Wärtsilä said the new plant can be converted to run entirely on hydrogen, representing a significant advancement over its current technology, which supports blends of natural gas and up to 25% hydrogen.

The hydrogen-ready plant is based on the Wärtsilä 31 engine platform, which the company says has over 1 million running hours and more than 1,000 MW of installed capacity globally.

The new power plant concept has received a Concept Certificate from TÜV SÜD as part of its H2-Readiness certification process. Wärtsilä plans to make the 100% hydrogen-ready engine available for orders in 2025, with deliveries expected to begin in 2026.

In the announcement, Wärtsilä Energy President Anders Lindberg emphasized the importance of flexible, zero-carbon power generation that can support intermittent renewable sources like wind and solar. He also noted the continued role of natural gas in power systems during the transition period.

“We must be realistic that natural gas will play a part in our power systems for years to come,” he said. “Our fuel flexible engines can use natural gas today to provide flexibility and balancing, enabling renewable power to thrive. They can then be converted to run on hydrogen when it becomes readily available: future-proofing the journey to net zero.”

In the Fall of 2022, a hydrogen-natural gas blending demonstration was conducted using Wärtsilä engines at the A.J. Mihm Generating Station in Michigan. The demo involved blending hydrogen in one of the three grid-connected 18.8 MW Wärtsilä reciprocating engines at the plant.

The partners demonstrated 25% hydrogen by volume fuel blending in the engine that was tested.

Several mechanical changes are needed for engines to be able to handle 100% hydrogen. One of them is to change the compression ratio to reduce temperatures, thus avoiding NOx increases and engine knocking. Another tweak could be implementing pre-chamber combustion to better control the ignition.

Pipelines also need to be code-certified for 100% hydrogen to prevent leaks.

The buyer is the city of Farmington and the existing power plant was identified as the city owned-and-operated Bluffview Power Plant. According to a signed equipment supply contract, the contract is worth approximately $13.9 million. Wärtsilä equipment for the project, including the generator sets and auxiliary equipment, is expected to be delivered by January 2025.

The two Wärtsilä 34SG natural gas-fueled engines selected for this project are also capable of operating on biogas, synthetic methanol and a hydrogen blend.

MORE: Exploring the hidden value of reciprocating engines using sub-hourly grid modeling

Farmington Electric’s Bluffview Power Plant produces approximately 60 MW. It is a combined-cycle natural gas plant that was completed and commenced operation in May of 2005. The plant includes a natural gas-fired gas Combustion Turbine Generator (CTG) with a heat recovery steam generator (HRSG),
duct burner and steam turbine. The facility also includes cooling towers, circulating water pumps, sub-station, and supporting equipment to produce and deliver electricity

Wärtsilä said the new expansion will replace lost generating capacity following the closure of a coal-fired power plant. The last unit of the San Juan Generating Station, located in Farmington, was officially removed from service in September 2022.

The shutdown of San Juan Unit 4 followed the retirement of Unit 1 in June 2022. The coal-fired plant had four units but was reduced to two in 2017, with the closure of Units 2 and 3. The plant’s first unit was brought online in 1973.

Public Service Company of New Mexico (PNM) is the majority owner of San Juan Generation Station, but the city of Farmington has a 5% stake. The city had aimed to keep the plant open, partnering with Enchant Energy for a carbon capture and sequestration (CCS) project

The project will be Basin Electric’s largest single-site generation project since the 1980s. It will include two Siemens STG6-5000F simple-cycle combustion turbines and six Wärtsilä W18V50SG reciprocating engines.

Basin Electric said preliminary estimates place the budget at approximately $780 million, which includes both generation and transmission assets. The co-op said load forecasts have showed the need for more electricity by 2025 to serve the Bakken region’s rapidly growing demand.

Burns & McDonnell is the EPC for the project.

Battery supplier Wärtsilä Energy and projects owner Eolian L.P., a portfolio company of Global Infrastructure Partners, say the combined projects make up the “world’s largest (in MWh) fully-merchant and market-facing energy storage facility built to-date.”

A Wärtsilä spokesperson told Power Engineering the exact MWh capacity per project site was confidential. She did say each of the two sites are greater than 250 MWh and longer than 2 hours in duration, so the project is above 500 MWh in total.

The Madero and Ignacio lithium-ion battery projects have a combined power capacity of 200 MW and will be operated using Eolian software.

Wärtsilä said this is also the first use of the Investment Tax Credit (ITC) for standalone utility-scale energy storage systems, which was introduced through the Inflation Reduction Act (IRA) of 2022. 

Construction of the projects began in January 2021.

“Texas needs more flexible capacity solutions like energy storage for grid support and energy resource optimization,” said Risto Paldanius, vice president Americas, Wärtsilä Energy. “This will help the state as it faces the natural replacement cycle of older inflexible generators and adapts to more frequent extreme weather events.”

Wärtsilä and WEC Energy Group announced the successful test of a commercially operating Wärtsila engine running on a 25% hydrogen blend.

Testing was completed in October 2022 at WEC’s 55 MW A.J. Mihm power plant in Michigan, using an unmodified Wärtsilä 50SG engine.

The Electric Power Research Institute (EPRI) also participated in the tests and led the assessment of the engine’s performance. Over three days of testing, EPRI found there were improvements in engine efficiency and reduced emissions, while staying compliant with NOx emissions.

A 95% engine load was achieved with the 25% hydrogen blend. Further testing showed that with a 17% hydrogen blend, a 100% engine load was attainable.

The EPRI report states that this class of engines can maintain its higher efficiency compared to simple-cycle gas turbines. Because engines in general have higher efficiency, their relative CO2 output compared to turbines will also be lower, as was shown in this study.

Wärtsilä said this was the largest commercially operated flexible balancing engine ever to run on a hydrogen fuel blend.

“We continue developing and futureproofing our engines to run on sustainable fuels and expect to have an engine and power plant concept for operating with pure hydrogen available by 2026,” said Anja Frada, Chief Operating Officer for Wärtsilä Energy.

In addition to the basic function of providing grid capacity and energy to their customers, some utilities have additional motivation behind their desire to build a new power plant, particularly as extreme weather, natural disasters, and geopolitical conflicts continue to threaten our power systems. Three recent cases where the added benefit of system or self-resiliency was a primary concern are described below.

Matanuska Electric Association (MEA), located in Palmer, Alaska, built a 170 MW power plant with ten Wärtsilä 18V50DF engines. A member of the Railbelt utilities, this was their first self-generation plant, having previously purchased and distributed power in the Railbelt network. Energy security and self-reliance are part of Alaska’s ‘belt and suspenders’ attitude towards life.

The plant is dual-fuel capable, with the primary fuel being natural gas, but also diesel fuel if the gas supply is interrupted.  The plant was also designed and built to withstand high seismic forces in this earthquake prone area. The generator sets are fitted with seismic dampers, specialized flex connections and special generator bearings, and many other aspects of the plant are built extremely robust to withstand earthquakes. 

This foresight was proven well-founded when in November 2018, the area experienced a 7.1 magnitude earthquake whose epicenter was located only 43 miles from the power plant. The facility experienced only minor damage, and MEA restored power to most of their territory in less than 24 hours.

Located in a much warmer place, Hawaiian Electric (HECO) serves 95% of Hawaii’s residents and has been in business for more than 100 years. Hawaii has one of the most aggressive goals towards achieving 100% renewable energy in the United States.

On the island of Oahu, HECO was able to combine a desire to provide a new, highly efficient, flexible 50 MW plant with the United States Army’s desire to provide increased energy security and resiliency for the Schofield Barracks Army Base. The result is the Schofield Generating Station, which has six Wärtsilä 20V34DF engines running on biodiesel fuel. The plant is located on land provided by the Army.

HECO is able to run this plant as part of their overall generation portfolio and dispatch it as needed when its grid requires it. However, should it be required, the Schofield Base has first call on the power in the event of a disruption in the grid.

As HECO’s website says, “In return for the value of the 35-year lease for the Schofield Generating Station project, Hawaiian Electric guarantees the Army energy security – ensuring it will be able to restore power to the three installations within two hours if they were to lose power. The lease requires Hawaiian Electric to conduct a one-time ‘full system test’ of this capability to prove it can be accomplished.” This test was performed in May 2021, when the microgrid serving the Base as an islanded load was successfully established and operated for 36 hours without any interruptions.

Another plant with recent real-world experience providing resiliency is owned by Entergy, a large utility serving parts of Arkansas, Louisiana, Mississippi, and Texas. Having been through several very serious hurricanes affecting New Orleans and South Louisiana, Entergy wished to replace a 1960’s era steam generation plant with a modern, highly efficient power plant located close to New Orleans. The utility chose to build a new plant consisting of seven Wärtsilä 18V50SG sets producing 128 MW. The New Orleans Power Station (NOPS) was designed to withstand the high wind and extreme rainfall present in hurricanes.

Once again, the designers proved to have good instincts, and Hurricane Ida struck South Louisiana on August 29, 2021. Ida proved to be the second most destructive hurricane to ever strike Louisiana, second only to Katrina, with sustained wind speeds of 150 mph. Entergy reported that within 48 hours, the NOPS plant was restarted and connected to the local grid.

Unfortunately, the damage to the local transmission and distribution system was so severe that full restoration of power to the New Orleans area took several days. However, some neighborhoods, and in particular, some critical facilities like hospitals and first responder facilities had power within 48 hours.

As extreme weather and natural disasters continue to shake our power systems, the need for resiliency is paramount. Adding in the variability of renewable power sources like wind and solar to extreme weather situations only increases the need for solutions that work when you need them. 

All these plants had aspects built into them to meet the desire for resiliency – they can all “self-start” without external power, and they all have multiple generator sets such that if one is down for service, the remaining sets can still operate. Two plants have been tested in the real-life situations of an earthquake and a hurricane, and the third has successfully completed a realistic demonstration test.

When building resilient energy systems of the future, utilities and power providers should consider assets that possess characteristics described in these three examples: dispatchability, dual and multi-fuel capabilities, low minimum operating levels, zero minimum down times and run times, fast ramp speeds and the flexibility to keep the lights on when disaster strikes. 

About the Author: Chris Whitney is a Mechanical Engineer who has worked for Wärtsilä for 35 years, first as a Project Manager for Power Plants, and currently as a Senior Proposal Manager. He worked initially for Schlumberger Offshore Services as a Field Engineer in the Gulf of Mexico, and following that as the Chief Engineer of a small independent oil company based in Lafayette, Louisiana. His current responsibilities include preparation of the technical specifications, performance data, and cost estimates for new offers produced by Wärtsilä for reciprocating engine power plants.

WEC Energy Group (WEC), Wärtsilä, the Electric Power Research Institute (EPRI) and Burns & McDonnell will partner to carry out hydrogen fuel testing in reciprocating engines at the A.J. Mihm power plant in Michigan.

WEC’s 55 MW plant currently operates with three Wärtsilä 50SG engines that run on natural gas. It was placed into service in March 2019.

The parties will aim for testing fuel blends of up to 25% hydrogen volume mixed with natural gas.

Wärtsilä said the engines can operate with this level of hydrogen blend with little or no modifications needed.

One engine will be selected for the test program and will continue to deliver power to the grid. The hydrogen content in the fuel will be gradually increased to 25%, with measurements of the engine’s performance made throughout the testing.

Wärtsilä said it has already hydrogen blending tests at facilities in Vaasa, Finland and Bermeo, Spain.

The project aims to support WEC’s goal of reducing carbon emissions 60% (from 2005 levels) from its generating fleet by the end of 2025. It could also inform similar hydrogen blending efforts in other reciprocating engines.

Each of Wärtsilä’s three engines at A.J. Mihm has its own 65-foot stack and are cooled by 24 radiator fans that reject heat from a closed-loop circulating antifreeze (coolant) system.

Fueled with natural gas, each engine is shaft-coupled to an electric generator. The units are housed inside a building with an exterior resembling a warehouse. The exhaust system is located outside the building and includes silencers, air quality control systems and stacks.

The plant uses selective catalytic reduction with urea injection for control of nitrogen oxides and an oxidation catalyst for control of carbon monoxide, volatile organic compounds and hazardous air pollutants.

“These hydrogen tests reinforce the viability of the internal combustion engine as a future-proof technology that plays a key role in decarbonizing the power industry,” said Jon Rodriguez, director for engine power plants at Wärtsilä North America.

The delivery comprises seven Wärtsilä 50SG gas engines operating with natural gas fuel. They will be part of a modern, low-carbon natural gas energy facility that will serve customers of WEC Energy Group utilities We Energies and Wisconsin Public Service in Wisconsin, USA. The Wärtsilä engines have the flexibility to rapidly respond to the inherent fluctuations from solar and wind, and will thus provide the necessary grid balancing for a reliable power supply for Wisconsin’s electric grid.

“Wärtsilä is helping to create a carbon neutral world for electricity providers and the Wärtsilä 50SG engine is a hallmark of that future-proof design,” said Jon Rodriguez, Director, Engine power plants, Wärtsilä Energy in North America. “With the ability to convert the engine to run on various fuels including hydrogen blends, the Wärtsilä 50SG will be able to support the reliability and flexibility demands of our client now and well into the future.”

Delivery of the Wärtsilä engines will take place in October 2022, and the commissioning of the plant is scheduled for March 2023. WEC Energy Group has earlier ordered Wärtsilä engines for two other power plant projects, with total output of 188 MW.

WEC Energy Group plans to exit coal by 2035, and intends to retire 1600 MW of older, less-efficient fossil-fuelled generation by 2025. A total of $5.4 billion is allocated to new investments in wind, solar, and battery storage.

With the new order included, Wärtsilä will have an installed base of more than 3,800 MW in the United States.

During the pilot project, hydrogen and natural gas will be mixed up to a 25/75 percent blend to power one of the generating units that serves customers of Upper Michigan Energy Resources, a WEC energy subsidiary. The units use reciprocating internal combustion engines, which were manufactured by technology company Wärtsilä and began service in 2019.

Reciprocating engines convert pressure into rotating motion using pistons, while gas or combustion turbines use the pressure from the exploding fuel to turn a turbine.

WEC is partnering with the Electric Power Research Institute (EPRI), which will lead the technical implementation of the project and share results to further educate the energy industry about how to successfully use hydrogen for power generation to support reducing carbon emissions.  

WEC described the hydrogen power pilot as among the first of its kind in the U.S.

“The potential of adding hydrogen as a clean generating fuel to our fleet of dispatchable plants is an important step as we bridge to a bright, sustainable future,” said Gale Klappa, executive chairman

WEC Energy Group has a goal of net-zero carbon emissions from electric generation by 2050 and net-zero methane emissions from natural gas distribution by the end of 2030.

In 2020, Wärtsilä said it was developing the combustion process in its gas engines to enable them to burn 100% hydrogen fuel. At the time it had tested its engines with blends of up to 60% hydrogen and 40% natural gas.

In addition to hydrogen, it said other potential renewable fuels also were being studied for future applications, that its engines were already capable of combusting 100% synthetic carbon-neutral methane and methanol.

The U.S. Department of Energy identifies two primary reciprocating engine designs relevant to stationary power generation applications: the spark ignition Otto-cycle engine and the compression ignition Diesel-cycle engine.

The essential mechanical components of the Otto-cycle and Diesel-cycle are the same. Both use a cylindrical combustion chamber in which a close fitting piston travels the length of the cylinder. The piston connects to a crankshaft that transforms the linear motion of the piston into the rotary motion of the crankshaft. Most engines have multiple cylinders that power a single crankshaft.

The main difference between the two cycles is the method of igniting the fuel. Spark ignition engines (Otto-cycle) use a spark plug to ignite a pre-mixed air fuel mixture introduced into the cylinder. Compression ignition engines (Diesel-cycle) compress the air introduced into the cylinder to a high pressure, raising its temperature to the auto-ignition temperature of the fuel that is injected at high pressure.

For combined heat and power applications, most installations use four-stroke spark ignition engines, the Energy Department said. Reciprocating engines are characterized as either rich-burn or lean-burn. Rich-burn engines are operated near the stoichiometric air/fuel ratio, which means the air and fuel quantities are matched for complete combustion, with little or no excess air.

In contrast, lean-burn engines are operated at air levels significantly higher than the stoichiometric ratio. In lean-burn engines, engine-out NOx emissions are reduced as a result of lower combustion chamber temperatures compared to rich-burn engines.