Latest News

• Region: Australia
• Date: Apr, 2021

Santos, as operator of the Barossa joint venture, has announced that a final investment decision (FID) has been taken to proceed with the US$3.6bn gas and condensate project, located offshore Australia.

The Barossa FID also initiates the US$600mn investment in the Darwin LNG life extension and pipeline tie-in projects, which will extend the facility life for around 20 years. The Santos-operated Darwin LNG plant has the capacity to produce approximately 3.7mn tonnes of LNG per annum.

Barossa is one of the lowest cost, new LNG supply projects in the world and represents the biggest investment in Australia’s oil and gas sector since 2012. It is estimated the project will create around 600 jobs during the construction phase and a further 350 jobs throughout the next 20 years of production at the Darwin LNG facility.

The Barossa development will comprise a Floating Production, Storage and Offloading (FPSO) vessel, subsea production wells, supporting subsea infrastructure and a gas export pipeline tied into the existing Bayu-Undan to Darwin LNG pipeline. First gas production is targeted for the first half of 2025.

At the end of last year, Santos announced the tolling arrangements had been finalised for Barossa gas to be processed through Darwin LNG and that Santos had signed a long-term LNG sales agreement with Diamond Gas International, a wholly-owned subsidiary of Mitsubishi Corporation, for 1.5 million tonnes of Santos-equity LNG for 10 years with extension options.

Santos has also signed Memoranda of Understanding with SK E&S and Mitsubishi to jointly investigate opportunities for carbon-neutral LNG from Barossa, including collaboration relating to Santos’ Moomba CCS project, bilateral agreements for carbon credits and potential future development of zero-emissions hydrogen.

A big step forward in the Santos strategy

Managing Director and Chief Executive Officer of Santos, Kevin Gallagher, said the FID on Barossa was consistent with Santos’ strategy for disciplined growth utilising existing infrastructure around the company’s core assets.

Gallagher commented, “Our strategy to grow around our five core asset hubs has not changed since 2016. As we enter this next growth phase, we will remain disciplined in managing our major project costs, consistent with our low-cost operating model. As the economy re-emerges from the Covid-19 lockdowns, these job-creating and sustaining projects are critical for Australia, also unlocking new business opportunities and export income for the nation. The Barossa and Darwin life extension projects are good for the economy and good for local jobs and business opportunities in the Northern Territory.”

“Less than a year since we completed the acquisition of ConocoPhillips’ northern Australia and Timor-Leste assets and despite the global economic impact of a once-in-a-hundred-year pandemic, it is a great achievement to have extended the life of Bayu-Undan following the approval of the infill drilling programme and now to have taken FID on the Barossa project. I’d like to thank the Australian, Northern Territory and Timor-Leste governments, our joint venture partners and our customers for their support. I am delighted to welcome our Barossa joint venture partner SK E&S as a partner in Bayu-Undan and Darwin LNG and appreciate their support for today’s Barossa development decision,” Gallagher added.

• Region: Asia Pacific
• Date: Mar, 2021

PTT Exploration and Production Public Company Limited (PTTEP) have announced a successful oil and gas discovery from the Sirung-1 exploration well in Block SK405B, offshore Sarawak in Malaysia, that was drilled by PTTEP Sarawak Oil Limited, a subsidiary of PTTEP.

Block SK405B is located in shallow waters approximately 137 km off the coast of Sarawak. PTTEP Sarawak Oil Limited is the operator with 59.5% participating interest, with MOECO Oil and PETRONAS holding a 25.5% and 15% interest respectively.

PTTEP Sarawak Oil Limited commenced the drilling of the Sirung-1 wildcat well in January 2021. The well was drilled to a total depth of 2,538 m where it encountered a significant oil and gas column of more than 100 metres, in the clastic reservoirs. An appraisal well is scheduled in the near future to assess the upside resources.

Drilling for long-term growth

The achievement is the latest outcome of PTTEP’s ‘Execute strategy’ which focuses on building reserves for long-term growth.

“The Sirung-1 exploration well marks PTTEP’s third discovery offshore Malaysia following SK410B’s Lang Lebah and SK417’s Dokong. PTTEP also plans to explore nearby prospects in the PSC next year. The achievements have strengthened our investment base as we continue to expand our exploration horizon in Malaysia,” commented Phongsthorn Thavisin, CEO of PTTEP.

Apart from the Sarawak SK405B, there are also SK410B, SK314A, SK438, SK417, PM407 and PM415, all still in the exploration stage. Major projects in PTTEP’s portfolio in Malaysia include the producing assets in Block K, SK309, SK311, the Rotan-Buloh field in Block H and the jointly operated gas fields with PETRONAS Carigali in the Malaysia-Thailand Joint Development Area. PTTEP is also a joint investor with PTT, through the PTT Global LNG Company, in the MLNG Train 9 Project, an LNG liquefaction plant in Sarawak.

• Region: All
• Topics: All Topics
• Date: Mar, 2021

International trade has been severely impacted over the last week after the Ever Given container vessel ran aground amid high winds and a standstorm in the Suez Canal, effectively shutting off the important maritime route, but now service has resumed as the vessel has finally been pulled free.

It is estimated that around 12% of total globe trade passes through the Suez Canal each year, and the effective sealing off of the channel has caused widespread disruption which has left few industries unaffected: it has been suggested that around US$9.6bn worth of goods has been held up each day. For the oil and gas sector, it was another setback after a challenging period which has seen hydrocarbon prices plummet over the last year. Although oil is still set for a fourth quarterly gain, the disruption in the Suez Canal provoked a dip in prices with West Texas Intermediate falling as much as 2.5% and Brent also falling.

Unwedging the Ever Given was no easy feat. With the vessel measuring nearly 400m and weighing almost 220,000 tons it was not a case of a simple manoeuvring operations once it became stuck. After nearly a week of continued efforts, in the early hours of Monday 29 March, thanks to the efforts of Egyptian and international salvage teams, the stern was finally freed. However, as was warned at the time, there was still much to do as the bow was still stuck rock-solid.

However, after achieving refloating once the tide had risen, efforts were redoubled and the Ever Given was fully dislodged on Monday afternoon (GMT). With the ship free to continue on its journey, traffic can finally flow once again after six days of holding, although it will take some time to clear the backlog of, according to Leth Agencies, more than 360 ships awaiting passage (some estimates suggest this could take up to 4-5 days). However the worst has been overcome, and the relentless efforts of the salvage crews and onshore workers to free the ship has surely saved several more days of disrupted maritime trade.

• Region: North Sea
• Topics: Decommissioning
• Date: Mar, 2021

As part of their 2020 Full Year Results publication, EnQuest have outlined their 2021 performance outlook, highlighting the scale of decommissioning work ahead of them as they seek to retire ageing fields.

2020 in review

In 2020 EnQuest’s average production decreased by 13.8% to 59,116boe per day. While Covid-19 implications did stifle production for some time, the company reported that the primary driver of this reduction was the declining production rates and ultimate decision to cease production at high cost assets such as Heather/Broom, Thistle/Deveron and Alma/Galia.

Production at Alma/Galia ceased in June 2020 with the EnQuest Producer floating production, storage and offloading (FPSO) vessel moving off station quickly to the oil terminal jetty at Nigg in September. The group is still evaluating the options for the vessel’s future.

At Heather, the cessation of production (CoP) application was accepted by the regulator also in June, paving the way for decommissioning to commence. The platform remained shut in and depressurised all year, with front end engineering activities being undertaken ahead of the resumption of the well abandonment programme in 2021.

In June, the CoP application for Thistle/Deveron was accepted, allowing for the decommissioning phase to begin. The facility remained unmanned all year, although preservation visits to the Thistle platform took place as part of the preparatory works ahead of the planned 2021 well abandonment programme.

At Broom the application for CoP has been submitted to the regulators and approval is expected shortly.

2021 decommissioning

As expected, the Dons ceased production in early 2021 following the receipt of necessary partner and regulatory approvals in respect of CoP. The Northern Producer floating production facility is being used for initial decommissioning activities, such as flushing of the sub-sea infrastructure and to support implementation of effective well isolations. Once these activities have been completed, anticipated early Q2, the vessel will depart the field and be handed back to the owner.

At Thistle/Deveron, work will continue on the rehabilitation project alongside ongoing preparations for commencement of the well abandonment programme, which is expected to commence in Q4.

On Heather/Broom, activities to optimise the well abandonment programme and ready the rig for decommissioning have continued. Once completed, plug and abandonment of the development’s 41 wells is expected to begin in Q3, with the work programme anticipated to continue for approximately three years.

Restoring production rates

With so many facilities being retired, EnQuest have turned to other fields in order to restore their production rates and, in February this year, signed an agreement to purchase Suncor’s entire 26.69% non-operated equity interest in the Golden Eagle area, comprising the producing Golden Eagle, Peregrine and Solitaire fields. EnQuest has estimated that the acquisition will add an immediate incremental production of 10,000boe per day, 18mnbbl to its net 2P reserves and 5mnbbl to its net 2C resources.

The agreement has been signed with an initial consideration of US$325mn, and upon completion, will add immediate material low-cost production and cash flow to EnQuest and will allow the group to accelerate the use of its tax losses. EnQuest plans to finance the transaction through a combination of a new secured debt facility; interim period post-tax cash flows between the economic effective date of 1 January 2021 and completion; and an equity raise.

EnQuest Chief Executive, Amjad Bseisu, commented, “We are delighted we have agreed the acquisition of a material interest in Golden Eagle, a high-quality, low-cost UK North Sea development. Upon completion, this acquisition will add immediate material production and cash flow to EnQuest and will allow us to accelerate use of our substantial tax losses. It also demonstrates our continued commitment to the UK North Sea and diversifies our existing production base.”

• Region: West Africa
• Date: Mar, 2021

At the subsea sub-Saharan Africa well intervention webinar, hosted by Baker Hughes, Bayo Ojulari, Managing Director of Shell Nigeria Exploration and Production Company (SNEPCo), participated in a fiery discussion on the advantages of riserless light well intervention (RLWI) compared to rig-based, riser intervention alongside host Sola Adekunle, Managing Director of Cranium Engineering; Matt Vick, Senior Subsea Engineer at BP; and Feyi Okungbowa, Executive Director of Baker Hughes.

Beginning the session, host Adekunle, explained that since its introduction in the North Sea in the 1980’s more than 1,000 wells have been intervened across the world by means of RLWI bringing tangible benefits such as higher operator efficiency, lower spread rates and increased manoeuvrability. This begs the question, is it a no brainer? And if so, why in the SSA market, where wells are in dire need of optimisation (the average age of subsea wells will be the highest in the world by 2025), has RLWI been so underutilised?

The benefits of RLWI

Vick, certainly believed there was no question that RLWI was the way forward and commented, “BP has a long history with RLWI across the world and we are pushing for this to be used more. It is high capability, especially as wireline and E-line advances; it is more efficient; and has a lower cost in general.”

“A lot depends on the scope as well. You do lose some efficiency on downhole runs due to the fact you are recovering tool strings through open water and on a wireline run by wireline run basis it is a little bit slower. But you tend to gain this efficiency back when it comes to mobilisation and then getting the vessel offsite when the job is completed. So, you gain on the back end and beginning to offset the speed you lose in the middle (and you can even optimise the sequence in the middle). So even if it does take longer on the critical path, you will still have a lower spread rate and will achieve a big gain.”

As Vick outlined however, there are still some things where you do need a high pressure intervention riser like coil tubing and cement spotting, but really there is not a huge number of operations that riserless cannot accomplish outside the current realm of copper tubing. “Right now, BP’s push is to go with riserless systems as you can structure interventions to not require coil tubing or capabilities of heavier based solutions. You can accomplish 95% of your objectives at a much lower cost and this has been our push in shallow and deep water wells.”

“There are also safety benefits as well. With riser interventions you often have a direct conduit from well to the surface, meaning employees are working in close proximity to live well hydrocarbons. However, with riserless you don’t bring tool string back to the surface through a hydrocarbon field riser, so the only hydrocarbons you should see coming back to the surface is going to be flushing lubricator out to get your well shut in. Personnel safety is therefore increased with some real improvements in HSE,” Vick concluded.

The SSA market

Ojulari, commented that around 15 years ago when the industry started to really develop deepwater wells in SSA it was more straightforward: all that was needed was a rig to drill wells that were very high producing.

Ojulari said, “Unfortunately, the 50,000 barrels per day wells are no longer very much in play now and most drilled are now producing at lower rates. Many are becoming old and natural production declines by about 10-15%. Now the challenge is that in order to sustain production we try to drill up wells and utilise rig-based intervention, but despite that the SSA region still suffers about 6-8% decline. This means we cannot drill or rig- based intervene our way to fully address our production decline. In order to fully meet this, we need to leverage the rigless and riserless intervention for us to be able to capture the low hanging fruits. We have been a bit slow going for it but for me there is significant opportunity here.”

Holding RLWI back?

Delighted with the comments from Ojulari and Vick, Okungbowa, added, “Everything said so far is music to my ears as a service provider. Baker Hughes has made a lot of investment in RLWI not only in SSA but globally, and it is an area of growth we see. But we cannot understand why we are not seeing more RLWI in SSA? In 2019 there were a couple of interventions, and obviously 2020 was disruptive but even still the opportunities were just not there. With the ageing of the assets and store base I struggle to understand why this market is not moving as quickly as it should- all the equipment is ready in the region, we have spent years training people for interventions and yet the uptake is not there.”

Answering Okunbowa, Ojulari commented that perhaps RLWI was not being taken up as much as it should due to the lack of awareness of business owners and business decision makers. In his experience, the main discussions around this form of intervention were centred around limitations and risks and often the total cost saving is not immediately obvious to the core leaders. “For me, the first thing that needs to happen more is around better education, and this seminar is a good example. More engagement and connection in promoting the capabilities of promoting riserless, sharing success and putting into numbers where it can save in comparison to the other options for intervention that we have.”

Collaboration and transparency

The panellist also noted that key to ensuring more RLWI is transparency and collaboration. Building portfolios, and properly evaluating closing wells that require intervention, and then working with other operators to organise campaigns together will ultimately reduce costs and lead to more well optimisations being performed.

Okunbowa said, “What I would say to Ojulari and Vick and every operator is that we need to be strategic, we need transparency and we need to almost become partners. If you bring problems to us we can then bring solutions and help structure it in a way that unlocks value. We have heard of rig clubs but we now need to get comfortable with a vessel club situation. Being able to do a campaign across 3-4 companies back-to-back using the same assets, each operator will see significant cost savings.”

Highlighting the additional value of larger campaigns, Vick added, “You gain efficiency from crews repeating a task, and small learnings can add up. If you have many operators with different wells lined up, you gain efficiency from one well to the other whereas you lose efficiency with one-offs. With drilling operations you can see drilling times cut in half by the end of the campaign, and it is the same opportunity here. As a vessel keeps working you get gains in safety, efficiency, performance across the board. Success breeds success. I feel if we can show this being done with some big campaigns with good results we can get this success moving and more operators will see it makes commercial sense to collaborate.”

Unlocking value

Adekunle concluded the session, “Riserless intervention saves money, increases production and can be used as a production maximisation tool rather than reaction tool. With collaboration between different disciplines, different contractors and services providers you can unlock value for operators. Really it is not about which operator or which service provider, it is about looking and seeing how much value the industry can unlock by using this technology.”

In the panel it was made abundantly clear that utilising RLWI, and collaborating on these campaigns, would ultimately unlock value for industry and these opportunities should be embraced rather than feared; as Okunbowa commented, "Don't be a dinosaur." But what was made clear most of all is that this would only be achieved through conversations such as these, to make clear the benefits, the cost savings, the success stories and not just the limitations of RLWI, to key decision makers and indeed the entire industry.

To listen to the full webinar, click here. 

• Region: Australia
• Date: Mar, 2021

Santos has awarded a major contract to BW Offshore (BWO) for the construction, connection and operation of the Floating Production, Storage and Offloading vessel (FPSO) for the Barossa gas field, located 300 km offshore Darwin.

Barossa will be developed via the FPSO with six subsea production wells, in-field facilities and a gas export pipeline tied into the Bayu-Undan to Darwin pipeline system that supplies gas to Darwin LNG. Barossa production is expected to commence in the first half of 2025 and will provide the next source of gas for the existing Santos-operated Darwin LNG plant once current reserves from the Santos-operated Bayu-Undan field in the Timor Sea have been depleted.

The FPSO

The unit for the Barossa gas field will be a large FPSO with processing capacity for up to 800mn cu ft per day of gas and design capacity of 11,000bbl per day of stabilised condensate. It will be turret moored with a newbuilt hull based on BWO’s RapidFramework design.

“Our skilled project execution organisation, experience from the Catcher project and working with well-known suppliers and yards, positions us to efficiently design, construct and deliver the newbuild FPSO for Barossa using the BW Offshore RapidFramework design,” said Marco Beenen, CEO of BWO.

The FPSO will be built in South Korea and Singapore before being towed and permanently located in the field. Condensate will be stored on the FPSO for periodic offloading.

One of the lowest LNG cost of supply projects in the world

The FPSO services contract is subject to a final investment decision (FID) on Barossa and represents the largest capital expenditure component of the approximately US$3.6bn Barossa offshore gas and condensate project to backfill Darwin LNG. The contract contains an upfront pre-payment and an option to buyout, and achieves an overall reduction of approximately US$1bn in capital expenditure.

Managing Director and Chief Executive Officer of Santos, Kevin Gallagher, commented “The decision to proceed with an FPSO services contract maintains a low ongoing operating cost while engineering enhancements have significantly reduced the project’s carbon footprint. This reduction in capital expenditure makes Barossa one of the lowest cost of supply projects in the world for LNG and will provide new supply into a tightening LNG market.”

Santos currently holds a 62.5% operated interest in the Barossa joint venture along with partner SK E&S. A final investment decision on the Barossa project is anticipated in the coming weeks with first gas targeted for the first half of 2025.

• Region: Middle East
• Date: Mar, 2021

Saipem, a leading company in the engineering, drilling and construction of major projects in the energy and infrastructure sectors, has been awarded a contract from Qatargas worth more than US$1bn related to the North Field Production Sustainability Pipelines Project located offshore and onshore the Qatar peninsula.

The contract (EPCL package) entails the engineering, procurement, construction, and installation (EPCI) of offshore export trunklines and related onshore tie-in works and is part of the development of the North Field production plateau, which also includes the EPCI of offshore facilities (“EPCO” package) previously awarded to Saipem in February.

The scope of work for this award (EPCL package) includes three export trunklines starting from their respective offshore platforms to the Qatargas North and South Plants in Ras Laffan Industrial City for a total length of almost 300 km, as well as associated onshore tie-in works and brownfield activities on existing onshore and offshore facilities. Pipelaying operations will be executed by the DE HE and Saipem Endeavour vessels.

Stefano Porcari, Saipem E&C Offshore Division COO, commented, “This additional contract awarded by our key client Qatargas strengthens our consolidated relationship and represents a further proof of the trust in Saipem’s ability to deliver challenging projects and is a sign of success of our positioning strategy in Qatar. We are very proud to increase our contribution to such a strategic development for the country.”

Double haul for Saipem

This agreement is an expansion of the US$1.7bn contract awarded by Qatargas to Saipem for the EPCI of various offshore facilities for the extraction and transportation of natural gas, including platforms supporting and connecting structures, subsea cables and anticorrosion internally cladded pipelines. The agreement also included the decommissioning of a pipeline and other significant modifications to existing offshore facilities.

Saipem will enhance the overall project execution, comprising both EPCO and EPCL scope of work, by combining relevant planned schedules and project management. Once completed the project aims at increasing the early gas field production capacity to 110mn tonnes per annum. Saipem will start activities immediately and project completion is expected by mid-2024.

• Region: North Sea
• Date: Mar, 2021

Neptune Energy has announced the safe and successful installation of four Enhanced Horizontal Subsea Tree Systems (EHXT) for the Duva development project in the Norwegian sector of the North Sea.

The Duva development, on Production Licence 636, is an oil and gas subsea tie-back to the Gjøa semi-submersible facility, of which Neptune Energy is also the operator.

While conventional installation of EHXTs would be carried out with a drilling rig, Neptune Energy, together with its partners and contractors, conducted the installation using the vessel Far Samson, operated by Solstad Offshore.

Thor Løvoll, Director of Drilling & Wells in Norway, Neptune Energy, commented, “By introducing the latest available technology combined with quality planning and teamwork, we completed the installation safely, successfully and ahead of schedule. Deploying the subsea trees from a vessel saved about 20 days of rig time, reducing costs, time and emissions.”

The 20 days of reduced rig time is equivalent to approximately US$12mn savings for the license partners and by using a vessel instead of a rig, emissions were reduced by more than 60% during the installation activities.

It was the first time Neptune Energy has installed EHXTs in a standalone operation with a vessel. They were successfully deployed on the template wellheads over an 18-hour period, with the total installation and subsea system testing completed within eight days. The operation was carried out in close cooperation with TechnipFMC, Ross Offshore, Solstad Offshore, Oceaneering, Fugro, IKM and Tigmek.

The Duva project

Neptune Energy’s Head of Gjøa Subsea Development, Crawford Brown, added, “We are progressing with the Duva project at pace and have reached an important milestone. The efficient installation of the subsea trees allows the project more schedule flexibility as we enter the drilling and completion campaign for the Duva production wells.”

“Duva is an important part of Neptune’s geographically-diverse, gas weighted portfolio of developments, and will both increase production and extend the operational life of our operated Gjøa platform.”

The Duva oil and gas field was Neptune’s first discovery in the Norwegian North Sea, a strategically important area supporting the company’s growth. It is located 14km northeast of the Neptune-operated Gjøa field, at a water depth of 360 metres. Gross 2P reserves are 88 mmboe (gas 76%).

The drilling rig Deepsea Yantai, operated by Odfjell Drilling, will drill and complete the remaining sections of the Duva well programme during Q2/Q3 2021, and first production from Duva is expected in the third quarter of 2021.

• Region: Latin America
• Date: Mar, 2021

Equinor, together with license partners Repsol Sinopec Brasil and Petrobras, have approved the development concept for BM-C-33, a gas/condensate field located in the Campos Basin pre-salt in Brazil.

“BM-C-33 is a key project in our portfolio and concept select is an important milestone in our effort to mature the project. It is important to further optimise and improve the project business case to make it more robust for the future market,” said Geir Tungesvik, Senior Vice President for Projects at Equinor.

The well streams will be sent to a floating production, storage and offloading unit (FPSO) located at the field, which will process both gas and oil/condensate to sales specifications and then exported. Crude will be offloaded by shuttle tankers and shipped to the international market after ship-to-ship transfer. A new-build hull has been selected to accommodate for 30 years lifetime of the field.

The gas export solution is based on an integrated offshore gas pipeline from the FPSO to a new dedicated onshore gas receiving facility inside the Petrobras TECAB site at Cabiúnas, before connecting to the domestic gas transmission network.

"BM-C-33 holds substantial volumes of gas. A completion of the ongoing liberalisation of the natural gas market in Brazil in line with the current plan, is key for the further development of the project. BM-C-33 is an asset that can generate value for the society, both through the creation of direct and indirect jobs, ripple effects, and through a gas supply that can induce industrial growth, as has happened in other countries,” commented Veronica Coelho, Equinor’s Country Manager in Brazil.

Gas export capacity is planned for 16mn cu/m per day with average exports expected to be 14mn cu/m per day, which represents a significant volume based on current Brazilian gas demand. Daily oil processing capacity is of 20,000 cu/m.

The concept select is a conclusion of a technical and commercial assessment of various developing concepts and landfalls. The chosen concept provides the most robust solution to develop the BM- C-33 project and gas value chain.

Details on project timeline towards next decision gates and start of production are still to be concluded.

• Region: West Africa
• Topics: Integrity
• Date: Mar, 2021

A new partnership between Ashtead Technology, an integrated subsea technology and services specialist, and inspection and asset integrity company Ocean Atlantic Petroleum SA (OAP) has, after successfully executing its first marine services project in West Africa, received awards for further work in the region.

Leveraging their joint capabilities, Ashtead Technology has completed a multi-asset, class-approved mooring inspection campaign for Total E&P Angola in the Girassol and Dalia fields, and has been awarded further work in the Pazflor and CLOV fields.

The underwater inspection scope, which will avoid the need for drydocking, combines Ashtead Technology’s visual inspection, chain cleaning, measurement and 3D modelling technologies, with OAP’s team of experienced offshore technical personnel. OAP’s operations base in the country’s capital city of Luanda will be used to store and maintain the equipment.

“Coronavirus-related travel restrictions have added an extra logistical challenge,” commented David Mair, Business Development Director of Ashtead Technology. “By teaming up with OAP we have solved the problem and can continue to deliver a high quality, reliable service on schedule and within budget,” Mair added.

“This aligns with our overarching strategic focus for West Africa, which centres on providing a broader asset integrity service to clients and supporting local content objectives,” Mair added.

A formidable partnership for the future

Headquartered in Aberdeen, the UK, Ashtead Technology has nine facilities in energy hubs around the world. It has one of the largest equipment fleets in the subsea supply chain coupled with the R&D capabilities to develop bespoke solutions.

Established in 2014, OAP provides a variety of technical services to the Angolan energy sector, including subsea inspection and asset integrity. OAP’s knowledge of the Angola market and in-country technical expertise makes them the ideal partner to support the partnership’s growth ambitions in Angola.

Benoit Peyrichout, Managing Director of OAP SA, said, “Our partnership with Ashtead Technology has created the perfect marriage and a very compelling business proposition for clients in Angola.”

"With our local facilities and strong technical expertise forged with Ashtead’s engineering capabilities and fleet of technologies, we are ideally placed to win further awards and expand both businesses in the future.”

Winning the campaign for Total E&P Angola straight off the bat underlines the strength of the combined offering to operators in the region and indicates there could be much more to come from this partnership in the future.

• Region: North Sea
• Date: Mar, 2021

Wintershall Noordzee has contracted Swift Drilling BV to carry out a plug and abandonment (P&A) campaign in the North Sea using the Swift 10 light jackup rig.

The Swift 10 is a fully Dutch owned and operated rig, which together with Wintershall Noordzee, will focus on the safe, efficient, and economic P&A of offshore wells on the Continental Shelf of the Netherlands and Germany. Before the three to four year campaign begins in the summer, in the coming period the rig will be revitalised and restarted after its original five year LTI free campaign for Shell/Nam.

The Wintershall Noordzee and Swift team will use the highly automated Swift 10 and focus on continuous improvement to effectively P&A wells. Both parties see the cooperation as a start of a new era, whereby old wells are plugged and abandoned according to the latest standards and protecting the environment of the North Sea.

“We’re extremely happy to revive the Swift 10 for Wintershall Noordzee. Together we share the ambition to create a long-term cooperation to P&A wells safe, efficient and economical as one team. The cooperation with Wintershall Noordzee aiming at the realisation of our shared ambition so far has been enjoyable and the right basis for successful P&A campaign,” said Erwin Lammertink, CEO of Van Es Holding, which Swift Drilling is part of.

The Swift 10 is a 300ft Gusto MSC SEA-2750 fully automated drilling rig, with a POB of 50 originally delivered in 2011. Its light jack up drilling concept matches the shallow water conditions of the Southern North Sea and due to its X/Y cantilever design, it is capable of serving the majority of the production platforms in the region with drilling wells, work overs and well abandonments. It is currently located in Rotterdam where it is getting ready for her P&A campaign.

• Region: All
• Date: Mar, 2021

Expro Group (Expro), an international oilfield service company, has signed a three-year agreement with global vessel provider FTAI Ocean LLC (FTAI Ocean), a subsidiary of Fortress Transportation and Infrastructure Investors LLC, for the supply of the DP3 M/V Pride well intervention vessel to provide full light well intervention (LWI) services to the subsea oil and gas sector.

FTAI Ocean is a leading marine services provider to the international offshore energy industries. Its expertise includes well intervention, subsea, umbilicals, risers and flowlines (SURF), offshore construction, inspection, repair and maintenance (IRM), remotely operated vehicles (ROVs) and survey and positioning services.

Expro, a premier well flow optimisation service provider, already maintains a leading position in the subsea landing string and well intervention markets, enhanced by its Riserless Well Intervention (RWI) and Intervention Riser System (IRS) equipment supply.

The new exclusive alliance, creates a full service offering for the riserless and riser-based well intervention and P&A markets, providing all marine, ROV, well intervention, wireline, e-line, coilhose, subsea well access, hydraulic intervention, well planning, execution and offshore well management by a single supplier using one contracting entity. The agreement will allow both companies to expand their capabilities and resources to deliver a fully integrated intervention package to the industry.

Expanding capability through collaboration

Graham Cheyne, Vice President of Well Access and Subsea at Expro, commented, “This partnership is a significant step forward for both companies. It will strengthen our position in the subsea well access and P&A markets combining our efforts to provide a bespoke project-specific complete subsea intervention package to meet our customers’ exact requirements.”

“The new alliance and technology offering were paramount in Expro’s recent five-year contract award for the supply of light well intervention services for the Chevron-operated Gorgon facility, offshore Australia.”

“We have introduced the first fully integrated alliance package to the market. This not only enhances our LWI offering but represents Expro’s strong and continued commitment to safety through reduced risks, lower operational costs, and greater efficiencies for our customers,” Cheyne added.

Jon Attenburrow, Managing Director of FTAI Ocean, said, "We are very pleased to be working with Expro, a world leader in well flow technology, with a global footprint and strong track record in subsea well intervention. We look forward to collaborating with Expro to offer clients the highest calibre of subsea intervention services on a global basis.”

Supported by innovation

Both services and technologies will be deployed under the alliance, and will be supported by the introduction of FTAI Ocean’s innovative well intervention smart tower system, which will expand the alliance’s LWI vessel services with the provision of both riser and riserless equipment and services.

Expro and FTAI Ocean will offer the new integrated smart tower system, which has been designed, tested, and classed to DNV standards. The system, operational in water depths up to 1,500m in riser mode and 2,500m in riser-less mode, will be installed on the flagship DP3 M/V Pride Offshore Construction Vessel.