Being developed at Haibin harbor in Lianyungang city, the pilot project entails an investment of CNY9.88bn ($1.38bn). It is said to become the largest offshore solar farm in China.

The solar farm will comprise an energy-storage facility with a capacity of 400MW. Its solar panels will cover an area of 18.8km^2.

The Chinese offshore solar project is being constructed in the warm seawater area designated for China National Nuclear Power’s nuclear power station in Tianwan.

An area of the water is used for the nuclear power plant’s warm water discharge, while the neighbouring space is designated for the offshore PV construction. The project is divided into two parts, namely offshore and onshore, reported Global Times.

The offshore section includes solar power generation, with the produced electricity sent to the onshore step-up substation through an overhead corridor bridge. It will then be integrated into the state grid following voltage adjustment.

According to the publication, the onshore energy storage project is in its last phase of construction and is likely to be completed and operational by the end of June 2024.

The offshore solar project will be linked to the state grid in September 2024 and its full capacity is slated to be connected next year.

The project is expected to produce 2.23 billion kilowatt-hours of power during its lifespan of 25 years. This clean energy produced will address the annual production and life requirements of 230,000 people.

Furthermore, the solar project is estimated to offset carbon dioxide emissions by 1.77 million tons per year as well as save approximately 680,000 tons of standard coal.

CNNP, has been quoted by South China Morning Post, as saying: “Upon completion, it will cross couple with the nuclear power station, forming a 10GW large-scale clean-energy production base.”

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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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Under the terms of the agreement, the Spanish electric utility will pay Avangrid’s shareholders $35.75 per share to buy out the remaining shares of Avangrid, which is a renewable energy developer based in Connecticut.

The consideration represents a premium of 11.4% over the closing price of Avangrid common stock on 6 March 2024 and a 15.2% premium over the volume-weighted average price of Avangrid common stock over the 30 trading days.

Currently, Iberdrola holds around 81.6% of Avangrid’s capital.

Through the acquisition, Iberdrola aims to expand its presence in the networks sector within the US. Iberdrola is prioritising growth in markets having robust credit ratings and in regulated sectors such as networks.

Upon the completion of the transaction, a formal request will be submitted to delist Avangrid shares from the New York Stock Exchange (NYSE).

Presently, Avangrid has $44bn in assets and operates in 24 US states. The company focuses on two primary business areas, which are networks and renewables.

In the networks sector, Avangrid supervises eight electric and natural gas companies, serving more than 3.3 million customers in New York and New England.

Simultaneously, in the renewables sector, the company oversees a diverse portfolio of renewable energy generation facilities across the US.

Avangrid CEO and president Pedro Azagra said: “We are excited about Iberdrola’s continued investment in Avangrid and commitment to the United States.

“As a wholly-owned member of the Iberdrola Group, we will continue to serve our customers and build our renewable energy assets work to achieve our vision to lead the clean energy transition with a strong commitment to sustainability, community, governance, and our employees.”

Subject to customary conditions, including shareholders and the Federal Energy Regulatory Commission (FERC), the Maine Public Utilities Commission and the New York Public Service Commission approvals, the deal is expected to be complete in Q4 2024.

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The 347MW wind farm representing an investment of approximately A$569m ($370.3m) is owned by Ark Energy, an Australian subsidiary of Korea Zinc.

The State Significant Development (SSD-10315) application was lodged in 2021.

The number of wind turbines was reduced to 56 from 60 in response to community concerns.

The construction timeframe for the Bowmans Creek Wind Farm is approximately 18 months and the life of the project is 25 years.

Bowmans Creek wind farm is estimated to generate enough electricity to power over 172,600 homes and save over 957,800 tonnes of greenhouse gas emissions per year.

Location Details

Bowmans Creek Wind Farm is located approximately 185km north of Sydney, near the sparsely populated rural localities of Bowmans Creek, Davis Creek, Goorangoola, Greenlands, Hebden, McCullys Gap, Muscle Creek and Rouchel Brook.

The onshore wind farm’s total development footprint, including road upgrades, is approximately 411 hectares (ha), out of which 280ha is native vegetation.

Bowmans Creek Wind Farm Background Details

In October 2017, Epuron commenced wind monitoring onsite using a portable SoDAR (sonic detection and ranging) device and has deployed additional SoDAR devices including two wind monitoring masts.

The Application for State Significant Development Consent and the project’s Scoping Report was submitted to the New South Wales (NSW) Government in May 2019.

In May 2022, Ark Energy Corporation completed the acquisition of Epuron Holdings (original proponent), after the sale agreement received regulatory approvals.

NSW Department of Planning and Environment (DPE) completed its whole-of-government assessment of the project and referred it to the NSW Independent Planning Commission (IPC) for determination in November 2023.

The NSW IPC approved the Bowmans Creek Wind Farm in February 2024.

The project involves a Community Enhancement Fund of A$3,842 ($2501) per wind turbine per year, from the start of generation to the end of life of the wind farm, indexed to CPI. Based on the proposed layout of 56 wind turbines and an estimated operational life of 25 years, the Community Enhancement Fund amounts to A$215,000 ($139965) per year to support local initiatives and projects.

Bowmans Creek Wind Farm Project Details

The project development plan includes 56 turbines with a generating capacity ranging between 5 to 7 MW and associated ancillary infrastructure, including two onsite substations and a new 330-kilovolt (kV) transmission line to connect to the Liddell substation.

The maximum height of the wind turbine generators (WTG) is 220m from ground level to the blade tip.

Each WTG) will be mounted on a reinforced concrete footing accompanied by a transformer and will be controlled remotely from the Operation and Maintenance (O&M) facility. The 45m tall towers will be spaced at intervals of 200 – 300m depending on topography.

The WTGs produce electricity at 690 voltage, which will be stepped up to 33 kV by the transformer within the WTG for more efficient reticulation within the site.

Power generated from the WTGs is sent to the substations via the reticulation cables and powerlines. Underground cables of approximately 40km will be installed in trenches approximately 2m wide and 1m deep. The approximately 17km overhead transmission line will be supported by single-pole steel or concrete structures.

The transformer in the substations will step up the reticulation voltage (33 kV) to (up to 330kV).

The generated green electricity will be exported to the existing TransGrid network via the Liddell substation through a new single or double-circuit 330 kV transmission line.

Contractors Involved

Green Bean Design (GBD) was engaged to undertake a Preliminary Landscape and Visual Impact Assessment (PLVIA) for the project.

Sonus, an Australia-based acoustic services provider was contracted to undertake the Noise and Vibration Impact Assessment for the Bowmans Creek wind farm.

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Located nearly 85km northwest of Borkum and approximately 110km west of Helgoland, the offshore wind project represents an investment of close to €2.4bn.

Once operational, the He Dreiht project will generate sufficient clean energy to deliver electricity to 1.1 million households. The annual yield of the offshore wind farm, which will feature 64 Vestas V236-15 wind turbines, is expected to be 3.6 billion kWh.

The German offshore wind farm is owned 50.1% by EnBW, while a partner consortium consisting of Allianz Capital Partners, AIP and Norges Bank Investment Management holds the remaining 49.9%.

EnBW secured the contract for the He Dreiht offshore wind project back in 2017 during the first offshore auction held in Germany.

The company plans to install the first foundations in the seabed in the coming few days by utilising the Thialf floating crane.

Besides, the foundation installation works will continue into the summer. The wind turbines and cables are being manufactured simultaneously and are scheduled to be installed and laid in early 2025.

The He Dreiht offshore wind farm is slated to achieve full operations at the end of 2025. Dutch-German grid operator TenneT is anticipated to link the wind farm to the grid by leveraging an offshore converter station and two high-voltage DC export cables.

EnBW CEO Georg Stamatelopoulos said: “EnBW will play its part in further accelerating the energy transition in Germany, which is why it wants to invest a total of 40 billion euros in the energy transition by 2030 – the lion’s share of it in Germany.

“We are investing around 13 billion euros alone in constructing wind farms and solar parks as well as flexibly controllable and hydrogen-ready gas power plants. Our aim is to be a climate-neutral company by 2035.”

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Built 13km to 24km off the northern coast of France, in the Normandy region, the French offshore wind project represents a total investment of approximately €2bn.

It features 71 offshore Siemens Gamesa turbines, each with a generation capacity of 7MW.

The Fécamp offshore wind farm is expected to generate clean energy enough to supply electricity to approximately 770,000 people. This is equal to 60% of the annual power consumption of the Seine-Maritime department.

Besides, the French offshore wind facility will contribute towards the country’s energy transition goals. France aims to attain a 33% share of renewable energy in its energy mix by the end of this decade.

EDF Group chairman and CEO Luc Rémont said: “This new low-carbon electricity production facility would not have been possible without close, ongoing dialogue with elected representatives and local authorities, environmental associations, fishermen, economic players and local residents.

“The development of the Saint-Nazaire and Fécamp offshore wind farms has led to the emergence of a new industrial sector in France, essential for the development of future wind farms, in particular our Calvados, Dunkirk and Manche Normandie projects.”

The Fécamp project has generated around 3,000 jobs in the Normandy region for its construction. It has also created 100 local jobs for its operations.

The first energy production from the French offshore wind farm was achieved in July 2023 and wind turbine installation was completed in March this year.

Enbridge power president and corporate strategy executive vice president Matthew Akman said: “The successful completion of the Fécamp Offshore Wind Farm marks a significant milestone for Enbridge and our project partners.

“Following the successful completion of Saint-Nazaire in 2022, Enbridge continues to advance the development and construction of several offshore wind projects in France, including the Provence Grand Large floating offshore wind project, and the Calvados, Dunkirk and Normandy offshore wind projects.”

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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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Shetland 2 is a 525kV High Voltage Direct Current (HVDC) subsea cable project, planned to connect ScotWind’s offshore wind farms with the main Great Britain (GB) transmission system.

The need for a second HVDC link from Shetland to the main GB transmission system has recently been confirmed by independent electricity system operator National Grid ESO, as part of its ‘Beyond 2030’ plan.

According to the plan, SSEN would invest £5bn in the north of Scotland by 2035 to strengthen the region’s energy infrastructure.

In addition to connecting three ScotWind offshore wind farm sites to Shetland, Shetland 2 will also support decarbonisation and energy security ambitions, said SSEN Transmission.

SSEN Transmission managing director Rob McDonald said: “Sumitomo’s investment in a new cable manufacturing facility in Nigg will help deliver a homegrown supply chain to help support our energy security and net zero infrastructure requirements.

“This is great news for the Highland economy and will support hundreds of skilled jobs in the region, helping unleash the economic potential the clean energy transition presents for the north of Scotland.”

In a separate development, Sumitomo Electric has started construction on a new, advanced subsea transmission cable factory at the Port of Nigg, Scotland.

The Japanese company plans to commission the new subsea cable factory in 2026.

The new facility, planned to be built with a £350m investment, will supply critical elements for the UK electricity grid and connect renewable energy production facilities to the grid.

It will create more than 150 highly skilled jobs in the Scottish Highlands and use the local supply chain for the production of cables and construction of transmission cable systems.

Furthermore, the new factory would provide critical electricity transmission infrastructure to connect and deliver renewable energy to the UK and help achieve the UK Net Zero Target.

Sumitomo Electric Group president Osamu Inoue said: “I am pleased to announce the commencement of this innovative High-voltage cable factory in Scotland.

“Transmission cables are key essential infrastructures to make the so-called Energy Transition to renewables into reality.

“I believe, this factory will make good contributions towards the establishment of local supply chains and to realise UK and Scottish Governments’ net zero initiatives.”

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