’s analysis of the market for gas turbine-powered electrical generation for 2020-2029 projects sales totaling $102.33 billion. This is an increase of 6.5% from the sales projection for the 2019-2028 period. In terms of units, the analysis projects worldwide sales of 4,291 gas turbines for electrical power production between 2020 and 2029. This represents an increase of 4.8% over the equivalent figure in last year’s review. This is the first sign in five years of a recovery in the gas turbine electrical power generation market. Efforts by the companies operating in this sector to adapt to the hostile environment are finally bearing fruit.

Despite this improved outlook, 2020 will not be remembered as the year when the recovery started. The worldwide Covid-19 pandemic stole the headlines, shutting down the power generation industry along with much else. The dominant response was to institute a lockdown. Companies sent most workers home. Government policy severely restricted movement and interaction. The effect was to drastically reduce industrial activity for at least three months and possibly much longer.

Yet for all the dramatic scenes of closed stores, empty roads and people either unemployed or working from home, evaluation of the impact of Covid-19 on the market shows that it will only be short term and is already quickly being absorbed. This situation can be summarized by saying that the effect of the virus was to suppress the market in the short term, but to bring about a corresponding enhancement in medium-term recovery.

In the power generation sector, the initial result of the Covid-19 pandemic was a decline in energy demand of between 19% and 21% due to industrial facilities closing operations. This was partly offset by arrangements for staff to continue working from home. As countries adapted to the new environment, electric load declines of 3% to 11% were recorded. Less than half of the reduction is probably attributable to the virus. These developments led the U.S. Energy Information Administration (EIA) to project that a total of 4.9 GW of previously planned capacity expansions will be delayed into at least 2021 or 2022.

Even this may prove to be unduly pessimistic. The situation as it developed throughout 2020 is much more complex than a simple cause-and-effect relationship. At the time of writing, an examination of expenditures and contracts showed that some orders, especially those from government organizations have been brought forward. The U.S. Navy, for example, has brought some warship construction orders forward by three to four months. This appears to have been done to support companies with income during the lockdowns while also providing the resources needed to make their facilities compatible with Covid-19 health and welfare requirements.

Further complicating matters, problems caused by the pandemic may have been contained in the short term. But a longer-term problem is emerging. The power generation gas turbine industry and its clients have coped with the maintenance and support side of operations by running down established stockpiles of components and deferring scheduled maintenance for which parts were scarce or unavailable. The latter, in particular, can only be continued for so long. The consequences from work deferment may echo in unexpected ways for several months or years.

As a direct outcome of the power generation industry recession that started in 2014, all three of the leading companies in the power generation equipment sector – GE, Siemens and Mitsubishi Power – have undertaken major restructuring to reduce costs and rationalize production. In an inevitable result, these companies announced major redundancies.

At present, GE controls some 42.9% of the projected market by value, Siemens 25.7% and Mitsubishi Power 19.5% for a total of 88.1%. Siemens has formed its energy operations into a new consolidated group known as Siemens Energy, which has been spun off as a separate entity. In effect, Siemens has converted itself from a conventional multinational conglomerate into a constellation of three companies. They each operate (and are quoted on the stock market) independently and are subject to strategic guidance from the central holding company. That holding company holds a dominant but not majority shareholding in each of the constellation companies.

GE adopted a different strategy with its Baker Hughes subsidiary. Baker Hughes (no longer BHGE) has rationalized its activities, discontinued marginal and no-longer-viable product lines and streamlined its business. This process was completed when the revived and modernized company was launched as an independent entity. GE retains a non-majority stockholding. This process is normally a prelude to the floated entity being acquired by another company, although the process may take months or years to be completed. It is not yet clear whether this will take place with Baker Hughes.

The former Mitsubishi Hitachi Power Systems (MHPS) was subject to a different process. It had been apparent for some years that the formation of the Mitsubishi-Hitachi joint venture had generated neither the business opportunities nor the technology benefits expected. Both companies were heading in different directions. Opportunities for synergistic growth declined quickly. Representatives of Mitsubishi Heavy Industries interviewed at trade shows made little effort to hide their disillusionment with the benefits of the partnership. In the early months of 2020, MHPS ceased to exist. Mitsubishi Power emerged.

Despite the eruption of the pandemic, the impact of reduced demand, overcapacity, and soft prices will slowly work itself out and a recovery will take place. Covid-19 has extended this recovery later than originally projected. But it will be slightly stronger as projects delayed from 2020 finally get underway. Once the middle- and long-term periods are reached, the industry will be dominated by large combined-cycle facilities in the industrialized nations, notably Japan and countries in Europe and Asia.

All this reflects the current need for more baseload capacity additions, as well as for increases in individual power plant capacity. In the mid- and long-term, escalating demand for electricity supplies will continue to drive worldwide demand for gas turbine-based power plants using the latest technology. As a result, the focus of investment will be on the largest and most expensive category of industrial gas turbines – those with the highest outputs. They can be expected to be procured heavily in areas such as China, North Korea, Vietnam, Indonesia, Thailand, Brazil, and the Middle East.

But analysis of the power generation gas turbine market is being complicated by increasingly complex and more granular market drivers. The primary drivers in today’s environment are neither technical nor economic. They are political and environmental. Environmental objectives of reducing emissions and economizing on the use of fossil-fuel resources are being met by subsidies to promote the deployment of renewable resources and low-emissions fuels. These distort the market and serve to complicate the relationships between energy demand and generation capacity.

The once-simple relationship was: increasing demand for electrical power, which translated into the installation of additional capacity and leading to the installation of gas and steam turbines. Over the last 15 years, however, this simple pattern has fragmented. More recently, a significant proportion of demand has been met by improving efficiency. Modern control systems have also reduced the amount of spinning reserve required as a proportion of baseload capacity. A case could be made that the root of today’s problems could be the progressive change from a simple bilateral relationship between supply and demand to the current, highly complex multilateral relationship.

With so many factors influencing the marketplace, gas turbine procurement is no longer directly related to rising power demands. Instead, the option of procuring additional gas turbines is but one of many that exist. The same effect may be obtained by converting an existing simple-cycle plant to combined cycle through the installation of a heat recovery steam generator (HRSG) and a steam turbine. An indirect approach may be to invest the money that would have been used to procure new power generation facilities in grants to improve domestic energy efficiency and thus reduce power demand. These options are not theoretical; they already exist and account for a steadily rising proportion of power generation capacity.

The modularity and flexibility of smaller turbines as well as their low emissions levels are major advantages promoting their adoption. However, they are being offset by the continued development of diesel engines for hospitals, schools and other standby power applications. Largely as a result of continued application in the personal vehicle market, the new generation of diesels is quieter, has reduced levels of emissions and can burn natural gas as fuel. With these advantages, diesels continue to be viable competitors. Superior operating economics in some cases make them attractive in certain applications.

At the other end of the scale, the power output of large gas turbines continues to increase. While 200 MW was considered a large gas turbine a few years ago, outputs five times that figure are not uncommon. A growing number of large turbines are being deployed with heat recovery units in combined cycle power plants with efficiencies well over 60%.

An examination of output power from gas turbines and their unit cost reveals a non-linear relationship. A 400 MW gas turbine costs significantly less than two 200 MW machines. The difference increases steadily as output rises. Therefore, it is much more economical to use the largest gas turbines when building large, centralized power generation facilities.

Once more, the situation becomes complex. A large centralized power station requires a sophisticated and reliable electrical grid to distribute the generated power. This is not necessarily available in many parts of the world. In such cases, the costs of establishing such a grid must be included within any economic analysis. In some cases, the added capital cost of establishing distributed generating capacity using numerous smaller turbines may be less burdensome than the costs of providing a distribution net.

The same may apply to fuel sourcing. If coal is abundant and the infrastructure to transport it to the point of use already exists, these factors may override the advantages of gas. An example can already be seen in the development of integrated coal gasification plants and the continued procurement of coal-powered steam turbines.

In summary, Covid-19 has brought into focus the extent to which economic analysis of the power generation gas turbine market and its structure extends far beyond a simple consideration of gas turbines themselves. The days are long gone when developments in that market were directly related to changes in demand for power. Trends in power demand are but one factor in a complicated equation wherein many of the variables in play are either subjective or hypothetical. At times, these variables may be unpredictable and arrive from left field. Perhaps the major lesson from 2020, then, is that overall, the three major power generation gas turbine producers have coped relatively well with a complex and unfavorable environment.

Stuart Slade is the Senior Industrial & Marine Gas Turbines Analyst at Forecast International. This article provides data compiled from Forecast’s Platinum 4.0 information and analysis service.

Carter Palmer is an Industrial & Marine Gas Turbine Analyst at Forecast International with a focus on smaller gas turbines and microturbines. For more information, visit: www.forecastinternational.com

Articles

Worldwide Market Report: 2020 proved to be an interesting year for gas turbines

EPA Administrator Andrew Wheeler said he thought the rule could lead to the construction of new coal-fired power plants. Shortly after the rule was published in The Federal Register, a coalition of 29 states, cities and the District of Columbia sued to block ACE’s implementation. It is likely that litigation over this clean air rule, like litigation over the Obama administration’s Clean Power Plan rule, could go all the way to the U.S. Supreme Court.

Deregulatory steps taken by the White House, Department of Energy, Department of Interior and Environmental Protection Agency have loosened regulation of the oil & gas industry. This has helped spur dramatic gains in domestic oil and gas production.

As yet, nothing similar has been achieved in power. Indeed, coal use to generate electricity (by utilities, independent power producers, and commercial and industrial customers) is projected to fall to 538,000 short tons in 2019 and 526,000 short tons in 2020, a decline of about 50% over the last 15 years.

While the fate of ACE may not be known for a year or more, no one has announced plans to build a new coal-fired generator since the draft ACE rule was issued more than a year ago. However, President Trump’s efforts to overturn President Obama’s environmental rule limiting carbon dioxide (CO2) emissions from power plants were welcomed by the National Mining Assn. as well as three major electricity trade groups. Despite the actions of the president and his EPA administrator, energy markets have spoken longer and louder. Nothing in the foreseeable future is expected to change that. Based on the tracking of planned spending in the power industry, we see an even more pronounced version of what has been observed for years: coal being eclipsed by natural gas and renewables as the leading source of new-build electric generation. One piece of good news: developers’ top-line plans to build new electric generation have trended upward in recent years, hovering around 212,000 megawatts (MW) for the three most recent five-year periods, well above the trough of roughly 160,000 MW from the three earlier five-year period.

Not all of this generation capacity will get built. Historically, roughly 25% are either cancelled or delayed in any given year. That average obscures differences between differently fueled power plants: natural gas-fired power plants have lower rates of cancellation or delay than renewable energy plants. Renewable energy generation, mainly solar and wind, is expected to account for 72% of all new-build generation projects scheduled to begin construction between 2020 and 2024. By contrast, renewables were expected to account for about 57% of all new-build generation between 2019 and 2023 in last year’s forecast. Natural gas is expected to be the fuel for approximately 26% of new generation over the 2020–2024 period. Last year, gas was projected to fuel about 41% of all new-build generation constructed between 2019 and 2023. The outlook is clear: U.S. new-build generation over the next five years is expected to be even greener, but less gassy, than in prior five-year assessments. As always, technology, economics and the sentiments of utility regulators play important roles in shaping the long-term outlook for U.S. power generation. Notable this year is the small-but-growing trend among state utility regulators to oppose new gas-fired generation in favor of renewables, distributed generation, battery energy storage projects and customer programs to reduce energy use or shift peak demand periods. Developers even plan to build more new fuel oil-fired generation than coal-fired generation over the next five years.

Coal Mining Employment Source: Federal Reserve Bank of St. Louis

The Federal Reserve Bank of St. Louis uses Bureau of Labor Statistics data to track employment across a range of industries including coal mining. Its most recent depiction of coal-mining employment documents the decline of coal-fired generation in the U.S. Three decades ago, nearly 180,000 people were working in the coal-mining industry. That dropped to about 53,000 in mid-2019.

Coal-mining interests point to the last three years, where employment increased by around 4,000, as evidence that the Trump administration’s commitment to end the “war on coal” has succeeded in staunching the bleeding. Before you can rebuild, mining interests would say, you have to stop the bleeding. U.S. asset owners have closed over 546 coal-fired units representing aggregate generating capacity of about 102,000 MW in the last decade, according to the Energy Information Administration (EIA).

Source: U.S. Energy Information Administration

Operators intend to close another 17,000 MW or so by 2025, the EIA said.Federal environmental regulations like the Cross-State Air Pollution Rule (CSAPR) and the Mercury and Air Toxics Standards (MATS) have played a role in dimming the future of U.S. coal mining and coal-fired generation. But the shale revolution that has unlocked trillions of cubic feet of low-priced natural gas, and continuing improvements in the technologies and economics of renewable generation, also played important roles.

In recent years, different partisan organizations have waged a war of words over “who killed coal?” Some overlook the role that automation played in thinning the employee ranks at coal-mining companies.

All of that notwithstanding, there is only one new-build coal-fired project scheduled to kick off over the next five years: a 75 MW power plant at a magnesium processing plant in Nevada scheduled to begin construction in 2023. That construction kickoff has a low probability of keeping its schedule. Most of the capital invested in the U.S. coal fleet over the next five years will go to in-plant maintenance, environmental compliance, turbine upgrades and the like. Over the next five years, about $7 billion is expected to be spent on these in-plant capital projects.

We expect to see heavy investments by utilities such as Dominion Energy, Northern Indiana Public Service Company (NIPSCO), Santee Cooper, the Tennessee Valley Authority and Vistra Energy as well as operating units of American Electric Power, Berkshire Hathaway Energy, Duke Energy, Entergy, NRG and the Southern Company.

Natural gas is expected to secure a smaller share of the new-build market over the next five years. It will account for about 26% of new-build construction, down sharply from recent years.

State utility regulators’ concerns about the potential over-reliance on gas-fired generation is one reason for the expected drop. In 2019, utility panels in California, Arizona and Indiana rejected utility plans to build gas-fired generation. Regulators in states that toughened their renewable portfolio standard (RPS) or ramped up their greenhouse gas emission-reduction program were called upon to issue decisions that would limit new gas generation. There has been a deceleration over the past year of plans to build new gas-fired generation in the Southeast, Great Lakes, South-west and Northeast regions.

The five-year outlook to build new gas-fired generation slipped slightly in the West Coast, New England and the Mid-Atlantic regions and rose a tad in the Rocky Mountains area. A number of utilities in the Southeast, including Florida Power & Light (FPL), Gulf Power and Tampa Electric have cancelled or pushed back the start of construction for new-build gas-fired generation. FPL has been shuttering older, less efficient fossil plants for years, replacing them with high-efficiency natural gas combined-cycle generation. But it made a turn toward the sun and energy storage during 2019.

Plans to build new renewable energy generation — defined as solar, wind, hydro and other — soared over the last 12 months. There are plans to begin construction on about 131,000 MW of renewable generation over the next five years. That is roughly 72% of all new-build generation. Historically, nearly 33% of renewable generation projects are either cancelled or delayed. Still, the dominance of renew-able energy is an inescapable fact, contained in integrated resource plans (IRPs) from utilities around the country.

New-build solar is expected to account for just over half of the renewable generation built between 2020 and 2024. The economics of renewable energy continue to improve. On a cost per kilo-watt of installed of capacity, wind generation costs have fallen 69% over the last decade, and further reductions are possible, according to a mid-2019 research report from Lawrence Berkeley National Laboratory and the National Renewable Energy Laboratory. Photovoltaic (PV) solar generation costs also have dropped more than 70% over the last decade, according to research from the Solar Energy Industries Association (SEIA) and Wood Mackenzie Power & Renewables. That cost decline has helped fuel dramatic gains and projected gains of PV deployment.

Planned growth for solar PV generation. Source: SEIA/Wood Mackenzie Power & Renewables

In addition to aligning well with environmentally conscious regulators, renewable energy is popular with customers, particularly commercial and industrial (C&I) customers who may be operating under a green supply chain mandate from headquarters. In years past, those directives led to increased purchases of green energy from local utilities, but more recently the drive to go green has meant installation of distributed renewable generation at a C&I customer’s site.

Deloitte’s Resources 2019 Study, released in mid-2019, noted that many U.S. businesses have targets for renewable energy procurement. Customers are driving this trend. The study said a portion of business support for renewable energy procurement is due to consumer demand, with 67% of consumers voicing concerns about climate change and the environment.Businesses, Deloitte wrote, “see a connection between green (resource management programs) and green (financial gain). And more than ever, they see energy procurement as a way to create value, not as a cost.”

Plans to construct new renewable energy generation account for nearly all of the planned generation additions in the Midwest over the next five years. Several areas — the Rocky Mountains, South-west, West Coast and New England regions — expect to have renewable generation account for roughly three-quarters of generation that will be built over the next five years.

The Northeast, too, is poised to increase its reliance on renewable generation. During 2019, New York and New Jersey announced plans to ramp up clean energy plans, that include a healthy dose of offshore wind generation. New York wants to have 9,000 MW of offshore wind generation by 2035; over the summer, it began negotiations with developers of two offshore wind farms totaling 1,696 MW. Under the recently enacted Climate Leadership and Community Protection Act (CLCPA), the state has committed to getting 70% of its electricity from renewable resources by 2030.In mid-2019, New Jersey signed a contract with Danish developer Orsted for 1,100 MW of wind generation located about 15 miles off the coast of Atlantic City. Other states on the East Coast have moved forward with planned offshore wind projects.

But it is important to separate grandiose plans from stubborn reality. Despite its widespread popularity in Europe, where thousands of offshore wind turbines operate, only one offshore wind farm is operating in the U.S.: the 30 MW Block Island project off the coast of Rhode Island, which Orsted spent about $290 million to build. That five-turbine wind farm began operating in late 2016.Plans to build U.S. offshore wind generation typically have been met by pro-longed and vociferous local opposition, which a few years ago doomed the planned $2.5 billion Cape Wind project off the coast of Massachusetts.

Some 24 proposed U.S. offshore wind farms with a total generating capacity of more than 12,000 MW and a total investment value of about $44.4 billion have been cancelled over the last decade. Only days before New York Governor Andrew Cuomo announced that negotiations had begun with two developer teams for 1,696 MW of offshore wind, a different developer abandoned plans to build offshore wind farms off the coast of Long Island. Will states invoke force majeure to override local opposition to offshore wind as well as land-based utility-scale solar farms? It is hard to see how many of those projects will get built otherwise over the next five years.

Only one new nuclear power plant (Blue Castle, Utah) is scheduled to begin construction over the 2020–2024 period. But that two-unit plant, which has a price tag of around $20 billion, has experienced more than a decade of delays, and there are serious doubts that it will ever be built.

Construction of two new units at the Alvin W. Vogtle Nuclear Plant in Georgia continues to chug along, with projected in-service dates of November 2021 (Unit 3) and November 2022 (Unit 4). The addition of two units at Vogtle is about 77% complete, but the costs — an estimated $25 billion to add 2,234 MW of new nuclear capacity — casts a long shadow over other new-build nuclear projects. At least Southern Company and its Vogtle co-owners can reasonably expect to receive electricity for their investments in that project.

No such luck for utilities that tried to add two new nuclear units at the Virgil C. Summer Nuclear Power Station. After spending a reported $9 billion in the project, South Carolina Electric & Gas and Santee Cooper abandoned it a few years back. The only thing it has generated is controversy, as investigations have dogged the two utilities since construction was cancelled in 2017.

Aside from the Blue Castle nuclear project, there are plans to invest about $3.3 billion in small modular reactors (SMR) by the Utah Associated Municipal Power Systems (UAMPS). These are the only new-build nuclear generation projects on the horizon.However, about $9 billion of work at nuclear plants is likely to be spent over the next five years. Most of that is earmarked for decommissioning and demolition (D&D) of shuttered nuclear plants in New Jersey, Vermont, Michigan, Pennsylvania, Massachusetts and Iowa. That book of business may grow once owners of shuttered nuclear plants in California, Nebraska and Florida finalize their D&D plans.

Roughly $1 billion in planned D&D spending for two nuclear plants in Ohio — Perry and Davis-Besse — looks like it will be pushed back. During the summer of 2019, the Ohio legislature passed, and the state’s governor signed, legislation that provided about $1 billion in subsidies over seven years to the plants, owned by a unit of FirstEnergy Corporation. The owner said the plants would be closed if the subsidies did not come through.In addition to nuclear D&D work, other in-plant capital projects in nuclear plants are scheduled to begin between 2020 and 2024. These projects include nuclear refueling, construction of dry cask storage units, steam generator replacements, water system upgrades and controls upgrades.

Battery energy storage systems (BESS) have grown rapidly in recent years, and are expected to grow even faster in the next few years. One reason is the technology’s flexibility. Some call BESS the “Swiss army knife of the energy industry.”

These systems can provide voltage support to the transmission and distribution grid, store renewable energy, relieve overloaded distribution transformers, provide uninterrupted or backup power and operate as part of a microgrid. This asset class is here to stay.

More than 700 MW of BESS have been installed in the U.S. to date, and an additional 4,000 to 7,000 MW should come online by the end of 2022. Roughly 4,000 MW are either under construction now or are expected to begin construction by the end of 2020.

The areas with the most active pursuit of BESS include the West Coast, Southwest, Southeast and the Rocky Mountains.Another factor behind BESS’ dramatic growth trajectory: Order 842 from the Federal Energy Regulatory Commission (FERC), which required battery storage technologies to be used and compensated as a stand-alone resource or in conjunction with other generation resources.

FERC has asked all regional transmission groups to complete a comprehensive review of potential deployments of BESS technologies by the end of 2020, but some groups have asked for an additional year to complete the analytic work.

The U.S. has over 650 MW of microgrids up and running, and another 200 MW are scheduled to go live by the end of 2019. Roughly $1 billion of microgrid construction projects are scheduled to begin construction this year. That $1 billion is a down payment on about $2.85 billion of microgrid projects that are in an early stage of development or plan to begin construction by 2026.

C&I customers, as well as government agencies, are drawn to microgrids for the same reasons they are considering BESS: power reliability and power quality. Manufacturing and service businesses, such as finance, are relying to an ever-greater degree on reliable power. Many define their needs as five nines (99.999% availability).

Driven by burgeoning demand from C&I customers, educational institutions and units of government, the microgrid business could balloon into a $20 billion market by 2026. In recent years, these customers have taken steps to insulate themselves from electric disruptions caused by natural disasters such as wildfires and earth-quakes as well as severe weather like Hurricane Harvey and Superstorm Sandy.

For certain types of customer, cost is less important than staying online 24/7/365. In addition to the autonomy from the grid that microgrids offer, cybersecurity makes them attractive to the military as well as units of federal, state and city governments.

There is a cost, sometimes a hefty one, to these benefits. Depending on which bells and whistles a customer wants, building a microgrid costs between $1.5 million and $3.8 million per installed MW of capacity. Depending on the complexity and scale of a microgrid, costs for controls, software and switching systems have a mean cost of about $155,000 per installed MW of capacity, with a range of $6,200 to $470,000 per installed MW of capacity.

The regions most interested in micro-grids are the same regions that have been hard-hit by severe weather in recent years: The Southwest (especially the Gulf Coast), Southeast and East Coast. Microgrids, like BESS, remain in a relatively early stage of development, subject to the same kinds of risks and uncertainties as any emerging technology.

Distributed energy resources (DER) have grown, though they are still a nascent part of the electricity business. IIR expects this sector to continue growing over the next five years. As a category, DER includes a broad range of resources: rooftop solar, community wind or solar, BESS, electric vehicles (EVs) — basically anything that is not utility-scale and that does not burn fossil fuels. Public policy, including supportive FERC and state utility commission decisions, have helped DER grow. For larger-scale DER, FERC Orders 828 and 842 provide for compensation if the resources provide generation or frequency support. Utility generation owners have had some concerns about implementing Order 842, but DER can also rely on FERC Order 828 for support in the market.

Spending on DER looks likely to accelerate sharply in the coming years. Between 2016 and 2018, roughly 450 MW of DER came online, according to data tracked by IIR. Over the 2019–2020 period, we see as much as 3,000 MW of DER beginning to operate. The regions with the greatest level of DER project activity are the Southwest, West Coast and the Great Lakes.

Industry veterans accustomed to building baseload coal and nuclear generators may scoff at the industry’s plan to invest so heavily in building renewable generation over the next five years. They may question the rush to build BESS, microgrids and DER.

We do not expect all of these planned projects to be built. But neither do we expect to see a resurgence of the traditional baseload coal and nuclear generation projects over the next five years. Those days are gone, at least for the foreseeable future, barring some dramatic “black swan” event like a reliability crisis or a dramatic run-up in the price of natural gas.

The U.S. power generation business still is in an early “discovery” mode about integrating renewable generation and BESS into the grid. And the proliferation of microgrids, though tiny by comparison to the U.S. generating fleet, remains in an early stage of exploration. All of these are disruptive trends that bear watching.

At the end of the day, most generation plans must still pass muster, to one degree or another, with each state’s utility regulatory commission. Right now, those regulators are increasingly operating under a “greener is better” mandate from their governors, legislatures and citizens.

The novelist F. Scott Fitzgerald, author of The Great Gatsby, remains a widely read author in part because he was an eternal optimist. He often wrote with a sense of wonder about the dramatic changes — technological, social, economic — he witnessed in the early years of the 20th century. At one point, this is how he explained his optimism about the future:

“I saw the improbable, the implausible, often the ‘impossible,’ come true.”

That is not a bad perspective to bring into the next five years.

Britt Burt is vice president of Global Power Industry Research for Industrial Info Resources (IIR), which is headquartered in Sugar Land, Texas, and has six offices in North America and 12 international offices.

Brock Ramey is North American Power Specialist for IIR, which provides global market intelligence for companies in the power, heavy manufacturing and industrial process businesses. For more information see industrialinfo.com or email power-group@industrialinfo.com

President Donald Trump’s goal of achieving energy dominance took several steps forward in 2019. In the power business, the most significant move was the finalization of the Afford-able Clean Energy (ACE) rule in June.









U.S. Power Industry Outlook 2020

The combined cycle power plants (CCPPs) built in the 1990s and 2000s were designed for baseload operation. But a quarter of a century later, the picture has changed dramatically. With renewables flooding onto the grid in unprecedented numbers, CCPPs are being forced to cycle, start, ramp and load faster.

The Achilles heel in this new mode of operation is the heat recovery steam generator (HRSG). Subjecting HRSGs to constant shifts in temperature causes problems such as exfoliation, tube failures and other damage as the systems were not designed to cope with cycling.

“Exfoliation is a combination of long service at high temperature, which builds the oxide layer then thermal cycling that causes exfoliation,” said Bob Anderson, an HRSG expert who is Principal at Competitive Power Resources. He spoke at the HRSG Forum, which met in Orlando, Florida in July 2019 to delve into every aspect of HRSG operation, maintenance and repair.

Anderson, the technical leader of the event, introduced Eugene Eagle, Lead HRSG Engineer at Duke Energy’s Carolinas Natural Gas Regional Engineering Services. Eagle detailed the company’s experience in preparing HRSGs for cycling operation. “Like many utilities, Duke is anticipating substantial growth of renewable generation that will require more flexible operation,” said Eagle.

Some plants will be shutdown, he said, with others being readied to ramp up rapidly and run in low-load operation. The Duke fleet has been practicing cycling with grid operators to gain operational experience. This is being done to pre-emptively find and correct issues in gas turbines (GTs) and HRSGs. The goal is to find out how to operate these units in a cyclic mode while mitigating thermal and mechanical fatigue damage. Most of the Duke GTs are F-class units in combined cycle plants, including triple-pressure HRSGs with duct firing. Current estimates have reduced expected design life from 30 to 20 years due to cyclic rather than baseload operation.

“With daily cycling there is a significant reduction in design life due to delta temperature changes,” said Eagle. As a result, the company is implementing best practices to avoid fatigue damage and other cycling issues. By improving startup and shutdown procedures, fatigue on HRSG pressure parts is reduced, and maintenance costs are lowered with fewer forced outages. “We manage the asset rather than the asset managing us,” said Eagle.

He strongly recommends instituting such practices to avoid tube repairs. Slow starts are the best, he said, as they cause the least amount of damage. Cold ambient starts cause the most damage as you have to heat up thick, high-pressure parts in an uncontrolled manner early in the cold start. Duke measured the estimated thermal fatigue damage per cycle event. A turbine trip and immediate restart was by far the most severe, followed by cold ambient starts and forced cooldowns. Normal shutdown is done at 2°F per minute GT exhaust temperature. A forced shutdown, on the other hand, is done at 5°F.

Eagle said it is difficult to maintain hot startup conditions (which require more than 500 psig HP drum pressure) due to various factors, such as auxiliary steam requirements, drain operation, pre-start purge, leaking valves and lack of a stack.

Further challenges include drain system designs with varying performance between sites, gaining staff and management buy in and drain pot thermocouples not working for hot startups. Additionally, Eagle noted gas turbine differences between OEMs. He contrasted the different exhaust gas temperature pro-files during startup of the GE 7FA and the Siemens 5000F.

With regard to superheater and reheater drains, Eagle mentioned that logic upgrades have been completed at most sites to automatically keep drains closed for the hot shutdown but still maintain the ability to cycle open when necessary as designed.

• Make sure the drain system can cope with the volume of condensation generated during startup and the amount of water present due to attemperator leakage (which should be zero)

• Avoid reducing attemperator set-points below 1,050°F. It is better to over-shoot on steam temperatures than to over-spray to saturation

• Double block and bleed valve configuration on attemperator spray water are best to prevent leak-by, or use upgraded full-metal seated ball valves

• Always maintain drum saturation temperature and steam temperature ramp rates within OEM recommendations. “We continue to have spray-to-saturation events especially during startup and shutdown that are very damaging to steam piping downstream elbows and HRSG pressure parts,” said Eagle. “We have made modifications to GT exhaust gas temperature profiles during startup to help reduce or eliminate such issues.”

• Always use exhaust temperature matching for every startup and shutdown on the GE 7FA

• Steam cool the HP superheaters within 50°F of saturation during shut-down as this reduces damaging differential temperatures and the impact of condensate quench

• Ensure both the HP drum saturation temperature and HP steam temperature ramp rate limits are not exceeded during shutdown

• After transfer to bypass valves, build HP drum pressure back up to 1,600-1,800 psig with bypass valves

• Complete a final stabilization of around five minutes at the GTs minimum load before ceasing to fire.

HRSGs can suffer from a variety of problems including rust, build up of oxide, exfoliation and tube failure

Jake Waterhouse, Director of Dekomte de Temple, discussed casing penetration seal solutions and Dekomte expansion joint technology. He contrasted metallic bellows with fabric expansion joints (his company offers both).

The traditional metallic bellows have lower initial cost and are well regarded for first-time installations. They generally use single-ply stainless steel, and are suitable for axial movement but can accept minimal lateral movement. Possible issues include convolution, distortion, splitting and corrosion of the seals. “Fabric seals have anywhere from one-to-four layers of loosely packed insulation and have greater flexibility in the most compact designs and are favored for high movement areas,” said Waterhouse. “Possible issues include tearing of the fabric and loosening of the clamp bands.”

He added that visual and thermographic inspection is vital to understand the existing scene and see what is needed. This makes it possible to evaluate the fabric belt as well as the associated insulation. Maintenance personnel can then dis-cover what joints are likely to fail and take preemptive action. “CCPPs endure greater challenges due to duct fatigue during temperature transients and irregular stress caused by movement,” said Waterhouse. “Fabric expansion joints are the best option for retrofits.”

Barry Dooley, a Consultant at Structural Integrity Associates provided an update on cycle chemistry for combined cycle HRSGs, using data based on over 100 plant assessments world-wide. It included the latest chemistry guidance concerning the use of film-forming substances in HRSGs and air-cooled condensers (ACCs).

“Flow accelerated corrosion (FAC) is the number one problem in HRSGs,” said Dooley. This applies to power plants with HRSGs, as well as industrial plants, LNG producers and nuclear facilities. FAC is found mainly in evaporative and HP economizer tubing. However, plant personnel are not identifying the type of FAC correctly (single-phase or two-phase FAC).

Single phase FAC has a mottled surface like an orange peel and is often red in color. You can see markings like chevrons pointing in the direct of flow. Two-phase FAC typically can be identified with a black, shiny surface, and has small dimples instead of chevron markings. Therefore, it is vital to adjust chemistry to address FAC.

Example of the dimples often found in two-phase flow accelerated corrosion

Dooley also covered film-forming sub-stances (FFS). FFS is sometimes needed, but not always, he said, and cautioned users to be wary of vendor claims that FFS are suitable for all-ferrous and mixed metallurgy feedwater systems. This is not necessarily the case. Experience in the field indicates some problems after FFS has been added. This included increased oxide deposition in boilers and turbines, and tube failures.

“If you don’t get the chemistry right, you can have massive amounts of iron coming out of the ACC due to FAC,” said Dooley. “If you apply IAPWS TGD8-16 Section 8 for any FFS deposition, you will have no problems with chemistry.” He referred the users to the IAPWS website (IAPWS.org) as well as his own organization’s literature for more details.

Dooley went on to discuss repeat cycle chemistry situations (RCCS) based on study of 220 plants. RCCS, he said, relates to the basics of power plant chemistry and thus plant reliability and performance. If a plant has more than two or three RCCS indications (such as presence of corrosion products, evaporator deposition, contamination ingress, drum carryover and air in-leakage), this means they will have a problem in the near future. “It is important to watch out for the presence of RCCS, recognize the negative impact and develop action plans to correct it,” said Dooley. “RCCS should be an inte-gral part of any corporate chemistry directive.”

Creep-strength-enhanced ferritic (CSEF) steels, also known as Grade 91, are metallurgically complex alloys that achieve improved elevated temperature strength through controlled chemical composition and heat treatment. However, the quasi-stabilized structure produced in CSEF steels slowly breaks down under the influence of stress at high temperatures.

Originally developed by Oak Ridge National Laboratory and Combustion Engineering, the first major installations were in the 1980s. Since that time, Grade 91 has been favored in the power industry where thermal cycling was anticipated (such as in HRSGs).

Jeff Henry, President of ATC, a materials engineering services company, said the ASME had reduced the allowable stress limits for Grade 91 steel. This action has caused some confusion at plant level over the impact on future operation of plants with Grade 91 pressure parts, he said. A type II form of Grade 91 is being recommended. “For existing fleets, the reduction in allowable stress values does not mean operating equipment is suddenly at risk,” said Henry. “An assessment should be carried out to determine the significance of the change related to individual HRSG components.”

Stan Rosinski, Technical Executive at the Electric Power Research Institute (EPRI), followed with a characterization of pressure-wave cleaning for application to HRSGs. “Pressure wave cleaning was first introduced in 2015 and the results have been positive.”

Fouled tube bundles in HRSGs can penalize overall plant performance, he said. A common practice is to periodically perform a maintenance cleaning, generally when the pressure drop reaches an action-required level. Pressure-wave cleaning involves inflation and detonation of bags containing a gas mixture whereby the resulting over-pressure and pressure wave from detonation cleans fouled tube bundles. As a response to some of its members concerns over the possibility of damage to HRSG components, EPRI has been testing this technique to determine if tube damage is possible. To date, no damage has been observed in HRSG tube samples exposed to worst-case testing. A final technical report is expected soon.

Some users reported recent reheater tube failures, with oxide growth and exfoliation noticed in their HRSGs. Dooley and Anderson jointly covered how these problems were dealt with at the Bahia Bizkaia Electricidad (BBE) plant in Northern Spain.

Anderson said the 800 MW facility comprised two GE 9FA DLN 2.0 GTs (now DLN 2.6) and a GE D11 steam turbine, which had been operating for nearly 100,000 hours. Its Nooter/Eriksen triple-pressure boiler had a steam temperature of 565°C. Modifications to super-heater/reheater drains and attemperators have eliminated high-pressure superheater (HPSH) tube leaks, but reheater tube failures continue.

Dooley said maintenance personnel noticed oxide growth and exfoliation (OGE) in the steam circuits, perhaps due to more starts and cycling and fewer actual operating hours. BBE runs one unit for a week then shuts it down and runs the other one for the following week. Two re-heater tube leaks appear to be caused by severe and localized internal oxide exfoliation — possibly a first for this mechanism. “OGE has been an enormous problem in conventional fossil plants since the late 60s,” said Dooley. “Oxide on internal tube surfaces falls off and causes blockage, as well as solid particle erosion in the steam turbine and control valves.”

BBE experienced tube failures which appeared to be from thermal fatigue. Inspection revealed 50% of the wall thickness gone at the top and bottom of the tube, not at the sides. Localized internal oxide exfoliation was evident in the thinned areas. The probable cause was blocking or partial blocking at the bend in the tube leading to a heat spike and more oxide formation. Remediation actions have begun. Thermocouples have been added at the edge and middle of the module as a baseline to verify the heat spikes and to help assess tube temperatures. Radiography is also being used to find the amount of oxide present inside the tubes.

Ian Perrin, Vice President of Technical Development at Structural Integrity said the health of components suffering progressive degradation and damage has typically been achieved by performing Non-Destructive Examination (NDE). However, this can be costly. Success depends on being in the right place at the right time. Technology now exists to track the health (or aging) of key components, such as HRSG headers or piping components due to creep, fatigue, or in the case of attemperators, water impingement. Since leaking and overspray of attemperators are a common industry issue, Perrin provided an example of how online monitoring could identify when these events occur so corrective action can be taken, and damage evaluation conducted in a timely manner.

GT upgrades have the potential to increase unit output, efficiency and flexibility. How-ever, the impacts of any proposed GT upgrade on the HRSG and the wider balance of plant (BOP) must be considered to ensure that new process conditions are acceptable, that any enhanced risks to process safety or component damage are understood and to ensure that the full capabilities and commercial value of the upgrade will not be limited by the water/steam cycle.

"You have to assess the impact on the water and steam cycle to determine if an upgrade is viable,” said Dan Blood, Team Leader for Steam Asset Engineering at Uniper Technologies. “The BOP might restrict the potential value of any upgrade.”Implementing a new GT package or update may shift the damage mechanisms in the HRSG. These risks must be understood. He said Uniper offers a process to answer these questions and mitigate risk.

Blood gave the example of plants wish-ing to implement GE’s Variable Load Path (VLP) upgrade on the GE 9FA/FB. VLP is a GT control feature that uses inlet guide vane control to keep exhaust temperature lower during startup. This significantly decouples the GT output from HRSG and ST constraints. The goal is to provide more MW in less time, lower the fuel burn, reduce load imbalance and start emissions, and lower startup costs. However, it causes a redistribution of heat through the HRSG’s gas path.

A detailed HRSG and ST assessment was done by Uniper. In the two plants studied, startup times would be reduced considerably. But modeling of the cold path predicted that the IP evaporator would be overwhelmed, and IP safety valve capacity would be insufficient. This needed to be mitigated by an exhaust flow boundary but would reduce the commercial value of the upgrade. One way to get around this would be to add an additional IP drum safety valve.

Installation of failed re-heater piping on HRSG

In the final presentation of the HRSG Forum, Bob Anderson summarized a new method for automatically controlling superheater and reheater drains. HRSGs have long suffered thermal fatigue damage due to failure to drain the large quantities condensate formed during startup. He discussed a new system developed by his company (Competitive Power Resources), EPRI and Flexim. The system uses Flexim ultrasonic flow meter equipment (with modified signal processing) to distinguish between water and steam in the drainpipes, then using this information to discharge water at the appropriate times without releasing steam. The system requires no penetration of the pressure boundary and is mechanically robust.

The 2020 HRSG Forum will be held July 20–23 at the Rosen Shingle Creek in Orlando. For more information, visit hrsgforum.com

How to cope with increasing cycling, start and ramp-up issues plaguing heat recovery steam generators.

HRSG Forum Report

One of the newest frontiers in simulation is the concept of the digital twin. By using product-mounted or virtual sensors, companies can collect operating data from the field in real time and use that information to create an exact replica of the working product in a controlled virtual space. By studying how the simulated product model performs under real-world conditions, companies can flag performance issues, schedule predictive maintenance, reduce downtime and minimize warranty expenses. This is an attractive proposition. Yet many businesses have faced challenges in implementation due to the specialized expertise and cross-functional partner-ships required.

For decades, engineers have leveraged simulation to develop products in a virtual design space. By applying a range of physical forces and operating parameters to three-dimensional designs, engineers have been able to launch products with confidence they will perform as expected under real-world conditions.

Once a visionary idea, simulation-driven product development is a best practice applied by all types of companies, saving time and money.What has been missing, though, is a closed-loop approach that ensures simulation remains a competitive advantage once products are launched into the field. The digital twin adds the ability to monitor product performance over time, empowered by advances in digital technology.

A digital twin is a simulated model of an actual working product in the field. It is informed by sensors that gather and feed-back real-time, real-world operating data. By studying the digital twin, companies can see how the product performs over time in the physical environment. This enables a product development team to close the loop on initial simulations. Engineers can make more informed choices for future designs and make simulations even more accurate.

More importantly, digital twins make the dream of true predictive maintenance possible. Instead of over-servicing or over-maintaining turbomachinery to perform repairs, replace components and avoid downtime, companies can act “just in time” to address any performance issues. They can visualize exactly when and where maintenance is needed, instead of making blind guesses and safe bets.

The time and cost savings are substantial. Connected product technology allows durable, competitively priced sensors to be mounted on working products to sup-ply data to digital twins cost effectively.

Digital twins of turbomachinery, however, remain largely the province of a few companies due to a lack of dedicated resources. Specialists are needed to create a simulated product model, verify the model, connect it to actual working products and then analyze the collected information. As this process involves multiple functions and technology platforms, practical challenges inhibit implementation. An easy-to-implement simulation solution is needed to realize the potential of digital twins.

Such technology is now available. It consists of a platform that can be integrated across business functions to place digital twins within reach of more companies. Leveraging the concept of digital twins involves three steps:

• Building a digital model of the product system

• Implementing it by connecting it to the physical product in the field.

Those harnessing engineering simulation to design products have already accomplished the first two steps. Engineers supporting the digital twin initiative would build a three-dimensional product model and verify and optimize its performance by applying multiple physical forces that replicate the real world in which the product operates. Models and data from the original product development process can be reused to save time and money.

Twin Builder helps turbomachinery operators create and operate digital twins. Courtesy of ANSYS

Solutions exist that integrate with smart sensors mounted on equipment, as well as third-party technology systems and tools. Data captured by sensors continuously update the model as time passes and conditions change. Insights gained from the digital twin inform future product development efforts, while helping operations personnel optimize lifetime maintenance and repairs.

The digital twin opens the door to actual predictive maintenance that can analyze the physical effects of vibration, wear and other stresses. Maintenance managers can visualize and study exactly what is happening inside critical systems via a three-dimensional virtual model that is subjected to the same environmental conditions as the working product.

Sameer Kher is Twin Builder Product Line Director in the Systems Business Unit of ANSYS. The ANSYS Twin Builder platform provides an easy way for turbomachinery opera-tors to implement the digital twin. For more information, visit ansys.com

A simulated product model can visualize exactly when and where maintenance is needed, instead of making blind guesses and safe bets.

Digital Twins

The use of hydrogen as a power plant fuel is all over the news. Several manufacturers are actively promoting their capability to burn hydrogen as a gas turbine (GT) fuel.

We saw a similar kind of fervor in the 1970s surrounding coal gasification plants. It happened again in the 1990s for carbon capture and sequestration (CCS) initiatives, and we are seeing it currently in what is effectively a hydro-gen-for-energy-storage play. There was an entire U.S. Department of Energy program for many years on GT combustion with high-hydrogen fuels. Several OEMs demonstrated their GTs with up to 100% hydrogen fuel.

Let us review the rationality of this trend, beginning with the source of hydro-gen. There are two processes commonly used to obtain hydrogen in large quantities.

1. Partial oxidation via synthesis gas from coal or natural gas using gasification or steam reforming. This is the most common process used by process, refinery and chemical companies to make hydrogen in industrial quantities. If the argument for hydrogen production is driven by atmospheric decarbonization, hydrogen production from fossil fuels does not resolve the greenhouse gas issue.

2. Electrolysis of water. It only makes sense if water is cheap or freely avail-able. The conversion efficiency of electrolysis is less than one on an electric energy in (in electric kW-hr) versus hydrogen chemical heat energy out (in Joules or BTU) basis.) This concept only works for energy storage applications where electricity is available from intermittent power plants, such as wind or solar.

Hydrogen from electricity, then, is effectively nothing more than an energy storage option, and possibly an energy transportation alternative if one considers hydrogen transport by pipeline or truck.

Now let us talk about using hydrogen for power. From the GT perspective, hydrogen is an excellent fuel. It is flammable, has good flame stability and has a reasonable heating value. There are drawbacks:

• A low auto-ignition temperature and delay time

• A high flame speed, which can cause flashback difficulties• A higher water percentage in the exhaust, which may require a firing temperature reduction to keep hot-section part life unaffected.

Hydrogen combustion also requires a secondary liquid or gas fuel and purge skid for safety during startup and shutdowns. Hydrogen combustion up to 100% in GTs has been done for the last 40 years by multiple vendors for gasification, steel mill and refinery applications. A customized combustor and fuel gas supply system is required. But otherwise hydrogen-fueled GTs are a manageable engineering challenge.

Obviously, package safety must be considered, and special purge cycles must be implemented to avoid explosion risk during failed starts. Originally, most GT hydrogen combustors were diffusion flame with a diluent for NOx control. More recently, there have been developments for lean pre-mixed combustors for hydrogen with high-velocity pre-mixers, micro-mixers or staged combustion systems.

There is a reason that hydrogen in its pure form does not occur abundantly in nature unlike other fuels, such as coal, natural, gas and oil. It is highly reactive and, thus, very explosive. This makes it difficult to handle, store and transport.

Does this sound like a great energy storage medium? It is not necessary go all the way back to the Hindenburg airship or the Challenger Space Shuttle accident to find problems with hydrogen. Recent hydrogen fueling station explosions in California and Norway are reminders that it is must be handled carefully.

Aside from volatility, there are major economic challenges. The roundtrip energy-storage efficiency of hydrogen-based systems is low. Production from electrolysis based on energy in versus energy stored is 70% to 80% for modern systems. State-of-the-art efficiency of heat engines is below 65%. Therefore, total storage roundtrip is at best 50% without considering parasitic and auxiliary losses. Once compression power, leakage and electrical losses are included, roundtrip efficiency of 45% is optimistic.

And then there is transportation to consider. Rather than 100% hydrogen, it may be more practical to spike natural gas with the produced hydrogen. Mixing lower levels of hydrogen into existing pipelines is a viable option with current technology and infra-structure. A natural gas-hydrogen mixture with moderate levels of hydrogen can be burned in more or less standard lean pre-mix systems, the gas compressors already installed in pipelines can remain in service, and safety issues regarding failed starts or leaks are manageable.

Several studies have shown that this approach works with up to 5% hydrogen and can possibly be extended to as high as 10% without significantly affecting transportation requirements and power plant operation. However, natural gas with hydrogen above that percentage becomes expensive since all existing pipelines and power plants would need to be re-engineered and retrofitted. Also, transporting hydrogen in higher concentrations in pipelines is inefficient since it is a light gas. There is nothing on the horizon to indicate that the necessary infrastructure is being built to generate hydrogen from renewables in an amount that would even create a 1% hydrogen content in natural gas pipelines.

At current prices, hydrogen is too valuable to be burned in a GT. It takes too much energy to make and transport it and its roundtrip efficiency is low. Bottom line: hydrogen power may be all over the news, but like the Hindenburg, this trend will ultimately go up in flames.

Myth: Hydrogen fuel is the future

Unbalance is an important source of vibration and the focus of attention for the operation, reliability and maintenance of turbomachinery. Balancing, then, is a process of attaching masses to or removing masses from the rotor assembly so that the centrifugal forces on the rotor are balanced.

The art of balancing depends on logical methods for the selection of these masses. Instead of attaching a correction mass to the rotor at an appropriate location, the same balancing effect can be achieved by removing the same size mass from the diametrically opposite side of the rotor at the same axial location.

The inherent unbalance forces should be in equilibrium after the balancing. Balancing procedures have been well established for many years for rigid rotors, although modern developments in automation, instrumentation and computation have produced marked improvements in practice. However, the balancing of flexible rotors has been less clearly understood and is a matter for debate. Fortunately, routine procedures have been established for flexible rotors.

The balancing procedure is a step-by-step approach in which the unbalance in each mode is corrected in turn, starting with the first mode. At each stage, the residual modal unbalance (the initial unbalance in the mode plus the modal effect of any corrections made to the lower modes) is determined by a modal interpretation of the rotor vibration for a speed close to the corresponding critical speed.

The first step is to choose a balancing speed, close to the selected critical speed. Then, measure shaft vibration at convenient locations. The correction step is to attach a series of trial masses (number of masses is equivalent to mode number) to the shaft at properly selected axial locations. These are selected to lie on either side of the node point in the selected mode (opposite sides). In addition, trial masses should be proportioned so that these masses will not upset the previous mode correction.

For example, three correctly proportioned masses are needed to balance the resultant defect in the third mode without upsetting the balance attained previously in the first and second modes. The procedure depends upon the orthogonality, or independence, of the modes of vibration. The process can be theoretically extended to any number of modes.

For flexible rotors, the important point is that the first and second modes have been balanced successively: and that in correcting the second mode defect, no new unbalance has been introduced into the first mode. Further modification of the components of unbalance in the third, fourth and higher modes can be done. But this is of less importance if these modes are far above the operating speed. It is not easily known whether the modification increases or decreases the various components of unbalance.

Sometimes it is necessary to balance modes whose critical speeds are above the maximum operating speed (or test speed) due to different reasons. For a large, critical piece of turbomachinery which needs a fine level of balancing, the equipment may be balanced in its first three modes for which the critical speeds are below its operating speed. However, it may have a relatively significant vibration at the operating speed due to unbalance in the fourth and fifth modes.

A complication can arise in the above process in relation to closely located critical speeds. The modal balancing technique deals with the unbalance in each mode, in turn, by identifying the corresponding component of vibration. If two critical speeds are close together, so that the modal components of unbalance cannot be separated in this way, an advanced method (such as a polar plotting technique) should be used for the isolation of the modes. In these circumstances, vibration measurements are made at shaft speeds throughout a range of speeds around the corresponding critical speed.

The combination of modal balancing is normally enough to ensure that the vibration of the shaft is reduced to tolerable levels throughout the operating speed range. This procedure does not ensure that there is no residual unbalance in the rotor assembly. Within the accuracy of practical procedure, the residual unbalance in the lower modes will have been reduced to near zero and the vibration at the operating speed kept within specified tolerances. Almost certainly, though, after balancing, the residual unbalance will have non-zero components in modes higher than those for which corrections were made. In principle, this residual unbalance will not lead to significant vibration within the operating speed range of the machinery.

Vibration caused by unbalance can result from an initial bend in the shaft. This is manifested by the run-out at a low speed, although the characteristics are different. If a shaft has an initial bend instead of, or in addition to, unbalance, it experiences a forced whirl with shaft speed frequency, similar to that encountered due to unbalance. But there are subtle differences that can be important in practice in applying the balancing procedure.

How to deal with unbalance

Red and blue may be the dominant colors on a political map of the U.S. But green and light blue are the only two shades that matter in our annual assessment of the U.S. power market. Provided exclusively to Turbomachinery International by Industrial Info Resources (IIR), this report details current and planned power plant installations for the next five years.

Green, of course, means renewables and light blue rep-resents natural gas in the chart that anchors the report. Apart from one remaining nuclear plant that is still on the table for the Rocky Mountains region (which is unlikely to open), there are no other power plants going to be built in the nation except for natural gas, wind, solar and battery.

This stands in marked contrast to a decade or so ago when coal and nuclear stood tall. At that time, solar was nowhere and wind power had a marginal national presence. How things have changed. Coal appears to be in its death throes despite resuscitation attempts by the current administration. Natural gas build out is also being throttled back in some areas. According to IIR:

“U.S. new-build generation over the next five years is expected to be even greener, but less gassy, than in prior five-year assessments.”

As part of our annual Turbomachinery Handbook, Forecast International provides a breakdown of the worldwide gas turbine (GT) marketplace. Things have been far from healthy on that front for a couple of years. The bad news is that the depressed order trend will be with us for another year or so. The good news is that an uptick is on the horizon.

The forecast is for sales over the next decade to be 10.6% lower than what was expected a year ago. How-ever on a positive note, the market low of around $8 billion per year will return steadily to around $11 billion within a decade. Annual unit projection follows a similar trajectory. From a forecast low of 328 units in 2020, it is predicted to rise to 496 by 2028.

Turbomachinery International also attended the recent HRSG Forum in Orlando. You can read all about it in our show report. What became clear during the many sessions was the fact that the HRSG is not designed to cope with the heavy cycling mode of operation currently in vogue. This equipment was intended for steady baseload operation.

In some ways, the Achilles heel of combined cycle power plant cycling could well be the HRSG. Operators at the show swapped best practices, fixes and remedies for the many issues they encounter due to cycling. These days, they have to cope with exfoliation, rusting, tube failures and other damage and somehow keep their plants operating.

It is perhaps ironic that the surge of renewables onto the grid could lead to lowered combined cycle availability and a greater number of unscheduled shut-downs. If these HRSG challenges are not adequately addressed, we might see the day when GTs and combined cycle plants are labelled unreliable, in the same way that power industry traditionalists labelled wind energy as intermittent and unreliable not so long ago.

In our next issue, you can read a report from the Turbomachinery & Pump Symposium in Houston, TX. It includes plenty of interesting material on bearings, GTs, steam turbines, seals, condition monitoring, coatings, stress corrosion cracking, centrifugal compressor revamps, hot corrosion and more. We also look forward to seeing you at PowerGen Europe in Paris and PowerGen International in New Orleans, LA.