In May, Algeria’s cabinet authorised the energy ministry to evaluate the potential for the development of the country’s shale oil and gas resources, estimated to be among the largest in the world.

According to the US government’s Energy Information Administration (EIA), Algeria has recoverable shale gas reserves of 20 trillion cubic metres, behind only China and Argentina in the global pecking order.

According to Ramtane Lamamra, Algeria’s minister of foreign affairs, the government has made a “strategic decision”  to investigate the potential of its shale resources, which also include an estimated 248 billion barrels of oil. A cabinet statement issued on 21 May detailed an initial work plan including at least 11 wells to be drilled over a period of seven to 13 years.

Licensing round

The government had included some shale gas concessions in its latest upstream licensing round, launched in January. Of 31 concessions on offer, 17 are shale gas prospects, according to a statement by Sid Ali Betata, head of state licensing body Alnaft.

Several international companies have expressed interest in Algeria’s shale gas programme, including Italy’s Eni, ExxonMobil of the US, and French firms Total and GDF Suez.

“The geological potential is pretty massive,” says Adam Pollard, an upstream analyst specialising in North Africa at UK energy consultancy Wood Mackenzie. “There is no reason from a geological point of view that shale exploitation can’t happen.”

Algeria’s shale plans are only in their infancy, however. There is a huge gulf between technically recoverable shale reserves and commercially recoverable reserves, which are estimated to be between 2-4 trillion cubic metres, and Algeria will have to start from scratch in creating an industry to support new forms of exploration and development.

“Compared with the US [where the shale gas industry is already established], Algeria doesn’t have the supply chain to cope with the number of wells you’d have to drill,” says Pollard. “Lots of work needs to be done building up the expertise and supplies in the country before shale takes off in any meaningful way.”

Water scarcity

Shale exploitation also requires large amounts of water, although this is not insurmountable.

“Water is not as big an issue as you would imagine given that the projects are in the Sahara,” says Pollard. “People in the desert obviously have limited water supplies, but there are aquifers that are already being used to pump water into existing wells. It’s not potable water so it’s not used for drinking water supply.”

There is the potential for water supply contamination, however, with more than 500 chemicals used in the extraction of shale gas. While the government insists that all necessary measures will be taken to protect water supply and the environment, new regulations may have to be introduced to ensure this is enforced.

Sonatrach

The major challenge for Algeria is the economic viability of shale exploitation. Operators in Algeria sell gas to state energy firm Sonatrach for about $7.5 a million BTUs, a healthy price compared with many other markets in the Middle East.

But the domestic energy market is heavily subsidised, meaning the provision of energy is a costly business for the government, especially with rapidly rising local demand. The costs involved in shale gas exploitation are also much greater than those for conventional gas.

“There’s a reasonable gas price in Algeria, but shale is still challenging economically,” says Pollard. “Algeria is a much more expensive place to operate in than North America, and things happen more slowly. But if they can build up the skills and equipment over time then shale gas can become more viable.”

Conventional sources

Some analysts argue that Algeria should concentrate on making the most of its existing conventional reserves before it moves on to shale.

“Everywhere outside North America, if you can possibly find conventional gas, you don’t want to be messing around with shale,” says Jonathan Stern, head of gas research at the Oxford Institute for Energy Studies in the UK. “It’s so much more difficult. You have to drill 50 wells before you know whether you’ve got anything, and then hundreds more to get commercial volumes.”

Pollard agrees, saying: “Jumping from conventional fields to shale is a big step. It makes more sense to exploit conventional gas and tight gas reserves first.”

But he also suggests that starting the process early is no bad thing. “It makes sense to start looking at shale now, because it will take a long time. They’ve acknowledged they need expertise. Part of the rationale behind the bid round is to attract operators with non-conventional experience.”

Hydrocarbons law

Alnaft, which was created under revisions to the hydrocarbons law in 2005, has had limited success in its licensing rounds so far. In the three rounds to date, only a quarter of the licence areas on offer were awarded. The fourth round will be the first to be held since further changes to the law were introduced in January 2013, in an effort to sweeten the terms for operators, particularly for unconventional gas.

“Exploration periods have been increased for unconventional projects from seven to 11 years, including a four-year pilot phase, and there are some general changes making a small improvement in the terms,” says Pollard. “They’ve added an ‘R’ factor to make taxes commensurate with profitability, which is a definite improvement. Whether it’s big enough to encourage lots of investment is difficult to say.”

Data rooms have already been held for the latest licensing round and poposals are due by 4 September, with a public opening of bids the same day and the signature of contracts on 2 October.

“There’s been lots of interest in the bid round,” says Pollard. “But it’s difficult to second-guess companies’ response to what they’ve seen in the data rooms. Given the tax breaks, I would imagine there might be some interest in tight gas, and there may be some interest in shale for the longer term.”

Declining gas production

Algeria’s government has acknowledged that the realisation of its shale resources is a long way off, and with the relative failure of recent licensing rounds – and a five-year gap between the third and fourth rounds – supply increments in the coming years are likely to be patchy.

“The past few licensing rounds have not amounted to much and we’re starting to see the effect of that now,” says Pollard.“Oil production is in steady decline as the big mature finds are starting to become really mature and there are not many new developments in the pipeline. Gas production is declining for similar reasons at the moment, although there will be an increase from 2017 when new gas comes on stream in the southwest.”

Gas output declined from 88.2 billion cubic metres in 2005 to 81.5 billion cubic metres in 2012, and again to 78.6 billion cubic metres in 2013, when supply was further hampered by the outage of the In Amenas gas plant, following a terrorist attack on the facility in January 2013. Oil and liquids production declined from 2 million barrels a day (b/d) to 1.6 million b/d over the same period.

Some projects have nevertheless come on stream in recent months, most notably the El-Merk oil project and the Gassi Touil gas scheme. El-Merk was commissioned in 2013 and has been ramping up to full capacity of an estimated 140,000 b/d of oil, condensate and liquefied petroleum gas (LPG). Gassi Touil, a gas processing facility with capacity of 4.4 billion cubic metres a year (cm/y), was inaugurated in February.

In the medium term, hopes for increased output rest on four major gas schemes in the southwest: Timimoun, Reggane North, Touat and Ahnet. All are significantly behind schedule due to delays over the construction of the GR5 pipeline that will connect the region to Algeria’s trunk pipeline network. Sonatrach finally awarded the engineering, procurement and construction (EPC) contract for GR5 to a local firm in 2012 and work is under way, with construction due for completion in 2016.

In the wake of the pipeline award, progress has been made with three of the four field developments, which between them promise to add about 10 billion cm/y of gas production.

Major projects

In August 2013, Spain’s Tecnicas Reunidas was awarded the $1bn EPC contract for the Touat field, including processing facilities for an estimated 4.5 billion cm/y of gas and 1,700 b/d of condensate. In February this year, South Korea’s Samsung Engineering signed the $800m EPC deal on the Timimoun project, covering the construction of a 1.8 billion cm/y processing facility and a 180-kilometre pipeline.

In May, the UK’s Petrofac signed the $970m main construction contract for work on Reggane North, covering a gas treatment station, a gas collection network and a 74km pipeline. The project will have capacity of an estimated 3 billion cm/y. France’s Total signed a deal for the Ahnet concession in January 2010, but field development work on the scheme is yet to be tendered. Once on stream, the field will produce an estimated 5 billion cm/y of gas.

Also due on stream in the next few years is Ireland-based Petroceltic’s Ain Tsila field development in the southeast.

Front-end engineering and design (feed) work is expected to be carried out this year, after the government approved the company’s development plans in December 2012. The feed work had initially been scheduled for 2013, but was delayed by the terrorist attack on the In Amenas gas facility, less than 100km away from Ain Tsila. The project is due to come on stream in 2017, with expected production of 3.7 billion cm/y of wet gas.

With shale gas exploration not expected to yield commercial production for another decade at the very least, it is to these projects, and to the results of this year’s bid round, that Algeria will look to reverse its dwindling gas output in the coming years.