W A Bechtel Co was a relatively young firm when it · PACESETTING PLANTS, Class of 2007/2008 59 Class of 2007/2008 How one project can define a company’s capabilities W A Bechtel

PACESETTING PLANTS, Class of 2007/2008 59

Class of 2007/2008

How one project can define a company’s capabilities

W A Bechtel Co was a rela-tively young firm when it partnered with five other western construction

companies in a consortium called Six Companies Inc to construct Hoover Dam, the largest civil engineering project ever undertaken. The mile-stone technical and organizational challenge was won with a fixed-price bid of just under $49 million—$5 million less than that of the next lowest bidder. The year was 1931.

Warren Bechtel was a very visible leader at the dam until his untimely death two years after work began. This personal involvement indelibly connected the Bechtel name with the project’s incredible success, including completion of construction more than two years ahead of the contracted seven.

In sum, Hoover Dam repre-sented a pivotal event in Bech-tel’s history. There have been bigger projects in recent years and there probably will be larger ones in the future. But never again will Bechtel be involved in a proj-ect that so profound-ly shapes its sense of itself.

When one dissects the low-emissions combustor conver-sion on five GE model 7E diffusion-flame gas turbines (GTs) at CoGen Lyon-dell Power Generation Facility (since renamed Altura Cogen LLC, see Side-bar 1), you get the sense that it may well be the defining project for PSM of Jupiter, Fla. At a minimum, the Altura retrofit—completed in spring 2007—showcases the company’s lead-ing-edge technology, formidable engi-neering capabilities, considerable proj-ect management skills, and proud and highly motivated personnel.

Challenging project scopeAltura was reported to have a sum-mertime rating of 534 MW at the time of the sale, somewhat less than the as-installed nameplate ratings. The 6 × 1 cogeneration plant, which provides steam to a petrochemical complex and electricity to both that facility and the grid, was built with the following major equipment:n Five GE Energy (Atlanta) 7E

diffusion-flame GTs, rated 80 MW each, were installed in 1985 along with companion heat-recovery steam genera-tors and one steam turbine. The GTs were upgraded in 1997-1998 to increase their

respective firing temperatures to 2035F from 2020F. Shortly thereafter, they were modified to increase the amount of steam injected for NOx control. The engines originally were permitted

for 96 ppm NOx, but new stan-dards required 42 ppm and that was achieved by injecting more steam. There was no facility cap on pollutant emissions at that time.

n The five HRSGs are rated 275,000 lb/hr each at nominal steam con-ditions of 1250 psig/900F with-out supplementary firing; two of the boilers have duct burners to provide operating flexibility. Spe-cifically, at night when electric demand is down, firing duct burn-ers enables the generating plant

to optimally run the GTs and also provide all

the process steam needed. Operat-ing flexibility was enhanced further in 1996 when a new packaged boiler (Nebraska Boiler Co, Lin-coln), equipped

with a Coen Company Inc (Foster City, Calif)

burner system, was installed.

n Note that the two supplementary-fired HRSGs are the same as the other HRSGs except that they have

larger steam drums. A pres-sure-reducing station is pro-

vided to reduce main steam pressure to that required for process use, if necessary.

n The GE steam turbine, rated 135 MW, is a single-extraction con-densing machine. The non-reheat unit is arranged as follows: one HP (high pressure) section, two IP (intermediate pressure) cylin-ders, and one double-flow LP (low pressure) section. Process steam is taken from the back end of the HP turbine; IP steam from the HRSG is injected into the second section of the IP turbine. A mechanical-

Altura Cogen LLCChannelview, Tex

EnergyCo

1. Altura’s 7E gas turbine essentially is a “new” engine with its LEC III com-bustion system, redesigned exhaust end, and higher-capacity blowers for cooling the exhaust frame and load tunnel

Exhaust upgrade

LEC III combustion system

Blowers

60 COMBINED CYCLE JOURNAL, Fourth Quarter 2007

draft cooling tower dissipates heat absorbed by the condenser cooling water.

n One 80-MW GE 7EA with a DLN-1 combustion system was installed in 1996 along with a Babcock & Wilcox Co (Barberton, Ohio) HRSG. More detail on plant equipment

and operations philosophy is avail-able in Sidebar 2.

New emissions regulations. Altura is located in the Houston/

Galveston nonattainment area where regulations implemented after the millennium proposed sharp reductions in NOx emissions from stationary sources by 2006. For the cogen plant, this meant reducing its NOx releases by more than 80%. The revised regulations retained the emissions-rate limit of 42 ppm NOx for each engine and also specified a total annual plant emis-sions limit. Altura's limit, finalized in April 2007, is 631.7 tons/yr of NOx.

Dynegy’s analysis indicated that the best emissions-reduction solu-tion for the Channelview site was to replace the 7E diffusion-flame combustion systems with PSM’s low-emissions LEC III®—certainly not as simple as it might sound. PSM had converted several engine types to the LEC III previously—including three 7Es—and was confi-dent in bidding its largest project ever at a fixed price (access “Pacesetter Texas City: Combustion system retrofit allows cogen plant to reduce NOx emissions by 80%” at www.combined-cyclejournal.com/archives.html, click 4Q/2005, click article title on cover).

The Altura job included the follow-ing conversions/upgrades:n Convert the diffusion-flame com-

bustion system to LEC III.n Install an inlet bleed heat (IBH)

system on each GT. IBH enables a wider range of part-load opera-tion, reducing the minimum load on DLN-equipped machines from about 75% down to about 55%.

n Upgrade the exhaust system for each GT.

n Provide a new fuel-delivery sys-tem for each engine—including fuel skid, piping, and manifolds. All fuel-handling/treatment equip-ment on-skid was PSM’s responsi-bility; all off-skid was Altura’s.

n Replace the original GE Mark IV control systems for the GTs with Ovation® (Emerson Process Man-agement’s Power & Water Solu-tions division, Pittsburgh).A new continuous emissions moni-

toring system (Cisco Systems Inc, San Jose, Calif) was provided for each unit to measure NOx and O2 at the stack; previ-ously two engines shared one CEMS, toggling back and forth every 15 minutes. Responsibility for specifica-tion and installation of the CEMS was assumed by the plant. Plant Manager Randy Cormier said such a proj-ect might be a challenge for

others but his experienced and proac-tive staff handled it in stride. Exist-ing sample lines from the stack were retained. Note that CO is not moni-tored because the regulatory limit is over 100 ppm and the plant emissions generally are in the single digits.

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1. CoGen Lyondell renamed Altura after saleShortly after Dynegy Inc, Hous-ton, completed the overhaul and upgrade of the CoGen Lyondell Power Generation Facility in Chan-nelview, Tex, it sold the power-plant to EnergyCo—a joint venture between a subsidiary of Cascade Investment LLC and PNM Resourc-es, the Albuquerque-based energy holding company. The cash pur-chase price reportedly was in the neighborhood of $470 million.

EnergyCo, based in Las Colinas, a section of Dallas suburb Irving, was formed in early 2007 to pursue unregulated energy opportunities. The sole member of the private Cascade Investment entity is Wil-liam H Gates.


Good results thus farCormier said the entire project was on schedule and “pretty much” within budget. Project Specialist Daryl Whitfield played a major role in the effort from the plant

side. Upgrades were done in parallel with hot-gas-path (HGP) inspections, which normally take two weeks per engine. The first unit was upgraded in six weeks during spring 2006. Con-version of the second and third units to LEC III in fall 2006 also required six weeks each. Experience allowed PSM to shave a couple of weeks off the schedules for the final two units, com-pleting each in a month during spring 2007.

Test results for the first engine retrofitted were impres-sive. It had produced more than 2100 lb/day of NOx for a typical 24-hr operating period with the original combus-tion system. After conversion to LEC III, NOx emissions dropped by 90% to 220 lb for an average day.

More extensive testing after three units were convert-ed to LEC III showed NOx emissions below 4 ppm and CO

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2. Details. . .The bullet points below offer more detail on Altura’s physical plant and on its operation:n Natural gas supply/treatment. Three independent

pipelines supply gas of similar composition and oper-ate continuously. One line is on pressure control; two on flow control. The gas is heated by LP steam until it has 15 deg F of superheat. Plant assumed responsi-bility for adding an extra scrubber—Burgess-Manning Inc (Orchard Park, NY) vertical coalescing scrubber—to knock out all liquids in the gas before heating.

n PAG steam. Although steam is no longer used for NOx control, the GTs can accept it for power aug-mentation purposes. For example, when the steam turbine is not operating, IP steam is injected into the GTs.

n Boiler feedwater quality is the responsibility of the petrochemical facility, which treats both condensate returns and makeup for the cogen plant. Essentially, steam is traded for high-purity water. Arrangement works; Altura has experienced only one tube failure in its history.

n Personnel. Altura requires a staff of 36 to operate efficiently. The staff is dominated by operators and technicians, in particular those with electrical and controls disciplines. This plant must be a good place to work: Many original employees remain.

n Operation. Three GTs—the 7EA and the 7Es equipped with duct-fired HRSGs—typically operate around the clock while the others cycle. GT outages normally are conducted every 18 months: two units in the spring, two in the fall, and two the following spring complete one cycle. GTs that run around the clock normally go into an outage with 12,000 actual operating hours and about 30 actual starts; the units that cycle average about 10,000 actual hours and 500 actual starts.

GT output normally extends from 40 MW to rated base load depending on ambient air temperature. Typically, plant operators start the units, put them in AGC (automatic generation control), and the grid operator handles the rest.


typically less than 5 ppm across all ambient conditions and premix load ranges. Plus, turndown to 55% of the full-load rating without exceeding 4 ppm NOx was verified with the new IBH system in service. PAG (power augmentation) steam flows of up to 80,000 lb/hr also were possible with-out exceeding 4 ppm NOx. Note that these results were achieved “right out of the box,” with no engine disas-sembly or retuning required.

A “clean bill of health” following a combustor inspection (CI) in fall 2007 on the first engine converted to LEC III confirmed expectations that low-NOx operation would have no adverse effects on parts life. The engine had

accumulated about 10,000 actual hours of service and approximately 500 actual starts prior to the inspec-tion. Documentation of parts condi-tion is maintained by PSM.

Cormier and his team said PSM is very conscientious, noting that the company is continually evolving and improving and it is proactive in sharing advancements and operating experiences. Service “after the sale” has been excellent, they added.

One lesson learned: Plan and con-duct training prior to project comple-tion. The plant thought PSM could have done a better job with respect to training, but with several mods being made for the first time, spare

time was at a premium and training got squeezed.

Another observation by plant per-sonnel: PSM parts are more exacting than those typically provided by the OEM. Makes sense because tight control of the combustion process to maintain sub-5-ppm NOx emis-sions demands precision components. Altura has found that relatively few shops are qualified to make repairs to PSM parts—at least now.

The beginning Pat Conroy, PSM’s VP of commer-cial operations, who has spent the better part of four decades work-ing in power generation, says most machines are amenable to a wide range of upgrades and performance-enhancement improvements. Capa-ble engineers equipped with the latest design tools can achieve well-founded operational objectives, he continues; however, economics dictates what’s practical to do and what’s not.

Each project must be evaluated based on the particular machine, its fuel(s) and firing temperature, control system, auxiliaries, etc, and the specific goals the owner has in mind. A detailed engineering effort is required in virtually every case, Con-roy notes, because equipment differs even within a given model series and designs generally are not scalable.

Other things that impact decision-making include such idiosyncrasies as the inability of old Westinghouse machines to readily accommodate a premix system because of limited space inside the combustor casing. The old adage, “the devil is in the details,” certainly applies to re-engi-neering of GTs.

Conroy says that inquiries from users today often have two principal goals: (1) Extend the lives of their GTs and (2) convert from diffusion-flame to DLN combustion systems to reduce NOx emissions. While both are realistic objectives, be prepared for a reduction in power output of possibly 5%, or a little more, when running the machine dry. The primary reason is the elimination of steam injection for NOx control which increases mass flow and power output. Another rea-son: DLN combustors have a higher pressure drop because air and fuel are mixed prior to combustion.

PAG steam can help restore lost capability but it is expensive: Demin-eralized water used to make the steam is never recovered and steam injection adversely impacts the lives of rotating and stationary turbine blades. Also, low NOx levels only can be maintained if HGP parts are

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First steps. Shortly after Dynegy asked PSM to suggest an economic solution for reducing emissions at the Channelview facility consistent with regulatory demands, Clay Moran, director of customer and product sup-port group, spent long hours prepar-ing the company’s proposal.

PSM engineers worked with Moran to conceptualize what would be required to achieve Dynegy’s

objectives, how that work would be done, how long i t would take , and how much it would cost. A con-fident PSM bid the job and Dynegy rewarded it with a contract.

Shortly there-after, Don Adams, director of engi-neering programs, was assigned as the program man-ager for the proj-ect. His first action was to visit the plant and scope out the job. Adams says this work took about three days. He spent most of that time “crawling over” an engine that had been removed from service and cooled down to take the physi-cal measurements necessary, record

observations in a notebook, and pho-tograph everything from various angles. Thorough due diligence as Adams puts it. A PSM team also installed instrumentation to monitor key engine variables necessary for design work.

Adams

2. New transition pieces are part of the upgrade package 3. Liner is held in place by special jig during installation

4. Stub cases and end covers are installed next. Stub cases add space to accommodate the premixing of air and fuel required to achieve low NOx emissions

Air flow

Dynamicsensor

Purge cabinet

Nitrogen purge bottles

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6. Combustion dynamics monitoring system protects the engine against damaging pressure pulsations that can occur at the conditions required for efficient operation with minimal NOx emissions

5. Fuel manifolds and combustors are connected with flexible metal hose

Moran


Designers needed precise mea-surements on the 7E machines with-in their respective packages to ensure that the mods planned could be pre-fabricated and that their installation would be possible without interfer-ence issues. PSM hired a third-party contractor with ATOS (for advanced topometric optical sensor) system experience to digitize the engines, associated piping, etc, to obtain this information.

Preliminary information gather-ing complete, Adams and associates shifted into high gear with much work to do while facing the challeng-es of integrating their effort into the customer’s planned outage and meet-ing a hard restart date.

One action was to create separate design teams for aero/mechanical/engine performance and for electrical/controls. Note that about half of the conversion effort involved controls, electrical, and fuel-skid work. The design effort was “pretty convention-al” in approach, continues Adams. Computer models helped identify design options, which then were eval-uated based on cost, schedule, inter-changeability, performance, etc.

LEC III retrofitJust how the Altura diffusion-flame combustion system was replaced with PSM’s ultra-low-NOx LEC III is perhaps best described by way of

illustrations. Fig 1 presents an over-view of the completed project: The “new” GT with its LEC III combus-tion system, redesigned exhaust end, and higher-capacity blowers for cool-ing the exhaust frame and load tun-nel all are in place. The remaining

8. CDMS purge cabinet is where the long sensor lines—so-called “infinite” tubes—are connected to nitrogen bot-tles to eliminate any moisture present

Primaryfuel

Secondary fuel

Transferfuel

7. Sensors transmit to the CDMS pressure pulsations that occur during the combustion process

9. Fuel-system model shows how each of the three concentric fuel ring manifolds (primary fuel on the outside, transfer fuel in middle, secondary fuel on the inside) is connected to each combustion chamber


illustrations show how the PSM team got to this point.

Installation of the new transi-tion pieces (TPs) is in Fig 2; one of the combustor liners is installed in Fig 3; stub cases and end covers are installed in Fig 4; combustors and fuel supply are connected in Fig 5.

Stub cases lengthen the combus-tors to allow for premixing of fuel and air upstream of the burner. A pre-mix zone is necessary to achieve the lean fuel/air mixtures necessary to minimize flame temperature and the formation of so-called thermal NOx. Recall that of the three mechanisms associated with NOx formation—the other two being prompt NOx and the reaction that converts nitrous oxide (N2O) to nitric oxide (NO)—thermal NOx is the dominant mechanism in most GT combustors.

For more detail on how low-NOx combustion systems work—specif-ically the DLN-1 used on Altura’s 7EA—access www.combinedcy-clejournal.com/archives.html, click 3Q/2007, click “7EA User Group report” on issue cover and scroll to “Troubleshooting DLN-1 systems.”

Dynamic instabilities associ-ated with the combustion process at lean conditions have the potential

for damaging engine components. A critical function of the combustion dynamics monitoring system (CDMS) installed at Altura is to detect harm-ful pressure pulsations (Fig 6).

The dynamic sensor, a sophisti-cated pressure transducer, is circled in Fig 7; the long sensor lines—so-called “infinite” tubes—are required to provide a quality signal. Sensor lines must be kept dry and a nitrogen purge system is installed to ensure that (Fig 8). The heart of the CDMS system is the Alta Systems Inc (San Diego) computer that runs propri-etary software to analyze combustion dynamics. It triggers alarms when necessary.

Fuel system. The 7Es, as sup-plied, had two ring headers serving the combustion system, one for fuel and the other for NOx-abatement steam. The new system has three manifolds—all gas: one each for primary fuel (green in Fig 9), sec-ondary fuel (inner ring header, purple), and transfer fuel (middle ring). Details on how transfer pip-ing from the fuel skid intercon-nects with the engine are shown in Fig 10. The plant was responsible for installing the piping required to connect the new fuel skids (in PSM’s scope of supply) to their respective engines.

Note that air flows through the

Primary fuelTransfer fuel Secondary fuel Purge air

10. Piping that connects the fuel skid and the engine was the plant’s responsibility

11. Manifold purge valves, painted yellow, are easy to identify in fuel skid


transfer fuel circuit at all times except during the 45-sec period during engine startup when the combustion system transitions from the lean-lean mode to the premix mode.

The fuel skid, made by Mitten Manufacturing Inc, Syracuse, NY, incorporated the original single-body main gas and stop/ratio valves (one per engine) along with the new split-ter and purge valves. In Fig 11, the component in the foreground on the right-hand side is the main gas and stop/ratio valve. The transfer mani-fold purge valves (yellow), which did not exist in the original fuel system, are at the rear of the skid next to the main splitter valve.

Inlet bleed heat. When operat-ing in the premix mode and required to reduce load, fuel flow is throttled back. IGVs (inlet guide vanes) close as fuel flow is reduced. If load was reduced to less than about 75% of the full-load rating, the Altura engines would be in danger of compressor icing were the IGVs to close further.

But by installing the inlet bleed heat (IBH) system mentioned earlier, PSM was able to maintain minimum flame temperature to permit turn-down to about 50% to 55% of rated capability. What the system does is simply inject a portion of the hot compressor discharge air into the

compressor inlet air stream. There is a part-load heat-rate penalty for doing this, but emissions compliance is maintained and operating flexibil-ity is increased.

Fig 12 shows the original silencer section of the inlet air house with the inlet elbow and filters removed. A new module, designed to fit in the same space, incorporates both the IBH and new, but shorter, silencers (Fig 13). The IBH, facing front in the photo, consists of a series of vertical distribution pipes with holes drilled in them. The horizontal pipe is the

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13. Inlet-bleed-heat manifold and new silencer are packaged into the same space occupied by the original inlet silencer

12. Original silencers are exposed after air-inlet elbow is removed


manifold serving the distribution network.

Exhaust arrangement. Modifi-cation to the cooling system of the 7E exhaust-system frame was necessary to accommodate the higher gas tem-perature experienced when operating in the premix mode at high turndown. PSM hadn’t designed an exhaust sys-tem previously but because it was all about fluid flow and temperature the company was confident in its ability to do so and Dynegy supported that decision.

PSM replaced the two existing 75-hp blowers with 100-hp units and reconfigured the cooling circuit

as shown in Fig 14. Originally, air from the ring manifold was supplied to the exhaust case and load tunnel via 42 “J” tubes; the new manifold has four major supply pipes (Fig 15). To accommodate this design, four 5.25-in.-diam holes were cut through the exhaust case. After the existing “J” tubes were removed, the holes associated with them were plugged and small nozzles were installed to divert some of the air flow to cool the turbine case.

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A clean sheet of paperJesse Sewell, who transferred to PSM from Calpine Corp’s respected Turbine Maintenance Group several years ago, managed the controls and electrical portion of the Altura proj-ect, as well as installation and com-missioning in the field. Listen long

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14. Original and modified exhaust arrangements are pre-sented in one illustration (left)

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enough to some plant per-sonnel and coworkers and you might begin to think the guy’s a folk hero. “He started with a clean sheet of paper” is what the edi-tors typically heard during interviews. That certainly piques your interest, but what does it mean?

Briefly, the Altura proj-ect involved several industry firsts and the control system had to be designed from scratch. And that’s what Sewell did. “He just sketched out how the control system would be transitioned from a Mark IV to Ovation and it worked,” say several people close to the project. Talk to the modest Sewell and he’ll admit to having started “with a clean sheet of paper,” but he credits many others for the project’s success.

The list includes PSM engineers, working in small interactive groups, who designed the controls logic, sys-tem by system. Mitch Cochran is one of those people—an indepen-dent controls engineer and Ovation expert hired by PSM for the Altura project. He played a major role in the implementation as the controls “lead” responsible for coordination among PSM, the plant, and Emer-son Process Management. Sewell reminds that EPM, in addition to

providing Ovation hard-ware, wrote the control-sys-tem software based on the logic diagrams that PSM engineers created.

Some controls engineers would be intimidated by a project as complex as Altu-ra’s, but not Sewell and Cochran; both seem unflap-pable. Sewell will tell you

it was not very different from any other project he has done: He began by developing a well-organized and thorough plan, taking extreme care not to underestimate the complex-ity and time it would take to do any given task. Then he started at “Step 1” and worked through to the end. Confidence based on years of relevant experience, certainly not arrogance.

Cochran says new control systems were necessary for the GTs because the existing Mark IVs could not be configured to support DLN opera-tion. Altura had deep experience with Emerson’s WDPF® controls which were installed on the plant’s HRSGs and balance-of-plant systems. Recall that the Westinghouse Distributed Processing Family was developed by what is now Emerson’s Power & Water Solutions group when it was a division of Westinghouse Electric Corp. That group was not among the

Westinghouse assets purchased by Siemens 10 years ago.

Migration from WDPF to the more powerful Ovation is common and relatively easy to accomplish as evi-denced by presentations at user-group meetings dedicated to West-inghouse frames. The plant also had direct experience in transitioning from GE controls to Ovation from its fall 2004 upgrade of the steam tur-bine/generator’s Mark III controls to the Emerson platform (Sidebar 3).

Getting started. One of the first things Sewell and Cochran did was to conduct a comprehensive audit of the existing controls infrastructure. Other important tasks included the following:n Gather all pertinent documen-

tation available at the plant—including P&IDs.

n Develop a database of all control-system components.

n Discuss with plant personnel the control-system functionality required.

n Review PSM’s DLN logic.n Identify instrumentation that had

to be changed out or added to meet design criteria.

n Develop SAMAs. Note that these are control-loop drawings in a format developed by the Scientific Apparatus Manufacturers Assn. They go beyond P&IDs, which are

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prepared to ISA (Instrumentation, Systems, and Automation Society) guidelines, in terms of their abil-ity to fully describe complex con-trol logic.

n Write specifications to support the control-system purchase order. The audit of control-system

infrastructure included identifica-tion of all the field wiring connected to the Mark IV system. A goal was to maintain the field terminations “as is” to simplify the project. De-termination and re-termination lists were compiled and field-wiring terminal strips were unbolted from their I/O cards in their cabinet, adjacent to the Mark IV cabinet, and placed on the floor. After the old cabinet was removed and the new one installed, the termination boards were bolted in place. Emer-son was given the information to design a compatible replacement termination cabinet.

Cochran recalls that it took a team of three very experienced electricians only about a week to connect the field wiring into the new control sys-tem, “shoot loops,” etc. Connecting up

PSM’s DLN cabinet took a little lon-ger because all the cabling was new. Neither work package was a critical-path item.

To ensure that installation of field wiring for Ovation did not adversely impact schedule, cable was pulled and conduit installed prior to unit shutdown. Terminations were com-pleted (about 400 points) in about a week; loop check-out took another week. Functional checks, including final calibration of valves using lube oil as hydraulic oil, was done after mechanical completion. Large scope of work, notes Cochran, but it was relatively straight-forward.

Don’t get the impression that the entire job was “plug ’n play.” Control logic for some auxiliaries—such as fire protection, generator protection, and lube-oil systems—was integrat-ed into the Mark IV and it had to be recreated and brought into Ovation. PSM engineers did the design work, Emerson the programming.

One of the toughest assignments went to Emerson. The company com-mitted to accurately duplicating the functionality of the Mark IV in Ova-tion. This meant its engineers had to write special algorithms to allow Ova-tion methodology to match GE meth-odology. By way of example, consider

3. Steamer upgrade to Ovation preceded the 7E conversionAdvancements in control system technology and the reluctance of the OEM to support legacy sys-tems, justified upgrading Altura’s steamer from GE Mark III to Emer-son Process Management’s Ova-tion in fall 2003. The WDPF turbine auxiliary control processor was retained.

New Q-line I/O cards mimic the I/O provided in the Mark III and connect to the Ovation controller for processing. Two link interface cards provide the Modbus gateway from the plant’s existing WDPF controls to Ovation. A new turbine supervisory monitoring system was included as part of the project, along with upgraded valves and transmitters.

Altura Controls Specialist Tommy Huffman says the Ovation migration was done during a steam-turbine major inspection and was not a criti-cal-path item. Tuning was done after the major. Huffman adds he is still amazed at how well the job went. He couldn’t recall any issues other than a few minor valve-positioner card problems on startup. Final comment: Troubleshooting is much easier with Ovation than the Mark III.

Safety is at the core of every project we deliver

“We take safety seriously for our employees, contractors and visitors, and we’re pleased that our High Bridge project is achieving that goal.”

—David WilksPresident,

Xcel Energy Supply

PO012008001MKT© 2008 CH2M HILL

When Xcel Energy chose CH2M HILL as the EPC contractor to build their complex High Bridge combined cycle power plant, they got more than they expected including a Minnesota STAR award for 1 million work hours without a lost-time incident—a fi rst for a new power plant in the state. This project contributed to our current safety record of more than 5 million work hours without a lost-time accident.

As a global leader in engineering, procurement, construction, and operations, providing full services from a single source, CH2M HILL is delivering many exciting projects that will produce energy from natural gas, coal, oil, and renewable resources around the world.

Outperformance™ ch2mhill.com/power

The large heat recovery steam generator sections, fully assembled outside the building, are being rolled into fi nal position, saving time and money for the project.


the triple redundancy GE builds into the operation of its fuel valves. Emer-son had to assure that in its system. The company also developed a spe-cial algorithm for the CDMS to sim-plify logic and make the system very accurate. In sum, all of the control, operational modes, and protection functions that were included in the Mark IV controller are incorporated in the Ovation system.

Simulation. An important task assigned to Cochran was the design of a simulator to verify control-sys-tem functionality during the factory

acceptance test (FAT). Emerson built the simulator and incorporated per-tinent lessons learned on the Texas City project.

Sewell says the FAT in the sprawling assembly area of Emer-son’s Pittsburgh headquarters build-ing was rigorous, taking about a month. The first week was spent debugging the simulator, the sec-ond verifying system functionality; a few more days were invested in checking hardware performance. FAT drills, including participation by Altura personnel, were the final step. Result: a few minor design refinements were made as suggested by simulation results.

Testing, commissioning. Fol-lowing field installation, a series of tests was conducted to ensure that the plant had control of the tur-bine—that is, speed control, mega-watt control, trip capability, etc. Cold commissioning was next; it took an experienced crew of three about four weeks to complete for the first unit. More people were involved in com-missioning future units because they were retrofitted in pairs and done back-to-back. Schedule compressed as experience was gained.

Cold commissioning includes loop checks, equipment functional tests, leak checks, verification of the venti-lation system and just about anything else that could turn “on” or “off” or be modulated during operation. This is when you want to identify possible problem areas, stresses Sewell, not when you’re online.

Hot commissioning is the final step before commercial operation. It usually begins about a week to 10 days after you prove operation of the hydraulic system “cold.” Hot commis-sioning is very systematic, continues Sewell. If no problems are identified you should be up and running in three starts or less. One of the five Altura units went to full speed/no load on the first attempt. ccj

Visit booth 213 HRSG 2008

Are You Experiencing EHC Varnishing Issues?

Avoid downtime. Learn how to troubleshoot EHC problems from a certified professional who designs systems

for a major power generation OEM.

Contact: Steve Golya, Power Generation General ManagerDees Fluid Power1809 Fashion CourtJoppa, MD [email protected]

Visit booth 116 WTUI 2008

Details as they become available at:http://ge7ea.users-groups.com

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