There’s no app for this. There are no shortcuts. In the 21st Century, turbomachinery requires just as much repair and maintenance as ever, only now those repairs can be more accurately predicted and planned in advance.
The name of the game is efficiency. Technologies are emerging to perform maintenance, repairs, retrofits, and overhauls while gauging asset health remotely. Engineers are adopting video calling to train other engineers and operators to perform their duties. Drones are even being deployed for inspections. Part availability, too, is a hot issue. Plant operators increasingly seek alternatives for parts.
Meanwhile, several shops note a slowdown in overhauls and retrofits as cash-strapped utilities kick the can down the road. Fewer projects and more competition could spell trouble for smaller service companies in the months ahead. In some cases, residual life assessments are replacing traditional maintenance outage windows. Information gathered from continuous diagnostics and monitoring dictate if and when an outage takes place.
As grids grow more reliant on renewables, combined cycle plants in the U.S. have largely shifted from base load to cycling operation. Faster, more frequent cycling and harder duct firing wreaks havoc on heat recovery steam generator (HRSG) gas- and water-side components.
But let’s hear what the experts have to say. Those interviewed include HRST, Doosan Škoda, EthosEnergy, Rotating Machinery Services, Rotoflow, Sulzer, John Crane, Siemens Energy, MAN Energy Solutions, Riverhawk, and BRG Machinery Consulting. They offer insight into engineering and technical advisory services, OEM and non-OEM retrofits and upgrades, field services, repair/replacement of parts, 3D scanning, and on-site machining.


Liburdi Turbine Services is a specialist engineering and repair company for turbine flow-path component repairs, compressor airfoils, fuel nozzles, combustor parts, turbine blades, and vanes and shrouds. Most of its repairs involve bringing a part back to the form, fit, and function of the original. Any change, even in the coating applied, could affect the part to a degree that could require testing, which adds cost.
Liburdi relies on an institutional understanding of metallurgy and the various competing damage mechanisms in any gas turbine. The company created rejuvenation and reconstruction processes to refurbish and fortify parts to mitigate against future damage.
“Operators do not want to scrap their components, and neither do we,” said Robert Tollett, Director of Marketing at Liburdi.
There’s an inherent contradiction in the trends identified by Liburdi engineers. As the next generations of gas turbines are commercialized, components will be progressively optimized for efficiency. The achievement of efficiency generally adds complexity. Yet complexity is unforgiving in terms of design margin and reparability.
“There could be a time when most turbine parts become one-use expendable,” said Tollett. “That will be an unfortunate waste of resources akin to the cellphone industry.”
In response to COVID-19 restrictions, Liburdi noticed shortages of available parts as well as deferral of outages. Yet its shop has operated close to full capacity for a year.



HRST has observed a significant uptick in high-pressure drum weld cracking due to steam drums bearing the brunt of cyclic operation damage. This often requires nondestructive examination and analysis to determine if the unit is fit for service and what repairs are necessary. Aging duct burners and superheaters/reheaters are also impacted by cycling and duct firing.
The company is embracing new technologies to address these problems, as well as the need for more frequent inspections of turbine exhaust ducts, expansion joints, liner systems, catalysts, and silencers. HRST now uses drones as part of its inspection routine.
“During offline inspections, duct burners, catalysts, silencers, and stack dampers can be inspected by a drone at a fraction of the price of erecting scaffolding,” said Sam Shaw, Systems Engineer at HRST. “Drone technology allows for high resolution photography of these components while maintaining a safe distance for the inspector.”
Drones can also be equipped with Forward Looking InfraRed (FLIR) cameras to perform online thermal inspections. This can prove useful in detecting pen seal failures, expansion joint failures, casing hot spots, and insulation degradation on HRSGs and simple cycle exhaust duct work. Weeping pressure safety valves on some HRSGs, for example, can be detected this way as the silencers run at an elevated temperature.
Another market shift noticed by HRST is that peaking units see more run time and starts as more renewable generation comes onto the grid. This sharpens the requirement for reliability and preventive maintenance. It can mean more frequent inspections for peaking turbines and related duct work.


EthosEnergy has seen greater focus on a risk-based maintenance strategy and away from traditional OEM recommendations. This results in increased demand for condition-based maintenance programs and fast response to unplanned outages. The company has adapted by enhancing its engineers’ capacity to handle technical or commercial concerns.
The company is one of many reporting a slow, steady return to pre-pandemic business activity. This includes the gradual return of normal outage planning and repair and maintenance service requests.
Even before the pandemic, cost cutting measures had created higher demand for remote access to shops and technical personnel. Now, the company says that has become a standard necessity. EthosEnergy now has a live video feed for customers to interact with engineers in real time. Additionally, the company’s life extension and rotor solutions address changing asset demands and duty cycles, as well as energy security and grid stability challenges.
Rotating Machinery Services (RMS)
RMS is an OEM provider of AC-brand axial, centrifugal, and oil-free screw compressors, and Conmec-brand axial and centrifugal compressors, as well as gas and steam turbine repair and maintenance services. The company performs overhauls, repair and refurbishment, upgrades, spare parts and kit boxes, and nondestructive testing and analysis. As maintenance budgets tighten over time, RMS customers are increasingly cost-conscious of spare parts, overhauls, rerates, and redesigns.
“We serve as the OEM (for AC Compressor) but have always been a service provider to all nameplates of equipment,” said Alex Tetlow, Vice President of Sales at RMS. “This mix of OEM and non-OEM knowledge allows us to be creative in our solutions.”
Staying current with the latest technology in 3D printing, CFD, FEA and CAD is a priority for RMS, as well as the integration of remote communication and measurement into field maintenance routines. Over the past year, it has been difficult to schedule field crews to perform planned turnarounds. But now, there is more urgency in the market to conduct urgent repairs due to unplanned outages.



Rotoflow, an Air Products business, is a manufacturer and operator of rotating equipment, offering turbo expander repair, field service, machine rerates, root cause analysis, nondestructive testing, and reverse engineering. As well as repairing and maintaining turbomachinery, the company develops strategies to improve uptime, including proper sparing, site assessments, and condition-based monitoring.
During the pandemic, Rotoflow adopted video calling to show customers test data in real-time as an alternative to an in-person mechanical spin test. The company also redeployed field service technicians who were no longer able to travel to customer locations. As travel restrictions eased, the field service team is now performing work at customers’ sites, both planned and emergency maintenance and repairs, while following strict safety protocols.


MAN Energy Solutions offers services for spare parts, turbomachinery maintenance and repairs, modular service agreements, and individual consulting and field service. For non-MAN rotating equipment, the company offers services under its Omnicare brand through a global repair shop network. It also safeguards equipment with remote machine diagnostics and provide training for operational and maintenance skills with a service called PrimeServ.
Like others, MAN has noticed a shift from time-based to condition-based maintenance.
“Customers seek higher uptime and reliable, uninterrupted operation with longer maintenance intervals,” said Oliver Tromm, Head of Product Center Zurich/Berlin, MAN Energy Solutions, MAN PrimeServ. “Optimization of residual lifetime is key today so high equipment reliability must be ensured.”
MAN is adjusting to the same trends as the rest of the industry. Turnarounds were shifted, investments into upgrades and modifications were questioned and delayed, a higher degree of remote services was requested, stock inventory was checked, and risks were minimized with higher stock levels.


Siemens Energy services drivers and driven equipment, including aeroderivative gas turbines, medium and small gas turbines, steam turbines, generators, all types of compressors, and gas engines. It provides OEM services for parts, field service, repairs, overhauls, inspections, and remote operational services. The company listed several trends: customers want no repairs to go unplanned, minimal outages time, lower emissions, reduced inventory over time, and higher employee productivity, with a tendency towards using its own employees and teams rather than subcontracting.
“Customers are keen to adopt new technologies, like additive manufacturing, sensors and remote monitoring,” said Erhard Eder, Senior Vice President, Industrial Applications Services for Siemens Energy. “They also want more predictive maintenance options, like asset performance management to transition to condition-based maintenance.”
Since the COVID-19 pandemic, the company invested more in its remote offerings. This begins on the factory floor, with remote testing, then to the field with remote performance monitoring and diagnostics, and field service when needed. Accordingly, Siemens Energy trained its regional field teams to carry out maintenance with remote tools. Remote Inspection and Testing Acceptance (RITA) allows customers to be virtually present when its turbomachinery is being tested. Cameras film the components during actual test procedures. Footage and critical data are transmitted in real-time.


Riverhawk designs and manufactures bolt tensioning solutions and is a full-service diaphragm coupling manufacture and repair center that specializes in refurbishing OEM diaphragm couplings. Along with its coupling offerings, the company supplies all the installation tooling to install couplings and torque management solutions. The biggest challenge it faces is the demand need for service within weeks rather than months.
Most users shut down for only a brief period of preventative maintenance. If there is no spare coupling, they need an existing coupling serviced and returned before completion of the turnaround
“Returning a coupling in as-new condition with a short lead time can be a challenge, especially if parts are damaged beyond repair and need replacement,” said Riverhawk’s Pat McCormack, Business Development Manager.
Over the years, the company has seen formal safety standards shift. Sometimes it means showing a simple video on a facility’s safety requirements. In other cases, it requires an all-day class before entering the facility. In addition, the company has seen a growing demand for detailed documentation of repair work such as Material Certifications, Calibration Certificates and pictures of certain portions of the repair.
Riverhawk has no plans to abandon face-to-face meetings. But they are being supplemented by video conferencing software and high-resolution cameras to provide proper guidance in the use of tooling. Overall, McCormack said maintenance spending was down about 20% from initial 2020 projections. Nevertheless, he remains optimistic that 2021 will be a good year for those in maintenance and repair.


C. Hunter Cloud, Ph.D., President of BRG Machinery Consulting, a Virginia-based provider of rotating machinery technical services, commented on a long-term trend of fewer experienced machinery engineers being present in plants. As a result, he often sees repairs made without addressing the root cause of problems. The rush to return critical machinery to full operation can contribute to a lack of due diligence that should include a thorough failure analysis by internal or external technical experts.
As margins in operating plants shrink, Cloud said, decisions to refurbish aging equipment are being delayed. Repairs attempt to extend the life of inefficient equipment, often beyond the original design. Cost reductions have also led to the use of third-party repair shops who can be unfamiliar with the equipment’s design, placing more reliance on the user to determine which repairs are necessary.
Some large manufacturers, Cloud added, are evolving into global organizations. At times, this can create barriers to having the right people involved with a repair or failure investigation. Further, field support may now involve quarantine before and after, which affects timing and costs. Oversight of shop work requires more detailed documentation along with virtual inspections, such as for bluing contact checks and witness of rotor balancing.



Sulzer is an OEM for pump parts and offers maintenance and repair services for pumps, turbines, compressors, motors, drives and generators. The company is constantly keeping up with customer demand for alternatives for spare parts. This is especially important for a non-OEM service provider like Sulzer, whose main focus is increasingly seal reliability.
Since the start of the pandemic, Sulzer has seen fewer overhauls in a more competitive market. Fernando Romero, VP Engineering at Sulzer, said clients often want a re-rate until they know the cost.
Sulzer has invested in automation in the form of computerized numerical control capabilities to support manufacturing, dimensional inspections and, welding.
“With remote maintenance, you lack control over the capabilities, workmanship, and resources of the party at the other end of the line,” said Romero. “Care is required in the division of responsibilities.”


John Crane offers project management services for turbomachinery performance restoration as well as pre-commissioning and commissioning services. The company manufactures gas seals, separation seals, conditioning, and asset monitoring systems. It works constantly to raise seal, speed of rotation, diameter, and resistance to process gasses, in addition to running at colder temperatures.
“We have made progress of late raising the understanding of seal health dry gas seal lifespan,” said Mike Weegenhausen, Director, Turbomachinery Products & Services at John Crane.
He gave examples of the type of projects the company is engaged in. The operational lifetime of centrifugal compressors, for example, can be cost-effectively extended by upgrading components such as motors, impellers, seals, bearings, and control systems. A common upgrade is a dry gas seal retrofit for oil-seal-equipped centrifugal compressors.


Turbomachinery services are a key line of business for Doosan Škoda Power. All types of overhauls and inspections of machines in combined cycle power plants have remained the key driver in turbomachinery services. The company also sees growth in the waste-to-energy industry and in the nuclear segment.
Doosan Škoda Power can perform online remote borescopic inspections of turbine internal parts and remotely access turbogenerator control systems as part of long-term service agreements. This enable tuning and adjusting of operating parameters and alarms.
“We can manufacture spare parts in the original quality in the same workshop used for new build installations,” said Stanislav Šnejdar, Director of Service at Doosan Škoda Power. “Our service team is located under one roof along with all subject matter specialists and R&D engineers.” ■

Articles

Technologies are emerging to perform maintenance, repairs, retrofits, and overhauls while gauging asset health remotely. Drones are being deployed for inspections. Some parts can be scarce, so plant operators are increasingly seeking alternatives.

Drones, Scarcity, Efficiency: Repair & Maintenance in 2021

Imagine 21,000 of the top experts on oil, gas, LNG, electricity, and renewables, including their political advocates, being on the same Zoom call. That describes the 39th CERAWeek by IHS Markit. Often referred to as the “Davos for the Energy World”, CERAWeek is customarily held in Houston, Texas. After being cancelled in 2020 due to the pandemic, the latest version was held virtually in early March 2021. The timing was amazing for two reasons:
A newly elected U.S. administration was on hand to explain its green energy ambitions.
A massive winter storm in Texas two weeks earlier caused havoc in the power and gas markets.

Many attendees and speakers wanted to know about the contemplated transition from fossil fuels to green energy. How fast will it happen? What has gone right so far? What could go wrong? Ask three energy experts, get three different answers. Ask three politicians, get nine different answers.

It takes courage to predict 30 years into the future. Innovation and change always seems to occur at a slower pace than imagined by the visionaries. It wasn’t so long ago that people wrote about the impossibility of U.S. energy independence. Just when you think you have it figured out, a disruptive technology emerges or an unexpected war causes a revision or reversal. The big question at the show: What is more valuable? 100% green energy, or the reliability of a diversified generation mix that includes affordable, abundant, and secure resources – nuclear, coal, natural gas, hydro, wind, and solar?
Bill Gates delivered the first keynote address at CERAWeek. He explained an economic concept of “Green Premium.” This is the incremental cost of doing something with zero emissions technology. For example, the Green Premium is relatively low for driving an electric car versus a gasoline powered car. The Green Premium is high when it comes to making cement or flying a commercial airline.


Gates became bullish about nuclear power if it can be reinvented into a smaller, modular power plant with lower cost for construction and operation. With reinvention, nuclear power could become the primary base load electricity source to back up intermittent supply of wind and solar power, he said. Without reinvention, nuclear power seems destined to be eliminated in western Europe and diminished to a level of about 10% in generation mix in U.S.
Gates believes it will be impossible to achieve 2050 decarbonization goals without carbon capture. He was not optimistic about developing economic improvements to existing carbon capture technology; that is removing CO2 from the flue gas of a coal plant or a gas turbine. He seemed fascinated by an alternate approach called Direct Air Capture. This involves stripping CO2 out of ordinary ambient air, much like the way companies such as Linde and Air Products separate out oxygen and nitrogen. Direct Air Capture is not economically feasible today – like much of Gates out-of-the-box thinking, it is only an invention away. He voiced a pricing goal for Direct Air Capture of $100/ton for CO2 removal.
Lisa Murkowski, U.S. Senator from Alaska articulated an interesting viewpoint: Energy security should not be abandoned as we contemplate a major energy transition. Take the case of electric vehicles (about 2% of new cars ordered during 2020 were electric). How rapidly can electric cars be adopted and replace gasoline-powered vehicles? Murkowski worries that after five decades unshackling the nation from oil dependency, we may now be lured into lithium dependency.
An electric vehicle strategy makes perfect sense for China, she said, with huge reserves of lithium and limited oil and gas reserves. If 25% or more of the U.S. automotive fleet was electric, where would we get lithium in the event of an embargo?


As Texas bounces back from the February crisis with rolling blackouts, there are many questions to be answered and plenty of blame to spread around. What improvements should be made by ERCOT to prepare for more extreme weather? The same question applies to PJM, ISO New England, CALISO, and other regional grids.
Is money no object to providing 99.999% reliability in order to cover the most extreme weather events? As we make the grid more reliable and resilient, how will we know when we are done? Is it more than a technical discussion about winterization of generation equipment? Texas learned that keeping the lights on also involves upgrading electrical transmission and distribution lines, gas storage, oil switching capability for gas turbines, and highway access during storms so technicians can respond to emergencies. ■

Many attendees and speakers at the 39th Annual CERAweek wanted to know about the contemplated transition from fossil fuels to green energy. How fast will it happen? What has gone right so far? What could go wrong? Ask three energy experts, get three different answers. Ask three politicians, get nine different answers.

Energy transition to green uncertainty

The big surprise was the bullishness of oil & gas executives about the future of natural gas. They presented a united front on the necessity of hydrocarbons within the energy mix, while at the same time working hard to reduce emissions.

Hydrogen-based turbomachinery and carbon capture, utilization, and storage (CCUS) of natural gas loomed large in the agenda. Similarly, the expansion of liquefied natural gas (LNG) merited several sessions, as well as ways to lower the carbon footprint of oil & gas operations.

Lorenzo Simonelli, Chairman & CEO of Baker Hughes, kicked things off by explaining the “Energy Forward” conference theme. He emphasized that energy is, and will continue to be, the foundation for the world’s progress.

“There are people who believe hydrocarbons should be relegated to the history books, that economic progress is at odds with environmental stewardship,” said Simonelli. “I think that is short sighted; we can be the positive agents of change.”

His argument centered around the fact that the peak of oil production and consumption could occur in the next ten years. Yet energy demand will continue to rise. There are nearly a billion people without access to electricity. As a result, it will be difficult to counter the demand for coal in the developing world.

“There is no scenario where hydrocarbons disappear so efficiency matters and we must work on reducing emissions,” said Simonelli. “Hydrogen generation, CCUS, and energy storage must become more cost competitive and scalable.”

He outlined what his company is doing on these fronts. This includes the acquisition of a carbon capture company and successfully testing its NovaLT gas turbines operating on 100% hydrogen.

“There is no scenario where hydrocarbons disappear, so efficiency matters and we must work on reducing emissions,” said Lorenzo Simonelli, Chairman & CEO of Baker Hughes.

“Renewables will not scale fast enough to displace energy demand in the coming years so we must learn to consume hydrocarbons in a better way,” said Simonelli. “Natural gas should serve as both a transition and a destination fuel; its efficiency is compelling.”

He ended by making the case that LNG is a favorable option for countries that lack home-grown resources. Baker Hughes is engaged in improving LNG’s emissions profile, as well as addressing methane venting, fugitive emissions, and flaring, which Simonelli regards as a bigger opportunity to reduce greenhouse gases (GHG) than CO2.

 One of the scenarios proposed to reduce carbon dioxide emissions. Carbon capture, switching from coal to gas, and raising equipment efficient account for more than 50% of potential gains.[/caption]

The Baker Hughes AM is a gathering of top oil & gas execs from around the world. Several offered their views on the oil & gas market.

Peter Coleman, CEO of Australian LNG and energy producer Woodside, has attention on handling emissions from his company’s massive storage operations, such as addressing leaks from valve stems, and the elimination of flaring. He said process upsets can lead to flaring, so work is being done to prevent such upsets.

Coleman expressed doubts about Europe’s attempt to turn away from gas, while Asia is embracing it.

“Despite severe economic stress, LNG grew 2% globally last year,” he said. “Fundamentally, Asian nations know their pathway to climate commitments has gas as an important element.”

Woodside’s plans to reduce its emissions include investment in hydrogen, carbon sinks such as growing trees, and CCUS, which he said will be attractive to deploy within a few years.

“We are protecting the value of our existing business and looking at what we can invest in based on what we are good at,” said Coleman.

On hydrogen, he said we still need to crack the hydrogen code. A little-known fact is that ten times the energy is needed to convert hydrogen from water compared to what it takes to make LNG.

Meanwhile, Woodside has formed an agreement with Japanese companies JERA, Marubeni, and IHI to undertake a joint study examining the large-scale export of hydrogen as ammonia for use in decarbonizing coal-fired power generation in Japan. It will examine the construction and operation of large-scale ammonia facilities and optimization of supply chain costs.

Another deal with the Tasmanian government in Australia is a pilot project to turn abundant hydroelectric power into hydrogen. The hope is that a five-ton electrolyzer will provide hydrogen to power the transportation fleet on the island. But Coleman drew attention to the small scale of this equipment in comparison to typical LNG projects. The scaling up of hydrogen has not really been thought through, he said.

He ended by pointing out that there is no industry around the world other than oil & gas with the funding or the ability to deploy the vast resources, the personnel, and the equipment anywhere in the world needed to bring hydrogen to fruition. He called for common sense about the future of energy.

“It will be 2030 before hydrogen at scale is available,” said Coleman. “The transportation market will move at a different pace to power generation as each has a different price point for viability.”

Elena Burmistrova, Deputy Chairman of Gazprom Management Committee, Director General of Gazprom Export, continued the positive theme.

“Gas can substitute for coal quickly, efficiently, and economically while lowering emissions,” she said.

Burmistrova laid out the case for gas in any energy mix: It has mature market mechanisms, self-balancing characteristics compared to oil, price predictability, is a known technology, and has the lowest emission rates among existing fuels. Gas pipelines are also the cheapest way to transport energy. She believes it makes sense to invest in pipeline infrastructure in a way that hydrogen, biogas, and syn gas can gradually be introduced to take advantage of the network.

“The rise in renewables raises the volatility of energy production and gas is needed for stabilization,” said Burmistrova. “Overly ambitions emissions goals foster regulations that are pushing immature solutions and exclude technologies that are efficient.”

She complained that the EU is proposing very low criteria for power plants that she believes are an attempt to outlaw gas plants. She also doubted the economics of green hydrogen when blue hydrogen makes more economic sense. (Blue hydrogen is produced from gas using steam methane reforming, with related carbon emissions offset. Green hydrogen is produced from renewable energy using electrolysis. In both production processes hydrogen is combined with nitrogen to form ammonia to enable it to be shipped as a liquid).

Bob Dudley, Chair of the Oil & Gas Climate Initiative and former CEO of BP, had a similar take.

“I see no scenario that is credible for an energy future without natural gas,” he said.

This assertion is supported by analyst assessments. IHS Markit predicts that the worldwide share of renewables will rise from 25% today (including hydro and biomass) to more than 50% by 2050. Coal will continue to dominate followed closely by natural gas. But gas will displace coal and become the top energy source during the 2030s. Its use will expand steadily through 2050. Coal usage, however, will begin to decline slowly but won’t disappear. According to IHS Markit, coal use will be around the same as photovoltaic solar by 2050 and will still amount to more than onshore wind.

Many of the AM sessions focused on LNG. The current installed capacity of LNG is about 460 million tons per annum (MTPA). Demand is expected to double in the next 15 years. Final investment decisions should be made for another 100 MTPA of LNG over the next year or two.

While the LNG market is expanding rapidly, those involved are working to make the technology cleaner and greener. Approaches include the adoption of low-emission equipment that can be integrated with combined cycle plants, renewables, hydrogen, and CCUS. Baker Hughes’ new LM9000 gas turbine, for example, has 44% simple cycle efficiency. It has been designed to reduce project cost and the time required to provide mid-sized train modules for LNG.

Nicholas Fulford, Global Head of Gas and LNG at the GaffneyCline Consultancy, explained that about a quarter of the emissions attributable to the burning of natural gas are from LNG and its various operations.

“Upstream gas production, processing, and transport emissions contribute heavily to the carbon intensity of LNG,” said Fulford. “Liquefaction is next in volume of emissions with shipping being the lowest.”

“With respect to past projects, today we can reduce emissions and carbon in LNG production by 30% with no additional cost in production using existing technologies,” said Daniele Marcucci, LNG Decarbonization Manager, Baker Hughes. But there is no silver bullet. Waste energy recovery, zero leakage compression, high efficiency gas turbines and centrifugal compressors, eLNG, combined cycle gas turbines, H2 blending, and digital efficiency will all play a part.”

He said an LNG plant utilizing LM9000 gas turbines instead of heavy duty units could achieve an emissions reduction of up to 20%. The LM9000 provides 73 MW at 44% efficiency with 15 NOx and 25 ppm CO. Baker Hughes eLNG option pairs the LM9000 with a 40 MW electric motor-driven compressor for modularized, midscale LNG in the 0.8 to 1.0 MTPA per module range. Weighing less than 2000 tons with less than 2000 square meter footprint, it can lower LNG train emissions by 30%.

LM9000s are to be used in Novatek’s Arctic LNG 2 project in Eastern Russia. The company has 4 trillion cubic meters of resources in its Russian Arctic portfolio. It plans to produce 70 million tons of LNG produced by 2030 via its Artic LNG 1 and 2 projects. By building two transshipment terminals (one further south where the Pacific Ocean won’t freeze up), it plans to have year-round service.

“Let’s not be apologetic about our industry as we are lifting millions out of poverty,” said Mark Gyetvay, Deputy Chairman of the Management Board at Novatek. “Without fossil fuels, society would not be where it is today. Natural gas is clean energy. It is a false narrative that it is harmful.”

He called for the industry to unite as one voice to combat misinformation. The Keystone Pipeline, he said, is an example of what can happened if we don’t advocate our clear message. He believes the correct transition is from coal to renewables and natural gas.

The company’s Yamal LNG project is operating and has already offloaded 500 cargoes amounting to more than 40 million tons. It consists of four trains. Artic LNG 2 has train one half finished with contracts signed for about 84% of the project’s total expenditures.

Gyetvay reviewed the various models and scenarios proposed to reduce carbon emissions. Regardless of the scenario, he said Asia will use more natural gas, not less. Even with the achievement of net zero carbon by all countries by 2060, there will still be 480 MTPA of LNG consumed. With business as usual, it would be 740 MTPA.

“Natural gas will play a large role in the energy mix despite any net zero scenarios,” said Gyetvay. “We will be a supplier of natural gas for many decades.”

Baker Hughes is partnering with Novatek to develop low carbon hydrogen technology for LNG trains. A pilot program will introduce hydrogen blends into the main process for natural gas liquefaction to reduce carbon dioxide emissions from LNG facilities, including the Yamal LNG complex.

Carbon capture, utilization and storage received more attention at this year’s AM than at the last ten combined.

Hege Rognø, Head of R&D, Low Carbon Oil & Gas Technologies at Equinor, called CCUS a “climate mitigating business opportunity.” Her company (formerly known as Statoil of Norway) has industrial-scale experience with CCUS. Its Sleipner Field in the North Sea has been doing CO2 injection since 1996. In that time, it has stored more than 18.5 million tons in subsurface layers. In addition, the Snohvit Field has injected 8.5 million tons of CO2 since 2008. And its Test Center Mongstad (TCM), operating since 2012, is testing a variety of technologies and approaches for carbon capture.

On the more adventurous side, Equinor’s Longship project will capture CO2 from plants on the east coast of Norway, compressed it, take it on ships, and into a storage facility on the west coast where it will be piped offshore to be injected. In conjunction with Total and Shell, Equinor plans to have this one operational by 2023. Eventually, it will scale up the number of ships to gather CO2 from ports around Europe. The company is also working on CCUS projects in the UK and is searching for viable saline aquifers and depleted oil and gas fields as new places for storage.

“CCUS is key to achieving large volumes of hydrogen,” said Rognø.

Like Equinor, Baker Hughes is pursuing CCUS. It has invested in solvent-based post combustion carbon capture technology. A cyclic and continuous absorption/desorption process uses an aqueous solvent. In the absorber, the CO2-rich flue gas is treated by a CO2-lean solvent that can capture CO2. The solvent is then discharged from the absorber, and the solvent is regenerated in the stripper for reuse. A chilled ammonia process helps prevent solvent degradation and means less energy is needed in compression. It is being tested currently at TCM Equinor.

Baker Hughes acquired this technology via its purchase of Compact Carbon Capture (3C), a company specializing in carbon capture. 3C’s technology differs from traditional solvent-based solutions by using rotating beds instead of static columns to distribute solvents in a modularized format. The rotating bed technology is said to enhance the carbon capture process while having a 75% smaller footprint and lowering capital expenditures.

Baker Hughes has more than 70 gas turbines worldwide operating with a natural gas/hydrogen blend, including the NovaLT gas turbine product family which can start-up and burn gas blends up to 100% hydrogen. An ongoing project has the goal of finding the ideal hydrogen concentration, one that would not require a major gas turbine retrofit. Currently, an upgrade can be done on a 7EA gas turbine. This enables it to run on 25% to 30% hydrogen with a minor impact on footprint and output. The major adjustment is that the DLN fuel gas skid is moved outside the GT package.

 Turbomachinery will be needed in all areas of the hydrogen value chain.[/caption]

Powered by a blend of up to 10% hydrogen, a Baker Hughes NovaLT12 turbine will be installed at Snam’s gas compressor station in Istrana, Italy. 70% of Snam’s pipelines are already built with “hydrogen ready” pipes. The unit recently completed testing and will be installed later this year 2021. By blending 10% hydrogen into the total annual gas capacity transported by Snam, it is estimated seven billion cubic meters of hydrogen could be introduced into the network each year.

“Hydrogen can be cost competitive within five years,” said Marco Alverà, CEO of SNAM.

He estimates it will cost around $2 per kg to produce hydrogen gas. But it will cost a lot more to get it into someone’s truck. More like $9, he said. ■

Turbomachinery International has been a regular visitor to the Baker Hughes Annual Meeting (AM) in Florence, Italy. But this year, a virtual format had to suffice.









The bright future for natural gas

Rotating parts and components such as impellers and blade rows could be in resonance with any excitations generated by turbomachinery. Resonances for the first and second natural frequencies can be dangerous. Generally, there could be numerous cases of resonance. The second natural frequency of a rotating component, in one example, proved to be almost exactly an integer multiple of the first natural frequency. This led to an excitation and operational problems. Fluid induced vibration, oscillatory changes of fluid pressure, and turbulent flow (vortex formation) might also cause high vibration or even failure.

Fatigue, too, is often a root cause in failures of rotating parts. Individual stress amplitudes should be analyzed to ensure associated components will not fail due to different forms of fatigue such as high-cycle fatigue (HCF) and low-cycle fatigue (LCF).

For shaft failures, the reasons behind failures can be broken down into:

Mechanical: such as overhung/bending/torsional/axial load.

Residual: manufacturing/repair processes.

Thermal: temperature gradients, rotor bowing.

Environmental: corrosion, moisture, erosion, wear, cavitation.

Before the root cause of a shaft failure can be determined, it is necessary to understand shaft loadings and stresses. Ability to characterize the microstructure and surface topology of a failed shaft is critical. Visual inspection, optical scanning, electron microscopes, and metallurgical analysis can be used, for example.

Many failures can be diagnosed using a fundamental knowledge of shaft failure causes and visual inspections. This can later be confirmed through a metallurgical laboratory or other methods.

Based on case studies from several plants, the main reasons for shaft failure are: corrosion (35%), fatigue (32%), brittle fracture (16%), overload (11%), and creep/wear/erosion/abrasion (6%). Some studies found fatigue responsible for more than 50% of failures. Therefore, pay attention to surface discontinuities such as keyways, steps, shoulders, collars, threads, holes, snap ring grooves, and shaft damage or flaws.

Keyway regions are often problematic. Keyways are commonly used to secure rotating components, rotor cores, and couplings to the shaft. The take-off end (or drive/driven end) is where highest shaft loading occurs. Fatigue cracks usually start in the fillets or roots. A keyway that ends with sharp step(s) has higher stress concentration than one using a sled-runner type. In the case of heavy shaft loading, cracks frequently emanate from sharp steps. Avoid connections using keys if possible. If it can’t be avoided, obtain sufficient edge radius.

Fatigue-related failures usually follow the weakest-link theory: Fatigue leads to an initial crack on the surface; cracks propagate until the shaft cross-section is too weak to carry the load; and finally, a sudden fracture occurs.

Remember that residual stresses or initial defects/deflections could be independent of external loadings. There are manufacturing or repair processes that can affect residual stresses, initial deflections, and defects. These include: drawing, bending, straightening, machining, grinding, surface rolling, shot blasting, and polishing. They can produce residual stresses and defects by plastic deformation. And thermal processes such as hot rolling, welding, torch cutting, and heat treating can lead to problems.

Finally, shaft fretting can cause serious damage. Typical locations are points on the shaft where a press or slip fit exists. The presence of rust between mating surfaces helps confirm fretting took place due to movement between mating parts. Once fretting occurs, the shaft can become sensitive to fatigue cracking. Shaft vibration can worsen this situation. ■

There are many reasons for turbomachinery problems and failures. Resonance, for example, is often overlooked.

Tip: Don't overlook resonance in turbomachinery failures

The first question is: What data do we actually need besides the obvious such as pressures and temperatures at the compressor suction and discharge, and the flow? Things like the gas composition, the compressor speed, and ambient conditions are also required. Gas composition is often neglected because it requires extra effort to sample gas and send it to the lab or at least have a calibrated on-line gas chromatograph. It obviously must be the gas composition at the time of the test, not some mixture sampled weeks ago. Even in pipelines, gas compositions changes frequently.

Test data is subject to uncertainties. As well as accuracy of the end-device, this includes the entire measurement chain, instrument location, number of instruments, and process stability. There can be systematic or random uncertainties. In field performance tests, systematic uncertainties dominates; averaging a lot of data does not automatically help. Many tests have uncertainties exceeding several percentage points, especially for low pressure ratio compressors. In these cases, the test must be done with accurate and calibrated instrumentation.

Unsteady operating or process conditions are particularly problematic for the accuracy of test data. It is near impossible to correct for unsteady operating conditions from process changes or ambient conditions. Most test codes were written for factory testing and provide allowable limits for unsteadiness. But these are often not easily achievable in a field test. A good test plan will include steps to ensure steady operating conditions for the duration of the test.

"It is possible to obtain valuable and accurate test data in the field. But it requires planning, preparation, careful testing, and the understanding of fundamental principles."

If a test point is to be compared with a compressor map to determine if the measured efficiency meets manufacturer predictions, we need to know compressor head, speed, and flow. These measured values each have associated uncertainties. Compressor speed is usually measured accurately whereas flow and head can have significant uncertainties, depending on instrumentation, operation, and process conditions. Note that flow measurement impacts the comparison of the measured and the predicted efficiency – if the flow is measured incorrectly, the measured efficiency is compared to the wrong efficiency on the compressor map.

It is often a good idea to plan for redundant measurement. For example, one can determine a compressor’s absorbed power from both thermodynamic measurements on the compressor and from data gathered from the driver. For a gas turbine driver, the engine fuel consumption, data from the engine factory test, or (if installed) from a shaft torque meter measurement, allow for direct comparison of driver and driven power to check if the measured compressor performance is reasonable. For electric motor drivers, the required power can usually be obtained from current measurements at the motor terminals. However, gearbox losses and motor efficiencies must be considered.

There are two reasons to test a compressor: to verify performance or to use measurements to verify the power from the driver. For the latter, we don’t need to test compressor efficiency. We only need compressor absorbed power. This also means that it’s not important where on the map we operate as long as the compressor absorbs the driver’s full load. Accuracy of power measurement depends on many variables.

Just to be clear and for all who are now worried about their test results based on this article’s title: It is possible to obtain valuable and accurate test data in the field. But it requires planning, preparation, careful testing, and the understanding of fundamental principles. ■

Many of us have to verify compressor and driver performance in the field. We do a test, read the data, and convert it to flow, head, and some other parameters. Voila, we have done a valid test and we believe our data. Not so fast!

My test is accurate

 Rui Fernandes, General Manager, Shaft Current Solutions (dba Sohre Turbomachinery), discusses the problems created by shaft current and electrical discharges, as well as how to resolve them.[/caption]

Shaft Current Solutions (dba Sohre Turbomachinery) manufactures equipment and provides consulting services, relating to the protection of rotating equipment from electrical discharges. They sell grounding brushes, design shaft grounding/earthing systems, and help diagnose the cause of shaft current problems.

What are some of the problems that can result from shaft currents and electrical discharge?

The most common problem is pitting and deterioration of the interface surfaces between components such as bearings, journals, seals, and gears. Depending on the intensity of the electrical discharges, the damage can be gradual, slowly eroding bearing surfaces and requiring the replacement/refurbishment of components during scheduled services; or it can cause extensive damage and force the machine offline in just a few hours of operation.

What misconceptions might operators have about shaft current?

The biggest misconceptions are that installing a grounding brush assembly will address the problem, and that one should not use more than one brush in a machine train. Although installing grounding brushes is a good first step, an effective system must take into consideration the grounding circuit, how all the components of a machine train are electrically connected, operational requirements, and safety of the grounding system. We have not found it to be true that installing more than one grounding brush on a machine train can lead to “recirculating currents.” However, we found on several occasions that grounding brushes can be too far from the components they are meant to protect.

What might happen if you ignore such issues?

Depending on the source of the electrical discharge, ignoring the issue can lead to reduced component life and unscheduled outages. In some cases, magnetized components can produce high enough current levels to force machines offline. There were some extreme cases in which the levels of magnetism were intensified by the current generated (known as self-excitation), which led to rapid and catastrophic machine failure.

What are the various ways to deal with this issue?

There are three primary approaches to address the problem: eliminate the source of the electrical current, change the properties of lubricating fluids to eliminate charge accumulation, or dissipate excess electric charges to ground (earth) using sliding contacts. The elimination of electrical sources is ideal, and we work with our customers to do so whenever this is feasible, as is the case with magnetized components. In our experience, that is the most dangerous source of electrical currents. However, the generation of electrical charges is inherent in the flow of fluids and those we cannot fully eliminate. There have been several attempts at changing the conductivity of lubricating fluids to prevent the accumulation of charges. However, our anecdotal experience is that this seems to change the discharge voltage threshold rather than eliminate electrical discharges. Lastly, the approach that is used by us and others, is the use of sliding contacts to dissipate accumulated charges.

Unlike other applications of sliding electrical contacts, such as motors and generators, where emphasis is placed on carrying large and known current levels, shaft currents require materials that can carry a relatively low level of energy at unpredictable voltage levels for long periods of time with low levels of maintenance. Sohre brushes are designed from the ground up for this single purpose. They are part of a complete system focused on dissipating shaft currents. From bristle materials (silver, gold, etc.), to electrical grounding/earthing circuit, everything is specifically developed for the task of protecting machinery from stray shaft currents. Other shaft grounding/earthing brushes do not address the whole circuit from the brush to ground/earth and make use of repurposed (less expensive) materials such as carbon and copper. This can compromise long-term reliability, maintenance, and effectiveness.

We work with our customers to design shaft grounding/earthing solutions for the complete machine train. The solution addresses a variety of factors such as: operating environment, safety, run cycles, and maintenance intervals. This can range from providing the components to a comprehensive solution involving installation, maintenance procedures, and baseline measurements. Sohre brushes are available as installed options by most turbomachinery OEMs, and as retrofit.

Our preferred approach to install a shaft grounding/earthing system on a machine train is to follow these steps:

1) Take baseline shaft voltage measurements of the running machine to understand the situation

2) Design the system to customer requirements

3) Work with the customer to install and review the system

4) Measure shaft voltage after the installation and develop a maintenance plan

There has been an increase in the number of brushes we have installed in potentially explosive environments. This is challenging. But with the right steps, we have been able to install effective shaft grounding/earthing systems in problematic environments. ■

Q&A: Resolving shaft currents and electrical discharges

The U.S is in second place globally in installed wind capacity. Solar is catching up rapidly. According to Industrial Info Resources, 80% of the 214 GW of new generation planned over the next five years will be renewables.

But there is a big problem. The transmission grid can’t cope with the influx. Wind and solar resources are often far from load centers. Power lines don’t have enough capacity to carry all the energy from those facilities to markets. Efforts to build high voltage superhighways face enormous challenges. Federal Regulatory Energy Commission (FERC), as well as state and local rules, make it difficult to gain the right-of-way approvals, licenses, and permissions. Anyone able to tackle that labyrinth faces stiff opposition from almost every community along the route. That’s why some estimate it’s ten times more expensive to build infrastructure in the U.S. compared to other parts of the world.

Meanwhile, states play one-upmanship when it comes to Renewable Portfolio Standards (RPS). One says it will reach 30% renewables by 2025, another says 50% by 2030, and someone else ups the ante with a target of 100% by 2040. These lofty goals may make politicians feel warm and fuzzy, and garner votes, but they are steeped in unreality. They have zero chance of success unless they face up to these challenges:

The need for a massive overhaul of the U.S. transmission network with new high voltage direct current (HVDC) lines, as well as upgrading or replacing the aging transmission lines currently in place.

The lack of financial incentives for utilities and generators to provide ancillary services such as synchronous condensing, spinning reserve, and energy storage.

U.S. power producers hamstrung by legislation and restrictions that either kill the profitability of power plants, burden them with almost unattainable limits for emissions, or shove their generation capacity to the back of the queue behind wind and solar.

What appears to be happening is that the desire to see more renewables on the grid is being done in such a way as to deny gas turbines any role at all. A recent example comes from the blackouts suffered in 

. Yes, there were obvious failures to outfit wind turbines, power plants, and gas processing stations with de-icing technology and other winterization safeguards. But another factor contributing to the debacle concerns changes initiated by the Clean Air Act. Some pipeline compressors were switched from running on natural gas to running on grid-based electricity. When the blackouts hit, lack of electricity stalled the compressors. Gas could no longer be pumped to consumers and power plants.

Diversity of generation, then, is necessary for a reliable grid. Fossil resources are going to be needed for the foreseeable future. Rather than denying this fact, the obvious answer is to steadily channel generation towards a largely renewable future that is ably supported by the lowest emitting generation assets available – natural gas-fired generation sited close to load centers. Perhaps one day, hydrogen power and battery storage will come of age. But don’t count on it anytime soon.

The American transmission network consists of hundreds of thousands of miles of high-voltage and millions of miles of low-voltage power lines. They connect thousands of power plants to hundreds of millions of electricity consumers. However, many of these assets date back to the Jurassic era. The PJM Interconnection serving 13 states in the Eastern U.S. has two thirds of its transmission assets more than 40 years old. Over a third have passed the half-century mark and more than a few local lines are approaching 90 years of age.

As well as aging lines, the U.S. grid does not operate as a unified system. PJM is part of the Eastern Interconnect. There are also the Western Interconnect and the Electric Reliability Council of Texas (ERCOT) networks with each operating independently. There is no synchronization of power flow between them. In other words, AC power from one has to be converted to DC, transferred to the neighboring interconnection and converted back to AC.

Without a major build out of transmission, renewable assets have nowhere to go.

Now factor in that most of the wind and solar resources are far from load centers. 15 states between the Rockies and the Mississippi River account for 88% of the nation’s wind potential and 56% of solar potential, yet that same region will only need 30% of its expected 2050 electricity production.

Further, offshore wind power is about to go into hyperdrive in the Eastern U.S. 29 GW of lease areas along are open for development. New York and New Jersey are each planning about 2.5 GW of offshore resources. And they are boldly going where no renewable portfolio standard (RPS) has dared to go before. New York legislated a 70% RPS by 2030 and 100% by 2040; Connecticut targets 100% by 2040; New Jersey and Maryland want 50% by 2030; Maine wants 100% clean energy by 2050. The current eastern grid could accommodate less than a quarter of the 29 GW of offshore wind that might come online soon – and that doesn’t take into account the many other wind and solar resources that are planned.

Without a major build out of transmission, these renewable assets have nowhere to go. Plenty of plans are afoot, but all face obstacles. One example is the Western Interconnect’s proposed high voltage lines from Wyoming to the Southwest. The TransWest Express Transmission Project could provide 3 GW of transmission capacity to deliver Wyoming wind to Arizona, Nevada, and California. 730 miles and 500 kV of transmission infrastructure is battling its way through a patchwork of federal, state, local, and native land jurisdictions, never mind mountainous and desert terrain. Every few miles sees another showdown with well-organized local groups intent on stopping infrastructure projects around their communities.

Currently there are more than 100,000 miles of lines operating at 345 kV or greater in the U.S. But more are needed. Transmitting electrical energy at higher voltages reduces line losses so more of the power transmitted reaches its destination. HVDC line losses are 3.5% per 1000 km, compared to 6.7% or more for AC lines at similar voltage levels. There are further losses at converter stations of up to 1% of delivered power. And HVDC reduces the transmission footprint. A 765 kV line on a 200-foot-wide right-of-way carries the same amount of power as 15 x 138 kV lines requiring a width of 1,500 feet: Fewer permitting headaches, but it’s anyone’s guess if local communities in their path will see it that way.

But HVDC lines are as vital as they are expensive. Cheaper options include reconductoring existing lines to carry higher transfer capacities. Flow controllers can also be used to route power to less congested parts of the network.

“These are relatively cheap and easy to install, and they can be moved around as the need arises,” said Carl Zichella, recently retired from the Western Energy Imbalance Market (EIM) and now an energy consultant. “Flow controllers can’t be used everywhere but are especially useful in more heavily populated areas where reconductoring or building a new line will be especially challenging.”

In addition, substations can be upgraded to the latest standards. Adding capacitor banks and turning the generators of idle turbines into synchronous condensers can boost the transfer capacity of transmission lines and help replace lost grid inertia when power generation equipment is retired, and renewal power generation is installed in its place. Various assets, then, can be called upon to strengthen the security and reliability of the grid.

All of this must be backed up a more flexible grid of interconnected power nodes such as rooftop solar panels, electric vehicle batteries, and microgrids. This should include buildings, factories and businesses generating their own power independent of the grid and feeding current back into the grid.

Grid monitoring advances can also help. Dynamic line rating (DLR) and ambient line rating technologies calculate line rating variations (tension levels) and temperatures shifts on transmission lines to boost efficiency.

Many of these are elements of the evolving smart grid. Smart sensors are being introduced that feed data via Internet of Things (IoT) networks into analytics engines connected to system monitors. Phasor measurement units, for example, are one type of sensor used to improve system awareness. Instead of providing measurement of system conditions every two to four seconds, the latest sensors can ping the system 30 times a second.

Multiple technical elements, therefore, must dovetail together. There is no silver bullet.

Market instruments can play an important part. A good example is the Western Energy Imbalance Market (EIM). It stimulates utilization of existing power rather than grid build out. Participants donate the rights to excess transmission to facilitate trades in the market. Differences between forecasts and demand are swapped around 15- and five-minute markets. The EIM helps to settle imbalances and reduce curtailments of wind and solar resources. Since its inception in 2014, the EIM has provided participating entities with more than $650 million in value. Major regional players have either joined or announced their intent to do so, including Los Angeles Department of Water and Power (LADWP), Arizona-based Salt River Project, Seattle City Light, and the Bonneville Power Administration (BPA).

“This easing of concerns about a regional market will inexorably lead to transmission expansion to capture the geographic diversity and capacity value of resources that could be traded in the larger market,” said Zichella.

Spinning reserve is another tool that can be used to stimulate U.S. markets. PJM was an early pioneer. When requested, generators get paid to have their generation capacity available online. During this period, the plant is rewarded for having that power on standby, and able to be on the grid within ten minutes whenever needed. This kind of service will become even more vital as more renewables flood onto the grid. If wind or solar resources suddenly become unavailable or there are unscheduled outages elsewhere, it makes sense to have plenty of power on standby. Control software brings the turbine rapidly up to near-synchronous speed in order to engage or disengage the turbine via a synchro-self-shifting clutch. When disengaged, the generator continues to spin (thus, ancillary services known as spinning reserve). The revenues earned from spinning reserve paid for the clutch within a few years.

“Just as the Eisenhower interstate highway system unleashed U.S. manufacturing in the 20th Century, a strong macro grid will deliver massive economic and public health benefits for all Americans in the 21st Century,” said Rob Gramlich, Executive Director of Americans for a Clean Energy Grid.

Simple cycle gas turbine peakers around the U.S. as well as some combined cycle facilities are suffering badly due to their power resources being parked at the back of the line. There are even efforts to decommission some. Favorable spinning reserve cost structures can make it economical to keep aging turbines online and make poorly utilized plants profitable.

Inertia and reactive power are further reasons to incentivize the existing turbine network to remain online. Real power delivers energy from the generation source to the load. It is measured in volts, amps and watts. Reactive power does no actual work and is measured in volt amperes reactive (VAR). It is the form of electricity which creates or is stored in the magnetic field surrounding a piece of equipment. It can be positive or negative. The amount of current in a device impacts the amount of reactive power needed. If you double the amount of power being consumed in an area, the reactive power consumed quadruples. Long transmission lines operating at heavy loads consume VARs. This can lead to conductor heating and voltages falling.

Various kinds of reactive power devices must be placed near the load to correct the power factor and avoid equipment damage and system instability. Capacitor banks, static VAR compensators, and synchronous condensers are commonly used. The latter are the most flexible. Some are sophisticated electrical systems that add or subtract VARs where required. Modern inverters are also becoming available that help wind and solar generators to provide sufficient reactive power.

But investment levels can be kept low by modifying decommissioned or rarely utilized turbines into synchronous condensers. After all, more than 50% of capacity in California, Texas, Florida, New England and the Southwest currently comes from natural gas-fired generation. 2018 and 2019 saw natural gas as the source of the highest amount of generation in the U.S. Many of those assets will gradually be replaced by renewable resources. Even if these gas or steam turbines become rarely or no longer needed to provide power, retrofitting them with a clutch can turn them from a unit producing power to one that feeds VARs to the grid, improving power factor and increasing grid stability.

Energy storage is another way to enable the transmission systems to be more robust and secure. Battery storage is being widely promoted and implemented. But it must be augmented by bulk energy storage on a grid scale. Pumped hydro storage is one approach that is widely used where there is the geographic capability. Compressed air energy storage (CAES) is another technology that can provide large bulk energy storage and compliment renewable generation. Also, systems such as Liquid Air Energy Storage in combination with existing combined cycle plants and renewable generation have the potential to offer distributed energy storage at rates competitive with battery storage.

There is more than 100 GW of U.S wind capacity right now. About half of that materialized due to improved transmission that could transmit power to load centers in Texas and the Midwest. Building a better grid is a vital necessity. Yet the volume of 500 kV lines being built right now is almost non-existent.

“Cost recovery and benefits assessment for new long distance lines (across several planning entities or across interconnections) have been complicated by utilities and RTO planners focused solely on local reliability needs, as opposed to major infrastructure improvements to move large amounts of renewable power from remote areas to load centers,” said Zichella.

Incentives are the mechanism that propelled wind and solar to their current heights. Without massive investment in the grid, wind and solar capacity are going to bottleneck. Incentivizing transmission build-out, transmission upgrades, smart grid technologies, spinning reserve, synchronous condensing, and other ancillary services could foster conditions that lead to the establishment of transmission superhighways crisscrossing the nation, like the freeway network that appeared in the fifties and sixties.

“Just as the Eisenhower interstate highway system unleashed U.S. manufacturing in the 20th Century, a strong macro grid will deliver massive economic and public health benefits for all Americans in the 21st Century,” said Rob Gramlich, Executive Director of Americans for a Clean Energy Grid. 

 By retrofitting clutches like this onto aging or idle turbine generators, greater grid stability and voltage control can be achieved at relatively low cost. (Courtesy of SSS Clutch)[/caption]

A stable renewable-rich grid needs transmission build-out, and incentivized ancillary services.








Solving U.S. Transmission

The latest Asia Turbomachinery & Pump Symposium (ATPS) aired virtually in February of 2021, a sister show to the Turbomachinery & Pump Symposium, organized by Texas A&M’s Turbomachinery Laboratory.

A jam-packed schedule touched on topics such as centrifugal compressors, gas turbine (GT) performance, combustion, additive manufacturing, turbomachinery in refineries, and operations & maintenance.

Ben Gunn and Rainer Kurz, both Managers at Solar Turbines, and Klaus Brun, Director at Elliott Group held a session on applications for centrifugal compressors, drivers, and gas turbines in the oil and gas industries. They discussed the types of equipment favored for use cases such as gas and oil wells, pipelines, storage, gas gathering and export compression, enhanced oil recovery, recycle compression, and refrigeration. As well as typical operating requirements they touched upon process behavior, dynamic behavior, and how to handle long and short-term process changes.

The speakers also discussed rotordynamics and defined limits for speed, pressure, and the number of impellers. They offered examples of driver performance characteristics to consider in gas turbine operation, including power as function of ambient conditions and the power output at various output speeds.

Kurz and Brunn were later joined by Bernhard Winkelmann, Director of Technology and Gas Turbine New Product Development at Solar Turbines in a gas turbine tutorial. They laid out the ideal operating conditions for gas turbines, real-world applications, and the controls and condition monitoring systems required to ensure safe and efficient operation.

"Site elevation, relative humidity, ambient temperatures, drive speed, fuel type, and load conditions must all be considered in gas turbine operation."

Site elevation, relative humidity, ambient temperatures, drive speed, fuel type, and load conditions must all be considered in gas turbine operation. Changes in ambient temperature impact full-load power and heat rate, as well as part-load performance and optimum power turbine speed. In addition, they mentioned the peculiarities of single-shaft and dual-shaft machines, as well as methods used to collect performance data for trending and comparison purposes.

Speakers from Solar Turbines presented at a later session on compressor station optimization. They highlighted the challenges involved in the interaction of multiple machines in a compressor station, the multiple services running within a station, and dealing with multiple stations along a pipeline. Optimization efforts centered upon fuel consumption, maximum throughput, minimum emissions, and lengthening maintenance intervals. To gain optimal performance, interactions of multiple machines should be considered on a component, station and system level, said Kurz.

Many new pipelines, in turns out, start out with 50% capacity or less and grow to full capacity over the years. Speakers helped attendees understand the various growth scenarios that might increase pipeline capacity and their repercussions. Single-stage compressors, for example, might have to be replaced with two-stage compressors. Alternatively, compressors may have to be installed in series to meet higher-

The show must go on: Takeaways from 2021 ATPS

 Cover image for our March/April 2021 issue.[/caption]

Perhaps it’s a sign that good times lie ahead. Suddenly, a series of virtual shows took place around the world. Though far from an adequate replacement for the real thing, they at least were well produced, well attended, and outlined a positive future for the industry.

The Baker Hughes Annual Meeting (AM) began with fighting talk from the company CEO about the future. “Renewables will not scale fast enough to displace energy demand in the coming years so we must learn to consume hydrocarbons in a better way,” said Lorenzo Simonelli. “Natural gas should serve as both a transition and a destination fuel; its efficiency is compelling.”

Bob Dudley, Chair of the Oil & Gas Climate Initiative and former CEO of BP, agrees. He sees no credible scenario for an energy future without natural gas.

And then came the Russians to ramp up the rhetoric. “Overly ambitious emissions goals foster regulations that are pushing immature solutions and exclude technologies that are efficient,” said Elena Burmistrova of Gazprom.

Mark Gyetvay of Novatek called for oil & gas to unite as one voice to combat misinformation. “Let’s not be apologetic about our industry as we are lifting millions out of poverty.”

You can read what they and other oil & gas executives had to say in our report on the AM. Additionally, that article includes plenty of news about liquefied natural gas (LNG), carbon capture, utilization, and storage (CCUS), and hydrogen generation, as well as an exclusive interview with Rod Christie, President and CEO, Turbomachinery and Process Solutions at Baker Hughes. When pressed about the reality of actual hydrogen turbomachinery sales, he said such projects will happen with greater frequency over the next two or three years. But they will be limited to specific applications and geographies.

The new issue also contains a report on the Asia Turbomachinery & Pump Symposium (ATPS) as well as one from CERAweek in Texas. With the February 2021 large-scale blackouts in Texas, that show largely focused on those grid disruptions, their causes, and various remedies. You can read about that in our CERAweek show report, as well as in a feature on the Texas grid.

As it happened, we have been working on a special report on the U.S. transmission grid for many months. Our feature explains the architecture of the grid, its shortcomings, and how turbomachinery can help shore it up. It’s a shame that so much stimulus money doled out by either administration has failed to comprehensively address crumbling road networks and a rickety grid. Both would directly contribute to a rapid recovery from the events of the past year.

Our cover story showcases the talents and services of the turbomachinery aftermarket. This industry is rich in resources to troubleshoot any kind of turbine, compressor, or auxiliary equipment. Whether through inspection, monitoring, repairs, or upgrades, an army of maintenance & repair professionals keep the show on the road. As well as traditional services, our cover feature includes trends such as greater use of remote monitoring and deployment of drones for inspection.

What else do we have? An article on hot gas path upgrades, a vendor spotlight on Chentronics featuring its ignition and flame detection technology, a Q and A with Sohre about shaft currents and electric discharge, a Myth Busters column on the accuracy of testing, a Turbo Tips review of turbomachinery failures, and plenty of news and new products as usual.

Hoping to see you at a live event some time soon. ■

No Apologies

On Wednesday, Feb 10, 2021, it became apparent that a polar vortex (formerly known as winter) storm approaching Texas would likely cause plenty of pain. The Electric Reliability Council of Texas (ERCOT) issued an advisory warning to all generators to prepare for extended freezing weather. On Friday, the governor of Texas declared a state of emergency for all 254 counties. Spot prices for natural gas climbed as did the wholesale price of electricity.

As temperatures continued to drop on Saturday and Sunday, demand for natural gas and electricity soared. Freezing problems began to affect production at wind farms as well as natural gas wells and processing plants handling wet gas. The first trip of a thermal plant occurred on Saturday afternoon. By Sunday night, 14 Feb, electricity demand exceeded the previous all-time winter record of 65,915 mw set on 18 Jan 2018.

Generating units of all types (gas, coal, renewables, nuclear) began falling out of service on Saturday. At 10:30 PM Sunday, one of two nuclear reactors located near Corpus Christi tripped offline, a 1,200 MW forced outage. ERCOT initiated rolling blackouts to prevent a blackout of the entire Texan grid. Should a complete grid collapse occur, it can cause extensive damage to transmission lines and connected equipment. That would add weeks or even months to arrive at a full recovery. The decisive action to quickly implement load shedding avoided such a grid collapse with only a few minutes to spare.

During the next three days, supply did not come close to meeting demand. The shortfall exceeded 20,000 MW at times. By Thursday, some of the forced outages at generation plants had been resolved. Higher temperatures enabled the rolling blackouts to be shortened or eliminated. Power had been fully restored to most customers by Friday 19 Feb except a few isolated areas where had damaged distribution lines.

The Texas grid does not fall under the authority of the Federal Energy Regulatory Commission. Most Texans like it that way. Feds in Washington D.C. don’t. This wiring diagram was created during World War II as protection from any event that could possibly take down the electric grid of the entire country.

After the storm, some floated the notion that if ERCOT had been electrically connected to the Eastern and Western grids, power could have been imported to avoid blackouts. This is false. The regions of the grids adjacent to ERCOT were also affected by the storm. They incurred shortages of natural gas and rolling blackouts. There would have been no power available to import.

Fossil fuels are a big part of the Texas economy. For 20 years, they that have felt the squeeze as renewable energy has grown to generate approximately 25% of the electricity in the state. So it would be convenient for fossil fuel advocates to blame the problem on the highly diminished output of wind and solar generation during the storm. Indeed, wind turbines were shut down due to freezing and solar panels contribution fell to almost nothing due to cloudy daytime conditions along with snow and ice. But there is plenty of blame to go around, too, for thermal plants including gas, coal and nuclear that produce the other 77% of the power.

The facts are that the thermal fleet was not properly winterized. Why not? One possible explanation is that during 2020, the winterization inspections called for by ERCOT were done virtually instead of in person. Another possible explanation is that the process of winterizing a thermal plant causes some reduction in performance during the summer months. Most generation in Texas is privately owned with financial results normally pegged to performance during the hottest days in June-Sept. Therefore, there is a natural bias for asset managers to be more highly focused on summer instead of winter.

A brief word about wind turbines and freezing. The 4 big wind OEMs are Siemens, GE, Mitsubishi and Vestas. Each offers a “cold weather package” as an option for purchasers of wind turbines. The blades can be made out of special materials, the gear boxes are better insulated, and a higher grade of lubricants is utilized. But this can increase the capital cost of the wind turbine by 10-15%. Given the relatively warm climate of Texas, most wind farm developers decided not to purchase the cold weather package. Keep in mind that during normal winter conditions, power prices in Texas are low. The economic decision to use the low-cost design generally made sense. But don’t be surprised if there are a lot of cold weather retrofit kits installed on wind turbines during the spring and fall of 2021.

In summary, politicians will hunt for a scapegoat to serve their narrative. The ERCOT grid works well with renewable energy producing about 25% of the electricity. But increasing the renewable component much further may not be practical. Bulk storage of electricity via batteries is still uneconomical, without huge subsidy, when compared to storage of fuel in a coal pile or gas/oil in a tank at the site of a thermal plant. The state of Texas has added approximately 4 million residents since 2010. It seems that more generation of all types will be needed with greater attention given to winter readiness.

The ERCOT grid in Texas works well with renewable energy. But increasing the volume of renewables further may not be practical. More generation of all types and greater attention to winter readiness is needed. 

March/April 2021