Nigeria Deploys Thousands of Rigs but Crude Output Remains Stagnant

Nigeria’s decade-long investment in oil exploration and drilling has yet to produce the sustained increase in crude oil output expected from higher rig activity, with ageing fields, underinvestment and delays in developing new projects continuing to weigh on production.

Rig count is widely regarded as an important measure of exploration and production activity. Higher deployment should ordinarily translate into increased output as operators drill new wells, maintain existing facilities and develop additional reserves.

But official records reviewed by Financial Vanguard indicate that crude production has struggled to rise significantly since 2016, despite substantial drilling activity.

Industry experts attributed the mismatch to declining output from mature fields and the slow development of new wells.

OPEC data showed that 2,099 rigs were deployed in Nigeria between 2016 and 2026. The figure represents investments running into billions of US dollars.

Rig deployment peaked at 360 in 2018, while the lowest annual figure, 87, was recorded in 2021.

The cost of maintaining such drilling activity is substantial. Deepwater drilling can cost between US$400,000 and US$600,000 per day for the rig alone. That excludes drilling mud, casing, cementing, logistics, helicopters, supply vessels, insurance and other associated services.

An individual offshore exploration well can cost between US$50 million and more than US$150 million, depending on water depth and complexity.

Yet Nigeria’s crude output, excluding condensate, reached a high of only 1.734 million bpd in 2019 during the period under review, well below annual budget projections. By 2022, production had dropped to 1.143 million bpd.

Mature fields deepen production challenge

The decline from mature fields is adding to the problem.

NUPRC data showed that average output from five mature producing fields dropped 20.8 per cent year-on-year to 10,930 bpd in June 2026 from 13,794 bpd a year earlier.

These fields have moved beyond their early development and peak production stages and are naturally exposed to declining reservoir pressure, increasing water production and falling output. Maintaining production therefore requires additional investment, workovers, new wells and enhanced recovery techniques.

Abo field, operated by Eni/Agip and in production since 2003, saw output plunge 39.2 per cent year-on-year to 6,870 bpd in June 2026 from 11,297 bpd.

Pennington fell 45 per cent to 3,880 bpd from 7,107 bpd, while Ugo Ocha, also known as Jones Creek, dropped 16.6 per cent to 26,900 bpd from 32,246 bpd.

Sea Eagle, operated by Renaissance Energy, recorded an 8.3 per cent decline to 14,570 bpd from 15,886 bpd, while Okwori, operated by Antan Producing Limited, slipped marginally to 2,430 bpd from 2,435 bpd.

Investigations across Abia, Akwa Ibom, Bayelsa, Cross River, Delta, Edo, Imo, Ondo and Rivers states indicate that many fields have become significantly depleted since Nigeria’s first commercial oil discovery in 1956.

Although some operators have continued to invest in additional wells, workovers and other production-enhancement measures, others have struggled to provide the capital required to arrest declining output.

Operators: Mature-field decline is natural

Renaissance Africa Energy, operator of Sea Eagle, said the field’s declining output was consistent with its maturity.

“Sea Eagle, a Renaissance JV asset, is a mature field and its production performance remains broadly in line with expectations set out in the approved Field Development Plan,” the company said.

“As is typical for mature assets, the field is experiencing a natural production decline associated with field life cycle progression.”

The company said Sea Eagle’s production profile had already been incorporated into its business and growth plans and had not materially affected its operations.

It added that it continued to evaluate opportunities to optimise production and maximise value from its assets while complying with approved development plans and regulatory requirements.

Eni similarly pointed to Abo’s long production history.

“Nigeria’s deep offshore Abo field produced its first oil in April 2003 and has remained consistently in production for the past 23 years, a remarkable achievement,” Eni said.

The company added that the field’s current performance was consistent with its maturity and that production optimisation measures, including upgrades to gas compressors, were being implemented.

From 2.5 million bpd peak to weaker OPEC influence

The production challenge has broader implications for Nigeria’s position in the global oil market.

Nigeria’s crude production peaked at approximately 2.5 million bpd in November 2005, according to historical production data. At the time, the country was one of the major forces within OPEC and the international oil market.

Today, even with investment efforts following the Petroleum Industry Act, national production including condensate has remained below 1.7 million bpd.

Nigeria’s diminished production capacity was also reflected in its absence from the seven OPEC+ countries that met virtually on August 2, 2026, to assess oil market conditions and production plans.

OPEC said the seven countries — Saudi Arabia, Russia, Iraq, Kuwait, Kazakhstan, Algeria and Oman — agreed to implement a 188,000 bpd production adjustment from the additional voluntary cuts announced in April 2023.

The adjustment is scheduled to take effect in September 2026.

OPEC said the measure would also enable the participating countries to accelerate compensation for previously over-produced volumes.

The seven countries reaffirmed their commitment to full conformity with the Declaration of Cooperation and said they would continue monthly meetings to review market conditions.

For Nigeria, the latest OPEC+ decision underscores a more fundamental problem: the country is struggling to produce enough crude to take full advantage of market opportunities, meet its OPEC allocation and satisfy growing feedstock demand from new domestic refineries.

Analysts warned that continued losses from mature fields, inadequate investment, crude theft, pipeline vandalism and delays in new projects could further reduce government revenue and foreign-exchange earnings.

Experts call for focus on existing reserves

An industry expert who spoke anonymously said Nigeria must move beyond simply increasing exploration and focus on converting proven reserves into actual production.

“Exploration must be accompanied by aggressive field development, enhanced recovery from mature assets, improved security, infrastructure upgrades and faster regulatory approvals,” the expert said.

“Nigeria already possesses substantial proven reserves, and the greater challenge is converting those reserves into sustained production rather than simply discovering additional hydrocarbons.”

The expert warned that without addressing the structural constraints, increased exploration spending alone would not deliver the crude volumes needed to improve government revenue, foreign exchange earnings and Nigeria’s position in the global oil market.

The expert also called for accelerated completion of projects including Bonga North, Southwest/Aparo, Zabazaba and Etan.

The importance of sustained investment in mature assets was also demonstrated by Brittania-U’s Ajapa field.

Its Chairman/CEO, Catherine Uju Ifejika, said the company invested more than $400 million after acquiring the asset from Chevron. The investment included drilling additional wells and deploying an FPSO facility.

She said the investment enabled Ajapa to commence production at about 2,300 bpd in 2010, after which output increased and became more stable.

Professor Emeritus of Petroleum Economics, Wumi Iledare, said the NUPRC data pointed to a structural problem with direct implications for government revenue.

“Declining production translates directly into reduced government revenue, weaker external reserves, lower foreign-exchange inflows, and diminished economic value creation,” he said.

According to Iledare, Nigeria should respond with faster regulatory approvals, incentives for re-entering selected abandoned wells, infill drilling, workovers, artificial-lift optimisation and enhanced oil recovery technologies where commercially viable.

He said the Petroleum Industry Act already recognises the maturity of Nigeria’s fields through production allowances and a progressive royalty structure designed to balance government revenue with the need to sustain investment.

“A barrel that remains underground due to commercial or regulatory disincentives generates no revenue for government, no return for investors, and no value for the economy,” he said.

“The core challenge, therefore, is not simply increasing production, but maximising economic recovery from existing assets within their remaining productive life.”

He concluded: “This is the essence of petroleum asset optimisation — and ultimately, public value optimisation.”

Africans Angle Editorial