He said the scale of data center customers’ ambitions is “10x” what it was just a couple years ago, adding that it’s no longer uncommon to see these companies asking for 500 MW of power for a single campus.

“It seems like an arms race right now to see who could be bigger,” said Schurr, who is Chief Commercial Officer at Enchanted Rock.

The current and future demands on the grid placed by data center, crypto and manufacturing customers present an opportunity for Enchanted Rock, a company with strong bona fides in onsite and backup power generation.

With all of this demand, Schurr noted many data centers will face delays for a firm grid connection while transmission and other infrastructure get built. Interconnection could take three years on the low end or up to ten years in certain markets.

Therefore, Enchanted Rock is promoting its “Bridge-to-Grid” microgrid solution, so data centers and other power-intensive industries can build, commission and operate on their own schedules.

The company’s solution is multi-purpose, depending on the status of power. When grid power is delayed, the microgrid provides prime power to the facility. With grid power, the microgrid can provide “flexible capacity,” backing up the facility and providing power during peak conditions to prevent grid emergencies.

Typically, data centers distribute diesel generators building-by-building throughout their campus for backup power, but these generators can’t support the grid like natural gas-fired generation can.

“For us to be able to get the power we need, we have to be somewhat flexible, self-sufficient during certain hours of the year,” said Schurr. “And you can’t do that with diesel generators.”

Natural gas-fired turbines or reciprocating engines would be the workhorse of Enchanted Rock’s microgrids. Schurr said the company evaluates about ten factors at a given site to determine the appropriate technology, including the duration of bridge power, environmental constraints, and space requirements.

Schurr said if long-term backup power is needed after interconnection, using reciprocating engines for bridge power offers the advantage of already having the equipment on-site, eliminating the need for additional diesel generators. This functionality, he noted, along with reciprocating engines’ ability to start quickly, often makes them the most cost-effective solution.

In general, Schurr said he’s starting to see a trend where companies are thinking about strategically locating their facilities near gas resources. Some data centers have asked Enchanted Rock to help them with site evaluations.

“I’d say some of the some of the more forward-thinking ones are absolutely looking at gas infrastructure as a siting criteria,” said Schurr. “They’ve never had to do that before.”

Enchanted Rock said it can go to market with the microgrid as a service, where the company owns the generating assets and provides bridge power and flexible/backup power needed during the grid connection period. Schurr noted that while it’s not common due to regulatory hurdles, some data centers do want to own the generating assets.

“We find a lot of them like it as a service, they like someone to take full accountability for building it, operating it, maintaining it, so that they can focus on just adding more data center capacity,” said Schurr.

Enchanted Rock hasn’t announced many data center projects yet. However, one of its microgrid projects will be fueled by renewable natural gas (RNG) to power a Microsoft data center in San Jose, California. The project aims to ensure maximum uptime for the facility by providing backup power during grid outages. Procurement of the RNG is scheduled to begin in early 2026. 

Schurr predicts that in five years, big data centers projects won’t be able to get a firm interconnect in most locations and will have to come with flexible generation component for peaking hours. Just another hint at the paradigm shift taking place in the power sector.

“I talked to the CFO of a big utility a few months ago,” he said. “And he said, [data centers] used to come in here asking for concessions. And now it’s like, ‘do you have power’?”

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

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.

Automotive OEM supplier Raloy Lubricantes selected the mtu Series 500 gen-sets for powering operations at the Santiago Tianquistenco facility. In addition to the electricity used at the plant, heat from exhaust will warm up thermal oil for mixing processes.

At the same time, thermal energy from jacket heat will be recaptured and run through an absorption chiller to produce chilled water for cooling plastic bottles manufactured in Raloy’s sister company, Thermfluidos.

The new Series 500 generator set at Raloy’s manufacturing plant is expected to be commissioned by April 2022.

“It is not common to work with a customer that is ready to embrace new technology and lead an industry, as it has been with Raloy,” said Javier Gonzalez, Senior Manager of Gas System Sales, Americas, at Rolls-Royce Power Systems. “Raloy knows and trusts the high quality of our products and this added with their genuine interest of developing sustainable processes, is why they decided to put them to work in their operations.”

The mtu Series 500 is the new successor to the Series 400 and reportedly improves on engine efficiency and generates 30 percent more power, according to Rolls-Royce. The system is dual fuel, available to run on either natural gas or biogas, and can be ready for a blend of up to 10 percent carbon-free hydrogen.

Raloy Lubricantes makes motor oil and other automotive and generator-set lubricants. The company is 100-percent Mexican-owned and employs more than 200 people.

MTU became part of Rolls-Royce when the latter acquired Tognum Corp. in 2011.

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On-site power, hydrogen and CHP all are topics of content sessions happening at POWERGEN International live Jan. 26-28 in Dallas. Registration is now open.

Lakeland Electric awarded the EPCM contract for the project to be built on the existing McIntosh Power Plant site. Sargent & Lundy has led several RICE projects in the region.

MAN Energy Solutions will supply six 18V51/60G engines,, along with the major power island auxiliaries to Lakeland Electric based on Sargent & Lundy’s developed specifications.

The gas-fired engines will offer quick-starting, flexible power resources to replace the recently retired coal-fired plant.

The Lakeland plant is scheduled for commercial operation by late 2023.

McIntosh’s final operating Unit 3 was decommissioned earlier this year. The municipal utility has previously spent more than $5 million to fix issues with Unit 3 in the past year, resulting in several outages, according to reports.

Sargent & Lundy has guided EPCM duties for RICE projects ranging from the Montana-Dakota Utilities gas-fired plant to others in more than a dozen countries.

Research by consulting group M.Cubed indicates that the generator population in the Golden State climbed by double-digit percentage points in the past year. Two air quality districts, the South Coast and Bay Area, collectively are home to more than 23,000 backup generators.

Combined those on-site gen-sets account for 12.2 GW of electricity capacity, close to 15 percent of California’s entire grid, according to the M.Cubed analysis. Of that total gen-set population, more than 20,000 are diesel-fueled.

The backup generator count rose 34 percent in the Bay Area Air Quality Management District alone in the past three years, according to M.Cubed.

Many businesses and mission critical services such as hospitals and military bases are bolstering their backup plans with microgrids which include solar and storage combinations. A large part of those microgrids also include a gen-set, fired by natural gas or diesel, to deploy when circumstances require it.

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State and local leaders know all this and are, of course, concerned deeply about the emissions impact. At the same time, the state’s energy commission allowed four gas-fired engine gen-sets to be brought in to provide resiliency to the grid in the midst of wildfires and lowered hydropower production due to drought conditions.

“We have long been concerned about the proliferation of diesel backup generators here in the Bay Area, as highlighted in this report,” said Jack Broadbent, executive officer of the Bay Area Air Quality Management District. “Emissions from these backup generators can harm local residents, regional air quality and the global climate. This is particularly true in communities already overburdened by air pollution and the Air District is actively pursuing regulations to curb this pollution.”

However, backup generators provide Californians with energy security as they deal with a myriad of weather and grid events. The state is seeking a goal of 100-percent clean energy power by 2045, but must deal with the challenges facing its journey to net-zero carbon emissions.

Four gas-fired flexible gen-sets approved to help California through a brutal summer are still online and available to support the state’s grid, according to the latest Department of Water Resources statement.

Two units each have been temporarily installed at two sites in Northern California: Greenleaf Unit 1, operated by Calpine in Yuba City, and the Roseville Energy Park, operated by Roseville Electric. Each unit can produce up to 30 MW of power, totaling 60 MW of power at each site. The units run on natural gas but can run on a blend of up to 75 percent hydrogen. 

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On-site power and microgrids will be a focus of content sessions at POWERGEN International happening Jan. 26-28 in Dallas, Texas. POWERGEN and DISTRIBUTECH Internationall will be co-located there. Registration is now open for both.

Zachry Group will lead the building of both the Standing Bear Lake and Turtle Creek stations. The Nebraska municipal utility hopes to get both gas-fired power plants, totaling 600 MW in capacity, up and running by 2023.

Design work is underway and major construction expected to begin on both projects in the first quarter of 2022, according to Zachry. Standing Bear Lake Station will be a 150-MW facility in Douglas County, while the 450-MW Turtle Creek will be located in Sarpy County.

“We are thrilled to once again work with Omaha Public Power District on this important project that supports their net zero carbon goals,” said Scott Duffy, Senior Vice President, Business Development at San Antonio, Texas-based Zachry. “This work aligns well with Zachry Group’s long-standing resume in the power market, our full suite of engineering and construction capabilities, and our focus on helping our customers’ maintain reliability and resiliency as their customers and communities grow.”

Both projects are part of OPPD’s Power with Purpose initiative first outlined in 2019. Power with Purpose was centered around 400 to 600 MW in solar installations, but also added gas-fired capacity for balancing and backup. Standing Bear Lake will be a reciprocating engine site offering quick response capabilities, while Turtle Creek was planned as a simple cycle turbine power plant.

These plants are considered flexible generation which back up the solar installations. Siemens Energy was contracted to provide two SGT6-5000F gas turbines to power the Turtle Creek peaker plant.

Those turbines can be adapted to run on 30-percent hydrogen mix, which would lower the carbon emissions even further. Siemens hopes to have all of its gas turbines capable of running on 100-percent hydrogen (which does not emit carbon dioxide) by 2030.

OPPD selected Wärtsilä to deliver nine of its multi-fuel 18V50DF internal combustion engines to power the Standing Bear Lake Station. Those RICE engines can also be adapted to run on hydrogen blends, according to reports.

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The New Energy Mix and Trends in Conventional Power are the two Knowledge Hubs which will offer content on the POWERGEN International exhibition floor. POWERGEN is happening Jan. 26-28 in Dallas. Registration is now open to attend the nation’s biggest show focused on power generation in all its forms.

The California DWR noted that the gen-sets, first approved earlier this summer, are temporary and spread out across several locations in the state. California has been impacted by high temperatures and a drought which brought down hydropower capacity across the western U.S.

Two units each have been temporarily installed at two sites in Northern California: Greenleaf Unit 1, operated by Calpine in Yuba City, and the Roseville Energy Park, operated by Roseville Electric. Each unit can produce up to 30 MW of power, totaling 60 MW of power at each site. The units run on natural gas but can run on a blend of up to 75 percent hydrogen. 

“DWR’s expertise as the fourth largest power producer in California allowed us to work quickly with the CEC, the California Independent System Operator, and our regional partners in Yuba City and Roseville to bring these units online,” said DWR Deputy Director for the State Water Project Ted Craddock. “DWR is proud to play a role in safeguarding the state’s energy grid and doing everything possible to avoid power shortages and outages as a result of climate-induced conditions.”

The generators would be deployed under emergency conditions determined by the California Independent System Operator (ISO) under a contingency plan developed in coordination with the CEC and the California Public Utilities Commission. The plan includes a range of measures to address potential energy supply shortfalls, including Flex Alerts, coordination with adjacent balancing authorities, demand reduction strategies, and bringing online new resources such as the temporary generators.

“These temporary generators are an important last resort resource that can be relied on to support electricity reliability across California during grid emergencies,” said CEC Commissioner Siva Gunda. “The state’s energy agencies are committed to ongoing monitoring of these facilities in coordination with DWR and local partners to ensure any impacts are accounted for.”

The four generators are located next to existing power plants operated by Calpine and Roseville Electric. They can be online within five minutes at the direction of the California ISO or the Western Area Power Authority.

The project cost for the four temporary emergency generator units is $196 million which will be paid for through emergency funds. The units will be available until December 31, 2023. 

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Flexible power generation is a key topic in the New Energy Mix Knowledge Hub planned on the POWERGEN International exhibition floor. POWERGEN is happening live Jan. 26-28 in Dallas.

Technology group Wärtsilä and Gabon Power Company (GPC) have signed a Concession Agreement with the government of Gabon for a 120MW gas power plant.

The project represents one of the largest of its kind in Sub-Sahara Africa and a sizeable energy infrastructure project for Gabon.

The plant will be located at the industrial site of Owendo, close to Libreville, the country’s capital. When commissioned, the plant will supply electricity to Gabonese utility Société d’Energie et d’Eau du Gabon (SEEG), under a 15-year PPA.

Marcelin Massila Akendengue, General Director, Gabon Power Company, said: “There is currently a structural deficit between the supply capability and the demand for electricity, which is increasing year by year.

“This project will play an important role in bridging this deficit, and some 600,000 people will ultimately benefit from a more sustainable and economical electricity supply delivered to SEEG. The plant will replace rented generation assets by SEEG and bring significant benefits, in line with Gabon sustainability ambitions.”

Wärtsilä will lead project development with GPC, build the plant under a full EPC contract and will then operate and maintain the plant under a long-term Operation and Maintenance (O&M) agreement.

The EPC contract and the O&M agreement will be signed in 2022 with Orinko S.A., the joint venture between Wärtsilä and GPC.

“This is a major and very comprehensive project that will deliver sustainable energy at a competitive price,” said Nicolas Mathon, Director, Project Development, Africa and Europe, Wärtsilä Energy and Managing Director, Orinko S.A

The project is being developed under a Public-Private Partnership framework, with the asset to transfer to the Gabonese authorities at the end of the concession agreement.

Gabon Power Company is a subsidiary of the Sovereign Fund of the Gabonese Republic (FGIS) dedicated to developing energy and water infrastructure in the country.

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Boortmalt, a malting company, has tasked Wärtsilä with converting its Punta Alvear dual-fuel plant to a gas-fueled system.

This will help the malting firm to lower its production and operating costs and aligns with the company’s sustainable development strategy, which aims to reduce energy consumption and carbon emissions by 50% by 2030.

The upgrade is expected to increase the plant’s efficiency and power output, and the process reduces Bootmalt’s malt production expenses. The project is also expected to help reduce the plant’s carbon footprint.

Jorge Alcaide, Wärtsilä Energy Business Director, Americas, Region South, added: “By carrying out this gas conversion project, we are in effect future-proofing the plant’s operational performance, since it will facilitate the future integration of energy from renewable sources, such as wind and solar. In the meantime, it will reduce the need for power from the grid, thereby lowering costs.”

Gas conversions will also enable the transition to future synthetic fuels, such as hydrogen.