Hydrogen – the world’s lightest and most abundant element – has been touted as a solution to radically decarbonize industries and societies. Several countries have included it in their medium and long-term emissions reduction plans, with the likes of Canada, France, Germany, and Japan rolling out strategies specific to hydrogen. 

Equipped to support 30% hydrogen co-firing, Mitsubishi Power’s J-Series gas turbines can produce up to 700 MW of electricity while reducing CO2 emissions. (Photo Credit: Mitsubishi Power)

To spur mass adoption of this zero-carbon molecule, a more robust supply chain is necessary. However, cost is a major barrier. Certain methods of hydrogen production, storage, and transport are specialized and expensive, especially when compared to more carbon-intensive alternatives. 

One way to make hydrogen more economically viable is to significantly scale demand. The installation of a single 400 MW, 100% hydrogen-fired gas turbine combined cycle power plant, for example, would use the same amount of hydrogen as 2 million hydrogen fuel cell vehicles. Such a shift would generate enough impetus to expand the build-out of hydrogen-related infrastructure.

Energy sector players need not start from scratch to ramp up hydrogen utilization. They can use existing gas power infrastructure. For decades, the energy sector has already successfully used hydrogen in various proportions within small gas turbines. The next step is to develop larger machines that can safely deploy hydrogen for utility-scale power generation. To date, there has been success in converting large gas turbines with dry low-NOx combustors to run with a 30% hydrogen and 70% natural gas mix. Exclusive hydrogen-firing is projected for 2025. 

Conversion of legacy systems to accommodate hydrogen firing can be done with minor structural modifications. Piping and valving sizes must be increased given the greater volume of hydrogen needed. But the compressor, turbines, and other auxiliaries can remain largely the same. 

To ensure the safe deployment of hydrogen in large-scale power generation, the combustor design has been reimagined. Most existing large gas turbines can run with up to 20% H. But as its proportion increases, hydrogen’s explosive nature and wide range of flammability must be addressed. One notable effect of the significant rise in temperature with hydrogen combustion is the increase in formation of NOx. 

A higher incidence of NOx emission can be mitigated by premixing fuel and air before entering the combustor. However, doing so poses a new challenge. Adding hydrogen raises the combustion speed of the fuel mix. It accelerates flame propagation to the point where it may exceed the fluid velocity of the premixed gases. This increases the risk of flashback – where the flame moves upstream in the fluid and can ignite fuel outside the combustion chamber.

A dry low-NOx combustor with an improved swirler nozzle has been developed to mitigate this challenge. Air is injected from the tip of the nozzle, increasing the velocity at the center of the swirling flow. This design boosted flashback resistance while enabling low-NOx combustion.

The energy sector can help drive demand for hydrogen, but it cannot act alone. Leaders in both public and private sectors can take steps to stimulate hydrogen demand and supply, while striking a balance between economic feasibility and environmental performance. 

The existing hydrogen supply chain is not decarbonized. With the bulk of commercially available hydrogen derived from fossil fuels, the IEA estimates that hydrogen production generates 830 million tons of carbon dioxide annually. This is equivalent to the combined CO2 emissions of the UK and Indonesia. 

There are several ways to produce hydrogen that can drastically reduce or eliminate carbon from the process. This includes pyrolysis of hydrocarbons (forming solid carbon as byproduct) as well as using steam reforming systems with carbon capture capabilities. Another option is to generate green hydrogen using renewable power. The rapid growth of renewables in several places has led to oversupply, forcing power producers to curtail renewable power generation or sell excess power at a loss. In theory, this surplus electricity from renewables can be harnessed to power electrolyzers to produce carbon-free hydrogen. 

However, to make green hydrogen competitive at scale, capital expenditure and operating expenses need to go down. The European Commission estimates that hydrogen derived from fossil fuels costs about $1.80 per kg, whereas green hydrogen ranges between $3.00 and $6.55 per kg. 

To bring hydrogen further down the value chain, suitable transport and storage systems are also needed. Traditionally, hydrogen is stored in tanks at high pressures (350 to 700 bar) and low temperatures (below -252.8°C). These extreme conditions mean that tanks must be specially designed, with large compressors enabling such processes.

Salt caverns, such as those used by the Advanced Clean Energy Storage project in Utah, present a viable alternative for hydrogen storage. When operational, the system will be integrated with existing power grid infrastructure in the Western U.S. and provide up to 1 GW of renewable energy that can be tapped year-round. 

Ammonia, which is easier to transport at scale than hydrogen, is also advancing the development of a hydrogen ecosystem. Not only can it be used directly as a fuel in smaller power systems, but it has proven to be an effective hydrogen carrier. In Australia, the Eyre Peninsula Gateway project is set to generate up to 40,000 tons of green ammonia per year and will feature a 75 MW electrolyzer for green hydrogen production.

Mitsubishi Power teamed up with the Los Angeles Department of Water and Power and other partners to work towards at-scale green hydrogen procurement at $1.50 per kg in the Los Angeles Basin by 2030. (Photo Credit: Green Hydrogen Coalition)

Various parts of the world are at different stages of hydrogen adoption. In Europe, first-generation hydrogen projects are set to come online within the decade. These include the conversion of a 440 MW gas-fired power plant in the Netherlands to 100% hydrogen firing, as well as the development of a green hydrogen cluster in Hamburg. The U.S. has been leading the way in exploring hydrogen for energy storage, with ongoing projects and evaluations in Utah, New York, Virginia, Louisiana, and Texas. In Saudi Arabia, work is underway for a facility that will produce, among others, 650 tons of green hydrogen per day. 

In developing markets, limitations to infrastructure and access to capital are more acute. These countries can scale hydrogen adoption with blue or gray hydrogen and pair hydrogen production systems with carbon capture technologies. 

At the end of the day, the development of a global ecosystem for affordable hydrogen production, storage, transportation, and utilization will need partnerships across sectors and industries. One example is HyDeal Los Angeles where the local government is working with industry players to drive down the cost of green hydrogen to $1.50 per kg.

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How the energy sector can lead the hydrogen revolution. 

The economics of hydrogen

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

Remote steam assisted gravity drainage (SAG-D) oil plant with various steam generators.

One day an engineering lecturer at school discussed an accident at a nuclear power station. Seawater had entered the cooling pipes of the reactor. He asked the students what would happen in such a situation.

A Dean’s Honor-List student answered that neutron flux from the reactor would irradiate the sodium ions in the seawater salt molecules to create a short-lived isotope of sodium. This isotope would emit low-intensity alpha radiation which lodges in the interstices of the ferrous lattices of the steel alloys of the pipes, creating hot spots or fractures, leading to escape of radioactive seawater to the river.

No, the lecturer replied, the pipes will rust.

In troubleshooting, then, it is best to first suspect the obvious. Why make things more complicated than they really are? Recognizing that there is an overflowing sink and turning off the water, for example, can save a lot of time that might otherwise be spent trying to mop up the floor. To trouble­shoot problems, it is necessary to be aware of the various factors that may have a direct influence the situation.

The author collecting steam condensate samples for analysis for pH and conductivity from steam being injected below ground used to liquefy bitumen for extraction.

Condensate samples were taken of steam that was being taken from six once through steam generators (OTSGs) and two heat recovery steam generators (HRSGs) to several dozen well pads each with dozens of individual well pads. Each HRSG turbomachine produced 90 MW so a combined 180 MW with some extra headroom reaching 202 MW for peak loading. The HRSGs of oil producing steam assisted gravity drainage (SAG-D) sites make high-temperature, high-pres­sure steam. But only high-temperature, low-pressure steam is needed to be injected into the ground to liquefy bitumen for extraction, so it makes financial sense to run the steam through turbogenerators.

Above ground pipelines carry steam to the pads and above ground pipelines carry the produced bitumen back to the plant. The bitumen is then treated to separate the oil from the water, gasses, and steam. The steam in a SAG-D site is injected into the ground; heat and pressures change the viscosity of the heavy oil that is trapped in the sand and it flows downward by gravity to collection pipes and is pumped out. The gasses are collected and burned in the steam gener­ators to create heat to vaporize the recycled water from the wells and reuse it.

When samples of steam condensate samples were collected from the steam being injected into the ground, the high-tempera­ture, low-pressure steam was run through water cooled coils. The samples were analyzed for pH, residual amines and conductivity and the samples were also run through an Inductively Coupled Plasma Optical Emission Spectrometer (ICP-OAS) for elemental analysis. Samples are burned in a plasma flame that is 2,000°F hotter than the surface of the sun.

Steam condensate samples showing different colors from week to week and well pad to well pad.

The color of steam condensate samples collected varied depending on the well pad, as well as varying from one week to another. Many different tests were run in an attempt to find a statistical correlation between the changing shades. A vola­tile acid test was done, based on ester­ification of the carboxylic acids present. All volatile organic acids present are reported as their equiva­lent mg/L acetic acid. This led to the discovery that the darker the steam condensate, the higher the presence of carboxylic acids (an indication of potential corrosion). This results from this test can be statistically compared to steam generation parameters such as steam qualities, temperature, pres­sures, carryover, and amine additions for the set points of the steam engines.

This investigation led to further discoveries. This included the causes of scale taken from samples gathered from boiler pigging operations. X-ray diffraction (XRD) analysis done by an electron microscope scan of scale in an HRSG stream final pass going to a turbogenerator. Different kinds of scale have varying effects on heat transfer and metal expansion coeffi­cients, as well as vibration.

Troubleshooting pipeline steam condensate.

Keep it simple

Gas turbine fuel control has become more important than ever. Whether due to emissions mandates, maintaining efficiency, plant profitability or increasing the lifespan of a facility, operators and owners are looking for ways to achieve a tighter rein on fuel usage. Here are the top five reasons why now is a good time to upgrade your fuel system.

There are a great many gas turbines around that have been in operation for ten, twenty, thirty or more years. Machines that have been in heavy use are likely to have worn fuel valves, unreliable shutoffs, or systems that aren’t responsive enough to operator instructions. But even peaking turbines that have seen infrequent usage can suffer badly due to faulty fuel control systems or components. 

The Gas Fuel Shutoff and Control System from Continental Controls includes fuel metering, redundant pneumatic shutoff valves, pilot valves, flow measurement, NOx feedback, fuel heating value measurement, and gas leakage elimination via a coaxial valve.

As these units age further, components wear. This can lead to problems in starting up the machine as well as unscheduled outages and maintenance personnel continually having to babysit the fuel controls. 

Additionally, there are many turbines out there with fuel control systems that are either poorly supported or have been made obsolete by the OEM. There comes a point when it becomes too much of a burden to continually scramble to find components or keep aging controls running.

In this day and age, speed is everything. Operators demand turbomachinery that is going to start up rapidly on demand, and shutdown instantly should problems arise. The fuel control system must match these expectations. This means valves that provide the precise fuel mix and fuel shutoffs that do the job in a timely manner. 

Yet fuel controls don’t always measure up. In some cases, aging facilities have installed manual ball valves to keep their fuel control systems running. There is no place for such technology in a modern gas turbine plant. Even standard fuel control systems may not be good enough for current conditions. Response times of half a second to a second (and as much as two seconds for a slow motor) are commonplace. Such systems operate at risk. 

Pneumatically actuated valves are required with response times of 200 milliseconds or less. Only then, can the operator have peace of mind that shutoffs will occur rapidly enough to avoid damage. Furthermore, pneumatic systems are available that only need 1 amp at 24 volts DC. 

Fuel metering valves must also be able to function at the right pace. All-electric fuel control valves offer real-time flow control to dispense the right amount of fuel at the right time, as requested by the turbomachinery control system. This has everything to do with achieving performance objectives, while avoiding the possibility of falling out of emissions compliance.

Not so long ago, plants operated with large teams of skilled operations and maintenance personnel. But the demand to do a lot more with far fewer personnel has drastically shifted the skills picture in facilities. Couple that with an aging workforce with a steady parade of retirements and there is no place for finicky or unreliable turbine systems. 

Fuel controls, therefore, must not be the weak link. Instead of being composed of multiple components cobbled together over the years that require constant attention, they must be unified into one comprehensive, automated fuel metering, shutoff, and control system. Ideally, such pre-assembled systems would include electric actuation at low power to eliminate the need for additional high-powered electrical lines to be fed into them to operate motor-driven valves. It is even possible to operate the fuel control valves at the same pressure as the incoming gas. 

Such systems ease the burden on less-experienced plant personnel by offering them an engineered solution that is tested, integrated, and can be dropped in place. Veteran staff may be able to purchase the various components and competently tie everything together – if they have the time. But the generation entering the workforce demands fit-and-forget, leak-free systems. They want to spend their time on the big picture – overall performance, plant economics and emissions compliance – not in the routine of adjusting valves, checking for leaks, and troubleshooting fuel control issues.

Standards are continually evolving. Safety standards have altered markedly over the last twenty years. These days SIL 2 or 3 safety levels are the norm for new valves. Fast shutoff of fuel to the gas turbine is another aspect of safety. The flow of gas must cease immediately as dictated by plant control systems or whenever there is a loss of pilot pressure.

 Older systems lack the safety capabilities of the latest fuel controls. The latest systems offer redundant pneumatic shutoff valves, and a block-and-bleed architecture to prevent leaks. In addition, they offer pilot valves: A spring-loaded piston is activated by system pressure to open the valve; when pressure is released, the valve closes at once. This safety feature is an important fail-safe mechanism. Those relying on all-electric systems, however, can experience shutdown delays in the event of a power cut. 

There are plenty of other standards that apply. Those wishing to operate in Europe must meet ATEX requirements, which are steadily refined. In North America, valves, components, and systems are subject to ASME certification. Similarly, emissions regulations become ever more stringent. Gas turbine operators must maintain NOx and other emissions below regulated limits. More recently, gaseous methane compliance has been added to the compliance burden. 

This Gas Fuel Shutoff and Control System manifold by Continental Controls with integrated controller and sensors for temperature, pressure, and other parameters has been operating successfully on a gas turbine in Southern California.

Older fuel controls are found lacking when it comes to some of these standards. They struggle to remain in compliance and lack the flexibility to deal with shifts from high BTU to low BTU fuel, or vice versa. However, systems are available with complete fuel control assemblies fully certified and tested to meet local requirements.

Inefficient fuel systems exert a significant impact on plant performance and profitability. The ability to rapidly start, stop and adjust the various elements of fuel control translates directly into improved economics and an ability to meet market demands. Older systems lack the necessary degree of responsiveness. 

Component or system unreliability opens the door to unexpected shutdowns. This can mean the difference between a profitable and unprofitable facility. Those investing in modern, end-to-end fuel controls gain more certainty of performance. With that comes lowered risk and more predictable economic outcomes.

The Gas Fuel Shutoff and Control System from Continental Controls is a complete fuel train inclusive of fuel metering, redundant pneumatic shutoff valves that meet safety and other industry standards, pilot valves, flow measurement, NOx feedback, fuel heating value measurement, and gas leakage elimination via a coaxial valve. This integrated system includes a controller with sensors for temperature, pressure, and other parameters. All components are preassembled, welded, tested, certified, and delivered on one manifold. 

The design allows for precision flow, pressure, or position control measurement even with changing backpressure or other effects from the application that may cause other measurement techniques to be less accurate. Fuel flow measurement, for example, is available to the user for control, display, and logging purposes at ±2% reading accuracy or 0.5% of full scale, whichever is greatest. Fuel flow control is conducted by an electronic computer assembly. This computer receives the 4 to 20 mA fuel demand signal and compares it to the fuel flow signal from the built-in flowmeter. It then adjusts the throttling orifice to change the fuel flow as necessary to make the measured fuel flow equal to the fuel demand. Control is based on mass flow calculation, not just pressure or position. 

It provides fire-safe and fast natural gas shutoff, is SIL 2 to 3 certified, and can close in less than 200 milliseconds. The system is pressure tested with valves that close bubble tight with loss of pilot pressure. This integrated solution is suitable for operators and repackagers looking to repair or replace an existing fuel system on gas turbines up to 50 MW.

Five reasons why you should upgrade your fuel system. 

Turbine fuel control

Noise levels in plants necessitates the use of headsets and audio systems for tours, training, and worker communication.

Peter Drucker once said, “The most important thing in communication is hearing what isn’t said.” With all due respect to the founder of modern management theory, if Drucker had spent more time on the floor of an energy plant he may well have declared that the most important thing in commu­nication is hearing what is said.

Energy plants are noisy places. The level of noise can vary by the plant’s source of power and one’s location relative to operating equipment. A sound level of 80 decibels (dB) is considered unpleasant, 85 is the threshold for loud, and 110 is categorized as extremely loud. The thresholds for pain and potential perma­nent hearing loss are 140 and 150 deci­bels, respectively.

The mean noise levels are somewhat similar for coal plants and gas plants, with both averaging between 80 and 85 dB. However, prolonged exposure to noise in a gas-powered plant tends to be greater, with a time-weighted average (TWA) of 78 dB versus 69 for coal.

Wind power is relatively quiet, despite the complaints made by some who are opposed to construction of turbines near their homes. 55 dB are produced imme­diately adjacent to the turbine itself. 300 meters away (the minimum distance to nearby homes) the sound only averages 43 dB. At 500 meters the noise level falls to 38 dB.

However, noise levels from individual pieces of equipment in any of these plant types can run as high as 155 dB when they run combustion turbines or diesel engines. That can lead to hearing-related safety issues and workers compensation claims. The Bureau of Reclamation, which oversees management of water resources including dams and hydroelec­tric plants, reports that one fourth to one fifth of its workers compensation costs related to hearing loss. Noise exposure over time, even at lower decibels, can have a cumulative effect. This can result in other health issues, including cardiovascular problems.

Despite noise abatement measures to protect people from hearing loss, the noise generated by the operation of equipment can make it hard to hear someone else speak. The human voice is typically measured at only 60 dB. This makes it susceptible to audio blurring even in a relatively quiet plant. A background noise level of 85 dB means that people have to raise their voices to be heard by someone standing three feet away.

85 dB may seem innocuous, but noise at that level can create more problems than those resulting from 150 dB. Why? At the higher level, it is obvious to all parties that communication is impossible. There is no chance of misinterpreting a message that can’t be heard at all. However, when people talk over back­ground noise in the 85 dB range, a single word or phrase may be misunderstood without either party being aware of it. That can lead to poor decisions, ineffi­cient performance, weakened collabora­tion, and accidents.

By equipping anyone who works in a noisy energy plant with a communica­tion system consisting of a headset or earphone with a microphone, the speak­er’s voice can be transmitted directly to a receiver that allows it to be heard through another set of earphones. Such systems, originally designed for tours of noisy factories, are hands-free when used with a head-worn microphone. With this system in place, there are no issues in hearing instruct ions, warnings, or sharing of information. The only remaining barrier to communication will be hearing what isn’t said.

The energy industry has a problem with high decibel work environments.

Noise levels at energy plants

WHAT TRENDS HAVE YOU OBSERVED OVER THE PAST YEAR?

Especially with personnel working remotely, we’ve seen an increase in companies connecting and tracking equipment with sensors and other Internet of Things (IoT) hardware and software to enhance their preventative maintenance capabilities. The coupling industry is catching up with the rest of the world in terms of the data revolution. But even there, demand has exploded in terms of end user interest about how couplings are designed and selected, how they are manufactured, how they operate, how they are maintained, and how they are serviced.

Just like you and I track our orders from Amazon and get regular updates during the process, customers are looking for the same easily accessible live data for couplings. The procurement team needs quick access to product information to make purchases. Project managers are looking at Gantt charts to understand more about the process and status while couplings are being designed and manufactured. Installation and maintenance teams need access to manuals and service experts. The Regal Kop-Flex team is building a complete digital customer experience (DCX) to support these goals.

WHAT ADJUSTMENTS IS REGAL MAKING IN RESPONSE?

We have embraced smart manufacturing via Perceptiv monitoring and diagnostics. Our team utilizes remote monitoring for some customer critical equipment, providing real-time alerts and monthly performance reports. Integrating all a facility’s mechanical components is possible, and we are evaluating the cost benefits and overall ROI of doing so. For some, having their critical equipment monitored is enough, while others want to integrate our components into their existing smart ecosystem.

For example, we have been gathering data from couplings that allows plant operators to make better maintenance decisions by monitoring performance trends with the Kop-Flex Powerlign torque monitoring system. It allows users to minimize emissions and fuel costs by tracking performance trends in connected equipment. This system can be purchased new with couplings or retrofitted to existing Kop-Flex or other brand couplings.

Our Perceptiv intelligence group uses an array of torque monitoring solutions for online monitoring, predictive maintenance and failure analysis. This includes the use of augmented reality tools. Additionally, there is definitely a trend to have spares for all critical equipment. It minimizes downtime if you have a spare coupling to hand instead of having one shipped. Some customers send the main coupling back to our Kop-Flex team for recertification.

A Regal technician installing Perceptiv remote monitoring technology.

WHAT NEW PRODUCTS OR SERVICES ARE YOU OFFERING?

Regal continues to expand Perceptiv on-site and remote monitoring and diagnostics to help our customers install and monitor equipment 24/7 or as needed. These tools save money by diagnosing potential problems before they happen. Examples include torque monitoring, vibration observation, and motor current signal analysis.

The Regal Tag-It Program powered by Perceptiv intelligence is an asset management platform to view details on mechanical and electrical assets in operation and reduce redundant or obsolete inventory. The program creates a path for continuous facility improvement by enabling faster maintenance and simplifying the MRO procurement process. In addition, users can easily add Perceptiv wireless monitoring to keep an eye on critical equipment. This 24/7 monitoring technology will help customers to increase equipment reliability and maximize production. The combination of hardware, software and “humanware” provides a new way for users to interact with Regal products and their equipment. All of this helps customers to harness the power of IoT in their facilities.

We expanded our coupling recertification program to repair, rebuild, and recertify couplings removed from service to API 671 standards. This allows our customers to have a lower-cost recertification coupling available for future planned outages or emergencies. Customers can recertify their disc, diaphragm, and gear couplings for up to 50% savings from the cost a new item. Ship the used/worn coupling to one of Regal’s worldwide repair facilities, where they will be disassembled and undergo a non-invasive cleaning. Evaluation determines the material integrity and flexible elements, then we remove and replace any hardware, if necessary. They are then reassembled and rebalanced in accordance with API 671 or original OEM specifications. After a final inspection, they are returned to the customer within 4 weeks.

We also offer a Max-C resilient coupling that provides damping for applications with shock loading or cyclic torques. The Max-C can be mated to disc or diaphragm couplings to tune the drive train. They are frequently used on synchronous and variable frequency drive motors.

Dan Phillips, Technical Director, Monitoring and Diagnostics, Regal, discusses couplings, the Internet of Things, remote monitoring, diagnostics, and smarter maintenance practices.

Q&A: Making maintenance smarter via remote monitoring and digital tools

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

Turbomachinery Blog features postings from experts in all areas of turbomachinery, such as: gas turbines, machine diagnostics, materials, repairs, and aftermarket parts, and encourages users to participate, with reader engagement and interaction as its primary purpose.

Sensonics Sentry G3. Image courtesy of Sensonics. 

The Sentry G3 machinery protection system from Sensonics combines the flexibility of hardware in a single, easy-to-install and easy-to-use module type. The system is compliant to API 670– the most stringent protection requirement – and meets IEC 61508 up to SIL-3 standards.

The Sentry G3 system has been subject to ‘emphasis audits’ as part of its use in monitoring gas turbines in the UK. The emphasis method assesses a device’s compliance with IEC 61508 for functional safety standards, along with other requirements specific to the UK nuclear industry. It provides end-users with the confidence that both the hardware and software components in these protection systems meet the required high levels of design, testing and production which minimises the risk of systematic failures. 

Advanced features include vibration, position and speed parameter trending facilities, including log and view of up to 60 days of data, ‘look back’ at trends and alarms, plus the ability to download data for further analysis in Excel. It is also now possible to directly view proximity probe gap and vibration transducer bias voltages, to verify correct transducer operation and calibration. The Sentry G3’s single module concept helps reduce ongoing maintenance costs whilst also lowering the risk in retrofitting applications.

The system is fully software programmable and upgradable. It’s also easy to expand, simply by adding additional G3 monitors. It offers excellent channel density with up to 24 measurement channels housed in a compact 3U x 19” rack mounted format which can halve the space needed on existing installations. Multiple outputs are available on the back of the rack for up to 3 alarm levels and 2 analogue outputs per channel. Dual redundant Modbus communications to a module level provide a robust communication system, while the in-built LCD display offers readings, sensor integrity voltages, trending and FFT, all of which confirm the accuracy of the installation.

In summary, Sentry G3 provides state-of-the-art, flexible, easy-to-install and maintains space-saving protection for the following modes:

 - Absolute bearing and relative shaft vibration, shaft position and thrust wear, speed, phase and reverse rotation, differential and casing expansion, rod drop and temperature.

 - Shaft eccentricity, order tracking, dynamic pressure and mark - space differential expansion.

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The system is compliant to API 670 and meets IEC 61508 up to SIL-3 standards. 

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