Latest News

• Region: Latin America
• Date: June, 2021

Equinor (operator), ExxonMobil, Petrogal Brasil and Pré-sal Petróleo SA (PPSA) have agreed to develop phase one of the Bacalhau field located in the pre-salt Santros area offshore Brazil.

The Bacalhau field, situated across two licenses, BM-S-8 and Norte de Carcará, is a high-quality carbonate reservoir, containing light oil with minimal contaminants. The development will consist of 19 subsea wells tied back to a floating production, storage and offloading unit (FPSO) located at the field. This will be one of the largest FPSOs in Brazil with a production capacity of 220,000 barrels per day and two million barrels in storage capacity. Estimated recoverable reserves for the first phase are more than one billion barrels of oil.

“The development of the Bacalhau field is a strategic investment in our global portfolio and has the potential to bring high returns for ExxonMobil, our partners and the Brazilian people,” said Juan Lessmann, Lead Country Manager for ExxonMobil in Brazil. “This project has progressed due to the strong collaboration between ExxonMobil, Equinor, Petrogal and the government.”

Subsea Integration Alliance

For the engineering, procurement, construction and installation (EPCI) of the subsea pipelines (SURF) and production systems (SPS), Equinor has awarded a contract to Subsea Integration Alliance, a nonincorporated strategic global alliance between Subsea 7 and OneSubsea.

The development will include 140 kilometres of rigid risers and flowlines, 40 kilometres of umbilicals and 19 trees, as well as associated subsea equipment, in water depths of approximately 2,050 metres.

Project management and detailed engineering will take place in Rio de Janeiro, Brazil, with support from Subsea 7’s Global Project Centre in UK and France and various OneSubsea offices. Offshore activities will take place from 2022 to 2023 using Subsea 7’s reel-lay, flex-lay and light construction vessels.

Stuart Fitzgerald, CEO Subsea Integration Alliance, commented, “The award to Subsea Integration Alliance of the EPCI contract is a result of our strategy for early engagement and track record of major integrated projects. It underlines the strength and breadth of our global project management capabilities which underpin our delivery of large and complex integrated projects.”

Limiting climate impact

The development plan was approved by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) in March 2021.

Significant efforts have been made to reduce emissions from the production phase, including implementing a Combined Cycle Gas Turbine system to increase the energy efficiency of the power station.

Lifetime average CO2 intensity is expected to be less than 9 kg per barrel produced, significantly lower than the global average of 17 kg per barrel. Work will continue through the lifetime of the field to reduce emissions and increase energy efficiency.

The entire investment for the development is approximately US$8bn, with first oil planned in 2024. Due to the Covid-19 pandemic and related uncertainties, project plans may be adjusted in response to health and safety restrictions.

• Region: Gulf of Mexico
• Topics: Decommissioning
• Date: June, 2021

Heerema has announced that last month its deepwater construction vessel, Balder, completed the offshore removal of the Morpeth Tension-leg Platform (TLP) on behalf of client Eni US Operating Company.

The Balder vessel, constructed in Japan in 1978, is 154 metres long and 86 metres wide with a draft of 36 feet (which can be increased to 82 feet when ballast water is taken in). It is capable of a tandem lift of 4,000t and working within water depths from 70 feet and beyond.

Balder mobilised to the Morpeth Field in mid-April to begin executing the removal of the TLP. The campaign involved the engineering, preparation, removal, and disposal of the offshore infrastructure. The removal consisted of the 2,650 short-ton topside, 2,500 short-ton hull, and 1,300 short-tons of tendons and piles.

Following the successful removal of the components, the topside was transported by barge, the tendons and piles on supply vessels, and the hull wet towed for recycling at MARS (Modern American Recycling Services) facilities at various US locations.

This project was the first TLP removal campaign for Heerema and adds another successful decommissioning project to Heerema’s portfolio, following a record-breaking 2020 that saw the company remove 85,277 metric tons of decommissioned structures in one year.

• Region: Middle East
• Date: June, 2021

Baker Hughes has deployed its remote operations digital technology across Aramco’s drilling operations, encompassing more than 200 sites, the largest deployment of its kind in Baker Hughes’ history.

Building Aramco’s data management infrastructure this project provides the company with a single solution that covers data aggregation from the edge; real-time, unified data streaming and visualisation; data management; software development services; rig-site digital engineers; and monitoring personnel. The project supports Aramco’s ongoing efforts to further drive digital opportunities and initiatives and to enhance operating performance and reduce emissions.

By connecting all drilling sites with an integrated solution, Aramco enhances its view of its drilling operations in real time. Following the contract award to Baker Hughes in 2020, the combined teams worked in close collaboration and deployed the technology 50% faster than originally planned, despite working under pandemic conditions. Baker Hughes teams conducted more than 400 onshore and offshore trips across 350,000 km to install rig-site edge devices and integrate data streaming, monitoring and visualisation capabilities into Aramco’s existing digital infrastructure.

Benefits of Baker Hughes' solution:
• Remote monitoring personnel to receive faster, higher quality, standardised, real-time data delivered through a modern user experience, enabling enhanced well monitoring and management.
• Field-based personnel to have access to a unified view of wellsite operations from all providers on location, enabling effective and proactive mitigation of drilling hazards.
• Office-based personnel to have easy access to current and historical well data for quick visualisation and benchmarking, enabling proactive operations management.

Furthermore, to support the needs of more than 2,000 end users and 24/7 drilling operations, Baker Hughes and Aramco established a dedicated center staffed by a multi-disciplinary team of software engineers, data professionals and field service technicians. As part of Baker Hughes’ localisation strategy, the team is staffed with 90% Saudi nationals who are being cross-trained on essential digital competencies in data operations.

“This remote operations deployment, the largest in Baker Hughes’ history, is a strong example of how we are investing for growth with customers who are driving digital transformation at a rapid pace, such as Aramco,” said Maria Claudia Borras, executive vice president of Oilfield Services at Baker Hughes. “We will continue to expand our upstream digital capabilities to transform core operations, improve efficiency and reduce emissions. I am proud of the Baker Hughes team’s resilience in safely executing this complex project amid the challenges of the pandemic.”

• Region: North Sea
• Date: May, 2021

Well Expertise, a well management company providing well planning and operational support, has successfully used a mobile simulator for plug and abandonment (P&A) well control training to decommission several wells in the North Sea.

Well Expertise is the well management company for operator DNO during planning and execution of the permanent plugging and abandonment (P&A) of three subsea template wells at Oselvar.

Well Expertise worked closely with Drilling Systems and training specialist Survivex to develop high level well specific scenarios to simulate bull heading, reverse circulation, trapped gas and cutting casing operations. Six crews were then given various scenarios to test choke control and response to pressure increases.

This is the first time an on-the-rig (OTR) simulator has been used in-situ for P&A well-specific training to help prepare crews in advance of potential well control situations in the operation.

Following this and previous onboard simulator training success, Well Expertise will now be rolling out well specific onboard simulator training across its remaining drilling campaigns later this year with DNO, Wellesley and other operators.

Morten Laget, Business Development Manager at Well Expertise, commented, “We have an exceptional record of risk management and safety is our top priority. We strive to offer our clients any solution available that helps to reduce the risk of the operation and onboard simulator training is an excellent tool to help with this.”

“Killing the well is a key part of any decommissioning project and presents its own unique challenges. Plug and abandonment training is typically not addressed to this extent during periodic mandatory well control courses, but the OTR equipment allowed us to undergo some practical training on the rig itself during work time combined with review of subsea equipment and associated operations. This helped the crew in building competency and confidence and lowering the risk of major well control incidents,” Laget added.

Clive Battisby, Head of Simulation at 3t Energy Group, said, “The strength of the 3t Energy Group lies in our holistic offer, which combines cutting-edge technology with the very best of traditional training. For Well Expertise we combined tailored simulator training in-situ with experienced instruction to deliver a blended learning solution to meet the client’s needs.”

“To our knowledge this is the first-time blended learning with the OTR has been delivered for a P&A campaign and we are delighted it has worked so well. We are looking forward to working with Well Expertise again later this year on its forthcoming drilling campaigns.”

• Region: North Sea
• Date: May, 2021

Archer Oiltools has been awarded a plug and abandonment (P&A) campaign by Wintershall Noordzee B.V across 2021 and 2022. The scope awarded to Archer is to perforate, wash, and provide cement and formation integrity testing tools, services, downhole tools on tubing conveyed, and plugs-cutters for 22 wells with an option of another 20 wells.

Hugo Idsøe, Vice President of Archer Oiltools, commented, “Over the last decade Archer has delivered a high number of P&A and Slot recovery operations to our customers in the North Sea with great success. This contract is a milestone for the southern part of the North Sea and a testimonial of all the good work that we have done for Wintershall Noordzee B.V. over the last three years.”

“Our team have delivered excellent performance and we continue to prove that Archer’s Oiltools is an industry leader for smart and robust solutions in markets where well integrity, reliability and time savings are of upmost importance.”

“With a broad portfolio of products and services within P&A and Slot Recovery, Archer is in a unique position to deliver lower carbon solutions to our clients. Through our development of new technologies and solutions, we are rapidly adapting to and embracing the sustainability focus on lower emissions,” Idsøe added.

Archer has been carving a formidable presence for itself in the North Sea in recent months with this announcement coming soon after its acquisition of DeepWell, a leading Norwegian well intervention company focused on high-tech based wireline service. DeepWell commands one of the most modern wireline unit fleets on the Northern Continental Shelf and holds a strategic long-term contract in the light well intervention market, making a fine addition to Archer’s portfolio. It is therefore no surprise that the company was awarded another contract by Wintershall Noordzee B.V. and it is highly likely more work will be coming its way in the future.

• Region: Middle East
• Topics: Integrity
• Date: May, 2021

At the Offshore Well Intervention Conference, Middle East and North Africa 2021 host Tural Yusuboc, Senior Engineer of Well Integrity at ADNOC, was joined by an experienced panel to discuss the pressures shaping the well integrity market and the factors that will drive change for the discipline in the future.

Briefly outlining its history, Fayez Issa, Group Well Integrity Advisor for ADNOC, commented, “Well integrity has gone through different stages. If you go back 30-40 years it did not exist, there was minimum knowledge. But then after many incidents and major catastrophes the knowledge of oil integrity has become a vital aspect of oil and gas. It changed a lot ten years ago after the events on the Macondo field in the Gulf of Mexico. Before, people could happily ask things like do we really need to log cement? Is it important to see variations? Do we need special requirements for a gas lift? Additionally, a lot of things were done at minimum costs. Now if a well is planned to last for thirty years it has to be designed to last that long, a change partially due to the environmental challenges and more stringent regulations.”

Nowadays well integrity is a much larger concern for the industry, emphasised by Neil Ferguson, Business and Sales Development Manager of Well Intervention and Integrity at Expro Group, who noted that Expro now has 50% of its portfolio dedicated to this discipline whereas 20 years ago it was just 20%.

Exemplifying why well integrity and surveillance is such an important topic in today’s world, Mustafa Adel Amer, Well Integrity Focal Point at BAPETCO, said, “Ten years ago BAPETCO started doing well integrity management systems which accelerated the building up of knowledge. But unfortunately after the crash in 2014 the company took the decision to save costs and stop things such as corrosion logs etc. Now after six years the company is going to pay more to fix the unknown causes of corrosion and will have to probe the wells.”

While the discipline has grown significantly over the last few decades, the panellists noted that there was still room for improvement. Ferguson, suggested that there was perhaps a bit of a disconnect from integrity as it was so often bound up as part of drilling and production. The participants suggested that if well integrity is kept within these departments it might not perform its role as effectively, but having well integrity as a separate entity within companies would empower it to do so.

Abandonment

Switching the conversation slightly, Ferguson turned the focus on well integrity related to abandonment. He said, “One of my concerns is how do we help customers safely abandon their wells when they need to stay abandoned. There is now an expectation that once abandoned, these wells stay that way forever. The next challenge is figuring out how to do best possible job to ensure integrity in not just in a well’s operating life but once it is abandoned also. I don’t think we will be able to just forget these wells once they are abandoned and there will be elements of risk that will continue to challenge the industry. We have a huge responsibility as we move forward as to what we categorise as well integrity.”

Abandonment remains a difficult topic for the industry as, at the bottom line, it does not return any profit. As the panellists noted, drilling wells is exciting as you then get the reward, but this is not the case with abandonment and so often it can be neglected. This is exemplified by Bloomberg projecting that more than 32 millions wells worldwide are no longer producing and awaiting proper abandonment.

To ensure these operations are carried out and, importantly, are done so in a proper way to ensure the integrity is not compromised, the panellists suggested that cost must be projected forward, so that operators can plan for these financial hit in advance rather than bear the brunt unexpectedly at the end of a well’s life. Additionally, more stringent regulations would ensure that abandonment would be a requirement, but of course the implementation of regulations varies from region to region. Ultimately, the panellists agreed, if there is an event relating to an abandoned well’s integrity, it could easily be a catastrophic event that will affect everybody, not just the local region. Therefore it is also the responsibility of the oil and gas industry, not just the regulators, to ensure the integrity and abandonments of wells is taken seriously and performed in an environmentally responsible manner.

The role of technology

The participants noted that technology has played, and will continue to play, a huge role in the well integrity sector and, in recent years, perhaps the most significant advancements have been made with AI and big data.

Ferguson said, “AI is used in just about everything else we do in day to day life, so why shouldn’t we use it to our advantage in our industry to give us a predictive view on well integrity issues. We are in the era of big data and digitalisation, and there is so much data to look at that is very easy to miss some key information. The capacity for AI to interpret data and predict well integrity issues in the future is a huge cause for optimism and I think it is going to be hugely important moving forward.”

Adel Amer commented, “One of the challenges of performing corrective actions was the unavailability of material. We had one well, for example, that had three failures and we couldn’t acquire the material to replace the faults for one and a half years. But just replying on a simple data model, we can plan ahead for such instances by seeing how many faults occurred in previous years to predict what material we will need in the future. I think more solutions like this are going to come up if we make data available to these smart minds.”

Although enormous strides have been made with digitalisation and AI the panellists noted that there were still areas for improvement which would greatly enhance well integrity capacity. For instance, Issa noted that while there is a lot of data being collected from various sources such as corrosion logs, cement logs etc, there was still not enough surveillance data being conducted. Improving this would only enhance the ability to predict issues and rapidly remediate them.

Another area of improvement is centred around data sharing. As noted, the more data available the easier it is to predict potential issues in the future and, while perhaps there is scope for acquiring more, collectively oil and gas operators hold a plethora of data from locations across the world. If companies were more visible with their data, it would enhance opportunities to rapidly remediate wells and ultimately capture value for operators.

“But this is something the industry is not keen on, sharing products and data. This hinders a lot of the opportunities that could be unlocked without really spending any money,” noted Adel Amer. “If we want to move forward in the digital era we need to exchange data and make data sets available.”

The Covid-19 effect

The panellists also turned to how Covid-19 had affected the well integrity discipline, noting that perhaps the most significant change, which will most likely last into the future, was the withdrawal on reliance from externals. For instance, Adel Amer noted that in Egypt typically the company orders a lot of materials from abroad but this was, of course, dramatically hindered by travel restrictions and so, instead, local companies began manufacturing more advanced equipment. There was also an emphasis on training to ensure that the expertise was available within companies rather than seeking it from exterior sources. Issa noted that in ADNOC the company has recently issued a well integrity e-learning which was mandatory not only for those related to the discipline but also drilling and operation etc to ensure all employees know what they should be looking for.

It was clear from the discussion that while the discipline of well integrity had taken great strides over the last few decades, things such as lack of surveillance and a reluctance to share data was holding it back. Addressing these obstacles would only enhance the field, which would ultimately lead to healthier wells with extended production lives capable of providing more value to operators and the industry.

• Region: North Sea
• Date: May, 2021

Serica Energy plc, a British independent upstream oil and gas company with operations centred on the UK North Sea and gas accounting for over 80% of its production, has encountered difficulties in the drilling of the Columbus development well, located in the North Sea, 35km north-east of the Shearwater production facilities.

The Columbus development well was spudded in mid-March and drilled, as planned, to a total measured depth of 17,600ft by the Maersk Resilient heavy duty jack up rig. A 5,900ft horizontal section was drilled through the reservoir formations of the upper forties and encountered a sequence of sands and shales, in line with pre-drill expectations. The well required sand screens to be installed to prevent fine particles being produced and difficulties were encountered while running the screens so that it was ultimately not possible to install them.

As a result, the reservoir section of the well will be side-tracked and re-drilled, using data collected during initial drilling to optimise its trajectory and avoid the difficulties encountered running the screens in the original well. The additional operations are expected to take around 3-4 weeks at a net cost to Serica of around UK£3mn.

While this has raised the expense of the operation, these recent developments are not expected to affect the timing of production start-up, which is still projected during Q4 2021. Serica stated that further updates will be provided on each project when flow test data is available.

Mitch Flegg, Chief Executive of Serica Energy, commented, “Whilst frustrating, the additional operations on Columbus are not expected to affect the timing of first production, and the economic returns of the project remain very attractive for the company.”

A recent Competent Person’s Report estimates the Columbus gross undeveloped 2P reserves to be in excess of 14 million boe and, once production begins, the average gross production forecast is projected to be around 7,000 boe per day, of which over 70% is gas.

Rhum 3 update

Serica also provided an update on the R3 Intervention Project, situated on the Rhum field, which commenced in October. The company stated that the R3 well has now been cleared of all equipment installed when it was originally completed in 2005. Reservoir access has been regained, thus allowing new completion equipment to be run in preparation for production.

The new completion is currently being installed prior to performing a flow test on the well, which is expected to be carried out in June. A diving support vessel has been contracted to install the subsea control equipment required so the well can start producing in Q3 2021.

• Region: May, 2021
• Topics: Decommissioning
• Date: May, 2021

The Australian oil and gas industry is, unfortunately, making all the wrong headlines at the moment as a serious row over a decommissioning levy proposed by the Australian Government continues to rage.

The tinder for this firestorm is the Northern Endeavour floating production storage and offtake (FPSO) vessel, moored between the Lamarinaria-Corallina oil fields, which was shut down by the National Offshore petroleum Safety and Environmental Management Authority (NOPSEMA) after an immediate threat to health and safety caused by structural corrosion was found at the facility. Since the former owners Northern Oil & Gas Australia (NOGA) went into liquidation in late 2019, the national government has been maintaining the vessel until, at the end of 2020, it decided to decommission the facility and all related infrastructure once and for all.

To help cover the US$200mn expected cost of doing so, in its 2021-22 budget, the Australian Government announced it would be enforcing a levy to the Australian oil and gas industry, a decision which has so far come under heavy criticism from the sector.

Last week, Australian Petroleum Production and Exploration Association (APPEA) Chief Executive, Andre McConville, led the criticism against the Australian Government calling it an outrage that many companies who were never involved with the project will have to help pay. He also noted that such a decision could potentially hold back the Australian economy as well as the 80,000 jobs that it supports. 

Now ExxonMobil and Chevron have expressed their disapproval towards the Australian Government’s decision as well.

As reported by Reuters, a spokesperson for Chevron commented, "Chevron Australia is committed to working with the government on a decommissioning policy framework that would effectively preclude the need for this type of ad hoc, arbitrary action.”

Similarly, ExxonMobil noted that it had established a track record of executing successful decommissioning operations around the world and so shouldn’t have to shoulder the burden of covering costs for other companies as well. The company, therefore, was disappointed in the decision by the federal government, as detailed by Reuters.

While the debate will no doubt carry on for some time, the problem remains that at some point the Northern Endeavour and associated infrastructure will have to be decommissioned and dismantled. At this stage, however, who will pay for it is anyone’s guess.

• Region: Asia Pacific
• Date: May, 2021

PTT Exploration and Production Public Company Limited (PTTEP) has announced yet another gas discovery from its first exploration well, Kulintang-1, in Block SK438, located off the coast of Sarawak, offshore Malaysia.

Phongsthorn Thavisin, CEO of PTTEP, disclosed that PTTEP, through its subsidiary PTTEP HK Offshore Limited (PTTEP HKO), commenced the drilling of Kulintang-1 wildcat well in Block SK438 in March 2021 and successfully drilled to a total depth of 2,238 metres in April 2021.

Block SK438 is located in the shallow waters, approximately 108 kilometres off the coast of Bintulu in Sarawak. PTTEP HKO is the operator with 80% participating interest while PETRONAS Carigali Sdn. Bhd. (PETRONAS Carigali) holds the remaining 20%. PTTEP expects to drill another exploration well in this block in the second quarter of 2021.

Block SK438 is adjacent to Blocks SK405, SK309 and SK311, SK314A, all of which are operated by PTTEP, with existing facilities nearby. The location, therefore, provides an advantage for future development including the potential for cluster development.

PTTEP’s Malaysian success story

This discovery is the latest of PTTEP’s continued success in Malaysia. Already this year the company discovered a significant oil and gas column of more than 100 metres from exploration well, Sirung-1, in Block SK405B; revealed a high quality gas reservoir from the Dokong-1 well in Block SK417; registered a new record for its largest ever gas discovery from the Lang Lebah-2 appraisal well in the Sarawak SK 410B Project; and announced the start-up of natural gas production from Rotan and Buluh deepwater fields of Block H which targets production capacity at 270 million standard cubic feet per day.

“The Kulintang-1 well adds to the consecutive discoveries PTTEP has made this year which demonstrate our significant exploration progress in Malaysia. The discovery highlights our strong partnership with PETRONAS and continuous efforts in applying new techniques and interpretation to identify opportunities in mature areas. We are determined to explore further and make more oil & gas discoveries in Malaysia to serve future energy demand,” said Thavisin.

• Region: Gulf of Mexico
• Topics: Integrity
• Date: May, 2021

Magma Global has delivered the world’s first high-pressure composite riser pipe to HWCG’s storage location on the U.S. Gulf Coast, completing its rapidly deployable Offset Flexible Riser (OFR) system.

HWCG, to enhance its rapid deployment emergency well containment system, commissioned Magma Global to qualify and manufacture a high pressure, high temperature m-pipe to be used as a flexible riser connection. The lightweight, flexible m-pipe section will provide additional flow and capture emergency response options for HWCG’s members in the U.S. Gulf of Mexico.

The m-pipe is designed for rapid installation and is suitable for responses where vertical access is restricted and an offset is required such as water depths where the presence of combustible and volatile compounds affect personnel safety or where access under a floating production facility is needed. The system may also be used in deeper waters where more flexibility is desired in managing the marine systems during a response.

The 800 ft long section of m-pipe will provide a flexible riser connection between the capping stack placed on the incident well and a rigid riser suspended from a MODU. The m-pipe will form a horizontally oriented “S” shape between the capping stack and the rigid pipe riser, thus decoupling motion and decreasing surface station-keeping requirements for the temporary production facility. Once in operation, hydrocarbons released from the well flow through the complete riser flow path and are processed on board the temporary production facility to be collected in shuttle tankers for transportation.

Martin Jones, CEO at Magma Global, said, “This is a bittersweet success for Magma. We are proud to supply the first composite flexible riser for high pressure, high temperature hydrocarbons, for use in the Gulf of Mexico, yet we hope it will never have to be used. Nevertheless, m-pipe doesn’t corrode or degrade over time and hence will always be ready to enable HWCG to install at speed and with confidence.”

Bolstering HWCG’s well containment capabilities

HWCG’s response provides for the installation of a capping stack within 7-14 days and the ability to commence contingent flow and capture operations within 18 days, assuming no weather or other uncontrollable delays. Once installed the m-pipe is qualified to operate for at least six months, which is enough time to drill a relief well to provide final well kill and containment.

Mitch Guinn, Technical Director for HWCG, commented, “HWCG was one of the first organisations to accept the responsibility for providing equipment and personnel to respond rapidly and safely to a deepwater well incident. The addition of a flexible riser component to our suite of response equipment further enhances our ability to respond even more efficiently by allowing more flexibility in selecting a temporary production facility and enabling the selected facility to increase its operating window regarding weather conditions. The addition of Magma’s composite m-pipes is a huge benefit for our Members and is seen as one of their critical response components. We hope this work will open the doors to future applications of this breakthrough technology.”

Andy Jefferies, Deep Sea Development Services, and OFR Project Manager for HWCG, added, “The initial concept, and subsequent evolution, of the Offset Flexible Riser builds on the industry’s use of riser technology to manage unique operating conditions and environments requiring incident well flowback as part of a well containment strategy. The engineering and design aspects of this breakthrough technology have been led by DSDS for HWCG. The application of the Magma m-pipe design represents a step change in that technology and brings a time effective solution to well containment for flow and capture operations for all scenarios, but is particularly well suited to shallow water, high-rate gas wells, and wells requiring an offset flow and capture operation.”

• Region: Middle East
• Date: May, 2021

SEAJET Systems has launched to the subsea intervention market to provide the ability for companies to own and operate the most advanced controlled flow excavation (CFE) technology without third party interference, providing a more flexible, cost-effective and efficient solution.

Established by industry leaders Hector Susman, a pioneer of industry-leading excavation equipment, and Faisel Chaudry, who has more than 15 years’ experience in the sector with Rotech Subsea, Reef Subsea and James Fisher, SEAJET offers one of the most versatile CFE systems on the market. Developed by optimising existing CFE equipment, the company’s build-to-order technology introduces advanced hydrodynamic properties suitable for a wide range of applications and variable seabed conditions. SEAJET offers a tailored aftermarket support package to inspire client confidence to own, operate and maintain their own-in-house CFE equipment.

Chaudry commented, “We’ve launched SEAJET to meet the significant demand for cable trenching and de-burial in the rapidly growing offshore wind market. In addition, the use of CFE equipment continues to escalate in the inspection, maintenance and repair, decommissioning and salvage applications across oil and gas and marine sectors. Our unique mix of expertise in this specific area of subsea intervention provides customers with a solution they can trust.”

Susman added, “Having designed 95% of the CFE tools available on the market today, with the new SEAJET excavator, I have taken all lessons learned over that 25-year period and introduced the most advanced CFE system to date. Our technology has been optimised to work in the widest range of applications and soil conditions. We have honed the real sweet spot between flow and velocity, resulting in something others cannot offer – a flexible solution with enhanced performance and a business model that has efficiency built-in at every turn.”

Headquartered in Dubai, with operations in Europe and South East Asia, the company currently employs a team of seven people. Together, the senior management team has delivered more than 30 builds of MFE/CFE systems and execution of over 600 trenching/excavation projects globally.

• Region: Australia
• Topics: Decommissioning
• Date: May, 2021

The Australian government has come under fire after it announced, in its 2021-22 budget, a levy to cover the cost of decommissioning facilities around the Lamarinaria-Corallina oil fields in the Timor Sea.

In 2019, the 170,000 bpd Northern Endeavour floating production storage and offtake (FPSO) was shut down by the National Offshore petroleum Safety and Environmental Management Authority (NOPSEMA) after an immediate threat to health and safety was found at the facility, caused by structural corrosion.

The task of decommissioning the infrastructure fell to owners Northern Oil & Gas Australia (NOGA) but, in late 2019 the company went into liquidation and so the facility has been abandoned, with the national government forced to maintain the facility. At the end of 2020, the government decided it was finally time to push the facility into retirement, announcing it would take on responsibility to decommission the FPSO and all related infrastructure.

The estimated cost of such an undertaking is an eye watering US$200mn and, to help cover this, the Australian government has now issued a levy to the oil and gas industry to help foot the bill.

The announcement has gone down poorly and the Australian Petroleum Production and Exploration Association (APPEA) Chief Executive, Andrew McConville, has led the criticism against the government. McConville was outraged that many companies that have never been involved with or benefited from the project will have to help pay, and noted such a decision had the potential to hold back Australia’s economy and the 80,000 jobs the industry supports.

McConville said, “Tonight’s announcement of a new levy on the entire (offshore) oil and gas industry is a terrible precedent and could have serious repercussions to Australia’s economy and to jobs. Everyone agrees that the Northern Endeavour needs to be decommissioned and the costs managed, but there are a number of ways that the government can do so without risking undermining investment confidence in the oil and gas industry.”

The Chief Executive added that there were other options still available, such as making the government’s current management of the operations more efficient, reducing the cost of decommissioning through collaboration, and looking at alternative funding such as selling the asset or accessing PRRT credits.

While leading the charge, McConville did note that he was glad there will be extra consultation where APPEA will be able to put forward alternatives that the government should consider to meet the costs of decommissioning. He said, “We stand ready to work with the government to look at how best to manage the decommissioning of the Northern Endeavour.”