Articles

Handbook 2022

TELL OUR READERS ABOUT ATLAS COPCO GAS & PROCESS.

Gas and Process is a division within the Sweden-based industrial group Atlas Copco, which has about 40,000 employees. Gas and Process is part of the Compressor Technique business area. We provide centrifugal gas compressors according to API 617 chapter 3, as well as turboexpanders per chapter 4, air compressors according to API 672, API 610 centrifugal pumps, and gas screw compressors.

Gas and Process is active in all segments of hydrocarbon processing, power generation (both conventional and renewable), industrial gases, as well as new energy and circular economy markets. It has production facilities in Germany, the United States, India, China, Canada, and Korea, and offers its corresponding aftermarket services worldwide. 

Traditionally, Atlas Copco Gas and Process has deep roots in air separation. We are still very active in this growth market; it is currently fueled by tremendous growth in chip and electronics production, for example, and this industry’s need for air and nitrogen. But today, the the majority of our business comes from hydrocarbon processing.

TELL OUR READERS ABOUT YOUR INTEGRALLY GEARED TURBOCOMPRESSORS 

Integrally geared compression (IGC) has been used successfully for more than 70 years. It is the core technology offered by Atlas Copco Gas and Process. IGC was originally developed for air separation and has seen growing use in chemical/petrochemical driven by several factors: Advances in dry gas seal technology, modern aerodynamics, rotor dynamic and thermodynamic knowledge; and advanced manufacturing and testing methods producing accurate rotating parts and complex components at reasonable cost.

In 2002, API included IGC in the 7th edition of API 617 under chapter 3. This confirmed its industry acceptance. Today our IGCs are used in industrial gases, power generation and all kind of hydrocarbons, as well as in new energy and emerging markets for decarbonization. 

Generally speaking, since they are a high head technology, IGCs are a good fit for all kinds of gases. In decarbonization, they are well suited for high mole-weight gases such as CO2.

The overriding trend is decarbonization, which causes processes to change and impacts compression. In emerging decarbonization markets, IGCs have gained a foothold as an efficient and reliable alternative to other compression technologies. Decarbonization of hydrocarbon processes is intertwined with the move towards carbon capture, utilization, and storage (CCUS). These factors drive R&D efforts of turbomachinery OEMs as they advance CO2 and hydrogen compression.

Hydrogen is challenging because of its physical properties and low molecular weight, as well as possible hydrogen embrittlement. But it provides many new opportunities. 

For CO2, Atlas Copco Gas and Process is focused on: using the existing and available CO2 molecules such as CO2 post-combustion processes; and blending CO2 with hydrogen.

WHAT DO YOU OFFER IN NON-GEARED TURBOCOMPRESSORS?

Our non-geared compressors for polyolefines and main air handle flows up to 65,000 m3/h, with a max. input power of 10 MW and max. pressure of 45 bar. Our non-geared compressors for main air handle flow volumes up to 500,000 m3/h, with a maximum input power of 30 MW. They are a good choice for applications with high flows requirements (we are now seeing requirements of 600,000 m3/h, or power requirements of 40 or more MW. In the hydrogen market, non-geared compressors could be an option for large flows since hydrogen does not require intercooling, and volume changes are minimal.

Companders combine compressor and expander functionalities: they are installed on a single gearbox and skid. Companders are used in several hydrocarbon processing applications, including carrier LNG, small-scale LNG and chemical/petrochemical, as well as sCO2. A compander is a feasible choice when the process provides an opportunity for energy recovery (process waste heat) or pressure reduction, with compression required from the adjacent processes.

WHAT ARE SOME OF THE CHALLENGES FOR HYDROGEN-RICH TURBOEXPANDERS?

ne of the key elements for hydrogen liquefaction is a turboexpander providing efficient refrigeration down to 20 degrees Kelvin. Radial inflow turboexpanders have been used in hydrogen-rich petrochemical applications (ethylene and propane dehydrogenation plants) for off-gas recovery for many years. The process gas for these petrochemical applications contains up to 90% hydrogen. However, the turboexpanders required for hydrogen liquefiers using pure or very high hydrogen mixtures are more challenging. This is due to high isentropic enthalpy drop, low volume, and speed limitation. These turboexpanders need aerodynamic and mechanical designs such as low-flow coefficient turboexpander wheel, high peripheral speed, thermal management, special materials, and innovative sealing. For standard 10-30 TPD liquefiers, oil-free bearing turboexpanders with hydrogen compressor load are preferred.

WHAT TURBOEXPANDER PRODUCT IS AVAILABLE FOR GLOBAL GAS PROCESSING?

While the oil and gas industry is typically viewed as a custom design market, local gas processing developers require standard package turboexpanders for plant sizes ranging 80-400 MMSCFFD. Early on in the shale gas boom, the market demanded turboexpander-compressors to be standardized for quick delivery. To meet this demand, Atlas Copco developed a product we call ECOTS (Expander Compressor Off The Shelf). Apart from the aero dynamic flow path parts, the package is a standardized and modular design. Our recently released ECOTS Plus has a smaller footprint, improved efficiency, and configurability to suit international gas processing markets.

WHAT NEW AFTERMARKET SERVICES DO YOU OFFER?

We recently added remote servicing and support through our family of connectivity solutions. Turboview enables us to connect to the customer site, identify problems, and provide initial advice remotely. We equip our technicians with Hololens technology, enabling aftermarket back office to better guide and support them at the customer site.

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Ulrich Schmitz, Vice President of Marketing Atlas Copco Gas and Process, discusses integrally geared compression, and how the company is responding to emerging markets for decarbonization, hydrogen, and CCUS. 

Integrally geared compression, decarbonization, and emerging markets. 

A high energy pump at a water injection station in El Furrial, Venezuela exhibited extremely high vibration levels prior to an overhaul. It then suffered a catastrophic failure during startup following overhaul. The hydrodynamic bundle, rotor, and drive end (DE) bearing suffered damage. 

This centrifugal pump is a 3,000 HP, double-case volute, boiler feed water pump type. It has nine stages, outputs 750 gpm of water with suction pressure 1800 psi and discharge pressure 5250 psi. Rated speed was increased from 6000 to 6600 RPM to enhance the hydraulic performance. However, the pump’s actual discharge pressure was about 4,500 psi, well below the target value of 5,000 psi. The coupling was reportedly poorly fitted. 

The increased RPM created rotordynamic concerns of getting closer to a critical speed, thus the operator wanted to know about the synchronous regime. The operator also wanted remedial measures and temporary mitigation steps to keep the pump running for 4-6 months until remedies were finally enforced. 

The course of action for this investigation was clear since the beginning: conduct an internal clearances analysis and a forced response rotordynamic study. 

A thorough study of internal clearances was conducted. Table 1 shows the results from this study featuring a comparison between internal (hydrodynamic bundle) clearances from different data sources, namely: design data, shop measurements, API-610 minimum clearances, and typical clearances for a similar pump with vibratory problems. As a result, the recommended clearance for the center seal, balance piston, eye, and impeller hub seals are shown in the bottom part of Table 1.

Due to the high vibration levels (20 mil DE, 5 mil NDE) reported before the overhaul, a simulation of the pump’s forced response rotordynamic behavior was attempted using a trial unbalance weight located in the coupling. A mass-elastic mathematical model incorporating the effect of the internal seals at 1X and 2X design clearance (as suggested by API 610) was used for this purpose. 

One can expect a flexible rotor behavior (first critical speed below operating speed) for this high-speed, long slender shaft, but the stiffening effect provided by the internal seals (Lomakin’s effect) locates the first critical speed in the vicinity of 9,000 RPM, well above 6,600 RPM operating speed. Retrofitting the bearing and coupling with the technology presented below raises this first critical speed to approximately 10,000 RPM, thus discarding the likelihood for resonance despite the steep vibration plot obtained during a ramp up vibration survey.

Our attention was focused on balancing and the effect on the dynamic stability of the rotor-bearing-support substructure. A bearing and coupling retrofit was recommended with a balancing plane on the coupling and an added mass on the bearing housing. It was discovered that the shaft was excessively long on the DE. Shortening the shaft together with a reduced moment coupling proved to be beneficial in keeping rotor synchronous response away from resonances. Such coupling design has a center of gravity and flex discs moved closer to the bearing.

tilting pad bearing is a good option for stability and support of this slender high-speed shaft. A pad load distribution analysis showed increased clearances unloading the top pads and the six-pad arrangement offered the best support. Furthermore, a lateral stability analysis revealed six-pad bearing to have the best stability parameters (whirl mode, log dec, amplification factor, undesirable speeds).

Effective mitigation measures that ran for a few months with acceptable vibration levels turned out to be:

Increase internal clearances and bearing clearances (max 6 mil).

Finning the bearing housing ribs for enhanced heat dissipation.

Using the coupling as a balancing plane; adjusting and balancing the coupling.

The most likely cause of failure was attributable to tight clearances found in the hydrodynamic bundle’s internal seals. OEM design and even API clearances were considered to be too tight. Reducing internal clearances below API 610 recommendations exposes these pumps to catastrophic failures during start up. For the impeller eye, we recommend a 50% increase (to 27 mil) over API values for stages 1–4 and a 25% increase (to 23 mil) for stages 5–9. Clearances for other rotor locations are shown in Table 1. 

Trimming the shaft in the DE side and installing a reduced moment coupling helps in separating the operating speed from the first critical envelope, thus reducing the amplitude of vibration.

Failure investigation, remedies, and mitigation of a centrifugal pump. 

Centrifugal pumps

This Forecast International market analysis of gas turbine-powered electrical generation projects that sales over the period 2021-2030 will total $107.705 billion. The prospect of recovery is convincing; however, 2021 might be stagnant with a similar outlook to 2020 due to the lingering COVID-19 pandemic. The dominant response has been to keep most workers home and severely restricted the movements of the rest. Depending on the geographical region, it remains to be seen if further lockdowns will be implemented. 

Yet despite COVID-19, it will be a short-term impact only and is already being quickly absorbed. Some countries will differ in their recovery. Therefore, production in Europe, Asia and the Americas might differ slightly. But a medium-term recovery is projected. 

In the power generation sector, the initial result was a significant decline, estimated at between 19 and 21% in energy demand as industrial facilities shut down. These developments have led the U.S. Energy Information Administration (EIA) to project that a total of 4.9 GW of previously planned capacity expansions will be delayed into at least 2021 or 2022. Natural gas consumption in the United States decreased in 2020 with some recovery likely in 2021.

Still, it is apparent from both the EIA analysis and our own data (which largely supports the EIA assessment) that the impact of COVID-19 on the power generation equipment industry is surprisingly limited at this time. It is mostly expressed as a delay of projects rather than a dramatic reduction in demand. It is a shallow, short-term dip in the recovery from the much more severe recession that has afflicted the industry since 2014. This situation may change if there are additional waves of the pandemic.

The extent of the market collapse over the last six years is remarkable. The estimated size of the market in this year’s market overview is just 48% of the figure recorded in 2014. When Larry Culp became CEO of GE in October 2018, he quoted a similar figure as part of the reason GE had suffered so severely during this period. Siemens’ assessment in 2018 estimated falling sales and industry production overcapacity to be in the same general ballpark.

This sharp fall is a direct result of the spreading crisis caused by overcapacity in the power generation equipment sector and the resulting softness of prices. In short, companies are selling significantly fewer power generation gas turbines than they had predicted and receiving a lower unit price for each sale. 

As a direct outcome, all three of the leading companies in the power generation equipment sector – GE, Siemens, and Mitsubishi Power – undertook restructurings to reduce costs and rationalize production. In an inevitable result, these companies announced redundancies. Yet these measures proved of only limited effect; a more fundamental reorganization of the sector appears to be taking place. 

General Electric has adopted a different strategy with its former Baker Hughes subsidiary. GE has divested itself from the oil & gas industry whereby Baker Hughes currently supplies gas turbines for compressor drive and power generation for that market. This is evident in that the relatively new LM9000 is marketed solely by Baker Hughes. 

The former Mitsubishi Hitachi Power Systems (MHPS) was subject to a different process. It was apparent for some years that the formation of the Mitsubishi-Hitachi joint venture had generated neither the business opportunities nor the technology benefits expected. In addition, the two companies were heading in different directions, with the opportunities for synergistic growth declining quickly. Representatives of Mitsubishi Heavy Industries (MHI) interviewed at trade shows made little effort to hide their disillusionment. In the early months of 2020, MHPS ceased to exist, to be renamed Mitsubishi Power. This has been consolidated further in 2021 into the fold of MHI.

Similarly, Siemens spun off all of gas turbines into Siemens Energy. However, GASTURBINES Like dollar value, unit production of gas turbines worldwide is beginning a slow recovery. But by 2024, sales will have jumped significantly from today’s level. This is projected to peak around 2027 and remain flat at a higher level for the remainder of the decade. unlike GE, the turbines offered seem to cover both the Power Generation and oil & gas industries as mechanical drive machines are still offered.

Often overlooked within the gas turbine market are the Eurasian countries of Ukraine and Russia. In regard to power generation, this is often attributed to a limited area of sale. Currently, Russia generally sells to Russia with Ukraine selling to slightly more customers. Licensed production usually takes the place of physically sending turbines to international operators. There is little information available from United Engine Corp. of Russia and Zorya-Mashproekt of Ukraine. But it seems that within both countries, maintaining machinery with some limited production in the power generation field is the current state of affairs. 

From a global perspective, the impact of reduced demand, overcapacity, and soft prices will slowly work itself out of the market. A recovery will take place. Natural gas and renewables will continue to gain ground over the next ten years thus securing the gas turbine’s place in the power market. COVID-19 means this recovery will be later than originally projected, but it will be slightly stronger as delayed projects finally get underway. Once the middle- and far-term periods are reached, the industry will be dominated by large combined-cycle facilities in the industrialized nations, notably Japan and countries in Europe and Asia.

In the period 2021 to 2030, Forecast International is projecting a worldwide unit production of 8,446 microturbine electrical power generation units, a significant increase over earlier projections of about 3,800 units. Value of production is projected to be $779 million. 

Reference to 2017 is important, as that was a pivotal year in the microturbine market. The increase in unit production and the decrease in average unit price are attributable to new, very small microturbines currently coming to market. Although they do not add much to the 2021-2030 overall value estimates, their production numbers are significant. 

Microturbines have generally grown in power output over the years, and that still holds true. When they started to become a significant market factor in 1999, the average unit on sale had a power output of about 35 kW. Ten years later, this had increased to approximately 100 kW, and it is now approaching 150 kW. There is even a 400 kW stand-alone machine; however, it is not in mass production. There is no indication that the trend of power increases is slowing. There are, however, microturbines going in the other direction. 

A trend is developing in Europe toward very small turbine applications. There was a time when microturbines were too powerful for a private residence. But times are slowly changing. MTT’s EnerTwin produces 3.2 kW of electricity and 15.6 kW of thermal power. This puts the machine in a prime position to be utilized in smaller buildings. These new turbines change the forecast significantly. Between 2017’s projection and this current analysis, unit production increases significantly, average unit value decreases significantly, and the total value for the forecast period remains nearly the same.

These new small machines from the likes of MTT and Bladon might change the landscape somewhat, but previous trends still hold true: microturbines have become more powerful, more fuel options are becoming available, and Capstone is still the market leader in terms of value. 

Today, microturbines are primarily used for remote power applications in the oil and gas industry and for cooling, heating, and power (CHP) and combined CHP (CCHP) applications in the commercial, industrial, and residential high-rise markets. The success of Bladon’s 12 kW machine would add power in remote locations to the list. An increasing energy demand-supply gap, a rise in the adoption of low-emission power generation sources, and the need to generate power cost-efficiently are some of the factors that will hold microturbines’ place in the market globally. 

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The gas turbine sales forecast for the coming decade. 

Worldwide Gas Turbine Market Report 2022

"Elections have consequences,” goes the political adage. That was particularly true for the electricity generation business during the first year of the new administration. On Day 1, President Biden issued a flurry of executive orders, including one to make the electric generation business carbon-free by 2035 as a step toward a net-zero carbon economy by 2050. 

All federal agencies were instructed to review, with an eye to reversing, all actions taken by the Trump administration that might conflict with or undermine the new president’s commitment to decarbonize the electricity business and the broader economy. 

“Confronting the carbon crisis” became a catchphrase. In some ways, this follows in the wake of the electricity business, which has been decarbonizing for years. That trend has been the product of federal and state tax incentives, state regulatory mandates, and technological gains that have improved the cost competitiveness of renewable energy. A growing preference for no- or low-carbon electricity also continued to gain traction among consumers and businesses during 2021.

A January 20, 2021, executive order revoked several executive orders from his predecessor on energy and electricity. Other Day 1 moves included returning the U.S. to the Paris Agreement and establishing an interagency working group to determine the social cost of greenhouse gases. Former EPA Administrator Gina McCarthy also became the first-ever White House national climate advisor. 

“The world must be put on a sustainable climate pathway to protect Americans and the domestic economy from harmful climate impacts, and to create well-paying union jobs as part of the climate solution,” the executive order stated.

The U.S. transformation from hydrocarbon-based electric generation to lesser or non-emitting generation accelerated during 2021, and most experts see further acceleration in the years to come. 

Although the COVID-19 pandemic cut overall electricity demand by 3.9% in 2020, the virus did not alter the existing trend to build fewer new power plants that burned coal or gas. For the 2022- 2026 period, Industrial Info Resources (IIR) expects renewables will continue to constitute the overwhelming majority of new-build U.S. electric generation projects, accounting for about 88% of all new electric generation capacity. Gas will account for about 11% over that five year period, with nuclear, fuel oil and coal sharing the remaining 1% of new generation construction (see map).

About 316,000 megawatts (MW) of new-build generation projects are being tracked with a scheduled construction start date between 2022 and 2026. Not all planned projects will be constructed according to their original schedules. Depending on the technologies involved, and developers’ ability to secure financing, offtake arrangements, and regulatory support, we typically see between one-quarter and one-half of all announced projects delayed or cancelled. But then again, new projects are announced on a near-daily basis. 

While all 316,000 MW of new generation are not expected to be built as announced, the trend for the 2022-2026 period is clear and consistent with longstanding projections: cleaner and greener new-build generation. 

And while coal has been out of favor in the new-build market for some time, the black rock certainly came to the rescue of existing electric generators and consumers in 2021. 

Once COVID-19 vaccines became readily available, U.S. consumers responded with a vengeance, driving up gross national product (GNP) and with it, electricity demand. For 2021, the U.S. economy is expected to grow 6.6%, and another 5% in 2022, according to mid-year 2021 projections from the U.S. Energy Information Administration (EIA). Based on projected strong economic growth (and assuming COVID is contained), the agency forecasts 2021 electric demand to grow about 2.7%.

Rising electricity demand in 2021 came as natural gas prices were on the upswing, rising about 60% through the first seven months of 2021, to about $4 per million British thermal units (MMBtu). For 2021, the EIA projected gas will average $4.46 per MMBtu. 

Generators that could switch fuels increased their use of coal in 2021, driving up coal use about 17% compared with 2020 (Figure 1). The EIA’s preliminary estimate of coal use in 2022 by power generators shows a decline of about 9% in 2022, as asset owners switch back to what they assume will be lower-cost gas. But as wave after wave of summer heat drove up electric demand, gas prices similarly went upward while coal stayed relatively flat. Could coal hold onto some of its newfound gains in the electric fuels market in 2022? 

Electricity generators drew down on their coal inventories to meet rising demand, according to EIA estimates (Figure 2). Roughly 23% of U.S. electricity was generated by coal in 2021, up from 20% in 2020, the EIA said. In 2022, coal’s market share is expected to fall to 21%. Existing coal- and gas-fired generators continued their bare-knuckled fight in the electric fuels market, where a shift of a few pennies per MMBtu can cause generators to swing from one fuel to the other. 

New-build coal-fired generation, however, continued to struggle in 2021 and faces a bleak future over the 2022-2026 period. Another recent force increasing King Coal’s misery has been the rising influence of environmental, social and governance (ESG) investing, which effectively bans investment in the coal business. By some calculations, ESG assets under management (AUM) soared to more than $100 trillion by the end of 2020 (Figure 3). 

During 2021, generators across the U.S. announced plans to phase out coal in the pursuit of net-zero carbon emissions. That trend is expected to continue in 2022 and beyond. 

The Tennessee Valley Authority (TVA), for example, has retired or announced the retirement of about 8,600 MW of coal-fired generation. It is evaluating the impact of retiring the remaining 6,000 MW of its coal fleet by 2035. That retired generation has been replaced by adding nuclear, solar and gas-fired generation as well as upgrading its hydroelectric power stations. 

In a mid-year 2021 announcement, TVA said it planned to invest about $1 billion to build new gas-fired combustion turbine generators totaling approximately 1,500 MW. The new facilities will replace aging gas-fired combustion turbines. 

In announcing that decision, Jacinda Woodward, senior vice president of power operations at TVA, said, “As we continue to evolve our generation portfolio, natural gas is the right choice at this time because it provides the flexibility and reliability we need to add more solar energy. It’s important to remember that solar power is an intermittent generation source, but natural gas delivers reliable electricity even when the sun doesn’t shine.” TVA will continue to consider natural gas’ role in its fuel mix as it studies the closure of its remaining coal fleet by 2035 while adding about 10,000 MW of new solar generation. 

TVA’s announcement came during a year when asset owners from Oregon to Florida announced plans to accelerate their move away from coal. During 2021, coal plant closure announcements were made by numerous asset owners, including Consumers Energy, Alliant Energy, Vistra, GenOn, Xcel Energy, PPL, Minnesota Power, NRG, Mississippi Power, American Electric Power and Lakeland (Fla.) Electric. 

IIR expects a surge in renewable energy construction over the 2022-2026 period, which would push overall new-build generation for that period to nearly 316,000 MW, up nearly 50% from the five-year plans of only one year ago (Figure 4).

At mid-year 2021, roughly 42,000 people were working as coal miners, up slightly over the year-earlier number of about 39,700. But the ranks of coal miners have thinned by about 75% since 1985, according to data tracked by the St. Louis Federal Reserve (Figure 5). 

In recent decades, employment in industry has been crippled by increased automation of mining, coupled with demand being crushed by ever-more stringent environment regulations, and the rising competitiveness of substitute fuels like gas and renewables. 

U.S. generators closed more than 100,000 MW of coal-fired generation between 2010 and 2020, and another 34,000 MW is expected to close during the next five years, according to data tracked by IIR (Figure 6). Though some states, like Wyoming, have tried to erect legal barriers to the closure of coal mines and coal-fired power plants, most observers don’t think those laws will be upheld by the courts. Economics more than laws will determine the future of coal and coal-fired generation in the U.S. 

Over the 2022-2026 period, construction is unlikely to begin on any new-build coal-fired power plants. Capital spending at coal generators will be for environmental remediation, particularly cleaning up coal ash ponds, and in-plant capital improvements like turbine upgrades.

Construction on about 35,000 MW of new-build natural gas-fired generators is expected to start during the 2022-2026 period. That’s about 11% of the 316,000 MW of new generation that developers plan to begin building during that fiveyear timeframe (Figure 7). The areas with the greatest amount of planned new-build gas generation are the Great Lakes, the Mid-Atlantic, the Southwest, the Rocky Mountains, and the Northeast. Very little new gas generation is scheduled to be built in the Southeast, Midwest, or West Coast. 

Developers and asset owners who have delayed or cancelled gas-fired, newbuild generation typically cite “market forces” as the reason for their decision. That covers a wide range of factors, including an inability to obtain financing, reach offtake agreements, or secure transmission rights. As gas pipelines start to run into opposition, stymied gas pipeline projects like the Atlantic Coast Pipeline are another market force with which developers have to contend. Finally, another powerful market force is a state’s regulatory regime, and several have turned against gas in recent years.

Renewables will continue to constitute the overwhelming majority of new-build U.S. electric generation projects. 

That’s certainly the case in California, Arizona and New York, where state commitments to reduce greenhouse gas emissions in the electric sector or increase the percentage of renewable energy in the electric mix work against gas. In addition, methane emissions have emerged as another market force working against natural gas generation. Methane is a much more potent greenhouse gas than carbon dioxide, at least over the short term.

The cancellation or delay of approximately 48 new-build gas-fired power plants has been documented in 25 states that were scheduled to begin construction in 2021. The total investment value of those plants was about $12.6 billion. As more states, and possibly the federal government, enact measures that cut against gas-fired generation, the number of new-build generation projects should continue to decline over the 2022-2026 period. 

About 35,000 MW of new-build gas-fired generation is scheduled to begin construction between 2022 and 2026. That is down a little over 10% from last year’s five-year tally and about 60% less than what was planned to kick off construction during the 2019-2023 period.

It was not that long ago that the power industry was proclaiming a “dash to gas,” as coal plants closed and before sharp declines in renewable energy costs. But recent trends shows a dramatic slowdown in new-build gas generation. Though most U.S. regions show a decline in planned gas-fired project kickoffs, the most dramatic declines are in the West Coast and Southwest (Figure 8).

Gas’ loss has been renewables’ gain. Renewables are now projected to account for about 88% of all U.S. new-build generation capacity over the 2022- 2026 period, roughly eight times the amount of gas-fired generation scheduled to be built over that time (Figure 9). That gap has widened over time. In 2018 looking at a five-year construction cycle between 2019 and 2023, renewables were scheduled to account for about 57% of all new-build generation scheduled to be built in the U.S compared with 41% for gas. But renewables’ improving cost competitiveness stemming from efficiency gains, coupled with a growing embrace by regulators and Corporate America, has widened its lead in the new-build race.

Over the next five years, solar is expected to surpass wind for the first time in utility-scale renewable energy construction (Figure 10). The widespread popularity of rooftop solar, both for residential and commercial settings, is not reflected in Figure 10, so the growing popularity of rooftop solar likely would give that energy source an even larger slice of the renewables’ pie.

About 1,450 renewable energy projects are scheduled to begin construction over the next five years. Those projects have a total investment value of about $390 billion. 

Again, all of those projects are unlikely to begin construction as scheduled. But over the next five years, the new-build renewable power business looks particularly green in the Rocky Mountains, the Southwest, the Great Lakes and the West Coast (Figure 11). 

Nevada and Arizona are the states in the Rocky Mountain region with the largest dollar value of solar projects under development. In the Southwest, solar project activity is taking place almost exclusively in Texas. The Great Lakes region also has a robust pipeline of solar projects being developed, with Ohio and Indiana in the lead, followed by Kentucky and Illinois, according to project data being tracked. 

Although fewer wind projects are being developed than in prior years, mostly because the areas with the best quality wind resource already have been tapped, the Rockies, Midwest, Southwest and New England are the regions with the largest dollar-value of wind power projects scheduled to begin construction between January 2022 and December 2026 (Figure 12). The Rockies, Wyoming, New Mexico, and Arizona are the regions and states with the largest dollar value of wind projects under development, according to data tracked.

The $390 billion of renewable energy projects under development include 27 offshore wind projects valued at about $39 billion. The Atlantic Ocean is far and away the leading body of water for proposed offshore wind power projects. The Biden administration wants to see as much as 30 gigawatts (GW) of offshore wind power developed in the Atlantic Ocean by 2030.

When politicians try to fight against markets, markets often win. We saw that most clearly in the Trump administration, which unsuccessfully fought against market forces to try to restore coal in the electric fuel mix. But Biden is taking the opposite approach, working to accelerate market-driven changes already well underway.

While in years past renewable energy projects would have had to include the cost of a transmission line to bring the energy to a market hub, several renewable energy projects announced during 2021 plan to be built on or near large shuttered plants to take advantage of existing transmission infrastructure.

Examples are NextEra Energy’s plan to construct a 690 MW solar plant next to its closed Duane Arnold nuclear plant in Iowa, and Xcel Energy’s plan to build a 460 MW solar plant on the site of its soon-to-be-closed Sherco plant in Minnesota. There should be many more over the next five years. Use of existing transmission lines also enables a developer to fast-track their project around clogged queues in regional markets.

The outlook for new-build nuclear is as bleak as the outlook for renewables is upbeat. The only planned new-build nuclear project, the Blue Castle nuclear power station in Utah, continues to be developed, with a planned construction start date of spring 2025 and a projected start-up date of mid-2032. The Blue Castle project is expected to utilize two 1,100-MW advanced passive reactors from Westinghouse. This project has been on the books for more than a decade, and its projected costs have mounted as its commercial operation date has been pushed back. There is a very low probability of this project ever getting built.

At the other end of the spectrum, a small modular reactor (SMR) project called the Carbon-Free Power Project continues to be developed by the Utah Associated Municipal Power Systems (UAMPS), a group of community-owned electric utilities across the intermountain West. 

In 2020, the group received a ten-year, $1.4-billion grant from the U.S. Department of Energy to develop and deploy 720 MW of SMRs in 60-MW modules. Originally, 12 were planned to be built at the Idaho National Laboratory in Eastern Idaho, with construction starting in 2025. But plans for that project were scaled back in mid-2021, as some UAMPS utilities rethought their participation in the project. 

Now, the UAMPS project envisions constructing only six modules, but a spokesperson for the group said these modules will be more efficient than previously thought. Instead of 720 MW consisting of 12 60-MW modules, the project now consists of six modules of 77 MW each, for a total of 462 MW.

Across the country in Tennessee, the Tennessee Valley Authority (TVA) is also contemplating SMRs as part of its plan to decarbonize generation. The agency has big hopes for the smaller nuclear generators, but its long-term resource plan does not contemplate construction beginning until 2027 at the earliest. 

The only new-build nuclear project still being constructed in the U.S. is the two-unit addition to the Alvin W. Vogtle Nuclear Power Station in Waynesboro, Georgia. Helmed by Southern Company subsidiary Georgia Power, Unit 3 expected to begin operating sometime during 2022. Unit 4 is scheduled to begin operating about one year later. 

As the project missed milestone after milestone in recent years, a construction oversight panel filed ever-gloomier reports about the costs and in-service dates of the two new units. A mid-2021 report from that oversight panel cast serious doubt on Georgia Power’s projected in-service dates for Units 3 and 4, and said construction costs could be as much as $2.4 billion over the most recent agreed-upon amount. 

Whenever those units are finished and whatever their eventual cost, expect a pitched fight at the Georgia Public Service Commission (GPSC) over how much of its investment Georgia Power can recoup from its customers. The unit addition’s other three owners, all municipal agencies, are not jurisdictional at the GPSC. But whatever that panel decides about Georgia Power’s 45.7% stake in the two new units could cast a long shadow over the other three owners’ regulatory decisions about the prudence of that investment, the quality of construction, and the effectiveness of construction management.

The other owners of Vogtle units 3 and 4 are Oglethorpe Power Corporation, a 30% owner, the Municipal Electric Authority of Georgia, which has a 22.7% stake, and Dalton Utilities, a 1.6% owner. Most of the value of work scheduled to be performed on nuclear plants over the next five years exists at the other end of the product life cycle: dismantling and decommissioning shuttered nuclear plants. A dozen closed nuclear stations are awaiting D&D work totaling about $19 billion. 

Roughly two dozen in-plant capital projects for nuclear generators are being tracked, including steam generator replacements, control upgrades, and extended power uprates. The value of this work is about $1.8 billion.

The outlook continues to brighten for battery energy storage systems (BESS) to become a more significant part of today’s marketplace (Figure 13). Regulators are providing incentives and allowing it to enter regional markets as a stand-alone generation resource. BESS is utilized for many applications, including: stand-alone generation resource; grid stability; renewable energy utilization; and storage for thermal generation.

Demand for BESS is rising, particularly in areas prone to natural disasters. The fast-paced push in the West Coast and Southwest to integrate these systems into electric markets is another factor creating a boom in this sector. 

In ERCOT, there is over 40 GW of BESS in early-to late-stage development being proposed for 2021-2023. This number may decline as projects confront permitting challenges, financing hurdles, and regional transmission constraints. 

Another driver for BESS growth is the late-2020 extension of the federal Investment Tax Credit (ITC) for solar energy. The guidelines grant ITCs to BESS assets based on its proximity to solar generation, its ownership, and whether it was being charged at least 75% of the time. The extension of the Production Tax Credit (PTC) for wind energy did not include a BESS provision. 

Like many other projects, BESS suffered COVID-19 supply-chain issues. The strong demand growth for lithium may act as a limiting factor in the near term, as projected demand for that metal, used in electric vehicles, cell phones, smart devices as well as battery energy storage projects, far exceeds estimated supply. There have been calls to expand lithium processing facilities in the U.S., but any such project would be years away from commercial operations. 

About 3.5 GW of battery energy storage that will become operational in 2021 is being tracked, an 80% increase over the capacity that began operating in 2020. Another 4.3 GW of BESS capacity is slated to come online in the U.S. by the end of 2022. The West Coast and Southwest are the regions with the highest level of project activity for BESS.

Currently, the U.S. has 115 operational microgrids that include over 2 GW of generation, according to the EIA. The referenced microgrids range from a segment of 500 kW to more than 100 MW.

Right now, these microgrids are being installed at military bases, universities and colleges, hospitals, police, fire and first responder stations, industrial complexes, government centers, and other settings where a high value is placed on having uninterrupted power. The annual spend to install microgrids is expected to be just below $1 billion in 2021. 

The pandemic dramatically slowed the deployment of microgrids in 2020 and 2021, and may not see a rebound until the pandemic and all its variants is conclusively defeated. COVID created a near-term pause in deployments, but growth should resume, possibly by mid-2022. The regions with the highest interest in microgrids are the West Coast and Southwest.

Natural disasters and prolonged power interruptions tend to drive microgrid deployment decisions, and there has been no shortage of natural disasters and power outages in recent years. Years of wildfires in the West, flooding, hurricanes, and the Texas grid breakdown of February 2021 are likely to lead a wider appreciation of the benefits of microgrids that utilize distributed generation such as solar or wind plus BESS. 

The cost of a microgrid will not be irrelevant in a company’s or agency’s planning. But we expect more projects will achieve financial viability when entities sharpen their proverbial pencils and take a closer look at the cost of a microgrid compared to the cost of power interruptions or unreliable power. 

Utility-scale microgrid projects, on the other hand, have encountered a variety of headwinds — including regulatory, permitting and financing — in recent years. Those headwinds have caused many projects to stall or be shelved. Construction costs continue to be a high hurdle to overcome at an estimated $2.6 million to $4 million per installed MW of capacity. 

State and federal grants for research & development have supported microgrid deployment. Congress is scheduled to consider a clean energy bill that includes up to $1.5 billion for microgrid R&D grants. About $2 billion in planned microgrid spending for 2022 is being tracked, a doubling of planned spending for 2021.

Over the last several years, distributed energy resources (DER) have become a more important element of the power generation business. As a category, DER includes a wide range of assets in smaller-scale settings, typically less than 10 MW in size. Types of DER include: small combined heat and power (CHP) units; wind; solar; battery storage; flywheel; biomass; waste-to-energy incinerators; small hydropower; fuel cells; reciprocating internal combustion engines (RICE); and generation that is part of a microgrid. 

DER also includes onsite power generation located at industrial or institutional sites such as colleges, universities, chemical processing plants, refineries, medical centers, military bases, manufacturing plants, and more. 

More than 29 GW of DER generation currently under development across the country is being tracked, with an additional 1.4 GW of generation in the early planning stage, with possible deployment by 2022- 2023. The regions with the largest planned spend on DER are the Southwest, Northeast, and Rocky Mountains. 

Orders 828 and 842 from the Federal Energy Regulatory Commission (FERC) determined that DERs deserve to be compensated if they provide generation or frequency support. Utility generation owners continue to have some concerns about FERC Order 842. 

In September 2020, FERC issued Order 2222, which expanded the definition of DER to include rooftop solar, electric vehicle charging system (EVC), and other micro-generation sources when coupled together. FERC followed that order with 2222-A, issued in March 2021, which removed other barriers to aggregated DERs in wholesale markets.

It is unclear whether full decarbonization of the U.S. electricity business can be achieved by 2035. But in the current business climate, decarbonization doubters have largely gone underground. Those advocating cleaner and greener power are driving the narrative.

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The Biden Administration stresses new-build renewables, but rising gas prices gave new life to coal-fired generators. 

US Power Industry outlook 2022

Before beginning specification, the turbomachinery should be sized. Final sizing will be done by the vendor/manufacturer. But a preliminary sizing is needed for a quality specification: such as specifying a single-stage turbo-compressor when a multistage turbo-compressor is not appropriate. There is often more than one turbomachinery type suited to a defined task. 

For instance, in many modern compression services both integrally-geared turbocompressors and conventional-type turbocompressors could be used. Once the different turbomachinery types are reviewed, various factors sway the decision. The key point is this: It is quite difficult to write a comprehensive multipurpose specification. Therefore, some decisions should be made at an early stage such as the type of turbomachinery. The specification can then be written based on these decisions. That specification outlines what the turbomachinery needs to accomplish and how reliable it should be.

Operational conditions should be divided into a set of normal condition(s) and those other than normal (such as alternative, emergency, etc.). Off-design or unusual conditions such as abnormal gas molecular weight (as might be encountered in a startup), a holding period where part of a plant is not in operation, and similar situations should be accurately included and explained. If anything is missed it could lead to future problems. 

The purchaser generally should know a lot about the plant, the processes involved, and its operation. In particular, the purchaser should be much more aware of unusual conditions, involved risks, and potential upsets. It is unwise to assume that a vendor is completely knowledgeable about the plant or process. 

Reference check any previously successful turbomachinery references in similar facilities. However, each plant or unit has its own set of challenges and specific requirements. Note that turbomachinery manufacturers are specialized in machinery design and manufacturing. Their staff, background, structure, and business are not focused on processes or plant operation.

Off-design or unusual conditions should be included in any specification. 

If the vendor’s engineers have experienced a problem in a process or facility similar to the plant under discussion, they may raise a question. However, this is not often the case. Take fluid temperature runaway potential in hot units. A specification should note some expected maximum temperatures and ask the vendor about the maximum temperature that the turbomachinery can handle. 

Past experience of operation could provide guidance concerning requirements such as the material selection. Stating minimum material requirements can help a vendor in part selection. On the other hand, a specification should not be so rigorous that it seriously limits the vendor. Any specification should specify the minimum material requirements and invite manufacturer input based on their experience.

A large number of unscheduled shutdowns are traced back to vendor design, manufacturing, material selection or component selection such as seal problems, bearing issues, excessive fouling, high degradation, corrosion, and erosion. However, many of these issues could be prevented if the purchaser communicated turbomachinery requirements, expected conditions, and technical specifications properly.

One example could be the selection of austenitic stainless steel. This is a premium material, but cannot be used if chlorides are present due to inter-granular corrosion and subsequent cracking problems. All traces of corrosive, sour or problematic materials should be accurately specified by the purchaser to prevent the selection of wrong material.

There have been many discussions whether to install machinery outdoors or indoors. If in doubt, specify an external location without roof or shelter. But later stages can add shelter or a roof if there is a need to increase overall reliability.

Turbomachinery design parameters, such as turbomachinery speed, should be given as the allowable values after enough research and checking into the most recent technologies and modern turbomachinery installations. These maximum allowable values should be insisted upon to keep bidding compatible.

More time is often spent specifying accessories than is spent on the core turbomachinery, mainly because options are so numerous. Some engineers reported that more than 50% of their discussions and communications with vendors have only been about instrumentations, condition monitoring, electrical systems and control items. All items related to electrical, control and instrumentation should be fully specified early in specifications and clarified at the earliest opportunity. Otherwise, lengthy and challenging discussions are to be expected. Reference: Royce N. Brown, Compressors Selection and Sizing, Third Edition, 2005 (Gulf Publishing, Elsevier).

A step-by-step guide on the turbomachinery specification process, including considerations for unusual conditions and indoor vs. outdoor installation. 

Turbo Tips: How to specify turbomachinery 

Hydrogen is a colorless, odorless gas that burns with a near invisible flame. So why do we constantly hear about green, blue, grey and other colors of hydrogen? What are these colors for?

Hydrogen “colors” colloquially refer to the way the hydrogen is generated. We have a rainbow of colors including brown, grey and black that are not part of the rainbow. For the most part, turbomachinery that either utilizes or transports hydrogen doesn’t care where and how the hydrogen originated. But it is still important to understand the basic nomenclature.

 hydrogen is produced without any greenhouse gas emissions. It is made by using electricity from renewable sources, like photovoltaics or wind power, to electrolyze water. Electrolyzers use an electrochemical reaction to split water into its components, hydrogen and oxygen.

 hydrogen is produced from natural gas using a process known as steam reforming, where natural gas and steam react to form hydrogen, but also carbon dioxide. To make hydrogen “blue,” the carbon dioxide must be captured and sequestered. If the same process is used, but the carbon is not captured, it is called grey hydrogen.

 hydrogen are made through partial oxidation gasification from black coal or brown coal (lignite). This is the type of hydrogen that creates the largest amount of environmentally damaging by-products.

) hydrogen is generated using electricity from nuclear energy. Just like green hydrogen, an electrolysis process is used. The difference is that the nuclear waste is created as a by-product of these processes. There are also some ideas to use the high-temperature reactors or available steam.

) hydrogen is made by a process called methane pyrolysis. The by-product is solid carbon. Depending on the thermal process that is used for pyrolysis — for example, whether it comes from renewable sources — and the capability to store the solid carbon permanently, this can be a low- or no-carbon process.

 hydrogen is produced by electrolysis directly from solar energy without the intermediate step of creating electricity. In some publications, the term ‘yellow’ hydrogen is used when the electricity for the electrolysis process comes from multiple sources, some of them renewable, some of them conventional.

 hydrogen, is naturally occurring geological hydrogen. Yes, there is a process that involves drilling a hole in the ground to get to hydrogen, with some fracking involved; however, there is currently no large-scale exploitation of this relatively rare resource.

Why do we care about these colors of hydrogen, especially since the machinery is agnostic to its source? There are two areas where the production source can make a difference: the pressure at which the hydrogen is available and the composition of the hydrogen gas.

Why are these features so important? Both relate to the fact that hydrogen compression is energy intensive. For a given mass flow, the amount of work to get a certain pressure ratio with pure hydrogen is almost 10 times higher than that of natural gas. Of course, hydrogen has a much higher energy density on a mass basis than natural gas (the lower heating value of hydrogen on a mass basis is 2.5 times that of natural gas), but even for the same energy flow, the compression work for hydrogen is four times higher.

On the other hand, even a small amount of composition impurity of the hydrogen, such as 4-5% carbon dioxide, can substantially lower the compression work by a factor of two. Therefore, it makes a big difference at what pressure and composition the hydrogen is made available in various compression processes. Also, both the combustion characteristics and the compression work change if other components (such as carbon dioxide or methane) are part of the hydrogen produced. Lastly, the capability of hydrogen to cause material issues (such as hydrogen embrittlement) can be influenced by the presence of other substances in the gas composition.

A third consideration of the source of hydrogen has less to do with the gas itself and more with the by-products of its generation process. Specifically, in processes that produce hydrogen from fossil fuels, carbon dioxide usually also is generated. For example, if blue hydrogen is produced from natural gas using steam reforming, about 10 kilograms of carbon dioxide are produced for every kilogram of hydrogen. In these cases, the separation, transport, and sequestration of carbon dioxide is necessary to maintain greenhouse gas neutrality — and that requires additional compression infrastructure.

The Myth Busters discuss the many colors of hydrogen and their place in the energy economy.

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