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.
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.”
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.
A recent report on the North America Decommissioning and Closure Service market by Verified Market Reports forecasts that the market will reach US$14.8bn by 2030, growing at a CAGR of 6.9% from 2024 to 2030.
This is driven by factors such as ageing infrastructure, stricter environmental policies and the increasing cost-effectiveness of decommissioning technologies, with key advancements including improved safety standards, automation of certain decommissioning processes and enhanced waste management techniques.
Ageing infrastructure is a major driver with older plants requiring decommissioning and closure as they reach the end of their life cycle, to ensure compliance with safety and environmental standards, such as the BSEE regulation that stipulates that wells must be plugged and abandoned within three years of being deemed ineligible for further work, and platforms must be removed within five years of being no longer useful for operations.
Increasingly stringent environmental regulations and policies related to waste disposal, emissions control and site remediation are pushing companies to engage in responsible decommissioning practices and improve the environmental footprint of their operations, which is vital for safeguarding public health and the environment.
Trends such as the emphasis on environmental sustainability and the integration of circular economy practices also play a significant role in shaping the market’s future, with an increasing focus on repurposing and recycling decommissioned assets.
Technology plays a critical role in improving the efficiency, safety and environmental impact of decommissioning services. The integration of advanced technologies such as AI, drones, robotics and automation in the decommissioning process has significantly improved efficiency, reduced human exposure to hazardous environments, and lowered operational costs. Furthermore, advancements in data analytics and AI help companies manage decommissioning projects more effectively by predicting potential risks and improving decision-making.
Challenges highlighted by the report include ongoing supply chain disruptions, particularly in the materials needed for decommissioning projects, which can result in delays, necessitating the improving of supply chain management and diversification of sources of materials. Navigating complex regulatory environments can also delay projects, with increased collaboration between service providers and regulatory bodies needed to streamline approval processes. Pricing pressures are also a constraint, driving the leveraging of technology to reduce operational costs and improve overall efficiency.
The global high pulsed power market for well intervention, valued at approximately US$267mn in 2023, is poised for remarkable growth, according to a market report by Transparency Market Research.
The organisation has indicated a compound annual growth rate (CAGR) of 23.2% from 2024 to 2034 for the sector.
By the end of 2034, the market is expected to reach an estimated US$3.5bn, according to industry analysts.
High pulsed power solutions have become indispensable in modern well intervention, offering efficient energy delivery to address blockages and enhance the productivity of aging oil wells.
As global energy demand rises and production rates from mature wells decline, the oil and gas industry is increasingly relying on these technologies to extend asset life and improve recovery rates.
Additionally, growing investments in onshore intervention activities are further propelling market expansion, as operators prioritise maximising output from existing assets over drilling new ones.
Well intervention encompasses a range of techniques—such as workover, slickline, wireline, and coiled tubing operations—aimed at maintaining and boosting the production of oil and gas wells. High pulsed power technology plays a critical role in these interventions by compressing and delivering energy pulses that effectively break up blockages and improve fluid flow. Typically, these systems power specialised equipment, such as diamond drilling bits, which help remove debris and optimise hydrocarbon flow.
1. Rising adoption of liquefied gases and renewable energy initiatives
As global energy demand escalates and mature wells struggle to maintain production, operators are increasingly turning to interventions to extract additional resources. High pulsed power solutions are proving essential for enhancing the efficiency of these operations, particularly in onshore fields where aging assets require innovative technologies to boost recovery.
2. Increased investment in onshore interventions
Developing countries, aiming to reduce their reliance on imported oil, are ramping up investments in onshore interventions. For instance, Petrobras recently tendered for 15 land rigs to perform intervention activities in mature fields. Such initiatives are driving market demand as operators seek to extend the life of existing wells and optimise asset performance.
3. Research and development of pulse modulators and advanced components
Ongoing research into standardised pulse modulators and the development of high-voltage interconnects—including cable assemblies and receptacles—is expanding the product portfolio of high pulsed power systems. These innovations are crucial for delivering reliable and energy-efficient solutions that meet the demanding requirements of well intervention operations.
In 2023, North America dominated the high pulsed power market for well intervention, driven by the adoption of efficient and cost-effective techniques for well maintenance. The region’s focus on optimising existing oil and gas assets—through advanced technologies such as wireline perforating and coiled tubing—has significantly bolstered market growth.
The states of Louisiana, Mississippi and Texas are suing against a new rule that tightens up the criteria for oil and gas companies to prove they can meet the financial obligations for decommissioning, according to a recent press article published by Public Radio wbhm.
Oil and gas companies with offshore infrastructure are obligated to decommission it when it is no longer useful, by plugging wells and removing platforms within set deadlines.
As of June 2023, more than 2,700 wells and 500 platforms were overdue for decommissioning in the Gulf of Mexico, according to the US Government Accountability Office. It states that the lack of effective enforcement by the Bureau of Safety and Environmental Enforcement (BSEE) has contributed to widespread decommissioning delays that have grown into a substantial backlog, and that the Bureau of Ocean Energy Management (BOEM) does not effectively assure that operators have the financial and technical capacity to meet decommissioning obligations in advance of potential delays, bankruptcies, or other defaults. Delays can increase environmental and safety risks, as well as potentially indicating that companies are in financial trouble and may leave the government to foot the bill for decommissioning.
A 20-year-old BOEM rule requires a company to provide financial assurance to prove it can clean up the infrastructure afterward before it can get a lease to drill. In April 2024, the BOEM passed a new rule, substantially strengthening the financial assurance requirements for the offshore oil and gas industry operating on the U.S. Outer Continental Shelf (OCS), to better protect the American taxpayer from bearing the cost of oil and gas facility decommissioning. It includes the requirement that companies which cannot provide adequate financial assurance have to put up a surety bond.
“The offshore oil and gas industry has evolved significantly over the last 20 years, and our financial assurance regulations need to keep pace,” said BOEM director Elizabeth Klein at the time of the issue of the updated rule. “Today’s action addresses the outdated and insufficient approach to supplemental bonding that does not always accurately capture the risks that industry may pose for the American taxpayer – like financial health of a company or the value of the assets that the lessee holds.”
The three states are suing against the new rule on the grounds it would be unaffordable for independent small and mid-sized oil companies, potentially causing bankruptcies and job losses. Meanwhile, environmental groups, the API and major oil companies (who might be better able to shoulder any additional costs), are supporting the new rule.
It is reported that the district judge for the Western District of Louisiana will decide whether or not to approve an injunction, which will pause the rule while arguments are heard. In the meantime, the rule remains in effect.
An analysis by Ocean Conservancy has shown that the number of offshore oil wells that are overdue and in need of decommissioning could likely double by 2030.
A report entitled 'Protecting the Ocean and Taxpayers by Strengthenening Standards for Offshore Oil and Gas Decommissioning,' that was released during the end of last year, provides a comprehensive outlook at the state of offshore oil and gas decommissioning in the Gulf of Mexico, the growing consequences of the failing regulatory system, and policy changes to address them.
As of 2023, the federal waters of the Gulf of Mexico contained roughly 2,700 wells and 500 platforms that were overdue for decommissioning and considered delinquent. This idle and deteriorating infrastructure in the ocean is a growing risk to the environment and wildlife, and a growing risk to taxpayers if the government is forced to use tax dollars to cover cleanup costs. Risks associated with delinquent oil wells include oil spills which not only pose a major risk to the environment and wildlife, but are also a growing risk to taxpayers if the government is forced to use tax dollars to cover cleanup costs.
An analysis by Ocean Conservancy found that if the challenges with decommissioning policy are not fixed and the backlog is not addressed, the number of overdue wells in need of decommissioning could nearly double by 2030, ballooning to more than 5,000 wells.
“Experts estimate the cost to decommission all Gulf of Mexico oil and gas infrastructure–including active and idle– could be anywhere from US$40mn to US$70bn. Meanwhile, the federal system that governs offshore decommissioning is plagued by widespread and substantial shortcomings,” said Andrew Hartsig, an expert on offshore oil and gas policy and senior director of Arctic Conservation at Ocean Conservancy. “We need to make changes before this already-failing system comes under more strain and leaves taxpayers footing the bill.”
A recent report by the Australian Academy of Technological Science and Engineering on offshore oil and gas decommissioning highlights technologies that can facilitate alternative uses for in situ decommissioned platforms.
As the report points out, in situ decommissioning and repurposing of infrastructure can preserve marine ecosystems, reduce decommissioning requirements, and mitigate the risks of transporting invasive species. Such alternative uses can include rigs-to-reefs, commercial fishing, tourism, maritime logistics, alternative energies, coastal surveillance and research. Some of these approaches are already being used or planned in the Gulf of America. However, it is important to ensure that legal and regulatory issues, as well as technical challenges such as preserving structural integrity, are adequately addressed to ensure the long-term viability of repurposed assets.
Infrastructure that is intended to be repurposed will need to be prepared accordingly, assuming all the regulatory approvals have been obtained, to include ensuring integrity of the structure, removing or containing any contaminants to ensure there are no leaks throughout the lifespan of the repurposed facility, and continuous monitoring to mitigate against any ongoing risks.
Measures can include geotextile wrapping to protect against corrosion and guard against potential contaminant release; and stabilisation and encapsulation of contaminants to ensure their long-term containment and prevent leakage.
As would have been the case with the original facility, ensuring integrity of the repurposed structure for its proposed lifespan will be crucial. Approaches can include reinforcing infrastructure such as concrete and steel to boost structural integrity and extend lifespan, particularly where re-use purposes require topside refurbishing with heavy equipment; advanced anti-corrosion coatings and treatments; and capping and plugging for long-term well integrity.
Continuous monitoring of the infrastructure itself as well as the sea and ecosystem surrounding it is crucial to preserve the local marine environment. Here, autonomous systems and sensor technologies capable of providing real-time data to facilitate prompt remediation when necessary can come into play. Miniaturised sensors using nanotechnology dispersed throughout the marine environment can collect data on various parameters such as water quality, pollutants, and biological indicators. Genetically engineered microorganisms or synthetic biological systems could be designed to detect specific pollutants or environmental changes in real-time.
Advanced machine learning algorithms could be integrated into monitoring systems to analyse vast amounts of data and identify anomalies that could indicate environmental disturbances or hazards. These algorithms would continuously learn from historical data and real-time observations to improve their accuracy in detecting abnormal conditions and trigger alerts.
DOF Group ASA has announced two more contracts for subsea projects for two international companies in the Gulf of Mexico.
Skandi Implementer, which has recently departed Mexico due to a contract termination, will be deployed for the projects. Overall the projects’ expected duration is approximately two months.
The vessel will complete the integration of survey services and two of DOF’s remotely operated vehicles (ROVs).
Mons Aase, CEO of DOF Group ASA, said, “We are pleased to be able to quickly secure work for Skandi Implementer following the recent contract termination. Beyond contributing with asset utilisation and backlog, these contract awards represent advancing another of our I-class vessels into our subsea project business in line with our plan to add subsea service scopes to our most recent additions to the fleet.”
The Skandi Implementer was designed for subsea construction, inspection, repair and maintenance (IRM) and ROV services up to 3,000m of depth.
Earlier this month DOF Group also announced the acquisition of two subsea contracts in the APAC region for work offshore Malaysia and Indonesia.
A United States-based oilfield technology company called Deep Well Services stepped into the United Arab Emirates with its acquisition by Enersol, a joint venture comprising ADNOC Drilling Company and Alpha Dhabi Holding.
DWS, through Enersol, will drive the development of the UAE’s conventional and unconventional energy resources. Its contribution, alongside other Enersol companies, will add the technological support necessary to deliver ADNOC Drilling’s US$1.7bn worth of contract that involves leveraging 144 unconventional wells.
Established in 2008, DWS is known for its advanced technology services within the energy sector. Its patented Hydraulic Completion Units (HCU) are designed for high-pressure, long lateral, and multi-well completion operations, enabled by its data analytics software, BoreSite. The HCUs are also known for tackling workover of laterals, multi-well pads, high-pressure operations, and complex fishing programmes.
The company's other patented offering is the data acquisition system (DAS), BoreSite, which can allow operators to attain production optimisation by leveraging vast data sets into actionable insights for them. Its live feed reflects operations condition in real-time, which can be monitored and gauged remotely to make prompt corrections if required.
DWS' blowout preventers that are manufactured in the US with an API 16A & 6A certification are available in 10k and 15k pressure ratings. These, along with its range of accumulators, assures reliable well control and traceability for wellbore intervention activities.
The blowout preventers feature:
The company's pressure management services offer a compact and mobile 5000 psi hot tap drill to release trapped pressure by exercising caution and following all safety protocols. It is equipped with the necessary tools from casing valves to drill pipes for operators to get their production back online.
The company also covers training and development, offering globally accredited programmes with a special focus on operational safety and efficiency. It also assists in automating flowback operations via a joint venture called AutoSep Technologies. Besides its vast experience across multiple basins in North America, DWS has served more than 70 E&P companies that include both small-private operators and large-cap national energy companies.
Enersol has acquired a 95% stake in DWS at approximately US$223mn, including performance-based payments, subject to necessary regulatory approvals and other customary conditions precedent. The joint venture reflects ADNOC Group's readiness to adopt advanced oilfield technologies to maintain the Middle East's relevance in today's oil and gas industry. DWS has been the venture's fourth acquisition in 2024, following agreements to take over a downhole visual analytics company called EV; acquire 51% interests in NTS Amega, a manufacturer of advanced precision equipment and solutions provider for the energy sector, and a 67% stake in US-based Gordon Technologies that offer measurement while drilling services.
These acquisition strategies aim to build a next-generation technology portfolio with the scope to expand its presence in a previously untapped yet dynamic market.
To know more about the global well intervention scene click here.
The UK’s North Sea Transitions Authority (NSTA) has highlighted the role of new technologies in making P&A operations more efficient and cost-effective, and the potential of the UKCS as a test bed for pioneering P&A technologies which could be rolled out in other basins, such as the Gulf of America.
Nowhere is the need for new technologies to improve operations more acute than the Gulf of America, given that around 2,300 non-producing wells are scheduled for plugging and abandonment by this year, with decommissioning costs forecast at between US$40-US$50bn and environmental compliance expenses continuing to grow.
In the NSTA Technology Survey and Insights 2024, which raises awareness of solutions and approaches operators are using in the UKCS, the NSTA highlights that Well P&A, the most expensive part of the decommissioning process, is a field of active innovation, driven by both vendors and operators and including through-tubing logging, barrier placement, and downhole wireless sensing.
It highlights that there has been progress in introducing novel barrier materials and deployment techniques, and tools for removing control lines from downhole gauges. It notes that modular workover rigs for platforms and light well intervention vessels for subsea abandonments can lower P&A costs when compared to the use of standard rigs.
In the area of well inspection and cement condition, there are several emerging technologies including multi string logging for barrier verification and assessing cement quality behind the production casing.
There are several examples of conductor cutting techniques reported in the survey, with one operator confirming deployment of a combined hydraulic cutting tool with a pinning tool to allow combined cutting and pinning operations.
In the area of barrier placement and verification, operators are using deployable technologies such as through tubing abandonment, ongoing field trialling of non-alloy barriers, fusion-based alloy plugs, and suspended well abandonment tools for rigless abandonment using lower cost vessels. One operator plans to use self-healing cement to incorporate downhole gauge cables which prevent effective plug setting. Emerging technology is being progressed through trials of novel abandonment techniques.
Operators are considering light well intervention vessels for subsea open-water abandonments and subsea shut-off devices for open-water tubing retrieval. Emerging technology includes novel approaches for breaking the cement bonds on casing strings, with the swarf recovery unit and a casing recovery system being new developments.
The survey also highlights the use of innovative solutions for improving well access for interventions, low-cost platform workover rigs/modular drilling rig systems, rigs specifically configured for well P&A, and riserless P&A systems. The latest innovations include an inside casing status visualisation technology, subsea vessel based fishing tools and a casing expander tool.
Page 2 of 18
Copyright © 2025 Offshore Network
