Modern centrifugal compressors using double-end variable-speed electric motors are high performance, efficient and reliable options for critical compressor services. The compressor train is usually equipped with two compressor casings coupled through two gear units on either side of a double-end variable speed drive (VSD) electric motor. Alternatively, a high-speed VSD electric motor can be used without any gear unit, or just one gear unit for the high-pressure casing.


A compressor of this type can easily compress a large volume of gas from the atmospheric level to a pressure above 150 Barg using a single train with two compressor bodies (casings), and each casing having eight or nine impellers. For some relatively heavy gases, discharge pressure above 250 Barg could easily be achieved using such a compressor train. Modern electric motor-driven compressors offer high reliability and availability, if designed, manufactured, and operated properly. A single shutdown every four years would not be unusual.


Single-end electric motor-coupled to two or three compressor casings have been the traditional configuration for multi-casing centrifugal compressors. One of the problems with a single-end electric motor has been difficulties in accessing the casings in the middle of the compressor train.


An integrally geared compressor is a multi-shaft centrifugal compressor which has different compressor casings, each driven by a pinion gear through a main gear. This is a cost effective and compact compressor option which offers many advantages. Typical benefits are high efficiency, low cost, lightness, and small footprint. Each individual impeller speed can be selected and optimized for the best overall performance and efficiency. The combined compressor package including intercoolers, aftercooler and piping can also be configurated in a very cost effective and compact unit. So which is best?


For process applications which require dry gas seals, a VSD double-casing compressor train might be a better option since the integrally-geared option might require 10 separate dry gas seals compared to four in a double-casing configuration. In addition, variable-speed operation (which could be in the 70%-105% range of nominal speed for double-casing machinery using a double-end VSD electric motor) might offer greater operational flexibility compared to fixed-speed integrally geared compressors. An integrally geared compressor cannot be variable speed due to complexity and design limitations. They use a less flexible inlet guide vane capacity control method.

In high-pressure process gas applications, the VSD double-casing compressor configuration is often a better option than an integrally geared compressor.

It is true that a compressor string with two gearboxes, two compressor casings and a VSD electric motor might result in a complicated torsional situation. In cases where torsional vibration frequencies coincide with resonance frequencies, large torsional deflections, and internal stresses could be generated. Continuous operation under resonance conditions could result in fatigue failure. Overall, however, the dynamic and torsional situation is less complex compared to the ones of integrally geared compressors.
In alternative configurations, high-speed VSD electric-motors with one gear unit or direct-drive arrangement, the dynamic situation is usually more favourable than with gear units or integrally geared compressors. The elimination of one or both gear units can ease the situation. Such a direct-drive configuration can offer better operation, efficiency and reliability.

Another factor to consider is that VSD electric motors generate pulsating torques. Even if the pulsating torques are very small with respect to the main torque, they can excite compressor train resonances with risks of damage to shafts or couplings. But aVSD double-casing compressor can be configured to improve access to bearings, seals and rotating assemblies. This compressor arrangement typically does not require interconnecting piping to be removed for normal maintenance access. Also, the allowable nozzle loads can be two or three times the allowable nozzle loads as per API-617. All these can offer a better piping, access and maintenance compared to integrally geared compressors, which mandate much lower nozzle loads (API-617 ones or even lower). Too often, expansion joints are needed. As an indication, nearly 50% of large integrally geared compressors in critical services have one or more nozzles with expansion joints.


Integrally geared compressors often use many interstage coolers and particularly large numbers of water-cooled heat exchangers combined in a compact package configuration. For a typical integrally geared compressor, the coolers should be supplied by the vendor, and there are more cooled stages and more coolers. In such a compressor package, though, coolers are usually marginally designed (often with minimum margins), and the interstage piping and associated pressure drops can be minimized by locating the intercoolers close to the compressor.


For some facilities, the use of water cooling isn’t an option. Air coolers should be used. In other units, the number of coolers should be minimized. For these cases, double-casings and four cooled sections might be a better option compared to the five or six cooled sections in an integrally geared compressor package.


For some compressor packages, coolers should be designed and fabricated by specialized cooler manufacturers with large margins and special provisions. There is a necessity to exclude coolers from the compressor vendor scope. The coolers should be ordered separately through a specialized cooler manufacturer under the direct supervision of the purchaser. There is a danger that coolers manufactured by independent manufacturers might not be coordinated to be included in a compact compressor package of a typical integrally geared compressor train. For such cases, an integrally geared compressor may not be a good option. The pressure drops between stages for air coolers, or independently provided water-cooled heat exchangers and associated long piping, can diminish the overall efficiency gains from the integrally geared configurations.


Usually, VSD double-casings compressors offer better operation, flexibility, reliability, and arrangement for high-pressure process gas services. They are recommended for many process services rather than integrally geared compressors.


Integrally geared compressors should be limited to specific applications where they can offer definite benefits. The best way to select between these two options is the evaluation of total cost of purchase and operation. Based on experience in nearly 70% of all high-pressure process gas applications, the VSD double-casing compressor configuration is qualified as a better option compared to an integrally geared compressor. On the other hand, there have been applications and services where an integrally geared compressor can be a better option than a VSD double-casing compressor package. There have been cases where the efficiency, compactness, low weight, and lower purchase price of the integrally geared compressor can offer an advantage over other compressor configurations. There have been cases where an integrally geared compressor was the only viable option for a facility. ■

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

Articles

Turbo Tips: Comparing Compressors

During a recent international turbomachinery conference, I participated in an interesting discussion about compressor impeller manufacturing. One of the participants confidently pronounced that three-piece and two-piece impeller manufacturing was outdated and should not be used anymore. The implication was that all compressor impellers must be manufactured as a single piece. I asked the basic question “Why?” to which neither he nor any my other expert colleagues was able to give a satisfactory answer. The current trend in manufacturing is clearly toward single-piece manufacturing. However, in many cases there is no justifiable reason or logic behind this.


Before getting into this discussion, some background information is warranted on how compressor impellers are currently manufactured. Industrial centrifugal compressors use fairly standardized casing, sealing, and rotor support elements, but their internal flow path must be customized for a specific application. To accomplish this, the compressor manufacturer usually develops families of impellers that are optimized for certain head and flow ranges. Some manufacturers will further scale, crop, or otherwise adjust the bases designs. So, what are the current processes to manufacture and assembling compressor impellers?


The key components of an impeller are the hub, the shroud, and the blades which, when assembled, are mounted on the compressor shaft or form part of the shaft. These components can be fabricated either in individual pieces or as single, two, or three-piece assemblies using:

1.	Machining (2D or 3D) from multi-axis milling, drilling, or turning. The most advanced being 5-axis machining which allows for the fabrication of complex shapes using subtractive manufacturing for almost all commonly used construction metals.


2.	Electrical Discharge Machining (EDM), which is a newer subtractive technology that is relatively slow and expensive but highly accurate. It produces accurate representations of a desired impeller geometry and can be used for most metals.


3.	Conventional casting which requires a carefully executed molten metal pouring and cooldown process. Casting methods allow an efficient production of identical impellers.

4.	Investment casting, a highly accurate process that produces quality individual impellers or components. It is seldom used for very large pieces.


5.	Additive manufacturing (AM) is a newer class of fabrication techniques based on building up geometries using small quantities of directionally layered materials to achieve a desired shape. The most common, commercially available AM method for printing metal compressor impellers is laser metal sintering using a metal powder bed. Here, a laser acts as a localized heat source to melt and fuse metal powder into a desired 3D shape, using sequentially layered metal powder. AM has shown promise for the manufacturing of smaller impellers. But most commercially available AM machines are limited in size and cannot handle impellers larger than about 20 inches in diameter, have relatively high dimensional tolerances, are limited to the use of a small number of expensive metals, and require post-processing to refine the surface finish. To date, many of the original promises of AM have yet to be realized. There appears no clear path forward to address some of the apparent limitations of this manufacturing technology.

Single-piece impellers are not always possible and are not the answer to everything.

As previously noted, single-piece constructed impellers are either cast, five-axis machined, or (less often) fabricated using EDM or AM. For impellers that are not of single-piece fabrication, they still need to be assembled to achieve the final geometry once individual pieces have been fabricated. Two or three-piece impellers are usually machined and then individual pieces are brazed or welded together. The most common approach is to utilize a two-piece construction where the hub is machined with the blades as one piece and the shroud is welded onto the hub assembly. Older impellers also sometimes used rivets and or even screws to fasten the shroud to the hub. But this is not commonly done for modern 3-D impellers and usually does not provide sufficient strength for highly loaded impeller applications.

How do we decide which fabrication and assembly technique is the most appropriate? They all work and have been demonstrated in thousands of compressor installations worldwide. The ultimate goal is to reproduce the aerodynamic designer’s intended geometry as closely as possible while staying within the required structural strength and dynamic fatigue limits and keeping fabrication costs reasonable. This is especially true for modern, complex geometry 3D impellers. Significant aerodynamic design improvements due to advanced CFD and FEA tools have changed the shape of impellers from traditional, simple 2D to highly flow-shaped, curved 3D geometries. The move from 2D to 3D compressor impeller geometries happened in parallel with a slow industry transition from two or three-piece construction to single-piece construction.

Single-piece impellers can often handle higher stress loads than two-piece impellers and may also reduce the potential for fabrication quality flaws. However, some shapes are difficult to machine as a single piece using 5-axis or EDM since these manufacturing tools require a line of sight access into all section of the internal geometry. Obviously, a clear line of sight internal access is not always possible for impellers that are highly backswept, have long inducer sections, curved splitter blades, or use other highly three dimensional geometry features. In this case, the only alternative is multi-piece fabrication, casting, or AM. Casting is expensive for one-off manufacturing and, as previously discussed, AM has severe limitations in size, tolerance, surface, and available materials. Thus, welding or brazing of two or three machined pieces is very often required.

It is not fair to simply malign multi-piece impeller construction. This type of compressor fabrication has been utilized for nearly 100 years and there is a wealth of industry experience and technology available to assure that it is performed without affecting the integrity of the impeller. The vast majority of all closed compressor impellers in the world utilized welded or brazed two-piece construction. Reputable compressor manufacturers have tightly controlled quality and inspection programs to assure that the welding or brazing fabrication process meets rigorous industry standards and the final product easily handles the strength and fatigue requirements of the compression application.


Clearly, there are advantages for single-piece impellers from a stress design optimization. In particular, AM as well as 5-axis milling or casting allow for the optimization of geometry for either stress or aerodynamic performance. But single-piece impellers are not always possible and are not the answer to everything.

Single piece impellers can be expensive and are more difficult to inspect for internal defects. AM is pricey and limits the types of metals that can be used. EDM is slow and expensive but accurate. 5-axis milling works best for high-flow impellers, and may not be feasible for low-flow impellers. Casting is only inexpensive if done for multiple identical impellers, but requires a well established inspection and quality control process. Two or three-piece impeller welded construction requires highly trained welders and inspectors, and two-piece brazing imposes size limitations.

Thus, there are pros and cons to each approach. There is no one-fit answer. All impeller fabrication and assembly methods can be appropriate and should be considered when designing and manufacturing a new impeller. Single-piece impellers are great but are not always the best answer for all compressor impeller designs. All methods have a place in the market. There should be no oversimplified, reflexive, unsubstantiated prejudices against any impeller manufacturing method or assembly methods. ■

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 and Gas Applications Committee.

SINGLE-PIECE IMPELLERS ARE NOT ALWAYS THE ANSWER

MYTH: IMPELLERS SHOULD BE SINGLE PIECE

WHAT DO YOU OFFER IN THE TURBOMACHINERY SECTOR?

Founded in 1867, Voith Group has more than 20,000 employees and locations in over 60 countries worldwide. The Voith Turbo division offers intelligent drive technology, systems, and services. Our family of geared variable speed drives (GVSDs) includes mechanical and hybrid drive technology suitable for various industrial applications such as compressors, pumps, fans, crushers, and generators. Furthermore, we have an extensive range of turbo gear units, previously known as BHS Gears. We have expertise that covers almost the entire horsepower range of global installed machinery, and our controls andactuator product range ensures reliable operation of turbines and industrial equipment.


In the thermal generation market, there has been continuous adaptation to more stringent environmental regulations. This trend will continue to play a pivotal role as almost every product required to sustain life is derived from the hydrocarbon molecule. We foresee newer processes and potential fuel sources coming to the fore; however, the critical installed base will continue to operate for the foreseeable future.


Turbomachinery equipment will remain vital to the extraction, transport, and processing of oil & gas products. But the transition to greener technology with electrification is resulting in a more extensive electric motor install base, especially within greenfield and retrofit projects. Overall, the big trends are the development of hydrogen and carbon capture technology, sustainability, electrification, and digitalization.


At Voith Turbo, several R&D initiatives are in place with a focus on carbon capture and hydrogen technology. We partner with engineering, procurement, and construction (EPCs) contractors and users to examine the market space and integrate our solutions into potential new applications. We plan to support the industry’s endeavor to become more sustainable.

WHAT IS YOUR TAKE ON THE GEARBOX VERSUS DIRECT DRIVE DEBATE?


The direct drive is unfeasible in most turbomachinery applications. Currently, no connected technology can replace the flexibility and reliability gearboxes offer. Gearboxes are proven and efficient, and the advances in metallurgy and manufacturing processes have increased reliability and durability.

Forming part of the Vorecon family, the VoreconNX is a hydrodynamic power transmission in combination with planetary gear. Thanks to the adjustable pump guide vanes in the torque converter, it offers an efficiency improvement of up to 8% at part load. This enables processes to run at precisely the required speed, resulting in better efficiency and energy savings. The latest generation VoreconNX is based upon components with a MTBF of 48 years in long-term operation. The integrated oil system supplies operating oil for the torque converter while simultaneously providing the drive motor and the driven machine with lubricating oil.


Since it was launched a few years back, Vorecon sales have remained relatively steady, and we engage interested customers daily. This technology offers substantial Capex savings.


Designed for the energy, petrochemicals, technical gases, and oil & gas markets, our single and multi-pinion integral gearboxes are efficient, require fewer stages than inline compressors, and have lower capital and operational cost. Voith integral gear units, formerly BHS Gear Units, have a smaller footprint and require a shorter installation period than other solutions. Furthermore, when it comes to safety where volatile gases need to be considered, peace of mind is guaranteed as our units are approved to handle inflammable, explosive, corrosive, and toxic gases.

For more information, visit voith.com 

QA: GEARBOXES WITH VOITH

Emerson is a global technology and software company headquartered in St. Louis, Missouri. It provides solutions across multiple markets and process industries, including power, oil and gas, and downstream hydrocarbons, among others. This includes technologies to manage, control, and optimize turbomachinery asset operation.

“Our portfolio includes automation & control software for turbomachinery operating in the power generation and process industries,” said Jim Nyenhuis, Manager of Performance Consulting for the Power Industry at Emerson. “More specifically, we provide turbomachinery control systems, supervisory control and data acquisition (SCADA), condition monitoring, and safety systems complemented by operations management software for asset and operations performance, data management and digital twin simulation.”

In addition, the company offers digital solutions for predictive AI-driven maintenance, remote monitoring, automated operational decision-making, and cybersecurity services designed to identify vulnerabilities, close protection gaps, and secure process control systems before an attack threatens to impact operations. For functional safety (SIL), it offers SIL3-capable safety systems together with an in-house expert team for SIL implementation on turbomachinery applications. The SIL safety system is integrated with the Emerson control system.

Nyenhuis noted several evolving trends associated with the transformation of the broader energy landscape to net zero and aggressive decarbonization. Reliance on renewables, for example, brings new challenges when working with intermittent power sources: That, in turn, requires greater asset flexibility and the necessity to closely monitor assets that operate differently than originally intended.

Workforce transitions, too, are exerting a significant impact on the industry: The accelerating loss of skilled technical workers due to Baby Boomer retirements, the mass resignation phenomenon coming out of the pandemic, and the influx of a digital native workforce generation. Combined, these factors bring to the forefront the need to address how organizations can operate and maintain equipment and facilities when faced with reduced staffing equipped with varying levels of hands-on experience.

Additionally, there is increasing interest in leveraging digitalization and data analytics taking root in an environment where many plants continue to operate with controls and automation systems of varying vintages from varying suppliers. This can impact both reliability and efficiency. It can be difficult to locate spare parts and personnel with the expertise to conduct the needed services for multiple outdated systems.

The modern plant environment calls for several elements: Quickly recognizing and responding to changing operational conditions for improved plant performance and flexibility; improving load flexibility by increasing ramp rates; better unit cycling performance and consistency; more robust and stable minimum load operation; and a decrease in the number of forced outages by reducing equipment stress.

New tools are emerging to help personnel make sense of the massive amounts of data they now collect. These tools and algorithms monitor equipment as well as process efficiency and health. When paired with various machine learning techniques and AI-based diagnostic solutions, the resulting intelligence can be used to predict and better manage potential failure situations.


Accordingly, Emerson offers a unified automation and software platform known as Ovation that helps to eliminate complexity and risk by capturing and contextualizing process and operational data.

“Ovation automation technology enables secure, reliable power plant, and equipment operation,” said Nyenhuis. “Emerson’s five decades of power generation expertise is embedded within Ovation software and technologies to form a digital platform that optimizes plant and equipment performance while reducing operations and maintenance costs.”

A single platform provides full power plant control, optimization, digital twin simulation, and analysis of all generating assets including major equipment, individual units, or multi-plant fleets. The software is also designed to incorporate renewable and distributed energy sources into the energy mix. It extends beyond the bounds of traditional distributed control and data acquisition systems to include integrated vibration monitoring, generator excitation control, safety instrumented systems, scalable footprints for small or distributed applications, virtualization, and embedded simulation.

Specific to the turbomachinery sector, Ovation Machinery Health Monitor integrates machinery protection and condition monitoring into an Ovation control system. The module snaps into the existing I/O base to provide continuous online monitoring of vibration and other machinery health parameters with orbit, waveform, and spectrum analysis display capabilities. Instead of alarms being generated after damage has occurred, Ovation HMIs display alerts based on sensor peak and phase values as well as Emerson PeakVue readings for rolling element bearings. Connecting the module to Emerson’s AMS Machine Works application provides condition monitoring capabilities outside of the Ovation network. A defense-in-depth approach to cybersecurity is built into the platform.

“The stress placed on rotating equipment can introduce premature component wear and other thermal and mechanical-related issues,” said Nyenhuis. “Failure events can develop slowly and quickly escalate to failure with little to no warning, putting the safety of plant operations and staff at risk. Vibration and asset monitoring solutions identify developing faults well in advance of breakdowns.”

Such technology is also being implemented in fields such as hydrogen generation, carbon capture and storage (CCS), and energy storage. For example, Mitsubishi Power America’s Advanced Clean Energy Storage Hub uses renewable electricity to power electrolyzers to produce green hydrogen. The hydrogen is then stored in salt caverns and dispatched when required to the Intermountain Power Project (IPP Renewed) to generate electricity from hydrogen-fueled turbines. Emerson is providing an integrated Ovation control and safety platform to optimize the hub’s production efficiency and help ensure safe operations.


Remote, real-time access to operations is more critical than ever, especially with the increase of geographically dispersed and often unmanned assets. Emerson has made progress in the establishment of remote operations centers. Control software detects the onset of an abnormal condition and alerts the operator to take action to avert potential problems. Plant data can also be sent to a centralized monitoring and diagnostics (M&D) center for longer-term, strategic analysis across the entire fleet.

“Remote and mobile capabilities enable secure and efficient access to data from anywhere at any time,” said Nyenhuis. “This enables faster and more precise responses to critical issues, as well as the ability to proactively address maintenance issues, minimizing costs and improving safety.”

For compressor drive units, for example, progress has been made integrating the compressor and prime mover controls for easier operation and maintenance and to streamline cybersecurity protection. Such gains are enabled by many factors, including advancements in the speed and bandwidth of networking technologies.


Digital transformation is being embraced across the industry as organizations seek to boost operating efficiency, decrease downtime, and reduce costs. Advances in Internet of Things (IoT) and automation technologies are opening the door to greater levels of digitalization.

However, Nyenhuis cautions those engaged in digital transformation that while a game-changer, it can also be a disruptor. It is not only about technology.

“Organizations are increasingly factoring in not only process and technology, but also their culture—seeking buy-in from the people who will be interacting most with the technology,” he said. “This last element, commonly overlooked in the past, is essential for successful digital transformation.” 

OVATION AUTOMATION & CONTROL SOFTWARE FOR TURBOMACHINERY 

VENDOR SPOTLIGHT: EMERSON

Siemens Energy has expanded its Innovation Center in Orlando, Florida. As the company’s first global hub for innovation, it is dedicated to accelerating the development of products and solutions to drive the energy transition through collaboration, rapid prototyping, and testing.

The company has spent more than $30 million over the last few years in building its research & development operations in Florida. Another $7 million during 2022 added an extra wing as well as equipment for the machine shop, further additive manufacturing (AM) machines, and more robotics to inspect and repair components for equipment like turbines capable of running on hydrogen. The expansion increases the space from 17,000 sq. ft. to 30,000 sq. ft.

“We operate with a start-up mentality, where ideas that used to take six months to test now take six weeks,” said Rich Voorberg, President, North America for Siemens Energy.


Turbomachinery International visited the center during its grand opening in October 2019. On our return in September of 2022, it was immediately clear that things had changed considerably. The company has substantially increased its manufacturing capability, increasing the volume of work in terms of man hours by around three times. A tour highlighted the fact that further space reorganization was ongoing to make room for yet more equipment.

“We have skills in-house that span mechanical engineering, electrical engineering, AI, welding, and a multitude of other disciplines,” said Voorberg. “We need all kinds of machinery to hand so we can develop prototypes rapidly and efficiently.”

Cliff Hatcher, CTO of the Innovation Center, led the tour. He said that the center was originally an experiment to see the effect of putting experts from multiple disciplines under one roof. Based on its success over the past three years, similar centers are being established in Berlin, Abu Dhabi, and China. In addition to new product and process developments, they will function as showrooms for what Siemens Energy is doing in the field of transformative technology.

“We wanted to be agile and have a footprint that could change as market needs changed,” said Hatcher. “We can work on one topic this week, and pivot immediately to another as required.”

AM represents a recent pivot. The center is working more extensively with AM to streamline the supply chain for 3D printed parts. It will help determine which parts should be made where based on quantity and complexity, as well as prototyping new parts to be printed and developing new techniques and processes. The company is also involved in the White House’s AM Forward initiative to help small businesses learn and adopt AM. This is just one facet of a shift from being a purely internal operation to using the center to engender creativity with customers and across the supply chain.

A customer site in South America, for example, had a legacy guide vane that was damaged during the disassembly process. The manufacturing plant no longer had the capability to make the part on an expedited schedule. After an exhaustive search for an existing part the service team ran out of options to meet the outage time schedule. They turned to Innovation Center Orlando to manufacture a new part that would meet the outage schedule of 15 days. The Innovation Center team 3D printed a replacement and shipped to their manufacturing facility in Charlotte to finish machining. In parallel, the center also machined a part from a block of steel on its 5-axis CNC machine. The parts arrived on time, costly damages were avoided, and the customer met its outage schedule.


During the tour, we previewed work being done to make the 3D printing of blades feasible. Previously, 3D printing was only really viable for smaller parts due to the process involved: a layer of metallic powder of about 40 microns is laid down and laser sintered then another layer and another. For larger parts subject to high stress and temperatures such as blades, the center is using Wire Arc Additive Manufacturing (WAAM). It lays down 20 mm layers of molten metal at a time. The process is being refined and requires a lot more finishing than traditional 3D printing.

Rich Voorberg said customers are keen to co-fund and co-create projects such as blade advances as well as in carbon capture, hydrogen, and other areas of the energy transition.

“Some customers are working with us to push turbine development to be able to run on 100% hydrogen,” he said. “The challenge is not so much in burning hydrogen but in establishing the entire hydrogen supply chain.”

Easier said than done. Hydrogen supply is extremely limited. Siemens Energy has developed electrolyzers and is working to scale up green hydrogen production. The recent infrastructure package enacted into law provides a $3 per kilo green hydrogen incentive, which will help ease funding stress on this technology. Nevertheless, we are looking at a long runway before hydrogen or some other fuel will replace natural gas.

“The amount of hydrogen you need to burn in large gas turbines is incredible,” said Voorberg. “We see the most viable market for hydrogen power being in areas such as buses, trains, and forklift trucks. But we will gradually see more hydrogen being blended with natural gas where it is available and economical to do so.” ■

Our site tour of Siemens Energy focused on additive manufacturing, prototyping new technologies, and decarbonization.

Siemens Energy Innovation Center 

The gas turbine power generation market is on the way to some normalcy after a decline in the mid-2010s and the COVID-19 pandemic. With recovery in prospect, the shift to greener machines is underway with the major turbine players announcing increasing amounts of hydrogen to power their turbines. Siemens Energy, General Electric, and Mitsubishi, in particular, are developing burners to adapt to a natural gas and hydrogen mix or even pure hydrogen. With that said, gas turbines will be needed moving forward to augment renewables, especially in North America and Western Europe. Gas turbines will continue to see advances in efficiency and will remain attractive options for power production.


This Forecast International market analysis of gas turbine-powered electrical generation projects that sales over the period 2022-2031 will total $117.087 billion. This is indicative of a recovery in the gas turbine electrical power generation market. The recovery from the mid-2010s was somewhat thwarted in 2020 by the COVID-19 pandemic. As COVID-19 hampered all activity for a time, the pandemic should be seen as a blip in terms of turbine production and not a lasting effect.

Hydrogen’s entry into the market should not be understated, and is becoming an attractive option as a fuel for gas turbines. Green, blue, or gray hydrogen can be used to power turbines. Green hydrogen especially can be produced in a carbon-neutral manner. When a turbine burns pure hydrogen, it emits no particulate or carbon monoxide emissions. This means the machine can be a renewable supplier of energy if the infrastructure is there to transport the gas.

Either electrolysis for onsite hydrogen or pipelines are needed to make hydrogen a reality in running gas turbines. According to some sources, a natural gas pipeline can transport a mix of up to 15% hydrogen with little modification. Higher mixtures would need adaptation. Over the mid and long-term, the industry will be dominated by large combined-cycle facilities in the industrialized nations, notably Japan and countries in Europe and Asia.

A major impact in the U.S. and Western Europe has been the emphasis on conserving energy and adopting energy efficient alternatives to existing equipment. For example, consumers have been urged to switch from the old-style incandescent lightbulbs to compact fluorescent lightbulbs (CFLs) and to LED bulbs. The cost savings are significant for the homeowner. In addition, it smooths out the spike in demand that takes place when people come home from work.

Changing user consumption profiles is a worldwide phenomenon, although the motivation may differ from region to region. In Europe and America, the primary driver is to reduce electricity demand and thus reduce pollution and eliminate potentially harmful emissions. In other areas, the economic benefits of new, power-efficient technologies are the leading driver, placing electrical equipment within the reach of people who otherwise could not afford to run it. This will work to increase popular demand for available and reliable power supplies. Thus, the same basic consumer trends that will depress demand for additional generating capacity in some regions will increase it in others.

 The impact of improved distribution and control networks is continuing to blur the distinction between baseload capacity and the rest. Only nuclear-powered generation is unequivocally considered baseload due to its long run times at steady-state load. In contrast, fossil-fuel plants are experiencing a different pattern of operation that exhibits frequent starts, load-following, and shutdowns to meet seasonal demands. As quick-reacting gas turbines replace steam machines, this trend is likely to continue.

However, it is well understood that the majority of breakdowns happen when a plant is either started up or shut down. This evolving operational profile is likely to increase the frequency of outages and the cost of procuring replacement parts. In parallel, sales of G-,H-, and J-class machines are increasing as utilities place more importance on efficiency and vendors accumulate operational experience with new designs.

Germany, France, and other countries are moving away from nuclear and focusing on renewables. Existing natural gas capacity will likely not be augmented, but will probably not be shut down. There are currently plants sitting idle but some may be brought back online. However, Russia supplied a majority of Europe’s gas. With the ongoing war, supplies of natural gas cannot be taken for granted. Norway can pick up some of the slack and run at increased output until 2030. It remains to be seen how the natural gas situation develops in Europe.

Electricity generation is rising in Eastern Europe, including Romania, Poland, Slovenia, Bulgaria, and Czech Republic. Aging coal plants are being replaced with combined-cycle natural gas plants. Renewables are not as prevalent in comparison to Western Europe; however, combined cycle plants will likely lay groundwork for more renewables.

 Southeast Asia’s energy demand is projected to grow by 80% by 2040 as the regional economy triples in size and population rises by almost a quarter to 760 million. As a result, it is likely that oil demand will rise from 4.7 million barrels per day in 2024 to 6.8 million b/d in 2040. At the same time, natural gas use will grow by almost two-thirds to around 265 billion cubic meters. In sharp contrast to other regions, coal demand will greatly expand and overtake oil to become the largest fuel. Renewables will make inroads but should decline from 26% of the fuel mix to 21%. The share of fossil fuels will rise to 78% by 2040.

India and China are the two most populous countries in the world by a wide margin. Both are short on electrical power. The generation capacity is inefficient and a major cause of pollution, while grids are incomplete and lack proper coordination and administration. As in Eastern Europe, coal plants will be replaced by natural gas.

In summary, Forecast International predicts that the importance of gas turbines will not diminish over time. More efficient machines will continue to be produced and hydrogen will play more of a role, although how big of a role remains to be seen. ■

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 www.forecastinternational.com

POSITIVE SALES PROJECTION FOR THE NEXT DECADE

GAS TURBINE FORECAST 2023

Conventional wisdom held that President Biden’s plan to decarbonize the U.S. Power industry was wounded critically, if not fatally, by the one-two punch of the U.S. Supreme Court’s Clean Air Act ruling in West Virginia v. EPA and U.S. Senator Joe Manchin’s (D-W.Va.) resistance to supporting Biden’s plan to fight climate change.


But Manchin reversed course and agreed to support a slimmed-down piece of legislation, the Inflation Reduction Act of 2022, that would direct an estimated $369 billion to renewable energy and climate-change measures. That law broadened and extended the federal government’s intervention in the power industry that stemmed from the 2021 Infrastructure Investment and Jobs Act (IIJA), which directed tens of billions of dollars into various aspects of electric power generation and grid reliability and resilience. But the U.S. power business appears to be headed for cleaner and greener pastures, according to new-build power plant data tracked by Industrial Info Resources (IIR).


Whether the U.S. generating fleet is cleaning and greening fast enough to make a dent in global climate change is the question. The Paris Agreement of 2015 pledged to take action to limit global temperature gain to either 1.5°Celsius or 2°C above pre-industrial times. The globe is nearly there, with cumulative temperature gain of approximately 1.2° C through 2022.
As the U.S. emerged from COVID-19 restrictions in 2021 and the government distributed trillions of dollars of aid, consumers engaged in “vengeance spending,” scooping up cars, taking vacations, and renovating homes.


The reckoning started in late 2021 and mounted in 2022 as prices rose for all goods and services — including energy. Gradually, the U.S. public became familiar with supply chain bottlenecks. Across the U.S. economy, inflation rose to a four-decade high, scrambling the energy sector. For the power generation industry, the wait list for new transformers stretched as long as three years.


As natural gas prices shot up, coal made some opportunistic market-share gains among operating power plants. But the sharp price increase of fossil fuels is expected to cause U.S. electric demand growth to revert to the mean of between 0% and 1% in 2022 and 2023, according to a global electricity report from International Energy Agency (IEA).


There is, however, no evidence that gas vs. coal jockeying for market share among operating power plants has had any bearing on the power industry’s new-build rush to renewables.



In 2014, when then-President Barack Obama first proposed his Clean Power Plan to reduce carbon emissions from coal-fired power plants by an estimated 870 million metric tons by 2030 compared with a 2005 baseline. The rule was finalized in 2015, but was never implemented because the U.S. Supreme Court, in a highly unusual step, blocked it. Years of litigation followed. The Clean Power Plan was the most litigated rulemaking that never went into effect in U.S. history.


While litigants wrestled, the market moved. For more than a decade, electric utilities, perhaps seeing the writing on the wall but certainly driven by the Clean Air Mercury Rule of 2005 and the Mercury and Air Toxics Standards rule finalized by the EPA in 2012, began closing coal-fired generators or switching them to burn natural gas instead. Federal activity on carbon regulation was also backstopped by state public utility commissions, which compelled utilities to file integrated resource plans (IRPs) on their proposed long-term electric generation options. Increasingly, those IRPs focused on decarbonization as well as low-cost options. As renewable energy became more competitive with traditional fossil-fueled generation, regulators pressed utilities to switch to the cleaner generation.


Long before the Supreme Court handed down its decision in West Virginia v. EPA, the market accomplished what lawmakers and regulators could not: meaningfully reducing CO2 emissions from coal-fired power plants. Between 2005 and 2020, according to the U.S. Energy Information Administration (EIA), CO2 emissions from coal-fired power plants dropped by about 1.2 billion metric tons — far exceeding the aims of the Obama Clean Power Plan (Figure 1).


As a demonstration of how far and fast the market has moved, renewable energy is now expected to account for about 94% of all new-build power plant construction over the 2023-2027 period. That is up from 88% of all new-build project kick-offs only a year ago. Five years ago, renewable energy was expected to account for about 56% of all new-build power plant activity over the 2018-2022 period.


For the 2023-2027 period, the rush to renewables is generalized across the U.S., but is particularly pronounced in New England, where renewables are scheduled to account for 100% of planned power plant construction, the Midwest (98%), the West Coast and Rocky Mountains (both 96%), and the Northeast (92%) (see map).


Overall, developers have scheduled the construction of about 405 GW of new generation over the next five years. That is up about 28% from a year ago, and nearly double the planned capacity additions from two years ago (Figure 2).

Not all of that new generating capacity will be built as scheduled over the next five years. Depending on the technologies involved and developers’ ability to secure financing, lock down offtake arrangements, and achieve regulatory support, we typically see between one-quarter and one-half of all announced projects delayed or cancelled. Higher interest rates mean that fewer projects will pencil out. But then again, as we have seen over the last 30 years, new power projects are announced on a near-daily basis.


Bottom line: Renewable power developers are in the green, and carbon-based developers are singing the blues.



IIR is not aware of any new-build coal-fired power project that is scheduled to begin construction between 2023 and 2027. This continues a long downward trend for new-build coal as well as in the number of coal miners and overall coal use by the power sector. Coal burned by U.S. electricity generators is expected to fall slightly in 2022, to about 482 million metric tons, and a further decline for 2023 is forecast by EIA (Fig. 3). Employment in coal mines held steady at about 38,000, as mines and their customers rationalized the demand for and supply of thermal coal (Fig. 4).

The IRA and IIJA laws provide some federal dollars for carbon capture and sequestration (CCS), which could help existing coal-fired power plants stay open. But we think those credits, on their own, will not be enough to help make any proposed new-build coal plants move forward. Over the next five years, most of the project spending that will take place among coal-fired power generators is expected to be for: dismantlement & demolition (D&D); environmental remediation, such as closure and cleanup of coal ash ponds; and in-plant capital spending on maintenance and upgrades.


We estimate that about $2.85 billion will be spent on D&D activities at U.S. coal plants over the 2023-2027 period. An additional $4.4 billion is scheduled to be spent on environmental remediation over that time. A third category of coal plant project spending, in-plant capital spending, covering boiler revamps, fuel switching, generator rewinds and turbine refurbishments, will reach about $820 million over the next five years. And $600 million is expected to be invested in planned maintenance at coal-fired generators over the next 2023-2027 period.


Although Coal Country welcomed the Supreme Court decision in West Virginia v. EPA, and cheered Joe Manchin’s months-long resistance to the president’s climate legislation, there was scant possibility that either would reinvigorate coal-fired generation or lead to the construction of new coal-fired generation. Mid-summer analyses from Morgan Stanley and Glenrock Associated were even bleaker: the Supreme Court decision in West Virginia would not create an opportunity to extend the lives of existing coal-fired generators, much less build new plants, analysts said. The court decision may be a setback for the Biden administration, “but utilities aren’t changing their plans,” according to Paul Patterson, an equity analyst with Glenrock Associates. He added that most of the action on reducing greenhouse gas emissions (GHGs) from the power sector has been driven by state policies, federal tax incentives, and corporate green power purchasing decisions. In the absence of federal action, there were plenty of other drivers pushing coal to the margins.

Once a coal plant is deactivated and mothballed, it’s not economic to reverse course and bring it back online. Approximately 115 GW of U.S. coal-fired generation was closed between 2011 and 2021. Going forward, we expect another 44 GW of coal-fired generation to be closed by 2025 (Fig. 5).

Numerous asset owners announced the closure of coal-fired power plants in 2022 or moved up the closure dates. During the year, the PJM Interconnection deactivated about 3.2 GW of coal-fired generation, most of which was owned by Energy Harbor. AES announced plans to exit coal by 2025. Duke told investors it would be coal-free by 2035. Xcel Energy plans to stop using coal by 2032. Public Service Company of New Mexico announced plans to close two units of its San Juan complex in September. There were many other announcements along these lines.


Another driver working against new-build coal generation is the rise of Environmental, Social and Governance (ESG) investing. More than 3,400 institutional investors have signed the U.N. Principles for Responsible Investing (PRI), and their assets under management (AUM) exceeded $121 trillion as of March 30, 2021 (Fig. 6). That means developers seeking to build new coal-fired generation have fewer places to source their capital.

In a cruel irony, it may be that the most valuable assets owned by retired or retiring coal-fired power plants are their transmission lines and their land. Numerous coal-fired plant sites — including those in Illinois, Colorado, Nevada, New Mexico, North Dakota, Nebraska, Minnesota and Maryland — are slated to be transformed into renewable energy and/or battery energy storage projects in the next few years, according to an investigation by The New York Times. In addition, two retired coal-fired power plants in Massachusetts and New Jersey are scheduled to be converted to receive power generated by offshore wind farms. Further out, Bill Gates-backed TerraPower has plans to build a small nuclear power plant on the grounds of a Wyoming coal-fired power plant that is scheduled to be closed in the late 2020s.


The outlook for new-build natural gas generation in the U.S. has dimmed considerably in recent years. Looking forward to the 2023-2027 period, that erosion is expected to continue. Over the next five years, new-build natural gas generators are scheduled to account for only 5% of all new powerplants scheduled to be built. Last year, that percentage was about 11%, and five years ago it stood at about 41% (Fig. 7).


What happened? One view is that gas became a victim of the “Carbon is Public Enemy #1” campaign undertaken by environmental organizations. A more nuanced perspective is that the hands of regulators have been tied by state laws and goals on renewable portfolio standards (RPS) and GHG reduction. Gas has a bleak future in states that are driving down their GHGs while increasing their RPSs.


On a percentage basis, the Mid-Atlantic region has the highest share of proposed new-build gas generators in the U.S., accounting for about 14% of all new power plants scheduled to be built over the 2023-2027 period. Following the Mid-Atlantic are the Great Lakes (12%), the Northeast (8%) and Southwest (7%). In terms of raw numbers, the Southwest has scheduled construction of the greatest amount of new-build gas-fired generation, at 5,456 MW, followed by the Great Lakes (5,376 MW) and the Mid-Atlantic (3,033 MW) regions.
Over two dozen proposed gas-fired generators that were scheduled to be built over the next five years have been cancelled. The aggregate value of those proposed projects exceeds $13 billion. The states with the largest number of project cancellations on a project-dollar basis are: Virginia ($1.8 billion); Texas, Pennsylvania and New Jersey ($1 billion each); and Florida, California and West Virginia (all slightly less than $1 billion each).


An additional 41 new-build gas-fired generation projects with aggregate value of $15.8 billion were scheduled to begin construction over the next five years but have been delayed. Texas is far and away the state with the largest dollar-value of project delays, at more than $8 billion, followed by Michigan ($2 billion) and Ohio ($1 billion). COVID-19 has been the cause of some of those project delays. The pandemic caused labor and materials shortfalls that have affected the entire power industry. Some of these delayed gas power projects could become reactivated over the next five years.


Organized wholesale regions like ERCOT (Electric Reliability Council of Texas) and MISO (Mid-Continent Independent System Operator) have sounded alarms of a potential generation shortfall in recent years, and the heat dome of Summer 2022 stretched those regions to the limit. Electric emergencies or rolling blackouts could focus the minds of regulators on the need for more dispatchable capacity. This bears watching, as events could cause regulators to relent and permit some new gas power development.


It is too soon to declare new-build gas plants a dead artifact of the 20th century. The thousands of MW of renewable energy that are operating, under construction or scheduled to be built will need to be backed up. That challenge outstrips the current capabilities of battery energy storage systems, even leaving aside the technological challenges of lithium ion battery systems, as well as concerns over the available supply of lithium. Pumped storage hydro facilities could be paired with intermittent generation, but the cost and timeline for building new pumped-storage facilities is daunting. In short, as much as policymakers and developers want to quickly move toward higher reliance on non-emitting generation, we see a continued need for new-build gas-fired generation.

In addition to new-build generation, IIR is tracking more than $13 billion in planned in-plant capital spending at U.S. gas plants over the next five years. Also, developers, engineers, and analysts are investigating the potential to co-fire gas plants with hydrogen.



Even before Senator Manchin reversed course over the summer and supported the president’s slimmed down climate-change bill, plans to build renewable energy generating capacity over the next five years were exploding. They have risen to about 379 GW or 94% of all planned new-build capacity over the next five years. Last year, renewables were scheduled to account for 88% of all new-build construction over the 2022-2026 period. Five years ago, for the 2018-2022 period, that percentage was 55%.


In assessing the new-build generation market, we did not include renewable energy plants that could get built due to the Inflation Reduction Act of 2022, as the thinner version of “Build Back Better” was tabbed. That proposal, with an estimated $369 billion in clean electricity funding, includes Production Tax Credits (PTCs) for wind, solar and battery energy storage, among other things. The PTC for solar power would be new, as that industry has depended on Investment Tax Credits (ITCs) for years. If anything, our estimate for the new-build renewable generation market for the next five years could be conservative.


On a percentage basis, the U.S. regions with the greenest hues are: New England (where 100% of new-build generation is expected to be renewable); Rocky Mountains and West Coast (each 96%). On a MW-basis, the regions leading the green power parade are: Rocky Mountains (133 GW), Southwest (78 GW), Great Lakes (39 GW), and West Coast (36 GW). Again, we don’t expect all this planned renewable generation to be built as proposed. But the 2023-2027 period is starting off with an enormous number of renewable energy projects.


“Other” renewable energy projects, such as hydropower and geothermal, are expected to account for as much as 49 GW, or about 12% of all renewable capacity scheduled to be built over the next five years. Hydropower, in particular, is expected to benefit from some $754 million in incentives contained in the Infrastructure Investment and Jobs Act, signed into law in late 2021 by President Biden. New-build hydro could also benefit from the Inflation Reduction Act of 2022, depending on how the enabling legislation is written: Will hydro be defined as a “renewable” source of energy? Given that people define “renewable energy” differently, we thought it would be helpful to provide a more granular look at how plans to build renewable energy break down.


The “run to the sun” has accelerated in recent years. In a category once dominated by wind power, plans to build solar generation have taken a decisive lead, with 49% of planned renewable new-build capacity, or about 184 GW, set to begin construction over the next five years (Fig. 8). Areas with the greatest amount of planned solar generation construction include the Rocky Mountains (55 GW), Southwest (52 GW), Great Lakes (26 GW) and West Coast (13 GW). A huge countervailing factor that could limit the growth in new-build solar is the rise in prices that started to become evident in 2021. The supply-chain bottlenecks and soaring costs for materials have derailed or delayed some of these planned solar projects.


Among renewable projects, wind power has long been the hare to the solar industry’s tortoise. But for the next five years, wind power will fall into second place with about 22% of all new-build generation, or about 82 GW. The U.S. regions with the greatest amount of wind power project activity over the 2023-2027 period, measured on a GW basis, include the Rocky Mountains (about 23 GW), Midwest (17 GW), Southwest (10 GW), and New England and Great Lakes (9 GW each).


Plans to build battery energy storage systems (BESS) have skyrocketed in recent years. Developers have announced plans to build as much as 64 GW of BESS over the next five years. Data from the EIA shows that developers proposed to sharply increase large-scale BESS projects between 2022 and 2024. Operational BESS capacity more than tripled in 2021, to 4.6 GW from 1.4 GW in 2020, according to the EIA (Fig 9). Most of that capacity was being deployed by regional transmission organizations (RTOs). Going forward, construction of new BESS capacity is expected to surge. The EIA projects BESS capacity will shoot up from an estimated 4.6 GW in 2021 to about 22 GW by 2025 (Fig. 10). About 382 BESS projects are scheduled to be built over the next five years, valued collectively at about $81.1 billion. The regions with the greatest amount of BESS construction activity are the: Rocky Mountains, with 76 projects valued at $33.3 billion; Southwest, with 109 projects valued at $23 billion; and West Coast, with 76 projects valued at $12 billion.


The first iteration of the nuclear renaissance looks like it will be ending with a whimper, not a bang: the last new-build nuclear power project, the two-unit addition to the Alvin W. Vogtle Nuclear Power Station, is scheduled to finish construction in 2023. Years late and billions of dollars over budget, the Vogtle unit additions, totaling 2,234 MW, were expected to be the showcase of a revived nuclear industry when they were announced in 2008.


The two new units now have an estimated $32 billion price tag, nearly three times the original cost of $12 billion. If the units are brought online in 2023, it will be roughly seven years after the first unit was scheduled to begin commercial operations. The owners, led by project manager Georgia Power Company, are embroiled in litigation over who pays what for the project. And GPC can expect some tough questioning from the Georgia Public Service Commission when prudency hearings begin.


As difficult as the Vogtle experience has been, and for the Virgil C. Summer Nuclear Power Station before it, at least those plants succeeded in getting steel in the ground. Another nuclear plant announced at the same time as Vogtle, the Green River Blue Castle Nuclear Power Station in Utah, hasn’t made it out of the starting gate, and may never. That two-unit project, with total generating capacity of 2,000 MW, has been under development since 2008. It was designed to use two Westinghouse AP1000 reactors before Westinghouse exited the nuclear business with a 2017 Chapter 11 bankruptcy. Currently, the developer plans to begin construction in 2025. There are more questions than answers for that Utah project.


For a lot of reasons, utility leaders have been looking elsewhere for carbon-free generation that can be dispatched. The thinking now is the future is smaller — specifically, small modular reactors (SMR). One SMR design, from NuScale Power, received an approval from the U.S. Nuclear Regulatory Commission in August 2020. The Utah Associated Municipal Power Systems is trying to develop SMRs at Idaho Falls, Idaho. And Terra Power is eyeing construction of a different type of nuclear reactor, a sodium-cooled plant to be built at a soon-to-be retired coal-fired power plant in Wyoming. Both of those projects are scheduled to begin construction toward the end of the 2023-2027 timeframe. Also near the end of 2023-2027, the Tennessee Valley Authority and OPG (Ontario Power Generation) plan to begin construction of SMRs in Oak Ridge, Tennessee.


The Inflation Reduction Act law contained production tax credits for nuclear, recognizing its role in decarbonizing the electricity industry. IIR doesn’t think those tax credits will be enough, on their own, to lead to new-build nuclear power plants over the next five years, but they would help keep existing plants open. On that front, license-renewal applications for several plants are likely over the next few years, including Comanche Peak (Units 1 & 2) in late 2022, Perry in 2023 and Clinton in 2024. IIR also is tracking almost $1.5 billion in scheduled maintenance activity and more than $33 billion of in-plant nuclear capital spending over the next five years. These figures don't include new-build nuclear construction projects.


In another sign of a nuclear resurgence, some in California are advocating that Diablo Canyon remain open after its scheduled closure dates of 2024-25, to provide generation and grid support for the energy-hungry Golden State.


Project spending by commercial, industrial, and institutional (CI&I) customers to construct non-utility generation in the U.S. has increased in recent years, and  IIR expects that trend will continue over the 2023-2027 period. There are various drivers:

•	Renewable onsite generation is being constructed by CI&I customers for decarbonization or GHG-reduction goals.
•	Some large customers have been investing in onsite generation to ensure always-on power.
•	Some are building onsite generation to offset the rising cost of electricity from utilities.
•	Large energy-hungry operations like data centers and bit-coin-mining operations have built industrial energy producers (IEPs) to ensure predictably priced power.
•	Local environmental regulations are causing some to replace diesel-powered generators with natural gas or even renewable natural gas.
•	Some power-sensitive manufacturers have resorted to building generation when local power quality is low.
•	CI&I customers that are remotely sited are installing independent power generation to ensure 24/7 operations. 

Sometimes this non-utility generation powers a microgrid. Other times it is for standby or emergency uses. As more companies in the CI&I sector tabulate the true cost of power outages or low power quality, we expect a growing number will choose to install their own generation.


New opportunities for this generation are presenting themselves. Although the idea behind distributed generation is that it will be used to power a particular site, ISOs and RTOs increasingly are seeking to interconnect the non-utility generation with the grid in order to provide reserve power or voltage support when grid-connected generation is stressed or stretched. Several independent system operators (ISOs) and RTOs across the country count on these resources to be ready to operate when the grid needs them. ERCOT, the system operator that supports most of Texas, is counting on these generators. Several times during 2022, ERCOT has called upon these resources to help meet the state’s peak electric demand.


Other states, such as New York and California, are pushing to connect these independent energy generators to their respective grids. Some studies have shown that use of onsite generation assets can cut overall power generation spending by 20% or more. As the rising price of natural gas pushes up the price of power purchase agreements, the installation of onsite power assets is becoming more appealing. IIR is tracking plans to spend more than $10 billion on non-utility generation over the 2023-2027 period. That number does not include smaller generation assets, such as rooftop solar or generators that have less than 300 KW of capacity.


Non-utility generation, like all other segments of the power business, is working to repair its damaged supply chain. The current three-year wait for transformers, plus bottlenecks and rising costs for solar photovoltaic and battery energy-storage materials, are evidence that broken supply chains are nowhere near repaired.


Microgrids are becoming more popular among CI&I customers for the same reasons as independent energy production. When powered by renewable generation, microgrids sometimes are part of an organization’s decarbonization push. When powered by fossil fuels, microgrids may backstop utility-supplied power. Microgrids can be part of grid strengthening and hardening, as we see after each bout of extreme weather.


Spending on microgrids could reach several billion dollars annually during 2023-2027. CI&I customers and utilities are finding that microgrids can fill an important need. Some utilities deploy them as part of a multifaceted effort to prevent wildfires, or to support remote communities at risk of outages.


The industrial sector looks to microgrids for onsite power during times of need and for protection against cybercriminals. Microgrids also provide power to the grid during peak demand. Industrial Info is tracking plans to invest more than $2.4 billion in microgrids over the next five years, (not counting potential commercial or residential). Microgrid projects are experiencing supply chain shortages, and competition for required skilled workers and equipment.


In the same way that transmission organizations and local utilities sometimes call on independent energy generators to fire up and provide generation or capacity to the grid during times of high demand or resilience events, microgrid operators are receiving similar emergency requests for grid support.


Over the 2023-2027 period, we expect new-build power to be characterized by market disruptions including: Technologies that generate electricity or support transmission and distribution; economic assessments of options; environmental regulations and exigencies surrounding generation; the regulatory framework; inflow of federal funds to support generation technologies; and consumer expectations.


The predicted rise of electric transport will likely add new strain to electric distribution networks and generation. But now, the power industry faces another disruption from employee expectations. A growing number want greater work flexibility. If employers want to win the war for talent, they need to learn to flexible and responsive to this aspect of industry disruption. 

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Britt Burt is Vice President of Global Power Industry Research for Industrial Info Resources (IIR), which is headquartered in Sugar Land, Texas, and has offices in North America and around the world.

Brock Ramey is a 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 www.industrialinfo.com or email powergroup@industrialinfo.com

CAN ANYTHING REVERSE THE RUSH TO RENEWABLES?

Handbook 2023