Atura Power, a subsidiary of Ontario Power Generation, is expanding the power generation capacity at its 900 MW Napanee Generating Station in the Town of Greater Napanee, Ontario. The planned expansion has a targeted completion by 2028.

Atura Power will add an M501JAC combustion turbine from Mitsubishi Power Americas, that will operate in simple cycle and provide up to 430 MW of additional electricity. Mitsubishi Power Americas said its M501JAC is known for its operational flexibility and startup times, and can also operate as a peaker. The turbine will join two M501GAC units already operating in combined cycle at the site. This will be the fifth Mitsubishi Power M501JAC turbine in Canada.

In 2019, Ontario Power Generation acquired the Napanee Generating Station and two other gas-fired plants in a $2.8 billion deal with TC Energy (formerly known as TransCanada). The facilities included the 683 MW Halton Hills power plant, the 900 MW Napanee generating station which was nearing completion at the time, and TC Energy’s 50% interest in the 550 MW Portlands Energy Center.

The deal was subject to a number of closing conditions which included regulatory approvals and Napanee reaching commercial operations as outlined in the agreement.

In their respective second-quarter earnings reports, NRG Energy and Vistra discussed potential opportunities for data center co-location.

NRG’s 21 generating sites are “ideally suited for new large loads and power plant development, offering co-location opportunities both behind and in front of the meter,” said NRG President and CEO Larry Coben on the company’s earnings call Thursday.

Coben said NRG’s facilities would be attractive to data center developers for their access to water for cooling, premium fiber channel access for low latency and existing grid access for rapid market entry. NRG’s fleet includes a mix of natural gas, renewables and coal.

“We were getting lots of people sort of throwing us bids for our sites,” Coben told investors.

He continued: “We know they think we’re just a bunch of power guys who don’t know anything about data centers. So, if that’s what they’re bidding us, we really need to look at this, because it means there’s a lot more value in there than the bids that we’re receiving.”

Regarding discussions with data center providers and any potential co-location deals, Coben said NRG was working on a strategy and would release more details later in 2024.

The concept of large loads co-locating with generation continues to draw interest. The most-watched proposal would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in Pennsylvania.

Multiple utilities protested the proposed Talen Interconnection Service Agreement (ISA), prompting FERC to call for a technical conference in the fall to discuss the larger issue of co-location.

For Vistra, the pending Talen case or upcoming FERC technical conference “has not slowed the conversation down” on potential data center co-location deals, said company President and CEO Jim Burke.

“We’re in due diligence for a number of sites,” Burke told investors on the company’s Q2 call. “This is a really big opportunity for our industry to meet customer needs.”

Vistra reiterated the company can provide data centers the speed to market advantage since there wouldn’t be the same level of buildout needed on the transmission side.

“I think there’s going to be plenty of data center load behind-the-meter or co-located, and also front of the meter,” Burke said.

On planning for load growth and building new gas plants

The industry’s rapid load growth is being driven by data centers, electrification and new manufacturing. This is compounded by the retirement of fossil-fired plants. As a result, both NRG and Vistra see emerging supply gaps and tightening markets.

Among the regions expected to experience a surge in demand, ERCOT’s current long-term load forecast shows peak demand increasing from 86 GW in 2024 to 137 GW in 2028. This load growth will require significant planning and construction of new generation and transmission.

While NRG and Vistra operate plants outside of Texas, most of their growth is taking place in the ERCOT market. Both companies are taking advantage of the Texas Energy Fund (TEF), a government low-interest loan program used to incentivize the development of more dispatchable generation and smaller backup power in the state.

NRG has filed TEF loan applications for three separate projects, totaling more than 1,500 MW of capacity. Thee company would begin construction on two of the three facilities as early as October of this year.

One of these projects is a new 689 MW natural gas combined-cycle unit with Mitsubishi Power M501JAC equipment, located at NRG’s Cedar Bayou plant in Baytown, Texas. The target completion date would be late-2027.

The 415 MW simple-cycle unit at TH Wharton would include Siemens Energy’s SGT6-5000F equipment and could come online by mid-2026.

Finally, the 443 MW simple-cycle unit at Greens Bayou would be powered by a GE 7HA.03 turbine and could be finished by mid-2028.

“We believe our projects are well-situated for a timely approval, given their shovel-ready nature and the completeness of the applications that we submitted,” said Coben.

Texas Lt. Gov. Dan Patrick recently said 81 applicants representing over 41 GW of dispatchable power had applied through the fund, as of May 31. Patrick said the state planned on expanding the program during the next legislative session.

Coben told investors NRG could apply for more loan funding in a potential second TEF round, but also noted the challenge of multi-year lead times for turbines and other equipment.

“If you don’t have a place in the turbine queue today, there’s no way you’re getting a new project online before 2030, at the earliest,” he said.

In May, Vistra announced plans to add up to 2,000 MW of natural gas-fired capacity in West, Central and North Texas.

860 MW of simple-cycle peaker plants would support West Texas, including the state’s growing oil and gas industry. The company is seeing multiple demand drivers, including data centers and the electrification of oil field operations, specifically the Permian Basin of West Texas

Vistra would also convert its coal-fired Coleto Creek plant near Goliad to natural gas after the plant retires in 2027. Repowering would enable up to 600 MW of gas-fired capacity.

Also included are 500 MW of augmentations at existing facilities, nearly half of which are already finished, Burke said on the Q2 earnings call.

In its quarterly report, Vistra leadership noted the industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment needed for the construction of renewables projects. As a result, Vistra has deferred some of planned capital spend for these projects, the company said in its 10-Q filing.

The company did announce two long-term power purchase agreements (PPAs) with Amazon and Microsoft for two new large-scale solar facilities.

Supply chain disruptions have also increased the lead times to procure certain materials necessary to maintain Vistra’s natural gas, nuclear and coal fleet, according to the filing.

“We have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages,” the company reported.

In its Q2 report, NRG said procuring mid to long-term generation through PPAs continues to be part of its strategy. The company has entered into renewable PPAs totaling nearly 1.9 GW with third-party developers, all of which were operational as of July 31.

While electric utilities and developers use terms like “hydrogen-ready” or “hydrogen-capable” in their project plans, IEEFA said this is little more than marketing designed to obscure the challenges of hydrogen co-firing in gas turbines.

The biggest obstacles to hydrogen co-firing in gas turbines include building new infrastructure and ramping up supply, according to the Institute in Hydrogen: Not a solution for gas-fired turbines.

U.S. utilities and developers have announced myriad of “hydrogen-ready” projects over the last several years, ranging from technology demonstrations to large-scale commercial developments. But IEEFA said for at least the next 10 years, any “hydrogen-capable” gas-fired power plants are going to operate almost completely, if not entirely, using natural gas.

The institute said state regulators and potential project investors should scrutinize assertions that hydrogen gas will be widely used in natural gas-fired turbines.

Lack of supply

IEEFA noted the U.S. produces about 10 million tons of hydrogen every year, nearly all of which is consumed in the petrochemical and fertilizer sectors. Any hydrogen co-firing in the power sector would require a lot of new production, the institute said. Just running the 15 largest natural gas combined-cycle (NGCC) plants with hydrogen would require doubling current U.S. production and would replace less than 10% of the electricity now generated annually from natural gas, IEEFA said.

The report cited a 2022 demonstration where Long Ridge Energy tested a 5% hydrogen blend at its newly commercialized 485 MW combined-cycle plant in Ohio. While the demonstration was a success, the company told the U.S. Energy Information Administration (EIA) it burned 325,000 cubic feet of hydrogen during the tests, producing 17 megawatt-hours (MWh) of power.

IEEFA said the example underscores the enormous amount of hydrogen needed for even a small level of blending and the challenges of scaling even larger. According to EIA, the company has not used any hydrogen in the Long Ridge turbine since the 2022 demonstration.

Lack of pipeline infrastructure

The institute noted that no pipeline network exists to distribute the fuel to hydrogen-capable gas turbines being proposed in the U.S. IEEFA also said building such a network would take years and cost billions of dollars, and the time and effort required for this buildout would slow the transition from fossil fuels.

While the U.S. has a sprawling natural gas pipeline network, with approximately 305,000 miles of inter- and intrastate transmission lines, there are only roughly 1,600 miles of hydrogen-dedicated pipelines in the U.S. Virtually all the existing infrastructure is concentrated in Texas and Louisiana, where there is petrochemical and other industry activity.

Blending hydrogen into existing pipelines has been proposed as a possible alternative, but IEEFA said the latest research has raised more questions than answers about the technical and safety implications of introducing hydrogen into the system. In short, blending hydrogen into pipelines would weaken the steel, IEEFA said, potentially leading to cracks, leaks and complete failure.

Read the full report here.

For perspective, AEP’s systemwide peak load at the end of 2023 was 35 GW. The utility serves 5.6 million customers in 11 states through its subsidiaries and has the country’s largest transmission system.

AEP Interim CEO Ben Fowke said the company continues to work with data centers to meet their increased demands for power, while ensuring that new contracts are fair to all of its customers.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly, and the right investments are made for the long-term success of our grid,” Fowke told investors.

Fowke cited AEP filing new data center tariff proposals in Ohio and large-load tariff modifications in Indiana and West Virginia.

In Ohio, the proposed rate structure would require new data centers with loads greater than 25 MW and cryptomining/mobile data center operations with loads greater than 1 MW to agree to meet certain requirements before infrastructure is constructed to serve them.

Data centers specifically would be required to make a 10-year commitment to pay for a minimum of 90% of the energy they say they need each month – even if they use less.

Along with Exelon, AEP is also protesting a proposal that would result in the co-location of an Amazon Web Services (AWS) data center at Talen Energy’s Susquehanna nuclear plant in northeast Pennsylvania. The utilities claim the proposed interconnection agreement would result in unfair cost burdens on ratepayers and negatively impact market operations and reliability.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used.

The burgeoning of data centers is one reason utilities are planning for the largest increase in natural gas-fired plants in over a decade. Buyers of F-Class, advanced-class and aeroderivative gas turbines are reportedly experiencing lead times not seen since the gas boom of the early 2000s.

AEP’s Public Service Company of Oklahoma (PSO) plans to seek regulatory approval for the purchase of Green Country, a 795 MW natural gas combined-cycle plant in Jenks, Oklahoma. Subject to approval, PSO expects to close on the transaction by June 30, 2025.

On impact of environmental regulations

In the utility’s 10-Q, AEP said federal rules and environmental control requirements would impact the utility’s generation fleet. AEP noted EPA’s suite of measures to crack down on pollution from fossil-fired plants.

Under one of the measures, coal-fired plants which plan to stay open beyond 2039 would have to reduce or capture 90% of their carbon dioxide emissions by 2032. As of June 30, 2024, AEP said approximately 46% of the company’s owned generating capacity was coal-fired.

AEP said it is in the early stages of identifying the best strategy for complying with the rule while ensuring resource adequacy.

The company, along with other utilities, states, companies and trade associations challenged the rule and requested a stay, which was denied by the D.C. Circuit Court of Appeals.

AEP and other utilities have now filed applications with the United States Supreme Court seeking an emergency stay.

Terry Schoenborn has certainly noticed this renewed interest, which he attributes to projected rising electricity demand from data centers and manufacturing.

“In the last 10 years, there hasn’t been as many new greenfield sites going in, but we’re starting to see some of that activity pick up,” said Schoenborn, who is Senior Vice President of Operations and Maintenance (O&M) at EthosEnergy.

This was just one trend discussed in a recent interview with Schoenborn, who highlighted the evolving market dynamics that are shaping plant O&M.

Plants are changing hands

Schoenborn told us there is a lot of Merger & Acquisition (M&A) activity right now in the power generation market, driven by factors like the Inflation Reduction Act and a renewed interest in reliable gas capacity.

“I just think it’s a dynamic market right now,” he said, “and there are opportunities for investors to take advantage.”

As assets flip, adaptation is important for EthosEnergy, which has operated more than 100 generation facilities (mostly gas) dating back to its inception in 2014.

For example, the company was recently awarded O&M contracts for six natural gas combined-cycle (NGCC) plants in Mexico. This was shortly after the Iberdrola-owned facilities were sold to private equity firm Mexico Infrastructure Partners (MIP).

When EthosEnergy takes over O&M for multiple, let alone six plants at once, the process of scaling up manpower and training can be challenging. The work starts with assessing the condition and staffing levels of those facilities.

Schoenborn said some plants EthosEnergy takes on are in good condition and others require more care and effort.

“We may have to have more resources, spend time at that plant to get it up to speed or the level that our customers expect,” said Schoenborn.

A plant’s condition often depends on where it is in its lifecycle and how much a customer thinks it can extract out of it, he said.

“It could be just as simple as, if the customer knew they were selling the asset, they are probably not going to invest as much into it,” he said. “So it just gets into disrepair.”

While EthosEnergy has close to 800 employees in its O&M division, the company has brought in approximately 100-150 just in the last two years as it has taken on new contracts.

The importance of peaking power

Gas turbines are taking an increasingly important role as peaking power sources, since they can be ramped up and down quickly to meet demand spikes, filling in gaps when renewable resources are not generating electricity.

For that reason EthosEnergy earlier this year launched its Houston-based Performance Center, where the company monitors generators in 20 different countries.

The center combines 24/7 remote start-stop capabilities with monitoring and diagnostics. EthosEnergy operators control start-stop operations through encrypted cyber-secure VPN technology. They can use video surveillance to monitor a customer’s assets using real-time thermal imaging.

Schoenborn noted a lot of peaking plants with low capacity factors are fully-staffed and operate almost on-call. He said using the performance center is a good solution to optimize the reliability of these assets that sit idle most of the time, and from a cost perspective.

“We felt like it was a something we needed to have to play in this market,” Schoenborn told us.

Schoenborn said the capabilities of the performance center have opened up new discussions with customers, particularly as the energy transition may run slower than anticipated.

As customers target aggressive net-zero goals, EthosEnergy works with them to develop realistic maintenance strategies. Schoenborn emphasized the importance of maintaining reliability without overinvesting in assets that could be repurposed or shut down in the near-future.

“How we’re working with them is saying, ‘Let’s really sit down and talk about what maintenance you need to have to make sure you maintain the same level of reliability,’” he said.

Watch the full interview with Terry Schoenborn above.

Following successful permitting, the company plans to build a two-unit, 1,200 MW combined cycle plant in Monroe County. The facility would be on land already owned by Oglethorpe Power and adjacent to the Smarr Energy Facility, another gas-fired plant. Oglethorpe claimed the new addition would be the “highest-performing, lowest-emitting and most efficient natural gas plants in the state.” Total capital investment would be approximately $2 billion, the company reported.

In Talbot County, Oglethorpe would also build a simple-cycle combustion turbine unit at an existing plant. This new approximately 240 MW peaking unit, which would be the seventh at the Talbot Energy Facility, would have dual-fuel capability. The development of this new unit would represent a capital investment of approximately $360 million.

More details on the projects’ construction and timelines would be available after permits are received, Oglethorpe said.

Oglethorpe Power continues activity in Georgia, where it recently acquired Walton County Power, a 465 MW, three-unit combustion turbine generation facility in the city of Monroe. The facility was purchased from Mackinaw Power Holdings, an affiliate of the global investment firm, The Carlyle Group. Financial terms of the transaction were not disclosed.

U.S. natural gas-fired power generation is expected to grow faster than it has in years. Recent Integrated Resource Plans (IRPs) indicate that utilities are planning for the largest increase in gas plants in over a decade, with the years 2028 and 2030 expecting dramatic increases in renewable energy usage to balance and maintain grid reliability.

Natural gas is yet again making headlines for its role in providing reliable power to maintain grid stability.

Amid federal and state mandates driving the sector toward cleaner and more efficient solutions, natural gas has emerged once again as a crucial player in the transition to a more sustainable energy landscape. Recent Integrated Resource Plans (IRPs) indicate that utilities are planning for the largest increase in gas plants in over a decade, with the years 2028 and 2030 expecting dramatic increases in renewable energy usage to balance and maintain grid reliability.

Regulatory drivers aside, the need for energy-dense, dispatchable electricity is fueled by the continuous retirement of coal facilities, the burgeoning of data centers, the rapid development of AI technologies and the onshoring of manufacturing trends. By 2028, the growth of data centers, supercharged by the development of AI, could consume 7.5% of all electricity in the U.S. This calls for an urgent need for the U.S. to enhance its infrastructure to accommodate this significant load growth in addition to what’s currently planned. These factors highlight the challenge that renewable energy sources alone face in supplying the necessary power capacity to meet escalating energy demands. 

The demand for new gas generation builds is back 

Given the prevailing demand, the lifecycle of gas projects is now being significantly prolonged. Essentially, if you haven’t started proactive project planning yet, you may be already running behind.

A reoccurring conversation we’ve been having with customers is about the need to build new gas generation in addition to renewables. With simple-cycle and combined-cycle gas turbines in such high demand, buyers of F-Class, advanced-class and aeroderivative gas turbines are experiencing lead times not seen since the gas boom of the early 2000s.

Historically, the steps for developing a new gas generation project included front-end studies, siting and permitting and interconnecting to the grid before buying the equipment needed for the project. In the current market, securing long-lead equipment and entering the interconnection queue has become the main priority. 

Yes, the gas boom is back. Its resurgence in the market highlights its indispensable role in today’s energy transition. Natural gas facilities can provide the critical path forward to support and solve the challenge of increasing load growth. Nearly half of the coal-generating capacity seen in 2011 is expected to be retired by the end of 2026 as the U.S. continues its sustainable efforts. 

Signs of a booming market for simple-cycle, combined-cycle and recips are prominent across the United States. It may be too early to tell what it will bring and how long it will last, but keep an eye on signs such as lead times for major equipment, craft labor availability and changes in project development processes as indicators of the ongoing longevity of the gas boom. 

About the Author: Joey Mashek is the U.S. sales and strategy director for the Power Group at Burns & McDonnell. With nearly 20 years of experience, he discusses, develops and negotiates generation needs for utilities, independent power producers (IPPs), cooperatives, municipalities and end users across North America.

In 2023, the use of coal-fired generation in PJM fell to 34% of capacity. Yet coal generators were dispatched less frequently last year, contributing 14% of PJM’s generation, while making up 18% of its generating capacity.

By comparison, in 2013, the capacity factor of coal-fired power in the market was 56%, when coal made up 44% of the market’s generation and 38% of its capacity, EIA said.

PJM is the largest wholesale electricity market in the nation and includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and Washington, D.C.

Operating costs of resources are significant factors for PJM and other wholesale electricity markets to determine which plants will run. How much the plant is called on affects operator decisions to keep coal-fired plants open. Other factors influencing dispatch and retirement decisions include local demand, wholesale prices, fuel supply contracts, maintenance costs and debt service.

Competitive pressure from other energy sources, particularly natural gas, has significantly reduced generation from PJM’s coal fleet, increasing retirements. Since 2013, operators have retired about 34 gigawatts (GW) of coal capacity in PJM and switched about 2 GW of coal capacity to other energy sources, mostly natural gas.

Although PJM still has the most independent power producer (IPP) coal capacity in the U.S. (17.6 GW), IPP coal plants accounted for most of the retired coal capacity in PJM since 2013, about 24 GW. As a result, the generation from IPP coal in PJM has fallen more than the generation from regulated facilities, which unlike IPPs, operate with cost recovery that tends to lower financial risk.

In 2023, 11 coal-fired power plants generated over three-quarters of the region’s coal power, operating an average of 330 days a year with only three week-long shutdowns, EIA said. In contrast, the other 22 PJM coal plants operated 175 days on average, with nine shutdowns lasting about a month each.

Coal-fired units, designed for steady-state operation, face higher maintenance costs from frequent startups and shutdowns, influencing their operating strategies and competitiveness in the PJM day-ahead market. Consequently, coal plants might not be selected to operate when competing with other energy sources.

Coal remains PJM’s third-largest energy source, following natural gas and nuclear. However, competitive pressures from natural gas and renewables are leading to planned retirements of nearly 20% of PJM’s coal capacity by 2028. The remaining coal plants will likely continue to show varied run times.

All this is not to say older fossil-fired units within PJM could be retired as soon as possible.

In January PJM asked Talen Energy to delay the retirement of two units at the fossil-fired Herbert A. Wagner Generating Station in Maryland until transmission upgrades are in service.

PJM cited concerns about reliability impacts the retirement of Wagner Units 3 and 4 would cause.

In October, Talen Energy told PJM it planned to retire the 834 MW Wagner plant, which consists of three oil-fired units and a natural gas combustion turbine unit, as of June 1, 2025, citing environmental permitting and economic reasons.

But PJM is urging Talen to wait to retire Units 3 and 4 until the 2028 timeframe, when it said the transmission upgrades would be completed. According to the RTO, these upgrades were part of a solution identified to address reliability violations following the announced retirement of the adjacent 1,295 MW Brandon Shores facility, also owned by Talen and also requested to deactivate on June 1, 2025.

Southeast Texas is experiencing economic and population growth, leading to a “significant” rise in electricity demand that Entergy Texas says has created the need to add 40% more generation capacity to its power grid in four years.

• The Legend Power Station is a 754 MW, $1.46 billion combined-cycle facility that will be located in Port Arthur, Texas. This project would be carbon capture-enabled and feature a hydrogen-capable combustion turbine, the company said.
• The Lone Star Power Station is a 453 MW, $753 million combustion turbine facility that will be located near Cleveland, Texas and would feature a hydrogen-capable combustion turbine.

The proposed generation resources are expected to be in service by 2028, Entergy said. The Public Utility Commission of Texas will consider approval of these power plants in the coming months.

“As Texas continues to grow, so does our need for more dispatchable, reliable power to help businesses in Southeast Texas and across our great state thrive,” said Texas Governor Greg Abbott. “Entergy’s two new power stations will help bolster the electric grid, adding over 1,000 megawatts of generation capacity in four years.”

Entergy Texas’ dispatchable generation application is part of the company’s Southeast Texas Energy Plan, also known as STEP Ahead. The six-step plan aims to add an additional 1,600 MW of generation capacity to the power grid by 2028, transmission to get power where it’s needed and grid-hardening projects to help Southeast Texas withstand extreme weather.

The HRSG market is healthy! According to McCoy Power Reports, 7,975 individual heat recovery steam generator (HRSG) units were installed between 1980 and 2018 for a combined capacity of 555 GW. Since then, another 40 GW of combined cycle plants have come online and the projections are for a lot more. Analyst firm SkyQuest predicts that the HRSG market will be worth $1.1 billion annually by 2030 with a growth rate per year of 3.5% between now and the end of the decade. SkyQuest reports that this is being fueled by surging interest in clean energy solutions and sustainability. Heat recovery is seen as an obvious way to increase the efficiency of gas turbine plants and reduce their environmental impact. Further, modern HRSG designs can lower emissions and ease the maintenance load.

Those procuring HRSGs, therefore, should engage with manufacturers to ensure they obtain the right design – one that fits current needs and is set up to meet future performance and regulatory demands. That entails design customization. There is no cookie-cutter approach to HRSG design.

“Each plant is different, even within fleets that utilize the same gas turbines and have very similar requirements,” said Kevin Slepicka, Vice President of Heat Recovery Boilers at Rentech Boiler Systems.

Some try to fit the facility to the HRSG which may be a little cheaper by specifying standardized HRSG designs. But that rarely aligns appropriately with the space or the workflows of the facility. The recommended approach is to fit the HRSG to the exact needs of the facility.

“A customized design reduces the amount of work that needs to be conducted onsite,” said Slepicka. “It also reduces disruption during the assembly and installation process.”

Custom HRSG are built, preassembled, and tested in the manufacturer’s facility to ensure they meet the specifications of the plant. Once they have been satisfactorily tested, they can then be shipped in pieces to the site. Sending them in pieces simplifies the transportation and installation process. In the case of large HRSGs, it may not even be possible to transport them unless they are broken down into several parts. Parts and components can also be sent in stages to minimize space requirements during installation. As parts are needed, they arrive at the facility and are assembled. That frees up space for more parts to be delivered and, in turn, assembled. A relatively small amount of work is required to combine the parts at the site.

“Design customization is the best way to circumvent space limitations, while providing the facility with equipment that is more closely suited to its needs,” said Slepicka. “As the HRSG was fully assembled and tested by the manufacturer before being disassembled and shipped, final installation and commissioning are much faster.”

These are some of the reasons why many embrace the customized approach. It often makes financial sense to specify an HRSG that exactly fits site requirements. By matching and integrating the system to the plant layout and the combustion turbines selected, it is possible to maximize the efficiency of the units while containing overall costs. 

Case in point: College engineers contacted Rentech to go over their exact needs on how to couple new HRSGs to existing Solar Titan turbines. Instead of ordering a standard HRSG size and then trying to cobble that together with their turbines, they took the time to work with the manufacturer to precisely size the HRSGs to fit their operating, performance and emissions parameters. This entailed many meetings and design revisions, but the result was the installation of HRSGs tailored to their exact needs.

Design with an eye to the future

Designing the HRSG for current requirement may appear smart. Costs can be contained by allowing little margin in terms of drum size, wall thickness, emissions and overall output. But things rarely stay the same for long. It is quite possible that the plant owners may decide they need higher output, lower emissions or wish to introduce changes at a later point. Slepicka recommends a conservative design approach.

For example, a slightly larger drum size and wall thickness than are strictly necessary will save on maintenance costs over the long term while enhancing the longevity of the unit. A larger steam drum prevents water carrying over into the superheater. How? It allows better separation to remove water from the steam before it arrives at the superheater. If feedwater flow is lost, a bigger drum gives the plant operator more time to correct any water issues before steam levels fall. This is far more desirable than scrambling with only a minute or so before the normal operating level on the steam drum falls enough to result in a low-level trip. That can be a disaster in terms of lost production as it can sometimes leave too little time to correct the situation.

“By sizing and building conservatively, warranty problems can be avoided, and sites typically gain far more reliability,” said Slepicka. “However, those that size HRSGs with little margin may pay a little less but at the risk of overall reliability.”

About the Author: Drew Robb has been working as a full-time freelance writer in engineering and technology for the last 25 years. For more information, contact drew@robbeditorial.com.