Latest News

• Region: Gulf of Mexico
• Topics: Decommissioning
• Date: Decemeber, 2024

Gulf of Mexico leads with 26 of the 56 case studies that have been conducted by the International Association of Oil & Gas Producers (IOGP) before releasing a comprehensive benchmark on jacket decommissioning.

The benchmark has been calculated on the basis of the offshore execution cost that is proportional to the duration of offshore execution. Survey from companies such as AkerBP, bp, Chevron, Petrobras, and Repsol, to name a few, have backed the data that went into the making of the benchmark. 

Starting from 2008 to 2023, the records include removed jacket weights that range from less than 250 tonnes to 20,000 tonnes, and jacket configurations from monopods to 8-legged jackets. For most cases, below 500-tonnes jackets have been removed by single lifts, while multiple lifts took less than five attempts. The removal of a single jacket usually takes up to 10 days.

The 56 jacket removals are predominantly multi-installation removals, with 40 occurrences. There were 13 cases of jacket and topside removals, while only three instances of standalone removals.

• Region: North America
• Topics: Well Intervention
• Date: Jan, 2025

Chet Morrison Contractors, LLC (Morrison) was recently awarded the crucial pipeline decommissioning contract, which marked a pivotal step in addressing the longstanding issue of orphaned infrastructure in the Gulf of Mexico.

With particular focus on eight pipelines in the Matagorda Island Area, the contract which was issued by the Bureau of Safety and Environmental Enforcement (BSEE), will allow Morrison to conduct essential on-site pipeline decommissioning activities in the region. 

Abandoned infrastructure often pose a threat to offshore safety and the environment. Decommissioning orphaned pipelines will therefore contribute to the long-term health of the Gulf ecosystem and open up areas for safer navigation and commercial activities.

“Morrison values its long-standing relationship with BSEE and appreciates their continued confidence in our team to deliver on this important decommissioning initiative,” said Chet Morrison, CEO and founder of Morrison. “BSEE recognises that Morrison is more than qualified to handle a scope of this magnitude. We will utilise our experienced people, our versatile fleet of barges and equipment, and the smart approach that we’ve become known for over the years.”

• Region: West Africa
• Topics: Well Intervention
• Date: Dec, 2024

Shell Nigeria Exploration and Production Company Limited (SNEPCo), a subsidiary of Shell plc, has reached a final investment decision (FID) for the Bonga North deep-water project off Nigeria’s coast.

This subsea tie-back will connect to the Shell-operated Bonga Floating Production Storage and Offloading (FPSO) facility, where Shell holds a 55% interest.

The Bonga North project encompasses drilling and starting up 16 wells—split equally between production and water injection wells—alongside upgrades to the Bonga Main FPSO and new subsea hardware installations. The initiative aims to sustain production at the Bonga facility, with recoverable resources estimated at over 300 million barrels of oil equivalent (boe). Peak production is expected to reach 110,000 barrels of oil per day, with first oil anticipated by the decade's end.

Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director, described the project as a significant investment contributing to stable liquids production and reinforcing Shell’s Upstream portfolio. Bonga North’s development aligns with Shell’s strategy to drive cash generation through its Integrated Gas and Upstream business into the next decade.

SNEPCo operates Bonga North in partnership with Esso Exploration and Production Nigeria Ltd. (20%), Nigerian Agip Exploration Ltd. (12.5%), and TotalEnergies Exploration and Production Nigeria Ltd. (12.5%), on behalf of the Nigerian National Petroleum Company Limited (NNPC). Situated in OML 118, Bonga is a deep-water field with production beginning in 2005. It achieved its one-billionth barrel milestone in 2023, and the FPSO has a production capacity of 225,000 barrels of oil daily.

Bonga North’s recoverable volumes exceed 300 million boe, classified as proven and probable (2P) under the Society of Petroleum Engineers’ standards. The project is also expected to surpass Shell’s hurdle rate for its Upstream business, leveraging near-field opportunities, technical expertise, and simplified, replicable operational models.

• Region: North America
• Topics: Decommissioning
• Date: Dec, 2024

The Bureau of Safety and Environmental Enforcement (BSEE) is a leading federal agency appointed to improve safety and ensure environmental protection relating to the offshore energy industry. BSEE's regulations for the decommissioning of oil and gas wells in the Gulf of Mexico are rooted in a combination of safety, environmental protection, and financial accountability. The regulatory framework is designed to ensure that operators properly manage the risks associated with the abandonment of wells and the removal of infrastructure. These regulations address several key aspects:

• Well Plugging and Abandonment: Operators are required to follow strict procedures when plugging wells to prevent any leaks or seepage of oil, gas, or other fluids into the surrounding environment. These procedures involve sealing the wellbore with a series of plugs and cement barriers to ensure the well is securely closed off. BSEE closely monitors these operations to ensure compliance with safety standards.
• Infrastructure Removal: The decommissioning process includes removing all associated infrastructure, such as rigs, pipelines, and platforms. This prevents these structures from becoming a hazard to navigation or marine life. BSEE requires operators to submit decommissioning plans that outline how they will safely dismantle and remove these structures. The regulations ensure that operators responsibly dispose of materials and avoid leaving hazardous materials in the ocean.
• Environmental Protection: The environmental impact of decommissioning is a major concern for BSEE. The Gulf of Mexico is home to diverse ecosystems, and any unaddressed environmental risks during decommissioning can have lasting consequences. As such, BSEE requires operators to conduct environmental assessments before beginning decommissioning activities to evaluate potential impacts. This includes studying the effects on marine life, water quality, and the surrounding habitat.
• Post-Decommissioning Monitoring: Even after decommissioning is completed, BSEE requires monitoring to assess the long-term effectiveness of abandonment procedures. Operators are required to conduct post-decommissioning surveys and submit reports that ensure all equipment has been removed, and there is no ongoing environmental risk. BSEE may require corrective action if issues arise.

• Region: Middle East
• Topics: Well Intervention
• Date: Dec, 2024

When a leading oil-producing nation like the UAE hosts a global climate summit such as COP28, the message to the world is clear: balancing climate commitments with energy realities is a complex but necessary endeavour.

The recent conference in Dubai reaffirmed the goal of limiting global warming to 1.5°C. However, with fossil fuels still providing about 80% of the world’s energy, their role in meeting global demand cannot be overlooked in the near term.

This reality, coupled with ongoing geopolitical and economic challenges, has driven energy companies to prioritise efficient methods of boosting production. Enter well intervention – a critical tool for optimising output from existing oil fields.

Jenny Feng, Supply Chain Analyst at Rystad Energy, emphasised the importance of this strategy:  “…operators will look to ramp up production from existing fields, and well interventions will be a vital piece of the puzzle. 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."

According to Rystad’s research, spending on well interventions reached nearly US$58bn last year. With sustainability now a central focus, this figure is expected to rise, as the proportion of wells eligible for intervention is predicted to grow to 17% by 2027, representing approximately 260,000 wells globally.

As the world grapples with the challenge of balancing urgent climate action with a continued reliance on oil and gas, the Middle East finds itself at the forefront of this critical transition. One of the region’s key strategies is leveraging digital technologies to optimise its oil and gas operations, ensuring efficiency and sustainability.

With advancements like artificial intelligence (AI) and machine learning (ML) becoming integral to enhancing well production, the industry is undergoing a significant transformation. These cutting-edge technologies are redefining workflows, using advanced algorithms and automation to maximise output while minimising environmental impact.

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.

• Region: Australia
• Topics: Decommissioning
• Date: Dec, 2024

Planning and preparation are underway for Australia’s largest offshore decommissioning project. Esso Australia Pty Ltd, a subsidiary of ExxonMobil Australia, has awarded Allseas the contract to dismantle up to 12 retired platforms from the Gippsland Basin in the Bass Strait.

The platforms, with a combined weight of approximately 60,000 tonnes, mark a historic milestone for offshore operations in the region.

For the first time, Pioneering Spirit will bring its revolutionary single-lift technology to Australian waters. This cutting-edge capability enables the removal of entire offshore structures – both topsides and jackets – in a single lift, allowing the massive scope of work to be completed within just a few months.

“This landmark decommissioning project represents a significant milestone for Allseas in Australia,” said Evert van Herel, General Manager of Allseas Australia. “Over the past 20 years, we’ve built a strong track record delivering subsea pipelay and construction services for major greenfield projects in these waters. It’s an honour to now bring our expertise to the first removal of platforms of this scale from Australian waters.”

The ambitious timeline includes the removal of up to 12 topsides and 11 steel jackets during a 3–4-month campaign set to begin in late 2027. Once removed, the structures will be loaded onto barges or vessels for transport to the Barry Beach Marine Terminal in Victoria, where they will be dismantled and recycled by an onshore contractor.

The engineering and project management work is being led from Perth and Melbourne, with additional support from Allseas’ offices in Delft and Kuala Lumpur.

“This historic project gives us an opportunity to showcase the capability of our single-lift technology in challenging environments like the Bass Strait,” added Evert. “We’re very much looking forward to working with Esso Australia to make this a successful project and thank them for their trust in Allseas to carry out this landmark project!”

• Region: Latin America
• Topics: Decommissioning
• Date: Dec, 2024

Helix's Q7000 purpose-built DP3 semi-submersible vessel will undergo hull clearance among other maintenance activities at Namibia’s Port of Walvis Bay before it is all set to start for delivering a decommissioning contract off the coast of Brazil as agreed with Shell in 2022

The year-long contract also mandates plug and abandonment services at the Bijupira and Salema fields in Brazil’s Campos Basin. 

It will take an estimated 10 days – that will also involve the removal of maring growth from the pontoons – to have the vessel prepared for operations offshore Brazil. 

Q7000 vessel features 

Helix's Q7000 vessel that was built in 2019 is equipped for riser-based subsea well intervention and decommissioning operations. With a capacity to withstand harsh environmental conditions, the unit supports production enhancement operations, well-cleanup, and field development. With a variable deck load capacity of about 3,000 metric tons besides well intervention and service fluids, Q7000 can support a crew of as many as 140 people.  

The upper deck has a 600-metric-ton well intervention tower with active and passive heave compensation, and a skidding system for well intervention support equipment and tubular storage make up the large flush deck. The below deck comprises twin work-class ROV systems, bulk fluid storage, and pumping systems.

• Region: North America
• Topics: Well Intervention
• Date: Dec, 2024

As a reflection of the energy transition, the offshore industry is ushering in a new age of optimisation to hit production targets rather than chasing after new discoveries. 

Operators are hence increasingly looking at marginal fields or brownfield projects and collaborating with service providers to deploy the best digital advancements in the industry to boost production form these assets. The Director of Mature Assets Solutions at Baker Hughes, Guillaume Fauchille, notes that maximising production from existing assets have turned out to be cheaper than investing in new fields. The reason behind 70% of today's oil and gas production coming from mature fields is being attributed to faltering investment in greenfields, the Covid-19 hangover and geopolitical turmoil.

Baker Hughes has also found that as less as 1% boost of the recovery factor of mature assets can make a difference by unlocking access to two to three years of additional worldwide consumption.

Growth spearheaded by North America

As market experts predict around 4-6% growth of the global well intervention industry, most agree that this growth will be led by North America, a region that would be responsible for a large part of future expansion. Intervention activities in the Gulf of Mexico will be primarily driven by technological advancements such as automated systems, data analytics, and advanced downhole tools to name a few. 

Of the latest examples from the region, Subsea7 will be installing of a production flowline and related subsea infrastructure as part of engineering, procurement, construction, and installation (EPCI) contract for production optimisation from Shell's Phase 3 Silvertip Development. 

• Region: North America
• Topics: Decommissioning
• Date: Dec, 2024

The National Subsea Centre (NSC) a centre for subsea research and technology development, has received a grant to develop a subsea decommissioning optimisation software demonstrator with PlanSea in a move which could make waves across the global offshore sector.

The scale of the decommissioning challenge facing the global offshore oil and gas sector remains a formidable one, to say the least. While there are certainly more instances of such operations being conducted, this is largely outweighed by the number of new wells coming online, an action that will ultimately only serve to increase the size of the decommissioning bill that must be paid. This invoice has already reached eye-watering proportions; as of June 2023, there was an estimated US$40-70bn cost accrued in the Gulf of Mexico alone. As a result, any efforts to simplify the decommissioning process and potentially reduce the decommissioning bill are a welcome sight to those who will ultimately have to foot it.

In receiving the new grant, NSC will work with PlanSea and utilise its expertise in offering world-leading marine logistics AI technology. The two have already collaborated for many years but will now deploy their technology and skills to address the needs of the subsea decommissioning sector.

Specifically, the two are developing a robust task-based formalisation of offshore decommissioning activities that will extend the benefits of PlanSea marine-logistics AI. Decision-makers will have the ability to stimulate with a high degree of accuracy the cause-effect relationship between different strategies and KPIs of interest.

“The AI demonstrator is aimed at addressing both standalone and collaborative campaign optimisation of current and future decommissioning,” remarked Jim Cargill, CEO of PlanSea. “Additionally, as in marine logistics, we offer a digitalised process for users whilst at the same time enhancing visibility of operational activity.”

The robust AI tool that will be produced has been fast-tracked for initial trials in Q2 2025.

James Njuguna, NSC Director of Research & Innovation, added, “Our centre is uniquely positioned to address the subsea industry’s most pressing challenges. Our in-depth knowledge of marine operations offers a great opportunity to collaborate with PlanSea to provide operators with substantial savings and reduce emissions. I am confident that this collaborative project will harness our research expertise and PlanSea’s cutting-edge industrial knowledge to deliver a pioneering solution for the energy transition.”

• Region: Europe
• Topics: Well Intervention
• Date: Dec, 2024

Adverse weather conditions have disrupted TotalEnergies EP Danmark’s operations, delaying production from the remaining fields at its natural gas redevelopment project in the Danish sector of the North Sea.

As a result, the company has updated its timeline for achieving full production capacity at the Tyra gas field, Denmark’s largest natural gas field.

The Tyra redevelopment project has been underway since March 2024, with the first gas export from Tyra II marking the successful initial production following a major revamp. However, challenges have emerged in the process of reactivating and optimising offshore wells, particularly in relation to the reactivation of the Tyra satellite wells. These wells are critical to achieving the anticipated production plateau, and the necessary well interventions have been delayed by adverse offshore weather.

A key operational challenge arose from issues related to two transformers supplying power to essential gas compressors, which have impeded the full commissioning of the project. Despite these setbacks, TotalEnergies has made significant progress in repairing and commissioning equipment, although the anticipated timeline for full technical capacity was initially set for mid-November 2024. Uncertainties about remaining operational conditions have led to delays.

The ramp-up phase, which is closely tied to well intervention activities, has allowed for gas production to be restored from three of the six fields. However, due to weather conditions and other operational issues, the reactivation of the Tyra satellite wells has faced further delays. Offshore weather constraints, including limited weather windows, have hindered the progress of well interventions and postponed the critical reactivation of these satellite wells.

Given the current weather forecasts, the timeline for reactivating all satellite wells to achieve plateau production has been extended by approximately three weeks. The revised timeline now places the expected achievement of plateau production in the second half of January 2025.

The Tyra field is part of the Danish Underground Consortium, with TotalEnergies EP Danmark (43.2%), BlueNord (36.8%), and Nordsøfonden (20%) as the key stakeholders.

Euan Shirlaw, CEO of BlueNord, commented, “Although it is disappointing that plateau production is now expected in the new year, we are confident that the recent above-ground challenges are well understood. Once the remaining satellite wells have been reactivated, the performance of the field will no longer be constrained by weather, as has been the case during the startup phase. We look forward to reaching plateau production in January 2025 and sharing the promising results of our HEMJ program.”

TotalEnergies points out that oil and gas supply nearly 50% of Denmark’s energy needs, and once the Tyra field reaches plateau production, it is expected to contribute around 6% of the European Union's natural gas output, marking Denmark’s return as a net gas exporter.

Additionally, in June 2024, drilling operations in the Harald East area, conducted with the Shelf Drilling Winner jack-up rig, led to the discovery of additional gas condensate resources in the Harald field, which is located in shallow waters 250 km off Denmark's west coast. These new reserves could further boost production from the region, with ongoing well intervention efforts to optimise the production from the field.

• Region: Gulf of Mexico
• Topics: Decommissioning
• Date: Dec 2024

Amidst the tightening up of decommissioning regulations, and the substantial amount of infrastructure coming to the end of its operational life, the Rigs-to-Reef programme has emerged as an attractive option in the Gulf of Mexico in the face of spiralling decommissioning costs.

Over the course of their lives, oil and gas structures in the marine environment become a haven for marine life. The Rigs-to-Reef programme, operated by the Bureau of Safety and Environmental Enforcement (BSEE) provides an alternative to the obligation to onshore disposal by converting retired platforms into permanently submerged ‘artificial reefs’. Such a method (achieved through tow-and-place, topple-in-place, or partial removal) allows operators to save an estimated quarter of the cost of a full service removal and is something of a trademark of the region, with around 600 platforms turned into reefs since conception in 1984. According to an article in the Scientific American, of the 15 structures decommissioned in the Gulf of Mexico in depths greater than 400 feet, 14 have been “reefed.”

According to the BSEE, the benefits of such an approach include saving fuel emissions that otherwise would be expended transporting and disposing of obsolete structures; enriching the marine life in the area, given the natural bottom of the Gulf of Mexico offers very little natural hard bottom and reef habitat; attracting recreational and commercial fishing and diving; and promoting biodiversity. A typical eight-leg structure provides a home for 12,000 to14,000 fish, according to a study by the Coastal Marine Institute, while a typical four-leg structure provides two to three acres of habitat for hundreds of marine species. For the oil and gas companies themselves, repurposing obsolete structures saves them the costs of removing, transporting, and disposing of them onshore. BSEE regulations require that, within one year of a lease's expiration, the obsolete structure must be removed.

All five Gulf of Mexico coastal states have approved artificial reef plans and have incorporated decommissioned platforms into their artificial reef programmes. Converting into reefs entails meeting strict criteria and requirements, such as the structure being sound, stable, clean, and overall beneficial to the environment, while protecting the Gulf of Mexico's natural resources. The operator is required to make a donation to the state, which goes towards the management of the state’s artificial reef programme. Once the operator has received approval, converts the structure to a permanent artificial reef and has complied with all permits and donation agreements, the title and liability for the structure is transferred from the operator to the state.

While there are examples of rig-to-reef approaches in other regions of the world and interest is growing, there are as yet no international standards governing the reefing of rigs, and the Gulf of Mexico has the most developed and regulated system. While some stress the benefits of the initiative, and the environmental damage that could be caused by complete removal of a rig with the potential destruction of a rich aquatic ecosystem, many are less convinced, and public perception is often not in favour. Many oppose any oil infrastructure being permitted to stay in the ocean given it could be seen to let oil and gas companies off the hook financially, arguing that operators should be required to return the area to its original state.

• Region: Asia Pacific
• Topics: Well Intervention
• Date: Dec, 2024

There has been a number of efforts to expand production in Malaysia’s offshore oil and gas fields, with a number of key industry players increasing their stake in the region.

TotalEnergies, for instance, has finalised the acquisition of interests of OMV and Sapura Upstream Assets in SapuraMOV Upstream, an independent gas producer in Malaysia. SapuraOMV’s main assets are its 40% operated interest in block SK408 and 30% operated interest in block SK310, located offshore Sarawak. In 2024, SapuraOMV’s operated production (100%), supported by the start-up of the Jerun gas field, is expected to reach approximately 590 Mcf/d of natural gas, feeding the Bintulu LNG plant operated by Petronas, as well as 10 kb/d of condensates.

Elsewhere, EnQuest Petroleum Production Malaysia announced in December an agreement to develop approximately 155 Bscf (c.27mn barrels of oil equivalent) of additional Seligi field gas resources along with a 50% equity share.

In partnership with PETRONAS Carilgali Sdn Bhd and E&P Malaysia Venture Sdn Bhd, the agreement enables the parties to develop and commercialise the non-associated gas resources in the PM8E PSC contract area and, in line with expected demand, supply around 70mmscf per day of sales of gas. EnQuest will produce additional Seligi Field non-associated gas by modifying its existing infrastructure, providing a cost-efficient way to deliver new volumes into the Peninsula Malaysia gas system.

“Malaysia is a key area for EnQuest’s growth strategy, and this agreement complements the signing of the DEWA Complex Cluster SFA PSC in October this year,” remarked EnQuest CEO, Amjad Bseisu.

December was also marked by PETRONAS awarding production sharing contracts for three discovered resource opportunities clusters and one exploration block offered under the Malaysia Bid Round (MBR) 2024 which was launched earlier this year. The resources are located next to existing infrastructure, enabling synergistic development and swift monetisation that, PETRONAS said, will allow for efficient and cost-effective resource extraction.

“We are pleased to see our petroleum arrangement contractors growing their portfolios in Malaysia,” said Senior Vice President of MPM, Datuk Ir. Bacho Pilong. “With their strong track records and proven capabilities, they continue to contribute significantly to the growth of Malaysia's petroleum sector… The year 2024 marks another successful year with the award of 18 PSCs across exploration, DRO and Late Life Asset. This is a testament of investors' confidence in PETRONAS' innovative asset offerings with high monetisation potential, solidifying Malaysia’s position as a preferred destination for upstream investments.”

While Malaysia is already a strong point in the APAC region for well intervention services beyond drilling, the expansion of production in the country suggests that even more opportunities will be forthcoming for such service providers.