TGS has announced the commencement of the EGY-2DRE2026, a large-scale two dimensional (2D) seismic reimaging project covering 34,000kiometres across offshore Egypt.
The project will integrate input from the GeoStreamer 2016, 2018 and 2023 surveys, together with other available conventional 2D data, to build a single, consistent regional framework across the offshore basins.
“This merged dataset will be put through an advanced velocity model building and pre-stack depth migration workflow, including TGS’ proprietary DM-eFWI technology, to deliver clearer, more reliable imaging of the pre-, intra- and post-Messinian salt intervals”, the Norwegian geophysical company says in a release..
Final products for a priority subset of 2D lines are scheduled for delivery in the second quarter of 2027, with the remaining full project scheduled for completion in first quarter 2028.
“By resolving these intervals with greater confidence, the reimaged dataset is designed to give operators a sharper, basin-wide structural framework to support prospect identification and maturation, helping customers direct exploration budgets toward the areas of highest potential in the anticipated future licensing round, and support activity in the offshore Nile Delta, Herodotus Basin, and wider Eastern Mediterranean Basin”, TG offers.
Italian explorer ENI has announced a significant gas and condensate discovery in Egypt, following the successful drilling of the Denise W 1 exploration well in the Temsah concession, located offshore in the Eastern Mediterranean.
Preliminary estimates indicate approximately 2Trillion cubic feet (Tcf) of gas initially in place (GIIP) and 130Million barrels of associated condensates, the company said in a statement April 7, 2026.
The discovery comes at a time of desperate hunger for new gas in Egypt, a onetime gas producing, processing and distribution hub, which has been hobbled by declining production in the last four years, falling from approximately 6Billion standard cubic feet per day (6Bscf/d) in 2022 to less than 4Bscf/d by 2025..
ENI is the leading hydrocarbon producer in Egypt and, like other producers, it has been heavily courted by Karim Badawi (the Minister of Petroleum appointed in July 2024), to press the throttle on exploration and boost production. Under Badawi’s watch, Egyptian Gas Holding Company (EGAS) has proposed an increase to the price it pays for domestically produced gas from five E&P companies by 30-50%, with deepwater fields set for the highest increases.
Badawi arrived at the Ministerial desk to meet a pile of debt, owed by the government to international oil and gas partners. As of June 30, 2024, the month before he took the job, the arrears were at a peak of $6.1Billion. He launched a repayment plan, paying back nearly $5Billion in overdue bills in the last 20 months, part of an effort to encourage companies to intensify operations and address declining gas production.
ENI’s spud of the Denise W 1 well follows the binding agreement signed in July 2025 with Egyptian General Petroleum Company (EGPC) and Egyptian Gas Holding Company (EGAS) for the 20-year renewal of the Temsah Concession. ENI operates the Denise development license within the Temsah Concession with a 50% interest, along with bp, which holds the remaining 50%. The asset is managed by Petrobel, the operating company of the joint venture between ENI and EGPC.
The Denise W discovery is located 70 kilometres offshore, in a water depth of 95 metres, and less than 10 kilometres from existing infrastructure; this allows for significant synergies for accelerated development. “Like the nearby Temsah field, which has been producing since 2001, it features an excellent-quality gas-bearing sandstone reservoir with approximately 50 metres of net pay”, ENI said in a statement.
The Hidden Costs — and the Indigenous O&M Opportunity Prepared By: Bade Olotu / Mark H. Smith Contributions from: Dimeji Bassir
1. Executive Summary The Nigerian upstream sector is currently witnessing a significant trend: indigenous operating companies are acquiring substantial fleets of land rigs to execute their drilling/workover campaigns ⁽⁵⁾. One of the most publicly documented recent examples is Sahara Group, which announced the acquisition of seven new rigs as part of its upstream growth plan ⁽¹˙²˙³˙⁴⁾. Industry reporting also points to additional acquisitions by other indigenous players, including one reported land-rig purchase by Matrix Energy Group ⁽⁵⁾. While this demonstrates a commitment to local content and operational control, this paper argues that the Asset Owner-Operator model is fundamentally unsustainable for the majority of these companies. Driven by intermittent funding, irregular drilling programmes, and the high technical demands of rig maintenance, this model has historically led to stranded assets and financial losses. In practice, indigenous producers often face funding constraints and stop-start drilling programmes, and the combination of high carrying costs (preservation, licensing, crewing readiness and maintenance) and intermittent utilisation can leave rig assets idle for extended periods ⁽⁷⁾. In Nigeria’s rig disposition records, for example, the St. Elaine swamp barge (listed against Aiteo’s operations) appears as Standby and Not Licensed (May 2023) ⁽⁶⁾, consistent with “stranded/underutilised” rig capacity risk. In a similar vein, industry reporting in 2025 on Neconde’s OML 42 notes that its drilling/workover campaign scheduled to begin in June of that year was to be the first rig-based development operation since it acquired the asset in 2011, illustrating long programme gaps that weaken the economics of owned rigs ⁽⁸⁾. And there is the example of Seplat Energy, which disclosed it had agreed to acquire four rigs from Cardinal Drilling Services Limited in 2021 ⁽⁹⁾, and later reported selling the “turnkey rigs” (formerly Cardinal) for $12.3Million in 2024/2025 ⁽¹⁰⁾ — an outcome consistent with the stranded-asset and value-erosion risk highlighted in this paper.
“The current Chinese/international operator-driven O&M model can deliver short-term capability, but it is structurally suboptimal because it creates a “shadow compliance” problem: rigs may be locally owned, yet operational control, high-value decision-making, and a large share of economic benefits remain foreign-dominated. Indigenous O&M firms are the practical mechanism for making the Nigerian Oil & Gas Industry Content Development Act and NCDMB objectives real”
The core position of this paper is: • Rig ownership only works sustainably when an operator has a long, well-funded well inventory, consistent execution governance, and the technical/maintenance ecosystem to run rigs at high utilization with high reliability. • For many indigenous operators, those conditions do not hold (short work scopes, intermittent funding, logistics constraints, people constraints, spares constraints, and weak “asset-integrity discipline”). • The result is predictable: low utilization + high fixed cost + rising downtime + declining safety/compliance margin, which erodes value quickly. • However, the same reality creates a strong, scalable Operations & Maintenance (O&M) services opportunity: third-party rig management, maintenance systems, spares strategy, competence assurance, and performance-based uptime delivery. This paper therefore argues that the industry should pivot from a model of asset ownership to one of strategic outsourcing, positioning local O&M contractors as the critical enablers of indigenous drilling campaigns, establishing an imperative for a shift from “everyone should own rigs” to “owning is optional; running well is the differentiator.” 2. What Is Driving the Operator-Owned Rig Push? Historically, rig ownership in Nigeria was the domain of dedicated service companies (e.g., KCADeutag, Mallard Bay, Hilong, HPCN, etc). However, the last three years or so have seen a seismic shift. Indigenous operators, seeking to guarantee rig availability and capture perceived cost savings, have invested heavily in their own fleets. Recent rig acquisitions in the public-domain include: Shoreline — 3 Land Rigs ⁽²¹⁾; Matrix Energy — 1 Land Rig; Sahara Group — 7 Land Rigs ⁽¹˙²˙³˙⁴⁾. This trend has fundamentally altered the rig ownership matrix in Nigeria. Even when it is not economically optimal, operators are pulled into rig ownership by a mix of commercial, operational, and psychological drivers: • Perceived control of schedule and availability: operators want to avoid rig scarcity, long lead times, and day-rate volatility. • Local content and “national capability” framing: owning assets can signal seriousness to regulators, host communities, and financiers. • Fear of being deprioritised by contractors: some operators believe contractor rigs will always go first to the “bigger payers.” • Misreading of unit economics: a rig can look “cheap” at purchase price compared to multi-year day-rate spend — until full lifecycle costs appear (people, spares, audits, repairs, certification, overhauls, and NPT). • Asset-backed financing logic: some acquisitions are driven by the availability of equipment financing structures, not by confirmed well inventory. 3. Why Operator-Owned Rigs Often Become Unsustainable While the acquisition of rig assets appears to be a sign of growth, the financial and operational models underpinning them are often flawed. The following structural issues render this approach unsustainable: A. Portfolio Reality: Not Enough Wells to Carry the Fixed Cost • Many indigenous operators have drilling/workover sequences that are: too short (a handful of wells), too discontinuous (campaign gaps), too uncertain (inadequate subsurface data, approvals, access, partner alignment), and too funding-sensitive (cashflow and FX volatility). • A land rig’s economics demand high utilization. When campaigns pause, the rig still carries crew cost, preservation/stacking cost, insurance, yard cost, OEM support subscriptions, certification upkeep, and a continuous maintenance burden. • When stacked for long periods, rigs do not just sit idle — they deteriorate. This leads to a phenomenon where the cost of maintaining the idle rig exceeds the cost of hiring a third-party rig when needed. Reality: An operator may drill two wells per year but must pay for rig crew, maintenance, and storage for the remaining months in the year. Consequences: You can “own the rig” but still be unable to “afford to run the rig.” B. Intermittent Funding → Stop-Start Operations → Integrity Decay Stop-start rigs degrade faster than steadily utilised rigs: preventive maintenance gets deferred; cannibalization of parts begins; “temporary fixes” become permanent; and deferred overhauls compound into major failures. Drilling is a high-capex activity. Many indigenous operators rely on cash calls, joint venture (JV) funding, or debt financing, which are often subject to delays. Reality: When funding dries up mid-campaign, the operator is still left with a rig to run, accumulating significant day-rate liabilities to themselves (in internal accounting) or forcing them to cannibalize other budgets to maintain the asset. Consequences: Downtime then rises, and the rig becomes a stranded asset that needs a significant capital injection to recover. C. Maintenance and Spares Are a Business by Themselves Owning a rig is not the same as sustaining a rig. A rig is a complex industrial asset requiring a specialised supply chain for spares, routine maintenance, and periodic recertification. A modern rig requires structured maintenance (CMMS discipline), critical spares strategy (min/max, reorder points, consignment), OEM interface management, planned shutdowns, reliable workshops, and supply chain lead-time control. When these are weak, failures migrate from “random” to “systemic,” causing chronic NPT and unsafe workarounds. Reality: Operators are oil and gas producers, not drilling contractors. They often lack the streamlined procurement processes and vendor relationships that dedicated service companies possess to source spares cheaply and efficiently. Consequences: Maintenance costs for operator-owned rigs are often significantly higher, and downtime is more frequent due to a lack of specialised in-house expertise. D. Skilled Personnel Scarcity Becomes the Bottleneck Operating a rig requires a highly skilled, certified crew. In the owner-operator model, crews often face uncertain employment continuity between campaigns. Nigeria’s experienced rig talent pool is limited, and competition is intense across drilling, workover, and projects. Operators that buy rigs often underestimate: the depth of roles needed (not just crews — also planners, reliability engineers, QA/QC, HSE, materials, warehouse, training assessors), competence assurance requirements, and the true cost of retention (rotations, welfare, career structure). Reality: If an operator has no wells for six months to a year, they cannot retain a full, competent crew. When the next campaign arrives, they must hire a new team, leading to a loss of procedural memory and increased safety risks. Consequences: When staffing quality drops, downtime and incident exposure rise. E. Fiscal Risk: Affiliate Service Arrangements and Transfer Pricing A further, often overlooked dimension of the operator-owned rig model is the fiscal exposure that arises when an operating company engages an affiliate entity to provide rig-related services — maintenance, technical support, procurement, or crew supply. For instance, Nigerian Production Sharing Contracts (PSCs) impose strict conditions on such arrangements: charges from affiliates must reflect actual cost only, must be consistent with international market prices, and must contain no element of profit ⁽¹⁹⁾. NNPC / Nigerian Upstream Petroleum Regulatory Commission (NUPRC) benchmarks these charges against industry averages for comparable affiliate services across other contractors. Where these guidelines are not rigorously adhered to, transfer pricing risk emerges. Transfer pricing — the pricing of goods, services, or intangibles exchanged between related parties — directly affects the taxable income reported by each entity and, therefore, the government’s share of petroleum profit under PSC terms. Inflated affiliate charges reduce the contractor’s reported profit (and thus the state’s take), while underpriced services do the reverse. Tax authorities are empowered to adjust prices to arm’s-length equivalents, triggering additional assessments, penalties, and, in cross-border scenarios, the risk of double taxation. For indigenous operators managing rigs through related-party service entities, non-compliance with PSC affiliate-service provisions or to contract law arm’s length principles could therefore result in significant fiscal losses — not only for the operator through penalties and back-taxes, but for the Nigerian state through erosion of petroleum revenues. Robust governance, transparent cost documentation, and independent benchmarking of all affiliate rig-service charges are essential safeguards. 4. Historical Precedents Nigeria has had multiple past attempts where operator-linked or financially structured rig ventures struggled to remain commercially strong over time. The market is littered with examples that validate our position: • Aiteo: Acquired rigs that ultimately failed to deliver sustained value and became non-performing assets ⁽⁶⁾. • Neconde: Similarly struggled to utilise 2 rigs effectively, facing the same utilization and funding challenges ⁽⁷˙⁸⁾. • Seplat (Cardinal / Omega): The challenges faced with the Cardinal and Omega rigs (formerly associated with Seplat’s JV) highlight that even major indigenous players are not immune to the complexities of managing drilling assets. This is a widely referenced case cluster that involved Cardinal Drilling Services and its financing disputes, which became publicly reported and required resolution actions involving Seplat Energy and Access Bank ⁽⁹˙¹⁰⁾. The “Stranded Asset” Syndrome: These precedents confirm that when the well sequence stops, the asset quickly transforms from a strategic tool into a financial liability. 5. Rig Ownership vs Rig Access: The Decision Logic The following test framework helps operators assess whether rig ownership is rational for their specific portfolio circumstances:
Position: For many indigenous operators, the honest answers are “NO” across at least 2–3 of these tests — meaning ownership becomes a prestige asset rather than an economic asset.
6. The Market Opportunity: The Rise of the Indigenous O&M Specialist If operators continue to buy rigs (whether or not it’s optimal), the industry will urgently need competent third parties — specialised Operations & Maintenance (O&M) companies — who can run these assets at drilling contractor standards. A. The Value Proposition of O&M Services For efficiency and utilisation, operators should engage O&M contractors to manage their rig assets under a “Fleet Management” or “Fee-for-Service” model. • For the Operator: they retain the asset on their books (if they wish) but transfer the headache of maintenance, staffing, and uptime reliability to a specialist. This converts a fixed cost (ownership) into a variable cost (operations). • For the O&M Provider: they achieve economies of scale by managing multiple rigs for multiple clients, ensuring high utilization of their technical staff and maintenance workshops. A credible O&M provider is effectively a rig operating company inside the operator’s rig business unit, delivering: • Operations Management: rig SOPs, PTW integration, well control readiness, daily reporting, NPT tracking, performance routines. • Maintenance & Reliability: CMMS setup and execution discipline, preventive maintenance compliance, reliability engineering (bad-actor elimination, RCA, planned shutdowns). • Spares & Materials Management: critical spares lists and min/max strategy, vendor framework agreements and consignment options, inventory accuracy and warehousing controls. • Competence Assurance: role profiles, training matrices, assessments, crew stability plan and succession coverage. • HSSE & Compliance: audit readiness, equipment certification tracking, contractor management systems, incident learning, barrier management focus (well control, lifting, pressure systems). B. The Strategic Imperative: Why Indigenous O&M Companies Must Lead Indigenous-led rig O&M is a strategic necessity for Nigeria’s upstream sustainability, not just a local-content preference. The current Chinese/international operator-driven O&M model can deliver short-term capability, but it is structurally suboptimal because it creates a “shadow compliance” problem: rigs may be locally owned, yet operational control, high-value decision-making, and a large share of economic benefits remain foreign-dominated. Indigenous O&M firms are the practical mechanism for making the Nigerian Oil & Gas Industry Content Development Act and NCDMB objectives real — where OEMs provide the technical backbone, but Nigerians lead execution, workforce development, logistics, and the growth of local supply chains. Indigenous O&M companies also have the deepest fit with Nigeria’s operating realities — community interface, security, bureaucratic navigation, and local spares/repair ecosystems — translating into faster problem-solving and lower downtime than foreign rig O&M operating models. Critically, they reduce capital flight by retaining profits, taxes, and reinvestment in-country, and they resolve the “technology transfer paradox” by structuring O&M around knowledge transfer (maintenance management, reliability engineering, calibration, and innovation), rather than keeping these capabilities with expatriate partners. In sum, while foreign-led O&M has filled an immediate gap, it treats the symptom — not the underlying capacity deficit. Empowering indigenous O&M companies is the only scalable route to aligning operational efficiency with local content mandates, keeping more value in Nigeria, building durable national rig-management capability, and fostering a competitive local ecosystem that lowers cost and improves service quality for operators. C. O&M Service Models That Can Actually Work in Nigeria7. Recommendations and Conclusion A. Recommendations For Indigenous Operators • Treat rig ownership as a portfolio decision, not a procurement decision. • If you cannot keep >70–80% utilization over time, plan for: third-party backfill work, shared rig pools, or chartering instead of owning. • Ring-fence rig operations with contractor-grade governance and KPIs. • If you own a rig, budget explicitly for critical spares, OEM interface, planned overhauls, and competence assurance (not just “crew cost”). • Where affiliate entities are engaged for rig-related services, ensure all inter-company charges are documented at actual cost, independently benchmarked to international market rates, and fully compliant with PSC affiliate-service provisions — treating this not as an administrative formality but as a core governance obligation with direct fiscal consequences.
For O&M Service Providers • Build a repeatable operating system (CMMS + spares + competence + HSSE) that can be deployed rig-by-rig. • Offer performance-linked commercial models (operators respond to cashflow and accountability). • Create a “multi-operator spares ecosystem” to break lead-time pain. • Invest in a small, elite reliability/maintenance engineering core — this is where most value is created.
For Nigerian Revenue Authorities The surge in operator-affiliated rig ownership presents a specific compliance frontier for the Nigerian Revenue Service (NRS): where an operating company engages a related-party rig entity, transfer pricing scrutiny must ensure all inter-company charges reflect genuine arm’s-length values — preventing quiet profit-shifting that erodes Nigeria’s petroleum industry-related tax base.
“When stacked for long periods, rigs do not just sit idle — they deteriorate. This leads to a phenomenon where the cost of maintaining the idle rig exceeds the cost of hiring a third-party rig when needed.”
B. Conclusion The Nigerian market is likely to see more operator-owned rigs, as shown by recent public announcements and industry reporting. But ownership without sustained utilization and contractor-grade operating discipline will repeatedly destroy value. That is exactly why rig O&M is the scalable opportunity: it converts stranded or underperforming operator-owned assets into reliable execution capacity — without requiring each operator to reinvent the drilling-contractor business inside their organisation. The future of efficient drilling in Nigeria lies not in fragmented ownership, but in centralised, expert management. By separating the ownership of the asset from the operation of the asset, the industry can avoid the cycle of stranded rigs and create a robust, sustainable service sector that ensures rigs are working, maintained, and available when needed. Equally, as indigenous operators bring affiliate service relationships into their rig management structures, the integrity of the fiscal framework demands that such arrangements be governed with the same rigour applied to any arm’s-length commercial relationship. Failure to do so risks transforming a local-content and cost-control strategy into a source of regulatory exposure and fiscal loss — undermining the very value that rig ownership was intended to create.
References 1. Sahara Group. (2025, September 25). Sahara Group kicks off bold upstream growth with 7 new rigs and spudding of Okoloma-02. Retrieved from https://www.sahara-group.com 2. Sahara Group. (2025, October 5). Sahara Group targets 350,000 bbl/d, acquires 7 rigs to boost upstream operations. Retrieved from https://www.sahara-group.com 3. The Punch. (2025, October 9). Sahara acquires seven rigs, targets 350,000 bpd oil output. Retrieved from https://punchng.com 4. Drilling Contractor. (2025, October 6). Sahara Group acquires seven rigs to boost upstream operations. Retrieved from https://drillingcontractor.org 5. Africa Oil+Gas Report. (2025, December 11). A caravan of oil rigs soon to descend on the Niger Delta. Retrieved from https://africaoilgasreport.com 6. NUPRC. (2023, May 12). NUPRC rig disposition report [PDF]. Retrieved from https://www.nuprc.gov.ng 7. Business Day. (2026, January 20). Local oil firms face funding hurdle as ambitions outstrip capital. Retrieved from https://businessday.ng 8. The Guardian. (2025, October 28). Neconde raises output to 50,000 barrels per day on OML 42. Retrieved from https://guardian.ng 9. Seplat Energy. (2021, October 28). Unaudited results for the nine months ended 30 September 2021 [PDF]. Retrieved from https://www.seplatenergy.com 10. Seplat Energy. (2024, October 29). Unaudited results for the nine months ended 30 September 2024 [PDF]. Retrieved from https://www.seplatenergy.com 11–21. [See original paper for additional references.]
Disclaimer: This article includes information on operators acquiring rigs, drawn from publicly available internet sources as cited in the bibliography. While every effort has been made to ensure accuracy, readers are encouraged to verify details independently, as these references may evolve or contain interpretations subject to change. The authors and publisher disclaim liability for any reliance on this content.
Italian explorer ENI has announced a significant discovery each in deep-water offshore two west African countries in one single week in mid-February 2026.
In Angola, ENI and BP are each 50 % owner of operator Azule Energy, whose “discovery of oil volume of approximately 500 Million barrels in the Algaita-01 exploration well”, was announced February 13, 2026 by the country’s upstream petroleum regulator: National Agency for Petroleum, Gas and Biofuels (ANPG).
Algaita-01 was drilled in Block 15/06, in a water depth of 667 metres and approximately 18 kilometres from the Olombendo FPS.
“It intercepted oil-bearing sandstones in Upper Miocene reservoir intervals”, the ANG said in a release. “Preliminary interpretation of wireline logging and fluid samples indicates the presence of multiple reservoir intervals with excellent petrophysical properties and fluid mobilities”.
Azule Energy operates Block 15/06 with 36.84% with partners including SSI Fifteen Limited (26.32%) and Sonangol E&P (36.84%).
In Côte d’Ivoire, ENI operates Block CI-501, where it reported, on February 16, 2026, “ a significant gas and condensate discovery, successfully drilling Murene South-1X, the first exploration well” in the acreage. “The discovery, named Calao South, confirms the potential of the Calao channel complex that includes also the Calao discovery and represents the second largest in the country after Baleine, with estimated volumes of up to Five Trillion cubic feet (5Tcf) of natural gas and 450Mllion barrels of condensate (approximately 1.4Billion barrels of oil equivalent). The discovery was made in high-quality Cenomanian sands”.
ENI’s 90% operatorship has the state hydrocarbon company Petroci Holding as 10%) partner. “Murene South-1X is located approximately Eight kilometres in southwest of Murene-1X discovery well in the adjacent CI-205 block. Drilled by the Saipem Santorini drilling ship to a total depth of around 5.000 metres in a 2.200 metre water depth, the well underwent an extensive data acquisition campaign. Murene South-1X confirmed the main hydrocarbon bearing interval with a gross thickness of around 50 metres, with excellent petrophysical properties. Murene South-1X will undergo a full conventional drill stem test (DST) to assess the production capacity of the Calao discovery”.
Currently, the Baleine field produces over 62,000Barrels of oil and more than 75Mllion cubic feet of gas per day MMscf/d from Phases 1 and 2. With the launch of Phase 3, production is expected to rise to 150,000BOPD and 200MMscf/d.
UAE Dana Gas has reported encountering new gas in the North El-Basant 1 exploratory well, onshore Nile Delta, in Egypt.
The company describes the hit as “significant”.
While not citing either net or gross reservoir footage, Dana Gas claims estimated reserves of 15 – 25Billion cubic feet (Bcf) of gas in the accumulation, which it says is “ahead of expectations”.
“Production is expected to exceed eight million standard cubic feet of gas per day (8MMscf/d) once connected to the national network “, Dana explains in the statement.
North El-Basant 1 is the fourth of the 11 development and exploration wells under the Sharjah headquartered company’s $100Million investment programme to boost gas recovery and long-term production to support domestic gas production, increase reserves and meet growing energy demand.
Earlier in 2025, Dana Gas completed the drilling of three wells successfully adding 10MMscf/d. The programme is expected to increase long-term production and add approximately 80BCF in recoverable gas reserves throughout the programme’s life.
“In parallel, the company successfully re-completed three wells, adding 9MMscf/d of production outside the current investment programme. Accordingly, drilling and recompletion programmes executed are adding approximately 30MMscf/d of new production.
Dana Gas expects to spud the fifth well in the programme, the Daffodil exploration well, in the first week of January 2026..
Italian major ENI never stopped being a constant fixture of the Libyan oil patch, even in the heyday of the 2011 to 2012 revolt and the immediate aftermath, when several other operators were on the retreat.
But the company has been absent from the country’s offshore in the last five years, while it continued operations onshore.
Now its resumption of offshore operations is the subject of headlines in energy news media worldwide.
ENI’s re-entry of the exploratory well C1-16/4 (also known as BESS-3) in contractual Area D (previously Block NC-41), in Libya’s northwest, is meant to offset dwindling gas output from key assets. It is part of the country’s overall bounce in drilling and field redevelopment activities.
ENI is focused on Libya’s gas exports to Italy, which have been dropping, reaching to 21-year lows in 2024 and on course to fall significantly further in 2025 according to the influential Middle Eastern Economic Survey MEES. But Italy itself is not necessarily demanding more gas. The September 2025 Monthly Gas Market Report published by the Gas Exporting Countries Forum, says that Italy’s natural gas consumption fell sharply in August 2025, down 13% y-o-y to 113Billion cubic feet, largely due to reduced demand from the power sector.
C1-16/4 lies approximately 95kilometres off the Libyan coast and around 15kilometres from the Bahr Essalam gas field.
ENI operates the Libyan offshore asset via Mellitah Oil and Gas Company, its joint venture with NOC, the state hydrocarbon company.
In September 2025, Karim Badawi, Egypt’s Minister of Petroleum, took the unusual step of visiting the London headquarters of bp, along with state company with EGAS to sign a Memorandum of Understanding, to drill five wells in the Mediterranean.
Less than a month later, on October 13, 2025, bp announced the award of a rig contract to Valaris for the DS-12 deep water drillship rig to drill five wells offshore Egypt, in water depths ranging from 300 to 1,500 metres.
Drilling operations are expected to commence in 2026, with the programme aiming to accelerate the development and production of gas reserves while utilizing existing production facilities in the company’s operational heartlands of West Nile Delta.
bp reports that it has made 10 exploration discoveries across its global portfolio in the first half of 2025, with two of those discoveries in Egypt. The Fayoum-5 gas discovery well and the El King-2 exploration well, both part of the West Nile Delta basin.
The British major plans to increase production to 2.3-2.5Million barrels of oil equivalent a day in 2030 with the capacity to increase production out to 2035.
The rig contract signing ceremony took place at the Ministry of Petroleum and Mineral Resources and was attended by Karim Badawi, Minister of Petroleum and Mineral Resources and Mahmoud Abdel Hamid, Chairman of the Egyptian Natural Gas Holding Company.
London listed Energean Oil &Gas, which pulled out of Egypt and other countries to concentrate, in part, on Morocco, has derailed badly in its first operation in the Northwest African kingdom.
Its exploration target in the appraisal well, Anchois-3, has been a spectacular disappointment, with the prognosed gas bearing reservoirs turning out to be water wet.
“Clearly, we don’t see the upside we were hoping for that would justify a major development,” Energean chief executive Mathios Rigas told analysts.
The project’s commerciality, he declared, “will depend on the type of development and negotiations we will have to have with Moroccan government about gas prices”.
But Chariot Energy, which sold part of its equity to now-operator Energean, is looking at the bright side. “Further detailed work will be needed to understand the impact of these results,” it says in a release.
Anchois-3 was to test the eastern upside of the Anchois gas field, discovered with the Anchois-1, which had been audited as hosting total remaining recoverable resource in excess of 1Trillion Cubic Feet (Tcf), comprising 361Billion Cubic Feet (Bcf) 2C contingent resources and 690 2U prospective resources.
The appraisal and exploration well, Anchois-2, “drilled safely, on time, and on budget, discovered excellent quality, dry gas across seven reservoirs with approximately 150 metre net pay”, Chariot had reported.
With Anchois-3 result, Chariot’s claim that the Anchois gas field “covers an area of approximately 1,794km²”, is also up in the air. The water depths range from the coastline to 850 metres.
The current plan may also be in abeyance. It was to be subsea-to-shore development involving three initial producer wells, comprising the existing Anchois-2 well, the Anchois 3 well and potentially an optional fourth well.
Chariot itself describes the well as a pilot hole, saying “the primary objective of the initial pilot hole was to evaluate the upside exploration potential of reservoirs in the Anchois Footwall prospect, which were found but are interpreted to be water-bearing.”
The so called pilot hole was plugged and abandoned, and a sidetrack — the main well bore now drilling ahead has intercepted gas in the B sands, one of the five-already encountered- sands that were meant to be appraised before the probe goes deeper to target the North Flank exploration prospect which could hold 213 Bcf of gas.
“Preliminary interpretation indicates the presence of gas bearing reservoirs in the B sands”.
Khalda Petroleum Company, the joint venture between the American independent Apache (APA Corp.) and the Egyptian General Petroleum Corporation (EGPC), has announced a new oil discovery in West Fewebs-1 in the Kalabsha Development Area of the Egyptian Western Desert.
The well “was tested by drilling 270 feet into the Paleozoic sands, and the recovery on a 1-inch production opening was 7,165 barrels of oil and 23Million cubic feet of associated gas per day”, Khalda says in a release. The oil is light, with API gravity of 44 degrees.
“Electrical logs of the well confirmed the presence of hydrocarbon indications in the Paleozoic component with a total net thickness of 462 feet”, the statement explains.
Apache hadn’t focused much on expectations from this exploratory drilling in its 1st Half 2024 operations report. While the company talked of “rebalancing our drilling and workover rig programmes in Egypt”, it was more concerned with field optimisation. “We benefitted from newly implemented water injection initiatives on our base production and redirected workover rig capacity to opportunities on recompletions and offline volumes”.
The Norwegian geophysical firm, TGS, has signed an agreement with Mauritania’s Ministère du Pétrole, des Mines et de l’Énergie which strengthens its position as sole provider of Mult Client subsurface data for oil and gas exploration and evaluation in the Northwest African country.
The agreement allows TGS “to integrate, enhance and license additional subsurface data, strengthening their position as the sole provider of multi-client subsurface data in the Republic”.
It also “allows TGS to significantly expand the onshore and offshore data available across Mauritania”.
The new subsurface data includes ten narrow azimuth input three dimensional 3D seismic surveys, processed by ION in 2022 using 3D pre-stack depth migration, resulting in a fully merged and migrated volume of 19,092 km². Additionally, there is approximately 84,000 km² of 3D surveys from offshore block relinquishments, offshore and onshore wells, and around 20,000 line km of onshore 2D seismic data within the Taoudeni Basin.
Offshore exploration in Mauritania has focused on the Cenozoic salt-draped channel plays, highlighted by the discovery of the Chinguetti field in 2001. Since then, most wells have targeted this proven play. Recent exploration in deepwater and neighboring regions has revealed significant potential in the Cretaceous channel sand plays and shelf clastics above the carbonate platform. Untapped potential also exists in the carbonate platform and syn-rift areas.
TGS thinks “these critical datasets will provide comprehensive subsurface insights, connecting drilled prospects to underexplored regions like the deepwater. When combined with TGS’ extensive database along the MSGBC basin, this will enable a thorough mega-regional analysis, enhancing understanding of analogs and variations along the margin.”
Even when it is not economically optimal, operators are pulled into rig ownership by a mix of commercial, operational, and psychological drivers:
7. Recommendations and Conclusion
