Machinery capital cost for the acquisition of a 

 can be significant. Engineering efforts, therefore, must not be spared when it comes to updating technology and maximizing reliability while controlling capital cost.

Overall costs are impacted by the number of compressor casings needed to achieve the required pressure ratio, the gas mole weigh, flow and materials. Driver selection also plays a key role in lifecycle cost, and is guided by the required reliability and controllability as well as the availability of power, steam or gas to feed the main driver.

The crude oil stabilization process at the Saudi Arabian facility being discussed generates a large amount of light and heavy mixed gases that are compressed downstream for subsequent separation and recovery in natural gas liquid (NGL) plants.

One of the compressors trains installed in the large stabilization oil plant handles a complex chemical composition gas with abundant content of heavy gases including propane, butane and pentane isomers. The average mole weigh of the mix is 42 with the compressor operating at 19,000 HP. The compressor handles a heavy mix gas and boosts pressure from 1 to 33 bars.

The train was installed in the early 1970s. Through the years, the train required extensive maintenance. Inspections to the hot gas path of the gas turbine revealed damage to combustion liners, nozzles and blades, as well as issues with the hydraulic starter, instrumentation failures and casing ovality (deviation from being completely circular). Further recurring issues included failures in the seal oil seal of the compressors, vibration and instability due to the presence of riveted impellers in the compressor rotor. The situation was complicated by a diversity of instrumentation in the gas turbine and train components such as bearings, seals, proximity probes, temperature and pressure gages, and control valves.

The new compressor train had to meet design conditions requires compressing 99400 ACFM (actual cubic feet per minute) from 1 Kg/cm2 abs (absolute pressure) to 33 Kg/cm2 abs. To achieve such a pressure ratio, the first casing is a double suction compressor with six impellers, and the second casing consists of a two-stage compressor and a back-to-back rotor with five impellers. The first casing pushed the gas to the second casing without cooling. Therefore, from a process standpoint, the first compression stage is completed in the second casing. This means that two additional impellers are needed in the second casing to compress the gas before delivering it to the intercooler. Finally, there is a gearbox between the first and second compressor casings to increase speed from 4,800 to 7,100 RPM.

 Figure 1: New compressor rotor assembly. Courtesy of Siemens/Dresser Rand.[/caption]

The configuration for the new compressor is a back-to-back rotor with five and four impellers per stage, similar to Figure 1. The technology improvements observed in the new design rely on several factors. Mathematical modeling and CFD tools were used to develop an improved aerodynamic 3D design for the impellers with high flow coefficients allows a more appropriate profile in the vanes. This is especially useful in the configuration of the first two impellers.

In the early 1960s, the first tilting pad journal bearings application in compressor began operation to solve instability problems. At that time, operating speed was limited to prevent oil whirling and oil whip. Researchers gradually spread a better understanding of vibrational phenomenon and rotordynamics. As a result, enhanced dynamic features were incorporated into compressor design based on advances in rotor dynamic and lateral analysis.

Finally, advances in manufacturing enable automated CAD-CAM tools to machine complex designs, especially in small coefficient impellers with a tip width smaller than 15 mm. Development in laser sintering powder and the electron beam welding process have cleared the way for the production of smaller impellers, as required in injection compressors with discharge pressures above 5,000 psi. Some manufacturers have extended these capabilities as high as 14,500 psi (1000 bars).

Flow coefficients for compressors typically range from 0.01 to 0.16. The first stage impeller of the new compressor train has a flow coefficient of 0.09. At the second stage, the flow coefficient drops to 0.02, which limits the efficiency in the second stage below 80 % as a consequence of density changes in the first stage (Figure 2).

 Figure 2: Polytropic efficiency vs. impeller flow coefficient in centrifugal impellers.[/caption]

There is an inherent reliability enhancement in the compressor due to a reduction in the footprint of components such as the gearbox, compressor casing, dry gas seals (DGS) and bearings, as well as improvements in the anti-surge system with enhanced depressurization during emergency shutdown.

The materials used in the compressor includes 17-4 PH impellers (good for preventing of stress corrosion cracking in sulfide environments), fluorosint interstage labyrinth seals and a stainless steel-cladded casing. A substantial reduction in footprint was achieved via the new design.

The aerodynamic design of the compressor had a type II test according to ASME PTC 10 test code rules. This is done using a nonexplosive inert gas. Typically, the gas molecular weight in the test is higher than the real service gas. This enables lower equivalent test speeds and a lower power requirement for the driver. The new compressor’s performance was successfully tested with Freon 134a. The total absorbed power was 2.5% lower than expected.

 Figure 3: First stage behavior during shutdown without depressurization.[/caption]

A dynamic analysis was performed to assess the system needed to prevent surge (Figure 3). Many factors were discovered which impacted the selection of the antisurge system. Aggressive reverse flow was discovered that derived from a high-pressure ratio (10-1) in the first stage. Additional reverse flow was found at the discharge side of the first stage once the second stage antisurge valve diverted the gas to the suction side. Further, sudden pressurization at the first stage suction prevented activation of the pressure relief valve during emergency shutdown. Blow off valves were installed at the discharge sides of the stages to depressurize and prevent damage in the compressor, static equipment and pipes located at the compressor suction side (Figure 4).

 Figure 4: First stage behavior during shutdown with blow-off valves at both stages.[/caption]

Limitations in the existing gas turbine forced operation at a fixed speed to limit the temperature at the exhaust side and to keep steady load (load sharing was not available). This condition required the compressor to recycle during periods of instability. Fortunately, the plant generates excess steam, which drove the decision to select a steam turbine as a driver. The existing single-shaft gas turbine was replaced by an eight-stage impulse steam turbine.

The new steam turbine includes a dual control valve to allow start-up without the use of a combined trip and throttle valve, and brush seals in the external labyrinth to reduce steam leaks to the gland condenser. The steam turbine is an 82% isentropic efficiency back pressure machine. Construction materials include ASTM 470 for the rotor, ASTM A-565 for the first stage blades and AISI 403 for second- to eighth-stage blades.

Overall, the exceptionally high-pressure ratio for a single casing machine triggered special challenges to design an optimal compressor and a corresponding anti-surge system. The resulting single casing compressor directly driven by a back-pressure steam turbine is expected to start operations in first quarter 2021.

Articles

Compressor train replacement: A summary of efficiency and reliability opportunities

The commercial shipping industry has generally avoided gas turbines for primary propulsion and onboard electric power needs, turning instead to reciprocating engines, which have a history of operating on low-cost liquid fuels. Ships’ crews have experience working on these engines, and operations and maintenance staffing and infrastructure tend to be centered around them.

Sweeping emissions rules implemented in 2020, however, are changing the marine landscape. The International Maritime Organization is working toward the carbon-reduction standards laid out in the 2050 Paris Accord. The industry is under pressure to identify clean fuels to meet these goals. The low-grade fuels reciprocating engines burn generate NOx emissions as well as sulfur oxides, particulates and heavy metals. Meeting stricter emissions standards while continuing to run reciprocating engines will significantly increase operating costs for commercial shipping operators. To support low emissions, liquified natural gas (LNG) is becoming a key marine fuel due to increasing availability and clean combustion. In addition, LNG carriers (i.e., tankers that carry liquefied natural gas) are becoming more popular.

Gas turbines provide a clean, cost-effective alternative to reciprocating engines under these conditions. The arguments against gas turbines — often focused on efficiency, fuel suitability, costs and noise — are based on outdated perceptions. Today’s turbines already serve marine applications like offshore platforms and floating production storage and offloading (FPSO) vessels.

Meeting stricter emissions standards while continuing to run reciprocating engines will significantly increase operating costs for commercial shipping operators. To support low emissions, liquified natural gas (LNG) is becoming a key marine fuel due to increasing availability and clean combustion.

Concerns about using gas turbines are often centered around efficiency requirements for clean combustion air, fuel suitability and noise. Since we find gas turbines abundantly in other types of marine applications, like offshore platforms and FPSOs, the question is certainly admissible as to why gas turbines are not used in commercial shipping.

Today, gas turbines are significantly more efficient than the available types used 15 or 20 years ago, and provide superior durability and reliability. They can be installed as combined cycle, or combined heat and power systems. Combined cycle systems for gas turbines are more efficient and smaller than similar systems for reciprocating engines due to the higher turbine exhaust temperatures. To optimize efficiency, the systems should be sized to match the operation profile of the ship.

Additionally, today’s air inlet systems use considerably improved technologies that have brought about lowered operational costs. Despite the higher air throughput of gas turbines, compared to reciprocating engines, modern air filtration media and construction technology effectively removes particulate, water and salt from the air, thus reducing engine fouling and performance deterioration.

The use of heavy liquid fuels, like heavy fuel oil (HFO) still favors reciprocating engines, but these are the very fuels that become less desirable due the environmental impact. If an owner runs High Sulfur HFO, they will need to install scrubbers in the exhaust system. These scrubbers are expensive both to install and to operate. This reduces any advantage of running on so-called cheaper fuel.

LNG has become a viable alternative marine fuel. LNG is more economical than HFO. It creates significantly less harmful emissions, such as NOx, particulates, sulfur, unburned hydrocarbons or heavy metals. This is particularly true for LNG tankers, where some of the transported LNG is available as boil-off gas.

Gas turbine lifecycle costs are comparable to those of reciprocating engines, especially considering that the higher power density, lower weight and reduced space requirement of gas turbine installations allow for higher payload. Additionally, air inlet systems on today’s gas turbines help lower operational costs. Despite a higher air throughput than reciprocating engines, modern gas turbine air filtration media and construction technology effectively collect particulate, water and salt, therefore reducing engine fouling. In addition, the lower maintenance needs of gas turbines require fewer crew.

Therefore, it is surprising that we don’t see a greater interest in gas turbines for electric power and propulsion for LNG carriers, cruise ships and other commercial shipping. Being turbomachinery people, we’re looking forward to seeing more gas turbines in commercial shipping services. Maybe we will see a similar situation as when, in 1894, the first (steam) turbine powered ship, the Turbinia, ran circles around the more conventional ships of the Royal Navy.

We would like to acknowledge the help from Paul Bullara, Camfil Power Systems, and Jim Bertsch, Solar Turbines. ■

Myth: Gas turbines don't belong on commercial ships

 is the Senior Director of Market Intelligence and Strategy at Mitsubishi Power. 

Tell our readers about  Mitsubishi Power

Mitsubishi Power was formerly known as Mitsubishi Hitachi Power Systems. The company continues to provide power generation and storage solutions. We offer a full range of 50 Hz and 60 Hz gas turbines, from aeroderivatives between 30 MW and 140 MW to heavy duty turbines between 40 MW and 560 MW. All of our gas turbines will be hydrogen-enabled to help meet the decarbonization goals for the power sector. In addition, our power islands include steam turbines tailored to maximize output and efficiency. And our energy storage solutions allow for the safe storage of alternative green fuels such as hydrogen.

Our most popular model is our J-Series advanced class turbine, which has a single turbine output range of 330 MW to 425 MW. With over one million operating hours, it best serves our base load utility-scale clients that need a blend of reliability and efficiency. The J-series can can use a mix of 30% hydrogen and 70% natural gas. We are committed to creating turbines that can run on 100% hydrogen by 2025.

What are some of the biggest trends you have observed with regard to gas turbines?

It’s all about creating a future-proof gas turbine while ensuring flexibility to manage the grid. As the trend towards decarbonization continues, customers do not want to buy a gas turbine package that may become obsolete in 20 years when and if regulations demand 100% renewable power on the grid. We’ve been anticipating this need for a while, which is why our J-series turbines can already use a 30% hydrogen mix, with the goal of being able to convert those same turbines to 100% hydrogen gas turbines in the near- to medium-term future.

We are creating the building blocks of the world’s first autonomous power plant, 

 using the Tomoni digital suite. This digital platform enables advanced analytics and control systems to improve efficiency, generating more electricity with less fuel. The technology monitors and optimizes every aspect of a power plant’s operation; and the processing capacity of the algorithms uses a wealth of information to monitor performance, make continuous improvements to the power plant, and conduct predictive analysis.

T-Point 2, our grid-connected validation facility featuring the M501JAC gas turbine and Tomoni, began operation in Takasago, Japan earlier this year and officially opened in July 2020. By creating our second owned power plant, we’re continuing to validate our newest products on our dime and in real utility scale operations. This ensures our products are thoroughly vetted and protects our customers. The plant is also an important step in achieving our goal of building the world’s first autonomous power plant. This provides real-world operating experience for our digital solutions so again, we’re not testing on our customers. This means that we’re able to bring both an operator and an OEM mindset to the development of customized digital solutions.

As part of our strategy to help our customers decarbonize the power grid, we are investing heavily in energy storage. With more customers setting targets to be carbon neutral in the coming decades, short duration and long duration storage will play a key role. We recently announced a project with the Hecate Grid to supply battery energy storage systems totaling 20 MW (80 MWh) at Johanna 1 and Johanna 2 in Santa Ana, CA. We will service the project under a 10-year long-term service agreement.

We’ve also made strides in long duration storage using green hydrogen. We’re developing the Advanced Clean Energy Storage project in Delta, Utah. And we’ve been issued full notice to proceed for the hydrogen-powered 840 MW gas turbine combined cycle Intermountain Power Project.

Many customers have more coal retirements planned in what we consider Phase 1 of power grid decarbonization: retiring coal-fired power plants and replacing them with a combination of renewable power and natural gas. But for some power sector customers, Phase 1 has already played out. In California, for example, almost all coal-fired power generation has already been retired. So the question is what comes next? We believe that Phase 2 will be to replace natural gas with a combination of renewables and short- and long-duration energy storage. ■

Q&A: Gas turbines, hydrogen and energy storage

Most compressors purchased today are delivered with dry gas seals. Overall, they have provided increased compressor reliability, improved safety and reduced process gas loss. As a result, users continue to extend the range of applications using dry gas seals.

As seal manufacturers develop their understanding of dry gas seal essentials and identify root causes for failures, design changes are delivering an improved product. This includes more elaborate seal support systems for dry gas seals.

Critical factors for achieving higher sealing pressures are seal ring material, secondary sealing elements and the secondary dynamic sealing system. Tungsten carbide and carbon graphite are often used for seal rings in many dry gas seals. However, the flatness of a carbon graphite stationary ring is difficult to maintain with larger rings at higher pressures and temperatures. Newer seal designs extend the seal’s pressure, temperature and speed range by using silicon carbide seal rings. Improved processes for manufacturing silicon carbide has extended these parameters even further.

Secondary sealing elements are another important feature for accomplishing higher pressures. They seal against the compressor’s seal cavity, rotor and internal locations within the seal (Figure 1). O-rings were traditionally used for these elements, but voids in the material allow gas seepage into them. When pressures exceed approximately 800 psi, reducing pressure around the O-ring too quickly causes the trapped gas to expand before it can escape. This produces ruptures and blistering on the O-ring, preventing it from sealing again. This is referred to as explosive decompression. With 90 durometer (a standard for hardness measurement) Viton (a synthetic rubber and fluoropolymer elastomer), it typically occurs at decompression rates greater than 300 psi/minute. To overcome this challenge, polytetrafluoroethylene (PTFE) secondary sealing elements are used. PTFE is impregnated with other materials, adding additional features to produce the right seal material for high-pressure dry gas seal applications.

With secondary sealing elements managed, another concern is the dynamic secondary sealing system (Figure 2). This system allows the non-rotating seal ring to move axially and maintain an effective gap between the seal ring faces. The major components in the dynamic secondary sealing system are the dynamic sealing element and the balance sleeve.

When pressure is applied to the balance sleeve, the sleeve diameter shrinks. This increases the clearance between the seal ring inner diameter and sleeve. A balance sleeve that changes minimally as extreme forces are applied prevents extrusion from occurring. Using a material with high compressive strength such as tungsten carbide minimizes these changes in balance diameter.

Applications as low as -94°F and as high as 482°F commonly use dry gas seals. The standard 90 durometer Viton O-rings employed for secondary sealing elements are rated for temperatures between approximately -40°F to 380°F. Special O-ring material or PTFE sealing elements are used to extend that range.

Just as with pressure, the balance sleeve expands and contracts with temperature changes. The usual industry design incorporates a large clearance between the balance sleeve and the non-rotating seal ring inner diameter. When the seal is cold, however, sealing element extrusion can occur. As the seal temperature rises, insufficient clearance can lock the seal ring and lead to failure. Designs for cold applications incorporate smaller clearances, which increase as the seal cools. But this can also lead to extrusion.

The best approach is to construct the balance sleeve from a carbide material to provide a much smaller clearance change as seal temperature changes. The thermal expansion coefficient between tungsten carbide and silicon carbide is much closer compared to silicon carbide and 410 stainless steel – the typical material combination. An additional tungsten carbide ring supporting the dynamic sealing element further eliminates clearance changes no matter how extreme the temperature change. This design manages temperature ranges from -94°F to +482°F or more.

It is detrimental to operate any mechanical seal with no sealing media between the seal ring faces. This causes face contact and leads to a seal failure. Pumps in tank farms are often run dry for extended periods and these seals continuously fail. To manage this problem, a process was developed to grow a layer of diamond on seal ring faces. This layer greatly increases pump seal life. This same technology was applied to dry gas seals to manage face contact.

Dry gas seal ring faces are in contact when inadequate pressure is applied to the seal rings or when a compressor is rotated at speeds below 500 rpm. When a ratcheted compressor or one operating on a turning gear are operated, no seal gap is produced or the sealing media is absent between the seal faces. This leads to contact operating modes.

Even when the compressor is pressurized, the secondary seal still has the possibility of insufficient pressure, leading to face contact. For silicon carbide seal rings, diamond-like carbon (DLC) is applied to the faces. This permits contact operation for small time increments. Seal rings made of tungsten and carbon graphite are more forgiving and can operate for longer periods in contact. The downside to this combination is that the carbon graphite face wears as contact occurs, producing carbon dust. When in contact with dry nitrogen, the graphite face wears even quicker and generates more carbon dust. This has some impact on the flatness of the seal ring face, and negatively impacts seal reliability. The dust collects in the grooves and around the dynamic sealing element, contributing to premature failure.

To effectively manage long periods of face contact, a diamond coating is applied to the seal ring faces (Figure 3). This increases seal life due to its hardness, low friction coefficient and heat dissipation. These traits prevent any detrimental effects when seal ring faces operate in contact.

There are many factors contributing to seal leakage. Seal size, operating speed, operating pressure, operating temperature and seal media are dictated by the application and the compressor. Groove geometry, seal ring material, and seal gap are all part of seal design and controllable or changeable by the seal manufacturer.

Dry gas seals typically have unidirectional spiral grooves. Manufacturers have identified the spiral groove as the best for producing a stiff gas film to prevent contact between seal ring faces. Through finite element analysis and programming developed to determine how groove geometry effects seal leakage and gap generation, a bidirectional groove has been developed. It produces the lowest leakage, with the higher film stiffness and reliability. If a compressor has been turned backwards inadvertently, this can damage or destroy unidirectional seals. A bidirectional seal eliminates this concern.

A 2-dimensional groove formed in the seal face is the most common profile used in the industry (Figure 4). This produces an edge around the groove that traps debris. As debris builds, the groove becomes ineffective at producing a sufficient gap and gas film stiffness. A 3-dimensional groove with an angled groove profile, on the other hand, allows debris to flow through it without impacting groove effectiveness.

Dry gas seals typical operate with a three- to four-micron seal gap. This provides safety to prevent contact between seal ring faces due to any seal ring deformation. If the gap is too small and contact occurs, the seal ring faces are damaged, and failure can result.

Part of a dry gas seal factory test is opening it after the completed testing to check that no marks are visible on the seal faces. This verifies that there is an adequate gap and gas film stiffness to manage any seal face deformation within the designed operating range. The reduction of seal ring deformation is achieved by manufacturing it from silicon carbide. This allows for a reduced seal gap. Using diamond as the coating to dissipate heat generated in the seal gap also reduces seal ring deformation. The combination of a rigid seal ring, a 3-dimensional, bidirectional groove and a diamond coating, results in the lowest achievable dry gas seal leakage.

Liquids must be kept away from a dry gas seal to work effectively. As fluid film bearings lubricated with oil are next to the seal, it is crucial to ensure no lube oil enters the seal. Process gas, too, must not enter the bearing cavity. A separation seal addresses these issues.

Originally a split labyrinth was used. Air or nitrogen is injected into the middle of the labyrinth, so no lube oil migrates into the dry gas seal and process gas is directed out the secondary seal vent. Labyrinths were robust, but didn’t always prevent oil in the dry gas seal or process gas in the lube oil system. Carbon ring seals were a better fit, but experienced similar challenges to labyrinths. Carbon rings also had a lower mean time between repairs than the dry gas seal.

A coaxial barrier seal (Figure 5) was developed to overcome separation seal shortfalls. This end face seal eliminates the direct flow path from the lube oil cavity to the dry gas seal cavity or visa-versa. Reliability, lifespan and safety are all improved while reducing separation seal gas consumption.

It is not always possible to prevent liquids entering or forming in a seal. Process gas, for example, can be exposed to ambient temperature and can drop in pressure and temperature as it flows from the compressor supply takeoff, through the seal gas supply system and across the seal faces. Exposure to these conditions can cause a component in the gas to change its phase to liquid. Seal failures have occurred due to phase change.

Gas conditioning is incorporated into seal gas supply systems to prevent liquid from entering the dry gas seal. But this adds to operating costs. Ideally, a seal should function even when liquid is present. Liquid, though, takes more energy to sheer than gas. Sheering produces heat. Heat, in turn, deforms the seal faces, which causes contact. This creates more heat and face deformation, which leads to a seal failure. Additionally, when a compressor stops, liquid between the seal rings creates a bond. High torque is required to break this bond. This can damage a seal ring.

A seal design to work effectively with a dual phase gas must:

• Reduce torque to break the liquid bond

• Reduce seal ring impact forces from drive and anti-rotation pins

3-D grooves reduce the torque required to break the liquid bond between seal rings. Flexible or soft torque anti-rotation and drive pins reduce impact forces that damage a seal ring. Diamond coated silicon carbide reduces heat buildup and conducts it away. Incorporating these features enables a seal to operate with gas, dual-phase gas and liquid. The only requirement of this new seal design is for the sealing media (gas, dual phase gas or liquid) to contain no larger than three-micron particles. This provides a user reliable seal operation. ■

Glenn Schmidt is Senior Sales Director for Turbomachinery Solutions at Eagle Burgmann, a manufacturer of dry gas seals and other sealing, coupling and expansion joint products. For more information, visit EagleBurgmann.com

Dry gas seal advancements address sealing pressure, temperature range, face contact, leakage and oil migration

Wet compression consists of spraying atomized water into the compressor of a gas turbine engine. It is usually done after the air has been fully humidified by fogging, evaporative cooling with a media-type cooler or by chilling the air to below the ambient dew point temperature. The heat of compression causes the water droplets to evaporate inside the compressor where they provide an inter-cooling effect. This reduces the work of compression. Since the compressor consumes less power, more power is available at the GT output shaft.

A gas turbine compressor consumes half or more of the work produced by the expansion turbine. Therefore, an increase in compressor efficiency can produce a significant rise in the power output and fuel efficiency of a gas turbine. The added mass flow of water also causes a power increase. But this is small compared to the power boost resulting from the reduced work of compression.

Wet compression has been around for many decades. The first gas turbine that produced useful shaft power (built by Norwegian inventor Jens William Elling in 1903) used two, three-stage axial compressors with inter-stage water injection. Wet compression was also used in developing extra thrust during takeoff for both commercial and military airplanes from the late 1930s through the 1970s. The first patents for wet compression for industrial gas turbines date back to the 1940s.

More recently, NASA has funded research into the use of water injection into aero engine compressors to reduce NOx emissions from commercial aircraft during takeoff. Such systems also reduce hot-section temperature for the same thrust, thus potentially decreasing engine maintenance costs. This has led some researchers to suggest the use of wet compression for takeoff and the climb to cruising altitude.

In 1996, Mee Industries installed a wet compression system at the Ralph Green Power Station in the U.S. as part of an EPRI capacity enhancement program. The system cooled the inlet air and injected an “overspray” of liquid water at a rate of about 0.5% of the air mass flow. The wet compression system produced a 6% increase in power for the GE-7EA turbine.

Nearly one third of the more than 1000 MeeFog systems installed on gas turbines around the world in the past 30 years were specifically designed to provide additional spray for wet compression. However, a fog system designed only for evaporative cooling can also be used for wet compression if it is operated when ambient conditions don’t allow for full evaporation of the fog spray. Wet compression systems typically have water flow rates from 0.5% to 2.5% of the gas turbine inlet-air mass flow rate—about 20 to 90 gpm for a 7EA turbine, or as much as 156 gpm of a large F-class.

One of the early adopters of modern wet compression systems was the Watson Cogeneration Plant in Southern California. It installed four wet compression systems in 1998 and continues to use fogging for most of the year.

Watson Cogen is headquartered in Carson, about 15 miles south of downtown Los Angeles. The owners of the plant are Marathon Petroleum and NRG. Watson provides high-pressure steam and electricity to the Carson Refinery, as well as electricity to the grid. The refinery is California’s largest. It produces gasoline, diesel fuel, jet fuel and anode-grade coke. In addition, the facility produces the gas powering Watson Cogen’s turbines.

The plant has four natural gas-fired GE 7EA turbines, each rated at 83.5 MW (ISO). Exhaust gases from these turbines feed a duct-fired heat recovery steam generator, which generates both high- and medium-pressure steam. Around half of the high-pressure steam goes to the refinery. The rest is sent to two Dresser Rand steam turbines powering electric generators.

Watson’s Principal Engineer, Steve Ingistov, an ASME Fellow, has steadily introduced improvements, innovations and upgrades to the facility which boosted output from an initial level of 385 MW up to 425 MW. The gas turbines were originally supplied with once-through evaporative coolers. When operated at their design flow of 200 gpm, excessive water carry over resulted in compressor blade erosion. To address this issue, the plant upgraded the first seven rows of compressor blades to Carpenter 450 stainless steel.

The original fog systems at Watson were designed to provide 16 gpm of fog spray, which represents 0.35% of the air mass flow, or about 16°F of cooling. The fog systems were intended to provide evaporative cooling downstream of the under-performing evaporative coolers, plus wet compression fogging.

The nozzle array was installed downstream of the inlet air silencer panels. Fog that didn’t evaporate in the inlet duct, entered the compressor where it provided a power boost. On cool and humid days, nearly all the fog failed to evaporate in the duct. It entered the compressor as wet compression spray.

In 2010, Ingistov removed the once-through, 150 gpm evaporative coolers, in part due to regulatory pressure to reduce the amount of water consumed. He relocated the nozzle arrays upstream of the silencer panels, with the fog nozzles aligned so they sprayed into the gaps between the panels. The new nozzle arrays spray 30 gpm of fog, which equates to 30°F of cooling, or 0.67% of the air mass flow, for the GE 7EA turbines.

Watson Cogen is close to the Pacific Ocean so it tends to be cooler and more humid than inland Southern California. Hot summer day conditions are given as 92°F dry bulb, 68°F wet bulb. It is possible to get about 23°F of evaporative cooling on a typical hot day.

Ingistov uses fog aggressively to achieve the greatest output. Since 2010, he has been operating all the fog nozzles whenever the ambient temperature is above 50 °F (nearly 24-hours a day, year-round). During cool and humid days and nights, most of the fog spray fails to evaporate in the inlet air duct and enters the compressor. On warm, dry days, most of the fog evaporates before entering the compressor, so most of the power boost is due to evaporative cooling. Evaporative cooling gives about twice the power boost of wet compression per mass-unit of spray.

Ingistov conducted a controlled experiment to compare media-type evaporative cooling with fogging. The evaporative cooler was removed from Unit 4 and replaced by a fogging array with a flow rate of 30 gpm. Performance measurements over several months demonstrated that for the vast majority of days, Unit 4 with only fogging outperformed the other units which had the evaporative coolers and the original 16 gpm fogging arrays. Under certain conditions, the evaporative coolers added almost no power. With the new system, when it is cool and the relative humidity is high, the evaporative cooler gives almost no power boost, while fog continues to boost performance through wet compression.

Taking into consideration the water consumption and the test results showing fog to offer a greater long-term performance boost, a decision was made to remove the rest of the evap coolers and replace them with fog nozzle arrays.

The facility has ran only the 30 gpm MeeFog systems for fogging and wet compression for nearly a decade. According to Ingistov, “during 20 years of operation, the MeeFog wet compression system has not caused blade erosion.”

Thomas Mee is CEO of Mee Industries, a manufacturer of inlet air fogging and wet compression systems with more than 1,000 installations around the globe. For more information, visit MeeFog.com. 

A multi-decade perspective on wet compression

Until 2016, coal’s fall from grace and the growing share of renewables on the grid had caused the ST market to contract. But growth and stability have returned. Demand is returning for small- and mid-sized combined cycle power plants (CCPP), combined heat and power (CHP), petrochemicals, biomass and concentrated solar power (CSP) solutions. All include an ST element.

With sales recovering, globalization is another trend noted by ST OEMs. Most have established joint ventures with customers and suppliers across the world, which helps turbine companies boost market share, decrease costs, and gain access to new business.

Innovation in STs may not be fast paced when compared to the developmental progress made in the gas turbine field. Nevertheless, OEMs such as Mitsubishi Compressor, Doosan Škoda Power, Siemens Energy, Fincantieri, Triveni Turbine, Baker Hughes, Howden, Ansaldo Energia, Elliott, GE Steam Power and MAN Energy Solutions, among others, have made strides in performance optimization, reduction of carbon emissions, improved efficiency, start-up speed/flexibility and in raising steam parameters.

Turbomachinery International Magazine interviewed several of these OEMs to find out the latest trends dominating the steam turbine sector. They offer a diverse set of market insights.

Mitsubishi Heavy Industries Compressor (MCO) said its steam turbines are used predominantly in the petrochemical market. Particularly for ethylene plants of 2.0 million tons per annum (MMTPA) and above, the company has developed 20” longer blades to allow a wider variability in operating range. It has also developed STs designed for capacities of 3.0 MMTPA. As a result, its machines can now provide up to 140 MW to drive the cracked gas compressors (CGC) that are central to ethylene plant operations.

Overall, MCO offers API 612-compliant ST packages ranging from 3 MW to 140 MW. In conjunction with other MHI group companies, the company also serves the power generation market.

In recent years, MCO has focused on enhancing the operational efficiencies, reliability and maintainability of its ST packages, according to Tomohiro Mori, Application Engineer, at MCO. They are capable of automatic operation. The sequence from start-up to shut down is controlled by the programmable logic controller (PLC).

One of the company’s most popular models is the 9EH. “9” indicates the frame size (basic diameter of the control stage is approx. 900 mm). “EH” refers to the condensing turbine with an extraction pressure that controls the turbine under high-temperature and high-pressure conditions. It is typically used with a cracked gas compressor in ethylene plants.

In addition, the 9EH model addresses higher plant capacity. It can handle steam at very high temperatures (566°C/1050°F) and pressures (150barg/2133psig). It also provides improvements in energy consumption: the extraction steam from a cracker gas compressor steam turbine is used as the inlet steam for the refrigerant compressor ST.

Doosan Škoda Power has been around for more than 100 years. Its STs range from 3 MW to 1,200 MW, and serve gas, solar biomass, and other segments. It is especially competitive in the medium-sized ST market. The company’s turbines are single-casing, high-speed units, either condensing or back-pressure, in a compact configuration.

The DST-V is a variable-speed driven turbine that an output of up to 35 MW. The largest model of that line (up to 80 MW) is the DST-S10, a power generation synchronous ST running at 3,000/3,600 RPM with steam parameters up to 165 bar and 580°C.

The company’s primary market has traditionally been Europe and Latin America, but it is expanding into Southeast Asia and the Middle East.

Siemens Energy claims to have the largest share of the steam turbine market. It offers units from 10 kW to 1,900 MW. The company noted an uptick in demand since 2016, with biomass and waste-to-energy applications growing, especially in sectors such as cement, metal and mining, chemical or pulp, and paper. Decentralized power generation and CHP are additional areas of growth.

“Overall, we see a steady and healthy business with industrial steam turbines,” said Tannas Tsakiris, Vice President for Sales Industrial Steam Turbines, Siemens Energy, adding that Siemens has found a stable market in STs ranging from 5 to 250 MW.

Siemens units are typically tailor-made for customer needs using a modularized building block system. The company acts as a consultant to optimize the whole energy system beyond the turbine generator set.

“We analyze boundary conditions, the water steam cycle, space availability, and the necessary extractions for process steam to provide a turbine package/system that fits the required and requested needs,” said Tsakiris.

Fincantieri, an Italian company known for shipbuilding, develops STs used in oil refineries, paper mills, sugar mills, petrochemicals, waste-treatment, biomass, CHP, food production, cement works and steel plants. Its STs are available with power outputs of up to 50 MW, steam inlet conditions of up to 140 bar/540°C, and rotational speeds of 3,000 to 13,000 rpm. The lineup includes condensing, backpressure, controlled extraction, multi-stage, multi-valve, single-stage, and single-valve turbines.

Fincantieri’s most popular steam turbines are the THR and TVR series, with a maximum capacity of 4.4 MW. They have a simple construction, high reliability and moderate cost. The turbine wheel, with a single stage or a Curtis stage plus a second impulse stage, is assembled overhanging the pinion shaft, creating a compact geared turbine unit. The steam exhaust (directed axially) allows easy positioning on the floor. A modular system breaks its turbines into various subassembly units.

Indian steam turbine manufacturer Triveni Turbine has an installed base spanning 70 countries and generating over 13 GW. The company is capitalizing on a growing demand for refurbished turbines and after-market solutions to meet changing conditions, such as growth in size and scale, or aging machinery.

Triveni Refurb, the repair arm of the company, services older generation and third-party turbines. It offers efficiency upgrades to help customers avoid the purchase of a new unit. Its turbines range up to 30 MW. It primarily serves South and Central America, India, Middle East, Africa, Russia, Turkey, Europe and South East Asia.

Triveni’s turbines have a steam inlet temperature of up to 545°C and an inlet pressure of up to 120 bars. The company can provide straight condensing, bleed condensing, extraction condensing, double controlled extraction condensing, injection condensing, axial condensing, reheat condensing, backpressure steam turbines. straight backpressure, extraction backpressure, and bleed backpressure.

The most popular models are the TST2018, TST1150 and TST2150IR. They typically serve process cogeneration, sugar cogeneration and the cement waste heat recovery market segments. The TST2018 is an extraction condensing turbine that gives process steam through extraction and power for captive use, aimed at the CHP market. The TST1150 is a back-pressure model used for process steam and power. TST2015IR is an injection condensing turbine used mainly in cement and waste heat recovery.

Howden steam turbines range from 100 kW to 15 MW. Some are focused on the mechanical drive market such as its API611 models. Others are more appropriate for power generation applications. They operate at inlet pressures from saturated steam at 10 bar to overheated steam at 131 bar/530°C. Discharge pressures range from 0.06 bar abs up to backpressure applications at 45 bar.

Howden Mono and Twin turbines are available for power generation. They favor an integrally geared overhang design. One benefit is nozzle group valve control that enables higher efficiency at part load operation.

For Twin turbines, Howden configures two overhang turbine casings with one integral gear. This setup allows for higher performance, good part load behavior and precisely controlled extraction pressure. All turbines can be equipped for automated quick start without pre-heating.

Recently, Howden has been working on digitizing its steam turbine operations.

“Digitized operation will facilitate predictive maintenance, optimize steam turbine efficiency and improve operability,” said Dr. Matthias Schleer, R&D director for Steam Turbine Products at Howden.

Ansaldo Energia offers large ratings for reheat applications suitable for supercritical and ultra-supercritical conditions, as well as compact modules for smaller ratings and single- and two-cylinder model for non-reheat thermal cycles. It also caters to district heating and cogeneration applications. They are available in a back pressure or condensing configuration.

The lineup includes the RT-30, a 150 MW to 1,000 MW steam turbine for reheat. The MT15, MT20, and MT10, all for non-reheat applications, range from 40 MW to 350 MW. The GT is the company’s geothermal model with capacity from 40 MW to 150 MW. Steam turbine retrofits are available.

Baker Hughes offers condensing and back-pressure units, multiple extractions or injections, single- or double-flow configurations, axial or radial exhaust, and baseplate and concrete mounted solutions. These STs range from 2 MW to 150 MW, with steam inlet pressures of up to 140 bars.

SC/SAC/SNC/SANC series models have impulse and reaction blades for high efficiency over a wide range of operating conditions. A modular design enables customization to meet steam-cycle needs. MP/MC/P/C series units feature an impulse design with a simple architecture and easy maintenance requirements. Reliable and compact, this series is suitable for small power generation, boiler feedwater pump drivers, and marine applications.

Elliott STs serve industries such as oil and gas, chemical and petrochemical, pulp and paper, power generation and food processing. As power requirements, steam conditions, and speeds continue to rise across the industry, Elliott has developed units to meet changing operating conditions. They are rated for inlet steam conditions up to 2,000 psig/1005°F and speeds up to 20,000 rpm.

Elliott STs range from 20 HP (15 kW) single-stage units to 175,000 HP (130 MW) multi-valve, multi-stage extraction condensing units. They are customizable and can be built to API standards.

Single-stage YR series units are known for operating in harsh conditions. Multi-YR (MYR) turbines combine the reliability and parts interchangeability of the YR turbine with the power and efficiency of multi-stage turbines. MYRs produce more power without additional steam and can be installed in areas where single-stage STs are currently operating.

Multi-stage (or multi-valve) STs are another core component. Designed to API 612 standards, they have a small footprint and offer high efficiency. Under typical operating conditions (600 psig/750°F) they provide more than 80% efficiency. They can also operate under high-pressure/high-temperature conditions (1300 psig/ 905°F).

Elliott also offers ST generators for on-site generation with standby power of up to 50 MW, including renewable energy applications and green energy initiatives.

41% of the world’s combined cycle, 30% of fossil, and 50% of nuclear plants are said to be powered by GE STs. They span all fuels, outputs from 100 MW to 1,900 MW, and accommodate various site, operational, steam cycle and application needs.

GE makes fossil STs such as its STF-D Series; combined cycle units, such as its STF-A650 and the STF-D600 for reheat; and its Arabelle nuclear steam turbine. The STF-A650 has an 85 MW to 300 MW output. The STF-D600, a two-casing, double-flow low-pressure section, combined cycle steam turbine, has a capacity ranging from 180 MW to 700 MW.

GE’s STF-D Series is a modular product platform for utility reheat STs in the 100 MW to 1,200 MW range. The STF-D Series is designed for main inlet conditions up to 650°C (1200°F) and 330 bar (4786 psi) and reheat temperatures up to 670°C (1238°F).

Steam turbines from MAN Energy Solutions can be used for mechanical drive or power generation applications. With a power range between 1 MW and 180 MW, they can be scaled for special process and customer requirements.

These STs are used in waste-to-energy, biomass, geothermal, CSP and industrial power generation applications like waste heat recovery. Moreover, the same technology is applied to new solutions for power generation such as expansion of methane, carbon dioxide or air.

Its small and medium units are among its most popular. The MST040 operates between 3 MW and 15 MW at 140 bar inlet pressure and 540°C. MAN offers five others with the same inlet pressure and temperature, but higher power outputs, maxing out at 180 MW for the MST120 series. ■

Wherever heat is available and there is a demand for power, you are likely to find one of turbomachinery’s oldest and world-changing inventions – the industrial steam turbine (ST). The technology has come a long way since its first modern manifestation in 1884, persisting through every market boom and bust.

Steam is here to stay. Demand grows for small and medium-sized steam turbines

Vendors such as AAF, Donaldson, Camfil, Freudenberg Filtration, Mann+ Hummel, Gore and Eagle Filters have been working to improve the quality of their filters, to provide higher levels of protection in any environmental conditions, and to design complete systems that reduce maintenance requirements while filtering out harmful elements.

They note trends such as the development of better hydrophobic (tending to repel water) media, greater attention on the prevention of salt and hydrocarbon ingestion, and a wider range of filtration options to suit different budgets, performance objectives, and equipment or retrofit needs.

The Gas Turbine Systems division of Donaldson provides engineered filtration solutions for all environments and most air intake and lubrication systems for gas turbines, industrial compressors, and generator sets. Donaldson Turbo-Tek Cartridge Filters use an Er|W|P rating system instead of capture efficiency, as measured by MERV ratings. It also tests for watertightness and pulsability, and rates on a 0 to 5-point scale:

• Efficiency (Er0 to Er5) – what proportion of airborne contaminates does it capture?

• Watertightness (W0 to W5) – how does it handle high humidity and moisture?

• Pulsability (P0 to P5) – How readily do the filters in self-cleaning systems recover peak performance after pulsed with compressed air?

These attributes differ from one filter to another. In combination, they drive operating costs and performance under specific environmental conditions. Donaldson’s filter line can be divided into three categories:

Base medias are economical options that consist of cellulose and synthetic fibers. They are moisture-resistant with a high watertightness rating; however, they have a lower capture efficiency rating (Er1 – Er3) and do not provide (H)EPA-level efficiency.

Performance synthetic range of medias offer F9/MERV 15 efficiency, combined with a P5 pulse recovery rating. This option is for users not needing a high capture efficiency but are dependent on strong pulse recovery in desert or arctic environments, for example, where there is exposure to dust, snow, and ice buildup, or sudden episodes of heavy loading.

Premium (H)EPA filtration captures over 99.5% of 0.1p penetrating particle size. Turbo-Tek H20+ is the most watertight option, rated Er5|W5|P1. Its synthetic media acts as a barrier to water. It is suitable for coastal environments, stopping salts and other corrosive water-soluble contaminants. Turbo-Tek (H)EPA Pulse has surface-loading blended media with a rating of Er5|W1|P4. The P4 pulse recovery rating and high Er5 efficiency rating are best for deserts or areas with a high dust load that depend on a strong pulse recovery.

Cassandra Light, Manager of Gas Turbine Systems for the Americas and APAC, Donaldson Company, gave the example of a plant on the humid Australian coast using Turbo-Tek H20+ filters. The air was laden with sea salt and smoke from nearby brush fires, yet filter life rose from 18 months to 48 months with 0% loss in compressor efficiency, stable differential pressure across the filters (DP), clean blades, and elimination of on-line water washes of the filters.

“A site in a harsh environment in China with a high volume of hydrocarbons has increased filter life from one year to nearly three years and has eliminated water washes (on-line or off-line) altogether,” said Light.

In addition to filtration for gas turbine air intake systems, the Donaldson Gas Turbine Systems Quick Lock Yoke filter retention system ensures secure installation and reduces filter changeout time. Light said that in a test, the time required for filter replacement could be reduced by a little less than half.

AAF International offers a wide range of filters. It recently launched the DuraShield S filter cartridge to protect gas turbines and reduce compressor fouling, as well as cold and hot end corrosion. The DuraShield S has a high MERV 15 (F9) initial efficiency that provides sustainable performance over its operational life.

Other features include a high dust holding capacity, low pressure drop and cartridges that act as a water barrier, withstanding high humidity, mist, fogs or rain. This means differential pressure (dp) can remain predictable and stable and dp spikes are not a concern.

The company provides an online platform to help customers determine the best filtration approach for their plant. As well as the geometry of the filter, it takes into account climate, environmental and operating conditions, high humidity, extreme temperatures, coastal and offshore locations, and other variables such as the presence of hydrocarbons, dust and gas turbine mode of operation.

Stuart Blackburn, Product Management Director at AAF International, noted a change in attitude recently to address the disparity that often occurs between onshore and offshore filtration systems. In the onshore environment, higher grades of filtration are well adopted but are not found as frequently offshore. Yet the offshore environment must deal with salt, which if untreated will drastically reduce the efficiency, performance and life of any GT.

Camfil Power Systems offers a full range of pre-filters and final filters for turbomachinery applications. This includes bag filters, panel filters, compact filters and cartridge filters. Efficiency ranges are available up to H13. In addition, the company provides complete air inlet systems including filter houses, acoustics and ventilation (enclosures and silencers), environmental protection such as anti-icing systems, air treatment systems (inlet cooling and heating), weather protection (hoods, louvers/mist eliminators and insect/bird screens), ducting and retrofit services. The company also offers engineering laboratory services, site analysis, CamLab (on-site mobile engineering laboratory), remote monitoring, training, life cycle cost analysis (LCC), installation and filter change and performance optimization.

CamGT compact filters, for example, are engineered for extreme environments. They are designed for EPA efficiency to boost power by minimizing degradation while maintaining a low, stable pressure drop. New features increase equipment availability, reduce corrosion risk and improve fuel consumption and carbon footprint.

Hydrophobic media and a double-sealed construction eliminate the risk of dissolved contaminants passing through the filters. The filter construction offers a more open face geometry and the aerodynamic grid redirects exiting air to reduce pressure drop. In addition, drainage has been improved on the latest models.

The latest generation includes three models. The CamGT 4V-300 (12” depth), the New CamGT 3V-440 (17”), and the CamGT 3V-600 (24”). CamGT filters are offered from ISO ePM1 75% (F7) to E12 efficiency and fulfill standards for efficiency, burst strength and water repellency. Camfil offers a value rating feature on its website to help evaluate filtration effectiveness and economics.

“This line is designed for all environmental conditions including extreme conditions of humidity, salt, and heavy pollution that threaten gas turbine performance,” said Marc Van den Eynde, Vice President at Camfil Power Systems.

He offered some general advice on filter selection: Efficient Particulate Air filters (EPA) static filters are well-suited for wet, salt-laden or coastal/offshore environments. Pulse filters are recommended for dusty environments with low humidity. Depending on location, application, construction, ambient conditions, and particulate type/amount, the filter solution could vary from one stage to multiple stages with a variety of filter options.

Camfil is introducing a service that digitizes the coupled performance of the inlet system and GT. Known as PowerEye, it digitally monitors inlet system and GT metrics to provide trend analysis and forecasting. Ambient aerosol and weather conditions, current pressure drop, turbine load and heat rate are some of the metrics that can be analyzed to determine such things as future power output, and an optimized schedule for off-line compressor washes or filter replacement.

Gas turbine air filtration solutions from Freudenberg Filtration Technologies address areas such as particle removal, prevention of compressor fouling and corrosion. The Viledon hydroMaxx coalescing filter repels moisture at the pre-filter stage. The Viledon T-60 is a pre-filter used by turbine and turbocompressor OEMs for its dust holding capacity. The Viledon eMaxx is a final filter that protects equipment to the E10-E12 HEPA range. For systems using a cartridge or canister-type filter, the Viledon GTS double cylindrical filter offers high performance dust holding capacity and optimized pulse jet operation. It uses a nested design; one cylinder fits inside the other, reducing storage and shipping volumes. Besides filter elements, the company provides engineering staff for filter house construction, retrofitting, or modification to existing installations.

Mark Arsenault, USA Turbomachinery Sales Manager for Freudenberg Filtration Technologies, emphasized the capabilities of the Viledon hydroMaxx. It can convert any single-stage filter house into a multi-stage filtration system, is equipped with a clip-on system that allows close coupling to the intermediate or final filter in one filter wall, and drops out moisture before it causes problems in the inlet system. It also sheds snow and ice from its leading edge, preventing blinding and allowing air to pass through.

Mann+Hummel, headquartered in Germany, offers a range of high-performance air filtration solutions. It recently launched new products for all stages (coalescing stage, pre-filtration and final filters) and introduced pulse jet cartridges.

The Aircube Pro Power S and Nanoclass Cube Pro Power S for GTs are designed to meet the extreme operating conditions found, for example, on oil platforms at sea. They provide low pressure drop, high burst pressure and a high dust holding capacity (DHC). The media that Mann+Hummel developed in cooperation with a partner is water and salt repellent. Testing showed a burst resistance of 35.000 m3/h above a pressure of 8.000 Pa.

“The air filter market for this application has been dominated so far by micro glass fiber media, which has disadvantages such as sensitivity to mechanical stress and low water resistance,” said Mohammed Asif, Business Development Manager, Middle East & Africa, Mann+Hummel. “The synthetic media in the Aircube and Nanoclass Cube offer higher resistance to mechanical stress than glass fiber media and stable high efficiency during operation.”

He has noticed a trend toward the adoption of greater filtration efficiency on each stage, often using EPA filters at the final stage. This may increase pressure drop, but better air filtration efficiency improves overall GT efficiency of the gas turbine, he said. It also heightens performance in challenging environments such as offshore.

W.L. Gore & Associates offers Gore E-12 HEPA Turbine Filters. They are available in an array of pulse-cleanable and static operational mode cartridge and panel configurations to fit into existing filter houses. All Gore Turbine Filters contain Gore’s 3-layer synthetic composite with a depth loading layer, hydrophobic ePTFE membrane, and strong pleated backer for long life, low pressure drop, and protection from airborne contaminants, salt ingestion and hydrocarbons.

The company plays in multiple markets across the globe including power generation, oil & gas production, refining and LNG. In particular, it does well in environments where maintaining operational effectiveness is critical such as applications without backup options or built-in process redundancies.

“In applications where the user does not have the option to shut down their equipment, the filter’s job is to protect the turbine from particulate damage, to remove particles that would reduce its efficiency and to allow the turbine to remain online until the operator is able to perform their scheduled maintenance,” said Paul Vierra, Regional Sales Manager, at W.L. Gore & Associates. “All Gore solutions for gas turbines are all high efficiency E-12 HEPA filters.”

Gore Turbine Filters accomplish high particulate capture capacity. The filter must have the dynamic capability to function in varied applications which can be anything from coal dust from a nearby deposit to fine metal powder from a wrecking yard next door. HEPA E12 efficiency means that the media can pick up fine dust the eye cannot see. Studies show that sub-micron sized particles in the atmosphere account for a large majority of particulate count when compared to the number of larger than micron-sized particles. It is these sub-micron particles that are missed by traditional filtration technologies. By capturing these particles, the end user can keep its compressor clean and avoid performance degradation or shutdowns.

Vierra also touts the effectiveness of his company’s filters in water management. Poor water management leads to water build-up on the surface of a filter that will eventually blind the surface so air cannot pass. This results in inlet differential pressure spikes, load reduction and sometimes shutdown. Gore filters remove water from the inlet airstream, which can contain a number of dissolved elements including salt and other corrosives. Eliminating these from the airstream prevents harmful particles from contacting turbine parts.

“We have seen a push by OEMs to adopt HEPA technologies for this reason,” said Vierra. “Effective water management means filters must be able to continue to operate while blocking large amounts of moisture from rain, fog and mist.”

His advice to users is that the filtration selection process begins with knowing your environment. He also recommended a full return on investment analysis that includes an estimate of the total cost of filtration over the lifetime of the turbine. The plant must balance media costs, replacement costs, frequency of replacement and filtration effectiveness against risk such as lost production, increased operational costs and/or capital costs from damaged turbine parts.

Eagle Filters produces GT inlet air filtration products ranging from coalescers to HEPA final filters. They come in all forms and shapes with various connection methods to fit in any inlet house. The company can also upgrade filtration without having to modify inlet house structures using two-layer cartridges and snap-on attachment methods for square filters.

TurboMaster cartridge/canister type HEPA grade filters have a two-stage structure enabling filter houses to be upgraded to two-stage filtration. Both stages operate independently providing longer service life and predictable end-of-life behavior.

TurboMaster can be equipped with a prefilter sock that further improves service life by effectively making it a three-stage filter in a single cartridge/canister slot. The company produces its own filter media with no membranes in the filtration structure for better salt durability.

“Our fully synthetic product range provides excellent protection against humidity and salt,” said Pertti Sundberg, Director of Sales at Eagle Filters. “Our three-stage HEPA filtration offers excellent cleanliness and high GT efficiency without the need of on-line or off-line washing to regain the GT output lost to degradation.”

The company’s website features a GT degradation estimator. It takes into account the difference in turbine performance before and after off-line washing, as well as annual operating hours to determine the MWh lost each year. This helps users determine if their current method of inlet air filtration is sufficient.

For desert environments, Eagle Filters offers a way to address sand blockage of first-stage filters after sandstorms and the high average lifetime dp of pulse filters which can lead to loss of GT output. It’s large surface panel prefilters can be replaced quickly after a sandstorm, enabling a plant to run with static filters throughout the year at much lower lifetime dp.

The bulk of GT wear and tear may be caused by foreign particles entering via inlet air system as a result of poor filtration. But Sundberg noted the challenge inherent in convincing plants to invest in better filtration. Budgeting for HEPA-grade filter upgrades, he said, can be far less common than paying far more for the turbomachinery damage caused by particulate.

Filtration needs vary depending on the environment. Here are some of the site conditions to look out for:

High particulate, industrial areas: Refineries and areas of heavy traffic generate tiny hydrocarbon particles. HEPA filtration is recommended. In the presence of sticky hydrocarbons, prefilters are needed to extend the lifespan of HEPA filters.

High particulate, desert areas: Coarse sand can block first-stage filters after sandstorms. Pulse cleaning and pre-filters are among the options offered by vendors.

Salty coastal line: Anywhere within 50 miles of the coast can suffer from salt particles, but especially near the sea. Salt particles are small and demand adequate prefiltration to protect HEPA filters.

Offshore platforms: Salt and hydrocarbons are the primary challenges offshore. Recent studies show offshore facilities often require stronger filtration than has traditionally been implemented.

High humidity: Humid environments should opt for hydrophobic filter material, with the moisture removed in multiple stages.

“Organic material such as cellulose will absorb moisture and swell, increasing the dp as the media becomes blocked,” said Sundberg. “Also, the wet tensile strength of organic materials is typically much less than the dry tensile strength. Weak wet material with high dp is the most common cause of filter ruptures.”

The filtration of gas turbine inlet air has always been important. But its profile has been raised as more becomes known about filtration efficiency, the need to filter out small particulate and the role of filtration in overall turbine performance.







Better Filtration = Better Performance: Inlet air filtration in gas turbine performance and efficiency

I just heard the disappointing news that PowerGen International in Orlando in December has been postponed. At times like this, trade publications such as Turbomachinery International are the primary way to reach your peers and your customers. Accordingly, we have stepped up our efforts to assist the industry to make it through these unusual times. Our days are peppered by video chats with OEMs and aftermarket suppliers to discuss industry trends, company news, potential contributed articles and how we can help them to get their message out.

We have established a strong webinar program to provide a forum for companies to communicate important issues and discuss their products and services. These webcasts are attracting large audiences. The Q and A portions at the end always generate far more questions than we can possibly cover.

On the content side, we have beefed up our online presence via newsletters, blogs and LinkedIn posts, and have expanded our print coverage. Which brings us to the current issue.

The cover story concerns gas turbine inlet air filtration. We surveyed the market leaders in this field to find out what is new, what trends are emerging and the different products they offer. They told us about improved filtration technology to deal with challenging environments as well as how the different filter classifications can be used to fit a variety of environments, owner preferences, equipment ages and price points. In the absence of traditional booth visits at trade shows, vendor roundup articles like this offer an opportunity to find out about the latest products and services available.

We took a similar approach to our steam turbine feature, interviewing almost all manufacturers about their available products, features, materials and capabilities. There is far more technical development in this area than many realize. Gas turbine innovation garners most of the headlines. Yet steam turbines have quietly evolved to fit the modern age. These machines remain an essential element of the power industry.

September/October 2020