Blue hydrogen, and more long-term, green hydrogen (i.e., hydrogen produced via renewable-powered water electrolysis), holds enormous potential in helping the world achieve its decarbonization goals. In particular, green hydrogen promises to bring flexibility and dispatchability to emissions-free power from intermittent sources like solar and wind.

Two central building blocks are needed to make this reality:

A sufficient source of blue/green hydrogen production

A needs-based storage and transportation network that can reliably and cost-effectively supply hydrogen to end-users.

Given the high costs and complexity associated with developing new transportation infrastructure, many pipeline operators and regulatory bodies are asking the question, “How much effort would be required to repurpose existing natural gas infrastructure to accommodate hydrogen?”

Let’s look at some specific changes required to make pipeline assets ready for hydrogen operation, focusing on the rotating equipment within compression stations.

Contrary to popular belief, the effective transport energy density of hydrogen in an existing gas pipeline is only slightly lower than that of natural gas. Therefore, the switch from natural gas to hydrogen would have little impact on a pipeline’s capacity to transport energy. However, the much lower molecular weight and heating value of hydrogen relative to natural gas have implications on the type and design of rotating equipment used in compression stations.

For pipelines transporting 100% hydrogen, reciprocating compressors are currently the most economical solution. With reciprocating compressors, the gas is efficiently compressed in the cylinders. By increasing the number of cylinders and drive power, as well as a parallel arrangement of compressors, a viable transport capacity of up to 750,000 Nm³/h can be achieved.

The compression of hydrogen with turbocompressors is more complicated. Although centrifugal compressors for hydrogen recycle service have been used in downstream and petrochemical applications for decades, their efficiency is lower than that of reciprocating compressors.

For a given impeller tip speed in a turbocompressor, the pressure increase is directly proportional to the molecular weight of the gas. Hydrogen’s molecular weight is approximately 1/16th of methane, which means that achieving a comparable pressure ratio to an existing natural gas line would require much higher impeller tip speeds or a much higher number of compressor stages in several compressor casings.

Impeller mechanical strength limits are directly correlated with tip speed. The maximum allowable tip speed of the impeller varies depending on the material used. Typically, these material strength limitations are not a concern when designing compressors for service with air, CO2, or natural gas. In the case of low weight gas compositions, like hydrogen, however, they can be approached. Therefore, the design of a compressor for hydrogen operation is not dictated by aerodynamic limits, so much as it is by the impellers’ mechanical strength limits.

Extensive studies on the design of blades and impeller geometry have shown that when high-strength titanium alloys are used, these stress levels can be reduced to allow for pressure ratios of up to 1.45:1 per stage. Therefore, a six-stage machine with a total pressure ratio of 4:1 with 100% hydrogen is technically possible. It can be assumed that the commercial availability of these machines will increase in the coming years when the market demands them.

Overall, the extent to which compression equipment will need to be adapted will depend on the pipeline’s hydrogen content. If the admixture is less than 10% hydrogen, the compressor can be operated without any significant changes.

When the admixture is under 40% hydrogen, the compressor housing can be maintained, but the impellers and feedback stages and gears require adjustment. For pipelines with greater than 40% hydrogen content, the entire compressor must be replaced.

 Figure 1: Sulfide-stress-cracked impeller from a plant where the operator failed to specify hydrogen sulfide in the gas.[/caption]

The switch from natural gas to hydrogen also warrants consideration of the materials used for rotating equipment and the physical pipelines. Hydrogen embrittlement, or hydrogen-induced cracking (HIC), is a type of deterioration that occurs when atomic hydrogen diffuses into an alloy (see Figure 1). Depending on the steel grade and the operating conditions of the pipeline, this reduction in toughness can lead to the growth of existing crack-like defects, thus reducing the service life of the line or component.

Although HIC can occur in pipeline walls, it is unlikely as there are rarely dynamic pressure fluctuations during regular operation, and no atomic hydrogen is produced during transport. It is generally accepted that both are required for the phenomenon to occur. HIC, however, is a concern in impellers, which are subject to stress due to high speeds.

While the titanium alloys used for high-speed impellers offer excellent strength, they are subject to hydrogen embrittlement and HIC in the presence of high concentrations of hydrogen. To avoid these deteriorating mechanisms, titanium impellers require reliable surface coatings.

Design changes can be made to reduce the likelihood of HIC in compressor impellers, for example, better interstage cooling. Ultimately, however, better alloys must be developed with greater component reliability.

A test method has been developed to simulate high-speed impeller conditions in a turbocompressor operating in pure hydrogen service. The technique will be presented at a technical conference late in 2020. It challenges a historical specification limit within the oil and gas production work. The goal is to provide guidance on a new NACE standard for testing HIC and identify fit-for-service environments, much like the limits for stress corrosion cracking (SCC) in NACE MR0175 (Figure 3).

 Figure 3: Siemens Energy proposes a test method where corrosion-resistant autoclaves are required to perform the tests on pre-stressed specimens at elevated pressures and temperatures.[/caption]

Gas turbines that drive compressors draw their drive energy directly from the line. They must be adapted accordingly to the hydrogen admixture.

The combustion characteristics of hydrogen differ from natural gas and other hydrocarbon fuels. This poses challenges for the design of hot gas path components. It is a challenge to control the flame, maintain combustion system integrity, and reach the desired level of emissions.

Many gas turbines are already capable of operating on high percentages of hydrogen fuel, some at 100% hydrogen (Figure 2).

 Figure 2: Hydrogen content possible in various Siemens Energy models.[/caption]

The capability of each unit depends on multiple factors, one being the type of combustion system the turbine utilizes, either dry-low emissions (DLE) or wet-low emissions (WLE). Existing turbines can be upgraded to allow increasing hydrogen content in the fuel or even work with 100% hydrogen in the future.

In gas turbines with DLE combustion systems, fuel and air are mixed before combustion to control flame temperature. This, in turn, controls the rate of emissions. The relative proportions of fuel and air are one of the driving factors for NOx and flame stability. Hydrogen’s higher reactivity poses challenges for the mixing technology in DLE systems, including:

• Higher flame speeds increase the risk of the flame burning closer to the injection points, traveling back into mixing passages, or burning too close to liner walls. This risk increases as hydrogen content rises and with increasing combustion inlet and flame temperature.

• Hydrogen’s lower auto-ignition delay compared to methane increases the likelihood of igniting the fuel in the mixing passages.

• Changes to thermoacoustic noise patterns because of the different flame heat release distribution can lower component life.

DLE combustion systems are available using swirl stabilized flames combined with lean premixing that can achieve low NOx emissions without diluting the fuel. Hardware and control system changes are also required for higher hydrogen fuel content to allow systems to operate safely, meet NOx emissions limits, and manage varying fuel compositions. A goal has been set of making industrial turbines with DLE capable of burning 100% hydrogen by 2023.

Non-DLE technology uses diffusion flames or partially premixed flames. It can handle variability in fuel composition. On certain non-DLE models, 100% hydrogen is already possible. A disadvantage is that diffusion flames require dilution to control NOx emissions. Higher flame temperatures mean higher NOx emissions without abatement. Dilution is achieved by the introduction of nitrogen, steam, or water into the flame:

Nitrogen dilution is often economical in power plant applications as it is a byproduct of gasification. Steam is also available in combined cycle applications. However, this is not the case in compression stations, with the turbine in mechanical drive. Additionally, for single-shaft turbines, surge margin can be a challenge with diluted high-hydrogen fuels due to changes in the balance of volumetric flow between the compressor and turbine. This issue can typically be managed by making modifications to the compressor or turbine.

A building block of a low-carbon energy system is a needs-based storage/transportation network to supply hydrogen to end-users. In parts of Europe, establishing a hydrogen infrastructure may be possible with little effort. The pipeline networks can gradually be converted to hydrogen operation with an investment of an estimated 10-15% of the cost of new construction. ■

Articles

Readying pipeline compressor stations for 100% hydrogen

Hydrogen compressors are widely used for process applications in refineries, petrochemical plants, and energy storage. More recently, there is discussion centered on compressing hydrogen for pipeline transport to support a carbon-free hydrogen economy.

These compression applications can be divided into two main groups: hydrogen-rich and pure hydrogen. A hydrogen-rich application has a process gas that has a high percentage of hydrogen but contains other constituents. A hydrogen-recycle compressor in a refinery is an example of this as it compresses both hydrogen and other hydrocarbon gases. A pure hydrogen process is just that, 100% hydrogen, and the typical application for this is an energy storage compressor.

Hydrogen compressors increase the density of the gas by adding mechanical work. There are two common compressor types used for hydrogen compression: reciprocating (positive displacement) and centrifugal. Reciprocal compressors decrease the volume of the trapped gas and increase its density by displacement of a piston inside a cylinder. Centrifugal compressors are continuous, dynamic rotating machines that impart tangential kinetic work using a series of spinning impellers and stationary diffusers with return channels to increase the gas density. Barrel-type centrifugal compressors are preferred for hydrogen compression because of their ability to operate at higher pressures and to be reliably sealed, as well as allowing easier access for maintenance and repairs.

Compressing hydrogen and other low molecular (mole) weight process gases presents significant challenges. Hydrogen is a very light, low mole weight gas with a high speed of sound. Consequently, it has a low-pressure rise for each stage inside the centrifugal compressor. This necessitates a large number of stages or very high impeller operating speeds.

There are three main problems with this. The first is that centrifugal compressors can mechanically fit only a limited number of stages between the bearings and inside the casing. The longer the bearing span, the more complex the rotordynamics, and there are finite limits to shaft length in any compressor. The second is that the material for the impellers needs to have sufficient strength while being light enough to handle the centrifugal hoop stresses at high rotational speeds. For hydrogen compression, the compressor material also must withstand hydrogen embrittlement, or the ingress of hydrogen into a component. This can reduce the ductility and load-bearing capacity of the compressor, and cause cracking and catastrophic brittle failures at stresses below the yield stress of susceptible materials. Finally, difficulties arise in static and dynamic sealing because of the size of the gas molecules. Hydrogen molecules are small and light, which allows them to escape and leak through gaps most other process gases cannot.

 Figure 1: Elliott hydrogen hydrocracker compressor used in refinery processes.

This unit processes a low mole weight gas (4.0 MOL) that is approximately 91.5% hydrogen. It has five impeller stages, an inlet pressure of 2,335 psia, maximum continuous operating speed of 12,027 rpm, and can process 1,692 ICFM through its 10-inch inlet nozzle.[/caption]

Elliott’s work in hydrogen compression can be seen in hydrocracker machines found in many refinery and petrochemical processes (Figure 1). The company continues to advance its hydrogen compression capabilities with developments in areas such as hydrogen recycle, pure hydrogen, net gas hydrogen, and hydrotreater feed. High speed and long bearing span are best addressed with advanced rotor dynamic analysis and robust bearing designs. The number of stages per compressor should be limited to keep the bearing span and vibrations within acceptable levels. The risk of hydrogen embrittlement should be managed by restricting the yield strength of the materials used and adding stainless steel cladding or coatings.

API specification 617 limits materials in hydrogen gas service to those with yield strength less than 120 ksi or hardness less than 34 HRC to prevent hydrogen embrittlement. The material yield strength limit reduces the maximum allowable speed potential of any given impeller. However, hydrogen-rich compressors often operate at high speeds to achieve the required pressure rise. This issue can be addressed with high head impellers, and using alternative materials with higher strength-to-density ratios. Some examples are titanium alloys, continuously wound carbon fiber, and ceramics. A continuously wound carbon fiber shaft has high torsional strength and a quarter of the density when compared to a steel shaft.

 Figure 2: A specialty hydrogen recycle coating developed by Elliott was applied to a 5-stage compressor rotor in hydrogen service. Its anti-fouling properties prevent buildup of material in the gas path, provide corrosion resistance against ammonium chloride, and increase wear and durability resistance to solid particle erosion. It is good for continuous operation up to 500°F (260°C).[/caption]

In addition, gas-compatible static O-rings and dynamic dry gas seals can be employed in hydrogen-rich machines to address sealing issues. Using dry gas seals also has the benefit of eliminating oil contamination issues found in reciprocating compressors.

Hydrogen recycle machines in refineries have specific corrosion and fouling concerns due to ammonium chloride, which can form during the process. Ammonium chloride is highly corrosive, and traditional compressor coatings are not effective in minimizing corrosion and fouling due to ammonium chloride. A specialty coating is available to deal with such issues (Figure 2). It is typically used in refinery processes, particularly if the compressor runs on nitrogen for startup or catalyst regeneration. Pure hydrogen compressors would not require this type of coating.

 Figure 3: The Flex-Op arrangement, developed by Elliott in collaboration with Voith Turbo, is comprised of three to four individual centrifugal compressors arranged around a single multi-pinion gearbox. The stages are split up into separate bodies to manage the bearing span.[/caption]

To improve the head, flow, reliability, and operational flexibility capabilities of hydrogen compressors, the Flex-Op compression arrangement has been developed (Figure 4). It is comprised of four compressors on a single gearbox. In addition to hydrogen compression, it is suitable for energy storage, processes, refining, and chemical compression. Originally designed for high-pressure ratio and high-flow compression, it has enough flexibility to allow individual compressors to either run in series or in parallel (or both) (Figure 3).

Hydrogen compression requires a large number of compression stages to achieve a reasonable head for a very light gas. With the Flex-Op arrangement of three to four casings, up to forty impeller stages can fit into a footprint that traditionally only fits up to ten. This shrinks the linear footprint of the compressor section from upwards of forty feet to roughly ten feet and offers up to four times the compression capability within the approximate linear footprint of one compressor (Figure 4).

 Figure 4: Conventional compressor tandem versus Flex-Op arrangements.[/caption]

This design is operationally flexible. It can run up to four compressor casings in series or in parallel, with multiple extractions and side streams. Since each rotor is connected to its own pinion via a flexible shaft coupled to the central gear, the rotor speeds can be individually optimized for highest aerodynamic efficiency. A barrel casing coupled with a single multi-pinion gearbox allows the whole assembly to be powered by a motor with a Variable Frequency Drive (VFD) or a motor in conjunction with a Variable Speed Drive (VSD) (Figure 5).

 Figure 5: Flex-Op couples up to four Elliott barrel casings with Voith’s single multi-pinion gearbox, powered by a motor with a VFD, or by a motor in conjunction with a VSD for speed control.[/caption]

The gearbox design enables each compressor to operate at a different speed. If clutch or torque converter couplings are implemented at the compressor shaft ends, engagement/disengagement of individual compressors is possible. The arrangement of the casings allows the compressors to operate in parallel for double the throughput, or in series with intercooling between bodies for maximum pressure ratios. The series option is important for higher pressure ratios with low mole weight gas.

During hydrogen recycle startup, nitrogen is used to purge and heat up the reactor. This is because lighter gases do not generate much heat during compression. However, higher mole weight gas cannot be compressed through forty stages designed for low mole weight gases without consequence. By changing valves, nitrogen can be compressed at a lower speed through two or more bodies in parallel to increase the flow rate during startup to warm up the reactor. The machines can be switched to series operation as the mole weight drops. This is unnecessary for pure hydrogen service since there is no reactor to warm up.

This design can accommodate multiple side streams or extractions for carbon sequestration, gas plant and pipeline, fleet CNG and bio fuel gas, and other non-hydrogen applications. Casings of different sizes can be selected. For example, a larger compressor can be accompanied by two smaller casings. This option works well with higher mole weight applications such as CO2. Similarly, four compressors can be run with a single motor and gearbox in parallel (and turned on/off as necessary) for a pipeline application to handle a wide range of flow. This design concept even allows for compression of two different process gases in parallel using one motor and one gearbox.

The Flex-Op design concept is efficient. It has advantages over competing designs such as reciprocating compressors or extremely high-speed centrifugal compressors. It uses standard design compressors and impellers. The arrangement is compact and easy to maintain and repair. It is operationally flexible, with the potential to engage/disengage individual compressors, to switch between series and parallel operation, and to run each compressor at different speeds. Most importantly for pure hydrogen compression, the process gas is safe from risk of oil. Finally, the Flex-Op design concept is not limited to just hydrogen applications. For flexible high-pressure ratios and high flow with multiple extraction or injection points, Flex-Op is proven technology.

 is Director of R&D at Elliott Group. Over the past 20 years, Elliott has produced more than 100 hydrogen-rich compressor trains for a wide range of applications.

 is Manager of Compressor Development, R&D, at Elliott Group, a manufacturer of centrifugal compressors for hydrogen service since 1955. For more information, visit Elliott-Turbo.com

 is a Compressor Development Engineer, R&D, at Elliott Group, a company that designs, manufactures, installs, and services turbomachinery for prime movers and rotating machinery.

 is Senior Vice President of Research & Development for Industry at Voith Turbo. Voith Turbo, a division of Voith GmbH, specializes in intelligent drive technology and systems. For more information, visit Voith.com

Integrally geared barrel compressors address the challenges of hydrogen compression

Fans, blowers, and compressors lie at the heart of air and gas handling applications for many industrial processes. Over time, however, an increasing requirement for depth of focus has evolved for many application engineers while the breadth of experience and vision has diminished. It is crucial to appreciate the range of compression technologies available and balance the demands of performance reliability, operational efficiency, and capital expenditure. 

Positive displacement compression may be considered cyclic. Gas is drawn into an increasing volume of compression chamber before being closed from the inlet. The compression chamber volume is subsequently reduced, thus creating an increase in pressure (and temperature) which can then be “pushed” into the higher pressure outlet system by means of a valve or port as the compression chamber continues to reduce. Closing the outlet and opening the inlet valve or port completes the cycle. 

A piston or diaphragm compressor uses the reciprocating linear motion with valves to execute the cycle whilst rotary displacement compressors such as screw and lobe compressors operate using a porting system to sequence the suction and compression cycle. 

Figure 2: Twin screw compressor. The slide valve feature present in Howden’s oil-injected screw compressor range gives the added benefit of an energy-efficient method of capacity control.Oil-injected twin screw compressors operate with oil injection into the rotor chamber, which is used for cooling, sealing off the clearance gaps, and lubricating the rotors. The directly driven male rotor, in turn, drives the female rotor using the injected oil as a hydrodynamic film to maintain efficiency and prevent wear. Conversely, oil-free screw twin compressors are designed to operate using a timing gear set up to synchronize the rotors and negate the need for oil injection. 

Certain types of gases are not suitable for compression in an oil-injected twin screw compressor, such as polymer-forming or corrosive gases and gases with high particulate contamination levels. The oil injected into the rotor chamber mixes with the gas being compressed. In this case, compression in an oil-free screw compressor is often the best approach, as, in this variant, the gas being compressed is not contaminated with any other medium. 

Typically oil-injected twin screw compressors can achieve discharge pressures of up to 75 bar and oil-free range, reaching discharge pressures of up to 45 bar. Capacities up to 74,000 m3/hr and a compression ratio of 15:1 are possible. 

Twin screw compressors have the characteristics and stability of a reciprocating compressor and offer the advantages of reduced size, low vibration, and fewer moving parts. This extends operating life and reduces maintenance costs. 

Reciprocating piston compressors utilize the linear reciprocating motion of a piston within a cylinder to draw air or gas into an expanding chamber. Reversing direction, the piston then reduces the volume of the chamber to compresses the air or gas to a point where it exceeds the downstream system pressure and is then delivered to the pipework system or storage. Spring-loaded plate valves operate as non-return valves for suction and discharge, being fitted close to the cylinder head or cylinder wall to minimize clearance volume and increase volumetric efficiency (Figure 3). 

Typically an electric motor or driver provides power and rotary motion to the crankshaft of a compressor, which is then transferred into linear motion by a connecting rod. For an air compressor, the connecting rod is coupled directly to the piston providing a single compression effect with suction and discharge plate valves mounted within the cylinder head. 

A more complex arrangement for reciprocating gas compressors is required where a crosshead and guide is connected to the connecting rod and used to create linear motion. A piston rod passing through distance pieces and several sealing arrangements joins the piston guide to the piston. The gas is compressed on both sides of the piston and is referred to as double-acting. Dependent upon the application, the piston compressor can be oil lubricated or oil free using PTFE (Polytetrafluoroethylene) or similar piston rings. 

Reciprocating compressors are rarely single cylinder and can be arranged in vertical, Vee, W, and horizontal opposed configurations. The more complex gas and higher compression ratio duties tend towards horizontally opposed machines arranged to facilitate free draining of any condensable liquids. These are frequently demanded within the oil and gas industries. 

Compression ratios are of the order 4 to 1 per stage. Pulsation dampeners are essential for suction and discharge. Inter-stage cooling and separation of condensate allow reliable compression of gases ranging from atmospheric pressure to 600 Bar and higher. Typical applications include refinery, chemical, petrochemical hydrogen and process gas compression. 

Diaphragm compressors are a separate form of a reciprocating compressor. They specialize in the compression of high purity/ultra pure gases, corrosive gases, and extreme pressure applications. 

The diaphragm ensures total separation for the gas from any form of lubrication or consumable friction seal. The diaphragm’s reciprocating action is achieved by direct mechanical means or indirect hydraulic pressure applied across the diaphragm’s underside for higher pressure and more complex/hazardous application. Modern materials used in the laminated design of actual diaphragm, have dramatically increased the reliability of these machines and provided early warnings of potential rupture. 

Capacities are restrictive with diaphragm compressors, but sealing and purity are assured for pressures up to 3000 Bar and beyond. Typical applications include medical and pharmaceutical gases, specialty gases for semi-conductor production and hydrogen fueling stations. 

For high workloads, dynamic compression can deal with large volumes and provide the highest efficiencies. Axial and radial/centrifugal design concepts are available. A dynamic compressor works with pressure as the constant. The high-speed rotation of blades or an impeller accelerates the gas velocity to provide kinetic energy or dynamic head, which is transformed into static pressure through a tapered diffuser. The molecular weight of the gas being handled together with external factors (such as temperature and pressure) affects density and performance. For uncontrolled constant speed operation, increased gas density at inlet produces increased pressure rise and mass flow with a corresponding increase in power. 

Dynamic compressors have an advantage in term of compression capacity. With noncontact components, performance does not degrade under normal operation. Once placed into service, dynamic compressors can operate continuously for several years. 

Low-pressure rise single-stage axial fans using blades, for example, are commonly used for building ventilation systems. They are used in applications such as cooling towers, handling high-temperature flue gases, mine shaft ventilation, tunnel ventilation, and aerodynamic wind tunnel testing. 

They can become extremely large two-stage units fitted with drivers above 10 MW. Significantly higher pressure rises can be achieved with multistage axial turbine compressors that operate with substantially higher blade tip speeds, more resemblant of an aero jet engine, and equally high cost. Air separation plants and gas-processing plants sometimes make use of these machines. 

Low-pressure rise single-stage centrifugal fans, on the other hand, use fabricated impellers to accelerate the gas stream and provide pressure head. Typically, industrial fans operate with tip speeds up 150 m/s, exceeding 200m/s for higher-head applications. Typical applications include industrial handling of air and gas for combustion, processing, and hygiene ventilation. 

Demand for increased pressure rise has led to tip speeds increasing beyond 250m/s (can exceed 500m/s given modern materials and design techniques). This is the territory of turbo blowers and compressors where the gas is channeled through the impeller and efficiency gains are obtained by minimizing the gas stream’s turbulance as it passes through the machine at velocities factored in term of mach number. Applications include reactor and furnace/smelter air supply, aeration during wastewater treatment and flocculation of precious metals, sulpuric acid plants and fertilizer production, process gas handling and mechanical vapour recompression (Figure 4). 

 Multistage centrifugal compressors can take the form of single-shaft multi-impeller or integrally geared where reduced diameter impellers and shaft are mounted around a central drive gear. Standard application of multistage centrifugal compressors trend toward process plant air with large bespoke designs for oil and gas processing. ■ 

Richard Smith is Director of Product Strategy at Howden, a provider of air and gas handling compressors for over 160 years. For more information, visit howden.com.

The Powerhouse of Industrial Processes: Centrifugal, screw and reciprocating compressors

A Review of Compressor Cleaning Options and Best Practices

The purpose of owning and running a gas turbine (GT) is to harness work. As a fouled turbine lowers output and throughput, cleaning must be done correctly to maintain a productive, profitable turbine.

Fouling consists of deposited airborne particles ingested from the environment. These can include salts and minerals or hydrocarbons, as well as aggressive gases such as SOx, NOx or chlorine. Once these particles adhere to the compressor blading, surface roughness increases. This impacts aerodynamic and compressor performance.

In addition, ingested pollution contributes to blade corrosion. These chemicals react with moisture from the environment to create acidic compounds that reduce the operational life of the machine and raise maintenance costs.

As bleed air can be contaminated by foulants entering the cooling system, fouling can block or partially block cooling passages in hot section stators and blades. This results in accelerated thermal fatigue.

 Table 1: Advantages and disadvantages of different cleaning regimes[/caption]

There are four main cleaning options (Table 1), each with advantages and disadvantages. Abrasive cleaning is seldom carried out anymore due to its risk potential. The other three are performed regularly on GTs of varying sizes across the world.

A review was done of the net work produced before and after a wash on a 45 MW turbine collected over 15 weeks at one plant. An increase of 35% net work is seen when using a combination of, offline and hand washing. When only online washing is carried out, performance is also boosted, albeit with a downward trend post-wash. It is recommended, therefore, that both online and offline washing are used as they can be carried out during operation and require no shutdown (Figure 1).

 Figure 1: Effect of cleaning on net work using various compressor washing techniques.[/caption]

The question of whether to use water or chemicals should be considered on a case to case basis. It depends on the type of fouling seen. Fouling elements can originate from the environment, fuel impurities, corrosion, or leakages. Some of this can be mitigated with fuel selection and effective maintenance schedules. To maximize efficiency returns, the right injection fluid must be selected.

The three main categories of wash fluid are demineralised water, hydrocarbon aromatic solvent, and surfactant-based fluids. A mixture can be used to widen the effective range of foulant removal (Table 2).

 Table 2: Types of injection fluids[/caption]

Some operators are moving away from hydrocarbon solvent-based wash fluids, preferring fluids they can dispose of more easily and that require fewer safety considerations. Many of the most popular fluids on the market are surfactant based, which are well suited to capturing foulant and carrying it through the engine without redepositing on later stages.

Another consideration when selecting wash fluids is foaming and how long the foam takes to rinse out of the turbine. Excessive foaming can extend wash times and the number of rinse cycles with an associated increase in the volume of wash effluent requiring disposal management. On the other hand, foam increases the surface area of the fluid. This enhances fluid distribution and the foulant penetration. This also enables the foulant to be carried out of the engine more effectively.

Operators are advised to perform an effectiveness test with a foulant sample to ensure the right chemical is selected. Effectiveness can vary widely based on foulant composition and chemical brand.

In a heavily salt-laden environment, a water wash may be the most effective type of wash. But in most other environments, the foulant will be a regular surfactant mixed water wash. Ideally, it should be used in conjunction with a less frequent offline solvent or solvent mix wash to remove heavy/difficult fouling if the seals permit it. Once foulant has been removed by the wash fluid, it passes further into the GT compressor. It is usually expelled out of the exhaust or drained from the compressor along with the wash fluid.

To ensure no significant build-up occurs in later compressor stages, a regular offline wash should be performed with a suitable number of rinse cycles, ensuring the effluent is within recommended boundaries for conductivity and appearance. The effluent taken from successive rinse cycles shows a definite change in conductivity and appearance (Figure 2). This suggests the offline wash only loosens the dirt; it is the rinse cycle that removes it from the compressor. This highlights the importance of offline cleaning to remove foulant and any later-stage deposits.

 Figure 2: Effluent samples taken during an offline wash.[/caption]

If done incorrectly, compressor cleaning can unintentionally cause more damage due to erosion. Material erosion is dependent on droplet velocity and material exposure. Larger droplets, higher velocities or longer exposures create higher erosion rates. However, a threshold must be crossed before any erosion takes place or material is removed.

Smaller particles travel at much higher velocities than larger but are less lightly to impinge on the surface. With less impingement one would expect to see less erosion or material loss. This suggests that as particle size reduces, the velocity threshold where erosion occurs rises. Further, a small amount of friction is necessary for the removal of foulant. However, too much will cause damage to turbine blades by removing material. A spray with a 100-250µm average droplet size (Sauter mean diameter) will be large enough to remove foulant, but not so big as to pass their velocity threshold and cause damage.

The factor of wettability must be considered with regard to cleaning effectiveness. Wettability is measured by the contact angle of droplets. Hydrophilic surfaces allow droplets to spread wide, giving a low contact angle below 90°. On hydrophobic surfaces, droplets keep their shape with contact angles over 90° (Figure 3). Typically, metallic materials are hydrophobic while ceramics tend to have very good wettability. GT compressor blades are generally made from titanium which is hydrophobic. Thus, one would expect them to have limited wettability. However, modern compressor blades have ceramic coatings to improve heat resistance. Their secondary benefit is enhanced wettability with a much lower contact angle than titanium alone.

 Figure 3: Contact angle of different surfaces[/caption]

For the wash fluid to properly coat the turbine blades, viscosity also plays a key role. High viscosity fluids take longer to spread over the surface, limiting cleaning effectiveness. It appears that viscosity has a greater effect on wetting time than on the contact angle with little change when the contact angle is increased. This is relevant to GT applications as injected droplets have limited contact time with compressor blades; the shorter the wetting time, the better fluid will cover and clean the surface.

Online cleans require specialist hardware that may not be have been installed when the machinery was manufactured. However, it is often possible to retrofit this hardware and add online cleans to the maintenance schedule. ■

The essentials of turbine cleaning

Transforming gas turbines into low or zero-carbon emitting systems can be done through pre- or post-combustion options. Pre-combustion choices include the use of hydrogen, renewable or synthetic methane, or biofuels. Post-combustions options include carbon capture and oxy-fuels. As hydrogen is both a fuel and an energy carrier, it is being viewed as a potential critical element for decarbonization of many sectors, including power generation.

Fuels containing hydrogen have been used extensively in the power generation industry for decades. However, there are multiple challenges due to differences in fundamental characteristics (Table 1). Hydrogen has a higher flame temperature than methane, which may lead to increased NOx production. Hydrogen’s lower heating value (on a volumetric basis) is 1/3 the value of natural gas, requiring fuel accessory systems that can accommodate the increased volumetric flow. Increased reactivity is another challenge. Figure 1 shows relative reactivity as a function of inverse blow-off time, which is taken to be a characteristic chemical reaction time. This is plotted against the modified wobbe index. From this graph, it is seen that high hydrogen fuels have a relative reactivity that is ~100x faster than natural gas fuels.

Greater reactivity leads to increased flame speed (defined as the velocity a flame will propagate upstream into unburned fuel). Hydrogen’s flame speed is an order of magnitude faster than methane (Figure 2).

Even blends of hydrogen and natural gas will exhibit increased flame speed; a 50% blend of hydrogen and natural gas has a flame speed at least twice that of 100% methane. Higher flame speed increases the risk that the flame could propagate upstream into the premixer. If the flame is able to anchor and stabilize inside the premixer, this is known as flame holding. Both situations can lead to combustion hardware distress and even fuel nozzle damage (Figure 3).

To mitigate some of the challenges of operating with hydrogen and similar low heating value fuels (i.e. syngas, steel mill gases, refinery waste gases, etc.), gas turbines were configured with diffusion flame combustion systems. These combustors had physically different geometries that mitigated the risk of flashback and flame holding. However, these systems operate at combustion conditions that allow near peak-to-peak NOx formation (Chemically, these are stoichiometric reactions where fuel and air are present in balanced chemical proportions; these reactions also have an equivalence ratio of one) (Figure 4). Depending on the fuel and the combustion system, this could result in NOx emissions in the range of 200-600 ppm. A typical mitigation for high NOx emissions is injection of a diluent (water, steam, nitrogen) into the combustor, but this may result in reduced performance.

A path to resolving this challenge is shifting to equivalence ratios less than one; this is where dry low emissions (DLE) and dry low NOx (DLN) combustion systems operate. However, traditional DLE and DLN systems are not used with hydrogen due to concerns of flashback and flame holding.

One solution was to develop a different type of premixed combustion system with modified geometries for swirl-based DLE and DLN systems. An alternative approach to hydrogen combustion that mitigates the risk of flashback is lean direct injection (LDI). As the name implies, LDI-based combustors operate in a fuel lean mode and achieve rapid mixing of fuel and air using hundreds or thousands of small-scale mixers. The scale of these injectors is such that the bulk velocity of the gas exiting the injector is higher than the flame speed of the fuel, reducing the potential of flashback or flame holding. In addition, the diameter of these holes may be smaller than the quench distance of the flame, mitigating the potential risk of flame holding (The quench distance for a flame is the distance between two plates, or the diameter of a tube, that will quench a flame when it attempts to propagate through the geometry. Physically, the walls of the channel or tube wall conduct enough heat away from the flame that it is extinguished locally).

Numerous studies examine LDI variations and configurations, including co-flow mixing, swirl-based mixing, and jet in cross-flow mixing (Figure 5).

All feature a number of small diameter fuel injectors. Due to their scale, they require more intricate methods of delivering fuel and air. The NASA mixer uses a system in which air flows axially into the multi-tube assembly and through the 25 injection elements (Figure 6). The hydrogen flows into a fuel plenum in the assembly, and is injected axially into two locations in each element, creating a jet in cross flow mixing system.

The jet in cross-flow (JICF) is classic fluid mechanics mixing process where a jet is injected nominally perpendicular to a primary flow. In Figure 7, the jet breaks up and starts to mix as it is sheared by the primary flow.

Combining these concepts, a hybrid LDI/JICF combustion system utilizes a very large number of injectors as well as a jet in cross-flow to create a premixing region inside each injector (Figure 8).

In this mixer, air flows through numerous straight tubes in a parallel array with a fuel plenum that surrounds the tubes. Like the NASA mixer, fuel flows into the mixer through a ring manifold on the outer diameter and is injected radially into the air flowing axially through small-diameter holes in the tube walls. The distance from the injection point to the tube exit plane may vary depending on the fuel and engine conditions. As these tubes have small diameters, bulk air velocity may be greater than the flame speed of the fuel to avoid flashback, including velocities greater than the flame speed for fuels with significant hydrogen content. Even though generating these high velocities can impact performance, due to the short axial length of these mixers, they are able to achieve a relatively low pressure drop.

An advantage of the multi-tube mixer that features many small elements is the scalability of the design to any size nozzle or combustor with limited impact on performance. This has allowed initial concept systems to be scaled up to full-scale gas turbine hardware. This has been demonstrated by multiple research organizations and gas turbine manufacturers who developed full-scale prototypes for testing and commercial operation (Figure 9).

GE’s new multi-tube combustion system is known as the DLN 2.6e (Figure 10). Although optimized for operation on natural gas, it still utilizes the LDI/JICF physical geometry and mixing concepts that provided improved operability on hydrogen. Combustion tests demonstrated that this system can operate on blended hydrogen and natural gas with up to 50% (by volume) hydrogen.

The power generation industry is in transition with increasing momentum to reduce carbon emissions. Each year more renewable-based power is generated, changing the traditional electrical grid model. However, the grid still requires firming with dispatchable assets. In the future, these assets may need to have reduced or zero carbon emissions.

Solving the challenge of lean hydrogen premix combustion with highly reactive fuels

Responding to market demand for larger compressors

Manabu Saga, President, Mitsubishi Heavy Industries Compressor International (MCOI), discusses his company’s centrifugal compressors, integrally geared compressors, and steam turbines as well as trends such as the need for larger capacity machines.

With over 100 years of technical expertise in the design, engineering and manufacturing of API compressors, steam turbines, critical auxiliaries and their associated control systems, Mitsubishi Heavy Industries Compressor (MCO) possesses technologies for the hydrocarbon processing sector.

MCO subsidiary, Mitsubishi Heavy Industries Compressor International (MCOI), was established in Houston, TX in 2012. Its Pearland Works facility began operations in 2015. Over the last eight years, MCOI has re-introduced MHI’s API turbomachinery product lineup into the North American market by supplying new equipment as well as servicing our existing fleet. Since our inception, the North America supply record has increased over 300%.

What single shaft centrifugal compressors do you offer? 

MHI manufactures API 617 Chapter 2 compressors in both our Hiroshima, Japan and Pearland, TX factories. Our centrifugal compressor lineup offers a wide application range from low pressure/high flow (horizontally split) compressors in applications such as ethylene and propane dehydrogenation (PDH) to high pressure/low flow (vertically split) compressors in applications such as gas reinjection. Our compressors provide high reliability and efficiency, as well as easy maintainability.

The Mitsubishi family of companies manufactures steam turbines for mechanical drive and industrial power generation. Our custom designed turbines include straight through condensing, backpressure, extraction condensing, admission condensing, as well as other configurations.

Do you make integrally geared compressors?

Our integrally geared compressors (IGC) have found application principally in air, booster, N2, CO2, and natural gas applications. Our IGC design has a capability range of 200 bar discharge pressures and 500,000Am3/h suction flows.

What trends in compressors have you observed?

Our customers are continuously evaluating larger and larger plants in order to maximize economies of scale. All the while efficiency, reliability, and safety requirement demands remain of the utmost importance. Based on these trends and requirements, we work closely with our clients to ensure the MHI R&D and engineering teams are focused on developing the best solutions for these mega-plants. As a result, we’re supplying some of the largest API turbomachinery in the world for ethylene, propane dehydrogenation (PDH), LNG, ammonia, and methanol plants.

In many applications, such as midstream gas processing, plants have gotten to a size range where compressor technology needs to be transitioned to centrifugal compression in order to reduce overall plant CAPEX as well as limit lifecycle costs (OPEX).

The increase in the scale of petrochemical plants, particularly ethylene and PDH, has been remarkable. Ethylene plant capacity increased by 130 % and PDH plant capacity by almost 100% compared to the previous decade. This led to an increased in the size of equipment. Consequently, the steam flow rates in the high-pressure and low-pressure stages of the steam turbine have amplified. Thus, it became necessary to apply larger components including main valves, casing, longer blades, and longer rotors.

At Pearland, we offer repairs and refurbishment, spare parts manufacturing, inspections and overhauls, advisory field services, reverse engineering, hands-on training courses, asset management, and high speed balancing – all on a planned and emergency basis.

What kind of testing facilities do you have?

In our Pearland facility, we have the capability to perform ASME PTC-10 Type 2 and mechanical running tests on API 617 Ch. 2 centrifugal compressors. This allows our customers to have better access to witnessing their compressor testing as well reducing lead times and limiting shipping constraints. We’re the sole OEM, in the Gulf Coast region, to be able to test API centrifugal compressors. Additionally, we have high-speed balancing capabilities for compressor and turbine rotors which are typically performed after modifications or repairs are made.

What is the latest news from the company? 

MCOI has been awarded a contract by Gulf Coast Ammonia (GCA) to supply compression for a new ammonia production facility in Texas City. The equipment will be purchased by Air Products, who will build and operate the facility in parallel with its largest ever U.S. investment. The equipment on order includes one syngas compressor train and one ammonia refrigerant compressor train. Together, they consist of four compressors and supporting auxiliary systems. They will be jointly built and tested by MCO at its factory in Hiroshima, Japan and at MCOIs Houston facility. All trains are to be packaged at MCOI. GCA’s ammonia facility will produce approximately 3,600 metric tons per day of ammonia, which will make it the world’s largest ammonia plant once fully operational. ■

Q&A with Manabu Saga, President of Mitsubishi Heavy Industries

Highly stressed turbomachinery components, including impellers, shafts, housing, and bolts are subjected to severe loading, oxidation, corrosion, and in some cases hydrogen embrittlement. High-strength titanium alloys and high-strength, nickel-based alloys are widely used for those components. The main criteria for choosing materials are strength, specific strength (tensile strength to density ratio), fatigue strength, toughness, and corrosion/oxidation resistance. Titanium alloy Ti-6Al-4V, and the nickel-based alloy 718 and alloy 625 fit these criteria. Cost and machining issues limit application.

High-strength, corrosion-resistant (HSCR) steel is a possible low-cost alternative. Premium-quality HSCR steel ingots are produced by vacuum melting processes. A powdered form of HSCR steel is produced by atomization processes, including vacuum atomization.

Components can be manufactured from HSCR steel by four processes:

Hot working (HW) of ingots by forging or rolling followed by machining and hardening.

Powder metallurgical-based, hot isostatic pressing (PM HIP) to near net shapes (NNS) followed by finish machining, and hardening (NNS PM HIP).

Additive manufacturing (AM) followed by surface finishing and heat treatment.

Vacuum casting followed by hot isostatic pressing, finish machining, and hardening (Casting + HIP).

Hardening of HSCR steel consists of austenitizing and rapid cooling, optional refrigerating, and tempering at low, medium, and high temperatures (secondary hardening) depending on the required properties. Formation of NNS by PM HIP enables manufacturing of various complex-shaped components. The process provides precise geometry and properties close to the forgings. Also, PM HIP supplies a homogeneous microstructure through any cross section.

The cost of components made by PM HIP is generally higher than the same products made by HW. However, small batches of complex products produced by PM HIP are economically feasible compared to HW (Figures 1A & B).

 Figure 1A: Impeller made by PM HIP from Ti-6Al-4V alloy powder (A) (Source: LNT PM).[/caption]

 Figure 1B: Gas compressor impeller made by PM HIP from Inconel alloy 625M powder.

NNS components made by PM HIP are cost effective due to waste minimization and their buy-to-fly ratio (mass of raw material to mass of product) being lower than HW components.

The high cost of titanium alloy and nickel-based alloy powders, as well as issues with machining, limit their application. Critical components made by PM HIP from HSCR steel powder are a good alternative to those made from titanium nickel-based alloys due to lower cost and better machinability for the same lifetime and durability.

 Table 1: Mechanical properties of HSCR steel, Ti-6Al-4V alloy, and Inconel alloy 718 made by four different processes.[/caption]

The components made by AM have a buy-to-fly ratio lower than the components produced by PM HIP. However, the high cost of powder for AM, high-energy consumption, and issues with surface finishing limit application of AM processes.

Casting + HIP has the lowest cost among processes. But it supplies lower strength compared to HW, PM HIP and AM. A combination of casting + HIP is feasible for manufacturing of components from HSCR steel. The projected cost reduction of critical components is 65% (more when compared to the same weight of components made by AM from Ti-6Al-4V alloy and alloy 718 powders).

The various processes used produce different mechanical properties (Figure 2). A variety of techniques are employed, depending on the material. HW + hardening of forged HSCR steel, for example, is accomplished by quenching, refrigerating, tempering, and finally air cooling. Forged Ti-6Al-4V alloy and Inconel alloy 718 are hardened by heat treatment.

 Figure 2: The room-temperature mechanical properties of HSCR steel, Ti-6Al-4V alloy and Inconel alloy 718.[/caption]

Figure 2 shows a comparison of the mechanical properties of vacuum melted, forged, and hardened HSCR steel, Ti-6Al-4V alloy, and Inconel alloy 718. HSCR steel possesses higher specific stiffness (E/ρ) and specific strength (UTS/ρ), higher fatigue limits (S), lower fracture toughness (K1c) and higher impact toughness (CVN) compared to Ti-6Al-4V alloy. Additionally, HSCR steel has a higher elevated temperature strength up to 950°F compared to Inconel alloy 718 and a higher elevated temperature strength up to 1200°F compared to Ti-6Al-4V alloy.

HSCR steel also has greater workability and machinability, and better wear resistance. Alloy 718 and Ti-6Al-4V alloy have better corrosion and oxidation resistance compared to HSCR steel; but HSCR steel has no rust after a salt spray test (ASTM B117 using a 5% NaCl concentration, natural pH, at 95°F, for 200 hours).

Given its mechanical properties, critical components made by HW, PM HIP, and AM processes from Ti-6Al-4V alloy and alloy 718 can be replaced by HSCR steel without sacrificing stiffness, durability or lifetime (Table 1).

 Table 2: Qualitative rating for HEE of materials tested at 75°F under hydrogen pressure of 9.8 ksi. Those deemed negligible or small risk can be utilized in the specified hydrogen pressure & temperature range. Those graded high can be cautiously utilized only for limited applications; the extreme and severe classes are not recommended.[/caption]

In terms of cost, HSCR steel is an attractive alternative (Figure 3). There is a significant reduction in cost for components made by HW, PM HIP, and AM using HSCR steel. At the same time, utilization of HSCR steel reduces dependency on Ti, Ni, Mo, and Nb. Efforts by Siemens Energy, GE Gas Power, Mitsubishi Power, Ansaldo Energia, and others to develop hydrogen-fueled turbines have shifted into high gear.

Hydrogen embrittlement of critical components is a major challenge. The hydrogen environment embrittlement (HEE) rating of materials varies widely (Table 2). Ti-6Al-4V, Inconel alloy 718, Inconel alloy 625 and HSCR steel should not be utilized for hydrogen-fueled gas turbine components.

High-strength aluminum alloys 2000 and 7000 series are a better choice; however, their strength up to 70 ksi at 75°F and up to 30 ksi at 400°F limits application. Similarly, Type 316 austenitic stainless steel has a negligible HEE rating, but possesses strength of only 90 ksi at 75°F and 80 ksi at 400°F. That is not enough for the highly stressed components.

A protective coating or plating is required. For prevention of HEE in high strength steels, the most attractive are Zn-Ni and Zn-Ni-Me coatings (thermostability up to 500°F). Components made from HSCR steel and protected by such coatings can be utilized with hydrogen-fueled gas turbines. A more robust approach consists of plating or cladding of HSCR steel components with 316 stainless steel.

Los Angeles-based LNT PM and Synertech PM have developed NNS PM HIP technology for critical gas turbine components. This includes hydrogen-fueled parts made by PM HIP from HSCR steel powder. Pilot production of these parts is underway. ■

Dr. Gregory Vartanov is chief engineer at Advanced Materials Development Corp., a Toronto-based company that develops high-strength steels and alloys. He holds an M.S. and Ph.D. in materials science and metallurgy. For more information and more details on these materials, please contact info@amdoncorp.com or visit amdoncorp.com

High-strength, corrosion-resistant steel can be an effective alloy alternative

The energy sector is in a constant state of change, perhaps more than ever. Stricter emissions requirements have come on the heels of shifting public support for environmental sustainability.

Efficiency has often been center stage in the turbomachinery sector, but as governments across the world promise carbon neutrality by mid-century, the end goal for OEMs has taken on a greater purpose. Gas turbines are now expected to burn more variations of fuel and be more flexible in their application, all while competing with wind, solar, and battery storage systems.

"With or without hydrogen, gas turbine technology continues to advance."

Natural gas generation will remain strong for decades

, according to reports from the International Energy Agency. But alternatives like 

 have garnered intense interest due to clean burning qualities and government support. Accordingly, most manufacturers offer turbines that can handle some level of natural gas-hydrogen blend. They are working to create future-proof turbines that can efficiently run on 100% hydrogen or a high hydrogen blend.

 The Ansaldo Energia AE94.3A F-Class outputs 495 MW in combined cycle and 992 MW in a 2+1 configuration.[/caption]

Ansaldo Energia is developing larger and more efficient H-class gas turbines for the combined cycle and peaking markets. Flexibility features include part-load operation, high turndown, and cycling operation to support the renewables, and the needs of large combined cycle plants.

In addition, the company is increasing the hydrogen combustion capability of all new engines and retrofits. The trick in developing blended fuel turbines is to reduce the negative side effects of hydrogen combustion such as derating, which drops power output and efficiency, increases emissions, and lowers operational flexibility. The company already has more than 200,000 operating hours in burning hydrogen-enriched fuels in its AE94.3A gas turbine.

Sequential combustion technology, such as that in Ansaldo Energia’s GT26 and GT36 turbine models, offers advantages for hydrogen combustion. The latest high-pressure tests at full engine conditions, demonstrated that the engine’s sequential combustion is suitable for hydrogen combustion.

Ansaldo Energia’s most popular gas turbines are the GT36 H-class and AE94.3A F-Class. The GT36 H-class outputs up to 538 MW and can use hydrogen up to 50% volume without derating. It is a good fit for combined cycle plants. The AE94.3A F-Class outputs 495 MW in combined cycle mode and 992 MW in a 2+1 configuration. It can burn up to 25% hydrogen by volume. Further improvements are under testing.

GE has a well-known gas turbine portfolio that includes H-class, F-class, B and E-class, and aeroderivative turbines. The HA and F-class turbines offer the greatest fuel flexibility and power.

The company’s ability to close transactions, particularly services parts & upgrades, has been impacted by constrained customer budgets and access to financing due to oil prices and economic slowdowns. GE said it anticipates the power market to continue to be impacted by overcapacity in the industry, increased price pressure from competition on servicing the installed base, and the uncertain timing of deal closures. The company has gained 32 orders so far in 2020. That compares with 52 for the first three quarters of 2019. The company remains the top gas turbine manufacturer; it is forecast to account for nearly 30% of units produced over the next decade.

GE’s 384 MW 7HA.02 combustion turbine, which can burn between 15-20% hydrogen by volume, is known for its ability to use various gas blends at high power and efficiency. The turbine is being used at the Long Ridge Energy Terminal, a 485 MW combined cycle power plant in Ohio, that will transition to run on hydrogen as soon as next year. The plant is the first purpose-built hydrogen plant in the U.S.

The company has also been developing a multi-tube combustion system known as the DLN 2.6e. Optimized for operation on natural gas, it can operate on blended hydrogen and natural gas, with up to 50% (by volume) hydrogen.

 Cross section of Opra OP16 turbine engine[/caption]

OPRA, a Dutch turbine OEM, has developed combustor technology to utilize up to 100% hydrogen in its gas turbines. Earlier this year, it ran its turbine successfully in a test using 100% hydrogen.

Its most popular model, the OP16, is an all-radial gas turbine, which provides robustness, reliability, efficiency, and low emissions. Its main markets are industrial, oil & gas and waste-to-energy applications.

The OP16 can operate on a wide range of gases, from ultra-low calorific gases (~5 MJ/kg) to high calorific gases including 100% H2 while fulfilling stringent emissions regulations. The turbine can also handle sour or contaminated gases often seen in oil & gas applications.

The OP16 comes in three variants: The OP16-3A, a diffusion combustor; the OP16-3B, a dry low NOx combustor; and the OP16-3C, a low-calorific fuel combustor.

 Kawasaki 1 MW class M1A -17 gas turbine.[/caption]

In the last decade, CO2 reduction has become a global trend. The Japanese government has set policy to expand the use of hydrogen to reduce CO2 emissions from its thermal power generation plants.

Kawasaki Heavy Industries came up with a hydrogen supply chain concept almost ten years ago and has been making company-wide efforts to build a hydrogen chain for producing, transporting, storing, and using hydrogen. The company is developing technologies that can handle a wide range of applications, from hydrogen mix with natural gas to 100% hydrogen combustion. These technologies are being developed for 1 MW gas turbines and will be gradually introduced to the market.

In Kobe, Japan, the company is conducting a hydrogen demonstration project. In 2018, it demonstrated that a 1 MW M1A-17 gas turbine could burn 100% hydrogen, utilizing the generated electricity and steam at a nearby large-scale event facility and hospital. This year, the demonstration is using an MMX combustor (Dry Low Emissions – DLE) instead of NOx reduction by water injection. The test operated at 100% hydrogen with DLE for the first time and achieved an efficiency improvement of 1 point from the wet (NOx) method.

“We are developing and demonstrating the technologies necessary to build a hydrogen supply chain in order to respond to the expansion of hydrogen utilization worldwide,” said Koji Tatsumi, Senior Manager of Gas Turbine Engineering Department for Kawasaki Heavy Industries.

November/December 2020