At a time when oil companies are becoming markedly more selective in their investment choices and long-term demand projections diverge, owning oil underground is no longer enough to guarantee its extraction. On the African continent, many discoveries remain in limbo, having failed to demonstrate their profitability.
From Mauritania to Liberia, several African states hold deposits identified sometimes more than ten years ago without ever being brought into commercial production.
The example of Benin’s Sèmè field, however, nuances this observation: the planned marketing in October 2026 of a first cargo of about 250,000 barrels proves that a site long considered too modest, too costly, or technically complex can become profitable again once the economic, industrial, or technical context changes.
The Sèmè field, limited in size, had already produced nearly 22 million barrels between 1982 and 1998, when a barrel traded at around $14, before being shut down.
For the Beninese state, expected benefits will rest on three levers: a 15% stake in the project, a 10% royalty on production, and a share of profit oil as provided for in the production-sharing agreement.
This return to production crowns several unsuccessful attempts. As early as the 2000s, SAPETRO undertook new drilling and deployed equipment to revive operations, but neither the project’s profitability nor the technical results allowed it.
Ultimately, Akrake Petroleum, by taking over the site in 2023, changed the situation: the main reservoir had naturally repressurized during the period of inactivity, two horizontal wells optimized recovery of remaining crude, and a lighter setup based on leased floating units providing production, storage, and offloading limited costs.
Thanks to shallow water depth of between 20 and 30 meters, this economic approach made it possible to monetize 5.7 million barrels of reserves now considered proven and probable. It is precisely this kind of economic turnaround that keeps hope alive for other African reserves left behind.
The Mauritanian case illustrates a comparable scenario. Since production at Chinguetti stopped in 2017 after eleven years of operation that began in 2006, the country no longer has any active oil field.
It nevertheless has the Walata deposits, formerly called Tiof, credited by the Ministry of Energy with about 280 million barrels, and Tevet, estimated at 40 million barrels.
According to authorities, a feasibility study on relaunching Walata is still underway; bringing it into production would reactivate an oil windfall for the state, whose hydrocarbons code guarantees production sharing with contractors as well as public participation of at least 10%.
In Madagascar, the obstacle is not geological but qualitative. The Office of National Mines and Strategic Industries (OMNIS) estimates the heavy oil reserves at the Tsimiroro site at 1.7 billion barrels.
Although a development plan was approved as early as 2015, the project remains at the preparatory stage, held back by the very nature of this oil, which is difficult to extract and monetize.
Madagascar Oil has nevertheless supplied heavy fuel to local industrialists since September 2022, even though the absence of a refinery on the island complicates any transformation into vehicle fuels.
A challenge found, on an incomparable scale, in Venezuela: its 303 billion barrels of proven reserves the world’s largest are also mostly extra-heavy crude, difficult to exploit.
Namibia finally proves that this problem is not limited to small deposits. On license PEL39, after several discoveries, Shell had written down nearly $400 million in assets in 2025, citing low reservoir permeability and too high a proportion of gas.
A twist occurred in June 2026, however: the Merlin-1X well uncovered light oil in a better-quality reservoir, prompting the British group to continue evaluating commercial development of the block.
These projects will now have to find their place in a market whose future remains uncertain but promising.
According to the International Energy Agency (IEA) scenario incorporating policies already adopted or officially announced, global oil demand would peak at around 102 million barrels per day around 2030, before beginning a slow decline.
Taking only currently enacted policies into account, it would remain at 113 million barrels per day in 2050, according to the World Energy Outlook 2025, versus 124 million barrels per day according to OPEC projections for the same date. By comparison, current global consumption is around 105 million barrels per day.
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