Plant staff, EPC contractor team to minimize water consumption at ZLD site

When Reno-based Sierra Pacific Power Co merged with Nevada Power Co in 1999, 100 years had passed since one of its predecessor companies built the first generating station on the east side of the Sierra Nevada range—the Farad Hydroelec­tric Plant on the Truckee River. The company installed and operated only a few small hydro and diesel facili­ties until the 1960s, buying most of the power it distributed to customers.

The 1961 installation of a 10-MW W171G diesel-fueled gas turbine at what is now known as the Frank A Tracy Generating Station—doubled Sierra Pacific’s installed capacity of 10.05 MW at the end of the 1950s.

That engine still runs when need­ed, but it is no longer alone at the picturesque site 17 miles east of Reno off Interstate 80. The station has expanded to 12 generating units with a combined winter rating of 1094 MW (Fig 6-1). Most recently, a 2 × 1 F-class combined cycle entered service. A visit to the site provides valuable historical perspective on the evolution of gen­eration technology over the last half century—an operating Smithsonian so to speak (Sidebar 1).

Tracy has two of those early West­inghouse frames a stone’s throw from the latest F-class gas turbines, small gas-fired steam/electric units capable of operation on oil, a coal gasification system (decommissioned; Sidebar 2), the first commercial GE 6FA, cooling lake, wet cooling towers, air-cooled condenser, wet surface air cooler, evaporation ponds, controls technolo­gies from pneumatics to the latest digital offerings, etc.

The editors visited with Region­al Director Wade Barcellos, Main­tenance Manager Brian Lawson, and Plant Engineer Jesse Murray to learn how the new combined cycle was integrated into the existing plant and to review the first year’s operat­ing experience.

The Frank A Tracy Combined Cycle Plant doubled the station’s capacity when it went commercial in July 2008—a milestone for NV Ener­gy because it made the company’s northern Nevada service territory virtually self-sufficient on generation for the first time.

Principal contractors for the proj­ect were CH2M Hill (Englewood, Colo) subsidiary LG Constructors for EPC services; GE Energy, Atlanta, for gas and steam turbine/generators, and Nooter/Eriksen Inc, Fenton, Mo, for heat-recovery steam generators (HRSGs). NV Energy purchased the HRSGs and turbines directly from N/E and GE. Principal equipment is highlighted in Sidebar 3.

The project was proposed to the Public Utilities Commission of Nevada by Sierra Pacific in July 2004. Construction was approved by that regulatory body in December 2005. Recall that Sierra Pacific and Nevada Power were subsidiaries of Sierra Pacific Resources until the SPR name was changed to NV Ener­gy Inc in September 2008.

At first blush, the Tracy combined-cycle project doesn’t seem much dif­ferent than perhaps 100 other GE 7FA-powered 2 × 1 plants. So the casual industry observer might think “no big deal.” But it really was. Con­sider the following:

  • Emissions limits. The Tracy per­mit says NOx must be held to 2 ppm on a dry volumetric basis cor­rected to 15% O2. Are others forced to meet such a rigorous standard? Yes, but they are relatively few in number. More typically you hear something like “less than 3 ppm.” As small as that number is, it’s 50% higher than Tracy is allowed.

CO emissions are limited to 3.5 ppmvd at 15% O2 with duct-burner firing. That’s a challenging number by itself, but especially so at 2 ppm NOx. Plus, VOCs are restricted to 4 ppmvd at 15% O2 with duct burners in service.

  • Construction schedule: 26 months from site mobilization to commercial operation. Have others done as well? Yes. Have others done it in less time? Yes.

But were those others challenged by the unavailability of skilled work­ers (because the area workforce already had been absorbed by an unprecedented boom in Nevada com­mercial construction)?

And were those others challenged by the unavailability of structural steel, piping, electrical cable, etc (because of unprecedented global demand)?

To successfully address these challenges, CH2M Hill (1) relied significantly on skilled subcontrac­tors from nearby states; (2) installed the majority of piping and electrical conduit underground to complete that work early in the project and spread out craft needs; (3) developed contingency plans for workarounds as delays in material deliveries sur­faced; and (4) even purchased P91 ingots to assure availability of the premium steam pipe required.

Regarding the last point, not all piping for Tracy was made from pur­chased ingots; some was available through traditional sources. Recall that P91 is a particularly sensitive material and strict adherence to QA/QC procedures was required during its manufacture, welding, and han­dling.

All weld prep was done in a quali­fied shop and piping runs were pre­fabricated there as well—to the extent possible. All field welders were qualified to pre-approved pro­cedures and pre- and post-weld heat treatments were closely monitored by trained inspectors.

1. Thumbnails of Tracy’s generating units

Peaker Unit 1: Westinghouse Electric Corp 171G, a 10-MW distillate-only engine with air-cooled generator; installed in 1961.
Peaker Unit 2: Westinghouse Electric Corp 171G, a10-MW distillate-only engine with air-cooled generator; installed in 1963.
Peaker Units 3 and 4: Each a GE Energy 7EA equipped for dual-fuel firing and rated 72 MW. Both have GE air-cooled generators and were installed in 1994.
Unit 1: Conventional steam plant installed in 1963 with Riley Stoker Corp gas-fired boiler and 53-MW, hydro­gen-cooled GE Energy turbine/generator.
Unit 2: Conventional steam plant installed in 1965 with Riley Stoker Corp gas-fired boiler (backup fuel, No. 6 oil) and 83-MW, hydrogen-cooled Westinghouse Elec­tric Corp turbine/generator.
Unit 3: Conventional steam plant installed in 1974 with Babcock & Wilcox Co gas/No. 6 oil-fired boiler and 108-MW hydrogen-cooled Westinghouse Electric Corp turbine/generator. DCS and turbine control sys­tem are Ovation® (Emerson Process Mangement).
Units 4/5: A 108-MW 1 × 1 combined cycle installed in 1996 as part of the Pinon Pine IGCC Power Proj­ect (Sidebar 2) is powered by a 62-MW, gas-fired, steam-injected GE Energy 6FA (Unit 4, Serial No. 1) and includes an ATS (now Express Integrated Tech­nologies LLC, Tulsa) heat-recovery steam generator (HRSG) and a 46-MW GE Energy steam turbine/generator (Unit 5). Both generators are air-cooled. DCS is Siemens Moore APACS (Siemens Energy & Automation Inc); turbine control systems are GE Energy Mark V.
Units 8/9/10: This 541-MW 2 × 1 combined cycle, which began commercial operation in July 2008, is powered by two GE Energy 7FAs (Units 8 and 9) and includes two Nooter/Eriksen Inc HRSGs and a GE Energy D11 steam turbine/generator (Unit 10). All generators are hydrogen-cooled. DCS is Ovation (Emerson Process Management); turbine control sys­tems are GE Energy Mark VI.

The project’s safety record was particularly impressive: 1.5 million safe work hours during construction with zero lost-time accidents. This was attributed in large measure to a strong culture of safety, communi­cation, and collaboration among the Northern Nevada Building Trades, CH2M Hill, and the NV Energy proj­ect team headed by Executive of New Generation Andy McNeil.

No dripping faucets

Minimum water consumption was one of NV Energy’s goals for Tracy. The company also wanted the new combined cycle’s water supply and treatment systems integrated into site infrastructure to the maximum extent possible (Fig 6-2). Duplicating equipment that was already there didn’t seem to make sense (Fig 6-3).

But system integration proved far more difficult to achieve than key decision-makers believed at the start of the project. Part of the problem may have been that the subcontrac­tors involved did not have an accu­rate water balance to begin with. That’s believable—perhaps even understandable—given the number and variety of generating units and their varying dispatch schedules.

However, understanding did not make things any easier for Barcellos’ Tracy team, which spent long hours working through some poor assump­tions and re-engineering what didn’t meet expectations.

A year after COD, the gritty crew is able to manage the water sup­ply and treatment systems with an acceptable level of reliability while recognizing that there’s still more to do. Critical to reliable system opera­tion was the installation of a new evaporation pond after commission­ing (it is located to the left of the coal dome and not visible in Fig 6-1). Note that Tracy is a zero-liquid-discharge (ZLD) facility.

To illustrate how dramatically thinking had changed in the dozen or so years from the time the 1 × 1 6FA-powered combined cycle was designed to 2005 when the new 2 × 1 was approved, compare the heat rejection philosophies for both plants. The first has a surface condenser and wet cooling tower, the second an air-cooled condenser. Plus the Pinon Pine project had a so-called water destruc­tion system (evaporation tower) that eliminated blowdown from the clari­fier and sidestream softener serving its power island.

The only evaporative cooling used in the new combined cycle: A wet-surface air cooler (wet SAC) for the closed cooling-water system; evap coolers for the two 7FAs. The first is used when ambient temperature exceeds about 80F (or about 10% of the annual operating hours) and the dry fin-fan cooler (to left of ACC near the bottom of Fig 6-1) cannot main­tain the level of cooling desired. This reflects the degree to which designers went to conserve water.

Plant personnel learned early in the startup process that the waste­water treatment system was capaci­ty-challenged. Reducing the volume of influent to the system was critical. There were three major blowdown streams to manage from the new combined cycle: HRSG, wet SAC, and evap cooler. Here’s what was done to reduce the flows from each:

  • HRSG blowdown ranges from about 40 to 50 gpm per boiler in sum­mer. Original design relied on dilu­tion with service water (surface water available at the site) to lower blowdown temperature to what was required for processing by the wastewater treatment system.

Dilution, of course, increases the amount of water to process—the heart of the problem.

How to eliminate dilution was the challenge. Plant personnel came up with the idea to install a plate-and-frame heat exchang­er in the blowdown line and use spare heat-rejection capacity in the closed cooling-water system to reduce the temperature of the waste stream. CH2M Hill assisted in implementation of this idea, which proved successful.

  • Reducing wet SAC blowdown required no hardware modi­fications, only a reinforcement of operational philosophy: Use the wet SAC only when neces­sary. Sounds obvious; however, the message must be repeated as necessary. The manager of one plant not owned by NV Energy recently told the editors that he often found the wet SAC in service when it was not needed; operators were reluctant to take it out of ser­vice because they would only have to put it back in service the next day.
  • Evap coolers offered a “lesson learned.” Original plan was to use surface water as evap-cooler makeup. However, the responsible parties were unable to accurately predict the variations in surface-water constituents year-round and organics proved problematic at certain times. Evap coolers now have a simple diet: pH-adjusted well water. To minimize blow­down, evap coolers are used only when they provide a financial return.

2. Pinon Pine reminds industry of risks associated with new technologies

Electric utilities are relentlessly pressured by regulatory entities, special interest groups, and customers to reduce emissions and heat rate while simultaneously improving reliability—all without increasing the cost of electricity, of course. It’s a tall order that most people expert in the production and delivery of electric power would consider impractical.

The process of continual improvement requires “pushing the envelope” in the design and operation of conventional equipment as well as the development of new technologies promising a quantum leap forward. Such goals are laudable, but they often fall victim to unrealistic expectations with respect to performance, cost, and/or schedule of implementation.

Coal gasification is a case in point. Integrated gasification/combined-cycle plants (IGCC) are touted for their ability to produce a clean fuel from “dirty” indigenous resources to power gas turbines—the most efficient and least-polluting of the fossil-fuel-fired generation alternatives.

Sounds simple enough; yet after more than two decades of effort and an investment of countless millions by both DOE and private sources, there are only two utility-class IGCCs operating in the US. One is at Tampa Electric Co’s Polk Power Station, the nation’s only greenfield, commercial IGCC. The other is the Wabash River Coal Gasification Repowering Project, now owned by the Wabash Valley Power Assn and operated by Duke Energy Indiana. The editors believe there are only two IGCCs operating outside the US.

The Pinon Pine IGCC Power Project was a 50/50 government/industry partnership funded under DOE’s Clean Coal Technology program along with Polk and Wabash River. Its goal was to demonstrate the commercial viability of the air-blown gasification system developed by Kellog/Rust/Westinghouse.

Sierra Pacific Power Co, which later merged with Nevada Power Co to form NV Energy, entered into a cooperative agreement with DOE in August 1992 to install Pinon Pine at its Frank A Tracy Generating Station. By the time DOE participation in the project ended—the cooperative agreement expired at the end of 2000—the gasifier had not operated successfully for more than 24 hours at a time. Several technology-based reasons are offered for its failure.

The gasification system remains in place at Tracy, a silent reminder that new technology has very significant risks and that extrapolation of one or two success stories into a plan for an entire industry is foolhardy. By contrast, the GE Energy 6FA-powered 1 x 1 combined cycle installed as part of the project met expectations and operated base-load on natural gas until the more efficient 2 × 1 7FA-powered combined cycle entered commercial service last July.

Commissioning, teething problems

The schedule impacts created by late deliveries of equipment and consum­ables, and the need to use out-of-state craft labor, squeezed the Tracy commissioning schedule. The new combined cycle was needed to meet summer 2008 load projections.

The compressed commission­ing schedule for the HRSG was an inconvenience. It required creative solutions. For example, plant per­sonnel had to modify the conden­sate system to accommodate hard blowdown while the unit was in ser­vice, instead of removing mill scale and other debris before commercial operation.

3. Principal equipment, Units 8-10, Frank A Tracy Generating Station

Commercial operation: July 7, 2008
EPC contractor: CH2M Hill
Owner’s engineer: Zachry Holdings Inc
Type of plant: Combined cycle
Key personnel
Regional director: Wade Barcellos
Operations manager: John Frankovich
Maintenance manger: Brian Lawson
Plant engineer: Jesse Murray
Gas turbines
Manufacturer: GE Energy
Number of machines: 2
Model: 7FA
Control system: Mark VI
Combustion system: DLN 2.6
Fuel: Gas only
Water injection for NOx control? No
Water injection for power augmentation? No
Air inlet house: Braden Manufacturing LLC
Air filters: Donaldson Company Inc
Inlet-air cooling system, type: Evap cooler
Generator, type: Hydrogen-cooled
Manufacturer: GE Energy
GSUs: GE Energy
Manufacturer: Nooter/Eriksen Inc
Control system: Ovation® (Emerson Process Management)
Attemperator(s): CCI-Control Components Inc
Duct burner: Coen Company Inc
SCR: Peerless Mfg Co
Catalyst supplier: Cormetech Inc
CO catalyst: Englehard Corp (now BASF Catalysts LLC)
Steam-turbine bypass valve/desuperheater: CCI-Control Components Inc
Water treatment
HRSG internal treatment, type: Phosphate, ammonia
Chemical supplier: Nalco Co
Reverse osmosis installed? No
Demineralizer installed? Yes
Cooling-water chemicals: Nalco Co
Wastewater treatment system, type: ZLD
Supplier: Siemens Water Technologies

ACC commissioning also was challenging—this despite design opti­mization of steam-duct runs to reduce the amount of exposed metal surface and pressure washing of steam ducts prior to steam blows. Again, the com­missioning team addressed the prob­lems and, according to plant staff, it took nearly six months to get the ACC clean. The plant was in opera­tion most of that time.

Steam blow and chemical cleaning were CH2M Hill’s responsibility. To avoid overwhelming the wastewa­ter treatment system during these activities, the EPC contractor had to run temporary blowdown lines to storage tanks.

Operations personnel said the plant cycled often during its first year of service, and it was necessary to blow down the condensate pot on every start to get system chemistry correct. Iron transport continues until today, although it does not inhibit operation. Staff and a water treatment consultant are investi­gating the source of the magnetic particles found at the bottom of the condensate tank.

There were other issues asso­ciated with the ACC as well. For example, steam bypass valves suf­fered significant wear and tear from debris, even though blow-through kits were used. Repairs after steam blows were expensive. Trim replace­ment was required on spray-water valves as well, because of debris car­ried over into the condensate/feedwa­ter system.

Problems also occurred with the two-speed fans. One lost a blade dur­ing startup operations; another fan threw a blade after commercial start. There was a hub issue as well. The solution: Fan was redesigned and all fans were replaced.

Then there was a steam-duct inci­dent. Plant staff said that operation of the attemperator as installed in the HP bypass line was controlled by steam temperature. However, bypass of HP steam weakened the large-diameter duct and it collapsed under ACC vacuum. Solution: The HP bypass was converted to enthalpy control, which addresses both pres­sure and temperature, and stiffen­ers were installed in the replace­ment section of steam duct.

Another operational issue was fan stall, attributed to severe cross winds in the canyon where Tracy was built. Some fans and streets are more affect­ed than others by the bidirectional winds out of the West or East. Plant staff has worked diligently to address ACC capacity reductions associat­ed with thunderstorms, which can cause chaotic wind patterns. Capacity reductions are short—often measured in minutes or at most a few hours—but engineers continue to study wind patterns and ways to minimize the impact of such upset conditions.

The foregoing examples illustrate the challenges experienced by indus­try leaders, such as NV Energy, as they strive to stay at the leading edge of design, operation, and mainte­nance practices. You can benefit from the Tracy experience by participat­ing in the inaugural meeting of the ACC Users Group, Nov 12-13, at NV Energy’s headquarters in Las Vegas (see advertisement in the preceding section on Higgins Station).

Teething problems corrected, Tracy staff said the ACC generally works well. Inspection of the steam duct during recent warranty inspec­tions revealed no visible issues. Icing was not problematic last winter. The ACC design allows isolation of individual streets via large butterfly valves, which helps keep water out of streets not required in cold weather. The OEM optimized operation of the two-speed fans using modeling soft­ware and then followed up with field-tuning. The DCS directly controls ACC operation. ccj

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