Ashtead Technology, an integrated subsea technology and services provider, has penned a deal with Zetechtics, a leader in subsea control systems for ROV tooling intervention, to offer customers a range of new ROV tooling technologies.
The deal gives both organisations the scope to add further specialist equipment based on demand and will allow Ashtead Technology’s nine customer service hubs to offer an array of torque tools, control systems and associated peripherals from the subsea control systems specialist.
Ashtead Technology noted this was part of their strategy to continually develop and expand their capability to meet the diverse needs of their customers around the world, who operate in all areas of the global energy industry.
David Mair, Business Development Director for Ashtead Technology commented, “These new technologies offer improved performance, reliability and efficiency, as well as a greater level of user-friendliness. Zetechtics has 27 years of experience for us to draw on and this collaboration is set to add undeniable value to our customer’s operations.”
Alan Duncan, Commercial Director of Zetechtics, added, “Customers prefer to use modern, easily-supported equipment, with the type of technical features they would have access to if buying new. We are excited to collaborate with Ashtead Technology and by introducing a wide range of new equipment to the market in this way will enable their customers to unlock the potential of our market-leading solutions.”
At Hannover Messe, April 12-16, Bosch Rexroth will present the SVA R2 Subsea Valve Actuator, a disruptive innovation for electrically actuating valves in the subsea process industry.
The SVA R2 is the world’s first electric actuator that can replace conventional hydraulic cylinders with field-proven safety technology and without taking up additional space. The integrated electric controller offers precise motion control and, thanks to condition monitoring and a safety spring, the SVA R2 satisfies Safety Integrity Level (SIL) 3 in accordance with IEC 61508 and IEC 61511.
The actuator minimises energy consumption and is geared toward delicate ecosystems. The functions, operating life and safety of the actuator have already been successfully tested in accordance with international standards and when the SVA R2 is used in subsea factories at a depth of up to 4,000 meters, hydraulic pipes or power units are no longer required. The electric supply pipes which are already installed for sensors are adequate to ensure the reliable operation of the actuators.
Changing the subsea process industry
Up until now, the operators of process systems have mainly relied on hydraulic cylinders in order to open and close subsea valves with a quarter turn and a defined force. With offshore installations, for example for oil and gas production, these cylinders are supplied by a central hydraulic power unit with hydraulic pipes several kilometres in length. This solution uses a great deal of energy in order to compensate for the cumulated losses and it cannot control the movement with precision. To date, plant engineers and operators have still relied on hydraulic cylinders because they are the only components to offer field-proven safety systems with a mechanical spring in a compact design (the electric actuators which are currently available do not have such a safety function as this is not possible given the size and weight requirements). Additionally, approaches designed to ensure safety using subsea batteries cannot guarantee the reliable closing of valves over the required operating life of up to 25 years.
For the agile development of the SVA R2, the Bosch Rexroth team worked closely with a number of suppliers and operators of offshore installations, as well as international universities. The new module comprises a pressure-compensated container that contains an electric drive, a motion control system and a safety device – and can replace the hydraulic cylinders previously used on a 1:1 basis. It requires only one cable for the power supply and communication. The SVA R2 is designed to actuate valves reliably with the power supply that is commonly used for subsea sensors. Switching to compact and safe electric actuators means that hydraulic pipes (several kilometres in length along with the associated power units and controllers) are no longer required.
The Subsea Valve Actuator is designed for high volume production, has proven robustness and reliability and is suitable for applications above and below water such as hydrogen production, CO2 storage and general applications in the oil and gas process industry. This innovative new technology has been nominated for the prestigious Hermes Award and, after its premiere at Hannover Messe in April, the first pilot tests are due to start in the third quarter of 2021 before being offered to Bosch Rexroth’s global client base.
Safe Influx has announced that the rig trial of the industry’s first ever integration of Managed Pressure Drilling (MPD) and Automated Well Control technology has been completed following months of preparation by Weatherford, Safe Influx and Finesse Control Systems.
A series of pre-agreed tests were successfully performed on Weatherford’s test rig in Houston, to demonstrate and verify the integration and functionality of both systems.
A "game changer" for the industry
The combination of Weatherford Victus intelligent MPD and Safe Influx’s Automated Well Control system provides automated secondary well control, which will allow wells to be drilled and constructed with the highest level of efficiency and integrity. As a standalone application, the MPD system can detect, control and circulate out an influx, which is within the well’s operational envelope.
If the parameters within the well’s operational envelope are exceeded, the Weatherford MPD system sends a series of real time signals to the Safe Influx Automated Well Control system which then commences the Automated Shut-in sequence: space out, shut down the top drive, shut down the mud pumps, and finally shut-in the BOP.
“We are delighted to have successfully completed the rig trial of the integration of MPD and Automated Well Control systems. The combination of the Safe Influx patented technology with Weatherford’s comprehensive portfolio of MPD products provides a game changer for the industry. We are confident that this is a reliable tool which has the ability to mitigate risks and enhance efficiency and safety in well operations, to prevent the loss of life, minimise environmental impact, deliver substantial cost savings and protect company reputation,” commented Bryan Atchison, Managing Director at Safe Influx.
Fraser Dunphy, Managing Director at Finesse Control Systems who build the Safe Influx equipment and developed the logic programming, said, “It has been great to work with Safe Influx and Weatherford on this ambitious and innovative combination of technologies. We have been involved with this project since its initial phase and we are thrilled to see this integration working on the rig trial. The successful results reveal the value of combining technologies, knowledge and experience to create a cutting-edge solution to the oil and gas industry.”
The rig trial is part of the Memorandum of Understanding (MoU) signed by Weatherford and Safe Influx in September 2020. Under the MoU, the companies will cooperate globally to focus on revolutionising well integrity during the construction phase by bringing to market the integration of MPD solutions and Automated Well Control technology. This integrated offering will automate the mitigation of drilling hazards, while drilling in the most efficient manner possible.
Halliburton Company (Halliburton) will offer Optime Subsea’s (Optime) innovative technologies as a service across its global portfolio as part of a new strategic alliance.
As part of the agreement, Optime’s innovative Remotely Operated Controls System (ROCS) will be applied to Halliburton’s completion landing string services. The companies will also collaborate to offer intervention and workover control system services leveraging Optime’s Subsea Controls and Intervention Light System (SCILS) technology, a remote digital enabled system that compliments Halliburton’s subsea intervention expertise.
The alliance will facilitate umbilical-less operations and subsea controls for deepwater completions and interventions delivering increased operational efficiencies while minimising safety risk through a smaller offshore footprint.
Daniel Casale, Vice-President of Testing and Subsea at Halliburton, commented, “We are excited to work with Optime and leverage their technologies within our existing subsea completions and intervention solutions. Our alliance advances remote capabilities and provides a capital efficient solution, allowing customers to reduce safety risk, operational footprint, setup and run-time.”
Jan-Fredrik Carlsen, CEO of Optime Subsea, added, “We believe that strong mutual alliances across the vertical supply chain drives continuous improvements needed in our industry. By solidifying this relationship with Halliburton and combining their well-established, reputable service and technology capabilities with Optime’s innovative controls and intervention technology, more customers will have access to these cost-efficient subsea solutions.”
Another step forward for Subsea Optime
The collaboration with Halliburton marks another step in Optime’s short but impressive history, since its foundation in 2015, as an integrated system and service provider with the capability to optimise well interventions and completion operations. Recently the ROCS, perhaps their most successful offering, proved its worth when it was deployed during a completions operation for a production well for Aker BP on the Ærfugl-field on the Norwegian Contintental Shelf in late February. The operation was a success and optimised operations with noticeable reductions in HSE risks and overall cost. Now the ROCS (and the rest of Optime’s offerings) has the opportunity to perform on the global stage, and this partnership with Halliburton will help the company expose its services to a wider customer base.
Al Gihaz Contracting, part of Al Gihaz Holding, has announced its acquisition of assets, intellectual property and the management systems of Enshore Subsea, a UK-based subsea trenching company, providing seabed intervention services to major projects across industries around the world.
The acquisition will see the creation of a new joint venture with the aim of forming a leading seabed intervention and construction management services provider. The joint venture will rely on the acquired specialised assets of the company, the skilled team and the company’s successful track record of completed projects to aid the Kingdom of Saudi Arabia’s drive to generate 58.7GW of clean energy by 2030 as part of the Saudi Vision 2030.
Sami Alangari, Group Vice Chairman of Al Gihaz Holding commented, “With this acquisition, Enshore Subsea will benefit from the technical and financial expertise of Al Gihaz Contracting, which for many years has been a leading power and manufacturing services provider locally and internationally. We will be able to provide competitive, resilient and diverse services to cover projects globally, and in the Kingdom of Saudi Arabia. This investment is in line with the Vision 2030 of the Kingdom and will pave the way for a strong involvement of the Group in this field.”
Enshore Subsea
Enshore Subsea will be based out of the existing operational facility in the port of Blyth in the UK, which is supported by a skills base that facilitates the supply of services into the global offshore seabed intervention market. Services will include subsea engineering and construction management, skilled manpower supply and equipment rental for subsea trenching, seabed intervention, development of seabed tooling technology and submarine flexible product installation. The expertise of the existing management and operational teams from Enshore Subsea will remain with the joint venture.
Pierre Boyde, Managing Director of Enshore Subsea, said, “I am delighted that through this cooperation with Al Gihaz, we are able to take the company forward with a sustainable cost base, renewed energy and focus on our areas of expertise. We aim to be the Contractor’s contractor of choice, supporting seabed intervention projects worldwide.”
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.
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.
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.
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.”
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.
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.
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.
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