Once operational, the Raia gas project is expected to deliver up to 16 million cubic metres of natural gas per day. This output could account for around 15% of Brazil’s natural gas demand, strengthening national energy security while also contributing to Equinor’s international equity production and long-term cashflow. The project is operated by Equinor (35%) in partnership with Repsol Sinopec Brasil (35%) and Petrobras (30%). The drilling work builds on the partners’ extensive deepwater expertise, including prior collaboration on the Bacalhau field, where the same drillship previously participated.

Alongside drilling, work continues on integrating and preparing the floating production, storage and offloading unit (FPSO), a central component of the Raia gas project’s development concept. The FPSO will process oil/condensate and gas produced from subsea wells.

Natural gas from the Raia gas project will be transported via a 200-kilometre pipeline linking the FPSO to Cabiúnas in Macaé, Rio de Janeiro state. With a total investment of around USD 9 billion, the development represents Equinor’s largest international commitment to date. The FPSO is projected to rank among the most carbon-efficient globally, with average CO₂ emissions intensity of approximately 6 kg per barrel of oil equivalent.

“Raia is Equinor’s largest project under execution and marks the deepest water depth operation in our portfolio. Together with our partners and suppliers, we are applying world-class technology and decades of offshore expertise. While drilling takes place, integration and commissioning activities on the FPSO are progressing well putting us on track towards a safe start of operations in 2028”, Says Geir Tungesvik, executive vice president, Projects, Drilling and Procurement.

The P-78 is deployed in the Búzios field in the Santos Basin, located approximately 180 to 230 km off the coast of Rio de Janeiro, Brazil. Permanently moored at a water depth of around 2,100 meters using a spread-mooring system, the vessel ranks among the largest FPSOs ever delivered to Brazil. The facility is designed to produce up to 180,000 barrels of oil per day and 7.2 million cubic metres of gas per day, with a minimum storage capacity of 2 million barrels of crude oil. Through the six P-Series FPSO projects Seatrium is building – P-78, P-80, P-82, P-83, P-84 and P85. Brazil is expected to gain an additional 1.305 million barrels of oil per day of production capacity.

The achievement was supported by extensive collaboration with Petrobras and Seatrium’s international vendor network. Together, they worked to ensure that critical systems were fully prepared for operation, including the main process compressors, export compressors, and gas injection compressors. These systems are essential to enabling the safe and efficient introduction of gas injection into the production process. Throughout the development and commissioning phases, Seatrium maintained strict safety, quality, and operational standards across all participating facilities. Delivering the first gas injection according to schedule reflects the company’s strong Health, Safety and Environment performance, as well as its consistent track record of completing complex offshore energy projects on time.

Following the successful milestone, Seatrium is moving forward toward the next key phase of the project, which includes completion of the delivery stage and the Final Acceptance of the vessel by Petrobras. The company is focused on ensuring a seamless transition to full operations and supporting the long-term performance of the FPSO.

The Lapa field is located in block BM-S-9A in the pre-salt Santos basin and began production in December 2016 using the FPSO Cidade de Caraguatatuba. The start-up of the Lapa Southwest project strengthens the field’s operational performance while utilizing existing infrastructure. By linking the new wells to the FPSO, the project expands output capacity and supports continued production growth from the offshore development. The latest start-up also highlights the long-term role of the Lapa field within the broader offshore portfolio managed by TotalEnergies and its partners.

The commissioning of the Lapa Southwest project comes as TotalEnergies continues to expand its exploration and production presence in Brazil. The project follows the start-up of Mero-4 in May 2025 and precedes the planned start-ups of Atapu-2 and Sépia-2, which are expected in 2029. TotalEnergies’ exploration and production portfolio in the country currently includes nine licenses, of which four are operated. In 2025, the company reported an average production level in Brazil of 184,500 barrels of oil equivalent per day, underscoring the country’s importance to its global upstream portfolio.

Repsol is also strengthening its exploration and production activities in Brazil, where the country is considered one of its core growth regions. The Raia project located in BM-C-33 within the Campos Basin is among its key projects. Being developed in partnership with Equinor and Petrobras, the project is expected to begin operations in 2028 and has the potential to become one of the country’s most significant sources of natural gas.

TotalEnergies has maintained a presence in Brazil for 50 years. Its activities extend across Exploration & Production, gas, renewable electricity including solar and wind, lubricants, and chemicals. In addition to upstream investments such as the Lapa Southwest project, the company is expanding its renewable energy footprint in Brazil. In October 2022, TotalEnergies entered a partnership with Casa dos Ventos, Brazil’s leading renewable energy player, to jointly develop a 12 GW renewable energy portfolio including onshore wind, photovoltaic, and battery storage projects.

The exploration well 1-BP-13-SPS was drilled at the Bumerangue block, located 404 kilometers from Rio de Janeiro, in a water depth of 2,372 meters, as disclosed by BP. In 2022, BP secured the rights to the block that holds a 100% interest in it, with Pré-Sal Petróleo S.A. as the production sharing contract (PSC) manager.

Gordon Birrell, BP’s Executive Vice President for Production & Operations, said: “We are excited to announce this significant discovery at Bumerangue, bp’s largest in 25 years. This is another success in what has been an exceptional year so far for our exploration team, underscoring our commitment to growing our upstream. Brazil is an important country for bp, and our ambition is to explore the potential of establishing a material and advantaged production hub in the country.”

Results of the rig-site study show elevated concentrations of carbon dioxide (CO2). A laboratory analysis will now be conducted to further define the reservoir and fluids found, giving further information on the potential of the block. Depending on regulatory approval, additional appraisal operations are also scheduled.

Notably, Bumerangue is BP’s tenth discovery in 2025, after Beryl and Frangipani in Trinidad, Fayoum 5 and El King 5 in Egypt, Far South in America’s Gulf, Hasheem in Libya, and Alto de Cabo Frio Central in Brazil.

Further discoveries in Angola and Namibia have been made by Azule Energy, the 50-50 joint venture of BP with Eni. Eni and BP recently entered into an agreement with the Egyptian General Petroleum Corporation (EGPC) and the Egyptian Natural Gas Holding Company (EGAS) for the development of exploration activities in the Mediterranean.

Additional discoveries in Namibia and Angola were made through Azule Energy, BP’s 50-50 joint venture with Eni. Eni and BP also recently signed a deal with the Egyptian General Petroleum Corporation (EGPC) and the Egyptian Natural Gas Holding Company (EGAS) to initiate exploration activities in the Mediterranean.

This is in alignment with the major oil and gas discovery giant’s agenda to grow its global upstream production to  capacity to 2.3-2.5 million barrels a day equivalent in 2030, with the opportunity to increase production out to 2035. Along with the Bumerangue prospect drilling campaign this year, an exploration well planned for the Tupinambá block in 2026, in terms of the Brazilian plans.

Project Overview: The Strategic Importance Of Gato Do Mato

Gato do Mato is one of a slew of ambitious, cut-rate initiatives to tap Brazil pre-salt oil reserves, which are believed to hold massive potential. Located in the Santos Basin, the project involves the development of two adjoining blocks, BM-S-54 and Sul de Gato do Mato. This enormous development will focus on BM-S-54, which was acquired in 2005, and Sul de Gato do Mato, which was obtained via a production-sharing agreement in 2017. Combined, they cover an area believed to be home to significant oil and gas resources, including an estimated 370 million barrels of recoverable oil.

As a deep-water gas-condensate discovery, Gato do Mato is set to serve as a cornerstone in Brazil’s rising oil output. Designed to produce up to 120,000 barrels of oil per day, the project would provide further stability and growth in Brazil’s oil and gas sector.

Technological Advancements in Floating Production and Storage

The Gato do Mato project is centered around an FPSO, or floating production, storage and offloading vessel. Its innovative technology will enable the extraction, processing and storage of oil on the high seas, generating effective production at the depths of the Santos Basin. Designed for the deep-water environment under which it will operate, the FPSO will allow continuous oil production with minimal operational risk.

By resolving on a FPSO vessel, we underscored engineering excellence and innovation, the organizing principles of the Gato do Mato endeavor. The project also employs high-engineering solutions in its design to minimize geological difficulties in pre-salt reservoirs. The project will significantly enhance Brazil’s energy security, with over an estimated 300 million barrels of recoverable resources.

Environmental Concerns and Future Gas Exports

Gato do Mato will not only represent a new style of urban living but will be environmentally sustainable too. Early activities will be concentrated on reinjecting natural gas into the reservoir to maintain pressure and improve oil recovery. Following this method, the emissions of gas are the least and according to environment global standards, project is implemented.

The project also has potential future gas exports to onshore facilities. This flexibility is vital for allowing Brazil to make the most of the natural gas reserves in the Santos Basin by increasing gas production to meet domestic demands while also lining it up for the international gas markets.

Strategic Timeline: Operations and Outlook for Gato do Mato

The Brazil Gato do Mato project is anticipated to begin operations in 2029 — ushering in a new chapter in Brazil energy development. The project meets SHEL’s objective of sustaining and growing its liquid production over the near to medium term, while also providing an excellent return on investment, enhancing SHEL’s participation in energy transition. SHEL’s investment in the Gato do Mato project is anticipated to yield a net internal rate of return (“IRR”) significantly north of the hurdle rate applicable to SHEL’s upstream operations, indicating the financial success of the project.

Most importantly, as the project moves towards the goal of production, SHEL, and its partners are firmly committed to conducting the project as safely, environmentally and socially responsible as possible. If developed successfully, Gato do Mato will take Brazil one step closer to becoming a leading energy player on the world stage, with long-term economic benefits for the country.

Finally, the approval of the Final Investment Decision of the Gato do Mato project is a great milestone for Shell Brasil and the partner consortium. It demonstrates a common commitment to driving Brazil’s energy future through strategic investment, innovation and environmental stewardship. By capitalizing on this opportunity, Petrobras’ new Gato do Mato development shows that Brazil is writing the new chapter in its oil story, unlocking critical resources and ensuring that it remains a leader in the oil and gas industry.

Asia is forecasted to account for 60% of this demand increase and, without a surprise, happens to be led by China. According to the IEA, the demand from Asia especially in China is going to be driven totally by petrochemical feedstocks and also by refined fuel demand stagnating.

Apparently, the global supply of oil saw an increase of 240 kilobarrels per day (kb/d) in February 2025 and reached 103 mb/d. This was driven primarily due to Kazakhstan’s output of OPEC+, which reached an all-time high because of the Tengiz field expansion. Apart from this, Iran and Venezuela also pushed their production ahead of the tighter sanctions.

It is well to be noted that the growth estimates when it comes to the fourth quarter of 2024 and the first quarter of 2025 have already been revised to 1.2 million barrels per day (mb/d) YoY because of lower-than-anticipated delivery data as well as macroeconomic uncertainty. The IEA went on to note that the recent data pertaining to oil demand happens to have underperformed in developing as well as advanced markets.

Non-OPEC+ production is anticipated to see an increase by 1.5 mb/d in 2025. The US, Canada, Brazil, and also Guyana happen to be contributing most when it comes to the supply, with the US producing at an all-time high. The fresh US tariffs on Mexico as well as Canada, w.e.f. from April 1, may as well see an impact on the flow as well as prices. Apparently, Canada and also Mexico comprised almost 70% of the US crude imports in 2023.

It is worth noting that the OPEC+ production could very well see stability in 2025 if the voluntary cuts happen to extend beyond April. The fact is that the actual supply rise from the unwinding cuts may as well be less than the minimal 138 kb/d, as just Saudi Arabia and Algeria happen to have the capabilities to raise the output.

IEA estimates say that other members happened to exceed their targets by 1.2 mb/d in February 2025.

Notably, the global crude runs slashed by 570 kb/d MoM in February 2025 to 82.8 mb/d, thereby continuing the fall from last December’s five-year high of 84.3 mb/d. It is forecasted to average almost 83 mb/d in 2025. Interestingly, the refining margins have recovered as the crude prices have gone on to see a dip.

Demand for global oil exceeded supply, leading to a drawdown of 40.5 million barrels from stocks in January 2025. Non-OECD crude investors went on to see a slump of 45.3 mb/d, whereas the OECD stocks gained momentum by 11.2 mb, which includes a 25 mb growth when it comes to the industry’s crude stocks. Oil on water saw a dip of 6.7 mb in January 2025, but it did observe a rebound in February. The prices of crude oil dipped by almost US$ 7 per barrel in February 2025 and also early March. ICE Brent futures saw a drop of US$ 11 a barrel throughout 8 weeks and is trading at almost US$ 70 a barrel. As per the IEA, global oil demand may exceed supply by 600 kb/d in 2025, potentially tightening the market. If OPEC continues to ensure to unwind the output cuts without any kind of overproduction addressing, another 400 kb/d can as well get added into the market.

Compressions stations are located at Piuma, Aracruz and Prado.

Construction

Construction of the Cacimbas-Vitória section commenced in mid-2005 and was completed in November 2007.

Work on the GASCAV section was started in 2006 and completed in 2007. This section was built in three phases. The first phase included a 78km segment from Cabiúnas terminal to Campos de Goytacazes in Rio de Janeiro. The 126km segment from Campos de Goytacazes and the Piúma compression station was constructed in the second phase.

The final phase of GASCAV included a 96km segment between the Piúma compression station and the pressure reduction station in Serra in Espiírito Santo.

Construction of the GASCAC section commenced in March 2008 and was divided into six. The parts were constructed simultaneously. The section included 151 river crossings and 88 unique crossing area projects and was completed in March 2010.

The GASCAC section included different types of terrain, resulting in several construction challenges. To overcome these problems special technologies were used during construction. In rocky terrains, rocks were blasted using explosives in a controlled and localised manner instead of the conventional ditch opening process.

The Pipe Sak technique was used to concrete the pipelines. This technique involved use of woven polypropylene bags filled with gravel. These bags are attached to the pipeline to stop buoyancy in floodplains.

A vacuum lifter was used for lifting pipes. The device uses vacuum suction to lift pipelines without ropes, wires or straps.

Pipeline route

The Cacimbas-Vitória section of the pipeline transports natural gas produced at the Peroá-Cangoá fields to Vitória in Espírito Santo. From Vitória, natural gas is carried to Cabiúnas, in Rio de Janeiro, by the GASCAV section of the pipeline.
The GASCAC section transports natural gas from Cacimbas to Catu in Bahia. It is also linked to the Catu-Carmópolis-Pilar pipeline.

Contractors

Petrobras awarded a $239m EPC contract to Sinopec in April 2006 for constructing the GASCAV section of the pipeline. Sinopec was also awarded the EPC contract for the GASCAC section in January 2008.

“The GASCAC section transports natural gas from Cacimbas to Catu in Bahia.”

In 2007, TenarisConfab won a contract to provide pipes for the GASCAC section.

Siemens Energy won a contract in 2008 to supply 11 compressor trains for the three compression stations of the project. Siemens awarded a $10m contract to Rolls-Royce to supply 11 RF3BB-20 centrifugal gas compressors. The compressors are powered by 7.68MW Siemens SGT-200 gas turbines.

Socoril do Brasil, a unit of Socotherm, was awarded a $50m contract for providing anti-corrosion coatings for the pipeline. The company provided three-layer anti-corrosion coating of PLASTYKOTE and internal flow coating of INNERKOTE.

The Barracuda and Caratinga fields lie 160km east of Macae in block BC-50B, offshore Brazil. Together, they will add 30% to the current one million barrels per day output from the Campos Basin region. The two fields cover a combined area of 230km2.

The fields lie in water depths of 785m in Barracuda and 1,035m in Caratinga, although some wells sit in deeper water, down to 1,148m. Recoverable reserves for Barracuda are estimated at 867 million barrels of oil and 10.7 billion cubic metres of gas, while Caratinga, to the south, contains an estimated 362 million barrels and four billion cubic metres of gas. Since 1998, the fields have produced from 20 wells tied back to the Petrobras P-34 floater.

New discoveries

In May 2010 Petrobras reported two light oil discoveries in the Caratinga field. The first accumulation was a post-salt reservoir discovered at a depth of 3,950m by well 6-CRT-43-RJS. The reservoir is estimated to contain about 105 million barrels of oil.

The second accumulation was a pre-salt reservoir discovered at a depth of 4,275m. The reservoir is an extension of a previous discovery made by Petrobras in February 2010. The reservoir is estimated to contain 40 million barrels of oil. The discovery was made by exploratory well 6-BR-63A-RJS drilled by Diamond Offshore’s Ocean Worker semi-submersible rig.

The new discoveries will be developed following tests to evaluate their productivity and may be linked to the P48 platform. Petrobras is expected to submit an evaluation plan to the National Petroleum Agency for the new discoveries.

Barracuda and Caratinga contracts

“The fields lie in water depths of 785m in Barracuda and 1,035m in Caratinga.”

The Petrobras-owned Barracuda and Caratinga Development Corporation awarded the $2.6bn field development contract to Halliburton’s Kellogg Brown & Root (KBR) and Halliburton Energy Services business units.

This contract covered a full engineering, procurement, installation and construction (EPIC) contract, which included the construction of the wells and the fabrication and installation of flowline and risers, as well as the construction and installation of two FPSOs.

Development of the Barracuda field was done in two phases, with the pilot system and the final system. The field came onstream in late 2004. The final system was developed by FPSO P43, which is hooked by a spread mooring system at a depth of 800m.

The field has 34 wells, out of which 20 are production wells and 14 injecting wells. Barracuda produces an average of 170,000bopd and Caratinga produces 141,000bopd. The Caratinga field has 21 wells – 13 production and eight injection wells hooked to the Caratinga Production platform.

In September 2009 Framo Engineering was awarded a contract to install a multiphase pumping system at the Barracuda field. The helicon-axial-type pump will be the first-of-its-kind to be installed. It will pump oil, water and gas from a satellite well in the field to the P48 platform.

Installation of the system will help to increase the oil production and recovery rate. It will also help to produce from wells located away from the production platforms.

Subsea development

The EPIC contract covered the construction of 55 wells (22 horizontal producers, two multilateral horizontal producers, eight horizontal injectors and eight piggyback injectors). The development also included the 15 old wells connected to the P34.

“Barracuda has 81 pull-ins while Caratinga has 52 pull-ins.”

Part of the produced gas was used for gas lift in the wells, while water injection strategies demand between 200,000 and 250,000bpd. The drilling is being carried out by Petrobras under a subcontract to KBR. Between four and seven rigs operate in the field simultaneously, including the Transocean Driller, Diamond Ocean Alliance and R&B Falcon’s Peregrine III.

FPSOs P43 and P48

The development is based on two large FPSOs, which KBR bought from Stena. These FPSOs were planned be moored 12.7km apart.

Barracuda uses the P43, originally Stena Continent, which was converted at the Jurong Shipyard in Singapore. The topsides were integrated at the Maua Jurong yard in Niteroi near Rio. Oil production from P43 began in December 2004.

Caratinga was developed by converting Stena Concordia into the P48. This work was carried out at the BrasFels yard in Angra dos Reis, near Rio. Each of the FPSOs has a storage capacity of two million barrels. In addition, each FPSO has production capabilities of 150,000bpd. The FPSOs are moored by 18 polyester and chain lines each via a taut-leg system.

“The fields lie in water depths of 785m in Barracuda and 1,035m in Caratinga.”

The oil production from P48 started in February 2005. The subsea wells are connected individually to the FPSO by flexible risers. The total cumulative riser length will be 420km or over 170 reels. Each well will have a production flowline and annulus line.

On Barracuda there are 81 pull-ins while Caratinga has 52 pull-ins. Both have 26 spare slots. These flexible risers range in size from 4in to 9.5in and are manufactured by Wellstream. Another 40 reels contain 243km of control umbilicals.

Halliburton KBR used reel vessel Toisa Perseus and DSND’s Commander 3000.

Barracuda and Caratinga export

Oil is offloaded into a shuttle tanker from the two FPSOs, while the gas is piped via two 9.5in diameter gas export risers to a 60t pipeline end manifold. A 12in gas export riser takes it the PNA-1 platform.

“The Bauna field is estimated to hold reserves of 113 million boe while the Piracaba field is estimated to hold reserves of 83 million boe.”

The Bauna field, owned solely by Petroleo Brasileiro (Petrobras), is estimated to hold reserves of 113 million barrels of oil equivalent (boe) while the Piracaba field is estimated to hold reserves of 83 million boe.

Operations at the two fields are being carried out through the floating production storage and offloading (FPSO) vessel Cidade de Itajai, which is operated by the Odebrecht and Teekay (OOG-TK) consortium.

The FPSO is currently connected to well 9-SPS-88, which has a production capacity of up to 12,000 barrels per day. Production from the two fields is expected to intensify with the connection of ten additional wells to the FPSO by August 2013. The ten wells will comprise five production wells, four water injection wells, and one gas injection well.

Geology of Bauna and Piracaba oil fields

The oil fields contain light oil in sandstone reservoirs located above the salt layer at depths of about 2,160m.

Development of the Bauna and Piracaba oil fields

The development plans (DP) and the declaration of commerciality of light oil in the two fields were submitted to the Natural Gas and Biofuels Agency (ANP) of Brazil in February 2012. The owner had earlier carried out the Exploratory Assessment Program involving an extended well test (EWT) at the two fields prior to the declaration of the commercial viability from the fields.

Details of the FPSO conversion for the development of Bauna and Piracaba fields

The contract for the delivery of the FPSO for the development of Bauna and Piracaba fields was awarded to Teekay in October 2010. The contract was worth $370m.

It called for the detailed engineering, installation and integration of 16 topside modules, installation of the mooring lines and power generation systems, and upgrade of the accommodation facilities. The project also involved the installation of the piping and electrical cabling systems.

Related project
Sapinhoa Oil Field, Santos Basin, Brazil

The Sapinhoa (formerly known as Guara) oil field is located in block BM-S-9 of the Santos basin, about 310km off the coast of Rio de Janeiro, Brazil.

FPSO Cidade de Itajai was converted from the Aframax tanker MT Arc II. The conversion of the Aframax tanker was carried out at Sembcorp Marine’s Jurong Shipyard in Singapore and was delivered to the operators in November 2012.

The scope of the $351m contract includes the conversion of the tanker and operation of the facility for nine years, which is extendable by an additional six years. The contract for the FPSO was signed after the tanker was partly converted at the Jurong shipyard.

The FPSO is designed for 15 years of deployment without dry docking. It has a capacity to process up to 80,000 barrels of light oil and two million cubic metres of gas per day. It is placed at a water depth of 275m, about 210km off the Sao Paulo coast. The produced oil from the facility is shipped using relief tankers.

The topside solutions for the FPSO were supplied by Siemens. The equipment included two SGT-400 power generation units, a sulfate removal unit (SRU), and an electrical house (E-house).

Cidade de Itajai FPSO dimensions and features

The Cidade de Itajai FPSO measures 244.5m in length and has a moulded breadth of 42.65m. It has a deadweight tonnage capacity of 105,384t with capacity of carrying 206.7m³ of potable water on its port tank as well as starboard tank, and 668.2m³ of potable water on its aft peak tank.

The FPSO can accommodate 70 people and is equipped with two lifeboats. It also features a helideck for the Sikorsky S92.

The FPSO also has two electric-hydraulic pedestal cranes with a lifting capacity of 25t at an outreach of 35m and 15t at an outreach of 47m.