Related Articles
Forward article link
Share PDF with colleagues

Heavy oil is bottom of the barrel

Beyond Canada, only Venezuela and a handful of other producers are still persisting with very heavy oil

NOT LONG ago, the world’s barrel of oil seemed destined to get heavier. Dwindling supplies of light sweet crude forced global refiners to start retooling to take heavier feedstock. A rush was on to exploit the world’s tarry pits.

All manner of costly schemes − from extraction of shale-bound kerogen using giant ovens to liquifying coal − were concocted to find brass in the muck. Fracking and tight oil changed all that and with the new abundance of lighter grades, especially from the US, heavy oil’s development outside North America is being stunted. Outside Canada, Venezuela’s huge Orinoco reserves make it the main player, while Estonia still relies on shale oil. Kuwait and Jordan are also pursuing projects. Otherwise, the world has moved on.

It’s not for want of resources. Deposits are found on almost every continent − especially North America, home to the most developed heavy oil production, transportation and processing networks in the world. But Russia, the Middle East, Africa and Asia all have reserves. Despite myriad proposals, some backed by majors like Total and ExxonMobil, few projects have made it past the exploration phase.

A dense affair The reason is a combination of technical and cost considerations. Regardless of an abundance of reserves – the US Geological Survey estimates the world’s resources amount to 5.5 trillion barrels of bitumen oil and 3.4 trillion of heavy oil – production is constrained by the effort it takes to get it out of the ground and the ability of refineries to process it. Depending on the extraction method, it also tends to need special handling infrastructure compared to other crudes.

Globally, about 6m barrels a day of production is heavy, though much of this is considered conventional oil too. For heavy oil-dedicated developments the number is around 3.5m-4m b/d.

Opec commissioned a study in 2010 on heavy oil and it found that just 45% of the world’s refineries could be configured to run the stuff – and most of the plants were in the US. Taken as its own market, this has meant that heavy oil isn’t really a globally traded product. It’s largely a North American and Venezuelan business, with processing a mainly American affair.

As with conventional light, so-called heavy oils encompass a broad spectrum of grades and quality based on viscosity, which also determines its price. The American Petroleum Institute (API), defines heavy oil as crude with a gravity of 10-20oAPI. But much of it is even heavier. Bitumen, also called natural asphalt, or even more commonly as pitch, refers to anything 10oAPI or less, but above coal.

The distinction matters for how it is produced and processed. Conventional heavy oil will flow of its own accord, albeit with the assistance of pumps or steam injection to get it out of the ground – so-called in situ or in-place recovery. By contrast bitumen is immobile and without exception requires mechanical recovery.

Some form of energy – be it shovel, steam or solvent – has to be applied to move it. It then requires special processing to convert it into refinery-ready crude, either by coking in specialised (and expensive) pressure vessels called upgraders or by diluting it with natural gas liquids to reduce viscosity and allow it to flow through pipelines. A global cottage industry has emerged promising silver-bullet technological solutions to a very basic problem.

It also has other idiosyncrasies. On one hand, it trades at a much lower price than conventional oil – as much as 30-50% beneath global benchmarks. This isn’t necessarily a problem, because it still yields a higher cut of diesel and other byproducts, so value is accrued further down the processing chain. But production is dirtier than for conventional oil – it produces higher emissions of greenhouse gases and unwanted byproducts such as petroleum coke. The heavier the barrel, the higher the carbon content. When it assessed the environmental impact of the proposed Keystone XL pipeline from Canada’s oil sands to the US Gulf coast, for example, the State Department concluded that heavy oils emitted a fifth more than conventional oil processed in American refineries. The US still processes some of its own carbon-intensive crude, but that was enough to bring a rejection of the pipeline. Globally, the carbon problem is a serious drag on heavy oil’s market penetration.

Strenuous extraction

So it’s not an easy business. Venezuela offers a case in point. It is the largest heavy oil producer outside Canada, and state-run PdV says the country produced 1.33m b/d of extra-heavy crude from the Orinoco Belt in 2015, accounting for around half the country’s total output. But most of that production comes through upgraders built around 15 years ago, and a shortage of cash to build new units has made it difficult to grow much from that base.

For now, PdV and its partners – notably Chevron, PetroChina, Rosneft and a consortium of Repsol and Indian state companies – have found a workaround to the upgrader problem: they are importing light oil to create an exportable crude blend from the Orinoco’s heavy oil. The plan is to add around 0.5m b/d over the next couple of years with this blending strategy.

But even this more modest growth plan will be difficult to achieve given the low oil price and the country’s persistent political tumult and economic chaos. In the latest sign of the toll the country’s economic crisis is taking on the oil sector, Schlumberger said in April that it was paring back its Venezuela business because PdV wasn’t paying its bills on time.

Heavy oil is holding on elsewhere, but the pickings are thin. One of the biggest international projects is in another Opec member, Kuwait, which began awarding initial contracts for the $7bn Lower Fars development last year. Construction has begun with a production target of 120,000 b/d by 2020. The field will use a variation on a technique known as cyclic-steam injection (CSS), or “huff and puff”, in which oilfields are alternatively injected with steam and then produced. A second phase will eventually come on stream to increase production to around 270,000 b/d.

Efforts to develop Madagascar’s heavy oil deposits have been hampered over the years – and still are – by the country’s deeply unstable political scene. Now, the oil price drop has killed off any hope of early progress.

Independent Madagascar Oil has been running a steam-flood pilot facility on the Tsimiroro deposit, which the company has estimated to hold almost 1bn barrels of contingent original-oil-in-place. But the firm said last September it had run out of storage capacity at the plant, with over 150,000 barrels of crude in its tanks, and would scale down operations until it had found a partner and signed an offtake agreement with a local buyer, neither of which it has done so far. France’s Total took acreage in the adjacent Bemolanga oil sands in 2008, but decided – even then – that the play was uneconomic. The deposits contained about half the concentration of bitumen found in similar Canadian oil sands.

Working on returns

Beyond Canada and Venezuela, the most established international player remains tiny Estonia. Eesti Energia, a private firm, boasts of being the biggest oil shale (as opposed to shale oil, or tight oil) company in the world. But the scale of its business is hardly Aramco-like. The company plans to increase production from synthetic shale oil – or kerogen – to 20,000 b/d in 2016 from 4,000 b/d in 2013. Almost all of this output is used firing electricity plants (kerogen’s chemical properties, richer in oxygen and nitrogen than mainstream crudes, makes it more suitable for middle distillates like diesel). Green opponents hate the practice, blaming it for most of Estonia’s air pollution. But the oil shale business remains strategic for Estonia, which is not eager to rely on Russian energy – Estonia’s kerogen meets the bulk of its electricity supply.

Eesti Energia is also involved in Jordan, which may at last be about to exploit its own substantial oil shale deposits – estimated by the government to total at least 40bn tonnes – having courted various partners, also Shell and Saudi interests. Jordan also has deep worries about energy security and power shortages.

A vital cash injection has come from China as part of a wider package of investments agreed between the two countries. In January, Attarat Power Company (APCO), majority owned by Eesti Energia, said it had signed agreements with two Chinese banks to provide $1.62bn debt funding for the construction of a 470-megawatt oil shale-fired power plant in the desert of central Jordan and the open cast mine from which it would be supplied.

Eesti Energia’s 65% stake in APCO’s holding company is expected to decrease when the deal closes in the next few weeks. The Jordanian government has said work on the project could start in June and the plant is scheduled to open in 2019.

Edited by Ian Lewis and Justin Jacobs

Also in this section
Kosmos sheds frontier portfolio
22 September 2020
Explorer divests non-core assets to cut costs and focus attention on proven basins
Latest licensing rounds
22 September 2020
The industry's most comprehensive list of current and recent rounds for onshore and offshore licences
Petrobras pulls back spending
18 September 2020
Spotlight falls on pre-salt production as Latin American NOC dials down capex