 IGV blades at the inlet of a compressor pre-swirl gas flow entering the impeller, reducing the amount of work needed from the main driver.[/caption]

The transportation industry is responsible for 70% of global oil demand. Air travel alone consumes approximately 8 million barrels per day (MBPD) of oil feedstocks. During the last few months, refineries around the globe have operated at significantly reduced capacities. As the transportation industry (and the world at large) 

, process conditions in refineries will change yet again. These dynamics are prompting plant operators to evaluate 

 and their control systems to ensure they operate at peak efficiency.

 compressors used in refineries can last for 30 years or longer. Re-vamps, re-rates and upgrades to compressor components such as motors, impellers, seals, bearings and control systems extend operating life. They can also enhance performance characteristics to meet new operating requirements.

An upgrade that can boost efficiency and help refineries lower energy costs is the addition of Inlet Guide Vanes (IGVs). IGVs are a series of blades arranged at the inlet of a centrifugal compressor. Pneumatically driven IGVs pre-swirl the gas flow entering the impeller. As a result, turndown is increased while reducing the amount of work needed from the main driver.

 IGVs retrofitted onto an existing Sundyne multi-stage compressor.[/caption]

IGVs are especially valuable when process conditions change. When plants operate at lower capacities, they move less gas through their compressors. This alters the velocity vectors of the gas passing through the impeller of the compressors. Impellers have fixed blade angles; any change in the gas speed vector relative to the impeller blade speed vector can trigger internal stalls and begin surge conditions. An anti-surge system will protect the unit. However, opening the anti-surge valve boosts electrical or water consumption, as well as energy costs.

IGVs help to smooth out surge conditions. During turndown, the compressor control system rotates the IGV to pre-swirl the gas and adjusts the flow to fit the fixed impeller inlet blade angle. Adjustment of the internal geometry keeps the compressor within its best operating range and lowers the surge threshold. Like the wing of an airplane, each vane is designed with an airfoil cross-section. This minimizes aerodynamic losses in the full open position (vanes positioned parallel to the rotational axis). The inlet guide vanes can modulate from fully opened to fully closed positions to provide a variable degree of pre-swirl.

IGVs have long been considered a requirement for high-flow applications such as reactor feeds, gas boosting for power generation, or overhead boost in gas treatments for LNG applications. They are now standard on new equipment. But given the 20- to 30-year lifespan of centrifugal compressors, there are thousands of machines running in refineries that could implement this upgrade.

Such installations are straightforward: an IGV assembly replaces the inlet flanges, using the same bolting and interface. It does not require disconnection of any piping.

Refineries in the U.S., France, Singapore and Kazakhstan recently added IGVs to their compressors. As part of the process, each plant audited its operating conditions and compared past trends to current requirements. They made standard adjustments to boost efficiency and retrofit capacity. Additionally, they performed basic maintenance on the bearings and seals. The combination of regular maintenance and the upgrade enabled each plant to enhance turndown by up to 30% and achieve an average of 10% power savings for less than 7% of the cost of a new machine. This was accomplished in a few days during a standard turnaround without the need for hot work permits, welding or concrete work, or crane operation. In addition to boosting efficiency, IGV upgrades minimize stress on the entire system, which helps to extend the mean time between maintenance intervals. ■

Donald de Regnier III is Aftermarket Product Manager at Sundyne, a manufacturer of compressors since 1965 with thousands of deployments in refineries and petrochemical plants. Sundyne’s aftermarket services group can retrofit IGVs onto existing Sundyne multi-stage compressors. For more information, please visit www.sundyne.com or email Donald.deRegnier@sundyne.com.

Articles

Centrifugal compressor upgrade: Boosting plant efficiency by adding inlet guide vanes to aging compressors

The cold available at an LNG import regasification terminal is a resource that can be harnessed to produce cheap electric power. At most terminals, this resource is wasted. At the few sites that attempt to utilize it, the full potential to produce low cost power at minimum investment is not met. Utilizing this cold for inlet air cooling of the gas turbine of a combined cycle plant results in a power increase of only about 20% and a minor fuel rate improvement. For the same gas turbine applied to the new LNG Regasification Re-Condensing Power Cycle, the power increase is nearly 40% with a 15% decrease in the fuel rate. This cycle does not use steam, thus eliminating the problems associated with water treatment, condenser air leaks, deaerators and air ejectors corrosion. In addition, it has a small footprint and low dollar per MW cost.

 14 MW Atlas Copco expander turbine generator in an ORC plant.[/caption]

At most LNG import terminals, atmospheric pressure LNG is converted from a minus 260°F liquid to gas at pipeline pressure by first pumping cold LNG to high pressure. The cold, high-pressure liquid is then heated in a sea water heat exchanger to produce high-pressure natural gas, which is directed to the receiving pipeline. Most of the time, the available cold in the LNG is wasted by cooling sea water.

A few installations have incorporated processes that can use the cold such as a co-located air liquefaction plant. Other sites have integrated the gasification process with power generation, using some of this resource for gas turbine inlet air cooling in a combined cycle power plant to boost power output.

At a small number of facilities, LNG is pumped 500 to 1000 psi higher than the receiving pipeline pressure. It is heated with both sea water and a high-temperature heat source such as the exhaust from a gas turbine. The high-temperature, high-pressure natural gas stream is then expanded through a radial inflow turbine to produce power. The turbine discharge is directed to the receiving pipeline. This process has been combined with gas turbine inlet air cooling. Various Organic Rankine Cycle (ORC) cycles have been proposed for power generation integration with LNG regasification.

OnPower has devised a more efficient alternative. Its Re-Condensing Power Cycle is as follows: the LNG is pumped to a high pressure, heated and expanded to produce power. The LNG is first pumped to about 1500 to 2000 psi, heated in the vaporizing side of a vaporizing/condensing heat exchanger, superheated with gas turbine exhaust, expanded in a turbine to produce power, and then re-condensed back to LNG at a pressure of about 520 psi and -130°F in the condensing side of the heat exchanger. At that point, the 520 psi/-130°F LNG is pumped 500 to 1000 psi higher than pipeline pressure, heated, and expanded through a second radial inflow turbine to make additional power, with the discharge of the turbine directed to the pipeline. The cold in the -130°F stream can be used to make additional power via ORC. Residual cold from the ORC can also be used for gas turbine inlet air cooling. The radial inflow turbines involved in these processes can be combined on a single gearbox driving a single generator (See sidebar for a detailed explanation).

The results from this cycle are as follows; The fuel rate falls to between 4,500 to 5,500 BTU/KW-HR depending on the size and characteristics of the gas turbine, system design and other parameters; the power per mass of gasified LNG is more than 1000 kW per Kg/sec; sea cooling is reduced by up to 90%; as no steam is involved, there are no associated problems related to water treatment, corrosion or vacuum leaks; and the equipment has a smaller footprint compared to an equivalent combined cycle plant.

In addition to LNG import terminals, the system can be installed at large peak shaving LNG plants. Most of such plants operate for only a few hundred hours per year. When combined with the Re-Condensing Power Cycle, however, they can perhaps be utilized for thousands of hours per year. To do so, they would store gas as LNG at night using off-peak power and return it to the pipeline during the day while producing on-peak electric power.

In the Northeastern U.S., environmental concerns have restricted the building of sufficient pipelines to satisfy gas demand. A large peak-shaving LNG plant could reduce the need for new pipelines while providing peaking power.

Over-supply of natural gas makes it likely that natural gas and LNG prices will remain low for some time to come. This presents another potential application. LNG export terminals located in areas of high peak electric rates, using a portion of the produced LNG, could cheaply produce on-peak power as a revenue stream.

While this is a new process, the turbomachinery, heat exchangers and cryogenic pumps are well within proven manufacturing capabilities. Primary heat would typically come from gas turbine exhaust. However, it could also come from a gas engine. If ORC is added to the cycle, it can be sized to allow a second identical gas turbine to supply exhaust heat. Alternatively, the exhaust flow from a single gas turbine could be split between the LNG power cycle and ORC. There would be enough residual cold from the ORC to chill the inlet air of the gas turbine(s). Adding ORC to the Re-Condensing Power Cycle almost doubles power output with a nominal impact on fuel rate.

Two different temperature heat sources can be harnessed as part of this cycle such as the exhaust of a gas engine, and the jacket cooling water/turbocharger intercooler heat. With an intercooled gas turbine such as the GE LMS100, it is possible to use the exhaust heat and the compressor intercooling heat of the turbine.

• Atmospheric pressure LNG in reservoir 95 is pumped to about 1500 to 2000 PSI in pump 90

• The LNG is gasified in vaporizing/condensing heat exchanger 10, then heated in heat exchangers 20, 30, 50, and 40 to about 550°F.

• The heated high pressure gas produces power in turbine 65 as the fluid expands to a pressure of about 530 psi.

• The gas then flows through recuperator heat exchangers 50 and 60, returning heat to the cycle.

• The gas is directed to the condensing side of vaporizing/condensing heat exchanger 10 and re-condensed to an intermediate pressure LNG stream (about 520 psia/-130°F) against the cold upcoming high pressure LNG stream.

• The intermediate pressure LNG is pumped to 1500 to 2000 psi in pump 96 and heated and gasified in ORC condenser 70 and recuperator 60.

• The heated gasified stream is directed to turbine 66 where power is generated as the gas expands down to the receiving gas pipeline pressure.[/caption]

Sites with cheap off-peak electric power could utilize hot heat transfer fluid heated as the second heat source using electrical resistance heaters. Power could be stored for use at peak times.

Another potential storage opportunity concerns the use of liquid air as the initial cold liquid as part of a liquid air energy storage system. In this application, the second pumped, heated and gasified liquid air stream is expanded through a turbine all the way down to atmospheric pressure. Alternatively, a portion of the heated and gasified air can be directed to a gas turbine combustor to substantially increase the gas turbine power. The remaining portion can be expanded through a turbine to atmospheric pressure.

The following manufacturers are thanked for their support with equipment selections and performance data: Chart Industries (cryogenic heat exchangers), Atlas Copco Gas and Process (radial inflow expander turbines); Siemens Energy (gas turbine performance), Tulsa Heaters (gas turbine exhaust gas heat exchangers) and Nikkiso Cryo (cryogenic pumps).

Jim Berry is Technical Consultant at OnPower, a packager of turbomachinery, a designer and builder of control panels, and service provider for gas turbine generator sets. In addition to 200 gas turbine generator sets, OnPower’s experience encompasses supercritical CO2, solid oxide fuel cells, gas turbine packages for patrol boats, rocket fin coatings and generator sets to support fracking operations. For more information on OnPower’s patent pending Re-Condensing Power Cycle, visit onpower.com.

New concept for power integration with LNG

 This N-hance filtration system from AAF provides EPA E12 protection on BP’s Clair offshore platform. This level of filtration can be retrofitted onto existing small, high velocity intake filter housings.[/caption]

Air in the offshore environment contains numerous airborne particles that have the potential to harm gas turbines (GTs). These include water droplets, sea salt aerosols, salt in solution and sub-micron particulate, as well as industrial airborne particulates from burnt and unburnt hydrocarbons, drilling activities, mud burn and grit blast. When sour fuel is running, components within the turbine section are exposed to accelerated hot-end corrosion. This results from the combustion of sour fuel gas, rich in hydrogen sulphide (H2S), reacting with salt (NaCl) from the intake air.

Cooling passages on the turbine blades must remain free of contamination. If they are not protected, blockage can result in fatigue and cracking. Variable guide vanes and pneumatic parts are particularly exposed contamination and corrosion offshore. This can lead to seizure. Air filtration systems can promote better compressor cleanliness and long-term part integrity.

In Europe, products are tested and clarified in laboratories in accordance with EN779 and EN1822 use. EN filtration efficiency grades range from G1 to U17; the higher the number, the higher the level of filtration. In the GT market, filtration typically ranges from G3 to E12. Filters in the G3-M5 range are commonly used as pre-filters.

Typically, onshore modern GT filtration systems have a minimum of an F9 classification. Systems are now regularly commissioned with levels of filtration up to EPA E12. About 85% of offshore GTs are protected by small, high velocity filtration systems that fall into the pre-filtration classification range of G3-M5. These systems were widely adopted from the late 1970s. Selection was based on research by the National Gas Turbine Establishment on an ocean-going marine vessel. It involved taking samples of air from less than 10m above sea level as an indicator of offshore air quality. What was less well understood at the time was the difference in air quality between sea and platform level (30m) where most particles are sub-micron.

Testing at that time considered that 95% of offshore particles were above 5 micron, and that filter bags would be effective in arresting them. Recent research revealed that 98% of particles on offshore platforms are 1 micron or below (Table 2).

Traditional filter bags offer minimal filtration and particle arrestance for particles less than 1 micron. They are designed to allow water, moisture or fog to coalesce as it passes through the filter bags. This creates larger droplets that are captured by a downstream vane. However, some water and salt in solution passes through the vanes. Water can collect on the floor downstream of the bags and upstream of the final vanes. It evaporates over time, allowing salt crystals to be carried into the GT.

 Table 1: A comparison between the aerosols from the National Gas Turbine Establishment (NGTE) and AAF platform measurement, highlighting the difference in particle sizes at platform level.[/caption]

 Table 2: Air cleanliness at 0.3 micron. AAF’s N-hance EPA E12 filtration technology is 1900 times cleaner compared to traditional high velocity technology.[/caption]

Air filters with EPA E12 classification capture 99.5% of particles at the Most Penetrating Particle Size (the most difficult size to capture at a predefined airflow speed.

When they first became available offshore, EPA E12 technology required a large equipment envelope. The air intake housing had to be replaced to lower airflow. This raised costs and foundation loads. That’s why it is primarily used on the platforms of super-majors. They invested in upgrades when oil prices peaked.

EPA E12 filtration is now available as a retrofit within high velocity filtration systems without the need of a larger filter house.EPA E12 cost effectively captures substantially more harmful particles than other filtration classes. The upgrade is designed to deal with large amounts of moisture and salt. This type of filtration reduces water washing frequency, increases production efficiency and lowers CO2 emissions, while providing longer operational life for the gas turbine. ■

Graeme Turnbull, CEng, MIMechE, MIOA, is System Product Manager at AAF International. For more information, visit aafintl.com.

New research prompts reassessment of offshore filtration selection

 Cogeneration plant undergoing extensive upgrades.[/caption]

There are many aging boilers out there in urgent need of replacement. Whether they are in refineries, power plants or combined heat and power (CHP) facilities, there are many factors to take into account in boiler or Heat Recovery Steam Generator (HRSG) selection, installation, cost and maintenance.

Some sites are suitable for a package boiler fabricated in a factory and shipped to the site for installation. Their standardized sizes don’t fit the needs of some refineries and power plants, but those that can make them work often gain a good boiler at lower cost.

Beyond a certain size, though, it becomes prohibitive to ship packaged boilers. That’s where stick-built (or customized) boilers come in. They are tailored to the individual facility, with components shipped to the site where they are assembled and welded. They are more expensive and take longer to install as they are made to specific site and process conditions.

A hybrid approach combines elements of package and stick-built boilers. Design is done to facility specifications. It is preassembled and tested at the manufacturer’s site before being transported in one or more pieces for installation and commissioning. This greatly reduces the amount of onsite construction work that needs to be done, hence their lower cost compared to stick-built alternatives.

A large ethanol plant in the U.S., for example, needed a boiler to that could provide 290,000 lbs of steam per hour at 250 psig and 555°F of superheat. It also needed to rapidly ramp up or down in response to demand. Rapid ramping requires a maximum heat release of less than 80,000 Btu per hour per cubic foot, which places a limitation of about 200,000 pounds per hour on the size of unit that can be shipped. A hybrid approach was preferred.

The convection section, and the mud and steam drums were manufactured and shipped to the field for installation. The tubes were attached in the field. The boiler can ramp from 20% to 100% load in about five minutes without breaking down due to thermal stress. Oversized downcomers are positioned out of the heat path. This eliminates deviation from nucleate boiling where steam goes up the downcomers and fights with the water coming down (a common cause of rupture).

Large power plants, refineries and petrochemical facilities can cost tens and even hundreds of millions. A boiler represents a tiny fraction of overall costs. But an unreliable boiler or problematic HRSG can bring the facility to a standstill.

Sizing boilers with little margin, therefore, may be ill-advised. Smaller boilers that constantly run near capacity may be cheaper, but reliability eventually becomes an issue due to constant wear and tear. They may suffer from water carry over from the steam drum to the superheater. Eventually the superheater blows out.

To minimize unscheduled downtime, it is generally advisable to specify large furnaces, steam drums and oversized boilers. A larger steam drum offers more separation to more easily remove water from the steam before it arrives at the superheater. And in the event of loss of feedwater flow, a large steam drum provides operators with valuable minutes to address the situation before steam levels fall and a trip is triggered.

By running the boiler well below capacity, the likelihood of a breakdown is greatly lowered. Warranty problems can also be avoided. A more conservative approach to specification helps the facility gain a more reliable boiler for a small increase in cost. In the long run, it usually turns out to be far cheaper than trying to keep a smaller boiler constantly running at or near capacity.

Take the case of the new CHP plant at Ford’s Dearborn, Michigan campus. It was originally specified at 23 MW to include two Solar Mars 100 gas turbines and a 3 MW condensing steam turbine. While this meant lower capital and operating costs, it didn’t allow for fluctuating steam and electricity requirements, or future expansion. In partnership with developer DTE Energy, Ford opted for a larger facility that could generate enough electricity to be sold externally.

A new design called for two 14.5 MW Solar Titan 130 gas turbines, a 5 MW condensing steam turbine from Siemens and Rentech HRSGs. The facility is designed to produce heating, steam and electricity for internal use as well as feeding the grid. The 34 MW, 370 k-lb/hr steam CHP plant offers enough steam load for Ford, and optimized sizing to provide electricity for the grid. Ford gains long-term contracts for steam and power from DTE as well as an on-site generation, greater energy efficiency and lowered emissions.

Older boilers are often a source of regulatory concern. When upgrading or adding a new boiler, the specification of larger furnaces is a good way to curtail emissions and minimize problems with flame impingement. Selective Catalytic Reduction (SCR) and LoNox burners can also lower NOx production.

Coal-burning and simple cycle gas turbine facilities in some areas face new regulations that severely limit emissions. California, for example, has set targets to reduce greenhouse gas (GHG) emissions to 40% below 1990 levels by 2030. It includes a 20% reduction in emissions from oil refineries. This is forcing many to replace older coal-fired boilers. Those that desire onsite power as well as process steam are switching to natural gas-fired combined cycle plants. This requires the addition of an HRSG.

Example: Morning Star Packing is a California-based producer and packager of tomato-ingredient products. It decided to install new boilers, combustion systems, and an SCR system at one facility to double steam production while lowering NOx emissions. Morning Star opted for two boilers from Rentech with register burners and an SCR system by John Zink Hamworthy. The register burners brought NOx levels down to less than 30 ppm, which the SCR then reduced to 5 ppm. Boiler efficiency was raised from below 80% to around 85%, thereby lowering fuel expenditure.

No two refineries or power plants are identical. Equipment and products produced can vary considerably. One facility may require an abundance of steam from a boiler that follows steam load and can fire up or down on demand. Another site demands recovery of waste heat to raise efficiency and lower emissions. And a third may suffer from severe space constraints that limit options. Thus, a cookie-cutter approach to specification can lead to problems. The owner requirements, the needs of the process and the conditions of the site should ultimately determine the boiler selected.

An east coast refinery serves as a case in point. It had to deal with new regulatory requirements to install expensive emissions equipment to cut NOx and SO2 emissions. This included leak detection and repair, SCR, Continuous Emissions Monitoring Systems (CEMS), reduction and eventual elimination of fuel oil burning, and ultra-low NOx burners to help bring NOx emissions below 0.040 lb per mmBTU.

An important part of meeting its refinery steam requirements was the replacement of older boilers with two more efficient units that brought emission levels to the required range. These units came with water-cooled membranes, accelerated natural circulation of the water, and burners that could use natural gas or refinery gas. Each boiler could deliver 250,000 lb/hr of superheated steam at 575 psig and 730º F. In conjunction with all the other emissions control technologies, this brought NOx emissions down to 2 PPM, CO to 20 PPM and NH3 slip to 5 PPM.

Another design feature specific to this site was redundancy. Each boiler can produce enough steam to run the entire plant, with the other on hot standby. Each has dual fans as well as monitoring and safety systems. Each boiler comes 1,200 RPM forced draft fans from Robinson Industries driven by a Dresser-Rand steam turbine with a Lufkin gear. The turbines are controlled by a Woodward electro-pneumatic governor with a Flowserve Valtek pneumatic actuator.

 Every site has a different layout and different needs. Boilers must be tailored to those needs.[/caption]

Aging household appliances are far less efficient than the latest models. Similarly, aging boilers, some dating back to the early days of the Cold War, can be costly to run and have higher emissions. By adding high-efficiency, natural gas boilers, fuel costs can be slashed and emissions lowered.

The reason for such gains is the evolution of technology. The latest generation of equipment comes with features such as SCR and LoNox burners integrated into the boiler. Modern designs lower the amount of refractory, so operators don’t need to worry about replacing refractory seals or rebuilding refractory walls. Additionally, placement of the superheater in the convection section protects it from hot exhaust gas, boosts reliability and extends lifespan.

Oregon State University (OSU), for example, replaced aging boilers with a CHP plant. The new facility consists of a combustion turbine from Solar Turbines, an HRSG, an Elliott steam turbine and two auxiliary boilers. This provides all the steam as well as half of the electrical needs of the 570-acre OSU campus located in Oregon.

The central steam plant hadn’t been upgraded since 1948. The replacement facility had to comply with Oregon’s State Energy Efficiency Design (SEED) i.e., exceed code efficiency requirements by at least 20%, and lower emissions. The campus uses absorption chillers, so there is little fluctuation in electricity demand throughout the year. Steam is used for heating, cooling and humidification the buildings, providing hot water, sterilizing greenhouse soil and lab experiments.

The new CHP facility consists of a 5.5 MW Solar Taurus 60 engine that can run on multiple fuels (natural gas, distillate, biodiesel or methane), a Rentech HRSG with a preheater, duct burners from R&V Engineering, two auxiliary package boilers with LoNOx burners, each capable of 85,000 lbs of 200 psig steam per hours, a 1 MW Elliott backpressure steam turbine generator, and an Emerson Delta V control system. The plant can produce up to 6.5 MW of electricity and up to 280,000 lbs. of steam per hour. By switching from utility to onsite power, the university estimated annual savings of more than half a million dollars.

Boiler best practices: Boiler upgrades and HRSG installations require care

No one saw a Covid-19 pandemic coming. Big 

 were made virtually overnight. Most in the sector report decreased sales, project delays, supply chain disruption and warehouse shortages. The pandemic is expected to reduce power consumption in U.S. commercial and industrial sectors by more than 4%, according to GlobalData.

Yet there are encouraging signs. Oil prices have rebounded somewhat, and infrastructure projects are restarting as economies cautiously reopen. For example, GE completed its first major onsite inspection project since the Covid-19 outbreak in China.

Turbomachinery International interviewed turbomachinery industry leaders to see how they’re faring, what’s changed, and how they are responding. Companies such as Mitsubishi Hitachi Power Systems, Howden, Rotoflow, SSS Clutch, Velo3D, Sullair, Voith, MTU Power and PAL Turbine Services reported on how they are adjusting to social distancing and other guidelines. Some of them said they are pivoting from onsite work to remote maintenance services. Others are investing in new technologies such as digitalization and the Internet of Things (IoT) or providing employees with better training. More than a few have stripped down their operations to focus on core competencies.

Howden, a manufacturer of compressors, steam turbines, heaters, fans, and blowers, noted postponements and cancellations of planned outages with subsequent cancellation of spare part orders. That’s hit their bottom line.

In response, Howden expedited the launch of a new remote service that uses an augmented reality annotation technology with real-time communications based on the Chalk app from PTC. It connects remote product experts to on-site field technicians and customers. The company also hired a dedicated IoT Strategy Manager to improve its digital solutions.

“We see opportunities in remote monitoring and support; as well as customer self-service interface points as key elements of a post-Covid world,” said Darryl Halter, Vice President, Aftermarket at Howden. “As customers continue to place requests for quotes, we see that as a good indication that they are looking to proceed with projects when this is over.”

Halter’s advice? Adapt and innovate. “When situations like this arise, we are leaning into it, not fighting it. Accept that this is the reality. Adapt to it and innovate in ways that benefit the customer and the company.”

Sullair, an Indiana-based manufacturer of portable and stationary rotary screw air compressors (a subsidiary of Hitachi), has felt Covid’s impact, particularly in its operations and facilities in China. It is continuing to focus on its core business. With no trade shows on the horizon, it is stepping up efforts along other marketing channels.

“We are actively looking at other means we can communicate our message including virtual events,” said Brian Tylisz, Senior Vice President of Sales for the Americas at Sullair.

After mandated shutdowns ended, Sullair ramped factory activity back up. But when business-as-usual will return is anybody’s guess.

“Nobody within our industry had this in their business plans for 2020,” said Tylisz. “With nearly six months to go in the year, it is difficult to predict a full-year impact.”

While thankful for tools that make it easier to communicate digitally, he said that nothing can replace face-to-face interaction.

“There is nothing like sitting down, having a meal and looking somebody in the eye while talking business,” said Tylisz.

Despite Covid, business at Mitsubishi Hitachi Power Systems (MHPS) is doing well. The company had a record year, and ranked first in market share by megawatts for gas turbine orders in the first quarter of 2020. The MHPS remote monitoring and diagnostics centers have helped the company leverage real-time data to help users make risk-informed decisions on delaying planned maintenance safely.

“Right now, it’s all about flexibility and ensuring that our customers are able to reliably keep the lights on while so many other factors in our lives remain unknown,” said Marco Sanchez, Vice President and Head of Intelligent Solutions at MHPS Americas.

The current crisis has made it clear that plant operators need remote operating solutions to improve operations and protect employees. As a result, MHPS is focusing even more on its 

“Going forward, we expect many inspection and maintenance tasks will be supported from an offsite location instead of in person,” said Sanchez. Both artificial intelligence (AI) and machine learning will allow the knowledge of today’s experts to be captured for the future.”

Sanchez’s advice to others in the turbomachinery sector? Have flexible contingency options in case of future disruptions. This should include cyber-secure communication channels with sufficient bandwidth for the desired level of implementation.

SSS Clutch, a Delaware-based manufacturer of automatic overrunning clutches for high-power and high-speed applications, was remodeling its UK facility when the world went into lockdown. It paused construction for six weeks, delayed employees from moving in and instituted remote work.

“Things were far from perfect and seamless, but there has not been a huge disruption,” said Morgan Hendry, President, SSS Clutch. “The situation has helped us to establish better workflows and practices for the future. It prompted us to make positive changes.”

SSS Clutch obtains about a quarter of its business from marine propulsion, a quarter from mid-stream and down-stream oil and gas and from half power generation. Hendry said the company hasn’t skipped a beat on the operations side.

“We expect bumps in the road but not a fall off,” he said. “There will be some delays and cancellations within our oil & gas portfolio, but we believe our overall business will not see a material effect.”

Rotoflow, a manufacturer of companders and expanders, has been operating at full capacity. It implemented heightened safety procedures for those allowed to remain at work in its manufacturing facilities. Office employees worked from home.

The effect of the crisis on the company for 2020 overall is uncertain. But one good sign is that it recently achieved record production in the industrial gases space.

“Once the crisis is over, we are looking forward to re-engaging with customers face- to- face, offering even more value-added solutions, and introducing new products,” said Sarah Farnand, Rotoflow’s Global Sales Manager, New Equipment. “One potential opportunity from the pandemic has been time to spend on some of our product development initiatives.”

Her advice to the turbomachinery world: “Focus on what you can control, keep your employees safe, and don’t let your guard down.”

For MTU, which offers diesel and gas power generation system services, protecting customers from disruptions has been top priority. It temporarily scaled back to emergency staffing levels at its Berlin facility where GE LM series turbines are serviced. As well as protecting employees, this was a result of supply chain disruptions. With reduced staffing, the company maintained minimum service levels, carried out field services and received delivered engines and parts. This minimized disruption for customers.

“We intend to flexibly adjust shop capacities to meet demand going forward as we monitor the supply chain situation, COVID-19 developments and regional trends daily,” said Gregor Stoecker, Director of Sales, Industrial Gas Turbines at MTU Power. “We can also support the ramp-up operations of our customers by offering intelligent repair solutions, flexible lease and rotable services, and sourcing of serviceable material.”

The German-based Voith Group, which manufactures drive components and systems for turbomachinery, has weathered the crisis relatively well. It has carefully monitored its supply chain to keep it up and running. A few suppliers from regions like Italy and India struggled. But overall, its supply chain is almost back to normal.

That said, some large capital expenditure projects, especially in the Middle East, have been postponed. Further, travel restrictions have caused challenges in the aftermarket, especially in Europe and the U.S.

“Thanks to our global service footprint, we benefit from close customer proximity and the situation in China improved much earlier than in many other areas, so China strongly supported our business in the past weeks,” said Rolf Schweizer, Executive Vice President & CEO Voith Turbo.

The drop in oil and gas prices hit Voith particularly hard. It specializes in drives for electrically driven gas compression for up-, mid-, and downstream applications. In response, it is strengthening its capabilities in the retrofit area.

In the short-term, Voith sees potential in service and aftermarket businesses.

“We will continue to invest in new products and solutions (such as VoreconNX variable speed drives, the VECO-Drive VFD, AeroMaXX turbo gear technology or new condition monitoring solutions) that provide competitive advantage,” said Schweizer. “The current crisis has uncovered significant potential for digital collaboration, autonomous operation and remote maintenance.”

Only a few months ago, for VELO3D, a metal additive manufacturing (AM a.k.a. 3D printing) solutions provider, AM applications in aviation and oil and gas were still vital sales targets. However, all signs now point to those sectors scaling back capital expenditure investments. VELO3D has had to make some operating and capital adjustments but still intends to launch new machines into the market later this year, such as their 1-meter tall Sapphire system.  The company was able to secure an additional $40M in funding amid these unprecedented times and hopes to be profitable by mid-2022.

“As a smaller business, we are more agile and can shift our focus a little more easily than larger, publicly listed companies,” said Benny Buller, founder and CEO of VELO3D. “We are targeting other industrial segments like aerospace, defense and energy. We are also putting more investment into marketing and business development.” The company also recently landed a $20M order from an existing aerospace customer.

One potential opportunity is in printing parts traditionally manufactured via casting. 3D printing offers much shorter lead times and lower cost for small quantities. Buller’s advice to others in the turbomachinery sector is to stay agile.

“Agility is your strongest asset,” said Buller. “Make investments in technologies that will enable you to be flexible to keep costs down and respond to customer and market needs quickly.”

PAL Turbine Services, a subsidiary of Pond and Lucier, a field engineering services company focusing on legacy gas and steam turbines, is an example of the unforgiving nature of market disruption. The company has virtually ground to a halt with purchase orders drying up, according to Dave Lucier, owner and general manager.

He complained about public utilities and many private owners of gas turbines (refineries, process plants) looking with fondness at the lowest bid instead of insisting on experience and technical capability. As a result, PAL’s 20 full and part-time engineers (each forty-year plus veterans) don’t have much work.

“Clients don’t want us to retire, but they won’t send us business until they are in trouble,” said Lucier. “Even then, they want us to accept reduced rates, though we charge about half OEM rates.” ■

Weathering the Covid-19 storm: Diversification, liquidity, and maintaining contact

Control – always a hot topic. The reds and blues fight for control of Congress. There will be a monumental battle for control of the U.S. come the November election. And of course, there are currently a whole lot of people telling us what we can and cannot do, where we can and cannot go and who we can meet – if anyone at all.

Like political control, turbomachinery controls are dynamic and changing. That is the subject of our cover story. A wave of innovation has swept across the controls and instrumentation field recently. We’ve talked about many of these technologies for years. But they were never quite ready for prime time. Many of them have now reached sufficient maturity to be trusted by plant operators and fleet owners.

The Industrial Internet of Things (IIoT), digitalization, microprocessors, new software platforms, the cloud, advanced analytics, machine learning, wireless technology, mobility, connectivity, augmented reality, virtualization, artificial intelligence, cybersecurity, big data, Software-as-a-Service and many other breakthroughs have advanced the field like never before. This has given rise to enhanced capabilities for remote monitoring and operation, digital twins, remote field service, maintenance automation, real-time plant and fleet management and tighter inventory control. Those harnessing these tools report fewer unscheduled outages, and longer plant and equipment lifespans.

"Turbomachinery software and controls are destined to be a hot area of the market for some time to come."

In these times of dire forecasts about turbine sales and slow market recoveries, it appears that software and controls are destined to be a hot area for some time to come. Those holding onto aging turbines without replacement should at least want to operate them with the latest controls. Similarly, the business world at large is adopting these tools in a big way. Whether from head office, partners, customers or rivals, pressure will inevitably mount to adopt the latest control and instrumentation software capabilities. Those looking for market growth, or for an avenue to replace lost revenue, would do well to look into how they can utilize these technologies to add value, bring about greater connectivity and better serve their users.

The issue is otherwise packed with goodies. We have a follow-up story to our May/June cover story on Covid-19. Things appear less grim and many are seeing a slow return to normality. There is also an overview article on Power-to-X: an umbrella term for various approaches to the conversion, storage and reconversion pathways that take advantage of surplus electric power from renewable energy (typically from solar during the day or wind at night). The X stands for the type of energy into which the electricity surplus is being converted. This is generally gases, liquids or heat.

Further feature article topics include how to upgrade centrifugal compressors using inlet guide vanes, a more efficient way to conduct LNG regasification, offshore air filtration, how to repurpose aging turbines into synchronous condensers, and best practices for boiler and HRSG upgrades. Columns take up subjects such as a summary of recent webinars, gearbox trends, turbomachinery startup and post-commissioning, and the differences between the storage and transportation of energy.

After close to two decades at the helm, our publisher Richard Zanetti has retired. Richard’s leadership revived the fortunes of the magazine and made it what it is today. Richard is replaced as publisher by Mike Tracey, a veteran of the publishing field.

Further changes at the magazine: Our new associate editor Rory Pasquariello has taken over the online and newsletter functions from Kalyan Kalyanaraman. Kalyan is thanked for his many years of service. You can find Rory’s email address in the masthead. Please add him to your press distribution list.

We hope to have a chance to visit your booths sometime in the near future – perhaps at PowerGen, if not before. Wishing you all good fortune in your efforts to emerge from this period of economic turmoil.

July/August 2020

Centrifugal compressor upgrade: Boosting plant efficiency by adding inlet guide vanes to aging compressors

New concept for power integration with LNG

New research prompts reassessment of offshore filtration selection

Boiler best practices: Boiler upgrades and HRSG installations require care

Weathering the Covid-19 storm: Diversification, liquidity, and maintaining contact

Who is in control?