By Joey Mashek, U.S. Sales and Strategy Director, Energy Group, Burns & McDonnell

The evolving regulatory landscape has presented power generation utilities with a complex choice as they consider large-scale gas generation projects and whether to build simple-cycle or combined-cycle power plants. With the U.S. Environmental Protection Agency’s (EPA) updated New Source Performance Standards (NSPS) for greenhouse gas (GHG) emissions, decision-makers must carefully balance operational efficiency, financial feasibility and output needs, while maintaining regulatory compliance. While results of the recent election and new administration may lead to some uncertainty with NSPS, the rule is currently still in effect.

The EPA’s NSPS aim to reduce greenhouse gas emissions from new and modified gas turbine power plants. Originally set at 1,000 pounds of carbon dioxide (CO2) per megawatt-hour (MWh), the standard under 40 Code of Federal Regulations (CFR) 60 Subpart TTTTa is now 800 pounds per MWh, with a further reduction to 100 pounds per MWh beginning January 2032.

These new standards significantly influence the decision between simple-cycle and combined-cycle plants, as they dictate whether plants can operate as baseload units or must operate at a lower imposed capacity factor if the above limits cannot be met. Adding further complexity, the updated standard introduces the concept of intermediate load facilities, with a required limit of 1,170 pounds per MWh and a capacity factor limit of 40%.

Combined-Cycle plants: High-efficiency, higher cost

Combined-cycle gas plants have traditionally been preferred as a baseload technology due to their higher efficiency. These plants utilize both a gas turbine and a steam turbine, significantly improving fuel efficiency compared to simple-cycle setups. While they are more expensive up front, their main advantage is generating more electricity from the same amount of fuel (which also results in a lower CO2 per MWh emissions rate).

However, complying with the upcoming limit of 100 pounds per MWh will require future baseload facilities to incur significant additional costs to mitigate carbon emissions, most likely through CCUS technology. CCUS technology also requires a large amount of auxiliary power, which would offset some of the traditional efficiency advantage of combined-cycle plants. For example, a 1×1 J-class combined-cycle plant with CCUS might generate roughly 750 megawatts (MW) of capacity with duct-firing but the auxiliary power requirements associated with CCUS might reduce the effective output to about 600 MW. While employing CCUS would allow the plant to continue operating as an unrestricted baseload facility, the economic impact of deploying carbon capture must be considered.

Alternately, utilities could forego the investment in CCUS and opt to build combined-cycle plants as intermediate load facilities, which then would be limited to a 40% capacity factor under the current rules. This decision would sacrifice a significant portion of the facilities’ potential energy production each year.

Simple-Cycle plants: Flexibility at a lower cost with trade-offs

Simple-cycle gas plants offer different advantages and trade-offs. They are generally cheaper to build and operate, with a less complex design and lower initial investment. Simple cycle plants are often used for peaking power, making them an attractive option for utilities needing to respond quickly to fluctuating demand.

From an emissions perspective, modern J-Class combustion turbines can meet the 1,170 pounds per MWh limit on their own. Given their lower output and efficiency, utilities are unlikely to invest in CCUS technology behind simple-cycle engines, which would put them in the intermediate load category.

In the case of simple-cycle plants, decision-makers must evaluate the levelized cost of electricity over the life of the facility. Simple-cycle plants have lower up-front costs, but efficiency would still be less than that of combined-cycle plants (even with CCUS), leading to higher fuel expenses over time. Utilities need to weigh whether the reduced initial investment would offset potentially higher operational costs, especially with fluctuating fuel prices.

A situational decision: Balancing needs and constraints

The choice between simple-cycle and combined-cycle gas plants is situational, depending on several unique factors for each project. For utilities seeking higher efficiency and baseload power, combined-cycle plants with carbon capture may be ideal, despite higher up-front costs. Conversely, utilities prioritizing flexibility and lower initial costs may find simple-cycle plants more advantageous for covering peak demand. Capacity needs are critical to the decision, and under the current rules there are more options to consider than ever before.

As an example, if a utility needs approximately 600 megawatts (or 5,250 gigawatt-hours per year) of replacement generation, a combined-cycle setup could achieve this with fewer units and greater efficiency, while a simple-cycle approach would require multiple smaller units. The decision also depends on the utility’s anticipated emissions profile and willingness to invest in emissions-reducing technologies, like CCUS.

Additionally, utilities must consider other constraints, such as land availability, project timelines and financial resources, when making a decision. As lead times for acquiring equipment increase and regulatory pressures grow, it is essential to begin the decision-making process early and to thoroughly evaluate all variables.

Navigating complex choices

Unfortunately, there is not a clear choice between simple-cycle and combined-cycle gas plants under the updated NSPS. The decision depends on each utility’s specific needs, priorities and constraints. Combined-cycle plants offer higher efficiency and baseload capacity but come with significant costs, especially when incorporating carbon capture. Simple-cycle plants are more economical upfront but may struggle to meet future emissions standards.

Ultimately, utilities must balance efficiency, cost and compliance while staying attuned to regulatory changes. Engaging with peers, staying informed about technological advancements, and starting early are critical steps in successfully navigating these complex decisions.

Comparison chart: Simple-Cycle vs. Combined-Cycle gas plants

Originally published by Burns & McDonnell. See original article here.

The Korea-based Hanwha Power Systems is an industrial compressor supplier and a provider of sCO2 power generation systems and hydrogen/ammonia gas turbine solutions. Hanwha Power Systems plans to secure this sCO2 commercialization project as a foundation for expanding its sCO2 power generation business in the North American pipeline market.

The MOU outlines the installation of an sCO2 power generation system at a compressor station owned and operated by TC Energy in the state of West Virginia. The system is intended to recover the unused waste heat exhaust from a gas turbine compressor set, and provide a lower cost, carbon free renewable generation solution.

sCO2is a fluid that, under conditions exceeding 31°C temperature and 74 bar pressure, exhibits both the properties of a liquid and a gas. The sCO2 power generation system combines this characteristic of supercritical CO2 with Hanwha Power Systems’ integrally geared turbomachinery technology, maintaining the sCO2 in a closed-loop system.

Power cycles based on super-critical carbon dioxide (sCO₂) as the working fluid have the potential to yield higher thermal efficiencies at lower capital cost than state-of-the-art steam-based power cycles, according to the U.S. Department of Energy (DOE). When carbon dioxide (CO₂) is held above its critical temperature and pressure, it acts like a gas yet has the density of a liquid. In this supercritical state, small changes in temperature or pressure cause dramatic shifts in density – making sCO₂ a highly efficient working fluid to generate power.

“This MOU with TC Energy brings us one step closer to the successful commercialization of sCO2 power generation systems,” said Justin (Koo Yung) Lee, CEO of Hanwha Power Systems. “We will continue to contribute to carbon reduction in the oil and gas market by successfully expanding the application of sCO2 power generation systems across a wide range of compressor stations.”

Earlier this year, the Supercritical Transformational Electric Power, or “STEP” Demo pilot plant generated electricity for the first time using sCO₂ power cycles. The $169 million, 10 MW sCO₂ facility at the Institute in San Antonio is demonstrating the next- technology in a project led by GTI Energy. Partners include SwRI, GE Vernova, the U.S. Department of Energy/National Energy Technology Laboratory (U.S. DOE/NETL) and several other industry participants.

For the first time, SwRI said the pilot plant’s turbine achieved its full speed of 27,000 RPM at an operating temperature of 260°C and generated a small amount of power. The Insitute said the STEP team would slowly ramp up the operating temperature to 500°C and generate 5 MWe of power. After completion of this first test configuration, the STEP Demo project entered its final phase, where the pilot plant would be reconfigured to boost its efficiency and overall energy output. SwRI said this modification requires the installation of new equipment, as well as a new commission and test phase that would continue into 2025 until the pilot plant is running at full power. At the end of its final phase, the pilot plant would produce 10 MWe hourly.

The STEP Demo pilot plant is one of the largest demonstration facilities in the world for sCO₂ technology. However, the pilot plant’s sCO₂ turbomachinery is approximately one-tenth the size of conventional power plant components, which shrinks the physical footprint and construction cost of any new facilities.

The demonstration, which EPRI and TVA call the first U.S. test and the “largest conducted in the world,” was performed on a 76-megawatt (MW) dual-fuel natural gas/diesel unit at TVA’s Johnsonville site in Tennessee.

EPRI collaborated with TVA’s Innovation & Research and Johnsonville Operations teams to evaluate the gas turbine across a range of operating conditions, including at full load with no turbine or control system modifications. The companies argue the test demonstrated how renewable diesel could support near-term decarbonization of dispatchable thermal power generation assets, providing on-demand power with up to 75% fewer lifecycle greenhouse gas emissions compared to conventional diesel.

Renewable diesel is a fuel made from fats and oils, such as soybean oil or canola oil, and is processed to be chemically the same as petroleum diesel. It also meets the ASTM D975 specification for petroleum in the United States. Renewable diesel can be used as a replacement fuel or blended with any amount of petroleum diesel.

The past several years have seen “tremendous growth” in new renewable diesel plants, the Department of Energy (DOE) says, many of which are located in western U.S. states and were converted from existing petroleum refineries. The fuel is used primarily in California because of economic benefits provided under the Low Carbon Fuel Standard.

“As growing electricity demand underscores the continued need for dispatchable power generation, low-carbon fuels present a potential pathway for existing units to contribute to net-zero goals,” said Neva Espinoza, EPRI senior vice president of Energy Supply and Low-Carbon Resources and chief generation officer. “Collaboratively demonstrating emerging technologies and approaches at scale is key to accelerating a reliable and affordable energy transition.”

EPRI plans to soon publish a report outlining the demonstration’s results as part of the Low-Carbon Resources Initiative (LCRI) to both share details and learnings with industry and other stakeholders. The companies argue the demonstration could have industry implications for peaking units.

Woodward is a global provider of design, manufacture, and service of energy conversion and control solutions for the aerospace and industrial equipment markets. GE Vernova said the transaction is an “important component” of its strategy of investing in U.S. manufacturing and strengthening its domestic supply chain.

Under the terms of the agreement, and subject to meeting all closing terms and conditions, GE Vernova is expected to acquire all assets related to Woodward’s Greenville site, which today is nearly entirely dedicated to supplying parts and services to GE Vernova’s gas turbine manufacturing operations. GE Vernova has had a presence in the Greenville area for more than 50 years with current operations including manufacturing and testing gas turbines, providing global engineering support and other activities.

“We are excited to acquire and integrate this critical capability for our domestic supply chain as we continue to see increasing demand for our heavy-duty gas turbines and upgrades globally,” said Eric Gray, President & CEO, GE Vernova’s Gas Power business. “Welcoming these experts to our Greenville, S.C., team will further enable us to address this growing demand from our customers and meet the electrification needs of our country while serving as an indicator of our commitment to the industry and the community.”

“We are pleased to sign this agreement with GE Vernova,” said Chip Blankenship, Chairman and CEO of Woodward. “This targeted transaction is good for our customer and members and will allow us to focus resources on products that will drive the most value as part of Woodward. I am grateful for our Greenville members’ longtime dedication to Woodward and to serving the customer. They will have opportunities to continue their great work as GE Vernova takes on ownership of the operations.”

While financial terms of the acquisition are not being made public, the transaction is expected to close in early 2025, subject to certain closing conditions.

Balico, LLC recently submitted an application to rezone more than 2,200 acres for the proposed campus.

The campus would have a “dedicated, 3,500 megawatt gas-fired power source,” according to a press release issued by Balico.

According to renderings submitted to the Pittsylvania County Planning Commission, the project would feature 15 30-MW Mitsubishi Power FT8 MOBILEPAC aeroderivative gas turbines.

“This power source would use the most advanced turbine technologies available and take advantage of the existing Mountain Valley Pipeline Infrastructure in the Banister District,” Balico said in its release.

The renderings also note a second phase that would include at least one Mitsubishi Power M501JAC gas turbine, in a simple cycle configuration. A “stack” is noted on the renderings as being 187 feet tall, meaning more turbines could be added. The M501JAC generates 330 MW to 453 MW in standalone configuration, according to Mitsubishi Power.

The campus would be comprised of more than 70 data center buildings, each spanning 394,000 square feet and reaching 40 feet tall. The site proposes buried power lines, along with 13 acres for a switchyard, substation and wastewater treatment facility.

The proposed project is expected to face steep opposition from local residents. Balico plans to hold meetings tonight and tomorrow for the community to provide feedback.

Balico was also the developer for the proposed 1,600 MW Chickahominy Power Plant in Charles City County, Virginia. The project was eventually abandoned. Balico is the parent company of Chickahominy Power.

“Unfortunately, opposition from outside interests and regulations, largely advanced by the renewable energy industry and state legislators that supported them, made it impossible to deliver natural gas to the site,” reads a message on the Chickahominy Power website.

Facing grid connection delays and competition for power in certain markets, some data center developers plan to build onsite natural gas-fired generation. We recently reported that pipeline companies are increasingly working with data center companies seeking direct pipeline connections for onsite gas power.

The demonstration was carried out at the RWG facility in Aberdeen, UK, which provides maintenance, repair and overhaul services for Siemens Energy industrial aero-derivative gas generators and power turbines.

The SGT-A35 gas turbine was originally introduced to the market in the 1970s. Siemens Energy used 3D printing to manufacture the new components required for methanol fuel conversion, demonstrating the potential for retrofitting existing gas turbines for decarbonized operations.

Charlie Booth, project manager, NZTC commented in a statement: “Methanol’s unique properties make it an exceptional choice as a retrofittable, low-carbon alternative fuel and it is great that we are able to showcase the opportunity that exists in adapting existing infrastructure to meet our net zero targets and energy needs.”

The demonstrations are being delivered through NZTC’s Alternative Fuel for Gas Turbines project, one of seven projects under NZTC’s Net Zero Technology Transition Program (NZTTP).

This achievement builds on NZTC and Siemens Energy’s 2023 demonstration on the less powerful SGT-A20 turbine running on bio-methanol. This test showed CO2 emissions could be reduced by up to 75% when compared to conventional fuels.

Benefits of methanol

According to NZTC, one of the key benefits of methanol as an alternative to fossil fuels is that is can be produced from a variety of feedstocks. These include blue methanol, using carbon capture and storage, as well as bio-methanol or green hydrogen and captured CO2 (e-methanol).

Methanol produced from natural gas can reduce CO2 emissions by 10% compared to traditional liquid fuels and renewable methanol can cut CO2 emissions by up to 95%.

Methanol also reduces other emissions including NOx, PM, SO2 and smoke.

Originally published by Pamela Largue in Power Engineering International.

The two units, one in Sumter County and the other in Reno County, would come online in 2029 and 2030, respectively. The plants would cost more than $2 billion total to build and would operate for 40 years.

Utility officials said the new units would support reliability as the region faces significant electricity demand growth. They said dispatchable natural gas would complement the utility’s growing number of wind and solar resources.

Demand for electricity is rising in much of the U.S., driven by new manufacturing facilities for batteries and semiconductor chips, as well as data centers.

“Kansas is experiencing record economic growth, and Evergy is prepared to deliver the reliable, affordable, and sustainable energy needed,” said Evergy President David Campbell.

Earlier this year, Evergy updated its Integrated Resource Plan, projecting an additional 1,900 MW of capacity need over the next 20 years compared to just one year earlier in 2023. During that same period, Evergy would retire more than 4,500 MW of coal generation.

Over the next 20 years, Evergy projects it will need to add 5,100 MW of renewable energy from wind and solar and 6,000 MW of firm, dispatchable generation – including 2,500 MW of new natural gas generation across 2029-2032.

Today, almost half of the power generated by Evergy comes from emission-free sources, including the Wolf Creek nuclear plant and renewable energy sources. The company has reduced its carbon emissions by more than 50% since 2005, progressing towards the interim goal of a 70% reduction in owned generation carbon emissions from 2005 levels by 2030.

Evergy is targeting to achieve net-zero carbon equivalent emissions, for scope 1 and 2, by 2045 through the transition of its generation fleet. Achieving these emissions reductions is expected to be dependent on enabling technologies and supportive policies and regulations, among other external factors, Evergy said,

On August 2, 2024, 7.1 million MWh of natural gas-fired electricity was generated in the United States, 6.8% more than the previous summer’s record set on July 28, 2023. Nine out of the ten days with the most U.S. natural gas-fired electricity generation on record occurred in the summer of 2024; of those, six occurred in August 2024. Overall electricity generation for the summer (June–August) of 2024 was up by 3% from summer 2023. The daily average for natural gas-fired electricity generation for the summer also increased 3% to 5.9 million MWh.

Reasons for increased U.S. natural gas-fired electricity generation included hotter weather, low natural gas prices, the addition of new combined-cycle generating capacity, and increased generator capacity factors, EIA said.

Just weeks before August 2, U.S. power plant operators generated 6.9 million MWh of electricity from natural gas on a daily basis in the lower 48 states on July 9, 2024, the U.S. Energy Energy Information Administration (EIA) said, which was “probably” the most in history at the time, and definitely the most since at least January 1, 2019, when the EIA began to collect hourly data about natural gas generation.

The spike in natural gas-fired generation on July 9 was because of both high temperatures across most of the country and a steep drop in wind generation. According to the National Weather Service, most of the U.S. experienced temperatures well above average on July 9, 2024., with particularly high temperatures on the West Coast and East Coast.

Additionally, U.S. electricity generation is expected to increase by 3% – 121 billion kilowatthours (BkWh) – this year compared to 2023, largely driven by solar power and natural gas, according to Short-Term Energy Outlook analysis from EIA.

The increase in natural gas generation was driven by low fuel costs and higher overall electricity demand, EIA said. A few new combined-cycle plants have come online in the past year, but the new capacity has been offset by other plants’ retirements, EIA added. Forecast natural gas generation in 2024 is increasing the most in the Midwest (up 11 BkWh) and in the Mid-Atlantic (up 9 BkWh). EIA expects less natural gas generation in California this year (down 6 BkWh) and in the Southwest (down 2 BkWh), in response to large increases in solar generation.

The combined-cycle facility began commercial operations in 2007, and its power is sold to the Electric Reliability Council of Texas (ERCOT).

Calpine has recently been making moves to develop or buy new power generation in multiple regions.

After seeing positive market signals in Texas, Calpine began redevelopment efforts in the Lonestar State last year. The company is reportedly on track to add over 1,000 MW of generation to its Texas fleet over the next few years.

Additionally, in response to skyrocketing energy prices within PJM Interconnection, Calpine plans to explore multiple new locations for generation capacity, particularly in Ohio and Pennsylvania. The company also said it would explore a potential expansion of its existing fleet. Over the last decade, Calpine has brought online 1,600 MW of new gas-fired generation within PJM territory. PJM is the largest grid operator in the U.S.

The company’s fleet is also involved in multiple carbon capture demonstrations.

Earlier this year, Calpine announced that it executed a cost share agreement with the U.S. Department of Energy (DOE) Office of Clean Energy Demonstrations (OCED) for a full-scale carbon capture demonstration project at its Baytown Energy Center near Houston.

The Baytown Decarbonization Project is designed to capture 95% of CO2 emissions from two of the three turbines at the company’s Baytown Energy Facility, enabling the facility to produce electricity as well as steam for collocated industrial use. Calpine began the first phase of the DOE cooperative agreement, with other phases to follow upon successful completion of phase one and finalization of plans for subsequent phases.

In addition to the company’s Baytown project, Calpine continues to advance its similarly sized Sutter Decarbonization Project in California, for which it also recently executed a cost share agreement with OCED. The Sutter Decarbonization Project would be designed to capture 95% of carbon emissions from Sutter Energy Center. Calpine now plans to begin the first phase of the DOE cooperative agreement, which will support the engineering and design of the project. Sutter Energy Center is located in Yuba City, California. The 550 MW combined-cycle plant became commercially operable in 2001.

Gas engines show advantages in their single cycle efficiency value (figure 2) and a very fast startup performance. Photo courtesy: MAN Diesel & Turbo

The transforming energy market shifts focus to reducing power plant environmental impacts, where financial and technical benefits improve competitiveness. This leads to an increased share of renewable power generation and also a focus on highly efficient, flexible and cleaner conventional power plants. Consumer perception and recent regulations have led to some coal and oil fired power plants to be shut down, depending on changing weather conditions, are not consistent and require very fast power generation capacity response to ensure a stable grid.

Power plant operators and investors looking to operate on natural gas have the choice between gas turbines and pure gas or pilot oil fueled engines, the latter technologies enjoying a recent and significant development. Engine power outputs now exceed 20 MW and benefit from increasing efficiency. Combined cycle engine based power plants emerge in the market place. Exceeding 200 MW becomes more common.

This article presents specific decision criteria that highlight key differences between applications and site performance of both technologies in gas-fired power plants.

Some obvious criteria that follow allude to the paper’s content: Single cycle efficiency, an expedient fats startup performance (within 3 minutes), and reduces load operation (below 25 percent) benefit the support of fluctuating renewable power generation. Low gas pressure requirements benefit distributed power projects. A project’s heat energy and electricity balance will favor a specific technology and site specific conditions and will also influence the decision process.

Power plant projects below 400MW require modernized decision criteria when it comes to selecting engines and/or turbines. This article offers guidance in a more objective choice between both technologies.

Technical Parameters Comparison

In any power plant technology comparison the list of parameters needing appropriate consideration includes at a minimum:

• Power plant load profile/start up time
• Start-up time
• Plant life cycle cost
• Project site ambient air temperature
• Plant altitude
• Agine/maintenance over operating time
• Reliability/availability
• Efficiency
• Power to heat ratio
• Dual Fuel requirements/capabilities
• Overall plant footprint

Most of these parameters impose severe impact when considering technical concepts or commercial feasibility and therefore are discussed in more detail.

Startup Time Comparison – 1

Electrical Efficiency Comparison at MCR for Single Units – 2

Power Plant Load Profile/Start-Up Time

The traditional load scenarios are:

• Base Load – with dominant constant load phases and basically continuous operation
• Intermediate – with more fluctuating load phases needed across a significant amount of operating hours
• Peak Load – with quick need of extra power at fast ramp-up rates

With an increased amount of fluctuating renewable power generation being fed to the grids sometimes during the day the demand may possibly be generated from renewable sources. However, depending on weather conditions on other days or at other times during the day, generation from such sources often remains insufficient. Sub sequentially required back-up, or reserve-means of power generation, therefore are a factual necessity. Many existing thermal plants, however, were designed for more or less continuous high loads. Presuming renewable power generation being prioritized when feeding the grid, the existing thermal plants can no longer do what they were intended to, but have to consider a stand-by position with decreasing annual operating hours at highly fluctuating load requirements. As a consequence, intermediate and peak load scenarios with the need of frequent fast equipment start for limited operating times of few hours only become a common requirement.

Gas engines show advantages in their single cycle efficiency value (figure 2) and a very fast startup performance. Multiple equipment starts per day are possible and reduced load operation at 25 percent or even lower are common features of modern engines. One hundred percent of output can be achieved under five minutes, starting from warm standby condition, compared to 30 minutes for a turbine under the same conditions. Such technological features are tentatively better suited to match the modern industry and energy market demands as described above.

Figure 1 shows a typical comparison of a gas engine plant start-up versus gas turbine combined cycle, both from warm conditions i.e. prior shut down of more than eight hours.

Gas Turbines, however, demonstrate superior performance under a relatively continuous stable load regime.

Tentative Plant Life Cycle Cost

While life cycle costs of any thermal power plant are vastly dependent on fuel cost, appropriate reflection of the expected load profile need to be incorporated into any comparison of various technological concepts. The number of full load hours and especially the increasing amount of part load hours need to be forecasted as precise as possible, however strictly individually. Conversion to full load equivalent hours tentatively includes the risk of ignoring the efficiency losses factually occurring under part load operation. Whenever limited overall operating hours and part load phases or even multiple starts and stops dominate the load profile, a GT and/or combined cycle option may disqualify. Gas engine maintenance costs often turn out to be lower than those for turbines, depending on actual project parameters.

Project Site Ambient Air Temperature

For gas turbines, maximum power is often defined by maximum component temperature in the turbine, permissible forces to the shaft, or the generator frame size. For gas engines, maximum cooling water temperature often is the limiting factor. The gas engine output is hardly affected by increases in ambient air temperature and stays at 100 percent up to around 38OC. When running a gas turbine, however, power output continuously decreases.

Plant Altitude over Sea Level

Figure 3 compares the plant altitude effects on the performance of gas engines versus gas turbines. Again, the diagram duly takes into account the different “regular” ISO conditions for gas engines as shown in the diagrams legend. The equipment behavior differs dramatically. While engines offer full load output at any altitude up to 1,000 meter above sea level, the industrial gas turbine’s output decreases by 10 percent.

Effect of Altitude Comparison – 3

Aging/Maintenance over Operating Time

The aging behavior of the different technologies can be seen by examining the “heat rate” evolution as a continuously increasing factor in between maintenance periods as compared in Figure 4. Furthermore, and “peaking” demand vs. a regular baseload operation has additional effects on gas turbines because every gas turbine start accounts for some extra operating hours being added to the counter. Operating hours counting of gas engines is not affected by multiple starts. Subsequently peaking operation with gas turbines will exaggerate gas turbine maintenance costs with overhaul activities appearing earlier.

Plant Efficiency

Comparing both technologies under the same plant load, in single or combined cycle, helps to understand the superior efficiency of the gas engines over operating time.

If we add the particular consideration of part load efficiencies for a single machine, we can clearly see the efficiency difference between the competing technologies where the gas engines are significantly less affected by reduced load demands.

Power Plant Footprint & Civil Works

Gas Engines are now available in up to 20.2MWe where a power plant of 100MW requires an area of around 60mx60m. A gas turbine power plant can achieve ~100MW output by installing 2x50MW units, which will install with a more compact foot print at subsequently reduced civil works cost.

Aging Effect Comparison – 4

In general, with gas turbines, the total installed masses are smaller. This is an advantage for transportation into remote areas and installation. A gas turbine power plant requires fewer auxiliary systems, as well as no, or fewer, additional exhaust devices. Pure machine weight-related issues should be considered as well where gas turbines benefit from much lower equipment weight than gas engines.

Summary

Many technical and commercial parameters need due consideration when selecting the proper gas power plant technology in accordane with the actual project parameters. Such parameters and other required data will be presented and further discussed as part of the convention’s presentation.

In general, the reciprocating four-stroke gas engines show advantages in single cycle efficiency, high efficient part load operation and a very fast startup performance. Reduced load operation at 25 percent or lower is also possible if needed. This makes gas engines ideally suited to compensate for the fluctuating renewable power generation.

Low gas admission pressure requirements for engines (6 bars comparing to around 21 – 40 bar for turbines) reduces infrastructure costs and risks and allows placing of such generators close to the consumers. Therefore engine based power generation also supports the decentralized power generation concepts, as well as reducing CAPEX and OPEX by eliminating the need of fuel gas compression.

In case thermal energy can be utilized, an overall plant efficiency beyond 90% can be achieved.

The engine technology is furthermore less sensitive to hot ambient temperatures and altitude in comparison to gas turbines. Base load gas turbine combined cycle power plants of >400 MW can provide full load efficiency of >60 percent. When running many thousand full load hours annually, such big plants clearly outperform any gas engine configuration as a function of reduced fuel spending. Gas turbine plants typically also benefit from a smaller footprint compared to engine based power plants.

Finally, gas turbine combined cycle plants may also take advantage from any location being incorporated in industrial areas by selling steam to neighbor industries. However, the same logic applies to a potential gas engine plant in CHP configuration. Thermal energy provision to neighbor industries or any district heating provider with heat being provided by means of hot water efficiently generated from advanced heat recovery systems can create extra profitability.

In the power range up to ~200-300 MW we see an interesting field in which both technologies can be fairly considered.

Author

At the time this article was written, Ralf Grosshauser was the senior vice president of MAN Diesel & Turbo SE. Grosshauser now serves as CEO of Thermamax GmbH…

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Decarbonization, Optimizing Plant Performance, the Future of Electricity, the New Energy Mix (CHP, microgrids) and Trends in Conventional Power are all tracks planned for POWERGEN International happening Jan. 26-28 in Dallas. The POWERGEN Call for Speakers is now open and seeking session ideas around projects and case studies.