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.
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.
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.”
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.
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.”
Following an offer letter signed in April 2021, Archer has announced that it has signed a sales and purchase agreement (SPA) to acquire DeepWell for NOK177mn on a debt and cash free basis which will be financed using existing cash and liquidity reserves.
DeepWell is a leading Norwegian well intervention company which provides wireline and downhole services to oil companies on the Norwegian Continental Shelf (NCS). The company currently employs approximately 200 people and, across 2020, had a revenue of around NOK360mn.
The acquisition of DeepWell, which commands one of the most modern wireline unit fleets on the NCS and holds a strategic long-term contract in the light well intervention market, will greatly enhance Archer’s well intervention service offerings in the North Sea.
Lage Nordby, Vice-President of Wireline at Archer, commented, "We are pleased to welcome DeepWell’s team of employees to Archer. By strengthening our wireline equipment fleet and organisation, increasing our low emission solutions, and continuing our track record for service quality, Archer is well positioned on the Norwegian Continental Shelf. The acquisition of DeepWell gives us access to equipment and employees needed in order to fulfill our obligations under our recently awarded wireline contracts with Equinor and ConocoPhillips."
Jan Erik Rugland, COO of Moreld AS and CoB of Deepwell, said, "We are pleased to have reached an agreement with Archer securing continued operations on existing contracts and the continued development of DeepWell’s state of the art wireline technology. I want to thank all the employees, both on- and offshore, for their dedication and perfection. This transaction is in line with our strategy to divest capital intensive businesses in order to focus our energy on transition and growth plans."
The closing of the transaction is expected to be finalised during Q2 2021 and is subject to customary closing conditions and regulatory approvals.
The rate of technological advancements is advancing, and it is pulling the oil and gas industry into new realms of digitalisation, automation, AI and more. The field has become more competitive and yet, despite this, the latest innovation from Blue Spark Energy, the wireline applied stimulation pulsing technology (the BlueSpark tool) which has the potential to radically increase the efficiency of well intervention operations, stands apart.
In a virtual webinar, Blue Spark Energy representatives Todd Parker, CEO, and Chris Grahame, VP of Sales and Marketing, presented the technology, describing it as the future of environmentally responsible wellbore interventions.
As Parker explained, the engineers at Blue Spark Energy have utilised electrical energy in a third format outside of AC or DC, high pulsed power, for application within the well intervention sector. High pulsed power is the idea of taking electricity and compressing it to be released in a very short period of time. Returning to school physics, power equals energy over time, so by reducing the time taken, the power is much higher. By example, Parker demonstrated a test in the Blue Spark Energy laboratory which used the energy equivalent to two cell phone batteries and releasing it in microseconds to generate power in the hundreds of megawatts range. The company has taken this and built a device to take electrical energy, compress it and then produce a high power output for use in the well intervention sector.
Production enhancement
So what can this technology actually do? Well, as Parker continued, “The primary application of this technology is to return oil wells to optimal production by removing blockages that could cause disruptions. The BlueSpark tool, through repeated high power pulses, can effectively remove organic and inorganic debris in production zones and reopen perforations which have been plugged either immediately after perforation or as the well has matured.”
Already Blue Spark Energy has deployed this technology in hundreds of wells across the globe and returned with some incredibly promising results. Listing some of these examples, Parker stated that in one example in the Middle East, a customer used the BlueSpark technology for two remote wells and found that the high power pulses were just as effective as coiled tubing acidisation methods and was able to more easily target specific zones. Additionally, the small footprint and ability to rapidly mobilise to the remote location (due to the small amount of equipment and personnel required) meant the BlueSpark tool produced the same result in just 10% of the time and led to an aggregate increase of 60% in oil production across the two wells.
Parker noted that the technology can be used to clear blockages across the wellbore – be that in the productive zone or the completion equipment further up – any part that has the capacity to create somewhere for debris to start building up the BlueSpark tool is effective at treating the disruption. It is also not restricted by the kind of debris that is obstructing the well, and anything from waxes, calcium carbonate or even iron sulphides can be treated. With other intervention methods you often need deeper diagnostics to ascertain what chemicals are required, for example, but all Blue Spark Energy operators need to confirm is if there is debris and where – they are not concerned with what it looks like or what it is.
To emphasise this, Parker added, “In the North Sea at an unmanned installation the operator encountered a barium sulphate scale build up in the tubing and across the surface controlled subsurface safety valve (SCSSV). Operators were unable to use conventional methods due to scale build up restrictions above the SCSSV and were therefore required to shut-in the well and set up a plug as a barrier below the SCSSV. We were able to take out a small wireline mast and within 24 hours place the technology across the SCSSV, remove the debris and put the well back into production. This was a 3500bpd producer in danger of being shut which we were able to rapidly treat without causing any damage.”
Multiple applications
In addition to cleaning screens and gravel packs in oil production, the BlueSpark tool has also been deployed for usage in other applications such as water source wells or improving geothermal efficiency, proving its versatility across the energy sector. In another case in the North Sea, Parker showed how the technology was used to improve the efficacy of decommissioning wells by removing debris to allow for a rigless type of decommissioning as opposed to section mill or something more complicated.
This technology, as Parker continued, is particularly suited when deployed by wireline tractor, and is compatible with all wireline industry equipment – if a perforating gun can be run off the wireline unit so can the BlueSpark tool. It is very transportable, able to be transferred in a helicopter for example, and is deployed in pairs to de-risk operating time. It also has an incredibly small environmental footprint, without using chemical fluids, explosives and requiring only a small amount of energy. Although the pulses are released at high power, due to the low energy used, there is no risk of damaging any equipment.
Saving money as well as the environment
After the webinar, Parker spoke to Offshore Network to shed more light on this innovative new technology and which markets the company is targeting in the future.
Parker said, “The process people are talking about a lot at the moment is the electrification of a lot of carbon intensive processes. The BlueSpark tool can become that intervention device that leads in the electrification of conventional well intervention techniques. There is no risk of creating a situation worse than you had before, no safety hazards, and finally you are reducing the carbon footprint of your intervention operations.”
Aside from the environmental and safety benefits, the BlueSpark technology also offers significant financial incentives as well. Parker added, “The costs savings mainly come from operators not having to move a rig or heavy equipment, and the ability to intervene quickly. It costs less to transport, there are less people required to move it, and it’s very fast to set up (there is no wellbore preparation). Looking from a fiscal perspective you are probably looking at being able to save more than 50% over using a conventional technique to accomplish the same result. We have case studies where we have saved customers days of operating time and millions of dollars.”
The story so far
Parker took some time to reflect on Blue Spark Energy’s journey so far which, at times, has been quite frustrating. He said, “The physics is basically high school physics, the engineering was not, so it took some time to build the tool robust, durable and slimmer to access more wellbores, but we finally had a commercial model in 2013 which we started to take around the world.”
“Unfortunately this is where you run up against the inherent conservativeness of the industry itself. From 2013 to 2018 we really faced that from a lot of operators who, broadly speaking were interested in new technology but really struggled to introduce it as it is radically changing their intervention, not changing a small part of it such as introducing a type of chemical. It took us a few years to get some customers to where they were comfortable making that change.”
Currently Blue Spark Energy has quite a large capacity, after deploying to more projects and manufacturing more assets to meet demand. It has ongoing projects in Nigeria, Denmark, Norway, the UK, Malaysia and the Middle East and, to date, has completed over 600 projects across the world working with a variety of clients such as Exxonmobil, Chevron, Shell, Equinor and more. Across the thousands of well descents attempted by the technology, it boasts a 99.6% operating efficiency and rarely creates downtime for customers. As there is a small amount of equipment and capex required to perform an operation, it is a relatively easy fleet to maintain. Additionally, as there are no complicated moving parts and the supply chain is quite simple, it is an extremely scalable business.
Looking ahead
Turning to the future, Parker commented, “Covid had an impact on business, 2020 was not our best year but it was our second best year. Now there is a tremendous backlog of wells that require maintenance and people want to do it rapidly and effectively, so we are envisioning a big uptake in activity in the short term. We think it is an opportunity for a lot of customers to see the benefit of this technology.”
Parker continued, “We want to continue to operate in logistically challenged regions, that is the easy argument. In some regions such as Africa, the Middle East, and Far East it is hard to get equipment to these locations, so why not try something radically different that is easy to get there.”
“The second dimension is we are still discovering additional applications. People are coming to us and asking, can we do it for this or use it for this purpose and we are continually refining the technology. So while there is a geographic spread there is also some technical growth we are seeing as well. Being able to help the decommissioning process, for example, to more effectively cut off any methane leaks in the future is exciting, as it is a big topic which at the moment has tremendous costs for operators. We are starting to get some real interesting air time in that space.”
Petrofac has secured a contract with BP to develop operational procedures for the Greater Tortue Ahmeyim (GTA) Project in Mauritania and Senegal.
Centred on minimising risk and harm to personnel, plant and the environment, the procedures will encompass all offshore operations, including subsea, floating production storage and offloading (FPSO) and hub.
The Tortue Ahmeyim gas field, with estimated resources of 15 trillion cu ft of gas, is located offshore the border between Mauritania and Senegal in water depths of more than 2,000 metres. Spanning five blocks (three in Mauritania and two in Senegal) in addition to the GTA unit, the LNG project will have BP as operator and is being jointly developed by BP, Kosmos Energy, Societe des Petroles du Senegal (Petrosen) and Société Mauritanienne des Hydrocarbures.
The final investment decision (FID) for phase 1 of the project was taken in December 2018 with the FID for phase 2 expected in 2022. Initial production was projected in 2022 before Covid delays caused this to be pushed back to 2023. Once completed, the GTA LNG project is expected to produce up to 10mn tonnes of LNG a year.
The integrated gas value chain and near-shore liquefied natural gas (LNG) development will export LNG to global markets as well as supplying gas to Senegal and Mauritania.
On the opportunity to take part in this exciting project, Steve Webber, Senior Vice-President of Operations at Petrofac, commented, “BP is an important longstanding client and we look forward to supporting them in operating safely and responsibly, in their delivery of the GTA Phase 1 Project, which is creating a new LNG hub in Africa.”
Aker BP was the first operator worldwide to use bismuth alloy to plug the top section of old oil wells. Since then, the technology is now used on 30 wells on the Valhall field, resulting in safer, permanent well plugging.
The Valhall field
The Valhall field in the southern part of the North Sea has produced over a billion barrels of oil equivalent since it began production. To ensure consistent performance, old oil wells must be plugged to make room for new wells in the hopes that over the next 40 years another one billion barrels of oil will be drawn up.
Martin Knut Straume, Aker BP’s Chief Engineer for Plugging and Abandonment, commented, “We’ll continue to work on Valhall for many decades to come. That means we have to make sure that we shut down and abandon old wells safely, so that it is safe for us to be there when we continue to produce and drill new wells at the same time. We use the best available technology, and in this case, in the top part of the old wells, that means bismuth.”
Aker BP has already started removing the old field centre on Valhall with the living quarters platform removed in 2019. Another two installations will disappear over the next five years and all wells connected to the old drilling platform will be permanently plugged over the course of 2021.
Egil Thorstensen, Senior Engineer for Plugging and Abandonment at Aker BP, said, “We’re currently installing bismuth plugs in the top section of all the wells; in other words, in the 30-inch casing. That’s the last thing we do before we cut and pull the pipes from the seabed to the platform, and the well is permanently abandoned.”
Diverse solutions provided by new technology
Plugging wells on Valhall may pose an additional challenge both due to gas migration to the surface, and due to subsidence and compaction. The seabed around the Valhall field has sunk seven metres since the early 1980s, and the top of the reservoir has dropped about 15 metres.
This means that cement, which is commonly used as a barrier material to plug wells, is an inadequate solution as it can fail when subjected to wellbore or casing stresses resulting from subsidence and compaction events. In the worst case, hydrocarbons in old wells could migrate upwards and potentially leak into the sea.
“Aker BP installed a trial plug over two years ago, and was the first operator worldwide to use bismuth alloy in the top section of the well. When we use this technology, we make sure that the plug is 100% impermeable. Gas cannot leak to the surface,” said Thorstensen.
Bismuth is a metal with unique properties that make it particularly well-suited for applications in P&A operations. As a solid metal, it is completely impermeable and is heavy as lead, making it less prone to contamination during its placement into the well. When melted, liquid bismuth flows like water, giving it the ability to flow into the smallest interstices in the well. When bismuth solidifies, it expands, which helps provide permanent sealing capability inside a wellbore.
Additionally, unlike cement plugs which need to be several dozens of metres in length in order to qualify as barrier, a 2.5 metre-long bismuth plug suffices to provide long term isolation in the well.
Reducing environmental impact
Bismuth alloy is typically a more expensive option than cement but total costs of plugging the top well sections are less due to decreased rig time for these operations.
“Even so, we have chosen to use it on Valhall because of the unique field conditions. For us, this is a matter of making sure that we minimise the carbon footprint from our operations, while ensuring that the wells are plugged and abandoned to the highest standard. Bismuth has what cement lacks: it changes almost instantaneously from liquid to solid when the heating source is removed, it is completely impermeable, and it is not affected by contamination issues,” commented lead technical engineer at Aker BP, Laurent Delabroy.
During the autumn of 2020 and winter this year, bismuth plugs were installed continuously from the Maersk Invincible rig on the Valhall field centre. The plugs are up to 2.5 metres long and weigh 9 tonnes. The work has been performed through the jack-up rig alliance between Aker BP, Maersk Drilling and Halliburton. Time spent per well was cut in half to a record-low 30 hours this winter which has resulted in significant cost savings and freed up several months of rig time that can now be used for new operations.
Delabroy concluded, “We succeeded through strong teamwork and close collaboration with our solid technology partner, BiSN. And last but not least, because we are part of a company that dares to use new technology. Aker BP is not only the first in the world to develop and perform this type of operation, we are now the world’s largest users of this technology, and many other oil and gas operators are following suit. That says something about our company.”
Baker Hughes has been awarded a subsea oilfield equipment contract from Petrobras as part of the Marlim and Voador field revitalisation plan in the Campos Basin, offshore Brazil.
The contract includes several key technologies from Baker Hughes’ Subsea Connect portfolio and will provide Petrobras with a connected suite of solutions to help drive efficiencies, reduce costs and improve execution speed.
Baker Hughes will supply up to five subsea production and injection manifold systems, which benefit from a lightweight and compact design for installation from smaller vessels and include integrated hydraulic connection systems and retrievable choke modules to realise life of field cost savings. The manifold systems will also include Baker Hughes’ field proven vertical mechanical clamp connection system which increases installation efficiencies.
In addition to the manifold systems, Baker Hughes will provide 32 modular, structured, subsea control modules (called Modpods) which are powered by SemStar5 technology, manufactured in the company’s Nailsea facility in Bristol, UK. The modules have extensive field deployment history with a mean time between failures of more than 150 years.
Neil Saunders, Executive Vice President of Oilfield Equipment at Baker Hughes, commented, “This order is an important example of how Subsea Connect is bringing structured technology to improve execution certainty. We are able to deliver world-class subsea solutions with a breadth of expertise and skills to bring flexibility, scalability and versatility to complex projects. We are proud to partner with Petrobras on the revitalisation of Marlim and Voador and offer our latest subsea technologies for Brazil.”
The contract will include a global team of experts delivering the subsea production and injection manifold systems, subsea control modules, subsea connection systems and field installation support. The manifold systems will be fabricated, tested and assembled in Baker Hughes’ Centre of Excellence facility in Jandira, Brazil.
Adyr Tourinho, Vice President of Brazil and Oilfield Equipment for Latin America at Baker Hughes, said, “This contract is a culmination of our multi-year engagement with Petrobras and builds on our history supplying subsea production systems to deepwater projects in Brazil. Our lightweight, compact technology is engineered to combat the most demanding conditions found in today’s deepwater environments.”
A bright future ahead
Baker Hughes’ recent Q1 2021 results show that the company had faced a challenging year, suffering year on year declines in areas such as orders and revenue. However this is a squeeze being felt unanimously across the energy industry and Lorenzo Simonelli, Chairman and CEO of Baker Hughes, noted that he envisioned a bright future for the company, which will no doubt be aided by the recent agreements with Petrobras and other major players such as Saudi Aramco.
Simonelli commented, “We are pleased with our first quarter results as we generated strong free cash flow, continued to drive forward our cost-out efforts, and took further meaningful steps in the execution of our strategy. During the quarter, TPS delivered solid orders and operating income while OFS continued to execute cost-out programmes to help drive another strong quarter of margin performance. We also advanced our position in the energy transition, investing in strategic areas for growth and entering important partnerships to advance new energy frontiers including hydrogen and carbon capture, utilisation and storage.”
“As we look ahead to the rest of 2021, we remain cautiously optimistic that the global economy and oil demand will recover from the impact of the global pandemic. We expect spending and activity levels to gain momentum through the year as the macro environment improves, likely setting up the industry for stronger growth in 2022.”
Beacon Offshore and Claxton, the lead brand for the Acteon drilling and decommissioning business segment, have signed a master services agreement for the severance and recovery of more than 100 subsea wells in the Gulf of Thailand.
While detailed information of the agreement has so far been withheld, Sam Hanton, CEO of Claxton, stated, “The relationship with Beacon Offshore is a milestone for long-term collaboration in the region which was underpinned by significant effort and commitment by all parties.
“We are very excited about this project as it highlights Claxton’s rigless P&A capabilities and reflects the expertise of Claxton as a trusted partner in vessel-based decommissioning.”
Asia Pacific decommissioning
This is the latest agreement regarding decommissioning operations in Asia Pacific, a market which is expected to take off in the next few years largely due to the shared global desire to limit climate impact by ensuring abandoned wells are properly plugged and abandoned with infrastructure removed. While, traditionally, complicated government regulation and lack of experience has restricted such campaigns in the region, this problem is fast becoming too large to ignore, especially with a large number of fields approaching the end of their production life.
As Jean-Baptiste Berchoteau, Wood Mackenzie’s Asia upstream analyst, told Breakbulk last year, “With more than 380 fields expecting to cease production in the next decade, the magnitude and cost of work can no longer be ignored. Through learning from global decommissioning projects, the industry can adopt and adapt practices best suited for Asia-Pacific’s own set of challenges.”
Breakbulk noted that across the 380 fields there are 35,000 offshore wells, serviced by 2,600 platforms representing 7.5 million tonnes of steel and more than 55,000km of pipelines which will need to be retired in the forthcoming years – representing an enormous challenge which operators will have to deal with in order to meet their environmental commitments. Such a challenge, however, opens a very promising door for service providers such as Claxton who in the coming years will no doubt be called into action to conduct more decommissioning operations in this region.
Reliance Industries Limited (RIL) and bp have announced the start of production from the Satellite Cluster gas field in block KG D6 located about 60km from the existing onshore terminal at Kakinada on the east coast of India in water depths of up to 1,850m.
RIL is India’s largest private sector company spanning hydrocarbon exploration and production, petroleum refining and marketing, petrochemicals, retail and digital services. Together with bp, the company has been developing three deep-water gas developments in block KG D6 – R Cluster, Satellite Cluster and MJ which are expected to produce a combined 30mn cu/m per day (around one billion cu/ft a day) of natural gas by 2023.
Both of the developments will utilise the existing hub infrastructure in the KG D6 block. RIL is the operator of the block with a 66.67% participating interest, while bp holds a 33.33% participating interest. It had originally been scheduled to start production in mid-2021.
The Satellite Cluster is the second of three scheduled developments to come onstream, following the start-up of R Cluster in December 2020. R Cluster is located at a water depth of greater than 2,000m, is the deepest offshore gas field in Asia, and is expected to reach plateau gas production of about 12.9mn cu/m per day in 2021.
Mukesh Ambani, Chairman and Managing Director of Reliance Industries Limited, commented, “We are proud of our partnership with bp that combines our expertise in commissioning gas projects expeditiously, under some of the most challenging geographical and weather conditions. This is a significant milestone in India's energy landscape, for a cleaner and greener gas-based economy. Through our deep-water infrastructure in the Krishna Godavari basin we expect to produce gas and meet the growing clean energy requirements of the nation.”
bp Chief Executive, Bernard Looney, added, “This start-up is another example of the possibility of our partnership with RIL, bringing the best of both companies to help meet India’s rapidly expanding energy needs. Growing India’s own production of cleaner-burning gas to meet a significant portion of its energy demand, these three new KG D6 projects will support the country’s drive to shape and improve its future energy mix.”
Together the R Cluster and Satellite Cluster are expected to produce about 20% of India’s current gas production. The third KG D6 development, MJ, is expected to come onstream towards the latter half of 2022.
Page 76 of 90
