Smaller gas turbines find their niche

Drew Robb

Turbomachinery Magazine, January/February 2019,

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

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 Turbines

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%.

Combined Heat & Power

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 goes CHP

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. ■

Sidebar: Customized lubrication

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.


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.”

Hydrogen challenges

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

Alternate fuels

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.

“Given broad market dynamics such as the increasing penetration of renewables, the greater flexibility of combined cycle plants, and its high efficiency, the 6F has the right footprint,” said Aileen Barton, 6F.03 Senior Product Manager for Medium-Sized GTs at GE.

The GE 6F.03 provides 68 MW to 87 MW and offers 57% efficiency in combined cycle mode. It has 32,000-hour combustion and hot gas path inspection intervals. All versions of the turbine can run on gases and liquids, and additional fuels are added with each technology advancement. This includes natural gas, LNG, lean methane, LPG, H2 blends, sour gas, light distillate, oil, naphtha, and light crude oils.

The 6F.03 AGP (Advanced Gas path) upgrade includes the DLN 2.6+ combustor, as well as improved materials, coatings and cooling. Better metal seals reduce leakage and tighter clearances are achieved with abradable coatings. GE is also promoting a way to upgrade a 6B or 6E machine to the 6F. This leads to a 3% efficiency gain and major fuel savings, said Barton. ■

download issueDownload Issue : January/February 2019