Onsite - Combined Cycle Journal

Plant-network, data-link, communications issues revealed during commissioning

By Team-CCJ | May 16, 2022 | 0 Comments

Mini network connects multiple TCP/IP network devices to the Modbus gateway (port 502) and then converts the signals from Ethernet to the fiber going back to the DCS
Mini network connects multiple TCP/IP network devices to the Modbus gateway (port 502) and then converts the signals from Ethernet to the fiber going back to the DCS

While the industry makes progress towards the fully connected, largely automated powerplant with a meta-organization of onsite staff, remote monitoring and diagnostics (M&D) assistance, and market delivery setpoints, there are some serious and costly gaps that are overlooked in data links and industrial communications. According to Jeff Downen, business owner, Black Start LLC, these gaps are often revealed and corrected during commissioning.

Some root causes of the gaps include the following:

  • Scope irregularities between the automation platform’s OEM and the plant’s EPC, often based on technology design and concepts a decade or two out of date.
  • Insufficient communication between vendors while designing communication links and network paths, usually reflected in the I&C drawings and configurations.
  • Quantum leaps in data points being captured, transmitted, and monitored in sophisticated graphics with data speeds at the gigabit level.
  • EPCs using electrical engineers to do the design, rather than I&C/DCS engineers with IT networking experience.
  • Engineering and procurement documents often don’t address communications protocols, network speeds, connection types, and media conversion.

As Downen said in an interview, “All of these software packages and hardware procured from different vendors are designed so they can communicate, but someone still has to troubleshoot and integrate the systems so they will.”

Here are some of the most common issues Downen and his team encounter during commissioning while working directly for the EPC:

Improperly matched communications speeds. One example is multiple issues with incorrect baud rates on the serial links and 100/1000 base connections for fiber and Ethernet.  An example: SEL (Schweitzer Engineering Labs) 2730 small form-factor pluggable (SFP) ports designed as 1000 base fiber, and designed to connect with Emerson-provided EtherWAN media converters that were 100 base, are incompatible.

Media and cabling. Single- and multi-mode fiber issues crop up from the engineering and procurement phases. Example: A generator step-up (GSU) annunciator panel’s initial design called for an SEL serial device for a Modbus remote terminal unit (RTU). However, the network path only allowed a Modbus TCP/IP via the routers over port 502 and also needed a null-modem serial cable.

This was corrected by adding a mini-network for media and protocol conversion as shown in the photo. Port 502 is the Modbus protocol widely used for TCP/IP communications, allowing Modbus data links and traffic to pass through an IP network.

Another example involved the SEL discrete programmable automation controller (DPAC). The real-time automation controllers (RTAC) in the switchyard were using SEL 273A cables and communicating over a distributed network protocol (DNP). The serial nature of the protocol prohibits the cable from allowing traffic between the devices because the request-to-send (RTS) and clear-to-send (CTS) pinouts on the selected cable were incompatible. For non-IT types, RTS and CTS are data flow control mechanisms which are part of the RS232 standard connector.

This issue was corrected by changing over to the SEL protocol but would never have been an issue if SEL 272 cables were selected in the first place; it has the correct pinout.

IP addressing and subnets. Devices on the same network often are not configured properly, along with incorrect gateway assignments, port configuration issues, and the same subnets being used on the adjacent sides of a field router. An example that Downen found was an Ovation DCS with Ethernet link controller cards on the same subnet with identical IP addresses as some of the relays on an opposing network (each side of a router). This can be corrected by changing either side of the router’s respective devices.  An example:  RTACs and relay network settings to be changed out by reconfiguring the router files and the DCS programming.  Both are costly and time-consuming tasks.

Some ports, especially 80 (HTTP), 502 (Modbus), and 23 (Telnet) are not properly understood during design and end up being used incorrectly on a majority of devices for serial tunneling, web interfaces, and Modbus communications.

Spares and equipped spaces with blank equipment for a plant’s future use typically have a default IP address but are still connected to the same network in use by the plant, causing network collisions, or loss of information and errors while communicating.  This event can be witnessed when a master or client device is confused because an identical subnet is on the other side of the field router with similar device IP addresses.

User presentations: Benefit from your colleagues’ experiences

By Team-CCJ | April 19, 2022 | 0 Comments

Presentations by owner/operators are highly regarded at user-group meetings. The first-hand experience detailing how a particular job was conducted, what worked/what didn’t, lessons learned, etc, can be invaluable to someone considering a similar project. Plus, there’s the opportunity to ask questions and get straight-forward answers.

You should be aware of the six user presentations from the 2016 7EA Users Group meeting profiled here which might provide an assist in work you’re doing or planning. They are accessible to registered users on the organization’s website. The titles, immediately below, reflect the diversity of material shared at a typical 7EA meeting—including HV electrical, generators, gas turbines, valves, etc.

      • Bus replacement.
      • TIL 1398 inspection of stator-end winding axial support system hardware.
      • Hot-gas-path component life.
      • 7EA maintenance strategies.
      • Gas valve upgrade.
      • 7EA compressor issues.
      • Wrapper leak mitigation.

The bus-replacement presentation describes in detail (but few words) the retrofit of 15-kV/4000-amp circular non-segregated (non-seg) bus. More than seven-dozen photos of the components and their assembly and installation, foundations, plus detail drawings, walk you through the project quickly. A companion presentation, made by Bruce Hack of Crown Electric Engineering & Manufacturing LLC, covering circular non-seg bus, switchgear and circuit breakers, also is posted on the 7EA Users’ website.

TIL 1398-2, issued in March 2003, is applicable to all hydrogen-cooled, medium-size generators manufactured between July 1988 and September 2002. Its purpose is to remind users to inspect the tightness of the stator end-winding support hardware for loose, missing, and non-locking fasteners. Photos show damage done by liberated fasteners and how fasteners can be fixed in place with epoxy to mitigate the issue.

A table included in TIL 1398-2 identifies machines susceptible to loose fasteners (such as the GE 324 steam turbine/generator, 9A4, and 7A6), gives part numbers of interest, etc.

HGP component life reflects the experience of three 7EAs, each having a nominal 20 years of cogeneration service. The baseload units had operated roughly 165,000 fired hours and had fewer than 200 starts, respectively. Inspection schedule was combustion every other year, HGP every four years, and major every eight years.

Buckets:

      • First stage. DS GTD-111, 12 cooling holes, GT 33 coating and TBC. Typically repair at HGP and replace at about 100,000 fired hours. Longest demonstrated run was 105,000 fired hours.
      • Second stage. IN-738 and GTD-741, 10 cooling holes, scallop shroud, cutter teeth. Typically repair at HGP or major and replace at 100,000 fired hours. Longest demonstrated run on IN-738 buckets with eight cooling holes was 100,000 fired hours.
      • Third stage. U-500, cutter teeth. Typically repair at HGP or major and replace at about 135,000 fired hours. Longest demonstrated run was about 140,000 fired hours.

Nozzles:

      • First stage. FSX-414 with full MCrAlY and TBC coating. Repair at HGP and replace when no longer cost-effective to repair. Longest demonstrated run expected at next outage would be 140,000 fired hours. At the time of the presentation a set of nozzles with about 130,000 fired hours was at a shop for repair.
      • Second stage. GTD-222 with MCrAlY coating. Repair at HGP; replace when no longer cost-effective to repair. Longest demonstrated run expected at next outage would be about 162,000 fired hours.
      • Third stage. GTD-222. Repair at major; may replace at 200,000 fired hours or when no longer cost-effective to repair. Original sets of nozzles still in machines with about 165,000 fired hours of service and two repair cycles.

Shroud blocks:

      • First stage. HR-120 with cloth seals.
      • Second and third stages. Honeycomb.

7EA maintenance strategies. This presentation, rated “must review” by the editors, offers valuable insights based on the extensive experience of both the user and his company. The power producer has 51 7EA peaking units (no baseload) installed at six stations; 39% of the engines have Type 403cb stainless steel S1 airfoils, the remainder GTD 450. The strategies discussed had to do with S1 failure mitigation, post-outage performance loss, and rotor end-of-life.

Regarding S1, the speaker first reviewed inspection options, then discussed the company’s original failure-mitigation program and why some tweaking was required. He then explained the updated plan and reviewed ongoing development of yet another mitigation plan (referred to as the “alternative” plan) based on the efforts of EPRI and its members.

TIL 1884. The speaker addressed TIL 1884 first, noting that the OEM recommends dye penetrant for NDE. The user’s engineering department does not agree, believing greater accessibility is needed for a proper dye-penetrant inspection, excessive application of dye-penetrant chemicals is required, and results are inconsistent. It recommended eddy current (EC), finding it is easier to implement, results have less variability, and helps identify crack indications at a higher success rate. If an indication is found, the engineering department recommends confirmation with FPI (fluorescent penetrant inspection).

For more on TIL 1884 and what others think about the use of dye penetrant to achieve its goals, see the article above focusing on 7EA compressor inspection.

Continuing, the speaker said his company embraces 100% borescope inspection of the R1/S1 area for clashing and of recording clashing damage, if found, with photos and measurements. Mapping of clashed stators also is done.

Here’s how the speaker summarized the company’s S1 failure mitigation observations and efforts:

      • Corrosion of carbon-steel ring segments reduces vane damping and increases stator stresses if a rotating stall is experienced during startup and/or shutdown.
      • At the time of the presentation, S1 failures associated with GTD 450 were airfoil tip liberations; with 403cb, root liberations. The latter failures can occur with no clashing.
      • TIL 1884 recommends dye-penetrant inspections only for units experiencing clashing. It does not address units with 403cb airfoils which may have crack indications without signs of clashing nor does it offer a method for determining the magnitude of indications.
      • The speaker’s company has qualified EC as its preferred method of S1 inspection.
      • The power producer also evaluated its 7EA fleet based on S1 inspection results compared to operational profile and parameters, finding no correlation to predict S1 crack initiation and when an S1 failure would occur.

Post-outage performance loss. A relatively common complaint of owner/operators presenting on their recent major inspection experience is the deterioration of performance following restart. The editors have heard this at several user-group meetings with no particular OEM or third-party vendor singled out.

The 7EA speaker discussed performance loss after a combustion inspection (rare) and HGP. The typical finding: Pre-outage NOx margin was different that post-outage. Engines were tuned to lower firing temperatures to assure environmental compliance. The result was a 3- to 5-MW decrease in output. The user’s company, the OEM, and various third parties believe fuel/air variation explains the performance issues.

The owner has been flow-testing liners and comparing results against post-outage performance to determine allowable flow tolerances—this to maintain firing temperature at the highest possible level and prevent loss of top-end megawatts. Another objective is improved repair processes to achieve repeatable results with vendors and reclaim lost output.

Rotor end of life (EOL). The speaker explained the following four options for rotor failure mitigation:

1. Replace the existing rotor with a new or refurbished one. This is the highest-cost/lowest-risk option but one seriously worth considering if you have majors for multiple units in the same year.

2. Refurbish to regain half a lifecycle. This is a less expensive but higher-risk alternative than the first option.

3. Replace key rotor components to achieve life extension—less expensive than the first two options with less risk than the second.

4. Inspect but do not repair may be the option of choice depending on the strategy for unit retirement. This is the lowest-cost/highest-risk option of the four presented.

The presenter closed by listing critical items to consider before formulating an EOL evaluation plan and selecting a vendor:

      • Availability of rotor discs (OEM or third-party manufactured) if one or more do not pass inspection.
      • Capability of the EOL contractor for replacing one or more discs—if necessary.
      • Candidate contractor’s rotor inspection capabilities and experience.
      • Candidate contractor’s EOL analytical and engineering capabilities.

The gas-valve upgrade presentation provides some project photos, data, calibration settings, operating parameters and other information of value to users considering migration from hydraulic actuation to electric. This information, combined with the experience from a recent Frame 5 fuel-valve upgrade, should help any owner/operator considering a similar project.

7EA compressor issues. A hands-on engineering manager discussed issues experienced during execution of TIL 1884 recommendations. If clashing is in evidence, removal of S1 vanes may be necessary. Options for removing them: Pull the rotor or leave the rotor in place and try to push the lower-half ring segments out of the case. The presentation illustrates how the OEM’s stator removal tool handles the task with the rotor in place.

The speaker said the special tooling was successful on both machines serviced, but the task was challenging. On one unit, the hydraulic power unit developed 3100 psig to free up segments with heat and quench. The other unit required 5200 psi to break loose the ring segments.

Other discussion points: Replacement of a failed R17 blade (TIL 1346), shim pinning according to TIL 1562-R1, and turbine shell-to-exhaust frame slippage (TIL 1819-R2).

Ovation users ponder big issues, knuckle down on knotty plant problems

By Team-CCJ | April 19, 2022 | 0 Comments

Encompassing 1300 GW of global capacity, 450,000 MW of that in the US, and 120,000 MW of combined-cycle capability, the Ovation control system platform, according to Robert Yeager, president of Emerson Automation Solutions Power & Water, is Number One in global power generation control systems. But Yeager, in the traditional “bragging rights” opening remarks at the Ovation Users Conference, clearly wanted to put his competitors on notice that he is gunning for more.

“We’re going to knock the wind out of our competitors,” he said, referring to the relatively new OCC100 product, designed to compete head-to-head with the traditional programmable logic controller (PLC). The OCC100 also forms the backbone for Ovation-based microgrid control systems.

Features now fully integrated into Ovation, such as embedded simulation (Fig 1), vibration and condition monitoring, and predictive analytics obviate the need for separate packages—and separate vendors. Yeager claimed that the company is working on 35 active embedded simulator projects around the world. “In five years, operators will spend more time in the ‘virtual’ plant residing in the ‘cloud’ than with the real plant controls,” he predicted.

Underscoring the challenge cybersecurity poses to highly connected digital systems, Yeager also noted that the Ovation cybersecurity team has ballooned from three to 50 members in the last few years. “We’re providing cybersecurity services on competitor control systems, too,” he added.

Steve Schilling, VP of technology, and head of the Ovation Technology Team, amplified some of Yeager’s comments. Ovation’s “remote node interface module,” a/k/a Ethernet I/O, is in final testing, he said. It can be used, along with the OCC100, not only for wind and solar facilities, but also for smaller, dedicated control systems for skid-mounted process units—the traditional purview of the PLC.

Two other remarks by Schilling were, well, darn right chilling. First, he noted that “storage is the wild card in the power equation.” This is yet one more indication that grid-scale storage is seriously penetrating the power industry “psyche.” Commercial storage facilities are already lopping off the peak of the peak demand in major markets around the country and thus compete with quick-start gas turbine units.

Second, he said that half of one large utility’s 6000 employees are eligible to retire in five years. That’s more than a brain drain; that’s a potential vortex, at least in the time scales the electricity industry operates under.

Yeager had noted earlier that one-third of the attendees at the confab had never attended an Ovation User group conference before. Hopefully, some of those newcomers represent youthful energy, not veterans who had to take over control system duties because someone retired.

Schilling also put turbine vendors on notice, saying that Ovation now offers a “completely integrated turbine control solution incorporating new synchronizer, machinery health, and excitation modules.” He also addressed cybersecurity, stating that certification under ISA/IEC 62443 is underway.

 Modern to mundane. Up next in the general session was Emerson’s Glen Heinl, director of customer services, who addressed mapping your journey with an Ovation system. He said Ovation offers more than 50 formal classes for employee development and advanced skills, and 20 webinars are available without leaving your desk.

One important question he had for the folks on the deck plates: “Are you checking your power supplies?” Because users often add I/O cards and capabilities, the existing power supplies can quickly become overwhelmed. A preventive maintenance guide, addressing power supplies and other critical items for Ovation systems is expected to be released “within six months.”

Speaking of knotty problems, the modern simulator has come to the aid of the age-old mundane problem of inconsistent operator performance at one plant. Personnel there, suffering from the aging workforce challenge, committed to a formal operator training program anchored by the

Ovation embedded simulator, replacing a simulator onsite for eight years but not used.

Plant representatives reported the program led to a 44% reduction in startup and shutdown times. The five operator crews, a mix of veterans and new recruits, had been doing things differently. Following training, the crews are consistently following startup and shutdown procedures, performing tasks simultaneously, getting qualified “expeditiously,” and in general achieving more consistent performance.

Lucky sevens. Replacing seven gas-turbine control systems with Ovation in seven weeks could be like holding your breath at the casino, hoping for lucky sevens. What made this project more white-knuckle is that the seven turbines (at two different locations, one a combined cycle facility, the other a simple cycle peaker facility) were acquired from merchant owner/operators. Lacking experienced personnel in this area, the new owners essentially put their full trust in Emerson as system supplier and engineer—that is, not hiring a separate electrical contractor. All electrical demolition was also left to Emerson.

One of the objectives of the replacement at the combined-cycle facility was to automate the manual power augmentation and water injection NOx control subsystem, dubbed SPRINT™ by the turbine vendor. In fact, this was the core of project justification. At the peaking facility, it was to achieve remote operation.

A few of the candid lessons learned include the following:

      • The due-diligence team for the acquisition did not pay much, or any, attention to field instrumentation. Apparently, this is typical of due-diligence teams, and something others seeking to acquire plants should guard against.
      • While generally pleased with overall outcomes, the site representatives did note the Ovation team’s lack of experience with retrofits of machines from this type—for example, the turbine vendor locates I/O at the GT housing, while Emerson prefers to put the boxes in the control room (Fig 2).
      • Resolving disputes around the HMI (human machine interface) graphics and high-performance screen layouts was also a challenge.
      • The new owners discovered that the air permits for the peaking units were written in a way that prevented them from adequately conducting no-load tests. Only two starts per day were allowed if the units were not going to proceed to full load and compliance operation within 30 minutes.

Actuator acting up. Steam-turbine bypass systems and valves for combined cycles have been giving users fits for years. In one Ovation user’s case

, it was the actuators on the HP and IP bypass valves. It would do little good to show the list provided of what was wrong with the original actuator design, because essentially nothing was right with it. However, in fairness, it should be noted that this combined cycle, which came online in 2003, was originally designed for baseload service, but later began to cycle.

According to the facility reps, “the valve would go nuts” on a steam-turbine trip, and for good reason: It has to go from closed to 80% open (11.2 in. of valve stem travel), then throttle as if nothing happened, all in two seconds! Doing both well is difficult for a valve this size, they conceded. They also conceded that the actuator worked fine the first few years, suggesting that cycling may have been the root cause of their issues.

The original valve was fine, they said, but the actuator was poorly designed. For one thing, it was “full of O-rings, and other parts and pieces” and three derivative boosters (used with a positioner to increase stroking speed). Also, the rapid stem movement repeatedly broke the weld between the plug and stem.

The plant decided to go with pneumatic actuation because it would avoid oil leaks and fire hazards and the parts would be more readily available than for a hydraulic actuator. Emerson designed a bolt-on actuator (Fig 3), leaving the original valve in place, with far fewer parts and all the boosters of the same component. The new booster is three to four times the size of the original one.

According to these plant reps, the valve and actuator “haven’t been touched since” and the weld cracking issue has been resolved. Tuning is much easier and more consistent, and the control loop is more stable during startups.

Sabers for cyber. Protecting against cyber-intrusions and keeping the “bad guys” out consumes more and more of the digital control system community’s energy—and piles on costs. In addition, like environmental restrictions, there are multiple layers of compliance, standards, and jurisdictions.

During a cybersecurity panel, a representative from the US government’s Industrial Control System Cybersecurity Emergency Response Team (ICS-CERT, part of DHS) referred the audience to the C-SET, a cybersecurity evaluation tool. As described in a document available from ICS-CERT online, “it is a desktop software tool that guides asset owners and operators through a step-by step process to evaluate their industrial control system and information technology network security practices.” Available for free, users answer questions and the software generates a report comparing your practices to recognized government and industry standards and recommendations.

In addition to federal standards and recommendations, states are imposing their own, according to a consultant on the panel. New Jersey, for example, has mandated cybersecurity standards. He noted that costs for complying with mandatory requirements could be challenging for power producers in low-price markets. That includes most everyone in today’s world.

An expert from one of the largest combined cycles in the country, built in the early 1990s, explained how his plant went from “25 years of connecting everything to disconnecting from the sins of the past.” His plant had one supervisory control system for the entire plant, because it was designed to deliver all of its 1640 MW of capacity to one buyer as a baseload facility. The plant comprises 12 gas turbine/HRSG trains and three steam turbine/generators and, to complicate matters, two steam hosts and six packaged boilers.

Now they have to comply as a NERC CIPS 6 medium impact facility. “In the early days of compliance, we were patching one workstation every two to three days.” Plus, they are planning to add an 800-MW 2 × 1 combined cycle at the site.

Plant practices reported to the group included these:

      • Create action plans based on vulnerability assessment results.
      • Patch monthly to keep current.
      • Physical and electronic access control is key.
      • Use E-ISAC for threat intelligence.

The electricity information sharing and analysis center (E-ISAC) is operated by NERC but functionally isolated from its enforcement arm. It’s a central repository for physical threats, vulnerabilities, and incidents. According to information available from the program online, the following benefits are described:

      • Identify adversary campaign tactics, techniques, and procedures and share specific mitigation actions.
      • Reverse-engineer malware to better understand events and develop predictive capabilities.
      • Share tactical information to reduce cyber risk for all participants.
      • Cross-benchmark and evaluate with other critical infrastructure sectors.

TILs critical to 7EA inspection success

By Team-CCJ | April 19, 2022 | 0 Comments

The 7EA gas turbine’s many attributes—including generally high reliability and availability, and good efficiency in a wide range of applications on a variety of fuels—help make it the most popular mid-size (nominal 85 MW) industrial gas turbine. There are said to be about 1200 of these machines in service.

Annual meetings of the 7EA Users Group attract more than a hundred attendees, representing owner/operators from across the globe, to share experiences. Inspections and overhauls typically are a focal point of interactive discussions among users. Virtually everyone in the room wants to know what issues to be aware of, where they are likely to occur, what the indications look like, how frequently their engines should be inspected, etc.

The editors corralled Mike Hoogsteden, director of field services for Advanced Turbine Support LLC, which inspects scores of these machines annually, to learn how users can make their outages more productive and minimize the possibility of missing something that could contribute to a forced outage.

A good place to start, he said, is to review the OEM’s Technical Information Letters (TILs) pertaining to the 7EA, take notes, and bring your questions to the next user-group meeting. Your colleagues and participating suppliers are the best source of advice on what’s important and what’s not, Hoogsteden added. The knowledge gained will help you plan the optimal outage for your gas turbines.

Five TILs he suggested users become intimately familiar with are these:

      • 1884, “7EA R1/S1 Inspection Recommendations,” which addresses the need to inspect R1 and S1 airfoils for possible damage caused by clashing—the unwanted contact between S1 stator-vane tips and R1 rotor-blade roots during operation.
      • 1980, “7EA S1 Suction Side Inspection Recommendations,” which advises users to inspect for crack indications on S1 vanes made of type-403 stainless-steel, regardless of whether clashing damage is in evidence on S1 and R1 airfoils.
      • 1854, “Compressor Rotor Stages 2 and 3 Tip Loss,” which suggests blending and tipping to mitigate the impact on availability and reliability of R2 and/or R3 tip loss. This TIL supplements information provided by the OEM in the O&M manual provided with the engine.
      • 1562-R1, “Heavy-Duty Gas Turbine Shim Migration and Loss,” which informs users on the need to monitor the condition of compressor shims and corrective actions available to mitigate the risks of migrating shims.
      • 1744, “S17, EGV1, and EGV2 Stator-Ring Rail and CDC Hook Fit Wear Inspection,” provides guidance on the repair of dovetail wear and suggests hardware and software enhancements available to mitigate the potential risk caused by operating conditions that promote such wear.

There are many more TILs that demand your attention, to be sure. They include the following:

      • 1090-2R1, “Compressor R17 Blade Movement.”
      • 1067-R3, “Stage 2 Bucket Tip Shroud Deflection.”
      • 1634, “Stages 2 and 3 Bucket Low-Speed Rub Prevention.”
      • 1313, “Stage 3 Bucket Tip Shroud Overlap.”

TIL 1884

It took years for the OEM to address clashing in a TIL (Fig 1). Hoogsteden believes Advanced Turbine Support was the first company to alert the industry to this phenomenon—back in 2006. TIL 1884 was issued in spring 2013. During the intervening years, Advanced Turbine Support worked closely with the users to share inspection data important to problem definition and solution.

Developments in inspection technology contributed to a better understanding of first-stage findings and provided information of greater value for the resolution of issues. Follow this timeline: 2008, implementation of visible dye inspections; 2009-2010, measurements added to documentation (Fig 2); 2011-2012, inspection documentation with trending data reveals an obvious increase in damage year over year. Plus, the implementation of eddy-current (EC) testing suggests an elevated level of risk to owner/operators.

TIL 1884 went beyond clashing, recommending the checking of stator vanes for cracking in the co-called “area of interest” (Fig 3). Lock-up of vanes in carbon-steel ring segments can cause higher-than-normal operating stresses, which the OEM says “reach a maximum on the suction side of the vane near the mid-chord location.”

Cracking was first reported after TIL 1884 was published. In spring 2014, Advanced Turbine Support identified by way of dye penetrant two cracked S1 vanes in the same compressor. EC confirmed the findings. The company’s inspectors found cracks in more machines over the next several months. This experience revealed that some cracks can be too fine to bleed penetrant, as recommended by the OEM; however, EC was able to find them.

Hoogsteden’s suggestion to mitigate the possibility of serious damage from clashing and cracking is to perform an in-situ EC inspection to the trailing edges of all R1 rotor-blade platforms and the entire suction side of every S1 stator vane from platform to tip each peak-run season or every six months.

TIL 1980

TIL 1980, issued in January 2016, is viewed by the editors as an “addendum” to TIL 1884, addressing S1 vanes installed in legacy 7EAs (1996 and earlier) made of Type 403 stainless steel. This material is more susceptible to mid-chord cracking than the GTD™ 450 alloy used in the manufacture of vanes since 1997.

TIL1980 recommends inspection by visible means or by fluorescent dye to reveal suction-side cracks that might be present. Hoogsteden mentioned in his comments on TIL 1884 that these methods are inferior to EC for this purpose. He added that if the vanes are coated, visible or fluorescent dye penetrant inspections may not be dependable, nor have an acceptable probability of detection.

Regarding the effectiveness of ultrasonic (UT) inspection for this purpose, if coating degradation—such as disbanding—occurs, the value of UT could be compromised.

Advantages of EC Array include the following:

      • It can detect crack initiation faster than UT.
      • For coated vanes, the inspection equipment used by Advanced Turbine Support has the ability to maintain accuracy in flaw sizing (length and depth) for coating thicknesses of up to 0.125 in.
      • Superior to in-situ liquid-penetrant inspection, which may miss small cracks.
      • Two scans cover the entire suction face of a 7EA S1 vane.

Ultrasonic phased array can be used to supplement any suspect indications to confirm sizing of larger/deeper indications. But keep in mind that the UT probe does not cover the entire width of the stator vane—only about 0.75 in.

Hoogsteden went on to describe some of the damage found during its TIL 1884 and 1980 inspections, which go beyond what the OEM suggests. These are shown in Figs 4 through 8.

TIL 1854

TIL 1854, released in August 2012, informs owner/operators of E-class compressors about the blending and tipping of second- and third-stage rotor blades it recommends to mitigate the negative impact on availability and reliability caused by tip loss from heavy rubs (Fig 9) and/or corrosion pitting.

The OEM says fleet experience and engineering analysis have concluded that compressor rubs can be caused by casing distortion that progresses over time, and by hot restarts initiated between one and eight hours after shutdown. The latter causes critical clearances to decrease. Corrosion pitting, by contrast, can create a local stress concentration that may result in tip loss via high-cycle fatigue.

Hoogsteden pointed out that although this advisory does not address first-stage rotor blades, they too can suffer tip loss and should be included in your inspection regimen. For R1 and R2 rotor blades showing signs of tip distress, Advanced Turbine Support recommends, at a minimum, a visible dye-penetrant inspection to determine if radial cracks have initiated (Fig 10). For R3 blades, the company recommends a minimum of a 360-deg roll with a close-up inspection of all blade tips at the same intervals.

The editors asked the field-service director why his company espouses such conservatism when the OEM doesn’t. He said their recommendations are based on more than 1000 in-situ visible dye-penetrant inspections which have identified at least 64 cracked rotor blades and about half as many tip liberations.

TIL 1562

TIL 1562, issued January 2007, is likely the most familiar of the advisories in this group of five because it is more than a decade old and shim liberation has been discussed frequently in user-group meetings and in CCJ. Fig 11 provides a quick review. The left-hand drawing is of a typical shim, center photo shows a shim protruding from the compressor, right-hand picture is of a shim blended flush to the case because it couldn’t be removed completely without difficulty.

Hoogsteden recommends that users develop a shim map for their compressors to identify locations where shims might have been installed, then audit those locations for shims remaining. The map should be updated after every inspection. Shims protruding from the case by less than one-quarter of an inch should be monitored regularly. When the shim protrudes into the flow stream one-quarter of an inch or more it should be removed or ground off.

TIL 1744

TIL 1744, issued September 2010, said 7EAs operating at part load when ambient temperature is less than 40F are at risk for major damage caused by the lifting of 17th-stage vane segments. As the segments lift up they damage the hook fits and turn into the rotating blades.

A non-OEM repair procedure described at a user group meeting attended by the editors involved milling of the damaged slot to accommodate 18-in. inserts. They were installed in the upper and lower halves of the case to retain the new vane segments. The inserts are held in place with setscrews. The user describing the procedure cautioned against considering it a permanent fix because a root cause analysis had not been completed.

RO Part V: When to clean, how to clean

By Team-CCJ | April 19, 2022 | 0 Comments

This is the final part of a five-part series on the design, operation, and maintenance of reverse osmosis systems for powerplants compiled by Wes Byrne, U.S. Water’s consultant on membrane technologies. Parts I, II, III, and IV are identified below.

      • Part I: Value proposition, how it works
      • Part II: Importance of a pilot study in system design
      • Part III: Mitigating scale formation and membrane fouling
      • Part IV: System operation and monitoring

Chemical cleaning is a routine requirement for most RO systems. Frequency depends on the effectiveness of the pretreatment equipment.

As fouling solids or scale particles accumulate, their characteristics often change and they become more resistant to cleaning. Clay and biological materials will tend to compress against the membrane surface and become chemically resistant as water is squeezed out of their structure. Scale formations may change from being primarily calcium carbonate (relatively easy to clean) to calcium sulfate (difficult to clean).

The change in normalized RO performance variables can be used to determine cleaning needs. Most membrane manufacturers recommend cleaning before these variables change by about 15%.

Certain types of fouling solids or scaling salts may have a substantial impact on permeate quality. Aluminum salts may come out of suspension as a fouling particle, only to re-dissolve if the water acidity changes. This may then result in increased aluminum passage from the membrane surface through the membrane and into the permeate/purified water.

Calcium carbonate scale may leach a relatively high concentration of calcium carbonate through the membrane into the permeate stream and affect the conductivity. Most other fouling solids will not have a significant impact on RO salt rejection unless the fouling is extreme.

Membrane cleaning involves passing a cleaning solution through the membrane system at conditions that promote the dissolution or delamination of the fouling solids from the membrane surface or from the spacing material along the membrane flow channels. The optimum solution will depend on the particular fouling solids or scale particles, and the relative ability to clean will often be limited by membrane chemical tolerance.

Most strong oxidizing agents that would typically be effective in cleaning biological solids are not going to be compatible with the RO membrane. There will also be limits to the pH extremes that should be used. In addition, while higher temperature will increase the rate of cleaning, the solution temperature will be limited to below 105F or as designated by the membrane manufacturer.

The most critical characteristic of a cleaning solution is its pH. Acidic solutions are more effective in dissolving metals and scale formations, while alkaline (high pH) solutions are more effective in removing clay, silt, biological, and other organic solids. Strongly acidic solutions may stabilize biological solids and therefore should not be used as a first cleaning step. Finishing a cleaning with a strongly acidic solution will tend to leave the membrane with increased rejection characteristics but somewhat reduced permeate flow, while finishing with a strongly alkaline solution will have the opposite effect.

The addition of specific cleaning agents often improves the solution’s cleaning abilities. A chelating agent assists in pulling out metals from the fouling solids, while surfactants/detergents improve the solution’s ability to penetrate the fouling solids and suspend oily substances. The use of surfactants may reduce cleaning time but will increase the time required for rinse up.

When the fouling solids are causing a flow restriction, increasing normalized pressure drop, high cleaning flow rates (within the membrane manufacturer’s guidelines) through the membrane feed channels will cause agitation that will assist in breaking up the deposits. When the solids coat the membrane surface and reduce the normalized permeate flow rate, the delamination of these solids will be most easily achieved if water is not permeating through the membrane during the cleaning process and creating a force that holds the solids to the surface. This means cleaning at low pressure.

Achieving a high cleaning flow rate that is balanced throughout all of the membrane vessels usually requires that each vessel stage be cleaned separately. This also helps minimize the pressure required to push the solution through the elements. Cleaning solution is therefore pumped at high flow rates, as recommended by the membrane manufacturer. It is pumped at the maximum pressure required to achieve the target flow rate, but may be limited to 60 psi to reduce the potential for crushing or otherwise damaging the membrane elements.

The solution is directed in the normal feed-end direction of flow and the exiting concentrate stream is then returned to the cleaning tank at minimal backpressure. The flow direction may occasionally be reversed so that the solution enters the concentrate end of the stage when fouling solids are blinding the face of the lead-end membrane elements.

There may be a small flow of permeate that should also be returned to the cleaning tank using a separate line. In spite of its low apparent flow rate, the permeate should never be valved off because this may put certain membrane elements at risk of physical damage.

Data should be recorded during the cleaning process. With membrane surface fouling, it is difficult to gauge when original performance has been restored until the unit is rinsed and operated normally. If the fouling solids were causing an increased pressure drop in the RO, then the cleaning inlet pressure can be used as a measure of cleaning progress. If the pressure keeps declining, the cleaning is still removing fouling solids. If the fouling is severe, it may require a number of hours of circulation before the inlet pressure stabilizes.

Cleaning success is confirmed when the normalized pressure drop and normalized permeate flow rate return to their startup values.

HRSG best practices: Plan now for old age

By Team-CCJ | April 19, 2022 | 0 Comments

It happens to all of us. One day we wake up and realize, we’re not young anymore. You can, in the same breath, decide you need to do some things differently. Or, you can ignore it, and pay a larger price later.

The same thing is true with heat-recovery steam generators (HRSGs). Combined-cycle plants experienced the equivalent of the post WWII “baby boom” between 2000 and 2005 (Fig 1). These units are now in or approaching the second half of their 25-30-year design life.

The need to acknowledge this reality and plan accordingly was considered important enough that the Combined Cycle Users Group (CCUG), at its 2017 conference in Phoenix at the end of August, devoted the better part of a morning to the subject so that experts from HRST Inc could identify some the problems users could experience and possible solutions.

At an industry level, Bryan Craig noted that the general goal is to plan for and avoid similar ageing problems experienced with the fleet of fossil-fired boilers installed a generation earlier. The range of issues presented, and the photographic evidence from operating units, in the HRST slides is so extensive that users are strongly encouraged to access the original presentations. This article gives some highlights.

Like many fossil units, combined cycles often operate in ways not designed for—that is, less baseload and more cycling and dispatch. Some of the original design materials and methods may be questionable as well.

Creep and overheat damage in superheater and reheater tubes is the first problem Craig tackled. Most tube overheat incidences occur downstream of the duct burner and are caused by flame impingement. Flames should never make contact with tube metal yet they often do. Rules-of-thumb for flames are that they should be 6-10 ft long, they should be independent and separated, and reach one-half to two-thirds down the firing duct.

While users should view flames at least once daily, and preferably once per shift, through the unit’s viewports, a better idea is to install cameras in the firing duct on the walls, floor, and/or ceiling and wirelessly transmit the images to screens in the control room. Damage is often worse in areas difficult to view through the casing ports.

Up next were duct-burner problems, notably baffle sagging, cracking, and fluttering; flame-holder failures; coking; burner-nozzle cracking; and flow-distribution equipment failure. In the case of baffles, for example, they often sag under their own weight as the radiant heat weakens the metal. Because they also provide horizontal and vertical support to the burner elements, weakness in the baffles causes problems in the burners, such as fatigue cracks. Fig 2 illustrates the some of the issues with one type of burner and vintage, and the fix HRST has implemented.

Casings experience cracking and corrosion problems at the roof because of numerous piping penetrations, and on the sides where temperatures generally above 800F may exist. Unrepaired casing cracks can lead to graphitization and more extensive repair work. Of course, any cracks, especially in the roof, lead to rainwater ingress and insulation failures, which only compound problems with internal surface corrosion.

In the duct-firing area, there’s more insulation to protect against higher temperatures. However, when the burners are not running, this becomes the coldest area of the casing. If the temperature dips below the exhaust gas dewpoint, acidic condensation may occur, leading to rare cases of stress-corrosion cracking. High NOx environments, units with no SCR for example, are especially prone to SCC.

Ageing problems in economizers. Craig focused on the return-bend style of economizer design (different from panelized economizers). Much of the economizer’s weight is supported by the return bends, making them prone to corrosion fatigue. Startup thermal shock aggravates the situation. To address this, HRST has developed a retrofit support system that avoids any new pressure parts.

Craig offered suggestions and more robust inspection, testing, and assessments for addressing high-pressure evaporator waterside deposits and high-temperature piping. The API 579/ASME FFS-1 specification to assess “fitness for service” and remaining life should be considered for high-temperature piping. He noted that a “high percentage of welds being tested are problems.” For areas prone to corrosion under insulation, Craig suggested retrofitting vents and drains.

Steam drums demand regular inspection, continual attention

By Team-CCJ | April 19, 2022 | 0 Comments

Ever stop to think about what’s going on with your HRSG’s steam drums, out of sight for the most part and all wrapped up in insulation? Even if you were to hike up to the drum level what could you see?

Next question: How many people at your plant really think about the boiler? Their primary focus is at ground level, on the gas turbine/generators. The O&M team knows a great deal about the GTs given inspections every six months or so and the diagnostic instrumentation typically installed. Lifecycle data are tracked continuously.

How are you tracking the condition of your HRSG and its remaining life? Anything much more than looking for steam/water leaks and monitoring drum level and steam pressure/temperature, and an occasional inspection? At many plants, probably not.

That’s why the Combined Cycle Users Group (CCUG) steering committee invited HRST Inc’s Lester Stanley to talk about steam drums and their care at the organization’s 2017 conference in Phoenix at the end of August. He has been inspecting boilers of all types his entire professional career and likely crawls through more drums in a given year than the overwhelming majority of users do in a lifetime.

These thick-walled steel behemoths may seem indestructible, but they are very susceptible to life-threatening cracking and other problems when not properly operated and maintained. Stanley encouraged users to pay close attention to OEM-recommended warmup and cooldown procedures, closely monitor ramp rates, conduct regular inspections, and pay prompt attention to repairs suggested by experts.

He began his presentation, available to users online, with a quick primer on steam drums, their function, and refresher illustrations, and a list of five important drum components (Fig 1). Then he identified the five issues he would speak to:

      • Steam-purity degradation.
      • Drum-level-measurement piping condition.
      • Nozzle weld cracking.
      • Shell weld cracking.
      • Manway sealing reliability.

“Steam-drum performance and steam purity were probably carefully tested at commissioning,” Stanley said. But in the second half of life, “age is affecting the mechanical condition of the drum internals.” This can result in excessive water carryover. Specifically:

      • Primary and secondary separators get fouled with rust.
      • Fouling occurs in the final separators, increasing velocity and impairing moisture separation.
      • Gaps appear in the final separators, allowing wet steam to pass through.
      • Separator housing and supports fail from stress and also allow wet-steam bypass.
      • Errors occur in drum-level sensing, leading to higher water levels and less volumetric space for moisture to drop out; this is usually caused by level-transmitter calibration/compensation.

Detecting these problems is best done through more frequent saturated steam sampling, and even continuous on-line monitoring.

The condition of drum-level piping is critical for accurate level sensing. Age-related risks include plugging of sensing lines with debris and corrosion of the small-diameter piping. The latter risk grows with increased downtime. Removable insulation blankets exacerbate rainwater ingress. Solutions are to inspect under insulation more frequently and consider use of removable insulation with better protection against rainwater.

The focus for nozzle and shell weld cracking is the high-pressure (HP) drum but all steam drums should be inspected, Stanley urged. Although the intermediate-pressure (IP) drum is the least susceptible to weld cracks, it’s easy to include it in the inspection program for the HP and LP so you “sleep better at night.”

On/off cycling drives weld cracks in the HP drum. This causes temperature differentials between the shell and its nozzles because the drum pressure cycles across a wide range, such as from 0 to 400 psig. Problem is, there are numerous thick nozzles and shell welds in an HP drum. In the LP drum, internal pitting, leading to cracks, is the notable threat.

Stanley then spent considerable time reviewing several relevant inspection techniques and offered suggestions for how to prepare for and set up an inspection program. Perhaps the overriding message was, don’t try this at home; in other words, retain an experienced, qualified crew.

Manway reliability was Stanley’s final topic. The ageing risk is the deterioration of the gasket sealing surface over time from cleaning and removing old gasket material, impurities in water residue, gouging from steam cutting or closing damage, and corrosion during downtime. The gasket sealing surface has to be smooth but not “polished” smooth, and there’s more precision necessary in the serrations (like an album surface) than you might think.

There are a few specialists with the proper tools to re-machine the sealing surface, but sometimes replacing the door may be the best option. This allows you to ease the problems associated with achieving the minimum sealing stress for various types of gaskets. The proper seal stress is difficult to achieve with studs and a torque wrench because drum pressure in operation provides the last increment of stress necessary. Many HRSG OEM manuals require hot retorquing procedures, which are dangerous and should be avoided.

Stanley thinks a manway door with Belleville washers is a better design (Fig 2). Eliminating hot retorquing allows you to install a steam shield for additional personnel protection. Stanley noted that the Belleville washer design has gone through several years of demonstration in the field.

End notes. Encouragement for showing your steam drums greater respect might come from within if you think about the difficulty associated with making Code-qualified repairs to the thick-walled vessels and, in the extreme, replacing a drum. Fig 3, provided by Bremco Inc, offers some perspective.

Development of diagnostic tools and inspection techniques for tracking the life consumption of steam drums is ongoing. Someone at your plant should have the unofficial title of HRSG King (or Queen) with the responsibility for attending one meeting annually to keep up with these developments and the experiences of other owner/operators in their implementation.

If you don’t have a person on staff with deep HRSG experience, you might consider selecting someone from your O&M team to attend HRST’s rigorous three-day HRSG Academy (next session will be in Tucson, Ariz, Jan 23 – 25, 2018) to get the foundation necessary to help guide the plant’s boiler decision-making.

With a background in fundamentals, annual attendance at the HRSG Forum with Bob Anderson is recommended by the editors to keep up with technology, methods, procedures, equipment, services, etc, of importance.

Finally, it’s vitally important to incorporate the latest experience into your specifications for new HRSGs. Electronic cutting and pasting of a years-old spec will restrict your capabilities in such things as fast starting, fast ramping, etc, and possibly leave you vulnerable to current issues—such as poor control of attemperators and steam bypass systems.

Modern control systems and upgraded materials enable reduced drum storage volume, smaller drums, and thinner shells. Use of stack dampers, high-quality valves, steam sparging, robust modern instrumentation, etc, can maintain drum metal temperature above the recommended minimum during shutdown periods to maximize life.

Consider the impact of new operating regimes on your SCR

By Team-CCJ | April 19, 2022 | 0 Comments

It’s easy to forget about the “big box” selective catalytic reduction (SCR) unit sandwiched in your HRSG modules, even though it stands between you and compliance with your air permit, and your ability to operate.

At the 2017 conference of the Combined Cycle Users Group (CCUG), held in Phoenix the last week of August, Andy Toback, Environex Inc, did his best to remind users that SCR process parameters have to be re-evaluated when gas turbines are upgraded, plant operating tempos change, duct-burner operation is more prevalent or variable, and/or the latest G and H technology machines are being deployed. Otherwise, you may be leaving money on the table or setting yourself up for unexpected costs and performance issues down the road.

Toback’s main message is that you need to adjust the original design expectations for the SCR based on real-world operating data, the key to optimizing the process for new conditions.

For an actual 7FB.01 to 7FB.04 upgrade, for example, the new combustors added 7 MW of output and lowered turbine NOx levels entering the SCR (Fig 1). Because the catalyst going forward typically will convert 9 ppm NOx levels from the turbine, compared to the original design of 25 ppm, the relative catalyst activity level, representing the expected end of life, can now be projected out beyond 10 years (Fig 2), compared to 5.5 years with the original combustors.

Ammonia consumption and ammonia slip at the stack also are reduced significantly because of the lower NOx conversion requirement for the SCR system. Due to the improved combustor dynamics, gas-turbine CO levels are not expected to change even though the NOx levels have decreased.

Toback’s second example is a 7FA.03 to 7FA.04 + DLN 2.6+ upgrade (Fig 3). The good news is that the megawatt output gain was higher than expected, another reason why actual measurements are important. However, peak-load fuel and exhaust flows increased accordingly, the turbine exit NOx levels did not change appreciably, but the SCR temperature increased by about 20 deg F after the upgrade.

The original Dot 03-machine catalyst design life projection was about 21 years. The upgrade design expectation reduced it to around 13 years. Based on the actual operating data, however, the catalyst life should be more like 18 years (Fig 4). Both an expected increase in engine NOx from 9 to 10.4 ppm and higher exhaust flows impair catalyst life, but because the actual operating data showed no change in gas-turbine NOx levels, the minimum catalyst-activity requirement did not increase as much as anticipated.

For advanced G and H machines, the news isn’t so good. Toback states, “We’re being asked to achieve the same 2 ppm NOx and ammonia-slip levels (typical of the toughest permits) even though these machines have five times the turbine-exit NOx levels.” Plus, they likely will be required to cycle and operate at less than design output for significant operating hours over their lifetimes.

Fig 5 indicates that for these performance specifications, you’ll either have to accept high operating and compliance risk at the ragged edge of the capabilities of traditional single-bed SCRs or resort to a more complicated and more expensive SCR design.

When you operate advanced-technology machines at low loads, you tap out the capabilities of the design (Fig 6). “The ammonia injection grid can’t handle both the NOx levels at the maximum design output and what would be typical at 30-50% load, because of the corresponding changes in mass flow, temperature, and mixing.”

Environex specialists believe owner/operators of G- and H-class machines will have problems because vendors are supplying SCRs with inadequate catalyst volumes. It’s also important to consider adding a permanent grid made of stainless-steel tubing within the HRSG housing which allows you to periodically take 2-D distribution-grid measurements for NOx and NH3 and more accurately tune the AIG distribution valves.

Such capability nominally adds about $50,000 to the budget, a sum that looks paltry compared to the penalties of non-compliance.  The high NOx conversion requirements for these systems coupled with low ammonia-slip limits decrease the tolerance for non-ideal ammonia-to-NOx distribution. You should expect this to increase the required frequency for ammonia-grid tuning.

Duct burners, of course, are another source of NOx and CO which must be accounted for through real operating data. SCR inlet NOx can more than double at design GT output and full duct firing and the SCR operating temperature can climb by 50 to 100 deg F. Inlet CO, meanwhile can decrease. During interim periods as duct burners come up to full capacity, or remain at part load, NOx and CO emissions can be quite variable. These impacts can be quite striking if your unit was designed for baseload operation.

Generally, Toback concludes, increases in exhaust flow to the SCR impairs catalyst life, while decreases in SCR inlet NOx and CO emissions and increasing SCR operating temperature extend it. If your machines are no longer operating the way the SCR was designed, it’s time to consider a program to acquire the operating data needed for optimizing the SCR process for new conditions.

How natural-gas fuel variability impacts GT operation

By Team-CCJ | April 19, 2022 | 0 Comments

Natural-gas fuel composition has considerable influence on gas-turbine emissions and operability. This might not have been a concern to you previously, but the possible impacts on your engines of increasing reliance on non-traditional pipeline gas—in particular, shale gas, but also LNG, and byproduct fuels from industrial processes—suggests you might want to read on.

Even if you have “good gas,” be aware that the negative impacts of gas-constituent variability can be magnified by the high firing temperatures of today’s most advanced gas turbines, Scott Sheppard, Ben Emerson, and Tim Lieuwen of Turbine Logic told the editors. Reason is that these machines must “work harder” to achieve low-NOx emissions and thus have fewer “knobs” to mitigate fuel-composition impacts, the trio added.

The Wobbe and Modified Wobbe indices are two standard properties used in practice to determine the effects of fuel variability. But they only indicate the changes in heating value and usually cannot describe how changing fuel composition will affect emissions and some potentially damaging operability issues.

Aside from NOx and CO emissions, there are four operability issues of importance to plant personnel. They are:

      • Blowout, or when the flame physically exits the combustor; also referred to as blowoff.
      • Flashback, or when the flame moves upstream into premixing sections not designed to withstand high temperatures.
      • Combustion dynamics, or the damaging pressure oscillations associated with oscillations in the combustion heat release.
      • Autoignition, or the spontaneous ignition of a reactive mixture of fuel and air in the premixing section of the combustion chamber. The effects of autoignition and flashback are the same, but the underlying reasons and fuel sensitivities are completely different.

These four issues, which the Turbine Logic team routinely observes when performing root cause analyses, pose risks to gas turbines and are closely tied to operating conditions and fuel composition.

Before discussing the impacts of fuel variability on gas turbines, Sheppard, Emerson, and Lieuwen said it is important to understand the composition of natural gas, which in North America typically contains 85% or more of methane. The next most common constituent is ethane at about 7% or less, followed by propane at about 1.5% or less. Other components include other higher hydrocarbons, nitrogen, carbon dioxide, and hydrogen. From an operability point of view, it is convenient to divide the fuel constituents into three buckets: higher hydrocarbons, hydrogen, and diluents.

As previously mentioned, the Wobbe Index and Modified Wobbe Index both describe the effect of fuel composition on fuel heating value, with the Modified Wobbe Index also accounting for fuel temperature. In addition to Wobbe Index recommendations, OEMs typically include a fuel specification for their gas turbines on levels of higher hydrocarbons and hydrogen. By operating within these recommendations, operators generally can avoid some of the operational issues mentioned earlier. However, the combustion-dynamics issue is particularly sensitive and difficult and is an issue that must be actively monitored and managed by operators, the trio stressed.

There is a relationship between some of these operability issues and Wobbe Index—for example, higher ethane and propane contents in fuel leads to a higher fuel heating value, which also increases autoignition risks. Nonetheless, two fuels with the same Wobbe can have substantially different blowout, flashback, combustion-dynamics, and autoignition tendencies. Thus, Wobbe Index alone cannot be used to ensure safe, reliable operation.

Effects of fuel composition on operability

The operability concerns described below by Sheppard, Emerson, and Lieuwen apply mostly to dry-low-NOx/dry-low-emissions/ultra-low-emissions (DLN/DLE/ULN) systems. They are much more prone to these issues than diffusion systems—most notably combustion dynamics, which are a product of combustor design and the effort to keep NOx emissions as low as possible. Diffusion systems do experience some dynamics issues near blowout, but they can be avoided by operating with a sufficient blowout margin.

Blowout. One of the biggest factors impacting flame blowout—also known as blowoff or lean blowout (LBO)—is the flame speed of the different fuel mixtures. Flame speed is the speed at which the flame moves through the reactants during combustion. Hydrogen addition has particularly significant impacts on increasing blowout margin because of its much higher flame speed than methane.

Propane and ethane also have higher flame speeds, but the effect is much less significant than hydrogen. By contrast, diluents (particularly CO2) reduce blowout margins as they act to reduce the fuel’s flame speed.

Takeaway 1: Increases in diluents pose the greatest blowout risk.

Flashback. As previously mentioned, the presence of hydrogen and higher hydrocarbons can move a flame upstream into premixing passages. Swirlers, fuel lances, and premixing passages are not designed to withstand the high temperatures that would occur with a flame in the premixing section and can quickly sustain damage.

In some events, this hardware may liberate and travel downstream through the power turbine, causing catastrophic damage. Loosely speaking, flashback can be thought of as the “opposite” of blowout; for this reason, the H2 level limits in DLN system fuel specs are set by flashback margin.

Takeaway 2: Increases in hydrogen content pose the greatest flashback risk. 

Combustion dynamics. Fuel composition directly affects combustion dynamics. However, in contrast to other operability concerns, the effect is non-monotonic with operational parameters which make it particularly difficult to predict. For example, while increasing H2 levels always will decrease flashback margin, combustion-dynamics amplitude can either increase or decrease, depending upon other operating conditions.

Takeaway 3: Changes in fuel composition may decrease combustion dynamics, increase combustion dynamics, or have no effect at all. 

Combustion dynamics pose a direct threat to combustion liners, transition pieces, and cross-fire tubes. If the combustion-dynamics amplitudes are severe, liberation of these parts may occur, with hardware travelling downstream through the power turbine. Combustion instabilities can also lead to blowout and flashback.

Because of the sensitivity of combustion dynamics to the details of the flame configuration inside the combustor, dynamics are sensitive to all changes in fuel composition—that is, changes in higher-hydrocarbon, hydrogen, or diluent content. Note: In this case, the risk is changes  rather than increase. The Turbine Logic combustion dynamics monitoring group has observed increased challenges with dynamics, and the need for more frequent tuning because of gas composition issues.

Autoignition. Hydrogen and higher hydrocarbons also significantly decrease autoignition temperature and times, leading to increased autoignition risks. While symptomatically similar to flashback, the physics of autoignition is different. In this case, if the autoignition time of the fuel mixture falls below its residence time in the premixing tubes, the fuel mixture may spontaneously ignite in the premixing zone.

Similar to flashback, autoignition can damage premixing passages, swirlers, and fuel lances.  As with any of these other operability issues, liberation of any of these parts poses a threat to the power turbine. Fig 1 shows the how quickly autoignition times decrease with increasing amounts of ethane and propane in natural-gas fuel.

Takeaway 4: Higher hydrocarbons (especially when coupled with the higher compressor discharge temperatures of aeroderivatives) pose the greatest autoignition risk.

Nitrogen oxides. There are two main NOx formation pathways:

      • NOx produced in the flame, which generally is a few ppm and heavily influenced by fuel composition.
      • NOx produced post-flame, which really only depends on flame temperature.

Thus fuel composition influences on NOx emissions are somewhat dependent on the nominal NOx emissions of the gas turbine. Assuming the firing temperature stays fixed as fuel composition varies, for units with relatively high NOx emissions (nominally 15 ppm and higher), NOx production is dictated mostly by the firing temperature and is largely insensitive to fuel composition.

On the other hand, units that have fairly low NOx emissions (less than 5 ppm) will see a significant effect from changes in fuel composition. Data suggest that NOx concentrations may even double with changes in fuel composition for such low-NOx systems. Fig 2 shows how much NOx production can increase, in the low-NOx case, with increasing amounts of ethane and propane in natural gas.

Takeaway 5: The lower a gas turbine’s NOx emissions, the greater the impact of fuel composition on those emissions.

Carbon monoxide. The effects of fuel composition on CO production are largely controlled by whether it moves the system closer to, or farther from, lean blowout. If the unit is near LBO, CO emissions typically already are high, but can still be raised significantly by the presence of higher hydrocarbons and hydrogen in the fuel. Away from LBO, CO emissions may still rise with the addition of higher hydrocarbons and hydrogen, but the effect is quite small.

Takeaway 6: Similar to blowout, increased diluent content poses the greatest CO risk.

Recommendations

A fuel treatment system will mitigate the fuel-variability effects on each of the operability issues discussed above, Sheppard, Emerson, and Lieuwen said. These systems are equipped for removing solid particulates and higher hydrocarbons. The latter is accomplished by condensation and liquid removal.

Most OEMs also recommend some degree of fuel superheating before use in a gas turbine to ensure that no fuel condenses before reaching the fuel nozzles. Condensed fuel can cause significant autoignition issues, the trio warned. Even with a good fuel treatment system, small concentrations of liquid hydrocarbons from the fuel gas remain a risk when liquids are entrained from the liquid knockouts. This may occur with higher hydrocarbons, because the knockouts fill more quickly and require more frequent draining than experience might dictate.

Along with Wobbe Index recommendations, OEMs issue fuel specifications for their units. They are designed to accommodate blowout and flashback margins, and those phenomena should not occur when operating within the specs. However, even when operating within the recommended specs, combustion dynamics and emissions may be impacted by changes in fuel composition.

The greatest operational risk that cannot be managed by staying within OEM fuel guidelines is combustion dynamics. The Turbine Logic experts strongly recommend users have a combustion dynamics monitoring system (CDMS) to warn of impending issues, and also have protocols in place for ensuring sensors are healthy; plus, appropriate notifications if levels exceed alarms.

In their experience, every engine monitored by Turbine Logic has had multiple dynamics excursions exceeding thresholds as the ambient temperature and load varied. The need for shorter tuning intervals only can be confirmed by CDMS.

Several options are available to control loud combustion instabilities, and all are used by manual- or auto-tuning systems. These include varying the fuel temperature within the OEM spec, altering the fuel staging, increasing the non-premix pilot fuel, varying the amount of inlet air chilling, and varying the amount of steam/water injection. De-rating is the last resort.

To complicate things, because of the non-monotonic nature of combustion dynamics, a change in fuel composition can alter the unit’s response to each of these operational changes. Since combustion dynamics don’t have a one-to-one relationship for different operating conditions, installation of a CDMS can provide great insight into how your units respond to different operational changes. CDM systems provide nearly instantaneous feedback and will facilitate the building of a knowledge base around how your units behave regarding combustion dynamics.

If you continue to have combustion-dynamics issues while keeping NOx concentrations within regulatory limits, consider installing an auto-tuning system. It monitors dynamics and emissions and has control logic to minimize emissions while keeping combustion dynamics within acceptable limits to prevent hardware damage.

Auto-tuning systems typically have the ability to regulate several operational parameters— including firing temperature, fuel splits, and even fuel-split schedules. When either dynamics or an emissions excursion occurs, auto-tuning systems step in and nudge these parameters to return the gas turbine to safe and compliant operation. While seasonal tunes remain a good idea, and sometimes a necessity, the auto-tuning system will handle the day-to-day changes that gas composition variability may introduce.

Questions? Contact Sheppard, Emerson, or Lieuwen at connect@turbinelogic.com or 678-841-8420.

 

Paul White’s legacy

By Team-CCJ | April 19, 2022 | 0 Comments

When Paul White crossed over to the spiritual world from the physical Nov 16, 2017, he was well prepared for the journey and certainly was welcomed by those who had preceded him. White was a deeply religious man who taught Sunday school and gave church activities his full support—all while excelling in his engineering day job, and contributing to gas-turbine user-group initiatives with his deep technical knowledge and considerable people skills.

The challenge in writing an obituary for an exemplary human being and professional is that it never really meets your expectations, and likely those of the many readers who knew White well—there’s so much to say. Perhaps the best way to honor such an individual is to keep him in your conscious mind to help guide your thinking. You might ask yourself when dealing with a knotty problem: What might Paul have done in this situation?

The editors knew White best from his involvement in gas-turbine user groups. His highlight reel includes leadership roles in the following organizations:

      • 7F User Group steering committee member from just prior to the millennium until retirement as a full-time Dominion Resources Inc employee in the first quarter of 2013. He was a past chairman of that august organization.
      • Combustion Turbine Operations Technical Forum (CTOTF™), leadership committee member for many years—including several as chairman of the GE Roundtable and the Siemens Roundtable.
      • Combustion Turbine & Combined Cycle User’s Organization (CTC2), past chairman of the steering committee.

White was among the industry’s best discussion leaders and a great asset in any Q&A session having to do with gas turbines. He was successful in getting his point of view across without raising his voice or denigrating anyone’s opinion. His approach was debate, yes; argue, no. White’s technical knowledge and calm demeanor earned him industry-wide respect. One example: He was recognized by the Combined Cycle Users Group in 2015 with its Individual Achievement Award.

White took great pride in his ability to recognize talent from afar, recruit those individuals, and mentor them to the point where they could advance on their own and expand the capabilities of the gas-turbine technical support organization he led. White made it a point to bring new members of his team to user-group meetings and introduce them to as many participants as he could. He knew well that building a proper network to aid in decision-making was vital to success for both the employee and employer.

The registered professional engineer (North Carolina) also knew that he could not properly motivate and lead without keeping up with generation technology. White participated in many technical symposia over the years, several focusing on new materials and cooling schemes for gas turbines.

Consider that from the time he graduated from North Carolina State University in 1974 with a BS in Mechanical Engineering—two years after the nominal 52-MW GE Frame 7B was introduced—until he retired from Dominion as a part-time employee in December 2016—shortly after the 384-MW GE 7HA.02 became available—turbine inlet temperatures increased from about 1800F to 2900F.

Career profile

1974—Bechtel Power Corp, nuclear focus, design and field engineer.

1978—Duke Power Co, senior engineer, gas turbine (and steam turbine) technical support.

1997—Duke Energy North America, director of engineering, responsible for strategic turbine expertise in both current and developing technologies.

2000—Dominion Resources Inc, manager of O&M, provide technical support and strategic management for a fleet of about 75 gas turbines, spanning legacy to advanced technologies.

2016—GT & ST Consulting Corp, shop build surveillance on complete component and unit assembly tasks for Dominion’s first J machine.

Remembrances from. . .

Bob Kirn. Amidst the early 7F Users Group meetings that were more of a fruitless slugfest between the OEM and a handful of owners suffering from bucket munching turbines,  there emerged an individual who, while already known as a steady hand and cool head, would become one of the stalwarts of the gas-turbine industry.

Paul White, with his steadfast, oft-repeated belief that problem resolution could be best accomplished through cooperative efforts punctuated by full disclosure and free discussion, was quickly recognized by the user community as one who could be trusted to not only “find the solution” but to—and of such greater importance—“share the solution.”

His successful method of cooperative effort was so widely recognized that even GE invited him to speak to their services group in the company’s efforts to foster a more cooperative approach to customer service. Paul had made a lifetime of sharing his talent and he agreed to participate, and with the same level of honestly and enthusiasm that he approached everything.  No doubt the subsequent and on-going success of the 7F Users Group is a legacy to the open-forum structure he promoted and to the personal qualities that he so strongly displayed.

For more than two decades, Paul and I exchanged information, sought and offered advice for never-ending calamities and frequently crossed paths on the user-group circuit.  His commitment to finding solutions and providing the best information possible to anyone who asked never wavered; nor did my personal pleasure in seeing him at meetings and being able to swap stories, bounce new ideas, or just share a genuine handshake.

Christa Warren. Paul was the best manager and mentor I ever had, and will always remember what I learned from him. Thanks to Paul, I had to opportunity to join the gas-turbine industry and work with him. He created a legacy that will live on through all of his mentees. Wherever and whenever his name comes up it always results in a positive comment; no matter whom you talk to. Even I catch myself thinking, “What would Paul have done?”

He presented himself and his team with such class, humility, and respect he made everyone around him feel valued and respected. I will never forget how he would refer to all colleagues as his friends, and how when he described your role on our team he made you feel like a million dollars. It is sentiments like this that make people remember Paul for who he was. Although he will be deeply missed, the impact he made on those around him will continue to resonate through the years.

Sam Graham. Of all the good things I can say about Paul White, the one that stands out the most is his wonderful character. Paul was a true gentleman in every sense of the word, which was obvious to everyone around him; he was a genuine pleasure to be with. Paul worked constantly to mentor younger engineers and to make a positive impact on the 7F Users Group. He was a great contributor to the user community and a long-serving member of our steering committee.

You could always rely on Paul to provide a composed and thoughtful voice to any situation. His wisdom and self-control were vital during the hard conversations required with the OEM when these machines were in their infancy. Paul could be counted on when times were rough, always with a warm heart and a smile. This industry, and this world, could certainly use more people like Paul. He will be greatly missed.

John Gundy. We remember Paul White as a loving and devoted family man, mentor, and friend. Not only was he caring and compassionate, Paul was humble, adventurous, and enjoyed life, sharing his faith with those around him—which was something special. His contributions to the industry and willingness to teach others from his life’s lessons were priceless. I was blessed to be hired by Paul, and he mentored me before I took on the role of engineering manager for Dominion Energy’s Combustion Turbine Operations. Paul will be missed at Dominion Energy and by the many friends he made throughout his career.

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