Barren Bonga well adds to challenges facing Nigeria’s oil sector

Nigeria’s oil resources may be dwindling faster than expected, with promising fields turning up empty as seen in the latest well on Bonga oilfield, a development that could further compound the challenges in the sector, analysts say.

Already, the industry is constrained by the prevalence of crude theft, long contracting cycles, and high operational costs, now when drilled fields turn up empty, this could further raise operational costs.

Bonga-70 is the latest well in the ongoing multi-well drilling campaign on the Bonga field by UK major Shell, which turned up a disappointing dry hole, reports Africa Oil & Gas Report, an energy intelligence publication.

“This is an unusual occurrence on the Bonga field; the operators of the field need to conduct a new seismic survey around the areas to explore for new oil wells,” Toyin Akinosho, the publication’s publisher, told BusinessDay.

Alex Tarka, a former president of the Nigerian Association of Petroleum Explorationists, said the inability to find oil in the new well will delay the appraisal, field, and development plan for the Bonga field, and will have an immediate impact on Nigeria’s oil reserves.

“The dry oil well does not mean doom for the whole Bonga fields; it means the explorationists working on the project will have to use more unconventional technologies in other areas of the fields, which may lead to exploration of more wells,” Tarka told BusinessDay.

Bonga, Nigeria’s first deepwater oil field, currently has the capacity to produce 225,000 barrels per day (bpd) of crude oil and 150 million cubic feet of gas per day of gas, which feeds the Nigeria LNG’s plant at Bonny.

BusinessDay’s findings showed the initial field development had been expanded with further drilling of wells in Bonga Main Phases 2 and 3 and through a subsea tie back that unlocked the Bonga North West in August 2014.

“Nigeria is struggling to attract exploration investments, and this is starting to take a toll on the country’s assets,” an oil explorationist attached to an oil major operating in Nigeria’s offshore sector told BusinessDay.

The Nigerian Upstream Petroleum Regulatory Commission (NUPRC) inaugurated a project committee last June on the reactivation of inactive oil wells in Nigeria to spur production.

According to Gbenga Komolafe, chief executive officer of NUPRC, Nigeria had over 3,000 shut-in strings with huge potential to boost production in the short-term (six months), mid-term (one year), and long-term (over a year).

Wumi Iledare, a professor of economics and former president of the Nigerian Association for Energy Economics, believes a decline in active oil wells is the driver of Nigeria’s decline in oil production.

“This is obviously affected by the number of wells that are put into production and the less producing wells in a field at its peak, less the aggregate field output,” Iledare said.

Shell spokespersons could not be reached for comment.

Sources close to the project said Shell delayed expansion work at its Bonga Southwest field till 2024.

Developing Bonga Southwest was set to add around 1 billion barrels to Nigeria’s oil reserves. Shell had previously said it would develop the Bonga Southwest project across three phases with a total potential yield of 3.2 billion barrels.

Output from the field was one of the projects Nigeria was banking on to raise production to around 3 million bpd by 2023, officials of the Nigerian National Petroleum Company Limited (NNPC) said.

Nigeria, which produces high-quality light sweet crude oil, has seen its production slump to multi-decade lows, due to operational, technical and sabotage issues.

Nigeria has the capacity to pump around 2.2 million bpd of crude and condensate, but in 2022 output languished, hovering around one million bpd, according to the Organization of the Petroleum Exporting Countries (OPEC) estimates.

Developing the Bonga Southwest would cost $10 billion, according to estimates by the NNPC, the concessionaire of the field.

The bulk of Bonga Southwest’s resources are located in Oil Mining Licence (OML) 118, but it also extends into OMLs 132 and 140, operated by US major Chevron, where it is called Aparo. Other partners in the project are France’s TotalEnergies and Italy’s Eni.