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.

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.

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.

Articles

Troubleshooting pipeline steam condensate.

Keep it simple

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.

Rick Farrel is President of Plant Tours, a provider of headsets and communication systems for plant tours, staff training, and facility communication.  Learn more at 

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.

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

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.

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.

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.”

Click here to sign up for our free eNewsletter!

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

Vendor spotlight: Waukesha Bearings

BY JENS DICKHOFF, ATSUSHI HORIKAWA, AND HARALD FUNKE

A transformation of the energy market is ongoing. Renewable energy rose from 5,451 terawatt hours (TWh) in 2000 to 9,824 TWh in 2019. But there is a need for large-scale energy storage to satisfy power demands when solar and wind are offline.

Hydrogen is regarded by some as the green energy carrier of the future. But it faces technical and regulatory challenges. Gas turbines operating on some or 100% hydrogen will play a key role in the transition. They are a proven technology, provide electricity and process heat, and can be sized from kilowatts up to several hundred megawatts.

However, hydrogen combustion is not entirely straightforward, because of its extreme flammability range and flame speed that can lead to flashbacks. It also requires the right combustion technique to keep NOx production low. Wet NOx combustion is the current method used, where water or steam is injected into the combustion chamber to reduce the combustion temperature. The water/steam must be free from impurities. While reducing NOx emissions effectively, this approach is still not environmentally sound or efficient.

Dry low Emission (DLE) technology is likely to be the answer. But the combustion process means that engineers must think outside the typical lean combustion-low NOx box to develop new techniques.

To date, good progress has been made in achieving 30% volume H2 with only minor adjustments to the combustion chamber. But the pathway to 100% H2 is far from easy. 30% volume equates to 5% mass or 11% of energy when mixed with methane. Even 60% volume means around 15% mass. These fractions are acceptable for today when large amounts of H2 are anyway unavailable. But they are not sufficient for decentralized reconversion plants.

Another factor to consider is that at typical fuel-air ratios (e.g. Lambda 2.3) the turbulent flame speed starts to rapidly increase at around 35% to 40% volume H2 and reaches its maximum at around 70%. At that point, the danger of flashbacks for premixed combustors is extremely high. When the flame travels upstream and anchors in an undesired region such as a small step, it can quickly destroy parts of the burner structure.

Increasing the air cross flow velocity is also problematic. The pressure drop of the combustor section would increase, reducing overall machine efficiency. Additionally, burner geometries are not always perfectly smooth and typically feature small steps where flow can recirculate and autoignition can take place. This can trigger flash backs and represents a random phenomenon. Therefore, it is difficult to detect in tests since all burners are slightly different and manufacturing process quality control plays an important role here, which also has an impact on component price. Finally, the flow velocity on the wall is zero by definition. In contrast to methane, hydrogen is more prone to boundary layer flashbacks due to the higher flammability range and flame speed.

The real challenge, therefore, is how to burn greater than 90% volume of hydrogen at low emissions, without a water/steam admixture, and to fulfil safety, emission, pressure drop, and lifetime requirements inside the gas turbine. The only technology on the market bringing these points together is called Micromix (MMX) combustion.

In research and development since the late 1980s by Aachen University of Applied Sciences (AcUAS, FH Aachen), it has been the subject of many collaborative project s. These have primarily involved B&B-AGEMA and Kawasaki Heavy Industries (KHI). The basic ideas behind the concept are:

NOx suppression by residence time reduction. 

Jet-in-cross-flow mixing for flashback safety.

To suppress NOx formation, one can either lower the flame temperature or reduce the residence time of fuel/air inside the high temperature zone of the flame. NOx molecules can only form under certain fuel/air conditions and high temperatures. The best course is for N and O molecules to reach colder zones behind the flame before they undergo a chemical bond.

Pure hydrogen cannot burn. A diffusion flame is consequently flash-back safe whilst pre-mixed flames will always carry risk. By the jet-in-crossflow mixing process, rapid premixing lowers the average flame temperature. If the flame travels towards the H2 injector, the mixture becomes too rich to burn and is forced to travel back to its intended position without damage to burner components.

Early designs proved out the general concept and highlighted issues to overcome. By incorporating computational fluid dynamics (CFD) through the help of AcUAS and Kawasaki, this combustor technology was introduced into the Kawasaki M1A-17 gas turbine (2 MW).

Reactive flow simulations were performed in Siemens Simcenter STAR-CCM+ to study aerodynamic flow parameters and the combustion structures (flame shapes). The aim was to find the optimal design and length of the flame to ensure low NOx combustion and reduce the number of injectors. Simulations included reactive chemistry to predict the flame shape, size, and temperature signature. Siemens Digital Industry Services provided model tuning.

As a result of this research, AcUAS and B&B-AGEMA developed the fourth and fifth generation MMX combustor. It includes a new flame shape with very low NOx properties, based on CFD simulation, which was never considered before. The team developed a prototype burner.

An air-cooled borescope was developed to visualize the MMX flames inside the can combustor under full pressure. This optical monitoring device is equipped with an infrared or white light endoscope which can be inserted into the combustor.

The head is located downstream of the flames and exposed to the highest temperatures (>1300°C). This assisted in verifying combustor performance.

The overall target was to have less than 35 PPM NOx at 100% hydrogen from 50% to 100% load, with low NOx values at part-load operation as well. Additional requirements were stable ignition, no flashback, and an acceptable pressure drop. With an intensive program of CFD simulation, design optimization and benchmark validation on low- and high-pressure test rigs, an MMX burner design successfully met these targets.

The recent focus has been on implementing this technology into industrial turbines. In 2020, the Japanese New Energy and Industrial Technology Development Organization (NEDO) and KHI announced a successful demonstration of the first DLE 100%-hydrogen-fuelled gas turbine under commercial operating conditions in the port of Kobe, Japan.

New DLE combustor addresses NOx emissions and flashback. 

Hydrogen combustion

Steam turbines provide an efficient means of producing electricity. Improving the corrosion fatigue performance and damage tolerance of steam turbine blades can offer overhaul and maintenance cost savings, improved reliability, and reduced outages.

The application of surface residual compressive stress to components can enhance fatigue strength and reduces the effects of applied tensile stresses. Shot peening has been used for decades to reduce overall operating tensile stresses in steam turbine components. However, corrosion pits, erosion, fret[1]ting, and other damage can penetrate shot peening’s shallow layer of residual compression, providing a starting point for stress corrosion cracking and fatigue failures. Instead of settling for shallow compression, the introduction of a deep layer of compressive residual stress can extend service life.

To test the benefits of deep compression, high cycle fatigue tests were done on Type 410 stainless steel, a common alloy widely used in steam turbine applications, to compare the corrosion fatigue benefits of Low Plasticity Burnishing (LPB) to shot peening.

LPB is also a mechanical surface treatment, but it imparts a controlled layer of compression that is deeper than most surface damage. LPB was developed in the 1990s to keep cold work low when introducing compressive residual stress. 20 years of studying residual stresses led to the conclusion that residual compression introduced using high levels of cold working could be wiped out from in-service thermal and mechanical loads.

The first step in the investigation was to obtain sample specimens of 410SS machine-finished by low stress grinding (LSG) to serve as a baseline. Compressive stress was introduced either by LPB or shot peening. The LPB process is performed on conventional CNC machine tools and robots. Shot peening was done using a conventional air blast peening system.

Next to be tested was the fatigue strength of samples subjected to either mechanical damage or simulated corrosion and stress corrosion cracking. Mechanical damage simulates what can happen to the surface of the turbine blade from common fatigue damage mechanisms like foreign object damage, fretting, corrosion pitting, or erosion.

Mechanical damage was simulated through an electrical discharge machining (EDM) notch with a depth of 0.01 in. (0.25mm). For a portion of the LPB-treated samples, a deeper notch depth of 0.02 in. (0.51mm) also was investigated.

High cycle fatigue tests show that shot peening the 410 SS samples provided a modest improvement over the baseline condition with mechanical damage. Residual stress distributions revealed that the 0.01 in. (0.25 mm) notch completely penetrated the compressive layer introduced by shot peening minimizing any fatigue life benefit from shallow compression.

However, the deep compression provided by LPB doubled the fatigue strength and improved fatigue life near the endurance limit by a factor of over 100 compared to the shot peen condition. Even with damage twice as deep, the LPB-processed samples outperformed those that had been shot-peened.

When subjected to corrosion damage and salt exposure, simulated by testing samples in an active corrosion medium of a 3.5% weight NaCl solution after first exposing them to stress corrosion cracking (SCC) in the same medium, the LPB-processed samples again demonstrated double the fatigue strength.

Surface roughness measurements indicated roughness values of 19.5 μin for the baseline sample, 157.1 μin for the shot peened sample, and 4.5 μin for the LPB-processed sample. The roughness value for the shot peened sample is nominally 35X higher than that of the LPB-processed sample. Shot peening dimples produce a rough surface that can adversely impact fluid flow at the blade surface.

Some steam turbine manufacturers are now implementing LPB on their blades upfront to reduce overhaul and maintenance issues. Others use LPB as a faster and more economical repair technique. Depending on the steam turbine, manufacturers can apply LPB with the turbine blades installed on the rotor. LPB as a surface treatment does not add material or change the blade’s balance like traditional welding repair methods.

A repair solution for steam turbine compressor failures. 

Deep compression

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, 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.”

Woodward Turbomachinery Systems also offers remote monitoring systems to enable its technicians to gain remote access to address service issues.

“A key aspect of any remote monitoring or access system is cybersecurity,” said Greg Marino, Product Line Manager, Woodward. “In today’s world, no one is going to allow you to connect remotely without a thorough security review.”

He added that each new hardware upgrade carries with it a greater degree of cybersecurity to ensure Woodward products meet or exceed security standards. The company also offers system level security for Human Machine Interfaces (HMI), workstations, and networks in addition to controls to help users meet NERC/CIP, ISA 62443 and regional standards.

Woodward offers a line of turbomachinery controls that range from small hydro and mechanical- drive steam turbines through nuclear steam, gas turbines, combined cycle, and integrated gasification combined cycle. It also has SIL2/3 safety controls and matching electro-hydraulic and electric valve actuation products.

Marino said the 505 product line is the most popular turbine control platform with approximately 28,000 installed worldwide. It’s preprogrammed and configurable via an onboard multi-language HMI or remotely from a workstation. It includes self-optimizing control loops and is available in single valve, extraction, and dual-redundant versions, and has multiple international and regional hazardous location certifications.

“In larger controls, we see interest in cybersecurity, reliability, and integrated functional safety,” said Marino. “The use of functional safety controls or integrated functional safety is expanding in the oil & gas market. Buyers of smaller controls are more focused on ease of use, reliability. and cost efficiency.”

The newest Woodward platforms and updates are being enhanced to support analytics and secure Industrial Internet of Things (IIoT) functions.

EthosEnergy’s approach as an integrator is to evolve its cybersecurity to match the needs of users. Its scope had increased to include balance of plant controls, and helping bridge IT and OT security. Basic historical methods of network segregation, firewalls, and hardening workstations are standard for the core control system.

Jeff Schleis, Product Manager, EthosEnergy, has observed greater built-in security in controls. While plant-wide issues remain, features like keyed software/firmware, encrypted communication methods, and networking hardware/software that is co-developed with the control system manufacturer are all methods that increasingly harden the equipment we integrate.

Schleis emphasized the benefits the entire industry has experienced due to the dramatic rise in the amount of processing power available to control systems.

“Whereas in the past, we required multiple processors to handle demanding sub-10ms systems or large balance of plant systems, we can now perform well in one CPU with room to spare,” he said. “However, connectivity remains a challenge because of the large number of legacy systems in the plant.”

EthosEnergy has a fleet of units that it operates for owners. Predictive data analysis is used to optimize maintenance efforts via the company’s PHD Advance solution. It leverages cloud computing to process large volumes of data received from a plant. It identifies issues and negative trends that are further investigated by EthosEnergy engineers to find root causes and target maintenance activities to reduce maintenance spend, maintain plant performance, and increase availability.

Additionally, the company provides Icon control system upgrades and retrofits on gas and steam turbines. With over 1,000 systems supplied, these encompass nearly every OEM and industry.

Take the case of an LM6000 gas turbine. The base icon system upgrade for this turbine includes the necessary sequencing, fuel control, and protections. Optional solutions are available to solve problems surrounding the package and plant. One of those includes the ability to improve on-vent fan diagnostics. Rather than utilize the original flow switches, technology has been added to the motor control center (MCC) to diagnose when a fan is running, or if an abnormal situation is present. This reduces the possibility of a failed start and improves availability. Other enhancements improve diagnostics, increase performance, and reduce downtime.

It has been a common theme for EthosEnergy to expand this same hardware into the balance of plant systems and reduce the number of platforms that the site supports. This has been primarily for independent power producers or small petrochemical plants where a Distributed Control System (DCS) may not be present or has similar obsolescence issues as the turbine control system.

“Customers have issued specifications that include both the turbine control and the balance of plant controls where we can modernize those systems for the HRSG, water treatment, inlet chilling, and other systems,” said Schleis.

He noted other trends such as: adjusting controls to deal with cyclic operating profiles; increasing turndown and attempting to minimize stress on the unit; finding ways to peak fire and increase the plant’s usefulness to the power market; finding ways to improve availability and prevent downtime; redundancy requirements have increased as industrial customers have the budget to increase controller complexity, as well as instrumentation in the field to improve availability; and allocating funds for upgrades on older units that previously were not being considered.

“Larger projects to modify the unit to meet emissions and increase generating output are getting approved,” said Schleis. “Having the ability to mechanically modify the unit and provide the necessary control system upgrades are key to being competitive.”

Yokogawa has teamed up with Shell to develop the Plat form for Advanced Control and Estimation R5.03 as part of the OpreX Asset Operations and Optimization family. This software suite brings together Shell’s plant process control technology and Yokogawa’s real-time controls to improve productivity by increasing product yield and reducing energy consumption.

It incorporates a new communication standard that enhances security: The Open Platform Communications Unified Architecture (OPC UA), which improves plant systems interoperability and security. OPC is an interoperability standard for the secure and reliable exchange of data in industrial automation.

The new Yokogawa platform is suited to facilities such as oil refineries, petrochemical plants, chemical plants, and LNG trains. It incorporates the control of multiple variables based on predictions made using models of the dynamic characteristics of plant responses, as well as sensing to estimate quality in real-time based on temperature, flow rate, pressure, and other process values.

Tri-Sen reports a rise in discussions relating to the IIoT and big data. The issue there is the vulnerabilities inherent with a higher level of connectivity.

“We’ve been investigating methodologies for identifying and reducing connectivity risk in the solutions we provide, and are excited about the possibilities related to the top-down systems approach posited in the ‘System Theoretic Process Analysis’ for security (STPA-Sec),” said Thomas Bailey, Director of Marketing, Tri-Sen.

The company has begun using the STPA-Sec methodology to identify, frame, model, and evaluate security vulnerabilities associated with system connectivity for a given integrated turbomachinery control application/solution. Tri-Sen uses this approach to assess system expo- sure, then makes specific recommendations for reducing and controlling the cybersecurity risk associated with the respective turbomachinery controls solution.

Tri-Sen provides configurable, stand-alone turbomachinery controls, custom PLC-based turbomachinery controls, turbine-safety products, as well as turbomachinery controls-related engineering services. Its standard configurable products include digital turbine governors, digital positioners, and ancillaries. Custom solutions are delivered on the PLC platforms such as Triconex, Allen Bradley, and Siemens, as well as on major DCS platforms. Turbine-safety products include a TUV SIL 3 certified hydraulic trip interface, and a couple of electronic overspeed detection system offerings. It also offers dynamic model-based studies for compression applications that include compressor startup and shutdown evaluation (associated with surge control), piping arrangement, valve sizing, and control system optimization.

Currently, the Elliott-Tri-Sen alliance team is developing a solution to provide Elliott’s users with an advanced compressor monitoring, diagnostics, and controls capability. The Alliance Compressor Performance Monitoring System (ACPMS) is a modularized software/hardware solution that provides a monitoring took-kit with fleet monitoring functionality. Features include remote monitoring, fleet monitoring, analytics, surge control, vibration analysis, along with a digital twin (compressor model) that supports “what-if?” analyses.

As for the retrofit market, Bailey said such projects are getting easier because first and second-generation digital control platforms are being replaced due to hardware obsolescence issues and not so much because of performance issues.

“Challenges associated with retrofitting mechanical governors like speed measurement and the valve actuation interface are usually already resolved when replacing digital control system with another,” he said.

GE Gas Power Executive Product Manager for Controls & Digital, Chris Long has noticed major trends such as the increasing use of artificial intelligence (AI) in modeling and analytics to keep models current with evolving plant asset capability and degradation. To complement OT cyber solutions, the company is leveraging its OEM physics- based models augmented with AI to develop means for detecting, localizing, and neutralizing threats as part of a defense-in-depth strategy.

Supporting the changing needs of a grid with increasing renewables penetration is another area of focus. GE has controls for turbine combustion and electrical systems to support high rate of change of frequency (RoCoF) scenarios. Furthermore, generator controls leverage analytics in early event detection schemes to respond to frequency swings and voltage dips.

“There is greater interest in remote connectivity and control across all aspects of plant (remote operations, grid testing, monitoring, tuning) including centralized remote command centers,” said Long. The company recently introduced a Non-Optical Flame Detector (NOFD) leveraging digital twins of sensors to improve reliability and reduce maintenance costs.

Mitsubishi Power has also been active in cybersecurity. “There is a great need for control systems to strike a balance between openness and security in order to work with higher level systems and achieve optimum operation,” said Marco Sanchez, the company’s Vice President of Intelligent Solutions.

In response, Mitsubishi Power has developed cybersecurity solutions to meet the compliance requirements of the latest North American Electric Reliability Corporation Critical Infrastructure Protection (NERC CIP) standard. It consists of two components within the DIASYS Netmation 4S control system that enable flexible operations and meets functional safety standards as defined by IEC 61808:2010.

The first component is Virtualized Netmation that virtualizes HMI workstations on redundant servers. Virtualization creates a more secure environment by reducing exposure to outside threats and providing a framework to monitor continuously for malware and intrusion detection.

The second component is Netmation Protect Pack (NPP) that provides a framework for integrated threat management, risk management, application control and system health monitoring. NPP provides mechanisms to ensure that all software has up-to-date patches and a centralized portal to report, audit, and protect against intruders, malware, and ransomware.

Sanchez said Mitsubishi Power’s Tomoni can help facilities become digital power plants by adding automation and embedded intelligence. “Tomoni uses analytics, adaptive control, and AI to increase plant flexibility and provide profitable, clean power,” said Sanchez. “Plants utilizing it for remote monitoring and diagnostics operate with 1-2% higher reliability.

Ingersoll Rand (IR)has been building centrifugal compressors since the early 1960’s. This includes legacy Centac and Turbo-Air frames and the latest generation of Turbo-Air NX compressors ranging from 500 cfm to over 30,000 cfm with discharge pressures from 25 to 610 psig.

IR provides controls and automation equipment for its equipment to more easily manage compressor systems, enhance system reliability and improve efficiency. This includes flow and pressure controls, centrifugal compressor control systems, rotary compressor controllers, and compressor system automation products.

Its Xe-145F Series controllers (standard on MSG Centac) have a high-resolution color display. When it detects a problem, it can post information on the web or send email notifications. Maestro Universal is an equivalent air control system for managing centrifugal compressor performance, and is the standard controls for IR MSG Turbo-Air and MSG centrifugal compressors. The company can design a customized Maestro Universal controller upgrade for existing compressed air systems. Instrumentation packages and monitoring functions are configured to optimize compressor performance. In many cases, equipment can be repurposed. With the newest generation of controllers, IR enables expanded connectivity and communication capability, as well as increased memory and processor speed.

Maestro Universal controls are used on the Turbo-Air NX, which is built to operate in industrial applications, including the process air and air separation markets at often unmanned sites without backup for extended periods, years in some cases. It is rated for flows from 3000-7500 cfm and pressures from 35-210 psig discharge. An inlet guide vane and increased throttle range bring operating flexibility. Further models in this line include the NX 12000 and NX 8000.

“The Turbo-Air NX 5000 is applicable across markets demanding a consistent supply of oil-free compressed air or nitrogen,” said Sam Gooldy, Senior Global Product Manager, Ingersoll Rand.

The company also makes reciprocating compressors. Gooldy says they are typically applied below 500 cfm or over 600 psig discharge pressure. “For flows over 500 cfm or under 600 psig centrifugal compressors tend to be a clear winner due to reliability and the higher maintenance associated with a reciprocating compressor.”

Nexus Controls, a Baker Hughes business, has provided unit control, DCS, excitation, mechanical, cybersecurity, services, and software in more than 11,000 projects globally. These included gas/ steam turbine, hydroelectric, and compressors. “Cybersecurity is a fundamental part of managing the operating risks of pipelines and critical equipment,” said Terry Knight, Vice President, Nexus Controls, a Baker Hughes business.

The company’s offerings cover unit controls, generator excitation and protection, static starting systems, mechanical and instrumentation solutions along with BOP controls. Its turbine-driven compressor controls address operating efficiencies and surge. The Nexus OnCore Control System enables digitization through collecting, integrating, and analyzing data. The company is adding further analytic capabilities and remote monitoring offerings.

“We have seen increased interest for remote monitoring and operation, primarily from those seeking to optimize maintenance and operations expenses,” said Knight. “Capabilities include site installation, and integration of site audible and visual annunciation for occupational safety and health global standards compliance.”

Schneider Electric provides control systems for steam/gas turbines, compressors, automatic voltage regulation, generator automatic synchronization, generator power management, turbine auxiliaries, mechanical retrofit, data analysis, and HMI interfaces. It offers site surveys, machine assessments, dynamic simulation, consultation, performance optimization, controls troubleshooting, mechanical retrofits, predictive analytics, and performance monitoring. Controllers range from simplex Modicon to TMR Triconex PLCs.

“Customers desire increased time between turnarounds and decreased turnaround times,” said Hector Buchelly, Global Senior Director of Turbomachinery and Advanced Services, Industrial Automation Business, Schneider Electric. “The road to digitalization, which requires the ready availability of data, requires machinery to be upgraded and retrofitted so the digital solutions can have the value they represent.”

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

Cybercrime surge: how controls vendors are responding 

Even the most ardent supporters of natural gas generation acknowledge that curbing emissions is a good thing. Many main­stream power and oil & gas executives are some of the loudest voices calling for improve­ments. And they have been joined by U.S. President, Joe Biden.

The Administration unveiled a several tril­lion-dollar infrastructure plan that set the goal of net-zero carbon emissions by 2050. The plan would require major changes in the energy sector. (At this time of writing, the bill has yet to nego­tiate its way through Congress, and the overall amount is being trimmed down).

At an Earth Day climate summit, Biden called for cutting U.S. greenhouse gas emissions by 50% to 52% from the baseline year of 2005. In compar­ison, Obama’s target was 26% to 28%. The power industry is under the microscope as part of these plans as electricity generation accounts for 25% of U.S. emissions. That said, the sector has a much better record of curtailing emissions over the past twenty years than the transportation, commercial, or agriculture sectors. This is largely due to the switch from coal to natural gas, increasing adop­tion of renewables, and the implementation of effi­ciency and emissions reduction measures.

The administration’s plan would establish an Energy Efficiency and Clean Electricity Standard (EECES) to incentivize “more efficient use of existing infrastructure and continuing to leverage the carbon pollution-free energy provided by existing sources like nuclear and hydropower.” What his ultimately means to natural gas genera­tion is anyone’s guess. Opinions vary from it being a benign approach that will gradually phase out natural gas generation over many decades to a ploy to outlaw natural gas via extreme emissions requirements.

A tax reform proposal is included that would eliminate billions of dollars’ worth of “subsidies, loopholes, and special foreign tax credits for the fossil fuel industry,” according to the White House website. It intends to reinstitute financial penalties for companies contributing to pollution.

The American Petroleum Institute (API) believes that ending the tax breaks would have a catastrophic effect on the economy. “Targeting specific industries with new taxes would only undermine the nation’s economic recovery and jeopardize good-paying jobs, including union jobs,” the API.

The American Gas Association (AGA) expressed support for the U.S. Department of Energy’s initiative to fund technologies designed to reduce methane emissions. “We continuously examine our 2.6 million miles of infrastructure for methane reduction opportunities and are investing in ways to help other industries reduce emissions by injecting their methane into our delivery system,” said AGA Pres ident and CEO Karen Harbert.

American natural gas utilities have delivered methane emission reductions of around 73%, according to the 2020 Inventory of U.S. Greenhouse Gas Emissions by the U.S. Environmental Protection Agency (EPA). Research recently published in the journal 

calculated that existing technologies could cut methane emissions in half by 2030. These methods include reducing oil- and gas-related leaks and methane flaring, in addition to cleaning abandoned oil mines and expanding the use of feed supplements for cattle.

While there are contrasting views on some proposed measures, one area receiving broad support is an investment tax credit to incentivize buildout of 20 GW of high-voltage capacity power lines. This will be overseen by a new Gr id Deployment Authority at the Department of Energy. One of its duties will be to fast track right-of-way approvals for new transmission lines. States have been advised to remove regulatory obstacles that may impede the progress of the network.

Hydrogen is also in the spotlight. The plan calls for pairing 15 hydrogen demonstration projects with a new renewable electricity production tax credit (PTC) to encourage carbon emis­sion reductions. Pioneer facilities would test carbon capture systems on steel, cement, and chemical production plants. Power plant s were omitted from this program.

Green hydrogen from renewable sources is the priority, but there is room for blue hydrogen, produced from natural gas and other fossil-fuel facilities. Such projects may be able to take advan­tage of a production tax credit.

The proposed Storing CO2 and Lowering Emissions (SCALE) Act addresses the development of large-scale carbon sequestration technology. The plan encourages carbon capture, utiliza­tion, and storage (CCUS) through the expansion of a tax credit, intended to make the technology “easier to use for hard-to-decarbonize industrial applica­tions, direct air capture, and retrofits of existing power plants.”

A10-year extension of the produc­t ion tax credit and investment tax credit for renewable energy generation, high voltage transmission, and energy storage is another element of the plan. Biden also appears to be betting on LNG as a smart way to lower the U.S. carbon footprint. This is to be achieved by lowering the emissions profile of LNG while addressing methane venting, fugitive emissions, and flaring.

The Biden Administration unveiled a several trillion-dollar infrastructure plan that set the goal of net-zero carbon emissions by 2050. 

Infrastructure bill

The highlight of the annual Western Turbine Users Inc. (WTUI) show is the report on gas turbine trends by Tony Brough and Mark Axford. Tony Brough, President of Dora Partners, kicked things off by showing the latest trends. MW orders are down 3.2% in 2020 compared to the previous year, while unit orders are up 0.3%. Since 2012, however, MW orders are down 42% and unit orders are down 67%. 

“Over the past five years, gas turbine capacity orders have dropped from about 50 GW per year to just less than 40 GW,” he said. “In 2020, the market was unexpectedly good in light of COVID-19, likely due to the fact that the process of contracting and purchasing industrial GT’s is a protracted process that may well have started in 2018 and 2019.” 

Looking more closely at aeroderivative turbine trends, Brough commented on the resilience of the LM2500 and LM2500+. The LM2500+ accounted for 30% of the market over the past five years, by far the best selling aeroderivative. The various flavors of LM2500 also boast the largest aeroderivative gas turbine fleets followed by the LM6000. 

Although sales could be better, the overhaul and repair market for existing aeroderivative fleets is valued at $2.3 billion per year.

Outside of Russia, sales of aeroderivatives are dominated by GE/Baker-Hughes. The jump in their share of the market in 2020 was largely driven by Baker-Hughes’ newest unit, the LM9000. 

Brough provided an interesting point of comparison of the most recent seven year period compared to the previous seven years (ie, a 14 year total period). In the electric power and utility (EPU) market, there has been a sharp drop in aeroderivative units orders in all regions except the Middle East and Africa. Asia Pacific is down 34%, Europe and North American down 80%, South America down 54%, and Russia down 83%. In oil & gas, the picture is a little different. North America experienced a 174% spike in aero unit orders compared to the earlier seven-year slot. Every other area was down – anywhere from 33% to 84%.

“Only the North American oil & gas industry has seen long-term growth for aeroderivative units,” said Brough. This was mainly due to the need to power fracking sites, as well as for pipeline network expansion.”

During 2020, the worldwide market for aeroderivative gas turbines showed a 14% jump on the previous year, with MW orders up 7%. GE’s worldwide share was 67%. The LM9000 accounted for almost half of all worldwide orders, followed by the LM2500+ at around 30% with the LM6000 and Siemens SGT-A35RB (formerly RB211) sharing third spot. But North American aeroderivative unit orders and MW orders were both down 69% with GE grabbing 100% of U.S. business for the year.

Brough then turned his attention to the long-term outlook for industrial gas turbines. He said to expect wind and solar to grow dramatically over next 20 years. Therefore, it is important to determine what role gas turbines will have, particularly aeroderivative units. 

“Gas turbine utilization of hydrogen, methanol, ammonia, and other low-carbon fuels will gradually be introduced over the next 10-25 years, with a mix of these low-carbon fuels and natural gas initially.” he said. 

Another big push will be for green hydrogen i.e., produced with only renewable sources. Green hydrogen is viewed as the battery of the future whereby you take excess renewable energy and use it to via electrolysis to produce hydrogen. 

“Gas turbines can be retrofitted for hydrogen mixes as well as to work on 100% hydrogen,” said Brough. “But getting the hydrogen to the point of demand is going to be a major challenge and implementation of this green hydrogen vision is going to take a long time.”

He pointed out that the economics currently are hard to justify, but regulatory requirements and government incentives will propel this change over time. To run an LM2500 for a year on 100% green hydrogen would require a massive amount of excess renewable energy. Thus, major technical, fuel delivery infrastructure, and economic hurdles must be overcome in any transition to low carbon fuels. 

“There is a future for gas turbines with or without fossil fuels,” said Brough.

Mark Axford, President of Axford Turbine Consultants, took the stage by showing a graphic showing aeroderivative orders being flat for 2020. He expected it to be worse. He outlined the three factors responsible for long-term stagnancy in the markets: regulation, mandates, and subsidies. 

In the gas turbine business, the regulations started with pollutants. Limitations on NOx and CO were around 100 ppm when Axford started in the business during the 1970s. But the limits are now as low as 2 PPM in some states (2 PPM typically exceeds the error factor inherent in measurement equipment). Additionally, Axford noted unnecessary limits on ammonia slip, and the requirement to treat CO2 as a pollutant rather than an emission. 

As a result, renewable energy is the fastest growing component of U.S. electric supply. The Department of Energy's Energy Information Administration (EIA) now predicts that in 2030, more electricity production will be from renewables than gas. The current 40% share of natural gas will drop to 36% by 2050. 

“Solar is now growing so rapidly, it is forecast to be the largest component of renewable energy by 2040, surpassing wind,” said Axford. “But it remains to be seen if this will take place.” 

Axford moved on to the advanced gas turbine market. GE accounts for has 45% of advanced gas turbine MW orders since 2014 worldwide. Mitsubishi Power is in second place, followed by Siemens and Ansaldo. His view on this market will largely be driven by combined cycle plants being used to replace coal and nuclear facilities forced into retirement. But the market for these massive gas turbines is constrained by grid requirements. Many areas don’t have a grid that can support an 800 MW to 1 GW combined cycle plant. 

“This is too large for many countries with less developed grids,” said Axford. Meanwhile, the launch of the GE LM9000 aeroderivative gas turbine is off to a good start. Baker Hughes received an order for 20 units for the Novatek Arctic LNG project in Pacific Russia. This includes 12 LM9000s in mechanical drive and another eight gensets. 

Axford also noted that Siemens has ended production of its A45 and A65 (formerly Trent) engines due to factors such as cost and difficulty competing. Other engines in trouble include the LM6000 which has seen a sharp drop off of orders over the last decade, and several units with no orders in 2020: the LMS100, FT8 MobilePac, and FT4000. 

“The LM6000 has a fleet of more than 1,100 units, but has been getting few orders for some years,” said Axford. 

He added that part of the reason for this is competition from the Siemens SGT-800, which now dominates the 50-60 MW segment. Axford said factors such as price and combined cycle performance favor the SGT-800. Another area where GE is losing out is in refurbished LM6000s. ProEnergy has delivered 52 of them over the last few years. 

Turning to the electric vehicle (EV) market, Axford views the rise of the EV as good news for gas turbines. “As battery storage is adopted, the market for mid-sized gas turbines will be the big loser,” he said. “But at higher levels of renewables, it could be risky to rely on expensive battery backup so there will a place in the market for gas turbines.” 

He largely dismissed the concept of turbines running on 100% hydrogen provided from electrolysis. He said that steam reformation of methane is a far cheaper way to produce blue hydrogen. Further, the pipeline network is not built for hydrogen. Plastic distribution lines would embrittle, and there would need to be extensive rework done on 1,400 compressor stations in the U.S. to deal with hydrogen. 

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

He ended with some advice for plant managers and a prediction for the year. 

“As the supply chain has slowed down considerably, plant managers need to move away from just-in-time models to having parts at each site and suppliers in the home country even if it costs more,” said Axford. “2021 won’t see a recovery: I predict a 10% drop in MW orders.”

Despite a sluggish market, opportunities remain.

July/August 2021

Keep it simple

Noise levels at energy plants

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

Vendor spotlight: Waukesha Bearings

Hydrogen combustion

Deep compression

Cybercrime surge: how controls vendors are responding

Infrastructure bill

Gas turbine sales remain flat

Turbo Tips: Factors impacting compressor surge

Myth Busters: Dispelling air filtration myths in the age of Covid-19

Turbomachinery Expo 2021

Western Turbine users meeting covers everything related to GE aeroderivative operations and maintenance