PowerGen International offers an annual barometer of the power generation sector. The December 2018 event noted the many challenges the industry faces: the influx of renewables, an aging power grid, price volatility and changing regulations, to name a few. Yet the overall impression was one of optimism.

Organizations, such as Orlando Utilities Commission, ABB, MHPS, Emersion Power & Water and GE Gas Power, provided the view from the executive suite. Topics included digital transformation, the evolution of the grid, interaction with a new workforce generation, the rapidity of change, and how the industry can adapt. Overall, they presented a positive view of the future.

Teresa Hansen, Global Content Director, Clarion Events, MC’d the keynotes. She said 2018 had been a transformative year for power generation. As well as the struggle to stay competitive, renewable and small distributed energy installations are increasing steadily.

“Despite this, conventional thermal plants and combustion turbines will continue to supply most of the developed world’s electricity for many years to come,” said Hansen.

Orlando Utilities Commission President Gregory Lee described how his organization was adjusting to change. Its Stanton Energy Center, for example, has incorporated solar, natural gas, landfill gas and coal in one location. The city balances three factors: reliability, affordability and sustainability. By 2050, Orlando plans to be powered 100% by renewables, he said. “Power generation in 10 years will look vastly different from what it did a decade ago.”

Digital transformation was the theme of Robert Yeager’s keynote. The President of Emerson’s Power & Water Solutions business began by showcasing his company’s Ovation automation system that boasts 1.3 million MW of coverage worldwide.

“Digitization will eliminate human error, make it possible to innovate without fear, bring about effective knowledge transfer to retain and attract top talent,” said Yaeger. “The new generation of workers grew up with digital technology that they expect to find in their workplace. They want a digital plant, and many facilities have already started to implement digital elements to stay competitive.”

He urged attendees to adopt digital-twin technology. Rather than trying to innovate while a plant is online, the digital twin enables management to model potential changes, view the results and make any necessary changes to avoid risk.

These twins can be composed of as much as 10 million lines of software code. As they are automatically updated, they provide real-time synchronization of the entire power plant and its controls with the digital world.

“You can see if the changes you’d like to make would de-rate or trip your plant without risking real downtime,” said Yaeger. “It’s a great way to avoid problems in the future.”

A whole lot of software and IT changes are coming soon to the operational technology (OT) world of power generation: The cloud, augmented/virtual reality, artificial intelligence (AI), machine learning, blockchain, modern networking and edge computing. As such, power producers will need to find the right technology partners to help successfully implement them. But with all plants networked, a fix in one plant can be quickly exported to all plants.

ABB, for example, has embarked on a technology partnership to marry IT with OT. It collaborates with Microsoft and HP Enterprises to incorporate cloud and edge computing into its ABB Ability digital distributed control system (DCS) architecture.

“Digital solutions must be able to demonstrate tangible results that can scale across the enterprise,” said Greg Scheu, President, Americas Region, ABB. An integrated approach to digitization must encompass everything: from sensors and controls to security to the health of all assets.

He also covered preparation for the new workforce. By 2025, some 75% of personnel will be millennials with digital competence and knowledge, he said. Quite different from that of today.

ABB is working with partners in education to lay out career paths for industry jobs, such as lineman and plant operators. Instead of getting a degree or other skill and then showing up to work without any experience or practical know-how, they need the right training and programs to fit them for workplace.

Todd Buchholz, former White House economic policy director and economist, highlighted the “scissors economy” where the middleman gets taken out of the equation: transportation (Uber), hospitality (Airbnb), and even energy, where direct buying, microgrids and distributed generation challenge the role of the modern utility.

“Utilities and power generators need to adapt and evolve,” said Buchholz. “You must be more flexible, not just running turbines or plants, but involved in the last mile, as well.”

Scott Strazik, the new CEO of GE Gas Power (combining equipment and services for GTs under one entity), said that 700 GW of coal and nuclear power will be retired over the next two decades. He believes natural gas is needed to provide grid resilience to support renewables.

“Renewables may be growing faster, but there is a lot of opportunity for natural gas,” said Strazik. “Gas is dispatchable, flexibly, low density and affordable.”

He noted that CO2 reductions hit their peak at 27% and have been trending downwards since. During that period, coal had dropped from 50% to 30% of the generation mix. In the same period, natural gas rose from 19% to 34%. Two-thirds of the reduction in CO2 has resulted from the coal-to-gas switch and one-third from renewables, he said.

Another opportunity for gas is in liquefaction capacity. Currently, there is

369 MTPA of LNG capacity with another 92 MTPA under construction, and 875 MTPA proposed (half of which is in North America).

LNG markets are growing. Taiwan has decided to eliminate nuclear by 2025 and reduce coal to 30%. That opens the door for 13 GW of new natural gas combined cycle power plants.

• Bangladesh is adding 43 GWs of gas by 2041.

• Brazil may add 12 GW of gas by 2030

• North America will add 30 GW to 40 GWs of gas in the next five years.

This is showing up in a spurt of orders. GE has 30 of its HA turbines running with 220,000 operating hours to date. Its orders total 83 of which many are due online in the next year or two. The company is also pushing upgrades, of the GE fleet or cross-fleets. These typically involve GE’s Advance Gas Path (AGP) or its DLN 2.6+ combustor.

“We can now turn down a 7F turbine from 40% to 26%, which lowers NOx and CO, as well as fuel burn down to 25%, and greater opportunity for energy trading via ancillary services,” said Strazik.

Cross-fleet upgrades are on offer for machines, such as the MHPS 501F, the SGT6-5000F and the SGT-800. For example, at a Naturgy plant in Tuxpan, Mexico, 501Fs, steam turbines and generators were upgraded with the AGP to extend the maintenance interval to 32,000 hours, increase output by 9.2% and efficiency by 2.9%.

“We operate in a complicated and interesting power market, but gas will play a role in a cleaner energy future,” said Strazik. “As gas requires 50-to-100 times less space per MWH than renewables, the world’s many mega-cities will look to gas for their power.”

Mitsubishi Hitachi Power Systems (MHPS) CEO, Paul Browning, said that 2018 will be the first year where its GTs will earn the top spot in terms of megawatt orders. Browning estimates MHPS market share of around 35% for 2018. He puts this down to the transition from F-class to advanced class gas turbines, with MHPS having a head start on those machines over its rivals.

“We feel strongly that the power generation market will be dominated by natural gas, renewables and energy storage,” said Browning.

MHPS is adding renewables and battery storage to its portfolio, and it will act as a technology integrator and project developer. MHPS will begin its solar initiative in the Northeast U.S. The company has already created a development team in that area. The focus will be on offices, industrial and commercial, rather than utility-scale solar.

The company is also a developer for natural gas projects. Many Independent Power Producers (IPPs) have land and existing relationships for transmission. But they lack resources to either upgrade or expand their facilities. “As a partner we can help with finance and technology,” said Browning.

As an example, he cited a project MHPS developed in Brazil. The company arranged a 25-year gas contract with Shell, a 25-year power purchase agreement (PPA), and an investor. The project is moving forward using the MHPS JAC Gas Turbine and an MHPS Heat Recovery Steam Generator (HRSG).

The company recently announced the introduction of its 275 MW SmartER GAC (the M501GAC) turbine to compete against existing F-class peakers. It is an integration of MHPS’s G-Series turbine and MHPS-TOMONI analytics and AI.

It enables a 10-minute start, 50 MW/min ramp rate, 9 PPM NOx emissions, and an output of 275 MW. The higher output and operational flexibility is said to exceed the F units. MHPS announced its first order for this turbine from a Midwest utility and expects to announce other new orders for this technology in the near future.

“We plan to convert F-class peakers into GAC peakers,” said Browning.

MHPS may have the megawatt lead for 2018, but the big question is whether it can solidify its position moving ahead. According to Forecast International, GE is likely to install nearly half the total electrical power generating capacity to be added over the period 2019–2032. When licensees and subsidiaries are included, GE Energy is projected to deliver 49.34% of capacity installed during this period. Siemens will follow with 25.76%, while MHPS will contribute 15.53% (Figure).

“The strength of GE Energy in the power generation market is the result of a deliberate drive by the company to maximize its market penetration at a time when reduced demand, overcapacity, and soft prices look set to continue until at least the early 2020s,” said Stuart Slade, Industrial Gas Turbines Senior Analyst at Forecast International. “This strategy brought with it significant risks that were picked up by stock market analysts to reflect concern about the company’s performance.”

GE is partnering with Tampa Electric (TECO) to modernize Big Bend Power Station in Hillsborough County, FL using 7HA GTs and an upgrade to its steam turbine island. Similarly, IPP Chiahui Corp.is going to use the 7HA.O2 as part of a power-expansion project at Chiahui Power Plant in Chiayi Province, Taiwan. GE customers, such as Invenergy’s Lackawanna Energy Center in Jessup, PA and Aluminium Bahrain (Alba)’s Unit 1 at Power Station 5 in Bahrain achieved first fire status for their HA units.

In the past few months, Siemens has unleashed an avalanche of new orders, contracts and upgrade projects. It received an order for SGT-800 GTs in Panama earlier this year, along with a long-term service and maintenance agreement for the plant.

IPP Sinolam Smarter Energy (SSE) is the end user. The deal encompasses six SGT-800 units, an SST-600 industrial ST, and electrical generators. The plant will operate with liquefied natural gas (LNG). Commissioning for the power block is expected in the fall of 2020.

Siemens received another order from Lansing Board of Water & Light (BWL) to supply three SGT-800 GTs and generators for its new gas-fired generating station in Lansing, MI. It will feature three SGT-800s, two operating in combined cycle and one simple cycle, capable of producing 250 MW. Siemens will also supply its SPPA-T3000 digital control system.

Siemens is building a new energy service and training center in Bolivia to provide education on traditional and digital services. It will also function as a hub for servicing power equipment installed in the South America region. At the same time, Siemens is upgrading three CCPPs in Bolivia: Termoeléctrica del Sur, Termoeléctrica de Warnes, and Termoeléctrica Entre Ríos.

Doosan, meanwhile, showcased the Doosan DGT6-300H series gas turbine.

Now undergoing a battery of tests before being released to the market, it features an Advanced DLE combustor, new coatings and cooling systems, a 13-stage compressor, a flutter-free airfoil design, and over 3500 sensors inside. It will provide 270 MW in simple cycle and 400 MW in combined cycle. ■

Articles

New opportunities arise in the face of growing challenges at PowerGen.

A more optimistic PowerGen

Gas turbine (GT) OEMs have been racing for decades to deliver bigger machines, higher efficiency and larger combined cycle plants. Siemens scored a world record with a 4,800 MW combined cycle plant in Egypt (Turbomachinery International, Nov/Dec 2018).

GE and Mitsubishi Hitachi Power Systems (MHPS) both claim to have the biggest GT. GE’s 9HA.02 comes in at 557 MW, while MHPS’s M701JAC provides 563 MW. GE, Siemens and MHPS all claim the world record on combined cycle efficiency.

Yet market forces may be dictating a completely different direction — that bigger is not necessarily better. Small and mid-sized turbines are now receiving more attention as the power generation and oil & gas markets diversify. This trend is being driven by distributed generation, renewables, microgrids, combined heat & power (CHP), lower emissions and hydrogen-based generation.

“The industry has been guilty of building ever-larger machines and then trying to find a market for them,” said Mark Axford, President of Axford Consulting. “A better approach would be to find what the market needs and building machines to fit those requirements.”

Solar is a leader in small machines, producing GTs ranging from 1.2 MW to 22 MW. Some use a diffusion flame combustor and others a DLE system. The DLE system keeps flame temperature much lower (1,600°C versus 2,300°C) to keep NOx emissions down. Solar machines can operate with LPG, coke oven gas, landfill or digester gas.

“LPGs have become more common due to shale gas offering up more propane at low cost,” said Luke Cowell, Group Manager, Combustion Strategy, Solar Turbines. “This fuel can be burned in a Solar GT with lower NOx emissions and lower particulates compared to diesel.”

The composition of LPG around the globe can shift from 100% butane to 100% propane, said Cowell. With more butane, it is better to run it in liquid phase. Propane, though, has a lower dew point so is better in the gas phase.

At a Caribbean rum distillery in St. Croix, a Solar Centaur 50 is used with LPG for CHP. LPG is much lower priced there than diesel. As it has only 2.5% butane, the Centaur 50 is run in the gas phase with the fuel temperature maintained at around 200°F.

China’s Liheng Steel, meanwhile, is using four Solar Titan 130s operating on coke oven gas with an HRSG and steam turbine.

“LPG is an excellent turbine fuel, but you need to determine whether it is optimum to use it in its gas or liquid phase,” said Cowell.

For the mid-sized turbine market, MHPS provides the H-100. At 119.9 MW (50 Hz) shaft power, it is being used to replace less efficient machines without requiring a modification to the bottoming cycle. It is also used in mechanical drive applications.

H-100 specifications: 38.9% efficiency, exhaust flow of 302 kg/s, and an exhaust temperature of 573°C. Its DLE burner is a scaled-down version of the combustor from the MHPS M501G and M501J. It provides 9 ppm NOx and CO.

“The MHPS H-100 GT has been successfully validated with lean gas (up to 40% N2), rich gas with a high calorie value, such as LNG, and on-line switching between lean and rich fuel at a Wobbe Index rate of change up to 0.5% per second,” said MHPS CEO Paul Browning. “It is the world’s largest two-shaft turbine.”

The two-shaft MHPS H-100 is finding a niche in LNG liquefaction as an alternative to the single-shaft GE 7EA, said Browning. The LP rotor has a continuous speed range capability of 70% to 105%. The two-shaft design allows full settle-out pressure starts. MHPS is partnering with MCO Compressor to deliver a complete solution to the oil & gas field.

Another smaller machine gaining traction is PW Power Systems’ FT8, sold in modified form as a “Frack Pack.” It offers 30 MW of mobile power to electrify the well pad. U.S. Well Services in Texas, for example, bought six of these units. Instead of diesel, it uses natural gas from the local site. They move them from well pad to well pad based on demand.

Zorya-Mashproekt from Ukraine offers a series of GTs ranging from 2.5 MW to 114 MW. Some 1,200 have been manufactured to date along with about 2,000 centrifugal compressors.

Despite embargoes from Russia, Forecast International predicts Zorya’s sales to improve over the next decade with 25-to-30 sales per year on average. The UGT-15000, for example, is a 16.9 MW, three-shaft GT with an axial nine-stage low-pressure compressor and 10-stage high pressure compressor.

Vericor has two such gas turbines in its repertoire. The 3.3 MW ASE40 and 3.7 MW ASE50B GTs are compact units for stationary, continuous duty applications. These units boast 60,000 hours between scheduled shop visits.

They can run on natural gas or liquid fuel. In addition, they can be changed over from one fuel source to another while running under full load.

Vericor Power Systems is owned by MTU Aero Engines and is the OEM of the TF series and ASE series GTs. Its aeroderivatives are used in marine, offshore, industrial and mobile power applications.

The TF40 (4,000 hp) and TF50 (5,000 hp) are used in the marine sector. Its VPS3 (TF40F) and VPS4 (TF50F) are favored in oil & gas. Its VPS3 (ASE40) and VPS4 (ASE50) are used mainly in the industrial sector.

The microturbine market has been stable for some time. But that may be about to change. Capstone Turbine, FlexEnergy and Ansaldo Energia are market leaders. Blandon (formerly Bladon Jets), a UK company, Micro Turbine Technology (MTT) from the Netherlands, and Aurelia Turbines from Finland have also entered the market.

Ansaldo’s AE-T100 is a single-shaft, high-speed microturbine that delivers 100 kW. Some 600 have been made since its release in the nineties.

Primary uses include CHP with biogas feedstock, and areas where small amounts of power, less noise, vibration and emissions are needed. The GT comes with a recuperator, electrical system, exhaust gas heat exchanger, control system and a single-stage centrifugal compressor.

Bladon’s MTG12, a 12 kW machine, is designed to power cellular towers for telecom companies. Towers not connected to a grid are in demand, a market historically dominated by reciprocating diesel engines. The MTG 12 is said to have advantages over diesels, such as fuel flexibility and lower maintenance, and to require 90% fewer site visits.

MTT’s EnerTwin can provide 3.2 kW of output for heat or electricity. Potential applications range from larger homes to restaurants and schools.

Aurelia Turbines has introduced a 400-kW model. This microturbine can be used for process steam, chilling and direct current applications. Efficiency is above 40%.

Smaller gas turbines are in demand in areas where CHP is growing in popularity. The complexity inherent in the development of smaller onsite power and CHP assets is being addressed by regulated utilities supporting and developing projects at customer sites, said Kurt Koenig, Vice President Project Development at DCO Energy.

Instead of fighting CHP and regarding it as a potential competitor, some utilities are embracing it, said Koenig. They realize that they have the grid and technical expertise to develop these projects and partner with industrial customers for mutual benefit.

DCO Energy has identified several major customer groups as CHP collaboration targets: healthcare, government and educational institutions, military, industrial, manufacturing, data centers, gaming and corrections. Projects can either be self-funded, privately funded, publicly funded or can be a combination.

“Drivers for CHP include cost, environmental impact, and fewer service interruptions,” said Koenig.

Where public benefits can be identified, regulated utilities can be a catalyst for CHP and other distributed generation assets. Potential CHP sites may have a strong desire to build onsite power. But they lack the know-how, financing, and grid expertise to achieve it. By involving a willing utility, a mutually beneficial solution can sometimes be achieved.

For example, the local utility facilitated a CHP site at the Hudson Yards real estate project in New York by removing barriers to grid access. It included gas-fired boilers, centrifugal electric-drive chillers, a 7.2 MW GT with a waste heat recovery boiler, and gas-based reciprocating engines that provide, heating, cooling and power to commercial and residential space on Manhattan’s West Side.

In another example, Duke Energy worked with Clemson University on a 15 MW CHP plant on campus. Owned by Duke, the utility provides access to natural gas and the grid. The facility includes natural gas turbines and duct-fired HRSGs. It supplies electricity and steam to Clemson. Duke gains steam and electricity. The campus also gains its own microgrid, partially funded by Duke.

“In this case, the public good was served as the provision of steam drove down rates for electricity,” said Koenig.

A similar example was outlined by Ken Duvall, Managing Partner and CEO at Sterling Energy Group. He believes CHP is vastly underused with only 82 GW existing in the U.S. It is estimated that there is 200 GW of untapped CHP potential in the nation.

“Well applied, CHP is the most efficient method of generating power,” said Duvall. “It is based on established natural gas technology that has very low risk.”

He emphasized that a change of thinking is required. Instead of CHP only being viewed as a customer-owned resource, a variety of ownership and funding options are possible. Some utilities are happy to develop and own the entire facility, arranging attractive, long-term contracts for power supply.

The utility can sell the excess electricity to other customers. With steam as part of the equation, some industrial plants will take up much of the steam and some of the power. Many permutations are possible.

Duvall showcased a CHP project on Amelia Island in northeastern Florida. It serves Rayonier Advanced Materials a supplier of cellulose specialty products. Company expansion called for more steam for industrial processes.

Rayonier leased land to Eight Flags Energy (a subsidiary of Chesapeake Utilities) for the establishment of a CHP plant. Rayonier gains 20-year access to low-cost steam. It receives steam at 160 psi and 420°F. Eight Flags supplies electricity to Florida Public Utility (FPU, part of Chesapeake) to meet about half of Amelia Island’s electricity requirements.

The guts of the CHP system include a 20 MW Titan 250 GT from Solar Turbines and a Rentech HRSG. The facility considered running the GT in simple cycle mode, but that would have given it too low an efficiency to make the project economics work.

Adding an HRSG for combined cycle operation changed the equation. The HRSG recovers around 70,000 pounds of steam per hour and has the capability to increase that amount using Rentech duct burners to 125,000 pounds per hour of process steam.

De-mineralized water provided by Rayonier is channeled through a hot water economizer in the HRSG to increase the water temperature by 70°F. This hot water is sent back to Rayonier for use in production processes.

Eight Flags has a capacity factor of 95%. This 22 MW CHP plant has lowered electric costs by 10%, while lowering NOx by 80% and CO2 by 38%.

“Rayonier receives steam and power, which it needed for expand,” said Duvall. “We built it on an elevated coastal site to be above any storm surge.”

The plant paid nothing for the power and steam plant. As it did not need any additional power, the utility sells electricity to other customers. But the plant would not have been possible without the tight partnership between the local grid authority, the utility, and the industrial customer. Plans are ongoing to open a second CHP plant on the island, said Duvall.

 This Rayonier plant receives power from a nearby CHP plant powered by a Titan 250 GT from Solar Turbines and a Rentech HRSG[/caption]

Ford Motor Co., with DTE Energy, is building a 34 MW CHP plant at its site in Dearborn, Michigan. The Central Energy Plant, inclusive of the CHP plant, at the Dearborn Campus entails a $300 million investment.

The plant will be owned by DTE Electric, the regulated arm of DTE Energy, and constructed and operated by DTE Energy Services, a non-regulated arm of DTE Energy.

Michael Larson, Director Business Development, DTE Energy Services, said that the plant encompasses several components: 16,000-ton chiller system using mechanical and heat pump chillers; 40,000-ton/hr thermal energy storage; 6,400-ton geothermal system; 156 MMBtu/hr hot water supply system; two 14.5 MW GTs from Solar Turbines; 5 MW steam turbine from Siemens; and 370,000 lb/hr of heat recovery steam generators from Rentech Boiler Systems.

“Over the next 10 years, the steam load will sink and the electric load at the campus will rise while both will continue to have seasonal variations,” said Larson.

That made sizing of the CHP plant more complicated than usual. Ford initially looked at a smaller CHP plant. But that would only provide power for its own need and might not satisfy fluctuating steam and electricity requirements.

In addition, project economics demanded a larger facility that generated enough electricity to sell to external customers. Ford will purchase power and steam from DTE Electric. Construction of the facility is scheduled to be completed by the end of 2019. ■

ExxonMobil advises those running small or mid-sized turbines to take care when selecting lubricants. The decision should be based on the application environment and a thorough oil analysis.

Smaller turbines typically use gearboxes that run at a higher speed. However, their efficiency is lower than larger frame machines, which generally do not have gearboxes. For smaller machines, the choice of lubricant is important.

Mike Galloway, Equipment Builder Engineer at ExxonMobil, said the oil type should be tailored to the load. For the 6F, he recommended the Mobil DTE832 or 932GT meeting GE’s required GEK 101941 specification.

“6F turbines run hot and need a thermally stable oil that is oxidation and varnish resistant,” said Galloway. “If poor quality oils are used, varnish can quickly build up, and that can eventually lead to a trip.”

COT-Puritech (a Circor company) also offers value-added service to turbine owners. Christopher Tomerlin, Director of Global Accounts at COT-Puritech, said his company can be called in to flush out the entire lubrication system.

An analysis is done to determine the chemical mix required. To remove varnish, a high-velocity flush is often needed, followed by a purge to get rid of any chemical residues.

“We sample the oil and conduct extensive tests,” said Tomerlin. “This helps determine which process is best for cleaning. For example, a varnish flush might consist of 24 to 48 hours of circulating the chemicals to remove the varnish. Once completed, the system is drained and then purged to extract all the chemistry. After that, the new oil can be introduced.

Sidebar: HYDROGEN TURBINES AND OTHER ALTERNATE FUELS

Hydrogen-fueled gas turbines continue to be an active area of research and development (Turbomachinery International Sept/Oct 2018). Hydrogen has the potential to be a greener and cleaner fuel source for GTs, said Elena McKenzie, Market Analyst at Ansaldo Energia’s PSM division. Faced with the rapid growth of renewables, declining revenue, rising O&M costs, and the demand for cleaner generation, all OEMs are looking at how to further reduce emissions.

One approach is to mix hydrogen with natural gas. As well as lowering emissions, McKenzie touted the use of excess renewable capacity used to generate hydrogen through hydrolysis and then feeding that hydrogen into the combustion process. To meet modern power generation needs, though, all-hydrogen GTs would have to be supported by vast fields of renewable assets and colossal storage facilities.

Ansaldo Energia is currently testing a turbine running on 70% hydrogen. Combining hydrogen with natural gas has several benefits. Some 25% hydrogen offers 9% fuel savings, and a 9% reduction in CO2. Far from being theoretical, a Frame 9E is running in the Netherlands with 25% hydrogen.

“As you add hydrogen, the speed of chemical reaction in the combustor changes,” said McKenzie. “Inert gases, such as nitrogen, tend to reduce the speed of reaction; the flame shifts farther downstream, and you have greater risk of flame outs.”

More tuning is needed, too, as the hydrogen content rises. PSM has devised an autotune solution to avoid combustor problems and optimize operations.

Most OEMs have an ongoing hydrogen initiative. “The challenge is to keep the flame stable, avoid flashback and at the same time keep emissions down,” said Asa Lyckstrom, Commercial Manager Product Positioning at Siemens Medium GT Fleet. As hydrogen ignites and burns ten times faster than natural gas, the flame forms closer to the injector and has a wider flammable region than a fuel/air mix. However, only a fraction of the ignition energy is needed to get H2 going compared to methane.

Siemens has designed a 3D-printed DLE burner to keep NOx levels down despite rapid burning. It can be used with hydrogen in the Siemens SGT-600, SGT-700, and SGT-800. Inside the 57 MW SGT-800, 30 of these burners operate within the annular combustor. Siemens is also testing a burner running 100% hydrogen. It is confident that it can run the SGT-800 with 50% hydrogen by volume while keeping NOx below 25 ppm.

The Siemens SGT-A65 (formerly the Industrial Trent) can burn 100% hydrogen using a Wet Low Emissions (WLE) burner that keeps NOx at 25 ppm. It is a three-shaft, axial-flow, aeroderivative GT that produces 60 MW to 71 MW depending on its configuration and is suitable for flexible peaking and combined cycle applications.

More than 115 SGT-A65 machines have been manufactured and installed around the world. Some units have also been installed in mechanical load drive duty for gas boosting in Qatar. In mechanical drive applications, its three-independent-shaft design is suited to the higher power, variable-speed demands of applications such as natural gas liquefaction, gas transportation and gas induction for oil recovery.

The SGT-A65 includes a two-stage low pressure (LP) compressor with variable inlet guide vanes (VIGVs). It has a high overall pressure ratio and high thermal efficiency. In addition, the LP compressor boosts the airflow so that the power level is attained at a firing temperature sufficiently low to meet severe NOx requirements. Yet it is sufficiently high to give good cycle efficiency.

The intermediate-pressure (IP) compressor has eight stages and three rows of variable stators. The high-pressure compressor has six stages, with no variable stators. Overall pressure ratio is 34.1:1 for the 50 Hz dry low emissions (DLE) configuration.

Further, the SGT-A65 incorporates a series of staged pre-mix, lean-burn combustion cans that allow the GT to achieve low NOx and CO simultaneously. Eight combustors are incorporated into a single module.

The SGT-A65 has a five-stage LP turbine, a single-stage IP turbine, and a single-stage HP turbine. Each of these turbines drives its own compressor. The SGT-A65 LP Stages 4 and 5 have a larger gas path area and a lower exit Mach number than the Trent aero version.

A Siemens or Allen-Bradley control system provides integrated operation of multiple control functions while offering remote monitoring. The control system is designed for easy site installation by using remote I/O technology to decrease the number of interconnect cables between the unit control panel and the equipment skids. All train control systems are accessed by a Human Machine Interface (HMI) in the main control room.

The composition of fuels used in gas turbines varies considerably

GTs can burn a great many fuels including biodiesel, lean methane, hydrogen, liquefied petroleum gas (LPG), propane, and more.

“Gas turbines are flexible by nature and we are seeing many requests for them to burn all kinds of fuel,” said Jeffrey Goldmeer, Director of GT Combustion and Fuel Solutions at GE.

Biodiesel, for example, is experiencing a resurgence in Asia. Indonesia has mandated a blend of palm oil for power generation known as B20 (20% palm oil mixed with diesel). These fuels can be used by GTs.

Gas constituents and contaminants can vary widely depending on the source, said Goldmeer. Biodiesel typically has lower SOx emissions than heavy fuel oil, but its sodium content can be changeable. Sources include soybean oil, animal and vegetable waste, and canola oil.

Another alternative fuel of interest is LPG. However, one challenge is the lack of a universal definition: the propane and butane content can change markedly depending on geography or the season or the source wells. The scale of domestic supply logistics may limit build out in some countries.

GE has been running turbines with medium BTU gas, lean methane and fuels high in N2, CO2 or H2S. In regions with limited access to LNG, such fuels may be all that is available. Goldmeer said GE has over 1 million running hours on its GTs on these fuels.

However, he questioned the viability of what is known as green hydrogen: it is produced through the electrolysis of water and powered by solar generation. In his view, it is unrealistic due to the sheer quantity of water needed for electrolysis. Despite that, he entertained the possibility that LNG could be replaced by hydrogen power by 2050.

“But full decarbonization could double the cost of electricity,” said Goldmeer.

GE’s advanced pre-mixer is available for high hydrogen applications. It can deal with up to 50% of H2 by volume. Existing GTs can be upgraded to accommodate this change in fuel. But the rest of the plant may also have to be upgraded: ventilation, enclosures, safety procedures, and more. Heat Recovery Steam Generators (HRSGs) may have to be adjusted to deal with the presence of far more moisture.

“The more hydrogen you add into the fuel mix, the higher the moisture content,” said Goldmeer. “This also impacts heat transfer in the hot gas path, and HRSG operation.”

GE is putting renewed vigor behind its 6F machine in the medium-sized turbine market. With combined cycle plants owning 68% of the market and growing, GE is focusing the 6F in that niche.

Distributed generation, combined heat & power and hydrogen are driving the market for smaller and mid-sized turbines.

Smaller gas turbines find their niche

Martin O’Neill, General Manager of Aeroderivative Gas Turbine Services for GE’s Power Services business, discusses the company’s plans for its aeroderivative fleet.

How confident are you of growth in the aeroderivative market?

According to a 2016 study by Technavio, the global aeroderivative gas turbine industry is expected to grow at an annual rate of nearly 5% between 2016 and 2020. Aeroderivatives are likely to become the go-to technology to provide balancing services for renewable energy. These mounting power imbalances are increasingly forcing conventional generators to operate in a more flexible manner, ramping more frequently to balance intermittent renewables and provide grid-firming services. Given this crucial role in power infrastructure, downtime can be expensive, and it’s critically important that operators have plans in place to ensure continued operations and minimal lost time for maintenance and repairs.

$200 million is being spent to develop new technology and enhance our service capabilities. GE is investing in its Houston Service Center with an overall maintenance overhaul. We have added approximately 40 jobs, and will continue to improve the work environment, tools, fixtures and implement new IT systems. We have added digital capabilities and processes to service more than the current 500 engines and modules per year. This is more volume than any other GE repair center.

On the technology side, GE is continually upgrading the reliability and availability of the existing fleet, as well as repairs for the fleet. We also have some new units, including the LM6000-PF+, the next generation of the LM2500, which is in development, and the recently launched LM9000 aeroderivative.

The three pillars of our strategic direction are decentralization, digitization, and decarbonization. Decentralization is an area where aeroderivatives have been on the forefront in distributed generation applications under 100 MW, such as microgrids, combined heat and power (CHP), and others where the point of power generation is close to the point of consumption. Aeroderivatives were designed and built for these applications and have been doing it for 40 years. Distributed generation is a significant part of the energy mix and where a large portion of our current fleet is in service.

Decarbonization is about adding more solar and wind onto the grid to reduce the emissions footprint. Aeroderivatives are a critical component for renewables balancing. With quick start times under 10 minutes, they can cycle quickly without maintenance penalties and are therefore best suited for renewables balancing. In addition, Dry Low Emissions (DLE) technology, which does not use water, further reduces emissions from these gas turbines.

How is digitization being applied to aeroderivatives?

GE’s Asset Performance Management (APM) software provides aeroderivatives with data analytics to help predict and eliminate unplanned downtime and improve plant reliability and availability. GE provided a digital upgrade for an Italian petrochemical company’s aeroderivative gas turbine. GE’s LM2500+G4 aeroderivative gas turbine and generator will be upgraded with digital technology enhancements. The project marks the first digital implementation of an aeroderivative unit in Europe. APM software is expected to increase the availability of the power plant up to 97%.

What do you see as the primary role of the LMS100?

The LMS100 has a fleet of over 60 operating units (with another 13 being commissioned during 2018–2019). The majority are in North America, and those units are primarily being utilized to provide grid-firming for grids highly penetrated by renewables. As renewables grow around the globe, we believe the LMS100 will continue to be a good fit for much needed grid reliability with its ability to start up and provide 120 MW of power per unit within eight minutes, as well as high simple-cycle full-load and part-load efficiency.

What are your plans for the LM6000 and LM2500?

The LM6000 and LM2500 have greater than 2,500 gas turbines in service with a combined operating experience of over 130 million operating hours. Continued investment in these machines will improve product performance and flexibility. The original LM6000PA configuration was rated at 42 MW. Upgrades resulting in the LM6000PF+ have boosted that to 56 MW at 42% simple cycle efficiency. The first PF+ reached commercial operation earlier this year. The LM2500 platform was originally rated at 22 MW and that has grown to 34 MW in the LM2500+ G4 with 38% efficiency. The TM2500 mobile gas turbine utilizes the same LM2500 gas turbine technology and is the fastest growing aero fleet for GE.

The replacement of an entire engine is known as repowering, while upgrading is the replacement of individual components within the engine. The time taken to replace a unit is a critical factor. Cross-fleet comes into play where there is an existing other-OEM gas turbine running. Typically, these are older technologies with low efficiency and high emissions. A cross-fleet repower removes the other-OEM turbine and repurposes the plant with an aeroderivative unit. This creates greater output, better efficiency, and lower emissions. This allows older plants to become more economically viable. GE can use both new and refurbished equipment, depending on the customer’s economics and lifetime of the plant.

We can repower gas turbines manufactured by Siemens, Rolls Royce, Pratt & Whitney, Westinghouse and Mitsubishi, with our aeroderivative technology. We already have more a backlog of more than $15 million in cross-fleet repowers.

GE bets on aeroderivatives

Condition monitoring is a fundamental discipline using digital technologies that helps improve the safety and reliability of rotating equipment. Digitalization enables the monitoring of equipment on an unprecedented scale.

But just collecting data is not enough. It must be put to productive use. With a concept known as edge computing, data can be processed and analyzed locally with only the most relevant information being sent to the plant or enterprise-asset-management system.

This offers the opportunity to greatly extend the value of condition monitoring, which traditionally has been restricted to critical machinery. With edge computing, large fleets of non-critical assets are within easy reach of round-the-clock condition monitoring.

Condition monitoring has evolved over the years. From the 1980s, the focus was on wiring. Probes are wired to junction boxes and the signals are fed to monitoring systems housed in cabinets where they are read by a higher-level system.

Operational parameters are continuously captured and studied to predict future behavior. If the system detects an abnormality that exceeds a threshold value, it trips the machine to avoid damage. The data is extrapolated for further health analysis.

In the early 2000s, low-cost wireless technology became widely available. This expanded condition monitoring to more machines. However, it meant sacrificing the ability to continuously monitor the asset, as wireless sensors provide readings on a periodic basis to save battery power. Readings were collected and analyzed.

The use of wireless sensors has grown in the process and energy industries. But the investment required made it difficult to justify their deployment across large fleets of assets and auxiliary systems.

Brownfield sites, for instance, typically lack an existing wireless network infrastructure. More recently, technologies based on the Internet of Things (IoT) and Artificial Intelligence (AI) have improved the cost-effectiveness and accuracy of the condition monitoring.

This makes it feasible to monitor the condition of the many non-critical devices that support rotating equipment. Wireless access points can be placed around the facility within range of these machines. Sensors communicate with the wireless gateway that transmits the raw data to a system for analysis.

With wireless technology, the fleet of monitored assets can be increased from less than 5% to about 20% of all machinery. But what about the remaining assets? This is where edge computing comes in.

At BASF’s main site in Ludwigshafen, Germany, only a small number of its many rotating machines were being monitored. Sensors were deployed across the facility to detect bearing temperatures and vibrations and to send readings for analysis.

A single wireless sensor can generate up to 250 megabytes (MB) of raw data per day. More than 99% of it, however, is irrelevant to machine health trends.

Edge computing solves this problem. By processing data locally, inside the sensor attached to the machine, the volume of data sent to a higher-level monitoring system can be reduced from hundreds of MBs to a few kilobytes (kBs).

These devices store the measured raw data for a period of time, in the event the user wants to compare the raw readings with the processed information. Peripheral assets can tell the higher-level system any detected symptoms (such as vibration or temperature readings), and what it thinks the problem is.

This approach to monitoring is now being applied to critical machinery. These assets can be connected to a remote center enabling a team of experts to monitor a greater number of assets.

But critical machinery requires more than a smart sensors for analysis due to the quantity of information to be processed. Instead, a dedicated edge computer is connected to the machine’s control panel.

It reads even larger large streams of data than a smart sensor and converts it into health insights and maintenance relevant information. This can replace the need for 24/7 monitoring performed by a remote operator. Human support is only needed when an anomaly or malicious threat is identified.

There may be a trend in a vast sea of data that a human cannot detect, such as subtle changes over time. Artificial Intelligence (AI) can help to find these patterns.

Condition monitoring is about understanding status. Data can be translated into numerical key performance indicators (KPIs) that provide a value for the likelihood of a specific equipment failure. Data scientists are working to develop methods to predict failure modes.

By using mathematical modelling techniques, it is possible to define how a KPI will evolve in the upcoming weeks or months and calculate the residual time to failure.

With this information, a shutdown can be planned and executed. The more data processed by an AI engine, the more accurate become the predictions of the future behavior of the KPI. In turn, the threshold defining good or critical health can be even more precisely evaluated.

There will always be abnormal conditions caused by unexpected events or external factors. To cover all potential failures in all applications, it takes the involvement of human experts to add real value.

Monitoring systems can distinguish between a known pattern and an abnormal condition. Abnormal conditions are turned over to staff. A feedback loop can then be used to create new KPIs to consider new conditions and failure modes.

Edge computing and AI technologies, backed up by qualified employees, can systematically analyze the health of large fleets of rotating equipment, reducing plant downtime while improving productivity and performance.

Author: Diego Pareschi is global product manager for ABB’s rotating machines products and services for the oil, gas and chemical markets. ABB offers technology for power grids, electrification products, industrial automation and robotics and motion. For more information, visit abb.com or email diego.pareschi@nl.abb.com

 Condition monitoring can be extended from critical assets to all areas of the plant via control systems, smart sensors and digitalization

January/February 2019

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GE bets on aeroderivatives

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