Azeri Central East joins six other offshore platforms that were already installed on the ACG field, which has been producing since 1997. To date, the offshore Azerbaijani field, located off the coast of Baku, has yielded more than 4.3 billion barrels of oil.

The development of the ACE project was approved in April 2019. It is the first platform to come online since the start-up of the West Chirag platform in 2014.

BP operates two more platforms in the Caspian Sea, which serve the Shah Deniz gas field.

The ACE platform and its associated facilities are engineered to handle a capacity of up to 100,000 barrels of oil per day (bpd), with the project anticipated to yield approximately 300 million barrels throughout its operational lifespan.

The 48-slot production, drilling and quarters platform sits midway between the Central Azeri and East Azeri platforms in a water depth of 137m.

Its jacket has a weight of 16,000 tonnes and a height of 153m. The platform houses three production risers, one for water injection, one for oil export, and one for gas export.

BP projects senior vice president Ewan Drummond said: “I’m incredibly proud of the team at bp for safely delivering the first bp-operated offshore platform fully controlled from onshore. This establishes a new benchmark for innovative engineering and competitive project delivery for our company and the wider industry.”

Oil undergoes processing on the platform before being transported roughly 130km via a newly established in-field pipeline to the Sangachal terminal onshore, connected to an existing 30″ subsea export line.

Initial oil production from ACE is from the first well that was drilled from the platform towards the end of last year.

Production from ACE is projected to ramp up through 2024, to approximately 24,000bpd as two additional planned wells are drilled, completed, and integrated into operations.

BP is the operator of the ACG project with a stake of 30.37%. Its partners include SOCAR (25%), MOL (9.57%), INPEX (9.31%), Equinor (7.27%), ExxonMobil (6.79%), TPAO (5.73%), ITOCHU (3.65%), ONGC Videsh (2.31%).

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Digital twins are virtual replicas of physical assets, processes, or systems. They leverage real-time data and simulations to model the behaviour, performance, and condition of their real-world counterparts. In the context of hydropower plants, a digital twin of the entire facility can be created, capturing intricate details of turbines, generators, reservoirs, dam structures, and the surrounding environment. This virtual representation enables operators and engineers to gain insights into the plant’s operational status and behaviour without being physically present at the site. Moreover, digital twins allow for testing different operational scenarios and evaluating their potential impact before implementing changes in the physical plant.

Benefits of digital twins in hydropower

• Optimizing Performance: Digital twins enable hydropower operators to monitor the entire system in real time. They provide insights into turbine efficiency, water flow, and energy generation, empowering operators to identify inefficiencies and fine-tune operations for maximum output.

• Predictive Maintenance: By continuously analyzing data from sensors and historical performance, digital twins can predict potential equipment failures. This proactive approach to maintenance minimizes downtime and reduces repair costs, leading to substantial savings for hydropower plants.

• Safety Enhancement: Digital twins can simulate extreme scenarios and emergency situations, enabling operators to devise and practice safety protocols without endangering personnel or the environment. This enhances overall plant safety and mitigates potential risks.

• Environmental Impact Mitigation: Real-time monitoring of water levels and flow patterns facilitates better environmental management. By understanding the impact on local ecosystems, hydropower operators can make informed decisions to minimize ecological disruption.

• Improved Decision-making: Digital twins provide a data-driven foundation for decision-making. Operators can simulate the consequences of different strategies, leading to well-informed choices regarding plant configurations and energy generation.

Enhancing flexibility and efficiency in the value chain

Digital twins call for powerful software systems that seamlessly implement them along the entire value chain of hydropower plants. From planning and designing products, machines, and plants to operating products and production systems, this integration empowers users to act more flexibly and efficiently, customizing their manufacturing processes.

• Digital Twin of Product: The digital twin of a hydropower product is created as early as the definition and design stage. Engineers can simulate and validate product properties based on specific requirements, such as stability, intuitive use, aerodynamics, and reliability. Whether it involves mechanics, electronics, software, or system performance, the digital twin allows for thorough testing and optimization, resulting in better-performing products.

• Digital Twin of Production: The digital twin of production encompasses every aspect, from machines and plant controllers to entire production lines in a virtual environment. This simulation process optimizes production in advance, leveraging PLC code generation and virtual commissioning. By identifying and preventing sources of error or failure before actual operation begins, this approach saves time and lays the groundwork for efficient mass production, even for complex production routes.

• Digital Twin of Performance: The digital twin of performance is continuously fed with operational data from products or the production plant. This enables constant monitoring of status data from machines and energy consumption data from manufacturing systems. As a result, predictive maintenance can be performed to prevent downtime and optimize energy consumption. Companies can also leverage data-driven services to develop new business models, enhancing overall efficiency in their operations.

Siemens Digital Enterprise Suite

To facilitate the adoption of digital twins in the hydropower industry, the Siemens Digital Enterprise Suite offers a comprehensive and integrated set of software and automation solutions. A central data platform enables the digitalization of the entire value-added process, while intelligent industrial communication networks facilitate seamless data exchanges within different production modules, collecting operational data in real time.

To address growing industrial security requirements, the Defense in Depth strategy from Siemens ensures effective protection for industrial plants against internal and external threats. Additionally, MindSphere serves as a platform for developing new digital business models, providing state-of-the-art security functions for data acquisition and storage in the cloud.

Customers who have embraced the Siemens Digital Enterprise Suite are already witnessing impressive achievements. Special-purpose machine manufacturer Bausch + Ströbel has experienced increased efficiency of at least 30 percent by 2020, thanks to the time saved during engineering. Schunk, the world market leader in clamping technology and gripping systems, has streamlined its engineering process, leading to shorter project timelines, faster commissioning, and increased efficiency in building similar plants.

A Vuong Hydropower has embraced digitalization to optimize operating costs and improve efficiency. Leveraging Siemens Xcelerator portfolio elements, including XHQ Operations Intelligence and COMOS, the company’s leaders can make faster and more accurate decisions.

The first phase of their digital transformation, spanning from 2021 to 2025, focuses on creating a digital twin of their hydropower facility. By digitizing the system, A Vuong Hydropower gains access to real-time transparent data and reports, enabling faster decision-making and efficient monitoring of production.

Essential tools like XHQ Operations Intelligence provide real-time management and remote accessibility of production operations via a web browser. This system equips operators with reports, alerts, and online data analysis to enhance decision-making capabilities. COMOS, on the other hand, facilitates more efficient asset maintenance, reducing downtime and increasing overall productivity. The combination of these software products creates a powerful digital twin of the hydropower plant.

Challenges and future prospects

While digital twins offer immense benefits to the hydropower industry, their implementation is not without challenges. Integrating data from legacy systems, ensuring data security, and addressing computational complexities are some of the hurdles that need to be overcome. Additionally, developing accurate digital twins requires continuous calibration and validation with real-world data, demanding a robust data management strategy.

Nevertheless, the future prospects for digital twins in the hydropower sector are promising. Advancements in sensor technology, artificial intelligence, and cloud computing will bolster the capabilities of digital twins, making them more accurate, efficient, and accessible. The integration of Internet of Things (IoT) devices will enable a broader range of data collection and enhance the real-time monitoring capabilities of digital twins.

This article first appeared in International Water Power magazine.

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In the most energy-intensive industrial sectors, such as petrochemicals, but also cement, glass and steel, the use of alternative technologies, such as the recovery of waste heat otherwise exhausted to the atmosphere, can produce both economic savings and a reduction in carbon footprint. This is why, especially in highly industrialised countries, there’s growing interest in exploiting not only the noblest heat sources, thermodynamically speaking, ie, those characterised by high energy content and high temperature, but also those flows with lower temperature and lower enthalpy content, which inherently would have a lower conversion efficiency. These latter flows need technologies that can be economically sustainable with a low upfront investment.

One possible approach is the use of ORC (organic Rankine cycle) systems, which, although based on the traditional Rankine cycle, use a fluid or mixtures of organic fluids of various kinds within the cycle. Thanks to this peculiarity, the choice of fluid used allows the exploitation of thermal resources with a range of thermodynamic characteristics.

Exergy’s ‘Smart ORC’ R&D project

To meet the technical and economic requirements for ORC systems suitable for the recovery of thermal waste at low temperatures, Exergy, in collaboration with Regione Lombardia and the EU, successfully participated in the “Tech Fast Lombardia” call for proposals of the POR FESR (Programma Operativo Regionale del Fondo Europeo per lo Sviluppo Regionale 2014-2020) co-financed by the FESR.

Exergy’s project was called “Smart ORC” and involved the development of a family of “mini” (less than 1000 kW) and “micro” (less than 100 kW) modular ORC systems with very high efficiency, building on the company’s proprietary technologies.

Thanks to the involvement of the Politecnico di Milano and local manufacturing companies in the detailed design and construction of the most critical plant components, an ecosystem for the development of further high-efficiency ORC systems and turbomachinery, both turbines and compressors, has been created.

The production of electricity employing ORC technology can be regarded as a form of distributed generation, and with the ability to input waste heat to the cycle as well as to meet the production site’s own consumption, ORC systems have the flexibility of being able to feed into the grid, self-consume or store the energy produced (in electrical or thermal storage systems).

In current small ORC systems, volumetric turbines, eg, screw or vane, or small centripetal radial turbines are used. Both these turbine types are characterised by lower isentropic efficiencies than those recorded for larger ORC-based power plants equipped with radial outflow turbines.

If volumetric machines typically have lower peak efficiencies than turbomachinery, settling at values of around 60-75% (isentropic total to static), centripetal radial turbines are penalised by the difficulty of having to dispose of the entire enthalpy jump in a single stage and, consequently, suffer from limited efficiency.

The adoption of the Exergy radial outflow turbine (ROT), a technology covered by several patents, has many advantages:

• concurrent combination of fluid expansion and increased cross-sectional area;
• mechanical components designed to be easily removable, without the need to empty the system, reducing maintenance times;
• extended bearing life due to very low vibration;
• reduced rotor leakage and friction; and
• greater freedom of choice of both pressure levels and stage pressure gradient, limiting vortex formation and reducing fluid dynamic losses.

Overall, it is a more efficient and reliable turbine technology, with low vibration levels and less noise.

The range of sizes of standard ORC modules investigated and developed in the course of the Exergy Smart ORC project has been selected to suit a wide spectrum of possible heat sources available in the industrial world: 80 kWe; 160 kWe; 210 kWe; 450 kWe; 600 kWe; 850 kWe (gross electric power).

The refrigerant R1233zd(E) is employed as a working fluid.

For these capacities, modular, compact and standardised technology enables, on the one hand, faster installation, construction and reduction in overall system costs, and on the other hand, with the selection of a specific working fluid, promises high performance in compliance with the necessary requirements of safety, non-flammability and low environmental impact.

The resulting low mass and volumetric flow rates, which are considerably lower than those found in medium and large-size ORC plants, required some adjustments to the ROT turbine, the component with the highest level of what might be called technological content.

The new machine was therefore scaled down to a smaller size, with higher rotational speeds, than the reference ROT turbine, in order to maintain its high performance.

The high rotational speeds required (up to about 20,000 rpm) led to the development of specific methodologies for modelling and performing calculations for ‘fast’ rotors, as well as the design and manufacturing of vibration reduction systems known as SFDs (squeeze film dampers), typically used in the aviation industry on commercial and military engines, to stabilise rotors operating at high rotational speeds. The great usefulness of SFD systems lies in their dampening effect on the machine.

Also, the pressurised oil chamber employed in the new machine and its fixed anchorage to the bearings provide a considerable further reduction in vibrations, which are exacerbated by the destabilising action of the rotor’s sealing labyrinths, designed to contain the fluid during its expansion.

In addition to the rotational issues, it was necessary to adopt a speed reducer for the mechanical coupling to the electric generator. While the efficiency of the turbomachine is a function of blade rotational speed, typically the generator has a rotational speed determined by the number of poles it has and the frequency of the electricity grid to which it is connected. A ‘slow’ generator is preferable to a ‘fast’ one due to efficiency losses in the machine itself and in the frequency converter (inverter) needed at high frequencies. With the aim of limiting transmission losses between the turbine and generator, a straight-tooth, seven-satellite, low-service factor planetary-type gearbox was selected, manufactured, and fully integrated into the new machine.

Family of Smart ORC modules

Following the promising results obtained on the test bench, through the R&D project described above, Exergy has acquired the necessary know-how to propose a family of Smart ORC modules plus the associated development of small and standardised turbomachinery. This broadens the application of Exergy’s radial outflow turbine to very small (micro and mini) ORC systems for electricity production from such sources as diesel engine exhaust systems and waste heat available in several industrial processes.

Application of the R&D to date is expected to increase the efficiency of mini and micro ORC systems by about 5 to 15%.

This article first appeared in Modern Power Systems magazine.

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The H2Maasvlakte FEED study is being performed by Uniper, together with Technip Energies and Plug Power. The FEED study is supported by Topsector Energie (TSE) subsidies of the Dutch Ministry of Economic Affairs and Climate.

Support from the EU Innovation Fund makes a “significant contribution” to the realisation of the project, says Uniper. The fund received 239 applications, from which 41 were selected, including H2Maasvlakte. The latter was favoured because of “Uniper’s commitment to transforming existing fossil production sites into green energy sites.”

The Rotterdam harbour area, which includes the Maasvlakte, is the largest carbon-emitting industrial cluster in the Netherlands, Uniper notes. In 2021 the area emitted 23.4 Mton of carbon dioxide and “decarbonising this area alone would contribute significantly to the Dutch overall target to reach net zero by 2050.”

“As a port authority we support, stimulate and help companies in Rotterdam to reach the Paris climate treaty goals in multiple ways, including getting infrastructure like a hydrogen pipeline network in place in time”, said Allard Castelein, CEO of Port of Rotterdam.

“The H2Maasvlakte project marks a significant milestone for Europe’s transition to more sustainable, localised energy in response to geopolitical risk and climate change,” said Andy Marsh, CEO of Plug.

The Port of Rotterdam (PoR) presents significant opportunities for green hydrogen projects, notes Uniper, with the presence of multiple potential off-takers across the planned open access regional hydrogen backbone representing a huge demand for green hydrogen.

The Maasvlakte Energy Hub is “versatile and strategically located”, says Uniper and “all the necessities for a successful energy transition come together here”, with power from offshore wind farms, a port suitable for the import of green fuels,
and “pivotal infrastructure” such as the high-voltage grid and the future hydrogen pipeline network (being built by Hynetwork Services, a subsidiary of GasUnie, working with PoR).

The MPP3 power plant, one of the key production units of Uniper’s Maasvlakte Energy Hub, has an installed capacity of 1070 MW and runs on coal, biomass and residual (waste byproduct) flows from surrounding industry. As well as electricity, it supplies steam to local industrial consumers.

The Maasvlakte Energy Hub also includes various gas-fired production facilities and a large hybrid battery. In the coming years, Uniper plans to develop applications for green hydrogen and bio-fuels at the hub, among other things.

Green hydrogen “will facilitate the energy transition for the petrochemical, mobility, power and heating industries”, Uniper believes and notes that in the Netherlands, the momentum behind hydrogen is growing.

Uniper says its Maasvlakte site “is one of the most convenient locations to realise a large scale green H2 project” and offers “multiple synergies” including:

• Sufficient land available for large-scale green hydrogen production.
• Ability to make use of existing infrastructure: grid connections; demineralised water; natural gas network (could initially be used to blend H2); and cooling water systems of existing power generation assets.
• Opportunities to recycle waste heat from H2 production.
• Availability of power from offshore wind, with 3.5 – 5.5 GW landing at neighbouring TenneT substation within this decade.
• Proximity to Rotterdam hydrogen network (Port of Rotterdam & Gasunie), less than 3 km away as from 2023. This will be integrated, in the longer term, with the national hydrogen backbone towards neighbouring Germany.
• Nearby hydrogen consumers (chemical industry) currently using grey hydrogen that will need to decarbonise to achieve EU targets.
• Ability to benefit from the major role the Port of Rotterdam is likely to play from around 2030 onwards in the import of hydrogen, for Rotterdam and the surrounding area as well as neighbouring countries.

This article first appeared in Modern Power Systems magazine.

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According to the terms of the definitive merger agreement, Prysmian Group will pay $290 per share in cash to shareholders of the Nasdaq-listed Encore Wire.

The consideration represents about 20% premium to the 30-day volume weighted average share price (VWAP) of the US-based Encore Wire as of 12 April 2024.

Encore Wire chairman, president, and CEO Daniel Jones said: “This transaction maximises value for Encore Wire shareholders and provides an attractive premium for their shares. Encore Wire and Prysmian are two highly complementary organisations, and we anticipate a bright future for Encore Wire as part of Prysmian.

“Furthermore, as part of a larger, global operation, we expect this transaction will bring additional future opportunities for our employees, whose dedication and hard work made this transaction possible.”

Through the acquisition, Prysmian Group aims to boost its exposure to secular growth drivers as well as improve the company’s presence in North America.

Besides, the cabling solutions provider intends to utilise Encore Wire’s operational efficiency and best in class service across the former’s portfolio.

The deal will also allow the combined company to better address customers’ requirements in North America by expanding Prysmian Group’s product offering.

Prysmian Group is expected to generate approximately €140m in run-rate EBITDA synergies expected within four years from the closing of the transaction.

Prysmian Group designated CEO Massimo Battaini said: “The acquisition of Encore Wire represents a landmark moment for Prysmian and a strategic and unique opportunity to create value for our shareholders and customers.

“Through this acquisition, Prysmian will grow its North American presence, enhancing its portfolio and geographic mix, while significantly increasing the exposure to secular growth drivers.”

Subject to Encore Wire’s shareholders’ approval, regulatory approvals, and other customary conditions, the transaction is anticipated to be completed in the latter half of this year.

The deal has been unanimously approved by each company’s board of directors.

Goldman Sachs Bank Europe SE, Succursale Italia is sole financial adviser to Prysmian Group while Wachtell, Lipton, Rosen & Katz is the company’s legal adviser.

For Encore Wire, J.P. Morgan Securities is serving as financial adviser while O’Melveny & Myers is the legal adviser.

In February this year, Prysmian Group secured a contract worth €1.9bn for the 2GW Eastern Green Link 2 (EGL2) subsea electricity superhighway project between Scotland and England.

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The deal mainly involves Equinor transferring its 100% stake and operatorship in Ohio’s Marcellus and Utica shale formations in the Appalachian Basin, situated in southeastern Ohio, to EQT. This will be in return for a non-operational 40% interest from EQT in the Northern Marcellus formation in Pennsylvania.

To balance the transaction, Equinor will provide a cash payment of $500m to EQT.

Equinor said that the asset swap deal is aimed at bolstering resources contributing to increased cash flow and further decreasing the CO2 emissions intensity within the firm’s international portfolio.

After the transaction, the Norwegian energy major will raise its average working interest from 15.7% to 25.7% in specific Northern Marcellus gas units operated by Chesapeake. In order to fulfill prior gas sales obligations, Equinor will engage in a gas buy-back arrangement with EQT.

Equinor exploration and production international executive vice president Philippe Mathieu said: “With this transaction, we continue to high-grade the US portfolio and improve profitability by strengthening our gas position in the most robust part of the Appalachian Basin. These assets are well positioned to leverage anticipated positive developments in the US gas market.

“The proposed swap improves portfolio robustness with an expected reduction in well break-evens and upstream carbon intensity. This also means that we have now fully exited all operated positions onshore US.”

Through the agreement, Equinor will acquire an estimated 225 million cubic feet per day (MMcf/d) of projected 2025 net production from the Northern Marcellus shale formation.

On the other hand, EQT will receive approximately 26,000 net acres in Monroe County, Ohio, with an estimated 2025 net production of 135 million cubic feet equivalent per day (MMcfe/d) directly offsetting its operated acreage.

Additionally, EQT will gain around 10,000 net acres in Lycoming County, Pennsylvania, with a projected 2025 net production of approximately 15MMcfe/d from its existing operated assets.

Furthermore, EQT will obtain the remaining 16.25% ownership in the company-operated gathering systems that serve core operated acreage in Lycoming County, Pennsylvania.

EQT president and CEO Toby Rice said: “This transaction marks an extremely positive start to our divestiture program, bringing in over $1.1bn of value, including synergies and development plan optimisation, for 40% of our non-operated assets, while retaining gas price upside.

“We plan to opportunistically divest the remaining portion of our non-operated assets in Northeast Pennsylvania and have tremendous confidence in being able to achieve our de-leveraging goals.”

Contingent on customary closing adjustments, the mandated regulatory approvals and clearances, the deal is anticipated to close in late Q2 2024.

Last month, EQT signed a deal to acquire Equitrans Midstream in a move to create a major vertically integrated natural gas enterprise in the US, with an initial enterprise value of over $35bn.

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The current AP1000 activities at Khmelnytskyi are part of a Memorandum of Understanding (MoU) signed in 2022, for the deployment of nine AP1000 reactors in Ukraine.

The AP1000 is the only available operating Generation 3+ reactor that offers fully passive safety systems, modular construction design and the smallest footprint per MWe.

Currently, the AP1000 reactor is commercially operational in the US, China, and Bulgaria.

The technology is considered to be deployed at multiple other sites in Central and Eastern Europe, the UK, India and North America.

Energoatom head Petro Kotin said: “The Westinghouse company is our reliable strategic partner: both in the development and loading of alternative fuel into the VVER reactors, and in the creation of a fuel production line in Ukraine.

“During the war, we have not stopped, but on the contrary deepened and accelerated our cooperation.”

Ukraine’s Energy Minister Herman Halushchenko said: “The facilities that we plan to build at the Khmelnytskyi NPP will enable Ukraine to make the largest recovery since the Second World War. I am very grateful to Westinghouse.

“In 2020, we signed an agreement to develop fuel for VVER-440 type reactors for five years. But after the full-scale invasion, we significantly accelerated that process and did the impossible – Westinghouse, together with Ukrainian specialists, developed that fuel twice as fast.”

The first batch of Westinghouse VVER-1000 nuclear fuel has been delivered for the two operating units at the Khmelnytskyi Nuclear Power Plant.

Westinghouse manufactured the VVER-1000 fuel at its fuel fabrication facility in Sweden

The company also delivered the first batch of VVER-440 nuclear fuel to Ukraine’s Rivne Nuclear Power Plant in September last year, in a development program.

In addition to the AP1000 reactor, Westinghouse signed an MoU with Ukraine in September last year, for the development and deployment of the AP300 Small Modular Reactor (SMR).

Westinghouse president and CEO Patrick Fragman said: “Westinghouse is honoured to be a trusted partner supporting Ukraine in its pursuit of clean, reliable and secure energy for generations to come.

“This milestone moves us one step closer to bringing another AP1000 reactor online in Europe and joining our global fleet of AP1000 units in China and the U.S., and we remain proud to continue our long-standing, nearly 20-year partnership with Ukraine on proven and reliable nuclear fuel supply.”

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The permit has been issued by the North Carolina Department of Environmental Quality (NCDEQ)’s Division of Energy, Mineral, and Land Resources (DEMLR) after a thorough review. It is subject to customary conditions as well as those tailored to the project’s specifics.

The application for the mining permit was submitted by Piedmont Lithium on 30 August 2021.

Located in Gaston County, the Carolina project is to become a fully-integrated lithium project, encompassing mining, spodumene concentrate production, and lithium hydroxide conversion, all within a single site.

Currently, the American lithium project is in the development stage.

The Carolina lithium project is being designed to have an annual output of 30,000 metric tons of lithium hydroxide.

According to Piedmont Lithium, the projected capacity would more than double the present US production capacity of about 20,000 metric tons annually.

Besides, the Carolina lithium project is expected to greatly contribute to the energy security of the US.

The construction of the American lithium project is expected to begin after obtaining the remaining necessary permits, rezoning approvals as well as project financing activities.

Piedmont Lithium president and CEO Keith Phillips said: “The North Carolina mining permit approval is the precursor for the county rezoning process, and we look forward to continued engagement with the local community and the Gaston County Board of Commissioners.

“Construction would commence following receipt of all required permits, rezoning approvals, and project financing activities.

“We have had extensive and ongoing dialogue with possible funding sources for Carolina Lithium, including the U.S. Department of Energy’s Loan Programs Office and strategic parties who could provide some combination of capital, offtake, and technical support.”

In February 2024, Piedmont Lithium completed a 27% reduction in its workforce as part of the company’s cost-cutting measures amid a decline in lithium prices.

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The company made the final investment decision (FID) after receiving the necessary government and regulatory approvals.

The Whiptail project, which will use a Floating Production Storage and Offloading (FPSO) vessel, will entail an investment of around $12.7bn. It would include up to ten drill centres with 48 production and injection wells.

The FPSO vessel, set to be named Jaguar, is currently under construction.

By the end of 2027, the development is expected to increase Stabroek block’s production capacity by around 250,000 barrels per day.

ExxonMobil Upstream Company president Liam Mallon said: “Our sixth multi-billion-dollar project in Guyana will bring the country’s production capacity to approximately 1.3 million barrels per day.

“Our unrivalled success in developing the Guyana resource at industry-leading pace, cost and environmental performance is built on close collaboration with the government of Guyana, as well as our partners, suppliers, and contractors.

“The Stabroek block developments are among the lowest emissions intensity assets in ExxonMobil’s upstream portfolio and will provide the world with additional reliable energy supplies now and for years to come.”

ExxonMobil affiliate ExxonMobil Guyana operates the Stabroek block with 45% interest. The remaining stake is with Hess Guyana Exploration (30%) and CNOOC Petroleum Guyana (25%).

Currently, more than 6,200 Guyanese support Stabroek block operations. The figure represents 70% of the workforce.

The projects in Stabroek block also support economic development for Guyana, with more than $4.2bn been paid into the Guyana Natural Resource Fund since first production in 2019.

In November 2023, ExxonMobil and Hess commenced production at the $9bn Payara oil development on the Stabroek Block.

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As of now, High-Temperature Reactor (HTR) technology is being promoted by several countries and companies, especially due to its unique inherent safety features. These features are based on the reactor concept and the fuel design itself. Accordingly, many of the small modular reactor (SMR) designs that are emerging are also based on the HTR technology.

HT-SMRs

The dream of reducing the complexity of a nuclear power plant while increasing its safety is reflected in the concept of the Small Modular Reactor (SMR). The key focus lies on reducing the size of the reactor (compared with established designs). When this requirement is fulfilled, modularity, standardisation and increased design integration can be addressed. A more integrated design results in reduced complexity and number of components. Standardisation includes the ability to deploy the reactor more flexibly with less site and grid restrictions.

Nearly all known reactor concepts from the established ones to Generation IV designs can be designed as SMRs. The International Atomic Energy Agency (IAEA) defines them as reactors of up to 300 MWe per module. Similar considerations apply to microreactors, which cover the power requirements below the SMR range.

The Generation IV design, which is meant to be the successor of the high-temperature gas-cooled reactor (HTGR), is the Very-High-Temperature Reactor (VHTR). Both HTGR and VHTR designs use graphite as a moderator and reflector while helium acts as the primary coolant. The main application of the VTHR is synchronous hydrogen and electricity generation. This is enabled by the highest possible outlet temperature: the HTGR reaches temperatures up to 750 °C, while VHTRs are expected to reach about 1000 °C.

The comparably high temperature of HT-SMRs opens the door to a variety of chemical processes, which are not feasible at lower temperatures. One example is the production of hydrogen using high-temperature water electrolysis. This allows fossil fuels substitution for process heat and tackles a large source of current CO2 emissions.

However, the technical advantages of HTRs and SMRs are worthless if safety concerns are not addressed. In addition to the inherent safety features of the SMR concept itself, there are HTR-specific advantages. SMR-specific inherent safety features are, generally speaking, based on the scaled-down design with less fissile material and less complexity.

Inherent safety features of the HTR design also come into play. One is the retention of fission products which is already ensured by the strict requirements of the HTR fuel specifications. TRISO fuel has the key feature that all fissile material is encapsulated in layers of durable silicon carbide (SiC) as well as pyrolytic carbon. Most importantly, core meltdown is practically impossible as the generated heat will intrinsically be able to passively dissipate into the environment even without an active helium cooling circuit. This is supported by the small core power density (compared to a PWR) and the large heat capacity and temperature stability of the graphite-based core itself.

HTR concepts are thus suitable to be combined with the technical advantages of the SMR, modularity, the potential for standardisation, increased design integration and reduced size. The availability of high-quality TRISO fuel is key to all HTRs. The HTR-typical high outlet temperatures can also be utilized for chemical or other industrial processes that have used fossil fuel-generated heat so far.

HTR Fuel

The key component of each HTR is its tightly-specified fuel, which allows it to operate at full performance. Starting in the early 1960s, research and development of HTRs and their associated fuel was carried out in Europe and the USA. In Europe, work was concentrated in the UK and Germany. The German HTR programme was initiated in the early 1960s as part of a civil nuclear development programme.

Within this programme, NUKEM, for example, was focused on the design of fuel elements, fuel specifications, the development of the fuel manufacturing processes and the actual production of HTR fuel. During the 1970s and 1980s NUKEM’s 100% subsidiary HOBEG (Hochtemperaturreaktor-Brennelement GmbH) manufactured and supplied more than 250,000 spherical fuel elements for the AVR experimental nuclear power plant at Ju¨lich and more than 1,000,000 fuel elements for the Thorium High Temperature Reactor (THTR-300) at Hamm-Uentrop in Germany. Based on a highly systematic approach and the development of special quality control procedures for the production processes, fuel quality was continuously investigated and quality standards were established. Consequently, the highest level of HTR fuel quality with regard to minimum fission product release was achieved at this time – and still represents today’s quality standards.

The German experimental AVR (construction began in 1961) was the origin of succeeding pebble bed HTRs like the German THTR-300 (construction started in 1971), Chinese experimental reactor HTR-10 (construction began in 1995), its power producing predecessor HTR-PM (construction started in 2012, 250 MWt per unit) and the South African PBMR (never constructed for financial reasons, 400 MWt). PBMR and the HTR-PM are examples of HT-SMRs and both use spherical fuel elements which are based on the HOBEG/NUKEM pebble manufacturing process.

As opposed to the ‘German-origin’ pebble bed reactors there is another concept based on cylindrical fuel compacts originating from the United Kingdom experimental Dragon Reactor (construction began in 1960, 20 MWt). Fuel compacts are arranged in a prismatic fuel assembly – usually a hexagonal graphite block with rod-shaped openings that are filled with cylindrical fuel compacts.

HTR fuel in the form of a cylindrical compact or a spherical pebble consists of many small uranium kernels of about 0.5 mm in diameter. Uranium can either be in the form of pure uranium dioxide or uranium oxycarbide (UCO), which is a mixture of uranium dioxide with a certain fraction of uranium carbide.

While the German Thorium-High-Temperature-Reactor (THTR-300) utilised highly enriched uranium (HEU of 93 %) with added thorium, nowadays only uranium with lower enrichment levels is used due to the risk of proliferation. High-assay low-enriched uranium (HALEU) is established as the term to describe uranium with enrichments ranging from 5% to 20%, which are usually used for modern advanced reactors, including HTRs.

Each uranium oxide or carbide kernel is coated with several layers of pyrolytic carbon (PyC) as well as a durable silicon carbide (SiC) layer. While the inner PyC layer is porous and capable of absorbing gaseous fission products, the dense outer PyC layers form a barrier against fission product release. The SiC layer improves the mechanical strength of this barrier and thus the retention capacity for certain fission products.

The proven German TRISO spherical fuel, based on the NUKEM design, has demonstrated the best fission product release rate, particularly at high temperatures. The enriched uranium TRISO particles were contained in a moulded graphite sphere. A NUKEM fuel sphere consists of approximately 9 g of uranium (about 15,000 TRISO-coated kernels) and has a diameter of 60 mm – the total mass of a fuel sphere is 210 g. In more recent projects NUKEM also developed cylindrical compact fuel based on the same TRISO fuel kernels. A cylindrical compact has a typical length of about 25 mm and 12 mm in diameter. It contains about 1.2 g of uranium per compact (about 3,000 TRISO-coated kernels).

HTR fuel production

The HTR fuel production process can be divided into four major fuel production process areas as well as two recycling areas for the recovery of uranium and other valuable materials from liquid process effluents, as well as out-of-specification solid fuel material.

In the Kernel Production Facility, fresh U3O8 powder is dissolved in nitric acid (HNO3) and mixed with special chemicals to a viscous ammonium di-uranate (ADU) solution. This solution is drip-cast (vibro-dropped) to form microspheres from many small droplets, which are then gelled, dried and calcined to form UO3. The UO3 is reduced to UO2 and sintered to a kernel. In the case of UCO kernels, a similar process is utilised to partly form uranium carbide.

Within the Coating Facility, the kernels receive four coatings using a chemical vapour deposition (CVD) process to produce the TRISO-coated particles.

In the Fuel Compact (or Sphere) Production Facility, the TRISO-coated particles are overcoated with a layer of matrix graphite powder (MGP). The MGP-overcoated particles are dosed into pressing moulds together with additional matrix graphite powder according to the desired packing fraction, which determines the volumetric fraction of TRISO-coated particles relative to the total fuel element volume. The resulting fuel element is then carbonised and annealed in two consecutive furnaces – and thereby significantly hardened. In the case of a fuel sphere, this is the final fuel element production step and it is now ready to be introduced into a fuel assembly. Fuel compacts are first inserted into rod-shaped openings within a prismatic graphite block to yield the final fuel assembly.

Two recycling areas ensure that on the one hand, almost no enriched uranium gets lost within the process and on the other hand the required chemicals are reused as often as possible. All traces of uranium from spent liquids are retrieved before they are discharged in the form of decontaminated wastewater.

The liquid effluents from the production processes are recycled and cleaned in the Effluent Treatment Facility. The main purpose is to recycle process liquids for reuse in the Kernel Production Facility. The scrap material from the different stages of the production process – including odd kernels, oddly coated kernels and off-specification fuel elements, as well as other uranium-containing materials – is recycled in the Uranium Recovery Facility to form U3O8, which is ready to be reused in the Kernel Production Facility.

The HTR fuel element production plant operates as a closed-loop system that is designed to approach a 100% overall uranium yield from the raw material U3O8 to the final fuel compact or sphere; therefore, approaching zero emission. The installed quality control procedures ensure that only in-specification intermediate products (uranium kernels and TRISO-coated particles) are used to manufacture the final fuel compact or sphere which has to pass a final quality control step.

Improvements in the HTR production plant

As it became evident in the early 2000s that there may be further interest in Pebble Bed Reactors, NUKEM reactivated the key personnel who were formerly responsible for the development and adjacent commercial operation of the HOBEG fuel production plant. This unique know-how had a significant role in the revival of the HTR fuel technology within NUKEM.

NUKEM developed its up-to-date TRISO fuel production process mainly during the design of the Pebble Bed Modular Reactor (PBMR) fuel Plant. The PBMR Fuel Plant (PFP), originally to be constructed near Johannesburg, was intended to fuel the first South African PBMR. The design of the reactor was based on the fuel specification and the equivalence of the fuel elements to the German fuel. This equivalence is important for the fuel qualification as the former NUKEM fuel has been long-term tested through irradiation tests in the German AVR reactor performed by the Research Centre Ju¨lich in the 1980s.

In the course of more recent fuel plant designs, including PMBR, the process was continuously upgraded in accordance with the most advanced international norms and standards. In general, the focus shifted from administrative criticality safety control to technical control, i.e., the application of safe geometry as far as possible. The implementation of geometrically safe equipment is superior compared to administrative measures to prevent the occurrence of a critical configuration of fissile material. Safe maximum equipment dimensions are determined for certain worst-case scenarios – these limits are kept throughout the geometrically safe areas of a nuclear fuel production plant.

A lot of equipment of the former NUKEM/HOBEG was redesigned with safe geometry considerations in place. The processes for the near-total recycling of uranium and chemicals, as well as for decontamination and purification of liquid and gaseous effluents were also developed in more recent fuel plant projects with respect to criticality safety and radiological protection.

The important revival of the existing TRISO fuel production know-how, the consideration of modern techniques and state-of-the-art safety requirements represents a challenging engineering task, which was accomplished by NUKEM at the end of the 2000s.

The main target of the current century is to continuously replace fossil fuel-generated, CO2-heavy process heat. This can be achieved by building up a fleet of HTRs. Especially, the HT-SMR, which combines the advantages of the HTR with those of the SMR. SMRs can be deployed very flexibly in industrial cluster areas with high demand for process heat and NUKEM is ready to fuel the emerging HT-SMR fleet.

This article first appeared in Nuclear Engineering International magazine.

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