GBN is a so-called ‘arms-length’ body (i.e. directed by but separate from the government) intended to boost the delivery of new nuclear. The body has been launched with interim chair Simon Bowen and chief executive Gwen Parry-Jones and its ‘sponsoring department’ is the Department for Energy Security and Net Zero (DESNZ).

Key among GBN’s activities will be support for new small modular reactor (SMR) designs and a site selection process for SMR projects. It began the process of identifying SMR technologies to be supported with market intelligence gathering about reactor designs, which concluded in June 2023. That was followed in July with the launch of a £20bn competitive process to select SMR Technology Partners to design, develop, manufacture, supply, install and commission “various products, equipment or services related to the key plant required for SMR nuclear generation, including but not limited to reactor, steam generation, turbine, electrical generation, as well as the integrated design of these component parts”.

The Technology Partners will be responsible for “delivery to site of a designed and tested solution, a complete set of interface specifications, and installation and commissioning of the solution”. A tender for Technology Partners opened on the government portal, closing on 23 August. Effectively the tender is a ‘down-selection’ of technologies, which GBN said would be completed in Autumn 2023. GBN says it may make up to four awards, depending on the quality of tenders, as well as affordability and value-for-money considerations.

The Procurement Process will take the form of a Competitive Procedure with Negotiation. Applicants who pass the qualification stage will be invited to submit an initial tender. Up to four applicants will be invited to negotiate following evaluation of initial tenders, after which they will be invited to submit a ‘best and final offer’.

The next phase will launch “as quickly as possible”. This will be a contract notice setting out an intention to enter into a development contract with successful bidders. They will be offered:

• Funding to support technology development and site-specific design
• A close partnership with GBN, which will be ‘ready and able to provide developer capability’. GBN initially intends to establish project development companies, with developer capabilities.
• Support in accessing sites.

Up to 50% co-funding will be available through GBN on commercial terms to support Technology Partners in developing a generic design solution for Final Investment Decision (FID) by 2029.

GBN said in the tender that it is looking for a site-agnostic technology that may be deployed across sites with varying ground conditions and cooling options. Sites will include at minimum all those identified for nuclear deployment in the 2011 National Policy Statement for Nuclear Power Generation. GBN will award a two-stage contract (design and supply) for a Site Specific Design Solution. The supply stage is conditional on the exercise of an option by GBN and for a first-of-a-kind project in the UK will include manufacture, supply, installation, provision of fuel assemblies and supporting maintenance services up to and including the first refuelling outage.

Discussing the launch of GBN in his regular planning blog, Mustafa Latif-Aramesh, partner and parliamentary agent at law firm BDB Pitmans, said: “In stark terms, this will mean that the government is finally putting money where its mouth is for small and nuclear reactors.”

He said the government should “throw resources at updating the National Policy Statement for Nuclear” in advance of its 2025 publication target, and explicitly confirm that nuclear projects outside of existing or decommissioned nuclear sites can progress.

More investment in large and advanced units

Just days after launching GBN, UK DESNZ confirmed a £170m ($217m) investment of previously allocated funding for development work on Sizewell C. The investment – part of a £700m ($894m) investment scheme announced in November 2022 – will help fund Sizewell C’s continuing development so it can reach the point of a final investment decision, including preparing the site for future construction, procuring key components and expanding the workforce.

DESNZ said the investment would “help attract potential private investment into new nuclear projects”. Energy Security Secretary Grant Shapps said the planned EPR at Sizewell C “represents the bridge between the ongoing construction of Hinkley Point C and our longer-term ambition to provide up to a quarter of the UK’s electricity from homegrown nuclear energy by 2050”.

The UK government also announced funding for three research projects for so-called advanced modular reactors (AMRs), whose high-temperature operation means they can provide heat for hydrogen and other industrial uses while generating power. They are:

• Up to £22.5m ($28.7m) to Ultra Safe Nuclear Corporation UK in Warrington to further develop the design of a high-temperature micromodular reactor.
• Up to £15m ($19m) to the National Nuclear Laboratory in Warrington to accelerate the design of a high-temperature reactor, following its success in Japan.
• Up to £16m ($20.4m) to the National Nuclear Laboratory in Preston to continue to develop the capability to manufacture the coated-particle fuel that is suitable for high-temperature reactors.

GBN launch has mixed reaction

The UK’s Infrastructure and Projects Authority (IPA) is an ‘arm’s length’ body that describes itself as “the government’s centre of expertise for infrastructure and major projects”. In its Annual Report on Major Projects 2022-23, published on 20 July, the IPA chose to highlight Great British Nuclear.

The IPA held an Opportunity Framing workshop as part of the establishment of GBN aiming to drive consensus among key stakeholders, accelerate strategic decision making and define actions around GBN’s structure, scope and purpose. The IPA said it identified critical success factors, including the potential funding model and capability building, and aligned key stakeholders to a high-level decision roadmap and claimed that “by investing key stakeholders in the journey early on, the programme has been set up for success, ready to move forward in a joined-up way to achieve its vision”.

However, MPs on the Select Committee on Science, Innovation and Technology were doubtful GBN had the strengths claimed by the IPA.

Select Committees are cross-party groups of set up to scrutinise the work of government departments and also conduct ad-hoc inquiries in their sectors. The committee’s report, Delivering Nuclear Power, was also published in July and it warned that “the role of the recently launched Great British Nuclear is unclear beyond its initial task of running a selection between competing SMR developers.”

The committee warned that the government’s stated target of 24GW of nuclear-generating capacity by 2050 and its ‘aspiration’ to deploy a new nuclear reactor every year were “more of a ‘wish list’ than the comprehensive detailed and specific strategy that is required to ensure such capacity is built”. The committee’s chair, Rt Hon Greg Clark MP, was supportive of the government as it identified nuclear power as an important contributor to meeting electricity needs. But he said that achieving 24 GW of nuclear power by 2050 “would be almost double the highest level of nuclear generation that the UK has ever attained. The only way to achieve this is to translate these very high-level aspirations into a comprehensive, concrete and detailed Nuclear Strategic Plan which is developed jointly with the nuclear industry, which enjoys long-term cross-party political commitment and which therefore offers dependability for private and public investment decisions.”

The repeated requirement from witnesses across the nuclear industry was for a much clearer and more concrete strategic plan than currently exists. The committee sought fast action: it recommended that a comprehensive Nuclear Strategic Plan should be drawn up, consulted upon and agreed upon before the General Election due to be held next year.

The report said that for 70 years since the UK built its first civil nuclear reactor in 1956, “Britain’s nuclear energy policy has been characterised by intermittency”. Of the latest initiative to build 24GW of nuclear, including small modular reactors (SMRs), it said “targets are not a strategy”. An Energy Security Strategy  published in March 2022 was followed by  an Energy Security Plan in March 2023. But “Even taken together, the 2022 Energy Security Strategy and the 2023 Energy Security Plan, do not amount to the comprehensive, detailed and specific strategy that we believe is required if the Government’s aspirations are to be delivered.”

Some progress has been made. The committee report said, “A common theme of evidence to our inquiry was ambiguity as to what GBN’s role would be.” Interim chair of GBN Simon Bowen told the MPs that GBN requires statutory powers and they will be granted as part of the Energy Bill now under parliamentary scrutiny. The committee said, “ We are pleased to see this progress, as during our Inquiry the government had not been able to provide us with any clarity on GBN’s role or how it would be set up. But “there is still ambiguity over what GBN’s exact remit will be in the future, beyond running a SMR competition.”

Giving evidence to the committee Professor Grubb, University College London, said GBN “appeared to have multiple yet conflicting roles”.

After Simon Bowen was appointed as industry advisor to the proposed GBN in April 2022, his team was tasked with determining the scope and structure of the body. A report presented to the then-Prime Minister in September 2022, which included 25 recommendations for GBN remains unpublished.

The Select Committee wants the government to set out a comprehensive statement of GBN’s remit, operational model and budget, and its intended role with respect to ministers and government departments. Within this, the government should clearly define what the role for GBN will be on supporting new nuclear projects beyond the initial SMR competition.

The Committee said that although GBN had been tasked to run an exercise to choose between alternative SMR propositions (as above), “At this stage, it is unclear what contribution the government expects SMRs to make to its 24GW target”. It called for the Nuclear Strategic Plan to answer key questions on:

• What deployment of SMRs it wants to see, if any?
• What technologies and vendors it intends to deploy, and whether they will be from a single supplier or multiple suppliers?
• What sites should SMRs be located at?
• What financial model would be used to pay for the contribution of SMRs to electricity supply?

It said, “Each of these questions will require a clear answer if vendors are to be able to take decisions on whether and when to take the next steps towards eventually deploying SMRs.”

This article first appeared in Nuclear Engineering International magazine.

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STRUCINSPECT, a Viennese start-up founded in 2019 as a joint venture between PALFINGER AG, VCE and the ANGST Group, operates what it claims is the world’s first Infrastructure Lifecycle Hub for digital infrastructure inspection and lifecycle management. It is now partnering with Voith Hydro to make the digital assessment and tracking of hydropower dams easier and safer.

A web-based collaboration platform is the core of STRUCINSPECT’s portfolio and combines technologies and functions to maintain bridges, tunnels, and dams in a safe, sustainable, and resource-saving manner. It uses data collected by drones to efficiently visualise and analyse them with the help of artificial intelligence and other technologies such as building information modelling or augmented reality. Based on a set of configurable technology modules, STRUCINSPECT develops individual business solutions together with its customers in order to capture and precisely record inspection data, process it efficiently and use it for effective maintenance decisions.

In future, digital inspections will be performed in shorter intervals with less manual effort. Even the smallest changes will be identified by AI-assisted damage detection. This analysis serves as a base for engineers’ maintenance decisions and focuses their precious resources on exactly this core element. It can mean that maintenance and inspection become more precise and efficient, downtimes are reduced, and the performance of the plant is ensured.

While the solution is already applied in the transportation infrastructure sector the immense potential for hydropower dams is now on the rise. Voith Hydro sees great value in the offering for operators worldwide as there are thousands of dams with an average age of 50 years and many other assets like penstocks, powerhouses and tunnels that this technology can be used at.

“STRUCINSPECT’s digital inspection technology opens up the opportunity to offer new services globally,” Riedel says.

Pilot study

In a pilot project in 2022, the 72-year-old Scottish power plant Clunie was put through its paces. In terms of capacity and size, Clunie is described as being at the heart of SSE Renewables’ chain of power plants between Dalwhinnie, Rannoch and Pitlochry. So far, the inspections at Clunie are carried out twice a year in the form of walk-throughs of the entire structure but problems can occur if damages are not spotted during such manual inspections.

“This is where the advantages of our digital inspection technology come into their own,” emphasises Albert Karlusch, Managing Director of STRUCINSPECT.

“We are excited about the new opportunities this technology brings and happy with the two companies we have on board for its implementation,” says Stephen Crooks, renewables civil engineer at SSE Renewables which is taking a leadership role when it comes to digital inspection.  “With this approach, we have all data managed centrally and generate measurable business value out of it.”

This article first appeared in International Water Power magazine.

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The various gas turbine OEMs, as well as utilities and other users of gas turbines, are currently investigating the impact of firing H2 in their machines. A lot less attention is given to the impact of hydrogen firing on equipment complementary to gas turbines, notably heat recovery steam generators (HRSGs), to which a large proportion of the global gas turbine fleet is connected.

Mixing H2 with natural gas will result in an immediate CO2 emission reduction from gas turbines. The graph on p13 shows the non-linear relationship between increasing the hydrogen content (%vol) in a natural gas fuel mixture and the resulting CO2 emissions (%vol). The most significant CO2 savings are gained from replacing the last ~20% (by vol) of natural gas with H2.

But there are potential side effects for HRSGs of increased hydrogen firing that need to be considered. Depending on the gas turbine conditions set by the gas turbine OEM, the following considerations require attention:

• First of all safety aspects, related to potential H2 accumulation in the ‘attic’ of the HRSG in case of a gas turbine or duct burner trip.
• Higher NOx emissions in the incoming gas turbine exhaust gas, impacting the size and cost of the selective catalytic reduction (SCR) system required.
• Possible higher gas turbine exhaust volume flow and exhaust gas inlet temperature.
• Increased water content in the gas turbine exhaust gas, leading to higher risk of water condensation in the cold end. This increase in water dew point is however minimal up to 50% vol hydrogen content.
• Impact on HRSG performance and gas side pressure drop.
• Burner system-related challenges for HRSGs employing supplementary H2 co-firing.

Safety aspects

Safety concerns relating to hydrogen firing and HRSGs specifically arise in the event of gas turbine or duct burner trip. Potential accumulation of hydrogen in the ‘attic’ of an HRSG in such circumstances is a particular consideration for horizontal-exhaust-flow HRSGs. Design evaluation of the HRSG casing and attic and additional measures for optimal venting, can be applied as risk mitigation actions in accordance with NFPA and other applicable guidelines of local authorities.

Higher NOx emissions in the GT exhaust gas

During combustion, the local flame temperature and flame speed of hydrogen are contributing factors to NOx formation. Higher flame temperatures favour NOx production. Combustion of H2 may lead to higher flame temperatures than natural gas due to the higher heat of combustion of H2. Current tests show that gas turbines running on 100% hydrogen will produce significantly more NOx than those running on natural gas.

The higher NOx emissions directly affect the sizing of the SCR system. Any SCR adaptations after installation will be challenging due to space constraints. Thus, in anticipation of future H2 burning, a larger spool duct needs to be considered in the design of any new build installations. Furthermore, many existing power plants have supplementary firing systems installed either in the inlet duct of the HRSG or between the high-pressure superheater modules. Increasing H2 ratios in the combustion fuel of such burners will also likely increase the NOx emissions and impact SCR performance.

Higher exhaust volume flow and increased exhaust gas inlet temperature
Firing hydrogen can potentially also add extra volume to the exhaust gas flow compared to firing natural gas, depending on the gas turbine conditions.

CH4 has an LHV of 49 895 kJ/kg = 798.3 kJ/mol and H2 has an LHV of 120 087 kJ/kg = 240.2 kJ/mol. Hydrogen has a higher energy density per unit mass but a much lower energy density per mol. Since the compressor of the GT will suck in the same volume flow of air, practically independent of the type of fuel that is fired, and the same amount of energy needs to be added, it means that 3.324 times the amount of CH4 (in mols) need to be added in the form of H2 in case of 100% H2 firing. Typically, for a modern GT, about 4% of the molar flow of air is added as CH4. This will then increase to 13.3% in case of 100% H2 firing. The molar mass of the flue gas drops from 28.3 g/mol (100% CH4 firing, 60% RH @ ISO) to 27.2 g/mol (100% H2 firing, 60% RH @ ISO). A curious phenomenon now occurs: switching from 100% CH4 firing to 100% H2 firing, the mass flow of flue gas decreases by 1.3% while the volume flow of flue gas increases by 2.5%.

For new HRSG units, design parameters such as the sizing of the duct and casing, heating surfaces, internal gas flow distribution within the HRSG and acoustic provisions need to be analysed when designing the unit for H2 firing.

Increased water content in the exhaust gas flow

A combined cycle power plant running on natural gas produces a gas turbine exhaust gas with a water dew point of around 47-50°C. Mixing hydrogen with the natural gas results in increased water content in the exhaust gas (and consequently increased water dew point). While the increase in water dew point is minimal with an H2 content below about 50%, it becomes significant moving towards 100% hydrogen firing.

When adapting an HRSG installation for H2 cofiring, the condensate recirculation system needs to take into account the higher minimum water temperature, which is a function of the water dew point. Adaptation of heating surfaces at the cold end might also be considered, although this is only possible to a limited extent (or not at all) for existing installations.

Effects on HRSG performance and gas side pressure drop

Converting an existing combined cycle power plant fired with natural gas to hydrogen firing, with additional constraints such as maintaining the same GT back pressure, design temperature and HRSG pressures, can be expected to result in a slight decrease in bottoming cycle performance. This can be attributed to the decrease in mass flow and change in specific heat of the flue gas. For a given heating surface, this implies a decrease in heat transfer and consequently less steam production. However, the reduction of steam production is small, of the order of 1-2%.

The increased exhaust water dew point could also have a negative impact on performance, as additional thermal energy  needs to be used to recirculate the condensate to a higher temperature.

For new installations, in case of a larger volume flow of flue gas, the gas side pressure drop in H2 fired plants will be slightly higher than for natural gas units, resulting in a slightly lower gas turbine output.

HRSG burner design for H2 firing

The conversion of an existing NG-fired supplementary HRSG burner system into an H2- ready system capable of accommodating various blends of NG and H2 presents several challenges. These include, but are not limited to: change in properties and supply pressure of H2; increased flame radiation of H2; higher combustion velocity of H2; and increase in NOx emissions.

Overall, the design adaptations required to transition from an NG-fired supplementary burner system to an H2-ready system must be carefully studied on a case-by-case basis to ensure optimal operation and performance of the system.

For new build power plants, it is, in principle, feasible to design a supplementary firing system capable of firing H2 and NG blends in any ratio ranging from 0%-100%. However, the aforementioned challenges with respect to the combustion properties of H2 and NG need to be considered.

Hydrogen readiness certification

‘H2 readiness’ for a combined cycle power plant has already been clearly defined and a TU¨V SU¨D certification guideline is available.

The impact of H2 firing on a combined cycle plant is split into focus areas such as fuel gas supply, gas turbine, HRSG, explosion protection, etc.

The certification process is carried out for three phases of a power plant project: H2- Readiness Concept Certificate; H2-Readiness Project Certificate; and H2-Readiness Transition Certificate.

NEM Energy Group is already in receipt of the H2-Readiness Concept Certificate from TU¨V SU¨D, the first HRSG OEM globally to obtain such certification.

Components complementary to the HRSG, such as the exhaust gas bypass system, transition piece to inlet duct, burner system for supplementary firing, SCR and CO catalysts, are also included in the certification. The H2 readiness certification for a specific plant in the realisation phase will confirm that the plant (initially running on natural gas) has been built according to the H2 readiness concept of the bidding phase.

Navigating the hydrogen roadmap

All in all, the HRSG is impacted by firing hydrogen in the gas turbine and there are various challenges to be considered. However, as of today, HRSGs can be made hydrogen-ready in the design phase to minimise impacts when shifting to hydrogen at a later stage. NEM Energy offers heat recovery products behind GTs to support the hydrogen roadmap for both existing and new build applications.

Authors: Gayathri Hariharan, Pin-Hsuan Lee, Peter Rop, Sebastiaan Ruijgrok, Francesco Perrone, NEM Energy

This article first appeared in Modern Power Systems magazine.

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“A single person looks after the entire 34 MW, 87 000 square foot facility 76% of the time,” said Kevin Siess, Regional Operations Manager at DTE Energy. “Our plant operators are also our maintenance staff who can monitor the plant and its control systems while they are doing their rounds.”

Integrated systems

The CEP opened on the first day of 2020. Although its design included plenty of systems to streamline plant operations, COVID-19-inspired lockdowns provided the impetus to further innovate in plant monitoring. What has been assembled is a fully integrated array of software and control solutions:

• Vital Technology Services (VTS) HardHAT system provides the plant’s digital twin, front-end of 3D modelling, inventory and computerised maintenance monitoring systems (CMMS).
• MapEx Software provides first-principle physics-based modelling and heat balance that feeds into advanced pattern recognition (APR) software and machine learning-based analytics.
• SureSense APR (advanced pattern recognition) software by Expert Microsystems.
• Solar turbine’s Turbotronic control system for sequencing, control, and protection of the gas turbine package, and monitoring of associated auxiliary systems.
• A Rockwell Automation historian and Allen Bradley PlantPAx distributed control system (DCS) to control the entire CEP.

“Around 12,000 data points are gathered up in one place from the various control and software systems and all of it goes into the historian,” said Siess. “That data is all available in VTS.

We get trip alerts automatically on high-value critical equipment such as the gas turbines, heat recovery steam generators (HRSGs) and feedwater pumps.”

A lightweight 3D model is viewable by plant personnel on remote devices during maintenance rounds. Smart tags on components and equipment show up in the 3D model to provide abundant digital data. The system offers a single source of truth for document control, DCS, historian, CMMS, plant instrumentation (PI) system, inventory software, and more. In addition, drones are used to supplement maintenance checks. They incorporate image recognition technology that can detect hot spots and puddles as well as methane, steam or other leaks.

“Drones are a lot more efficient than putting hardwired AI/IOT sensors everywhere,” said Siess. Mathematical algorithms identify patterns in historical data. These patterns are trained into the system to detect changes in ongoing plant operating data that arise from a developing problem.

Turbine monitoring

The combined cycle facility includes two 14.5 MW Solar Titan 130 gas turbines and a 5 MW condensing steam turbine from Siemens Energy. As Ford does all its engine testing at a nearby dynamometer lab, there is almost no tolerance for electricity interruption.

Siess gave an example of how the CHP monitoring systems help prevent unscheduled outages. After a recent scheduled outage, SureSense generated an alert about a slight increase in oil temperature exiting shaft bearings. The seal had registered a temperature of 219°F since plant opening. Soon after the outage, it rose by 10°F. While still 40°F below the alarm level, the software flagged the condition as abnormal. The operator alerted Solar Turbines, which is monitoring the seal and plan to replace it during the next scheduled outage unless the problem worsens.

“A sudden shift in oil temperature can lead to more varnish potential and make the unit and ancillary cooling equipment work harder,” said Siess. “It is vital that we catch issues at an early stage to prevent a major failure.”

Another example concerned a problematic gas compressor. Drilling into data within the HardHat system, the operators discovered a slide gate out of calibration that caused unnecessary recirculation of gas. This increased parasitic load and system wear. It was repaired before serious problems arose.

Similarly, APR detected a thermocouple deviation in the gas turbine exhaust that hadn’t yet shown up in the turbine control system. A shutdown was ordered to rapidly clear the fuel injectors. As a result, a GT trip or outage was avoided.

Preventive maintenance (PM) is preferred to calendar-based maintenance schedules that can result in over-greasing of parts or unnecessary replacement of components.

The CMMS know the number of hours equipment, components and systems have run and sends alerts when it is time for inspection. All rotating equipment oils are sampled and analysed quarterly to make sure they are free of impurities.

HRSG operation and maintenance

The HardHat system aids operators in monitoring all aspects of running and maintaining two HRSGs from Rentech Boiler Systems. It keeps track of a great many parameters to ensure everything is running smoothly. For example, the high-fired
waterwall, O-type HRSGs should provide up to 225 kilo-pounds per hour (KPPH) of 200 PSIG saturated steam, which is vital to Ford operations. In addition, another up to 90 KPPH can be consumed in the steam turbine as part of combined cycle power generation.

“Advanced pattern management and 3D modelling enable operators to keep a close eye on the maintenance of HRSG steam production as well as hot water and high-pressure steam metrics,” said Siess.

Operators can view each HRSG in the 3D model and drill down into systems and components as needed. The CMMS push out maintenance actions coming due. Parts are flagged that need to be maintained or replaced, based on usage.

Take the case of a temperature transmitter in the HRSG’s feedwater header. The operator can click on the part to review documentation, part numbers, past maintenance records, examine any required safety checks, view instrument and sensor readouts and review work orders (a flashing feed control valve on the screen would indicate an active work order). At the end of a shift, the new operator can open the system to see any work orders opened and resolved that day, which reduces the need for a lengthy turnover of duties.

A recent incident involved power loss to the HRSG. The system automatically generated alerts. The investigation detected a power supply drop-off to the PLC, which then tripped the HRSG.

“We picked up this problem in the HRSG and resolved it within 90 minutes,” said Siess. “As the asset database in HardHat has information on all part numbers, vendors and specs, it saves us a lot of time in routine maintenance.”

The Rentech HRSGs include supplemental firing. By raising the gas turbine exhaust temperature via supplemental firing, steam production can be increased by approximately 300%. Operators control supplemental firing from the booth and can keep a close eye on temperature, pressure and steam output numbers to ensure everything is operating as intended.

“The key is to not to waste time and resources in looking for information or engaging in unnecessary activities – everything is prioritised and at the operator’s fingertips,” said Siess.

“This kind of automation is increasingly needed as the power generation labour pool is rapidly shrinking.”

Building confidence in automation

A system like this isn’t going to go in one day and hey presto, perfect operation from there on out. Siess laid out the trajectory of steady improvement the facility has undergone: nine unit trips in 2020; five in 2021; and two in 2022. Hours of unplanned downtime fell from 50 hours in 2020 to only four in 2022.

The facility schedules a spring and autumn outage to take care of major maintenance actions and inspections. During those windows, Solar Turbines comes on site as part of a long-term service agreement.

Each gas turbine and HRSG is taken down for two to three days. While one unit is being serviced, the other continues to operate to ensure the flow of steam to Ford is never interrupted. Features built into the Rentech HRSG provide further assurance of steam flow. A fresh- air-firing capability utilises a forced draft fan so the HRSG can be operated when the gas turbine is offline. The fan draws in ambient air and the duct burner provides heat to generate 80 KPPH of steam. A louvre-type diverter valve installed between the HRSG and the turbine facilitates steam/electricity switching. If there is no current steam demand, flue gas from the turbine can be diverted up a bypass stack and not through the HRSG to generate only electricity and not steam.

Siess added that automation enables DTE to untether the operator from the chair to go on maintenance rounds for 45 minutes or more without anyone in the control room. Data on plant operation is available via mobile device, which brings the control room into the field. Alerts are issued if anything needs attention.

“The right technology gives people enough confidence in automation so they can walk away,” said Siess. “Our operations staff are now comfortably performing 80% of all maintenance activities.”

This article first appeared in Modern Power Systems magazine.

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The agreement aims to enhance value creation and promote more efficient resource management in the companies’ operations on the Haltenbanken.

For Equinor, the move will see the firm increasing its stakes in the Heidrun field and Noatun discovery while reducing its ownership in the Tyrihans field, the Castberg field, and the Carmen and Beta discoveries.

The companies believe that the agreement will facilitate enhanced value creation for the Heidrun and Kristin/Tyrihans areas.

Currently, Equinor holds a 13% equity interest in Heidrun, with Petoro having a stake of 57.8%. Petoro will swap out ownership interests of 21.4% in Heidrun and 7.5% in Noatun.

In return, Petoro will receive ownership interests of 22.5% in Tyrihans, 3.7% in Johan Castberg, 9.3% in the Carmen discovery, and 10% in the Beta discovery. For Tyrihans, Equinor’s ownership stands at 58.8%, while Petoro does not hold any stake.

Petoro CEO Kristin Kragseth said: “Our good dialogue with Equinor has allowed us to reach an agreement that will lead to greater harmonisation and equalisation of important ownership interests.

“We are very confident that this will contribute to a more comprehensive and value-driven development of these fields, in the best interests of all involved parties.”

The Heidrun and Tyrihans fields are among the largest producers in the Halten area. According to Equinor, Heidrun is recognised for its long remaining life on the Norwegian continental shelf.

Upon completion of the transaction, Equinor’s stake in Heidrun will rise to 34.4%, while Petoro’s interest will adjust to 36.4%.

For Tyrihans, Equinor’s ownership will be reduced to 36.3%, and Petoro will gain a 22.5% share. Additionally, Equinor’s ownership in the Johan Castberg field will be 46.3%.

Equinor exploration and production Norway executive vice president Kjetil Hove said: “We have a strategy to continue the development and the value creation on the Norwegian continental shelf and expect to maintain a high production with lower emissions towards 2035.

“Alignment of ownership around the larger production hubs are important enablers for long-term value creation.”

The asset swap agreement is contingent upon various regulatory approvals, including the Norwegian Parliament’s consent. The effective date of the agreement is set for 1 January 2025.

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The accreditation encompasses the construction of Class 1, 2, 3, and metal containment pressure vessels and piping systems (N), as well as the construction of Class 1, 2, 3, and metal containment appurtenances with furnishing material (NPT), supports (NS), and shop assembly (NA). ASME’s certification follows a rigorous evaluation process, affirming TEi’s establishment of a Quality Assurance Program compliant with ASME Section III Code requirements.

As a subsidiary of Babcock Power Inc., TEi stands as the premier domestic supplier of Turbine Island heat exchangers to nuclear power stations, encompassing Moisture Separator Reheaters, Feedwater Heaters, and Steam Surface Condensers. TEi’s Joplin, Missouri facility has held ASME certifications for Section VIII Division 1 (U) pressure vessels, S stamp for boiler pressure parts, and R stamp for pressure part repairs and alterations since 1979. In 2016, TEi expanded its certifications to include Section VIII Division 2 (U2), further enhancing its capabilities to design and supply safety-related heat exchanger components and services for both existing and new-build nuclear stations, including traditional large-scale and modern small modular varieties.

Joseph Green, Chief Nuclear Officer at TEi, expressed excitement about supplying ASME Section III heat exchangers for customers, highlighting nuclear power’s ability to deliver high-capacity baseload power while minimizing greenhouse gas emissions. “We are committed to the highest levels of quality and performance in our products,” he added.

Ken Murakoshi, President and CEO of Thermal Engineering International (USA) Inc., emphasized the significance of the Section III N certifications in bolstering TEi’s support for the Nuclear Industry’s efforts towards global net-zero and energy security objectives.

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Nuclear energy is not weather-dependent and requires relatively little fuel to generate a significant amount of power. Meanwhile, stockpiling of uranium for nuclear power is a viable solution in enhancing Singapore’s long-term energy security. The Energy 2050 Committee has therefore identified Small Modular Reactors (SMRs) as a viable option to decarbonise the power sector and increase energy security.

Despite the potential benefits of nuclear energy for Singapore, establishing a nuclear plant in such a densely populated country poses a certain set of challenges and risks. The risks associated with nuclear energy are not solely technological but also sociological and environmental. Many conservationists remain opposed to its use due to concerns about the high risks it potentially poses to the population, the environment, and neighbouring countries. Risks include casualties and health risks due to radioactive exposure, security threats such as terrorist attacks, and environmental contamination. A comprehensive risk analysis provides insights into the risks and benefits of nuclear energy in a densely populated country, which can be used to make informed decisions about its use. It is crucial to thoroughly consider, assess, and evaluate all potential hazards before embarking on nuclear projects. This should be carried out by forming a team of trained experts, including scientists, engineers, and specialists from various fields to provide insights into nuclear energy technology, procedures, programmes, control measures, and risks, and act as advisors to the government on nuclear safety matters.

Key factors for ensuring safe nuclear energy operation are strict governance, robust safety procedures, and effective measures. By combining these elements with the latest advancements in nuclear technology and plant design, the probability of nuclear accidents can be significantly reduced.

Bowtie analysis of operating SMRs

The operation of a nuclear power plant is associated with several hazards that can have serious consequences for public health and the environment. Natural hazards, such as earthquakes, severe weather, wildfires, and flooding, are well documented. Human errors in nuclear plant design, maintenance, and operation are also reported that can cause the failure of critical equipment. In addition, nuclear power plants are also vulnerable to intentional harm caused by sabotage, terrorism, and cyberattacks.

The economic impact of a nuclear disaster can extend beyond the immediate area, causing damage to property, businesses, and investments and can have an impact on the health and well-being of neighbouring communities. This is particularly relevant for neighbouring countries such as Malaysia and Indonesia. Given the consequences, fear of a nuclear disaster can if not managed properly, lead to widespread scepticism of nuclear energy, which can have further societal and psychological effects.

Based on the identified hazards and potential consequences, a qualitative bowtie diagram, Figure 1, provides a visual representation of the potential treats to a nuclear power plant, the potential consequences, and the suggested barriers to prevent or mitigate those consequences.

Comparative analysis on reactor types

To further enhance the broad-based control measures depicted in the bow-tie diagram, it is crucial to gather and thoroughly analyse data from past incidents. This process enables the identification of causes of such incidents, the detection of patterns and trends, and the development of effective solutions to mitigate the risks.

The study aimed to identify the types of reactors that have contributed the most to nuclear accidents, as well as the common causes of safety system failures. However, the committee noted that such incidents primarily involved large conventional reactors and may not accurately reflect the safety risks associated with the SMRs that Singapore is considering. SMRs are gaining traction as a preferred option in the energy market due to their potential to provide flexible, affordable, and low-carbon energy. However, given their relatively recent emergence and unique design, there is currently limited data available on SMR nuclear accidents. To address this gap, this study relied on a database of nuclear events to expand the available information and develop sound recommendations for the Singapore government.

According to the analysis, Pressurized Water Reactors (PWRs) were found to be the most common type of reactor involved in nuclear events, accounting for 784 (62%) out of 1,256 incidents, followed by Boiling Water Reactors (BWRs) with 382 (30%) events. Further analysis revealed that the causes of nuclear events varied between them.

According to this data, design residuals are the leading cause of nuclear events for both PWRs and BWRs. Therefore, it is important to consider inherently safer designs when setting up SMRs in Singapore, and foreseeable operational risks must be addressed during the design stage. To prevent operator errors, design verification and testing can be conducted to ensure that operations are robust and that systems can safeguard operations from operator error.

While Singapore is unlikely to experience natural disasters such as earthquakes or tsunamis that could trigger a nuclear accident, tremors from earthquakes in neighbouring countries can occasionally be felt on the island. Thus, it is still recommended to design and build SMRs that can withstand tremors and other natural hazards to increase safety margins. This is also a requirement by the Nuclear Regulatory Commission for all nuclear plants in the United States, following lessons from the 2011 Fukushima Daiichi accident.

SMR retrofitting for Singapore

To ensure the continued safety and reliability of nuclear facilities, as well as to gain valuable experience and test new technologies, the implementation of a pilot project to retrofit SMRs prior to the construction of full-scale nuclear facilities is recommended. By retrofitting SMRs with advanced safety features and monitoring systems, we can evaluate their performance in a controlled environment and make any necessary improvements before scaling up to larger facilities.

SMRs require an Emergency Planning Zone (EPZ) with a radius of less than 0.3 km. The existing power stations in Singapore are located in industrial areas away from densely populated residential areas. The approximate distances between the power stations and the densely populated areas show that any of the three power stations can be retrofitted with SMRs while maintaining a safe distance from densely populated areas. Using Hierarchical Clustering analysis, the Senoko Power Station has been identified as the most suitable candidate for the initial conversion, with the potential to retrofit the other two stations in the future.

The selection of the Senoko Power Station as the primary candidate for SMR retrofitting is based on several factors, including its age of over 30 years and its reliance on oil that emits high levels of carbon dioxide. After a thorough evaluation of the power station’s various plants, the Hitachi 1983 Steam Thermal Plant, specifically either G7-243MW or G8-250MW, has been identified as the most suitable option for retrofitting with SMRs. To ensure the safe and efficient operation of the retrofitted plant, it is recommended to use an Integrated Pressurized Water Reactor (iPWR) for the project. This type of land-based, water-cooled SMR has a power range of 151 MWe to 250 MWe and can be matched with either the G7-243MW or G8-250MW oil-based plant for a one-to-one retrofitting capacity. Several models, including NUWARD, W-SMR, or mPower, are suitable for this project.

The retrofitting of SMRs may also present several construction and operational risks, which can be mitigated through the use of digital twin software and machine learning. The implementation of digital twin software and machine learning to simulate and evaluate the performance of SMRs will be an essential component of the SMR retrofitting process, allowing for thorough testing and optimisation of the technology prior to deployment. Digital twin models can help identify and prevent potential safety hazards, such as runaway reactions or loss of containment, by providing a virtual environment to test and optimize the technology. Machine learning techniques, such as supervised learning, can be utilised to ensure the safe operation of SMRs by detecting anomalies and predicting potential failures. Unsupervised learning, on the other hand, can optimise the maintenance and life cycle costing of all equipment by analysing patterns and identifying areas for improvement. Incorporating digital twin software and machine learning into the SMR retrofitting process can ensure the safe and efficient operation of these reactors. This approach will allow us to identify and resolve potential issues early on, minimising risk and ensuring the long-term sustainability of the facility.

Inherent safe design of SMRs

Based on comparative analysis, design errors have been identified as the leading cause of nuclear events. To mitigate this risk, it is imperative that the proposed Integrated Pressurized Water Reactor (iPWR) for Singapore is designed to be inherently safe, with a range of advanced features including:

• The ability to operate for more than three days without operator intervention for any design basis accidents and loss of electrical power supply under normal and emergency conditions.
• State-of-the-art fully digital Nuclear Instrumentation & Controls (I&C) powered by internal batteries for safe state monitoring without internal or external electrical power supply for up to three days.
• Process I&C that keeps the reactor in operation while maintenance I&C, which is independent from process I&C, remotely logs and implements predictive-based maintenance. The system data is under the control of a dedicated team in a remote-control room to protect the system from cyber-attacks.
• Active and passive safety management of core meltdown accidents with corium.

Another passive approach to nuclear safety is the use of in-vessel retention of the melted core, which can contain a core melt accident within the plant, thereby eliminating the need for evacuation measures for the surrounding area. This enables a smaller emergency planning zone to be established within the plant boundary. Additionally, the semi-buried (25m) underground nuclear configuration offers protection against potential acts of terrorism or malicious commercial plane crashes, as well as against the release of radioactive materials. This feature provides an added layer of protection against accidents and risks, ensuring the safety of the plant and the surrounding environment.

Emergency preparedness

Despite the safety measures put in place, accidents may still occur. Therefore, it is crucial to have a comprehensive on-site and off-site emergency response plan that can manage a credible nuclear plant emergency scenario in a highly populated country like Singapore. The plan must consider the challenges, limitations, and risks associated with the operation of a nuclear facility.

An off-site emergency response plan is a particularly critical component for ensuring the safety of the population and the environment in the event of a nuclear incident in Singapore. The plant operator and local government must work together to ensure that the necessary measures are taken to safeguard the population from potential threats and hazards related to the plant’s operations. To ensure the success of an off-site emergency response plan for a nuclear plant operating in Singapore, it is also crucial to engage with the local community and provide them with the necessary information about the plant’s operation, safety measures, and emergency response plans.

Managing a nuclear emergency in Singapore poses numerous challenges. Limited land space area makes it challenging to find a suitable evacuation site, while the high population density makes it difficult to safeguard the population. Limited resources and logistic issues, including a shortage of medical and emergency specialists and professionals, equipment, space, infrastructure, and supplies, further complicate responding to a nuclear emergency. Coordination and collaboration with local and neighbouring nations also present challenges, the different objectives and priorities of each party can lead to delays in establishing a unified approach, making the decision-making process difficult. Therefore, further research is necessary to address these challenges and develop effective strategies for managing a nuclear emergency in Singapore.

The Singapore government is recommended to establish legal requirements related to nuclear safety, operations, and emergencies, and drive international nuclear research collaborations to exchange knowledge and experience in the nuclear safety field and gain access to nuclear facilities. The government should also nurture a nuclear workforce to meet future demands of the sector through a competency progression model and engage the public on nuclear energy through awareness campaigns, seek their feedback for better collaborations, and understanding for future sustainability of energy management.

Next steps for nuclear Singapore

To prepare for a full-fledged nuclear facility by 2050, this study recommends a pilot project to retrofit an SMR into an existing power station. The implementation of inherently safe Integral Pressurized Water Reactor (iPWR) SMR is highly recommended due to its ability to contain emergencies within the site boundaries, putting large-scale emergency evacuation concerns to rest.

While the majority of past nuclear incidents may not be highly relevant in Singapore’s context, they do highlight the importance of establishing legal requirements related to nuclear safety, operations, and emergencies. This is necessary to ensure that Singapore is adequately prepared and equipped to respond to potential nuclear incidents. In addition, driving international nuclear research collaborations can facilitate the exchange of knowledge and experience in the nuclear safety field, further enhancing the country’s preparedness and response capabilities.

The Singapore government is also recommended to nurture a nuclear workforce to meet future demands of the sector through a competency progression model and engage the public on nuclear energy through awareness campaigns and feedback mechanisms for better collaboration and understanding towards the sustainable management of energy. A nuclear task force may work with the government to establish legal requirements, drive nuclear research collaborations, educate the public, and nurture a nuclear workforce.

By implementing these recommendations, Singapore can move towards a more sustainable energy future with a safe and reliable nuclear power source.

Authors: Eio Wee Kwang, Kerk Boon Hock, Muhammad Sarhan Samad, Ng Swee Wah, Ho Li Min Sarah, and Loh Tzu Yang, Department of Chemical and Biomolecular Engineering, College of Design and Engineering, National University of Singapore

This article first appeared in Nuclear Engineering International magazine.

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According to ADNOC Drilling, UAE’s capital Abu Dhabi currently has an estimated 220 billion barrels of unconventional oil alongside 460 trillion cubic feet (TCF) of unconventional gas.

To fulfil the contract and explore future opportunities in unconventional resources, ADNOC Drilling has established a new company, Turnwell Industries.

The new subsidiary of ADNOC Drilling will be responsible for delivering 144 unconventional oil and gas wells. Turnwell Industries will mainly focus on unconventional drilling operations.

ADNOC Drilling has also signed a term sheet to form a partnership with Schlumberger Middle East, a subsidiary of SLB, and Patterson-UTI International. This partnership is contingent upon the signing of definitive agreements and obtaining necessary regulatory approvals.

Both Schlumberger Middle East and Patterson-UTI are expected to hold minority equity interests in Turnwell Industries.

In exchange for their equity interest, Patterson-UTI plans to provide drilling, completion, and other oilfield service expertise to Turnwell Industries, along with a limited cash contribution for working capital.

ADNOC Drilling CEO Abdulrahman Abdulla Al Seiari said: “Abu Dhabi’s unconventional energy resources are among the world’s largest. This award, for 144 wells is just the beginning.

“It represents a transformational opportunity for ADNOC Drilling as the UAE’s world class unconventional energy resources will require many thousands more wells and we are in a prime position to deliver them.”

The initial phase of unconventional resource development is expected to utilise up to nine land rigs, five of which are already part of ADNOC Drilling’s fleet as of 31 December 2023.

The contract is anticipated to begin contributing to ADNOC Drilling’s revenue in the second half of this year.

ADNOC Drilling will utilise innovations in artificial intelligence (AI) powered smart drilling design, completions engineering, and production solutions. This initiative is supported by Enersol, its recent joint venture with Alpha Dhabi.

Enersol will enhance its scalable technology ecosystem through investments in and acquisitions of AI-enabled solutions and innovative technologies.

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Although the exact financial terms of the contract were not disclosed, Subsea7 indicated it to be in the range of $300m and $500m.

The contract, which is an expansion of an existing one with the Subsea Integration Alliance, will include the installation of Türkiye’s first floating production unit (FPU) as part of the second development phase.

Previously, in May 2023, a consortium comprising SLB, Subsea Integration Alliance, and Saipem was awarded the contract for engineering, procurement, construction, and installation (EPCI) for the second phase. The Subsea Integration Alliance represents a global partnership between OneSubsea and Subsea7.

The latest contract enhancement will see Subsea7 handling the installation and integration of risers, umbilicals, hook-ups, and mooring systems with the FPU. Project management and engineering activities will be conducted from Subsea7’s office in Istanbul, Türkiye.

The contract will be recorded in Subsea7’s backlog during Q2 2024.

Subsea Integration Alliance CEO Olivier Blaringhem said: “We are proud to receive this contract award extension by TP-OTC to install the country’s first floating production unit.

“We look forward to our continued collaboration with TP-OTC and our consortium partners to unlock the full potential of the Sakarya gas field and advance Türkiye’s energy security goals.”

Considered as the first deepwater gas field discovery and the largest natural gas reserve in Turkish waters, the Sakarya gas field development project was brought on stream by Türkiye Petrolleri Anonim Ortaklığı (TPAO) in April 2023.

The gas field is located within Block C26 in the western Black Sea, 165km off the Filyos coast in Zonguldak province. It is located within the Turkey exclusive economic zone, and in a depth of around 2,200m.

The consortium of SLB and Subsea7 also played a role in the Phase 1 EPCI project as well by bringing 10 wells into production. Each of the wells contribute 10 million standard cubic meters per day (MSm3/d).

Phase 2 of the project involves the development of an additional 26 wells, aimed at increasing production capacity by an extra 30MSm3/d. Upon the completion of Phase 2, projected for 2028, it is anticipated that the Sakarya field will supply 30% of Turkey’s natural gas requirements.

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As per the terms of the deal, Kinetik will pay $315m in cash and issue around 3.8 million of its shares as consideration to Durango Midstream, the parent company of Durango Permian. This amounts to a total upfront consideration of $765m.

Durango Midstream is an affiliate of Morgan Stanley Energy Partners.

The deal also includes a contingent payment of up to $75m. This will be linked to the capital cost for the Kings Landing complex, a natural gas gathering facility in the Permian Basin of southeast New Mexico.

The 200 million cubic feet per day greenfield processing complex is currently under construction. Anticipated to be ready in April 2025, the Kings Landing facility will boost the processing capacity of Durango Permian to 420 million cubic feet per day.

Kinetik expects further net capital expenditures of $78m for completing the construction of the Kings Landing complex.

Additionally, Kinetik has forged a 15-year deal with one of its key clients, having a considerable footprint in Eddy County, New Mexico, to deliver low-pressure and high-pressure gas gathering and processing services.

Kinetik will undertake the construction of gathering infrastructure, amounting to an estimated $200m in capital expenditure by 2026. The contract is slated to begin towards the end of this year, initiating with gathering services and expanding to processing services from Q2 2025 onwards.

In a separate transaction, Kinetik has entered a binding agreement to sell its 16% equity stake in the 720km Gulf Coast Express pipeline (GCX) in the Permian Basin to an ArcLight Capital Partners affiliate.

The anticipated total sale proceeds amount to $540m in cash, which includes $30m in deferred cash payment. The deferred amount is contingent upon a final investment decision regarding a capacity expansion project.

Kinetik president and CEO Jamie Welch said: “Following the Durango Acquisition and the expected completion of Kings Landing, Kinetik will own and operate over 2.4 billion cubic feet per day of processing capacity, entirely in the Delaware Basin, and approximately 4,600 miles of pipelines across eight counties.

“Proceeds from the GCX Sale and the aggregate issuance of $450 million of Kinetik Class C shares, in two installments, will be reinvested into projects at a mid-single digit EBITDA multiple.”

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