Forecasting

When considering quantities of oil the universally quoted unit of volume is the US barrel, which is 42 US gallons, 35 Imperial gallons or 159 litres. For comparison it is common to convert natural gas, coal and electrical units to their thermal equivalent in barrels of oil (boe). Another common unit is the metric tonne of crude oil which is equivalent to 7.33 barrels. When considering world production rates and the size of global reserves the barrel is multiplied by 1000 million to become the gigabarrel (Gb).

The production life-cycle of an oil field follows a "Hubbert Curve" ⁵ , conceived by the late Dr. M King Hubbert of the Colorado School of Mines. After development, production rises to a peak and then falls off. The area under the curve represents the total production of the field and its overall monetary value depends on the course of oil prices during its life-time. The production cycle curves of the individual oil fields overlap to produce a world peak curve. In practice the production rate of a field reaches a peak and then gradually tails off until exploitation of the field is uneconomic, following the "Hubbert" curve. In 1956, Dr Hubbert accurately predicted that US oil production would peak in 1970. 

Some fields have passed their "Hubbert" peak and national reserves are dwindling. Forecasts as to when global oil production reaches its peak have tended to be pushed forward with new discoveries and improved technology. Analysts have been accused of crying "wolf", but an "all-oils" production peak before or by 2010 seems now be generally accepted and as a result governments are giving serious consideration to fuel policy ⁹. Actually, according to BP ⁶, global production fell from 27.2 Gb in 2000 to 27.1 Gb in 2001 and further to 27.0 Gb/annum in 2002, but rose to 28 Gb in 2003, to 29.3 Gb in 2004, to 29.6 Gb in 2005 and to 29.8 Gb in 2006, a marginal increase of 0.4%. This included 0.24 Gb of synthetic crude oil from Alberta's tarsands.

The moderate rises in production were a response to surging crude oil prices, stimulated by economic growth in China and India. Saudi Arabia oil production decreased in 2006 compared with 2005 by -2.3%, perhaps passing its national Hubbert peak in 2005. However, if the rising internal consumption is subtracted from the production, the decrease in exported crude oil is -4%. In 2005 production rose 4.4% over that in 2004, in 2004 it rose 4.7% over 2003, showing a lowering ability to raise output when compared with a 13.8% increase in production attained in 2003 over 2002. It may be that the reducing increases in production from 2004 to 2005, presumably achieved by increased water injection - followed by the decrease in 2006 - indicates that Saudi Arabia's ability to fill production deficits as a "swing" producer may have come to an end.

The amount of oil in a field able to be exploited economically is estimated from geological surveys and estimates based on test boreholes. Experience and expertise is exercised to produce a figure for "proved" reserves, being the amount remaining in the ground likely to be economically exploited. The significance of the oil reserves to production (R/P) ratio is that if production continued at its current rate the reserves would be empty when the number of years elapsed equals the ratio. This ratio is used by the oil industry as an indicator of the comparative sizes of country reserves and their future potential. However, the monitoring of actual production figures and plotting them on a cumulative basis provides a better indication of the likely ultimate production from a particular country.

The Association for the Study of Peak Oil and Gas (ASPO) publishes a monthly newsletter ¹⁸ in which it provides a plot of global oil production from 1930 until the present and extrapolates the trends of the various types of production until 2050. The ASPO plot comprehensively takes into account the likely contribution from regular oil, heavy oil and tarsands, that from deepwater and polar exploration and gas liquids. The global production peak in regular oil is considered by ASPO to have already occurred in 2005, while a peak in "all oils" production is expected before 2010. An oil equivalent of natural gas production has been added to the plot.

From 2010, if not before, a downward production trend will have an deleterious effect on the world’s economies, particularly the USA which depends on oil for its lifestyle and by when its own reserves will have depleted further.

BP statistics

R/P ratios

BP publishes annually a "Statistical Review of World Energy" ⁶ on its web site which includes a downloadable spreadsheet giving detailed information on the world's oil, natural gas and coal reserves, production and consumption. The first worksheet “Oil-Proved reserves” gives proved reserves and R/P ratios for every producing country and for the world.

In its 2001 review BP commented "The world’s oil R/P ratio has fallen modestly since 1990 as world oil production growth has outpaced additions to reserves". A chart in the 2001 review shows 1990 as the year when the R/P peak ratio of 44 was passed, reducing to 40 by the end of 2000. At the end of 2002 the R/P ratio had reduced further to 39, to rise to 41 at the end of 2003, dropping back to 40.5 at the end of 2004,  shown at 40.6 at the end of 2005, slightly down at 40.5 at the end of 2006.  As production continues to rise and additions to reserves fail to match it, the ratio of oil reserves to production (R/P) will continue to decline and the price of crude oil will rise. 

The R/P concept used by the industry is flawed in that production will not continue to the end of the period defined by the ratio at a rate current at the time of the calculation and then suddenly fall to zero as a step change. It is however a useful guide for comparing one country's reserves in terms of its production rate with another, always providing that the reserves are not overstated.

For example, the Russian Federation is expending its reserves at a rate yielding an R/P ratio of only 22, whereas Saudi Arabia’s fields, if its reserves are of the size claimed, have an R/P ratio of 67. The Russian excessive rate of production offers a challenge to the production limitation policy of OPEC, but means that the Federation’s oil will dry up prematurely.  

Proved reserves

For the preparation of the 2007 annual statistical review for a period to end-2006, BP relied on data from official sources, the OPEC Secretariat, World Oil, O&GJ and an independent assessment of Russian reserves, but added reservations as to the accuracy of the data in the small print. The figure of 1208 Gb for proved oil reserves includes gas condensates, natural gas liquids and around 10 Gb for Canadian oilsands which are deemed "under development" and has shown little change from that of the previous year. 

It had been hoped that oilsands and oil shales, the so-called unconventional oils would provide huge additional reserves in great quantities for the future. In the event the contribution from tarsands is proving to be minimal.  BP has downgraded the optimistic figures of others for oilsands reserves to a more realistic 10 Gb. (Alberta's synthetic crude oil (SCO) production in 2004 was 219 million barrels, falling to 200 million barrels in 2005, rising somewhat in 2006 to 240 million barrels, with bitumen extraction of 399 mb in 2004, 388 mb in 2005, rising to 458 million barrels in 2006. Extraction of SCO from the bitumen was 55%, 52% and 52% respectively.)  

In BP's successive statistical reviews there is a backward revision in the sheet "Oil - proved reserves history" of the previous few years reserves' figures, smoothing out the unexplained additions in past years. For instance the reserves for 2003 in the 2004 review amounted to 1148 Gb, whereas in the 2007 review the reserves in 2003 are given as 1189 Gb. 

BP oil policy

BP is investing in a joint venture with a Russian company, TNK,  which has access to Russian oil reserves, from which a third of its future production is anticipated. The BP Annual Report for 2004 shows that exploration expenditure fell by 15% from $644 in 2002 to $542 million in 2003, rising to $637 million in 2004 and further to $684million in 2005, whereas investment in joint ventures rose from $4 billion in 2002 to $11 billion in 2003, to $13 billion in 2004 and to $12.6 billion in 2005. This indicates that the major part of BP's development investment is dedicated to participation in mature production opportunities rather than in exploration for new discoveries . 

BP is also involved in a crude oil pipeline project from Baku, the capital of Azerbaijan on the West shore of the Caspian Sea through Georgia and Turkey to a terminal at Ceyhan on its Mediterranean coast. The pipeline is designed to pump 1 million barrels per day (50 million tonnes/year). The through-put in 2007 was around 700,000 barrels a day. 

Peak oil

BP does not expect an imminent peak in world oil production, but acknowledges that there is a core of informed analysts who do believe in such an outcome. In defence of the "peak" analysts, production in the United States peaked in 1970, North Sea oil peaked in 1999, since when both are in decline. The aggregate of similar production profiles from the world's oil fields produces a unified global peak in production. Once this is past only a major discovery could produce a subsequent revival of production and a steady decline ensues.

UK reserves

British indigenous oil reserves, which comprise only 0.5% of the global total, are currently under the North Sea and at other not yet explored locations on the continental shelf. UK oil production passed its peak in 1999 and is now tailing off. (In January 2003, after its Forties field produced less than a tenth of its peak output, BP sold it to Apache, a company specialising in extracting oil from ageing reservoirs.) Rather than extract these reserves for oil company profits and government tax revenue, it would have been better to leave them where they are for later in the century when foreign oil resources will be exhausted.

The oil companies viewed their principle business as finding and exploiting oil and gas resources and indeed their main profit base was exploration and production rather than refining and distribution. The trend now is to acquire shares in established production companies, such as those in the Former Soviet Union. It must be assumed that little can be done to avoid the depletion of British reserves, which culminated in the net importation of oil and gas in 2006, of 9% and 12% of oil and gas consumption respectively.

Global reserves

According to successive BP statistical reviews, with new discoveries (less interim production), global reserves rose by around 139 Gb over the period 1993-2003 from 1009 Gb in 1993 to 1148 Gb in 2003, with the biggest rise over 2003 of 100 Gb. The principle contributions to this rise, subtracting the individual countries' reserve figures for 2002 from those for 2003, are as follows:-

Table 1

In the Statistical Review 2005, a further rise in the proved reserves of 41 Gb is shown, from 1148 Gb at the end of 2003 to 1189 Gb at the end of 2004. The biggest increase in reserves is in that of Kazakhstan, which improved by 30.6 Gb, from 9 Gb to 39.6 Gb in a year! (In the 2007 Statistical Review, the figures are revised with a step change occurring in 2001 from a previous 25 Gb to 39.6 Gb, now at end-2006 as 39.8 Gb.) The Russian Federation added 2 Gb to its stated reserves by end-2006 over end-2005. 

Unexplained increments

The above analysis of proved reserves is based on BP's  figures, but they in turn are based on a variety of sources and cannot be confirmed unreservedly by BP. In the 1980's statistics there appeared step increases in OPEC countries' reserve figures, originating from the Oil and Gas Journal which published the figures without question. With the exception of the Canadian increase, obtained by including 10 Gb of oilsands extractable reserves, there is no intimation of how the upgraded figures were derived.

OPEC’s quotas are based on a country’s capacity to produce, the demand for its oil and most significantly the size of its reserves. In the 1980’s the six major producers in OPEC declared significant increases in their proven reserves. In 1984 Kuwait upped its proven reserves by 39%; in 1987 Iran raised its by 90%, Iraq its by 112%, the Emirates raised its by 196% and Venezuela its by 125%; in 1989 Saudi Arabia raised its by 50%, presumably to enable their agreed quotas to be increased. ¹⁷  The effect of these adjustments was to increase the stated amount of the global proven oil reserves at that time by 303 Gb, i.e., by 45%.

It is now thought that these upwards adjustments in the 1980's were to establish a country's ultimate oil recovery, rather than show the remaining reserves. It is not clear from the 2004 or the 2005 BP reviews on what the more recent step changes are based; whether they are based on new discoveries or on a re-appraisal of previous estimates.

Since the 1980’s there has been little change in the stated reserves of these OPEC countries, excluding the recent adjustments to Iran's reserves listed above, in spite of production by the six since then totalling 142 Gb. Subtracting the 445 Gb (303 Gb of overstated reserves + 142 Gb of subsequent production) from the now stated global oil reserves of 1189 Gb leaves only 744 Gb, reducing the R/P ratio to 29 from 40.5. These figures deserve more analysis, since if the additions were political rather than actual, then the world's proved oil reserves are 60% overstated.

Middle East predominance

In 2002 the Russian Federation added 20% to its proven reserves from 49 Gb to 60 Gb, with an increase to 69.1 in 2003, increasing further to 72.3 Gb by the end of 2004 and to 74.4 Gb by the end of 2005. Another 5.1 Gb has been added to give 79.5 Gb at the end of 2006. There were two annual increases in production of 9%,  to provide 12% of global production in 2004 at 3.4 Gb and 3.5 Gb in 2005. With reserves of 79.5 Gb at end-2006 and production in 2006 at 3.56 Gb, the R/P ratio increased slightly from 21 to 22. 

The Russian Federation produces more in proportion to its share of global reserves than the Middle East countries and must soon realise that its own economy will need the oil it is currently exporting. Taking the BP figures for proved reserves (in the absence of clarification) means that by 2025 or sooner, Russian oil will no longer be exported, the smaller fields elsewhere will be extinct or in rapid decline and only the Middle East will have significant oil left.

From the latest BP statistical review, 62% of the world’s proved oil reserves reside in the Middle East, of which 22% are in Saudi Arabia, 11% in Iran, 10% in Iraq and 8% in Kuwait. Although at 2004 production rates Middle East oil has 82 years to run, now that the non-Middle East reserves are unable to raise production levels, demands are being made for the Middle East, in particular Saudi Arabia, to increase production to maintain world economic activity. 

If in consequence of world pressure Middle East production did rise to meet this demand, the 82 years would shorten, depleting inexorably the Middle East reserves. To further the anticipated growth in the global economy, Middle East production must continue to increase - it will soon be evident whether the so-called "swing" producers can pump enough oil to satisfy the rising economic aspirations of China and India. The omens are not favourable and it is unlikely that further production increments can be made.  

Political factors

As oil production nears its peak, the OPEC practice of maintaining oil prices by the control of supply and the moderating effect of Russian oils can be discounted. Rising oil prices will have a moderate effect on consumption, but revolution and political change may well lead to wells being capped. 

All the above named Middle East countries, with the exception since 2003 of Iraq, are autarchies and are the targets of Islamic fundamentalists. Fundamentalist control of just one of the above named countries, i.e., Saudi Arabia, would lock up what is claimed to be 22% of the world’s proven reserves. This will set the world in deadly competition with the USA for oil supplies. As the consumer of 25% of the world’s production, importing 67% of its requirement and with its own production falling, the USA’s procurement of its oil will be met either by paying a premium or secured by military intervention.

But the US economy boost from the Bush tax reductions with the predominance of high fuel consumption vehicles and with the rapid growth in China's economy, especially an increase in car ownership there, has meant that demand for oil has soared and may soon be unmatched by production.   

The coming shortage of oil and its consequent price rise means that by 2010, if not before, the upward trend of oil prices will have a significant impact on daily life and severe economic distress will affect those nations caught unprepared. The reliance on oil and associated natural gas is not confined to transport and heating fuels, but to almost all aspects of modern life. Oil and gas is the source of plastics and resins, synthetic fibres and rubbers, detergents, dyestuffs and agro-chemicals.

US policy

In the United States reserves in 1980 were 36.5 Gb (Gb = gigabarrel = 1000 million barrels), but at the end of 2006 totalled only 29.9 Gb. Peak production in 1971/2 was 4.1 Gb. In 2006 production was 2.51 Gb and consumption was 7.52 Gb, so that the USA was a net importer with 67% of its requirements met by external suppliers.

In 2002 the USA sent an elite force to train and equip Columbian government troops defending pipelines pumping oil from the Arauca field and petrol from Barrancabermeja refinery. The pipelines are subject to sabotage by paramilitaries causing spillages of crude oil and diversion of petrol for sale to fund their activities.     

In 2002 and 2003 the USA focused its attentions on the Iraqi regime and its capability in weapons of mass destruction, leading to the second Gulf War in 2003. Detractors maintained that the real aim of the USA was the procurement of Iraq's oil, which in national oil reserves ranks second in size. This view was supported by the coalition priorities after the war, when some of the oil production was restored and an end to UN sanctions was sought and obtained. 

UK

How will all this affect us?

·       UK oil reserves fell progressively from 5.0 Gb in 2000 to 4.9 Gb in 2001 to 4.7 Gb in 2002 , to 4.5 Gb in 2003 and in 2004, then to 3.9 Gb at the end of 2005 and 2006. 

·       The R/P ratio was 6.5 in 2006.

·       Production fell from 1.06 Gb in 1999, to 0.97 Gb in 2000, to 0.90 Gb in 2001 and 2002, to 0.82 Gb in 2003, to 0.74 Gb in 2004, to 0.66 Gb in 2005, then further to 0.60 Gb in 2006 showing that the Hubbert production peak was reached in 1999 heralding the start of a downwards trend.

·       Internal consumption over 2006 was 0.65 Gb which was 9% above UK production, so we are now somewhat dependent on imports of oil.

3. Natural gas 

Forecasting

BP Statistical Review 2007 provides the figures used below for analysing gas reserves and  production. The distribution of gas reserves does not correspond with the occurrences of oil. The countries of the Former Soviet Union hold 31% of the world's gas, of which the Russian Federation holds 26%, the Middle East 40.5%, Asia/Pacific 8% and Europe a mere 3.5%, of which Britain holds a minimal 0.3%! Of the current 40% of the world’s gas reserves in the Middle East, 15% are in Iran, 14% in Qatar, 4% in Saudi Arabia and 1% in Kuwait.

World gas production in 2006 was 2.87 trillion cubic metres (tcm), equivalent to 18.1 Gb of oil (Gboe). Reserves of natural gas at the end of 2006 were 181.5 trillion cubic metres or 1141 Gb oil equivalent. The world gas R/P ratio in 2006 was 63, compared to 40.5 for oil. At 2006 production rates, gas reserves would provide a source of energy for a further 22 years after oil exhaustion. However, as oil supplies run down more would be drawn from gas reserves in substitution, the rising production thus increasing gas depletion, so that an oil production peak in 2010 would be followed by a gas production peak in say 2020.

Since natural gas reserves were estimated in 2000 at 163 tcm, six years later, by the end of 2006 some 16 tcm had been extracted, leaving reserves of 181 tcm, so that some 18 + 16 = 34 tcm of reserves addition has been assumed. This represents an average exponential annual growth in consumption of 2.4%.

BP gives a figure of 181.46 trillion cubic metres for global proved natural gas reserves at the end of 2006, with minimal growth in reserves over the figure of 180.02 tcm given for the end of 2005, so the growth in reserves over 2006 replaced the production by only 50%. 

Liquefied natural gas

Because of the nature of gas it requires pressure pipelines for overland transmission or pre-processing to liquefied natural gas (LNG) for ship transport, in comparison to crude oil which can be loaded directly to ocean tankers and transported for processing at the consumer country.

An example of an LNG venture is the Sakhalin Island project off Eastern Siberia to be developed by a consortium of Shell, Mitsui and Mitsubishi.  Oil and gas from off-shore platforms to the North of the island will be pipelined for 800 km, the whole length of the island, to an ice-free port in the South, where an oil export terminal and gas liquefaction plant will be built. The frozen gas will be exported in special ships to Japan, Korea, China and the USA.

As a further example, Exxon/Mobil is liquefying and shipping LNG from Qatar in the Gulf to Asia, it being uneconomic to ship to America. It is involved in an import venture at its South Hook terminal in Milford Haven, where further up the estuary, Dragon LNG is also building a terminal. Both are expected to be in  production in 2008 when connections to the UK gas network will be completed. Supplies for the UK are mainly expected to derive from North Africa as well as Qatar..

Gas substitution for oil  

As oil reserves exhaust, world markets will turn to exploit the potential source of chemicals and liquid fuels in natural gas. In anticipation of this the oil and gas industries have invested in processes able to convert remote natural gas resources into liquid products, the so-called Gas-to-Liquid technology.

For example, BP is a partner in a 2500 tons/day gas-to-methanol plant in Trinidad. This will open up an alternative route for chemicals to that of petrochemicals. In 2003 BP commissioned a 300 b/day pilot plant in Nikiski, Alaska able convert gas to synthetic diesel, jet fuel, naphtha and synthetic lube stock. Apparently it was successful, but BP has no plans for further local development on the Alaskan North Slope where the gas is, favouring other stranded gas locations (yet to be defined) for subsequent liquid fuels production.

The new processes able to make liquid fuels will have to be sited on the gas fields to be economic. If in spite of this disadvantage, production rises to meet a demand for liquid fuels not provided by oil, the 2005 aggregate world gas R/P ratio of 63 could well reduce to match that for oil, so that although gas has a potentially longer life, this may shorten due to market equilibration. (See Section 5 - Table 2 and Figure 2 below)

The conversion thermal efficiency of gas-to-liquids processes is theoretically only 55%, which will be lower in practice. Oil equivalents are calculated on a comparison of the thermal values of crude oil and natural gas and dependent on the efficiency of the exploitation technology, the oil equivalents should be downgraded. The equivalent figure used varies depending on the composition of the oil and gas, but BP assumes that 1 thousand cm of natural gas is equivalent to 6.29 barrels of crude oil.

Location of gas fields and markets

The three countries of North America share a network of pipelines supplying it with 29% of global natural gas production. This is currently drawn from gas fields on the continent itself, but with an indigenous gas depletion rate of around 10%/annum, terminals for importing LNG are under construction.  

The members of the Former Soviet Union consume 19% of global production and if the enlarged EU consumption of 20% were to be supplied from the FSU, this together with the union's own requirement would at 39% take up more than its current contribution to world production of 22%. Russia itself consumes 71% of its gas production and while this has expanded by 15% over the last ten years, domestic consumption has increased by 23% over the same period.

The Russian Federation being the dominant supplier in the region will have to double its gas production to supply its neighbours growing, thus increasing its depletion rate. So although the EU expects to be supplied from pipelines from Russia, it will have be augmented with Algerian and Libyan LNG by ship. The UK will be at the penultimate end of the pipeline from Russia, which may mean that if there is a shortage or outage, it will be severely disadvantaged. Only Ireland is more unfortunately placed! 

North America is not so fortunate and for augmentation of indigenous gas, LNG supplies from Eastern Russia, Africa, Qatar, Indonesia and Western Australia are planned. The remoteness of the market from the gas fields means that a large number of gas ships will be required to maintain supplies and due to the warming of the liquefied gas during the shipment, gas has to be released into the atmosphere during the journey to avoid an over-pressure in the insulated tanks. For shipments to the USA from Australia or the Gulf, losses of around 4% - 6% can be expected. However, some of the gas otherwise vented to the atmosphere can be used to propel the ship. Korea and Japan expect to benefit mostly from the Sakhalin project and being neighbouring countries will enjoy a cost advantage over the USA. 

Although the liquefaction of the gas enables use to be made of "stranded" gas, remote from its markets, there is a loss of energy amounting to up to 30% of the raw gas feed, depending on the impurities in the gas which have to be removed before liquefaction. The feed gas may contain CO₂ and H₂S, the removal of which leaves the gas wet, so that before liquefaction it has to be dried. Propane, butane and pentane are removed by fractionation leaving ethane and methane to be liquefied. The propane and butane are stored and shipped in separate tanks, while the pentane is injected into crude oil (if it occurs with the gas). 

It may be that some of the remotely occurring gas will be converted to liquid fuels in Gas-to-Liquids plants adjacent to the gas fields in an attempt to ameliorate the shortfall in crude oil feedstock. The problem will be to decide whether it will be more viable to convert the gas to liquid fuels able to be shipped in normal oil tankers or liquefy it for shipping in special LNG tankers to an unloading terminal for re-gasification and addition to a gas supply network. 

UK

UK gas reserves fell from 0.74 trillion cubic metres (4.7 Gboe) in 2000 to 0.66 trillion cubic metres (4.2 Gboe) in 2001,  to 0.63 trillion cubic metres (4.0 Gboe) in 2002, to 0.59 trillion cubic metres (3.7 Gboe) by the end of 2003, to 0.53 trillion cubic metres (3.3 Gboe) by the end of 2004 and to 0.48 tcm (3.0 Gboe) by the end of 2005 and of 2006. So the UK Hubbert peak for natural gas was passed in 2000.

The UK R/P ratio for gas in 2006 was 6.0. The production of 80 billion cubic metres (0.55 Gboe) produced was insufficient to cover internal consumption of 90.8 billion cubic metres (0.57 Gboe), continuing us as from 2005 as a net gas importer.

4. Liquid fuels 

"The Limits to Growth" ¹ main finding was the reduction in the efficiency of capital as resources become leaner and scarcer. The exhaustion of the conventional oil reserves will mean that liquid fuels will become increasingly expensive and beyond the reach of developing nations. It is the breakdown in economic activity associated with a failure to replenish capital that brings the global crisis and the key economic activity of transport will be of the utmost significance.

Liquid fuels are the principle source of motive power for transport, so alternative sources for petrol, diesel and jet fuel are required or other means of propulsion must be developed.

Unconventional oil

It is argued that as reserves of conventional oil run down, more use will be made of "unconventional" oil extracted from oil shale, oil and tar sands and occurrences of heavy oil. 

Oil shales

For example, at one time there was a motive fuel industry in Scotland based on shale oil, but that is long gone. At one time reddish slag heaps created by the extraction could be seen when driving from Glasgow to Edinburgh. There are large shale oil deposits, especially in the United States, but also in Australia. Unfortunately the extraction process is so complex that there is a very limited energy gain (in practice none) and it presents a waste disposal problem. In 2003 a shale oil venture in Australia, called Southern Pacific, failed due to the high costs of production. 

Oilsands

At least 85% of the world's natural bitumen occurs in the Canadian province of Alberta where there are huge oilsands, which it is claimed, amount to reserves of 1600 Gb of oil. The deposits consist of sands impregnated with bitumen, which until now have been exploited by massive excavation of the overburden followed by steam or hot water separation of bitumen from the sand, the tailings from which fill huge ponds. 

New projects use in-situ techniques of slant drilling into deposits which are under 50 metres of overburden which allow steam injection from horizontal pipes into the oilsands deposits to liquefy the bitumen for recovery through a second pipe returning to the surface. Natural gas is also injected to reduce the gravity of the bitumen as an aid to uplifting in the product pipe. This is known as Steam-assisted Gravity Drainage (SAGD) and is being applied in 4 locations. The bitumen has then to be diluted for pumping to a refinery which has been extended to pre-process the bitumen, which is hydrogenated and desulphurised to form a "sweet" crude for normal refining.

In 2002 production was 0.3 Gb of bitumen, rising to 0.35 Gb in 2003, further to 0.40 Gb in 2004, dropping slightly to 0.39 Gb in 2005, but rising to 0.46 Gb in 2006. The non-upgraded balance was sold as bitumen for road surfacing and other purposes. Extraction is costly and energy consuming. Continued capital expenditure is under review and the natural gas used for steam raising, hot water heating and production of hydrogen is in short supply. Although the production of bitumen is rising, the annual production of extracted synthetic crude oil declined from 220 million barrels in 2004, down to 209 million barrels in 2005 but rose somewhat to 240 million barrels in 2006. SCO extraction from the bitumen was 55%, 52% and 52% respectively.

It is estimated that 174 Gb of the 1600 Gb reserves are recoverable, but the yield will be limited by the amount of natural gas available. Of the energy in the synthetic crude oil produced by SAGD, 30% is required in the extraction and processing. If this energy is obtained solely from natural gas as it is at present, the recoverable 174 Gb of synthetic crude oil would consume 8.35 tm³ (trillion cubic metres) of natural gas.

However, the natural gas reserves in Canada total only 1.67 tm³, having peaked in 1984/5 at 2.81 tm³. Assuming that 20% of Canada’s remaining natural gas could be earmarked for oilsands synthetic crude oil extraction, i.e., 0.33 tm³ - only 6.9 Gb of synthetic crude oil could be extracted from the oilsands reserves. This is less than nine month's  crude oil consumption in the North American market - the USA, Canada and Mexico consumed 9.0 Gb in 2005. As the industry is turning to natural gas for synthesis of petrol, diesel and jet fuel, there seems little point in importing LNG to extract bitumen rather than convert the gas directly to liquid fuels. For large trucks the LNG could more readily be converted to compressed natural gas (CNG) for direct use on board. 

The way forward may be to use more of the bitumen as a source of heat. Oxygen or air is injected into the oilsands layer to burn some of the bitumen in order to liquefy and bring other bitumen to the surface. There would still be the need for hot water for separation from the sand and for hydrogen (from methane) for upgrading to synthetic crude oil. This method is under development. 

Cumulative production of synthetic crude oil over the last ten years has amounted to around 2.3 Gb and even if the trend is reversed and it rises over the next few years, limitations in the supply of natural gas will cause a drop in production before 2010. Oil & Gas Journal added 174 Gb from oilsands to the global proved oil reserves, but BP was less sanguine and included only 10 Gb in respect to oilsands in its 2004 figure for proved reserves as being 'under active development'.

See "Canada's tarsands"

Heavy oils

Deposits of around 1200 Gb of bitumen and extra-heavy crude oil occur in Eastern Venezuela, North of the Orinoco River, of which around 270 Gb is considered to be recoverable. Bitumen is extracted from depths of 500 m to 1000 m by directional and horizontal drilling using screw pumps. To reduce its viscosity for pumping it has to be blended with a lighter oil diluent in order to be pipelined to the Orimulsion manufacturing plant, from where the diluent is separated and returned to the production field. Orimulsion is an emulsion of bitumen and water. It can be used in conventional power plants and could free some coal for liquefaction and manufacture of chemicals. 

Synthesis from natural gas

But liquid fuels can be synthesised more readily from natural gas. Unfortunately a gas-to-liquids (GTL) plant suffers from a lack of efficiency in the extraction process compared to crude oil refining. Because of the loss of some of the hydrogen as water and some of the carbon as CO₂, the process has a thermal efficiency of only 55%.

BP established a gas-to-liquids pilot plant at Nikiski in Alaska, which was successfully commissioned in 2003. There was a proposal to run a gas pipeline from Prudhoe Bay to the North American gas grid, to which presumably an enlarged plant would have tapped in, but the pipeline project was abandoned on economic grounds. There is a need to site the conversion plant on or near the gas field in cases where transportation of the gas to the markets cannot be performed by pipeline or shipped as liquefied natural gas, but siting the plant on the inhospitable North Slope of Alaska and sharing the Prudhoe Bay-Valdez oil pipeline was turned down by BP. 

Siting the process on a "stranded" gas field makes use of an otherwise intractable source of energy: the gas-to-liquid process creates more readily transportable end-products directly. Otherwise the low efficiency of the gas-to-liquid process compares unfavourably with using natural gas directly in, say, a combined heat and power generation plant.

Synthesis from coal

Town’s gas once came from coal gasification, one of the by-products being benzole, which was added to petrol. Liquid fuels can also be manufactured from coal tar, but as a by-product of a coal-using industry like steelmaking, the quantities available are minimal. When coal was "king" there was considerable research into coal-based products capable of substituting for oil which at that time was imported.

During the second world war, Germany produced its liquid fuels by synthesis from coal liquefaction. To avoid the effects of sanctions, coal liquefaction has been extensively used in South Africa by Sasol, which still has three plants running. The thermal efficiency of the conversion process is low, possibly as low as 20%. In the USA work is proceeding on co-processing of a crude oil and liquefied coal blend, which can be used as feedstock to a normal oil refinery. Worn tyres are also used with coal for liquefaction.

Electricity generation still uses coal, but gas turbine plants are supplying an increasing share of the demand. Indigenous natural gas which could have been used for the production of liquid fuels has been consumed for domestic and industrial heating and electricity generation. As oil depletes, gas will be increasingly used for synthesis of transport fuels and as gas reserves deplete, recourse will finally turn to synthesis from coal. 

Motor fuel

Trucks and cars can run on liquefied petroleum gas (LPG), compressed natural gas (CNG) or perhaps from liquefied natural gas (LNG), but as these are products of the oil and natural gas industry, this is not a solution in the long-term. Hydrogen can be used in fuel cells to produce electricity for motive power and directly in adapted internal combustion engines.^11,12 Its use has the advantage of producing no carbon dioxide, but distribution and storage at filling stations and on vehicles is problematic. 

Hydrogen is produced either using a fossil fuel, such as natural gas, or by electrolysis. To produce sufficient hydrogen by electrolysis and compression or liquefaction to support the needs of the current volume of road and air transport would require three times the electricity that is currently being generated. For transmission and storage it has to be compressed or cryogenically liquefied using electricity which could be used more directly and efficiently for rail and tram transport. Which ever way hydrogen is produced results in a net energy loss. It takes more energy to produce a fuel in a suitable form for motive power than is contained in it. 

So liquid fuel production will move from oil refining to natural gas processing to coal liquefaction, with perhaps upstream refinery feedstock will come from from all three fossil fuels. To keep everything going, the world’s oil, gas and coal will be used until exhausted to produce liquid fuels.

As oil provides about 95% of the fuel used in transport, the greatest impact of reserves depletion will be on all forms of transport unable to convert to electricity or to make use of the limited amount of bio-diesel from agriculture. This means an increased use of rail and tramways and some electric vehicles. Road transport will be rapidly and progressively attenuated as a series of fuel crises reduce supplies drastically.

Jet fuel

Air transport is totally dependent on jet fuel derived from oil and alternative supplies from gas and coal will be insufficient to maintain it at its current or projected level of activity. To make things worse, as North Sea oil runs out and Middle East oil predominates, so the yield of jet fuel reduces from 25% to 8%-10%. Expansion plans for air transport would require an increase in jet fuel production of 260% by 2030 and will not be realised.

We are about to become a net importer of oil as we are now for gas. Escalating world crude oil prices and the parallel rise in the prices of alternative fuels with little British production to moderate them will mean a drastic reduction in air travel and there will be no need for new terminals and runways. 

See How many air-miles are left in the world’s fuel tank?  

Prognosis

In 2000 transport consumed 25% of total energy in the UK. The proportion of the world’s energy used by transport is projected to reach 50% by 2020, but this assumes no limitation in the supply of energy and the competing energy demands will have to be reconciled to make the best use of a declining availability. What is therefore required is a strategy designed to reduce transport dependency on liquid fuels or to reduce the requirement for transport.

This will be desperately difficult for the undeveloped nations when suffering from drought and famine, with no alternatives to diesel-engined trucks for distribution of aid over the large distances involved. Jet fuel for food "drops" by aircraft will also be expensive for the aid agencies.

5. Energy sources 

To bring the situation into focus Table 2 shows the consumption of energy in the UK in 2004 by sources, based on BP's 2004 Statistical Review.

Table 2 

UK 2006 Primary Energy Consumption

In 2006, overall primary energy consumption in the UK rose 0.13% over that in 2005, 230.6 Mtoe from 230.3 Mtoe. Table 1 indicates that in 2006 around 69.2% (down from 73.0% in 2004) of the UK’s energy was derived from oil and gas and 9% of the UK's oil and 13.5% of its gas was imported. Oil consumption decreased by 2.5% (82.2 Mtoe from 82.9 Mtoe), natural gas consumption decreased by 3.5% (81.7 Mtoe from 85.1 Mtoe), while coal consumption increased by 2.5% (43.8 Mtoe from 39.1 Mtoe).  

Electricity consumed decreased marginally (399 TWh from 400 TWh). About 40% of the primary energy consumed was used for electricity generation. In 2006 indigenous coal supplied 4.9% of the UK energy requirements. The contribution made by renewable energy sources increased marginally from 1.3% to 1.7% of total energy consumption.

What should the UK’s energy policy now be in relation to oil and gas supplies? It might have been sensible to block exports and sacrifice the revenues of the oil exploration companies and the taxes raised therefrom in order to secure a few more years of secure supply. Since oil was available from elsewhere it might also have been pertinent to have suspended UK production, conserving the UK’s limited oil reserves for ameliorating a future crisis. However, this would not have been compatible with the concept that future UK energy supplies rely on a "liberalised" market, particularly in respect to gas from Russia via pipelines routed through the EU. Government intervention of such a nature in a privatised energy market (regulated but not controlled) and with prices lowered by competition is thus politically unacceptable. Given that the UK will is now a net importer of oil and gas and the "liberalised" market is the only option, hopefully the suppliers will be "liberal".

However, in 2002 the government had to rescue British Energy, the biggest private nuclear generator from bankruptcy. In 2007 several advanced gas-cooled reactors have been shut down for maintenance with the occurrence of cracks in boiler tubes and graphite moderating blocks. In these circumstances it is unlikely that sufficient capital will be raised to build new stations or to fund alternative means of electricity generation. Although a "liberalised" energy market has lowered prices, the participating generators cannot be allowed to fail and will draw on public funding to survive. 

A UK government Energy Review renewed in 2007 concluded that nuclear power would only be viable with the allocation of carbon "credits" purchased by emitters of more than their quota of carbon dioxide. Two majority French state-owned companies have express interest in building reactors in the UK, but have insisted on guaranteed carbon credits for the operational life of the stations, amounting to a subsidy.  

On the other hand, 74% of the UK’s coal is imported. At the current production rate the UK coal R/P ratio is 12, but this would be halved without the current level of imports. If having used up our oil and gas, UK coal was used for all the current combined requirements of oil, gas and coal, it would require 300 m tonnes oil equivalent/annum (which is 24 times current UK coal production) and the reserves of 220 m tonnes would last for half a year. It may be that undiscovered coal reserves might be found when required, but from 2015 or earlier, the UK will be almost totally dependent on imports for its fossil fuel requirements. Oil and gas imports will be restricted by increasing global demand for decreasing reserves and prices will rise excessively, so coal will be the only plentiful fossil fuel available for importation.

Energy supplier countries use the revenue from sales to sustain their domestic economies and will not be reluctant to export their oil, gas and coal until, as is about to happen in the case of the UK, internal consumption exceeds production. For example, in Saudi Arabia water supplies for the capital, Riyadh are pumped overland from desalination plants located on the Gulf coast, requiring energy. Unless alternative solar energy plants are introduced, oil supplies for water production will take precedence over exports. In any case Saudi Arabia uses 18% of its oil production internally, up 6% from the quantity consumed in 2005.  Russia consumes 71% of its natural gas production internally, but if hypothetically the current gas demand of the EU countries were to be pipelined from Russia, this would amount to 87% of its current production. It is not difficult to imagine a situation in which Russia's expanding economy consumes all of its indigenous gas production, leaving none for the EU. 

Nuclear power is due to be phased out by 2035 unless the current policy of planned obsolescence is revised, but in any case produces no liquid fuels (other than liquefied hydrogen by electrolysis with compression or cryogenics for storage). Although nuclear power produces 7% of the UK's primary energy, only 40% of this is usable as electric energy and if used for hydrogen electrolysis and liquefaction the resultant motor fuel is only around 20% of it, or less than 2% of the UK transport's requirement.

Dependency on oil and gas could be relieved by developing coal technology for producing liquid fuels and chemicals. The restoration of the coal mining industry is questionable, as is the possibility of increasing its output by a factor of 24. Even so, the creation of a coal liquefaction industry based on some expansion of UK coal mining and on coal importation is the solution most likely to succeed in the long term.

Fortunately, there has been a move from high energy-using heavy manufacture to service industries over the last 30 years. Steelmaking capacity has halved over the last decade, relieving demand on energy and reducing pollution. This has benefited regions like Strathclyde once dependent on heavy industry, which has boomed in prosperity since the polluting industries have largely disappeared, allowing science-based and service industry to prosper.

However, many of the heavy industrial products we need now come from abroad. Because of a shift to the Far East of so much manufacturing, some heavy industry will have to be retained or re-established, perhaps fuelled by coal or coal gas once more.

There is already recognition that sustainable and renewable forms of energy are required and a start in establishing wind farms and just one tidal system has been made. However, serious investment in these and other technologies is needed now, before the ability to raise the capital is lost. Even so there is little chance that alternative energy sources (reviewed below) will match the shortfall from non-renewable sources, so life will have to be reshaped to use less energy. In any case most alternative technologies provide electricity, with only bio-diesel as a significant liquid fuel.

It is planned to supply 20% of electricity from renewable energy by 2020, but from thereon further sites for wind farms will be difficult to find. This represents around 7.5% of the current total energy consumption. If imported coal makes up the loss of that currently supplied from the indigenous coal industry (which is being allowed to decline) a further 17.5% of current energy consumption could be found, totalling 25% of what is currently consumed. 

Thus with the dwindling of global oil and gas reserves, international competition for supplies of coal, the demise of the indigenous coal industry together with the gradual termination of nuclear power mean that in order to be secure from the consequences of external events, the UK has to rearrange its economy to run with only around 25% of its current energy consumption.

Alternative energy sources

Biological energy

This requires a two-pronged attack. First, the crops for the creation of a renewable source of energy must be planted. Forest products can be used for direct-firing, e.g. willow can be grown for combustion. Wood can also be grown for the creation of wood alcohol. Vegetable oil from oilseed crops with alcohol distilled from sugar beet can be processed with a catalyst into bio-diesel.

The second is for the industrial base to be developed. There are now several power stations burning broiler litter and willow. The need for incineration of animal wastes (now no longer processed as animal feed) can be assisted by augmentation with domestic rubbish and used for electricity generation.

Obsolete sugar refineries can be converted to alcohol production. Currently many may be demolished as sugar consumption dwindles resulting from health campaigns. Urgent action to avoid dismantling is needed.

Also breweries and distilleries could be converted for industrial alcohol production to supplement liquid fuels and provide a component for bio-diesel. For motive power a liquid fuel as an alternative to diesel is required and alcohol can be used in modified engines directly or as an additive to petrol.

Bio-diesel can be produced from vegetable oils with some alcohol. This would also provide an alternative tractor fuel and an activity for farmers in place of animal rearing. It would also provide associated industrial processing activity. The limitation is the amount of land needed to grow sufficient rape seed for oil extraction. 

Agriculture requires 1.4 million tons oil equivalent for motive power. Around 500,000 hectares are currently devoted to growing rape as an agricultural product and around 1,500,000 additional hectares would be required for rape and beet cultivation for the processing of sufficient bio-diesel to make agriculture self-sufficient in motive power. This represents around 8.5% of the agricultural land in current use. This needs to be balanced against other demands on the same land, but some of the set-aside could be re-employed.

Alcohol is cheaper if produced from sugar cane rather than beet, as the bagasse can be burnt to provide steam for distillation. Rape oil can be augmented by importing other oils such as palm oil, but these will have a transport premium.

Landfill gas electricity generation already makes a valuable contribution of more than 4 TWh per annum or 1.2 % of national electricity consumption. This is likely to continue for 10 years or so, depending on waste management policies. Landfill sites are progressively harder to locate and an increasing amount of recyclable material is separated in an attempt to reduce the amount disposed in landfill. The remaining waste should have a higher proportion of fermentables and could perhaps be handled in large enclosed vessels to allow methane generation. 

Geophysical energy

Powerful geophysical forces can be harnessed to provide clean and sustainable sources of energy. Wind, waves, the lunar energy of tides and solar energy (direct and including evaporation creating rainfall) are already harnessed for electricity generation, but much more can be done. It ought to be possible to provide the equivalent of nuclear power generation from geophysical sources, matching its phasing-out.

Hydro-electricity is the most established form of water power, but only provides around 0.8% of the UK's energy requirements, compared with New Zealand where the contribution is 30%. As the timings of wind, rain and sun are in a random fashion, more pumped storage systems are needed, whereby water is raised to an elevated reservoir when surplus electricity is available and the head of water is used to augment generation at peak times. 

There may yet be more opportunities for water power, perhaps even in rivers. For flood protection (See 17. Climate) large pumping stations associated with a national water grid are envisaged to take excessive water from rivers. In low lying areas where the siting of reservoirs is impractical, excess water from the national grid could be pumped into off-shore lagoons for generating electricity when emptying into the sea, thus recovering some of the energy used for alleviating flooding.

Wind power is harnessed by the installation of wind generators, often clustered in "wind farms". They are opposed because of their visual impact and noise from the revolving blades and many are consequently planned off-shore. There are also objections to off-shore wind farms because of the potential danger to birds. However, this is the only currently available substantive method of power generation able to provide up to perhaps 20% of the current energy consumption. The turbine towers could be utilised as water storage tanks for individual pumped storage systems or associated with a nearby reservoir for a wind farm collective system. This would have the benefit of evening out the transmission capacity needed.  

Wave power has potential but is undeveloped. There are sea-based types which make use of the energy from sea swell and shore-based systems which use incoming waves to force an air current through a shore-based chamber in which a counter-rotating turbine makes use of the bi-directional air flow to generate electricity. Both suffer from the damage caused by the wave forces they are attempting to harness.

More use could be made of tidal power, which in contrast to wind and wave power is predictably available in accordance with tide tables. At one time tide mills in association with tidal ponds were common. A working example can be seen at Woodbridge in Suffolk. It would be possible to create off-shore tidal lagoons with similar technology to that employed to create the Brighton Marina with interconnected caissons to form an enclosure. Electricity is generated during filling and emptying through turbines as the tide flows and ebbs. Estuarial barrages also make use of tidal flow and ebb, but cause problems for river navigation and to fish.

A better way to harness tidal power is a system of undersea turbines currently under test ¹⁵. The turbines are below the surface where they are unaffected by bad weather and placed in current streams at places where the tidal flows are enhanced by the underwater topography. They are free from the environmental concerns of off-shore wind farms as they have a low above-surface profile - no more objectionable than a large buoy. 

Solar power is useful for small users such as communications, but is too capital intensive to be a universal provider of electricity. The large surface area required means that only very light vehicles can be propelled and movement of heavy goods is not feasible. However, there are plans for a massive solar power initiative named "The Trans-Mediterranean Renewable Energy Cooperation" (TREC) which envisages the installation of massive solar thermal power plants in the North African deserts with transmission lines crossing the Mediterranean. 

Geothermal energy is obtained from hot rocks underground, often seen as as geysers and hot springs in volcanic regions. The prolific use of volcanic rocks in Iceland for district heating and power generation is unlikely to be repeated here, but there are buried heat resources that can be used for heating buildings. It requires water to be pumped through borehole circuits. As an example of this in the UK, a school in Cornwall is heated by this method.

So wind power being fully developed and universally applied is the most likely successor to fossil fuels, but only in connection with a drastic reduction in energy requirements. Marine current tidal power once developed has the potential to provide a similar contribution.

Methane hydrate

Methane hydrate belongs to a group of compounds known as clathrates. A clathrate is formed when molecules of one type form a lattice structure around a cavity, while molecules of another type are inside the cavity. A methane hydrate is a cage-like lattice of ice containing methane. The molecules of water create a crystalline structure holding methane molecules via hydrogen bonds to the oxygen atoms of the water. They were found to be naturally occurring in a Siberian gas fields in a frozen form and later in ocean sediments.

Methane hydrate has been seen as a possible energy resource with enormous potential. However, it has  proved difficult to extract a viable sample. As soon as temperature rises or pressure is released the methane is released from the ice lattice and dissolves in water or escapes to the atmosphere. Moreover the occurrences are discontinuous and it is now seen as an unreliable source of energy.  

Viability of alternative energy sources

If fuel prices are kept low for political reasons, the current viability of alternative energy systems may not be at a level able to attract private investment. Rather than subsidise the introduction of new energy sources with EU funding, as is the case now, it would be better to apply the escalator on fuel tax in order to increase private funding of alternatives. Tax on substitutes should be lower than that for petroleum-based fuels or removed altogether as a further incentive. In the April 2002 budget the tax on bio-diesel was cut by 20p compared to the standard diesel rate, but this is of no benefit to agriculture which already has "red diesel" with minimal duty. A similar cut in bio-ethanol duty was announced in the April 2003 budget.

There is a more fundamental assessment needed when considering alternative energy systems, viz., the ratio of energy inputs required to build, supply and maintain the system to the energy output over the plant life cycle. Systems must therefore be rated in terms of this ratio and those with the lowest input/output ratios preferred. Hydro and wind power offer the lowest inputs of around 7% of their lifetime outputs, with similar disputed claims for nuclear power (See below). Photo-voltaic solar power requires high energy inputs during manufacture and only qualifies for specialist low power users, such as remote telephones and calculators. One form of photo-voltaic generation requires a higher energy input than the output obtained.

The energy inputs are mostly reliant on liquid fuels with global warming consequences. For example maintenance of wind generators requires the use of mobile cranes to access elevated components. These are currently run on diesel, although it would not be impossible in a wind farm to drive an electrically driven crane from the other generators. Unless carefully considered and organised accordingly, alternative energy systems will contribute to global warming by requiring fossil fuel inputs. 

Nuclear power

The costs of producing the uranium fuel was covered mainly by the atomic weapons budget, as is the continued use of energy in storing and handling the waste material. When privatised, the state retained the uneconomic supporting infrastructure, but imposed a levy on the generator, British Energy, of £300 million/annum as a contribution to the costs of re-processing and waste disposal. In a liberalised market with natural gas allowed to be used for electricity generation and with this levy, nuclear power could not compete and in 2002 had to be financially supported by the government. "Nuclear liabilities" of more than £5 billion were taken over by the government in return for an equity share in British Energy, some of which has subsequently been sold, leaving the government shareholding at 35%.

As nuclear power generation theoretically creates no "greenhouse gas" the industry hoped to benefit from the imposition of carbon tax on others. ¹³ But the uranium mining, ore milling and processing, the fuels used by the civil engineering in building a nuclear station, the manufacturing and construction of the equipment do, as does the mining for waste disposal, so it cannot claim full immunity from a contribution to global warming. Also the de-commissioning and demolition of a station can take decades of which the latter also has to be performed with mobile machinery needing liquid fuels.

The energy inputs required by nuclear generation come under five headings:

• Energy required for plant building and operation 
• Energy for mining, refining and enriching uranium ores
• Energy for dealing with mine tailings
• Energy for conditioning used fuel elements prior to sequestration
• Energy required for sequestration of radioactive spent fuel
• Energy required for decommissioning and dismantling

The industry rates the sum of these inputs to represent around 9% of the life cycle output of a typical nuclear station, while opponents argue that a figure of 70% is applicable.¹⁴  The main source of contention is the energy used for mining, milling and enriching the uranium ores which requires the burning of fossil fuels and the release of "greenhouse gas". The expenditure of energy in the first two processes depends on the ore grade and as the richer ores are extracted it rises to a point where the additional energy required for the processing of leaner ores means that in its life-cycle a nuclear station could produce more CO₂ than an equivalent gas-burning plant.

Perhaps of more significance is the availability of ores of a high enough grade to support nuclear generation in the long term. Once the richer ores are exhausted, the energy input/output ratio worsens to a point where the "greenhouse gas" advantage over fossil fuels is lost and the energy produced is less than consumed. 

By considering only those ores of an "energy economic" grade a global R/P ratio (Reserves/Production ratio) can be derived for nuclear fuel. If the energy used in producing a particular generation rate is subtracted from it and this is related to the amount of uranium consumed the industry claimed R/P ratio of 50 for the current global generation rate is effectively reduced to 15. If hypothetically all electricity were to be provided by nuclear power, the R/P ratio reduces to 3. Thus the nuclear power industry is subject to the same resource attenuation as all other activities highlighted by the "Limits to Growth"  ² and is not sustainable. 

In 2006 and in 2007 the UK government in successive energy reviews decided that nuclear power is only viable if able to "sell" its carbon "credits" to carbon emitting equivalents in the emissions trading system (ETS). A White Paper was issued in 2008 in which the private sector was invited to build an undefined number of new stations with no government subsidy other than the issuing of the carbon "credits". The most likely  nuclear power station builder, EdF realised that such credits would depend on the continuation of fossil fuel combustion providing an ability and need for the purchase of the credits. As fossil fuels are running down it requested that such credits should be of a guaranteed value for the duration of the projects, which is at least the 60 years operational cycle. 

A factor in the decision was the reduction in "greenhouse gas" emissions falsely claimed by the industry, so the question of ore grades and reserves should have been taken into account. In the case of the currently operating nuclear reactors, the energy involved in their construction and in providing the stock of uranium fuel is already expended. So the policy most evident is to fund the losses of the industry until the existing reactors have completed their useful life. However it is likely that all seven of British Energy's Advanced Gas-cooled Reactors (AGR's) will be closed prematurely as the graphite moderating blocks are disintegrating, which could compromise safety by preventing the dropping of control rods into channels filling with debris.

There is no case for building more nuclear power stations, because mining production of the higher grade ores is insufficient to support more than half of the existing reactors and if recourse had to be made to the lower grade ores, as is suggested by the industry to make up for the deficit, then over their life cycles they would consume more energy than they could contribute and release an equivalent amount of CO₂ to that from a gas-fired station of the same output or more. They will simply add to the legacy of de-commissioning and waste handling, demanding an energy expenditure when energy will be at a premium.

Primary uranium production in 2006 was only 39,700 tonnes. For the current level of nuclear power (10 EJ) the uranium demand of 66,500 tonnes had to be met by topping up the production from mines with so-called secondary sources, such as inventories, ex-weapons grade highly enriched  uranium, MOX and re-worked tailings. For all electricity generation (65 EJ) to be from nuclear power, 400,000 tonnes/annum of uranium would be required. 

The substitution by nuclear power of the primary energy derived from the combustion of fossil fuels needs special scrutiny, because in its use the electrical energy generated is not directly usable on road or air transport and although it can be applied to rail or tramways with fixed conductors, it would have to be used for electrolysis for the production of hydrogen and for its compression or liquefaction. Assuming that around 40% of the energy produced would be used for motive power and taking into account the conversion energy needed, the present global primary energy of 440 EJ would require electrical generation of 700 EJ.  

This would require production of 4 million tonnes/annum of uranium (exhausting the entire global reserves in a year) to fuel 22,000 nuclear power stations of 1 GW(e) capacity (32 PJ). The idea that nuclear power can solve the coming energy crisis is therefore totally fallacious.

Moreover, nuclear power stations present a deadly target for terrorist attack with potentially unimaginable contamination consequences. The high costs of building nuclear power stations are likely to rise with demands for increased security, requiring a greater construction energy input. To augment the supply of uranium ores, part of the current inventory of the plutonium created as a by-product of nuclear reaction is to be processed at Sellafield as reactor fuel (MOX), though the proportion of fuel obtained is less than 5% of the total required. As the most poisonous substance known to man, the handling of plutonium requires extraordinary care and the use of it is controversial.

Nuclear sustainability depends on the breeding of new fuel in a number of breeder reactors. There is no commercially available fast breeder reactor, which in any case requires a facility for manufacturing plutonium fuel and a processing plant to separate the bred plutonium from the depleted uranium "blanket". There is little chance of such a tripartite complex being developed without inter-government financial support and while the nuclear industry falsely claims that there is no uranium fuel supply problem it cannot concurrently make a case for such an intervention, which in any case, as have previous attempts, is certain to fail.

It would be better to reduce energy requirements rather re-establish an industry with such a potential for menace to public life and the viability of which is subject to doubt. (See "Why nuclear power is not the answer to global warming")

Hydrogen

Thermal properties and production of hydrogen

The higher and lower calorific values of hydrogen are:-

Higher heating value (HHV)  = 142 MJ/kg = 39.4 kWh/kg

Lower heating value (LHV) after latent heat is subtracted = 120 MJ/kg = 33.33 kWh/kg

The lower value is obtained by combustion in an engine. Hydrogen does not occur naturally and has to be extracted and processed before it can be used as a transport fuel.

There are four processes, viz.,

  (i) Steam reforming of methane

 (ii) Electrolysis of water

 (iii) Compression

 (iv) Cryogenic liquefaction.

 These can be combined as             (i) and (iii) or (i) and (iv)

or (ii) and (iii) or (ii) and (iv)

 (i) Steam reforming of methane

Hydrogen can be extracted from methane by steam reforming in two stages. 

2CH₄ + 3H₂O = CO + CO₂ + 7H₂ and CO + H₂O = CO₂+ H₂

32 kg methane with 72 kg steam yields 16 kg H₂ and releases 88 kg CO₂, but the process is only 70%-90% efficient, so the yield is reduced to 12.8 kg. Assuming 80% efficiency,  2.5 kg methane (2.5 x 55 MJ = 137.5 MJ) is needed to yield 1 kg hydrogen (120MJ) while releasing 7 kg CO₂. The 7 kg steam required contains 24 MJ total heat, bringing the input to 161.5 MJ/kg or 45 kWh/kg. 

The equivalent power used to obtain the energy of 33.33 kWh/kg in the hydrogen is 45 kWh/kg and 7 kg of CO₂ is released. Thus more energy is used to extract hydrogen from the methane than obtained in it. 

(ii) Electrolysis of water

Electrolysis can consume between 3.7 and 4.5 kWh/Nm³ of hydrogen, which taking the mean is gravimetrically 58.6 kWh/kg (Say 59)

(iii) Compression

The energy used to compress hydrogen to a suitable storage pressure is around 12% of the HHV or 0.12 x 142 MJ/3600 KJ = 4.7 kWh/kg (Say 5)

(iv) Liquefaction

For large scale plants the energy used to liquefy hydrogen is around 40% of the HHV or 0.40 x 142 MJ/3600 KJ = 15.8 kWh/kg (Say 16)

(ii) + (iii) 59 + 5 = 64 kWh/kg

(ii) + (iv) 59 + 16 = 75 kWh/kg

Equivalent quantity required for UK transport in 2002

Cars use compressed hydrogen (Honda) or liquefied hydrogen (BMW and GM) while aircraft will need to use liquefied hydrogen because of weight and space requirements. 

An effective energy content of 120 MJ/kg H₂, means that vehicle energy of 1680 PJ (equivalent to 40 million tonnes /annum of petrol and diesel) would require 14 x 10⁹ kg H₂/annum, while aircraft energy of 546 PJ (equivalent to 13 million tonnes of jet fuel) would require 4.55 x 10⁹ kg H₂/annum.

This works out at 14 x 64 x 10⁹ = 896 TWh for compressed gas

and 14 x 75 x 10⁹ = 1050 TWh for liquefied gas.

For aircraft it works out at 4.55 x 75 x 10⁹ = 340 TWh

For the UK this means that to substitute for the 2002 level of road and air transport fuel by hydrogen would require from 1236 TWh to 1390 TWh of electricity generation, compared to the total UK generation of 400 TWh in 2005. 

While in the future a favoured minority will use hydrogen-propelled road vehicles, this would be such an inefficient use of renewable electricity that road transport will be substituted by rail (which can use electricity directly in traction engines). The establishment of a global hydrogen infrastructure for air transport seems an impracticable prospect. A tripling of global air traffic envisaged by 2030 would require electricity generation of 7000 TWh to be able to substitute liquid hydrogen for 260 million tonnes of jet fuel, which by then will be unavailable in sufficient quantities. 

Exhaustion of non-renewable energy resources

The UK probably still has oil and gas reserves under the continental shelf, but the retrieval on the Atlantic side will be progressively more expensive the further round the North coast of Scotland exploration progresses.  The increase in crude oil price is not leading to an increase in exploration and development of new oil fields by the oil majors, but in the acquisition of companies with reserves holdings or in gas ventures.

The UK coal mining industry has declined and more than half of our requirements are imported, UK coal reserves have been conserved. At the 2005 production rate the R/P ratio was only 11. If as a hypothesis the UK was in siege after 2010 and indigenous coal had to be used in substitution for imported oil and gas (and assuming the liquefaction processes were available) it would last for only a few years.

The world has large coal resources, with a R/P ratio in 2005 of 155 (cf. oil 41 and gas 65). As oil and gas production rates approach their "Hubbert" peaks in 2010 and 2020 respectively, coal resources will be utilised at a greater rate in substitution for liquid fuels and chemical products. Also the thermal efficiency of coal liquefaction process is around half of gas-to-liquids equivalents, increasing its demand enormously. If, hypothetically, coal provided for the combined world 2005 production rates for oil, gas and coal, its production would peak around 2040 to 2050, tailing off thereafter, indicating that fossil fuels will not outlast the century. 

Growth in demand for oil and gas is rising exponentially. Combined world production of oil and gas in equivalent units rose by around 1.50%/annum from 1990 to 2000, but from 1999 to 2000 it rose by 4%. The recession in the USA, now over, held oil consumption at its 2000 level in 2001, but gas consumption, having fallen somewhat in 2001, rose again in 2002. Strong economic growth in China, India and the Far East is likely to continue until restricted by emptying reserves. Unfortunately, as  reserves approach exhaustion, demand is accelerating, bringing the emptying of the reserves ever nearer. Over the last five years oil consumption has increased by 11% and gas by 14%.

Table 3 lists the achieved annual production rates in Gb/annum oil equivalents. The figures given refer to those extent at the end of each decade. Those for 1980, 1990 and 2000 are obtained from the BP statistical review of world energy 2001 ⁶ ands nclude all oils. The remainder are derived from extrapolating trends in demand growth and making assumptions on the rate of new discoveries which add to reserves. Since world production platformed to around 27 Gb/annum in 2000, 2001, 2002 and 2003, the peak of 30Gb/annum forecast in 2010 is unlikely to be reached and supply may never again match demand.

Table 3                

The table is illustrated in the chart below. As oil production reaches its peak in 2010, gas is used to take to make up the shortfall in liquid fuels. As gas passes its peak production in 2020, coal is used by liquefaction to allow liquid fuels to be available in the period 2020 to 2040. Thereafter coal also passes its peak production in 2040 and by the end of the century, all economic fossil fuels resources have been exhausted.

The UK government’s "The Energy Review" ⁹ issued in 2002 anticipated an "increasing scarcity" of oil after 2020 and increased dependence on supplies from the Middle East. The review concentrated on the risks associated with imports of gas from the Former Soviet Union and the Middle East, but failed to anticipate the use of gas for the synthesis of liquid fuels instead of the so-called "unconventional" oils which will remain largely unexploited.

Natural gas is increasingly utilised for electricity generation, but the escalating demand for liquid fuels for air and road transport will depend on the use of gas in substitution for oil as a source of jet fuel, petrol and diesel. The increasing demands on all uses of gas will bring forward its "Hubbert" peak, so that a peak in gas production in 2020 will follow that for oil in 2010 more closely than anticipated.

The investment made by the industry will be directed more towards utilising gas resources directly, rather than indirectly for the extraction and hydrogenation of bitumen and heavy oil. As normal refineries can handle liquefied coal as a blend with crude oil, the use of coal will then take precedence over the use of synthetic crude oil from oilsands bitumen, so that coal production will reach its "Hubbert" peak around 2040 and the economic extraction of fossil fuels may not survive the century.

It is not just a question of the availability of fossil fuels: it is also the efficiency of the capital employed in exploration, recovery and conversion to useful derivatives. The developed nations will adjust (whether by policy or by force of circumstances) to a different lifestyle, but the undeveloped world will stagnate. This was the key factor in the catastrophe forecast by the "The Limits to Growth" ¹ in the latter half of the 21^st Century, when "because of nonrenewable resource depletion ….. investment cannot keep up with depreciation, and the industrial base collapses".

The following chapters look at aspects of UK life and recommend adjustments aimed at securing the UK’s survival in this century.