Africa Oilfield Services Market Size & Share Analysis - Growth Trends and Forecast (2026 - 2031)

Africa Oilfield Services Market Trends and Insights

Rising Deep-Water Exploration Campaigns in West Africa

Operators are steering a larger slice of exploration budgets toward pre-salt and ultra-deep-water acreage that offers multi-billion-barrel potential, underpinning premium day rates for seventh-generation drillships. Shell’s USD 5 billion sanction of Bonga North in late 2024 mobilized subsea tree, riser, and dynamic-positioning packages that will keep contractors busy through 2028.^{[1]Reuters Staff, “Shell Gives Final Green Light to Nigeria’s Bonga North Project,” Reuters, reuters.com} Angola’s Azule Energy followed with a USD 1.2 billion award to TechnipFMC for Block 15/06 in early 2025, validating integrated EPC models that bundle drilling, completion, and installation.^{[2]TechnipFMC Investor Relations, “Azule Energy Awards TechnipFMC Integrated Subsea Contract,” technipfmc.com} Ghana’s Pecan field, already producing 40,000 bpd, is tendering a fourth development well, sustaining demand for jack-ups and cementing services. Concentrated activity gives specialized contractors like Transocean and Valaris pricing power, with day rates topping USD 400,000, while land-focused firms endure margin compression. The deep-water pivot is therefore a primary growth vector for the Africa oilfield services market over the medium term.

Recovery in Oil Prices Boosting CAPEX by NOCs & IOCs

Brent prices above USD 80 in 2025 restored economic viability for projects shelved during the 2020 downturn. Sonatrach earmarked USD 50 billion for upstream work through 2028, granting Schlumberger a five-year integrated-services contract covering 12 concessions.^{[3]Schlumberger, “2025 Annual Report,” slb.com} Nigeria’s NNPC secured USD 3 billion in financing to rehabilitate 21 marginal fields, an initiative expected to lift production by 200,000 bpd by 2027, thereby expanding opportunities for workover rigs and coiled-tubing units. Angola reopened licensing for eight offshore blocks in 2024; bids from TotalEnergies, Equinor, and Chevron depend on prices staying above USD 75 to justify high front-end costs. Although price volatility remains a risk, multiyear service contracts locked in during the current upcycle give the Africa oilfield services market a revenue floor through the short term.

Demand for Enhanced-Oil-Recovery in Mature Onshore Fields

Half-century-old Saharan and Niger Delta fields are entering tertiary phases, necessitating polymer flooding, carbon dioxide injection, and thermal stimulation. Sonatrach’s pilot CO₂-EOR in Hassi Messaoud injects 500,000 tons annually to raise recovery from 30% to 42%, potentially unlocking USD 2 billion in future injection equipment orders. Nigeria’s joint-venture operators are evaluating water-alternating-gas schemes but remain hampered by community disputes that keep EOR penetration below 15% of feasible reserves. Baker Hughes captured a USD 180 million artificial-lift package in Angola aimed at extending nine concessions by a decade. Sustained crude prices and ready access to low-cost CO₂ dictate project economics, positioning Algeria and Angola at the forefront of EOR adoption across the Africa oilfield services market.

Local-Content Mandates Spurring Indigenous Service Firms

Revised regulations now require up to 50% domestic participation for onshore drilling in Nigeria and 40% subcontracting for subsea work in Angola. Oando Energy Services won a USD 450 million, three-year contract in 2025 to supply drilling fluids and wellhead equipment for 40 wells, a record award for a Nigerian contractor. Saipem formed a joint venture with Sonasurf to fabricate flexible pipeline spools in Luanda, meeting Angola’s Presidential Directive 4/2024 while retaining engineering control. Ghana’s local-content matrix pushed Tullow’s Jubilee expenditure to 62% domestic in 2024, up from 48% in 2020. These rules fragment the value chain, lowering blended margins for global integrators but enlarging the addressable market for indigenous entrants, a dynamic that will keep the Africa oilfield services market competitive.

Political Instability & Security Risks in Key Basins

Pipeline sabotage in Nigeria’s Niger Delta adds USD 8 to USD 12 per barrel to lifting costs, and Shell divested its onshore stake for USD 2.4 billion in early 2025 to avoid community disputes and flaring penalties.^{[4]Financial Times Reporters, “Shell Sells Nigeria Onshore JV to Local Consortium,” ft.com} Cabo Delgado insurgent attacks totaled 47 in 2024, and TotalEnergies’ onshore LNG rebuild depends on a still-fragile security cordon. Libya’s rival factions forced three production shutdowns in 2024, driving drillers to demand advance payments or sovereign guarantees. These security premiums erode margins and nudge capital toward stable jurisdictions, moderating the near-term revenue trajectory of the Africa oilfield services market.

Investor Decarbonization Pressure Curbing Financing

Fourteen of the twenty largest project-finance banks now restrict funding for high-flaring exploration projects. TotalEnergies’ East African Crude Oil Pipeline faced a nine-month financing delay in 2024 after shareholder backlash, raising the project’s weighted-average cost of capital by 120 basis points. Shell’s Nigerian divestments were also driven by activist scrutiny over annual spill costs exceeding USD 400 million. In contrast, Eni raised USD 4.7 billion for Coral Sul’s second train in 2025, signaling investor appetite for gas-aligned, lower-carbon assets. This bifurcation creates a two-speed Africa oilfield services market, where oil-prone exploration faces capital rationing while gas infrastructure secures funding.

Segment Analysis

By Service Type: Drilling Anchors Revenue, Completion Lags

Drilling held 43.2% of the Africa oilfield services market share in 2025, propelled by multi-well deep-water programs in Angola and Nigeria. The segment is expected to advance at 6.8% through 2031, with Sonatrach slated to drill 120 exploration and appraisal wells and Azule Energy restarting Block 15/06 campaigns. Completion services captured about 28% of revenue but lag in growth because multi-stage hydraulic fracturing remains limited to Algeria’s tight-gas plays. Production-optimization services such as artificial lift are gaining traction: Baker Hughes installed 34% more units in Angola during 2025, illustrating rising demand for life-extension tools. Decommissioning, though still niche, is emerging as a high-margin play after Subsea 7’s USD 320 million Escravos contract, emphasizing widening opportunities beyond drilling.

While drilling retains volume leadership, automation, remote steering, and dual-activity rigs are narrowing the cost gap with ancillary services. As contractors upgrade fleets and integrate digital workflows, EBITDA margins for drilling could converge with completion by decade-end, preserving the segment’s centrality to the Africa oilfield services market.

Note: Segment shares of all individual segments available upon report purchase

By Location: Onshore Scale Meets Offshore Momentum

Onshore operations generated 76.9% of the Africa oilfield services market size in 2025, anchored by Algeria’s Saharan giants and Nigeria’s Niger Delta. Offshore revenue, though just 23.1%, is expanding at an 8.4% CAGR, outstripping onshore’s 5.7%. Ultra-deep campaigns below 2,000 m water depth require high-spec drillships like Transocean’s Deepwater Asgard, delivered to Angola under a USD 540 million contract. Onshore faces structural headwinds, security, aging rigs, and lower contractor returns, yet remains indispensable for NOC output targets. Offshore’s share is set to reach 28% by 2031, fueled by pre-salt discoveries and FLNG tie-backs, but absolute onshore spend will still rise in line with Algeria’s gas push and Nigeria’s marginal-field revival.

The diverging growth paths mean service providers must balance land-rig fleets for volume with deepwater assets for margin. Firms that straddle both arenas will be best positioned to capture the Africa oilfield services market’s blended growth.

By Well Type: Conventional Dominance, Unconventional Upside

Conventional wells accounted for 73.5% of the Africa oilfield services market size in 2025, reflecting superior reservoir quality in the Niger Delta and Saharan basins. Unconventional activity - tight gas, shale, and coal-bed methane - is rising at a 7.9% CAGR through 2031 and is poised for further upside as Algeria commercializes Timimoun and Ahnet. Halliburton’s USD 680 million fracturing award for 42 horizontals in Timimoun exemplifies the emerging demand profile. Cost parity is improving; pad drilling and zipper fracs cut per-well expenses by 23% between 2023 and 2025. Still, conventional wells remain cheaper and less technically demanding, ensuring their numerical dominance through 2031. The well-type mix could shift to 68% conventional and 32% unconventional by 2031, supplying a broader technology runway for pressure-pumping fleets within the Africa oilfield services market.

Note: Segment shares of all individual segments available upon report purchase

Geography Analysis

Algeria secured 25.4% of Africa's oilfield services market revenue in 2025, driven by Sonatrach's USD 12 billion upstream budget and integrated project awards to Schlumberger and Weatherford. Mozambique, the fastest-growing geography at 9.5% CAGR, benefits from Coral Sul's expansion and Mozambique LNG's restart, which together require 14 subsea wells, 180 km of flowlines, and two FPSO units. Nigeria, contributing 22%, lags continental growth due to Niger Delta unrest and Shell's asset divestments, though NNPC's marginal-field program offers upside.

Angola's 18% share rests on Azule Energy's Block-15/06 spending and renewed licensing. Egypt accounts for 12%, sustained by Eni's Zohr and BP's West Nile Delta programs that keep 32 land rigs and six jack-ups active. Ghana's Jubilee and TEN complexes supply 5% of revenue but face plateauing output absent discoveries. Libya fluctuates between 4% and 6%, contingent on cease-fire durability, while Senegal, Gabon, Equatorial Guinea, and Congo form an 8% "Rest of Africa" cluster highlighted by Woodside's Sangomar first oil in mid-2024.

North Africa offers scale but runs regulatory inertia; West Africa promises high-margin deep-water work tempered by security risk; East Africa blends frontier gas potential with insurgent threats. Portfolio diversification across these blocs helps operators hedge geopolitical volatility, yet the center of gravity is tilting toward Algeria and Mozambique as gas monetization and transition alignment reshape capital flows in the Africa oilfield services market.

Note: Segment shares of all individual segments available upon report purchase