86 per cent of reserves are off limits
To make matters worse, 86 per cent of the world's oil reserves are held within Opec and former Soviet Union countries, which aren't generally welcoming to western investors. "International oil companies (IOCs) such as Shell and BP just don't have access to regions where many of the remaining easy-to-produce hydrocarbons are located," says David Hart, oil and gas analyst at broker Hanson Westhouse. "They have access to regions that are challenging or difficult in one way or another – more inhospitable environments and geographies. It's not like drilling in Saudi Arabia, which is relatively straightforward."
Easy-to-produce resources will instead mostly be developed by the national oil companies (NOCs) or state oil companies of the countries in which they are found. And whereas in the past NOCs had to partner with an oil major such as Shell, BP or ExxonMobil to access the necessary skills to develop their hydrocarbon finds, nowadays they can simply call in an oilfield services company.
Western oil firms are therefore having to explore in increasingly more remote and hostile regions of the world. And this is forcing them to develop more advanced and innovative techniques for finding and producing hydrocarbons, which is pushing the industry to the frontiers of both technology and geography.
Recent successes aren't enough
Frontier exploration has enjoyed lots of successes in the past couple of years, most notably in Uganda, Ghana, the deepwater US Gulf of Mexico and Brazil, although as Mr Bamford points out: "This is still not enough to replace production".
Alan Murray, exploration service manager at energy consultant Wood Mackenzie, explains that the oil and gas industry generally adds 20bn barrels of oil in a typical year, which is one that doesn't include a 'super-giant' discovery. Half of these finds might be brought into production within five years. While Mr Murray expects this rate of discovery to continue, he agrees with Mr Bamford that this alone won't be enough to replace the 30bn barrels or so of oil that are produced every year.
Majors need to replace production
This is creating a growing problem for IOCs, which need to discover new reserves in order to replace the oil they are producing. For example, BP produces just under 4m barrels of oil a day, and so has to actively search for large fields to develop to replace this output, failing which its business, and stock market rating, will decline. "Majors are having to throw a lot of money each year at maintaining low single-digit production growth rates," explains Mr Hart.
And finding enough reserves to replace current production is requiring ingenuity as well as large capital budgets.
Technological frontiers
BP's 'giant' oil discovery at its Tiber prospect in the deepwater US Gulf of Mexico was achieved using the deepest well ever drilled by the oil and gas industry. Located 400km (250 miles) southeast of Houston, the discovery lies in 1,259m (4,132 ft) of water, beneath which the well drilled almost another 9.5km. The total depth drilled of 10,685m is 20 per cent deeper than Mount Everest is high.
Colossal wells such as Tiber cost hundreds of millions of pounds to drill, and such costs are forcing explorers to try ever harder to identify the optimum locations within the most prospective hydrocarbon-bearing structures before drilling. But this isn't easy, given that targets are getting deeper and deeper, and are located in highly complex faulted rock strata. "It is becoming harder to model target reservoirs, which increases the importance of pre-drilling investment and surveys," says Wood Mackenzie's Mr Murray.
Furthermore, the most prospective drilling targets can lie beneath thick layers of salt, which makes seismic imaging – and therefore knowing what geology you are looking at – harder, and makes drilling technically more difficult. Salt is less stable than rock and any movements in its layers could damage or break a drill pipe or well, which would force an explorer to have to restart the drilling effort at great additional expense.
Advanced – and more expensive – seismic and data analysis, such as BP's wide-azimuth towed streamer and multi-azimuth seismic techniques, have successfully imaged reservoirs hidden by salt, and are enhancing the efficiency of reservoir appraisal and development. Other new industry technologies, such as hydraulic fracturing and artificial lift, are helping in the production of 'tight gas', which is gas that doesn't flow well on its own.
Floating LNG
Gas discoveries are often harder to commercialise than oil discoveries given the need for a local market or, failing which, a means to transport the gas to market. Liquefied natural gas (LNG) evolved as a means of transporting gas to market on ships. Shell is taking the process a stage further by seeking to develop floating LNG facilities, which would open up remote gas-prone areas, potentially including the Falkland Islands.
Big wells need big discoveries
The costs of ultra-deepwater wells such as BP's Tiber require the discovery of enormous, highly productive reserves to make them worthwhile, particularly where prospects are remote and field development would require the construction of new processing and transmission facilities. Happily for BP, 3bn barrels of oil should help offset the costs of drilling its Tiber well.
A remote gas discovery needs to be even larger to make viable the costs of developing infrastructure or LNG facilities to commercialise it. For example, Rockhopper Exploration's Johnson structure in the Falklands is estimated to hold a contingent resource of 1.6 trillion cubic feet of gas, yet it is not yet considered commercial given its remote location. However, being able to combine it with any drilling successes in the Falklands next year could change all that.
The oil price is key
The oil price is another key driver of exploration activity. "Frontier exploration has been brought back into focus by the current high oil prices," says John O'Sullivan, technical director of Providence Resources. "This trend is likely to continue with more spending on opening up these frontier basins over the coming years."
Hanson Westhouse's Mr Hart agrees, observing a common theme that, with the exception of Uganda, the exploration frontiers of the deepwater Gulf of Mexico, Brazil, Falkland Islands and Barents Sea all demand challenging exploration and development, and this requires the oil price to remain high.
"Most frontier basins tend to be deepwater high capital expenditure environments where total lifting cost per barrel of oil (or gas equivalent), fiscal terms and market access (in terms of gas) are key metrics in decision making," explains Mr O'Sullivan. "For instance, there is a significant difference between frontier deepwater North Atlantic gas projects, which are relatively close to developed infrastructure and markets, compared with the equivalent in the South Atlantic where there is currently little infrastructure and limited local markets. Oil projects are obviously less infrastructure constrained and it is these projects which are the current focus of industry frontier exploration programmes, as is currently being witnessed offshore Brazil and in the deepwater Gulf of Mexico."
Given the busy exploration plans of many companies, the industry has clearly taken the view that the long-term oil price will remain high.
