Commissioning is a set of tests, checks, and activities to convert a newly installed package to a full-capacity commercial operation. Commissioning is performed in four phases:

1. Pre-commissioning
2. Core commissioning
3. Start-up
4. Post commissioning


Pre-commissioning is a thorough site inspection that includes verifying design conformity, the status of electrical, mechanical, and instrument installations, running-in of equipment, flushing, cleaning, drying, etc.

Pre-commissioning activities usually start when mechanical completion is achieved. Frequently, however, these two activities overlap. For example, a package can be under pre-commissioning while neighboring units are still under construction. For this reason, a facility can be separated into easily manageable pre-commissioning entities.


Create a pre-commissioning checklist to track the comprehensive site inspection and pending items. Bolts and similar tightening parts should be tightened as required. (This is a common pending item.) Wiring in general and electrical/instrument wiring connections require a lot of attention. All switches, instruments, indicators, and other instruments and devices should be properly installed and prepared to be qualified for further stages, such as a loop test. Grounding is often missed, but this is an important step. Be sure the grounding status of all machinery and equipment is checked—the ground resistance should also be measured and verified. All tubing and networks of piping, conduits, etc., should be checked and verified, e.g., centralized lubricating systems. There should be no leakage, deformation, or damage, and the entire network should be complete and working properly. There should be no blockage as well.

Planning is the key to success in commissioning. Proper planning and sequencing of different construction, completion, pre-commissioning, and commissioning tasks for different units and packages are extremely important to transition from the erection and installation phase to operation. As part of the planning stage, an estimated number of laborers, technicians, and supervisors should be provided for each stage of the commissioning. As a part of pre-commissioning, most flushing, cleaning, etc., is implemented in the shop before delivering the turbomachinery to the job site.


Safety precautions are important in commissioning. Proper risk assessments should be done before any pre-commissioning and commissioning steps. There are many different risks and hazards in many commissioning tasks and activities, such as the risk of fire. Therefore, fire systems should be commissioned before any risky tasks are started, and/or temporary firefighting equipment should be provided.

Issues in previous stages, such as design, construction, etc., often surface during commissioning. A set of deviations may be necessary to facilitate the commissioning. However, there should be no deviations on matters related to safety, reliability, or operational flexibility.

Each phase of commissioning requires a dedicated form—inspections should be supported by the appropriate record/form, and proper forms/reports should be completed and signed upon completion of each stage of commissioning. All measured data from the commissioning stage should be recorded as well as the various technical parameters and measurements.

Troubleshooting is a major task in the commissioning. Complete troubleshooting guides should be prepared in advance for every machine, piece of equipment, or device in the plant to help identify and correct any malfunctions that may occur.


All required items, lubrications, chemicals, tools, spare parts, and bits and pieces for commissioning should be ready in advance. Further, the quantity and grade of lubrication oil should fit the turbomachinery. The incorrect types and grades of oil were frequently used in different machines in previous commissioning exercises, which caused difficulties during this phase, so ensuring the correct oil is being used is critical. Additionally, all required operational data should be supplied in advance, such as alarm descriptions, alarm set points, initial settings for commissioning, etc.

Handover is another critical task that requires details for each handover, as there are different types. For example, the handover from the construction team to the commissioning team—this is the official start of pre-commissioning. Another example is the handover from commissioning to operation.

And finally, a thorough visual inspection should be conducted to ensure there are no defects, obvious deformations, cracks, weld-joint problems, loose bolt connections, etc. The various modes of operation—starting and stopping, full range of part-load, emergency trips, etc.—should be conducted on each turbomachine. All limit devices, sensors, instruments, etc., should be checked for sensitivity and reliability. Also, safety and limiting systems such as brakes should be checked. An electric motor solo test should be done for all onsite motors to verify the motor’s operational characteristics such as vibration, temperature, noise, etc. 

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

Articles

The four phases of commissioning are important developmental stages for any turbomachinery package. 


Turbo Tips: Commissioning Turbomachinery

Over the years, we have seen requests to drive centrifugal compressors with a combination of gas turbines and electric motors in various configurations. These are often referred to as hybrid drives or dual drives, or in many cases, the electric motor is seen as a helper drive. Some of the confusion comes from the fact that these combinations vary and therefore so does the architecture of such drives. The combination of electric motor and gas turbine drivers to power a centrifugal compressor offers opportunities to take advantage of the individual strengths of each drive in a single package.

In these combinations, the gas turbines can be single shaft, offering very little operating-speed flexibility, or two shaft. On the electric side, we see variable speed motors (as variable frequency drives, although variable speed gearboxes are feasible), as well as electric machines that can be operated as motors or generators. The drivers can also be rated for similar or different power. For certain applications, constant-speed electric motors could be used. The architecture of these drives usually, but not always, requires a clutch between the respective drivers and the compressor.

The reasons for employing a dual-drive configuration are just as numerous as the different configurations. Single-shaft gas turbines, when driving compressor trains in LNG applications, for example, require sizeable starter motors because the starter not only has to accelerate the gas turbine but also the entire compressor train. The starter motor needs to have variable speed capability while also using 25% of the driver power. (That does not sound like a lot, but it would be a 25 MW motor for a 100 MW gas turbine) These motors can also be used to augment the gas turbine power on hot days, and a clutch allows the motor to disengage when it’s not needed. In similar applications, with two-shaft gas turbines, an electric motor can augment the power of the gas turbine, or it can be used as a generator to use surplus power for the generation of electricity. This looks attractive, but often the added complexity cannot be justified economically.

Other uses of hybrid trains seek to take advantage of low-cost electricity during certain times, operating the electric motor (with a disengaged gas turbine) when operating costs would be lower than gas-fired operation. Similar arguments can be made if emissions avoidance, together with high supply security in case of electric grid problems, are sought. In cases like this, the electric motor would be sized for similar power as the gas turbine, and the operation would see either the gas turbine or the electric motor but not both in operation. Therefore, one or two clutches are needed. Generally, to avoid tremendous windage losses, the power turbine of a gas turbine should not spin if the gas turbine does not make power. This means a minimum of one clutch is required.

In this circumstance, like in many other applications where the opportunity is to only use one of the drivers at a time, a centrifugal compressor that can be driven from both shaft ends is advantageous.

Economically, the case for dual drives is often difficult to make because essentially the project carries the cost of an extra driver, and the clutches and train become very complex, including control systems, lube oil control, and the torsional train behavior. Creating electricity to feed into a grid is not often financially rewarding. If the train is part of a facility that can consume the extra electricity, the economics change. The goal of supply security for predominantly electric applications can also be met by electric-only drives with a gas turbine-driven generator. This can include mobile, deployable gas-turbine-driven power generation systems.

“For certain applications, constant-speed electric motors could be used. The architecture of these drives usually, but not always, requires a clutch between the respective drivers and the compressor.”

There are other possible turbomachinery train combinations, including steam turbine drivers, but these are usually only employed in applications where excess steam is available, such as refineries or olefin plants. Similarly, combinations of steam turbines with motor drivers have been successfully employed in petrochemical applications where plant steam is abundant.

So, there are potential benefits to dual drives, but the decision needs to be carefully measured about the goals the operator wants to achieve, and how much added complexity is acceptable.

Klaus Brun is the Director of R&D at Elliott Group. He is also the past Chair of the Board of Directors of the ASME International Gas Turbine Institute and the IGTI Oil & Gas applications committee.

Rainer Kurz is the Manager of Gas Compressor Engineering at Solar Turbines Incorporated in San Diego, CA.He is an ASME Fellow since 2003 and the past chair of the IGTI Oil and Gas Applications Committee.

Any views or opinions presented in this article are solely those of the authors and do not necessarily represent those of Solar Turbines Incorporated, Elliott Group, or any of their affiliates.

Dual drivers—a combination of an electric motor and a gas turbine to power a centrifugal compressor—play on the individual strengths of each driver in a single package.

Myth Busters: Dual Drives Always Work Better!

The gas turbine business hasn’t exactly been thriving in recent years. About a decade ago, annual worldwide sales in MWs amounted to around 60 GW of new machines. However, the last five years have witnessed a market slump down to the 30-40 MW range. Things changed in 2022. Gas turbine sales rebounded to 50 MW worldwide. This is the industry’s best total in almost a decade.


More than 70% of the total worldwide MW sales business came from orders of large-frame gas turbines. These include a number of models from GE (7F.05, 7H, 9F, and 9H), Mitsubishi Power (F, G, and J series), Siemens Energy (F and H series), and Ansaldo Energia (94.3A and GT36). These large-frame units each provide at least 225 MW of capacity—some provide more than 500 MW. Hence, a relatively small number of sales of large units has a major influence on the annual total. 

GE traditionally dominates the large-frame gas turbine sector. However, big orders from China to Mitsubishi Power and Siemens Energy propelled both well ahead of GE in 2022. Mitsubishi Power accounted for about 33% of MW orders, Siemens Energy had 26%, GE had 18% (GE and Baker Hughes combined had a 25% share), and Ansaldo Energia comprised 10% of worldwide MW sales.

“Orders for large-frame turbines tend to be cyclic, so it is unlikely that 2023 will witness another jump in orders for these machines,” said Tony Brough, president of Dora Partners.

What tends to happen is that the major OEMs’ pendulum swings between getting contracts signed for new turbines and the manufacturing, delivery, and commissioning of those orders in power plants. One year, they may secure orders for dozens of turbines. When the order backlog lengthens, they shift focus to cranking out the turbines and getting them up and running in the field. Gone are the days when OEMs cranked out machines in the expectation that a healthy market would always be there. Due to the uncertain and ever-changing nature of the power market, they don’t want to be stranded with dozens of machines that nobody wants.

Meanwhile, restructuring continues among large turbine manufacturers. Siemens spun off Siemens Energy in 2020, which focuses on traditional power generation, renewable energy, and oil and gas. GE, too, divested itself of its GE Oil & Gas assets (now known as Baker Hughes), although the two companies share gas turbine technologies and supply chains. Mitsubishi Power has also undergone reorganization to be more tightly focused on the large gas turbine combined-cycle market.

This year, the trend continues. GE has split off its power generation assets into a new semi-independent entity called GE Vernova. 

Aeroderivative gas turbines are the bright spot forunit orders. Although they were down 6% in 2022, Brough sees aeros as the healthiest segment of the gas turbine sector. Outside of Russia, where Zorya-Mashproekt and United Engine Corp. have been the only game in town for many years, GE/Baker Hughes aeroderivatives gained a 93% market share for the year.

"LM6000 and LM2500+ orders were the big contributors to the GE/Baker Hughes share,” Brough said.

Since 2017, GE’s share of this market has never fallen below 60%, and its dominance is clearly growing. The Siemens Energy acquisition of Rolls-Royce hasn’t resulted in stiffer competition to GE aeroderivative sales. In fact, the combined Siemens Energy/Rolls-Royce aeroderivative slice of the aero pie has fallen from over 40% in 2017 to zero in 2022. However, it should be noted that Siemens Energy managed over 20% market share in 2021, so a rebound
is possible.

Mitsubishi Aero recorded 7% of aeroderivative orders in 2022—its best number since 2018. The company’s acquisition of PW Power Systems a couple of years ago has yet to take a serious bite out of GE aeroderivative unit sales.


Not surprisingly, GE boasts by far the biggest aeroderivative fleet. Leading the way are the LM2500 and LM2500+, with more than 2,500 units sold worldwide between them. They are followed by the LM6000 aeroderivative turbine at 1,185 units. The bulk of these machines continues to operate despite many being decades old. The first LM2500 appeared in 1969, and the first LM6000 in 1988.

Under the Siemens Energy/Rolls-Royce banner, we have the SGT-A65
(formerly the Trent 60) with 739 units sold worldwide. However, Siemens Energy has determined that this machine has reached its end of life. The Mitsubishi Aero FT8 has accumulated 547 units over the course of its lifespan. No other machine has a fleet of more than 350 units.

Looking over the long term, by far the healthiest segment of the aeroderivative space is North America. In fact, it is the only region where aeroderivative sales are up when you compare 2009–2015 to 2016–2022. Aero unit orders in North America were up more than 26% in 2022, and MW orders were 9% higher. More than three-quarters of these orders were for the LM2500+. This machine also dominated worldwide orders in 2022, followed by the LM6000.

“The expanding LNG industry continues to deploy many aeroderivative turbines,” Brough said. “But watch out for Solar Turbines’ upcoming introduction of the Titan 350 at 34–38 MWs, which is squarely aimed at the LM2500+ market.”


According to the U.S Energy Information Administration (EIA), natural gas accounts for almost 40% of current electricity production, followed by nuclear (19%), coal (18%), wind (11%), hydrogen (6%), and solar power at about 5%.

Mark Axford, a consultant at Axford Turbine Consultants, expects natural gas to hold most of its ground in the coming years. The momentum of wind, solar, and BESS has slowed due to supply chain challenges impacting cost and availability. Years of confident predictions about the affordability trend of batteries, for example, have proven faulty. The price per kWh of batteries was supposed to be below $100 by now. Instead, prices have gone up over the last couple of years. Axford notes a global shortage of lithium could further affect BESS economics.

How about hydrogen-fueled gas turbines? Axford is doubtful that hydrogen will eventually replace natural gas as the fuel used in gas turbine plants. He sees two basic problems with the green-energy vision of using surplus wind and solar to produce hydrogen via electrolysis: The inefficiency of the process, and the lack of infrastructure to store and transport hydrogen.

“I don’t expect that the percentage of hydrogen blended with natural gas will ever exceed 15%, and it will probably be much lower,” Axford said.


More than a year ago, Axford forecast that gas turbine orders would be slightly down in 2022. But the market is always subject to random factors. Who would have predicted, for example, that oil would surge again above $100 a barrel (as it did in the summer of 2022), that inflation would continue above 6% per year, or that the war in Ukraine would pass the year mark? Such events cause major market disruption and tend to throw off forecasts.

Despite the lack of a crystal ball to forewarn of major disruptive events on the immediate horizon, Axford expects overall worldwide gas turbine orders to drop in 2023, perhaps by as much as 20% in MW capacity. However, he predicts that unit orders will remain largely flat. 

Drew Robb, former Editor in Chief of Turbomachinery International, continues to write about technology and engineering.

Worldwide orders of turbines were up 47%, but 2023 sales are expected to be lower. 

Gas Turbine Sales Surged in 2022

At a Saudi Aramco facility, two magnetic drive pumps (Unit A and Unit B) were installed in a sulfur-treating unit to transfer liquid sulfur to a pestillator. Both ran 100% in continuous operation. These pumps were crucial, and failure would lead to a shutdown of the sulfur-treating unit. Due to continuous failure of the pumps, the plant elected to purchase an identical unit, as a spare, to improve system availability. At one point, two pumps were out of service, and the spare pump was installed onsite. However, the spare produced abnormal sounds. Fears of operational instability prompted an investigation.

A mechanically sealed pump can be used with a high amount of hydrogen sulfide (H

S) and total suspended solids (TSS). If TSS is high, a magnetic drive pump isn’t recommended. Hydrodynamically sealed pumps should be used when the process requires constant runtime, without frequent stoppage and positive suction pressure. Such design uses an auxiliary impeller to act as a dynamic seal.

The molten sulfur pumps are magnetic drive centrifugal pumps with the following design parameters (Table A-1):

Table A-2 below summarizes the liquid characteristics.

Magnetic drive pumps contain heating areas in which the pumped liquid (sulfur) must be kept at a constant temperature to avoid solidification of sulfur and keep it in its liquid state.


Several issues were discussed. Principally, the pump would not deliver sulfur at the required discharge pressure. The suction pressure was 14 psig and the discharge pressure was only 18.5 psig instead of the rated 106 psig. Further issues included:

Magnetic coupling failing due to high temperatures inside the magnets.

The system steam temperature was greater than 135°C, exceeding maximum tolerances.

Evidence of magnetic coupling slippage and abnormal sounds eminated from the pump bearing housing.

High casing vibration made the pump trips.

Instrument gauges experienced frequent plugging.

The pump vendor cited several possibilities, and the plant was instructed to check:

The correct fill level in the suction tank to prevent air pockets in the suction area, determined by draining the sulfur from the pump casing.

Inner magnet might be demagnetized, leading to a tumbling effect of the impeller. A demagnetization of the inner/outer rotor can occur if the pump is operated for a long time with a ruptured magnetic coupling.
Temporary suction line strainer, as it might be clogged.

Steam temperature inside the pump (steam line), as it might be too low due to high condensate content.

Integrity of the discharge valve. If the pressure does not change when opening and closing the discharge valve, the valve might be clogged, or the non-return valve is not working properly.

An extremely loud pump is an indication that the magnetic coupling is completely ruptured. After dismantling the pumps, several parts were shown to be damaged or broken. For Unit A, this included the bearing bushing (

), casing gasket, small pieces of the magnetic coupling ring, and the shaft sleeve bearing (

). High run-out was observed on both the top and pump shafts.

The plant contacted central engineering to investigate further. The company’s internal standards mandate the magnet torque rating to exceed the maximum torque of the pump (with maximum diameter impeller) by at least 50%. Torque value was calculated at 81.85 Newtonmeter (N.m). In this case, the maximum pump power is 17 kW, which means the synchronous magnet torque rating cannot be less than 139 N.m. However, the company was advised to use 99 N.m for testing the used magnets.


To test the integrity of the magnetic coupling, a special tool was fabricated for the drive shaft. Essentially, an M16 welding screw with an M24 nut (

On the lathe machine, the inner magnet was fixed to the lathe head while supporting the outer magnet on two lathe machine bearing holders. The special tool was mounted on the drive shaft until it reached the end of the thread. A torque-wrench placed on top of the special tool welded nut allowed adjustment to 99 N.m. They were to turn the wrench until the magnetic coupling moved or the wrench clicked.

For Unit A, the magnetic coupling slipped when the torque reached 35 N.m., indicating the magnet lost 60% of its strength. For Unit B, the torque test reached 99 N.m without any slippage, a positive result.


Several tests were performed to check the integrity of the casing and its drain, which should only be exposed to sulfur. But for this test, water was used in lieu of sulfur. Similarly, the casing and back cover jacketing should only be exposed to steam, but for this test, air was used in lieu of steam. The tests checked for pinholes between the steam and sulfur side. 

The pump was pressurized between 20-80 psig with water. Air was injected in the inlet steam line. Water did not exit the steam drain line. Air did not mix with water; water was drained from the discharge line, and air was injected to test if steam would mix with sulfur. Air only came out of the drain point, and water through the discharge line. Water was injected into the steam line inlet. It only came out of the drain line. Another water and air test was conducted for the other half of the pump. Water was injected into the pump suction, exiting through the discharge point.

This confirmed that the existing steam jacketing had no pinholes, so sulfur could not enter the outer magnet jacket. For this pump, steam enters the front casing at the top and leaves from the bottom to go to the top of the outer magnet jacket. It then exits from the bottom of the outer magnet steam jacket connection.


Central engineering recommended that a new magnet set be ordered for Unit A. The plant will conduct the test again after receiving all the materials, including bearings. The temporary suction strainer should be removed, and a check should be made on the suction gauge.

Before any pumps can be started, the shaft must be turned by hand. The
high-amp trip set point should be around 13.2 AMP. The end user should add calibrated pressure transmitters, if possible, and conduct the pump performance test. After removing the temporary suction strainer, the plant found the low discharge pressure issue disappeared. This strainer should only be used while commissioning the pumps and might be used a few months after full start-up. It should never be used after ensuring the lines are clean. The suction strainer is the main reason behind the starvation of these pumps, leading to failures.


In this case, several fruitful observations and suggestions can be made. All instruments were out of service or not reading correctly, highlighting the importance of maintaining a supply of spares. Replacing one of the pumps with a hydrodynamically sealed pump would enable constant uptime. One magnetic pump should be kept for emergencies. However, that solution is costly because the hydrodynamic pump skid has completely different dimensions. 


Wesam Khalaf Allah is a Rotating Equipment Engineer with 10 years of experience at Saudi Aramco, specializing in pumps and mechanical seals.
Amer Al-Dhafir is a Rotating Equipment Engineering consultant with over 20 years of experience in pumps and mechanical seals.

Pumping molten sulfur can be challenging for end users. With several design options, knowledge of proper system maintenance is crucial. 


Case Study: Maintenance Tips for Magnetic Drive Pumps 

Steeped in a rich history of steelmaking, Bethlehem, PA, is home to Rotating Machinery Services’ (RMS) 30,000 square-foot facility with 25-ton crane capacity. Turbomachinery International visited its repair and maintenance (R&M) shop in May 2023, which handles machinery turnaround, overhauls, rerates, remaining life estimations, and failure and performance assessments. Opening in 1998, the Pennsylvania location features a machinery assembly bay, dynamic balancing, blasting booth, machining shop, tungsten inert gas (TIG) welding up to 250 amps, and OEM technical support. 

“A significant amount of business comes from the AC compressor line since we are the OEM,” said Joe Gross, VP and General Manager. “However, most of the machines we service were originally built by other manufacturers.”

Entering the shop floor, a neatly arranged collection of multi-OEM equipment is on display, including some from Ingersoll Rand and Elliott. “All turbomachinery operating in such harsh environments will end up with this kind of wear and tear after about 5-6 years,” said James Wieder, General Manager of Manufacturing. At any given time, there are dozens of compressors and expanders on the shop floor.

A key element of RMS is its labor division, which largely aligns its equipment with its engineers and personnel. The Bethlehem shop is home to roughly 20% of RMS’ 350 overall employees who provide guidance on proper machinery operation and maintenance, review operational data from various sites, and suggests future repairs and upgrades. The Bethlehem facility primarily houses its expander and axial compressor product lines. Other products from RMS’s portfolio, such as steam turbines, power turbines, and centrifugal compressors, are also present.

Virtual learning is another component to its labor force—it incorporates solid models of equipment captured through digital scanning. This method can accelerate learning by pairing realistic 3D models with the knowledge of product experts. “We are creating a more visual way of working so that customers can interact with a realistic 3D simulation of the intricate details associated with overhauling a complex turbomachine,” said Dirk Paraschos, VP.

Its second facility in South Houston, TX, MEPCO, handles the majority of its centrifugal compressors, oil-free screw compressors, and AC equipment, usually overhung-type compressors. Depending on the type of equipment that needs to be serviced, one facility may be preferred over another due to its workshop capabilities. RMS also has a 100,000 square-foot machining center on the northside of Houston along with a 45,000 square-foot specialized rotating equipment shop in Pearland, TX. This combination of locations allows RMS to efficiently manage customer needs with specialized locations.

The RMS Bethlehem facility’s ready-for-finishing section handles the meticulous process of inspecting, bringing-back-to-life, and analysis of compressors. “One of the techniques we use on a lot of rotors and stators is applying a hard coating on many of the surfaces,” Wieder said. “This allows for an extension of the equipment’s life, providing an erosion-resistant surface to preserve the blade underneath. The end customer can potentially reuse the blades in the future.” He explained that RMS brings the blades in for inspection, strips them of the existing coating, ensures they are still in good condition, and recodes and reinstalls them.

“Our refurbishment process is capable of extending the usage life of these components by one or two maintenance cycles,” he said.

These blades, as well as stators, feature holes on the sides, which, according to Weider, mitigate the risk of blade failure. “By drilling into the tips of the stators and blades, it reduces the blade’s weight and frequency. We then conduct live testing pre-production and final production to confirm they are not in failure mode.” The way RMS approaches frequency analysis and blade balancing methods is rare in the R&M industry.

By providing this level of extended support, the quality of customer outcomes can be improved. 

Rotating Machinery Services’ shop in Pennsylvania is home to 30,000 square feet of turbomachinery repair and maintenance space.

Turbo Tour: RMS: A Multi-OEM Repair & Maintenance Shop

The gas turbine maintenance, repair, and overhaul (MRO) market continues to show signs of growth due to an aging fleet of gas turbines and government interventions to reduce carbon emissions, among other factors. According to the market research firm Lucintel, the gas turbine MRO market is expected to reach an estimated $17.8 billion by 2024 and was forecasted to grow at a compound annual growth rate (CAGR) of 3.4% from 2019 to 2024.

“The existing fleet of gas turbines from the construction wave of the late 90s to early 2000s will soon require extensive maintenance,” said Mike Petticord, Plant Manager at IHI Power Services Corp.

In fact, Research and Markets’ 2018 trends and forecasting report anticipated that the equipment in this aging fleet would require significant MRO services. The firm forecasted that in the next 10 years (2018 – 2028) an investment of $256.77 billion would be made for the commissioning of 17,680 gas turbines (excluding microturbines).

“OEMs and aftermarket suppliers are moving toward selling capital spares and seed components to allow for part exchanges and rotable spares as a way to ensure parts are drop-in ready versus the traditional process of inspecting, removing, repairing, and re-installing during a single outage occurrence,” Petticord said.

This driving factor, among others, is not only furthering the MRO market, but it’s driving technological innovations, trends, and a total shift in how the industry approaches repairs and maintenance. 

The industry has seen several shifts in the repair of gas turbines and compressors, including a shift away from value-added solutions toward an economic-based approach to component repairs, according to Chris Wilkinson, Senior Vice President, Growth for EthosEnergy. The industry has been impacted by labor shortages and supply chain availability issues, which is translating into more repairs versus replacements and postponing repairs. 

“In the past, customers would perform parts repairs immediately after an outage, but now they are pushing repairs, sometimes waiting two to three years [after an outage],” Wilkinson said. “This trend is driven by not only the aging nature of the fleet but also by political and environmental uncertainties.”

He said that because customers are looking to extend parts intervals and rotor life, they are more open to upgrading control systems, implementing combustion auto-tuning, and remote plant monitoring. The company performs approximately 30% of its repairs onsite, 60% in-shop, and 10% remote.

“The remote option is growing and will continue to do so in the coming years as technology advances and decisions at the plant ownership search for greater efficiencies,” Wilkinson said.

Gregor Stöcker, VP of Sales Industrial Gas Turbines at MTU Maintenance Berlin-Brandenburg, said there is an emphasis on repairing versus replacing parts for gas turbine engines. “In fact, due to the supply chain pressures, overhauled parts have become quite valuable within the MRO process,” he said.

As a result, MTU is focusing on bolstering its inventory of exchange parts by acquiring engines for teardown and sourcing individual parts. “The new material supply chain issues have caused such parts and engines to increase in popularity, which in turn, drives purchase prices upwards,” Stöcker said. “[But] we are able to handle engines in-house, salvage and repair parts, and know what a fair market value is for mature engines and used serviceable material.”

In fact, the company works as much as possible onsite to save transportation costs for its customers. MTU has a field service team and global network of level II IGT service centers next to its Ludwigsfelde, Germany facility. “However, working onsite has some technical limitations and depends on the work scope required,” Stöcker pointed out. Yet MTU also has remote capabilities to monitor a gas turbine engine. For example, to flag potential issues and make recommendations about shop visits.

Although in-shop work is ideal, Kraig Simpson, VP of Technology at Rotating Machinery Services (RMS), said the company’s current technology enables some turbomachinery field overhauls to be executed 50% of the time versus historical maintenance times. “Gone are the days of lifting a compressor rotor in and out of a casing to adjust clearances via tape checks,” he explained. “We are no longer required to use a mandrel to align diaphragms in a steam turbine. It’s not necessary to rotate rotors to perform shaft end alignment. We can even digitally dowel components to replicate their relative position and alignment. Virtual assembly changes the game, even in the field.”

Given the trend toward repairs versus replacements, parts need to last longer and have an increased tolerance. To adapt to evolving changes, “Both OEMs and aftermarket service providers remain highly focused on increasing part longevity, enabling longer service intervals, optimizing reliability, and enhancing operating flexibility, i.e., better turndown, fuel flexibility, etc.,” Petticord said.

However, many components and materials are evolving and need further refinement, such as “better material sourcing for thermal barrier coatings to elevate service intervals, stellite coating enhancements, and metallurgical advancements for single crystal parts to allow higher firing temperatures while escalating fatigue life,” according to Petticord.

Doug Nagy, Manager, Components Repair at Liburdi Turbine Services, said he’s noticed increasing complexity of component design, manufacturing, alloys, and coatings used. “As a result, many new components, especially thin-walled castings, are less tolerant of service damage, i.e., corrosion, impact damage, etc., and so reparability suffers,” he said. “Further, access to data and know-how on proprietary methods and materials hinders independent reparability options.” That said, Nagy did point out that independent shops are “upping their game in business practices and technology” and are developing and/or acquiring more in-house capabilities.

Among these repair trends, one universal issue in most industries is labor shortages. Because the workforce has changed significantly in recent years, factors such as shortages, retirements, and an overall lack of expertise/skilled workers have become more prevalent.

Petticord said that many technical and craft industry experts have retired. “The pandemic acted as an obvious catalyst for these problems and has left a lasting impact on staffing skilled field crews and technical experts, both of which are currently in high demand for field and shop services.” This deficiency can push OEMs and service providers to hire less-experienced workers, leverage subcontractors, or hire local craft workers with limited gas turbine experience.


“To ensure quality, owners and O&M providers must have adequate technical oversight in place during maintenance outages to ensure its standards are being met at the highest level,” Petticord said. Because of the scarcity of field resources, he said there’s been a major shift toward in-house shop work. “That, along with proper planning allows a more leveled playing field for shop resources throughout the year as teams manage peaks of heavy outage season demand.”

Many of these trends have pushed the industry to reinvent its approach to maintenance—be it because of labor shortages, the need for more durable, sustainable components to increase run times, increased outages, prolonged maintenance scheduling, or others. Data-based approaches like predictive and preventive maintenance as well as remote monitoring, augmented reality (AR), and 3D mapping are being beneficially adopted with more frequency in repair and maintenance practices.

“We must look beyond the next outage for gas turbine units,” Wilkinson said.

“The critical question is, ‘How long does this unit need to run?’ This dictates the approach to maintenance and the investment in the unit, whereas historically it was a very standardized approach to outages and repairs. Today, there is a much different approach based on whether the unit will run for 5-7 years as opposed to one that is planned to run for 15-20 years. We have to be flexible to meet these needs in the market and understand that no situation will be alike. It’s truly a customized approach.” EthosEnergy’s rotor life extension program offers hybrid Phoenix Rotors with new and Certified Previously Operated parts to support this need for flexibility.

Predictive maintenance approaches continue to rise to reduce machine downtime and increase early detection. “Online technologies such as blade-health monitoring systems for rotating components and acoustic monitoring of stator parts have been integrated into remote monitoring to establish early problem-detection capabilities,” Petticord said.

“There is a renewed focus on predictive analytics, including sensor health monitoring and process data validation, which can be used alongside the software improvements to maximize reliability, optimize performance, and extend componentry lifetimes.”

Howden minimizes machine downtime using data with a focus on scheduled and predictive maintenance. Ellie Smith, product manager of augmented reality at Howden, said the company uses real-time augmented reality (AR)-enabled video calls to triage and diagnose problems, carry out inspections, monitor testing, supervise newly qualified engineers, and even enable its customers to carry out some basic repair and maintenance tasks themselves or with help from Howden.

“Customers want a quick reaction, lower costs, first-time fixes, etc,” Smith explained. “Howden Virtual Expert, our AR-based remote support platform, is a mobile-based app that shares a view of the user’s environment with Howden experts from all over the business. Everyone on the call can interact by making 3D annotations.”

The increased need for rapid repairs has been largely driven by longer equipment run times associated with postponing repairs and scheduled maintenance. It’s also resulted in an increase in unplanned outages, requiring around-the-clock repairs to restore operation, Simpson said. Subsequently, “The old way of performing dimensional inspections and setting clearances manually are now incompatible with market demand,” he said. “Customers are shifting away from time-based maintenance intervals and opting for condition-based monitoring. The industry desires a more visual way of working to capture critical data during each outage so that the accumulated data can be used for subsequent outages to drive continuous improvements in maintenance-related activities.”

The company’s use of precision measurement technology to virtually assemble equipment relies on a 3D platform that digitally maps the geometry of a spare compressor or turbine rotor, after which it digitally maps the corresponding casing internals to virtually overlay the rotor into its casing. “This enables us to identify and optimize internal clearances before physically installing the rotor,” Simpson explained. “When we install the rotor in the machine, we know it will fit the first time without the need for additional measurements and adjustments.

“We’re no longer taking an iterative approach to maintenance,” Simpson said. “We are not constrained to historical maintenance techniques. This technology enables us to take a step back and completely reimagine how we approach maintenance.”

Newer maintenance approaches, such as predictive and preventative maintenance, in addition to newly created virtual offerings, require innovation—either from technology upgrades or advancements.

Companies such as RMS have created a new technology team focused on using precision measurement and laser mapping tools, and it is also working to support virtual learning by incorporating models of equipment captured through digital scanning.

“We are creating a more visual way of working so that customers can interact with a realistic 3D simulation of the intricate details associated with overhauling a complex turbomachine,” Simpson said.

Howden is creating an AR addon to Uptime, its performance monitoring digital platform that uses data to analyze rotating equipment performance. The addon is a new way to visualize and interact with live data and analytics in the field by scanning a machine barcode. It allows the user to explore the 3D model and custom animations to understand issues, identify replacement parts, submit machine condition reports, and more. The company is also introducing self-service guided instructions for customers to carry out minor tasks themselves.

Nagy said that in the past it was rare to have a full metallurgical lab capability, but now it’s essential to perform routine quality control/assurance and collect post-service evaluations of service damage. “This allows feedback to users on durability of parts and repairs,” he said. “And it allows shops to develop specific repair ‘prescriptions’ for parts rather than relying on non-optimized generalized work scopes.” Liburdi Turbine Services conducts component inspections to identify non-reparable parts early in the shop-flow process.

EthosEnergy continues to perform ICON control system upgrades, ECOMAX combustion auto-tuning, and a range of site audits. It is also developing Advanced Gas Path parts, a remote operations center in the United States, and an expansion of its compressor capabilities in its Houston Service Center.

MTU is expanding its LM6000PF+ engine services from module MRO to the complete spectrum, including full overhaul and test.

Similar to steam turbines, Wilkinson said the trend will continue to shift more toward condition-based maintenance of gas turbines. “Maintenance and repair will be less routine, and owner/operators will continue to push the limits of their units for economic, environmental, and political reasons.,” he said. “This will result in an increase in forced outages and unplanned events.”

With the ongoing labor challenges, Petticord said, “Service providers must stay diligent in using seed parts to allow major component and rotating spare exchanges during outages.” He anticipates a larger emphasis on upgrades in fuel flexibility, such as incorporating hydrogen. “In the long-term, 3D printing of suitable components may eventually alleviate supply chain issues by allowing the creation of just-in-time spares to deploy,” he said.

Overall, utilizing these newer approaches, such as 3D capabilities, data-based approaches, predictive and preventative maintenance, and precision measurement technologies, can support the industry’s desire to reduce turnaround times, increase run times, and reduce downtimes during outages. 

Emerging market dynamics continue to play a role in the turbomachinery repair and maintenance landscape, leading to inventive methodologies.

Repair & Maintenance Trends Necessitate Tech Innovations

While natural gas is the cleanest large-scale combustion fuel in use today, its use as a fuel for power generation results in approximately 15% of all CO

 emissions in the United States—gas turbines are responsible for a large portion of these emissions. Renewable energy sources are continuing to make inroads into the global energy ecosystem, but gas turbines will continue to be prevalent; therefore, addressing their CO

 emissions is an important step toward achieving a carbon-free energy network.

Hydrogen is earmarked as a possible fuel to displace natural gas and provide CO

-free combustion in gas turbines and beyond. The main byproduct of combusting hydrogen is H

 emission-free fuel. A long-term goal is to burn 100% green hydrogen in gas turbines, replacing natural gas; in the shorter term, hydrogen can be blended with natural gas and burned in gas turbines for a fractional reduction of CO


When using hydrogen in conjunction with natural gas or as a full replacement, it is important to understand how the two fuels differ. A 100% hydrogen blend requires 208% of additional volumetric flow, roughly three times compared to methane. A 75% blend of hydrogen is required to reduce CO

emissions by 50%. These percentages make the immediate plug-and-play use of hydrogen in gas turbines difficult.

Additionally, hydrogen faces unique supply and infrastructure challenges. Hydrogen’s physical properties make production, storage, and transportation more difficult as compared to natural gas, and it can present safety concerns—such as larger flammability range, lower vapor density, faster flame speed, etc.—that must be considered in system design.


All gas turbines are not created equal. There can be large differences between industrial gas turbines (IGT) and smaller aeroderivative engines as well as across equipment manufacturers. Every gas turbine design needs to be evaluated on an individual basis to determine its hydrogen-burning ability and to what level of retrofit or design change(s) is required to improve
this ability.

Required design changes are highly dependent on the percent volume of hydrogen planned to be burned. Hydrogen burning can be segmented into low-, medium-, and high-percentage blend groups. A turbine operating on a low-percentage blend of hydrogen (5-10%) may not require any design or material changes, as the fuel-burn characteristics are similar to a 100% natural gas fuel stream. For medium-percentage blends (10-50%), the combustor and overall turbine architecture will be mostly unchanged, but design changes to existing combustor materials, fuel nozzles, and control systems will be needed. For higher blends of hydrogen, more than 50%, major modifications must be made to the turbines and likely a complete retrofit of the combustion system. Many OEMs are currently working on new combustion systems that support high-hydrogen blend levels.


Fuel system piping and valves in the enclosure must be compatible with hydrogen—materials must be hydrogen-compatible and engineering safety factors must be included in the design. Moreover, hydrogen-tight seals must support small hydrogen gas molecules. Piping and valves may have to be enlarged to handle the higher volumetric flow that hydrogen requires, depending on the blending percentage (FIGURE 2).

Safety systems for gas detection and fire protection must be modified to account for hydrogen’s volatility and detection differences. Similarly, explosion-proofing must be able to contain larger explosions, and ventilation systems need to be modified.


A turbine’s ability to burn hydrogen is almost solely dependent on the combustion system. The larger the hydrogen percentage in the fuel, the more challenged an unmodified combustion system becomes. To add to the difficulties, for the foreseeable future, combustion systems will have to maintain fuel flexibility and the ability to burn natural gas. The combustion system is challenged by:

Hydrogen is one-ninth the density of natural gas and is the smallest known molecule, which creates transportation and sealing challenges. 

Hydrogen’s heating value is one-third of natural gas, which means three times as much hydrogen fuel flow is needed to produce the same amount of power as compared to natural gas.

The flammability range of hydrogen is much larger than that of natural gas, creating elevated environmental, health, and safety concerns for both transporting and burning hydrogen (FIGURE 3).

Hydrogen burns hotter and has a faster flame speed than natural gas. This creates combustion instability and increases the potential for flame out and flashback.

Hydrogen flames are much less visible than natural gas flames, making flame detection difficult.

Additionally, hydrogen embrittlement occurs as soon as it is introduced into a system, and it cannot be reversed. Embrittlement lowers the material’s yield stress, which reduces the material’s fatigue capability, particularly for low-cycle fatigue. Temperature, pressure, and stress level can influence the rate or magnitude of embrittlement. However, not all materials are equally prone to hydrogen embrittlement. Both stainless steels and nickel alloys, commonly used in gas turbine combustion systems, experience increased levels of embrittlement at elevated temperatures. This makes combustion material selections for hardware, weld joints, and braze joints difficult.

There are several main combustion system types used throughout IGTs, and the challenges described above will impact these systems differently. The two main combustion system types used in today’s IGTs are diffusion combustion systems and lean premixed combustion systems.

In diffusion flame (or conventional) combustion systems, fuel is directly injected into the reaction zone with no intentional premixing with the combustion air. A diffusion, or non-premixed, flame burns at the flame surface, while fuel on the interior of the flame remains unburned. Diffusion flames generate higher gas temperatures as compared to premixed because the fuel burns close to the stoichiometric ratio.1 The stoichiometric ratio is the ratio between gas and air where complete combustion occurs. High gas temperatures result in lower carbon oxide levels, but higher NO

In the primary zone of a diffusion combustor, fuel is injected and burned. Incomplete fuel combustion occurs due to the mixture of fuel and air. A secondary zone, where additional air is added to the combustor, is required to complete full combustion of the fuel. The gas temperatures aft of the primary and secondary zones are too high for downstream turbine component health, thus a dilution zone is used to inject additional air and drop the gas temperature to an acceptable level.

Diffusion combustors offer greater flame stability over a wider range of flame temperatures and fuel compositions, including hydrogen, as compared to lean premixed systems. Because the flame burns close to the stoichiometric ratio, it is less prone to lean blowout during operation; and due to higher gas velocities, it is less likely to flashback. With more flame stability, combustion dynamics remain within acceptable limits. Currently, some diffusion combustors can burn 100% hydrogen, but elevated NO

 emissions are expected and require more dilution at the fuel-injection zone.

 challenges in diffusion combustors, many of today’s new gas turbine designs are equipped with lean premixed combustion systems: dry low emissions (DLE) and dry low NO

(DLN) combustors. “Dry” indicates that no diluents, such as steam or water, are used for emissions control. While diffusion combustors are currently more capable of burning hydrogen, the gas turbine industry recognizes that lean premixed combustors, with superior emissions control, will continue to be the dominant combustion system for new designs, even with hydrogen.

The main difference between the lean premixed and diffusion combustors is that the fuel and air are mixed prior to injection into the combustion chamber in a lean premixed system. The homogeneous mixture of air and fuel allows for a uniform and lower temperature flame, reducing NO

 emissions without the use of dilution and the associated efficiency penalty. Most modern lean premixed combustors also use fuel staging with lean fuel-air ratios to help further control emissions. Lean premixed systems can look vastly different between OEMs and even turbine designs. DLE technology has been continuously evolving, as there has been a constant push for higher efficiencies and lower emissions. The wide variety of designs translates to a large range of hydrogen-burning capabilities across turbines. But today, in almost all cases, lean premixed combustors can handle lower volume percentages of hydrogen when compared to diffusion combustors.

When considering hydrogen in DLE and DLN systems, similar challenges that exist for diffusion combustors are magnified. First, hydrogen’s higher flame speed as compared to natural gas (greater than three times), and the slower moving flame center in a DLE system increases the flashback risk.

Next, the higher flammability range of hydrogen increases the risk of fuel ignition inside the mixing passages. Combustion dynamics are also altered with hydrogen usage. With hydrogen, elevated dynamic amplitudes over a larger range are expected since flame stability is reduced. During transient operations—such as startup and shutdown—dynamics are the greatest concern. And for the foreseeable future, a safe fuel, such as natural gas, will be required for non-steady operation (startup, shutdown, part-load). In summary, the stable operability window for most lean premixed combustors is narrower as compared to diffusion combustors, which means premixed combustors are only capable of lower percent blends of hydrogen.


Since all the combustion takes place downstream of the compressor, the combustion of hydrogen does not have a direct impact on the compressor. There are a few indirect impacts that pertain to NO

 abatement. There are two possible ways to minimize NO

 emissions, either through unit derate or dilution (standard combustor). If unit derate is chosen, the off-design point selected must be acceptable for compressor performance and health. If additional dilution in standard combustors is chosen, the surge margin may be adversely impacted by the change in mass flow of the turbine section relative to the compressor section.


The biggest concern to hot gas path components is the fact that hydrogen’s higher burning temperature increases turbine firing temperature. Additionally, the gas temperature profile leaving the combustor will be hotter and look different when firing hydrogen versus natural gas. For example, the gas temperature profile exiting a diffusion combustor will likely look peakier (highest temperature in the center of the combustor) when burning hydrogen if no additional changes are made. An increase in firing temperature and changes in the combustion profile shape will drive modifications to the component cooling and coating designs to avoid part-life reduction.


Hydrogen presents an opportunity to drastically reduce CO

 emissions. Many technologies exist or are under development that will help make hydrogen prevalent in the future energy economy. Many of these technologies are very promising, but the major challenges are scale and making hydrogen generation, distribution, and usage economically viable and truly green. Further, gas turbines will continue to be an important part of the world’s energy network as they complement renewable energy sources and have a large existing installed base. OEMs are committing significant resources to design hydrogen-burning technologies into their new engines and to create modification packages for existing engines. 

Jason Neville is the Engineering Manager and Consultant at Turbine Generator Advisers, an ENTRUST Solutions Group company.


1. Greenwood, Stuart A. “Low Emissions Combustion Technology for Stationary Gas Turbine Engines” 2002; Technical Report. San Diego: Solar Turbine Inc., Document.

Running traditional natural gas turbines with hydrogen will play an increasingly important role in reducing CO2 emissions in power generation. 
