Drew Robb

Test engineer on Elliott's new cryogenic testing facility test floor. Image courtesy of Elliott Group. 

Turbomachinery International visited Jeanette, Pennsylvania to witness the opening of Elliott Group’s new $60 million cryogenic pump test facility. Construction on the Cryodynamic Products testing facility kicked off in December 2019. The ribbon cutting ceremony took place in late October, 2021. It included industry representatives as well as county, local, and company officials.

The speakers were: Toichi Maeda, Chairman and Director, Ebara Corp., parent company of Elliott; Curtis Antoniak, Mayor of Jeanette, PA; and Mike Lordi, CEO Elliott Group, who ended the formalities with a toast.

The new complex includes six buildings, with about 30,000 sq. feet under roof on the 13-acre campus. It will generate approximately 100 jobs. The test loop features two cryogenic pump test stands and a dedicated cryogenic expander test stand. As it is indoor and enclosed, weather conditions have no impact on testing.

"We can test a full range of cryogenic pumps and liquid expanders, from the smallest units, to units larger than those currently available in the industries we serve,” said Mark Babyak, Vice President of Cryodynamic Products and Industrial Products at Elliott. “We can test units with liquid nitrogen, natural gas, or propane, depending on their specific application, and we’re equipped with the latest instrumentation technology."

The facility has its own dedicated 25 kV electric utility service, a 25-ton crane with a 10-ton independent auxiliary hook, an energy-efficient cooling system, vacuum-jacketed insulated piping, redundant in-line heat exchangers, vessel-mounted tube bundle heat exchangers, and insulated vessels. In addition, its liquid storage tank farm houses a 60,000-gallon liquid nitrogen (LN2) tank, a 60,000-gallon liquefied natural gas (LNG) tank, and a 36,000-gallon liquefied petroleum gas (LPG) tank.

There are two cryogenic pump test stands. Test train 1 has three vessels (two pump and one dedicated to expander testing) with a maximum pressure of 2,160 psig and a maximum flow of 4,000 M3H. It has a 5 MW medium-voltage drive (range of 2,300 to 6,900 volts) and a 1 MW low-voltage drive (380 to 690 volts). 

Test train 2 has two pump vessels with a maximum pressure 3,600 psig and a maximum flow of 1,300 M3H, as well as medium- and low-voltage drives with the same specs as test train 1.

The dedicated cryogenic liquid expander test stand has an easily configurable test loop, standardized loop designs for upward or downward flow, and can test pumps while setting up the expander test loop. Its modular piping design can deal with inlet pressures up to 2000 psig.

Babyak said a few pumps had been tested as trial runs and that the facility would shortly go into full production. On the agenda are major tests for pumps and expanders destined for LNG projects around the world.

“We can test both column-mounted and vessel-mounted units,” said Babyak.

The company’s previous testing facility was not completely enclosed so weather such as strong winds often delayed tests. Further, only one test loop was available. Now with two test loops, Elliott can carry out lengthy setup procedures for one test while another test is ongoing. That means far more tests can be done, the size of unit that can be tested has doubled, testing times are decreased, and delivery schedules can be brought forward. The electrical load limitations of the older facility have also been eliminated.

“The size of liquefaction plants and expanders continues to grow,” said Babyak. “Hardly anyone else on the planet can conduct such tests, and our facility is much larger and more modern than any other.”

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Turbomachinery International attended the ribbon-cutting ceremony in late October, 2021. 

Elliott opens new cryogenic facility 

FS-Elliott is a manufacturer of oil-free air and gas compressors. In addition, it provides a line of lubricants and control systems. The company has been in business for over 50 years and operates in more than 90 countries. “Despite widespread cuts in spending from customers due to COVID-19, we are experiencing increased demand in some industries,” said Alex Curtin, Product Manager, Engineered and Air Separation at FS-Elliott. “The fact that the major oil indexes have steadily rebounded and major investments to address the global chip shortage are indicators of a strong air compressor market.” But the pandemic caused a shift in strategy for 2020. The company refocused its efforts on internal process and product management modifications to offer engineered products with improved prices and lead times. In addition, it revamped extended warranty programs, and released a new control panel to market.

FS-Elliott has two compressor product lines, the Polaris+ and the PAP Plus. Polaris+ air compressors serve customers in industries such as food and beverage, textiles, industrial manufacturing, plastics, and power generation. The PAP Plus line is mostly utilized in oil refining, petrochemical, and LNG production and transport. It offers compliance to API 672 and API 614 standards. The company is also active in the air separation industry, where both of its compressor lines are used. 

The PAP Plus A1 is FS-Elliott’s workhorse compressor for oil and gas. Primarily used as an instrument air compressor, the A1 is available in cost and short lead-time pre-engineered configurations to meet API 672/614 with critical reliability features. The A1 can be customized to meet specific requirements to ensure year-round reliability and operation. 

Curtin commented that compressor life-cycle costs are generally organized into three groups: capital investment or purchase price; maintenance; and energy usage. When purchasing a new compressor, the primary focus is generally on the purchase price. Over the life of the compressor, that is typically the lowest cost. Energy costs are the highest, followed by maintenance. The other impact to consider is the effect the air source can have on the finished product. 

“Oil-flooded compressor air sources use expensive separation systems and can leave trace amounts of oil that can transfer to the finished product,” said Curtin. “For those producing textiles, food products, or medicines, any potential for oil contamination is unacceptable.” 

He recommends that audits are performed on existing compressed air systems by a company certified by the Department of Energy AirMaster+ Program or that completed Compressed Air Challenge training courses for compressed air systems. The return on investment of an air system audit can be immediate based on what is uncovered during the process and the final recommendations. One example is an automotive component manufacturer in North Carolina that saved $100,000 per year on electrical usage and $25,000 per year on annual maintenance costs by converting three oil-flooded rotary screw compressors to a more efficient oil-free centrifugal compressor.

FS-Elliott offers a range of control systems, including both microprocessor-based and PLC solutions. Its control panels support needs ranging from a basic user wanting to turn the compressor on and let it run without worry to more complex solutions encompassing redundancy and monitoring of every characteristic of compressor operations. 

The new FS-Elliott R2000 control panel features improved energy efficiency and a better user experience while reducing downtime. On the energy savings front, an Energy Advisor makes suggestions to improve efficiency based on operating trends. Its maintenance notification system tracks compressor usage and provides predictive maintenance advice.

The FSE-TurboCool line of fluids feature extended fluid life, wear protection, and resistance to foaming. FSE-TurboCool and FSE-TurboCool HD are ISO 32- and ISO 46-grade lubricants selected based on coolant temperatures and environment. FSE-TurboCool FG is a food-grade version of a 32-grade lubricant created to meet H1 requirements for fluids with incidental food contact (FDA 21 CFR 178.3570). FSE-CentriMax is a 32-grade premium mineral oil and FSE-TurboCool CC cleans heavily varnished air compressors while the unit remains in operation.

FSE-TurboCool uses an ester-based lubricant suitable for use in all centrifugal compressors and offers advantages over glycol-based lubricants. “In most glycol-based lubricants, a secondary oxidative inhibitor must be added to capture water and aid in water separation, which deactivates over time,” said Curtin. “FSE-TurboCool’s oxidative resistance offers long-lasting protection against deposits and varnish, enables moisture buildup from condensate to drain, and improves the efficiency of the compressor’s mechanical components.”

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Vendor spotlight: FS Elliott

Now that coal plant emissions have been largely curtailed across much of Europe and North America, attention is swinging onto gas turbines. Such plants, by and large, do a good job at reducing emissions such as NOx and SOx.

"Power producers have already made great strides in lowering the carbon intensity of the power sector in the U.S., largely due to retiring coal and replacing it with a combination of natural gas and renewables,” said Evan Canady, Mitsubishi Power.

The solvent-based CO2 capture process. Source: IDTechEx.

The direct air capture process. Source: IDTechEx.

However, the current demand is that gas-fired plants greatly reduced their carbon emissions. This can be accomplished either by pre-combustion carbon separation (usually using methane steam reforming to syngas with subsequent water shift and CO2 removal) or post-combustion flue gas CO2 removal. 

The big hurdle, of course, is cost. Current technology is expensive and energy intensive. Not only is the carbon to be captured, it also needs to be stored somewhere and increasingly utilized in some process. Hence the term carbon capture utilization and storage (CCUS). (Note: It is also sometimes called CCS. 

Most attention, to date, has been lavished upon solvent-based capture i.e., the gas stream is exposed to a liquid medium to absorb CO2 via some kind of physical or chemical mechanism. Regeneration is also needed to break absor-bent-CO2 bonds.

Drawbacks include high energy consumption, corrosion, difficulties in scaling, and raw economics. Why spend money to develop and implement the technology in an environment that shows little love for fossil-based fuels. Nevertheless, advances have been made. Amine-based solvents from Mitsubishi have been used in the Petra Nova facility in Texas. Shell Global’s CanSolv is another solvent being used at the Boundary Dam project in Canada. Similarly, physical absorption solvent breakthroughs have been made such as Lurgi’s Rectisol process using chilled methanol as a solvent. Further areas of development include: solid sorbents are being developed by Svante in conjunction with Chevron and others; the Polaris membrane by Membrane Technology and Research in collaboration with the U.S. Department of Energy; SES Innovation’s cryogenic carbon capture; and FuellCell Energy’s fuel cell technology for carbon capture, using electrochemical membranes to separate CO2 from industrial waste gas streams. Further, Chart Industries (owner of LA Turbine) has developed Cryogenic Carbon Capture (CCC) technology. The cost to produce cement and capture CO2 using CCC technology is said to be 24% higher than producing cement with no capture.

Another approach is direct air capture (DAC) to strip CO2 from air using chemical and physical processes. Those working on this include Climeworks with a plant in Switzerland and Carbon Engineering from British Columbia, Canada, that plans to build a Permian Basin facility that to capture a million tonnes of CO2 per year by 2024 using a high-temperature aqueous method based on potassium hydroxide. Global Thermostat, too, has pioneered a porous, honeycomb ceramic approach to carbon capture. 

According to IDTechEx, capturing a tonne of CO2 directly from the atmosphere costs between $600 and $1,300 using current technology, compared with approximately $40 to $80 for capturing a tonne of CO2 from the flue gas stream of a coal-fired power plant. Despite that, the analyst firm forecasts that DAC is likely to gain a growing share of global CO2 capture capacity over the next few decades.

Wherever you turn, there are contrasting views concerning carbon capture. Some see it as entirely feasible, some as completely impractical, and others are somewhere in the middle.

Geert Laagland, Head of Engineering at electricity and district heat utility Vattenfall, said high upfront costs for CCUS means it is only going to be viable if a plant is going to run a lot of hours.

Mark Axford, Principal at Axford Turbine Consultants believes that CCUS represents a more credible path to lower emissions than the ongoing love affair with hydrogen. 

“Carbon capture of natural gas is probably a far more economical path than trying to convert everything to 100% hydrogen,” said Axford. 

“Post-combustion CO2 removal is technically viable but impractical because of the large volume flow and the need for high ratio CO2 compression,” said Klaus Brun, Director, Research and Development, Elliott Group. 

Let’s hear from the OEMs on how they plan to overcome the technical and overcome hurdles present in CCUS.

According to Arja Talakar, Senior Vice President, Industrial Applications Products, Siemens Energy, the critical element in CCUS is early engagement. With carbon capture, that means engaging early in the pre-FEED and FEED study stage. 

“The most successful CCUS projects will be those where the OEM and the developer have optimized cycle performance with machinery economics and considerations,” said Talakar. “While there are few commercial projects right now, many projects are being discussed and evaluated.” 

Siemens Energy is collaborating with BASF on proton exchange membrane (PEM) electrolyzers for hydrogen pro-duction with an output of 50 megawatts and the possibility of modular capacity expansions. It is also working with Aker Carbon Capture to develop carbon capture solutions that can be applied to gas turbines and gas-fired power plants. 

“New turbines and CCUS can provide sustainable solutions for the 21st century,” said Talakar. 

Why aren’t there more carbon capture projects addressed to natural gas-fired power facilities? He believes coal gets all the attention as it is dirtier and there represents the low-hanging fruit. He out-lined three points to bring down the cost of carbon capture projects associated with a combined cycle gas turbine (CCGT):

Be as efficient as possible to reduce the quantity of CO2 to be captured.

Reduce the temperature of the flue gas to reduce the need for cooling before capture.

Increase the concentration of the CO2 in the flue gas. 

Siemens Energy is conducting optimization studies with Total and others on ways to reduce CO2 emissions, focusing specifically on natural gas liquefaction facilities and associated power generation.

“To reach a 50% reduction in CO2emissions by mass, you need about 80% volume of hydrogen fuel content,” said Talakar. “While it isn’t economically viable today to operate large gas turbines at this level of hydrogen fuel mixture, these levels are within reach with smaller gas turbines, especially when considering hydrogen flare gases from petrochemical sources.” 

Adding 10% volume of hydrogen to natural gas will reduce CO2 emissions by 2.7%. A 600 MW combined-cycle power plant that runs 6,000 hours a year at 60% efficiency would equate to a reduction in approximately 1.26 million metric tons of CO2. In Brazil, for example, the company has two SGT-600 turbine generator sets operating on residue gas with high hydro-gen content at a cogeneration plant. 

“Compressors can be used to safely and cost-effectively transport and store CO2 or hydrogen,” said Talakar.

Alongside several companies led by Highly Innovative Fuels (HIF), Siemens Energy is developing and implementing a commercial large-scale plant in Chile for the production of e-fuel (synthetic methanol for e-diesel, e-gasoline, or e-kerosene). Electrolyzers use wind power to split water into oxygen and hydrogen via Proton Exchange Membrane (PEM) electrolysis CO₂ is captured from the air and combined with hydrogen to produce methanol. About 40% of the methanol is converted into synthetic gasoline.

Atlas Copco Gas and Process has been involved in CCUS for about 15 years, supplying compression equipment for a variety of applications. It is currently seeing increased activity in the utilization of supercritical CO2. 

A CO2 compressor by Atlas Copco Gas and Process. 

“Many major players want to continue operating their fossil-based processes so they are putting more focus on capturing and using CO2,” said Ulrich Schmitz, Marketing Manager at Atlas Copco Gas and Process. Some developed countries are not only sequestrating the CO2, they are utilizing it to produce consumer goods such as blending it with hydrogen to make methanol.” 

Most R&D focuses on two main types of CO2 utilization, he said: Using existing and available CO2 molecules for CO2post-combustion processes (oxy combustion); and blending CO2 with hydrogen to create methane or methanol.

CO2 has special characteristics and challenging properties such as a heavy mole weight gas and abundant volume. Centrifugal machinery, therefore, is a very good fit to process it, particularly integrally geared compression which is a high head technology. In addition, it pro-vides a favorable pressure ratio as well as intercooling.

MAN is another company with extensive experience in CO2 compression – more than 20 years. Out of 18 large-scale facilities in commercial operation around the world, eight use MAN’s CO2 compression technology. For instance, MAN’s RG integrally geared compressor has been deployed at a commercial-scale CCUS project to tackle carbon emissions at an oil-sand operation in Alberta, Canada. Shell’s Quest plant has captured and injected more than one million tons of CO2 underground annually since 2015.

MAN'S RG integrally geared compressor for carbon capture and storage. 

"Power, heat generation and industries like cement and steel production are responsible for approx. 60% of all CO2 emission and thus are the focus of decarbonization,” said Peter Klotzsche, MAN Energy Solutions.

The company has signed a technology-cooperation agreement with Aker Carbon Capture to provide new energy-efficient compression solutions for CCS applications with heat recovery. Further, it supports CO2 utilization applications for urea production, Enhanced Oil Recovery (EOR), methanization, synthetic fuels and methanol production with compression and reactor technologies.

The Baker Hughes take on CCUS is that there is no single solution. The approach to carbon capture on an offshore natural gas platform, for example, would vary from a carbon capture design for a refinery or a cement plant. Accordingly, the company has several arrows in its CCUS quiver. It acquired Compact Carbon Capture, which uses a rotating bed technology instead of static columns to dis-tribute carbon capturing solvents in a compact and modular format. It secured the exclusive license of SRI’s Mixed Salt Process, a solvent process that uses potassium and ammonia. In addition, it is examining how the chilled ammonia process (CAP), which uses aqueous ammonia as a solvent, can capture carbon dioxide from mid- to large-scale industrial sites and other sources of CO2 emissions.

“We’re also engaged in the Borg CO2 carbon capture project in Norway, which is centered on an industrial cluster approach,” said Chris Barkey, Chief Technology Officer, Turbomachinery & Process Solutions, Baker Hughes. “Separately, we are working with Horisont Energy to find optimal technologies for an offshore lower-cost carbon storage project named Polaris in Norway, part of the Barents Blue ammonia production project.” 

Most recently, Baker Hughes announced an investment in Electrochaea, a company developing bio-methanation technology which enables CO2 recycling into grid-quality, low carbon synthetic natural gas (SNG), contributing to decarbonization of hard-to-abate sectors, such as transportation and heating. In conjunction with Baker Hughes post-combustion carbon capture technology including Compact Carbon Capture, Electrochaea’s bio-methanation technology can help develop and commercialize an integrated carbon capture and utilization tailored to applications utilizing CO2 sources with biogenic origin (biomass, waste-to-energy), as well as sources based on combustion of fossil fuels. 

To reach net-zero for large-scale natural gas plants, Barkey added that CCUS technologies must address exhaust gases. The company is investing in post-combustion carbon capture solu-tions for gas turbine exhaust gas applications. An alternative approach is to redesign turbines to produce fewer emissions. The LM9000 aeroderivative gas turbine, for example, now has simple cycle efficiency in excess of 44%. 

“Efficiency is key to driving lower carbon intensity of the LM9000,” said Barkey. “It has been designed for 15ppm NOx emissions in dry condition.” 

“ The challenge of implementing large-scale CCUS will be to reduce the installed cost and minimize the operating costs,” said Chris Barkey, Baker Hughes.

Baker Hughes has been involved in CO2 compression since the 1960s where its first application was for urea synthesis. Today, it can pro-vide CO2 compression across a range of applications including reinjection of up to 550+ bars in almost pure form. It recently introduced a main compressor prototype for supercritical CO2 that is compact and high speed. It reached over 800 kg/m3 density at the discharge and operated just on the critical point of the CO2 at the suction.

“CO2 is a highly compressible gas so the main challenge we have been tackling is to build a compact, efficient machine which can deal with the huge aerodynamic forces acting on the rotor,” said Barkey.

Mitsubishi Heavy Industries (MHI) began developing CCUS technology over 30 years ago. It has an amine-based technology known as the KM CDR Process. It is used in the world’s largest post-combustion carbon capture facility, which was installed on a coal power plant in 2016. MHI was also selected as the technology provider for a feasibility study of carbon capture at Lehigh Cement Company’s Edmonton Cement Plant. This project is being jointly conducted by the International CCS Knowledge Centre and Lehigh Cement with a target delivery of fall 2021. It has received support from Emissions Reduction Alberta. The capacity is estimated to be 600,000 tonnes of CO2 annually.

Additionally, MHI and Drax Group agreed to a long-term project for Drax to use the company’s carbon capture technology in combination with MHI’s KS-21 sol-vent at Drax’s power station in Yorkshire, U.K. A further element is offshore geological storage under the North Sea. MHI also has commercial experience in carbon capture of natural gas boiler exhaust. The applications are predominantly for chemical production such as methanol or urea. NextDecade Corporation, too have signed an agreement with MHI to use KM CDR Process post-combustion technology in gas turbines at the Rio Grande LNG project in Texas. 

“A number of confidential studies are underway focused on natural gas boiler exhaust as well as natural gas turbine exhaust with the goal of sequestering the CO2 or utilizing it,” said Evan Canady, Senior Business Development Manager, Renewable Fuels, Mitsubishi Power.

GE has developed many projects using amine technology and chilled ammonia in Europe and North America to remove CO2 post-combustion. While tradition-ally applied to coal plants, these technologies can be applied to natural gas power plants. 

There are plenty of opportunities, too, in CO2 compression at the capture site, along the transportation corridor, and the injection site. At a power plant, for example, the CO2 needs to be dried of any moisture, and compressed to 70 – 80 bar for pipeline transportation. At the well head or injection point, booster compression is often needed to increase pressure for injection into the Earth’s crust. 

“Most new CCS project requests tar-gets natural gas power,” said John Catillaz, Director of Decarbonization – Marketing GE Gas Power.

CCUS deals primarily with the separation and sequestration of carbon dioxide either pre- or post-combustion from a hydrocar-bon power plant fuel or from an industrial process that emits CO2. The most com-mon forms of separation are pre-combustion from synthesis gas in a gasification plant, post combustion from flue gas, and blue hydrogen production from natural gas reforming. Thus, CCUS can also require compression and pumping of synthesis gas, hydrogen, nitrogen, oxygen, natural gas or other gaseous feed-stocks. Elliott Group manufactures centrifugal compressors that can be utilized for the compression and transport of carbon dioxide and any of the other gases of the various CCUS processes. The company has several ongoing R&D activities that focus on the improvement of compressors for CCUS as well as the development of new products. 

Most of the discussion of CCUS for natural gas-fired turbines is directly related to the production of blue hydro-gen. Blue hydrogen can be either produced near a hydrocarbon source and then transported to the plant via pipeline or the hydrocarbon can be transported to the power plant using existing infra-structure to be converted to blue hydro-gen near the power plant consumer site.

"Most new CCS project requests targets natural gas power,” said John Catillaz, GE Gas Power.

“The latter option appears more practical since it avoids the cost of having to develop an entirely new hydrogen transportation infrastructure,” said Klaus Brun, Director R&D, Elliott. “There are three value streams in blue hydro-gen-based CCUS: Natural gas, hydrogen, and carbon dioxide.” 

Elliott is currently working with several end-users and operators throughout the world to develop customized com-pression solutions for blue hydrogen pro-duction. This includes Elliot’s Fex-Op compressor arrangement which can be utilized for both hydrogen transport and CO2 applications as well as the company’s existing line of TCH140H pipeline compressors for natural gas compression. 

“Post-combustion carbon capture tends to be significantly more challenging and costly than pre-combustion separation because of the low concentration of CO2 in the flue gas,” said Brun. 

Elliott has been in discussion with process developers to provide the high pressure ratio compression solutions required to take near-atmospheric flue gas CO2 to pipeline and injection pressures.

In 2020, there were 26 commercially active CCUS projects in the world, representing a carbon capture capability of approximately 40 million tonnes per annum (Mtpa). Currently, there are a handful of other CCUS facilities currently under construction, with a few more in advanced development and several more in early development. However, these facilities collectively represent less than 100 Mtpa of carbon capture capacity set to come online. That is far from enough to satisfy the goals set by bureaucrats in Europe and the U.S. 

Whether pre- or post-combustion, or some other approach entirely, comes to dominate, what is certain is that more projects are very much on the horizon. As well as those noted above, LNG exporters Cheniere Energy and Sempra Energy plan to add CCUS capabilities to U.S. LNG projects. This may be in response to an order cancellation from France which claimed U.S. LNG was too dirty. Sempra’s Port Arthur LNG terminal in Texas and Cameron LNG plant in Louisiana are being looked at for CCUS, as are Cheniere’s Corpus Christi plant in Texas and Sabine Pass terminal in Louisiana.

 Meanwhile, Venture Global LNG intends to capture and sequester carbon at its Calcasieu Pass and Plaquemines LNG facilities in the U.S. After compressing CO2, it will be transported and injected into subsurface saline aquifers. The goal is half a million tons of carbon per year. ExxonMobil, too, has announced plans for deep storage of carbon in the Gulf of Mexico. 

“We have committed real dollars to development and engineering,” said Cheniere CEO Jack Fusco. “Customers are going to expect us to continue to offer a sustainable LNG product.”

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Lowering carbon emissions from gas turbines. 

Carbon capture

Carbon capture has become a hot topic. After suffering for years from lack of funding, it is finally attracting investment. Capturing carbon from coal remains the focus. It should certainly be the priority outside the U.S. A study by Environmental Research Letters laid out the top ten hyper-polluting power plants in the world. It found that up to 49% of global electricity-based CO2 emissions could be eliminated by targeting these plants. 

Out of 29,078 fossil-fuel powered plants from 221 countries, researchers found that 73% of carbon emissions come from the top 5% of polluters. The study suggests that targeting this top 5% with reforms could significantly reduce global emissions levels. It outlined some potential policies: lowering intensities to match a national, then international, average, switching to natural gas, and implementing carbon capture technology. 

The results show that the implementation of these policies could reduce electricity-based CO2 emissions. South Korea, for example, could cut electricity-based CO2 emissions by a whopping 76%. China would reduce its CO2 output by only 20.7% due to the bulk of its coal plants being high polluters. Switching coal plants to natural gas would result in a 29.5% drop. 

Investment in carbon capture at coal plants makes the most sense outside of the US, therefore. It would result in the biggest gains. Within the U.S., coal plants are firmly under the boot of regulators. Most have drastically reduced their emissions and are scheduled for closure. 

That’s why it’s smarter for American dollars to be spent on carbon capture for natural gas plants, not coal. None of the top polluting coal plants are in the U.S. Almost all are in Asia, except for one Polish plant (the worst on the planet) and one in Germany. Yet U.S.-based carbon capture research is overwhelmingly funded for coal. The last time I heard someone from the Department of Energy mention Carbon Capture, Utilization and Storage (CCUS), coal project funding outdid natural gas by more than an order of magnitude. 

That appears to be changing. Our cover story summarizes the latest developments in CCUS. It gives a brief rundown of the technology, explains some of the challenges, and shares what the vendor community is doing about it. 

A Baker Hughes paper, “CCUS is a net-zero imperative,” offers some insight. The company is investing heavily in CCUS. It sees it as the only way to address a major proportion of industrial emissions. The paper states that 25% of industrial emissions resulting from industries such as power generation, transportation, and cement production cannot be avoided by moving to alternative fuels as they come from industrial process activity. It concludes: “Without CCUS technology, it will be nearly impossible to remove emissions from large parts of the global economy.” 

More investment and incentives are needed to overcome the cost premium for CCUS. Switching from coal to natural gas and adding carbon capture will probably have as much impact on carbon reduction as adding more renewables. It isn’t an either-or proposition. We need to do both – lower carbon emissions while steadily adding more wind and solar. 

Perhaps in some fairyland, coal and gas plants will disappear overnight and the world will be happily powered ever after. But areas intent on that dream are struggling. California just had another summer of rolling blackouts. Now the governor has announced “temporary” plans to build gas plants to ease the state’s electricity crisis. 

Investment in CCUS, therefore, makes sense. And it looks like the gas turbine OEM and supply chain community is rising to the challenge, as your can read in our latest issue.

Click here to download Turbomachinery International's August/September issue!

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In August/September 2021's Turbo Speak column, Editor-in-Chief Drew Robb highlights the need for investment in natural gas carbon capture and storage. 

Turbo Speak: Capturing carbon

Siemens Energy hosted a roundtable in advance of its recent North America Energy Week event. Tim Holt, member of the executive board, began by saying that half the company’s portfolio is decarbonized and that is not good enough. To remedy this, the company is spending more than a billion Euros annually on R&D. One of the major investments is in arriving at zero-emissions power generation via the interim step of low-emissions power generation. The company has set a target to have its own operations carbon neutral by 2030.

Holt believes that proposed ideas to create hydrogen from renewable energy via electrolysis using excess power may not be the most efficient way forward. He characterized it as turning an electron into a molecule and back to an electron.

He pointed out that the lifespan of a gas turbine plant is around 25 years. That ties in with most projected targets to achieve carbon neutrality or for the complete elimination of fossil fuels. He suggested that investment in such facilities made sense. However, customers need reassurances about longevity.

“Many customers want to know that the turbines they are evaluating can eventually run on 100% hydrogen,” said Holt. “They want to be sure they do not end up with a stranded asset.”

He added that the discussion has shifted markedly from a year ago. Suddenly, there is momentum behind hydrogen and decarbonization in the U.S. However, there is a need for balance. As it is impossible to achieve net zero overnight, a transition is needed. Holt said natural gas will be the transition fuel. Even today, 40% of global power is generated by coal. That represents a big opportunity.

Take the case of Germany. With governmental policy making it a challenge to build or operate gas turbine plants, the unforeseen circumstance was that the country fell back on burning lignite. CO2 emissions are now higher than they were 10 years ago.

“You have to ensure you achieve the right balance that offers a sensible transition,” said Holt. “Storage is not developing fast enough. Gas is the best choice.”

Richard Voorberg, president of Siemens Energy North America, acknowledged that 51 utilities have set the goal of decarbonizing by 2050. But when it comes to shifting from burning natural gas to hydrogen, he believes the gas turbine is the easy part. By 2025, all the company’s turbines will be hydrogen capable. By 2030, all will be able to run on 100% hydrogen. Currently, the company commits to 50% hydrogen in its largest model.

“The challenge is how to produce, store, distribute, and utilize hydrogen at scale,” said Voorberg.

How do you sell in a market where everyone wants hydrogen power but a) the turbines are not quite there and b) hydrogen is not available in quantity and at a low cost?

Statistically, emissions currently from power generation in the US are a third of what they were in 2005. No other sector can boast such progress. Yet Public Utility Commissions, grid operators and universities don’t want to even consider gas as an option.

“At the end of the day, they need power; we have to explain that you can’t run a grid only on renewables,” he said. “We need some rolling mass there and natural gas generation provides that.”

A roundtable held by Siemens Energy discussed the role of gas turbines in the ongoing energy transition. 

Siemens Energy Talks Decarbonization, Hydrogen, and the Future of Gas Turbines 

The direct air capture process. Source: IDTechEx. 

However, the current demand is that gas-fired plants greatly reduce their carbon emissions. This can be accomplished either by pre-combustion carbon separation (usually using methane steam reforming to syngas with subsequent water shift and CO2 removal) or post-combustion flue gas CO2 removal.

The big hurdle, of course, is cost. Current technology is expensive and energy intensive. Not only is the carbon to be captured, it also needs to be stored somewhere and increasingly utilized in some process. Hence the term carbon capture utilization and storage (CCUS). (Note: It is also sometimes called CCS.)

Most attention, to date, has been lavished upon solvent-based capture i.e., the gas stream is exposed to a liquid medium to absorb CO2 via some kind of physical or chemical mechanism. Regeneration is also needed to break absorbent-CO2 bonds.

Drawbacks include high energy consumption, corrosion, difficulties in scaling, and raw economics. Why spend money to develop and implement the technology in an environment that shows little love for fossil-based fuels? Nevertheless, advances have been made. Amine-based solvents from Mitsubishi have been used in the Petra Nova facility in Texas. Shell Global’s CanSolv is another solvent being used at the Boundary Dam project in Canada. Similarly, physical absorption solvent breakthroughs have been made such as Lurgi’s Rectisol process using chilled methanol as a solvent. Further areas of development include: solid sorbents developed by Svante in conjunction with Chevron and others; the Polaris membrane by Membrane Technology and Research in collaboration with the U.S. Department of Energy; SES Innovation’s cryogenic carbon capture; and FuellCell Energy’s fuel cell technology for carbon capture, using electrochemical membranes to separate CO2 from industrial waste gas streams. Further, Chart Industries (owner of LA Turbine) has developed Cryogenic Carbon Capture (CCC) technology. The cost to produce cement and capture CO2 using CCC technology is said to be 24% higher than producing cement with no capture.

Another approach is direct air capture (DAC) to strip CO2 from air using chemical and physical processes. Those working on this include Climeworks with a plant in Switzerland and Carbon Engineering from British Columbia, Canada, that plans to build a Permian Basin facility to capture a million tonnes of CO2 per year by 2024 using a high-temperature aqueous method based on potassium hydroxide. Global Thermostat, too, has pioneered a porous, honeycomb ceramic approach to carbon capture.

Mark Axford, Principal at Axford Turbine Consultants believes that CCUS represents a more credible path to lower emissions than the ongoing love affair with hydrogen.

“Carbon capture of natural gas is probably a far more economical path than trying to convert everything to 100% hydrogen,” said Axford.

“Post-combustion CO2 removal is technically viable but impractical because of the large volume flow and the need for high ratio CO2 compression,” said Klaus Brun, Director, Research and Development, Elliott Group.

Read the rest of this article in Turbomachinery International's September/October Issue.

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The introduction to September/October's cover story discussing the state of carbon capture technology. 

Lowering carbon emissions from gas turbines

ISFD technology, shown here as part of a Flexure Pivot tilt pad journal bearing, provides precise stiffness and damping to increase the dynamic stability of the rotor/bearing system. Courtesy of Waukesha Bearings.

Waukesha Bearings provides custom-engineered hydrodynamic fluid film bearings, active magnetic bearings systems, and damper and seal technologies for turbomachinery across the oil & gas, power generation, marine, and industrial markets. Engineers apply design codes and predictive tools to tailor thrust, journal, or combination bearings to achieve optimum performance across the machine operating range.

The Waukesha Bearings Maxalign tilting pad journal bearing, for example, features a specialized ball and socket pivot, along with Directed Lubrication and trailing edge cooling to increase reliability and reduce power loss for rotating equipment with shaft diameters greater than 300 mm. Engineers optimize the bearing size and pad materials and tailor insulation, hydrostatic jacking, and instrumentation according to requirements.

“Each application is unique so we design each bearing to meet performance requirements, whether they are tilt pad or fixed profile, babbitt, bronze, polymer or ceramic, and small, medium, or large,” said Andrea Masala, Product Manager, Waukesha Bearings.

Waukesha Bearings fluid film bearing solutions support the market move toward decarbonization. For supercritical CO2, hydrogen, and other high[1]power density applications, the integral squeeze film damper and pocket damper seals help ensure stable rotordynamic systems.

Fluid film journal bearings with ISFD technology are ideal for applications requiring optimized stiffness and damping. Initially used as a problem solver for turbomachinery experiencing high vibrations due to rotor unbalance or instability, ISFD technology is used on high-speed and high-power density applications, such as integrally geared and inline compressors.

As compressors and turbines are designed for higher pressures and speeds to achieve the full potential of hydrogen and sCO2, the integration of ISFD technology enables rotor/bearing systems with journal peripheral speeds above 130m/s.

“The controlled stiffness and damping of ISFD technology, and the precise placement of critical speeds and rotor modes that this allows, will help address potential destabilizing forces in the system and minimize unbalance response,” said Masala.

Stability can be enhanced further with the application of pocket damper seals. Based on bulk-flow analysis, they can cope with a range of speeds and gas conditions to counter seal-induced instabilities. Waukesha Bearings is also working on new pocket damper seals to further increase damping characteristics and lower leakage.

Waukesha Magnetic Bearings has been involved in magnetic bearing technology development for more than 30 years. Challenging applications in high pressures and aggressive gas have driven the market towards a mechanical solution with controller architecture. High controller functionality is available for both low-power controllers (for applications below 1 MW) and high-power controllers (for applications above 25 MW).

Modularity is another element of Waukesha Magnetic Bearings systems. The Zephyr controller, for instance, allows enough flexibility to integrate software and hardware features within the same enclosure. Automated commissioning is also available. This is a repeatable process that provides commissioning and maintenance autonomy for OEMs and end users, with available training, remote support and field service from active magnetic bearing (AMB) specialists.

The skid-mounted magnetic bearing controller introduced by Waukesha Magnetic Bearings in 2019, reduces installation time and avoids the need for long field cables from the controller to the machine. Skid mounted AMB controllers can provide modularity for different size units, oil free operation, and the convenience of remote maintenance that fluid film bearings cannot. Skid mounted AMB’s primary application is in turboexpanders for gas processing plants, but have also been applied in various industries and services.

The ARES AMB Turboexpander-Compressor from L.A. Turbine features the industry’s first on-skid magnetic bearing controller. Courtesy of L.A. Turbine.

Brush seals are commonly used in gas and steam turbines to minimize leakage and improve performance. They are also applied to increase the efficiency of compressors operating on fluid film or magnetic bearing systems.

The Waukesha Bearings’ brush seal is closely packed with alloy bristles that deflect with rotor movement and experience minimal wear. This brings about a smaller leakage gap between the sealing surface and rotor. The bristle strips can be replaced without throwing away the seal assembly.

On AMB-equipped compressors, brush seals protect and augment labyrinth seals. The gap between the levitated rotor and labyrinth seal must correspond to the distance from the rotor to the auxiliary bearings. Otherwise during coast down, the rotor would contact and roll the labyrinth seal teeth. Augmenting labyrinth seals with brush seals reduces sealing clearances and leakage during operation. Upon rotor delevitation, the bristles deflect in response to rotor weight, protecting the seal. The bristles return to their original state once the rotor is levitated.

Modular brush seal assembly on an AMB-equipped compressor. Courtesy of Waukesha Bearings.

Custom-engineered solutions rely upon rotordynamic analysis. In AMB-equipped turbomachinery, the bearings, rotor, and process are deeply integrated in shaping machine dynamics. Waukesha Bearings’ engineers collaborate with OEM engineers throughout design and development to understand application needs and support rotor design optimization. Direct measurement of forces and displacement with magnetic bearings, and correlation with operating conditions, allows the characterization of mechanical and process interaction. Control algorithms address destabilizing seal effects and process upset conditions.

“In traditional power generation and oil & gas applications, we see OEMs and end users push equipment to produce more power from the same footprint, operate more efficiently and be more operationally flexible,” said Masala. “From a fluid film bearing perspective, that translates into requirements for power loss reduction, higher load capacity, highly tuned bearing dynamic characteristics, and the ability to handle higher temperatures, frequent starts and stops, and off-design conditions. These demands are being met with a combination of design elements, such as trailing edge cooling, ISFD technology and damper seals, and advanced bearing materials, such as polymer and aluminum tin.”

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Fluid film bearings, active magnetic bearings systems, and damper and seal technologies for turbomachinery. 

Vendor spotlight: Waukesha Bearings

The WTUI show covered all aspects of the maintenance and repair of aeroderivative gas turbines. Courtesy of MTU Maintenance. 

The Western Turbine Users, Inc. (WTUI) show occurred virtually this year spread over three weeks. Due to print magazine deadlines, we could only summarize the first half of the event in the previous issue. Here are the highlights from the latter sessions: 

Jason Miller, Director of Reliability for GridSME, provided an overview of the combustion turbine from the perspective of the California Independent System Operator (CAISO). He said gas generation has been rising in share over last ten years in the region. 

“There is still a place for gas, especially in the peaking market,” said Miller. 

He drew attention to the August 2020 period when the state suffered rolling blackouts (the same happened this year). Unanticipated high demand was satisfied by natural gas facilities despite heat-related forced outages. In Miller’s view, gas saved things from getting worse. 

“There was no fault found with the gas fleet related to any the blackouts,” he said. 

Miller also explained the need for natural gas generation to provide reactive power and grid stability. “Renewables are not synchronous machines, so you need reactive energy injected for frequency response and to stabilize the grid,” he said. He’s worried that bodies like CAISO and LA DWP are retiring a lot of rotating generators, particularly steam generators. That amounts to 3 GW of retirements in the next 4 years (1 GW this year). Over the same period, a large amount of battery storage is due to be added. Miller believes this represented an opportunity for gas turbines to work in tandem with battery plants to serve peaking and other markets

The last two days of WTUI featured vendors pro-viding insight and tips on aeroderivative gas turbine operations & maintenance. Rikki Blair, Director of Operations, EthosEnergy, talked about extending the life of assets. His company does reverse engineering using blue light scanning and 3D modeling as well as 3D prototyping using production 3D printing. A prototype is done in plastic. Once con-firmed it is then printed in metal. This can be aluminum, nickel, steel, cobalt, or titanium. 

Blair laid out an LM2500 case study. It suffered compressor degradation despite a lot of offline water washing. GTE provided a high-pressure online water wash without detergent that raised availability by 2%, performance by 1 to 4%, reduced fuel consumption, and lowered emissions. It also used less water that offline water washes and cut down the wash cycle from 110 minutes to 30 minutes.

Maintenance work being done on an LM2500. Courtesy of MTU Maintenance. 

Another example discussed was an LM6000 controls retrofit for a Texas peaker. Four units at two different sites experienced reliability issues, slow start ups, and were not meeting output demands. An upgrade to poorly configured control raised output by up to 2%. It also solved grid synchronization problems to satisfy 10 min startup to full load condition. This was accomplished using the icon control system. The project also corrected UPS, power distribution, and wiring issues. Blair said EthosEnergy had done over 100 controls upgrades on LM engines. 

Mcleod Stephens Jr., General Manager at Braden Filtration, followed with a briefing on the history of filter cartridge design, media, styles, and evolving technologies. He laid out the various factors to consider in selecting the right filter for the right turbine and environmental conditions. 

Maintaining and upgrading LM series turbines to reliably meet the demands of today’s grid, with the topic chosen by David Cicconi, Turbine Business Development Manager at Emerson. The focus of that session was on upgrade options avail-able to users of legacy Woodward and GE control systems. Using a case study of a recent project, he detailed a variety of upgrade solutions and enhancements available for these units, as well as some lessons learned to ensure success in managing such an upgrade.

For example, he mentioned Ovation control optimizations that could be done to improve the reliability and on-time dispatch of automatic pre-start. Another feature, automatic NOx water adjustment instantaneously compensates for variation in ambient conditions. Emerson offers a retrofit for some Woodward and GE systems. This drop-in replacement matches the footprint, is easy to install, and fully factory tested. 

Monitoring the health of bearings was the topic presented by Simon Wilson, Sales Director, Energy & Industrial, GasTops. He explained that bearing damage events and unreliable detection technologies are causes of unplanned shutdowns in aeroderivative gas turbines. Damage typically occurs gradually over time and may be predicted in advance using detection technology. GasTops offers Oil Debris Monitoring (ODM) and MetalSCAN online condition monitoring as well as oil, filter, and chip analysis.

Field Results from ice blasting were outlined by Bobbi Monacelli, President, US Cleanblast. He tied this into high-pressure compressor (HPC) efficiency improvements and overall life extension. He touched upon performance tests on ice blasting by GE, which revealed improvements in com-pressor efficiency, increased mass flow, and a MW power gain. 

The process is used to eliminate dirt and hydrocarbons in the compressor, which lead to lower power. Monacelli said that if water washing is becoming less and less effective and a borescope inspection shows that the machine is dirty, ice blasting is a possible option. 

A plant in Georgia, for example, gained 3 MW by using the technique on an LM6000. The HPC and casing was cleaned by ice in only 12 to 18 hours. This resulted in no damage to the substrate. As well as being much faster than cleaning by hand, the compressor is much cleaner when ice is used.

 The following session featured Bob Tollett, Director of Marketing, at Liburdi Turbine Services. He covered how to maximize component repair yields to reduce engine overhaul costs. His company is involved in a great many hot section combustion repairs, as well as first and second stage blade and nozzle repairs. He recommended blade alloy rejuvenation to return blades to an as-new state. He also touched upon vacuum-heat treatment to restore the micro-structure and improve the creep strength of components. 

Many users deal with grid stability and frequency response issues. Mike Toll, Account Manager at Woodward, took up this subject during the last day of the virtual WTUI event. 

“Grid fluctuations are caused by imbalance of electrical supply and demand,” said Toll. “Without compensation, the frequency varies with generation and load changes.” 

If, for example, consumption is greater than production – perhaps in the early evening if there is no wind would – frequency drops. If consumption is less than production – perhaps the middle of the day when the sun shines and the wind blows – the energy produced has nowhere to go and frequency rises.

There is still a place for gas, especially in the peaking market," said Jason Miller, Director of Reliability for GridSME. 

Toll detailed various control system approaches to dealing with frequency and instability challenges. Droop, for example, is a control method that automatically varies gas turbine out-put in response to changes in frequency. When grid frequency decreases, unit load increases, and vice versa. He also touched upon local MW set-point control, automatic generation control (AGC), remote MW setpoint, and primary frequency controls that can be implemented. 

WTUI tries to cover as much ground as possible related to LM series O&M. The last few hours of the show featured a great many topics. Patrick Jansen, Chief Services Officer, VBR Turbine Partners, promoted Decide, a system that tracks the component behavior and degradation over time. It combines historical and ongoing engine health condition monitoring data to provide predictive maintenance. Jeff Bause, CEO of Noxco, presented on emissions compliance. Pierre Ansmann, Global Marketing Director, Arnold Group, educated the audience on thermal insulation for LM2500/6000 exhaust collectors as a way to reduce package temperature. Florian Winkler, Marketing Manager, EMW filtertechnik, covered the benefits of (H)EPA GT air intake filters. His presentation helped users to make better filtration choices. Finally, Jon Neal, Head of Global Field Service at Brush Group, tackled how to avoid forced outages through site-specific preventive maintenance of generators based on operating condition and environment. 

The 2022 WTUI show will take place from March 27-30 in Long Beach, CA. For more information, visit WTUI.com

Show highlights the many aspects of LM Series operations and maintenance. 

Western Turbine Users part II

First there was the Colonial Pipeline hack. The gasoline supply to the U.S. Eastern Seaboard shut down until a near $5 million ransom was paid to Eastern European criminals. Then came an alert that Siemens programmable logic controllers (PLCs) had a security hole that was being exploited by attackers.

Siemens AG released firmware updates to address this vulnerability in Simatic S7-1200 and S7-1500 PLCs. If exploited, malicious actors could remotely access protected areas of memory and achieve unrestricted and undetected code execution. This vulnerability means an unauthorized person could access the network and write arbitrary data and code to protected memory areas or read sensitive data to launch further attacks.

The ability to execute code on PLCs that might be running plant systems, power stations, or various items of turbomachinery is bad news. It represents another level of hacking sophistication beyond that seen in the Stuxnet exploits that caused trouble to Iranian nuclear facilities a few years ago. To make matters worse, such attacks can evade detection by security tools. All the attacker needs is a way to get onto the network, which entails little more than tricking a gullible employee to click on a malicious email link or attachment. This kind of incursion is very much on the rise in turbomachinery (See our lead news story: Report Reveals the Rise of Ransomware and the Importance of the Human Element).

Despite the presence of the Siemens update, there is no guarantee that all users of the PLC will deploy it across their systems. Too often in cybersecurity, the bad guys use known vulnerabilities to access systems. The moral of the story is to keep systems current with the latest updates and patches.

With cybercriminals actively seeking potentially lucrative targets related to infrastructure, what are control systems OEMs and suppliers doing about such threats? What changes are they making to their offerings? And what else is new on the turbomachinery controls and software front? Let’s hear from the vendors.

Siemens Energy SPPA-T3000 for turbine controls.

Siemens Energy, as distinct from Siemens AG that provided the PLCs noted above, has placed plenty of emphasis on cybersecurity of late. Its Eos.ii software helps energy companies use cyber threat intelligence targeting operational technology (OT) and information technology (IT) networks connected to physical energy assets. Siemens Energy has partnered with IT software firm ServiceNow as part of this offering. Those impacted can use it to deploy appropriate, targeted and proportionate measures to correct and recover from cyber incidents.

Additionally, Siemens Energy’s MDR system provides a unified picture of anomalous behavior for defenders with insights to stop attacks. The service goes beyond conventional monitoring by achieving understanding of how digital systems relate to the real world. With its unified OT and IT data stream, the platform uses artificial intelligence (AI) and digital twin technology to compare billions of real-time data points against a correctly functioning asset. This provides context for analysts to determine not only which events are abnormal, but which are consequential.

Dieter Fluck, Vice President of Controls Systems & Innovation for Siemens Energy, noted that security has become more important of late as companies gain familiarity with remote monitoring. His company has been remotely monitoring its fleet for more than 10 years to provide faster support and to enact quality improvements.

“Questions around compliance with cyber security norms and regulations have been a constant feature of conversations about remote monitoring with customers,” said Fluck. “This hinges on finding a good balance between the benefits of cost and efficiency while ensuring long-term safety and security of critical customer assets.”

All Siemens Energy controls solutions offer remote connectivity. This ranges from basic connectivity to complete digital twin-based support through company Remote Expert Centers (RECs). RECs lets users tap into a network of in-house experts that address issues ranging from process know-how to software/hardware issues. Turbine experts can evaluate performance, analyze and diagnose changes in operational behavior and provide recommendations.

The SPPA-T3000 for turbine control of gas and steam turbines in power generation encompasses governor, protection, and auxiliary controls combined in one control cabinet. All devices are integrated into this control system. Independent SIL3 protection systems can be added, if desired.

Specific to oil and gas, the controls interface at the individual asset level as well as the plant (or enterprise) level. At the asset level, controls are available for turbine and electric motor-driven compressors and pumps. All Siemens Energy compressors are offered with process controls including modules for anti-surge and load sharing.

Fluck said the growing demand for data coupled with ease of communication and data transmission has driven several trends. Cloudbased controls, for example, are being used more to foster data consistency and availability for asset optimization. Companies are also seeking greater interoperability of assets across platforms. There is growing demand, too, for systems that support autonomous plant operation without the need for manpower onsite.

“In the power generation market, there are increasingly complex requirements targeted towards grid stability and security,” said Fluck. “In the industrial and oil & gas markets, customers have been looking for greater asset reliability and availability which often translates into demands to push the operational profile of our machines beyond established precedence while ensuring all applicable safety standards are still met.”

Controls vendors are coming to market with advanced features anchored by enhanced cybersecurity. 