In the pipeline?

The future of oil is not as gloomy as some would have us think – if only the industry would come up with new extraction techniques now. Rob Coppinger reports.

Oil doomsday, when the supplies run out and the fighting starts, is far from inevitable – but only if the global energy industry raises its game on the adoption of new technology, according to leading experts in the field. The oil industry needs to speed up the rate at which it adopts new technologies in areas such as deep-sea extraction or face a crisis within 20 years.

The public has been told for years that we have only a few decades before the earth’s oil runs out. This has always been untrue. There are an estimated 11 trillion barrels-worth of oil in the earth, compared to the one trillion used since the oil economy began in the 19th century. However, economics have always prompted oil companies to open new wells rather than extract the entire reserves of the first one.

The problem is developing the technology to get at it in an efficient enough fashion that it remains economically viable to meet the world’s voracious appetite.

Some within the petrochemical community are worried that the risk-averse, conservative – and notoriously secretive – industry is not moving fast enough to develop the technologies needed to extract more oil before the current readily available supply of about three trillion barrels dwindles.

Its progress in developing ways to find untapped oil reserves is, as we shall see, reasonable. Its record in the area of developing new, economically viable extraction and processing capabilities is less impressive.

Prof. Martin Blunt, head of the petroleum engineering and rock mechanics research group at Imperial College, London, is concerned about the lack of action by government and industry to face up to this challenge. ‘In 10 to 20 years there could be a crisis because there isn’t so much cheap oil,’ he said.

‘I think we have a short-term economic outlook and we’re not moving to a less oil-based society. So there will be a shock because of a problem between supply and demand. In 10 years if oil prices are shooting out of control with no planning for energy efficiency you’ve got a major problem.’

‘Seabed technology could be a way of getting round the ice problem in the Arctic,’ said Andrew Palmer, professor of petroleum engineering at the University of Cambridge. ‘It could be done but it is very expensive. It’s not a technology that is needed but it could be developed in 15 years if somebody wanted it.’

The challenge, then, is to extract more oil and gas, more cost-effectively, or face a major economic crisis.

The US Department Of Energy estimates that advanced technology could increase oil recovery by at least one million barrels a day by 2015. Technologies such as deep and ultra-deep water drilling, working at depths of up to 1,500m, is seen as vital to a continued supply of economically viable oil.

A DOE report, Offshore Technology Roadmap for the Ultra Deep Gulf of Mexico, put it bluntly: ‘Acceleration of ultra-deep water development is essential to the future stability and security of US energy supplies.’

The vision of the future set out by the US planners would transform sub-sea oil wells into technology-rich factories on the ocean floor. Remotely operated, they would use robotics technology to enable oil and gas wells to be drilled and maintained economically deep below the sea. They would produce ready-to-use fuels close to the source of the well, avoiding the costs of transportation, storage and fluid processing at major surface facilities.

At its most ambitious, electricity would be generated offshore and the power moved to a national network, while exhaust gases would be reinjected into the reservoirs from which they were produced. In short, an alluring vision of a super-efficient, self-renewing enclosed energy system.

But all this presupposes that the industry is moving quickly enough to embrace the type of deep-sea technologies needed to make the vision a reality.

Working on the seabed presents engineering challenges in some of the harshest conditions imaginable. Electronic systems that can function happily on land, for example, are hugely more vulnerable to failure on the ocean’s floor.

David Appleford, managing director of UK engineering firm Alpha Thames, spent more than a decade trying to persuade the oil industry to adopt the seabed processing system developed by the company. The module is designed to sit on the seabed and separate oil from water and other impurities at the well head. Finally, a division of Shell agreed to trial the technology, which its developers claim could reduce the cost of oil production by carrying out vital separation processes on the seabed rather than the surface.

According to Appleford, part of the reason for the long delay was the innately conservative nature of the oil industry, which is in many cases wedded to the traditional way of doing things. ‘It’s an uphill battle to introduce new technology into such a conservative industry,’ said Appleford. ‘You have to fight every step of the way to get the support you need.’

If Alpha Thames’s system passes its Shell testing process it will be available for the oil giant, and the rest of the industry, to use. Even then, Appleford believes it may not be out of the woods. ‘These are huge companies, and even when you have won acceptance you are still up against conflicting internal interests,’ he said.

It took Appleford and Alpha Thames 12 years of relentless door-knocking to get their technology to the top table. If that is replicated by a seabed technology emerging now, it will be running tight up against Blunt’s 10 to 20 year timetable.

In the past, given the difficulty of extracting more than 30 per cent of the oil in any one field, the industry has found it more convenient to look for new fields rather than continue to produce from mature wells. But that is changing out of necessity,according to Mark Holtz, petroleum engineer for the University of Texas’s Bureau of Economic Geology. ‘I think there is a focus on getting more out because it’s getting more and more difficulty to find super and giant fields. Many of the larger independents certainly do that: extract more.’

One example he gave was the Barnett shale rock field in northern Texas. This had produced oil for many years, but further seismic analysis of the well found that gas was held in another part of its shale. The firm that exploited the well, Oklahoma-based Devon Energy Corporation, used water injection to generate fractures in the shale, increasing permeability and driving out the gas.

This use of repeated seismic analysis is a new trend in the industry, and points to a growing awareness of the need to get more from the fields we know about. For decades finding oil has involved exploding charges and recording and interpreting the sound echoes that are returned by the rock strata deep beneath the engineer’s feet. The industry is now using computing technology to carry out seismic surveys that visualise the rock strata graphically in 3D.

According to Holtz, this advanced processing of seismic data is crucial. One method uses neural networks that are trained to relate seismic attributes to what are termed petro-physical characteristics of the rock strata. The neural network generates a 3D model showing the likely location of oil and gas based on that initial seismic data.

The repeated analysis over the life of a well is known as time-lapse seismic surveying. It enables companies to identify areas of bypassed oil and barriers to extraction and to monitor production efficiency. It is expected to improve incremental recovery by up to seven per cent, and accelerate the rate at which it can take place.

Other significant remote sensing tools include gravity surveying. This identifies how fluctuations in local gravity levels are related to the presence of hydrocarbons. Electromagnetic monitoring examines changes in the Earth’s magnetic field, also due to the presence of oil and gas.

Then there are geophones – sophisticated microphones that pick up the seismic noises. These previously would have been placed temporarily around the well but in the future there could be permanent surface geophone grids for the many seismic surveys over the well’s life.

Once they are located the oil and gas have to be pumped to the surface. The US DOE has various programmes, in co-operation with the industry, to develop technologies for this in a three-stage process divided into primary, secondary and tertiary recovery.

Primary is where oil and gas pressures naturally force them to the surface. This will recover only 20 per cent of the hydrocarbons. The secondary involves techniques to drive oil or gas to the surface, usually with water injection. But gas is also used, including carbon dioxide. CO2 has attracted more attention in recent years due to the need to stop it getting into the atmosphere. Its burial, referred to as sequestration, has been the subject in the UK of a DTI feasibility review, announced by energy minister Brian Wilson last September. An implementation study is due for completion at the end of this year.

That review’s manager, Brian Morris, has already said that, so far, implementing sequestration has looked prohibitively expensive. And this view is echoed by DTI consultant Philip Sharman, who has worked with the department’s Cleaner Fossil Fuel Unit: ‘Though it could be used to increase North Sea oil output, the viability of pumping the gas offshore is dependent on oil prices and the amount of CO2 required to extract each extra tonne of oil.’

However, the DOE continues to study it, and oil giant ExxonMobil is funding a study at California’s Stanford University that is focusing on sequestration.

Whatever the future of CO2, the growing need to extract more from existing wells means that tertiary technologies are becoming a focus for research. The tertiary recovery process involves thermal, chemical and microbial techniques.

The thermal process involves steam flooding the well. This is already being used in California where the oil can be heavier and more viscous. The steam heats up the oil, increasing its fluidity to make it easier to recover. The chemical method involves adding soap-like compounds to the water. These are able to bond to the oil, unlike water, and help to ‘sweep out’ the oil from the fractures. Another variant involves injecting microbes into the reservoir to help break down the heavy oil. The microbes can also produce CO2 to aid with the oil breakdown.

All these developments may go a long way to assisting the recovery of more oil. However, the will to develop a wide range of technologies that can enable them to operate effectively, whether at the bottom of the sea or in the Arctic, remains the key. As ever with the oil industry, development is inextricably linked with economics.

According to some experts, oil price rises could actually be the solution. Prof. Palmer said that when increased prices bring a flow of cash into the global industry investment in technology tends to follow.

Seabed technology, he said, could offer an array of solutions to problems facing the industry, for example in oil-rich arctic regions. ‘It could be done but it is very expensive,’ said Palmer, adding that such technologies could be developed within 15 years – but only if the oil industry wants them.

Others have a touching faith that everything will turn out alright in the end. Bill Severens, research director for digital exploration and production strategy service at consultancy Cambridge Energy Research Associates, said the oil industry will come up trumps. ‘I think the industry has a knack, that when the economics are there it allocates resources to bring the technology into being. The question is only how and when.’

That is a big question. The answers will be important for all of us.

Sidebar: The Geopolitics of ‘black gold’

Since the oil age officially began in 1859, the world is estimated to have consumed around one trillion barrels of the ‘black gold’. ExxonMobil expects another trillion to be consumed by 2020, and that rate will continue to accelerate due to world economic growth.

But the developed western economies are not expected to retain their position as chief consumer. On existing world growth projections provided by ExxonMobil, developing countries will overtake the OECD nations in terms of energy consumption by 2010. This is because while OECD members average two per cent growth per annum, the developing world achieves twice that.

What this means in terms of the ongoing global struggle for access to supplies is largely in the hands of the politicians. But it inevitably points to a need for more oil.

According to BP’s Statistical Review of World Energy June 2003, the world economy currently needs 75 million barrels of oil every day. Proven oil reserves are believed to be one trillion barrels. Proven means that nations and companies are prepared to agree that they definitely exist and can be economically retrieved with currently available technology.

The US Geological Survey estimates, however, that total world oil reservoirs amount to seven trillion barrels of oil. It states that two trillion oil barrels can be economically extracted today and for the foreseeable future, leaving five trillion for future technologies currently in development.

But these account for only what are known as ‘conventional’ oils. There are also heavy oils, known as ‘unconventional’ oils, and the US Geological Survey estimates the world has four trillion barrels of these, making a grand total of 11 trillion barrels.Despite the many theories that a future fuel crisis is looming the history of oil exploration suggests that known reserves will grow rather than shrink.

According to Oil and Gas Journal, in 1980 the world’s total proven oil reserves amounted to just 642 billion barrels. Twenty years later that had doubled to about a trillion. Whatever level the reserves stand at 30 years from now, the geopolitics is unlikely to change.

For many decades to come the political centre of the world’s energy supply will be the unstable areas of central Asia and the Middle East. Although ExxonMobil expects West Africa, Russia and the Caspian Sea to be major oilfields in the 21st century the Middle East will still dominate.

The US DOE states that the reserves of both oil and gas are clustered in just a few regions of the world. Middle Eastern countries have well over half the proven oil reserves, while the former Soviet Union, Iran and the tiny Gulf state of Qatar account for 60 per cent of proven gas reserves.

Sidebar: The unplumbed resources of global oil supplies

Developing the technology for oil and gas discovery and extraction requires an understanding of the rock strata within which they are found. This area of studyis called geo-mechanics or rock physics.

Oilfields are not, as some might imagine, underground lakes of black liquid which can be drilled into and extracted. Most of the world’s oil is mixed in with what is known as fractured chalk rock, but sandstone is also common.

A fractured rock is a stratum with cracks in it – essentially a porous rock full of oil and gas. The fractures are important, because they mean the stratum is permeable to oil and gas. The higher the permeability the better suited the field is for extraction.

Yet however permeable the stratum, extraction remains a major, ongoing technical challenge even for oilfields that have been producing for decades.

None of the oilfields that have been opened since the beginning of the current age of oil exploration has been emptied, despite breakthroughs in drilling technology that now enable drills to bore into a field at any angle.

The oil industry is notoriously secretive about the technologies it hopes will bring about the big breakthroughs that will allow it to squeeze the last drop from the world’s reserves.