Technology and Design Considerations to Reduce Footprint in Energy Storage Systems

The Kincardine floating wind farm, located off the east coast of Scotland, was a landmark development: the first commercial-scale project of its kind in the UK sector. Therefore, it has been closely watched by the industry throughout its installation. With two of the turbines now having gone through heavy maintenance, it has also provided valuable lessons into the O&M processes of floating wind projects. 

In late May, the second floating wind turbine from the five-turbine development arrived in the port of Massvlakte, Rotterdam, for maintenance. An Anchor Handling Tug Supply (AHTS)

vessel was used to deliver the KIN-02 turbine two weeks after a Platform Supply Vessel (PSV) and AHTS had worked to disconnect the turbine from the wind farm site. The towing vessel became the third vessel used in the operation.

This is not the first turbine disconnected from the site and towed for maintenance. In the summer of 2022, KIN-03 became the world’s first-ever floating wind turbine that required heavy maintenance (i.e. being disconnected and towed for repair). It was also towed from Scotland to Massvlakte. 

Each of these operations has provided valuable lessons for the ever-watchful industry in how to navigate the complexities of heavy maintenance in floating wind as the market segment grows. 

The heavy maintenance process

When one of Kincardine’s five floating 9.5 MW turbines (KIN-03) suffered a technical failure in May 2022, a major technical component needed to be replaced. The heavy maintenance strategy selected by the developer and the offshore contractors consisted in disconnecting and towing the turbine and its floater to Rotterdam for maintenance, followed by a return tow and re-connection. All of the infrastructure, such as crane and tower access, remained at the quay following the construction phase. (Note, the following analysis only covers KIN-03, as details of the second turbine operation are not yet available). 

Comparing the net vessel days for both the maintenance and the installation campaigns at this project highlights how using a dedicated marine spread can positively impact operations. 

For this first-ever operation, a total of 17.2 net vessel days were required during turbine reconnection—only a slight increase on the 14.6 net vessel days that were required for the first hook-up operation performed during the initial installation in 2021. However, it exceeds the average of eight net vessel days during installation. The marine spread used in the heavy maintenance operation differed from that used during installation. Due to this, it did not benefit from the learning curve and experience gained throughout the initial installation, which ultimately led to the lower average vessel days.

The array cable re-connection operation encountered a similar effect. The process was performed by one AHTS that spent 10 net vessel days on the operation. This compares to the installation campaign, where the array cable second-end pull-in lasted a maximum of 23.7 hours using a cable layer.

Overall, the turbine shutdown duration can be broken up as 14 days at the quay for maintenance, 52 days from turbine disconnection to turbine reconnection, and 94 days from disconnection to the end of post-reconnection activities. 

What developers should keep in mind for heavy maintenance operations

This analysis has uncovered two main lessons developers should consider when planning a floating wind project: the need to identify an appropriate O&M port, and to guarantee that a secure fleet is available. ‍

• Identification of the O&M port

Floating wind O&M operations require a port with both sufficient room and a deep-water quay. The port must also be equipped with a heavy crane with sufficient tip height to accommodate large floaters and reach turbine elevation. Distance to the wind farm should also be taken into account, as shorter distances will reduce towing time and, therefore, minimize transit and non-productive turbine time. 

During the heavy maintenance period for KIN-03 and KIN-02, the selected quay (which had also been utilized in the initial installation phase of the wind farm project), was already busy as a marshalling area for other North Sea projects. This complicated the schedule significantly, as the availability of the quay and its facilities had to be navigated alongside these other projects. This highlights the importance of abundant quay availability both for installation (long-term planning) and maintenance that may be needed on short notice. ‍

• A secure fleet

At the time of the first turbine’s maintenance program (June 2022), the North Sea AHTS market was in an exceptional situation: the largest bollard pull AHTS units contracted at over $200,000 a day, the highest rate in over a decade. 

During this time, the spot market was close to selling out due to medium-term commitments, alongside the demand for high bollard pull vessels for the installation phase at a Norwegian floating wind farm project. The Norwegian project required the use of four AHTS above a 200t bollard pull. With spot rates ranging from $63,000 to $210,000 for the vessels contracted for Kincardine’s maintenance, the total cost of the marine spread used in the first repair campaign was more than $4 million.

Developers should therefore consider the need to structure maintenance contracts with AHTS companies, either through frame agreements or long-term charters, to decrease their exposure to spot market day rates as the market tightens in the future.

While these lessons are relevant for floating wind developers now, new players are looking towards alternative heavy O&M maintenance options for the future. Two crane concepts are especially relevant in this instance. The first method is for a crane to be included in the turbine nacelle to be able to directly lift the component which requires repair from the floater, as is currently seen on onshore turbines. This method is already employed in onshore turbines and could be applicable for offshore. The second method is self-elevating cranes with several such solutions already in development.

The heavy maintenance operations conducted on floating turbines at the Kincardine wind farm have provided invaluable insights for industry players, especially developers. The complex process of disconnecting and towing turbines for repairs highlights the need for meticulous planning and exploration of alternative maintenance strategies, some of which are already in the pipeline. As the industry evolves, careful consideration of ports, and securing fleet contracts, will be crucial in driving efficient and cost-effective O&M practices for the floating wind market. 

Sarah McLean is Market Research Analyst at Spinergie, a maritime technology company specializing in emission, vessel performance, and operation optimization.

Spinergie | www.spinergie.com

According to the Energy Information Administration (EIA), developers plan to add 54.5 gigawatts (GW) of new utility-scale electric generating capacity to the U.S. power grid in 2023. More than half of this capacity will be solar. Wind power and battery storage are expected to account for roughly 11 percent and 17 percent, respectively.

A large percentage of new installations are being developed in areas that are prone to extreme weather events and natural disasters (e.g., Texas and California), including high wind, tornadoes, hail, flooding, earthquakes, wildfires, etc. With the frequency and severity of many of these events increasing, project developers, asset owners, and tax equity partners are under growing pressure to better understand and mitigate risk.

Figure 1. The history of billion-dollar disasters in the United States each year from 1980 to 2022 (source: NOAA)

In terms of loss prevention, a Catastrophe (CAT) Modeling Study is the first step to understanding the exposure and potential financial loss from natural hazards or extreme weather events. CAT studies form the foundation for wider risk management strategies, and have significant implications for insurance costs and coverage. 

Despite their importance, developers often view these studies as little more than a formality required for project financing. As a result, they are often conducted late in the development cycle, typically after a site has been selected. However, a strong case can be made for engaging early with an independent third party to perform a more rigorous site-specific technical assessment. Doing so can provide several advantages over traditional assessments conducted by insurance brokerage affiliates, who may not possess the specialty expertise or technical understanding needed to properly apply models or interpret the results they generate. One notable advantage of early-stage catastrophe studies is to help ensure that the range of insurance costs, which can vary from year to year with market forces, are adequately incorporated into the project financial projections. 

The evolving threat of natural disasters

Over the past decade, the financial impact of natural hazard events globally has been almost three trillion dollars. In the U.S. alone, the 10-year average annual cost of natural disaster events exceeding $1 billion increased more than fourfold between the 1980s ($18.4 billion) and the 2010s ($84.5 billion).

Investors, insurers, and financiers of renewable projects have taken notice of this trend, and are subsequently adapting their behavior and standards accordingly. In the solar market, for example, insurance premiums increased roughly four-fold from 2019 to 2021. The impetus for this increase can largely be traced back to a severe storm in Texas in 2019, which resulted in an $80 million loss on 13,000 solar panels that were damaged by hail.  

The event awakened the industry to the hazards severe storms present, particularly when it comes to large-scale solar arrays. Since then, the impact of convective weather on existing and planned installations has been more thoroughly evaluated during the underwriting process. However, far less attention has been given to the potential for other natural disasters; events like floods and earthquakes have not yet resulted in large losses and/or claims on renewable projects (including wind farms). The extraordinary and widespread effect of the recent Canadian wildfires may alter this behavior moving forward.

A thorough assessment, starting with a CAT study, is key to quantifying the probability of their occurrence — and estimating potential losses — so that appropriate measures can be taken to mitigate risk. 

All models are not created equal

Industrywide, certain misconceptions persist around the use of CAT models to estimate losses from an extreme weather event or natural disaster. 

Often, the perception is that risk assessors only need a handful of model inputs to arrive at an accurate figure, with the geographic location being the most important variable. While it’s true that many practitioners running models will pre-specify certain project characteristics regardless of the asset’s design (for example, the use of steel moment frames without trackers for all solar arrays in a given region or state), failure to account for even minor details can lead to loss estimates that are off by multiple orders of magnitude. 

The evaluation process has recently become even more complex with the addition of battery energy storage. Relative to standalone solar and wind farms, very little real-world experience and data on the impact of extreme weather events has been accrued on these large-scale storage installations. Such projects require an even greater level of granularity to help ensure that all risks are identified and addressed. 

Even when the most advanced modeling software tools are used (which allow for thousands of lines of inputs), there is still a great deal that is subject to interpretation. If the practitioner does not possess the expertise or technical ability needed to understand the model, the margin for error can increase substantially. Ultimately, this can lead to overpaying for insurance. Worse, you may end up with a policy with insufficient coverage. In both cases, the profitability of the asset is impacted. 

Supplementing CAT studies

In certain instances, it may be necessary to supplement CAT models with an even more detailed analysis of the individual property, equipment, policies, and procedures. In this way, an unbundled risk assessment can be developed that is tailored to the project. Supplemental information (site-specific wind speed studies and hydrological studies, structural assessment, flood maps, etc.) can be considered to adjust vulnerability models.

This provides an added layer of assurance that goes beyond the pre-defined asset descriptions in the software used by traditional studies or assessments. By leveraging expert elicitations, onsite investigations, and rigorous engineering-based methods, it is possible to discretely evaluate asset-specific components as part of the typical financial loss estimate study: this includes Normal Expected Loss (NEL), also known as Scenario Expected Loss (SEL); Probable Maximum Loss (PML), also known as Scenario Upper Loss (SUL); and Probabilistic Loss (PL). 

Understanding the specific vulnerabilities and consequences can afford project stakeholders unique insights into quantifying and prioritizing risks, as well as identifying proper mitigation recommendations. 

Every project is unique

The increasing frequency and severity of natural disasters and extreme weather events globally is placing an added burden on the renewable industry, especially when it comes to project risk assessment and mitigation. Insurers have signaled that insurance may no longer be the main basis for transferring risk; traditional risk management, as well as site and technology selection, must be considered by developers, purchasers, and financiers. 

As one of the first steps in understanding exposure and the potential capital loss from a given event, CAT studies are becoming an increasingly important piece of the risk management puzzle. Developers should treat them as such by engaging early in the project lifecycle with an independent third-party practitioner with the specialty knowledge, tools, and expertise to properly interpret models and quantify risk. 

Hazards and potential losses can vary significantly depending on the project design and the specific location. Every asset should be evaluated rigorously and thoroughly to minimize the margin for error, and maximize profitability over its life.

Chris LeBoeuf is Global Head of the Extreme Loads and Structural Risk division of ABS Group, based in San Antonio, Texas. He leads a team of more than 60 engineers and scientists in the US, UK, and Singapore, specializing in management of risks to structures and equipment related to extreme loading events, including wind, flood, seismic and blast. Chris has more than 20 years of professional experience as an engineering consultant, and is a recognized expert in the study of blast effects and blast analysis, as well as design of buildings. He holds a Bachelor of Science in Civil Engineering from The University of Texas at San Antonio, and is a registered Professional Engineer in 12 states.

ABS Group | www.abs-group.com

Grid modernization is having a profound impact on the nature and regulation of North American utilities. It represents a significant change to the way energy is managed, distributed, and used—today and in the future. As Environmental, Social, and Governance (ESG) targets become increasingly important to energy investors and regulators, how can organizations transform their Asset Investment Planning (AIP) processes to overcome challenges and take advantage of emerging opportunities?

Grid modernization

The energy transition refers to the global energy sector’s shift from fossil-based systems of energy production and consumption to renewable energy sources like wind and solar, as well as long-term energy storage such as batteries. The increasing penetration of renewable energy into the energy supply mix and the onset of electrification and improvements in energy storage are key drivers of the energy transition.

Grid modernization is a subset of the energy transition, and refers to changes needed in the electric transmission and distribution (T&D) systems to accommodate these rapid and innovative technological changes. Grid modernization often necessitates the increased application of sensors, computers, and communications to increase the intelligence of the grid and its ability to respond swiftly to external factors. The main goals of the grid are to provide the capacity, reliability, and flexibility needed to adapt to a whole range of new technologies (in the drive to net zero), while maintaining a comparable level of service and cost to the end customer.

Grid modernization projects are driven by both climate resilience through hardening of assets and changes to the T&D network to accommodate climate mitigation strategies. There are 3 broad categories for these types of projects:

1. Climate Resilience and Infrastructure Hardening
   • These investments cover physical improvements to T&D assets to reduce outages or damage, and enhanced system capabilities in the areas of flood resistance, storm hardening, wildfire risk mitigation, and cyber security.
      
2. Smart Grid and Distribution System Modernization
   • Projects in this area cover advanced grid technologies that enable two‐way communication, self‐healing, and autonomous restoration (using digital sensors and switches with advanced control and communication technologies). Advanced metering and communication infrastructure are also included in this category.
      
3. Distributed Energy Resource (DER) Optimization
   • These projects cover grid modifications required to support the integration of resources such as microgrids, distributed solar, wind, and storage (hydrogen, battery), as well as the inclusion of electric vehicle (EV) charging infrastructure.

Grid modernization is accelerating due to multiple factors, such as decarbonization, electrification, extreme weather, and security threats.

Valuing innovative projects

The changing demands dictated by grid modernization will require organizations to strike the right balance between cost-effectively managing the current business, while investing appropriately to meet future demands. Organizations are already seeing an increase in both the volume and variety of grid modernization projects. This is leading to increased planning complexity, requiring utilities to demonstrate that they are spending their limited budgets and resources to maximize value and drive their ESG and performance targets.

A value-based approach to investment decision making is key to establishing a common basis to evaluate potential investment opportunities and meet the challenges of grid modernization. The key to achieving your organization’s grid modernization goals is building a multi-year plan that breaks the work into executable chunks. This ensures adequate funding and resources are available to carry out the plan in the short-term, resulting in incremental progress toward longer-term objectives. 

With a value-based decision-making approach, organizations can ensure they are making the right grid modernization investments—and justify their plans to internal and external stakeholders.

Align decisions with strategic objectives

 Business leaders must develop frameworks that quantify the financial and non-financial benefits of all proposed investments on a common scale and understand how projects will contribute to their short- and long-term grid modernization initiatives and broader energy transition goals. A value framework also creates a clear line of sight from planned investments to regulatory and corporate targets, allowing organizations to provide transparency into the decision-making methodology—and demonstrate the benefits of their plans to regulators, stakeholders, and customers: 

Russ is a Director of Product Management, Decision Analytics at Copperleaf. He is an innovative leader with over 20 years of comprehensive business and technical experience in high-tech product development organizations. Russ holds a B.A.Sc. in Mechanical Engineering from the University of British Columbia and a Management of Technology MBA from Simon Fraser University.

Copperleaf | www.copperleaf.com