Best practices, lessons learned from compressor session paid expenses several times over.docx

8/13/2019 Best practices, lessons learned from compressor session paid expenses several times over.docx

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Best practices, lessons learned from compressor session

paid expenses several times overPosted onJune 2, 2013byTeam CCJ

Compressor presentations and discussion traditionally take most of the firstmorning at 7F User Group meetings and this year was no different. The session

ran nearly three hours, including the coffee break. The other sessionssafety,controls, auxiliaries, combustion, turbine, and generatortypically are budgeted

half that time or a bit less. One of the six compressor presentations wascoveredin 7F CCJ ONsite 1,published about a week ago; the others are summarized here.

Forced Forward Stator Replacement,well presented and well received,featured a valuable review of compressor issues and OEM responses (Technical

Information Letters and product changes) that owner/operators have endured

since the unit profiled began operating in spring 2005. The historical perspectivewas of particular value to the first-timers in attendanceabout half of the

registrants. If you didnt absorb all that the speaker had to say, access thepresentation atwww.7fUsers.org.The archives section of the organizations

website is for owner/operators onlyand requires a library card. Register today

online; its simple to do.The two 7FAs for this combined cycle were commissioned with the so-calledoriginal compressor blades and the OEMs modified water washing system. Given

the many design iterations for these components it is difficult to understand fromthis summary exactly what was installed in this users engines at the time.

However, he did say that the airfoils in the R0 and R1 rows of his units weresusceptible to erosion, foreign object damage, and associated cracking.

One of the reasons to attend user-group meetings is that you can query thespeaker to learn exactly what components his or her case history is referencing.

With all the OEMs design changes over the years, and the wide variety of third-

party parts available, there probably are more than a hundred unique engines inthe fleet.

Back to the case history. The plant beganinspections recommended in TIL 1509for R0 and R1 in fall 2005. A crack was found in an R0 blade on one unit in spring

2008 and blades were replaced with the original airfoils. The owner implementedthe OEMs recommendations based on fleet and user experience, including the

following:

No R0 upgrade.

No online water washing.

Aggressive semiannual inspection schedule.

Monitor the OEMs upgrade progress through the 7FA Users Group andthe GEsales team.

Evaluate third-party solutions.

In planning for the fall 2011 major inspection, the owners engineers fully

evaluated all upgrade options, including the OEMs enhanced compressor

upgradessuch as Package 3 to address R0 and stator failures, Package 5,

marketed as a proactive enhancement to address R1 cracking and other issues.
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In conducting its assessments, the outage team focused its analysis on issues

presenting the highest operational risksincluding R0/R1 cracking, statorcracking, aft stator rocking. Analyses complete, the owner, a transactional

customer, opted to wait until it had adequate time to evaluate field experiencewith both OEM and third-party alternatives before deciding on the specific

upgrades to install.

When Unit 1 was opened for the fall 2011 major, extensive corrosion pitting was in

evidence on blades in R1-R3, R6, and S1-S4; some pits exceeded the maximum

allowable depth after prescribed corrective blending. The pitting photos shown bythe speaker were very similar to those presented by John Molloy, PE, of M&MEngineering Associates Inc, in his4Q/2012 article in CCJ.They also were caused

by contaminated air, as described by Molloy.

The user presenting said his 18-stage compressors suck in air heavilycontaminated by vehicular emissions and salt. He also mentioned a four-month

shutdown in spring 2009 to address problems with the HRSGs. During that time

there was considerable air flow (natural draft) through the gas turbines.Experience of others suggests that air curtains and portable dehumidificationsystems are beneficial. The owner also believes that ineffective water washing

contributed to the pitting attack.

The poor condition of the compressor air path required a significant increase in

scope for the major inspection. Re-blading was necessary. Plant personnelconsidered themselves lucky because no blades were liberated despite theextensive pitting. GE was selected to destack and overhaul the rotor and rebuild itwith new blades, a job that took six weeks. The speaker said there was not

adequate time to evaluate the capabilities of third-party services providers and

invite them to bid on the work.

The plant had a spare rotor (with an enhanced R0), so it was inserted into Unit 1

and that engines rotor overhauled for Unit 2 during its major inspection in late fall2011. Unit 2s compressor also had extensive pitting damage. Interestingly, theplant is now operating two GTs with rotors having different features: One has a

Package 5, the other a Package 3.

Follow-on corrective action includes the following:

Increased frequency of water washing to multiple times weekly. R0 erosion is

being monitored.

Inlet inspections are characterized by greater vigilance for oil, dirt, grease,

moisture, etc.

An air-filter upgrade program will be complete by year-end.

Upgraded water washing system is being evaluated. Investigation of erosionpotential is part of the evaluation.

A second presentation by this userdescribed Aft Stator Replacement for thesame gas turbines. Since 2006, he said, semiannual inspections have been

conducted for compressor rubs and shim migration;TILs 1502, 1562, and 1769were mentioned. In 2008, a cases-off hot-gas-path (HGP) inspection included aft

blade tip blending, installation of third-party S17 vanes and exit guide vanes, and

pinning of shims by a third party.
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The first significant finding of stator rock was during the fall 2009 borescope

inspection. Rocking of from 30 to 50 mils was in evidence. The following spring,rocking of up to 67 mils was found. Inspection intervals were reduced to between

1000 and 2000 hours from that point on. Vane rock increased to as high as 95mils. Owner was concerned because at 120 mils the gas turbine must be shut

down.

Engineers set about evaluating upgrade options for the aft stator section of the

compressor for possible implementation during the fall 2011 major inspection. The

first option, replace in-kind, really was not a viable alternative: It doesnt solvethe problem because the case was already damaged and the likelihood of shimmigration was good. The OEMs so-called Bigfoot mod/ Package 4 was an

alternative, but that was viewed as an extremely intrusive and permanentmachining procedure that would become the critical path for the major. It also

involved a significant upfront commitment for parts and labor for a procedure withlimited operational experience (fleet leader at 13,000 hours at the time). Plus,

there wereemerging stator twist concerns.

A fallback position would be to wait until the 2014 HGP to implement a solution, aswas the strategy described earlier for the forward stator section. But a third-party

was offering multiple-vane segments using field-validated airfoils that were viewedpositively. Fleet leader had 24,000 hours at the time and these parts and their

installation were much less costly than the OEMs solution. Deal! The new partshave since passed the 12,000-hr mark and are said to look like new.

Another compressor presentationthat got high marks, 17th-StageCompressor Wheel Dovetail Cracking, provided attendees several lessons

learned/best practices. When preparing for a major inspection, an owners

engineers were warned about the possibility of finding dovetail cracking on the17th-stage wheel. Rotor out, cracks ranging from about 125 to 155 mils radial and60 to 220 mils axial were illuminated by red dye on the aft side of every flat-

bottom blade slot. The rotor had experienced 2025 actual starts and had recorded44,365 hours of service at that point in its life.

The OEM told the owner to blend-out cracks up to a depth of 100 mils; also, tosmooth all blunt edges and transitions of the blend and dye-pen the affected areato be sure the indication is gone. If a crack remains after blending 100 mils, the

OEM said, take a picture, estimate the size of the crack, and submit a PAC (PowerAnswer Center) case. One crack was known to exceed 100 mils, so the owner

leveraged EPRI research and decided that blending to 125 mils was acceptable.

Caution:At last years meeting, an attendee told the group it was his

understanding that if you blend and cant remove the crack it will propagate fasterthan if no blending had been done.

The forward sides of all slots also were dye-penned; all of those were cracked aswellfrom about 60 to 155 mils axial. EPRIs stress analysis concluded that 7FA

discs with flat-bottom dovetail slots will crack somewhere in the neighborhood of1000 to 1500 actual starts. The disk examined was considered good for another

900 factored starts.

A field service team fromSulzer Turbo Services was dispatched to the plant to

blend out the cracks. This is a difficult job to do in the field, the speaker said, but

Sulzer successfully removed all cracks. The owners plan is to order the new 17th
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stage wheel/stub shaft with round-bottom blade slots and install it during the next

HGP, which becomes a major because the rotor must be unstacked.

A root-cause analysis revealed that rim dovetail cracking is caused by thermal

transient stresses associated with cyclic operation. Hot restarts are the mostdamaging operating scenario; during a shutdown, the rotor rim cools quickly and

the wheel center stays hot. One user in the audience commented that rim cracksare not self-arresting. He added while round-bottom disc slots avoid stress

concentrations characteristic of flat-bottom slots, they also will crack, but are

expected to last twice as long as discs with flat-bottom slots.

There were two brief compressor-section presentations, one with the speakertalking through a series of photos of S17 vane segments from the time they were

removed from the engine for repair of the bolted shroud until they were reinstalledin the unit. A hiccup was reported on final fit-up. A poll of attendees revealedabout half a dozen users operating with shrouded S17 vane segments provided by

a third-party supplierone engine having more than 25,000 hours on those parts.

A user who presented last year on the difficulty in extracting damaged R0 blades

using a come-along and air hammer, and the galling of the blade slots

experienced with that method of extraction, was back at the podium again thisyear. He reported success (no galling) on another gas turbine by using a cuttingwheel to remove the airfoil and then a milling tool to evacuate the blade slots. He

said it took about three shifts to mill out all of the R0s. Outside California, headded, you can use a plasma torch and probably get the job done in one shift. Thefirst rotor goes to the shop this fall to replace the stub shaft and integral wheelwith the galled slots.

By show of hands during the open discussion period, about 80% of the group hasdone a compressor upgrade of some sortmost with the OEM. Other talking

points included ice damage on R0 and how to avoid it. This has been a discussion

subject at several user group meetings over the years. Use the search function atwww.ccj-online.comto access more information. There also was mention ofsystems for compressor-blade health monitoringboth OEM and third-partybut

relatively few attendees had experience with these promising diagnostics.

Borescope clinic: Condition-based maintenance demandsgood intel

Posted onJune 2, 2013byTeam CCJ

Mike Hoogsteden, field service manager forAdvanced Turbine Support LLC,reminded 7F users in Greenville (SC) last week that the intelligence gathered

during periodic borescope inspections is critical to getting top performance fromtheir engines. About half of the O&M personnel attending the 7F User Groups

annual conference were first-timers and benefitted considerably fromHoogstedens review of (1) what Advanced Turbine Supports inspectors are

seeing in the field and (2) several important Technical Information Letters (TIL)released by the OEM for this fleet.

Hoogsteden began with a review of the latest borescope and nondestructiveexamination (NDE) tools available. They enable experienced technicians, with
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deep knowledge of the engine model being examined, to identify potential

problems and evaluate the findings faster than previously possible. High definition(Fig 1) and large field of view (Fig 2) are two attributes of modern top-of-the-line

inspection equipment.

So-called stereo technology provides the borescope technician (1) a simple,

accurate method of measuring linear dimensions in an image (Fig 3), (2) distanceinformation between two points and a perpendicular line drawn to the line created

by the two points, (3) the difference in height between points on two different

surface planes, (4) a way to determine the surface area of a defect, and (5) thecapability to measure the length of a non-linear defect or feature.

1. Clear, bright photos 2. Large viewing area 3. Stereo tip measurements

Hoogsteden next described 3D Phase Measurement (PM)a new full-screen, on-demand optical measurement technologyas an exciting breakthrough forborescope inspections. He said it scans the part surface and creates a 3D map that

allows technicians to perform all measurements and views right on the 3D surface.This technology also allows technicians to determine turbine blade clearances (Fig

4).

4. Measurement of blade

clearances is possible only with

3D PM

5. A simple machining step allows borescope access

to the biscuit area for precise measurement of

rotation

Top technicians supported by state-of-the-art diagnostic equipment and the

capability to perform some critical maintenance remotely (including the removal ofprotruding shims close to liberation, minor blending, etc) permit the plant

manager to track concerns with confidence,thereby allowing cost-effectivecondition-based maintenance planning.

Be sure your stake is well done
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TIL 1870R1 (Mar 5, 2013) requires owner/operators to check for first-row blade

migration on F-class compressors that received an R0 re-installation betweenJanuary 2008 and January 2013. Concern is that there may be insufficient

interference between the stake marks and the blades, and that the airfoils mayhave moved forward. A small population of turbines reportedly has had migration

events related to improper blade installation.

This technical information letter is a sequel to TIL 1796 (Apr 25, 2011) which

required 7F owners to check for forward migration of R0 blades both visually and

physically. The latter is defined a simple lift and tug on each blade (not a hardyank) to confirm axial restraint. Blades that do not pass this test must berestaked.

Reasons blades might migrate: (1) Stake marks are undersized and unable toprevent the blade from moving forward. (2) The radial gap between the bladedovetail and slot bottom is excessive, allowing the blade to slip over the stake

marks. In the extreme, axial movement is conducive to compressor blades

rubbing against the casing bellmouth, damaging both the blade and the rub ring.

Improper depth, diameter, and/or height of stake marks, and improper use of

feeler gauges for gap checking, are the root causes of most blade migrationevents. Coincidentally,an insurer reporting at last falls CTOTF conference saidthat three-quarters of all powerplant losses had a worker componentincluding

ineffective training, supervision, etc.

Hoogsteden told the 7F users that TIL 1870R1 goes beyond TIL 1796 by requiring

owner/operators to check for biscuit rotation where this blade retention solutionhas been installed. It also calls for verification of staking measurements and radial

gaps during major inspections when the bellmouth can be jacked up to permitaccess for inspection.

For those user not familiar with biscuits (about half of the attendees were first-timers), Hoogsteden explained that after several blade installations there may not

be sufficient room along the edge of the slot bottom for staking and an insert(biscuit) is inserted into a cut-out in the first compressor wheel to perform the

same function as peening. A problem associated with biscuits can be their

rotation, generally precipitated by improper staking.

If you are not familiar with TIL 1870R1, contact your GE representative for a copy.

It explains how the biscuit should be staked and how much rotation is permissible.In the TIL, the OEM suggests the use of a mirror to facilitate visual inspection of

the biscuit. The speaker said Advanced Turbine Support believes the mirror is not

a sufficiently comprehensive aid for this purpose and might result in drawingerroneous conclusions. The company is validating an alternative approachintroduced by a customer that with simple machining allows borescope access to

the biscuit area for precise measurements of rotation (Fig 5).

Rocking solution conducive to stator blade twisting

TIL 1769 (Dec 1, 2010) instructs 7F owner/operators on how to inspect their gas-

turbine compressors for stator-vane rocking in stages S14 through S16. Much hasbeen published in the CCJon the subject of vane rock attributed to worn hookfits,

with many affected users opting for pinning of the individual square-based vanes
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into segments to promote rigidity and prevent the release of vanes into the air

stream. This solution, developed by Rodger Anderson of DRS-Power TechnologyInc,has proven effective over the years.

One of the OEMs solutions for dealing with vane rock is its so-called Bigfoot modwhich involves onsite machining of the casingto create a new hook fit for the

vanes.Inspections by Advanced Turbine Support of stages S14-S16 followingimplementation of the Bigfoot mod indicates twisting of stator vanes in some

cases. Such twisting is conducive to casing wear and tear because the Type-409

stainless steel compressor vanes are harder than the cast steel casing (Figs 6 and7). Hoogsteden suggested that users experiencing twisting might want to trendthe casing wear over time.

6, 7. Effects of twisting following a Bigfoot mod are easy to see at the left; close-up is at right

The editors asked a compressor expert what impact twisting might have onperformance. A back of the envelope calculation assuming a nominal 2.5-deg twist

could cost from 0.5 to 1% in compressor efficiency.

Wait, theres more

Hoogsteden presented thumbnails and offered experienced commentary onseveral more TILs during his presentation. Here are excerpts from the editorsnotes:

1509R3 addresses R0, R1, and S0. It recommends annual visual inspection forR0 root cracking, R0/R1 tip discoloration, rolled metal (Fig 8), and/or tip loss.

The TIL provides detailed recommendations if any of those deteriorationmechanisms are identified. Example: For S0 stator vanes, inspection personnel

are urged to look for trailing-edge cracks; if found, immediate replacement is

recommended. Dig deeper on 1509R3:Article 1,Article 2,Article 3.

Advanced Turbine Support is not in complete agreement with the OEMsrecommendations. It believes that annual visual inspections are not sufficientlycomprehensive and have the potential to miss small or tight indications that

could result in blade liberations and a catastrophic failure. The companysinspection experts have identified multiple rotor-blade tip cracks (Fig 9) with

visible dye penetrant that were not seen during unaided visual inspections.

1562 suggests monitoring the condition of compressor shims and the

corrective actions necessary to mitigate the risks of migrating shims on both E-and F-class machines (Fig 10). There are 20 possible shim locations in the first

five stages (R0 through R4) of 7F units and they are spaced approximately 60

deg apart from each other. Dig deeper on 1562:Article 4,Article 5.
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8/12

1638 addresses, among other issues, F-class R1 case-off ultrasonic

inspections for dovetail distress below the blade platform. The testing interval is8000 fired hours or 150 fired starts, whichever occurs first. This

recommendation is modified for peaking units performing more than 150 annualstarts to just before and following the peak season. Inspectors have found four

such cracks to date.

Advanced Turbine Support recommends users heed caution and opt for in-situ

inspections at more frequent intervals. In the case of the last in-situ discovery,

Hoogsteden believes there was a high probability of major damage before thenext OEM-recommended inspection interval, potentially leaving LTSA customersat risk.

1858, 1859, and 1863 concern the inspection of second-stage buckets on the7FA.03 (7241+e, enhanced compressor). The first advises users to perform theinspections recommended in the document for second-stage buckets of original

and modified design to mitigate the risks associated with tip-shroud creep (Fig

11). The second alerts users of the potential need for increased borescopeinspections when installing second-stage buckets of original or modified design.The third TIL alerts users of the potential need for increased borescope

inspections if the unit operating profile is changed.

1884 addresses clashing on bottom half of 7EA compressors, but Advanced

Turbine Support has growing concerns with F-class units as they havediscovered increasing evidence of clashing in the field including one such findingin the top half of the compressor. Dig deeper on 1884:Article 6,Article 7.

8. Compressor rotor blade

rolled metal9. Rotor-blade tip crack

10. Protruding stator vane

shim11. Measuring the extent of damage to a second-stage

bucket tip shroud
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9/12

Control systems earn higher profile at the 7F annual

conferencePosted onJune 2, 2013byTeam CCJ

The controls session at the 7F Users Group meeting has expanded in scope overthe last couple of years to help owner/operators address multiple challenges

including diminished OEM support of legacy control systems and the need fortighter operational control to accommodate renewables, satisfy NERC CIP

requirements, reduce emissions, etc. Several recent additions to the steeringcommittee with controls experience have contributed significantly to the more

robust program.

There were several user presenters in this portion of the 2013 conference. One

focused on frequency response for combined cycles using the DCS. The speaker

said the DCS emulates the governor and the preselected load set point is biased inproportion to the change in frequency. Critical to success is a high-resolution

frequency measurement; the SFL1 in the Mark V or Mark VI via PI is notsatisfactory. The solution here was to hard-wire a frequency meter to the DCS.

Another user presented on the value proposition of PI ProcessBook, which

makes it possible to efficiently display real-time and historical data residing in thePI system and other sources. He views ProcessBook as an efficient method forgetting the most out of PI. Its advanced features are real simple to use, he said,

and demonstrated this. Example: Scatter plots, good for identifying highlycorrelated items and for revealing when a process is off-track, are easier to build

in ProcessBook than in Excel. If youre unfamiliar with ProcessBook, theres plentyof material up on the Web.

Control system upgrade, replacement.It seems that the most popular controlspresentations at user group meetings concern system upgrades and replacements.

One user presented on an HMI replacement for a combined cycle that began

commercial operation in 2004. The original arrangement featured six GE HMIs andthree screens in the control room. There was no HMI for use as an engineering

work station (EWS). The new set-up features three of the OEMs HMIs: two in thecontrol room and one EWS. All machines are quad-monitor capable, the speaker

said. There are still three monitors in the control room; the EWS has twomonitors.

Another upgrade to the original system was the addition of a Wyse terminal (thinclient) to the Packaged Electrical and Electronic Control Compartment for each gas

turbine. The PEECC, sometimes shortened to PECC, is where the Mark VI and themotor control center for the GT reside. The inexpensive Wyse terminal is

connected to the Ethernet loop for the HMI and Mark VI. The reconfigured andupgraded system has been in service for more than a year; no negatives were

reported.

The replacement of Mark V control systemson two gas turbines serving a

combined cycle that started up in mid-2005 was the subject of another

presentation. Interestingly, the Mark V had reached end of life (EOL), according tothe OEM, in March 2004more than a year before plants commercial start; the

announced end-of-service (EOS) date is March 2014. The owner felt compelled toupgrade. By way of background, the Mark V TMR system has four processors

(referred to as cores) R, S, T, and C and a protective core P. It was initially
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provided with an IDOS operator system and subsequently with a

Windows/Cimplicity-based operator interface system and uses an ARCnet-basedcommunications protocol to communicate with the operator interface system.

The owners engineers reviewed many options, including the following:

Upgrade to MarkVI with its 32-bit computer system, Windows interface and

better software tools, and Ethernet-based communications. However, thissystem reached EOL four years ago and EOS is expected in only six more years.

Replace the Mark V with a Mark VIe. Advantages of the latter include (1)OEMs current offering, (2) support expected until 2025 or beyond, (3) Windows

HMI interface, and (4) Ethernet communications. Another benefit of a new MarkVIe is that it can be expanded to provide total plant control.

Mark VIe migration (Mark V retrofit). This option involves installing a Mark VIecontroller inside the Mark V cabinet and retrofitting it to the Mark V core. All

boards are upgraded to supportable versions.

Third-party DCS. The plant has Ovation for its balance-of-plant platform.

Third-party solution with PLC-based controllers.

What to do? Perhaps the most obvious option would be to do nothing. Reasonsinclude these: There are many Mark V systems operating in the electric power

industry, the OEM will support the platform until parts run out, the OEM does offerfield-service options (if you have the money, the OEM has a service team ready to

support you), there is robust third-party support for control system components,and theres access to support from other owner/operators via the 7F Users Group.

A replacement Mark VIe apparently was on the pricey side, although the speakerdid not talk about dollars or contract terms and conditions, as is the rule at user-

group meetings. One assumed cost was a concern because he said field I/O workwas required for a new Mark VIe and outage time would be a week or two,

possibly more.

Ovation was a serious consideration, but, in the end, the lack of experience of that

platform on 7F engines was the deal breakerthis despiteexcellent reviews fromthe one customer based on two years of service. Little was said about the PLC-

based option.

The preferred solution for this application was a Mark VIe migration because of the

speed and economy of implementation, and OEM controls reliability andcompatibility. Regarding the second point, minimal control system management

was required, the OEM support network was already established, and there weremultiple third-party options for control systems, automatic tuning, flamemonitoring, etc.

Value of the vendor fair.The editors stopped byCSE Engineering Incs booth onthe exhibition floor to ask what its team of experts would recommend to a criticalgenerating facility having legacy Mark V controls on its GTs and then compare thatsolution with the one selected by the owner who had presented earlier in the day.

Perfect question for Chairman Craig Corzine, a former GE employee having a deepbackground in Speedtronic control systems and gas turbines, but he was out in

the field. VP/GM Steve Morton was patrolling the companys 8 x 10 ft territory.
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Like many 7F attendees, he had served in the US Navy and managed shore-side

generation facilities.

Morton said CSE, which is celebrating its 20th anniversary this year, has decided

not to develop a retrofit control system package for the gas turbines but continuedevelopment of CSEs technology to extend the commercial viability of the existing

Speedtronic control system with specific emphasis on the Mark Vs. Asked aboutCIP compliance, Morton said the concern with CIP standard compliancy is not

related to the Mark V itself but to the HMI interfacing with the Mark V and it is one

of the areas that the small California company has focused on.

Corzine was patched into the conversation by cell phone and he said thatscrapping the Mark V on a controls refurbishment project was akin to throwing out

the proverbial baby with the bathwater. If it was installed, commissioned, and hasbeen maintained properly, its an exceptionally reliable system, the controls expertsaid. Spare parts and technical support are available and will be for several years

to come. The only reasons to replace a Mark V in his view probably would be to

accommodate a technological upgrade of the turbinesuch as a DLN retrofitorto transition to a fleet platform to reduce spare-parts inventory and to facilitatemaintenance.

Corzine said CSEs HMI is a CIP-compliant industrial monitoring andcontrol software platform designed specifically to replace the functionality of the

IDOS based Mark V and Windows/Cimplicity-based Mark V HMI. The system also is used to interface with the Mark IV and Mark V LM, and soon for theMark VI and Mark VIe as well. The system communicates with the Mark IVs andMark Vs using its native protocol over ARCnet and is provided with USB, PCI, PCIe,

and Ethernet communications drivers. The system can support up to four

individual ARCnet networks and can be used to integrate Mark IVs and Mark Vswithin the same system.

For the Mark V, incorporates all the functionality of the legacy andcurrent Cimplicity-based HMI systems, inclusive of Logic Forcing, Control ConstantEditor, I/O Configuration, Control Sequence Editor, EEPROM Utilities, Diag_C, View

Tools, and Auto-Calibrate. Additional features not available with the standard or Cimplicity-based HMI system include Automatic F Drive Synchronization acrossall systems, fully animated Real-Time Rung Display with sophisticated

search and navigation tools, Multi-generator Tie-Line Control, Integrated DataHistorian, Integrated Time-Sync Manager for all Mark Vs and balance-of-plant

individual controllers, and integrated offsite remote monitoring and control.

Additionally, the system is used extensively as a data historian and

gateway between the Mark V and other computers or control systems, providing adirect read/write data exchange path between the devices for monitoring andcontrol. Communications protocols include OSI PI, OPC (server and client), GEFANUC Series 90 (Serial and Ethernet), Allen-Bradley DF1 (Serial, DH+, and

Ethernet), DNP 3.0 (Serial and Ethernet), Modbus (Serial, Ethernet TCP, EthernetUDP, and Modbus Plus), Siemens S7-200, S7-300, and S7-400 (Serial and

Ethernet), Westinghouse WDPF, and many more.


12/12

Webinar promises a cost-effective outage on time, on

budgetPosted onJune 2, 2013byTeam CCJ

Register today for a user-only webinar that will

help you prepare for your next outage as never before. The benefit to your

company, your plant, and you: A cost-effective overhaul, on time and on budget.

The hour-long interactive program, Friday, June 14, 2 pm Eastern, is sponsored bythe Combined Cycle Journal and CCJ Online and features presentations by thefollowing experts from WoodGroup GTS:

Chris Wilkinson, VP of Major Maintenance.

Freddy Alvarez, Director of Operations (former Plant Manager).

The formal program is divided into four parts:

Developing overall scope and validating the process of task identification.

Reviewing the scope with budgetary limits in mind: Where can you safelyreduce expenditures?

How to deal with last-minute changes and cash reductions.

Tracking costs throughout the process; setting milestones and releasingmoney accordingly.

Q&A/open discussion will follow the formal program.

Who should participate: Plant and asset managers and others at generating plants

and headquarters locations responsible for planning and conducting outages for

heavy industrial frame turbines in simple-cycle plants, cogeneration facilities, andcombined cycles.
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Documents

Best practices, lessons learned from compressor session paid expenses several times over.docx