BALTIMORE — Offshore wind turbines can — and in the coming years, will — produce thousands of megawatts of electric power, which is way more than the onshore transmission system is currently able to absorb, according to Bill Magness, senior principal consultant at DNV.

States and offshore developers “want to see the most bang for the buck. … [They] want to see the maximum transfer into the system of those offshore resources,” Magness, the former CEO of ERCOT, said during a panel at the Business Network for Offshore Wind’s recent International Partnering Forum (IPF). “Moving into the onshore grid is where the rubber really hits the road, or the water, or whatever it’s hitting.

“The onshore grid is where the load is … where the ratepayers are, and the onshore grid is where an extremely sophisticated, complex, several-decades-old, AC-based system lives … [with] limits on reliability and limits on interconnections that have to be honored,” he said.

The most severe single contingency (MSSC) is one of those limits, setting a maximum amount of reserve power a balancing authority is responsible for in the case of a sudden, large outage. For ISO-NE, the limit is 1,200 MW; in NYISO, it’s about 1,310 MW; and for PJM, it’s 1,500 MW — all of which “are suboptimal from the perspective of the technology that you want to bring onshore,” Magness said.

Reflecting the integral role it will play in offshore development, transmission was a major theme at IPF, with its own track of focused panels looking at the solutions that will be needed to efficiently and cost-effectively bring offshore power on shore. Meshed HVDC networks, as opposed to individual radial lines, have been identified as the most optimal way of connecting offshore turbines to onshore substations. (See OSW Developers Look to Europe on Meshed HVDC Tx.)

But the MSSC issue “is one that highlights a number of other issues that we’re going to be facing,” Magness said. To begin with, reliability standards based on the MSSC “were not written with HVDC in mind. … People are finding that, well, maybe the single contingency breach for HVDC is different than we thought.”

The MSSC is not itself a limit, he said, but NERC uses it to set the reserves a BA is required to have, purchased and ready to go in such contingencies.

“If you lose certain generation, you will have to make that up within 15 minutes; that’s the standard requirement,” said Gaurav Karandikar, senior manager for reliability analysis and technical services for SERC Reliability. “The balancing authority can actually study their system and determine that value … and that drives how much reserve you are going to carry.

“The other aspect is that there is a 90-minute limit, where after that first contingency [where you] have used your contingency reserve,” Karandikar said. “You have to re-establish that contingency reserve within the next 90 minutes, so you’re ready for the next contingency.”

Factoring onshore wind into those equations may mean looking at the issue “in a more flexible way, in a more targeted way that can manage … the larger-end feeds that are coming onshore,” he said.

Echoing Magness, Shahil Shah, a senior engineer at the National Renewable Energy Laboratory (NREL), said the MSSC issue is complex; it’s part of the problem but also a potential solution. The current MSSC limits don’t “allow us to go for big cables that are currently available,” he said.

“We see many projects where cables are coming from the same lease areas going to the same substations, but there are multiple of them,” Shah said. The way forward will involve designing HVDC transmission that can quickly isolate and recover from outages or other contingencies, he said.

Super-fast, super-reliable DC circuit breakers and multivendor interoperability will be needed, as well as revised, more sophisticated MSSC limits, he said.

“We need to coordinate the reliability standards and the resource standards together,” which will also require coordination between regulators, Shah said.

Coming in with a developer’s perspective, Peter Shattuck, president of Anbaric Development Partners’ New England projects, called for an incremental approach to the tangled issues involved in MSSC limits.

“It’s really hard to navigate the challenge of finding the most cost-effective solution that’s responsive to signals we’re getting from procuring entities during a period where these myriad questions and challenges that have been laid out are not resolved,” Shattuck said.

Magness agreed that with new procurements coming, “it is really essential that we start to inventory what these [transmission] issues are, identify them and pick the ones that are most important and try to start solving them.”

A 2-GW Standard

The meshed, HVDC model is well established in Europe, where most recently TenneT, the transmission system operator in the Netherlands and parts of Germany, announced its plans for a standardized offshore transmission platform with 2-GW certified cable. The company intends to deploy this new system on at least 10 projects, a scale that could have significant impacts for offshore supply chains, Shattuck said.

“When there are tenders out there for 10-plus 2-GW systems, that’s where the supply chain is going to go,” he said. “So, if you want something else, if you want a customized solution or even kind of tweaking the 2-GW design to address some of these [MSSC] issues, that’s going to have implications for costs and the timelines for bringing [a] project online.”

At the same time, a standard 2-GW cable could provide considerable economies of scale, he said. While New England currently has about 6 GW of offshore wind in development, Shattuck cited an industry analysis that an additional 24 GW of projects or more will be needed to meet the region’s climate goals.

“If you’re doing that with 2-GW systems, then you’re going to need 12, and if you’re doing it with 1,200-MW systems, you need 20,” he said.

ISO-NE has taken the first steps toward resetting its MSSC from 1,200 MW to 2 GW, with a recent letter to its Joint Planning Committee with NYISO and PJM, asking for a feasibility study on the change.

“As the region moves forward with the interconnection of large-scale renewables, such as offshore wind resources, project developers may identify proposals larger than 1,200 MW,” Brent Oberlin, ISO-NE director of transmission planning, said in the March 27 letter. “The 1,200-MW limitation could constrain an otherwise optimal interconnection design. …

“Depending on system conditions in PJM and NYISO, this limit can be raised in real time to a maximum of 2,000 MW,” he said.

Magness also pointed to NYISO’s ongoing exploration of dynamic scheduling of reserves, which could allow New York to import more clean energy to meet its emission-reduction goals of 40% below 1990 levels by 2030 and no less than 85% by 2050. (See Study: NYISO Dynamic Reserves Could Lower Congestion, Costs.)

Panelists also said that, rather than trying to change any NERC standards — which would involve what Magness called a “baroque” process ― there are opportunities for regional changes that could address the MSSC limitations. Such solutions could “address reliability concerns and optimize the technology,” Magness said.

Low-hanging Fruit

NREL’s Shah argued that grid operators’ mandated levels of reserves are often higher than needed, “so we should be able to inject more power during those times. … That’s low-hanging fruit, just a slight modification in the standards.”

Multiterminal offshore grids might offer another option, assuming that not all terminals would be operating at full capacity, he said. “If the capacity factor is diversified, then also there is another way to make sure that we are within limits, but at the same time we are allowing points of high injections.”

Having 2-GW lines also could provide “head room” for capacity in the event of outages, Shattuck said. For example, with three 2-GW lines operating with a capacity of 1,500 MW each, if one line trips off, the other two lines can each pick up 500 MW of capacity, “so the system only loses 500 MW, well below the current contingency,” he said.

“The ability to pick up extra power just increases the more lines that are connected to shore and networked offshore,” Shattuck said. “So, in a way, the challenge is just getting over the near term … and getting these first projects built. In a way, the offshore grid becomes a solution to the constraints of the onshore side.”

Regional solutions can also be more finely tuned, Magness said.

“The regions that have seen more resources, wind and solar systems, some of what they have realized is … you’ve got to slice this thing a lot more finely than you used to,” he said. “You need to procure reserves during demonstrated hours and minutes when you need them, and you don’t need to procure reserves at the same levels when you don’t.

“You start to see what those patterns are, what seasons of the year in your particular region require [you] to have more reserves on hand, and you’re able to run the system more efficiently based on everything you’ve got on the system,” he said.

Such procurement strategies could also allow grid operators to take advantage of the “extremely fast response times” batteries can offer, he said.

Both Karandikar and Shah said that the foundation for such changes will be good research and good computer models, supported by industry.

“If you’re looking or asking people to come up with a realistic limit, we should be able to make sure that we are providing them with good information,” Karandikar said. It is incumbent upon industry to ensure “planners have enough tools,” he said.

“It will be possible that we can maintain reserves offshore, provided we are able to forecast accurately how much capacity is available,” Shah said, noting that NREL has run demonstrations of such forecasting. “It is possible if we have a coordinated design for the offshore wind generation.”

Magness sees a range of benefits for meshed HVDC offshore transmission and more flexible approaches to MSSC limits, including less curtailment and opportunities for redispatch, “being able to move the power around through software systems in much more effective ways,” he said.

The task ahead is to think “in terms of building out a network not only to optimize the amount of wind that comes into the system but provides the maximum controllability, flexibility benefits that we can get from HVDC technology,” he said.

“How do we imagine them in a world where we have a grid that serves load onshore but also a grid that doesn’t have load sitting next to it in the ocean?” he said.