and I’m responsible for determining the depth of fresh water aquifers using offset well information

and maps. I inform the drilling engineers where the aquifers are and they case and cement the well using the information I provide. Safety is our number one concern at Chevron, and there is always time to put the appropriate procedures in place.

As a well in the Marcellus or Utica Shale approaches the target reservoir horizon, it will kick off and drill horizontally for roughly another 4,000 feet. Throughout the horizontal portion of the well, our aim is to keep the drill bit in the most hydrocarbon-bearing and permeable part of the reservoir. Working with directional drillers on the rig to maintain the wellbore in the optimal part of the reservoir is a critical aspect of my job. We use directional surveying and measurement-while-drilling technology to determine our exact position and geosteer the horizontal wellbore. This allows us to optimize our preferred target position within these hydrocarbon-charged shales.

When I was in college, I talked to my professors about career choices. What stuck with me about the energy industry is the almost unlimited potential for growth. The industry is global and is spread across many different geologic basins. Also, the science is rigorous and there are many different disciplines to explore. The opportunities are endless at Chevron.

After I graduated, I assumed my role in the energy industry would focus solely on geology, but at Chevron I have found there is much more variety. Although I never took a petroleum engineering class in college, I now frequently work with drilling engineers and participate in active operations on our rigs. At this point, I wouldn’t make any assumptions about how my career will evolve.

Chevron’s excellent Horizons training program encourages you to rotate through three different roles in your first five years, giving you great exposure to various career paths. For me, Chevron is the best place to grow personally and professionally.



flowing. Geologists call such rocks tight. And because this type of oil doesn’t just oc-cur in shales, a more accurate name for it is light tight oil (LTO).

Tight rocks containing oil were commer-cially ignored up until the beginning of this

century, when rising oil and gas prices stim-ulated attempts to exploit the hydrocarbons in them. A small US company called Mitchell Energy experimented in 2000 with get-ting natural gas out of tight rocks in Texas. Mitchell used a novel combination of two established techniques – horizontal drilling and hydraulic fracturing – to great success. These techniques have since been applied extensively in North America to extract gas from shale rocks and now they’re being ap-plied to tight oil.

Their purpose is to increase the amount of contact between the well-bore and the oil-bearing rock. Horizontal drilling involves first drilling a vertical well and then kicking-off a horizontal section that follows the formation of interest. This isn’t easy, as LTO rocks can be found 2-3 km below the surface and hor-izontal sections can be 1-2 km long. A good model of sub-surface geology, established through exploratory boreholes and seismic studies, is essential (see p28).

Once the well is drilled and lined with cement, the horizontal section is perfo-rated and millions of litres of fracking fluid is pumped into it at high pressure. Typically this fluid is 95% water, with around 5% sand and less than 1% of other additives that help the fluid to flow smoothly or prevent corro-sion of drilling equipment. The pressure of the fluid, forced through perforations in the well casing, causes the rock to fracture into a network of cracks. Most of the fracking fluid is then pumped out but the sand keeps the cracks open, leaving behind spaces for oil to flow into. Pressure in the well is then reduced to encourage the oil to the surface.

The unconventional oil boom could result in lower oil prices and diminish the importance to the global marketplace of conventional-oil regions

Canada has already followed the US’ tech-nology trail and begun to develop its light tight oil (LTO) resources. Mexico, Argentina, China and Russia may not be far behind.

Canadian LTO output reached 190,000 barrels a day in 2011 from the Canadian part of the Bakken shale and other emerg-ing plays, according to the International Energy Agency (IEA). The IEA expects Canada’s total to exceed 500,000 barrels a day by 2035, with production of natural gas liquids (NGLs) from shale gas plays also increasing significantly, offsetting falling production from conventional gas plays.

Outside North America, there are promis-ing prospects for LTO in Mexico, which, like Canada, overlies parts of big proved LTO formations in the US, such as the Eagle Ford shale. Argentina’s Neuquén basin could be producing 150,000 barrels a day of LTO by the end of the decade; the region has at-tracted investment from large oil companies, including Exxon Mobil and Repsol. Chinese production could exceed this total, reaching 200,000 barrels a day by the end 2020, says the IEA, while Russia’s Bazhenov shale, in Western Siberia, is very large and appears to be geologically similar to the Bakken.

LTO is an attractive prospect to en-ergy-poor countries such as Argentina and Mexico; it means greater energy security – self-sufficiency in energy supply – and a reduced need for expensive imported oil.

However, the IEA believes that LTO and NGLs from shale are unlikely to make a large contribution to global oil supply dur-ing this decade. Access to infrastructure is part of the problem; while North America generally has sufficient drilling rigs and transport links, remote, inhospitable re-gions like Siberia often don’t. v

LTO revolution spreads



Fracking has been used to exploit LTO in the US since the early 2000s, but its use has accelerated recently. This is because the price of natural gas has fallen significantly (from more than $13 per British thermal unit in mid-2008 to below $3 by the beginning of last year). Operators who were fracking for gas have moved their drilling rigs to look for more profitable hydrocarbon liquids. These can be found in reservoirs containing wet gas – natural gas plays also rich in liquids – and in rocks with LTO.

Around 20 geological basins in the US con-tain LTO, but, so far, few have received much attention. To date, the 370-million-year-old Bakken shale (see map) – stretching from North Dakota to Montana and across the Canadian border – has led the way. In 2006, production amounted to just a few barrels a day, but, by late 2012, it had reached over 700,000 barrels a day (about 4% of US oil de-mand), pumped from around 8,000 wells in

North Dakota alone. Present estimates from the US Geological Survey are that 3-4.3 billion barrels could be recoverable from the Bakken.

Another standout play for both LTO and natural gas is the Eagle Ford shale, in Texas. Throughout 2012, there were around 160 drilling rigs operating there, compet-ing for an estimated 3-4 billion barrels of oil. Production rose from virtually nil in 2008 to 310,000 barrels a day by mid 2012. These and other unconventional plays have caused US oil production to rise by 25% since 2008, reducing the need for imports – a cherished geopolitical and economic goal of successive US governments.

North America’s energy landscape is being transformed by a surge in production of unconventional oil

Shale plays Stacked plays BasinsExisting playsProspective plays

* Mixed shale & chalk play** Mixed shale & limestone play*** Mixed shale & tight dolostone-siltstone-sandstone

Shallowest/youngestIntermediate depth/ageDeepest/oldest

Source: Energy Information Adminisatration based on data from various published studies.

Avalon-Bone Spring

Pearsall

Tuscaloosa

ManningCanyon

Niobrara*

Heath**

Big Horn Basin

Powder RiverBasin

Bakken***

Mowry

Niobrara*ParkBasin

Uinta Basin

DenverBasin

San Joaquin Basin

Monterey-Temblor

MontereySanta Maria,Ventura, Los

AngelesBasins

EagleFord

WesternGulf

TX-LA-MSSalt Basin

Chattanooga

AppalachianBasin

UticaMarcellusDevonian (Ohio)

Barnett-Woodford

Cody

Hilliard-Baxter-Mancos

Gammon

MancosHermosa

Lewis

Pierre

Excello-Mulky

Woodford

Bend

Fayetteville

Barnett

Conasauga

Floyd-Neal

Antrim

NewAlbany

Haynesville-Bossier

MontanaThrust

Belt

GreaterGreenRiverBasin

PiceanceBasin

Paradox Basin

San JuanBasin

RatonBasin

Palo DuroBasin

PermianBasin Ft. Worth

Basin

Ardmore Basin

AnadarkoBasin

Arkoma Basin Black WarriorBasin

Valley & RidgeProvince

Cherokee Platform

ForestCity Basin

MichiganBasin

IlinoisBasin

WillistonBasin

MarfaBasin

0 200 400100 300

Miles

N

US shale plays



Combined US production from the Bakken, the Eagle Ford and other emerg-ing plays might exceed 3.2 million bar-rels a day by 2025, according to the IEA – about a fifth of projected oil production in 12 years’ time. However, LTO output would probably start to tail off after around 2030, it says, unless new resources are identi-fied and developed.

Shale gas plays, meanwhile, are also contributing to rising production of hydro-carbon liquids in the US. The IEA says out-put of natural gas liquids (NGLs) could in-crease by 1 million barrels a day between now and 2020, reaching 3.2 million barrels a day before declining, as known liquids-rich gas plays are exhausted.

The unconventional oil boom could have a very significant impact on oil prices by re-ducing the oil-import requirement of the US – still easily the world’s biggest oil consumer – and opening up large reserves of uncon-ventional oil in other regions (see box p30).

It could also profoundly affect energy ge-opolitics, perhaps, for example, diminishing

the importance to the global marketplace of oil produced in the Middle East.

However, there are risks on the road to the successful development of LTO. Some are technical: establishing reliable estimates for the amount of oil recoverable from an un-conventional oilfield requires a profound un-derstanding of the geology of the tight rocks and experimentation to determine the best approach to fracking – the optimum water pressure and composition of the fracking fluid. Also, production can vary greatly be-tween wells on the same oilfield, so the op-erator must find the reservoir’s sweet spots. All this costs time and money.

In addition, once drilled, unconventional wells tend to reach their production peak within a few years and then decline quite rapidly, so companies need to keep drilling in order to maintain or increase production across a field.

Another risk to the successful devel-opment of unconventional oil is the price of crude. Leonardo Maugeri of Harvard University suggests that, depending on the

Drilling in North Dakota. Up to 4.3 billion barrels could be recoverable from the Bakken shale

© O

le Jørg

en Bratla

nd/Sta

toil


Profile – Pascal

Name: PascalCompany: SchlumbergerPresent job: Directional drillerAge: 28Nationality: GermanDegree: Masters, Mechanical engineering, Technische Universität, Munich

Directional drilling – the science of deviating a wellbore sideways to a target a given lateral distance from the vertical – has revolutionized the upstream industry.

It’s made a huge difference to our ability to recover oil: horizontal drilling keeps the drill-bit in the target formation for a greater distance than a vertical well would – increasing the contact between the well and the producing rock.

And the technical achievements are amazing. The world’s longest horizontal well is now about 12,000 metres in length – a distance it would take two hours to walk.

I’m a directional driller. In a typical crew, I work with a measurements-while-drilling (MWD) engineer to determine the location of the drill-bit and where to steer the well for optimal production.

In very simple terms, the MWD engineer – using special software to interpret data sent from sensors inside the drillstring – tells me where the drill-bit is and I advise the client where to drill next.

We use a host of data. For example, we send electrical waves into the formation to measure resistivity; as a poor conductor of electricity, oil has high resistivity. Another useful parameter is the rate of penetration of the drill-bit: if that starts to slow down, perhaps we’ve reached the top or bottom of the reservoir and it’s time to navigate up or down. There’s an art to it and, the more you do it, the more of a feel you get for it.

Schlumberger has been a very rewarding experience for me. That’s partly because of its first-class training programme and the quality of its training tools. For instance, our training centres have full-size rigs capable of simulating a wide range of jobs, and at one of our centres in Abu Dhabi, there is a huge pool with a life-size model ship in it for offshore seismic training.

Of course, when you’re in the field, the challenges change from job to job, but the training arms you with invaluable knowledge.

I started out at Schlumberger three years ago as an MWD engineer, which gave me an essential knowledge base for my more practical directional drilling role. I made the switch about a year ago and have since undertaken assignments in Romania, Ukraine, Turkey, Germany and Colombia.

For now, I plan to stay in the field, perfecting my engineering skills and knowledge. In the long term, though, I’m interested in seeing the bigger picture and will aim for a management role. That’s all possible at Schlumberger; you get as much responsibility as you can handle.

If you’re after a nine-to-five job, this might not be for you. But if you like travel, working with people from many different cultures, responsibility and if you have a quick and flexible mind – the chances are you’ll be as happy as I am. Oh, and if you’re worried about your work-life balance, don’t be: I’m living proof that you can enjoy the tough parts of the job and life the rest of the time.



oilfield, a barrel of unconventional oil in the US is profitable at $50-65 a barrel. In the past few years, prices have generally held steady at around $100 per barrel, helping the economics of many costly ventures; but prices need to stay high to make unconven-tional oil commercially worthwhile.

There are also worries about the environ-mental impact of additional oil production. At the local scale, there have been concerns that fracking fluids may contaminate ground-water or cause earthquakes. Scientific stud-ies have shown that the cracks produced at depth by fracking are not long enough to interfere with aquifers and the micro-sized earthquakes generated are too weak to

pose a surface risk – although if the lining to the well-bore is not robust enough then fracking fluids or hydrocarbons may con-taminate groundwaters.

Greater sources of concern may be pollu-tion at the surface from waste products and water stress that drilling-intensive fracking can extert on water-poor regions. Perhaps most worrying to environmentalists, how-ever, is the increasing consumption of fos-sil fuels that will result from growth in LTO production. This will result in an increase in greenhouse gas emissions, which could – unless successful mitigation efforts are de-ployed – exacerbate climate change.

The rise of unconventional oil has been rapid and largely unforeseen. It has gone rapidly from a niche industry to a mainstream component of the US oil industry, creating much-needed jobs and enhancing the coun-try’s energy security. As with gas, success in the US could be replicated around the world, with profound consequences for energy flows and the world economy. And – with care – minimal environmental damage. v

Canada and Venezuela hold the world’s big-gest unconventional oil reserves. The US Geological Survey estimates that 500 billion barrels of oil may be recoverable from east-ern Venezuela’s Orinoco belt. The Alberta government, meanwhile, estimates estab-lished reserves of tar-like bitumen in western Canada amount to 169 billion barrels.

Extra-heavy oil is young oil that hasn’t been cooked thoroughly. It’s viscous and doesn’t flow well. So special techniques are required to get it out of the ground.

Production methods vary. In Canada, some of the oil is close to the surface and can be mined. Oil deeper underground is recovered using in situ drilling. The most common method, steam-assisted grav-ity drainage (SAGD), involves pumping steam under ground through a horizontal well to liquefy the bitumen, which is then

pumped to the surface through a second well. At present, the oil sands account for around 50% of Canadian crude production. The Canadian Association of Petroleum Producers (Capp) estimates that oil-sands production will rise from 1.6 million barrels a day in 2011 to as much as 5.0 million bar-rels a day by 2030 – about 80% of a pro-jected national total for 2030 of 6.2 million barrels a day.

Mining is not applicable in the Orinoco Belt, where cold – non-thermal – produc-tion processes are generally used to pro-duce heavy oil. Techniques include install-ing downhole pumping systems and injecting diluents, such as light crude or distillate, into the wells to make the oil less viscous. The International Energy Agency estimates pro-duction from the region to be below 1 million barrels a day. v

Extra-heavyweights: Orinoco and Alberta

Fracking has been used to exploit light tight oil since the early 2000s, but its use has accelerated recently because the price of natural gas has fallen significantly


3.3  –  Refining technology

Cartagena: tops for bottomsThe chemical make-up of crude oils is changing and refiners must invest in complex conversion capacity to be able to process them. HTEIW visited Repsol’s new refinery in Cartagena

Repsol’s Cartagena refinery, on Spain’s southeast coast, is a quietly spectacular

feat of engineering. Spectacular because the recent moderni-

sation of the unit, Spain’s biggest-ever indus-trial project, consumed 20,000 tonnes of steel – equivalent to three Eiffel Towers. It required the installation of 1,100 kilometres of preci-sion-welded pipe. And it occupies a 60-hec-tare site – the size of 85 football pitches.

Quiet because, screened as it is from the nearby town of Cartagena by rolling coastal hills, you scarcely know it’s there.

Completed at the end of 2011, the four-year revamp cost €3.2 billion, part of a €4 billion programme to optimise Repsol’s Spanish refining base.

Large downstream investments in Europe are pretty unusual these days. Many oil companies have chosen to fo-cus on the exploration end of the business, closing down or selling off unprofitable re-fining capacity because of poor margins – the difference in value between the prod-ucts sold by a refinery and the crude oil used to produce them.

Going against the flowRepsol has taken the opposite approach.

One reason for investing heavily in refin-ing technologies, says Josu Jon Imaz, man-aging director of Repsol’s refining division,

is that downstream activities are a natural hedge to upstream operations: when crude prices are low, producing oil becomes less profitable, but refinery economics gener-ally improve. And vice versa. Being an in-tegrated company, with assets in all parts of the oil business – from exploration to retail-ing – helps keep profits steady through the oil-price cycle’s peaks and troughs.

Also, the right investments can turn re-fining into an attractive business, he says: since Cartagena’s reinvention, company refining margins in Spain have risen by $2 dollars a barrel. This improvement has occurred because Repsol can now pro-duce in-demand, high-value oil products from unpopular and relatively inexpensive grades of heavy crude – dense oil made up of longer-chain hydrocarbons that require extra processing.

Mediterranean refining

© Rep

sol





Distillation

Crudeoil

H2

Desulphurisation

Cracking

Gasoline reformulation

Chemical feedstock

Transport fuels

Others(heating

fuels, solid fuels,

lubricants, asphalts)

Fuel oil(0-20%)

Naphtha(8-15%)

LPG(4-5%)Gas treating

Gasoline(30-40%)

Kerosene(5-8%)

Diesel(30-40%)

Heating oil(0-20%)

Coke & bitumen(5-15%)

Residue conversion

Vacuum distillation

Figure 1. Processes in a typical refineryS

ource: Europia



The complexity of refining units varies widely (Figure 1 on p36 summarises the main refining processes, although not all of these are present in every refinery). The more complex a refinery, the more value it can extract from a barrel of oil.

From hydroskimming to cokingHydroskimming refineries are the simplest;

their process schemes consist only of distil-lation, reforming and hydrotreating. Most of the barrel is left unprocessed and ends up as low-value fuel oil. These refineries, which have high fixed costs and can generally only process premium grades of oil, are under the greatest economic pressure because of the limited value they can extract from crude.

The most complex refineries, meanwhile, have conversion capacity – units that can process low-value residues into premium products. Heat, pressure and catalysts break up unattractive combinations of hydrocarbons and reconfigure them into molecular arrange-ments with a high market value. These refin-eries are also able to handle heavy crudes, which are cheaper to buy because they re-quire more processing and because relatively few refineries around the world have the tech-nology to convert them into useful products.

Lower feedstock costs + higher end-prod-uct values = better margins.

Formerly a struggling hydroskimming unit, Cartagena is now equipped with the full range of conversion capacity, including vacuum distillation, hydrocracking and cok-ing units. Also, its processing capacity – pre-viously, 100,000 barrels a day – has more than doubled, to 220,000 barrels a day.

The ability to process heavy crudes is im-portant because the chemical make-up of crude-oil flows is changing. Increasingly, oil available to refiners is sour (rich in sulphur) and heavier, with higher proportions of res-idue. The shift from light oil to pretty much any type of crude also improves supply se-curity: heavy oil is available from a wider spread of countries, including many politi-cally stable ones such as Canada.

Cartagena’s end products include gaso-line, naphtha and liquefied petroleum gas (LPG), but the plant is geared to maximise output of diesel and kerosene – the middle distillate products the country most needs.

Diesel is in particularly high demand in Spain, where it powers four out of five cars. Spain used to import around a third of its middle distillate needs, almost 14 million tonnes a year. But Cartagena’s transforma-

The three hydrocracking units at Cartagena have steel walls 28 centimetres thick and weigh up to 1,350 tonnes apiece. Installing them was no picnic

© Rep

sol



tion has reduced its import requirement by 4.5 million tonnes a year. In fact, with diesel demand in the country falling because of the economic slump, Spain was – in late 2012 – a net exporter of diesel.

But before the fuel gets into your TDI, there is a lot of work to do – the bit that gets the engineers really excited.

Who says refining isn’t cool?The step-up in refining complexity starts

with vacuum distillation, which takes resi-due from the atmospheric distillation proc-ess and, under low pressure, converts it into an intermediate product called vac-uum gasoil; the use of low pressure means atmospheric-distillation residue can be boiled at a lower temperature than would be necessary at normal pressure, avoiding product degradation.

However, vacuum gasoil can’t be used in cars; another process – cracking – is re-quired to convert it into market-ready prod-

ucts such as diesel, kerosene and gasoline.Cartagena’s new hydrocracking unit

breaks down long, complex hydrocarbon molecules into simpler, lighter ones under the action of heat and high pressure – up to 200 bar – in the presence of a catalyst and a large amount of hydrogen.

Enter the coker The addition of the coker, meanwhile, has

taken the refinery to the ultimate level of so-phistication. As well as producing vacuum gasoil, vacuum distillation generates a res-idue; cokers use high temperatures to turn these leftovers, or bottoms, into lighter prod-ucts such as diesel and gasoline.

Furnaces heat up the residue to around 500°C and feed the resulting liquid into low-pressure drums, where long-chain hy-drocarbons are broken down into shorter ones, forming light and heavy gas oil. The light gasoil, at this stage, is ready for automotive use and the heavy frac-tion is processed again in the hydroc-racker to produce more road-quality die-sel. Meanwhile, the residue from the coker – petroleum coke – is sold to other indus-trial processes, such as cement and ce-ramics manufacturers.

Saving emissions: firing refinery furnaces on natural gas

© Energy Future

Deep conversion: Cartagena’s coker

© Repsol



3X

85X

3.2 billion

1,110 kilometres

Cartagena =



None of this additional capacity is much use, however, without desulphurisation equipment. Combusting sulphur-rich oil products in vehicles, diesel generators or industrial furnaces generates sulphur diox-ide (SO2) emissions – a cause of acid rain. So sulphur must be removed before prod-ucts are sold.

Products go through various processing phases in the plant’s hydrotreating, or hy-drodesulphurisation, units, which use cata-lysts in the presence of large amounts of hy-drogen – produced on site from natural gas, LPG or naphtha – to remove sulphur and other impurities. This produces a steadily accumulating yellow mountain of elemental sulphur within the refinery’s grounds – 500

tonnes a day of it – which is sold on to ferti-liser producers.

Cartagena’s redevelopment has slashed emissions of SO2, NOx (nitrogen oxides – a cause of smog and acid rain) and par-ticulates, and helped the refinery surpass European requirements for sulphur removal.

Complying with environmental legislation has become one of the main stresses on re-finery economics in general because it re-quires costly additional processing capacity.

But Imaz sees Europe’s tightening envi-ronmental standards as an opportunity to become more profitable. The obvious way of cutting CO2 emissions, for example, is to use less energy. And, because energy ac-counts for about two-thirds of Repsol’s re-fining costs, using less of it means big fi-nancial gains.

Leaner and greenerThis is achieved in various ways. Waste

heat from the furnaces is recovered and used to make steam for other processes within the plant, for example. Also, instead of fuel oil, furnaces are fired mainly by nat-ural gas, reducing CO2 and SO2 emissions.

CO2 emissions per barrel from Cartagena are now half what they were before the up-grade, says Repsol. And the switch to gas has reduced group CO2 emissions by 6-7%.

Indeed, the single biggest share of contin-uing investment – around half of it – will go on technology to improve energy efficiency and reduce CO2 emissions. That might not sound as spectacular as building a new re-finery, but it’s a vital step in becoming more competitive, says Imaz. “Reducing CO2 emissions is our next Cartagena.”v

Repsol had to hire one of the biggest cranes available in Europe to lift the heav-iest of Cartagena’s three steel hydroc-racker reactors, says Joaquín García-Estañ, director of engineering and devel-opment at Cartagena.

The hydrocracker reactor’s steel walls are 28 centimetres thick, so that they can withstand the high pressures and tem-peratures inside. As a result, the heaviest weighs a monumental 1,350 tonnes. The crane was also used to unload and trans-port the project’s other exceptionally bits of kit – four coker drums, a vacuum tower, four hydrotreating reactors and the derrick structure in the coker unit.

The logistical complexities didn’t stop there. The surrounding industrial zone con-tains numerous other facilities, including three combined-cycle power plants. There was a risk that passing 1,350 tonnes of steel under live electricity cables, which crisscross the area, would create an elec-trical arc – a dangerous discharge of lu-minous current. Repsol had to arrange for power to be switched off temporarily, says García-Estañ – a tricky operation given that the area produces as much as 10% of Spain’s electricity. v

Two cranes and a hydrocracker

The most complex refineries have conversion capacity – units that can process low-value residues into premium products

Gasoline

Kerosene

Diesel fuel

Asphalt, wax, lubricating oil

Naphtha

Petroleum gas

Furnace

Crude oil is heated until it vaporizes – to 350˚C plus. The resulting gas is pumped into a tall, thin tower called a fractioning column, or pipestill. The vapour rises up the tower, passing

through a series of trays with holes in them; as it rises, it cools down, condensing back into several distinct liquids. Lighter fractions, such as kerosene and naphtha, collect near the top of the tower; heavier fractions, such as lubricants and waxes, fall through weirs to trays at the bottom. Engine fuels such as gasoline are then processed further elsewhere in the refinery,

before being trucked out to filling stations or other market outlets. The heavy bottom fractions often undergo further treatment to convert them into more useful products (see p81).


Industry facts


Profile – Lavina Quay

Name: Lavina QuayCompany: TechnipPresent job: Process engineerAge: 28Nationality: MalaysianDegree: BA, chemical engineering; University of Malaya, Malaysia

I’m nearly five years into my career with Technip – designing large energy-infrastruc-ture projects, such as liquefied natural gas (LNG) and gas-treatment facilities.

I’m responsible for the process design of a plant. I study and specify the equipment, instruments and utilities that will be needed, as part of a design that aims to minimise waste and emissions while maximising pro-duction in an efficient and safe manner.

Although my role is largely office-based, I also go on site visits to help oversee the commissioning – and plant start-up – proc-ess of projects that I’ve worked on. That is a really satisfying experience – seeing what you designed on paper turning into a reality.

For example, I was given the chance to travel from my base in Kuala Lumpur, Malaysia, to a natural gas-liquefaction plant in China to carry out the pre-commissioning, commissioning and start-up activities.

Being in an operational environment pro-vides you with a new skill set: when you

design something on paper, everything is based on ideal conditions; in reality, though, there may be some fine-tuning to be done. If problems arise, you have to be ready to identify and solve them quickly.

The Chinese LNG plant was a good ex-ample. Before natural gas is cooled into liq-uid form, it must first be treated in an acid-gas removal unit (AGRU) and undergo other pre-treatment processes so that it meets the specification required for liquefaction.

The plant we had worked on was origi-nally designed to process very lean natural gas – gas that contains very little or no heavy hydrocarbons. But, when it came to project start-up, the available gas stream consisted of heavier hydrocarbons than expected at the design stage. These cause foaming in the AGRU contactor as the condensed heav-ier hydrocarbons mix with the circulated amine, making the process unstable.

Our task was to find out how to manage and stabilize the system, which we achieved by regularly cleaning the unit of condensed hydrocarbon via skimming operation, filtra-tion and injecting controlled amounts of anti-foam when required.

That type of experience has given me op-erational skills to complement my more the-oretical ones. It’s given me vital insights into how a plant operates and how it needs to be fine-tuned to run smoothly, which provides valuable lessons for future designs.

The combination I’ve had of design work, on-site experience and Technip’s excellent training programme – and involvement in a variety of energy projects – has given me great exposure over a short period. Soon I’ll be able to start helping younger engineers.

In five or 10 years’ time I may want to move into project management, but for now I’m interested in staying focused on de-sign work – I’m still young, there’s a lot more to learn and I would like to widen and strengthen my skills base.

Fill your knowledge gaps

• Introduction to the oil and gas industry• Introduction to the power industry• Financing energy• The Great Game: geopolitics and energy• Energy and the environment

Learn better. Learn faster.

Knowledge is power

www.energy-future.com


3.4 – Offshore technology

The pressure’s on: pushing the limits offshoreDeep-water drilling is sometimes compared to operating in outer space – both involve precision engineering and movement, often carried out by remote control from a long way away

Imagine the skill needed to sit on a drill ship in the middle of the ocean, guiding

a drill into the seabed 2.5 kilometres be-low you, steer it through hundreds of me-tres of rock below that, extract the oil and return it safely to the surface. That’s what is required of engineers working on today’s deepest offshore projects.

So far, the oil industry has been very suc-cessful at drilling in deeper and deeper wa-ter. By 2012, the record for a completed offshore production well was held by the Perdido platform in the Gulf of Mexico, owned by BP, Chevron and Shell. The well is almost 3,000 metres deep in total, includ-ing the section drilled into the seabed; the platform is located in nearly 2,500 metres of water (see box p50).

But how deep can we drill offshore? A lot further, it turns out. For example, in 2006, Chevron drilled an exploratory well, Jack 2, from a rig standing in around 2,100 metres of water in the Gulf of Mexico, which penetrated over 6,000 metres beneath the sea floor. The total depth was more than 8.5 kilometres.

How deep can they go?The company set a lot of technological

depth records on the way and did find oil. Yet there is a difference between locating hydrocarbons and being able to produce them successfully from that sort of depth.

Risers – the pipes connecting reserves to the rig – and other technology need to be rigorously tested to make sure they are safe and reliable in such unfamiliar conditions. Oil companies know it’s possible to produce from offshore wells deeper than the Perdido development, but no-one knows for sure how deep it can be done.

There are considerations to be taken into account beyond drills and risers. Deep wells are very costly – it can cost more than $100 million to set up a rig to carry out a drilling campaign in deep water. So there needs to be a good chance of hitting oil: no-one wants to spend that kind of money and come up dry.

Scarcity of drilling rigs has also been a problem, although that situation is chang-ing. In 2000, there were only around 10 rigs in the world capable of drilling deeper than 7,500 feet (2,286 metres). Now, there are more than 100.

It helps if sea conditions are right too. The Gulf of Mexico, for example, generally has benign sea and weather conditions (un-less a hurricane is passing through, in which case drilling is usually halted); other areas are less favourable. Several big compa-nies are contemplating drilling off the South African coast, for example, but they may have to contend with tricky ocean currents.

That’s not all. As oil firms go in search of oil and gas reserves in deeper and more com-plex geological formations, they must deal with increased pressures and temperatures that test the limits of existing technology. Many of these hard-to-get-at reserves lie in geologically young deep-water basins around the world, where large volumes of sediment

As oil firms go in search of oil and gas reserves in deeper and more complex formations, they must deal with increased pressures and temperatures



have been deposited. These include the Gulf of Mexico and the Caspian Sea.

Drilling equipment operating below those deposits may have to withstand pressures of up to 20,000 pounds per square inch (psi) and temperatures as high as 175°C. That’s a problem for today’s technology, which has a technical limit of 15,000 psi pressure and a temperature of 120°C.

BP estimates that the ability to operate under those more extreme conditions could give it access to an extra 10-20 billion bar-rels of resources. Given that BP had net proved oil and gas reserves of nearly 18 bil-lion barrels of oil equivalent at the end of 2011, the gains for the industry as a whole could be very significant indeed.

To kick-start development, BP has cre-ated an initiative called Project 20k – the fig-ure representing 20,000 psi – to encourage industry collaboration to come up with ways of improving existing technology.

The sort of equipment that will need to be perfected include:• Subsea valves, weighing 20 tonnes, capa-

ble of closing and isolating hydrocarbons in seconds;

• State-of-the-art sensing and monitor-ing systems for real-time subsea integrity management; and

• Blow-out preventers weighing over a 450,000 kilograms and standing more than 20 metres high.Safety needs to be seen to be at the heart

of all industry developments too; the equip-ment would need to be shown to work safely at 30,000 psi onshore for it to be deemed fit for use at 20,000 psi offshore.

Worth its saltDrillers in some parts of the world face an-

other challenge in the form of a layer of salt, often in a domed formation, created millions

Chevron’s Jack 2 well in the Gulf of Mexico reached a total depth of over 8.5 kilometres

Drillers in some parts of the world face another challenge in the form of a layer of salt, often in a domed formation, created millions of years ago



As the world’s supply of easily processed lighter crude dwindles, the industry is turning to reserves of heavier and more viscous oil. Although these crudes are more costly and complicated to extract and process, espe-cially offshore, high oil prices have in recent years generally justified the expense.

Total is among the pioneers of sub-sea technology, at its deep-water fields off Angola. In its first developments there, Girassol, Dalia and Rosa, the company used subsea production wells from which the ef-fluent produced was carried up to a floating production, storage and offloading vessel (FPSO) on the surface, where it was then separated out into oil, gas and water.

In 2011, though, it went one better with Angola’s Pazflor field, where the oil is heavy, viscous and located in low-pressure reser-voirs. The company installed three subsea separation units, each weighing 1,200 tonnes, which separate out the oil, water and gas on the seabed, at water depths of 800 metres. (the right-hand image below shows Pazflor’s subsea layout).

Placing the separation equipment on the seafloor reduces the pressure at the well-head that the oil must overcome to exit the well – helping oil in low-pressure wells flow out of the ground faster. Oil and water are then sent to the surface using powerful pumps, also installed on the seabed, while the lighter gas rises without assistance.

Locating processing equipment on the sea-bed also means a smaller, cheaper platform can be used at the surface.

But operating complex equipment hun-dreds of metres below the surface is no cakewalk, not least because you can’t get people down there easily to service it. It re-quires robust, reliable and safe technology capable of operating with minimal mainte-nance for 20 years or more – and which can also be managed remotely.

None of this is cheap: Pazflor was budg-eted at around $9 billion. But Total thinks it’s worth doing, because oil can be produced – and sold – faster.

As producers bring more deep-water heavy oil into production, manufacturers will develop more powerful pumps and equipment capa-ble of withstanding higher pressure. Framo Engineering, owned by oilfield services group Schlumberger, supplied the pumps for Pazflor and is due to supply another powerful pump-ing system for Total’s Girassol field in 2014 to help extend the life of those reserves, at a cost of around $200 million.

Subsea technology could also help bring more marginal small and isolated reserves into play, as these can be connected – or tied-back – to seabed units over a longer distance than is possible with surface rigs. That means that seabed processing equip-ment can be used to service more reservoirs than its surface-based counterpart. v

Seabed technology

… goes down hereThis kind of thing …

© FMC Technologies © FMC Technologies

Potential for exploration

Potential for development

RECENT GRADUATES F/M

Total will hire 10,000 people in 2012. Why not count yourself among them?Working for Total means opportunities for a varied, rewarding career. You will be part of a multicultural company open to the wider world, which considers employee talent, innovation and high technology the core focus of its strategy. Today 100,000 men and women support our corporate mission: to supply the world with the energy it needs and invent the energies of the future together.

Apply at

www.careers.total.comMore than 600 job openings are now on line!

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13P36170-FORUM_ECOLE_148x210.indd 1 01/02/13 15:37



of years ago, when the ocean above the then-seabed evaporated. These salt-cov-ered formations, known as pre-salt, sit be-low the rock of the present seabed and of-ten on top of hydrocarbons reserves, which are referred to as pre-salt (pre means that the hydrocarbons layer was laid down be-fore the salt).

The salt layer is a problem, first because it acts as a shield, making it difficult for seis-mic imaging sensors to see what is below it, and second because it makes producing oil more difficult. Indeed, it is only in the last 10-20 years that imaging technology has pro-gressed enough to assess with much accu-racy the presence of hydrocarbons in pre-salt regions.

And it is only recently that engineers have learnt how to tap those reserves suc-cessfully. The problem is that the layer of salt makes the rock beneath it fracture and break up. That makes it difficult to ensure the drilling fluid pumped down to encourage the oil to rise goes directly into the well sys-tem within the reserves, rather than getting dissipated into the surrounding rock.

It’s a costly challenge to overcome, but in the right circumstances, it’s one to which it’s worth rising. That’s certainly the case in off-shore Brazil, where there could be as much as 60 billion barrels of oil equivalent in pre-salt formations, according to some esti-mates. That’s roughly as much as has been found in the North Sea. v

The Gulf of Mexico’s Perdido facility is of a type commonly used for deep-water drilling – known as a spar platform. A spar involves placing a production platform on top of a large vertical cylinder running down several hundred metres, which is anchored to the seabed by ultra-strong mooring cables.• The structure, operated by Shell, is 267 me-

tres tall from the tip of the rig to the bot-tom of the submerged structure – that’s less than 50 metres shorter than the Eiffel tower. The development has set a number of other records aside from the overall drilling record.

• Deepest water depth record for an offshore oil drilling and production platform.

• First water injection in 8,000 feet of wa-ter in the Gulf of Mexico helps push oil through the reservoir, from the injector wells to the production wells.

• Deployment of an innovative subsea sep-aration and boosting system that compen-sates for the low-pressure reservoir and about 2,000 psi of backpressure from the wells. The system includes five specially designed 1,500-horsepower electric pumps embedded in the seafloor to boost produc-tion to the surface.

• First spar with direct vertical access wells and production hardware on the seafloor at a depth of more than 8,000 feet.

• Perdido weighs 50,000 tonnes and sits in water six times deeper than the height of the Empire State Building. v

Record-breaking Perdido

The Perdido spar sits in around 2,450 metres of water, the most amount of water under any platform. Its depth is equivalent to six Empire State Buildings stacked vertically

© Shell

Pond scum as fuelSan Francisco’s drivers last year became the world’s first regular motorists to fill up their cars with fuel made from algae blooms that form on the surface of water.Algae may be grown in outdoor ponds or cultivated in enclosed plastic tubes known as bioreactors. After harvesting, oil is extracted by running them through a press and by using a chemical solvent to separate oil from the vegetative pulp. Why the interest? Algae take as little as 10% of the land needed to produce the same amount of energy using other biofuel crops such as maize (corn) and sugar beet, according to the US Department of Energy. They can also be grown in harsh conditions, where land is unsuitable for agriculture.What progress has been made? As well as the San Francisco test programme, small-scale industrial and military tests have been carried out. Like other biofuels, algae fuel can be used to power virtually anything. German airline Lufthansa plans to produce aviation fuel from algae.So will algae soon go mainstream? Probably not. It’s expensive, pioneering technology and presents its own environmental problems: although algae absorb carbon dioxide, cultivating them may also release methane and nitrogen oxide. And according to the US National Research Council, meeting 5% of US transport needs with algae fuels would involve annual use of: • Somewhere between 123 billion and 142 trillion litres of freshwater,

depending on the technology• 6-15 million tonnes of nitrogen (44%-107% of total US nitrogen use)• 1-2 million tonnes of phosphorus (20%-51% of the present US total)

Courtesy of Sapphire Energy

Green Crude Farm in New Mexico, US

© Propel Fuels


Industry facts

Wish you were here ...

Going against the grainPeople like a soft, sandy beach. But less so when it comes to taking photos: if even a few grains work their way into the mechanism, they could wreck that shiny new SLR.The oil industry has a similar problem. Sand can damage processing equipment, and slow down or even stop production. And sand-laden fluids are erosive, which presents safety risks.Finding ways of stopping sand from getting sucked into wells along with the hydrocarbons has become a technology focus for the oil industry because drilling in weak, unconsolidated rocks is common. Oil major BP says sand-prone wells account for about half of its production and that its sand-control technologies could yield more than a billion barrels of reserves.

The most common sand-control method is gravel-packing: placing a metal screen down-hole and pumping a gravel slurry around it, forming a barrier that keeps the sand out of the well. But gravel-packing is hard to do at extreme depths, pressures and temperatures. And fines – sand – tend to plug up the gravel pack, decreasing production rates.A recent innovation – achieving a similar shielding

effect to a gravel pack but with greater scientific finesse – involves the use of shape memory polymers, a newish class of smart materials. Shape memory polymers have two distinct phases: below a certain temperature, they act as a glass or hard plastic; above that temperature – the “glass transition temperature” – they become rubbery.A polymer tube is heated to a temperature above its glass transition temperature, explains Baker Hughes, an oil field services company developing the technology. This makes the material elastic. A hydraulic compactor compresses the tube to a smaller size and it is then cooled to a temperature below its glass-transition temperature – freezing it into its new, smaller dimension. When the smaller, hardened tube is placed down a well, the material responds to the heat and expands to its original shape. The flexible material conforms to the hole’s abnormalities and provides a positive stress on the formation.Shape memory polymers are also being tested for use in other industries – in the car industry, for example, on parts such as bumpers that repair themselves when heated; and in the medical industry for instruments such as expanding stents that can be inserted into an artery as a temporary shape and expand due to body heat.

… Or here… But not here

52  –  www.energy-future.com

Industry facts


Industry facts


3.5 – Solar energy

Nearly out of the shadeCapturing the enormous potential of the sun's energy is not as easy as it might look, but even winning part of the prize is worth it

The sun is the ultimate source of energy for virtually all life on Earth.But this primary resource could also hold

the key to satisfying our energy-thirsty econ-omies in a world beyond fossil fuels. In one hour, enough solar energy hits the Earth’s surface to provide a whole year’s worth of power for our societies. This is an impres-

sive statistic. However, concentrating and converting this plentiful supply into a form we can use is far from simple.

Let’s catch some raysThe amount of solar energy the Earth re-

ceives varies geographically. The equator receives the most because it is at right-an-gles to the sun’s rays. Towards the poles, though, solar energy decreases because rays strike the Earth’s surface at an angle. The amount of cloud-cover and season-ality also control the amount of solar en-ergy reaching the surface; somewhere like southern England can expect to receive around 100 watts per square metre of so-lar energy, while Mali in sub-Saharan Africa receives an average of over 250 watts per square metre.

The Coalinga plant is the world’s largest solar thermal enhanced oil recovery demonstration facility. The 29 megawatt plant, which supplies energy to a Chevron oilfield in California, comprises a 327 foot tower, 3,822 heliostats and 7,644 mirrors

© Brig

htSource



The amount and quality of sunlight helps decide the type of technology that can be used to collect it. Two main approaches are used: solar photovoltaics (PV) and concen-trating solar power (CSP).

Solar PV directly converts the sun's rays into electricity. The simplest and most com-mon way of doing this is by using wafers of very pure silicon crystals (c-Si), much less than 1 millimetre thick. When the sili-con – a type of material known as a sem-iconductor – absorbs photons of sunlight some of its electrons may become ener-gised enough to break away from their at-oms. These electrons can flow in one direc-

tion only and, if positive and negative elec-trodes are attached to the wafer, they circu-late and generate an electric current. This is called a solar cell (see Figure 1). Many cells can be linked together to form larger mod-ules and panels.

Commercially available c-Si PV offers so-lar-to-electricity efficiencies – the amount of sunlight converted into electricity – of 10-20%. This is pretty good because the the-oretical best for solar cells made from one material is about 30%. Greater efficiencies – up to 40% – can be obtained by multi-junc-tion cells. These use layers of different sem-iconducting materials – such as germanium

Figure 1. How a solar cell works

POSITIV

ENEGATIV

E

Front contact grid Glass coverAnti-reflective coating

Photovoltaics is the conversion of light into electricity at the atomic level. Certain materials exhibit the photoelectric effect, a property that causes them to absorb photons of light and release electrons, generating a flow of electricity.

In solar cells, a thin semiconductor wafer – typically silicon – is treated to form an electric field that is positive on one side and negative on the other. When light strikes the cell, electrons are knocked loose from the atoms in the semiconductor material. With conductors attached to the positive and negative sides, forming a circuit, the electrons can then be captured in the form of an electrical current.

Back contact

N-type (negative)

siliconP-type (positive)

silicon

Source: Nasa, HowStuffWorks

Offshore substation being lifted into place © London Array Limited

All at seaThe world’s largest offshore wind farm is not in the US or China, where some of the biggest onshore wind farms are being built – it’s the London Array, in the estuary of the River Thames.The first phase of the London Array, which produced its first power in October 2012, is capable of producing 630 megawatts – enough to supply 470,000 homes. This has involved:• Transporting and erecting 175 3.6-gigawatt wind turbines across an

area of 100 square kilometres, 10-12 kilometres off the coast • Installing nearly 450 kilometres of offshore cabling• Building two offshore substations and one onshoreIt should also save carbon dioxide emissions of 925,000 tonnes a year, according to the developers, Denmark’s Dong Energy and Masdar, an Abu Dhabi company dedicated to green projects.It doesn’t end there. The developers hope to expand the capacity of the London Array to around 1 gigawatt – enough for 750,000 homes. That rivals the biggest onshore wind farms. Although they are more difficult and expensive to build than onshore wind farms, offshore plants have their attractions: it’s windier offshore, there’s more space and no-one has turbines spoiling the view from their veranda (unless your house backs onto a cliff and you’ve got a telescope).

Power for half a million homes

© London Array Limited


Industry facts



and gallium arsenide – that absorb photons from different parts of the spectrum. But the greater expense of multi-junction cells con-fines them to niche applications like power-ing satellites.

A different type of waferSilicon wafers are the most mature and

common PV technology, accounting for 85-90% of the world PV market. They are made by cutting thin slices off large, sin-gle crystals or groups of crystals. An alter-native, cheaper technology is thin-film PV. Thin-films are made by coating sheets of glass or plastic with layers of semiconduc-tor only a few thousandths of a millimetre thick. It's a quicker manufacturing process

that uses fewer raw materials, and makes thin-films more cost-effective to produce. Thin-films are easily integrated into build-ings – transparent PV sheets can cover win-dow panes, for instance – and have lower up-front costs than wafers, but they are less efficient, converting only 4-12% of solar en-ergy to electricity.

Globally, PV is a $100 billion industry and has seen unprecedented growth over the last few years. Around 70 gigawatts of capac-ity existed worldwide at the end of 2011, 10 times more than five years earlier. Thirty giga-watts of capacity were added in 2011 alone.

Domestic, silicon wafer PV – rooftop pan-els generating up to a few kilowatts – ac-counts for most of this growth. Countries

Germany’s world-leading photovoltaics capacity is located mainly on rooftops, such as these Bavarian ones



that have policies encouraging solar have had enormous uptakes of small-scale PV: Germany's 25 gigawatts of PV capacity – the largest in the world – are mainly found on rooftops.

But the supersizing of PV is beginning to take off. Right across the globe, where con-ditions are right, big PV schemes are being built. In Ghana, Africa, a 155-megawatt PV plant is planned for completion by 2015 that will boost the country’s electricity-generation capacity by 6%.

Developed nations too have recently built, and are investing in, big PV projects. Canada’s Sarnia plant covers a million square metres and has a capacity of nearly 100 megawatts. In the US, multi-billionaire Warren Buffett’s MidAmerican Energy has paid $2 billion to add two big Californian PV projects to its renewable portfolio. The Antelope Valley Solar Projects (AVSP) will generate 579 megawatts after their comple-tion in 2015 or 2016, offsetting nearly 800,000 tonnes of CO2 per year. AVSP is being built using US-based SunPower's building-block approach. This flexible system uses power blocks – c-Si solar panels mounted on plat-forms able to track the sun across the sky – that are shipped pre-assembled. They arrive on site ready to be bolted together, quickly creating a PV plant of any size required.

CSP warming upPV dominates the solar energy land-

scape, but CSP is catching up. CSP indi-rectly converts solar energy into electricity by using heat from the sun to turn water into steam and drive a turbine. This technology is best suited to power-plant-sized schemes. It needs direct sunlight to work and performs best in arid or semi-arid areas such as North Africa, the Middle East, southern Spain and the western US.

Most CSP plants at present use a trough design. Parabolically curved mirrors are ar-ranged in troughs sometimes over 100 me-tres long and typically 5-6 metres wide. A

tube filled with synthetic oil – called a re-ceiver – runs the length of each trough. Sunlight is focused by the mirrors onto the receiver and the oil inside is heated to up to about 380ºC. Heat from the oil is use to gen-erate steam for the turbine.

Tower CSP uses hundreds or thousands of ground mirrors – from 1 to around 100 square metres in size – called heliostats. These track the sun and reflect sunlight onto a tall central tower receiver, heating it to over 1,000ºC. These high temperatures can be used immediately to create super-heated steam to drive efficient, advanced turbines or stored for later use.

Energy storage is a big advantage of CSP over PV, and it can be built into tower sys-tems more easily than other CSP designs. Stored energy can be used after dark or to iron out ups and downs in power generation from variations in sunlight quality during the day. This makes CSP a potentially valuable part of the green energy mix as a source that can be relied on for base-load or peak power. In Andalucía, Spain, the 19.9 megawatt Gemasolar tower CSP plant, which opened in late 2011, gives 15 hours of storage potential. Under some conditions, it is capable of send-ing out electricity 24 hours a day. A joint ven-ture between companies from Spain and the United Arab Emirates, the plant stores ther-mal energy in molten-salt heated in the tower to 500ºC. Despite these innovations, almost all CSP plants are hybridised with fossil-fuels as a back-up to ensure supply: Spanish CSP for instance relies on natural gas to generate 12-15% of its electricity.

CSP is also good at filling niche tasks in remote areas, like producing energy for

CSP indirectly converts solar energy into electricity by using heat from the sun to turn water into steam and drive a turbine



water desalination in arid regions. Another role is in enhanced oil recovery (EOR). At Coalinga in California, a CSP tower scheme is being used by Chevron to bump up pro-duction there (see photograph p54). Built by BrightSource Energy, the CSP project pro-duces steam at high temperature and pres-sure, which is injected into the reservoir. The steam pressurises and loosens viscous oil, helping to bring oil to the surface.

With policy support, the future of solar energy is likely to be bright. Solar technol-ogies are becoming more commercially at-tractive: the cost of some PV modules, for instance, decreased by 40% in 2011. And on a cost-per-watt basis, the construction of solar plants in good locations are be-coming comparable with those of coal-fired power stations, which are around $3 per

watt. Importantly, once built, fuel costs for solar plants are virtually nil.

Solar PV and CSP produced less than 1% of the world’s electricity in 2011, but the International Energy Agency estimates so-

lar technologies could account for 7% of electricity generation by 2035. After 2050, solar energy might even provide as much as one-third of the world’s final energy de-mand, it says. The rapid growth of solar looks set to continue. v

The immense demand for solar PV over the last few years has triggered a boom in man-ufacturing. Production has shifted from the West to Southeast Asia, but there’s now a global oversupply of solar cells. This sur-plus and a drop in the price of silicon caused c-Si module prices to fall by 40% or more in 2011, challenging thin-film’s cost advantage. The economic downturn also reduced the opportunities for thin-film in new construction projects. While consumers have benefited, many Western solar companies have found the going difficult. Some, like California’s Solyndra, which specialised in thin-film, have gone bust.

There is also a risk that the availability of energy-critical elements (ECEs) will affect the future of thin-film PV. Tellurium (Te), in-dium (In), and gallium (Ga) are important in the semiconductors that most thin-film PV uses. They are found as Cadmium-Telluride (CdTe), Copper-Indium-Diselenide (CIS) and Copper-Indium-Gallium-Diselenide (CIGS). These elements are not common in the Earth’s crust and are not concentrated in deposits that are economic to mine. All of them are produced as co-products of mining

for other raw materials such as zinc, cop-per or tin.

Indium has been highlighted as a partic-ularly important element for thin-film. A rel-atively minor player at the moment, indium in CIGS has the highest solar-to-electricity conversion efficiency of any thin-film semi-conductor. If costs can be cut from the man-ufacturing process then CIGS might be able to compete on efficiency with c-Si PV.

But indium is also important to the con-sumer electronics industry. Indium-Tin Oxide (ITO) is unusual because it conducts electricity yet is transparent. Manufacturers of smart-phones and tablet computers coat ITO onto the surfaces of touch-screens. ITO allows the device to know when and where its screen has been touched because the human body also conducts electricity. Without ITO the boom in these revolutionary gadgets wouldn’t have happened. Around 80% of indium goes to make ITO and, al-though the price of indium came down from over $800 a kilogram in early 2011 to below $500 a kilogram in late 2012, an expansion of thin-film PV using indium faces stiff com-petition for this scarce resource. v

Turbulent markets and the future of thin-film

Solar PV and CSP produced less than 1% of the world’s electricity in 2011, but could account for 7% of electricity generation by 2035

You can’t turn back on tidalCountries with the right coastline could find tidal power a great source of renewable energy. In this sense, the UK is lucky: it may be able to generate 70 terawatt hours a year from tidal; that’s a fifth of national demand. One location – the Severn estuary in the southwest of the UK (see map) – could generate up to 5% of UK supply, depending on the technology used. The Severn estuary is the shape of a funnel pointing towards the Atlantic Ocean. When the tide comes in, water from the estuary’s wide mouth is channelled into its narrow end, producing the second-biggest tidal range in the world: a whopping 15 or so metres.Energy from the tidal range can be harnessed by holding back high-tide water behind a barrage across the funnel, then letting it flow back to sea through turbines. Such a project would cost as much as £34 billion ($53 billion) but might generate 17 terawatt hours a year – roughly equivalent to the output of two nuclear power stations. It would, however, damage habitats in the estuary, where 70,000 water birds overwinter, and disrupt the migration of fish.A tidal fence (pictured) uses current energy to force water through turbines as it naturally races through the estuary. This would be less damaging to local environments and would cost less than a barrage – a snip at around £3.5 billion ($5.5 billion). But it would also generate less power: a comparatively measly 3.5 terawatt hours a year.

The cheaper, less damaging, but less powerful tidal fence option

© Severn Tid

al Fence G

roup 2009


Industry facts


4.1 – Future fuels: biofuels

Sowing the seeds of sustainable fuelsMaking fuels from plants and waste could play a crucial role in stemming the rise of CO2 emissions and oil consumption

Bringing greenhouse gas (GHG) emis-sions under control may be the greatest

challenge facing the world. But oil and gas are so central to our way of life that they often seem irreplaceable. This is especially true in transport, where the internal combustion en-gine and the jet engine power the movement of people and global trade in goods upon which economies are built. The transport sector accounts for more than half of global oil use, and the International Energy Agency (IEA) predicts this will increase to 60% of the 100 million barrels a day the world is likely to be consuming in 2035.

So making transport less dependent on fossil fuels could significantly reduce over-all GHG emissions. Hydrogen-powered and electric vehicles are gradually becoming vi-able alternatives to oil; but they remain lim-ited by the power they can deliver and the lack of suitable refuelling networks.

A practical solutionBiofuels are a more practical solution.

Made by processing plant material to pro-duce hydrocarbons, they can be blended with, or even used instead of, conventional mineral fuels with no or minimal modifica-tions to car or aircraft engines. They can be distributed to and delivered from the pump, just like gasoline or diesel. Their net carbon impact is low (in theory, it could be neutral

– if the tractors that harvest the crops, the equipment that produces the biofuels and the trucks that distribute the end product were all powered by renewable energy). Biofuels are versatile too: they can be used for other pur-poses, such as heating homes or generating electricity. They can even produce methane (see p69), which can serve as a green substi-tute for any application of natural gas.

The biofuels in commercial use at present are known as first-generation bi-ofuels. Bioethanol is derived by ferment-ing plant sugars and starches – commonly from maize (called corn in the US), sugar cane, and sugar beet. Any long molecules like starch in the feedstock are broken down into shorter sugars by heating, grinding and the addition of enzymes. Microbes – includ-ing the yeast Saccharomyces cerevisiae, which is also used to make beer, wine and bread – then go to work on the sugars, pro-ducing bioethanol and carbon dioxide (CO2). Bioediesel is derived from plant oils – like rapeseed, palm oil and even waste cook-ing oils – or animal fats. It is simple to pro-duce: after the oil is purified, it is reacted with methanol at 20-80°C to produce a fuel that mimics mineral diesel.

Bioethanol and biodiesel are mainly blended with conventional fuels. The EU and Australia allow up to 10% ethanol to be mixed

Sweet wheels. Sugarcane now powers a third of Brazil’s road transport



with gasoline (called E10). In the US, E10 is sold almost nationwide, and E15 (15% mix) and even E85 (85% mix) are available.

However, ethanol is a less efficient fuel than gasoline or diesel because it contains less energy per unit of volume. Some oil and car companies, and some consumer groups, also say ethanol damages engines because it attracts water that interferes with lubrication of moving parts and clogs up fil-ters. Government agencies and environ-mental groups contest this and point to con-trolled trials demonstrating that E10 and E15 fuels do not cause damage.

However, fuels with high concentrations of ethanol like E85 can only be used in spe-cial engines. In Brazil, flexible-fuel vehicles – cars designed to run on a mixture of fuels, usually gasoline and ethanol – are common because of long-standing government sup-port for biofuels produced from the country’s abundant sugarcane resource, which now powers a third of the country’s road transport.

There are doubts, however, about the en-vironmental credentials of some first-genera-tion biofuels. It can be unclear just how much CO2 is being saved compared with fossil fu-els, since GHGs are emitted in the manufac-ture and distribution of biofuels. Also, wide-spread planting of biofuel crops may have a negative environmental impact, depend-ing on where they are planted and what they replace. A 2008 study by Danish biologist Finn Danielsen and colleagues from across Europe estimated that the clearing of virgin rainforest in Southeast Asia to plant palm oil for Western biofuels markets could actually emit around 200 tonnes of CO2 per hectare, as well as devastatingly reducing biodiversity.

There is sometimes also unhealthy com-petition for land between the food and fuel industries. As populations grow, pressure on land for cultivating food increases, and many – including big food producers such as Nestlé – blame biofuels for global food price rises. The situation is being worsened by extreme weather events that in recent years have caused crop failures in North America and Russia. This has increased the strain on food resources and the market price they fetch. Bioethanol producers, how-ever, maintain that the high cost of crude oil should be blamed for high food prices.

Government policy should eventually solve these conflicts. China, for example, does not allow edible feedstock to be used for biofuels. Last year, the EU proposed to limit the crop-based biofuel mix.

New types of first-generation fuel-crops that grow well on marginal – non-agricul-tural – land are being trialled. For instance, Jatropha (Jatropha curcas) has seeds that

Panicum virgatum. Switchgrass to you, sunshine

© Xxxxxxxxxx

Biofuels can be blended with or used instead of conventional fuels with no or minimal modifications to engines

Artificial trees © Institution of Mechanical Engineers

Can we fix it? A beginner’s guide to geoengineeringGeoengineering – the large-scale manipulation of environmental processes – has been around since the 1940s. After the Second World War, governments discussed ideas such as seeding rain clouds for agriculture and even using the weather as a weapon (the United Nations banned weather warfare in 1978). Geoengineering remains the stuff of futurists and the side effects of tinkering in this way are unknown, but it may yet emerge as a strategy for counteracting climate change.There are two main approaches:Shade the Earth from the sun – solar radiation management (SRM)SRM could be done by placing screens in space to bounce the sun’s energy away from the Earth. This is technically difficult and expensive. A cheaper alternative would be to spray droplets of seawater into the air, forming bright, white clouds in the upper atmosphere that would reflect sunlight. Remove CO2 from the atmosphere and lock it away below ground or in the sea – air capture (AC)One method of AC would involve fertisiling parts of the oceans that are lifeless because they lack nutrients like iron. This would encourage the growth of algae, which incorporate CO2 into their limestone skeletons as they develop. When they die their skeletons fall to the ocean floor – removing CO2 from the carbon cycle for long periods. Another technology would chemically scrub CO2 from the atmosphere on an industrial-scale using artificial trees (see image).


Industry facts



typically contain around 40% oil and could be a candidate for biodiesel production in Africa and India. The plant also contains tox-ins and requires careful processing but this hasn't prevented industry interest. Finland's NesteOil announced in 2011 it is expand-ing biodiesel production from jatropha; bi-oscience company Temasek, based in Singapore, has recently developed strains of jatropha with an oil content of 75%.

The latest biofuel manufacturing meth-ods draw upon cutting-edge biotechnol-ogy and chemistry to improve energy ef-ficiency and increase GHG emissions sav-ings. These technologies differ from first-generation biofuels and are collectively called advanced biofuels; some are on the verge of commercialisation.

Non-edible cropsSecond-generation biofuels, a subset of

advanced biofuels, use lignin and cellulose from plants as their raw material. These are the structural tissues of plants – wood and stems – and are among the most abundant of biological materials. Waste from forestry, farming (such as post-harvest corn stover) or households can be used. Dedicated ligno-cel-lulosic crops such as straw and tall energy-grasses, such as elephant grass (Miscanthus) or switchgrass (Panicum virgatum), can also be utilised. These grasses give high-yields, can thrive on poor soils, and are fast-growing: elephant grass can grow to a height of 3 me-tres every year for 15-20 years.

They also have better biodiversity foot-prints than other biofuel crops. BP estimates energy grasses can produce 1,000-2,000 gallons of biofuel per acre, compared with 400-500 gallons from corn or 150-200 gal-lons from agricultural waste.

Ligno-cellulosic feedstock is heated or treated with acids or enzymes to free the cellulose; then the long cellulose poly-mers are split by other enzymes called cel-lulases. The sugars produced can then be fermented by microbes in the same way as first-generation biofuels to produce bioeth-anol. Alternatively, the tough feedstock can be gasified into carbon monoxide (CO), CO2 and hydrogen (H2) at high tempera-tures. From here bacteria like the anaerobic Clostridium can generate bioethanol or syn-thetic diesel can be produced chemically us-ing the Fisher-Tropsch method.

Third-generation biofuels – another, more futuristic category of advanced bio-fuel – refers to the use of algae as feed-stock. Algae may be converted into a range

Algae, pictured inside a bioreactor, can be used to manufacture a range of fuels

© Rep

sol

Pond life

Policies that support biofuels could result in a saving in CO2 emissions of nearly 2 gigatonnes by 2035



of fuels, including kerosene for jet engines. They do not conflict with food crops and can be grown in open ponds on marginal land or in vertical water tubes. They are also more efficient at capturing CO2 than other feedstocks and can produce much greater amounts of biomass per hectare than ter-restrial plants – possibly up to 100 times as much, says a study by the US Department of Energy (DoE). But commercialisation ap-pears years away, as production costs are double those of terrestrial biofuels, accord-ing to the same DoE study. In 2011, Shell said it was moving away from algae be-cause of poor yields and refocusing on pro-ducing second-generation biofuels from

sugar-cane waste, in a $12 billion venture with Brazil’s Cosan.

Drop-in fuels – biofuels that can seam-lessly replace or be added to existing min-eral fuels – manufactured from ligno-cel-lulosic feedstock are also generating con-siderable interest among developers. Advances in production are occurring by genetically engineering microbes to cre-ate specific fuel molecules, and progress is happening fast. Since 2006, BP has in-vested over $1.5 billion in this area of tech-nology, and has also formed a joint venture with DuPont, a chemicals company, to pro-duce biobutanol. Butanol is a longer mole-cule than ethanol, can be mixed to 85% with

Energy grasses growing in Florida

© BP p

.l.c.



mineral gasoline without damaging existing engines and is easily converted to jet fuel. BP/DuPont's first commercial biobutanol plant is expected to be operational by 2014 and commercial biobutanol plants are also starting to appear in China.

Big potentialBiofuels still account for just a small part of

fuel supply. But they have considerable po-tential, especially if recent technological ad-vances in algal and microbial biofuel pro-duction can be translated to the commercial-scale. Policies that support biofuels could re-sult in a saving in CO2 emissions of around 0.5 gigatonnes by 2035, according to the IEA.

And biofuels have some high-profile back-ers: three years ago, the US military (which, if it were a country, would be the world’s 35th biggest user of oil) said that, by 2025, a quar-ter of its energy use would come from re-newables, including first-generation and ad-vanced biofuels. The US Air Force aims for

biofuels to account for 50% of its aviation fuel by 2016 and the US Navy wants 50% of its fu-els to come from renewable sources by 2020.

In military applications, alternative fu-els offer governments a strategic benefit (a more secure supply of energy) and an eco-nomic one (the opportunity to reduce spend-ing on defence). But the same benefits are applicable to society in general – and come with a considerable environmental upside. If the science can be perfected and commer-cialised, biofuels could become a central part of a sustainable energy future. v

The American way – biofuels produced from maize (corn in the US)

BP p.l.c.

Biofuels account for just a small part of fuel supply, but they have considerable potential, especially if advances in algal and microbial biofuel technology can be made commercial


4.1 – Future fuels: biogas

In the Swedish city of Gothenburg there’s an energy revolution about to take place. This year the people of Gothenburg hope to see the first biogas produced by the GoBiGas project, which will eventually provide 1 terawatt hour a year of energy – enough for a third of the city’s needs. And by 2030, the city’s public transport vehicles could be fossil-fuel free.

But what is biogas?Biogas is methane generated from veg-

etation or animal waste. Historically, it has been produced by anaerobic digestion (AD) – the break-down of organic mate-rial in the absence of oxygen. This involves organic feedstock being placed in sealed tanks where it is broken down by naturally occurring micro-organisms. The biogas given off consists of roughly 55-70% meth-ane and 30-45% CO2 (plus about 1% nitro-gen and trace elements of hydrogen sul-phide). There’s a wide range of suitable feedstocks (sometimes also known as sub-strate), from farm manures and crops to sewage sludge and food waste. The ideal mix of feedstocks contains carbohydrates, proteins and fat. Woody products aren’t generally suitable because they are slow to break down under anaerobic conditions.

AD feedstocks often undergo some form of pre-treatment, such as macer-ation to reduce particle size so that the material is fluid enough to be pumped through the process facilities. Reducing particle size also increases the material’s surface area, increasing contact between the bacteria and the feedstock.

AD is a mature technology; and because biogas is mainly generated from waste it is generally considered sustainable. Biogas production has been rising in the EU, driven by the bloc’s target of meeting 20% of final energy consumption with renewable

energy sources by 2020. The EU’s largest biogas producers include the UK, France, Italy and the Netherlands, but Germany is by far the biggest, with a share of the EU market of around 50%, thanks to its effec-tive system of feed-in tariffs. Germany has over 6,000 biogas plants in operation. By 2030, biogas could account for as much as 10% of German gas demand, according to the German Energy Agency.

Methane can also be produced through gasification of plant celluloses and lignins. This is the approach being used in GoBiGas. This type of biogas is called Bio-SNG (synthetic natural gas); unlike in AD, it is not produced using mi-cro-organisms. The feedstock is com-busted at high temperatures with a con-trolled amount of oxygen, producing car-bon monoxide and hydrogen gas, which can be converted into methane. The en-ergy-efficiency of the process can be in-creased to nearly 90% if heat from feed-stock combustion is captured using a combined-heat-and-power unit.

Biogas can also be extracted from land-fill sites by drilling wells and extracting the methane and CO2 as it is formed. Landfill sites can generate commercial quanti-ties of landfill gas for up to 30 years after wastes have been deposited. v

Where there’s biomass, there’s gas

Some Swedish trains already run on biogas. This one’s called Amanda

© Tekniska Verken


Profile – Oliver Taylor

Name: Oliver TaylorCompany: BPPresent job: Senior Research Technologist, Fuels and lubricants divisionAge: 28Nationality: BritishDegree: Engineering, Bath University

I’m a senior research technologist for BP in our global fuels and lubricants division.

I guess I was always going to be an engineer. My father has his own business restoring and building classic motorcycles. I grew up working with him, building engines and bikes from an early age.

I enjoyed maths and physics, so I did those at A-level. Then I elected to do engineering at Bath University. I chose Bath principally because it’s involved in

a competition called Formula Student. In this competition, in the final year of your degree, you get to build a single-seat race car and then take it to Silverstone, the main UK racing track, and race against all other universities that have also built these cars.

By my final year, I managed to project manage my team and we actually achieved the best UK finish in our year of the competition and were also placed sixth globally.

During my degree, I elected to do a placement year and I did that with BP in its global fuel and lubricants development centre. When it came to choosing graduate positions, the obvious choice for me was BP.

I’ve always been interested in motorsport, so the highlight of my career so far was leading a project to develop the oil for six of the cars on the Formula One grid.

This was a great project to combine my technical capability from university with all the skills BP has taught me – around lubricant development, statistics and project management.

One of the biggest challenges when developing any oil, particularly one that’s used in motorsport applications is to increase performance without sacrificing durability. I got to work directly with the engine manufacturers, to test and prove this new formulation would work – testing on Formula One engines and then got to see this launched into the Formula One season.

Considering where you want to be in the future is always a really hard question to answer. For me, when I look for the answer to that question, I look at what I really enjoy doing … and that’s technical engineering.

Going forwards, I want to combine that with increased levels of project and managerial responsibility. I also quite like working directly with manufacturers. So I see myself working in a technical liaison role within BP, working directly with global engine manufacturers.


4.2 – Future fuels: GTL

Newish kid on the blockGas-to-liquids plants make liquid fuels like diesel – but from natural gas instead of oil. They could be about to hit the big time

Gas-to-liquids (GTL) is a niche business. GTL fuels are produced in just a hand-

ful of plants around the world. And they sat-isfy a mere third of a percent of global de-mand for petroleum products. But, with plans being firmed up to build new capacity in the US, GTL may be about to become a more mainstream product.

The GTL process converts gas into die-sel and other refined oil products, such as jet fuel, naphtha and base oils. There is ro-

bust demand for those products and, as a result, they fetch a high price. They are also cleaner and burn more efficiently than com-parable products refined from oil.

So why isn’t everyone making GTL fuels? The plants – think of them as natu-

ral gas refineries – are expensive to build. At the peak of its construction, there were over 52,000 people working on Pearl GTL; around 2 million tonnes of equipment and materials were imported to the site and workers installed enough steel and pipes to make 2.5 Eiffel Towers every month. The plant ended up costing almost $20 billion.

You need cheap gasTo make the economics stack up, a devel-

oper needs a large amount of cheap gas and ready access to oil markets. For these rea-sons, most of the world’s GTL production is in Qatar, a small country with big ambitions when it comes to infrastructure projects, an

Qatar’s Pearl GTL plant: the biggest worldwide (of five)

© Shell



abundance of cheap gas (the North Field is the world’s biggest gas field) and state-of-the-art port facilities with access to Asian and Western markets.

Qatar is home to the world’s first commer-cial plant, the 34,000 barrels a day Oryx GTL facility, which opened for business in 2006. It is also the location of Pearl GTL, which started commercial operations in 2011, and is the biggest plant in the world, producing up to 140,000 barrels a day of GTL products.

Outside Qatar, there is a 36,000 barrels a day plant in South Africa; a 34,000 barrels a day unit under construction in Nigeria; and a small test plant in Malaysia.

The combined capacity of these five plants (one of which, Nigeria’s Escravos GTL plant, isn’t yet operational, but is due to come on stream in 2013) adds up to around 260,000 barrels a day of products – a drop in the ocean of the 87 million or so barrels of oil products consumed every day worldwide.

© N

ord Strea

m

Figure 1

The GTL process



But things could be about to change. Exploration in shale rocks has, in the past few years, endowed the US with a new and very large supply of cheap gas. Using domestically sourced gas to reduce expensive oil imports makes obvious economic and strategic sense.

Sasol, a South African energy company and the operator of Qatar’s Oryx plant, said at the end of last year that conditions were right to press on with preliminary work

for the construction of a big GTL plant in Louisiana. If built, the facility would produce four million tonnes a year – 96,000 barrels a day – of GTL-diesel and other chemical products, at a cost of up to $14 billion, ac-cording to Sasol. That, says the company, would make it one of the largest foreign di-rect investments ever in US manufacturing.

This might be small beer next to the big-gest oil refineries (ExxonMobil’s Baytown

GTL plants are natural gas refineries. Water, condensates and other components, such as sulphur, are removed from the gas (see Figure 1 p72). The gas is then cooled and natural gas liquids are separated using distil-lation, leaving pure natural gas – methane.

Methane and oxygen flow into a gasifica-tion unit with steam and, at high tempera-tures, are converted – or reformed – into a mixture of hydrogen and carbon monoxide, known as synthesis gas, or syngas.

The syngas enters a GTL reactor, where it comes into contact with a catalyst that speeds up its chemical conversion into long-chained waxy hydrocarbons and water – us-ing the Fischer-Tropsch (FT) process.

These hydrocarbons are then reacted with hydrogen and cracked into a range of smaller molecules of different lengths and shapes. Distillation separates out different products, which have different boiling points.

The liquids the process produces – known as synthetic fuels – are similar to the prod-ucts that are produced in a conventional oil refinery and include diesel, jet fuel, naphtha, kerosene, paraffins, gasoil and base oils.

GTL products have important similarities to conventional refinery fuels: they can be transported, distributed and marketed using the same infrastructure. Also, car engines don’t need to be modified to use them. So they fit neatly into the supply chain.

There are important differences, too: GTL fuels are cleaner than conventional re-finery fuels. They are virtually free of sul-

phur, nitrogen and aromatics, so they can reduce tailpipe emissions and local pollu-tion; however, GTL doesn’t result in much of a decline in carbon dioxide (CO2) emis-sions compared with products made from crude oil.

GTL fuels can also enhance engine per-formance; GTL diesel has a cetane rating – a measurement of combustion quality – of 70 or more, compared with closer to 50 in the case of standard refinery diesel.

The history bitIt might sound revolutionary, but the FT

process has been around for almost a cen-tury. It was invented in 1923 by a German chemist, Franz Fischer, and Czech-born Hans Tropsch, at Germany’s Kaiser Wilhelm Institute for Coal Research.

It can also be applied to biomass and coal to produce the same types of fuels. Biomass-to-liquids (BTL) has the considera-ble advantage over GTL and coal-to-liquids (CTL) technologies of being carbon neutral. But BTL remains relatively expensive and, for now, is impractical on the scale of GTL. CTL is also expensive and produces much more CO2 than GTL.

Germany, during the Second World War, and South Africa, during apartheid, demon-strated the strategic benefits of the FT proc-ess. Both regimes had coal, a need for mo-bility, but not enough oil and used CTL to produce synthetic fuels (although they both ultimately lost). v

How GTL works, what it produces … and some history



unit, for example, has a processing capacity of 28 million tonnes a year). But it’s a start, and if the US’ relatively small fleet of diesel vehicles expands, demand for more GTL capacity could grow quickly – yielding finan-cial, environmental and strategic benefits.

The Ubekistani connectionSasol is also behind a planned GTL

project in Uzbekistan that will convert part of the Central Asian country’s plentiful gas reserves into transport fuels to reduce the country’s reliance on imported oil products. The company has said it will take a decision on whether to go ahead with the 38,000 bar-rels a day plant in late 2013.

The South African firm says its Uzbekistani project proves you don’t need access to the sea to make GTL a success – until recently,

a commonly held belief. Uzbekistan is one of the world’s only two doubly landlocked countries (the other is Liechtenstein).

If Sasol’s experiment is a success in the US, more plants may follow there and in other countries with reasonably priced gas and a market for GTL products. And if the price of crude rises further, so will the value of GTL. v

GTL fuels can serve numerous purposes. In 2008, the Airbus A380 became the first commercial aircraft to fly with a synthetic liquid fuel processed from gas.

If the US’ relatively small fleet of diesel vehicles expands, demand for more GTL capacity could grow quickly – yielding financial, environmental and strategic benefits


4.3 – CNG

From A to B without too much CNatural gas is becoming a more popular transport fuel, as refuelling networks expand

If you’re looking for transport that’s cheap to run, while cutting greenhouse gas emis-

sions and pollution – and many people are – then natural gas vehicles (NGVs) fit the bill. More people than you might think already drive them, from taxi drivers in Tehran to truckers in Tennessee.

And their popularity is spreading – some in the industry say there could be four times as many NGVs on the world’s roads by 2020 as there were at the end of 2011.

The advantages are easy to see.Gas is generally cheaper than oil. And

it is cleaner: light-duty vehicles that run on natural gas, for example, produce up to 30% fewer greenhouse-gas (GHG) emissions than conventional vehicles. Emissions from medium and heavy vehi-cles are 23% lower.

Gas also generates less local pollution than oil. Vehicles running on compressed natural gas (CNG) produce 97% less carbon mon-oxide, 99% less particulate matter and 100% fewer evaporative emissions than gasoline.

Replacing 10% of the diesel engines used in heavy-duty transportation in the US with gas-powered engines could cut emis-sions of nitrogen oxide (NOx), a constitu-ent of smog, by as much as 200,000 tonnes a year, estimates the US’ Environmental Protection Agency.

NGVs are also quieter than normal cars, making them more pleasant to drive. In other respects – engine performance and styling – they’re pretty much the same.

But NGVs have drawbacks, too: most car engines aren’t optimized for gas use and con-verting them is expensive – typically $12,000-18,000, depending on the vehicle size (al-though subsidies in some countries can sig-nificantly reduce this). Also, purpose-built NGVs are generally more expensive to buy than conventional cars – $2,000-10,000 more than an equivalent gasoline vehicle, accord-ing to the International Energy Agency (IEA).

More significantly, refuelling networks haven’t been developed on a wide enough scale to make NGVs practical for most driv-ers. Gas is generally more suitable for city-bound vehicles – taxis, buses and refuse

trucks, for example – which operate within a limited range and are never far from a re-fuelling point. Long-distance haulage com-panies also often have fixed routes and can plan long-distance journeys even if there are very few refuelling outlets along the way. But private vehicle owners need more flexibility.

Then there’s the problem of the tank that is needed to store the gas. A vehicle that is converted to run on natural gas will proba-bly need to sacrifice valuable trunk space to make way for it – an inconvenience for private users. In purpose-built NGVs, the tank can be hidden away under a seat or elsewhere within the chassis to minimize or eliminate the loss of luggage space.

Another disadvantage is range: a CNG cylinder generally needs to be refilled more frequently than a gasoline or diesel tank. But with the spread of CNG refuelling points, this should become less of a prob-

NGVs have been around since the mid-20th century, but despite their economic and environmental benefits, they still account for a tiny percentage of cars on the road


4.3 – CNG

lem. And to some drivers – when the lower fuel costs are taken into account – it may seem insignificant.

CNG or LNG?NGVs typically use one of two types of

gas: compressed natural gas (CNG), which involves the storage of natural gas under high pressure – typically about 250 bar – in a thick-walled steel, aluminum, or compos-ite tank; or liquefied natural gas (LNG), in which the gas is chilled to -161°C and stored on board as a liquid. LNG cylinders resem-ble a thermos flask: they are a highly insu-lated to stop the gas from returning to its gaseous form and can maintain it as a liquid for two weeks or more.

CNG is the preferred fueling method for cars and light-to-medium NGVs. Heavy-duty vehicles tend to use LNG, which allows them to store more fuel on board with less tank weight because LNG is denser than CNG, so more energy is contained in the same space and driving range is extended.

A third option for gas storage – as yet not commercially available – is adsorbed natu-ral gas (ANG), which involves the storage of

gas in a nano-porous material (usually car-bon derived) at lower pressure than CNG (around 35 bar). As with LNG, ANG’s advan-tage over CNG is that the fuel is stored at a higher density.

NGVs have been around since the mid-20th century, but despite their economic and environmental benefits, they still account for a tiny percentage of cars on the road. At the end of 2011, estimates NGV Global, a trade association, there were more than 15 million NGVs in use, a very small number in the context of a global automotive market that is thought to number around 1 billion units.

Sales of NGVs and the way they are used vary widely from region to region and coun-try to country.

Around three-quarters of all NGVs and more than half of all fuelling stations can be found in just five countries: Iran, Pakistan, Argentina, Brazil, India and China; they’re particularly popular in countries that lack gasoline-refining capacity, such as Pakistan and Iran. In North America and parts of western Europe, gas is predominantly used in commercial vehicles, whereas in Asia, Latin America and the Middle East – the

Gas is cheaper and cleaner than oil, but there aren’t enough places to refuel … and you need one of these


4.3 – CNG

main growth areas for NGVs – it’s mostly used in cars.

NGVs account for less than 1% of total world road-fuel consumption and less than 1% of total world gas demand, but the mar-ket is poised for rapid growth. NGV Global believes that, by 2020, the total number of NGVs may rise as high as 65 million.

The US gets seriousThe US is a market with obvious growth

potential. At present, gas’s contribution to transportation in the US – a country that needs to reduce its reliance on oil imports, cut emissions and make more economic use of energy – is negligible. But if, over the next decade, trucking companies replaced their diesel vehicles with trucks running on either CNG or LNG, the country could cut oil imports by almost 30%, says Chesapeake Energy, a big natural gas producer and an advocate of the use of gas in vehicles.

And gas in the US, thanks to very large discoveries in unconventional deposits in recent years, is in plentiful supply.

The US is also considering using its gas to make synthetic fuels (see p71). These closely resemble oil products – although they are cleaner – and have the advantage over CNG of being able to make use of the same distribution and marketing infrastruc-ture that oil products use.

But the limited refuelling network remains a big stumbling block to rapid market devel-opment of CNG or LNG as transport fuels in the US and elsewhere.

Clean Energy, North America’s largest provider of natural gas for transportation, is trying to change this. It is building what it calls America’s Natural Gas Highway, a re-fuelling network that will initially consist of 150 LNG-truck filling stations connecting major transit routes across the US. Around 70 of these were in place by the end of 2012, with most of the rest due to be built in 2013. Backed by $450 million of funding from Chesapeake Energy and other inves-tors, Clean Energy plans to build on its core markets – the refuse, transit, trucking, shut-tle, taxi, airport and municipal-fleet markets.

Expanding the NGV refuelling station net-work around the world has proved tough over recent years, generally lagging growth in vehicle usage. However, it did manage to keep pace with a 20% annual increase in vehicles on the road in 2011, rising to 19,947 stations, according to NGV Global.

Countries that do not have an extensive fuel-distribution infrastructure are likely to fa-vour other alternative fuels, such as biofuel-powered and electric vehicles, says the IEA.

Another solution to the lack of refuelling in-frastructure would be to encourage the use of vehicles that also have a reserve tank of gasoline, which can be used if the natural gas runs out. In Latin America, almost 90% of NGVs have bi-fuel engines, capable of oper-ating either on gasoline or CNG. In addition, tri-fuel vehicles entered the market in 2005 in

Clean Energy, North America’s largest provider of natural gas for transportation, is building what it calls America’s Natural Gas Highway

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4.3 – CNG

Brazil and combine a flex-fuel vehicle – ca-pable of using either gasoline and ethanol, or both blended together – and CNG.

Green gasNGVs have another advantage: they can

run on biomethane, which is produced by eliminating contaminants from biogas (it-self produced by fermenting renewable bi-omass – see p69). Biomethane is, in practi-cal terms, the same as the natural gas that enters the grid and can be turned into CNG and LNG for use as an automotive fuel. But the big difference is that biomethane is po-tentially carbon neutral. So the expansion of the NGV fleet today may eventually achieve far greater environmental and energy-sup-ply benefits than can be attained using gas produced from fossil fuels.

Which vehicles can use natural gas?Natural gas is a versatile alternative fuel. It

can be used in spark-ignited or compression engines in a range of vehicles, from the small-est motorbike to the largest rail locomotives.

But gas is better suited to some vehicle types than others. Motorcycles have lim-ited storage space for fuel, for example, so they aren’t the best vehicles for gas, which need bigger tanks than gasoline or die-sel cars. Three-wheeler NGVs, however – such as Thailand’s Tuk-Tuks – are com-mon in Asia.

Cars that do high mileage, such as taxis, are ideal natural gas users, whereas low-mileage privately owned vehicles take longer to recoup the cost of conversion. Vans and trucks are also suitable for CNG, because of their high mileage and because they usually have plenty of space for fuel storage.

Urban buses – usually running on CNG, but sometimes on LNG – are one of the main users of natural gas as a transport fuel. Routes and mileage are fixed and buses op-erate locally, so refuelling is easy to plan.

Industrial vehicles, such as fork-lift trucks, are another good market for gas because

they never stray far from a refuelling point and can reduce pollution in the workplace.

Meanwhile, Peru, India and Sweden are using gas to power trains (Sweden is mak-ing use of renewable biomethane for this purpose). Boats such as ferries are suita-ble for gas use and gas may eventually be-come a mainstream fuel for the airline in-dustry – Boeing is studying the prospects for aircraft powered by liquefied natural gas and thinks these may be in use by around 2045 (see p128).

Refuelling a gas-powered car is simple (assuming you can find a natural gas sta-tion). NGVs are refuelled in a similar way to gasoline or diesel vehicles and the process usually takes about the same amount of time (although won’t get any natural gas on your shoes). This can be done in public filling sta-tions, depots and – increasingly – at home.

NGV Global says gas is one of the saf-est transport fuels available. Gas requires a concentration of 5-15% in air for combustion conditions to occur. In a CNG vehicle, the gas is stored under high pressure, so in the event of a leak, it escapes rapidly, tending to lead to high, non-combustible concentrations of gas near the leak. In addition, being lighter than air, it tends to dissipate quickly, reducing the chances of accidental ignition. v

Urban buses are one of the main users of natural gas as a transport fuel

Natural gas: special reportThe natural gas value chain 80What is natural gas? 82Measuring natural gas 88Liquefied natural gas: Chilled energy 91Uses of gas: Bridge to a low-carbon future 97 World natural gas reserves 100Getting gas to market 103Methane hydrates: Ice on fire 111





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1 Gas discovery 2 Extraction 3 Oil (if associated) 4 Gas processing 5 Pipeline 6 Liquefaction 7 LNG shipping 8 LNG receiving and storage 9 LNG truck 10 LNG storage 11 Vaporization 12 Local distribution 13 Underground storage 14 Residential (heating and

cooking) 15 Commercial (heating and cooling) 16 Vehicles 17 Industry 18 Power 19 Natural gas liquids 20 Gas-to-liquids 21 Butane 22 Propane 23 Ethane 24 Petrochemicals 25 Refinery 26 Liquefied petroleum gas 27 Diesel 28 Jet fuel

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Downstream


5.1 – What is natural gas?

What is natural gas?Natural gas is a familiar and vital energy resource. But the story of how it is formed and how it is extracted from the ground is anything but commonplace

Natural gas is a fossil fuel and originates from plant, algal or other organic re-

mains that accumulate and are preserved in anoxic – oxygen starved – sediments.

Anoxic conditions were widespread at times in the oceans and led to extensive gas and oil deposits forming, for instance during the Lower Jurassic – around 190

million years ago. But they have also oc-curred on land, as in the formation of vast coal deposits in the Upper Carboniferous – around 300 million years ago. When bur-ied, these organic-rich sediments – the or-ganic matter is now called kerogen (de-rived from the Greek for wax producer) – may go on to become source rocks for oil and gas. As little as 0.5% kerogen in a rock can lead to it becoming a source rock, but the best source rocks contain 5% kerogen or more.

What’s cooking in the kitchen?Kerogen must be chemically altered –

cooked or matured – to be transformed into a fossil fuel. Often this is described as hap-pening in a source-rock kitchen. Three in-gredients go into the recipe for cooking a fossil fuel in a kitchen.

Natural gas consists mainly of …

But contains other hydrocarbons, such as …

C2H6: Ethane C3H8: Propane C4H10: Butane C5H12: Pentane

CH4: Methane

GraduatesWhen it comes to the Gazprom Marketing & Trading business, there’s a lot waiting to be discovered. Rather than go into too much detail about our exciting graduate career opportunities here though, we’d like to point you towards our website. Once you’re there, you’ll be able to learn how we take a different approach to assessment, hear from some of our current graduates, and take a tour around our amazing new offices.

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The Energy to Succeed



First, the type of kerogen affects the type of fossil fuel produced: natural gas can form from the remains of algae or marine organisms (Type I or II kerogen) or from land plants (Type III kerogen) preserved in coal deposits.

Second, to make natural gas, kerogen generally needs to be heated to over 100°C – typically 150°C or more. This is consider-ably higher than the temperatures needed to generate oil. Temperature increases with depth below the Earth's surface, so natu-ral gas source rocks need to buried at great depths – perhaps 3 kilometres or more.

Third, once heated, tens of millions of years need to go by for enough kerogen to be cooked into gas to make a significant natural gas reserve. Once gas has formed, it often migrates laterally and vertically away

from its source rock, through spaces be-tween grains of sediment or along fractures. It may then become trapped in a reservoir rock – such as a porous limestone or sand-

stone – below an impermeable cap or seal rock, such as clay or salt.

Physically, getting natural gas out of the ground is expensive and the skill of the ex-ploration geologist is important in finding plays where the source-reservoir/seal re-lationship is likely to exist. A model-based

Methane burns very easily and releases large amounts of heat

Once heated, tens of millions of years need to go by for enough kerogen to be cooked into gas to make a significant reserve



sequence stratigraphy approach is often used, which considers large-scale geolog-ical events and global sea-level changes to identify play fairways – areas where natu-

ral gas finds are likely. Once discovered, and after the rock formation containing gas is shown to be economically viable, it can be exploited.

Wells are drilled, cased – to prevent nat-ural gas escaping until reaching the surface

– and a wellhead is fitted to prevent the gas, which is under high pressure, from leaking or explosively blowing-out at the surface. The formation can be penetrated by sev-eral wells at once, drilled at various angles if necessary, to drain it efficiently. The pres-sure that natural gas is under provides the means of driving it the surface.

Gas brought to the surface in the way just described is referred to as conven-tional gas, but some reservoirs require an alternative approach to exploit them. Gas produced in these other ways is called un-conventional gas, and is becoming increas-ingly important. Some reservoirs are tight, meaning that the rock is relatively imper-meable and inhibits natural gas from flow-ing through it. Production from tight rocks

Its advocates say natural gas can act as a bridge between today’s carbon-intensive economy and future low- or zero-carbon economies. The Brigg power station, England

© Centrica

The formation can be penetrated by several wells at once, drilled at various angles if necessary, to drain it efficiently



may be increased by pumping from the sur-face or, if the reservoir is limestone, by in-jecting acids partially to dissolve the rock. Another approach, hydraulic fracturing (fracking), stimulates flow by injecting wa-ter at high pressure into the rock, causing it to fracture, and creating spaces through which gas can move. The addition of small amounts of sand or other ingredients (prop-

pants) serve to keep fractures open. This technique can allow previously une-

conomic reservoirs to become productive. And gas-rich shale rocks that have low per-meabilities can now be produced econom-ically because of fracking. Indeed, fracking has become such a successful production method that shale gas has become a glo-bally important, market-changing source of natural gas.

A further unconventional source of natural gas is coalbed methane (CBM). Most coal contains large amounts of methane-rich gas within its fine internal structure. But this gas is trapped by water pressure within the coal seam. Pumping water out of coal deposits allows methane to become mobile and flow to the surface.

Mostly methaneAs it comes out of the ground, natural

gas is mostly methane (CH4) – between 70% and 90% – but with various other hy-drocarbons, such as ethane (C2H6), pro-pane (C3H8), butane (C4H10) and pen-tane (C5H12), present in relatively small amounts. Gas rich in methane is referred to as dry or lean, and termed wet if other hydrocarbons are present. Other impuri-ties, such as carbon dioxide (CO2), helium, nitrogen, hydrogen sulphide (H2S) and wa-

ter vapour can also be found, but gener-ally at low levels. Much of the non-meth-ane component of natural gas is removed through processing.

Methane burns very easily and releases large amounts of heat:

CH4 + 2O2 → CO2 + 2H2O + ENERGY!

It is this locked-up energy that makes nat-ural gas such a valuable resource. Although methane can be used as a fuel for vehicles, or to produce fertilizer, it is the energy sec-tor that draws most on natural gas, with two thirds of global gas supply generating heat and electricity for homes and industry. The only chemical products of combustion are CO2 and water (see equation); gas has none of the harmful pollutants, such as sulphur di-oxide or soot, associated with the chemi-cally more complex and impure fossil fuels oil and coal.

But it does release CO2, a primary contrib-utor to global warming. For every kilogram of methane burned, 2.75 kilograms of CO2 are released. But generating the same amount of energy from oil produces about 50% more, and coal around 100% more CO2.

The energy content of natural gas is not a constant value. It depends on how much methane and other hydrocarbons are present in the flow – the gas stream. Composition fundamentally varies be-tween gas fields, but end consumers also receive a gas stream that can subtly change over time.

The energy content of a particular stream of natural gas is given by calculating its calorific value (CV). This takes the chemi-cal composition of the stream into account and gives the amount of energy per unit vol-ume of the stream – in megajoules per cubic metre, for instance – under specified con-ditions. Knowledge of the CV of gas is an essential part of the day-to-day activities of suppliers because it determines the amount of energy being transported.

Most coal contains large amounts of methane-rich gas within its fine internal structure



CV information is: provided daily to gas ship-pers and suppliers; used to bill consumers; and to calculate transportation charges for ship-pers. Typical values for the UK gas network

range from 37.5 to 43.0 megajoules per cubic metre. Measuring the CV of natural gas is es-sential to determining the price of the product and in managing energy supply and demand.v

Transforming societies into ones that use energy sustainably is one of the biggest problems policymakers will face over the coming years.

Energy companies, politicians and regu-lators generally view natural gas as a path-way to a low-carbon energy future. Gas pro-duces the least carbon dioxide (CO2) of all the fossil fuels when burned – around 40% less than coal and 20% less than oil. Also, modern combined-cycle gas-turbine power plants have better thermal efficiencies – how well energy from fuel is converted into useful output – than coal-fired stations.

According to the International Energy Agency’s (IEA) World Energy Outlook 2012, global demand for electricity will increase by 70% between 2010 and 2035. But a greater reliance on gas instead of coal for power generation could mean that this only results in a 20% increase in CO2 emissions.

The overall vision is that natural gas acts as a bridge between today’s car-bon-intensive economy and future low- or zero-carbon economies. Gas provides a lower-carbon way of generating continu-ous – baseload – electricity, while supply-ing back-up for renewable energy sources until more are developed and introduced. It also presents a lower-carbon route for de-veloping countries to achieve higher stand-ards of living, eventually deploying renewa-bles when they can be afforded. It is impor-tant that the switch to gas happens soon, however, as acting early on lowering green-house-gas (GHG) emissions is likely to have a greater impact on stabilising them over the long term.

For developed countries, natural gas can be a low-carbon godsend. The 2011 Fukushima nuclear meltdown led to a large

scaling-back of nuclear power in Japan and in other countries, such as Germany. These states are likely to be more reli-ant on gas in future. In the US, the re-cent boom in unconventional gas produc-tion has helped a switch from coal to gas. Along with an increase in renewables this led to a 7% drop in CO2 emissions between 2006 and 2010.

Critics of the green view of natural gas worry that it might restrict the growth of re-newables. Gas generally remains readily available and affordable, especially when compared with oil products – and this may deter investment in more expensive renew-able-energy sources. But many companies are preparing for a future where carbon pric-ing – present in the EU, Australia and New Zealand – is a fact of life.

Another concern is GHG-emissions tar-gets: gas produces less CO2 than other fos-sil fuels, but it still puts GHGs into the air. Allowing average global temperatures to in-crease beyond 2°C above the pre-industrial level is not considered safe. It is estimated that to keep the rise in temperature at a safe level, the concentration of GHGs in the at-mosphere must be limited to 450 parts per million (ppm) of CO2 equivalent.

But the IEA says growing demand for fos-sil fuels, including natural gas, might push this figure to 650 ppm, which it says would be consistent with an eventual rise in the av-erage global temperature of 3.5°C.

Great efforts will be required to introduce renewables, improve energy efficiency and perfect new technologies, such as carbon capture and storage, to bring man-made cli-mate change under control. Increasing nat-ural gas usage in the medium term may just buy the time for that to happen. v

Natural gas, climate change and sustainability

Measuring natural gas

Natural gas conversion factorsTo convertNatural gas and LNG To Billion cubic Billion cubic Million tonnes Million tonnes Trillion British Million barrels metres NG feet NG oil equivalent LNG thermal units oil equivalentFrom Multiply by1 billion cubic metres NG 1 35.3 0.9 0.73 36 6.291 billion cubic feet NG 0.028 1 0.026 0.021 1.03 0.181 million tonnes oil equivalent 1.111 39.2 1 0.805 40.4 7.331 million tonnes LNG 1.38 48.7 1.23 1 52 8.681 trillion British thermal units 0.028 0.98 0.025 0.02 1 0.171 million barrels oil equivalent 0.16 5.61 0.14 0.12 5.8 1

Source – BP

Natural gas is usually measured by volume or energy content.

At the production end of the gas chain, volume is generally used – stated in cubic metres or (in North America) cubic feet. These measurements make standard assumptions about the pressure and temperature of the gas. There are 35.31 cubic feet in a cubic metre. One cubic foot is about 0.028 cubic metres.

Given the large volumes of gas that flow out of wells or are produced by companies and countries or used by populations, produced and consumed volumes are usually measured in the thousands, millions, billions and even trillions.

World consumption, for example, amounted to just over 3.2 trillion cubic metres in 2010, according to Cedigaz.

If you want to talk American, an average US home uses about 1,000 cubic feet of gas every four days for warming up water, heating rooms and cooking. That means 1 billion cubic feet of natural gas is enough to meet the needs of 10,000-11,000 US homes for a year.

At the consumption end of the chain, gas is frequently also measured by energy content, often British thermal units (Btus). A Btu is the amount of heat required to raise the temperature of a pound of water (roughly half a litre) by 1°F. It is equivalent to around 1,055 joules or 252 heat calories. Burning a matchstick produces about 1 Btu of heat. A therm is another common unit of heat, equal to 100,000 Btu and equivalent to about 100 cubic feet of gas.

A cubic foot of natural gas contains about 1,000 Btus of heat energy, so 1 million Btus is about the same as 1,000 cubic feet. However, the energy content of natural gas varies, depending on the gas field, and calculating energy content must take account of this.

Gas is also frequently described in terms of barrels or tonnes of oil equivalent. A barrel or tonne of oil equivalent is the amount of gas that would produce the same energy when burned as one barrel or one tonne of crude oil. A barrel contains about 5.8 million Btus and is generally deemed to have the same energy content as about 6,000 cubic feet of natural gas.

Mass is also used to measure gas. In the case of liquefied natural gas (LNG), it is common to talk in terms of tonnes and tonnes produced in a year. The world has just over 280 million tonnes a year of gas-liquefaction capacity. LNG production units – of which there are about 100 in use around the world – produce anything from a few hundred thousand tonnes of LNG a year to around 8 million tonnes a year. The average per train is about 3 million tonnes a year.

LNG ship sizes, however, are specified in cargo volume, usually in thousands of cubic metres.


Industry facts


Industry facts

The Ob River follows ice breakers through the Northern Sea Route

LNG via the Arctic: breaking ice and a recordIn December, the Ob River liquefied natural gas (LNG) carrier became the first LNG ship to deliver a cargo via the Northern Sea Route – a shipping lane from the Atlantic Ocean to the Pacific Ocean, along Siberia’s north coast. Mostly in Arctic waters, the route cuts the maritime distance from northern Europe to northeast Asia by up to 40% compared with southern sea routes via the Suez or Panama canals. As a result, it is a significant step in demonstrating the safe and commercial usage of this new maritime route, says Gazprom Marketing & Trading, which chartered the vessel.The Ob River sailed from Norway’s Snøhvit LNG terminal on 7 November and discharged its cargo at Japan’s Tobata LNG regasification terminal a month later. It spent 10 days in the Northern Sea Route, escorted by Russian nuclear icebreakers.

© Dynagas Ltd© Dynagas Ltd


Industry facts


5.2 – LNG

Chilled energyLNG is providing gas consumers with a good alternative to pipeline supply

Gas can be transported for thousands of miles by pipeline, but there are

limits. To deliver it from Qatar to northern Europe, say, or from Australia to virtually anywhere, pipelines just aren't practical. So, as demand for the cleanest fossil fuel soars, gas traders are turning to a more flexible alternative that can take their prod-uct anywhere in the world – chilling it into liquefied natural gas (LNG) and transport-ing it by tanker.

Once the LNG is on the water, it can be delivered anywhere that has a receiving ter-minal, where it can be regasified – and there are an increasing number of those around the

world to which LNG producers can export. The LNG revolution means developers

can commercialize gas resources that are too far away from markets to be carried to customers through pipelines.

Over the next decade and a half, LNG will be the second-fastest-growing segment of the world gas market after unconventional gas. Wood Mackenzie, a consultancy, fore-casts that LNG demand will rise by 4.8% a year between now and 2025 – much more quickly than the International Energy Agency’s projection for annual growth in the overall gas market of 1-2% over a similar pe-riod. Asia is set to account for around three-quarters of the growth, with most of the re-mainder expected to come from Europe.

Yet, despite the acceleration in consump-tion, LNG’s portion of supply is still dwarfed by that of piped gas. In 2011, LNG accounted for around a tenth of global gas supply and around a third of international gas trade. By 2030, it will still only account for around 15% of gas supply, according to BP.

Price $$$; size XLLNG has a relatively modest share of glo-

bal gas supply, in part because LNG projects are complex and expensive. Export facilities and the associated infrastructure that is nec-essary – a fleet of special tankers and, at the market end, regasification terminals to turn the LNG back into natural gas – are among the costliest engineering projects in the world.

Gorgon, a Chevron-led venture in Western Australia with a design capacity of 15 million tonnes a year, could end up costing $50 bil-lion by the time it comes on stream in 2015. That is a similar amount to the annual gross domestic product of Serbia or Uruguay.

To make an investment of that magnitude, the sponsors of LNG projects – energy com-panies, governments, banks and other lend-ing institutions – must be convinced that there will be a market for their product after the construction phase (which usually lasts about four years). As a result, before a final investment decision is taken, they need to pre-sell most of their planned output.

But that signals an important shift in the LNG market. Until recently, sellers generally needed to sell virtually all of their planned output before investing. And almost all LNG trade used to happen under long-term con-tracts, often lasting 20 years, between two counterparties. Tankers operated as a vir-tual pipeline, shuttling between a fixed pro-duction point and a fixed receiving point.

But, as the number of liquefaction plants, receiving terminals and LNG ships has grown, the market has acquired greater li-quidity. Buyers are confident enough in the demand outlook to feel comfortable about in-vesting in some liquefaction capacity without

Many of the technological leaps have occurred in Qatar, which has made the most eye-catching additions to global LNG supply


5.2 – LNG

signing up long-term contracts first. That suits many sellers, who don’t always want to be locked in to supply contracts lasting decades.

The most successful LNG suppliers are likely to be those that are prepared to trade on more flexible terms, says Frank

Harris, head of LNG Consulting at Wood Mackenzie. “Buyers are less certain about how much LNG they want, when and under what pricing basis,” he says. “Sellers that can offer flexible arrangements will have a competitive advantage.”

France’s Total, for example, has built up an adaptable supply system. It has stakes in liq-uefaction projects in the Middle East and west Africa, serving clients in Asia and Europe, and other Atlantic-basin markets. Backed by a flexible shipping fleet, its LNG-trading de-partment blends long-term trade with deals on the short-term and spot-trading markets

(which includes buying and selling cargoes not produced by Total’s own projects). Long-term contracts give the company visibility of earnings and the confidence to invest in in-frastructure; a presence on the spot market allows it to send uncommitted LNG to the highest-paying buyer at any given time.

The sellersThe global LNG-supply base is changing,

too. This is partly because of technological advances: the latest LNG trains – produc-tion units within an LNG plant – are nearly 30 times the size of the first ones, con-structed in the 1960s in Algeria (see p126). LNG ship size is also increasing, generating additional economies of scale.

Many of the technological leaps have oc-curred in Qatar, which has made the most eye-catching additions to global LNG sup-ply, rapidly building its capacity to a world-leading 77.1 million tonnes a year.

But Qatar may soon be overtaken by Australia, which will account for most of the growth in supply in the next five years (see p95). And numerous other nations are set to emerge as important LNG suppliers, in-

None of this comes cheap (LNG storage at Atlantic LNG in Trinidad and Tobago)

© BP

Asia remains the bedrock of the LNG business, as the relatively high price of gas there indicates


5.2 – LNG

cluding Mozambique and Tanzania, in east Africa, and the US.

At present, global gas-liquefaction ca-pacity amounts to just under 290 million tonnes a year (see Tables 1 and 2 p95), about a third more than six years ago, when – according to the IEA – it was 208 million tonnes a year. A similar growth rate should be sustained over the next five years; by 2017, facilities under construction will boost nameplate production capacity (the maxi-mum theoretical capacity specified by the manufacturer, which can’t be sustained un-der normal operational conditions and so is higher than physical output) by almost a third, to 376 million tonnes a year, according to a survey of liquefaction terminals carried out by Energy Future in 2012.

The buyersOn the market side, meanwhile, LNG

is changing from being from a niche com-modity to a global one. Receiving terminals have proliferated and LNG-import capac-

ity comfortably exceeds liquefaction capac-ity, creating abundant market opportunities for suppliers. Global regasification capac-ity should reach around 700 million tonnes a year by 2016, up from around 608 million tonnes a year at the end of 2011, according to the International Gas Union.

Asia remains the bedrock of the LNG busi-ness, as the relatively high price of gas there indicates: LNG seems likely to trade around $15 per million Btu over the next few years in Asia, compared with probable medium-term price averages for Europe and the US of $10 and $5 respectively. BP predicts Asian LNG demand will grow around twice as fast as the global average between now and 2030.

Consumption in Asia has risen recently be-cause of the accident at Japan’s Fukushima

The latest LNG trains are nearly 30 times the size of the first ones

Pluto LNG, the latest addition to Australia’s growing inventory of LNG plants

© Woodside Energy


5.2 – LNG

nuclear plant in March 2011; the disaster resulted in the precautionary shut-down of other Japanese nuclear plants, generating extra gas demand for power generation.

According to Cedigaz, LNG demand was 10% higher in 2011 than in 2010 – a very large increase over just one year and a spec-tacular recovery from the demand slow-down that occurred towards the end of the past decade because of the global recession.

That strong demand from Asia contin-ued in 2012. Japan and South Korea remain the world’s biggest consumers of LNG, but new buyers – in China, Thailand, Indonesia, Malaysia and Vietnam, for example – are add-ing to competition for supply. Interest in LNG is growing outside Asia, too, partly through growth in existing markets – mainly in Europe – but also from new buyers in countries such as Dubai, Kuwait and Argentina.

Fukushima has had a knock-on effect on LNG demand in Europe as well as in Asia. It has prompted Germany, for exam-ple, to decide to phase out nuclear power by 2022. Renewable energy, in which Germany is a world leader, will play an im-portant role in filling the gap left by carbon-free nuclear power; but extra gas will also be needed, because of its ability to gener-ate large amounts of energy reliably with-out pumping too much carbon dioxide into the atmosphere. If other countries follow Germany’s lead, researchers will be scur-rying back to their calculators to upgrade gas-growth forecasts.

The US: from buyer to sellerAnother recent – and significant – shift in

global LNG trading patterns has been the transformation of the US from LNG buyer to seller. A few years ago, the country was frantically planning and building import ter-minals in anticipation of a domestic gas shortage. But recent exploration and pro-duction successes in the country’s now pro-lific shale-gas deposits have transformed the domestic gas-supply outlook.

The unexpected excess of gas this has created means the US is preparing to build export projects instead. Around the end of 2012, the US Department of Energy was re-viewing at least 15 applications from compa-nies seeking to build gas export terminals.

Exporting gas makes particular sense for US producers. There is so much of it that gas prices have fallen to extremely low lev-els and much more money can be made by selling to high-paying Asian buyers. Markets such as Japan are accessible from the US’ west coast.

BG Group estimates that if all projects for which applications have been made were built it would enable the US to export around 150 million tonnes of LNG a year, compared with its existing capacity of just 1.5 million tonnes, from ConocoPhillips’s small Kenai plant in Alaska.

However, it is unlikely that that much ca-pacity will be built in the near future. One reason for this is politics: rapid growth in LNG exports from the US would cause do-mestic natural gas prices to rise. At present, they are much lower than in Asia and Europe and therefore immensely popular with US citizens and businesses (see Figure 1 p96).

So far, Cheniere’s Sabine Pass project is the only venture to have received approval to ship LNG to countries not covered by free-trade agreements with the US, which include important LNG destinations such as China and Japan.

BG’s chief operating officer, Martin Houston, thinks around 45 million tonnes of capacity – still a sizeable amount – might be built in the US by the end of this decade.

Another recent – and significant – shift in global LNG trading patterns has been the transformation of the US from LNG buyer to seller


5.2 – LNG

Led by Australia and Qatar, world LNG-production capacity is set to increase rapidlyAustralia is set to overtake Qatar as the world’s biggest liquefied natural gas (LNG) producer by 2017. However, Qatar is, for now, comfortably the leader, with 77 million tonnes a year of capacity and 14 trains (LNG production units). That is around 27% of world output capacity, according to a survey of liquefaction plants carried out by Energy Future (see Table 1).

Second-placed Indonesia has just over half of Qatar’s total, with 40.1 million tonnes. Worldwide, there are 100 LNG trains in op-eration, in 19 countries.

At present, Australia is in third place, with 24.1 million tonnes a year of capacity, pro-duced from seven trains, placing it be-hind Qatar and Indonesia, and just ahead of Malaysia, Nigeria and Algeria. But an addi-tional 13 trains and one floating LNG (FLNG) plant are under construction, which will add 61 million tonnes a year to Australian capac-ity over the next five years, bringing the coun-try’s total to around 85 million tonnes a year.

And Australia might not stop there. Another 50 million tonnes a year of capacity is un-der consideration – an extra 11 trains and two more FLNG plants. If all of these projects were to be built (which is far from certain) Australia’s LNG capacity would eventually rise to about 136 million tonnes a year – al-most a sevenfold increase from today’s total.

World capacity, meanwhile, is set to ex-pand by a third over the next five years, ris-ing from 287.5 million tonnes a year in 2013, to 376.1 million tonnes a year by 2017 (see Table 2). Australia will account for about two-thirds of the additions – most of the ex-tra capacity coming on stream in 2015 and 2016. The remainder of the capacity that is already in the construction phase is in Algeria, Angola, Canada, Indonesia and Papua New Guinea.

Who’s who in LNGTable 1: World LNG-export capacity

Source – Companies; Energy Future

million tonnes a year Qatar 77.1 Indonesia 40.1 Australia 24.1 Malaysia 22.7 Nigeria 21.2 Algeria 20.4 Trinidad & Tobago 14.8 Egypt 12.7 Oman 10.3 Russia 9.6 Brunei 7.2 Yemen 6.7 UAE 5.2 Norway 4.6 Peru 4.5 Equatorial Guinea 3.4 US 1.5 China 0.8 Libya 0.7 Total 287.5 Note: data researched by EnergyFuture 2012/13

Table 2: LNG capacity: operating, under construction and plannedOperating 287.5Under construction* 88.5Medium-term prospects (2012 to 2017) 118.7Long-term prospects (2017+) 122Floating LNG 10.5

Source – Companies, Energy Future.* Includes confirmed FLNG projects


5.2 – LNG

That would come from four projects – Lake Charles and Cameron in Louisiana, and Sabine Pass and Freeport in Texas.

Although global LNG-trading activity is on the rise, there are still a few hitches in the supply chain that must be smoothed out. For instance, charter rates for the world’s 370 or so LNG tankers have shot up recently be-cause of the gas-demand growth gener-

ated by Fukushima, which has stretched the transportation segment of the LNG industry. Also, some ports in Asia are too small to ac-commodate Qatar’s new breed of LNG su-per-tanker, the Q Max.

But these bottlenecks are being tackled. Port facilities are being upgraded and new LNG tankers are on order. For LNG – over the long term – the only way is up. v

At least six new countries are likely to join the ranks of the world’s LNG exporters over the next few years – Angola, Canada, Papua New Guinea, Cameroon, Mozambique and Tanzania – which would bring the number of LNG producer countries to 25.

Worldwide, if all the projects that have been proposed were to be built, global LNG-

production capacity would – in theory – rise to well over 600 million tonnes a year, but that will not happen for a long time. Wood Mackenzie, a consultancy, estimates de-mand for LNG in 2020 will be just 357 million tonnes a year, giving an indication of prob-able limits to growth in production capacity over the decade. v

Figure 1. US natural gas prices: popular with consumersUS dollars per million Btu

Source: Heren Energy, BPNotes: Btu = British thermal units; the Japanese price is based on the cif (cost+insurance+freight) price of LNG imports. The UK and US prices are average national gas-hub prices, for the UK’s National Balancing Point and the US’ Henry Hub.

Japan UK US


5.3 – Uses of natural gas

Bridge to a low-carbon futureGas has lower carbon emissions than coal or oil and it’s plentiful, making it a good choice to meet our energy needs while renewable sources are developed

One day, the world may well be pow-ered mainly by renewable energy – but

that day is decades away. Until we have in-stalled sufficient renewables infrastructure, improved the technology and brought the cost down, fossil fuels will remain central to our energy needs.

And if you need to burn fossil fuels and want to limit carbon emissions, then the ob-vious choice is natural gas. Reserves are increasingly accessible and it’s the clean-est of the lot. Gas produces, for example, about 45% less carbon dioxide (CO2) during combustion than coal to produce the same amount of energy.

How is it used?Gross gas production in 2011 was 4.13

trillion cubic metres, but not all of that ended up on world markets.

Around a fifth was used in other ways, in-cluding reinjection into underground depos-its and flaring, according to Cedigaz, an in-dustry body that generates data on gas.

The rest can be used in a variety of ways: electricity generation, transportation, heat-ing, lighting and cooking. Gas also powers factories and is used as a building block for generating a wide range of familiar, every-day products, from plastics and fertilizer to anti-freeze and fabrics. It can also be used to make hydrogen for use in fuel cells.

In addition, it works well alongside renew-ables. In electricity plants, gas is a load-fol-lowing resource: the output of gas-fired tur-bines can be rapidly adjusted upwards and downwards in response to swings in elec-tricity demand, which can change over a matter of minutes.

That means gas can serve as a flexible partner to power supplied from intermittent renewable technologies, such as wind and solar. Wind, for instance, typically has a low-capacity factor. The portion of a typical tur-bine’s capacity used over a given period is usually 20-40%. This means that for much of the time, when wind conditions aren’t op-timal, it is either not turning at all, or working below capacity.

Gas-fired power plants can fill this gap because their output can be ramped up quickly. And when the wind turbines are spinning again, the gas plant’s output can be reduced.

Coal-fired power stations are also flexi-ble, although it takes longer to adjust their output and their CO2 emissions are much higher. Nuclear power plants, another base-load electricity source – meaning they are capable of meeting most of the demands of a consumer market – can’t respond to rapid changes in the amount of electricity needed by the grid.

Gas is also abundant, readily available and can be supplied at a competitive cost. And, compared with other large power sta-tions, gas-fired plants are often relatively cheap and quick to build.

For these reasons, and others, gas will re-main an important part of the energy mix. It is the only fossil fuel for which demand

Gas can serve as a flexible partner to power supplied from intermittent renewable technologies



rises in all three of the International Energy Agency’s (IEA) long-term projections, or scenarios, of how energy demand might evolve in the coming decades.

Whatever policies are put in place, for now, the world relies on natural gas for over a fifth of its primary energy and gas should retain that share of an expanding energy mix over the next few decades, or even in-crease it slightly.

Gas to power

When people think of natural gas, they often think first about its use as a cooking fuel. But what has really driven the sector’s growth in recent years has been its use in electric-ity generation. And that’s likely to remain the case: according to the IEA’s New Policies Scenario, the power sector will account for the biggest additions to gas demand.

Gas may generate electricity in a steam, or gas turbine. In a steam-generation unit,

the gas is combusted in a boiler to heat wa-ter. The resulting steam then turns a turbine, which generates electricity. Gas-turbine en-gines, meanwhile, generate power by burn-ing the fuel in a combustion chamber and using the fast-flowing combustion gases to drive a turbine.

High efficiencies can be achieved by com-bining gas turbines with a steam turbine. In a combined-cycle gas-turbine (CCGT) plant, a gas-turbine generator produces electricity and the exhaust gases from the turbine gen-erate steam to produce additional electricity. The efficiency of modern CCGT power sta-tions can be more than 50%.

CCGT power plants are a cost-effective option for electricity generation in many countries; they are relatively cheap to build and construction times are generally shorter than for coal and nuclear plants.

In addition, although gas-fired power sta-tions produce CO2 emissions and will prob-ably eventually need to be combined with

Gas turbines

© Siemens



carbon capture and storage technology, their carbon impact is much lower than that of other fossil-fuel power plants. Emissions from gas-fired power plants built using the best available technology contain about 50% less CO2 and up to nine times less nitrogen oxide than emissions from coal-fired plants.

Gas for transportation

Globally, the use of natural gas in the road-transport sector remains negligible, although natural gas vehicle (NGV) technology has existed for several decades and is well es-tablished in some countries (see p75).

There are good reasons to use more gas for transportation. NGVs have environmen-tal advantages over gasoline and diesel cars, emitting fewer noxious and toxic air pollutants, and generating much fewer CO2 emissions.

Gas is also generally cheaper than oil to consumers at present. This differential is likely to be maintained because govern-ments will tend to favour the use of cleaner gas over dirtier oil through, for example, higher taxes on oil products.

But despite gas’s considerable bene-fits, expanding the NGV fleet is difficult. Refuelling networks have a very limited

reach in most places, if they exist at all, and building them is expensive.

Households, offices, buildings

Assuming distribution infrastructure exists, natural gas is often the preferred fuel for space and water heating, mainly in residen-tial, commercial and public-sector buildings. The principal competitor to gas in this sector is light heating oil, which is generally more ex-pensive on a heating-value basis and involves higher installation and maintenance costs.

Gas-fired condensing boilers – which now account for most new sales in OECD coun-tries – are very thermally efficient, with an average efficiency of around 90% compared with around 70-80% for conventional gas boilers or those running on heating oil.

Gas is also an effective cooking fuel: the heat can be rapidly adjusted, whereas elec-tric hobs are not as responsive.

Industry

Gas is used by industry mainly for produc-ing steam for mechanical energy and proc-ess heat, but there are many other uses for it, including lighting and cooling.

There are good reasons to use more gas for transportation

Gas is often the preferred fuel for space and water heating


Gas reserves, production and consumption


Gas reserves, production and consumption

30.00+ 20.00 to 29.99

3.00 to 19.99 1.00 to 2.99

0.01 to 0.99 Negligible

Notes: Proved reserves of conventional gas-generally taken to be those quantities that geological and engineering information indicates with reasonable certainty can be recovered in the future from known deposits under existing economic and operating conditions.

World natural gas reserves, 2011Source: BP Statistical Review of World Energy 2012

North America 10.8 trillion cubic metres World total

World reserves: 208.4 trillion cubic metresWorld gas production: 3.3 trillion cubic metresReserves-to-production ratio: 63.6 years

S. & C. America 7.6 trillion cubic metres

Africa 14.5 trillioncubic metres

Middle East 80.0 trillion cubic metres

Asia-Paci�c 16.8 trillion cubic metres

Europe & Eurasia 78.7 trillion cubic metres

LegendGas reserves (Trillion cubic metres)

Top 10 producers, 2011Country billion cubic metres 1. US 651.32. Russian Federation 607.03. Canada 160.54. Iran 151.85. Qatar 146.86. China 102.57. Norway 101.48. Saudi Arabia 99.29. Algeria 78.0

10. Indonesia 75.6

Top 10 consumers, 2011Country billion cubic metres 1. US 690.12. Russian Federation 424.63. Iran 153.34. China 130.75. Japan 105.56. Canada 104.87. Saudi Arabia 99.28. United Kingdom 80.29. Germany 72.5

10. Italy 71.3

Saudi Arabia

UAE

Oman

Yemen

Qatar

Kuwait

IranIraq

Red Sea

Persian Gulf



Gas is also used for waste treatment and incineration; preheating metals such as iron and steel (although coking coal remains the most widely utilised fuel for steel pro-duction); drying and dehumidification; glass melting; food processing; and fuelling indus-trial boilers. The biggest gas-consuming in-dustrial sector is chemicals (not including gas’s role as a feedstock in the petrochem-icals industry).

In industry, gas competes with coal, oil products and electricity, so the prevailing price of these various energy sources often determines which fuel is used. Gas prices often track oil prices, so gas generally re-mains competitive with oil once it is estab-lished as an industrial fuel. Relative to coal

in industry, in most countries, more stringent air-pollution regulations are likely to favour the use of gas.

Chemicals

Natural gas is made up of several compo-nents. Gases such as ethane, propane and butane may be extracted from natural gas and converted into ethylene and propylene, which in turn can be converted into a variety of familiar materials. These include polyeth-ylene, plastics, resins, paints, anti-freeze, packaging materials, textile fibres and other specialty foams and plastics. Many automo-bile parts and components are made from these products.

Natural gas may also be used to produce methanol, a chemical that may be used to produce fuel additives, formaldehyde, ace-tic acid, plastics, vinyl, textiles, and various other products. Methanol can also be con-verted into both ethylene and propylene. Gas is also used to manufacture ammonia, which can be used to produce urea/fertilis-ers, fibres and other products. v

Steel production: just one industrial use for gas

Emissions from gas plants built with the best available technology contain about 50% less CO2 and up to nine times less nitrogen oxide than from coal plants


5.4 – Gas transportation

Getting gas to marketWhat are the main steps in transporting natural gas from the wellhead to consumers?

Gas is much harder to handle than a liq-uid such as oil because … well … it’s

a gas. Costly infrastructure is needed to de-liver it to market.

First, it must be cleaned up. The gas that comes out of the ground is mainly methane, but it’s not quite the same as the stuff that burns on your hob, or fires the condensing boiler in the cellar.

It contains other components, such as ethane, propane, butane and pentane, which are separated for direct sale as a feedstock for the industrial and petrochem-icals markets.

Raw – unprocessed – gas also contains water vapour, hydrogen sulphide (H2S), car-bon dioxide (CO2), helium, nitrogen and other compounds. CO2 and H2S are both highly cor-rosive, so they must generally be removed before the gas can be transported.

After being collected at the field, gas is sent through a gathering system, a network of low-pressure, small-diameter pipelines, to a processing plant, where impurities are removed – producing pipeline-quality, dry natural gas.

After this, there are two main ways of transporting gas: by pipeline and on liq-uefied natural gas (LNG) ships. Long-distance pipelines and LNG infrastructure are expensive and can usually be financed only when buyers sign up in advance to long-term purchase agreements, some-times lasting 20 years or more. However, the economics of these delivery methods vary considerably, depending on factors such as the size of the resource, its dis-

LNG storage at the UK’s Grain import terminal

© National Grid



tance from market and the terrain that must be covered to get it there.

There are other emerging ways of devel-oping gas resources, including compressed natural gas and gas-to-liquids technology, but these account for a negligible amount of overall gas supply.

Pipelines or LNG?

Most of the world’s gas goes through pipe-lines, which are the most efficient way of transporting gas onshore and are generally more suitable than LNG for short distances, even if part of the route crosses water.

According to Cedigaz, about two-thirds of the gas the world consumes is sold within the country of production and almost all of this is piped to market. The remaining third is traded internationally and most of this – around 70% – is pipeline gas. The remain-ing 30% is shipped as LNG.

Offshore pipelines cost several times more than onshore ones: especially over long dis-tances, if the water is particularly deep or the terrain of the seabed is difficult to lay a pipe-line on. LNG becomes an economically at-tractive alternative where the gas must move over large offshore distances – perhaps 2,000 kilometres and more.

But these are just rules of thumb. There are large amounts of stranded gas in Alaska, for example. And even though an export pipeline would be routed across land, the distances involved mean a pipeline to the US and Canada might cost as much as $40 billion. In this case, turning the gas into LNG, at or near the point of production, might make more economic sense.

Strategically, LNG is a compelling idea for gas-consuming nations that are heavily reli-ant on piped imports (Europe is one exam-ple: it receives about 80% of its gas imports through pipelines from Russia, Algeria and Norway). Pipelines start and end at fixed points, but LNG can be shipped from and to virtually anywhere. Building the infrastruc-

ture needed to accept LNG cargoes – re-ferred to as LNG-receiving or regasification terminals – provides gas consumers with access to a wider choice of suppliers. The ability to import LNG helps keep the price of piped gas in check.

Figure 1

The LNG process



Conversely, LNG also gives gas produc-ers a wider choice of consumer markets and the flexibility to send some volumes to the highest-paying market at any given time.

First used in 1959, when a cargo was shipped from the US to the UK, LNG tech-nology has enabled the commercialisation of many gas resources that couldn’t have been developed using pipelines.

The relatively isolated country of Papua New Guinea, for instance, has a tiny domes-tic gas market that alone couldn’t have war-ranted the large investments needed to ex-tract its gas resources. But the country is be-coming a big player in world gas supply be-cause of LNG, creating wealth and jobs: PNG LNG, operated by US company ExxonMobil, is scheduled to begin operating in 2014, with an initial capacity of 6.6 million tonnes a year – about the same as the annual gas con-sumption of Colombia or Vietnam.

Meanwhile, thanks to the development of floating LNG technology by Technip, Shell and others, even isolated pockets of gas miles from shore can be brought into play.

But LNG has disadvantages, too. LNG plants are expensive and time-consuming to

build. Large gas deposits are required. The developer also needs access to a port (al-though it is also possible to transport small volumes of LNG by road).

Building pipelines

Pipelines can be relatively cheap to build if the market is near the gas field, or if a dis-covery is made in an area with existing gas-transportation infrastructure.

But for remote discoveries, long-distance gas-transmission lines, called trunk-lines, are necessary. These typically have a diameter of somewhere between 40 and 120 centime-tres and operate at much higher pressures than gathering systems, or local distribution networks at the market end of the gas chain.

Compressor stations are usually installed at regular intervals along the length of the pipeline to maintain the pressure of the gas flowing through it. Higher pressures require larger, thicker pipe and more powerful com-pression equipment, all of which increases capital and operating costs.

Long-distance pipeline projects can be extremely ambitious. The Blue Stream pipe-

Most of the world’s internationally traded gas is shipped by pipeline



line, for example, transports Russian gas to Turkey, across the acidic waters of the Black Sea at depths down to 3,000 metres. The Bolivia-Brazil gas pipeline traverses 3,150 kilometres of South American territory.

Yet pipelines have their limitations. Nobody is proposing to build one from the Middle East to Japan: even if it were technically fea-sible, it would be prohibitively expensive.

As well as overcoming financial and en-gineering difficulties, pipeline developers routinely face numerous political, legal and commercial hurdles, requiring treaties and complex negotiations.

Sometimes – if the countries have politi-cal differences – negotiations may fail. The Iran-Pakistan-India (IPI) pipeline envisaged the supply of gas from Iran to Pakistan and beyond to India. But although proposals of one sort or another have been around since the 1950s, the pipeline hasn’t been built.

LNG: liquefaction

Where pipelines aren’t feasible for technical, political or economic reasons, gas may be converted to a liquid by cooling it to -161°C.

This process reduces the gas’s volume by a factor of more than 600 – similar to reducing the volume of a beach ball to the volume of a ping-pong ball – making it possible to transport extremely large volumes on a single vessel.

Prior to liquefaction (see Figure 1), gas is pre-treated to remove impurities such as water and sulphur compounds, which may damage the refrigeration equipment, or re-sult in poorer-quality LNG. The resulting dry, sweet gas is then cooled by refriger-ant streams, allowing heavier hydrocarbons to be separated using distillation. This pro-duces mainly methane, which is liquefied using a system of heat exchangers and re-frigerants, much like a giant refrigerator.

LNG: shipping

The LNG is pumped at atmospheric pressure to a jetty for loading onto an LNG ship, where it is placed in insulated tanks that maintain the gas in liquid form during the voyage.

Like gigantic floating Thermos flasks, these cryogenic ships typically have a ca-pacity of between about 130,000 cubic me-tres and 180,000 cubic metres. The big-

Hammerfest LNG plant, Melkøya, Norway – the world’s most northerly liquefaction terminal

© Harald Pettersen/Statoil



gest LNG ships on the water – Qatar’s new generation of LNG carrier, the Q-Max – can carry up to 260,000 cubic metres of gas and stretch almost 350 metres in length.

LNG: storage and regasification

When LNG arrives at a receiving or regasifi-cation terminal, it is first placed in large cry-ogenic storage tanks, where it is kept in liq-uid form before regasification.

The UK’s Dragon LNG, which imports LNG from Qatar through a port in Wales, stores LNG at just above atmospheric pressure in tanks with a capacity of around 160,000 cu-bic metres. Its heavily insulated tanks con-sist of an inner shell made of a special nickel alloy designed to resist the low temperature.

A concrete outer shell catches any leaks from the inner tank. Sophisticated automatic protection systems monitor the tank levels, pressures, temperatures and any potential leakage from the inner tank.

Regasification occurs by gradually warming the gas back up to a temperature of over 0°C. On its way out of the termi-nal, the gas undergoes any additional treat-ment processes needed to bring its specifi-cations in line with regulatory and end-user requirements. Its heating value, for exam-ple, may be adjusted by altering nitrogen, butane or propane content, or blending it with other gases.

Gas distribution and markets

After gas arrives at a market – on an LNG ship or through a pipeline – it is distributed to end users through a network of low-pres-sure, small-diameter gas pipelines. Markets for gas include: electricity generation; indus-trial use; transportation; and residential and commercial usage for space heating, cool-ing and cooking (see p97).

Other options: CNG and GTL

Compressed natural gas (CNG) is widely used already, as gas is usually transported in compressed form in pipelines. Also, most vehicles that run on gas store the fuel on board in a pressurized tank (see p75).

CNG can also be used to transport large volumes of natural gas by sea and may be economically attractive for supply sources that are too small to justify investment in pipelines and LNG facilities.

Meanwhile, gas-to-liquids (GTL) technol-ogy uses chemical and thermal processes to convert natural gas into ultra-clean liquid products (see p71), such as synthetic die-sel and naphtha, which are traditionally pro-duced by refining crude oil. These can then be shipped in conventional oil-products car-riers, pipelines or trucks. vA giant floating thermos flask

Green wiresWind, wave and tidal energy are important to a low-carbon energy future. But they aren’t available all the time – back-up sources are needed to bridge the lulls and seasonal fluctuations in wind and wave power, and daily cycles of tidal energy.Nor are these resources evenly spread geographically.Europe hopes to address this problem by constructing a supergrid of electricity cables linking wind- and wave-rich North Sea countries and solar-rich North African nations with countries with poor access to renewable energy. This, it is hoped, will weather proof energy supplies across Europe and open up new markets – helping the continent achieve its aspiration of getting all of its electricity from renewables by 2050.Some elements of the supergrid already exist. The BritNed electricity cable opened in 2011 and links the electricity grids of the UK and continental European for the first time. Running under the North Sea, between Kent in the UK to the southern Netherlands, it is 260 kilometres long, uses 23,000 tonnes of copper and lead, and cost £500 million to build. The electricity flows as High Voltage Direct Current (HVDC), which loses less energy that AC (alternating current) over long distances. Up to 1 gigawatt of high-voltage DC can be transmitted in either direction. BritNed will make the 30 gigawatts of offshore wind power the UK plans to build in the North Sea by 2020 available to buyers in continental Europe.

Meanwhile, EirGrid’s East-West Interconnector, linking Ireland with Wales, was completed last year. The 260-kilometre cable, buried in water depths of 150 metres, can transmit 500 megawatts of HVDC. The world’s longest undersea cable is being planned to connect the UK and Norway. UK and Norwegian energy infrastructure companies National Grid and Statnett have agreed a deal to build the 700 kilometre, 1.4 gigawatt cable by 2020. An even longer cable is even being discussed between the UK and Iceland. This would have to be up to 1,500 kilometres long and would be extremely difficult to lay, but would open up Iceland’s zero-carbon geothermal energy to the rest of Europe.

The BritNed electricity cable, from the UK to the Netherlands, weighs 23,000 tonnes

Approved projectExisting projectProject under consideration

108 – www.energy-future.com 109 – www.energy-future.com

Industry facts Industry facts

The sink that might be filling up © London Array Limited

The oceans: shock absorbers for climate changeManmade emissions of greenhouse gases such as carbon dioxide (CO2) are warming the Earth, but the oceans have been taking some of the heat out of climate change. This is because the oceans are a carbon sink – a natural environment able to absorb substantial volumes of CO2 from the atmosphere.The Intergovernmental Panel on Climate Change estimates that the oceans absorb around 92 gigatonnes (92 thousand million tonnes) of carbon every year from the atmosphere but they only give back around 90 gigatonnes.The 2 gigatonnes of carbon the oceans hold onto represents about a quarter to a third of manmade output of carbon into the atmosphere. In total, around 120 gigatonnes of carbon is estimated to have been absorbed by the oceans between 1750 (prior to the industrial revolution) and 1994 – equivalent to a third to a half of all man-made CO2 emissions during this period.Oceanic absorption of CO2 helps buffer climate change. Yet it is leading to other problems: when CO2 mixes with water it reacts to produce carbonic acid, making oceanic water more acidic. Creatures that build skeletons from calcium carbonate (limestone), such as molluscs and corals, will find it harder to grow and maintain them. This is already being seen in plankton from the Southern Ocean, with unknown consequences for ecosystems. Research since the mid-2000s suggests that CO2 absorption in the oceans is slowing down, perhaps because of changing patterns of oceanic circulation or warming waters being less able to absorb CO2. If this important sink starts to fill up then limiting future climate change will become much more difficult.


Industry facts


5.5 – Methane hydrates

Ice on fireMethane hydrates could be an important future energy source, if commercial and technical barriers, and environmental risks can be overcome

Mention natural gas and people gener-ally think about vast reserves buried

beneath Russia or the Middle East. But this is just a fraction of all the gas on Earth. The biggest store on the planet is thought to be in the form of methane hydrates: deep on the ocean floor and bound up in permafrost.

These comparatively poorly understood deposits remain beyond commercial reach and their production may carry significant environmental risks. But if they can be pro-duced economically and safely, they could be an important energy resource for the future.

Also called methane clathrates, methane hydrates are a type of solid that looks like ice, but is a very different beast. They form

as pressurized water cools towards 0°C and begins to crystallize. The presence of meth-ane (CH4) interferes with the crystallization of water and results in individual methane molecules becoming caged in an open, rigid network of water molecules. Other gases, such as carbon dioxide (CO2) or ethane (C2H6), may also become trapped, but meth-ane dominates – often accounting for 99% or more of the total gas present.

The physical conditions that allow meth-ane hydrates to form are extreme and quite strict, and, until the 1960s, it was not know

that they occurred naturally on Earth. But methane hydrates are now known to exist worldwide in muds, sands and shales.

Methane hydrates form under high pres-sures and freezing temperatures in a re-gion called the hydrate stability zone (HSZ). This occurs at water depths of greater than around 500 metres and in polar regions, where the presence of permafrost means that they may be found about 150 metres below the ground, or sea-floor. The HSZ also has a maximum depth because of ge-othermal heat rising from the Earth, which means sediments buried deeper than 2,000 metres are likely to be too warm for methane hydrates to exist.

There must also be enough methane. This may migrate from deeper geological deposits, or be generated by the microbial decay of organic material.

Opening the cageA number of deep-ocean and onshore

drilling exercises have recovered samples of methane hydrates from depth and they have also been encountered beneath permafrost

Test drilling for methane hydrates in the Arctic

© USG

SMethane hydrates form under high pressures and freezing temperatures in a region called the hydrate stability zone



in areas of Siberia, in Russia, and Canada. But much of the knowledge of where meth-ane hydrates occur is based on theoretical models and evidence from remote seismic and well-log data.

Estimates of the size of methane-hy-drate deposits vary widely, although all consider them to be very large – between 1,000 and 5,000 trillion cubic metres. This resource is perhaps twice as large as all

known fossil-fuel deposits and could prove an important energy source for the future, especially for energy-deficient nations, such as Japan or India.

But the technical obstacles to commer-cial production are substantial and there are also significant local and global environ-mental risks involved.

Aside from their location in harsh environ-ments, such as deep oceans or the Arctic, unconventional-production approaches are required to destabilize solid methane hy-drates and release the gas from its icy cage. One easy way to do this is to depressurize the hydrate. If methane gas and water are continually pumped away from the base of the HSZ, where methane gas and liquid water may exist from being warmed by the Earth’s geothermal heat, pressure around the borehole will be lowered, causing the hydrates to decompose.

Depressurization is likely to be the first production method to be used commercially, but it may affect the stability of the seabed, which could damage drilling equipment, or allow methane gradually or even explosively to leak to the surface. Production rates would also be very slow.

An alternative approach is thermal stimu-lation of methane hydrates by flooding them

This is not Photoshop

The methane-hydrates resource is is perhaps twice as large as all known fossil-fuel deposits



with hot water or steam, or even heating them electrically. The heat required to de-compose methane hydrates is only a frac-tion of the energy that can be recovered from them. But a significant amount of heat is wasted, as it leaks into surrounding rocks, and the hydrate layer itself must be fairly po-rous to allow hot fluids to penetrate.

A third production method involves the introduction of chemicals to the hydrate to

destabilize it. This has been employed in Siberia’s Messoyakha gas field, to recover methane from hydrates under perma-frost, with methanol as the inhibitor. Using methanol has proved very expensive, but cheaper inhibitors, such as ethylene glycol, are now available.

Perhaps most promisingly, research has shown that injecting warm CO2 at high pres-sure can release methane, but leave the hy-

A risk often associated with methane hydrates is their role in causing underwater geohaz-ards. The paths of numerous submarine land-slides, hundreds of kilometres long, scar the continental margins, and methane hydrates may have helped to trigger them. If sea levels fall or oceans warm, the pressure and temper-ature conditions are felt by methane hydrates buried in the sea-floor change. This may lead hydrates at the base of the HSZ to break down into liquid water and methane gas, form-ing a loose, slippery layer that sediments on a slope can easily slide over.

One such landslide, the 8,000 year-old Storegga slide off northern Norway, caused an eight-metre tsunami to hit the coast of Scotland. And although events of this size are unheard of in the modern era, their po-tential to cause significant damage is sober-ing. Drilling and production operations must be wary of destabilizing methane hydrates in a way that could generate sediment slips. But besides their physical impact, another seri-ous effect of landslides is the release of large amounts of methane into the atmosphere that was previously trapped in the sea floor.

Methane is a powerful greenhouse gas – 25 times more potent than CO2 when meas-ured over a hundred years. So increases of methane in the atmosphere could have po-tentially dramatic consequences for the glo-bal climate. The fear is that a catastrophic release of methane from hydrates could trig-ger runaway climate change – where the re-lease of methane leads to warming, which leads to more methane release, and so on.

This has also been dubbed the clathrate gun, and there is evidence in the geological past of sudden, rapid warmings that may have been caused by immense inputs of methane into the atmosphere. But the amount of meth-ane required to warm the planet significantly is much larger than the volume liberated from a single submarine landslide; and is dwarfed by the annual amount of natural methane re-leased from tropical wetlands.

Methane survives for only around 12 years in the atmosphere. It then breaks down into CO2, which is a much greater long-term threat to the global climate.

Most methane-hydrate deposits lie in the deep oceans and are unlikely to be destabi-lized because these regions take thousands of years to respond to warming. But in the Arctic, methane hydrates exist in shallower waters and recent observations show rising methane emissions in the region. Some re-searchers have even reported the sea ap-pearing to boil, as plumes of methane gas hit the surface.

There is no certain evidence that these re-leases are caused by human-induced cli-mate change. Much of the methane ob-served may not be from hydrates, but from the decomposition of thawing organic mat-ter, and hydrates beneath the Arctic Ocean would take a lot longer than a century or so of man-made warming to become unstable.

Even so, as greenhouse-gas concentra-tions continue to rise, many eyes will be fo-cused on what happens to these hydrates in the coming decades. v

Slipping and sliding, bubbling and boiling



drate intact. Hydrates of CO2 are more sta-ble than methane hydrates, so local geology should remain stable while CO2 could be re-liably sequestered out of the atmosphere. This method was trialled in 2012 at the Ignik Sikumi onshore well on Alaska's North Slope in a joint venture by ConocoPhillips and the Japan Oil, Gas and Metals National Corporation (JOGMEC). Production was successful and data from the operation are being evaluated.

Testing the futureMethane-hydrate production methods

are still mainly confined to theory, the lab-oratory, or small-scale field tests rather than demonstrations of commercially viable projects. Exploiting methane hydrates in the new frontiers of the Arctic or the deep sea requires substantial investment not just in production equipment, but also in transpor-tation infrastructure. But energy companies and governments are beginning to increase

the pace of research and the number of pro-duction trials. Japan, for example, started a large-scale methane-hydrate production test early in 2012.

Some experts consider significant com-mercial methane hydrate production to be 10-15 years away – although the International Energy Agency, in 2011, did not consider that methane hydrates will have much of a role in energy supply at least up to 2035. But over the coming decades, the markets and government policies – particularly on climate change – may change the outlook for the production of methane hydrates as much as technological developments. v

The biggest gas resource is thought to be in the form of methane hydrates – bound up in permafrost or deep on the ocean floor

Methane-hydrate production methods are still mainly confined to theory, the laboratory, or small-scale field tests

The Directory of Leading Employers

BP� 117Chevron� 119Gazprom�M&T� 121Repsol� 123Schlumberger� 125Technip� 127

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China’s second West-East pipeline system will extend around 8,700 kilometres © GE

China’s pipeline featsSome of the world’s longest oil and gas pipelines lead to energy-hungry China, which is prepared to pay big money to tap into distant oil and gas reserves.China’s first West-East Gas Pipeline Project (WEPP), completed in 2004, runs for 4,000 kilometres across China to Shanghai. The four-year project involved digging and moving over 30 million cubic metres of earth and stone – enough to build a road 1 metre-wide around the Earth.Now, an even more ambitious second WEPP is being built. Costing over $20 billion, it includes a trunk line and eight branches totalling some 8,700 kilometres, carrying gas from Turkmenistan through central Asia to major centres such as Shanghai, Hong Kong and Guangzhou. The 4,978 kilometre trunk line was completed in 2011, crossing mountains, desert, swamps and 190 rivers. Despite its size, the 30 billion cubic metres a year pipeline system will supply less than 10% of the gas China expects to be using annually by 2020. That’s not the end of it – China started building a third WEPP in 2012 and is planning a fourth and, possibly, a fifth in years to come. By 2015, the total length of natural gas infrastructure in China is expected to reach over 100,000 kilometres.China also lies at the end of what will be the world’s longest oil pipeline. That’s the 1 million barrels a day, 4,200 kilometre Eastern Siberia-Pacific Ocean oil pipeline (ESPO), which is now close to completion.


Industry facts


BPGraduate and Intern Recruitment,Chertsey Road,Sunbury on Thames, Middlesex,United Kingdom, TW16 7LN.www.bp.com/ukgraduates

What will you discover? Graduate and Internship opportunities in engineering, science and business

Find out for yourself what it takes

to deliver energy safely to the world.

Discover how BP and its people find,

develop and produce essential sources

of energy. And see with your own eyes

how that energy is turned into products

you and everyone on the planet depend

on every day.

Heat. Light. Power. Mobility. Materials

to make the products that define the

life you live. All are made possible by

oil and gas. And as demand continues

to grow, delivering it sustainably and at

a reasonable cost remains one of the

biggest challenges in the world today.

Join us as a graduate or on a summer

or year-long internship and you’ll find how

our people make some truly amazing

discoveries to meet that challenge. Both

in terms of scientific and engineering

breakthroughs and what we as a team

are capable of.

bp.com/ukgraduates

n Number of graduate vacancies in 2011/12: 210n Number of intern vacancies in 2011/12: 120n Number of countries of operation: over 100To apply go to: www.bp.com/ukgraduates

More of these

* The New Policies Scenario, one of three main International Energy Agency projections for the long-term energy future, takes account of plans announced by governments around the world to cut greenhouse-gas emissions. The other two main projections are: the Current Policies Scenario, which assumes energy policies will remain unchanged; and the 450 Scenario, which sets out an energy pathway consistent with the goal of limiting the global increase in temperature to 2°C.

The long and winding road(s)There are around 45 million paved lane-kilometres of roads worldwide. That is about 30% more than a decade ago. And the number is expected to rise by 40% by 2035, reaching 62 million paved lane-kilometres, according to the International Energy Agency’s (IEA) New Policies Scenario*.About four-fifths of the new roads, which will cost something like $20 trillion, will be built in developing countries and more than half of them will be built in China and India alone.But more roads won’t necessarily mean better traffic. Congestion and pollution should worsen because car ownership is rising so fast. China’s road occupancy is set to soar by around 70% over the next 23 years and India’s will more than triple. That, says the IEA, will work against improvements in vehicle fuel economy, because stop-start driving in heavy traffic is more energy-intensive than driving on open, uncongested roads.

© Amanda Slater© Amanda Slater

And more of this

More of this


Industry facts


Chevron Headquarters6001 Bollinger Canyon RoadSan Ramon, California 94583USAwww.chevron.com/careers

Chevron is one of the world’s leading in-tegrated energy companies, with subsid-iaries that conduct business worldwide. The company is involved in virtually every facet of the energy industry. Chevron ex-plores for, produces and transports crude oil and natural gas; refines, markets and distributes transportation fuels and lubri-cants; manufactures and sells petrochem-ical products; generates power and pro-duces geothermal energy; provides en-ergy efficiency solutions; and develops the energy resources of the future, in-cluding biofuels. Chevron is based in San Ramon, California. More information about Chevron is available at www.chevron.com.

Why join Chevron?v Culture of collaboration and teamwork – You can succeed as an individual, sup-ported by a talented team.v The Chevron Way – More than just words, The Chevron Way values are lived out by our employees every day. v A global business – Your job will have an impact on the lives of millions around the world. At the same time, you’ll work with peo-ple of many backgrounds and experiences.v Career growth and development – Explore career paths and participate in training that will help you succeed person-ally and professionally.v Competitive pay and benefits – Chevron’s pay and benefits programs are designed to meet the diverse needs of our employees.

n Disciplines we recruit: engineering (petroleum, mechanical, chemical, process, electrical, environmental, drilling and completions, facilities and civil engineering), accounting, finance, geosciences, information technology, supply and trading, human resources and health, environment and safety professionals.n To apply: www.chevron.com/careers

The world’s cleanest internal-combustion production-line car is a natural gas vehicle (NGV) – the Honda Civic Natural Gas (see image, top left). It has a dedicated engine that is reported in areas with high pollution to produce exhaust emissions that are cleaner than the air going into the engine.

The Civic can drive from the West Coast of the US to the East Coast and emit less non-methane hydrocarbons than if you were to spill one teaspoon of gasoline.

There are around 15 million NGVs in the world, but this number could rise to something like 65 million by 2020.

Gas is a versatile automotive fuel, suitable for a wide range of vehicles. And, with the use of biogas and biomethane on the rise, NGVs could become even cleaner.

Source: NGV Global

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The Honda Civic Natural Gas

Tuk-Tuks in Bangkok

Gas-powered refuse collection in Paris

And locomotives, another application for the future

Refueling a CNG taxi in California

LNG truck

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© Loïc Journe; Mairie de Paris/DPE


Industry facts


Gazprom Marketing & Trading Ltd20 Triton Street London, NW1 3BF, United KingdomTel: +44 (0) 207 756 0000 www.gazprom-mt.com

Headquartered in London, Gazprom Marketing & Trading Limited (GM&T) pro-vides customers around the world with in-tegrated energy solutions. Established in 1999, the company has a global presence and offers a unique suite of products – from gas and power, LNG and LPG marketing, trading and supply, to carbon deals, ship-ping and logistics, derivatives and oil trading.

GM&T has demonstrated the sustain-ability of its commercial activities, achiev-ing a decade of growth and increasing the breadth and complexity of its business. GM&T has created a strong and stable base from which to deliver its strategic aims; ena-bling OAO Gazprom to access new markets whilst delivering excellent levels of service to our customers and counterparts. GM&T has offices in London, Manchester, Germany, France, Switzerland, USA and Singapore.

GM&T is part of OAO Gazprom, Russia’s largest company and the world’s largest natural gas producer, accounting for 85 per cent of the country’s gas production and more than 60 per cent of its reserves, cur-rently estimated at around 33.1 trillion cu-bic metres and equivalent to 18 per cent of the world’s total gas reserves.

Gazprom group is a global energy com-pany engaged in the exploration, produc-tion, transmission, storage, processing and marketing of natural gas and other hydro-carbons both in Russia and around the world. It operates the world’s largest trans-mission system and exports gas to more than 30 countries.

n Number of graduate places for 2013-14: 20n Intake for London, Manchester and Singapore offices (GM&T has a total 8 offices)n Application period: September - Decembern Web: http://www.gazprom-mt.com/CareersWithUs/GraduateCentre

The Yastreb rig has drilled more than 12 kilometres down

and nearly as far out to sea

Going down – and acrossIt is located in the sub-Arctic climes of the Russian Far East, it is called Z-44 and it measures 12,376 metres – that’s 15 times the height the world’s tallest building, the Burj Khalifa in Dubai.What is it? The world’s longest extended-reach oil and gas well.Situated in the Chavyo oil and gas field, Z-44 is part of the mammoth Sakhalin-1 energy project on and around Sakhalin Island, which had spawned six of the world’s 10 deepest wells by 2012, according to the operator, Exxon Neftegas.The project also holds the record for the world’s longest horizontal well.The Odoptu OP-11 offshore well, drilled in 2011, has a horizontal reach of 11,475 metres, as well as being one of the world’s deepest wells, at 12,345 metres. Technological breakthroughs have made it possible to turn drill shafts around corners and get access to oil and gas reserves from the side, or at an angle, making it easier for them to flow. This is known as extended-reach drilling.All these wells have been drilled by the Yastreb rig, which sits on the coast and uses its extended-reach capabilities to drill out below the sea. Yastreb is itself something of a leviathan, standing 52 metres high, about the height of a 17-storey building.

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Industry facts


RepsolCampus Repsol, Méndez Álvaro, 44 28045 - Madrid, EspañaE-mail: [email protected]: +34 91 7538000www.repsol.com

Repsol is an international energy company with over 23,000 employees and operations in more than 30 countries across five continents. We explore for and produce hydrocarbons in Europe, America, Africa and Asia, and operate six refining industrial complexes in Spain and Latin America. We market and distribute our products all over the world.

We pride ourselves in being a respon-sible and transparent company with a strong commitment to sustainability, so-cial development and the environment. Our investments in cutting-edge techno-logical innovation, research and develop-ment at our Technology Centre in Spain help us develop competitive technology to obtain the best possible products. Our diverse team of employees, with over 36 different nationalities, of which 25% are women, has access to popular tailored training and development plans, which include mobility and internal promotion. We also carry out regular assessments of performance and integration, and offer competitive social benefits, such as med-ical care, loans, insurance and pension plans, among others.

Repsol is a dynamic and growing company in a sector with a guaranteed future. This has a direct impact on the high satisfaction of our employees and in the low staff turnover.

Why not take a closer look.

n Repsol, worldwide energy leader in the Dow Jones Sustainability Indexes for a second consecutive yearn Repsol rewarded for its work to inte-grate people with disabilitiesn Named one of the Top Employers in Spain by the CRF Instituten 7/10 employees are proud to be part of Repsol.n Repsol has published a telework white papern Repsol, world energy leader in the Newsweek Green Rankingn To apply go to: www.repsol.com/es_en/corporacion/empleo//

Fracking zoneProbability of fractures extending more than 350 metres: around 1%

Generally at depths of around 600 metres

Barnett: 2-3 kilometres deepMarcellus: 2 kilometres deep

Aquifer

Shale

Not to sca

le

Tracking frackingFracking involves injecting pressurised water into rocks to crack them and release hydrocarbons. It has made new supplies of oil and gas available, but has also has raised environmental objections. One concern is that fracking fluids may travel through fractures and contaminate groundwater.However, recent research indicates that this is very unlikely to occur. In 2012, Richard Davies, a professor at Durham University, UK – along with colleagues from Wales and Norway – assessed the distances that fractures travel away from a well-bore. They analysed thousands of fracking events from five US shale formations: Barnett, Eagle Ford, Marcellus, Niobara and Woodford.Seismic traces of fractures showed that the probability of fractures extending more than 350 metres was around 1%. Most fractures were between 200 metres and 400 metres. One fracture in the Barnett shale travelled 588 metres vertically, while another in the Marcellus shale extended 536 metres. These longer fractures probably intersected existing faults.The Barnett shale lies at a depth of 2-3 kilometres and the Marcellus shale is around 2 kilometres under the surface. Groundwater aquifers are generally found at depths of around 600 metres and are, as a result, generally well insulated from fracking.However, aquifers are occasionally found at greater depths. Under these circumstances, care must be taken to ensure that there is a safe minimum separation distance between the fracking zone and the aquifer. However, more data from different geological settings are needed to fully appreciate how far fracks can go and what that distance should be.

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Industry facts


Schlumbergercareers.slb.comwww.slb.com

Sometimes referred to as the “biggest company you’ve never heard of,” we are the world’s largest oil and gas services company. Globally, we are trusted to deliver superior results and improved E&P performance for oil and gas companies. Founded in the 1920s by brothers Conrad and Marcel Schlumberger, the same principles of knowledge, technical innovation, and teamwork remain as central to our philosophy today as they were 85 years ago.

We invest more time and resources in our training and development programs than any other oilfield services company. We are committed to providing training, not just when you first start with us, but for the long-term. As your career progresses, we ensure you have the skills you need to succeed, whether that is in a technical role, or in a support role, such as HR, supply chain, or IT.

As soon as you start with the company you have responsibility. This means every day is different. Our varied and challenging positions around the world give you the opportunity to stretch your skills and reach your maximum potential. We take our investment in you seriously—our future success depends on it.

What will you be?

n 118,000 employeesn 140 nationalitiesn Operating in approximately 85 countriesWho we looking for?We need more than 5,000 graduates to begin dynamic careers in the following domains:n Engineering, Research, and Operationsn Geoscience and Petrotechnicaln Commercial and Businessn There is no fixed deadline to receiveapplications, Schlumberger recruits allyear roundn To apply go to: careers.slb.com

Construction of Qatar’s mega-trains

LNG: supersize me!The biggest liquefied natural gas (LNG) production units being constructed now are getting on for 30 times larger than the first facilities, built in the 1960s.

A plant in Arzew, Algeria, was the first to make commercial shipments – sending gas to the UK in 1964. The Arzew plant had a total nameplate capacity of around 0.85 million tonnes of LNG a year. This was produced by three separate production units – LNG trains – giving each train a capacity of about 280,000 tonnes a year.

The biggest trains in use at recently constructed facilities in Qatar can produce 7.8 million tonnes a year of LNG each. The power of the cooling compressors at Qatargas 4, developed by Qatar Petroleum and Shell, is equivalent to eight Boeing 747s at full take-off.

Although the Arzew plant, now decommissioned, was the first commercial LNG plant, the first ever shipment of LNG was from the US to the UK, in 1959.

© Q

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Industry facts


Technip89 avenue de la Grande Armee75116 ParisFrance

www.technip.com

Technip is a world leader in project management, engineering and construc-tion for the energy industry. From the deepest Subsea oil & gas developments to the largest Offshore and Onshore infra-structures, our teams draw upon ground-breaking technologies to offer the best solutions for the world’s energy chal-lenges. We have established a strong reputation based on our ability to antici-pate and adapt to changing market condi-tions, trends and client expectations. We are organized in 3 business segments:

Subsea – Our activities cover the de-sign, manufacture and installation of rigid and flexible flowlines and umbilicals. We have state-of-the-art manufacturing plants and a cutting-edge fleet. We de-velop innovative subsea technologies.

Offshore – We perform design, con-struction and installation of fixed and floating platforms for the development of oil and gas fields located in shallow to ul-tra-deep water. We are a major player in the FLNG sector.

Onshore – We are the leader in the engineering and construction of refining, petrochemical, gas treatment and lique-faction plants, as well as hydrogen, ethyl-ene and syngas units. Our onshore seg-ment also comprises other energy indus-tries and non-oil and gas activities.

To support the worldwide development of our business activities, we are looking for talented people to take the Group’s and their own career further.

n Number of people: 33,000 worldwide n Number of countries of operation: 48 n Application deadline: Year around n To apply: http://www.technip.com

Sugar FreezeLiquefied natural gas (LNG) is already being used to power trucks, buses and ships. By the middle of the century, it may be in use in aircraft too.

According to a study by Boeing, LNG has the potential to reduce fuel burn and emissions, as well as costs.

The US aircraft manufacturer’s concept – which it refers to as Sugar Freeze (Sugar stands for Subsonic Ultra Green Aircraft Research and Freeze is a reference to LNG’s low temperature) – might be feasible by 2040-50.

The idea has been developed as part of a Nasa programme to investigate ways of improving fuel efficiency. Nasa’s aim is to cut fuel burn by 60% from the present level. Using LNG in conjunction with various other energy-saving technologies might exceed this target, Boeing believes.

Source: Aviation Week

One day, this might be powered by LNG

© Rolls Royce p

lc


Industry facts

• Introduction to the oil and gas industry• Introduction to the power industry• Financing energy• The Great Game: geopolitics and energy• Energy and the environment

Learn better. Learn faster.

Knowledge is power

Fill your knowledge gaps at energy-future.com

Who are we?We are the world’s largest oilfield services company1. Working globally—often in remote and challenging locations—we invent, design, engineer, and apply technology to help our customers find and produce oil and gas safely.

Who are we looking for?We need more than 5,000 graduates to begin dynamic careers in the following domains:

n Engineering, Research and Operationsn Geoscience and Petrotechnicaln Commercial and Business

What will you be?

>118,000 employees>140 nationalities~ 85 countries of operation

careers.slb.com

years of

innovation85

1 Based on Fortune 500 ranking 2011. Copyright © 2013 Schlumberger. All rights reserved.

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