Production at Brazil’s Mero field is set to ramp up with the arrival of SBM Offshore’s FPSO Alexandre de Gusmão.
The FPSO, which has a production capacity of 180,000 barrels of oil (BOPD) per day and gas compression of 12mn cubic metres per day, left China for Brazil in December. It is scheduled to spend 22.5 years in the country according to the terms of a lease and operation contract with Petrobras signed in 2021. Alexandre de Gusmão will be the fifth FPSO unit operating at Mero, joining Pioneiro de Libra, Guanabara, Sepetiba, and Marechal Duque de Caxias. The addition of the new FPSO is expected to boost the field’s production capacity to 770,000 bopd.
The Mero field, located in ultra-deep waters (2,100 m) approximately 190 km off the coast of Rio de Janeiro in the pre-salt layer of the Santos Basin, reached the milestone of 500,000 barrels of oil produced daily on 28 February. Discovered in 2010, Mero is governed by the Libra Production Sharing Contract, operated by Petrobras (38.6%), in partnership with Shell Brasil (19.3%), TotalEnergies (19.3%), CNOOC (9.65%), CNPC (9.65%) and Pré-Sal Petróleo SA (PPSA) (3.5%), which, in addition to managing the contract, acts as the Union’s representative in the non-contracted area (3.5%). The pre-salt currently accounts for 81% of Petrobras’ total production.
"Since extracting its first oil, Mero’s production has been marked by technological advances, innovation and production records. The 500,000 barrels per day mark is the result of the work of several areas and the new technologies used in our projects and in our day-to-day operations. The company remains committed to operating sustainably, optimising production in existing fields and, in doing so, helping to provide the energy needed for the country’s development," said Magda Chambriard, CEO of Petrobras.
"Mero is the third largest field in Brazil and, in terms of volume of oil in place and production, is behind only Tupi and Búzios, also located in the Santos Basin pre-salt. And production will increase even further with the completion of the ramp-up of the FPSO Marechal Duque de Caxias and the start-up of the FPSO Alexandre de Gusmão. We have invested heavily in technological development, which allows us to increase productivity while minimising greenhouse gas emissions, with safety and integrity of the facilities," said Sylvia Anjos, Petrobras’ Exploration and Production Director.
Globally, spending on well intervention is growing. In 2023, spending on oil and gas well interventions was expected (by Rystad Energy) to top US$58bn – representing a jump of almost 20% from the year before. Moreover, the intervention rate (how many wells go through the intervention process) was forecast to reach 17% in 2027, or 260,000 wells across the world.
“As a quick, efficient, and cost-effective method of maximising existing resources, interventions are going to be a hot topic in the years to come,” explained Jenny Feng, Supply Chain Analyst at Rystad Energy.
The future will see more years under the belt for the global wellstock which, by many accounts, is already past its prime. According to SLB, more than 60% of the world’s production already comes from mature assets and, by 2030, this is expected to grow to nearly 80%. This, the company stated, is leading to a mounting industry reliance on well intervention to meet growing demand and further promote the use of the activity as a form of proactive maintenance. In addressing a field’s production rate before figures are significantly impacted, the cost of the value chain can be reduced by up to 30% per barrel.
This increasing reliance is also acknowledged by the likes of Gilmore, which has pointed at the oil and gas capital expenditure (capex) over the next five years indicating a compound annual growth rate (CAGR) decline of -2.3% against global upstream operational expenditure growing at a CAGR of 2.5% in the same period. These trends, it suggests, “reflect models that aim to boost production through cost-effective and efficient well interventions, rather than drilling new wells.”
This is a sentiment endorsed by Yeriandi Utama, Well Site Manager – Completion & Well Intervention at Pertamina, who believes that well intervention has a formidable future in the Southeast Asian market. Speaking to Offshore Network, Utama explained, “One of the biggest priorities here and in Indonesia right now is how to utilise mature fields. There are fields that have been producing for a long time and we need to optimise them with low costs and as efficiently as possible.
“One of the most significant problems in mature fields in this region is sand production, an issue due to the formation type of the wells which is mostly sandstone. This represents perhaps the most imposing challenge in Southeast Asia – and I worked in Malaysia and Thailand where it was the same – alongside water production.”
Nauticus Robotics has announced the signing of a definitive agreement to acquire subsea robotics expert SeaTrepid International.
The strategic acquisition, which is projected to be completed by May 2025, underscores Nauticus’ commitment to innovation and revenue growth in 2025. By integrating Nauticus’ AI-driven autonomy software ToolKIT into SeaTrepid’s existing ROV fleet, the combination will showcase strong advancements in power efficiency and operational performance.
The ability of ROVs and Aquanaut to communicate at depth unlocks new service opportunities which enable the two autonomous systems to collaborate in delivering cutting-edge underwater solutions.
Bob Christ, SeaTrepid’s previous CEO and now President of SeaTrepid Operations, said, “We look forward to combining with Nauticus to extend ROV capabilities and enhance execution on a global scale."
David Huber, current SVP of Ocean Minerals, commented, “SeaTrepid is a long-time reliable subsea services provider to the deepwater companies I have worked for over the past several decades. With the combination of Nauticus' autonomous cutting-edge controls technology coupled with SeaTrepid's deep knowledge of subsea services, I see this as a breakthrough development for the offshore sector."
While subsea pipelines that are not in use are considered obstructions and need to be cleared by operators from the seafloor, there are a number of gaps in regulations governing the decommissioning of subsea pipelines.
For example, when the BSEE staff refuses to find a pipeline as obstructive, they may proceed to clear the inside of the pipeline, secure its ends, and leave it on the seafloor. This is considered an exception which has resulted in nearly 97% of disused pipelines to remain on the ocean floor. According to the Governmental Accountability Office (GAO), operators had left around 18,000 miles of disused pipeline at the bottom of the Gulf of Mexico, as of 2021. Although these structures might go on to become an obstruction over time, their removal has been largely unsuccessful in most cases, due to a lack of funding mandate allocated towards pipeline removal.
Another notable loophole is the absence of fixed decommissioning deadlines within existing regulations. Verification regarding the absence of obstructions on decommisioned pipeline sites are also not mandatory. Moreover, BSEE regulations do not require operators to monitor and report on decommissioned-in-place pipelines, nor does BSEE itself monitor decommissioned-in-place pipelines. There is also no fixed data on the extent to which the industry is actually complying with any of the agency regulations that have been laid out.
Elemental Energies has expanded its senior management team with the appointment of Ross Provan as Head of Decommissioning Solutions.
Ross will bring 18 years of projects and operational experience to the role, with expertise spanning drilling, facilities engineering, subsea, project assurance, construction and decommissioning.
In his new role, Ross will lead Elemental Energies’ focus on EPRD (engineering, preparation, removal and disposal) and the integration of services including the existing wells decommissioning capabilities across all areas of the work breakdown structure.
Mike Adams, Chief Executive Officer at Elemental Energies, said, “With global offshore decommissioning spend projected to double over the next two decades, the need for integrated, cost-effective and innovative solutions is crucial […] With Ross leading this key area, we are confident that his experience and expertise will help us to continue to drive innovation and efficiency in the decommissioning sector.”
Elemental Energies has built a global reputation in engineering and project management, and has an extensive track record managing large-scale platform P&A, major subsea well decommissioning and integrated wells and facilities projects. Last year the company continue to expand its service offering with the joint venture announcement with Archer for global P&A services.
UK-based Hunting plc, which operates in the well interventions market and other areas, has outlined plans to grows its business in the Middle East.
“Hunting is looking to build its presence in the Middle East with the construction of a small laboratory in the UAE to service clients in the Eastern Hemisphere,” it said in a statement on 7th March, 2025.
“With the establishment of this laboratory, the sample lead time and overall analysis time will decrease as a result of closer proximity to the customer.
Hunting is a leading manufacturer of precision engineered products and integrated systems for the global energy market as well as other industries.
Its product suite includes well intervention equipment, well test and process systems, connection technology, logging systems and other areas.
The statement coincided with the acquisition of Organic Oil Recovery (OOR) technology, in a deal worth US$17.5mn. Field trials of the OOR technology — designed to prolong the life of a field and lower water cut during end-of-life production — are currently underway in the Middle East and other parts of the world, the company said in the statement.
“Following the acquisition of this exciting business, Hunting now has the ability to deploy this remarkable technology globally,” said the company’s CEO, Jim Johnson.
The company also reported its full-year 2024 results on 6th March with both revenue and earnings growth “despite the volatile energy markets” of last year, Johnson added.
The Middle East remains a key area of growth, it added, given the level of tender activity across the region.
The UAE is one of a number operating sites in the group’s Europe, Middle East, Africa (EMEA) business, alongside Saudi Arabia, the UK, the Netherlands and Norway.
Its well intervention portfolio includes pressure control and slickline equipment, tubing technology, e-line tools and control and injection units.
The Middle East’s intervention scene appears to have a promising future as operators seek to minimise emissions while maintaining production. An indication of such a future can be found in companies such as well integrity and production optimisation leader, Coretrax, showing increased business interest in the region.
“The Middle East is a key growth area for Coretrax ... As operators remain focused on maximising recovery efficiently and sustainably, our expandable technology is ideally placed to support this demand," said John Fraser, Coretrax CEO, while marking the Company’s first deployment of ReLineWL straddles in 2022 for a major Saudi operator.
With the help of Coretrax’s ReLineWL that provided maximum production conduit to surface over conventional options, the well was brought back online. Not only did it bring down water production by 31%, but also enhanced oil output by 1,400 bpd. This also resulted in a significant drop in carbon footprint.
ReLineWL straddles allow maximum protection against the pollutants, elevated salt levels or impurities that are generated from produced water by isolating perforation intervals to shut off water production zones. It simplifies the huge challenge of time-consuming water treatment, which is especially worse in brownfield establishments, costing operators a fortune. ReLineWL also eliminates the storage and transportation difficulties that come with water production.
A one-trip, wireline deployed straddle system to address common well integrity issues, Coretrax’s ReLineWL also offers solutions regarding corroded or compromised tubing, such as the loss of well integrity. Enabling intelligent, non-intrusive interventions, the tool’s emission reduction capacity makes a huge difference. It omits the need for extensive workovers, and even well plugging and abandonment in extreme cases.
Speaking of a latest addition to the Company’s product line called Restore Patch, Fraser said, “Through the advancement of expandable straddles like our Restore Patch, operators can effectively reline mature or non-producing wells to deliver efficient and economical recovery. Our leading expandable technology is already delivering substantial efficiencies and we are actively seeking partnerships with conveyance providers which will allow us to make this solution even more accessible to the global energy industry.”
Restore Patch can be run across coiled tubing and drill pipe to restore well integrity and tackle common issues of water production, completion leaks and sand ingress. The system’s shoeless design makes drill out redundant, saving valuable rig time with a one-trip solution. Its slim outer diameter also allows it to bypass inner diameter restrictions such as sub-surface safety valves. At a 75% expansion ratio, it delivers maximum oil and gas production conduit to surface. With more than 700% greater flow area, the tool provides unmatchable results when compared to traditional straddles. Deploying the Restore Patch that gives all-time reservoir accessibility without major intrusions will allow operators to seamlessly plan future well operations and end-of-life activities.
This is an extract from a report by Offshore Network, which explores how the Middle East’s adoption of digital solutions is reshaping the well intervention market, highlighting a forward-thinking approach that bridges the gap between traditional energy practices and the drive for a more sustainable future. Read more on this and other reports.
Last month, LLOG Exploration, a US-based privately owned oil and gas company, initiated development studies for two hydrocarbon-bearing wells following a successful three-well exploration and appraisal campaign in the Gulf of Mexico, now rebranded as the Gulf of America.
This is according to a report by Offshore Energy.
The campaign, which included the Who Dat East and Who Dat South wells, has yielded promising results, prompting further evaluation of potential development options.
The Who Dat East well, drilled in late April 2024 using Noble’s Noble Valiant drillship, revealed a hydrocarbon-bearing aggregate net pay thickness of 44 m measured depth (MD), with 31 m MD within two discrete reservoir units.
The joint venture partners—LLOG (operator, 40%), Karoon (40%), and Westlawn (20%)—are now conducting development concept studies to assess the technical and commercial viability of the Who Dat East prospect.
Karoon has revised its net revenue interest (NRI) for Who Dat East’s 2C contingent resource upward by 190%, from 5.4 million barrels of oil equivalent (boe) to 15.7 million boe, based on data from wireline logs, fluid samples, and subsurface studies.
The Who Dat South well, drilled in the fourth quarter of 2024 using Seadrill’s West Neptune drillship, reached a total depth of 7,014 m MD.
Preliminary interpretations indicated hydrocarbon-bearing sandstone intervals with an aggregate true vertical thickness (TVT) of 67 m, exceeding pre-drill estimates of 40 m.
Initial analysis of formation pressure measurements and fluid samples confirmed the presence of high liquid yield gas-condensate fluid.
The well has been suspended as a potential future producer pending further joint venture studies.
In contrast, the Who Dat West well, drilled in late December 2024 and reaching a total depth of 7,147 m in January 2025, did not encounter significant hydrocarbon-bearing intervals and has since been plugged and abandoned.
The Who Dat field, located in 800 m of water offshore Louisiana, has been in production since 2011. The field produces a mix of 60% oil and 40% gas from nine wells, processed through the Who Dat floating production system (FPS) and transported via common carrier pipelines.
Gross production in Q4 2024 averaged 29,576 boe per day, a 3% decline from the previous quarter due to an extended 18-day maintenance shutdown caused by Hurricane Rafael and a gradual 10-day ramp-up period to restore full production.
Average realised prices for Who Dat liquids, including oil, condensate, and natural gas liquids (NGLs), fell by 9% to US$68.44 per barrel, reflecting global oil price trends. However, the average realised gas price increased by US$83.07 per thousand cubic feet (mcf), driven by higher seasonal demand during winter.
Dr Julian Fowles, Karoon’s CEO and MD, said, “In the US, the Who Dat gross production for the quarter was 3% lower than in 3Q24, primarily due to the planned annual platform shutdown and gas compressor maintenance. As a mature asset, without interventions Who Dat production, is expected to naturally decline by approximately 15% pa on average.
“During 2024, natural decline was largely offset by well interventions, sidetracks and production system optimisations. 2025 production will also benefit later in the second half from two well interventions, in line with our long term aim to offset decline rates through periodic infield activities.”
Depending on the scenario, decommissioning oil and gas infrastructure can have potential negative impacts both on the economy and environment.
The top 10 research priorities were highlighted in a 2023 resarch paper which aid in making informed decommissioning decisions and enhance our understanding of its detrimental impacts.
Several contaminants are released into the environment during the decommissioning process. These include residual chemicals and reservoir constituents that can have significant negative impacts on marine life. As part of the risk assessment framework, all contaminants need to be carefully identified and assessed. Understanding the long-term, site-specific consequences of these contaminants is key to adequately assess risks from various decommissioning options including full removal, partial removal and leave in-situ decommissioning options.
A majority of risks associated with offshore decommissioning activities lack well defined baselines to measure potential impacts. In order to identify parameters that can be measured and monitored, a baseline needs to be predetermined, without which, the acceptability of decommissioning options cannot be assessed.
Due to a lack of knowledge and inconsistent or deficient regulatory guidance, the ongoing costs within current decommissioning decision-making processes are often overlooked. Liability frameworks should therefore be defined to determine the cost of full removal of structures, making remaining items safe, and returning the seabed to its pre-activity state. Costs involving alternative approaches such as the relocation of structures to a reefing location are also calculated by the industry.
To adequately assess and compare the social, technical and economic impact of decommissioning, the ecosystem services that are gained or lost from different decommissioning options need to be determined. While few marine-based environmental impact assessments (EIAs) are currently being integrated with ecosystem services, there has been limited success attributed to data gaps and the values have been ineffectively captured by ecosystem services. Hence, alternate schemes such as the Intergovernmental Platform for Biodiversity and Ecosystem Services (IPBES) and Nature's Contributions to People have been developed.
The long-term presence of offshore structures can have a positive and negative influence on ecological diversity, productivity and connectivity. For example, the presence of oil and gas structures in marine ecosystems can have negative consequences on the natural migration pathways of species that might be altered by the emission of sound, vibrations and light from structures. On the other hand, presence of these offshore infrastructures can also extend foraging opportunities of certain mobile species such as Australian fur seals. Long-term monitoring data should therefore be collected throughout the lifecycle of these installations to appropriately understand their impact on populations and connectivity.
Production and attraction mainly refer to whether fish are attracted to an artificial structure or whether it enhances fish production. When a new structure is installed, fish are rapidly attracted to the structure which can redistribute existing production. In some cases, fish production can significantly increase when infrastructures are installed in predominantly sandy, oligotrophic habitats since they provide additional hard substrata that can potentially increase the carrying capacity of organisms that utilise such habitats. Assessments should consider the duration of these structures in place and the extent of connectivity between fish populations on the structures and the broader ecosystem.
A range of research questions need to be addressed to assess the feasibility of re-using or re-purposing offshore structures. Firstly, it is important to understand the process of degradation of different materials beyond their initial design life. Secondly, the evolution of different seabed sediments and their impact on the stability and integrity of decomissioned offshore infrastructure need to be considered. Thirdly, the technology required to contain hazardous substances, monitor their impact on the ocean environment, pursue re-cycle, re-purpose and re-use opportunities for recovered infrastructure needs to be understood. Lastly, performing testing and validation is crucial to achieving confidence of the sector and inclusion in industry standards.
A review of stakeholder values regarding the benefits of offshore instrastructure identified both risks and opportunities. These involve a combination of social and economic values that are shaped by their knowledge frames. Since there is no one-size-fits-all, further research is required to understand the factors that influence the perceptions and attitudes of stakeholders towards decommissioning.
Although the decommissioning process contributes minimally to greenhouse gas (GHG) emissions in comparison to its full cycle, it still needs to be evaluated in regard to its total contribution to the global goal of reaching net zero emissions by 2050. It is also important to highlight the positive contributions of these structures such as the carbon sequestration potential of marine ecosystems formed around these structures in situ. Qualitative analysis of all sources of GHG emissions sequestered should also be considered. A combination of all these analyses would result in a net-carbon footprint being identified for each decommissioning option.
While classifying research priorities into disciplines is necessary to assess their impact, they are also in most cases, found to be transdisciplinary in nature.
Expro, a global energy services provider, has secured a contract to supply Tubular Running Services (TRS) for a significant Carbon Capture and Storage (CCS) project in the Netherlands.
This initiative involves converting legacy offshore gas wells into CO₂ injection wells, decommissioning shallow wells, and drilling platform slot recovery wells. As the first offshore CCS storage system in the Netherlands, the project aligns with Expro’s sustainability goals.
The company will utilise its proprietary non-marking TRS technology, designed for corrosion-resistant alloy (CRA) tubulars, ensuring long-term well integrity in highly corrosive CO₂ environments.
Iain Farley, Expro’s Regional Vice President for Europe and Sub-Saharan Africa, emphasised the significance of the contract: “Securing this contract for this major CCS project highlights Expro’s advanced technical expertise in deploying CRA tubulars. The specific technologies being used throughout the project are proven in the oil and gas sector and it is fantastic to see these capabilities helping to unlock the potential of the CCS sector. Expro TRS services are designed for safety, efficiency and precision, and so we look to be playing a vital role in supporting the success of this project. Expro has a well-earned reputation for delivering high-performance solutions for complex well construction challenges and we are committed to pioneering solutions for energy transition challenges. This contract cements the company’s role in advancing sustainable practices in the offshore energy sector.”
With a legacy dating back to 1938, Expro has established itself as a leader in tubular running services worldwide. The company also provides additional well integrity solutions, including performance drilling tools, wellbore clean-out, and cementing technologies.
Expro’s comprehensive portfolio includes tubular handling products for all sizes of large OD tubulars, surface and intermediate casing, production casing, and tubing. Additionally, the company offers drill pipe handling tools designed for demanding drilling conditions and heavy landing string applications.
The decommissioning process comprises a total of seven stages, with preparation being the third stage.
This stage involves well P&A, cleaning, purging and isolation, and a preliminary categorisation of material streams. Using renewable energy sources like wind, solar or wave power to perform offshore decommissioning activities offers a plethora of environmental and cost-saving benefits.
Some notable applications include:
The Shenandoah floating production system (FPS), a key component of Beacon Offshore Energy’s deepwater project, has reached the Gulf of America following its journey from South Korea.
Built at HD Hyundai Heavy Industries’ shipyard in Ulsan, the 26,050-metric-ton FPS was transported aboard the semi-submersible vessel Xin Yao Hua and arrived at Kiewit Offshore Services’ fabrication yard in Ingleside, Texas, on 10 February 2025.
The unit is now undergoing final preparations and regulatory inspections before its installation at the Shenandoah field in the Walker Ridge area.
With a nameplate capacity of 120,000 barrels of oil per day (bopd), the FPS is set to play a pivotal role in the Shenandoah Phase 1 development.
Mooring pile installation has already been completed, with infield pipelay activities scheduled for the first quarter of 2025.
The project’s 102-mile SYNC oil export pipeline and upgrades to the CHOPS GB 72 platform are also finished, paving the way for first oil production in the second quarter of 2025.
Located approximately 230 miles from New Orleans in water depths of up to 5,500 feet, the Shenandoah field is a major deepwater venture for Beacon Offshore and its partners.
The company has also sanctioned Shenandoah Phase 2, which includes drilling two additional wells, expanding the FPS capacity to 140,000 bopd, and installing a subsea booster pump to enhance hydraulic efficiency.
These activities, planned between 2025 and 2028, are expected to add 110 million barrels of oil equivalent (MMBOE) in resources.
To support the expanded development, Beacon Offshore and its partners, including HEQ Deepwater and Navitas Petroleum, have secured an additional US$mn in debt commitments, bringing total project financing to over US$1.2bn.
In parallel, Beacon Offshore is advancing plans for the Shenandoah South discovery in Walker Ridge 95. This project, located in water depths of 5,800 to 6,000 ft, will leverage the existing Shenandoah FPS infrastructure via a three-mile subsea tieback.
Initial production from Shenandoah South is anticipated in the second quarter of 2028, with an estimated 74 MMBOE of resources. A final investment decision for Shenandoah South is expected by mid-2025.
Page 3 of 83
