In the never ending global search for oil and gas "pre-salt" hydrocarbon basins have become increasingly important, not least because such basins often host super-massive fields. While such basins have been known about and drilled for many years, they burst into prominence in 2006 when a partnership led by Brazilian energy giant Petrobras and also including the UK's
Petrobras and BG have made numerous further discoveries offshore Brazil in the intervening years, confirming the great potential of the basin. Now, London oil and gas firms are starting to test the potential of several of the other most promising pre-salt basins around the world.
Peter Bassett, oil and gas analyst at Westhouse Securities, explains that pre-salt basins are found in the marine sections of the Brazilian coast, some of the West African coast - for example in Angola and northern Namibia - and parts of Kazakhstan.
Such basins are called "pre-salt" because they formed in rock intervals that were subsequently encased beneath thick layers of salt that can in some cases measure 2km in depth. The total drilling depth to reach these rocks - the distance from sea level through the seafloor to the oil reservoirs beneath the salt layer - can measure up to 7km.
Drilling to depths of 7km is challenging but lies well within industry capabilities. However, shooting seismic surveys through thick layers of salt is not so easy. The salt tends to scatter seismic waves into multiple paths, which blurs the resultant images and makes it difficult to pinpoint the best places to drill.
Drilling wells in pre-salt basins provides further challenges since thick layers of salt behave like unstable plastic when subjected to high pressure and temperature, which can lead to slippage of drilling equipment. Despite these challenges of imaging and drilling, pre-salt basins are vital because they have been found to host very large accumulations of hydrocarbons.
In the context of the oil and gas industry as a whole, pre-salt basins have only relatively recently been unlocked by advances in seismic imaging below salt, and drilling and completing deep wells. When they work, such new play types tend to yield large fields early since operators generally focus on the largest prospects first so as to maximise the chances of any discoveries being commercial. Another reason why pre-salt basins are often so highly prospective is that the layer of thick salt forms an impermeable barrier that is highly effective at preventing hydrocarbons from seeping away.
Petrobras estimates that the Tupi accumulation holds 5bn to 8bn barrels of recoverable oil equivalent (boe). This makes Tupi the largest oil find since the 13bn-barrel Kashagan field in Kazakhstan, which was discovered in 2000 and is also partly pre-salt in nature. Moreover, the prolific Pre-Caspian Basin that hosts Kashagan also hosts other super-giant fields lying in salt and pre-salt geology, such as Karachaganak and Tengiz.
Petrobras's Guará discovery, which like Tupi also lies in the Santos Basin, holds an estimated 1.1bn to 2bn boe. Overall discoveries of resources in Brazil in 2008 ranked among the top 10 largest in the world that year, according to Cambridge Energy Research Associates (CERA). CERA's early estimates put those discoveries at more than 50bn barrels in total size, almost all of which lies beneath thick layers of salt.
A spokesperson for oil major
Shell is just one of a number of firms currently busy in pre-salt basins. Petrobras/BG announced earlier in March the start of a new well test in the Iracema area of the Santos Basin. A floating production, storage and offloading vessel operating in water depths of 2.2km will spend around six months gathering technical data. The well will also flow at a rate of some 10,000 barrels of oil per day (bopd), which is constrained by the capacity of the vessel. The well test forms part of a fast-track development of the field, the final production system for which is expected to be in operation by the end of 2014, operating at an enormous capacity of 150,000 bopd.
Of potentially even keener interest to investors are the ongoing and near-term pre-salt drilling campaigns in Kazakhstan and offshore Namibia.
Emba B on its own doesn't boast the same massive scale as pre-salt prospects offshore Brazil and Namibia, although Max has ten prospects and five leads in its pre-salt portfolio. These range in size from 100m to 600m boe and Max estimates that these prospects and leads could in aggregate hold over four billion barrels of resources.
Most of these potential resources, including Emba B, are hosted in what Max terms "Type II" prospects. These are believed to be ancient coral reefs that are analogous to the super-giant fields found in the Pre-Caspian Basin. The significance of Type II prospects is that they all share a common primary risk factor: reservoir quality, and in particular porosity, which is the ability of a reservoir to absorb hydrocarbons. What this means is that should the Emba B well make a successful discovery that proves good reservoir quality, it would greatly de-risk the other Type II prospects in Max's portfolio.
April could prove a momentous month in pre-salt exploration by London's junior explorers. Not only is Max's Emba B result expected that month but
Tapir South could hold resources of up to 604m boe and Chariot estimates that drilling has a 25 per cent chance of making a discovery. The well will be drilled to a depth of around 5.1km and will aim for several reservoir targets. Similar to Max's prognosis of its prospects, drilling success at Tapir South would greatly increase the chances of Chariot making further discoveries across the Namibe Basin. The company has to date identified four prospects and two leads within its northern blocks and estimates that these could hold up to 2.8bn boe of oil and gas resources. The results of the Tapir South well should be known around the end of May.
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