Background: Legacy Turbine Users Group

The Legacy Turbine Users Group (LTUG), formed by Power Users earlier this year to facilitate the transfer of knowledge among members of the Frame 5, 6B, and 7EA Users Groups, greatly benefits owner/operators of these engines. With the number of experienced O&M personnel in decline because of staff reductions and retirements, it makes good sense to aggregate the talent on both the user and supplier sides for all to share—especially given that these GE engines have “common” elements.

LTUG’s first annual meeting was conducted as part of Power User’s Mega Event, Aug 29 – Sept 1, 2022, at the San Antonio Marriott Rivercenter, which attracted more than 350 owner/operators. Several reports on that conference are forthcoming. Here the editors review the backgrounds of the Frame 5 and Frame 6B organizations and salute BASF Geismar for its work in increasing the reliability of boiler drum-level controls. The 7EA Users Group, serving owner/operators of 7B-EA gas turbines, will be featured in the next issue of CCJ ONsite and include recent best practices from that fleet.

The GE Frame 5 is likely the most popular gas turbine ever produced for power and industrial applications. The first unit in this model series shipped 65 years ago from the OEM’s Schenectady (NY) shops and Frame 5s are still being built today—albeit by manufacturing associates abroad and at ratings about two and a half times those of the 12-MW models installed in the late 1950s and early 1960s.

Although more than 3000 of these machines have been sold over the years, the editors cannot find records of any formal user group meeting conducted since the millennium with the Frame 5 as its focus. Power Users believes this engine has value as a critical peaking asset and supported the launch of the Frame 5 Users Group as part of its 2022 Mega Event.

Frame 5s are, in a manner of speaking, “beasts,” and many don’t run very often. But that doesn’t mean they are immune to the problems found in more advanced machines that operate regularly and at higher temperatures.

Mike Hoogsteden, director of field services for Advanced Turbine Support, an industry leader in the conduct of borescope inspections to determine the condition of gas turbines and other assets, told the editors that a large majority of Frame 5 operators don’t perform semi-annual inspections, as do the large gas turbines running regularly. Depending on the run profile, a full compressor/combustion/turbine borescope inspection every one to two years probably makes best sense for many of these units.

Also recommended, and depending on unit designation, is an eddy-current inspection of all IGVs (fixed and variable) and the stage S0 or S1 stator vanes (first row of vanes). The EC scan would identify any cracks in the vanes.

Another location for a careful inspection is at the ninth-stage hook-fit, where component separation can be an issue. Recall that the thin ligament at the 10^th-stage extraction slot forms the hook that holds one side of the ninth-stage stator vanes in place. It is susceptible to cracking that could allow one or more vanes to work free and go downstream causing major compressor damage (Fig 1).

If you are unfamiliar with how best to prepare for a Frame 5 borescope/EC inspection, contact your service provider. A couple of things Hoogsteden recommends: (1) For the combustion section inspections, provide access to every other one of the 10 cans via removal of the fuel nozzles; (2) gain access to the second row of turbine blades by availing access into the stack.

Hoogsteden then provided a flavor of what might be found with a borescope by sharing findings from three recent Frame 5 inspections. Engine A was a Model M, B a Model P, and C a Model N.

Engine A. The inlet section was found in relatively good condition, but there was rust and debris on the inlet floor. Inspector’s recommendation was to prep the floor for a two-part epoxy coating capable of withstanding regular water immersion.

The compressor section, accessed through the inlet bellmouth initially and later through the removed upper case, revealed partial liberation of the IGV tip shroud, causing significant downstream damage (Figs 2 and 3). An engineering review was recommended before repairing and restarting the unit.

The combustion section was in good condition; water wash residue was visible on the hardware. Combustion liners were accessed through the fuel nozzles in cans 3 and 7.

The turbine section, accessed via the combustion liners, also was in good condition. The exhaust section was not inspected.

Engine B. Rust and debris was found on the inlet floor of this unit as it was in Engine A. Inspectors accessed the compressor section through the inlet bellmouth, finding two stage S0 stator vanes had liberated at the 6 o’clock position (Fig 4) along with one R9 rotor blade (Fig 5). Result: Extensive damage throughout the compressor.

Combustion liners were accessed through the fuel nozzles, the turbine section via the liners and exhaust section. The combustion section was found in good condition except for some debris found in the combustion-cap air slots (Fig 6). Impact damage and material loss was suffered by a majority of the first-stage turbine buckets (Fig 7). Condition of the exhaust section was “good.”

Engine C. Access (1) to the compressor section was through the inlet bellmouth and the ninth-stage air extraction, (2) to the combustion liners via fuel nozzles and crossfire tubes, and (3) to the turbine section by way of the combustion liners and exhaust section.

Impact damage was found at the leading edges of 13 R0 rotor blades (Fig 8), the debris causing minor damage throughout the compressor. Stator-vane hook-fit separation was evident in stage 9, where the gap between the case material and stator vanes ranged from 32 to 68 mils (Fig 9).

The combustion and turbine sections were in good condition; however, there was inner-barrel corrosion with material loss and cracking in the exhaust-section diffuser vanes (Fig 10).

Background: Legacy Turbine Users Group

The Legacy Turbine Users Group (LTUG), formed by Power Users earlier this year to facilitate the transfer of knowledge among members of the Frame 5, 6B, and 7EA Users Groups, greatly benefits owner/operators of these engines. With the number of experienced O&M personnel in decline because of staff reductions and retirements, it makes good sense to aggregate the talent on both the user and supplier sides for all to share—especially given that these GE engines have “common” elements.

LTUG’s first annual meeting was conducted as part of Power User’s Mega Event, Aug 29 – Sept 1, 2022, at the San Antonio Marriott Rivercenter, which attracted more than 350 owner/operators. Several reports on that conference are forthcoming. Here the editors review the backgrounds of the Frame 5 and Frame 6B organizations and salute BASF Geismar for its work in increasing the reliability of boiler drum-level controls. The 7EA Users Group, serving owner/operators of 7B-EA gas turbines, will be featured in the next issue of CCJ ONsite and include recent best practices from that fleet.

The 6B is a familiar GE gas turbine in cogeneration systems at process plants where staff typically is challenged to keep legacy assets operating on a low O&M budget, often without the support of a corporate engineering staff. The presentations and discussions at annual meetings of this users group provide know-how and proven solutions to help owner/operators achieve that goal.

These engines also are found in simple- and combined-cycle arrangements for electricity production only. In fact, the first Frame 6 (Model A, which preceded the 6B) was commissioned July 15, 1979 at Montana Dakota Utilities Co’s Glendive Power Plant. The 41-MW, dual-fuel-capable, simple-cycle unit was still in service about a year ago.

2021 conference in review. No formal user presentations were on the 2021 virtual conference agenda. Rather, owner/operators shared their experiences via four roundtable discussion forums: compressor, I&C, combustion, and turbine, each chaired by a member of the steering committee. Copies of the slide decks and an unedited recording of each discussion are available to registered users in the Frame 6B section of the Power Users website. Click on the “Conference Archives” tab. These are valuable training aids for O&M personnel, both experienced hands who might benefit from a refresher as well as newcomers.

Highlights of the compressor roundtable include the value of hydrophobic HEPA filters to engine performance, the need know the nature of blade deposits and before you water-wash to avoid pitting corrosion, and when to/when not to fog.

A highlight of the I&C presentation was what to know before you consider upgrading from a Mark IV to Mark VIe control system. It’s a big undertaking, despite what you may have heard to the contrary. Space constraints may be a challenge difficult to overcome.

Support documentation focusing on O&M safety available from the OEM is highlighted in the sidebar.

Two vendor presentations also are available on the Power Users website in the Frame 6B section, both concerning generators:

• “Generator cycling concerns,” W Howard Moudy, National Electric Coil. Presentation’s primary intent is to develop awareness of cycling-related concerns and affected components. It covers speed cycling, which involves taking the unit from standstill or turning-gear speed to full speed and back (one speed cycle), and load cycling, the fluctuating generator output required to follow demand. Also covered are the opportunities for monitoring, maintaining, and solving problems.
• “When a robot won’t fit,” Jamie Clark, AGT Services Inc. Focus is on generator minor inspection techniques and their limitations.

The third leg of the Frame 6B conference stool, conducted by the OEM on the second day of the meeting, consisted of four sessions, each running about 30 minutes. The subjects: Covid experience, condition-based parts management, decarbonization, and compressor and hot-gas-path Q&A.

To dig deeper, access the presentations on the GE Power Customer Portal (formerly MyDashboard). The new user interface features enhanced navigation to keep users informed on the disposition of TILs, provide the ability to follow your outage from planning to closeout, track parts orders, and retain reports and other documentation of importance—such as O&M manuals—in one location. Register for access at https://Registration.gepower.com/registration. To log in, go to https://mydashboard.gepower.com/dashboard.

Safety TILs affecting 6B gas turbines

TIL-2101, Modification of manual lever hoist for safe rotor removal.

2044, Dry flame sensor false flame indication while turbine is offline.

2028, Control settings for GE Reuter Stokes flame sensors.

2025, GE Reuter Stokes FTD325 dry flame sensors, false flame indication.

1986, Braid-lined flexible metal-hose failures.

1918, 6B Riverhawk load-coupling hardware and tooling safety concern.

1838, Environmentally induced catalytic-bead gas-leak sensor degradation.

1793, Arsenic and heavy-metal material handling guidelines.

1713, 6B, 6FA, 6FA+E, and 9E false-start drain system recommendations.

1709, 6B load-coupling recommendations.

1707, Outer-crossfire-tube packing-ring upgrade.

1700, Potential gas-leak hazard during offline water washes.

1633, Load-coupling pressure during disassembly.

1628, E- and B-class gas-turbine shell inspection.

1612, Temperature degradation of turbine-compartment light fixtures.

1585-R1, Proper use and care of flexible metal hoses.

1577, Precautions for air-inlet filter-house ladder hatches.

1576-R1, Gas-turbine rotor inspections.

1574, 6B standard combustion fuel-nozzle body cracking.

1573, Fire-protection-system wiring verification.

1566-R2, Hazardous-gas detection system recommendations.

1565, Safety precautions to follow while working on VGVs.

1557, Temperature-regulation valves containing methylene chloride.

1556, Security measures against logic forcing.

1554, Signage requirements for enclosures protected by CO2 fire protection.

1537-1, High gas flow at startup—Lratiohy logic sequence.

1522-R1, Fire-protection-system upgrades for select gas turbines.

1520-1, High hydrogen purge recommendations.

1429-R1, Accessory and fuel-gas-module compression-fitting oil leaks.

1368-2, Recommended fire-prevention measures for air-inlet filter houses.

1275-1R2, Excessive fuel flow at startup.

1159-2, Precautions for working in or near the turbine compartment or fuel handling system of an operating gas turbine.

Most drum-level control systems employ 3-element logic, with feedback to the controller on drum level, steam outlet flow, and feedwater inlet flow. Data provided by pressure and temperature transmitters are used to enhance the accuracy of the steam-flow value. To illustrate: If the drum-level instrument is a dP-style level transmitter, a pressure transmitter is installed on the drum to provide the data necessary to make the density correction needed for accurate level calculations.

Thus, the term “3-element control” is somewhat misleading because it involves a minimum of six instruments—boiler feedwater (BFW) flow, steam flow, steam temperature, steam pressure, drum level, and drum pressure—for controlling the drum level.

And it is likely that more than one drum-level instrument is used. Many boilers have two drum-level instruments and control using the average value of the two. However, if one instrument goes bad the average value will be inaccurate. With two conflicting readings, how does one know which is the more accurate?

If any instrument fails, particularly one of the main instruments (steam flow, BFW flow, drum level), the control system will not work. If any one of the supporting instruments fails (drum pressure, steam pressure, steam temperature), the control system may still work but it will be compromised.

Occasionally, Geismar’s steam flowmeter would fail. If it failed high, the signal sent to the drum-level controller would result in too much BFW flow, leading to carryover. If it failed low, there was a risk of BFW flow being reduced to the point of tripping the boiler on low drum level.

Similarly, if the BFW flow transmitter failed high or low, this inevitably would lead to high drum level and carryover or a low-drum-level trip.

Depending on your specific programming logic, some instrument failure scenarios will default the drum-level controller to manual. Geismar boilers had two level transmitters. If they disagreed by more than 4 in., the level controller would default to manual. This usually would occur when the level control valve already was open or closed too much, leading either to a carryover event or trip because of low drum level. The operator then would have to control the drum level manually and not have the option of returning the control to automatic.

During an unusually cold period one recent winter, the drum pressure transmitter froze and its milliamp signal went so high it caused an instrument input/output (I/O) error; the level control system defaulted to manual. Even if the drum pressure transmitter were wildly inaccurate, it generally would result in a drum-level measurement error of only a few inches, which is preferred over a default to manual. When the system defaulted to manual the drum level likely would get out of control and the unit would trip.

Given the drum-level measurement challenges, a third independent level instrument was installed—one using guided-wave radar technology. Having three level measurements available, control was changed from using the average of two level-instrument values to using the median value of all three instruments. If one went bad, the control system would continue without a hiccup; only if two instruments failed simultaneously would the level reading be impacted.

Regarding steam-flow measurement, Geismar uses a verification system to check reading accuracy. By modeling steam flow versus other operating parameters, staff can predict accurately what the steam flow should be. If measured steam flow varies from the predicted value by too much, the drum-level control system alarms and the predicted steam-flow value is used in place of the measured value.

For the plant’s conventional fired boilers, steam flow can be predicted accurately using fuel flow (figure). For the cogen unit with the unfired HRSG, steam flow is predicted based on gas-turbine output (megawatts), and for the cogen unit with the fired HRSG, on a combination of gas-turbine output and fuel flow to the duct burner.

All of these calculations are made by the DCS. So, it makes no difference if the steam-flow measurement is the result of a problem with the flow, pressure, or temperature transmitter because the predicted steam-flow value is close enough for the system to continue accurately controlling drum level.

Regarding the BFW flowmeter, this instrument is the most critical in the drum-level control scheme because the drum-level control is actually feedwater control used to regulate drum level indirectly. Geismar installed logic that monitors the difference between the measured feedwater flow and the feedwater flow setpoint. This difference normally is very small. A large difference indicates a problem (either measurement error or feedwater valve issue) and the control scheme would transition from a 3-element arrangement to single-element (drum level), thereby removing the faulty feedwater reading from the control scheme altogether.

For the drum pressure transmitter, staff removed the “default-to-manual” logic that occurred when an I/O error was received, defaulting the drum-pressure reading to a constant value typically seen during normal operations.

Results. The site lost all six of its steam producers (two cogen units and four conventional boilers) during a very hard freeze in January 2018. Reason: Low drum levels caused by a combination of the failure scenarios described above—inaccurate steam-flow measurement, inaccurate BFW flow measurement, and controller default to manual attributed to failed instruments.

Following the freeze event, the changes noted above were made and deficiencies in the heat-trace system were corrected. Since that time, the boilers have successfully weathered instrument failures on the steam-flow reading, drum-pressure measurement, and drum-level measurement.

A few instruments were affected during the hard-freeze event in February 2021, but the improvements made were sufficiently robust to keep all steam producers in service.

Shared by David Lucier, founder and GM, PAL Turbine Services LLC

Use correct names of gas-turbine components to avoid confusion

Components and auxiliary systems for GE gas turbines have specific names. It is important to use correct names when communicating with the manufacturer or service companies to be sure you’re understood. For some, it may be like learning to speak a new language, which can be called “GE-ology.”

In 1961, GE introduced the gas-turbine Packaged Power Plant. The company’s first PPP was the MS5001—a/k/a Frame 5. When introduced, the engine was designed to produce 12 MW, a rating that prevailed throughout the first half of the sixties. During the second half of the decade, demand for emergency power was unprecedented, with investor-owned electric utilities and municipalities placing orders for dozens of PPPs.

The PPP design had most of the auxiliary fluid systems located on the accessory base with the goal of minimizing installation and startup times. It included the following:

• Accessory gear with water, oil, and fuel pumps, and atomizing air compressor.
• Lube-oil (LO) tank integral to the I-beam base with oil pumps, coolers, filters, pressure regulators, etc, inside the base or above it.
• Hydraulic supply system using lube oil to provide high-pressure fluid for operating servo valves and the ratchet rotor-turning device, and for enabling clutch engagement. Earlier systems for clutch operation, diesel actuation, and ratchet engagement relied on high-pressure air.
• Fuel system components also atop the base included the following:
• Liquid-fuel pump and flow divider.
• Gas-fuel stop and flow-control valve.
• Cooling water system installed in the roof with radiators and fin-fan drive.
• Starting device (diesel engine or cranking motor) was on-base with jaw clutch.

Fig 1 presents the right-side view of a gas turbine showing its auxiliaries and their locations on the accessory and turbine base. Fig 2 provides an isometric view. Most everything needed to operate the turbine is tagged. Some of the components not visible in Figs 1 and 2 include the fuel pump, 12-position fuel pressure selector valve and gage for each combustor, and liquid-fuel flow divider. Other devices that would be installed on the gas turbine include two compressor bleed valves, two igniters (a/k/a sparkplugs), and ultraviolet flame detectors.

Given the availability of a cured concrete foundation onsite, PPP installation typically took less than two months. Bear in mind that this was the first time the gas turbine was “introduced” to its generator, load gear, control cab, generator breaker, and protective devices—all manufactured at GE facilities in other cities.

A typical PPP (Fig 3) shows the accessory base (left), gas turbine and exhaust (center), and generator (far right). This configuration of major components prevailed for over 50 years in the design of most GE Frame 5 and 6 gas turbines—even those installed inside buildings.

A simple way to check gas-turbine performance

GE gas turbines installed in electric generating plants from the mid-1960s to the late 1980s operate infrequently today—typically confined to peaking and emergency service—given the availability of more-efficient machines for mid-range and baseload duty. However, when your legacy engines do run it is good to know if they are operating “up to snuff.”

There’s an easy way to do this knowing compressor discharge pressure and exhaust temperature, calculating the pressure ratio, and plotting this information on the OEM’s performance graph provided in the plant’s Control Specifications.

Below are the steps involved, using the MS5001L gas turbine to illustrate the process. These so-called 5L turbines were designed with NEMA (National Electrical Manufacturers Assn) ratings of approximately 15 MW for a compressor inlet temperature of 80F and site elevation of 1000 ft (14.17 psia).

First, access the following information from the control system display (Fig 4) at full speed/no load (FSNL):

• Turbine exhaust temperature (TXA).
• Compressor discharge pressure (PCD).
• Fuel-pump stroke reference (VCO).

The data are repeated in the caption to facilitate readability. Given the compressor inlet pressure is 14.39 psia from site data (if not available, use the standard 14.7 as its impact will be minimal, especially for legacy turbines), the pressure ratio (CPR) can be calculated as follows:

CPR = [76.1 (PCD) + 14.39] ÷ 14.39 = 6.29.

Since speed is constant at FSNL, in preparation for the generator to supply power to the grid, consider that a new operating “plateau” has been reached: synchronous speed. Thereafter, the data of interest increase in direct relation to fuel flow to the combustors (Fig 5).

Again, the data are repeated in the caption to facilitate readability. As for the previous calculation, the compressor inlet pressure is 14.39 from site data and the pressure ratio at baseload is the following: CPR = [90 (PCD) + 14.39] ÷ 14.39 = 7.25.

Next, go to Fig 6 and plot the average exhaust temperature at full load (851F from Fig 5) against the compressor pressure ratio of 7.25 at baseload. That point occurs well below the base temperature control line, as the arrow indicates. Important to note that GE engines are designed to run on the lower control line. When operating below this line, the unit is under-firing—that is, performing below the design rating. Fig 7 illustrates this with a power output of 12 MW, lower than expected with 3.5 MVAr of reactive power.

Of course, you might choose to operate slightly below the engine’s design rating to maintain its reliability and minimize wear and tear, given the unit’s age. You can do this by adjusting the fuel regulator to reduce exhaust temperature.

Performance analysis. For the Frame 5L example, power production increases from 0 MW at FSNL to 12 MW, because fuel flow to the compressor increases during the ramp up in output. During this transition, compressor discharge pressure goes from 76.1 to 90 psig—a rise of only 13.9 psi, which is considered low and indicative of something being wrong. Here’s what to check:

• Fouled compressor, typically caused by poor-quality ambient air. Examples: Soot deposits are common in gas turbines downstream from a refinery or chemical processing plant, salt deposits in units located within five miles or so of an ocean or other body of saltwater. Action to consider:
• At FSNL, inject Carbo Blast or equivalent for dynamic cleaning of compressor blades. Veterans may recall walnut shells being used for this purpose back in the 1960s and 1970s.
• Partially opened compressor bleed valves. During startup, CBVs should be fully closed at about 75% of rated speed and never leak. Action to consider if your CBVs leak: Disassemble, inspect, clean, and lap sealing surfaces as required.
• Leakage at the compressor discharge—such as missing transition-piece side seals or at another unwanted opening causing a pressure loss. Action to consider: Bring in a qualified borescope inspection team to look for passages for leakage.
• Cracking or erosion of one or more first-stage nozzles. If the trailing edges of nozzle partitions are worn or eroded, the backpressure on turbine buckets will drop, reducing power output. Action to consider: Conduct a borescope inspection of first-stage trailing-edge partitions.

Finally, consider the case where power output increases from FSNL to the 15 MW designers intended for the Frame 5L. For these conditions, the expected average turbine exhaust temperature would be approximately 950F. Also, compressor discharge pressure should increase by nearly 20 psi—from 76.1 psig (refer back to Fig 4) to the 95 psig expected based on the NEMA rating for this machine with a clean compressor. The compressor ratio for the Frame 5L at NEMA conditions and using the same calculation presented earlier, would be 7.72.

Final step: Plot the 950F exhaust temperature and 7.72 pressure ratio on the Fig 6 chart (X marks the spot), noting that it is above the control line. This means the unit is over-firing and the exhaust temperature should be reduced by 20 deg F or so to minimize the wear and tear on first-stage nozzles.