KGI Coordinates Combined Cycle Plants Conference in Saudi Arabia

A conference was held on April 3, 2019, in Dhahran, Saudi Arabia to focus on issues associated with older installed combined cycle power plants. Adel Al-Shuraim, CEO Tamimi Energy, sponsored this conference.  This one-day conference was attended by over 80 customer personnel, and 6 vendors, and consisted of the following presentations:

1)    Introductions by Adel Al-Shuraim

2)    Combined Cycle Plant efficiency improvement studies—Joel Holt and Bruce Martindale, CoreTech

3)    Combined Cycle Plant Quicker start up cycle times-- Joel Holt and Bruce Martindale, CoreTech

4)    Gas Turbine Non-Capital Parts uprates—Bob Johnston, KGI

5)    HRSG improvements—Habib Grini and Raphael Stevens of CMI

6)    Steam Turbine upgrades—Dave Hagenbuch, MD&A

7)    Training programs for Gas Turbine, Steam Turbine and Generator—Dave Hagenbuch, MD&A

8)    Exhaust system upgrades/repairs, including dampers—Moustafa Al-Shami, Braden.

 This conference was attended by owners and operators of all the combined cycle power plants in Saudi Arabia—15 combined cycle plants in total.

 The focus of each presentation was to address specific issues that each vendor had experience with for other combined cycle power plants, and to show how this experience can also be applied to the combined cycle plants in Saudi Arabia.  The overall theme is that the collection of vendors at the conference had agreed to work together to provide complete solutions for the customers who have combined cycle power plants.

 The combined cycle power plants in Saudi Arabia have the same issues as combined cycle plants in other areas.  The OEM’s (and third parties)for the major plant components are willing to help with issues associated with their own equipment, but no one comes prepared to provide integrated solutions for the entire combined cycle plant.

 Some of the programs presented included;

• Quick start up—90 minutes—for a warm re-start of a CC Power Plant.  The significant penetration of renewables into the power generation market has resulted in many CC power plants having cycling duty, which includes quick start up when the renewal energy source is suddenly not available. Most new unit CC plants for the past few years have this requirement as part of the new unit installation. But, for CC plants over 5 years old, frequently warm starts take over 4 hours. By providing applicable procedures, software, and instructions, a 90-minute warm start is possible for all older CC plants

• Efficiency improvements—all older CC plants have suffered reductions in CC efficiency—many of which can be addressed. To fully assess areas that can be addressed to improve efficiency, a full new heat balance needs to be done, and compared with the original heat balance to show the main areas that need to be addressed. 

•  Gas turbine uprates---focused uprates within the capability of the existing equipment can be easily implemented.  Most older gas turbines get upgraded parts when they purchase spare parts, as all OEM’s continually improve the capability of the parts.  But, the OEM’s usually do not assess the overall capability of the gas turbine, when only selling spare parts. Frequently a thorough review will result in an additional 3% power from the gas turbine, as well as an increase in exhaust energy. Thus, the total CC plant will get additional power, and improved efficiency.

•  Audits of all operating procedures for combined cycle plants—frequently significant improvements in operations have been developed with more recent CC power plants. But, the overall integration contractor who originally installed the plant, does not continue to provide assistance to the CC plant customer personnel.

•  Repairs and/or replacement of key exhaust system components: ducting, dampers, etc.

•  Upgrades for the steam turbines.

•  Training programs for Gas Turbines, Steam Turbines, and Generators

•  HRSG improvements – Over the years, the HRSG can loose on efficiency. Main reasons are typically related to flue gas by-pass around the heat exchangers, closing and baffling plates removed, fouling of the external heating surfaces due to deposits of soot and sulfur, and internal fouling due to improper water quality. Another aspects closely monitored is the good operation of the diverter damper and sealing tightness in Combined cycle operation.

For any CC plant customer to fully evaluate the impact of implanting any improvements to his CC plant, he needs a good economic analysis of the benefits. As most CC customers do not have the ability to do their own heat balances, or to assess the overall impact of making any specific change to any of the combined cycle equipment,   it is difficult to get their management approval of any significant improvements. Thus, the CC plant efficiency continues to decline. The operator is not always immediately aware of the loss of efficiency, apart from the power output reduction. OEM’s have recommended some key parameters to be followed up, such as the flue gas temperature at the outlet stack, GT gas pressure increase, etc.  The collection of vendors at this conference have formed an alliance to work together to provide a complete market basket of solutions, within the capability of the existing plant equipment, along with associated heat balances to show the benefit to CC customers.

Bob Johnston, President, Keck Group International coordinated this conference.

Please contact any of the following for any follow up discussions, or questions:

---Bob Johnston, President, KGI, 404-513-9318,   bobjohnston99@comcast.net

---Joel Holt, Manager, Combined Cycle Engineering, 518-322-2970,   jholt@cticus.com

---Haitham Al-Akkawi, manager, Tamimi Power. +966 56 001 1666, hakkawi@al-tamimi.com

Heavy Duty Hot Gas Path Parts Supersedures/Interchangeability

Heavy Duty gas turbines usually have a long life—frequently much longer than the OEM advertises. All gas turbines require periodic maintenance that frequently involves gas path parts repair and/or replacement. Replacement parts are always available from the OEM, and also in many cases from third parties who reverse engineer the OEM parts. Over time, all OEM’s introduce design improvements for better parts life, higher output and efficiency, or longer maintenance intervals.  These improvements usually involve improved materials, coatings, and/or cooling schemes. Frequently these improved gas path parts are actually interchangeable in complete sets with the older gas path parts of the same frame size.  Unfortunately, it is hard for owners (or third parties) to understand the interchangeability, as they do not have the design records for both the original parts and the latest design parts. This is especially confusing for owners who have multiple sets of gas turbines of the same frame size, but, purchased at different time periods.

As an example, there have been over 80 different drawing numbers for a GE MS6001B since it was first introduced in the late 1970’s. In this example all later vintage designs can be retrofitted in any earlier vintage MS6001B gas turbine, as they are all interchangeable in form/fit/function, even though there have been numerous design improvements. But, in many cases, it is not “ok” to put the earlier vintage designs in later vintage production units, due to firing temperature changes over time.  In some cases, it is even “ok” to mix-n- match buckets with different drawing numbers in a unit to make up a spare bucket set. Great care must be taken if mixing-n-matching gas path parts to make sure all parts are identical in materials and cooling schemes.

In most cases for the GE MS5001N thru R, MS6001A & B, MS7001 A thru EA, and MS9001B thru E models, later design hot gas path parts can be used interchangeably on older vintage units in complete sets. The GE design approach has usually been to introduce changes in small increments, such that the new gas path parts had to be interchangeable with all the other older design gas path parts. Thus, interchangeability had to be built in by design.  This is a significant benefit to both customer and OEM. The OEM can produce only the latest vintage gas path parts for use in both new unit production, as well as for all spare parts applications. The owner can use this to his advantage to minimize spare parts stocking since one set can cover many units in his fleet. the GE fleet is quite large—over 2000 MS5001N thru R, over 1000 MS6001 A & B, over 1000 MS7001 A thru EA, and over 500 MS9001B thru E units in the fleet.

Similar to the discussion on the “E” class fleet above, most current vintage Hot Gas Path parts for the “F” class units can be used in complete sets in earlier vintage units. This applies for the MA6001F, MS7001F, and MS9001F class gas turbines.  There are only a few cases where in the latest vintage HGP parts cannot be put directly in the older vintage units. Note this only applies thru the 0.3 versions for these models.

Other OEM’s (Siemens, ABB, MHI, Ansaldo, Westinghouse, etc.) frequently had significant gas path changes every time they introduced a newer model. Thus, in most instances, customers with these OEM’s turbines usually have difficulty trying to upgrade the gas path parts on their older vintage units.

Keeping track of all the gas path parts for multiple frame sizes and models is a daunting task for most operators. The OEM will frequently provide a “supersedures” notice when supplying spare parts. That is, if the customer orders a set of gas path parts for an older vintage turbine, the OEM may supply a later vintage design, along with a notice that the new part supersedes the older vintage part. But, this is only one set of drawing numbers—not a complete interchangeability list of all drawings for that part that have been produced. So, the customer must take the OEM supersedures notice on faith.  For customers who need more help managing their gas path spare parts for their fleet of gas turbines, the Keck Group International (ww.keckgroupint.com) can help in many ways:

• Review all gas path spares in customer’s inventory for supersedures/interchangeability.
• Review maintenance intervals and parts life for any parts in the customer’s inventory.
• Review all gas path parts in any given gas turbine, to see if there are sufficient improved parts to qualify for an uprate.
• Review any third party gas path parts to see if they are suitable for the given application.

Contact information for the Keck Group International (KGI) can be found on our web site or through the link below.

Gas Turbine Performance Degradation

As a gas turbine accumulates fired hours, some performance degradation will occur in both output and efficiency. Non-recoverable performance degradation is defined as performance that cannot be recovered without significant maintenance (Hot Gas Path inspection or Major Inspection). Recoverable performance degradation is defined as that which can be recovered without significant maintenance (on-line compressor water wash, off-line compressor water wash, rice cleaning the compressor, etc.). Typical non-recoverable performance degradation is approximately 5% for output, and 2.5% for efficiency at approximately 20,000 fired hours. Of course, this varies somewhat for different site conditions, different operating conditions, and different fuels, but these are good averages for non-recoverable performance degradation for most operators.  Approximately 2/3rd’s of this performance degradation is due to compressor issues, and 1/3rd is due to hot gas path issues.  About half of this non-recoverable performance loss can be recovered during a Major inspection by proper maintenance and repair processes. This article will discuss compressor and turbine section performance degradation in separate sections.

Compressor Performance Degradation

Compressor performance degradation has many different causes:

• Dirt/Oil Fouling the Compressor Blades.  Dirt from the inlet air due to inadequate air filtration will collect on various parts of the compressor resulting in rougher surface finish, and more power being required to pump the air thru the compressor, and less air flow. This gets compounded by frequent oil leaks from the #1 bearing, resulting in a sticky film that retains more dirt. This performance loss is referred to as recoverable performance loss, as it can be regained by frequent off-line and on-line water washes. On-line wash would typically be done with cold water (potable water) and at a flow rate of 7 to 10 GPM thru small spray nozzles mounted in the inlet casings. This would be done during normal operation, at any load.   Off-line wash would be done with the unit on crank mode (approximately 20% speed), with hot water (potable water would be ok, but, some operators use boiler condensate water) some operators also use a soap compound mixed with the water, especially if oil deposits are present. Care should be taken to make sure the recoverable compressor performance degradation does not exceed 5% so as to avoid compressor issues.
• Compressor Blade and Casing Surface Finish Degradation.  Frequently local environment air will include different types of chemicals that may cause corrosion on the compressor blade surfaces. Such corrosion will result in non-recoverable performance degradation that can only be recovered during a major overhaul (new blades, and/or polishing each blade). Typical atmospheric corrosion causes include ocean salt air, chemical plants, fertilizer, etc. Most of this can be controlled with proper inlet filtration. 
• Wear on the Labyrinth Seals at the back end of the compressor (this seal is intended to provide a measured air flow from the compressor discharge, to the forward wheel space area for cooling).  This is harder for most operators to fully understand.  Average new unit clearances for the High Pressure Packing (HPP) labyrinth seal is approximately 40 mils, but, average clearance when units are opened up for the first Major Inspection (MI) is about 100 mils.  The performance derivative for HPP clearance is 20 mils increase in clearance will be a loss in output of 1% (or 3% for the increase from 40 mils, to 100 mils).  This performance loss would be classed as non-recoverable performance degradation as it cannot be corrected without a Major Inspection overhaul. This increase in HPP clearance can be due to many factors including rotor alignment or significant vibration. But, the major source of high HPP clearances is the over speed testing that is frequently done during commissioning to calibrate the over speed instrumentation. The sudden trip when the unit reaches the over speed limit will frequently result in significant rotor vibration (and consequently rubs on the HPP seal). All of the above can be addressed during commissioning and operation with much care by the operators, but, otherwise, significant non-recoverable performance degradation will result

Compressor Blade Coatings.  Smooth compressor blade coatings are offered by some OEM’s and also by third parties.  Such coatings are good, for a short time, but, will also suffer from the same types of compressor blade fowling and corrosion as the coatings get removed by erosion, due to dirt in the inlet air.  So, if the operator needs short term performance recovery after an outage, such coatings may be of use. But, if the customer needs a permanent performance improvement, the cost of the coating may not be a good investment.

Compressor Clearances.  All gas turbines some with a set of recommended clearances for all blades and seals. All these clearances should be carefully measured when the turbine is opened for maintenance, and again, just before closing the turbine after the maintenance. All clearances should be carefully recorded in the maintenance reports. The frequent answer that “we took all the clearances and did not record then, because they were all within spec.” usually means that no one actually took the clearances, and/or that many were out of spec. After the unit is closed up, and operating, it is too late to correct any issues related to out-of-spec clearances.  Typical performance loss when all compressor stages have a 20 mil increase in clearance is 1% in output, and efficiency.

Foreign Object Damage.  Foreign object damage is when solid objects (nuts, bolts, parts of silencers or inlet filters, etc.) enter thee compressor during operation. As these objects bounce around going thru the compressor, they can cause considerable damage to airfoil shape, and in some cases cause liberation of compressor blades. Actual damage and impact on performance are dependent on the extent of damage. A significant outage would be required to correct the damage.

Compressor Bleed Valve leakage.  Most gas turbines designed since the early 1990’s have bleed valves to bypass some compressor air during unit start up. This is to minimize possibility of compressor issues such as surge, stall, and stress during start up. On older units, sometimes these valves stick in the open position, and continue to allow air to bleed off during operation. This should be easy to check, as the air going thru these valves usually creates a significant noise. If the sticking valves cannot be corrected by impact, the unit may need to be shut down to fix the valves. 

Hot Section Clearance Performance Degradation

All hot section performance degradation would be classed as non-recoverable performance degradation.  Different types of hot section performance degradation would include the following:

• Air Foil Surface Degradation. Similar to the compressor blades, the blade surface finish is critical to optimum performance. Typical reasons for degradation in turbine blade surface finish are ash deposits from using heavy fuels, corrosion from contaminants in heavy fuels, and liquids in gas fuels. Significant surface finish roughness can result in up to 2% loss in output. Repair, replacement, or polishing of hot section airfoils should be considered during each HGP or M inspection to recover lost performance, as well as to maintain mechanical capability
• Turbine Bucket Tip Clearance. Turbine bucket tip clearance is the easiest to measure when taking opening clearance checks. Typical bucket tip clearances are large—up to 80 mils in many cases—so as to avoid rubs during operation.  Thus, by design, a lot of air flows over the tips of the buckets—a necessary performance loss, as bucket tip rubs sometimes result in significant damage to the unit. But, any rubs over the OEM’s recommendation, will lose significant additional performance. Increase in stage one bucket tip clearance can result in output loss up to 1% and efficiency loss of 0.5%. Typical reasons for bucket tip rubs are rotor alignment and high vibration events. 
• Labyrinth Seal Wear.  Labyrinth seals are used in several locations in the hot turbine section: stage 2 nozzle inner diaphragm, #2 bearing, and the bucket tip clearance for stage 2 & 3 buckets.  These seals can be damaged during high vibration events, or due to rotor alignment issues. Performance loss can be up to 0.5% for 40 mils rub on the stage 2 nozzle diaphragm or on the stage 2 & 3 bucket tips. These seals can only be repaired during a HGP of MI maintenance activity. 
• Stage One Nozzle Throat Area Increases.  Stage one nozzle area is critical to performance as any change will not only hurt performance due to surface finish issues, but, it will also impact compressor discharge pressure for a given air flow.  The relationship between compressor discharge pressure and exhaust temperature is typically how the control curves are set up. So, any change in stage 1 nozzle throat area will result in performance loss. 
• Bearing Seal Wear. Bearing seal wear will result in additional air flow leaking into the oil drain lines and thus, less air going thru the turbine to generate useful work. 
• Foreign Objet Damage (FOD).  Similar to FOD n the compressor, FOD in the hot gas path section will result in performance loss.  FOD in the hot section can be from pieces of combustion hardware upstream that was liberated due to a failure. So FOD of stage 2 and 3 HGP parts can be from failed parts of stage 1 HGP components.  Any FOD in the HGP section usually results in unit shut down, and significant repair.

Summary

Many of the above performance degradation issues can be controlled by the operators with care during operation. But, many others can only be addressed during Hot Gas Path of Major inspections, with proper repair processes.  There are also numerous advance tech sealing improvements available (brush seals, cloth seals, honeycomb seals, abradable coatings, etc. that can have a significant impact on reducing performance loses due to rubs.  The Keck Group International is available to help any customers evaluate their performance degradation, evaluate condition of all turbine parts during maintenance activities, to provide training to operating personnel on best operating practices to minimize performance loss, and/or to help with repair practices aimed to minimize performance loss.  For contact information:

Gas Turbine Liquid Fuel Operational Issues

There are several types of liquid fuels in use in gas turbines ranging from good quality #2 distillate, heavy fuels like crude or residual oil, and light end naphtha or benzene.  Also frequently gas turbines are set up with the capability to burn 2 or 3 different types of fuel, depending on the operator’s needs.  This article will try to address issues associated with the different types of fuel and different types of operational capabilities.

Liquid Fuel delivery

Good quality liquid fuel is an excellent fuel to use in gas turbines, as long as it is clean and properly stored.  Frequently a significant amount of dirt is in the fuel due to delivery methods, and/or due to extended fuel tank storage.  There have been many instances of dirt getting into the liquid fuel when the tanker or barge is not properly cleaned of contamination (dirt, sea water, etc.) before loading the next delivery of distillate fuel, thus, introducing contamination.  The gas turbine operations team should make sure they review the entire delivery scheme with the fuel supply vendor and also do an analysis of each fuel delivery, to ensure quality of the distillate fuel.

Liquid Fuel Storage

Fuel storage at site is always an issue for liquid fuels.  Dual fuel units that run infrequently on liquid fuel end up having the liquid fuel on site for extended intervals.  Thus, there is a significant probability that dirt/mold, and water will get introduced into the fuel. Fuel tanks generally “breathe” during the day due to changes in ambient temperature; thus, air with higher humidity can get introduced on a daily basis. Cooler temperatures at night may result in condensation of some of the humidity during the night. Thus, it is common to find several feet of water in the bottom of the liquid fuel tanks. It is recommended that customers periodically drain the water from the bottom of the liquid fuel tanks. Also, the air that “breathes” into the fuel tanks can contain dirt that also can collect in the tank.  Hopefully some of this dirt will leave with the water when it is drained. But, it is also good to schedule periodic cleaning of liquid fuel tanks to make sure a significant amount of dirt does not accumulate.  Fuel filters on the gas turbine are a good protection from dirt getting into the turbine during operation.  But, if/when the liquid fuel filters get dirty too quickly, it is an indication that the operator needs to take action on cleaning up the fuel tanks.  Dirty fuel filters tend to pass a certain amount of dirt when they get clogged up, thus, possibly negatively impacting gas turbine reliability.

Fuel Filtration

Fuel filters should always be supplied in a duplex configuration, such that the unit can run continuously when the filter needs to be changed, by switching to the back-up filter (on-line transfer valve).

Units that use heavy fuels usually have a significant additional amount of dirt, even when they have a fuel centrifuge. It is recommended that a duplex self-cleaning liquid fuel filter be installed just up-stream of the low-pressure fuel filter.

Liquid fuel impact on gas turbine maintenance cycles

Typically gas turbine recommended maintenance cycles are about 2/3’s of the maintenance cycle on gas fuel.  Natural gas has a 4:1 ratio of Hydrogen to Carbon (CH4). Distillate and heavy liquid fuels normally have Hydrogen to carbon ratio of 1:1 (CH).  Thus, liquid fuels have a higher % of Carbon fuel. Carbon burns at a higher temperature than Hydrogen.  Thus, the actual flame temperature (not the designated firing temperature, but, the actual flame temperature in the combustion zone) when burning liquid fuels is higher than the flame temperature.  Thus, the radiated temperature from the flame makes the combustion liners run hotter on liquid fuels, thus, reducing the recommended maintenance intervals for Combustion Inspections (CI). Similarly, the contaminants in all liquid fuels may impact the inspection intervals for the remaining hot gas path parts. 

Fuel filter pressure drops should be monitored frequently to make sure the pressure drop is not excessive (10 psig would be the highest recommended, but, the customer should consider changing the filters when the pressure drop exceeds 5 psig). 

Fuel pumps and flow dividers are continuous maintenance issues with continuous operation on liquid fuel—especially when using heavy fuels.  These accessories are high speed, close clearance devices that do not like dirt, water or any other types of contamination.  Due to their configuration and operation, it would be extremely difficult to make these devices redundant, such that you could switch to the back-up when one fails. Thus, you are basically stuck with a single source of failure on devices that fail relatively frequently.  Best recommendation would be to change out these items during each CI, but, economics frequently dictate to keep running the same devices if they have not failed. Vendors for these items frequently offer more expensive replacements as spare parts—buying the more rugged version as a replacement is one of the best decisions you can make as an operator.  

Heavy liquid fuels such as crude oil, or residual fuel

All heavy fuels require a lot of special handling, treating, heating, filtration, and additives to ensure highly reliability. 

All distillate fuels should be supplied at no more than 10 cks viscosity, to ensure proper combustion.  This applies at all on-site ambient temperatures. Frequently this will require fuel heaters to increase fuel temperature by 10F to 20F, to reduce viscosity to 10 cks. All heavier fuels (crude/residual) have a much higher viscosity than #2 distillate, and thus, significantly more fuel heating is required.  To minimize the amount of fuel heating for heavier liquid fuels, it is normal to supply a “high Pressure atomizing Air” compressor to better atomize the heavier fuels. With the HPAA system, it only necessary to heat the heavy liquid fuels down to 20 cks viscosity, thus, less fuel heating.  Heavy liquid fuel heating is also dependent on the amount and type of wax that is present in the liquid fuel. If the wax is not heated above the melting point, the wax may clog up the fuel filters quickly. Thus, it is recommended the heavy liquid fuels be heated to achieve the recommended minimum viscosity, and to ensure that the wax in in liquid form.

Sodium and Potassium are frequently present in all heavy fuels. These metallic contaminants will result in considerable corrosion of all the gas turbine hot gas path components, if allowed to get into the gas turbine. Thus, they must be removed to a concentration below 1 ppm. Most of the Sodium and potassium are dissolved in the water that is always present in these fuels. The most common approach to removing these metallic contaminants is to use a centrifuge.  This will also remove most of the dirt that is also present in these heavy liquid fuels. Depending on the amount of these metallic contaminants in the heavy fuel as supplied, it may be necessary to use a 2-stage centrifuge system, as a centrifuge will usually reduce the Sodium/Potassium by a 10:1 ratio.  The centrifuge should be installed up-stream of the low-pressure fuel filters.

All heavy liquid fuels usually have a significant amount of Vanadium. It is difficult to remove the Vanadium by any economical means on the large scale necessary for a gas turbine. The common approach is to introduce a Magnesium additive to the liquid fuel. The Magnesium will react with the Vanadium very quickly in the combustion system to lock it up in a compound that quickly turns to ash before it can react with the hot gas path components. If un-checked, the Vanadium will quickly result in considerable hot corrosion of the gas path components.  The resulting ash from inhibiting with Magnesium, will stick to all combustion and hot gas path components, resulting in reducing output.  Thus, when operating on heavy fuels with significant Vanadium content, it is recommended that a shut-down turbine wash be performed when the output has been reduced by a maximum of 5%. 

Crude fuel usually has a low vapor pressure/flash point.  A good rule of thumb is that if the flash point is below 140F (60C), then, the areas that have liquid fuel should be classified as Class 1, Group D, Division 2. This means that all arcing and sparking devices should be designed according to this area classification. This would apply to the turbine compartment, accessory compartment, heavy fuel forwarding skids, heavy fuel filtration skids, transfer valve skid, and any other areas that process the heavy fuel both up-stream and down-stream of these devices. The low flash point fuel is not a concern as long as there are no fuel leaks. But, due to the large number of connections, joints, and seals associated with all the liquid fuel system components, it is frequent that fuel leaks will occur.  Thus, design practice necessitates that liquid fuel leaks will be present many times during the life of the gas turbine.

Any heavy liquid fuel should be removed from the gas turbine when not in operation.  The easiest way to do this is to start-up and shut-down on distillate fuel—thus requiring additional fuel filtration and forwarding equipment for the distillate fuel. If the heavy fuel is allowed to remain in the gas turbine, it will eventually cool down, allowing the wax to solidify, increasing the viscosity, and eventually cause more carbon residue to build up in the liquid fuel system components.  Thus, it is always recommended to start-up and shut-down on distillate fuel when heavy fuel is used for operation.

Light Liquid Fuels

Use of light liquid fuels is not common in gas turbines, but there have been several cases where this is desirable due to availability and cost of these fuels. Light fuels that have been used in gas turbines include Naphtha and Benzene. The most common issue with these fuels is low viscosity. The lube oil pump and flow divider require a minimum viscosity of no less than 2 to 3 cks.  As these liquid fuels typically have significantly less viscosity, a “viscosity additive” is recommended to avoid excessive and quick wear on the fuel pump and flow divider.

It is also recommended that units that use these low viscosity liquid fuels start-up and shut-down on distillate fuel to make sure the lighter fuels are removed from the gas turbine when it is not in operation due to the low flash point associated with these liquid fuels.

Dual Fuel (gas/distillate) units

Most units that have dual fuel capability use gas fuel most of the time, due to high reliability, and minimal maintenance. They have the distillate fuel available for back-up/emergency use.  But, the infrequent use of the liquid fuel usually results in significant amounts of coke build-up in the liquid fuel system components located in the turbine compartment over time. Coke is the result of a liquid hydrocarbon fuel, high temperature, and oxygen all of which will be in the liquid fuel system when it is not used often. Most OEM’s do not supply robust liquid fuel purge systems to remove the liquid fuel from the turbine compartment when the liquid fuel is not in operation. Thus, each cycle to use the liquid fuel will result in additional coke build-up in check valves, fuel lines, fuel nozzles, etc. eventually resulting in keeping these devices from operating as desired.  A customer survey indicated that successful fuel transfer from gas to liquid fuel has about a 50% chance of success on traditional dual fuel systems on older operating units. A more robust purge system can be supplied using an inert gas to purge the liquid fuel from the turbine base fuel lines when the liquid fuel system is not being used. This also requires some changes to the turbine base fuel lines. This type system has been proven to be quite reliable with a successful fuel transfer rate in excess of 90%. 

The Keck Group International (KGI) has many engineers on staff that can help customers with any liquid fuel issues as detailed above. Please contact us thru our WEB site www.keckgroupint.com to see how we can help.

Compressor and Turbine Water Wash

Compressor Washing Systems

To achieve the best output and efficiency for your installed gas turbine, it is necessary to do a periodic compressor wash, to remove dirt and oil that will probably have collected. Even in relatively clean environments, dirt and oil can collect on the compressor blades. (For the non-believers, I’d suggest a test they can do easily at home. remove the vent cove from your home heating duct and rub your hand along the inner surface of the duct. You will quickly become a believer in compressor water wash).  Most gas turbines installed since the mid-1980’s have a compressor water wash manifold installed on the compressor casings, and an associated water wash skid. 

Off Line Water Wash

Most units have both an on-line water wash manifold and an off-line water wash manifold. The off-line water wash system is the most effective in removing dirt and oil from the compressor blades. This involves shutting down the gas turbine, and putting it on crank cycle (roughly 20% speed).  Then, injecting water (50 to 90 GPM) thru nozzles installed in the inlet bell mouth.  Typically the water wash cycle will last 20 to 30 minutes, but, to make sure the compressor is clean, you should monitor the water discharge, and let the system run until the discharge is clear. Water wash skids typically have a heater; to heat the water before the water wash cycle begins.  Water used for off-line water wash should be “potable” (ok to drink)—no need for boiler condensate or treated water.  The water temperature should be such that the temperature differential between the water and the compressor wheel space area is less than 200F. Typical time interval to cool down the compressor wheel space is 12 to 18 hours. For customers who need to minimize the time interval for a water wash cycle, can force cool down the gas turbine by putting the unit on crank cycle during the unit cool down to speed up the cool down process.  Normally the hot wash water is sufficient to remove the dirt, but many operators also add a detergent to the wash water. 

On Line Water Wash

Customers, who need to run continuously for long periods, also use an on-line water wash system. This system uses a separate manifold and nozzle system to inject water into the compressor.  This is done while the unit is at normal load. Typical water flows are between 6 and 10 GPM depending on size of the gas turbine. Typically this water is not heated. Also boiler condensate or treated water should be used so as to avoid injecting any metallic contaminants that may be present in potable water. The on-line water wash process is not as effective as the off-line process, but it usually does remove most of the dirt from the first 6 stages of the compressor. This is the most important part of the compressor to keep clean, to recover airflow, output, and efficiency.  Unfortunately, most of the dirt removed will then collect on the later stages of the compressor, thus, the need for periodic off-line water washes. Many customers schedule their on-line water washes coincident with the hottest part of the day, as the evaporation of the on-line wash water will cool the inlet somewhat, and give a little more power during the on-line water wash cycle. Use of the on-line water wash system can significantly reduce the need to shut down the unit for off-line water washes, by recovering most of the performance loss due to compressor fouling.

 It is important to mention that the customer should never let the gas turbine output decline more than 5% due to a dirty compressor, before an off-line water wash. 

Figure 1 - shows actual degradation over tine, including average degradation. Compressor fouling and online water washes are seen as the small “saw tooth’s” on the curve. Off line water washes show greater performance recovery. The large step changes are a result of compressor “hand scouring” during major maintenance outages. Over the life of the turbine there is some non-recoverable degradation due to casing roundness, blade finishes, seals, and other mechanisms.

Turbine Water wash

Units that use Crude fuel, Residual fuel, or any other type of heavier liquid fuel, usually have a turbine water wash system installed. The ash deposits (that result from adding an inhibitor for liquid fuels that have a significant Vanadium content) that get deposited on combustion hardware, buckets and nozzles will have a negative impact on gas turbine output and efficiency. The turbine water wash system is designed to remove most of the ash deposits. Typical water flow rates vary between 50 GPM and 90 GPM depending on gas turbine size.  The wash water should be heated to about 200F, to maximize the wash effectiveness.  Similar to the compressor wash process the turbine wheel space should be cooled down such that the temperature differential between the wash water and the wheel space is less than 200F. The wash cycle should continue until the drain water is clear. Immediately after the turbine wash cycle is completed, the unit should be fired to at least “full speed no load”.  The ash deposits are usually porous, and if any ash deposits remain after the turbine wash, firing the unit will cause any residual retained water to flash, thus, removing additional ash deposits.

Any customers needing additional help with their compressor or turbine wash systems can contact the Keck Group International—keckgroupint.com for additional help.

ASME Papers on Successful Gas Turbine Uprate Programs

Attached is a listing of ASME papers co-authored by customers and ex-GE retired engineers, who are now associated with the Keck Group International.  Over the past 30 years, there have been dozens of very large successful Conversions, Modifications and Uprates (CM&U) projects. Many of these projects have been documented in technical papers that were presented at ASME IGTI conferences.  Each of these ASME papers goes into significant detail on each of the following points:

• Customers decision process on pursuing the uprate
• Detailed listing of all the changes made to the gas turbines, and in some cases, also the load equipment.  This also includes a full breakdown of all performance related changes.
• A full review of all associated accessories and equipment
• Review of the performance test results
• Scheduling challenges associated with the uprate program

A listing of these papers is as follows, the ASME reference number is a link to the actual paper.

86-GT-40   New Technology Uprating of Process Compressors and Generator Drive Gas Turbine s (MS5001LA)  

87-GT-24   Performance and Reliability Improvements for Heavy Duty Gas Turbines

87-GT-123   Availability and Performance Improvements for a GE STAG 307E Combined-Cycle Power Plant

88-GT-143   The Modernization of a 1965 Gas Turbine: New Life for an Old Unit (MS5001K)

89-GT-8   Life Extension and Performance Enhancement of an Industrial Gas Turbine Through Upgrading (MS3002F)

90-GT-284 Modification of a MS7001B Gas Turbine for Increased Reliability by Using 7001E Parts

90-GT-350 MS3002 Advanced Technology Uprate Application and Operating Experience (MS3002)

91-GT-48 Field Performance Testing of an Uprated Gas Reinjection Compressor Turbine Train (MS5001R)

91-GT-49 Turbine-Compressor Train Uprated for 30% Increase in Gas Flow (MS5001R)

91-GT-318 Conversion of Two MS5001 Gas Turbines to Meet Emission Requirements in the Netherlands

92-GT-335 MS5002B Gas Turbine Advanced Technology Uprate for LNG Application

96-GT-13 MS7001E Gas Turbine Advanced Technology Uprate

97-GT-450 Results of the GT Prime Program Improvement at the T.H. Wharton HL&P Site

98-GT-359 Combustion Aspects of Application of Hydrogen and Natural Gas Mixtures to MS9001E DLN Gas Turbines at the ELSTA Plant in Terneuzen The Netherlands

Heavy Duty Gas Turbine Life Extension Evaluation

Life Extension Evaluations - Most of the heavy Duty gas turbines installed since they were first installed in 1950, are still in operation today. The earliest models had a design life of 100,000 fired hours. Starting in the mid 1950’s the design life increased to 200,000 to 240,000 fired hours.  Assuming the 240,000 hour design life (approximately 30 years when operating at base load), the earliest turbines are now over twice their design life, and still going strong.  This article will address all GE design gas turbines up thru the “E” class design (MS3000, MS5000, MS6000, MS7000, & MS9000).  At present, there are a large number of gas turbines in all frame sizes that currently exceed the 240,000 hour design life.  It is recommended that all turbines have a life cycle review between 200,000 and 240,000 fired hours, so as to endure continued successful operation.  A life cycle evaluation would address the following areas:

•    Compressor and Turbine casings. Compressor casings are all very rugged and are generally designed to last indefinitely.  The biggest issue for all casings is cracks along the vertical and/or horizontal flanges. Cracks can be the result of repeated thermal expansion/contraction, but are most commonly due to repeated maintenance cycles and over-torqueing the casing bolts. Smaller cracks that do not grow over time are not usually an issue. But, any crack that grows over time with repeated maintenance cycles should be addressed. All casing cracks should be well documented during each maintenance outage with measurements and pictures. A life evaluation study would evaluate the actual casings during an outage, and a thorough review of the maintenance reports.

•    Turbine Rotor. All turbine rotors are subject to very high temperatures during operation. They are also subjected to considerable strain during start-up (fast warm up under considerable centrifugal stress), and during shut-down (fast cool down).  A thorough turbine rotor inspection is recommended during each HGP/MI inspection. For customers near the 240,000 fired hour mark, who also intend to keep their turbines in operation for many additional years, it is recommended that they replace the turbine rotors at this operation interval. At the 240,000 fired hour mark, the wheels & shafts are well beyond the materials charts for design life. Any turbine wheel burst would be a major catastrophe. So, the best option for continued operation life a thorough review of all operating records and all maintenance reports should be made. Also, it is highly recommended that all customers consider replacing their turbine rotors.

•    Compressor Rotors and blades. Compressor rotors are not subject to the very high temperatures that turbine rotors see, but, customers should be very careful in evaluating the compressor rotors during each Major Inspection, and to keep very good records in the maintenance reports. It is recommended a complete compressor rotor break down inspection be done at the 240,000 fired hour interval and a thorough inspection of all wheels and shafts be down and documented. This would be a good time to also replace all rotating blades, depending on condition.  It is recommended that a thorough life cycle evaluation be done on the compressor rotor parts to ensure continued reliable operation.

•    Accessories and instrumentation. All these items are typically inspected and repaired at each normal maintenance interval. Similar to the design life for the actual gas turbine engine, all the accessories and instrumentation will likely be beyond their design life.  Thus it is recommended that all these items be considered for replacement at the 240,000 hour operating interval. At a minimum, all pumps and motors should be sent out for a complete rebuild; replace seals, gaskets, bearings, windings, etc. it is also recommended that additional spares be kept in stock, as failure rates of all these items will likely be higher due to the age of these items.

•    Packaging and Wiring. These items usually see a lot of wear and tear due to weather, maintenance, and operations issues.  All these items should be inspected during each maintenance interval, and repaired as needed.  It is recommended that all these items be thoroughly reviewed during the life cycle review and replaced during the next maintenance interval as needed.  

•    Controls. All vintages of control systems have a high reliability when first installed, and remain so, today, even though they may now be very old.  The biggest problem with older control systems is the availability of replacement parts. Frequently OEM’s will only stock replacement controls parts for 15 or 20 years.  Thus, it is recommended that all customers keep a large stock of replacement parts on hand, especially when their control panels approach the 15/20 year mark.  Third party suppliers will generally stock many of these items longer than the OEM’s, but as the state of design for electronics progresses, many of the smaller components of the control cards are no longer available, so, even these 3rd party suppliers cannot stock most of the controls replacement parts. A thorough tune-up of the controls system is recommended at each maintenance interval.  Upgrading to a newer vintage control system is recommended, if not already implemented, at the 240,000 operating interval, as it will give the asset owner considerable additional reliability, operability and flexibility needed for the best operating reliability going forward.

In our hearts we all know that our operating gas turbines will last forever. But, only if we keep them well maintained and replace/repair parts as needed.  All customers with older vintage gas turbines that have been in operation for longer operating intervals have had a great staff of operating and maintenance personnel at their plants. But, just as the gas turbines age, the long term experienced station personnel retire, and are frequently replaced with less experienced personnel, who at no fault of their own, do not have the experience and operating background of those who have seen the gas turbines thru their first 30 years of operation. Thus, owner/operators frequently need the help of experienced OEM or 3rd party service provider’s personnel, when doing a life cycle review, especially at the 240,000 hour/30 year interval. The Keck Group International (KGI) is available to help any and all customers who need help with their Life Extension Evaluation. We have several engineers on our staff that have helped many other customers with these evaluations.

FUEL CONVERSIONS

Frequently gas turbine owners’ needs change over time, especially for the types of fuel they want to use.  Changes in emissions requirements, fuel cost, fuel availability, unit reliability, ease of operation, or unit maintenance, frequently result in customers wanting to review different types of fuel capability for their installed gas turbines. The Keck Group International (KGI) has numerous engineers on their staff, who have extensive experience evaluating different types of fuel, and also in implementing fuel conversions for installed gas turbines. Different types of fuels that are frequently reviewed are:

• Converting to Natural Gas fuel, from distillate fuel

• Converting to use crude oil fuel, instead of distillate fuel

• Converting to residual fuel, instead of distillate fuel

• Converting to lower BTU liquid fuels like Benzene

• Converting to lower BTU gas fuels like coke oven gas, process gasses, high hydrogen fuels, etc.

• Converting to higher BUT gas fuels like Propane, Ethane, etc.

In the past 10 years, the following conversions have been implemented by engineers on the KGI staff:

• Converting 2 MS6001 gas turbines from distillate fuel, to crude fuel

• Converting 48 MS7001 gas turbines from distillate fuel, to Natural Gas fuel

• Converting a MS9001 unit from distillate fuel, to liquid Residual fuel

• Converting 3 MS9001 gas turbines from Natural Gas fuel, to process gas with 18% Hydrogen, on a unit with a DLN emission control system.

• Converting 2 MS9001E units to use liquid Benzene fuel

Special care must be taken in converting any gas turbine to dual fuel capability. Frequently carbon residue/coke can form in the liquid fuel lines, as a result of fuel transfers from distillate fuel, to gas fuel, due to residual liquid fuel being left in the on-base fuel lines. Surveys of customers with dual fuel capability indicate that they all have significant issues with fuel transfers due to in-adequate purging of the fuel lines. Recommendations for improved liquid fuel purging will be included in all fuel conversion studies, and projects.

For help in evaluating different types of fuel, and/or in implementing fuel conversions, or in improving the reliability of your existing fuel system, please contact us at www.keckgroupint.com.