The most serious issue for many large turbomachines, e.g., large pumps, turbocompressors, turbines, and others, is a cut-off of the lube oil flow. This could lead to a catastrophic failure of oil-lubricated bearings, such as hydrodynamic bearings, within a few seconds. It is important to understand how lube oil systems react to temporary faults, such as those that can stop the oil pump.

At least two full-sized lubrication oil pumps (one operating, another standby) should be employed in any critical turbomachinery with lubricated bearings. The lube oil pump changeover or switch-over (starting the standby pump) in various emergencies is an important topic for any piece of turbomachinery. Starting the standby pump is necessary when lube oil (header) pressure falls. A fast response time is essential, and although there are other solutions and configurations for a decrease in pressure, the direct pressure signal to fast start-up of the standby oil pump is the simplest and most cost-effective solution. Of course, in some cases, even this may not be sufficient and other provisions may be needed. 

A common cause of unscheduled downtime is the lube oil system’s inability to ride through transient events such as a 1- to 6-second loss of electrical power in the network. For some hydrodynamic bearings, even a 2- to 3-second interruption in lube oil flow during a transient situation could cause damage. When an electrical fault happens in the electrical network connected to the operating oil pump, the flow of oil could be lost for the duration of the fault. The question is can the turbomachinery tolerate such a situation?

Another concern when the oil pump fails is the time needed to start up the standby oil pump, which can be an electrical-driven pump connected to an alternative electrical network, a steam turbine-driven oil pump, etc. Can the turbomachinery continue operating properly during this transition? The same applies to many control and/or hydraulic oil systems. An oil accumulator can be used, if needed, to deal with these types of situations.

An oil accumulator—or a set of accumulators—maintains the oil pressure while the standby oil pump accelerates from an idle condition to an operating speed during a 1- to 6-second loss of electric power, for example, or during other transient situations. The oil pressure should always be above the equipment’s minimum-specified oil-supply pressure. The conservative sizing of the oil accumulator is necessary because:  

Over time, the situation may get worse, and some margin is needed. For example, an electrical-driven pump can degrade over time, which could decrease the available voltage to the electric motor of the standby oil pump. This voltage drop can impose serious limitations on the start-up time needed for the pump.

To deal with inaccuracies and uncertainties in the theoretical assumptions and analytical calculations. 

A bladder-type accumulator is recommended. Accumulators are usually constructed from a 300-series stainless-steel shell and often have a “nitrile” bladder, which forms a barrier between the inert gas (nearly always nitrogen) and the oil. Oil accumulators are usually installed vertically. Nitrogen is the best inert gas for this application because of its availability and chemical and physical properties. Air should not be used because of its corrosive or explosive properties. As a rough indication, the inert gas pre-charge is usually maintained around 80%-85% of the working pressure of the oil system. The high flexibility of the bladder causes the response time to be quick, which is an important factor considering the fast pressure drop in an oil system during an emergency or transient case. A properly selected large accumulator with sufficient pressure capability and a suitable differential pressure (between the oil accumulator and the oil consumption point) offers a fast response time. An oil accumulator should provide the oil flow fast enough and maintain the oil flow for the necessary period at sufficient pressure.

Standard methods and calculation procedures for commonly used water or process accumulators cannot be applied to an oil accumulator. A specific set of requirements and considerations is needed for oil accumulators in lube/control/hydraulic oil services, different from what’s needed for water or process services. An oil accumulator should push oil to the system once the minimum pressure (the low-pressure alarm + a margin) is reached. The required oil should hold up while the mid pressure (the pressure between the maximum and the minimum) is retained. This can result in two to four times more volume for the oil accumulator compared to a conventional water (or process) accumulator.

Amin Almasi is a Chartered Professional Engineer in Australia and the U.K. (M.Sc. and B.Sc. in mechanical engineering). He is a senior consultant specializing in rotating equipment, condition monitoring and reliability.

Articles

Guidelines and technical notes for dealing with lube oil, control, and hydraulic oil systems in turbomachinery.

Turbo Tips: How Transient Faults Affect Turbomachinery Lube Oil Systems

With the transition toward a more sustainable energy economy, the old debate between reciprocating versus centrifugal compressors —and which one is better—has reared its ugly head again. For conventional hydrocarbon compression applications, this discussion has been raging for at least 50 years. But over the last 10 years or so most industry experts have arrived at some kind of peace agreement and a common acceptance that there are some applications where one or the other makes more sense. This has not yet happened in the new energy economy where this debate has just started. Since this is a complex subject, we will discuss it in a two-part myth with part one focusing primarily on applications and design, and part two will outline the fundamental challenges of each compressor type. 

When talking about alternative energy sources, the primary gases of concern are green or blue hydrogen and CO

 for carbon sequestration. Both hydrogen and CO

 are physically very different from each other and from natural gas—which is still the most widely used energy source. Whereas the widespread use of hydrogen for major energy production applications is forecast to occur in maybe 10-20 years, the implementation of carbon capture and sequestration in power plants is happening right now. Therefore, we will focus this article on what type of machine is best for CO

 compression. We can have a similar debate about hydrogen later … maybe in a few years from now. 

Reciprocating and centrifugal compressors are fundamentally very different machines. They use different compression principles and function mechanically differently. A reciprocating compressor uses a piston inside of a cylinder with suction and discharge valves for a positive displacement volumetric gas compression process. These compressors are well-suited for lowflow capacity requirements, high-pressure ratio applications, and can handle varying process gas compositions. However, reciprocating compressors are relatively bulky, less reliable, require more maintenance, and can produce higher levels of pulsations, vibrations, and noise. 

A centrifugal compressor uses rotating impellers and stationary diffusers in a fixed-volume gas compression process. Compression is accomplished by dynamically adding work to the gas. These compressors are ideal for medium-to-high flow capacity applications, are more compact, require less maintenance, and provide a smoother operation with reduced vibration and noise levels. Centrifugal compressors excel in handling large volumes of gas, making them ideally suitable for large-scale industrial processes. 

So, what are the applications of a typical carbon capture and sequestration application? In the United States, over 70% of the CO

 from stationary sources is emitted by fossil-fueled electric power plants. In many developing industrial nations, this percentage is much higher. Thus, the primary and initial target—the low-hanging fruits—for industrial-scale decarbonization using capture and sequestration are large fossil-fueled power plants. These power plants are mostly fueled by natural gas or coal. There are different options for carbon separation in fossil-fueled plants, including pre-combustion hydrogen production or post-combustion flue gas cleanup. In both cases, the CO

 will be produced at relatively low pressures, usually below 30 psia. After separation, the CO

 needs to be compressed to supercritical pipeline transport pressures to around 2,000-2,200 psia, and then injected into a geological formation for permanent storage at similarly high pressures. The advantage of transporting CO

 at supercritical pressures is that it has a high density (similar to that of liquid water) and very low viscosity, allowing for efficient pipeline transport. Operating in the dense phase also significantly reduces the power demand for the pumping or compression stations along a CO

 pipeline, although applications where existing natural gas pipelines are to be used will operate at much lower, typically subcritical, pressures. Thus, for the new sustainable energy economy, the most common compression applications are:

(1a) pipeline injection from near atmospheric to 2,000+ psia

(1b) pipeline injection from near atmospheric to 600 psia

(2) pipeline recompression or re-pumping with typical pressure ratios        around 1.5, and 

(3) geological injection compression or pumping from the pipeline at pressures that depend on the final geological storage pressure, which can vary widely but can be well above 2500 psia.

As a side note, from an aerodynamic design perspective, there is not much of a difference between a compressor and a pump when they operate at high pressures above 1080 psia in the dense phase. Here the fluid is not very compressible, and any work input does not result in significant density and temperature changes. The primary difference is that pumps are usually designed to operate at the synchronous speed of an electric motor while compressors often run at much higher speeds using a gearbox of high-speed drivers. Consequently, to achieve a similar head, pumps usually require more stages than compressors, but because of their construction, they are usually less expensive.

The reality is that centrifugal compressors can also produce high-pressure ratios for fluids that have physical properties associated with low specific heat and a high molecular weight, i.e., most heavy gases.

Back to the discussion of what is the best compressor for a sustainable energy economy: Reciprocating compressor manufacturers (and their supporters) claim that their machines are good for hydrogen compression. There is some truth to that for low-flow applications since reciprocating compressors using piston compression can achieve high-pressure ratios with relatively few stages. Similarly, they claim that, since most CO

 capture applications require very high-pressure ratios, reciprocating compressors are equally superior in this area. However, this argument is false and based on a fundamental misunderstanding of compression thermodynamics. 

The reality is that centrifugal compressors can also produce high-pressure ratios for fluids that have physical properties associated with low specific heat and a high molecular weight, i.e., most heavy gases. This is especially true for CO

, which has a molecular weight of 44 and a specific heat of 0.8 kJ/kg K. A basic reading and simple analysis of Euler’s turbomachinery equation (which relates fluid angular momentum to head) and the isentropic relationships (which relate temperature differential - and thus head rise - to pressure ratio) demonstrates this. Here the physical relationship between pressure rise and head for centrifugal compressors shows that each rotating impeller stage can produce very high-pressure rise even at moderate impeller tip speeds. For example, a single-casing centrifugal compressor can easily compress CO

 fluid from 20 psia to 1,200 psia (well above its critical point) using only seven impellers running at normal tip speeds of 1,200 fps. This is a staggering pressure ratio of 60:1. Clearly, these impeller stages must have some intercooling to avoid excessive temperatures and to maintain high efficiency, but this is no different than what is required from all types of compressors, including reciprocating compressors.

On the other hand, centrifugal compressors have major operational advantages over reciprocating compressors in that they can handle much higher flows, are more reliable, require less maintenance, have nearly zero gas leakage, do not contaminate the process gas with lubrication oil, do not require pulsation control, are significantly quieter, have lower vibrations, have a wider operating range, are easier to scale, and provide for more concise and stable flow control. In the past, for lower-flow carbon sequestration applications, reciprocating compressors rather than centrifugal compressors were the traditional option. These were mostly electric motor-driven. However, as the industry is moving rapidly toward much higher CO

 capture flow rates, the limits of the practical use of reciprocating compressors are being reached. 

In part two of this Myth Busters article, we will discuss compression challenges and some of the lesser-understood disadvantages of reciprocating compressors for CO

The authors want to thank Karl Wygant and Rob Pelton, both at Elliott Turbo, for their contributions to this article.

Klaus Brun is the Director of R&D at Elliott Group. He is also the past Chair of the Board of Directors of the ASME International Gas Turbine Institute and the IGTI Oil & Gas applications committee. 

Rainer Kurz is the Manager of Gas Compressor Engineering at Solar Turbines Incorporated in San Diego, CA. He is an ASME Fellow since 2003 and the past chair of the IGTI Oil & Gas applications committee.

Any views or opinions presented in this article are solely those of the authors and do not necessarily represent those of Solar Turbines Incorporated, Elliott Group, or any of their affiliates.

Part one of this two-part myth on reciprocating versus centrifugal compressors addresses design and application differences.

Myth Busters: Part I: Reciprocating vs Centrifugal Compressors for Carbon Capture and Sequestration 

The U.S. Environmental Protection Agency (EPA) drafted a third set of greenhouse gas regulations using an explicit Congressional delegation of authority, but litigation is still expected. Although climate change has led to more weather extremes, decarbonization of the U.S. power sector remains a “two steps forward, one step back” exercise.

As the United States prepares to enter the third year of the Biden administration, with its priority to decarbonize the electric generation market, the challenges to decarbonization are so significant as to call to mind the Tennyson poem, “The Charge of the Light Brigade,” which chronicled the ill-fated attack launched by lightly armed British cavalry troops against better-armed Russian artillery forces during the Crimean War. As recounted by Tennyson, the British troops suffered a beating at the hands of the more numerous and better-equipped Russians:

Cannon to right of them, 
Cannon to left of them, 
Cannon in front of them Volleyed and thundered; 
Stormed at with shot and shell, 
Boldly they rode and well, Into the jaws of Death,
Into the mouth of hell
Rode the six hundred.

A seasoned dealmaker with 36 years of inside-the-Beltway experience as a U.S. senator, Joe Biden as President has notched impressive legislative victories to decarbonize the U.S. power industry. The Infrastructure Investment and Jobs Act, enacted in late 2021, and the 2022 Inflation Reduction Act, with $369 billion in federal support for renewable energy, will go a long way to reducing CO

In May 2023, the EPA issued its third set of draft regulations to reduce CO

emissions from current and future power plants. All significant accomplishments. But permanent? One wonders, given the forces that stand in opposition:

Congressional Republicans, furious about House Speaker Kevin McCarthy’s 11th-hour debt ceiling deal this past spring, are determined to claw back federal spending on renewable energy, among other items, under the rallying cry of fiscal austerity.

Coal-rich states such as Montana, Wyoming, West Virginia, Kentucky, and Utah have enacted various measures to impede the closure or sale of coal-fired generators in their states, prop up in-state coal mines, and preserve the flow of tax revenues into state coffers.

In the closing hours of the 2023 Texas state legislative calendar, lawmakers approved, and Governor Greg Abbott signed into law, a bill creating a $10 billion fund to support the construction of new gas-fired generation, as well as the modernization of existing gas-fired generators. Republican-elected officials and fossil-fuel interests staunchly oppose the EPA’s May 2023 draft Clean Air Act rule designed to limit CO

 emissions from power plants. Legal challenges are sure to come, perhaps even before the rule is finalized, and yet another trip to the U.S. Supreme Court appears likely. 

If such a legal challenge does make its way to the highest court in the land, the composition of the court seems unfavorable to those who seek to decarbonize the power sector. In 2022, the justices ruled 6-3 against an EPA effort to cut carbon emissions. Shortly after that decision, Congress closed the regulatory loophole that gave the justices such pause. Will the third time be the charm for this rule, or will the court find yet another reason to intervene?

These and other challenges to decarbonization emerged during 2023 and are expected to continue unfolding in 2024 and beyond to shape the U.S. new-build power business. The industry has an outlook that extends for decades, but small changes in the near term can lead to dramatically different outcomes in the long term.

That said, renewable energy continues to dominate the outlook for U.S. new-build power-generation projects scheduled to begin construction over the 2024-2028 period.

The transition to lower-emitting generation fuels has been underway for several years, but the 2022 Inflation Reduction Act’s direction of $369 billion of federal funds into renewable energy is expected to significantly strengthen a years-long trend of heightened investment in new non-emit-ting electric generation.

According to data tracked by Industrial Info Resources, 94% of all new-build power generation projects scheduled to begin construction in the United States between January 2024 and December 2028 will be for renewable energy (see the

That spending is expected to extend the rush to renewables, but what’s different about the 2024-2028 period is the dramatic increase in the projected volume of new-build construction: Developers plan to build about 482 GW of new generation over the 2024-2028 period, up 22% from last year and at least double the amount of any five-year period in the last 14 years (

By and large, electric utilities have found that their customers like and prefer renewable energy, provided it is cost-competitive with electricity produced from other fuels.

The COVID-19 pandemic, now apparently receding into the rear-view mirror, turned much of the discussion about the energy transition into a rueful recognition of the importance of supply chains. In 2023, electric utilities were forced to defer, or rebid, planned renewable energy additions, citing rising component prices and delayed delivery dates. Evergy, an electric utility serving customers in Missouri and Kansas, caught some negative publicity from members of the environmental community in mid-2023 after it went public with a revised schedule and mix of generating options that included building new gas-fired generation, per requirements of its grid operator, and keeping some operating coal generators open past their planned retirement dates. Other utilities have had to rejigger their clean-energy plans, some more publicly than others.

Ultimately, state utility regulatory commissions, along with grid operators, have the whip hand in deciding what gets built where and when. We expect that the shifting economics of generating electricity will force several public utility commissions (PUCs) to revisit decisions made in earlier integrated resource plan (IRP) dockets.

Texas already has decided: Going forward, natural gas will play a bigger role in the state’s electricity future. Lone Star State politicians were quick to blame—incorrectly, as it turned out—renewable energy for the rolling blackouts and multiple catastrophes triggered by Winter Storm Uri in early 2021. More objective analysis found that frozen natural gas lines and poorly winterized thermal power plants bore a more signifi-cant share of responsibility for that event.

Never letting the facts get in the way of a good story, Texas politicians and the state’s grid operator, ERCOT, have been advocating for an increase in dispatchable, i.e., gas-fired, generation to ensure the lights stay on during weather extremes. The state has weathered some white-knuckled summer peaks in recent years, so the call for more dispatchable generation wasn’t all home-state hoopla.

In mid-2023, Republican Texas Governor Greg Abbott signed into law a bill to create a $10 billion fund to support building new-build gas-fired generation and modernizing existing gas power plants.

Republican-led energy-producing states like Texas, Montana, and Wyoming, among others, effectively are working in partnership with U.S. Senator Joe Manchin (D-WVa), chairman of the powerful Energy and Natural Resources Committee, to preserve the role of fossil fuels in the nation’s electricity supply.

Natural gas is expected to hold a strong share of the electric fuels market for the near term, accounting for approximately 41% of electricity generated in 2023 and 40% in 2024, according to the July 2023 Short-Term Energy Outlook produced by the U.S. Energy Information Administration (EIA). Coal’s market share is expected to continue weakening in the near term, sinking from 20% in 2022 to an estimated 15% in 2023, before rising slightly to 16% in 2024. Nuclear’s share of the electric generating mix is expected to hold steady at about 19% over the 2022-2024 period, while solar and wind are expected to continue gaining market share.

New-build coal-fired generation has been a rounding error in recent years, and the 2024-2028 period is no exception. “Early retirement” continues to be the watchword for existing coal-fired generation, with nary a new-build project in sight.

About 133 GW of coal-fired capacity has been retired since 2010, and over the 2024-2028 period, Industrial Info Resources (IIR) expects another 51 GW of coal genera-tion to be retired (

But there are about 146 in-plant capital projects, worth an estimated $16.5 billion, that are scheduled to kick off at coal-fired power plants across the United States over the next five years. This broad category of projects includes automation; carbon capture, utilization, and storage (CCUS); debottlenecking; decommissioning and demolition (D&D); efficiency upgrades; environmental remediation; life extensions; upgrades; and uprates.

The states with the largest dollar value of in-plant capital projects are Wyoming (five projects valued at about $2.7 billion); Illinois (eight projects worth approximately $2.4 billion); Texas (19 projects valued at $2.2 billion); and New Mexico (one project worth about $1.3 billion).

The $16.5 billion of planned in-plant capital projects includes CCUS projects. A sharply increased federal tax credit of as much as $85 per ton of CO

 removed has led companies to schedule billions of dollars of CCUS projects to be constructed at coal-fired power plants over the next five years. We are tracking six CCUS projects, valued at $7.4 billion, that are scheduled to be built at stations in Illinois, Texas, Wyoming (which has three projects), and New Mexico over the next five years. These projects are expected to be vying for expanded federal tax credits under section 45Q of the federal tax code. 

Also included in that $16.5 billion sum are approximately 58 coal combustion residuals (CCR) remediation projects that are scheduled to begin construction by the end of 2028. The total investment value
(TIV) of these projects is about $3.6 billion. The states with the greatest dollar value of projects for remediating CCR, also known as coal ash ponds, are Montana, Texas, Indiana, and Missouri.

Coal power plant decommissioning and dismantling (D&D) projects also are included in that $16.5 billion in-plant capital sum. The value of these D&D projects is about $2.3 billion. The states with the largest dollar value of D&D projects include Ohio, Michigan, Indiana, Texas, and South Carolina. 

The grim outlook for coal-fired generation in the United States mirrors the outlook for coal mining. The number of people engaged in coal mining has leveled out at about 41,000, down more than 75% over the last two generations, according to the St. Louis Federal Reserve Bank (

). And the amount of coal burned to generate electricity, after briefly surging in 2021 and 2022 as utilities restocked their fuel-depleted piles, is expected to fall in 2023 and 2024 (

King Coal’s woes are a result of many factors—regulatory, legislative, economic, and technological—but another significant contributor is the rise of so-called “respon-sible” investing, where bankers and investment managers at pension funds, mutual funds, and other sources of public and private capital use environmental, social, and governance (ESG) metrics to identify companies in which they want to invest—and those they don’t.

Institutional investors with more than $120 trillion of assets under management have adopted the U.N. Principles of Responsible Investing (PRI), which don’t permit investing in or lending to companies in the coal business (

Because each trend spawns a counter-trend, there has been some recent push-back against ESG, or “responsible” investing: 18 states have enacted or proposed legislation restricting the state from doing business with companies that use ESG investing criteria, arguing that those criteria mask a political agenda. 

During 2023, coal generators in a variety of states, including Michigan, Utah, Pennsylvania, Tennessee, West Virginia, and Texas, either were closed or announced premature retirement decisions. Asset owners claimed a variety of reasons for the decisions, but, broadly speaking, there were two reasons: 1) renewable generation, even allowing for its recent price increases, is still more economical than operating existing coal plants; and 2) state and federal environmental regulations and laws made it uneconomic to continue operating those plants.

A countervailing trend to coal unit retirements is the delay in planned retirements due to delays in interconnecting renewables to the grid, supply chain bottlenecks, and permitting delays. In the face of rising electric demand and continued uncertainties surrounding new-build projects, an operating power plant—even one that burns coal—is worth more than projects that remain on the drawing board.

Natural gas generation is feeling the fossil-fuel “splatter” effect that has hobbled coal-fired generation. Even though natural gas only emits about half the CO

 as coal when burned for generation, gas-fired generation still contributes to global climate change.

After a decade when developers made a “dash to gas,” that bloom is off the rose. Only about 4.7% of all new-build generation scheduled to begin construction over the next five years will use gas as a fuel. By contrast, as shown in 

, five years ago that percentage was 41%. A decade ago, that percentage was a still respectable 36%. Gas’ share of the electric fuel market should rise over the next five years, as Texas begins disbursing its $10 billion to support dispatchable generation. But for now, the new-build gas market remains a shadow of its former self.

The regions with the largest share of planned new-build gas generation are the Mid-Atlantic (15.6%) and the Great Lakes (13.6%). At the other end of the spectrum, the regions that plan to build the least amount of gas generation over the 2024-2028 period are New England (0.1%), the Rocky Mountains (0.3%), the Southeast (0.7%), and the Midwest (1.6%). All told, IIR expects about 19 GW of new-build gas generation to be built over the next five years.

By contrast, about $19.1 billion of new-build natural gas-fired generation projects that were scheduled to kick off during 2024-2028 have been canceled or placed on hold, according to IIR’s data. The states with the greatest dollar value of project delays or cancellations are Texas (nine projects valued at $6.6 billion), Michigan (six projects valued at $ 2.5 billion), West Virginia (two projects valued at $1.4 billion), and Florida (six projects valued at $1.1 billion). 

As large as these numbers are, they pale in comparison with the prior five-year period (2019-2023) when developers canceled or placed on hold 224 proposed new-build natural gas-fired projects valued at $80 billion. For that period, the greatest dollar value of cancellations and project delays were Texas (41 projects valued at $18.2 billion), Pennsylvania (25 projects valued at $7.7 billion), Virginia (seven projects valued at $4.9 billion), Ohio (eight projects valued at $4.5 billion), and New Jersey (seven projects valued at $4 billion). 

The wave of proposed gas plant cancellations and deferments doesn’t reflect the sharp political divide between blue and red states. Deep-red states like Texas, Florida, Indiana, and Ohio are among the leaders in gas-fired project cancellations or deferments, alongside deep-blue states like California, New Jersey, New York, and Pennsylvania.

Whatever the drivers—remember Tip O’Neill’s famous quip that all politics is local—the dash to gas has slowed dramatically. What could revive it? Widespread generation-related power outages. Perhaps Texas had solid reasons—beyond supporting the home team—to create a $10 billion fund to build or modernize gas-fired generation. 

As the United States sweltered under an unrelenting heat dome during the summer of 2023, fingers were crossed that power plants that were being run hard and long would hold up.

Developers who canceled or placed proposed gas-fired power projects on hold cited the shifting economics of electricity generation, driven by technology advances and regulatory or legislative mandates to build non-emitting generation. For example, New York’s plan to fight climate change envisions 70% of all electricity coming from non-emitting generation. California’s renewable portfolio standard (RPS) requires 60% of electricity to come from renewables by 2030 and 100% by 2045. 

The Golden State recently reported that RPS-eligible resources accounted for more than 37% of electricity delivered to custom-ers in 2021. But there are signs that the Golden State may be rethinking its stance on gas, at least for the near term. In a mid-year 2023 article, “California just can’t kick its coastal gas plant addiction,” the 

“Three natural gas-fired power plants in Huntington Beach, Long Beach and Oxnard were supposed to shut down in 2020, under a regulation designed to protect marine life. But (in 2020) officials voted to let the polluting generators keep churning out power another three years, just a few weeks after California experienced its first rolling blackouts since the early-2000s energy crisis. Now regulators are gearing up to approve another three-year extension, which would allow the plants to run through 2026. It’s only the latest illustration of the difficult balancing act California faces in its quest to phase out planet-warming fossil fuels and show the rest of the world that addressing the climate crisis is possible.”

The hand of environmental regulators in the state was forced after several summers of wildfires and power outages led to unpopular public safety power shutoffs (PSPS), where investor-owned utilities were given permission to preemptively shut off power in certain areas under red-flag conditions: high heat, low humidity, and high winds. Those conditions, coupled with failing utility equipment, have sparked extremely destructive wildfires in recent years. But even the PSPS could not stop rolling blackouts in certain areas during the blazing hot summer of 2022.

The state’s environmental regulators, forced to choose between people without power during broiling summers or fish that could be harmed by warmer water from gas-fired power plants, opted for people over fish.

The decision also was shaped by the state’s deepening “duck curve,” in which there is a surplus of renewable power during off-peak periods, like mid-day during the summers, and a shortfall during summer afternoons. Dispatchable gas-fired generation to the rescue! At least, for the short term.

California has not greenlighted a new-build gas power plant. Instead, it is trying to get a few more years of service out of the gas-powered generators on the coast, until battery energy storage becomes large enough, reliable enough, and economically viable so that it can replace gas generation. Gradually, gas generation will fade in California.

But gas is proposed as the fuel to power several large planned CCUS projects in the Golden State. Overall, gas will be used in about 4% of new-build generation constructed in the western United States over the next five years; by contrast, developers plan to build far more renewable generation—about 49 GW worth—in that region over that timeframe.

Gassier regions include the Great Lakes, where about 6 GW of new-build gas generation is slated to start turning dirt over the next five years. Developers also plan to begin construction of about 5 GW of gas generation in the Southwest during 2024-2028. In the Mid-Atlantic, about 3.6 GW of new gas generation is expected to begin construction over the next five years.

Electric asset owners have paid more volatile prices in recent years when com-pared with the quieter period of 2015-2020 when prices averaged a little more than $3 per million British thermal units (MMBtu) (

). But Winter Storm Uri in early 2021, and Russia’s invasion of Ukraine in early 2022, briefly brought gas price volatility back with a vengeance, according to the EIA. Market forces of supply and demand have since reasserted control, driving pieces back down to pre-Uri levels.

Electric generators are expected to pay an average of between $3 and $4 per MMBtu during 2023 and 2024, the agency predicted. Longer term, the EIA expects gas use for electric generation to fall about one-third, from approximately 12 trillion cubic feet (Tcf) in 2022 to less than 8 Tcf by 2030, though the agency’s Annual Energy Outlook acknowl-edged there could be a high level of variance under alternate scenarios (

). Demand for gas among electric generators will fall as renewables capture market share.


In mid-2023, as heatwaves broiled large sections of the United States, grid operators and the North American Electric Reliability Corp. (NERC) warned, once again, that the U.S. electric supply was one banana peel away from a catastrophic crash. Judging from the surge in announced new-build generation plans in recent years (

), developers and utilities have taken notice, though only 5% of new-build generation over the 2024-2028 period is expected to be fired by natural gas (

King Coal ruled the electric kingdom for most of the 20th century. Gas was great—for a decade or two. Now, we are several years into a period where renewables rock.

According to data tracked by IIR, about 460 GW of new-build renewable generation is scheduled to begin construction over the next five years, roughly 94% of all new generation.

Our traditional caveat applies here. IIR doesn’t believe all this planned new generation will begin construction accord-ing to this schedule. This is particularly true for renewable generation, which has become more competitive over the years but still has some reliance on state and federal tax credits and incentives.

Our power plant database continues to show a high level of dynamism for planned renewable generation: Each day, new projects are added to our database while others are deferred or canceled. In our experience, as much as half of all planned renewable generation projects eventually are canceled or placed on hold—nearly double the rate for proposed gas-fired generation.

No matter how the future unfolds, this is what we know today: Renewables are expected to account for approximately 94% of all planned new-build generation projects in the United States over the next five years.

By region, the areas with the greatest planned reliance on new-build renewable energy are New England (99.9% of all scheduled new-build construction), the Rocky Mountains (99.1%), the Midwest (98.3%), and the Northeast (96.3%). The least green regions, the Great Lakes and the Mid-Atlantic, still show renewable energy projects accounting for more than 80% of planned new-build power projects over the 2024-2028 period.

By type of generation, solar continues to be the leader: Approximately 45% of all new-build renewable generation built over the next five years is expected to be solar, continuing a yearslong trend where power from the sun is rising, while wind power is slowing (

Battery energy storage systems (BESS) continue to make sharp gains in new-build construction kickoffs: Those systems are expected to account for nearly 20% of all new-build renewable generation over the 2024-2028 period, up from 17% last year and virtually nothing in the prior years.

This extraordinarily green future may not fully come to pass if Congressional Republicans are successful in clawing back some of the estimated $369 billion in investments designed to slash CO

Another potential headwind blowing against renewable generation is the yearslong interconnection queue, driven in part by the sheer number of proposed projects. Significant delays in connecting new generation have taken place at most RTOs and ISOs, including PJM, MISO, SPP, and even ERCOT. In PJM, some projects have been delayed at least 24 months because they were unable to secure an interconnection agreement.

Like other sectors of the power industry, renewable developers and utilities are still working to remove supply-chain bottlenecks that have caused project costs to rise and in-service dates to be pushed back. Some sectors have fared better than others, but supply-chain delays have led to shortages of panels, inverters, and transformers.

Supply-chain snafus also are threatening plans to build wind turbines offshore. President Biden aims to have 30 GW of offshore wind operating by 2030, but the U.S. Department of Energy’s most recent estimate is that only 7 GW will be spinning by 2029. In addition to a global shortfall of underwater cables and inverters, these proposed projects face opposition from commercial fishermen and environmental activists worried about the impact offshore wind could have on their livelihoods and the underwater ecosystem, most notably whales and dolphins.

For all the forces driving the renewable generation buildout and the construction of new BESS, resource competition and prices have emerged as significant headwinds. Electric vehicles (EVs), BESS projects, and renewable energy generators all use, to some degree, the same minerals: lithium, nickel, cobalt, manganese, and graphite. Also, EVs use much more copper than their internal combustion counterparts. Demand for EVs, BESS, and renewable generation has surged, putting upward price pressure on the minerals.

There remains a pitched debate over whether the projected supply of these clean energy minerals will be sufficient to meet projected demand, and at what price.

The International Energy Agency (IEA) released a midyear 2023 report, 

, with an anxious undertone. “At a pivotal moment for clean-energy transitions worldwide, we are encouraged by the rapid growth in the market for critical minerals, which are crucial for the world to achieve its energy and climate goals,” said IEA Executive Director Fatih Birol. “Even so, major challenges remain. Much more needs to be done to ensure supply chains for critical minerals are secure and sustainable.”

The first unit addition to the Alvin W. Vogtle Nuclear Power Station was brought online on July 31, 2023, billions of dollars over budget and years late. Unit 4 is expected to begin commercial operations at the end of 2023 or the start of 2024. And thus, will end the much ballyhooed “Nuclear Renaissance,” perhaps better titled “Nuclear Renaissance Part 1,” as hopes are rising about its sequel: small modular reactors (SMRs). 

Presently, IIR is tracking about 2 GW of new-build nuclear that is scheduled to begin construction over the next five years. This includes: 

809 MW in the Rocky Mountains, split between the Utah Associated Municipal Power Systems (UAMPS) at the Idaho National Laboratory and TerraPower’s Natrium project at the Kemmerer brownfield site in Wyoming

798 MW in the Southeast at the Oak Ridge Clinch River brownfield site

320 MW in the Southwest, the Seadrift project is scheduled to be built at a Dow Chemical site in Calhoun County, TX 

Overall, new-build nuclear is expected to account for less than 1% of all new generation over the next five years.

Given the last 50 years of performance by the nuclear industry, with any type of reactor design and cooling systems, we have our doubts the industry can clear even that low bar.

In 2020, the UAMPS project secured a $1.355 billion grant from the U.S. Department of Energy to build up to 12 SMRs at 60 MW each. At the end of 2022, it reduced the number of units and increased the size of each SMR so that the net result was about 462 MW, down from the 720 MW originally envisioned.

One reason for the reduced scope: NuScale, the developer, in early 2023 said the target price for power from those SMRs had jumped 53%, to about $89 per MWh, up from an earlier estimate of $58 per MWh. Construction of the project is scheduled to begin in early 2025, and the units are expected to be operational by 2030.

The microgrid sector of the power industry continues to grow as the push for decarbonization, resiliency, and distributed energy resources moves forward.

Over the last couple of years, federal legislation, such as the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, as well as state-level regulations and the reliability-related conclusions of cities, military bases, commercial customers, and industrial concerns, have combined to expand the prospects for microgrid installations.

Moving into 2024, IIR expects spending in this sector to continue to climb, with more than $500 million in projects scheduled to begin construction that year alone. We expect that number will grow as we move deeper into the 2024-2028 period.

Industrial energy producers are feeling the push to install microgrids through either site-specific unit additions or through third-party agreements for microgrids to be installed onsite by a third-party owner-operator. One of the drivers in the industrial manufacturing sector is a renewed federal government push for all federal and military sites to have a microgrid installed by 2030.

Renewables continue to rock the new-build electric generation market, but gas-rich Texas, and some locals, are pushing back.

U.S. Power Industry Outlook 2024

The gas turbine market, in terms of producing electricity, is returning to its pre-Covid levels, and the market will remain stable for the near-to-mid-term future. These levels of production will be driven by gas turbine replacements and the implementation of new facilities to cover increasing power demands worldwide. Projected energy demand for natural gas usage and in turn gas turbines will be a key driver of production moving forward. Other forms of power production, such as coal, will lose ground to gas turbines and renewables. 

If there is one factor that has changed the technology of power generation more than any other it is the shift away from coal as a fuel source and the rise of natural gas. This shift is the result of three converging influences: The first is a general concern over pollution and the drive toward environmental responsibility. This has been given added impetus in recent years by concerns over CO

 emissions and their reported effects on climate. However, the turn against coal predates climate-change issues and owes much to the use of lignite as a power station fuel. Lignite—also known as brown coal or its German equivalent, 

—is laden with impurities and contaminated with materials that give rise to toxic byproducts, including the notorious “acid rain.”

The polluting character of coal-fired power generation has led to a concerted drive to get rid of it. In Western Europe, and the United Kingdom in particular, coal-fired power plants are under sentence of death, and dates for their closure have been imposed. In the United Kingdom, coal-fired power has now been phased out from energy production. In contrast, combined-cycle gas turbines account for roughly 52%, and nuclear power 23%, of energy production. This pattern is being repeated across the rest of Europe and into North America. However, coal remains a favored choice for power generation in countries like China and much of Eastern Europe because of those countries’ huge coal reserves and less stringent environmental policies. Even lignite remains in use despite the environmental damage it causes.

Gas turbines are therefore here to stay but are not the only source of power. Although relatively clean when compared to fossil fuel-driven energy production, gas turbines are not as green as wind, solar, and other renewables. Renewable energy plants are notoriously fickle when it comes to output. A heavily clouded, sunless day can drastically reduce power output from solar panels, and a calm windless day can have the same effect on power from wind farms. In theory, at least, there is a marked need to provide additional conventional power-generating capacity to act as a gap filler. The introduction of hydrogen into gas turbines will make them cleaner; however, there are issues such as transportation of the gas and modification of turbomachinery that must be solved before hydrogen’s widespread use. Manufacturers are currently working with their gas turbine products to burn hydrogen; however, mixtures of natural gas and hydrogen will likely be the norm before gas turbines regularly burn 100% hydrogen.

GE Gas Power, Siemens Energy, Mitsubishi Power, and Ansaldo Energia are forecasted as the top four turbine manufacturers over the next 10 years. Due to the war in Ukraine, both the Russian UEC Perm and UEC Saturn and Ukraine’s Zorya Mashproekt will lose market share as production levels have likely been negatively affected. Recent analysis of UEC Saturn and UEC Perm’s websites suggest that Russia is currently prioritizing service over production. The capacity in Russia is there, so maintenance in their current situation makes more sense than replacing gas turbines for more efficient units. Ukraine is likely in a similar situation.

GE Gas Power, Siemens Energy, Mitsubishi Power, and Ansaldo Energia are forecasted as the top four turbine manufacturers over the next 10 years.

Forecast International is forecasting that the lion’s share of gas turbines sold over the next 10 years will be turbines in the 250-500 MW range for power generation. This conclusion is based on historical sales and the popularity of machines in this class. Turbines of higher output and lower MW still have their place depending on the needs of the end user. 

Microturbines also have their niche and are forecasted for slight growth over the next 10 years. Capstone will continue to dominate the market with FlexEnergy following.

The COVID-19 pandemic hurt the market, but with sales recovering, the 10-year forecast should experience minimal growth in terms of unit production and remain largely flat barring any unforeseen circumstances.

Carter Palmer is an Industrial & Marine Turbine Analyst at Forecast International, a provider of market intelligence forecasting, proprietary research, and consulting services for the aerospace, defense, and power systems industries. Forecast's Platinum 4.4 information and analysis service was used to compile this report. For more information, visit 

There is a positive sales projection for gas turbines over the next decade.

Worldwide Gas Turbine Forecast 2024

’s 2024 Handbook features a collection of the latest news and products from the turbomachinery industry, a series of articles discussing topics such as compressors for carbon capture, transient faults in lube oil systems as well as forecasts for the U.S. power industry and the global gas turbine market. In addition to providing technical insights and educated forecasts, our 2024 Handbook includes our annual company directory and equipment specifications from leaders in the turbomachinery industry, including combined cycle, electrical generation, turbocompressors, steam turbines, turboexpanders, and mechanical drives.

Amin Almasi establishes a series of notes regarding lube oil systems in his Turbo Tips column, 

How Transient Faults Affect Turbomachinery Lube Oil Systems

. The column conducts an in-depth discussion regarding the steps an operator should take when faced with temporary faults, such as starting up the standby oil pump and maintaining pressure through a series of oil accumulators. Klaus Brun and Rainer Kurz’s Myth Busters column, 

Reciprocating vs. Centrifugal Compressors for Carbon Capture and Sequestration

, tackles the age-old debate of reciprocating versus centrifugal compressors but in the context of the new energy economy. In part one of this two-part column, Brun and Kurz focus primarily on applications and design— in terms of alternative energy sources, the primary gases of concern are green or blue hydrogen and CO

Britt Burt and Brock Ramey provided their annual forecast: 

. The authors cite a constant political push and pull as one of the obstacles to new-build renewable energy projects. “Our power plant database continues to show a high dynamism for planned renewable generation: Each day, new projects are added to our database while others are deferred or canceled. In our experience, as much as half of all planned renewable generation projects eventually are canceled or placed on hold—nearly double the rate for proposed gas-fired generation,” Burt and Brock said. “No matter how the future unfolds, this is what we know today: Renewables are expected to account for approximately 94% of all planned new-build generation projects in the United States over the next five years.”

The duo further breaks down each sector of the power industry—from coal and natural gas to renewables, nuclear, and microgrids—and offers insights into energy storage and industrial energy production.

Carter Palmer offers our readers his annual 

. Forecast International forecasts the lion’s share of gas turbines sold over the next 10 years will be turbines in the 250-500 MW range for power generation. Palmer said with sales recovering post-COVID, gas turbines’ 10-year forecast should experience minimal growth in terms of unit production and remain largely flat barring any unforeseen circumstances. Companies such as Siemens Energy, GE Gas Power, Mitsubishi Power, and Ansaldo Energia are forecasted as the top four turbine manufacturers over the next 10 years. 

The 2024 Handbook features coverage on compressors for carbon capture, transient faults in lube oil systems, industry forecasts, and our annual company directory and equipment specifications.

Handbook 2024

Turbo Tips: How Transient Faults Affect Turbomachinery Lube Oil Systems

Myth Busters: Part I: Reciprocating vs Centrifugal Compressors for Carbon Capture and Sequestration

U.S. Power Industry Outlook 2024

Worldwide Gas Turbine Forecast 2024

Turbomachinery International: Handbook 2024