12 Wartsila 50DF tri-fuel engines
Quisqueya I and II multi-fuel power plants in the Dominican Republic: Both plants have 12 Wartsila 50DF tri-fuel engines that can run on natural gas
Credit: Wartsila

Rapid response times mean gas engine technology is winning followers as the need for flexible power to balance renewables grows. With a high electrical efficiency and desirable operational characteristics, is a new economic model for gas engines about to emerge? David Appleyard reports.

New renewable capacity is the current watchword of the electricity generation sector and significantly more renewable generation has been installed than any other technology over recent years.

While this is desirable in many respects, increasing volumes of variable output from renewable capacity is presenting operational and market challenges.

A webinar hosted by gas engine specialist Wartsila highlighted these issues, with Pierpaolo Barbone, president of Services and executive vice-president, observing: “Nowadays, we have 21 times more wind and solar capacity installed in the power system than in 2000 and the current capacity will be tripled by 2020. Wind and solar is low cost and emission free generation.”

However he added: “The other side of the coin is increased unpredictability and variability. Power system operators, utilities and electricity market designers are already calling for flexibility from the generation side to address the intermittency challenge. For the thermal fleet, flexibility means frequent starts and stops, deep ramp rates and more pulse-type of despatch, in operation modes that the existing fleet was not designed for.”

Picking up on this theme, Matti Rautkivi, general manager at Wartsila Power Plants, presented two recent case studies, from California and the UK, two regions which both have very ambitious targets for renewables. For example, Californians will see 33 per cent of their energy coming from wind and solar by 2020, says Rautkivi, and will face new challenges due to this development.

Referring to a typical day with a morning ramp in power demand, stable demand during the day, and then a bigger peak at around 18:00 or 20:00, Rautkivi explained the major role of gas generation in providing balancing services.

However, introducing renewables and intermittent generation to the mix, sees, for example, solar generation starting to produce after sunrise, with peak output at around midday and towards the end of the day tailing off to zero.

In the UK, which will have around 30 GW of wind capacity by 2020 – by then, part of the country’s 30 per cent renewable sources – similar challenges are being faced in developing and maintaining an adequate reserve capacity margin.

While demand is relatively easy to forecast, adding large volumes of wind generation into the equation leaves operators with the issue of potentially delivering thousands of megawatts of capacity which may need to be available to balance the system at short notice.

The challenge is how to use gas generation. In the case of California, a morning ramp-up of gas is required as it was before renewables, but in the high renewable penetration scenario now they are shutdown again just a few hours later as renewable generation capacity picks up.

Then once again in the evening – when there is no generation from the solar resources and peak demand kicks in – large volumes of gas generation have to be ramped up extremely rapidly to maintain system stability.

However, gas turbine peaking plants are typically designed to ramp up in the morning, hold a steady output throughout the day and come off line overnight. Now they are required to ramp up, ramp down and make far more stop and start cycles, Rautkivi says.

While system operators are facing operational challenges, utility companies are also facing these challenges in the market.

Rautkivi argues that while European wholesale electricity prices are quite stable currently, by 2030 – when these markets will have much more renewable capacity – price volatility is expected to significantly increase and with it comes market risk.

“We can see very low electricity prices when you have all the electricity from, basically zero marginal cost renewables, and we’re going to see sky high prices, of course, in the periods when you don’t have renewables,” he explains. “You still need gas or conventional generation to produce electricity, but the running hours are probably half what it used to be. So if you covered your capital expenditure in the past during 4000 hours operation, in the future you need to do the same during 2000 hours. So prices increase and this will cause volatility.”

He adds that “the message to utilities is that you need to be available when the price is high to cover your capital expenditure and go off line when the price is low – a lot of starts and stops to ensure profitability”.

The role of gas generation in these markets will be as the main provider of flexibility and balancing services for large volumes of renewable capacity in the future, argues Rautkivi, saying: “No more baseload operation: it will be a balancing role for them.”

He also notes that the low marginal cost of renewables means that “gas generation will need to give room for renewables, ramping down when the renewables are available”.

Ralf Losch, senior product manager for gas engines at MAN Diesel & Turbo echoes Rautkivi in his estimation of the issue, saying: “With an increasing share of renewable energies feeding into the grid, the operation of a traditional generation system becomes more and more challenging and lacks feasibility. Baseload power plants, for example lignite and nuclear, lack the reaction time needed to adapt to the varying output of renewable generation capacities.

“For any engine, operation at a constant load over extended stretches of time is an ideal scenario with regards to both mechanical stress and fuel consumption.

“Backing up renewable energy production demands a model that greatly differs from this traditional baseload approach. It calls for a lot of engine start-ups, short operation spans, steep ramp ups and partial load operation. More stringent emission regulations are challenging engineering creativity.”

State-of-the-art gas engines comfortably each maximum loading in five minutes, says Losch
Credit: MAN Diesel & Turbo

Flexibility and suitability

But he also highlights the flexibility of gas engines when compared with gas turbines, saying: “While even the most sophisticated heavy frame gas turbines depend on ramp-up times of approximately 30 minutes, state-of-the-art gas engines comfortably reach maximum loading in five minutes. Also their generation capacity is more suitable for decentralized power generation, which reduces the need for partial load operation and makes them a better fit to be operated within a decentralized landscape at a minimal environmental effect.”

Klaus Payrhuber, senior product manager for Jenbacher gas engines at GE’s Power & Water Distributed Power Solutions, also focuses on the advantages of gas engine technology in this application. “Gas engines are attractive for this kind of operation because they have a high electrical efficiency.

“In the last couple of years we developed the two-stage turbocharging technology to increase efficiency by another couple of percentage points, allowing us to have gas engines with extremely high efficiency without losing operating flexibility.

“The combination of both the high electrical efficiency and the operating flexibility makes it very interesting for running this type on engines in simple-cycle mode and balancing the grid for example.”

Payrhuber notes that the output of many gas engines, say between 4–10 MW, corresponds to the output of one or two large wind turbines, which are also installed in multiple units. This makes it possible to compensate for the variability issue of a wind farm with a multiple unit gas engine power plant installation.

However, this does not imply a one-to-one relationship between wind turbines and gas engines. While gas engines provide immediate flexibility, there is also some system robustness associated with large thermal and nuclear units, making for more efficient operation of the whole generation fleet.

This point is emphasised by Rautkivi, who says: “Flexible gas generation takes care of system balancing. So now you can operathe rest of the fleet – those combined-cycle and coal plants – at steady load, and you don’t need to use those to provide flexibility. You can handle the issue with the kind of assets planned and designed for flexible use.”

He adds: “Previously, plants were running at less than optimum efficiency, operating at part load with a lower efficiency than designed, and therefore consuming excess gas and producing higher emissions as a result. Now you can keep these [gas engine] plants on standby and ramp them up as needed, saving both money and emissions.”

Switching to flexible gas

It is clear that system operators such as National Grid in the UK and the California ISO in the US need new flexible investments to address renewable integration and to operate the system reliably in future.

Currently, transmission and distribution network operators have largely chosen gas turbines, either in simple or combined cycle, to perform the flexibility role, but Rautkivi argues that flexible gas engine generation should be considered in its place.

Citing the UK and Californian case studies, Rautkivi says these markets could see significant benefits from investing in gas engine technology. “The studies show California and UK power systems could save $1 billion per annum by investing in more flexible gas generation instead of traditional gas [turbine] generation. So these savings are available without any additional investment costs – pure savings to the consumer.”

“A 50 per cent saving in balancing costs could be achieved with flexible generation – we’re talking significant savings. In California, $900 million represents 11 per cent of the annual system operating cost.”

Payrhuber also focuses on the segment possibilities available with gas engines, saying: “The so-called ancillary services – in addition to providing just power on the grid – can be classified in primary, secondary and minute reserve. What we see is that more of the smaller operators with gas engines are providing ancillary services.

“Primarily this is the segment providing secondary and minute reserve. To play in this segment, our customers are bundling engines into a virtual power plant and then they sell positive or negative minute reserve of 100 MW or 200 MW plants.

“When you look to Germany you already have days in a year where the output from solar and wind are providing 50 per cent of the power load so this is extremely high compared to other countries but could be seen in other countries pretty soon too.

“When you have such a high load on the grid with 50 per cent coming from solar and wind, the big pressure is on the rest of the power generation portfolio to shut down as fast as possible. As a consequence that requirement creates a segment for negative minute reserve. So, if you can reduce the power quickly the grid operator pays you an incentive for that. This is a negative and positive segment because on the other side, if they need reserve power, they pay you a premium, if you can start up quickly.”

Technology developments

Engine manufacturers have responded to the changing segment dynamic in several ways.

Payrhuber highlights the 2010 introduction of the 24-cylinder J624 Jenbacher gas engine, the first with two–stage turbocharging, saying manufacturers are increasing efficiency, but not at the expense of other capabilities, such as the starting time.

However, he also notes that larger engines are also a key advantage: “The larger J920 FleXtra with 9.5 MW electrical output is ideally suited to qualify for the secondary reserve segment. That means with an engine larger than 5 MW the customer can also play in the secondary reserve segment, and that seems to be more attractive because fewer large power plants are participating in this segment.

“The two-stage turbocharged gas engines J920 FleXtra and the J624 are an ideal solution for combined heat and power, because of the high total efficiency at low installation costs. Adding a heat storage system, electric power supply and heat supply can be decoupled to avoid losing the operating flexibility required.”

Losch also points towards a trend for larger and higher efficiency engines: “With its newest gas engine 35/44G, MAN Diesel & Turbo brings the benefits of gas engines to power and cogeneration plants with electrical outputs of up to 200 MW, a category previously dominated by gas turbines. The V-type 35/44G offers 20 cylinders and an output of 10,600 kW. It can be activated rapidly, taking less than five minutes from start up to maximum output.”

In 2015, Man diesel & Turbo plans to launch its new gas engine 51/60G with an output of approximately 20 MW along with further innovations to increase the efficiency.

Despite these advances, Pritil Gunjan, energy and environment industry analyst at consultancy firm Frost & Sullivan, suggests there is little prospect for further significant technological gains. Gas engines are currently operating at around 50 per cent thermal efficiency, with a theoretical maximum of about 55 per cent, though CHP systems can achieve efficiency of 60 per cent or more.

Nonetheless, Gunjan does highlight the market opportunities, saying: “Load following is gaining a lot of attention these days with demand for baseload and peaking power across various regions of the world.

“Traditionally, baseload demands were dominated to a large part by gas turbines with the idea that they could also be quickly ramped up to meet spikes in demand.”

She adds: “With more and more renewables coming into play, there is a fairly good chance that gas engines are going to figure on that list, not because they have higher efficiencies, but because they prove more reliable and have better load following characteristics when it comes to ramping up or turning down.”

David Appleyard is a UK-based freelance journalist, who specializes in the global energy sector.

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