This article discusses how process and operation conditions can affect turbocompressors and their operation, performance, and reliability through three real-world case studies that address how downstream, upstream, the process itself, and all surrounding facilities and items impact turbocompressors.

Radial bearings of tilting-pad type in a critical centrifugal compressor showed spikes in bearing pad temperatures every 1 - 4 hours. Measured temperatures went from 96°C (baseline) to 115-119°C (spike). The recommendation by the operations team was to reduce the inlet lubrication oil temperature to limit the peak of the spikes below high temperature limits. The initial proposal was to reduce the temperature of the delive red lubrication oil to the compressor from 50°C to 45°C. It was implemented. However, the lubrication oil temperature reduction caused a higher temperature at the bearing pads. This might be because of more viscosity of lubrication oil and consequently more friction. In this case, a 5°C reduction in the lubrication oil supply temperature caused around 2-3°C increase in bearing (resistance temperature detector (RTD) temperatures. The reduction of supply lubrication oil temperature could not reduce temperature spikes at RTDs.


This is an example of how random actions cannot solve the problem. The root-cause of the problem should be identified and eliminated. After thorough studies, the root cause of temperature spikes was identified as varnish in the lubrication oil. Every time varnish settled on a bearing pad RTD, a spike in the bearing RTD temperature was recorded.


One indication that helped to correctly identify the root cause was a simple test of switching the lubrication oil filter to see if spike patterns changed. The switch of filter reduced varnish deposits on bearings temporarily and this reduced spikes in RTD bearing temperature and changed its patterns.

Investigation showed one of additives in the lubrication oil interacted with compressor process gas and produced varnish. It was decided to change the lubrication oil type for this compressor. The operation of the compressor has been smooth and satisfactory since this adjustment. 

The pressure ratio of a process centrifugal compressor was adjusted due to a change in gas composition and operating conditions. The pressure ratio (discharge pressure to suction pressure) could move theoretically from 2.25 to 2.51 because of these changes (gas composition change, higher required discharge pressure, etc). The compressor was initially rated for a pressure ratio of around 2.39.

Process and operation conditions can affect turbocompressors and their operation, performance, and reliability

The compressor data including compressor map, design conditions, compressor details, and thrust bearing data were carefully reviewed. Rises in differential pressure and load on thrust bearings were accurately determined and verified. Based on these studies, it was confirmed that there was no issue for the thrust bearing regarding this differential pressure rise. A thrust bearing should often be sized to absorb this kind of change. In this case, these changes were within thrust bearing limits. In addition, there were temperature measurements and vibration monitoring for the thrust bearings. These could highlight possible malfunctions. The compressor has been operated safely and reliably with the modified operating conditions.


The potential of liquid carryover to a refrigeration centrifugal compressor was raised by the operation team of a plant. Recorded data showed that prior to start-up of the compressor, the suction line was at 6.5 Barg and 5°C. Under these conditions, the refrigeration gas was theoretically liquid and could damage the compressor, seals, and inlet strainer when it started with liquid flowing through the centrifugal compressor. It was recommended by the operations team to depressurize the refrigeration gas to below 4.5 Barg prior to the start-up. In addition, they asked to investigate possible solutions to detect or automatically drain liquid refrigeration from the inlet piping at pre-start.


Investigations showed that liquid carryover was a false alarm. The temperature transmitter range was up to 5°C. It showed 5°C for any temperature above 5°C. The actual temperature in the suction line before the start-up was always above 20°C. Theoretically, there was a little chance for refrigeration gas conditions reaching the saturation point during a shutdown.


It was decided to change the temperature transmitter with a new one with a measurement range up to 40°C. There might be a remote chance that the gas condition during a shutdown could reach saturation point. In that case, draining of the collected liquid would be necessary. The operation procedure was corrected and a necessary step for the drain of liquid at the suction drain prior to the compressor start-up was included. ■

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

Articles

How operation & process can affect turbocompressors

TURBO TIPS: CASE STUDIES

New gas infrastructure will be required from well-head to gas consumer to meet rising worldwide demands for LNG.

As one of the world’s largest natural gas producers, the U.S. is now the leading global exporter of liquefied natural gas (LNG). U.S. export capacity for LNG is approximately 12 billion cubic feet per day, or about 15% of total natural gas production. Other major exporters of LNG include Qatar, Australia, Malaysia, Algeria, Russia, Nigeria, Indonesia, and Trinidad and Tobago.


Due to recent geopolitical turmoil, European demand for LNG has risen dramatically, requiring current suppliers to increase production and open new production facilities. There is significant political pressure and economic opportunity for the U.S. to make up the shortfall of Russian-supplied natural gas with LNG. Given the commitments made to potential European recipients, U.S. LNG production would have to increase by more than 20% (about 3 billion cubic feet per day) over the next 12 months.


Unfortunately, the solution isn’t as simple as turning on a faucet and waiting for more LNG to come out. No gas production, transport, or LNG facilities exist with any meaningful excess capacity. Significant infrastructure investments are required in the very near future to increase LNG production in North America. That includes new plant facilities, as well as expansions and additions to existing facilities across the entire natural gas value stream, from wellhead to production plant. A simple estimate is that every 1,000 horsepower of new compression inside an LNG plant requires about 10,000 horsepower of new compression for upstream and midstream gas production and transport compression.


On the receiving side, LNG terminals with regasification and compression must be constructed and tied into existing pipeline systems. Increased production requires not only additions to LNG production plants, but also increased natural gas production, gathering, treatment, transportation and regasification. Upping the amount of natural gas produced, most likely through fracking and new onshore/offshore drilling, calls for additional pipeline capacity, mostly through the addition of compression and pipe loops on existing lines. New gas liquefaction plants are another obvious need.

Since this column is about turbomachinery, let’s focus on this aspect of the added demand for LNG. From a purely turbomachinery perspective, increasing LNG production requires new or uprated machinery in:

1. Production gathering
2. Gas plant with separation, treatment,
and boost
3. Pipeline transport
4. Liquefaction plant, including treatment, separation, and refrigeration
5. LNG export
6. LNG receiving terminal, regasification and boost into pipeline network or power plant 

An increase of 20% in U.S.-exported LNG corresponds to an increase of 3% in U.S. natural gas production. That may not sound like much but becomes a staggering figure in the context of existing infrastructure and required new machinery. In the U.S. upstream sector — gas production and gathering — there are approximately 15,000 installed compressors, mostly smaller reciprocating compressors driven by engines or electric motors. In the midstream or gas transport sector, there are about 8,000 installed compressors, made up of a mix of older low-speed integral reciprocating, high-speed separable reciprocating, and gas turbine or electric motor-driven centrifugal compressors.


Ignoring downstream and LNG plants for now, there is an estimated 25 million horsepower in the upstream sector and 40 million horsepower in the midstream. Upping this by 3% requires another 2 million horsepower of new compression in the U.S. alone. Based on current worldwide manufacturing capacities, it would take about 2-3 years to meet this new demand for gas compressors. This doesn’t include lead times for material, transport, installation and commissioning/startup in an already resource-constrained economy. Since current lead times for compressor trains, valves and all major transport and production equipment are around 18-24 months between order and startup, it’s fair to estimate it would take the U.S. at least 3-5 years to ramp up LNG production to meet new European demands.


Regardless of actual lead times and manufacturing details, increasing U.S. LNG export capacity requires more than just production plants. It demands consideration of the entire natural gas supply chain. New gas infrastructure, including significant new compression, will be required from well-head to gas consumer to meet rising worldwide demands for LNG. ■

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.

Myth: We Can Quickly Make More LNG

Mitsubishi Power Americas, headquartered in Lake Mary, Florida, employs more than 2,300 power generation, energy storage, and digital solutions people. Its power generation solutions include gas, steam, and aeroderivative turbines; power trains and power islands; geothermal systems; photovoltaic (PV) solar project development; environmental controls; and services. In addition, its energy storage solutions include green hydrogen, battery energy storage systems (BESS), and services. It also offers intelligent solutions that use artificial intelligence to enable autonomous operation of power plants. Mitsubishi Power is a power solutions brand of Mitsubishi Heavy Industries (MHI).


“The power sector is undergoing deep transformation driven by decarbonization, digitalization, and decentralization,” said Bill Newsom, President and CEO, Mitsubishi Power Americas.

He sees three key technologies to watch in the next phase of the energy transition: hydrogen storage at scale, AI-driven decision making, and distributed power where people need it.

The company now delivers all of its heavy-duty gas turbines hydrogen-ready and offers services to convert existing natural gas turbines to run on hydrogen. Its gas turbines are currently capable of running on a blend of 30% hydrogen and 70% natural gas by volume to reduce carbon emissions. They are being developed to run on 100% hydrogen (or natural gas if needed) in the future.

“As the energy landscape began changing, we realized that we needed to grow beyond being just an OEM to become a total solutions provider and partner,” said Newsom.


Mitsubishi Power has developed Hydaptive green hydrogen packages that integrate gas turbines, renewable power, and storage technologies. They augment renewables with on-demand power from gas turbines and with lithium ion battery storage and green hydrogen production and storage.


Commercial utility-scale hydrogen projects are now being developed. The Advanced Clean Energy Storage hub in Delta, Utah, will be the world’s largest energy storage facility, a joint development of Mitsubishi Power and Magnum Development. The hub will produce green hydrogen, store it in underground salt caverns, and dispatch it as a clean fuel for power generation, transportation, and industrial applications. Two of these salt caverns will be built in the first phase to provide 150,000 MWh of storage capacity each.


Mitsubishi Power will also supply two M501JAC power trains for the Intermountain Power Plant in Delta, Utah, adjacent to the Advanced Clean Energy Storage hub. It will transition from coal, to natural gas and then to green hydrogen. The 840 MW combined cycle plant will use a blend of 30% green hydrogen and 70% natural gas at commercial operation in 2025 and 100% green hydrogen no later than 2045.


Further hydrogen projects include: a partnership with Texas Brine Company to develop large scale, long-duration hydrogen storage solutions to support decarbonization efforts – Texas Brine and its affiliates have salt positions in New York, Virginia, Texas and Louisiana; a strategic partnership with DT Midstream to advance hydrogen infrastructure across the U.S.; a joint development agreement with Entergy to develop hydrogen-capable gas turbine combined cycle facilities, green hydrogen infrastructure, nuclear-supplied electrolysis facilities with energy storage, and utility-scale battery storage; a joint development agreement with Puget Sound Energy on large-scale, carbon-free renewable generation and storage; and a joint development agreement with El Paso Electric to develop a roadmap to a carbon-free energy mix, including a strategy to convert EPE’s Newman Power Station from natural gas to a blend of up to 30% hydrogen, then to 100% hydrogen. In addition, Mitsubishi Power has retained CITI as Strategic Financial Advisor to help expand hydrogen infrastructure across North America.


Advances in technology are transforming how power is generated, distributed, and stored. Digitalization is the core of the “smart power plant” of the future. Mitsubishi Power has developed a suite of digital and service-based solutions called TOMONI to make power plants smarter, more resilient, and more profitable.


“TOMONI is the digital brain powering smart energy systems,” says Newsom. “It serves as the nucleus of the power plant, controlling all operations, driving all decisions, storing all information, and learning how to optimize performance.”


It comprises six capabilities geared toward maximizing asset performance, optimizing operations, and improving flexibility to enable energy systems to integrate the new energy mix.

: Multi-layered defense, remote monitoring and diagnostics, and real time support to strengthen cybersecurity and compliance.
•	

: Systems that automate critical activities and enable energy mix integration to improve asset visibility, agility, and efficiency, while providing a framework for predictable lifecycle support.
•	

: A combination of modeling, analytics, and AI to create a complete virtual replica of the entire energy system to support better O&M decision-making, increase efficiency, and lower emissions.
•	

: Cloud and on-site applications to increase plant operational flexibility and improve cost and performance.

: Software that collects, analyzes, and interprets data from hundreds of power plant sensors, transforming it into actionable insight.
•	

: Systems and components with built-in intelligence, fault-tolerance, and self-calibration.


The energy sector is adding distributed generation and storage for uses that include isolated areas, areas on regional grids prone to outages, and areas with intermittent supply problems caused by the expanded use of renewables on the grid. Mitsubishi Power’s aeroderivative gas turbines, which deliver 31 to 140 MW of on-demand power, can address many of these infrastructure shortcomings, including providing grid resiliency and emergency power.


The FT-8 MOBILEPAC gas turbine is a 31 MW mobile generation package. The MOBILEPAC design enables fast-track installation and commissioning, and demobilization and relocation with minimal crew. The compact, lightweight self-contained packages may be moved by land, sea, or air to meet changing demands. The equipment has multi-fuel capability: natural gas, liquid fuel, propane, and field gas. The field gas capability enables units to be situated where natural gas can be captured and used to power equipment on-site.


The FT4000 unit provides one of the highest power outputs of any aeroderivative gas turbine generator packages available in the market, offering 70 to 140 MW of power with low installed cost, easy operation and maintenance, and low total cost of ownership. The reliability, operational flexibility, and high power density of the FT4000 SWIFTPAC make it the ideal partner to intermittent renewable power. Developing hydrogen-fueled aeroderivative power gen solutions will help decarbonize power production further.


“Hydrogen, AI, and distributed energy are just three of the key areas we are focusing on in the move toward net zero carbon by 2050,” said Newsom.
For more information, visit amer.power.mhi. com and aero.power.mhi.com. ■

Decarbonization, digitalization, and decentralization.

VENDOR SPOTLIGHT: MITSUBISHI POWER

The promise of supercritical carbon dioxide (sCO

) Brayton cycle power systems has grown steadily over the past ten years. To understand the current status of these sytems, let’s start with some of the basics.

) is chemically stable, reliable, plentiful, low-cost, non-toxic, non-flammable, and readily available. This qualifies it as a safe working fluid for a closed cycle. Raising CO

 to be at or above its critical temperature and critical pressure puts the fluid in a supercritical fluid state (

 occurs at a relatively low pressure as compared to other gases, allowing for a high-density, low viscosity, and compressible fluid. When sCO

 is applied to a closed-loop Brayton cycle, this allows for increased efficiency of the resulting power cycle and high power density (substantially smaller footprint both physically and environmentally) as compared to air Brayton and steam Rankine cycles.

 in the supercritical fluid state are not a new concept. The Sulzer brothers patented a partial condensation CO

 Brayton cycle in 1948. But the challenge in implementing those cycles at commercial scale has meant a long development history. Solutions are now on the cusp of market entry.


There are a number of cycle variations associated with the closed-loop Brayton cycle that balance technologies, costs, and efficiency. Cycles pulling flow after the turbine to reheat it before reinjecting it into another turbine stage are called reheat cycles. However, the modest performance gain with reheating between turbine stages does not always provide sufficient gain in cycle performance for the added complexity and cost.


The two most prominent configurations are recuperated and recompression cycles (

). A recuperated cycle allows a portion of the unused heat from the turbine to be captured via a heat exchanger, which can then heat the compressor gas discharge, thus reducing the overall required external heat input. The recompression Brayton cycle uses a high-temperature and a low-temperature recuperator. Flow is split prior to entering the precooler, recompressed, and passed through the high-temperature recuperator after being reunited with the rest of the flow that has been heated by the low temperature recuperator. The recompression system offers high thermal efficiency (upwards of 50% depending on temperatures) but is one of the more complex and costly configurations.

 power cycles are heat-source agnostic. The heat may derive from any of several different sources: concentrated solar power, nuclear fission, waste heat from chemical processes, or recapturing the exhaust heat from a gas turbine (cogeneration).

 closed-loop Brayton cycles offer advantages over existing technologies that convert heat to electrical power. These include:

Increased cycle efficiency (power generated divided by heat put into the cycle)

Compact size: Power density means a reduced footprint compared to steam turbine plants or organic Rankine cycles, an advantage in applications where space is at a premium such as offshore platforms and ship propulsion. It also offers advantages in terms of the turbomachinery cost. The cycle may be optimized to achieve the best balance of power recovery for total installed cost (

The Brayton cycles are more efficient than steam and organic Rankine cycles at heat temperatures above 400°C. The resulting applications cover both fossil and renewable energy.

By combining with gas turbine-produced power, greater power output per unit of fuel consumed is achieved.


Hanwha Power Systems chose to focus on power ranges in the 5 MW to 25 MW range and leverage existing industrial technologies within the company to the extent possible. Development effort centered on technologies that proved system function and maximized reliability, such as sealing and wide range compression technology. The result is an integrally geared compressor-expander arrangement for turbomachinery that uses additive-manufactured compressor impellers and expander wheels to achieve aerodynamic configurations. Applications in this power range are predominantly concentrated solar power (CSP) (


Applying the design and operation of a high-power density system to an industrial market is challenging. It presents multiple technical barriers to market entry. One of the inherent risks associated with such high-density equipment is to over leverage the design on unproven technologies. This leaves little time to make corrections during tests and field trials.


Sandia National Labs established a 150kW sCO

 flow test loop to prove the efficacy of various cycles. Other national labs, research centers, and universities have similar test rigs for core research. At this scale, the turbomachinery operates at extremely high rotational speeds. Due to the small flow passages, it does not represent the component efficiencies achievable at larger scale. However, the cycle function is proven and paves the way for applying the lessons learned to larger machines.


Advances in analytical tools and manufacturing methods have opened the door to successfully applying sCO

 Brayton cycles and lowering dependency on unproven technologies. With solutions now at hand, the field is transitioning from academic and small-scale test rigs into the megawatt scale. The main challenges relate to proper understanding of the fluid properties, management of concurrent high-pressures and temperatures, and sealing against those conditions.


Understanding the thermodynamic properties of fluid properties in the supercritical regime requires substantial testing and validation work. The transient, start-up, and shut down sequences of the cycle must be managed carefully to control potential two-phase flow and fluid instabilities to avoid machinery damage.


Thermal management of conditions at 700°C may seem less challenging as compared to gas turbine temperatures exceeding 1200°C. But 700°C has to be managed concurrently with pressures of 250 bar or greater. Pressure containment favors thick-walled non-compliant systems to withstand mechanical stresses, whereas thermal management of mechanical systems is oriented toward structural compliance of parts to reduce thermal stresses.


One strategy is to make a closed system with no leakage. These canned systems eliminate sealing complications but add challenges with operating process flow bearings. Alternatively, conventional (rolling element or fluid film) bearing systems can be used. But then sealing systems must be applied to restrict gas leakage to atmosphere to manageable quantities. Due to high- pressure fluids, labyrinth and floating ring systems are insufficient. The use of dry gas seals is logical, but the pressures, surface speeds, and temperatures are just about at the limits of the capabilities of dry gas seals.


And there are other technical challenges. High pressures in turbomachinery components lead to high-thrust forces. Those forces can have a high degree of uncertainty due to variability in operational conditions and pressure fluctuations. In the case of heat exchangers, the exchangers must be efficient and able to handle quite high pressures (up to 280 bar) at not insignificant temperatures. Further, the selected materials must provide adequate strength and corrosion resistance at operating temperatures and pressures. Static sealing must be tolerant of CO

Overcoming the concurrent technical barriers of high rotational speeds, fluid pressures, and operating temperatures requires dependence on analytical tools and advanced manufacturing practices. Advances in analytical tools and, importantly, the ability to anchor predictions on low power scaled test results from universities and national labs from around the world, proved essential to achieving recent successes.

The preliminary compressor aerodynamic design was scaled and tested in air at Southwest Research Institute. Having this benchmark data allowed the design to be checked prior to testing in CO

. Compressor aerodynamics near the critical point of the fluid are challenging. The gas density flattens and small temperature and pressure changes create large swings in fluid density. This directly affects local velocity vectors. It also makes it difficult to accurately predict aerodynamic efficiency.


From a structural perspective, understanding the statics and dynamics of the fluid system is critical to avoiding fractures in the material during operation. A hydro test of the high-pressure compressor was carried out at 477 bar (6,918 psi), roughly equivalent to the pressure 2.9 miles below the ocean surface (Figure 7). With the use of finite element analysis techniques, the design succeeded in hydro test and subsequent aero-mechanical performance testing in sCO

 when cycling to holding at full pressure and temperature


A decade ago, dynamic simulations took weeks to converge. Nowadays, they take hours. This makes cycle and system layouts optimizable in short time frames. With the understanding of dynamic predictions of transient behavior, estimates are at hand of dynamic forces that the system must tolerate. Prediction of creep life and high-cycle fatigue can now progress in real time.
To overcome system level technical barriers on closed loop full scale cycles, greater than 1 MW, no options were available at existing test facilities.

Hanwha Power Systems, with the support of U.S. DOE funding and in collaboration with Southwest Research Institute, developed a 10 MW system and performed incremental section testing at the 1 MW scale, using only the highest temperature-pressure expander stage. Demonstrating the most challenging expander stage was taken as proof that the low pressure-lower temperature stages would be viable. This testing program (

) demonstrated mechanical, thermal, and aerodynamic capabilities of the expanders, compressors, gears, bearings, seals, and heat exchangers for operation in supercritical CO

 for pressures and temperatures up to 280 bar and 730°C.

Demonstration testing of major cycle components enables development to move to the next step: full-scale testing in the field. DOE funding applied to part of this program was from the Concentrated Solar Power (CSO) APOLLO program (to reduce the levelized cost of electricity for CSP). The ongoing phase of technical readiness is a pilot field test of a 5 MW sCO2 closed loop power system scheduled for 2024.


Acknowledgement: The material is based upon work supported by the Department of Energy, Office of Energy Efficiency and Renewable Energy (EERE), under Award Number DE-0007114. ■

SCO2 BRAYTON CYCLE POWER SYSTEMS PROBLEMS

SUPERCRITICAL CARBON DIOXIDE 

TELL OUR READERS BRIEFLY ABOUT SCHNEIDER ELECTRIC. 

Schneider’s technology, solutions and people are focused on efficient, resilient, and sustainable operations within the process and discrete automation industries. Our scope ranges from large, energy-intensive segments with our safety, control, and remote operations, all the way to the typical consumer with our at-home smart devices in power management and security. Schneider embraces digitization and circular economy standards to tackle decarbonization and ensure energy is accessible for all. 

WHAT DOES SCHNEIDER ELECTRIC DO THAT RELATES TO TURBOMACHINERY?

Schneider solutions for turbomachinery control (TMC) address and protect the high-risk processes that if not monitored, can mean loss of production or life. We provide prime movers (like gas turbines, steam turbines, hydro, motors), driven equipment (compressors of all types, generators, blowers), auxiliaries and subsystems that are part of the turbomachinery train (lube oil, seal oil, AVR, etc.), mechanical retrofits, safety, and extensive data analysis. Our services address the entire plant lifecycle, including front-end engineering design (FEED), TMC engineering assessments, or commissioning and startup support. Currently, Schneider Electric process automation technology enables: 1 TWH of power plants, 30% of global refineries, and more than 50% of global liquified natural gas (LNG) capacities. 

WHAT IS THE COMPRESSOR PERFORMANCE MONITOR (CPM)? 

Our CPM digital solution evaluates a compressor’s performance parameters and compares the value to a performance base line to determine the compressor deviation from an expected performance. These calculations allow for accurate estimations of financial loss. This can result in impactful metrics like wasted power or excessive carbon emissions where our experts consult customers on how to improve the efficiency and sustainability of their operation. 

WHAT TRENDS HAVE YOU OBSERVED IN TURBOMACHINERY SOFTWARE AND CONTROLS? 

We see our customers challenged with rapid advancements in technology, a generational shift in workforce, and stringent regulations, on top of the standard criticality of preventing equipment failures, reducing maintenance costs, reducing unscheduled shutdowns, and improving safety. This has driven new technologies into the turbomachinery industry, including big data analysis, industrial IoT, and remote services. 

WHAT IS SCHNEIDER ELECTRIC DOING ON INDUSTRIAL SUSTAINABILITY? 

Being recognized as Global 100 most sustainable companies in the world by Corporate Knights, sustainability is core to our company’s purpose and culture. It is integral to our full scope of solutions. We take a holistic approach to sustainability by focusing on the lifecycle of critical turbomachinery assets (in any segment or plant) and their impact to people, economics, and the environment. From robust mechanical retrofit solutions that allow online diagnostics, services and repairs avoiding machinery unscheduled trips that directly impacts the environment, people safety and the machine life span, to data analytics designed to reach asset excellence minimizing carbonization, fuel waste and optimizing power consumption. Also, through our relationship with AVEVA, we leverage digital twin applications to verify performance while avoiding risks to environment or people. 

Schneider maps the digitization journey in four pillars: readiness, maintenance, performance, and optimization. The turbomachinery market has been conservative with digital solutions, but that is changing. We have solutions to help customers get ready to adopt digital technologies for process instrumentation, network architecture, automation needs, and control system evaluations. We cover reactive to prescriptive maintenance, focusing on data collection and predictive analytics. We have solutions targeted on compressor performance and remote troubleshooting to minimize support time and to enhance machine operation and performance. Lastly, we coordinate and integrate our portfolio to optimize operations and achieve asset excellence. For instance, CPM can define the best performance for an operation, while TMC Predictive Analytics can predict if the machine is strained; both can be done in a simulation environment. They provide insights, but greater value comes from our TMC experts that can interpret and inform on the actions to take to achieve operational goals. Collectively, these solutions can address the challenges of resource restraints or in-house expertise of what data they have captured at their facility. 

We see a great opportunity in coordinated power and process systems, with the unified operation center being the driver of industrial automation. This architecture provides increased visibility, collaboration between teams, and clear asset performance management at an enterprise level – giving critical information that identifies outliers in a system. TMC assets are at the heart of operations and business planning. Understanding implications from things like unplanned downtime or these predictive failures through asset excellence based off digital tools can help customers potentially react in other areas of their value chain. This leads to improved operational resiliency, worker safety, and overall business value. As industries consider new greenfield projects, modelling power demands along with process systems becomes a key part of enabling this type of value down the road, protecting your investment and ensuring lifecycle performance is achieved. While turbomachinery is the heartbeat of operating assets, digital transformation unlocks collaboration between teams, and improves uptime and efficiency throughout a facility. For more information visit www.se.com ■

SCHNEIDER ELECTRIC BRINGS DIGITALIZATION AND AUTOMATION TO TURBOMACHINERY 

QA: SCHNEIDER ELECTRIC

It never ceases to amaze me the extent and sophistication of facilities owned by “smaller” players in the turbomachinery world. With so much attention lavished on the likes of GE, Siemens, Baker Hughes, and Mitsubishi Power, you can begin to think that they are the only ones with large plants and sprawling campuses. Yet tour after tour of places like Elliott, Capstone Green Energy, LA Turbine, Mee Industries, and others makes it clear that all are big concerns packed full of state-of-the-art equipment.


A tour of the Power Systems Mfg. (PSM) plant in Jupiter, Florida once again proved this to be true. The place is huge. And the company does far more than most people realize. It is gearing up to provide the combustors and other systems to support decarbonization initiatives.


PSM emerged around two decades back, profiting from a decision by Pratt & Whitney to move its major military aerospace engineering group from South Florida’s east coast up to Connecticut. PSM gobbled up many skilled engineers and put them to work in the commercial power generation space. The first major release was the LEC-III combustor. It guarantees sub-5 parts-per-million (ppm) NOx emission levels when operated on natural gas over the entire premix operating range, from baseload down to 80% relative load (respectively 50%-60% with inlet bleed heat system). CO emissions under these conditions are typically measured in the low single digits. Developed for implementation in B & E-class turbines, including GE Frames 6B, 7B/EA, 9E, and Siemens/Westinghouse 501B6/D5, it can either be a drop-in replacement for existing OEM DLN1 systems, or be part of a conversion from standard diffusion combustion systems. No changes to the control systems are needed for vintages Mark V and higher.

Two decades later, and after multiple ownership changes (Calpine, Alstom, and Ansaldo Energia), PSM is now part of Korea-headquartered Hanwha, a company with an emphasis on renewables, the hydrogen supply chain, and decarbonization.


The front of the building houses administrative offices. At first glance, it doesn’t look that big. But it stretches back endlessly with most space given over to production lines, repair processing cells, testing, and other engineering functions. The company isn’t in the business of re-engineering a “good enough’ replacement part for existing engines. Its goal is to offer technologically advanced aftermarket gas turbine components and performance upgrades, parts reconditioning, and repairs. These are available for the Frame 6B, 7B/E/EA, 7F, 9E, 9F, and 501F transactionally or as part of a flexible long term service agreement. It supports this with local execution centers based in the US, Europe, Asia, and the Middle East.
“Our repair and upgrade capabilities can outperform OEMs on life extension and repair yields,” said Jeff Benoit, Vice President of Clean Energy Solutions at PSM.


As the tour progressed, he showed me rooms full of R&D personnel working on current projects as well as new designs. One section dealt with combustors. As well as the LEC-III, PSM has also developed the FlameSheet combustor. It employs a canannular “combustor within a combustor” concept as well as fuel/air mixing to provide turn-down to 30% of base load turbine operating load range increase while maintaining single digit NOx & CO emissions. Designed to operate up to 32,000 factored hours between maintenance intervals, it is suited to shale gas, Liquefied Natural Gas (LNG), or alternate fuel operation such as ethane, propane, and hydrogen. PSM is commercially offering this combustor platform for up to 40% hydrogen by volume.
FlameSheet is often sold along with PSM’s Combustion AutoTune system that enables automated combustion tuning to maintain emissions and combustion dynamics within specified limits under varying environmental or fuel heating value conditions. Its purpose is to achieve optimal gas turbine operation from a reliability and performance standpoint.

FlameSheet is often sold along with PSM’s Combustion AutoTune system that enables automated combustion tuning to maintain emissions and combustion dynamics within specified limits under varying environmental or fuel heating value conditions. Its purpose is to achieve optimal gas turbine operation from a reliability and performance standpoint.

Another part of the plant dealt with rotor repair, life extension, and management. Using 3D steady state and transient analysis models, agedmaterial properties, a portfolio of rotor and blading design upgrades, and non-destructive testing and analysis toolset, PSM can service a wide range of turbines. Rotor service capabilities include rotor removal, inspection, ship and install, with capabilities to inspect, assemble, repair and balance. An in-house team provides analysis for disk repair or replacement approaches and life evaluation/extension, and supplies all required own-make parts including blades, fasteners and disks, many with improvements developed by PSM.


“If a company wants to change the way its machines operate to fit shifting market conditions, we are happy to be involved as we understand the various dynamics,” said Benoit. “Some want emissions lowered, some want more power, and others want as little maintenance as possible. Regardless of needs, almost every plant has to change the way they operate to a manner that rarely fits with the original design.”


As we walked through the place, turbine and compressor parts were everywhere. Some were being cleaned, some assessed and others, repaired, enhanced, coated, or 3D printed.

An unexpected aspect of the tour was a control room conducting remote monitoring and diagnostics of many gas turbines and other rotating equipment from around the world. PSM has Long Term Service Agreements (LTSAs) in place for dozens of plants. It offers operators part life guarantees, coverage during unscheduled inspections, control of inventory, service management, reconditioning, repair, field services, monitoring & diagnostics, and engineering assessments.


PSM is hard at work servicing the existing fleet of gas turbines. But it also involved in the development of the next generation of equipment. It is investing heavily in the hydrogen space, including upgrades LEC-III and FlameSheet combustor retrofits that can installed into OEM machines to co-fire variable blends of hydrogen and natural gas, with a development road map to allow a 0 to 100% range of hydrogen without the need for water, steam or nitrogen diluents to limit emissions.


For example, a sister plant in The Netherlands run by Thomassen Energy (also part of the same division within Hanwha) is going to retrofit one of the Uniper Rotterdam Capelle (RoCa) power plant’s gas turbines with the PSM HyFlex LEC-III combustion system capable of being operated with a variable blend of hydrogen and natural gas fuel. The RoCa plant in the Zuid-Holland Province has a net electrical output of 264 MW. It has two Frame 5 gas turbines commissioned in 1983 (RoCa 1 & 2) and one Frame 9E (RoCa3), manufactured by Thomassen, commissioned in 1996.


In 2023, Uniper is planning to switch the RoCa plant’s fuel source from Groningen natural gas to a high caloric gas supply. Uniper anticipates blending the new gas supply with upwards of 30% H2 while maintaining low emissions when coupled with an AutoTune system. This retrofit system has already been operating on three Frame 9E turbines in the Netherlands at another location since 2018 with up to 25% hydrogen.

Benoit sees an immediate market for hydrogen-based combustion and gas turbine systems for dealing with refinery off gas. Regulations are tightening and flaring is gradually being eliminated as part of decarbonization objectives. Facilities, therefore, will seek a way to utilize the hydrogen refinery off gas economically. Providing it to their power and steam generation assets is one obvious option.


“Decarbonization does not mean the disappearance of the gas turbine,” said Benoit. “With so much natural gas available in the U.S., blue hydrogen (hydrogen produced from natural gas) is likely to be the most viably available bridge over to green hydrogen in the years to come.” ■

GEARING UP FOR HYDROGEN-BASED GAS TURBINES 

POWER SYSTEMS Mfg. (PSM) 

The 32nd Annual Meeting Western Turbine Users Inc. (WTUI) conference kicked off this week with its traditional overview of gas turbine trends. Delivered by Mark Axford of Axford Turbine Consultants and Tony Brough of Dora Partners, the big news was a thriving aeroderivative market – and tepid large frame turbine sales.


New gas turbine orders down overall 12% (measured in MW) in 2021 but up on 8.5% in the number of units. But looking deeper at the numbers, aeroderivative unit orders in 2021 were up 11% for the year. When viewed outside of the volatile Russian market, aeroderivative unit orders were up 110%. Further, North American aeroderivative unit and ME orders were both up more than 300% in 2021. The LM6000 accounted for more than 50% of the MW orders and the LM2500+ for about 50% of the unit orders.


Worldwide, the LM2500+ dominates the market. It has a five-year share of 33% of all aeroderivative orders, 25% higher than the LM6000 in second place. The LM2500 and LM2500+ each have fleets in excess of 1200, with the Lm2500+ now leading. The LM6000 lies behind at around 1150.


“The LM2500+ continues to be the strongest GT and has been so for a long time,” said Brough.


The GE/Baker Hughes combo accounts for 80-90% of non-Russian aeroderivative unit orders. And, of course, the LM2500+ and LM6000 are the main contributors. This fits with an overall trend of lower sales in power generation and higher sales in oil & gas. In North America, the number of mechanical drive units sold in the past seven years is double what it was in the previous seven years.

Whatever the forecast, renewables are always expected to be up sharply. Yet, Brough believes gas turbines have a strong role to play over the long term. He noted all the attention on hydrogen but said this market will experience slow but steady progress. Meanwhile almost 400 hydrogen electrolyzer projects are already operational or under construction and nearly 500 more are at the feasibility or concept stage. About 50 plan to convert hydrogen into ammonia as a storage mechanism.

“It is unwise to dismiss hydrogen, but a lot of challenges have yet to be overcome in its utilization,” said Brough.


Mark Axford continued the presentation by showing the long downtrend in the gas turbine sector. 2021 was down 12% in overall gas turbine MW orders (including large-frame machines) and up slightly in unit orders.
“What was an annual GT market of 60 GW a few years ago is now a 30 GW market,’ said Axford.


But he echoed Broughs sentiments about the aeroderivative sector. Texas was a major contributor to the 2021 sure in aero orders, partly in response to the early 2021 power grid failures in that state.


He went into more detail about aero orders. Siemens Energy managed 19 sales in 2021 (up from zero in 2020) of its A35, A45, and A65 machines (formerly Rolls-Royce). It has ended production of the A45 and A65. The A35 remains in production. Mitsubishi's stewardship of the T9 MobilePac (formerly PWPS) pushed sales from 0 to 6 for the year.

There were 22 LM2500+ G4s ordered in 2020 and 47 in 2021. From 0 orders of the LM2500 Xpress in 2020, GE managed 17 last year. The TM2500 trailer increased from six to nine orders, and the LM6000 from 4 to 26 in 2021. GE LM9000 had a dire year, dropping to 0 from 20 in 2020. And the LMS100 continues fail to register any sales for the second year running.


GE U.S. aero orders in 2021 included 6 LM2500Xpress’ to Colorado Springs Utilities, 10 LM6000s to TVA, 2 TM2500 G4s to Entergy of Louisiana, 4 TM2500 G4’s to two power plants in northern California, 4 LM6000s to the Salt River Project in Arizona, and two LM6000s to WattBridge (ProEnergy in Texas).
“The LM2500Xpress is less expensive than a trailer-mounted TM2500 and can be relocated,” said Axford. “RWE in Germany also ordered 11 LM2500Xpress units.”

Meanwhile, ProEnergy has carved out a niche for itself. It refurbishes LM6000 gensets, making them more affordable, especially for those running less than 1000 hours. Its subsidiary WattBridge Energy owns and operates peaking plants within the Texas ERCOT system. This includes 38 LM6000s already and more are planned.


How about 2022? Axford forecasts MW orders to be down 10% in the U.S. and it to be an overall down year world-wide, particular for large-frame machines.
“But it should be a good year for small aero, especially if restrictions on oil and gas are lifted,” said Axford.


Finally, he expressed skepticism about the realities of hydrogen generation replacing natural gas for power generation.


“There are dozens of ongoing test projects with hydrogen fuel but in my judgment, hydrogen will not become a mainstream fuel for gas turbines,” said Axford. “Perhaps a niche market will evolve for blending 5-10% hydrogen into the gas supply of regional markets.” ■

STRONG AERODERIVATIVE MARKET, WEAK LARGE FRAME

GT MARKET TRENDS

While it is tempting to think of wire as an ideal conductor that gets a signal from point A to point B without alteration, this is often not the case – particularly for long cable runs. In an ideal world, the cable connecting a sensor to its associated monitoring system would be a perfectly lossless conductor that would not alter the signal whatsoever. In the real world, however, the cable exhibits, resistance, inductance, and capacitance ((Figure 1). These values for R, L, and C are typically expressed on a per-meter or per-kilometer basis when SI units are used. These distributed parameters act to alter and distort the sensor signal in four undesirable ways (Figure2).

Low-pass filtering effects: The distributed cable parameters form a low-pass filter that allows low frequencies to pass with little or no attenuation but effectively blocks high-frequency components of the signal from passing. This results in an altered waveform that may be unsuitable for conducting proper diagnostics. The signal may be so degraded that it is unsuitable not just for diagnostics, but protection as well.


Slew-rate effects: For speed measurements, the signal often originates as a rectangular pulse train but distorts due to the impact of wiring capacitance (known as slew-rate). The pulse train shape with abrupt vertical changes originates because the speed sensor is often observing a toothed surface, a key, a keyway, or some other physical discontinuity in the surface observed by the sensor. If there were no limitations on slew rate, such vertical discontinuities could be reproduced. But in real wiring, the capacitance limits the ability for instantaneous changes in signal voltage and the crisp, rectangular pulse train begins to resemble a series of smoothed pulses where the abrupt edges are rounded. While slew-rate rarely affects vibration and dynamic pressure signals, it can frequently affect speed signals.


Resistance effects: Cable resistance forms a voltage divider that drops some of the original signal voltage produced by the sensor across the wiring instead of entirely across the input impedance of the monitor. This has the undesirable effect of decreasing the signal-to-noise ratio.



Voltage and current must also be considered. When the signal is transmitted as a varying voltage, it is referred to as voltage-mode signal transmission. Although voltage-mode is considered the conventional method for transmitting vibration signals, and is commonplace, it is the most vulnerable to the four effects discussed above. As such, voltage-mode transmission tends to constrain the length of field wiring more than alternative modes. Many manufacturers, however, do not support anything other than voltage-mode transmission with their sensors.


When the signal is instead transmitted as a varying current, known as current-mode signal transmission, it mitigates many of these effects and allows much longer field wiring lengths than with conventional voltage-mode transmission.
Note, though, that there are certain situations in which neither voltage-mode nor current-mode transmission are adequate over long distances. By using frequency modulation to transmit the signal, certain combination of longer field wiring distances and frequency content can be supported, as an alternative to conventional 4-20mA scheme.


While signal degradation is always a constraint due to field wiring length, another constraint occurs when the installation is in a hazardous area andintrinsically safe (IS) methods must be used to achieve compliance: stored energy. Both cable inductance and cable capacitance have the effect of storing energy. When a fault in the wiring or device takes place, IS constrains a resulting spark from releasing sufficient energy to ignite the surrounding flammable atmosphere. It does not prevent a spark, but instead limits the energy in the spark. Consequently, approvals for IS provide strict limits on the total amount of inductance and capacitance that can exist in the hazardous area, and thus the amount of energy that can be stored and released as a spark.


Signal degradation is not the only constraint that exists on field wiring length when the installation involves a hazardous area and IS wiring. In such installations, the user must compute the wiring length constraint under both signal degradation and stored energy criteria and then use the more restrictive of the two separate constraints. 

Dr. Luc Fromaigeat, Technical Support Engineer Energy at Meggitt SA Switzerland. He has 35+ years of field experience in Vibration, acoustics analysis, and diagnostics. He teaches Vibrations for the Swiss “Brevet Federal de Maintenance” and for Meggitt worldwide. He authored an extensive application note with worked example calculations and a downloadable calculator for field wiring calculations https://meggittsensing. com/energy/app-note-cable-length/

AN INTRODUCTION TO CABLE LENGTH CONSIDERATIONS 

Field Wiring Effects

PowerGen 2022 represented elements of both joy and sadness. Joy at once again seeing our friends and the many vendors that are the lifeblood of the industry. Sadness as the show feels like the former capital of a once mighty empire that has been relegated to a peripheral and decidedly provincial role.
But at least there was some fighting talk during the Monday morning keynotes. Sandwiched among those advocating a hydrogen-powered and renewable future, former U.S. Secretary of Energy Rick Perry offered a reality check. He questioned the feasibility of achieving the net-zero targets for 2050 and defended fossil fuels and nuclear power.


He campaigned for a balanced approach, saying we need all sources of generation to power the nation. He made it clear that regardless of the plans for wind, solar, batteries, and hydrogen, we are going to need fossil fuels for a long time into the future. He also called for more attention to be paid to areas such as carbon capture, utilization, and storage (CCUS) and small modular reactors (SMRs) for nuclear power.


“Does anybody think that we’re going to be able to address all of the needs of the United States by 2035, with just renewables?” said Perry. “And if the world went to net zero by 2050, it would be one of the most apocalyptic losses of life in the world’s history.”


A session on the future of gas turbines focused on hydrogen. Adam Foust, Gas Turbine Proposal Manager at Siemens Energy, began with a history lesson. Advances in thermal barrier coatings (TBC), aerodynamics, manufacturing techniques such as additive manufacturing (AM or 3D printing), and combustion had led to steady gains in efficiency and MW capacity. He expected the industry to continue to make progress in raising efficiency and performance.

“AM is a key part of those improvements as it has led to increased firing temperatures, greater fuel flexibility and higher efficiency,” said Foust.


3D printing has enabled component and system designs with more complex geometries, which facilitates reduced cooling flows and greater rates of heat transfer. Better mixing of fuel and air in the combustion system means higher firing temperatures as well as lowered emissions and better fuel flexibility.


“In 1985, we were at 42 ppm NOx and that also needed dilution,” said Foust. “Now, 5 ppm NOx can be achieved without dillution.”


By introducing some hydrogen into the natural gas, he added, the amount of carbon dioxide can be lowered. Siemens Energy gas turbines have been tested to operate at 30% hydrogen or more. One has run successfully with 100% hydrogen. To manage flashback risk in hydrogen combustion, Foust noted in answer to a question that there is a derate with current combustion technology. But new approaches are addressing that.


The future of gas turbines, he said, is focused on improving efficiency, increasing hydrogen fuel flexibility, and bringing more AM into GT parts and even blades, while integrating renewables and energy storage.


Ajay Gupta, Director of Product Line Management at Mitsubishi Power, also outlined his company’s pathway to 100% hydrogen generation.
“Gas turbines are vital to the future energy mix but they need greater flexibility,” he said. “the combustor is the primary technology advancement for hydrogen operation.”


Gupta also touted hydrogen as a good form of long duration storage and batteries as short duration storage. And he covered his company’s Takasago Hydrogen Park in Tokyo that is scheduled to begin operating next year. It will produce H2 onsite in electrolyzers and store it. Beginning with the H25 gas turbine, the plan is to validate operation at up to 100% hydrogen. With that achieved, larger Mitsubishi turbines can then be tested and validated.


Most attention on hydrogen has centered upon the impact on the combustor. But what about the heat recovery steam generator (HRSG)? Richard Saab, a Sales Manager at Siemens Energy offered insight into the main impacts of firing H2 in gas turbines on HRSGs.


For example, the combustion of hydrogen will occur at higher flame temperatures than natural gas. One of the side effects of that fact is the production of more nitrogen oxides (NOx). Secondly, the water dew point of the flue gas increases when firing hydrogen in the GT. This means that cold parts which are in contact with flue gas will form condensation quicker. Thirdly, firing H2 adds extra volume to the exhaust gas flow. Lastly, he discussed safety when firing hydrogen.


Many of these impacts are due to the characteristics of hydrogen. It has a high mass related heating value of 51,600 BTU/pound, as well as a density that is eight times lower than methane. Despite that, its benefits are attractive.
“Natural gas generation with 30% hydrogen by volume delivers an 11% reduction in CO2,” said Saab


Hydrogen’s wider explosion range and lower ignition energy compared to natural gas presents some safety concerns for HRSGs. However, he said hydrogen is expected to accumulate in the same areas of the HRSG as natural has such as the attic. Current safety procedures already take this into account and should be sufficient, but should be checked.


On the exhaust side, hydrogen requires a much higher volume of gas be passed through the turbine due to its density. Thus, the HRSG needs to be engineered to avoid exceeding the design pressure drop since increased pressure drop can cause derated performance.


As emissions of NOx will go up as more hydrogen is added, he recommended leaving space in designs for new HRSGs where an SCR could be added in the future if needed.


“Those wanting to burn hydrogen in the future should set up the HRSG for it upfront,” said Saab. “Those that do can receive a hydrogen-ready stamp that can help with financing and will minimize costs. It is far more difficult to do afterwards.”


Retrofitting an SCR into existing HRSGs would be extremely challenging. If HRSG needs a LOT of modification, it might need a new HRSG if it is older.
Other impacts: Condensation increases in the back end of the HRSG due to hydrogen. Above 50% by volume, a lot more water accumulates and this can cause more moisture in the tubes. Hydrogen can be fired in duct burners. He suggested that separate valve trains and firing elements be installed due to differences in heating value and supply pressure. “It is recommended to keep different trains of duct burners with different design for natural gas and hydrogen,” said Saab.


With all the talk about green hydrogen, why not green steam? That was the question posed by Paul Brown, Vice President Custom Systems, Industrial Watertube Boilers at Cleaver Brooks. Hydrogen, it turns out is a viable fuel source in today’spackage watertube boilers whether they are used as auxiliary boilers in a utility power plant, a process boiler in a refinery, for cogeneration in a distributed energy center or simply as a heating boiler at the local university.


“The technology needed to facilitate hydrogen firing and eliminate CO emissions from the system is not new and does not increase risks associated with packaged boiler or burner design and operation,” said Brown
But there are design factors in both the boiler and combustion system that must be considered. The good news is that current boilers are ideally designed so they are in good shape to accommodate the burning of hydrogen.
“The flame temperature is higher with hydrogen so we must pay attention to the possibility of overheating,” said Brown. “But as all furnaces today have a 100% membrane wall construction with water-cooled surfaces and are conservatively sized, they can usually handle higher temperatures without changes.”


As far as unburned hydrogen collecting in pockets at the top of the boiler due to low molecular weight, once again there is little risk. Brown said D, O, and A style boilers leave very little space for accumulated hydrogen and thus a conventional purge cycle can eliminate the risk of hydrogen accumulation
He gave the example of a 100,000 lbs per hour boiler running at 600 PSIG and 750F. Operating on natural gas its efficiency is 84%, which drops to 79.5% on a high heating value (HHV) basis for hydrogen. At a low heating value (LHV), hydrogen has 94.1% efficiency, higher than natural gas’ 93%.


“Pay attention to LHV and HHV numbers and know which one is being referred to and design to deal with it,” said Brown.


Superheated steam from hydrogen would have a lower steam temperature (730F) compared to 750F for natural gas due to hydrogen’s lower gas side mass flow. This calls for minor design tweaks like adding more heating surface to the superheater.


A forced draft fan in an auxiliary boiler running natural gas would need to be 350 hp compared to 250 hp when fired by hydrogen. The reason a less powerful fan would be needed for hydrogen is that less combustion air is needed in combustion.”


Further pointers: hydrogen’s typically low supply pressure and low heating value requires larger fuel piping than natural gas to obtain the same BTU input to the boiler. Overall hydrogen components are likely to be larger and more expensive. To cope with higher NOx, hydrogen systems need increased flue gas recirculation (FGR) and/or SCR.


“Adding above 5% hydrogen to an existing natural gas fired boiler will push NOx over the limit,” said Brown.

Day 2 of PowerGen again featured plenty of hydrogen sessions. All were standing room only. Matt Ballew, Technology Strategist for Vista, said hydrogen can either be viewed as a threat or as an opportunity. He sees plenty of opportunity for hydrogen as a baseload fuel as well as in energy storage. When wind is strong at night, turn that power into hydrogen via electrolyzers and then sell later when prices are high.


The most surprising statement was about cost. Ballew said that the most optimistic projection is a dollar a kg or 7.45 cents per mm btu, which is twice that of gas – and he’s talking about hydrogen reaching that level of cost by 2050. That means hydrogen must rely on a tax on carbon or other incentives to make progress in markets.


“The markets don’t make sense right now,” said Ballew.

Dr. Ben Emerson from Georgia Tech covered how a retrofittable combustion system is needed to make hydrogen combustion work properly and to avoid flashback – the flame propagating upstream into the nozzle and igniting.
He called into question the idea that hydrogen resulted in higher NOx. His argument centered around the use of Dry Low NOx combustors for natural gas making it difficult to do an apples-to-apples comparison as hydrogen combustion has more moisture content. He said he was discussing this with the EPA. He ended by saying that it may be possible to design a combustor for hydrogen that lowers NOx significantly.


Alan Ettlinger, Senior Director of Research Technology Development at New York Power Authority (NYPA), delivered a teaser about testing being done in conjunction with EPRI. He gave no real concrete details but said a peaker plant on Long island is being run on “more than 5% hydrogen.” I got the idea it was a lot more than 5% but he wouldn’t say. Ettlinger said we would be surprised at the findings of a study being released in the fall. He commented on some of the challenges with hydrogen. NYPA trucked in the hydrogen, which he said was a flawed approach.


“The largest hydrogen storage facility in the USA is at NASA and it would only run our plant for three days,” he said. “The hydrogen supply problem needs addressed either by large-scale electrolysis or pipelines.”


Nethra Subramanya from GE laid out GE Gas Power’s capabilities for hydrogen blends in gas turbines. She felt that it makes most sense to blend with natural gas rather than seek to operate at 100% hydrogen.


The second day ended with a dose of reality on hydrogen. John Gulen, Bechtel Fellow for Bechtel Infrastructure and Power, began his talk by noting the hydrogen “hullabaloo.”


“I’m at PowerGen but where is the power and where are the turbines?” he said. “This is not the PowerGen I remember.”


He revealed some research findings on the optimum size and type of gas turbine to operate hydrogen. This will be covered in more detail in an article in the next issue. But it revealed that larger turbines would be far less efficient due to the amount of hydrogen that would have to be produced via electrolysis to power a combined cycle plant. The sweet spot, Gullen said, was around 200 MW.


“The smaller the GT, the better the chance of burning economically and realistically available hydrogen efficiently,” said Gullen.


He was followed by Ammar Moosa, Commercial Manager for ProEnergy, and Sairam Ellanti of WattBridge. Moosa addressed the need to design resiliency into aeroderivative turbine peaking facilities.


“Resilience is a function of time and how fast you can respond to any disruption,” he said.


Part of the problem is that no two gas or coal plants are the same. This is quite different from other industries, such as oil & gas and data centers. In these fields, repeatability is everything and that greatly improves resilience.
“Aging baseload retirements mean there is more pressure on peaking plants,” said Moosa. “Peakers are operating more than they were designed to these days.”


In addition, extreme weather conditions can cause devastation with forced outages and unmet demand. Lastly, with more wind and solar on the grid, standby peakers are needed more than ever for grid firming applications.
ProEnergy’s strategy is to bridge supply gaps by deploying its standardized LM6000 facilities for utilities and IPPs. That machine was chosen due to its fast start within 10 minutes, rapid ramp and low turndown, negligible maintenance penalty for frequent starts, and the ability to offer a low installed $/kW solution. ProEnergy announced an R&D program to assess the limits of hydrogen fuel mixes. The company will start testing below the established 30% hydrogen mix.


ProEnergy subsidiary WattBridge is supporting grid firming in ERCOT with 1,824 MW of peaking power operating or under construction in the Houston area, which is halfway to their goal of 4 GW of new power generation in Texas by 2025. Owned by WattBridge and operated by ProEnergy, these facilities require the perfect location for peakers (high-pressure, firm gas supply as well as ample transmission and water).


The H.O. Clarke Generating Station, for example, has 8 LM6000PCs. WattBridge includes various inlet conditioning including fogging to augment power output on hot days and anti-icing systems to protect operation on cold days.
During the big Texas storm of February 2021, the company’s units remained 100% available, operating continuously for 141 hours over a 6-day period – at a time when 60% of ERCOT capacity was unavailable. 

HYDROGEN GENERATION, DECARBONIZATION, AND DIGITALIZATION DOMINATE

July/August 2022