Changing the way the Power Generation Industry buys parts.

CTOTF: Offering total plant solutions and coverage of all GT models

Attendance by owner/operators at user-group meet­ings typically has been off year-ago numbers by 10% to 20% since last fall. The major reason is travel restrictions imposed by company manage­ment because of the eco­nomic downturn. The old adage, “Penny wise, pound foolish” comes to mind.

There is no doubting the value of attendance at user-group meetings. Most participants bring back to their plants ideas, imple­mented at little or no cost, that improve operation, maintenance, safety, etc. A tenfold return on the cost of attendance typically can be proved, according to TVA’s Bob Kirn, who chairs the Combustion Turbine Opera­tions Task Force (CTOTF).

Perhaps one of the reasons executives won’t exclude user-group meet­ings from the restricted travel list is because they don’t know how much the lessons learned from these conferences can impact their bottom lines. That’s where you come in. It’s nec­essary to document what you learned, what that knowledge means to the company, what you imple­mented, what you saved, etc, and send the message “uptown.”

No one knows this better than the CTOTF executive committee (organization chart): Kirn, Eddie Mims of Colectric Partners, Ray deBerge of AmerenUE, and Rich Evans of NAES/Wolf Hills Energy. All are generation executives who understand how corpo­rations “think.”

To facilitate communica­tion between meeting partic­ipants and their respective organizations, the executive committee recently launched a “Value Minutes” initiative. Its goal: Capture key les­sons learned/best practices from each of the roundtable discussions and make them available to all attendees.

The purpose of this is two­fold: (1) Provide bullet points for trip reports to demon­strate the value of atten­dance, and (2) Give regis­trants not able to participate in one or more roundtables a summary of key discus­sion points. Specific items of interest can be followed-up by speaking with the session chair or vice chair.

The second point is a particularly impor­tant one for CTOTF attendees. This organization offers a much broader technical program than any other user group serving the gas-turbine-based powerplant sector of the electric power industry; concurrent sessions are a neces­sity. The only way to cover the gamut of subject matter is to bring others from your plant or catch up on the highlights via Value Minutes.

CTOTF always has been the optimum meeting on the industry calendar for managers and engineers responsible for multiple GT models because all receive air time—Eddie Mims, the executive vice chair for turbines, sees to that. One meeting keeps you up to speed on what you need to know across the board. Mims’ lineup card features individual roundtables for Pratt & Whitney engines (FT8s and FT4s), GE aeros, and GE, Siemens, Mitsubishi, and Alstom frames.

The executive committee, formed after Kirn became chairman last year, has streamlined decision-making and facilitated the imple­mentation of new ideas. One result: Roundtables have been added to the program to satisfy the diverse infor­mation needs of today’s managers.

To illustrate: A fallout of the dereg­ulation movement in the generation sector is that managers of merchant plants now are responsible for the step-up transformers and high-voltage switchgear needed to deliver power to the grid. When vertical integration was the utility industry model, the T&D group generally took care of this equipment.

CTOTF launched a gen­erators roundtable and a high-voltage electrical roundtable—both chaired by RRI Energy’s Jack Borsch—to bring asset and plant managers up to speed in areas where they generally have little experience. Like­wise, the new combined-cy­cle roundtable, chaired by Salt River Project’s Mike Rutledge was established to address the integration of gas and steam turbines and heat-recovery steam genera­tors. Traditionally, STs and HRSGs have not been dis­cussed at GT user meetings.

Finally, everyone who goes to a baseball game hopes someone will yell “foul ball” if a scream­ing liner is headed in their direction. To make you aware of the foul balls in the generation business, the executive committee has repurposed its plenary session into an industry issues round­table. Also, the generic roundtable has been refocused and now addresses O&M and business practices.

Four intense days at every CTOTF conference—spring and fall—deliv­er significantly more presentation/discussion time than you’ll find at any other user group event. There’s also a vendor fair at every meeting. And plant tours when warranted. And Professional Development Units (PDUs) for those who need to main­tain professional certifications. And a Super Champions Advisory Board with subject-matter experts who interface directly with the executive committee on questions related to meeting content.

For more information on the user group offering the only program for total plant solutions, contact Wickey Elmo, group and meeting coordinator, wickelmo@ctotf.org, 704-753-5377.

Find, attract, retain the best people

Evans, CTOTF’s executive vice chair for power systems, is a “people per­son.” As a plant manager (day job), he knows that top talent is critical to achieving the owner’s expectations with respect to starting reliability, availability, efficiency, safety, etc.

Evans is the force behind CTOTF’s initiative to identify and attract promising technicians and engineers to the gas-turbine-based sector of the electric power industry and to make sure that the career rewards are in place to retain them. He invited industry leaders to a panel discus­sion on the subject to help attendees understand what works and what doesn’t when they are looking to replace or add employees.

The bad news was that half the panelists never made it to Tucson because of the extreme flooding in Houston last fall; the good news was the three panelists who participat­ed—Dan Scarborough, SVP, NAES; Dale Linaweaver, VP, Constellation Energy; and Dave Areghini, associate GM, Salt River Project—never ran out of ideas and experiences to share. A few are presented below to offer a flavor of what was discussed.

Evans started the program rolling by asking, “What processes do you use to identify high-quality can­didates for a position? The consen­sus reply was that there are only three ways to get people: attract from the outside, grow internally, or “steal” from someone else. Internal growth is preferred. Attitude is all-important and something that can­not be taught; the employee must bring that to the table.

When someone leaves, there’s an opportunity to rethink what you’re doing, the panelists agreed. Busi­ness processes, goals, objectives are in continual change. What should be the responsibilities of the position moving forward? What type of person is best qualified to achieve the new objectives? As soon as you finalize job requirements and think you know the type of person needed, move for­ward with dispatch. Your candidates are other’s candidates. Stress refer­rals and have a rewards system in place; people rarely suggest an inca­pable candidate.

Evans asked, “What are the char­acteristics of a good employee? A per­son who enjoys what he or she does, thirsts for more knowledge, has an ability to admit mistakes/make cor­rections/move forward, team player, flexible, commitment to excellence.

He followed this up with “What can companies do to adapt to the require­ments of the emerging workforce?” Broaden the recruiting approach without losing site of what made your company successful. Don’t become enamored with new gimmicks for finding people. Today’s workforce is diverse—age, ethnicity, educa­tion, etc. Different groups—working mothers, for example—have differ­ent priorities. In this case it might be flexible work schedules. Companies should be able to provide opportu­nities that help employees achieve their personal goals.

A question from the audience: “What are your companies offering new hires regarding real estate?” The panelists offered phrases like “tailored moving packages,” “adjust­ments for special needs.” But the bottom line basically is there are virtually “no offers to cover housing losses.” One of the panelists noted that the equity issues are “scary” and the real problem is getting HR to recognize how not addressing them is adversely impacting the company’s ability to attract the people it needs. Consensus: Most companies are very rigid and have to change.

“What are key retention factors?” Respected for contributions to the organization, have potential for advancement, “growing” profession­ally in the job, family happy in the area, good place to work, competitive compensation package, etc.

Evans’ next question: “How do you minimize the potential for a bad hir­ing decision and what do you do when you’ve made one?” Rigorous due dili­gence/reference checks are the first step. Listen to what your gut is tell­ing you. If something just doesn’t “feel” right based on your experience, go no further.

It’s good to have a six-month pro­gram with deliverables as part of the hiring process. If the new employee doesn’t quite measure up but shows some promise, you might offer a development program to help the person improve. Or not. One panelist suggested caution regarding excuses such as “wrong job for the person,” “wrong supervisor.” Rarely the case, he said. It’s just a bad fit—person to company.

Question from the floor: Would people rather work in a base-load plant or a peaking plant? All panel­ists agreed that nuclear workers are far more likely to switch to peaking plants than vice versa. At peaking facilities, empowerment comes with the job and many people like that. Nuclear is very rigid, one panelist said, but “you’re it” at gas-turbine-based generating plants. At the lat­ter, employees are measured on their ability to deliver power when needed; it’s demanding work. “Nuclear is safe employment,” he added.

7B reliability upgrades

Most presentations by owner/opera­tors at user-group meetings are brief—10-15 minutes, 10 slides or fewer. So when Joe Pineda, PE, manager of GT maintenance for Jacksonville’s munic­ipal utility (JEA), stepped up to speak to the three dozen or so legacy-round­table attendees at last fall’s meeting in Tucson about Frame 7B improve­ments, if that’s what you expected you got fooled.

Session Chair Steve Hedge was held hostage to Houston floods, so Mims opened the roundtable with some brief comments and turned the podium over to Pineda. It was about 0815. Pineda was just getting warmed up by the coffee break and not quite done by lunch. The half-day session was extended, Pineda return­ing after lunch, full audience in tow, to finish up.

There was a lot of interest in the presentation because many 7Bs are still in service, most installed in the mid 1970s. So the assets essentially are at “end of life” in financial terms and owners are faced with ques­tions such as these: Do you invest to keep this seemingly indestructible engine in operation? If so, what’s the duty cycle and how much can you afford to spend? What are the prior­ity upgrades?

Pineda helped participants answer those and other questions with a com­pelling history of JEA’s four 7Bs that focused on upgrades and reliability improvements to controls, instrumen­tation, turbines, compressors, and auxiliaries over a period of more than 15 years. Another area addressed was compressor-bolt issues.

Background. Each of the 7B dis­tillate-only peakers typically operates from 100 to 400 hours annually and has 100-200 starts. The company’s 90-MW reserve requirement is met by two of the engines, which can synchronize with the grid within 10 minutes of starting and be operat­ing at full load (50 MW) five minutes later. First-start reliability was 80% in the 1980s and in the high 80s/low 90s in the 1990s, making the case for upgrades.

Controls upgrade to Mark VI

The original controls, Speedtron­ic™ Mark II, had been changed to Woodward Netcon 5000™ in the mid 1990s. Pineda characterized the lat­ter as reliable and well thought out. But critical parts became difficult to obtain after GE bought this por­tion of the Woodward Controls Inc (Loveland, Colo) product line so JEA changed controls again during 2007-2008 to Mark VI Simplex. EX2100 exciter controls and an upgraded generator protection panel (GPP) were included (Fig 1).

First question Pineda answered: Why the Mark VI? Standardization and minimum parts inventory, pri­marily. JEA’s assets included two 7FAs in simple-cycle service, two more integrated into a combined cycle—all have the Mark VI. Plus the Mark VI controls the combined-cycle HRSGs, steam turbine, and balance of plant; and it is installed on two conventional fossil-fired units.

Another reason: Personnel. JEA has highly qualified internal resourc­es for Mark VI programming and troubleshooting. Significant market penetration by the Mark VI makes it relatively easy to find qualified troubleshoot­ing/tuning/repair techni­cians when more hands are needed. Also, having one controls platform minimiz­es personnel requirements. Finally, with assets at three different sites, having one type of control system facilitates troubleshooting from a central location.

Yet another reason: Technology advantages. Pineda opined that the Mark VI has better engineering tools than Netcon 5000 and offers better trending capability. It also facilitates forcing of points and handling of ter­minations. Plus, Cimplicity allows HMI redundancy, permitting opera­tion from multiple locations (Figs 2, 3).

However, the Mark VI is not a “perfect” choice. Disadvantages include the following: more expensive to purchase and repair, some control blocks can be programmed only by the vendor’s personnel, and signal tracing/troubleshooting sometimes is not as intuitive with the OEM’s Tool­box software as with some other sys­tems. Also, on the JEA project, field service personnel were not allowed the flexibility to make all customer-requested mods.

The conversion to Mark VI was done in two phases—two turbines per phase. Pair selection was dictated by GSU arrangement and reliability considerations. Each of the two gen­erator step-up transformers serving these units has two low-side wind­ings, one high-side; thus the loss of one GSU would prevent two 7Bs from accessing the grid. To minimize the risk of all GTs being unavailable, the turbines selected for each phase were connected to different GSUs.

Plan was to convert the first two 7Bs to Mark VI in six weeks and then do the second pair. Actual job took twice as long as planned. The participants: The contractor’s Colo­rado-based retrofit group; engineers located in India for programming and simulator work; local contractors for installation.

Several challenges arose dur­ing installation and commissioning that had to be worked through before the project could be completed suc­cessfully. These included changing subcontractors partway through the project; changing the “standard con­trol” package; differences between the factory and the site regarding factory acceptance testing (FAT); communications issues; and some general philosophical differences con­cerning turning-gear operation, lube-oil pump testing, operator-friendly test buttons for IGV (inlet guide vane) stroking, and a custom startup-permissives page (sequence page) that was a challenge to implement.

In the end, the contractor and its subs completed the job and returned the units to service, complet­ing all contractual require­ments and, in Pineda’s words “made it all work correctly.”

Lessons learned includ­ed ensuring that key plant personnel maintain a close working relationship with contractor and subs to miti­gate problems as they are identified. Another recom­mendation is to make sure all options over and above the standard

offerings are clarified upfront and that all parties understand what these are. Lastly, make sure the contractor’s controls engineer is involved from project start to ensure field work goes as smoothly as possible. This facili­tates the handling of issues when they arise.

Reliability improvements

Pineda grouped mechanical reliabil­ity improvements into three cat­egories: instrument upgrades, com­pressor/turbine, and auxiliaries. One of the instrument upgrades he discussed actually was part of the controls work: Deactivation of the mechanical bolt for overspeed pro­tection and its replacement with the OEM’s electronic package. Note that the bolt was not removed, just set to the maximum allowable speed; the hydraulic circuit remains enabled.

Other instrument upgrades done over the years included: (1) Upgrade of exhaust-gas and wheel-space ther­mocouples to more robust armored cables. The replacement TCs typi­cally last 10 years; the OEM’s origi­nal standard issue often did not last more than a few months. (2) Pres­sure switches used in the atomizing air, fuel oil, and lube oil systems all were replaced with transmitters. (3) Flame detectors were replaced with ones offering more reliable flame detection, no cooling, etc. Ignitors also were switched out with a model less prone to sticking.

Inlet air systems really take a beating over the years, especially when they’re located near plants burning solid fuels and ash is trans­ported in open trucks. The original JEA filtration systems had just a single-stage roll filter—one essentially designed to stop leaves and bugs; motors and switches failed frequently (Fig 4). The amount of dirt found in the compressors at each outage left no doubt that an upgrade was needed. The entire air inlet house for each engine was replaced with a two-stage filtration system having both a prefilter and high-efficiency vee filter—using the same filters as the company’s 7FAs, which reduces the need for any additional spares in inventory (Fig 5).

The amount of life remaining in turbine wheels of legacy machines is of great interest to owners. All OEMs have strict limits on lifetime starts and hours, and replacement wheels are expensive.

Outage planning for JEA’s peakers is “rust-based”—for lack of a more descriptive term. All the engines are located in a warm, moist, saltwater environment. Major outages are conducted at 12-yr intervals, hot-gas-path (HGP) inspections at six. Fir-tree wear over 30 years of turning-gear operation produced platform gaps that in some cases were double those recommended by the OEM.

Coating of fir trees and the use of larger seal pins to prevent hot-as access to critical surfaces only were effective for a few hundred operating hours. Ultimately, JEA had to replace the wheels—an expensive but necessary decision (Fig 6). Bore fans were eliminated in the process.

Compressor upgrades have been ongoing through the years, Pineda said. For example, during the outage to replace the Mark II control system with Netcon 5000, IGVs were swapped out with ones made of Cus­tom 450 and the inlet angle increased to 87 deg, thereby increasing output.

About the same time, JEA started coating turbines, compressors, and HGP parts—standardizing on formu­lations made by Sermatech Interna­tional, Pottstown, Pa. Compressors were coated with Sermatech 5380DP, which minimized corrosion. Fig 7 shows the coating mostly intact after 10 years of service. Deposits of coal dust and dirt noted earlier are clearly in evidence. These airfoils typically are hand-cleaned during outages. If deposits are too tenacious, blades are media-blasted clean and the com­pressor is recoated (Fig 8).

Casing corrosion has been an issue as well. There was leakage from the four-way joints at the compressor discharge case and combustor case, vertical joints at the aft end of the turbine casings, forward vertical joints of the exhaust casings, cracks in the legs of the compressor dis­charge case, and loss of casing mate­rial. Last sloughs off in sheets (Fig 9) unless a thin coat (less than 1 mil) of inorganic primer is maintained on exposed surfaces (Fig 10).

Pineda talked about the various methods JEA used to eliminate leak-age—for example, peening of joints, overstretching of bolts, various seal­ant formulations, remachining sur­faces (Fig 11), shims, etc. He also spent some time discussing vari­ous methods of fixing casing cracks, including: grind out cracks, drill “stop” holes, etc.

Broken compressor through-bolts were found on one unit (Fig 12). On two separate occasions, operators could not bring the unit up to speed. There had been no previous indica­tion of a problem—that is, no high or unusual vibration, no upward trend in vibration. High-cycle fatigue was the bolt failure mechanism (Fig 13).

Need more information on this topic? Users can access Pineda’s Pow­erPoint slides in the CTOTF Presen­tations Library (sidebar tells how to do this). The library is equipped with a keyword search feature to help find any other presentations, or articles from the COMBINED CYCLE Journal, on this subject in the group’s archives.

Siemens roundtable

Last fall’s Siemens roundtable was particularly robust. Ray Martens of Iberdrola Renewable Energies (don’t be fooled by the company name, he still manages an F-class combined-cycle plant) and Pierre Boehler of Mirant Mid-Atlantic LLC chaired a lively morning session dedicated to user presentations and discussion regarding turbine blade/vane, compressor, combustor, controls, and auxiliary issues.

National Electric Coil’s Howard Moudy closed out the morning with a presentation on what to inspect and what to look for during genera­tor overhauls and alternatives for addressing problems identified.

The afternoon was devoted to pre­sentations by Siemens Energy Inc engineers—including George Van Deventer, Greg Perona, Vijay Kapoor, and Ron Hitzel—covering rotor life extension, major overhauls, low-CO turndown alternatives, disc-cavity cooling, modernization and upgrade options, and SPPA-T3000 capabili­ties and system security.

One user reported on the libera­tion of angel wings from R3 blades (Figs 14, 15) and consequent foreign object damage (FOD, Fig 16). The unit, a 501FD commissioned in 2003, had accumulated only 170 starts and about 1000 hours of operation on natural gas only. Damage was dis­covered during an annual borescope inspection; the previous year only a slight rub was present.

The owner/operator’s root-cause analysis considered (and eliminated) the following: creep (too few operating hours for that), improper heat treat­ment during manufacturing (hardness test proved otherwise), FOD (no miss­ing material upstream), as well as poor alignment/installation of vanes (no hard rub present previously).

Another user in the audience said his plant had experienced the same problem three or four years ago. He and his col­leagues believed that the OEM’s clearances were too tight as designed and slight rubs built up mate­rial on the vane segment with a hardness similar tothat of tool steel. That’s what cut into the angel wings and liberated them.

The presenter said the OEM offered this explanation: Cause was ductile overload caused by uneven heating of the vanes as an assembly and each segment individually. Solution: The so-called “cut-back mod” which removes material from the trailing edge of vane segments to provide some margin against rubbing. Field experience reported by the OEM has been positive with no reported cases of contact following the mod. All new vanes now incorporate the cutback.

A second user presentation offered one plant’s fix of an exhaust-strut joint failure (Fig 17). Someone in the audience confirmed that similar damage had occurred in his plant. When the heat shield around the strut failed, he said, the strut dropped and thermocouple guidetubes were “sawed through” rendering the exhaust TCs inoperable.

The speaker then offered several photos of the homemade strut collar to correct the problem on his engine (Fig 18).

Environmental roundtable

The environmental roundtable has grown significantly in stature since its introduction two years ago. Chairman Scott Takinen, who manages Arizona Public Service Co’s (APS) West Phoenix Generating Station, is adept at both dealing with today’s requirements and anticipating what will be important tomorrow. The latter trait is particularly beneficial for this assignment.

Takinen’s session in fall 2008 featured presentations on air quality permitting and the importance of pH control for stable operation of ZLD (zero liquid discharge) systems. The session at the 2009 Spring Turbine Forum featured a presentation on coal hydrogasification with algae farming for CO2 management.

Chas Spell of APS updated attendees last fall on federal air-quality monitoring and reporting requirements which changed earlier this year. Starting in 1Q/2009, all industry sources were required to use the Emissions Collection and Monitoring Plan System (ECMPS) for submitting data to the EPA required by the Clean Air Interstate Rule (CAIR) regarding monitoring plans, QA/certification tests, and emissions.

It’s important to note that ECMPS also requires use of a new XML (Extensible Markup Language)-based data format. If you are not aware of this, begin your learning experience at http://www.epa.gov/airmarkets/business/ecmps/index.html.

Spell also reviewed the NSPS (New Source Performance Standards) Quad K standards. They establish emissions performance standards for new, stationary gas turbines to reflect recent changes in both turbine design and technologies for controlling NO_x emissions. Applicability: All stationary GTs with a heat input greater than or equal to 10 million Btu/hr; trigger date is Feb 18, 2005 for start of work on new units or for modification or reconstruction of existing units.

Mark Patterson of HPD, Plainfield, Ill, a Veolia Water Solutions & Technologies company, discussed the importance of pH control for ZLD systems. He is well known in the ZLD community and had presented at CTOTF previously.

Patterson began by reviewing the methods for achieving ZLD, starting with intermediate volume reduction using membrane concentration or falling-film evaporation. Final concentration mechanisms reviewed were evaporation pond, spray dryer, and forced-circulation evaporation.

Next, he gave a short course on scale formation in cooling-water circuits that addressed the causes and means for controlling calcite, gypsum, calcium and/or magnesium silicates, calcium phosphate, and iron oxide.

Another segment of the presentation was devoted to common corrosion problems in cooling-water circuits—including, low-pH circulating water, introduction of a corrosive contaminant, high-TDS (total dissolved solids) makeup water, and scale deposits. Here again, Patterson identified the causes of the various issues and suggested means for controlling them (aside from chemicals).

Case histories are always welcome at user-group meetings and Patterson presented two. One concerned low-load operation combined with chemical addition to control condenser scaling. End result was high TDS in the cooling-water circuit coupled with high sulfate to the ZLD system which combined to form glauberite (sodium calcium sulfate) in the plant’s falling-film evaporators.

The second case history involved the inadvertent emptying of the sulfuric acid tank into the cooling tower. Intermediate concentration was by a falling-film evaporator, which received the low-pH feed. The system did not provide for the unlikely necessity of having to increase pH. Piping and welds suffered severe corrosive attack.

Lessons learned in both cases supported the case for better operating procedures and staff training. Both incidents could have been avoided with them. Further, it is important to pay greater attention at the design stage to the fact that system upsets do occur—for a variety of reasons. While the low-cost system might look good on paper, it may not be the wise choice. A cost/benefit and risk analysis is suggested when evaluating alternatives.

The bottom line: All aqueous effluents and chemical treatments end up in the ZLD system, Patterson reminded, so process upsets must be handled promptly and correctly. Also, pH excursions are amplified in ZLD equipment. The higher the ionic strength and temperature, the more severe will be the excursion.

Ray Hobbs’ presentation at last spring’s meeting illustrates some of the challenging work being pursued to marry renewables and fossil energy. One idea offered in the NV Energy report further back in this issue is to pipe steam produced by a solar array into a heat-recovery steam generator to minimize the amount of duct firing required to meet system peak load.

Hobbs’ project is far more sophisticated. It combines coal with renewable energy to produce fuels and energy without greenhouse gas emissions. Hobbs has been involved in technology development for 18 of his 25 years at APS. The registered professional engineer with multiple university degrees is responsible for APS’ Future Fuels Program, which focuses on technologies relation to sustainability. He has published a couple of dozen technical papers, con­tributed to two books, holds multiple patents, and has received several awards over the years.

The advanced hydrogasification process (AHP) Hobbs reported on is funded by DOE’s National Energy Technology Laboratory (NETL). A major goal is to demonstrate an alter­native use for CO2 emissions. AHP is an integrated five-step process that includes (1) hydrogen produc­tion without CO2 emissions, (2) syn­thetic natural gas (SNG) production by flash hydrogasification of coal, (3) oxy-combustion of coal/char to pro­duce electricity, (4) carbon recycling of CO2 emissions through biological processes, and (5) biofuels production from carbon recycling.

Such integration of renewable and fossil resources is a strategy whereby renewable energy is stored as natu­ral gas and biomass. The creation of SNG from renewable energy—such as wind—creates a dispatchable renewable fuel which can be used in GT-based powerplants (Fig 19).

The process exposes pulverized coal to a hot hydrogen stream that quickly transforms carbon into meth­ane through flash hydrogasification, producing little or no CO2. Hydrogen is produced from renewable sources using commercially proven water elec­trolysis. The process produces elec­tricity in a steam/electric cycle using char from the hydrogasifier and oxy­gen (a byproduct of electrolysis) in an advanced oxy-combustion process.

The CO2 produced is supplied to an algae farm. It consumes the CO2 naturally while producing biomass, which can be used for the produc­tion of transportation fuels. APS is building an algae farm adjacent to its Redhawk Generating Station. It will be an engineering-scale system. This integrated system will process a slip­stream from the stack into the farm and produce algal crude.

GE roundtable

There’s always a full house at the GE frames roundtable. Market pen­etration is the primary reason; GE has more E- and F-class machines in operation than any other OEM. Session theme last fall was capacity enhancements. Dominion Energy’s Larry Rose chaired a well-balanced program.

Users presented on fog­ging, wet-compression, and inlet-chilling experience; Thomas Mee III, chairman and CEO of Mee Indus­tries Inc, Monrovia, Calif, conducted a short tuto­rial on inlet fogging sys­tems designed to optimize evaporation and minimize compressor water ingestion; and Tom Mason, president, Advanced Power Projects Inc, Fre­mont, Calif, showed users how to get more power and cleaner air at lower cost by converting simple-cycle gas turbines to the so-called simplified combined cycle (SCC).

Although Mee’s fogging presen­tation in Tucson followed the user case history, for the purposes of this report, it makes more sense to sum­marize the tutorial first, for back­ground purposes. Mee Industries has installed about 750 fogging systems on GTs worldwide since 1997, four score on F-class machines; it does not offer alternatives for inlet-air cooling.

According to the company’s cal­culations, fogging is less expensive than evaporative cooling because of the pressure-drop penalty associated with evap media. At the same level of cooling, Mee said, fogging may save upwards of $250,000 annually—depending on the duty cycle, of course.

Mee stressed that droplet size is the most critical fac­tor in GT fogging and sug­gested 20-micron droplets as the optimum. You want to avoid liquid-impaction ero­sion of GT airfoils, he said, adding that very large drop­lets are conducive to pitting and fractures.

On average, Mee continued, it takes a “good fog” about two seconds to evaporate. To achieve this goal, you should locate nozzles immedi­ately downstream of the air inlet filters. However, in many GE 7FAs, nozzles are installed downstream of the silencers, leaving insufficient time for complete evaporation. The location of these nozzle arrays should be changed, he advised.

Readers have two choices to dig deeper. One is to visit the CTOTF Presentations Library to view a copy of Mee’s presentation (sidebar), or to access www.combinedcyclejournal.com/archives.html, click 3Q/2008, click “To fog or not to fog: What is the answer?” on the cover.

Fogging case history. A user reported on work at his company to install fogging systems on two new simple-cycle 7FAs and on an exist­ing unit (retrofit). Engineering cal­culations showed fogging beneficial above 60F; a 21 deg F differential is achieved at the compressor inlet on a 95F (dry bulb)/40% RH day.

The presenter’s company has extensive experience with inlet cool­ing and offered a few lessons learned/best practices for others considering fogging, including the following:

• Best results have been obtained with one booster pump and a vari­able-speed-drive supply pump in series to provide the 33 gpm (maxi­mum) required for each 7FA. The 715-nozzle array is arranged in three zones. Previous systems had up to four pumps and nozzle arrays were arranged in six zones.
• Ductwork should be constructed of stainless steel.
• Drain should have a loop seal.
• Verify requirements, if any, for discharge of water drained from the bellmouth area.
• Check the bellmouth hourly for the presence of water carryover or streaking.
• Do routine preventive mainte­nance checks of the compressor inlet and take dental molds as recommended by the OEM. This user ran the fogging system about 250 hours on the existing 7FA equipped with standard R0 blades (the new machines had P-cut blades) and was approaching the OEM-recommended 8-mil erosion limit.

Note that the capacity gained from fogging is classified as “non-de­pendable power for dispatch” because the driver is ambient wet bulb tem­perature, over which the operator has no control. Plus, process control is limited by the use of a PLC-based system in this case; fogging is not controlled by the plant DCS. The presenter mentioned that set-up and tuning of the control system requires some time and patience.

Adding fogging capability to the existing engine required lengthening of the inlet ductwork. Original was of carbon steel; retrofit section, stain­less steel and about 20 ft longer to provide additional residence time for evaporation (Fig 20).

User discussion was lively, as anticipated. Many users have expe­rience with fogging systems—some good, some not so good. With so many variables involved, it’s difficult to correlate one plant’s experience with that of another. Here are a few of the comments/opinions/experiences offered by attendees:

• Use service water on pump seals to extend their run time; demin water is too aggressive.
  • Piston-type positive displacement pumps are a maintenance head­ache.
  • Nozzles must be cleaned peri­odically for best results. One user found ultrasonic cleaning espe­cially effective.
  • New standard R0 blades cracked near their root sections in less than 100 hours of fogging. This user no longer fogs.
  • Decision to fog (or not) demands careful economic analysis; don’t blindly follow the OEM’s recom­mendations.
  • All R0 blades are not the same; they are sourced globally. Conduct a modal analysis to ensure there are no marginal blades in the row. It is those blades that are most prone to cracking.

Wet compression (WC) was the subject of the next user presentation. Experience referenced was from the operation of four late-1980s, dual-fuel 7EAs equipped for fogging a couple of years after installation and later retrofitted for WC. Recall that wet compression decreases the work necessary to compress air, thereby leaving more power to drive the gen­erator, increasing output.

Foggers come on first. Operation of the WC system differs from fog­ger operation in that the former runs flat out when called into service. At this plant, the system kicks in at a wet-bulb temperature of 50F and water injection is a constant 62 gpm. Capacity boost per engine is about 6-7 MW. The existing demin system supplies water for both fogging and WC; a booster pump was added to meet WC requirements.

Retrofit of inlet chilling was the last user presentation in the capacity-enhancement segment of the session. Inlet chilling and ther­mal storage capability were installed at a site with two 2 × 1 7FA-powered combined cycles to better respond to emerging capacity markets. Only one of the 7FAs was chiller-equipped and operating at the time of the presen­tation.

Inlet chilling offers the opportu­nity to supply 50F air at the compres­sor inlet which for this site would provide a 60 MW boost in output on a hot summer day. Engineers determined that about 5600 tons of refrig­eration was required for each GT with ambient conditions of 95F dry bulb/75F wet bulb.

Thermal energy storage (TES) to accommodate the total chilled-water requirements on the “design day” for all four gas turbines would require one or more tanks with a total capac­ity of 9 million gal. The benefit of TES is that water can be chilled at night using less-expensive power than is available during the daytime peak. A rigorous financial analysis is required to determine if it is more cost effective to install full TES capa­bility or partial.

The four-pass, 14-coil bank was delivered to the site in eight pieces (Fig 21). It is designed for 4500 gpm and high delta T on the water side; a 1-in.-H2O pressure drop on the air side. All work on the filter house was done during a hot-gas-path inspection and it was the critical path. The proj­ect, which involved addition of more inlet-bleed-heat piping (Fig 22), took about three days longer than the 17 planned. Experience at this site was that construction cost about as much as the equipment—roughly $400/kW. Also that the pressure drop through the new coil bank was 0.8 in. H2O.

The benefits of and experi­ence with simplified combined-cycle (SCC) technology was covered by Tom Mason. SCC is a patented steam-in­jection technology which, in thermo­dynamic terms, results in the Bray­ton and Rankine cycles operating in parallel. It recovers energy from GT exhaust without the need for a steam turbine and its associated equipment.

SCC encompasses the Advanced Cheng System™ (more commonly known as the Cheng Cycle), Cheng Low NOx (CLN™), and Cheng Boost™ technologies invented and developed by Dr Dah Yu Cheng, Cheng Power Systems Inc, Mountain View, Calif.

One of SCC’s important features is the complete premixing of steam and natural gas upstream of the fuel noz­zles. Injecting steam through the fuel nozzles, premixed with fuel or not, is a way to increase power without exceeding NOx limits. The amount of steam that ultimately can be injected is limited by CO emissions.

Premixing allows considerably more steam to be injected through the fuel nozzles than is possible with other technologies—STIG™, for example—before the CO limit is reached. More steam flow also means that more heat is available for recov­ery in the heat-recovery steam gen­erator (HRSG), which is why the SCC has an enviable heat rate.

More background information is available in Mason’s slides, which can be accessed through the CTOTF Presentation Library, and in “GT upgrade technology promises more power at higher efficiency, lower emissions,” which is posted in this periodical’s archives at www.com­binedcyclejournal.com/archives.html, click 4Q/2007, click article title on issue cover. The PowerPoint slides are particularly valuable in that they provide performance data from test rigs and plant demonstrations. ccj

Independent voice of the gas-turbine-based generation sector

© 2014 CCJ Online, Inc. All rights reserved. | Published by PSI Media, Inc | 7628 Belmondo Lane | Las Vegas, NV 89128