Coal, Gas, Policy & Regulations

The Future of Gas-Fired Generation in North America

Issue 7 and Volume 119.

By Russell Ray, Chief Editor

The 550-MW El Segundo Energy Center consumes 30 percent less natural gas than the units it replaced and uses rapid-response technology to provide critical backup power for intermittent forms of generation such as wind and solar power. The new two-unit combined cycle cplant, owned and operated by NRG Energy, uses “Flex-Plant” technology from Siemens. Each unit features a SGT6-5000F gas turbine. Photo courtesy: Siemens

Natural gas-fired generation is projected to grow 3.1 percent a year through 2038. At that rate, more than 340,000 MW of gas-fired capacity will be added to the U.S. grid by then. Enhancing the reliability and extending the life of these assets is paramount as power producers turn to gas to supply a larger share of baseload capacity.

According to the U.S. Energy Information Administration’s 2014 Annual Energy Outlook, coal currently accounts for about 41 percent of the nation’s power versus 27 percent from natural gas. But by 2035, the agency anticipates natural gas will be the primary fuel for power generation.

The editors of Power Engineering sat down with three executives to discuss the transition to gas-fired generation in the U.S., the technology, and the operations and maintenance challenges related to a substantial increase in capacity factors for gas-fired plants.

Executives participating in this year’s roundtable discussion on natural gas are: Dan Lee, senior vice president of Fossil and Hydro Generation at American Electric Power; Thomas Alley, vice president of Generation for the Electric Power Research Institute; and Guy DeLeonardo, executive product manager for GE Power & Water.

Guy DeLeonardo
Dan Lee
Tom Alley

What follows is a transcript, edited for style and clarity, of that discussion:

Power Engineering: Several new combined-cycle projects are in some stage of development throughout North America. Describe the market for new gas-fired generation in the U.S. Is the dash for gas alive and well?

Alley: I believe we are still experiencing a robust dash for gas, driven by the favorable economics of building gas plants, confidence in the long term fuel supply, and the regulations that are making the market for coal-fired generation more challenging. The industry has or will close approximately 70 GW of coal generation by the end of 2016. This represents a significant amount of energy and capacity that is retiring from the US electricity market. The retired coal plant capacity in many cases is being replaced by natural gas combined-cycle (NGCC) units. Typically an NGCC plant is easier to site, permit, cheaper to build, has higher efficiency and requires less staff than most other large-scale generation options.

With gas forecasted pricing of $4-$6 per MMBtu (current prices are $1.60~ $2.60 per MMBtu) for the foreseeable future, and CO2 emissions meeting the proposed EPA Section 111(b) new source performance standards for carbon emission limits of 1000 pounds per MWh, NGCC plants are the obvious choice for bulk power generation. I see many organizations heading in this direction. I also see some interest in coal to gas conversion in boilers where infrastructure and pipeline capacity are present.

Lee: While we would agree that any new, centralized power generation in the U.S. in the near-term will likely be fueled with natural gas, we would not necessarily characterize it as a “dash to gas.” Within AEP’s service territory, we continue to see relatively flat forecasted demand, and capacity markets like PJM are simply not providing a clear economic signal for new gas generation. We are aware of newly permitted and proposed natural gas combined-cycle units in the PJM footprint, but “permitted and proposed” does not always result in units being constructed.

Based on a recent PJM study, just 7 percent of the total megawatt capacity of all new generation proposed in PJM between 2000 and 2014 was actually placed in service. It will be interesting to see how the capacity market adjusts after the coal retirements this year and changes to the PJM capacity market from the Capacity Performance proposals (expected to be ruled on by FERC June 9 with the PJM 2018/2019 capacity auction to follow in August.)

DeLeonardo: Drivers of coal retirements and low natural gas prices are fueling the need for both combined cycle and simple cycle capacity additions. GE forecasts half of the orders for grid-connected capacity in North America over the next five years will be gas generation. Especially in the case of the HA gas turbine economics, we are seeing those combined cycle projects displace smaller, higher variable cost assets throughout the U.S. Customers have technically selected 22 of GE’s new 7HA units for power projects in the U.S. in the last year. A technical selection is one of the first steps in developing a new power plant. It means that if the power plant is constructed and commissioned, it will use GE gas turbines. Following technical selection, a developer will proceed with securing financing, permitting and more.

Power Engineering: We’ve seen a substantial increase in capacity factors for gas-fired power plants for a number of reasons. Clearly, power producers are counting on gas to supply a larger share of baseload capacity. As these plants run longer and harder, how important is it for power producers to revisit and adjust their O&M strategies to reflect the actual operation of these plants?

Alley: I would challenge your description of the fossil fleet in terms of “baseload.” Today, I would reserve that description for the nuclear fleet, the only segment of the generation asset mix that regularly experiences long run times at steady-state load. I do agree that it is expected that the gas fleet will experience more operation, but it will be accompanied by frequent starts, load-following, and shutdowns to meet seasonal demands.

Maintenance internals and replacement part intervals for the combustion turbine typically are start-based or hours based, both of which I expect to increase so the frequency of outages and the costs of replacement parts will increase under these operational missions. We can easily predict that O&M costs are expected to increase. Owners of the equipment are wanting to understand the technical bases of inspection intervals and parts replacement intervals to evaluate strategies and opportunities to adjust these intervals to mitigate costs and optimize outages times. Understanding material degradation, improving inspection technologies and developing innovative approaches to parts management are priorities for many operators. This is particularly true for the older classes of turbines that have long-term service agreements that are expiring. EPRI has ongoing R&D to explore new NDE techniques for compressors, turbines and other components. We are also exploring ways to monitor combustion to extract data that can give us insights into the performance of the turbine and also provide early warning of component failure.

Likewise, maintenance costs for the heat recovery steam generator (HRSG) is expected to increase. We already know HRSGs have start-stop challenges to their drain systems, dampers and other components. Strategies to mitigate or reduce damage will become important. The role of instrumentation and monitoring to optimize maintenance strategies and assist staff to make informed decisions will be integrated in the O&M process and become much more important.

EPRI is conducting a pilot project of comprehensive “deep dives” into the technical issues around the changing missions of these assets. The objective is to collect industry experiences and best practices to develop guidance on how individual units can most cost-effectively accommodate new mission profiles.

Lee: Running natural gas-fueled units longer will result in adjusted outage schedules, increased variable O&M costs for things like fuel, chemicals and consumables, and increased fixed O&M costs for additional equipment maintenance related to how the units are operated. However, running a unit at base load may offer some maintenance advantages over cycling the units to follow load. Depending on the actual performance of, and demand on the gas fleet, we will adjust our maintenance activities accordingly, but there is no reason to believe that we could not sustain higher capacity factors on our gas fleet. O&M strategies that might need to be adjusted include winterization, equipment and controls redundancy, and removal of single-point failure liabilities.

DeLeonardo: We see the shift in focus on planned maintenance and in the scope of service agreements for what we call covered maintenance. This includes planning for available spares and overall maintenance event logistics/duration for combustion, hot gas path, and major inspections. From our perspective, we have simplified and packaged how the equipment and systems are assembled/disassembled to enable high availability and capacity factors.

Power Engineering: For the first time since F-Class turbine technology came to dominate the market over 20 years ago, the technology is no longer the leader in North America 60 Hz heavy duty gas turbine (HDGT) sales. Sales of advanced class turbines (typically defined as G-, H-, and J- technologies) have seen greater than 50% year-on-year growth in the past five years. Is this trend here to stay?

Alley: I sense there was hesitation on the part of the industry to embrace the advanced-class machines because of concerns (real or just perceived) about equipment reliability and the high costs of parts and maintenance. More recently, I have seen domestic deployment of the advanced class machines as utilities place more importance on efficiency, and as vendors are accumulating operational experience from the early deployment projects, mainly outside the U.S. I would expect this trend to continue as these new machines demonstrate their reliability and durability.

DeLeonardo: Advanced class economics are compelling even at low fuel prices. So yes, the trend will continue to grow as these offerings bring lower $/kw capital expense and lower variable cost through efficiency. The trend is there globally as well, with an expectation that 50 percent of all gas turbine orders will be in the H class.

Lee: Economic and environmental signals all point to higher efficiencies. Higher efficiency plants produce lower emissions and result in lower fuel costs to the customer. As regulatory agencies and utility commissions challenge utilities to consider the most efficient and most economic options for power generation, we will continue to see a push toward higher efficiency. However, a push toward higher efficiency is governed by the law of diminishing returns, and at some point the cost of achieving higher efficiency probably becomes too great for the incremental benefit. We believe economics can prove favorable for G-, H- and J-class technologies on a project-specific basis, but there likely exists a break point where the costs to incorporate new materials or state-of-the-art components will outweigh the efficiency gain, discouraging investment until the technology costs decline.

Power Engineering: Modern-day gas turbines and combined cycle systems operate at higher temperatures and higher efficiencies. The energy conversion rates for combined cycle plants range from 50 to 61 percent. Is there room for more efficiency improvements?

DeLeonardo: Absolutely, as is the nature with technology. Technologies related to materials, cooling, sealing and combustion continue to advance the ability to withstand the temperatures and pressures needed for over 61 percent efficiency. What is highly inter-related are advances in manufacturing technology as well related to additive technology and the ability to introduce complex passages to improve cooling effectiveness.

Alley: There is room for increasing efficiency but this is directly related to firing temperatures and compressor pressure ratios.

The advanced class combined-cycle units are designed to deliver net efficiencies on a lower heating value basis of ~ 61% with combustor temperatures of ~1600 degrees C and turbine rotor inlet temperatures of ~1425 degrees C. Getting to this point has required advances in metallurgy, thermal barrier coatings and cooling schemes for combustors and turbine blading, as well as improved aerodynamic designs and seals for compressors and turbines. EPRI is hearing of combined-cycle plant designs that will produce up to 65% efficiency, but additional advances are required to accommodate higher temperatures.

Lee: We are likely nearing the practical limits of thermal efficiencies utilizing a conventional steam cycle. However, we are monitoring technological developments around innovative power cycles like Supercritical CO2 and the advanced materials that will handle the high temperatures and pressures that such cycles might demand.

These technologies are still being developed at the bench and lab scale, but could offer significant efficiency improvements to the power generation industry in the 2025-2035 timeframe. Combined heat and power is another way to improve overall plant efficiency by capitalizing on waste heat available from the cycle and could present opportunities on a case-by-case basis for certain natural gas power generation projects

Power Engineering: Describe the need for improvements in the infrastructure for natural gas. If the EPA’s Clean Power Plan is finalized without delay, will the industry be able to achieve a sufficient expansion of pipeline and storage capacity in time?

GE’s 9HA.01 Gas Turbine being aligned into its final position for testing inside GE’s validation test stand at GE’s gas turbine manufacturing plant in Greenville, South Carolina. The final round of testing was completed earlier this year. Photo courtesy: GE Power & Water

Alley: Pipelines like many other energy-related projects can take years to site and construct. Whether pipelines can be built in a timely manner is a regional question based upon the consumption in that region and the capacity of the existing infrastructure. In the case of the U.S. Northeast, I believe that the answer to the questions is no — pipelines in this region of the country already are capacity-constrained during winter peaks, so expansion is needed now.

There are several projects currently under way; the gas pipeline industry is investing billions of dollars to increase pipeline capacity, but most would agree the problem with capacity will get worse if U.S. gas companies increase exports.

Lee: This question should more appropriately be addressed by the natural gas companies. Industry trade press and discussions on the topic suggest that gas companies are addressing these needs and do not anticipate issues, but there is still uncertainty with respect to gas availability and delivery in times of peak energy demand (particularly winter), as well as issues around how the electricity and gas markets interact to secure gas delivery for power generation.

DeLeonardo: In general, there is adequate gas infrastructure, however constrained areas exist which may introduce reliability concerns during extreme events, such as the 2014 polar vortex.

The implementation schedule must include sufficient time to ensure such necessary infrastructure upgrades can be planned, permitted, and constructed.