Each of these events significantly strained electric infrastructure causing inoperable utility equipment and power outages. Within the U.S., many of the regulatory agencies are mandating that resource entities identify cold-weather-critical equipment, develop freeze protection measures for this equipment, and document the minimum ambient dry-bulb temperatures that the resource can reliably operate to. For these mandates, typically, the minimum operating temperature can be based on historical operating data, equipment rating, or engineering assessment. Even more recently, some regulatory agencies have put into place requirements addressing wind speed and wind chill.

Cold weather procedures and equipment changes most common in the colder climates are making their way across the U.S. Generators need to be prepared for cold weather to avoid lost generating ability, which can translate into lost revenue, fines, and equipment damage.

Water and Wind

Water is a major freeze risk, and any equipment that uses water needs to be protected. Systems and equipment not needed during cold weather operation should be removed from service and the water drained to ensure the equipment is not damaged during a freeze event. Water wash systems, inlet chillers, or wet compression systems are examples of equipment that can be removed from service and drained if weather forecasts indicate cold weather approaching; this will allow winterization efforts to focus on items needed for plant operation during a cold weather event.

Some equipment using water will need to remain available, such as NO_x water systems, boilers, sensing lines, and heat exchangers. A common way to protect equipment is insulated heat tracing or the addition of a freeze inhibitor (glycol) if the water is part of a closed-loop heat exchange system. Some systems can be drained and then refilled prior to the unit coming online.

Wind on its own cannot cause freezing. The ambient temperature must be below freezing for water to freeze. At temperatures below freezing, wind can rapidly increase the freeze rate by increasing convection, or the rate at which heat is removed from a pipe or other water source. Wind effects can be negated by proper wind breaks and/or insulation.

Equipment Considerations

Fuel Systems. Natural gas is recommended to be maintained above 40F for proper fuel nozzle operation to minimize the condensation of hydrocarbons and moisture in gas. Liquid fuels will have their own minimum temperature that needs to be maintained. Gas lines are always buried below the freeze line, which helps maintain gas temperatures above freezing. It is good practice to insulate the main supply valve, and moisture filter drain lines should be protected to avoid freezing. Heaters may be needed for liquid fuels with minimum temperature requirements.

Gas Turbine Inlet and Bellmouth. Inlet icing or snow accumulation can cause excessive pressure drops, causing unit derate or trip. To avoid this, well-sized hoods should be used to protect the inlet from excessive accumulation. Coalescing-type filters, designed to remove and collect moisture, should be removed before winter.

Compressor bellmouth icing can occur when inlet air is cold and humid, even if the ambient temperature is above freezing. Isentropic acceleration of air can reduce the air temperature by as much as 4F. A viewport can be added to observe the bellmouth (Figure 1). If icing occurs, or a history of icing is known, inlet air heating can be added to avoid foreign object damage from ice ingestion.

Turbines and Generator. It is recommended to have a heater in each turbine and generator enclosure, dedicated to ensuring critical equipment inside the enclosure is protected. If the turbine and generator are located within a building, the building should incorporate multiple heaters to maintain temperature inside the building. Enclosure or building, doors and vents should be closed to minimize cold air intrusion. During extreme cold events, air entering from an open door or vent can overwhelm the ability of a heater to maintain enclosure temperature.

It is good practice to place turbines on a turning gear at sub-freezing temperatures. This will also keep lube oil flowing. Additional protection may be required for bleed and purge valves, equipment configuration depending.

Generators typically have internal heaters to ensure moisture levels are kept low. These internal heaters for moisture control do not negate the need for a separate compartment or building heater, especially during extreme cold weather events. It is noted that steam turbines are not sensitive to changes in ambient temperatures.

Valves, Instrumentation, Plant Air, and Pumps. Failure of small valves or drains can cause big problems. All critical valves should be insulated, and pressure, flow, and temperature transmitters should be kept in protective boxes with a heat source (Figure 2). Sensing lines utilizing water should be heat traced and insulated.

Plant air compressor drains should be kept from freezing and the air dryer should be capable of dropping the dew point by a minimum of 18F. Most dryers are capable well beyond this. Valves that pass undried air, such as compressor bleed valves, are at risk from freezing and should be protected with heat and insulation. Depending on valve position, windbreaks may be necessary.

Water pumps that are critical to plant function must be protected. Submersible pumps that sit in deep wells are typically protected as the water surrounding them does not freeze. In-line pumps, such as boiler feedwater pumps, will have to be protected by a heat source or warm water recirculation and wind breaks.

Lube Oil Systems. It is recommended to have extra immersion heaters available in case of a failure during a cold weather event. It is good practice to check the temperature of lube oil tanks during site rounds, especially at sites configured with exposed lube oil skids. Insulation of exposed lube oil lines may be necessary if sites are prone to experiencing high winds. Lube oil systems on exposed skids may require wind breaks or potentially an enclosure with a heater.

Weather Planning

Winterization Methods. All necessary water systems need to be protected with heat trace and insulation (Figure 3), recirculation from a warm water source, and any water treatment buildings should be heated. Cooling systems, wherever possible, should utilize a glycol-water mixture and all unnecessary water systems should be shut off and drained.

Critical equipment should be protected from the effects of cold wind. Typical protection methods are heat trace and insulation, windbreaks, and/or temporary enclosures with heaters.

Windbreaks should account for prevailing wind direction. Note that windbreaks need to be robust. Tarps tied around equipment will not be as robust as scaffolding wrapped in plastic or metal frames with metal walls (Figure 4). Adequate wind protection will minimize the effect of convective heat transfer.

Backup equipment, such as generators or air compressors, may be appropriate if the facility has a history of specific equipment failure during cold weather events. Extra winterization equipment should be kept onsite. This should include tarps, heaters (Figure 5), extension cords, and items to address emergent issues.

Cold Weather Operating Procedure. Sites should maintain cold weather plans appropriate for the plant location. The intent of a written procedure is to ensure a plan is in place and provides direction for how to keep units operating during cold weather events. Updates to the procedure are a critical part of risk mitigation because equipment failure modes can vary with age; weather patterns can shift; and plant operational modes, configurations, and personal can change. What worked in the past will not necessarily be sufficient in the future. A good cold weather plan should include the following:

• List of cold-weather-critical equipment.
• List of weatherization supplies and equipment.
• Responsible parties and contact information.
• Staffing requirements.
• Plan implementation details, including criteria (calendar date vs. temperature specific).
• Checklists.
  • Preparation.
  • In-action.
  • Post-action/corrective-action.
• Revision control.
• Documentation of historical minimum and maximum temperatures.
• Training requirements.

Summary

Cold weather events will continue to happen. Preparation and planning are critical for plants to remain operational during events.

To meet our customers’ requests to maximize plant availability during cold weather operation, TG Advisors has developed a “Weather Readiness Assessment” that accomplishes three goals through data analysis, review of plant maintenance records, engineering calculations, and expert experience. The assessment:

• Addresses regulatory requests (typically minimum ambient temperature capability and/or wind chill capability).
• Identifies equipment limitations and opportunities for improved robustness.
• Reviews a plant’s weather preparation and action plan and provides feedback for improvement.

TG Advisors’ process includes a plant walkdown and interview with key personnel to review equipment condition and plant configuration and to identify site-specific needs. Please reach out to us with any questions or talk to us about how we can help your site maximize availability during the cold weather season.

—David Butz (dbutz@entrustsol.com) is a senior consulting engineer, and Jason Neville is the engineering manager and a consultant, both with TG Advisors, an ENTRUST Solutions Group company. To learn how to prepare for hot weather, read “Hot Weather: How to Maintain Power Plant Readiness and Reliable Operation.”

Record-setting temperatures significantly strain electrical infrastructure and can cause inoperable utility equipment and power outages. Power outages can cause disruptions to essential daily operations for the public, such as disruptions of communications, closure of retail businesses, loss of air conditioning, and more. In turn, utilities lose revenue and face potential penalties.

Some regulatory agencies are acting to minimize disruptions. Within the U.S., many of the regulatory agencies are mandating that resource entities provide maximum ambient dry bulb temperatures to which the resource can operate without a forced outage, startup failure, or de-rate. Typically, the request requires the temperature capability to be based on:

• Historical operating data.
• Equipment rating and/or engineering assessment.

The verbiage of the requests is based on North American Electric Reliability Corporation (NERC) EOP‐011‐2 “Emergency Preparedness and Operations” and EOP‐012‐1 “Extreme Cold Weather Preparedness and Operations.”

Hot Weather Considerations

Turbines and Generators. Output reduction during hot weather should be expected and accounted for. For plants with gas turbines as the prime mover, hot weather adversely impacts heat rate and output due to the lower air density of hot air entering the compressor. Inlet tempering systems such as fogging or chillers offset some of the reduction in output that occurs during hot day operation. Exhaust over-temps can occur, but this is not a major issue based on firing temperature control logic. Additionally, emissions compliance can be more challenging on hot days. Note, steam turbine performance is typically not impacted by hot weather, but if run in combined cycle with gas turbines there can be an impact to the overall system efficiency.

Generator output limitations are captured by the generator-specific capability curves, and typically generators are sized such that they are not limiting during hot weather events. The three main types of generator cooling systems are open ventilation, enclosed water-to-air, and hydrogen cooled. In all cases, the fans and coolers should be in good working order. Exciter compartment overheating can cause unit shutdown once the exciter temperatures reach the trip limit. Like the generator, the cooling system for the exciter should be in good working order.

Typically, transformers, like generators, are sized not to be limiting, but elevated temperatures degrade insulation and reduce life of transformers. Oil levels should be maintained and all fans should be in good working order. Misting or water spray can be used to augment the existing cooling systems during extreme hot day operation.

Lube Oil, Cooling, and Water Systems. A common source of problems during hot weather operation is failure of cooling systems. Bearing metal temperatures need to be maintained below limits and typical plant configuration utilize fin-fan coolers to reduce the temperature of lube oil once it exits the bearings. Degradation of the lube oil coolers may only be apparent on hot day operation when the system is stressed. Plants utilizing inlet chillers on gas turbines will typically use a closed-loop heat exchanger as part of the system that reduces the air temperature within the filter house before it enters the compressor. On hot day operation, these inlet chillers can be critical for ensuring plant output can meet demand.

To ensure coolers or heat exchangers can meet the cooling demand, the sizing should be appropriate for the application and cleanliness should be maintained with recurring maintenance. All valves should be kept in good working order and any insulation should be checked for condition.

If coolers are not able to keep up, it may be necessary to add a water spray system to augment the systems during extreme hot day operation. Changes in plant configuration or usage pattern may necessitate upsizing the cooling system.

On-site water usage and criticality will depend on plant configuration. The primary water supply should be maintained. Any back-up or contingency for water supply should be in place before hot weather begins to ensure there is no impact to plant availability if there is an interruption of the water supply or if plant water usage exceeds supply.

Cabinets and Compartments. Instrumentation cabinets should always be climate controlled. Compartment temperatures are typically not limiting but will alarm. HVAC (heating, ventilation, and air conditioning) maintenance should be scheduled prior to the start of hot weather. During hot weather events, daily plant walkdowns should include checks to confirm all outside doors are appropriately positioned. Compartments utilizing climate control will typically need to have exterior doors shut, while compartments without climate control may benefit from an increase in ventilation with the door open. Portable air conditioners can be staged within key compartments if there is a known limitation on extreme hot day operation.

Weather Planning

Sites should maintain hot weather plans appropriate for the plant location. The intent of a written procedure is to ensure a plan is in place and provides direction for how to keep units operating during hot weather events. It is a living document. Updates are a critical part of risk mitigation because equipment failure modes can change with age, weather patterns can shift, plant operational modes can change, plant configurations can change, and plant personal can change. What worked in the past will not necessarily be sufficient in the future. A good hot weather plan should include the following:

• Revision control.
• Documentation of historical minimum and maximum temperatures.
  • Location specific record temperatures.
  • Successful minimum and maximum operating temperatures.
• Equipment lists.
  • Weather sensitive and critical standard plant equipment.
  • Additional weatherization supplies and equipment such as portable air conditioning units, fans, and portable tenting.
• Responsible parties and contact information.
• Staffing requirements.
• Plan implementation criteria and phases (time and temperature).
• Training requirements (annual).
• Checklists.
  • Preparation.
  • In-action.
  • Post-action/corrective-action.

The hot weather procedure plan should account for both a running and idle plant. Plan implementation criteria can be both time and temperature dependent to ensure all permanent equipment is prepared, and all non-permanent equipment and supplies are ready and available at the appropriate time.

Conclusion

Hot weather events should be expected to continue to occur at an increased frequency from past events. The regulatory requests for documenting hot weather temperature capability are here to stay and may become more detailed.

Preparation and planning are critical for plants to remain operational during events. Plants should maintain and annually update hot weather plans that make sense for the equipment on site and the geographic location.

To meet our customers’ requests to maximize plant availability during hot weather operation, TG Advisors has developed a “Weather Readiness Assessment” that accomplishes three goals through data analysis, plant maintenance records, engineering calculations, and expert experience. The assessment:

• Determines a plant’s current minimum or maximum ambient temperature capability and addresses regulatory body requests.
• Identifies equipment limitations and opportunities for improved robustness.
• Reviews a plant’s weather preparation and action plan, and provides feedback for improvement.

TG Advisors’ process includes a plant walkdown and interview with key personnel to review equipment condition and plant configuration, and identify site-specific needs. Please reach out to us with any questions or talk to us about how we can help your site maximize availability during the hot weather season.

—David Butz (dbutz@entrustsol.com) is a senior consulting engineer, and Jason Neville is the engineering manager and a consultant, both with TG Advisors, an ENTRUST Solutions Group company.

Jason Neville

Turbomachinery Magazine, July/August 2023, Volume 64, Issue 4

Running traditional natural gas turbines with hydrogen will play an increasingly important role in reducing CO2 emissions in power generation. 

While natural gas is the cleanest large-scale combustion fuel in use today, its use as a fuel for power generation results in approximately 15% of all CO₂ emissions in the United States—gas turbines are responsible for a large portion of these emissions. Renewable energy sources are continuing to make inroads into the global energy ecosystem, but gas turbines will continue to be prevalent; therefore, addressing their CO₂ emissions is an important step toward achieving a carbon-free energy network.

Hydrogen is earmarked as a possible fuel to displace natural gas and provide CO₂-free combustion in gas turbines and beyond. The main byproduct of combusting hydrogen is H₂O, making it a truly CO₂ emission-free fuel. A long-term goal is to burn 100% green hydrogen in gas turbines, replacing natural gas; in the shorter term, hydrogen can be blended with natural gas and burned in gas turbines for a fractional reduction of CO₂ emissions.

Comparison to Natural Gas
When using hydrogen in conjunction with natural gas or as a full replacement, it is important to understand how the two fuels differ. A 100% hydrogen blend requires 208% of additional volumetric flow, roughly three times compared to methane. A 75% blend of hydrogen is required to reduce CO₂ emissions by 50%. These percentages make the immediate plug-and-play use of hydrogen in gas turbines difficult.

Additionally, hydrogen faces unique supply and infrastructure challenges. Hydrogen’s physical properties make production, storage, and transportation more difficult as compared to natural gas, and it can present safety concerns—such as larger flammability range, lower vapor density, faster flame speed, etc.—that must be considered in system design.

Gas Turbine Considerations
All gas turbines are not created equal. There can be large differences between industrial gas turbines (IGT) and smaller aeroderivative engines as well as across equipment manufacturers. Every gas turbine design needs to be evaluated on an individual basis to determine its hydrogen-burning ability and to what level of retrofit or design change(s) is required to improve
this ability.

Required design changes are highly dependent on the percent volume of hydrogen planned to be burned. Hydrogen burning can be segmented into low-, medium-, and high-percentage blend groups. A turbine operating on a low-percentage blend of hydrogen (5-10%) may not require any design or material changes, as the fuel-burn characteristics are similar to a 100% natural gas fuel stream. For medium-percentage blends (10-50%), the combustor and overall turbine architecture will be mostly unchanged, but design changes to existing combustor materials, fuel nozzles, and control systems will be needed. For higher blends of hydrogen, more than 50%, major modifications must be made to the turbines and likely a complete retrofit of the combustion system. Many OEMs are currently working on new combustion systems that support high-hydrogen blend levels.

Turbine Enclosure
Fuel system piping and valves in the enclosure must be compatible with hydrogen—materials must be hydrogen-compatible and engineering safety factors must be included in the design. Moreover, hydrogen-tight seals must support small hydrogen gas molecules. Piping and valves may have to be enlarged to handle the higher volumetric flow that hydrogen requires, depending on the blending percentage (FIGURE 2).

Safety systems for gas detection and fire protection must be modified to account for hydrogen’s volatility and detection differences. Similarly, explosion-proofing must be able to contain larger explosions, and ventilation systems need to be modified.

Combustion System
A turbine’s ability to burn hydrogen is almost solely dependent on the combustion system. The larger the hydrogen percentage in the fuel, the more challenged an unmodified combustion system becomes. To add to the difficulties, for the foreseeable future, combustion systems will have to maintain fuel flexibility and the ability to burn natural gas. The combustion system is challenged by:

• Hydrogen is one-ninth the density of natural gas and is the smallest known molecule, which creates transportation and sealing challenges. 
• Hydrogen’s heating value is one-third of natural gas, which means three times as much hydrogen fuel flow is needed to produce the same amount of power as compared to natural gas.
• The flammability range of hydrogen is much larger than that of natural gas, creating elevated environmental, health, and safety concerns for both transporting and burning hydrogen (FIGURE 3).

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• Hydrogen burns hotter and has a faster flame speed than natural gas. This creates combustion instability and increases the potential for flame out and flashback.
• Hydrogen flames are much less visible than natural gas flames, making flame detection difficult.

Additionally, hydrogen embrittlement occurs as soon as it is introduced into a system, and it cannot be reversed. Embrittlement lowers the material’s yield stress, which reduces the material’s fatigue capability, particularly for low-cycle fatigue. Temperature, pressure, and stress level can influence the rate or magnitude of embrittlement. However, not all materials are equally prone to hydrogen embrittlement. Both stainless steels and nickel alloys, commonly used in gas turbine combustion systems, experience increased levels of embrittlement at elevated temperatures. This makes combustion material selections for hardware, weld joints, and braze joints difficult.

There are several main combustion system types used throughout IGTs, and the challenges described above will impact these systems differently. The two main combustion system types used in today’s IGTs are diffusion combustion systems and lean premixed combustion systems.

In diffusion flame (or conventional) combustion systems, fuel is directly injected into the reaction zone with no intentional premixing with the combustion air. A diffusion, or non-premixed, flame burns at the flame surface, while fuel on the interior of the flame remains unburned. Diffusion flames generate higher gas temperatures as compared to premixed because the fuel burns close to the stoichiometric ratio.1 The stoichiometric ratio is the ratio between gas and air where complete combustion occurs. High gas temperatures result in lower carbon oxide levels, but higher NO_x levels (FIGURE 4).

In the primary zone of a diffusion combustor, fuel is injected and burned. Incomplete fuel combustion occurs due to the mixture of fuel and air. A secondary zone, where additional air is added to the combustor, is required to complete full combustion of the fuel. The gas temperatures aft of the primary and secondary zones are too high for downstream turbine component health, thus a dilution zone is used to inject additional air and drop the gas temperature to an acceptable level.

Diffusion combustors offer greater flame stability over a wider range of flame temperatures and fuel compositions, including hydrogen, as compared to lean premixed systems. Because the flame burns close to the stoichiometric ratio, it is less prone to lean blowout during operation; and due to higher gas velocities, it is less likely to flashback. With more flame stability, combustion dynamics remain within acceptable limits. Currently, some diffusion combustors can burn 100% hydrogen, but elevated NO_x emissions are expected and require more dilution at the fuel-injection zone.

Due to NO_x challenges in diffusion combustors, many of today’s new gas turbine designs are equipped with lean premixed combustion systems: dry low emissions (DLE) and dry low NO_x (DLN) combustors. “Dry” indicates that no diluents, such as steam or water, are used for emissions control. While diffusion combustors are currently more capable of burning hydrogen, the gas turbine industry recognizes that lean premixed combustors, with superior emissions control, will continue to be the dominant combustion system for new designs, even with hydrogen.

The main difference between the lean premixed and diffusion combustors is that the fuel and air are mixed prior to injection into the combustion chamber in a lean premixed system. The homogeneous mixture of air and fuel allows for a uniform and lower temperature flame, reducing NO_x emissions without the use of dilution and the associated efficiency penalty. Most modern lean premixed combustors also use fuel staging with lean fuel-air ratios to help further control emissions. Lean premixed systems can look vastly different between OEMs and even turbine designs. DLE technology has been continuously evolving, as there has been a constant push for higher efficiencies and lower emissions. The wide variety of designs translates to a large range of hydrogen-burning capabilities across turbines. But today, in almost all cases, lean premixed combustors can handle lower volume percentages of hydrogen when compared to diffusion combustors.

When considering hydrogen in DLE and DLN systems, similar challenges that exist for diffusion combustors are magnified. First, hydrogen’s higher flame speed as compared to natural gas (greater than three times), and the slower moving flame center in a DLE system increases the flashback risk.

Next, the higher flammability range of hydrogen increases the risk of fuel ignition inside the mixing passages. Combustion dynamics are also altered with hydrogen usage. With hydrogen, elevated dynamic amplitudes over a larger range are expected since flame stability is reduced. During transient operations—such as startup and shutdown—dynamics are the greatest concern. And for the foreseeable future, a safe fuel, such as natural gas, will be required for non-steady operation (startup, shutdown, part-load). In summary, the stable operability window for most lean premixed combustors is narrower as compared to diffusion combustors, which means premixed combustors are only capable of lower percent blends of hydrogen.

Compressor
Since all the combustion takes place downstream of the compressor, the combustion of hydrogen does not have a direct impact on the compressor. There are a few indirect impacts that pertain to NO_x abatement. There are two possible ways to minimize NO_x emissions, either through unit derate or dilution (standard combustor). If unit derate is chosen, the off-design point selected must be acceptable for compressor performance and health. If additional dilution in standard combustors is chosen, the surge margin may be adversely impacted by the change in mass flow of the turbine section relative to the compressor section.

Hot Gas Path
The biggest concern to hot gas path components is the fact that hydrogen’s higher burning temperature increases turbine firing temperature. Additionally, the gas temperature profile leaving the combustor will be hotter and look different when firing hydrogen versus natural gas. For example, the gas temperature profile exiting a diffusion combustor will likely look peakier (highest temperature in the center of the combustor) when burning hydrogen if no additional changes are made. An increase in firing temperature and changes in the combustion profile shape will drive modifications to the component cooling and coating designs to avoid part-life reduction.

Summary
Hydrogen presents an opportunity to drastically reduce CO₂ emissions. Many technologies exist or are under development that will help make hydrogen prevalent in the future energy economy. Many of these technologies are very promising, but the major challenges are scale and making hydrogen generation, distribution, and usage economically viable and truly green. Further, gas turbines will continue to be an important part of the world’s energy network as they complement renewable energy sources and have a large existing installed base. OEMs are committing significant resources to design hydrogen-burning technologies into their new engines and to create modification packages for existing engines. 

Jason Neville is the Engineering Manager and Consultant at Turbine Generator Advisers, an ENTRUST Solutions Group company.

REFERENCE
1. Greenwood, Stuart A. “Low Emissions Combustion Technology for Stationary Gas Turbine Engines” 2002; Technical Report. San Diego: Solar Turbine Inc., Document.

“We are excited that TG Advisers has joined EN,” said Adam Biggam, CEO of EN Engineering.“ They bring extensive experience and expertise to a wide variety of turbine generator projects ranging from startup optimization to outage planning, maintenance, and root-cause failure analysis. They will be a great complement to our power services team.”

TG Advisers, LLC. was founded in 2004 and specializes in troubleshooting, risk-informed outage planning, and O&M optimization solutions. They help utilities navigate a challenging marketplace by leveraging decades of experience with turbines and generators and offer a robust suite of services and training.

“This is an excellent opportunity for us to partner with a nationwide industry-leading engineering firm,” said Thomas Reid, Director of TG Advisers. “We are excited to be able to expand our capabilities and partner with the EN power experts to offer turnkey solutions.”

About TG Advisers, LLC.

TG Advisers is a leading supplier of independent turbine and generator consulting services to the power industry. TGA’s team of turbine and generator consultants have designed units operating worldwide, developed novel service strategies, and engineered major unit upgrades. Today, they provide independent advice to utilities and operators worldwide. For more information, please visit www.tgadvisers.com.   

About EN Engineering 

EN Engineering’s 2,400+ professionals across 35 locations in the United States provide comprehensive and dependable engineering, consulting, design, asset integrity, data solutions, and automation services to utilities, operators, and industrial customers with excellence from start to finish. For more information, please visit www.enengineering.com.

For more information, please contact:

Erika Pacheco

epacheco@enengineering.com

(630) 967-0934

TG Advisers’ premier engineering consulting services are valued worldwide!

As independent consultants with extensive OEM experience who do not manufacture or supply equipment, we are able to provide analysis and technical field advisory services in an accurate and unbiased manner. 

The featured article written by TG Advisers’ President and Principal Consultant points out aspects for consideration when repowering or extending the life of a steam turbine generator. This article is even more timely given the potential changes in policy as owners weigh all the factors associated with fuel conversion and life extension of existing assets.
In addition, this month’s featured Health Assessment service points out the benefits of deferring or continuing with scheduled upcoming maintenance. In conjunction with our extensive knowledge of turbine generators, TGA’s Health Assessment service develops a risk-weighted plan to optimize operations and maintenance through report analysis, OEM experience, and plant personnel interviews. 

The Health Assessment service as well as our Root Cause Failure Analysis (RCFA), design review, and troubleshooting services all can be performed remotely.Contact us for details.

Feature Article

by Stephen R. Reid PE, President

Gas Conversions and Plant Life Extensions: Don’t Forget the Steam Turbine Generator

Gas Conversions and Life Extension Projects

Environmental pressures have caused most US power generation owners to reevaluate both short and long-term options for their generation assets. Retirements, life extensions, repowering, upgrading emission control technologies, and fuel conversions are the main options being considered. Natural gas conversion can provide an economical solution for some units in high-value regions of the US. Generally, these units are in the 250MW or lower range and do not provide the cost justification basis for the installation of the SCR and scrubber technologies typically used on 500+ megawatt units. The due diligence process in establishing the project costs for fuel conversion or life extension must consider the entire plant and not just the boiler conversion hardware.

Click to read the article in its entirety

Feature Service

Steam and Gas Turbine Generator Health Assessment –Unit History, Condition and Risk Assessment, and Outage Planning

TG Advisers, through its own established Turbine Generator Health Assessment Process, conducts interviews with operations and maintenance personnel, reviews available NDE and turbine outage inspection reports including those dating to unit commissioning, and incorporates detailed knowledge of turbine generator design, materials, and critical fleet service issues to develop a risk-weighted action plan and work scopes for the next major outage.

Click to find out more about this service

Summer 2021: TGA Training you virtually won’t want to miss!

Class descriptions with dates and times will post in our next newsletter.

Contact Linda via email atlinda.mionske@tgadvisers.com or give her a call at 302-691-3330 to be added to our class distribution list.

New Suite Address for TG Advisers

Suite 302 at 4550 Linden Hill Road, Wilmington, Delaware

In order to keep pace with the growing need for engineering consulting services we provide to the power plant industry, TG Advisers began efforts in January of last year to procure a larger office space. In the midst of a pandemic, renovations took place while we all worked from home, and in August we began to transition to the office.

Upgraded computer systems for data analysis and new technologies for better virtual meetings were implemented. We believe these additions to our virtual tools will allow for enhanced remote client outage and troubleshooting support. 

As much as we are loving our new space which presently is providing greater ease to social distance, we look forward to hosting clients more regularly when it is safe to do so.

RMEL’s 3-day Leadership Conference

We hosted our first virtual booth during RMEL’s 3-day Leadership Conference in September. We anticipate conferences like these will be the new norm for 2021 and an alternative moving forward to the in-person conferences pre Covid-19. We look forward to this being just one more opportunity for you to learn more about who we are and the services we offer.

President and Principal Engineer

TG Advisers, LLC.

Gas Conversion Projects

Environmental pressures have caused most US power generation owners to reevaluate both short and long term options for their coal generation assets.  Retirements, repowering, upgrading emissions control technologies and conversion from coal to natural gas are the main options that are being considered.  Natural gas conversion can provide an economical solution for some units in high value regions of the US. Generally, these units are in the 250 MW or lower range and do not provide the cost justification basis for installation of SCR and scrubber technologies which are typically installed on 500 megawatt units or greater.  The due diligence process in establishing the project’s costs for fuel conversion must consider the entire plant and not just the boiler conversion hardware.  

With the retirement of many coal units and favorable gas price projections, converted units  are expected to play a more strategic and operationally flexible role requiring more cycling and run hours.  As they will not have the same attractive heat rates of local combined cycle facilities, frequent on-off cycling will be required.  During high demand periods, there will also be an expectation to run for extended periods of time reliably.  Units under consideration for fuel conversion are typically much older coal assets that most likely were “on the bubble” for many years with maintenance planning budgets that supported near term retirement over long term reliability.  

What about the Steam Turbine Generator?

Failure to consider the steam turbine generator in the project budget can make reliability targets a difficult, if not impossible, goal to meet.  TGA has found that the associated steam turbine generator often requires major investments to maintain reliability for life extension of the plant.     The following section provides an overview of the major concerns that must be considered!  

Major Turbine Issues 

Rotor Integrity – After 30 to 40 years of operation, rotor flaws (see figure 1) can develop and/or propagate to a concerning size.  On high temperature rotors, creep voids can be initiated with extended time, temperature and stress exposure.  In addition, rotor materials can become embrittled from temperature exposure will most likely require more frequent inspections, longer startup thermal soak periods or, in some cases, replacement of the rotor itself.  

Figure 1 – Example of a rotor inclusion

Turbine Casing and Valve Body Integrity – Almost all casing and valve body cracks initiate and propagate from stop-starts/low cycle fatigue (LCF).  This cracking (see figure 2 for examples) usually appears later in a unit’s life when on-off cycles reach 300 to 500 events.  With increased cycling, LCF limits will be reached earlier than previous predictions of calendar life.  Repair or replacement options will need to be considered when cracking extends more than 25 to 35% of the casings’ thickness.  

Figure 2 – Turbine Casing and Valve Body Cracking Examples

Turbine Controls – Control systems typically become obsolete in ~20 years of operation.  

Water Induction Protection Systems – Turbine water inductions can cause major internal damage.   Exposure for units that are converted will most likely increase after the fuel conversion. 

Low Pressure Turbine Blading – The later stages of low pressure (LP) turbine blades operate in a low quality steam environment.   Depending on the degree of erosion, replacement may be required.  In addition, LP blades are the largest blades on the unit and, as a result, the most highly stressed.   On-off cycling can significantly consume the low cycle fatigue life of these blades.  

Figure 3 – Examples of LP Blades Water Droplet Erosion and Lasing Lug Cracking

LP Rotor Stress Corrosion Cracking (SCC) –In TGA’s experience, the real question of SCC of LP rotor dovetails is a matter of “When” and not a matter of “If”. In fossil units, TGA has identified this concern as early as 100,000 hours of operation with most units requiring repairs in the 200,000 hour range.  These repairs can be costly and require weld repair and new blading.  

Figure 4 – Example of LP Rotor Dovetail Stress Corrosion Cracking

High Temperature Turbine Rotor Dovetails – This failure mode is, again, an issue of time, temperature and stress exposure.  Dovetail creep or creep fatigue failures as shown in figure 5 become a concern on units with over 250,000 hours of operation.  

Figure 5 – Example of a Control Stage Creep Related Failure

Major Generator Issues

Generator Stator and Rotor Windings – Generator windings are designed to operate reliably for approximately 30 years.  Extending a unit’s life to meet the gas conversion goals of 20 plus years will most likely require a partial or full rewind prior to or during the extended life period.  Figure 5 below highlights a stator end winding connection crack that required a design upgrade to improve long term reliability. Rotor windings, particularly the end turn regions are susceptible to low cycle fatigue, resulting from cyclic start/stops stresses from centrifugal loading and thermal expansion/contraction cycles. Frequently LCF issues affect rotor radial lead pole flexible connections, as well as pole crossover jumpers.

Figure 7 – Stator End Winding Cracking Example

Stator Core Iron – Hot spots in the stator core iron can significantly reduce stator winding life.  Shorted laminations are a common finding on older units and should be monitored and if needed, repaired (see figure 8 below).   In extreme cases, a full core replacement can be required.  If a hot spot is identified near the ends of a core, a partial restack could be the answer.    

Figure 8 – Example of Core Lamination Damage (courtesy of Bill Moore PE)Excitation Systems – Many older units have been converted from rotating excitation systems to a static system.  This change out has addressed many of the reliability issues frequenting rotating elements.  Contingency planning for replacement of an aging excitation and automatic voltage regulator (AVR) systems should be developed.

Bill Robbins

Stephen Reid, PE

TG Advisers, LLC.

Background

The potential failure of generator rotor fan vanes and blower blades has been identified as an area for detailed risk assessment in the electric power generation industry. Liberation of fan component has caused catastrophic damage to both the rotor and stator components on a number of units.  Industry awareness of this high risk issue has improved, which has led to NDE inspections of all critical fan assembly areas.  Many units were previously evaluated by visual inspections only.  A visual inspection in most cases is not capable of finding small cracks in fan assemblies.  

Generator rotor fans/blowers are critical, highly-stressed components justifying design scrutiny, proper material selection, quality fabrication techniques, and judicious non-destructive examination.

Failure Mechanisms

Generator rotor fans/blowers are subject to both high steady and fatigue stresses during operation.  The fan/blower blade itself is highly stressed.  The highest stresses in an axial blower are developed in the base of the blade or in the blade root attachment to the blower hub. The highest stresses in a radial flow fan most often occur in the blade attachment to the side shroud or fan ring. These areas represent the most critical locations for NDE and evaluation for each major outage.  In addition, a recent study conducted by Electric Power Research Institute (EPRI) noted well over 25 case studies of industry failures in these locations.  The report evaluated both fossil and nuclear fan designs. 

As expected, there were significant variations in fan geometry existing between manufacturers.  The locations of the highest stress areas will vary to some degree as a result.   The design process must concentrate on optimizing attachment or fastener geometry.   As the fan blade increases in size an increased dovetail size may be used for better distribution of the resulting centrifugal loads.   Geometry variations can minimize sharp radius corners and other stress concentrations extending the life of a component significantly.  In most cases, small changes in the root contour can make a difference in failure or long term, trouble free operation. 

Other common points of crack development and potential failure are a fan wheels inner bore which is typically shrunk on to the generator rotor.  Similar to retaining rings, these surfaces are subject to larger interference fits which should periodically be inspected.   The failure mechanisms most common to generator fan wheels include:  low cycle fatigue, high cycle fatigue, brittle fracture, corrosion and erosion.

Installation Best Practices

For a large percentage of axial blower designs, bolting hardware works to retain individual blades to blower hubs.  Bolting is normally tightened to a specific torque and is prevented from loosening utilizing either a locking device or a staking procedure.  Failures have occurred due to the loosening of this mounting hardware; therefore to eliminate such failures the following should be adopted during assembly.

• Never reuse locking devices such as lock washers, tab washers and locking strips.
• Prior to an outage, check with the OEM and ensure the correct hardware torque and torqueing technique is being applied. 

Axial blower blades which have a threaded or smooth radial attachment can have an adjustable blade angle.  Flow may be adversely affected if the wrong angle is selected.  This can cause additional blade excitation such as flutter which may ultimately lead to a high cycle fatigue failure.  During assembly, ensure the following practices are followed.

• Verify correct method of angle measurement.
• Verify correct base angle setting and +/- angle tolerance.
• A set screw is normally utilized to lock the blade’s angular position.  If so, the torque and staking recommendations noted previously would apply.

It is common for both axial and radial blower hubs either to be bolted or shrunk fit to the generator rotor forging.  During assembly measure the rotor forging and inner hub diameters to ensure the interference fit is within tolerance.  Also, verify the proper heating method and metal temperature targets are being used.  

Case Study 

The figure below is a photograph of a generator fan that has its blades welded to an inner hub.  The hub is shrunk on to a generator’s rotor shaft end.  The highest stress location for this design is at the weld attachment areas.  After several years in service, one of the fan blades liberated from the hub caused extensive generator damage.  Figure 1 below shows the “as found” hub with the missing blades.  Further NDE of the fan wheel identified additional indications at the weld to hub interface (see Figure 2).  To eliminate the long term concern over this design, a redesigned fan hub and blade assembly was manufactured from a single forging, thus eliminating the blade weld.  

Figure 1 Welded Blade to Hub Fan Assembly

Figure 2 Common Blade to Hub Weld Indications

During a planned major outage, last stage blades were found with cracking in the blade attachment. The blades were of a free-standing design, which means they are not coupled to adjacent blades by means of a shroud, snubber or tie wire. The cracking was clustered in groups and were not present 360 degrees around the row.

Analysis Completed:

TG Advisers scanned the blade with blue light technology to create a solid model. TGA then meshed the solid model to complete a finite element analysis (FEA) of the blade. Using the FEA software, TGA completed a series of calculations including blade natural frequencies and blade root stresses.
The blade natural frequencies on large blades are important to ensure that the blade is well tuned, meaning it will not be excited by a multiple of running speed.
Analysis Findings: The results of the blade frequency calculations showed that the blade was well tuned against multiples of running speed. However, a key finding was that the stresses in the blade attachment, when vibrating at its first natural frequency, was highest at the location of observed cracking.

Free-standing blades are susceptible to aeroelastic vibration, both at high flows (unstalled flutter) and low flows (stall flutter) and certain combinations of LP exhaust pressure. It has been shown that adjacent free-standing blades with approximately the same natural frequencies are most susceptible to unstalled flutter. An industry best practice to reduce exposure to aeroelastic vibration on free-standing blades is to frequency test each blade and mix-tune the blades. This simply means to ensure there is a multiple hertz natural frequency variation between adjacent blades. This can be accomplished passively using manufacturing tolerances or actively by the manufacture of two different part numbers with slightly different geometry to produce the desired frequency variation.

Improvements:

Since the cracking was found during a routine major outage, the design change options were limited to return the unit to service as soon as possible. Ultimately TG Advisers recommended the following:

1. Mixtuning of blades – It was confirmed that the blades were not originally mixed tuned.
2. Material change – This upgrade offered improved strength.
3. Shot peening of blade attachments – This helps resist cracking by introducing a compressive stress layer on the surface.

To date, there has been no issues with the upgraded blades.

Best Practice:

If you have a turbine with large free-standing blades, ensure the blades are mix-tuned when assembling or replacing blades! Periodically audit flow and backpressure conditions to ensure they are compliant with allowables. Complete thorough inspections of the blade root and rotor attachments when possible. In addition to major outages, on many designs inspections of the L-0’s can be completed through the condenser after peak run seasons.

Turbine Generator Health Assessment Background:

TG Advisers began its health assessment program in 1991 and has completed over 350 turbine generator assessments to date.  Our database of units includes steam (nuclear, fossil, biomass) and gas turbine (aerodervative and industrial) units across all major OEM’s, vintages, and outputs ranges (8 MW to 1,500 MW+).  In recent years, the health assessment program has been applied to balance of plant equipment, boilers, ID fans, and cooling towers. 

Assessment Goals:

1. Establish current unit condition – function of design and past/future duty cycle
2. Define turbine generator problem areas and assess each for severity and likelihood of occurrence.
3. Define actions, outage scope, and capital needs to mitigate key asset risks
4. Allow for integration directly into plant workflow systems
5. Provide financial return with improved availability and optimizing outage and maintenance intervals and scopes.    

Establishing Unit Condition: 

TGA leverages decades of OEM, utility, and consulting experience in conjunction with plant operations and maintenance interviews, outage report reviews, and operational data assessments to establish unit condition.  

Unit Specific Problem Areas:

TGA divides a given turbine generator unit into on average 50 “Problem Areas”.  Problem areas are failure modes and chronic conditions judged to be of concern. For a steam turbine, problem areas are segmented by turbine elements, valves, generator, and system.  The advantage of breaking the unit into “problem areas” is that all background/history and actions for a given issue that could impact the availability of the unit is contained in a single location.  

Each of the approximately 50 problem areas will be evaluated for unit specific history and trends, inspection findings, part replacement history, effectiveness of past repairs, and TGA’s experience on like units.  In the next step of the assessment, the respective problem areas for a given unit are assigned weight risk rating. 

Problem Area Risk Analysis

When considering risk, TGA considers both the likelihood of occurrence as well as the duration of a forced outage and/or outage extension if the respective issue is encountered.  Multiplying the risk (severity) by the probability of occurrences yields a weighted “Availability Factor.”

The resulting availability factors range from 0 to 12.  As part of the health assessment, a color map is provided of all unit “Availability Factors” to drive priority of spend and scope.   

Figure 1: Availability Factor Range

Figure 2: Snapshot of Availability Factor Roll Up

Outage Interval Evaluation, Outage Scope, and Troubleshooting:

Based on the availability factor roll up, past/current duty cycle and mode of operation TGA will provide recommended outage intervals and scopes.  In addition, TGA will provide troubleshooting recommendations and key contingencies for unit specific issues as part of the assessment. 

Financial Return: 

Value is derived in multiple ways from a TG Advisers health assessment.  A example list is provided below:

• Bridges knowledge gaps due to staff retirements, turnover
• Increased availability and reduced forced outage costs
• Identifies major risk areas
• Enables contingency planning for emergent issues
• Mitigates short term repeat outages
• Allows for a T-18 Planning Process
  • Critical spare parts identified and procured
  • Allows time to develop comprehensive repair scopes and competitive pricing options
  • Mitigates expediting costs
• Targeted outage scopes – often opportunities for reduced outage scope and/or extensions beyond standard OEM outage recommendations. 
• Facilitates long and short term capital and O&M planning
• Fosters timely post outage updates
  • Captures lessons learned, best practice integration
  • Optimize outage intervals 
  • Ongoing monitoring recommendations
• Integration of best practices and lessons learned from other sites with like units.