WHY REASONABLE EMISSION RULES SHOULD REPLACE

Air priorities in the environment have changed over the past thirty years. It is likely, for example, that CO2 and fugitive methane emissions will overtake NOx and other pollutants as major new challenges. However, air pollutants, toxics and greenhouse gas (GHG) emissions come from the same sources. They can be prevented together. And efficient gas turbines (GTs) have a major role to play.

GTs, fueled mostly by natural gas and operating in conjunction with renewable energy, can provide large quantities of electrical and mechanical power, thermal heat and cooling services in an environmentally friendly manner. But there are a few facts that should be better understood.

Gas turbines are called that because their Brayton power cycle is based on air mass flow, not gas fuel. Natural gas is quite different that other types of fossil fuel as it is a hydrogen-based vapor that burns cleanly. Due to its low level of pollutants and CO2 emissions, local natural gas-based cogeneration and district energy offers an efficient and resilient energy cycle.

Advances in lean premix Dry Low NOx (DLN) combustion technology have lowered NOx emissions from the 150–300 ppm level of the 1980s to the 15–40 ppm level today, depending on the size and type of unit. This 90% reduction (3 kg/MWhr to 0.3–0.5 kg/MWhr) through cost-effective pollution prevention is unmatched by any other industrial sector and represents a major pollution prevention success story. However, while most DLN systems on large-frame engines work well, additional experience with new DLN systems in aeroderivatives and small units is required before users can be confident of their off-design operating ranges and reliability.

New hydrogen combustion systems that have high NOx but zero CO2 emissions could be credited with more flexible NOx requirements. It could also be claimed that with high-efficiency inlet air filtration capturing local ambient dust and volatile organic compounds (VOCs), there are no net particulate emissions from a modern GT system.

Most regions today have clean energy policies for efficiency, renewables and natural gas. When air pollution and GHG controls conflict with each other, the GT can sometimes get caught in the crossfire. It is recommended that governments and industry bodies switch to improving system efficiency and reliability instead of attempting to reduce NOx levels toward zero. It is unlikely that GTs emitting a moderate 25–30 ppm level of NOx have ever caused a significant air pollution problem.

If forced to further limit emissions to single-digit levels of 2–9 ppm, with high cost and little or no environmental benefit, the ability of GTs to participate with renewables on the grid will be limited. This would be the case, for example, if backend control with ammonia and Selective Catalytic Reduction (SCR) is used after DLN combustion to hit unrealistic NOx targets.

Ammonia-based liquids are dangerous to transport and handle, and SCR produces ammonia slip, particulates, and fouling of the Heat Recovery Steam Generator (HRSG). Additionally, catalytic systems with narrow temperature windows do not perform well in cycling. Their low temperatures may create nitrous oxide (N2O) as a greenhouse gas.

Low-ppm DLN combustors have been installed in large frame engines for peaking and combined cycles. However, smaller cogeneration units that are better matched to heat-to-power ratios for a thermal host have small combustors operating more reliably in the 25–40 ppm range. Operating ranges and start-up conditions could also be improved with simpler combustion designs, and the use of auxiliary duct burners. Low-ppm design requirements encourage larger plants, excessive fuel use, lower system reliability and collateral emissions from SCR.

In small GTs used for pipeline compression, reduced reliability may cause compressor engine trips that can lead to pipeline system upsets, methane venting and GHG releases. A more recent issue is the response to intermittent renewable energy. It requires flexible operating range and start-up/ shutdown cycles, which are difficult for both low NOx/CO combustion, and those using SCR systems. These and other issues call for a review of emissions policy to consider a broader view of environmental consequences instead of a rigid adherence to ppm limits.

One may wonder why gas turbines are still designed and regulated on the basis of NOx concentration (ppmv) standards when reciprocating engines, cars, aircraft and others use output-based standards, such as g/kWhr, g/mile or kg/1000 kg of thrust. A change is needed in the way emission rules are designed.

In 1992, a Canadian government- industry group produced a national guideline for GTs to promote cogeneration with low NOx emissions, based on grams of NOx per gigajoule of power output and GJ of heat output to promote cogeneration. These guidelines reflected cost-effective pollution prevention, CHP system efficiency and unit sizing while addressing both NOx and CO2 emissions. An update was published in 2016 to address larger GTs.

In 2006, the U.S. Environmental Prevention Agency issued a rule (40 CFR 60, subpart KKKK) to incorporate a lb/MWhr output-based emissions standard (OAR-2004-0490, amended in 2012) along with concentration-based rules. As with the Canadian rules, these did not require SCR and had a cogeneration thermal component with flexible emissions monitoring. More recently, several states have passed energy efficiency policies and laws to advance clean and renewable energy, mostly due to climate risk concerns. Most, however, still use ppmv standards for NOx/CO emissions.

A successful lb/MWhr (not ppmv) standard can allow for:

• More flexibility and reliability in clean energy system design. If these are applied to the plant instead of the unit, designers can think more about overall efficiency of power and heat and lower parasitic losses to minimize all emissions

• Recognition of the associated waste heat recovery system, HRSG and steam turbine or district energy piping, as useful “zero emission” or pollution prevent ion energy devices. A typical cogeneration plant with a H:P ratio of 1:1 will have a net CO2 rate of 250 kg (or 550 lb) per MWhr

• Better operation at transient load or changing ambient conditions if combustor mechanical design is not tied to low ppm constraints but rather to optimal power, fuel rate and mass flow. This allows better integration with wind and solar energy.

There is much discussion about life-cycle emissions, and how natural gas has half the GHGs of coal (cogeneration would be a net 70% reduction). A better way to conduct this analysis would be based on a combination of air pollutants, toxics and GHGs. A mix of gas turbine simple cycle, combined cycle and cogeneration systems would achieve a 70%-to-90% reduction in total air emissions compared with coal, if upstream methane emissions can be minimized.

Modern GT cogeneration plants represent a dramatic decrease in all air pollutants and carbon dioxide, while providing local reliability. With clean fuels, and in combination with all renewables and district energy, fuel cells and hydrogen systems, they represent a reasonably sustainable solution for at least the next 50 years. These topics will be considered at the upcoming Canadian Gas Turbine Energy Network conference in Banff Alberta, Oct 21–23, 2019 (

Manfred Klein is principal of MA Klein & Associates, a consulting firm specializing in natural gas energy systems, gas turbines, distributed energy and air emissions solutions. For more information, email maklein@rogers.com

Articles

Air emission prevention

Arja Talakar, Chief Executive Offi cer at Siemens Oil & Gas, discusses the impending separation and reorganization of its energy sector portfolio, as well as opportunities for growth

I began my career with Siemens in 1996 as a rotating equipment and automation systems engineer. I’ve held roles in the United States, Germany, South Korea and Saudi Arabia. Before becoming CEO of Siemens Oil & Gas, I was responsible for Siemens Saudi Arabia. We developed close ties with oil and gas, energy and petrochemicals companies, and executed large infrastructure projects. I hold an MBA from IMD Business School in Switzerland, and an Engineering degree from Germany’s Technische Universitaet Braunschweig.

Can you explain the reorganization and separation from Siemens?

Siemens AG will consolidate its Gas and Power (GP) Operating Company, which combines the Siemens oil & gas, power generation, transmission, and related service businesses into an independent, stock-listed energy company. Siemens Gamesa Renewable Energy will be part of the new company. The launch will create a pure-play company with a portfolio along the entire energy conversion value chain.

What opportunities does the spin-off offer?

It creates a company dedicated to overcoming the challenges facing the energy sector. Our portfolio will encompass conventional and renewable energy solutions from a single source. This will give us the agility we need to adapt to an ever-evolving market.

What equipment comes under the new entity?

For oil and gas customers, we will continue to provide engineering and digital solutions. Our focus markets will include offshore upstream; the entire gas-to-power value chain (gas plants, pipelines, LNG, etc.); refineries and petrochemical plants; and unconventional resources. Rotating equipment (steam and gas turbines (GTs), centrifugal and reciprocating compressors) will remain integral to our portfolio, bolstered through the acquisitions of Dresser-Rand and a division of Rolls Royce.

What trends do you see developing in LNG and pipelines?

Today’s hydrocarbon conundrum is less about supply than environmental impact. Renewables and natural gas are both part of the solution. The latter is abundant and economical, thanks in large measure to the U.S. shale boom. It’s also cleaner relative to other fossil fuels.

As we work to make renewables more cost competitive, the world needs natural gas. Growing demand for clean energy is driving the build-out of transportation infrastructure, namely LNG plants and pipelines, to move natural gas to destination markets. Siemens has developed solutions to address increasing demand to reduce emissions, and the related need for electric-driven LNG designs. We have been developing turnkey solutions, in some cases as an EPC joint venture partner.

The pipeline market is also under pressure to drive efficiency and competitiveness. Machine data and Internet of Things (IoT) solutions are part of that journey. LNG and pipeline operators can harness data to optimize critical equipment, thereby reducing risk and costs while driving efficiency.

Another emerging challenge is cybersecurity. Siemens has bolstered its IoT solutions for oil and gas with a dedicated cybersecurity team.

What trends are evolving in combined cycle power plants (CCPPs)?

Historically, CCPP designs have been used in traditional power plants to boost efficiency and in onshore oil and gas applications requiring large-scale power plants. More recently, we are seeing positive development in offshore CCPPs. This could become a trend due to the advantages of all-electric solutions that reduce the dimensions of CCPPs.

What can be done to reverse the downward trend in GT sales?

We need to differentiate between gas turbines above 100 MW and those below 100 MW. Above 100 MW, the market appears to be stabilizing. The oil and gas market has picked up, driven by the need for additional power. Regions like North America are driving growth because of increased needs for power, but they’re also using using GTs as mechanical drives for compression applications. This

is particularly true for large pipeline companies and gas processing companies. We’re seeing an increase in the use of large power block GTs in compressor trains, particularly in the pipeline market, due to the advantages of using fewer compression trains driven by larger (30 MW) turbines. Studies on compressor trains driven by large power block GTs show tremendous savings potential in terms of footprint and emissions.

How will wind and turbomachinery work together?

Wind energy and turbomachinery are complementary. With oil and gas, power generation, and transmission, the new company will provide the complete spectrum of energy solutions across the conventional and renewable energy landscape.

What digital solutions have the strongest market reach?

Advances in sensor technology and data analytics have paved the way for industrial asset optimization across all verticals. We can use machine data to predict and preempt the failure of critical equipment and enhance safety and efficiency. Similarly, artificial intelligence (AI) is taking asset optimization to the fleet level. Other areas of opportunity include additive manufacturing and virtual reality. Additive manufacturing makes it possible to ‘print’ spare parts and components on demand, and digital twins enable design, testing and training in virtual, risk-free environments.

Siemens prepares to launch energy company

Rotating equipment lies at the heart of most oil & gas processes. Wells, pipelines, refineries and liquefied natural gas (LNG) plants rely on turbomachinery to perform daily operations and fulfill their energy demands.

However, the presence of aging equipment, variations in process conditions and the financial penalties incurred by downtime make it important to pay close attention to maintenance. A vital first step is to understand the operating environment, the performance of a machine and expectations with regard to turnaround times and equipment lifespan. From there, sources of degradation and potential mitigation efforts can be assessed.

Whether it is a planned or unplanned outage, equipment needs to be inspected to understand the extent of damage and potential repair options. Visual and dimensional inspections are done to assess the components in their as-found condition. A range of non-destructive testing (NDT) procedures, such as wet magnetic particle inspection (MPI), ultrasound and liquid penetrant inspection can also be used to discover defects in components invisible to the naked eye.

Repair recommendations are made depending on type of damage, as well as size and location of defects. Based on this, it is determined whether a part can be salvaged, and if so, the most effective method of repair. Basic components, such as shaft seal sleeves, split rings and keys can be easily manufactured.

However, specialized tasks, such as improving impeller or turbine blade geometry require engineering analysis. Worn or damaged components can be refurbished by localized welding. If the damage is minimal, surface restoration coatings can be used instead of welding.

Weld repairs and coating restoration can often save expense by reconditioning the existing components instead of outright replacement. Reverse engineering is another possibility. This can even be applied to major rotating or stationary components such as rotating blades, impellers or diaphragms.

Oil & gas compressors perform a challenging role that places considerable wear and stress on parts. Regular maintenance inspections and planned repair schedules are essential for continued reliable operation, especially for highly stressed parts, such as rotors and critical sealing components.

Due to wear (erosion, corrosion) or damage (rubs, impact from foreign objects), the impeller may not be repairable. A new impeller must be reverse engineered and manufactured to replace the original component. Modern impellers can be made from a single forging of a low alloy or stainless steel using 5-axis milling or electrical discharge machining (EDM). These processes can save many weeks of manufacturing time while delivering a more dimensionally consistent and stronger component than the original, riveted or partially welded construction.

It may be possible to refine the impeller design along with changes to the vane geometry to provide a more efficient gas path design. Combined with improvements in materials and manufacturing techniques, efficiency and reliability can be upgraded. Gas path efficiency can be similarly improved.

Process seals are critical for compressors in oil & gas applications where process gas leakage to the atmosphere cannot be tolerated for safety and environmental reasons. Oil bushing seals and mechanical dry gas seals (DGS) are the most common types used. Oil bushing seals have been used extensively in centrifugal compressors for many decades.

There is still a lot of rotating equipment, especially in refineries, outfitted with this type of seal. They can suffer from buffer oil leakages, problems with oil quality or issues with the auxiliaries, such as oil pumps or degassing tanks. In addition, there are cases when oil bushings have locked up and affected the mechanical stability of rotors due to increased vibration. As a result, there is a trend toward upgrading oil bushing seals with mechanical dry gas seals (DGS).

However, substantial engineering effort should be done before such an upgrade is executed. But when installed, operated and serviced properly, DGS will improve reliability of the compressor and reduce operating and maintenance costs.

Steam turbine blades can fall victim to a variety of damage mechanisms from high temperature creep to erosion, fatigue and stress corrosion cracking. Boosting blade reliability is paramount when repairing a steam turbine. A complete engineering reevaluation of blade design is recommended if a failure has occurred or the turbine’s operating speed has changed.

Such evaluation includes a structural and modal analysis by means of finite-element analysis (FEA) software tools. It provides an insight about stresses in the critical areas (blade root, fillets, shroud) and natural frequencies of the blade that can be excited by the passing frequencies of stationary vanes at a certain running speed. This can cause resonance.

Based on the analysis, recommendations can be made to change the blade or locking hardware material or redesign the root. Resonance issues can be solved by avoiding the speeds of concern, modifying an airfoil or a shroud redesign to shift its frequencies and increase damping.

Upgraded blading provides both efficiency and reliability improvements, which can be further enhanced by the application of protective coatings to extend their life.

Coatings can be applied for dimensional restoration or protection of base material against wear or fouling. Air spray coatings are widely used for protection against fouling and corrosion. Teflon-based coatings, for example, applied to centrifugal compressor gas path components create a non-stick protective layer on the base metal surface.

This improves the efficiency of the parts in the presence of sticky hydrocarbons. Another type of air spray coating is used for corrosion protection. This is typically an aluminum-filled metallic- ceramic coating. Due to conductivity between coating layers, one substance acts as a sacrificial anode and prevents attack on the base metal.

Hard-face coatings, such as chrome carbide, tungsten carbide and stellite are applied by the high-velocity oxygen fuel (HVOF) process. They are harder than the base material to provide protection from erosion, rubbing or fretting. Common applications include steam turbine blades, shaft seals and other surfaces where touching and rubbing to the stationary components may occur.

In addition, hard-face coatings are sometimes used for dimensional restoration. They can be applied to rotating component bores to reclaim the required interference to the shaft, shaft journals and seal areas. This saves time during the repair process by allowing the part to be reused instead of replacing it.

■ Sulzer is an independent maintenance provider for rotating machinery with a global network of specialist service centers. For more information visit: Sulzer.com

Rotating machinery maintenance

The global power generation industry is undergoing a period of transformation as companies strive to keep up with rising customer expectations, more stringent environmental regulations and a rapidly changing energy landscape. But uncertainty, lack of investment and resistance to change has slowed this process. More funding for gas turbine (GT) research and development (R&D) and a willingness to consider alternative technologies may be the keys to future success.

Recent Electric Power Research Institute (EPRI) surveys of power plant operators reveal that inflexible power plants and the deep loss of technology expertise were top concerns. Those in the executive suite, on the other hand, worry mainly about how CO2 regulations will impact the future generation mix.

The U.S. National Electrification Assessment cited several scenarios that may play out by 2050: The conservative scenario has coal and nuclear quite slowly declining and gas generation almost doubling over that period. Other scenarios show a steep reduction in coal with only a small amount remaining based on Carbon Capture & Storage (CCS). Along with that, traditional natural gas generation goes into a steep fall after about 2030, with gas CCS helping to maintain the share of gas in the power mix.

“The U.S. is responsible for 44% of global CO2 emission reductions since 2005, and 80%

of that was from the electricity sector,” said Thomas Alley, Vice President of Generation at EPRI. “Energy efficiency and cleaner generation have been the reason for these gains. Fuel blending can also help lower CO2 further.”

Alley brought up the famous California duck curve which, he said, is getting

more pronounced. 2020 predictions show California needing to add 13,000 MW in 3 hours to cope with the sudden decline of solar generation during the evening peak period.

California may have the most extreme curve, but the same phenomenon is now being noticed in other areas, such as Arizona and even Italy, said Alley. In such areas, peaking plants pick up the slack. But the damage from frequent

start-ups and shut downs must be addressed in budgeting and in maintenance

He pointed out that many combine cycle power plants (CCPPs) will reach end-of-life starting in 2030. By then, the industry needs to develop new gas turbine technology that harnesses low carbon fuels.

Nations are passing strict CO2 emissions laws, and the power generation sector is in the cross hairs. In 2018, the power generation sector produced 36.2 gigatons of CO2, the bulk from coal.

The German government has announced that it will decommission all of its coal plants by 2030 (106 are currently operating). Several U.S. states are following a similar path. An estimated 60,000 coal plants are operating worldwide.

Emissions regulations gradually forcing coal plant closures are also impacting natural gas-fired facilities. In some quarters, the intention is to eliminate gas, or at least inhibit upgrades and new build.

“Technology investment in gas turbomachinery is key to a lower carbon

future,” said Guy DeLeonardo, General Manager for Application Engineering, GE Power. “An increase of one percentage point in CCPPs in the U.S. is the equivalent in CO2 emissions reduction of taking 2 million cars off the road.”

“In the U.S., three out of four kWh come from fossil fuels and nuclear,” he

said. “Natural gas offers the lowest cost per kW of any generation source.”

CO2 levels peaked in 2005. The switch from coal to gas in the power sector has contributed to 67% of the reduction in CO2 since that peak. Renewables contributed 33%. Additionally, the transportation sector has moved above the power sector as the largest contributor to CO2 emissions.

Two out of three new kW built in the U.S. and worldwide will be renewable.

Most forecasts show gas power-based electricity growing at around 2% per year (worldwide and U.S.) through 2027.

Coal is currently receiving about 10 times the investment of gas in R&D, said

DeLeonardo. Much of this has been going to CCS. A general lack of investment in GT research and development, and a cautious stance among OEMs means that alternate technologies receive little attention, he said.

The efficiency trajectory of simple cycle turbines has gone from around 33% in the early eighties to over 40% today, said John Gulen, Senior Principal Engineer at Bechtel. It can reach as high as 44% in some cases.

“OEM machines are finely tuned Swiss watches and their gradually improving technology path has accelerated in the past decade,” he said. “Materials, coatings, seals and cooling techniques have resulted in big gains.”

When it comes to CCPPs, the exhaust gas output monitors steam turbine output via the heat recovery steam generator (HRSG). Current GT turbine inlet temperatures (TIT) are above 1,600°C. CCPPs, like those in Irsching, Germany and Bouchain, France, are the most effi cient, he said. He estimates that the best field-measured net performance is between 61.5 and 62%.

The next hurdle is achieving machines with a 1,700°C TIT. Gulen believes Ceramic Matrix Composites (CMC), additive manufacturing (colloquially known as 3D printing), data analytics and model-based (adaptive) controls will help enable this.

“The best you can engineer a CCPP for efficiency at 1,700°C TIT is 65.3% based on basic thermodynamics and backed by wonderful engineering,” said Gulen

GT capacity currently outstrips demand by four times. 55 GW of GT orders worldwide in 2015 has declined to 25 GW in 2018. Meanwhile, trends toward decarbonization, decentralization and digitalization have made this a challenging time for power generation. Still, whatever the future holds, new GT designs are a necessity.

“Since the invention of the GT, it has been the standard practice to stick to conventional designs by increasing TIT as a means of efficiency augmentation,” said Meinhard Schobeiri, Professor at Texas A&M University. “This is no longer an option.”

Schobeiri’s ultra-high efficiency gas turbine (UHEGT) concept includes a fuel injection system, an ignition system, a stator system and a rotor system. The stator system includes multiple stators positioned radially around a central axis. The ignition system is located within the stator system where fuel is injected, and combustion takes place. The rotor system also includes multiple rotors positioned radially around the central axis downstream from the stators. This eliminates the combustion chambers, replacing them with a distributed combustion system using stator-internal combustion technology. This technology allows for an increase in GT thermal efficiency of about 7%.

“Basically, there are two combustion chambers and a low-pressure and high-pressure turbine,” said Schobeiri. “The pressure ratio has to be close to 38.”

Part of the logic of this concept is that conventional gas turbines have a large mixture and combustion zone that generates corner vortices. As a result, exit temperature non-uniformity is about 22%. This alternative design reduces these vortices by making the combustion path longer through controlled, induced secondary flows to keep fuel particles in circulation longer. Schobeiri urged investment in this approach to achieve market viability.

CHP is a potential growth area for GT-based power generation. Some 1,500 GTs currently provide CHP in the U.S., said Neeharika Naik-Dhungel, Combined Heat & Power (CHP) Partnership Program Manager for the U.S. Environmental Protection Agency (EPA).

Microturbine installs are up in the last decade along with small simple cycle units. But there has been a drop in larger combined cycle installs for CHP. Most installs are in California, Texas and New York. She believes there is abundant potential for CHP in the nation, but policy changes have led to speculation that energy storage could replace GT peakers. This may inhibit CHP growth.

“Gas CHP can economically improve efficiency and reduce emissions, but it requires consistent state policy to promote CHP growth,” she said. Ongoing programs for advanced turbines and future power systems include work on integrated gasification combined cycle (IGCC), i.e., using a high-pressure gasifier to turn coal into syngas then removing impurities from the gas prior to the power generation cycle.

The U.S. Department of Energy (DOE) is also funding projects that use natural gas instead of coal with this technology. “Switching from H-class to J-class turbines in an 820 MW plant is equivalent of removing 14,300 cars from the road,” said Richard Dennis, Technology Manager, Advanced Turbines and SCO2 Power Cycles Programs at the DOE’s National Energy Technology Lab. Supercritical CO2 Supercritical CO2 (sCO2) has a higher efficiency and potentially a 20% lower cost of energy than steam, said Dennis.

But ongoing R&D efforts in this technology are not enough. Supercritical CO2 will require regulation that favors the implementation of CHP and natural gas to encourage sufficient investment. GE Global Research is examining an sCO2-based closed Brayton Cycle, along with other working fluid alternatives. A 10 MW sCO2 demonstration plant is under construction. It uses CO2 instead of steam. Rather than condensing the fluid, it is cooled and reused.

Douglas Hofer, Senior Engineer at GE Global Research said sCO2 can be effective in high-temperature and low-temperature applications. With a 150°C increase in temperature beyond steam, there is a 6.8% bump in Carnot efficiency. sCO2 also has benefits for small applications. It can go below 100 MW without the need for a reduction gear. Low-temperature applications apply mainly to waste heat recovery.

“CO2’s single-phase heat transfer is a bet ter match than steam for the GT exhaust,” said Hoffer. “That means lower HRSG losses.”

Changes in emissions policy and permitting are needed to promote the expansion of clean gas turbine-based energy that includes low-carbon solutions, said Manfred Klein, Principal Consultant at MA Klein and Associates. The system changes as more renewables enter the grid.

“We need other solutions that can partner with renewables to address the intermittency of renewable generation,” said Klein. “Thermal power should also be used for district heating and cooling.”

He emphasized the efficiency and emissions-reduction credentials of the power industry. Cogeneration, using HEPA air filters, duct firing, steam or water injection, Dry-Low NOx (DLN) combustion, methane leak prevention, fast and flexible response time, and waste heat recovery have all helped to raise efficiency and lower all types of air emissions.

“DLN is a huge success story: no other industrial technology has prevented emissions to that degree,” he said. Klein attacked the notion that reducing NOx to tiny levels was a sensible course. States such as California try to hold gas turbine plants to NOx levels below 10 ppm and sometimes as low as 5 ppm. He believes ppm is a misleading metric and prefers pounds per MWhr of power and heat output, as it gives a more accurate picture of actual pollution. If a ppm level had to be set, he felt 25 ppm (or one lb/MWhr) was more than enough for most applications. Anything below that just adds heavy cost, does not deal with CO2 mitigation, is difficult to accurately measure and does not provide much return in terms of real emissions reduction.

Efficient natural gas should not be painted with the same brush as oil and coal, he said. It gets lumped together with these others under the fossil-fuel umbrella. This is leading to a knee-jerk reaction in some areas to try to eliminate gas generation, although more must be done to address fugitive methane leakage.

“Gas is very different from oil and coal; as a hydrogen-based fuel you don’t have to turn it from oil or a solid into a vapor to then burn it,” said Klein.

In Europe, the big market trends are decarbonization, decentralization and digitalization, said Christer Björkqvist, Managing Director of the European Turbine Network (ETN). The EU has legislated a 20% drop in green house gas (GHG) emissions by 2020, a 40% drop by 2030 and an 80% drop by 2050 (measured against 1990 levels), he said.

But the majority of EU members states advocate net zero emissions by 2050. They believe that electrification, energy efficiency, the use of hydrogen as an energy carrier, and new technology backed by lifecycle changes will help to reach that goal.

Power-to-X, for example, is garnering a lot of attention and has two meanings. Primarily, it refers to the conversion of typically renewable energy into methane gas (Power-to-Gas), liquid methanol (Power- to-Liquid) and others. It also refers to conversion technologies that enable an integration of the energy consuming sectors — buildings (heating and cooling), transport, and industry — with the power producing sector. The X refers to the numerous conversion possibilities, for example: power- to-hydrogen, power-to-ammonia, power- to-chemicals, power-to-heat, power- to-liquid, power-to-methane, power- to-mobility, and power-to-syngas. In the latter case, the resulting synthetic gas can be transported through existing pipelines and used in gas-powered engines.

Germany alone produces more than 40,000 MW of wind and solar, yet 5,500 MW is lost as the grids cannot absorb all of it. This excess power could be used for production of hydrogen and oxygen via electrolysis. Due to the shortage of H2 infrastructure, you can add CO2 to hydrogen in a methanation reactor to produce a methane- based syngas, which would be regarded as carbon neutral. It could be used in power generation or transportation using existing infrastructure.

Björkqvist believes gas turbines have a future both in the energy transition and beyond. He cites rising investment and demand for LNG and natural gas in recent years to show that traditional hydrocarbon- based fuels still have a role to play for many years to come. Looking ahead, he thinks it is feasible to convert peaking plants and combined cycle power plants to gradually run on an increasing percentage of renewable syngas and eventually supply net-zero electricity.

Meanwhile, European countries are initiating CO2 taxes ranging from $24 to over $100 per ton. This is happening in tandem with legislation to outlaw coal. Norway already has no coal, France plans to get there by 2022, Sweden by 2022, UK by 2025, Italy by 2035 and Germany by 2038.

“Rising CO2 taxes give more incentives for coal replacement,” said Björkqvist. “Fast-growing renewables also offer grid balancing and Power-to-X opportunities for gas turbines.”

EU policy makers consider gas turbines as little more than a bridging technology to achieve the 2030 targets until other technologies mature. A major challenge lies ahead to convince politicians that GT technology can be developed to operate safely on low-carbon and carbon-neutral fuels by 2030 when natural gas may be labelled a high carbon fuel.

“The gas turbine is not just a transitional technology to 2030; it can be an enabler in meeting the long-term climate and energy targets,” Björkqvist said. “The perception of our technology has to change to ensure public funding and support for the required research & development.”

Many politicians believe that increasing energy efficiency, introducing more renewables and smart grids and implementing available storage technologies should be enough to meet their goals.

Björkqvist said this pathway will not succeed. The more intermittent renewables (wind and solar) there are in the energy mix, the higher the backup capacity and load following capability that will be required. “The future is in our hands,” said Björkqvist. “We have to make the general public and governments realize the value of our technology and, in parallel, ensure that the required technical solutions are being developed."

Key concerns: plant flexibility, loss of technological expertise, deficient R&D investment and more stringent emission laws.

September/October 2019

Air emission prevention

Siemens prepares to launch energy company

Rotating machinery maintenance

The future of power generation