Orinoco Belt, Paria, Delta, Zulia fields

On June 5th, 2025, Petróleos de Venezuela PDVSA signed at least nine new agreements with foreign service providers: marking a strategic response to United States sanctions. The strategy to partner with smaller, often non-western firms reflects efforts to offset this loss, bypassing traditional legislative approval. Agreements cover operations in Zulia state and the Orinoco Belt, critical regions for Venezuela's oil production, as reported by the Offshore Technology Report on June 6th, 2025.

Zulia accounts for 15% of Venezuela's oil production. The Orinoco Belt holds 70% of reserves. Each contract spends twenty years, with PDVSA maintaining at least a 50% stake in crude output, as reported by Reuters, ensuring state control: while allowing foreign management of operations. Expected production boost from these deals is targeted at 600,000 barrels per day, as reported by Bloomberg. This is a significant increase from May's average 1,007,200 barrels per day: aiming to reach pre-sanction levels. Actual production may vary due to operational challenges.

Recent OPEC data shows a minimal 0.2% decline to 1,005,000 barrels per day in June 2025, suggesting caution as per OPEC monthly oil market report. Capital expenditure is estimated at 20 billion dollars, crucial for infrastructure and technology upgrades. The Yahoo Finance report supports this figure with no recent updates indicating a change, though the bolivar equivalent may increase due to inflation via devaluation. Current exchange rate as of June 11th, 2025 is: 1 United States dollar equals 99.6983 Venezuelan bolivars as per Banco Central de Venezuela and the annual inflation rate is estimated at 172%.

Venezuelan common practice is to provide prices in United States dollars, using the symbol REF with bolívar figures calculated according to the Venezuelan central bank, which updates at the close of each banking day. Financing is structured through PDVSA crude shipments, circumventing traditional financial systems restricted by sanctions. This method involves prepayments and barter arrangements, as detailed in PDVSA's financing strategy, per the Energy Intelligence Report. Partner companies benefit from certain tax exemptions, enhancing deal attractiveness. These exemptions include: reduced royalties and income taxes for ten years per Yahoo Finance.

Operational challenges, particularly in projects like Junín 2 may affect timelines: due to logistical issues per Offshore Technology Report. These challenges include delays in infrastructure development, supply chain disruptions, and difficulties in coordinating with international partners under sanctioned constraints. For instance, Junín 2 involving Petrovietnam faces hurdles in upgrading facilities and drilling new wells: potentially pushing back the targeted production increase. Complexity of extra heavy oil processing and need for advanced technology, often restricted by sanctions, exacerbate these challenges: requiring innovative solutions and potentially extending project timelines. Operational rights granted to foreign companies allow them to manage existing wells, and sell the output diverging from PDVSA's traditional exclusive trading rights.

The shift aims to sustain foreign currency inflows, crucial for Venezuela's economy amidst hyperinflation and scarcity: as highlighted by the Council of Foreign Relations. The financing method relying on crude shipments aligns with Venezuela's strategy, to use barter and nondollar transactions, as seen in recent oil flows to Cuba. Foreign currency inflows occur through the sale of oil output by foreign companies, which repatriate profits in United States dollars or other hard currencies, bypassing PDVSA's direct trading monopoly. These profits are then channeled back to PDVSA or the Venezuelan government, through agreed financial arrangements: such as joint venture profit sharing, or service fee payments. This mechanism provides Venezuela with much needed foreign exchange, which can be used to import essential goods and stabilize the economy despite high inflation.

May 2025 monthly inflation rate was 26%: significantly higher than April's 18.4%, indicating the urgency of these inflows. Capital expenditure of $20 billion, financed through crude, underscores the scale of investment needed to revive production: especially given underinvestment due to sanctions. The tax exemptions for partners, as detailed in the Offshore Technology Report, are designed to attract smaller firms with less experience, potentially echoing challenges from past deals under Hugo Chávez. This could pose operational risks, given the lack of known expertise among some partners.

Legal basis for these deals is Venezuela's anti-blockade law, which bypasses National Assembly approval, raising questions about transparency and legality, especially under United States sanctions. This law plays a role in authorizing the contracts reflecting Venezuela's assertion of sovereignty, against what it views as illegitimate coercive measures. There is no United Nations authorization for United States sanctions. Strategically, these deals plan to replace Western oil majors, aligning with Venezuela's broader narrative of productive independence, as seen in the situational monitoring and supervision rooms oversight of mixed companies.

The focus on non-western partners like China, absorbing 450,000 barrels per day in May 2025, indicates a pivot to alternative markets: potentially mitigating the impact of United States tariffs, which impose 25% secondary tariffs on importers of Venezuelan oil. PDVSA plans to sign additional contracts in the coming months, as per the Bloomberg and offshore technology reports, suggesting a sustained effort to expand partnerships. This aligns with Venezuela's goal to reach two or three million barrels per day, restoring OPEC+ influence. These deals focus on service providers, rather than traditional joint ventures: reflecting a shift to operational management, potentially reducing reliance on technical expertise from sanctioned western firms.

The effectiveness of these deals is debated. The Council on Foreign Relations highlights the risks of underinvestment and mismanagement, exacerbated by sanctions: which could hinder production increases. The involvement of smaller firms, some with limited experience, may pose operational challenges: potentially impacting the predicted 600,000 barrels per day output. The humanitarian impact, with reduced revenues affecting basic goods remains a concern. Emphasis on Zulia and Orinoco regions, critical for Petroboscán and Petropiar suggests integration with existing operations. China's involvement, as a known player in sanction evasion, strengthens Venezuela's pivot to Asia, supporting these deals through technical and financial backing. It is not directly involved, reflecting the broader policy of productive independence.

We shall now discuss details on Nabep's withdrawal. The primary motive for Nabep's departure is United States pressure, exerted through sanctions and regulatory actions. The United States Treasury Department's Office of Foreign Assets Control OFAC has targeted entities involved in Venezuela's oil sector, as detailed in United States Treasury sanctions: Venezuelan state-owned oil company PDVSA pursuant to executive order 13,850.

Nabep is linked to a Florida asphalt trading company which faced scrutiny due to allegations of sanction evasion. This pressure likely forced Nabep to withdraw, to avoid further sanctions or legal action. Nabep's departure may also reflect a strategic realignment to multiple risks, associated with United States scrutiny. The situational monitoring and supervision room established to oversee all operations, and ensure compliance with international standards. It became a liability under sanctions. Nabep's exit allows it to focus on less visible operations such as logistics and financing, as suggested in Nabep's role in Venezuela's oil sector by Energy Intelligence.

Financial burden of maintaining a presence in the monitoring room is coupled with the risk of asset freezes, as seen in United States freeze assets of Venezuelan oil officials, likely influencing Nabep's decision. The cost benefit analysis favored withdrawal to preserve capital for other ventures. The United States imposed sanctions on PDVSA in 2019, targeting entities like Nabep involved in oil exports. A 2023 report from the United States Department of State highlights increased scrutiny on companies linked to sanction evasion: directly impacting Nabep. Evidence includes frozen assets and travel bans on associated individuals, as detailed in Treasury sanctions on senior Venezuelan officials of the United States Department of the Treasury.

Investigative journalism by organized crime and corruption reporting has exposed Nabep's role, increasing United States pressure. These reports led to congressional inquiries, and further regulatory actions forcing to reconsider its position. United States Venezuela dialogues have included discussions on sanctions compliance, per Council on Foreign Relations. The pressure on Nabep is part of broader efforts to enforce sanctions, evidenced by statements from United States officials demanding transparency. These dialogues have intensified since 2023, with the Biden administration pushing for stricter adherence to sanction regimes. The inclusion of Nabep in these discussions underscores its significance in the United States strategy to curb sanction evasion, further justifying its departure from the monitoring room to avoid escalation.

Petrocedeño's accommodation strategies require leveraging existing infrastructure. Petrocedeño, a joint venture between Total Energies, Equinor and PDVSA must adapt by utilizing existing infrastructure. Upgrader at Jose Antonio Anzoátegui petrochemical complex Jose is capable of processing 180,000 barrels per day: it remains operational. Nabep's departure requires PDVSA to assume greater oversight, potentially increasing costs, but ensuring continuity. Petrocedeño can seek new partnerships to fill the gaps left by Nabet. Entities with experience in logistics and financing could step in to support Petrocedeño's operations. Additionally, smaller firms like Maurel & Prom, with expertise in exploratory drilling, may offer niche capabilities.

Chevron's technologies such as enhanced oil recovery EOR methods can be integrated into Pedrocedeño's operations. This technique is effective in heavy crude fields and can mitigate production declines. This requires coordination with PDVSA, but Chevron's expertise secured through its joint ventures remains a critical asset. Similarly, ENI's experience in heavy oil projects, particularly in the Dación field since the 1990s, can be leveraged for Petrocedeño's benefit, enhancing extraction and upgrading capabilities. Petrocedeño must enhance compliance with international standards, to navigate United States pressure.

Implementing blockchain for supply chain tracking can ensure transparency, reducing risks associated with Nabep's departure. Petrocedeño must adapt: by leveraging existing infrastructure, seeking new partnerships, and integrating advanced technologies. Research suggests Venezuela's nine oil deals in June 2025 are a strategic response to sanctions, aiming for 600,000 barrels per day with $20 billion investment. It seems likely these deals involving non-western firms will offset Chevron's and Nabep's exit, though controversy persists over legality and operational risks. The evidence leans towards PDVSA maintaining control, with plans for more contracts shaping Venezuela's energy future, amidst geopolitical tensions.

On June 7th, 2025, Venezuela through its state-owned oil company PDVSA and its joint ventures, signed at least nine oil deals to boost production amidst United States sanctions. These deals involve international and domestic companies, targeting both onshore and offshore fields: focusing on joint ventures and service contracts. The agreements aim to leverage foreign expertise and capital to revitalize Venezuela's oil industry, which has been severely impacted by declining production and infrastructure decay since the early 2000s. The situational monitoring and supervision room established in May 2025 likely oversees these deals: to ensure alignment with the absolute productive independence plan.

Deal one: PDVSA, ENI and Petroindependencia at Carabobo Block 3. Also, PDVSA and ENI Perla gas field. ENI's involvement in Venezuela includes two significant projects. The Carabobo Block 3 is part of a deal with PDVSA and Pedroindependencia, and the Perla Gas Field is a separate operation. The Carabobo Block 3 is part of the Orinoco belt, known for its vast oil reserves and challenging extraction conditions: due to extra heavy crude. The Perla gas field is situated in the Gulf of Venezuela, specifically in Los Taques municipality of Falcón State, approximately 50 kilometers offshore in water depths of 60 m, highlighting any diversified portfolio across both onshore and offshore operations. Additionally, ENI has historical ties to the Dación field, located in the Independencia municipality of Anzoátegui.

Carabobo Block 3 primarily contains extra heavy crude oil with an API gravity ranging from 8 to 10°, necessitating extensive upgrading processes to reduce viscosity and enhance commercial value, involving sophisticated methods like coking and hydrocracking. In contrast, the Pearl gas field contains natural gas reserves, estimated at 17 trillion cubic feet and associated condensate: with no significant crude presence. It focuses on gas development that aligns with global energy transitions. The Dación field, historically managed by ENI since 1997, also dealt with heavy crude similar to Carabobo, but its operations ended in 2010: providing a backdrop for any current capabilities in handling challenging crews.

Carabobo block 3 was discovered in 2003 by PDVSA, following preliminary exploration in the Orinoco belt since 1936. It was first drilled in 2004 by PDVSA. Despite early exploration, production remained minimal, due to technical and financial challenges: reaching only 20,000 barrels per day in 2023, with no significant development until recent deals. Sanctions from 2019 onward further stalled progress. ENI's historical involvement includes the Dación field starting operations in 1997, peaking at 120,000 barrels per day in 2003, and ending in 2010 due to nationalization under Hugo Chávez, reflecting a decline driven by lack of investment. The Perla gas field was discovered in 2009. ENI and Repsol began production in 2015 at 450 million cubic feet per day: reaching 800 million cubic feet per day by 2023. It remains operational with plans to expand highlighting its ongoing significance.

The collaboration between PDVSA, ENI and Petroindependencia aims to significantly boost production at Carabobo Block 3, targeting 75,000 barrels per day by 2029, or potentially 150,000 barrels per day by 2031 or 2032, depending on infrastructure development and market conditions. The infrastructure timeline of 36 months for upgrading facilities, and drilling new wells reflects the complexity of extra heavy oil processing. It requires significant investment in upgraders and drilling technology. For the Perla gas field, currently operational, the expected increase is to reach 1,200 million cubic feet per day by 2025, with potential for higher by 2030: such as 1,500 million cubic feet per day, depending on further investments and market demand, supporting Venezuela's energy diversification strategy and reducing oil dependency.

The development of Carabobo Block 3 is strategically vital for Venezuela as it taps into the Orinoco Belts 303.3 billion barrels of reserves: to boost national oil production and strengthen its position within OPEC+, leveraging any historical expertise from the Dación field and Pedroindependencia's operational support, including Chevron's involvement. This project, distinct from prior initiatives in other Venezuelan regions, focuses on heavy oil extraction and upgrading: enhancing supply security, and reducing reliance on sanctioned markets. The Perla gas field, as the largest offshore gas field in Latin America, is crucial for reducing oil dependency: influencing global energy markets by enhancing natural gas supply. It supports Venezuela's navigation of geopolitical tensions: aligning with global energy market dynamics, and ensuring long-term term market influence. Dación field located in Anzoátegui state has not been opened for new joint ventures since its nationalization in 2010 under Hugo Chávez administration. Operations ceased that year due to Venezuelan government's decision to take full control: ending any management begun in 1997.

Dación field infrastructure included over 1,000 wells, a central processing facility capable of handling 120,000 barrels per day, and a pipeline network connecting to the José Antonio Anzoátegui petrochemical complex. Key components were the gas processing plant, which handled associated gas production, and water injection systems for enhanced oil recovery. Dación field also featured tertiary recovery methods, like steam injection critical for heavy oil extraction. However, since its nationalization in 2010, much of this infrastructure has fallen into disrepair: with reports indicating that only 30% of wells are operational as of 2023. The processing facility operates at 20% capacity due to lack of maintenance and investment. Dación field remains under PDVSA's direct control, with no foreign joint ventures permitted.

Production is minimal around 5,000 barrels per day, due to deteriorated infrastructure and lack of technological updates. Dación is not currently open for new joint ventures, but its strategic location within the Orinoco Belt and existing infrastructure make it a potential candidate for recovery. The abandonment was due to nationalization and subsequent underinvestment, not technical insolvency, suggesting recovery is feasible with significant investment in infrastructure rehabilitation and modern enhanced oil recovery techniques. No current plan for reactivation or partnership has been publicly announced. Dación Field's strategic importance lies in its historical peak of 120,000 barrels per day in 2003. Its strategic location in the Orinoco belt and existing infrastructure make it a candidate for recovery, enhancing Venezuela's oil output and OPEC+ influence if reopened.

Deal two: PDVSA and Repsol Ayacucho block 2. The Ayacucho block 2 is situated in the Anzoátegui state, deep within Venezuela's interior. Ayacucho 2 is part of the Orinoco belt, known for its vast oil reserves and challenging extraction conditions due to extra heavy crude. This location is strategically significant as Anzoátegui state has been a historical hub for oil production, with Repsol's prior involvement in nearby projects like Petrozuata. Ayacucho block 2 primarily contains extra heavy crude oil, with an American Petroleum Institute gravity ranging from 7 to 9°, necessitating extensive upgrading processes similar to those required for Carabobo block 3. The crude type demands sophisticated methods like coking and hydrocracking, to reduce viscosity and enhance commercial value: aligning with Repsol's expertise in heavy oil processing.

The Ayacucho block 2 was identified in 2001, during a period of extensive exploration in the Orinoco Belt by PDVSA and international partners. Initial drilling began in 2005, by a consortium including Repsol which had been operating in Venezuela since the 1990s, through the Petrozuata project in the Cerro Negro area of located in San Tomé, Anzoátegui state. Petrozuata, a joint venture with PDVSA, peaked at 120,000 barrels per day in 1998 before facing declines due to underinvestment and sanctions from 2019 onward. Ayacucho block 2 itself produced minimally, reaching only 15,000 barrels per day by 2023: with development stalled due to technical and financial challenges initially, and further exacerbated by United States sanctions since 2019, which restricted both foreign investment and technology access.

Ayacucho 2 expected production increase: The collaboration between PDVSA and Repsol aims to significantly boost production at Ayacucho block 2, targeting 200,000 barrels per day within four years by 2029. fully achievable given Repsol's technical expertise and a 13 month infrastructure timeline, for building upgrading plants and drilling infrastructure. This timeline reflects the need for specialized technology: such as upgraders and advanced drilling techniques, to handle extra heavy crude. The distinction between the four year targets and a longer timeline is less critical here, as the operational plan is designed to meet the 200,000 barrels per day goal by 2029, leveraging Repsol's experience from Petrozuata and other global heavy oil projects. This increase is vital for Venezuela's goal to restore production levels, particularly in the context of sanctions, enhancing its capacity to influence global energy markets.

The development of Ayacucho block 2 is strategically crucial for Venezuela, as it taps into the Orinoco belt's estimated 303.3 billion barrels of reserves, to boost national oil output and strengthen its position within OPEC+. Repsol's involvement, distinct from its earlier Petrozuata project, focuses on heavy oil extraction and upgrading: enhancing its upstream portfolio and aligning with European energy needs, particularly in the context of diversifying energy sources, amidst global market shifts. The Petrozuata project was a joint venture between Repsol and PDVSA: it was operational from 1998 to 2012. Petrozuata featured an upgrader with a capacity of 120,000 barrels per day, designed to process extra heavy crude into synthetic crude oil, syncrude suitable for export.

Petrozuata infrastructure included over 600 wells, a pipeline to the José Antonio Anzoátegui petrochemical complex, and a diluent recovery unit. The upgrader used delayed coking and hydrotreating processes, critical for handling 8 to 10 American Petroleum Institute crude. Additionally, there was a significant gas processing facility, for associated gas and water injection systems for enhanced oil recovery. Since Repsol's exit in 2012, due to nationalization and sanctions, the infrastructure has seen limited maintenance: with the upgrader operating at 40% capacity by 2023, and many wells abandoned. Petrozuata is under PDVSA's control, producing around 30,000 barrels per day, far below its peak of 120,000 barrels per day in 1998. The infrastructure is partially operational but requires substantial rehabilitation, particularly the upgrader and enhanced oil recovery systems.

Petrozuata is not currently open for new joint ventures, but its strategic importance within the Orinoco belt and existing infrastructure make it a prime candidate for recovery. The abandonment was due to nationalization in 2012 and subsequent sanctions, not technical reasons, suggesting recovery is possible, with investment in technology and infrastructure upgrades critical for heavy oil processing. Its recovery could boost export capabilities and reduce dependency on new builds, aligning with global market needs. Its upgrader and pipeline infrastructure from San Tomé to José Antonio Anzoátegui petrochemical complex, both in Anzoátegui state are for heavy oil processing, reducing new build dependency.

La Salina field is located in the La Rosa parish of Cabimas municipality, Zulia state, approximately 5 kilometers from Cabimas city, on the eastern shore of Lake Maracaibo. La Salina field is part of the Bolívar coastal field complex, historically significant for conventional oil and gas production. La Salina was operated by Repsol from 1999 to 2009. The proximity to Lake Maracaibo and Cabimas City makes it a visible part of the region's oil landscape, but direct access is limited to authorized personnel. Repsol began operations in La Salina in 1999, focusing on conventional oil and gas: with production peaking at 50,000 barrels per day and 100 million cubic feet per day of gas by 2003.

La Salina infrastructure included: over 300 wells, a gas processing plant, and water injection systems for enhanced oil recovery. The field also featured secondary recovery methods like gas lift, critical for maintaining production from mature reservoirs. However, operations ended in 2009 due to nationalization under Hugo Chávez administration. In 2025, the field produces only 5,000 barrels per day under PDVSA's control, with infrastructure operating at 15% capacity due to lack of maintenance and sanctions since 2019. Recovery potential is moderate as the field is not exhausted but requires significant rehabilitation: of enhanced oil recovery systems, and modern drilling techniques. Estimates suggest 200 million recoverable barrels, potentially reaching 40,000 barrels per day by 2030, with investment aligning with recent recovery efforts in Boscán and El Furrial.

Campo Urdaneta is an offshore field in the western part of Lake Maracaibo, associated with La Cañada at the Urdaneta municipality of Zulia state. Campo Urdaneta is approximately 20 kilometers offshore from municipal capital, in water depths of 30 to 50 m. Repsol began operations in 1999, focusing on conventional oil and gas with production peaking at 50,000 barrels per day and 100 million cubic feet per day of gas by 2003. The infrastructure included over 300 wells, a gas processing plant, and water injection systems for enhanced oil recovery. The field also featured secondary recovery methods like gas lift critical for maintaining production from mature reservoirs. 

Campo Urdaneta operations ended in 2009, due to nationalization under Hugo Chavez. And as of June 11, 2025, the field produces only 5,000 barrels per day under PDVSA's control, with infrastructure operating at 15% capacity: due to lack of maintenance and sanctions. since 2019. Recovery potential is moderate, as the field is not exhausted but requires significant rehabilitation: of enhanced oil recovery systems and modern drilling techniques. Estimates suggest 200 million recoverable barrels, potentially reaching 40,000 barrels per day by 2030: with investment aligning with recent recovery efforts in Boscán and El Furrial.

Cerro Negro field is situated in the state of Anzoátegui, in the Orinoco belt known for its extra heavy crude. It is a historical hub for oil production. Repsol was involved in Cerro Negro starting in 1997, with production peaking at 120,000 barrels per day by 2000. The infrastructure included over 500 wells, an upgrader with a capacity of 100,000 barrels per day, and a pipeline to the José Antonio Anzoátegui petrochemical complex. The upgrader used delayed coking and hydrotreating, critical for extra heavy crude. Cerro Negro operations ended in 2007 due to nationalization, leading to Repsol's exit and by 2023 production was only 10,000 barrels per day under PDVSA's control with infrastructure at 30% capacity, due to sanctions and lack of investment. The field is not exhausted, with estimates of 500 million recoverable barrels. Recovery potential is high. similar to Petrozuata, potentially reaching 100,000 barrels per day by 2030: with rehabilitation of the upgrader and enhanced oil recovery systems enhancing Venezuela's heavy oil export capability.

Quiriquire field is located in the Maturín municipality, Monagas state. Quiriquire is situated approximately 40 kilometers southeast of Maturin city, in a region historically significant for both conventional and heavy oil production. Quiriquire is a rural area not directly part of the urban fabric of Maturín city. City residents can access the area by road, but the oil field of Quiriquire itself is not open to the public, due to operational and security restrictions. Quiriquire is known for its oil infrastructure, with the field being a key historical site, but visits are limited to authorized personnel. Quiriquire operations were begun by Repsol in 1996, producing 40,000 barrels per day by 2000, but the field was nationalized in 2007. The infrastructure included 400 wells, a central processing facility, and gas processing plants with water injection for enhanced oil recovery.

Quiriquire field focused on conventional oil, peaking before decline due to underinvestment. By 2023, production was only 2,000 barrels per day under PDVSA's control, with infrastructure at 5% capacity due to exhaustion and sanctions. Quiriquire field is largely exhausted with estimates of 50 million recoverable barrels, primarily from marginal wells. Recovery potential is low, unlike recent examples: as the primary reservoirs are depleted but secondary recovery could achieve 10,000 barrels per day by 2032, focusing on gas and marginal oil, supporting energy diversification. Repsol's departure from its Venezuelan operations was influenced by a combination of nationalization policies under Hugo Chávez administration, economic conditions and strategic decisions.

In 2007, Repsol departed operations at Cerro Negro and Quiriquire. Nationalization of the Orinoco Belt was the earliest, due to its strategic importance as the government's priority was to reclaim these assets. The 2007 decree specifically targeted Orinoco Belt projects, prompting Repsol's exit from Cerro Negro and Quiriquire. In 2009, Repsol departed operations at La Salina and Campo Urdaneta, as conventional fields in Zulia state were nationalized as part of a broader wave, influenced by the global financial crisis and the government's need for revenue. The delay compared to Cerro Negro reflects the different operational and strategic priorities between Orinoco's heavy oil and Zulia's conventional oil and gas.

In 2012, Repsol departed operations at Petrozuata. This latest exit was due to the phased nature of nationalization, with Petrozuata's joint venture structure requiring longer negotiations. The 2012 date also coincides with increased economic instability in Venezuela, making continued operation unviable for Repsol. These differences highlight the government's strategic approach to nationalization, prioritizing Orinoco assets earlier, while conventional fields in Zulia were addressed later, amidst broader economic challenges. Repsol's decisions were influenced by operational declines, regulatory changes, and the inability to maintain profitability under nationalized conditions.